10 Questions You Should to Know about LNG on-vehicle cylinders soared over 80 times
Liquefied natural gas - Wikipedia
Form of natural gas for easier storage and transport
"LNG" redirects here. For other uses, see LNG (disambiguation).
Not to be confused with liquefied petroleum gas, nor with compressed natural gas, nor with natural-gas condensate (natural gas liquids).
Liquefied natural gas (LNG) is natural gas (predominantly methane, CH4, with some mixture of ethane, C2H6) that has been cooled to liquid form for ease and safety of non-pressurized storage or transport. It takes up about 1/600th the volume of natural gas in the gaseous state at standard conditions for temperature and pressure.
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LNG is odorless, colorless, non-toxic and non-corrosive. Hazards include flammability after vaporization into a gaseous state, freezing and asphyxia. The liquefaction process involves removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons, which could cause difficulty downstream. The natural gas is then condensed into a liquid at close to atmospheric pressure by cooling it to approximately '162 °C ('260 °F); maximum transport pressure is set at around 25 kPa (4 psi) (gauge pressure), which is about 0.25 times atmospheric pressure at sea level.
The gas extracted from underground hydrocarbon deposits contains a varying mix of hydrocarbon components, which usually includes mostly methane (CH4), along with ethane (C2H6), propane (C3H8) and butane (C4H10). Other gases also occur in natural gas, notably CO2. These gases have wide-ranging boiling points and also different heating values, allowing different routes to commercialization and also different uses. The "acidic" elements such as hydrogen sulphide (H2S) and carbon dioxide (CO2), together with oil, mud, water, and mercury, are removed from the gas to deliver a clean sweetened stream of gas. Failure to remove much or all of such acidic molecules, mercury, and other impurities could result in damage to equipment. Corrosion of steel pipes and amalgamization of mercury to aluminum within cryogenic heat exchangers could cause expensive damage.
The gas stream is typically separated into the liquefied petroleum fractions (butane and propane), which can be stored in liquid form at relatively low pressure, and the lighter ethane and methane fractions. These lighter fractions of methane and ethane are then liquefied to make up the bulk of LNG that is shipped.
Natural gas was considered during the 20th century to be economically unimportant wherever gas-producing oil or gas fields were distant from gas pipelines or located in offshore locations where pipelines were not viable. In the past, this usually meant that natural gas produced was typically flared, especially since unlike oil, no viable method for natural gas storage or transport existed other than compressed gas pipelines to end users of the same gas. This meant that natural gas markets were historically entirely local, and any production had to be consumed within the local or regional network.
Developments of production processes, cryogenic storage, and transportation created the tools required to commercialize natural gas into a global market which now competes with other fuels. Furthermore, the development of LNG storage also introduced a reliability in networks which was previously thought impossible. Given that storage of other fuels is relatively easily secured using simple tanks, a supply for several months could be kept in storage. With the advent of large-scale cryogenic storage, it became possible to create long term gas storage reserves. These reserves of liquefied gas could be deployed at a moment's notice through regasification processes, and today are the main means for networks to handle local peak shaving requirements.[1]
Specific energy content and energy density
[edit]The heating value depends on the source of gas that is used and the process that is used to liquefy the gas. The range of heating value can span ±10 to 15 percent. A typical value of the higher heating value of LNG is approximately 50 MJ/kg or 21,500 BTU/lb.[2] A typical value of the lower heating value of LNG is 45 MJ/kg or 19,350 BTU/lb.
For the purpose of comparison of different fuels, the heating value may be expressed in terms of energy per volume, which is known as the energy density expressed in MJ/litre. The density of LNG is roughly 0.41 kg/litre to 0.5 kg/litre, depending on temperature, pressure, and composition,[3] compared to water at 1.0 kg/litre. Using the median value of 0.45 kg/litre, the typical energy density values are 22.5 MJ/litre (based on higher heating value) or 20.3 MJ/litre (based on lower heating value).
The volumetric energy density of LNG is approximately 2.4 times that of compressed natural gas (CNG), which makes it economical to transport natural gas by ship in the form of LNG. The energy density of LNG is comparable to propane and ethanol but is only 60 percent that of diesel and 70 percent that of gasoline.[4]
History
[edit]Experiments on the properties of gases started early in the 17th century. By the middle of the seventeenth century Robert Boyle had derived the inverse relationship between the pressure and the volume of gases. About the same time, Guillaume Amontons started looking into temperature effects on gas. Various gas experiments continued for the next 200 years. During that time there were efforts to liquefy gases. Many new facts about the nature of gases were discovered. For example, early in the nineteenth century Cagniard de la Tour showed there was a temperature above which a gas could not be liquefied. There was a major push in the mid to late nineteenth century to liquefy all gases. A number of scientists including Michael Faraday, James Joule, and William Thomson (Lord Kelvin) did experiments in this area. In Karol Olszewski liquefied methane, the primary constituent of natural gas. By all gases had been liquefied except helium, which was liquefied in .
The first large-scale liquefaction of natural gas in the U.S. was in when the U.S. government liquefied natural gas as a way to extract helium, which is a small component of some natural gas. This helium was intended for use in British dirigibles for World War I. The liquid natural gas (LNG) was not stored, but regasified and immediately put into the gas mains.[5]
The key patents having to do with natural gas liquefaction date from and the mid-s. In Godfrey Cabot patented a method for storing liquid gases at very low temperatures. It consisted of a Thermos bottle-type design which included a cold inner tank within an outer tank; the tanks being separated by insulation. In Lee Twomey received patents for a process for large-scale liquefaction of natural gas. The intention was to store natural gas as a liquid so it could be used for shaving peak energy loads during cold snaps. Because of large volumes it is not practical to store natural gas, as a gas, near atmospheric pressure. However, when liquefied, it can be stored in a volume 1/600th as large. This is a practical way to store it but the gas must be kept at '260 °F ('162 °C).
There are two processes for liquefying natural gas in large quantities. The first is the cascade process, in which the natural gas is cooled by another gas which in turn has been cooled by still another gas, hence named the "cascade" process. There are usually two cascade cycles before the liquid natural gas cycle. The other method is the Linde process, with a variation of the Linde process, called the Claude process, being sometimes used. In this process, the gas is cooled regeneratively by continually passing and expanding it through an orifice until it is cooled to temperatures at which it liquefies. This process was developed by James Joule and William Thomson and is known as the Joule'Thomson effect. Lee Twomey used the cascade process for his patents.
Commercial operations in the United States
[edit]The East Ohio Gas Company built a full-scale commercial LNG plant in Cleveland, Ohio, in just after a successful pilot plant built by its sister company, Hope Natural Gas Company of West Virginia. This was the first such plant in the world. Originally it had three spheres, approximately 63 feet in diameter containing LNG at '260 °F. Each sphere held the equivalent of about 50 million cubic feet of natural gas. A fourth tank, a cylinder, was added in . It had an equivalent capacity of 100 million cubic feet of gas. The plant operated successfully for three years. The stored gas was regasified and put into the mains when cold snaps hit and extra capacity was needed. This precluded the denial of gas to some customers during a cold snap.
The Cleveland plant failed on October 20, , when the cylindrical tank ruptured, spilling thousands of gallons of LNG over the plant and nearby neighborhood. The gas evaporated and caught fire, which caused 130 fatalities.[6] The fire delayed further implementation of LNG facilities for several years. However, over the next 15 years new research on low-temperature alloys, and better insulation materials, set the stage for a revival of the industry. It restarted in when a U.S. World War II Liberty ship, the Methane Pioneer, converted to carry LNG, made a delivery of LNG from the U.S. Gulf Coast to energy-starved Great Britain. In June , the world's first purpose-built LNG carrier, the Methane Princess, entered service.[7] Soon after that a large natural gas field was discovered in Algeria. International trade in LNG quickly followed as LNG was shipped to France and Great Britain from the Algerian fields. One more important attribute of LNG had now been exploited. Once natural gas was liquefied it could not only be stored more easily, but it could be transported. Thus energy could now be shipped over the oceans via LNG the same way it was shipped in the form of oil.
The LNG industry in the U.S. restarted in with the building of a number of new plants, which continued through the s. These plants were not only used for peak-shaving, as in Cleveland, but also for base-load supplies for places that never had natural gas before this. A number of import facilities were built on the East Coast in anticipation of the need to import energy via LNG. However, a recent boom in U.S. natural gas production ('), enabled by hydraulic fracturing ("fracking"), has many of these import facilities being considered as export facilities. The first U.S. LNG export was completed in early .[8]
By , the U.S. had become the biggest exporter in the world, and projects already under construction or permitted would double its export capacities by .[9] The largest exporters were Cheniere Energy Inc., Freeport LNG, and Venture Global LNG Inc.[10] The U.S. Energy Information Administration reported that the U.S. had exported 4.3 trillion cubic feet in .[11]
LNG life cycle
[edit]The process begins with the pre-treatment of a feedstock of natural gas entering the system to remove impurities such as H2S, CO2, H2O, mercury and higher-chained hydrocarbons. Feedstock gas then enters the liquefaction unit where it is cooled to between -145 °C and -163 °C.[12] Although the type or number of heating cycles and/or refrigerants used may vary based on the technology, the basic process involves circulating the gas through aluminum tube coils and exposure to a compressed refrigerant.[12] As the refrigerant is vaporized, the heat transfer causes the gas in the coils to cool.[12] The LNG is then stored in a specialized double-walled insulated tank at atmospheric pressure ready to be transported to its final destination.[12]
Most domestic LNG is transported by land via truck/trailer designed for cryogenic temperatures.[12] Intercontinental LNG transport travels by special tanker ships. LNG transport tanks comprise an internal steel or aluminum compartment and an external carbon or steel compartment with a vacuum system in between to reduce the amount of heat transfer.[12] Once on site, the LNG must be stored in vacuum insulated or flat bottom storage tanks.[12] When ready for distribution, the LNG enters a regasification facility where it is pumped into a vaporizer and heated back into gaseous form.[12] The gas then enters the gas pipeline distribution system and is delivered to the end-user.[12]
Production
[edit]The natural gas fed into the LNG plant will be treated to remove water, hydrogen sulfide, carbon dioxide, benzene and other components that will freeze under the low temperatures needed for storage or be destructive to the liquefaction facility. LNG typically contains more than 90% methane. It also contains small amounts of ethane, propane, butane, some heavier alkanes, and nitrogen. The purification process can be designed to give almost 100% methane. One of the risks of LNG is a rapid phase transition explosion (RPT), which occurs when cold LNG comes into contact with water.[13]
The most important infrastructure needed for LNG production and transportation is an LNG plant consisting of one or more LNG trains, each of which is an independent unit for gas liquefaction and purification. A typical train consists of a compression area, propane condenser area, and methane and ethane areas.
The largest LNG train in operation is in Qatar, with a total production capacity of 7.8 million tonnes per annum (MTPA). LNG is loaded onto ships and delivered to a regasification terminal, where the LNG is allowed to expand and reconvert into gas. Regasification terminals are usually connected to a storage and pipeline distribution network to distribute natural gas to local distribution companies (LDCs) or independent power plants (IPPs).
LNG plant production
[edit]Information for the following table is derived in part from publication by the U.S. Energy Information Administration.[14]
See also List of LNG terminals
World total production
[edit] Year Capacity (MTPA) 50[22] 130[23] 160[22] 246[24]The LNG industry developed slowly during the second half of the last century because most LNG plants are located in remote areas not served by pipelines, and because of the high costs of treating and transporting LNG. Constructing an LNG plant costs at least $1.5 billion per 1 MTPA capacity, a receiving terminal costs $1 billion per 1 bcf/day throughput capacity and LNG vessels cost $200 million'$300 million.
In the early s, prices for constructing LNG plants, receiving terminals and vessels fell as new technologies emerged and more players invested in liquefaction and regasification. This tended to make LNG more competitive as a means of energy distribution, but increasing material costs and demand for construction contractors have put upward pressure on prices in the last few years. The standard price for a 125,000 cubic meter LNG vessel built in European and Japanese shipyards used to be US$250 million. When Korean and Chinese shipyards entered the race, increased competition reduced profit margins and improved efficiency'reducing costs by 60 percent. Costs in US dollars also declined due to the devaluation of the currencies of the world's largest shipbuilders: the Japanese yen and Korean won.
Since , the large number of orders increased demand for shipyard slots, raising their price and increasing ship costs. The per-ton construction cost of an LNG liquefaction plant fell steadily from the s through the s. The cost reduced by approximately 35 percent. However, recently the cost of building liquefaction and regasification terminals doubled due to increased cost of materials and a shortage of skilled labor, professional engineers, designers, managers and other white-collar professionals.
Due to natural gas shortage concerns in the northeastern U.S. and surplus natural gas in the rest of the country, many new LNG import and export terminals are being contemplated in the United States. Concerns about the safety of such facilities create controversy in some regions where they are proposed. One such location is in the Long Island Sound between Connecticut and Long Island. Broadwater Energy, an effort of TransCanada Corp. and Shell, wishes to build an LNG import terminal in the sound on the New York side. Local politicians including the Suffolk County Executive raised questions about the terminal. In , New York Senators Chuck Schumer and Hillary Clinton also announced their opposition to the project.[25] Several import terminal proposals along the coast of Maine were also met with high levels of resistance and questions. On September 13, , the U.S. Department of Energy approved Dominion Cove Point's application to export up to 770 million cubic feet per day of LNG to countries that do not have a free trade agreement with the U.S.[26] In May , the FERC concluded its environmental assessment of the Cove Point LNG project, which found that the proposed natural gas export project could be built and operated safely.[27] Another LNG terminal is currently proposed for Elba Island, Georgia, US.[28] Plans for three LNG export terminals in the U.S. Gulf Coast region have also received conditional Federal approval.[26][29] In Canada, an LNG export terminal is under construction near Guysborough, Nova Scotia.[30]
Commercial aspects
[edit]Global Trade
[edit]In the commercial development of an LNG value chain, LNG suppliers first confirm sales to the downstream buyers and then sign long-term contracts (typically 20'25 years) with strict terms and structures for gas pricing. Only when the customers are confirmed and the development of a greenfield project deemed economically feasible, could the sponsors of an LNG project invest in their development and operation. Thus, the LNG liquefaction business has been limited to players with strong financial and political resources. Major international oil companies (IOCs) such as ExxonMobil, Royal Dutch Shell, BP, Chevron, TotalEnergies and national oil companies (NOCs) such as Pertamina and Petronas are active players.
LNG is shipped around the world in specially constructed seagoing vessels. The trade of LNG is completed by signing an SPA (sale and purchase agreement) between a supplier and receiving terminal, and by signing a GSA (gas sale agreement) between a receiving terminal and end-users.[31] Most of the contract terms used to be DES or ex ship, holding the seller responsible for the transport of the gas. With low shipbuilding costs, and the buyers preferring to ensure reliable and stable supply, however, contracts with FOB terms increased. Under such terms the buyer, who often owns a vessel or signs a long-term charter agreement with independent carriers, is responsible for the transport.
LNG purchasing agreements used to be for a long term with relatively little flexibility both in price and volume. If the annual contract quantity is confirmed, the buyer is obliged to take and pay for the product, or pay for it even if not taken, in what is referred to as the obligation of take-or-pay contract (TOP).
In the mid-s, LNG was a buyer's market. At the request of buyers, the SPAs began to adopt some flexibilities on volume and price. The buyers had more upward and downward flexibilities in TOP, and short-term SPAs less than 16 years came into effect. At the same time, alternative destinations for cargo and arbitrage were also allowed. By the turn of the 21st century, the market was again in favor of sellers. However, sellers have become more sophisticated and are now proposing sharing of arbitrage opportunities and moving away from S-curve pricing.
Research from Global Energy Monitor in warned that up to US$1.3 trillion in new LNG export and import infrastructure currently under development is at significant risk of becoming stranded, as global gas risks becoming oversupplied, particularly if the United States and Canada play a larger role.[32]
The current surge in unconventional oil and gas in the U.S. has resulted in lower gas prices in the U.S. This has led to discussions in Asia' oil linked gas markets to import gas based on Henry Hub index.[33] Recent high level conference in Vancouver, the Pacific Energy Summit Pacific Energy Summit convened policy makers and experts from Asia and the U.S. to discuss LNG trade relations between these regions.
Receiving terminals exist in about 40[34] countries, including Belgium, Chile, China, the Dominican Republic, France, Greece, India, Italy, Japan, Korea, Poland, Spain, Taiwan, the UK, the US, among others. Plans exist for Bahrain, Germany, Ghana, Morocco, Philippines, Vietnam[35] and others to also construct new receiving (regasification) terminals.
LNG Project Screening
[edit]Base load (large-scale, >1 MTPA) LNG projects require natural gas reserves,[36] buyers[37] and financing. Using proven technology and a proven contractor is extremely important for both investors and buyers.[38] Gas reserves required: 1 tcf of gas required per Mtpa of LNG over 20 years.[36]
LNG is most cost efficiently produced in relatively large facilities due to economies of scale, at sites with marine access allowing regular large bulk shipments direct to market. This requires a secure gas supply of sufficient capacity. Ideally, facilities are located close to the gas source, to minimize the cost of intermediate transport infrastructure and gas shrinkage (fuel loss in transport). The high cost of building large LNG facilities makes the progressive development of gas sources to maximize facility utilization essential, and the life extension of existing, financially depreciated LNG facilities cost effective. Particularly when combined with lower sale prices due to large installed capacity and rising construction costs, this makes the economic screening/ justification to develop new, and especially greenfield, LNG facilities challenging, even if these could be more environmentally friendly than existing facilities with all stakeholder concerns satisfied. Due to high financial risk, it is usual to contractually secure gas supply/ concessions and gas sales for extended periods before proceeding to an investment decision.
Uses
[edit]The primary use of LNG is to simplify transport of natural gas from the source to a destination. On the large scale, this is done when the source and the destination are across an ocean from each other. It can also be used when adequate pipeline capacity is not available. For large-scale transport uses, the LNG is typically regassified at the receiving end and pushed into the local natural gas pipeline infrastructure.
LNG can also be used to meet peak demand when the normal pipeline infrastructure can meet most demand needs, but not the peak demand needs. These plants are typically called LNG Peak Shaving Plants as the purpose is to shave off part of the peak demand from what is required out of the supply pipeline.
LNG can be used to fuel internal combustion engines. LNG is in the early stages of becoming a mainstream fuel for transportation needs. It is being evaluated and tested for over-the-road trucking,[39] off-road,[40] marine, and train applications.[41] There are known problems with the fuel tanks and delivery of gas to the engine,[42] but despite these concerns the move to LNG as a transportation fuel has begun. LNG competes directly with compressed natural gas as a fuel for natural gas vehicles since the engine is identical. There may be applications where LNG trucks, buses, trains and boats could be cost-effective in order to regularly distribute LNG energy together with general freight and/or passengers to smaller, isolated communities without a local gas source or access to pipelines.
Use of LNG to fuel large over-the-road trucks
[edit]China has been a leader in the use of LNG vehicles[43] with over 100,000 LNG-powered vehicles on the road as of Sept .[44]
In the United States the beginnings of a public LNG fueling capability are being put in place. An alternative fuelling centre tracking site shows 84 public truck LNG fuel centres as of Dec .[45] It is possible for large trucks to make cross country trips such as Los Angeles to Boston and refuel at public refuelling stations every 500 miles. The National Trucker's Directory lists approximately 7,000 truckstops,[46] thus approximately 1% of US truckstops have LNG available.
While as of December LNG fuel and NGV's were not taken to very quickly within Europe and it was questionable whether LNG will ever become the fuel of choice among fleet operators,[47] recent trends from onwards show different prospect.[48] During the year , the Netherlands introduced LNG-powered trucks in transport sector.[49] Additionally, the Australian government is planning to develop an LNG highway to utilise the locally produced LNG and replace the imported diesel fuel used by interstate haulage vehicles.[50]
In the year , India also began transporting LNG using LNG-powered road tankers in Kerala state.[51] In , Petronet LNG began setting up 20 LNG stations on highways along the Indian west coast that connect Delhi with Thiruvananthapuram covering a total distance of 4,500 km via Mumbai and Bengaluru.[52] In , India planned to install 24 LNG fuelling stations along the 6,000 km Golden Quadrilateral highways connecting the four metros due to LNG prices decreasing.[53]
Japan, the world's largest importer of LNG, is set to begin use of LNG as a road transport fuel.[54]
High-power, high-torque engines
[edit]Engine displacement is an important factor in the power of an internal combustion engine. Thus a 2.0 L engine would typically be more powerful than an 1.8 L engine, but that assumes a similar air'fuel mixture is used.
However, if a smaller engine uses an air'fuel mixture with higher energy density (such as via a turbocharger), then it can produce more power than a larger one burning a less energy-dense air'fuel mixture. For high-power, high-torque engines, a fuel that creates a more energy-dense air'fuel mixture is preferred, because a smaller and simpler engine can produce the same power.
With conventional gasoline and diesel engines the energy density of the air'fuel mixture is limited because the liquid fuels do not mix well in the cylinder. Further, gasoline and diesel fuel have autoignition temperatures and pressures relevant to engine design. An important part of engine design is the interactions of cylinders, compression ratios, and fuel injectors such that pre-ignition is prevented but at the same time as much fuel as possible can be injected, become well mixed, and still have time to complete the combustion process during the power stroke.
Natural gas does not auto-ignite at pressures and temperatures relevant to conventional gasoline and diesel engine design, so it allows more flexibility in design. Methane, the main component of natural gas, has an autoignition temperature of 580 °C (1,076 °F),[55] whereas gasoline and diesel autoignite at approximately 250 °C (482 °F) and 210 °C (410 °F) respectively.
With a compressed natural gas (CNG) engine, the mixing of the fuel and the air is more effective since gases typically mix well in a short period of time, but at typical CNG pressures the fuel itself is less energy-dense than gasoline or diesel, so the result is a less energy-dense air'fuel mixture. For an engine of a given cylinder displacement, a normally-aspirated CNG-powered engine is typically less powerful than a gasoline or diesel engine of similar displacement. For that reason turbochargers are popular in European CNG cars.[56] Despite that limitation, the 12-litre Cummins Westport ISX12G engine[57] is an example of a CNG-capable engine designed to pull tractor'trailer loads up to 80,000 pounds (36,000 kg) showing CNG can be used in many on-road truck applications. The original ISX G engine incorporated a turbocharger to enhance the air'fuel energy density.[58]
LNG offers a unique advantage over CNG for more demanding high-power applications by eliminating the need for a turbocharger. Because LNG boils at approximately '160 °C ('256 °F), by using a simple heat exchanger a small amount of LNG can be converted to its gaseous form at extremely high pressure with the use of little or no mechanical energy. A properly designed high-power engine can leverage this extremely-high-pressure, energy-dense gaseous fuel source to create a higher-energy-density air'fuel mixture than can be efficiently created with a CNG-powered engine. The result when compared to CNG engines is more overall efficiency in high-power engine applications when high-pressure direct-injection technology is used. The Westport HDMI2[59] fuel system is an example of a high-pressure direct-injection system that does not require a turbocharger if paired with an appropriate LNG heat exchanger. The Volvo Trucks 13-litre LNG engine[60] is another example of an LNG engine leveraging advanced high-pressure technology.
Westport recommends CNG for engines 7 litres or smaller and LNG with direct-injection for engines between 20 and 150 litres. For engines between 7 and 20 litres either option is recommended. See slide 13 from their NGV Bruxelles ' Industry Innovation Session presentation.[61]
High-power engines in the oil drilling, mining, locomotive, and marine fields have been or are being developed.[62] Paul Blomerus has written a paper[63] concluding as much as 40 million tonnes per annum of LNG (approximately 26.1 billion gallons/year or 71 million gallons/day) could be required just to meet the global needs of such high-power engines by to .
As of the end of first quarter of , Prometheus Energy Group Inc claimed to have delivered over 100 million gallons of LNG to the industrial market within the previous four years[64] and is continuing to add new customers.
Use of LNG in maritime applications
[edit]LNG bunkering has been established in some ports via truck-to-ship fueling. This type of LNG fueling is straightforward to implement, assuming a supply of LNG is available.
Feeder and short-sea shipping company Unifeeder has been operating the world's first LNG powered container vessel, the Wes Amelie, since late , transiting between the port of Rotterdam and the Baltics on a weekly schedule.[65] Container shipping company Maersk Group has decided to introduce LNG-powered container ships.[66] The DEME Group has contracted Wärtsilä to power its new generation 'Antigoon' class dredger with dual fuel (DF) engines.[67] Crowley Maritime of Jacksonville, Florida, launched two LNG-powered ConRo ships, the Coquí and Taino, in and , respectively.[68]
In , Shell ordered a dedicated LNG bunker vessel.[69] It is planned to go into service in Rotterdam in the summer of [70]
The International Convention for the Prevention of Pollution from Ships (MARPOL), adopted by the IMO, has mandated that marine vessels shall not consume fuel (bunker fuel, diesel, etc.) with a sulphur content greater than 0.5% from the year within international waters and the coastal areas of countries adopting the same regulation. Replacement of high sulphur bunker fuel with sulphur-free LNG is required on a major scale in the marine transport sector, as low sulphur liquid fuels are costlier than LNG.[71] Japan's is planning to use LNG as bunker fuel by .[72][73]
BHP, one of the largest mining companies in the world, is aiming to commission minerals transport ships powered with LNG by late .[74]
In January , 175 sea-going LNG-powered ships were in service, with another 200 ships ordered.[75]
Use of LNG on rail
[edit]Florida East Coast Railway has 24 GE ES44C4 locomotives adapted to run on LNG fuel.[76]
Trade
[edit]The global trade in LNG is growing rapidly from negligible in to what is expected to be a globally substantial amount by .[77] As a reference, the global production of crude oil was 14.6 million cubic metres (92 million barrels) per day[78] or 54,600 terawatt-hours (186.4 quadrillion British thermal units) per year.
In , global LNG trade was of 3 billion cubic metres (bcm) (0.11 quads).[79] In , it was 331 bcm (11.92 quads).[79] The U.S. started exporting LNG in February . The Black & Veatch Oct forecast is that by , the U.S. alone will export between 10 and 14 billion cu ft/d (280 and 400 million m3/d) or by heating value 3.75 to 5.25 quad (1,100 to 1,540 TWh).[80] E&Y projects global LNG demand could hit 400 mtpa (19.7 quads) by .[81] If that occurs, the LNG market will be roughly 10% the size of the global crude oil market, and that does not count the vast majority of natural gas which is delivered via pipeline directly from the well to the consumer.
In , LNG accounted for 7 percent of the world's natural gas demand.[82] The global trade in LNG, which has increased at a rate of 7.4 percent per year over the decade from to , is expected to continue to grow substantially.[83] LNG trade is expected to increase at 6.7 percent per year from to .[83]
Until the mid-s, LNG demand was heavily concentrated in Northeast Asia: Japan, South Korea and Taiwan. At the same time, Pacific Basin supplies dominated world LNG trade.[83] The worldwide interest in using natural gas-fired combined cycle generating units for electric power generation, coupled with the inability of North American and North Sea natural gas supplies to meet the growing demand, substantially broadened the regional markets for LNG. It also brought new Atlantic Basin and Middle East suppliers into the trade.[83]
Contact us to discuss your requirements of LNG on-vehicle cylinders soared over 80 times. Our experienced sales team can help you identify the options that best suit your needs.
By the end of , there were 19 LNG exporting countries and 40 LNG importing countries. The three biggest LNG exporters in were Qatar (77.5 MT), Australia (55.6 MT) and Malaysia (26.9 MT). The three biggest LNG importers in were Japan (83.5 MT), China (39 MT) and South Korea (37.8 MT).[84] LNG trade volumes increased from 142 MT in to 159 MT in , 165 MT in , 171 MT in , 220 MT in , 237 MT in , 264 MT in and 290 MT in .[84] Global LNG production was 246 MT in ,[85] most of which was used in trade between countries.[86] During the next several years there would be significant increase in volume of LNG Trade.[81] For example, about 59 MTPA of new LNG supply from six new plants came to market just in , including:
- Northwest Shelf Train 5: 4.4 MTPA
- Sakhalin-II: 9.6 MTPA
- Yemen LNG: 6.7 MTPA
- Tangguh: 7.6 MTPA
- Qatargas: 15.6 MTPA
- Rasgas Qatar: 15.6 MTPA
In , Qatar became the world's biggest exporter of LNG.[79] As of , Qatar is the source of 25 percent of the world's LNG exports.[79] As of , Qatar was estimated to supply 26.7% of the world's LNG.[84]
Investments in U.S. export facilities were increasing by , these investments were spurred by increasing shale gas production in the United States and a large price differential between natural gas prices in the U.S. and those in Europe and Asia. Cheniere Energy became the first company in the United States to receive permission and export LNG in .[8] After a US-EU agreement in , exports from USA to EU increased.[87] In November , U.S. producer Venture Global LNG signed a twenty-year contract with China's state-owned Sinopec to supply liquefied natural gas.[88] China's imports of U.S. natural gas will more than double.[89] U.S. exports of liquefied natural gas to China and other Asian countries surged in , with Asian buyers willing to pay higher prices than European importers.[90] This reversed in , when most of US LNG went to Europe. US LNG export contracts are mainly made for 15'20 years.[91] Exports from the U.S. are likely to reach 13.3 Bcf/d in due to projects coming online on the Gulf of Mexico.[92]
Imports
[edit]In , the UK and France made the first LNG trade, buying gas from Algeria, witnessing a new era of energy.
In , 19 countries exported LNG.[79]
Compared with the crude oil market, in the natural gas market was about 72 percent of the crude oil market (measured on a heat equivalent basis),[93] of which LNG forms a small but rapidly growing part. Much of this growth is driven by the need for clean fuel and some substitution effect due to the high price of oil (primarily in the heating and electricity generation sectors).
Japan, South Korea, Spain, France, Italy and Taiwan import large volumes of LNG due to their shortage of energy. In , Japan imported 58.6 million tons of LNG, representing some 30 percent of the LNG trade around the world that year. Also in , South Korea imported 22.1 million tons, and in Taiwan imported 6.8 million tons. These three major buyers purchase approximately two-thirds of the world's LNG demand. In addition, Spain imported some 8.2 MTPA in , making it the third largest importer. France also imported similar quantities as Spain.[citation needed] Following the Fukushima Daiichi nuclear disaster in March Japan became a major importer accounting for one third of the total.[94] European LNG imports fell by 30 percent in , and fell further by 24 percent in , as South American and Asian importers paid more.[95] European LNG imports increased to new heights in , remained high in and , and increased even more in .[91] Main contributors were Qatar, USA, and Russia.[96]
In , global LNG imports reached 289.8[97] million tonnes of LNG. In , 72.9% of global LNG demand was located in Asia.[98]
Cargo diversion
[edit]Based on the LNG SPAs, LNG is destined for pre-agreed destinations, and diversion of that LNG is not allowed. However, if Seller and Buyer make a mutual agreement, then the diversion of the cargo is permitted ' subject to sharing the additional profit created by such a diversion, by paying a penalty fee.[91] In the European Union and some other jurisdictions, it is not permitted to apply the profit-sharing clause in LNG SPAs.
Cost of LNG plants
[edit]For an extended period of time, design improvements in liquefaction plants and tankers had the effect of reducing costs.
In the s, the cost of building an LNG liquefaction plant cost $350/tpa (tonne per annum). In the s, it was $200/tpa. In , the costs can go as high as $1,000/tpa, partly due to the increase in the price of steel.[79]
As recently as , it was common to assume that this was a "learning curve" effect and would continue into the future. But this perception of steadily falling costs for LNG has been dashed in the last several years.[83]
The construction cost of greenfield LNG projects started to skyrocket from afterward and has increased from about $400 per ton per year of capacity to $1,000 per ton per year of capacity in .
The main reasons for skyrocketed costs in LNG industry can be described as follows:
- Low availability of EPC contractors as result of extraordinary high level of ongoing petroleum projects worldwide.[20]
- High raw material prices as result of surge in demand for raw materials.
- Lack of skilled and experienced workforce in LNG industry.[20]
- Devaluation of US dollar.
- Very complex nature of projects built in remote locations and where construction costs are regarded as some of the highest in the world.[99]
Excluding high cost projects the increase of 120% over the period - is more in line with escalation in the upstream oil & gas industry as reported by the UCCI index[99]
The ' financial crisis and the Great Recession led to a general decline in raw material and equipment prices, which somewhat lessened the construction cost of LNG plants.[100][101] However, by this was more than offset by increasing demand for materials and labor for the LNG market.
Small-scale liquefaction plants
[edit]Small-scale liquefaction plants are suitable for peakshaving on natural gas pipelines, transportation fuel, or for deliveries of natural gas to remote areas not connected to pipelines.[102] They typically have a compact size, are fed from a natural gas pipeline, and are located close to the location where the LNG will be used. This proximity decreases transportation and LNG product costs for consumers.[103][104] It also avoids the additional greenhouse gas emissions generated during long transportation.
The small-scale LNG plant also allows localized peakshaving to occur'balancing the availability of natural gas during high and low periods of demand. It also makes it possible for communities without access to natural gas pipelines to install local distribution systems and have them supplied with stored LNG.[105]
LNG pricing
[edit]There are three major pricing systems in the current LNG contracts:
- Oil indexed contract, used primarily in Japan, Korea, Taiwan and China;
- Oil, oil products and other energy carriers indexed contracts, used primarily in Continental Europe;[106] and
- Market indexed contracts, used in the US and the UK.
The formula for an indexed price is as follows:
CP = BP + β X
- BP: constant part or base price
- β: gradient
- X: indexation
The formula has been widely used in Asian LNG SPAs, where base price represents various non-oil factors, but usually a constant determined by negotiation at a level which can prevent LNG prices from falling below a certain level. It thus varies regardless of oil price fluctuation.
Henry Hub Plus
[edit]Some LNG buyers have already signed contracts for future US-based cargos at prices linked to Henry Hub prices.[107] Cheniere Energy's LNG export contract pricing consists of a fixed fee (liquefaction tolling fee) plus 115% of Henry Hub per million British thermal units of LNG.[108] Tolling fees in the Cheniere contracts vary: US$2.25 per million British thermal units ($7.7/MWh) with BG Group signed in ; $2.49 per million British thermal units ($8.5/MWh) with Spain's GNF signed in ; and $3.00 per million British thermal units ($10.2/MWh) with South Korea's Kogas and Centrica signed in .[109]
Oil parity
[edit]Oil parity is the LNG price that would be equal to that of crude oil on a barrel of oil equivalent (BOE) basis. If the LNG price exceeds the price of crude oil in BOE terms, then the situation is called broken oil parity. A coefficient of 0. results in full oil parity. In most cases the price of LNG is less than the price of crude oil in BOE terms.
In , in several spot cargo deals especially in East Asia, oil parity approached the full oil parity or even exceeded oil parity.[110] In January , the spot LNG price of $5.461 per million British thermal units ($18.63/MWh) has broken oil parity when the Brent crude price ('32 US$/bbl) has fallen steeply.[111] By the end of June , LNG price has fallen by nearly 50% below its oil parity price, making it more economical than more-polluting diesel/gas oil in the transport sector.[112] LNG briefly touched the oil parity in winter of /[113] and then rose above it during the recent global energy crisis in mid-[114] only falling below it in early .[115]
S-curve
[edit]Most of the LNG trade is governed by long-term contracts. Many formulae include an S-curve, where the price formula is different above and below a certain oil price, to dampen the impact of high oil prices on the buyer, and low oil prices on the seller. When the spot LNG price is cheaper than long term oil price indexed contracts, the most profitable LNG end use is to power mobile engines for replacing costly gasoline and diesel consumption.
In most of the East Asian LNG contracts, price formula is indexed to a basket of crude imported to Japan called the Japan Crude Cocktail (JCC). In Indonesian LNG contracts, price formula is linked to Indonesian Crude Price (ICP).
In continental Europe, the price formula indexation does not follow the same format, and it varies from contract to contract. Brent crude price (B), heavy fuel oil price (HFO), light fuel oil price (LFO), gas oil price (GO), coal price, electricity price and in some cases, consumer and producer price indexes are the indexation elements of price formulas.
Price review
[edit]Usually there exists a clause allowing parties to trigger the price revision or price reopening in LNG SPAs. In some contracts there are two options for triggering a price revision. regular and special. Regular ones are the dates that will be agreed and defined in the LNG SPAs for the purpose of price review.
Quality of LNG
[edit]LNG quality is one of the most important issues in the LNG business. Any gas which does not conform to the agreed specifications in the sale and purchase agreement is regarded as "off-specification" (off-spec) or "off-quality" gas or LNG. Quality regulations serve three purposes:[116]
- 1 ' to ensure that the gas distributed is non-corrosive and non-toxic, below the upper limits for H2S, total sulphur, CO2 and Hg content;
- 2 ' to guard against the formation of liquids or hydrates in the networks, through maximum water and hydrocarbon dewpoints;
- 3 ' to allow interchangeability of the gases distributed, via limits on the variation range for parameters affecting combustion: content of inert gases, calorific value, Wobbe index, Soot Index, Incomplete Combustion Factor, Yellow Tip Index, etc.
In the case of off-spec gas or LNG the buyer can refuse to accept the gas or LNG and the seller has to pay liquidated damages for the respective off-spec gas volumes.
The quality of gas or LNG is measured at delivery point by using an instrument such as a gas chromatograph.
The most important gas quality concerns involve the sulphur and mercury content and the calorific value. Due to the sensitivity of liquefaction facilities to sulfur and mercury elements, the gas being sent to the liquefaction process shall be accurately refined and tested in order to assure the minimum possible concentration of these two elements before entering the liquefaction plant, hence there is not much concern about them.
However, the main concern is the heating value of gas. Usually natural gas markets can be divided in three markets in terms of heating value:[116]
- Asia (Japan, Korea, Taiwan), where gas distributed is rich, with a gross calorific value (GCV) higher than 43 MJ/m3(n), i.e. 1,090 Btu/scf,
- the UK and the US, where distributed gas is lean, with a GCV usually lower than 42 MJ/m3(n), i.e. 1,065 Btu/scf,
- Continental Europe, where the acceptable GCV range is quite wide: approx. 39 to 46 MJ/m3(n), i.e. 990 to 1,160 Btu/scf.
There are some methods to modify the heating value of produced LNG to the desired level. For the purpose of increasing the heating value, injecting propane and butane is a solution. For the purpose of decreasing heating value, nitrogen injecting and extracting butane and propane are proven solutions. Blending with gas or LNG can be a solution; however all of these solutions while theoretically viable can be costly and logistically difficult to manage in large scale. Lean LNG price in terms of energy value is lower than the rich LNG price.[117]
Liquefaction technology
[edit]There are several liquefaction processes available for large, baseload LNG plants (in order of prevalence):[118]
- AP-C3MR ' designed by Air Products & Chemicals, Inc. (APCI)
- Cascade ' designed by ConocoPhillips
- AP-X ' designed by Air Products & Chemicals, Inc. (APCI)
- AP-SMR (Single Mixed Refrigerant) ' designed by Air Products & Chemicals, Inc. (APCI)
- AP-N (Nitrogen Refrigerant) ' designed by Air Products & Chemicals, Inc. (APCI)
- MFC (mixed fluid cascade) ' designed by Linde
- PRICO (SMR) ' designed by Black & Veatch
- AP-DMR (Dual Mixed Refrigerant) ' designed by Air Products & Chemicals, Inc. (APCI)
- Liquefin ' designed by Air Liquide
As of January , global nominal LNG liquefaction capacity was 301.5 MTPA (million tonnes per annum), with a further 142 MTPA under construction.[119]
The majority of these trains use either APCI AP-C3MR or Cascade technology for the liquefaction process. The other processes, used in a small minority of some liquefaction plants, include Shell's DMR (double-mixed refrigerant) technology and the Linde technology.
APCI technology is the most-used liquefaction process in LNG plants: out of 100 liquefaction trains onstream or under-construction, 86 trains with a total capacity of 243 MTPA have been designed based on the APCI process. Phillips' Cascade process is the second most-used, used in 10 trains with a total capacity of 36.16 MTPA. The Shell DMR process has been used in three trains with total capacity of 13.9 MTPA; and, finally, the Linde/Statoil process is used in the Snohvit 4.2 MTPA single train.
Floating liquefied natural gas (FLNG) facilities float above an offshore gas field, and produce, liquefy, store and transfer LNG (and potentially LPG and condensate) at sea before carriers ship it directly to markets. The first FLNG facility is now in development by Shell,[120] due for completion in .[121]
Storage
[edit]Modern LNG storage tanks are typically of the full containment type, which has a prestressed concrete outer wall and a high-nickel steel inner tank, with extremely efficient insulation between the walls. Large tanks are low aspect ratio (height to width) and cylindrical in design with a domed steel or concrete roof. Storage pressure in these tanks is very low, less than 10 kilopascals (1.5 psi). Sometimes more expensive underground tanks are used for storage. Smaller quantities (say 700 cubic metres (180,000 US gal) and less) may be stored in horizontal or vertical, vacuum-jacketed, pressure vessels. These tanks may be at pressures anywhere from less than 50 to over 1,700 kPa (7.3'246.6 psi).
LNG must be kept cold to remain a liquid, independent of pressure. Despite efficient insulation, there will inevitably be some heat leakage into the LNG, resulting in vaporisation of the LNG. This boil-off gas acts to keep the LNG cold (see "Refrigeration" below). The boil-off gas is typically compressed and exported as natural gas, or it is reliquefied and returned to storage.
Transportation
[edit] Main articles: LNG carrier and Aviation_fuel § LNGLNG is transported in specially designed ships with double hulls protecting the cargo systems from damage or leaks. There are several special leak test methods available to test the integrity of an LNG vessel's membrane cargo tanks.[122]
The tankers cost around US$200 million each.[79]
Transportation and supply is an important aspect of the gas business, since natural gas reserves are normally quite distant from consumer markets. Natural gas has far more volume than oil to transport, and most gas is transported by pipelines. There is a natural gas pipeline network in the former Soviet Union, Europe and North America. Natural gas is less dense, even at higher pressures. Natural gas will travel much faster than oil through a high-pressure pipeline, but can transmit only about a fifth of the amount of energy per day due to the lower density. Natural gas is usually liquefied to LNG at the end of the pipeline, before shipping.
Short LNG pipelines for use in moving product from LNG vessels to onshore storage are available. Longer pipelines, which allow vessels to offload LNG at a greater distance from port facilities, are under development. This requires pipe-in-pipe technology due to requirements for keeping the LNG cold.[123]
LNG is transported using tanker trucks,[124] railway tanker cars,[125] and purpose built ships known as LNG carriers. LNG is sometimes taken to cryogenic temperatures to increase the tanker capacity. The first commercial ship-to-ship transfer (STS) transfers were undertaken in February at the Flotta facility in Scapa Flow[126] with 132,000 m3 of LNG being passed between the vessels Excalibur and Excelsior. Transfers have also been carried out by Exmar Shipmanagement, the Belgian gas tanker owner in the Gulf of Mexico, which involved the transfer of LNG from a conventional LNG carrier to an LNG regasification vessel (LNGRV). Before this commercial exercise, LNG had only ever been transferred between ships on a handful of occasions as a necessity following an incident.[citation needed] The Society of International Gas Tanker and Terminal Operators (SIGTTO) is the responsible body for LNG operators around the world and seeks to disseminate knowledge regarding the safe transport of LNG at sea.[127]
Besides LNG vessels, LNG is also used in some aircraft.
Terminals
[edit]Liquefied natural gas is used to transport natural gas over long distances, often by sea. In most cases, LNG terminals are purpose-built ports used exclusively to export or import LNG.
The United Kingdom has LNG import facilities for up to 50 billion cubic meters per year.[128]
Refrigeration
[edit]The insulation, as efficient as it is, will not keep LNG cold enough by itself. Inevitably, heat leakage will warm and vapourise the LNG. Industry practice is to store LNG as a boiling cryogen. That is, the liquid is stored at its boiling point for the pressure at which it is stored (atmospheric pressure). As the vapour boils off, heat for the phase change cools the remaining liquid. Because the insulation is very efficient, only a relatively small amount of boil-off is necessary to maintain temperature. This phenomenon is also called auto-refrigeration.
Boil-off gas from land based LNG storage tanks is usually compressed and fed to natural gas pipeline networks. Some LNG carriers use boil-off gas for fuel.
Environmental concerns
[edit]Natural gas could be considered the least environmentally harmful fossil fuel because it has the lowest CO2 emissions per unit of energy and is suitable for use in high efficiency combined cycle power stations. For an equivalent amount of heat, burning natural gas produces about 30 percent less carbon dioxide than burning petroleum and about 45 per cent less than burning coal.[129] Biomethane is considered roughly CO2-neutral and avoids most of the CO2-emissions issue. If liquefied (as LBM), it serves the same functions as LNG.[130]
On a per kilometer transported basis, emissions from LNG are lower than piped natural gas, which is a particular issue in Europe, where significant amounts of gas are piped several thousand kilometers from Russia. However, emissions from natural gas transported as LNG can be higher than those of natural gas produced regionally and piped to the point of combustion, as emissions associated with transport are lower for the latter.[131]
However, on the West Coast of the United States, where up to three new LNG importation terminals were proposed before the U.S. fracking boom, environmental groups, such as Pacific Environment, Ratepayers for Affordable Clean Energy (RACE), and Rising Tide had moved to oppose them.[132] They claimed that, while natural gas power plants emit approximately half the carbon dioxide of an equivalent coal power plant, the natural gas combustion required to produce and transport LNG to the plants adds 20 to 40 percent more carbon dioxide than burning natural gas alone.[133] A peer-reviewed study evaluated the full end-to-end life cycle of LNG produced in the U.S. and consumed in Europe or Asia.[134] It concluded that global CO2 production would be reduced due to the resulting reduction in other fossil fuels burned.
Some scientists and local residents have raised concerns about the potential effect of Poland's underground LNG storage infrastructure on marine life in the Baltic Sea.[135] Similar concerns were raised in Croatia.[136]
Safety and accidents
[edit]Natural gas is a fuel and a combustible substance. To ensure safe and reliable operation, particular measures are taken in the design, construction and operation of LNG facilities. In maritime transport, the regulations for the use of LNG as a marine fuel are set out in the IGF Code.[137]
In its liquid state, LNG is not explosive and can not ignite. For LNG to burn, it must first vaporize, then mix with air in the proper proportions (the flammable range is 5 percent to 15 percent), and then be ignited. In the case of a leak, LNG vaporizes rapidly, turning into a gas (methane plus trace gases), and mixing with air. If this mixture is within the flammable range, there is risk of ignition, which would create fire and thermal radiation hazards.
Gas venting from vehicles powered by LNG may create a flammability hazard if parked indoors for longer than a week. Additionally, due to its low temperature, refueling an LNG-powered vehicle requires training to avoid the risk of frostbite.[138][139]
LNG tankers have sailed over 100 million miles without a shipboard death or even a major accident.[140]
Several on-site accidents involving or related to LNG are listed below:
- October 20, , Cleveland, Ohio, U.S. The East Ohio Natural Gas Co. experienced a failure of an LNG tank.[141] 128 people perished in the explosion and fire. The tank did not have a dike retaining wall, and it was made during World War II, when metal rationing was very strict. The steel of the tank was made with an extremely low amount of nickel, which meant the tank was brittle when exposed to the cryogenic nature of LNG. The tank ruptured, spilling LNG into the city sewer system. The LNG vaporized and turned into gas, which exploded and burned.
- February 10, , Staten Island, New York, U.S. During a cleaning operation, 42 workers were inside one of the TETCo LNG tanks, which had supposedly been completely drained ten months earlier. However, ignition occurred, causing a plume of combusting gas to rise within the tank. Two workers near the top felt the heat and rushed to the safety of scaffolding outside, while the other 40 workers died as the concrete cap on the tank rose 20'30 feet in the air and then came crashing back down, crushing them to death.[142][143]
- October 6, , Lusby, Maryland, US. A pump seal failed at the Cove Point LNG import facility, releasing natural gas vapors (not LNG), which entered an electrical conduit.[141] A worker switched off a circuit breaker, which ignited the gas vapors. The resulting explosion killed a worker, severely injured another and caused heavy damage to the building. A safety analysis was not required at the time, and none was performed during the planning, design or construction of the facility.[144] National fire codes were changed as a result of the accident.
- January 19, , Skikda, Algeria. Explosion at Sonatrach LNG liquefaction facility.[141] 27 killed, 56 injured, three LNG trains destroyed, a marine berth damaged. production was reduced by 76 percent. Total loss was US$900 million. A steam boiler that was part of an LNG liquefaction train exploded, triggering a massive hydrocarbon gas explosion. The explosion occurred where propane and ethane refrigeration storage were located. Site distribution of the units caused a domino effect of explosions.[145][146] It remains unclear if LNG or LNG vapour, or other hydrocarbon gases forming part of the liquefaction process initiated the explosions. One report, of the US Government Team Site Inspection of the Sonatrach Skikda LNG Plant in Skikda, Algeria, March 12'16, , has cited it was a leak of hydrocarbons from the refrigerant (liquefaction) process system.
Security concerns
[edit]On 8 May , the United States withdrew from the Joint Comprehensive Plan of Action with Iran, reinstating Iran sanctions against their nuclear program.[147] In response, Iran threatened to close off the Strait of Hormuz to international shipping.[148] The Strait of Hormuz is a strategic route through which a third of the world's LNG passes from Middle East producers.[149]
In January , Qatar halted tankers of liquefied natural gas through the strait of Bab-el-Mandeb after US-led airstrikes on Houthi targets in Yemen increased risks in the strait.[150] The LNG tankers were forced to sail around Africa via the Cape of Good Hope to avoid the war zone.[151]
The company is the world’s best LNG Marine Tank supplier. We are your one-stop shop for all needs. Our staff are highly-specialized and will help you find the product you need.
See also
[edit]- NATURAL GAS
[Senate Hearing 111-276]
[From the U.S. Government Publishing Office]
S. Hrg. 111-276
NATURAL GAS
=======================================================================
HEARING
before the
COMMITTEE ON
ENERGY AND NATURAL RESOURCES
UNITED STATES SENATE
ONE HUNDRED ELEVENTH CONGRESS
FIRST SESSION
TO
RECEIVE TESTIMONY ON THE ROLE OF NATURAL GAS IN MITIGATING CLIMATE
CHANGE
__________
OCTOBER 28,
Printed for the use of the
Committee on Energy and Natural Resources
U.S. GOVERNMENT PRINTING OFFICE
54-945 PDF WASHINGTON :
-----------------------------------------------------------------------
For sale by the Superintendent of Documents, U.S. Government Printing
Office Internet: bookstore.gpo.gov : toll free (866) 512-; DC
area (202) 512- Fax: (202) 512- Mail: Stop IDCC, Washington, DC
-
COMMITTEE ON ENERGY AND NATURAL RESOURCES
JEFF BINGAMAN, New Mexico, Chairman
BYRON L. DORGAN, North Dakota LISA MURKOWSKI, Alaska
RON WYDEN, Oregon RICHARD BURR, North Carolina
TIM JOHNSON, South Dakota JOHN BARRASSO, Wyoming
MARY L. LANDRIEU, Louisiana SAM BROWNBACK, Kansas
MARIA CANTWELL, Washington JAMES E. RISCH, Idaho
ROBERT MENENDEZ, New Jersey JOHN McCAIN, Arizona
BLANCHE L. LINCOLN, Arkansas ROBERT F. BENNETT, Utah
BERNARD SANDERS, Vermont JIM BUNNING, Kentucky
EVAN BAYH, Indiana JEFF SESSIONS, Alabama
DEBBIE STABENOW, Michigan BOB CORKER, Tennessee
MARK UDALL, Colorado
JEANNE SHAHEEN, New Hampshire
Robert M. Simon, Staff Director
Sam E. Fowler, Chief Counsel
McKie Campbell, Republican Staff Director
Karen K. Billups, Republican Chief Counsel
C O N T E N T S
----------
STATEMENTS
Page
Bingaman, Hon. Jeff, U.S. Senator From New Mexico................ 1
Fusco, Jack, President and Chief Executive Officer, Calpine
Corporation, Houston, TX....................................... 32
McConaghy, Dennis, Executive Vice President, Pipeline Strategy
and Development, TransCanada Pipelines, Ltd., Calgary, Canada.. 25
McKay, Lamar, Chairman and President, BP America, Inc., Houston,
TX............................................................. 10
Murkowski, Hon. Lisa, U.S. Senator From Alaska................... 2
Newell, Richard, Ph.D., Administrator, Energy Information
Administration, Department of Energy........................... 3
Stones, Edward, Director of Energy Risk, The Dow Chemical Company 20
Wilks, David, President, Energy Supply Business Unit, Xcel
Energy, Inc., Minneapolis, MN.................................. 15
APPENDIXES
Appendix I
Responses to additional questions................................ 61
Appendix II
Additional material submitted for the record..................... 117
NATURAL GAS
----------
Wednesday, October 28,
U.S. Senate,
Committee on Energy and Natural Resources,
Washington, DC.
The committee met, pursuant to notice, at 10:05 a.m. in
room SD-366, Dirksen Senate Office Building, Hon. Jeff
Bingaman, chairman, presiding.
OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. SENATOR FROM NEW
MEXICO
The Chairman. Why don't we go ahead and get started.
Today's hearing regards the significant increase in
estimates of technically recoverable natural gas resources as
reported by the Energy Information Administration and other
experts, such as the Potential Gas Committee.
The witnesses will discuss factors leading to increased
supply, the impact on future natural gas usage that is expected
as a result of that supply--increased supply. The witnesses
will also discuss how natural gas resources may be used to
mitigate climate change and also provide their perspectives on
pending climate change legislation.
Some of the key questions that I hope we can find answers
to are--let me mention five:
No. 1, what are the latest domestic reserve estimates and
the economics of delivering natural gas from those newly found
reserves?
No. 2, how will this updated supply picture impact the fuel
mix used for power generation, and how will this affect
electricity prices?
No. 3, will an expanded supply reduce the volatility and
the price spikes that have characterized the natural gas market
in the past decade?
No. 4, what are the most appropriate roles for natural gas
to play in the mitigation of climate change? Would a simple
price on carbon cause natural gas to be used in those roles or
should some other policy option be considered?
No. 5, if natural gas usage increases, how will industries
using natural gas as a feedstock respond to potential price
increases?
We have a distinguished group of witnesses.
Before I introduce the witnesses, let me call on Senator
Murkowski for any statement she has.
STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR
FROM ALASKA
Senator Murkowski. Thank you, Mr. Chairman.
Good morning to all the witnesses. I am impressed with the
very distinguished panel. I have had an opportunity to meet
with many of you before, but it's nice to have you here today.
I know that several of you are engineers by training --
petroleum and materials, chemical, and mechanical. I think that
this technical expertise will help us focus on the facts and
realities of natural gas in the context of climate policy.
I have made it very clear that any climate policy that
decreases the use of natural gas would be a step backward,
because natural gas is a natural ally of our low-carbon goals.
Previously described by some as ``too precious to burn,''
it's now clear that natural gas can play as valuable a role in
America's energy future as any other resources out there. The
Alaska gas line continues to make important progress, and shale
deposits from the Rockies, all the way to New York, are
becoming economical to produce.
While we have a greater supply of natural gas than ever
before, both the House and Senate climate bills fail to
acknowledge and embrace its potential. I'm hopeful that today
we can draw attention to these deficiencies and remedy them in
any bill that draws enough support to move forward.
I also want to address concerns that have been raised by
the coal industry. First, I guess I'd like to point out that
Alaska's has more coal than any other State, about half of the
country's total endowment. I want to make sure that coal is not
sterilized as a valuable energy resource. I think clean coal is
particularly critical to our future, not least because millions
of Americans rely on its development for their livelihoods and
the viability of their regions.
This hearing is not intended to take anything away from
coal's status as a large component of our energy supply or its
viability, going forward. I think the purpose here is to simply
examine how natural gas can serve as a complement to clean
coal, to nuclear, to renewables, in an all-of-the-above energy
policy.
Now, some would have it that certain domestic resources
simply get pushed out entirely from our energy--future energy
mix. I think that is unacceptable. For starters, the world will
use an estimated 45 percent more energy in than it does
today. EIA tells us that U.S. energy consumption won't
decrease, but rather increase by half a percent per year over
that period. Senator Inhofe and I, on Friday, released a memo
from CRS demonstrating that America has more recoverable fossil
fuel resources than any other nation.
Given the projected growth in demand and our own abundant
supplies, I think it's pretty clear that Congress does not need
to pick between energy resources. Rather, we need to pick all
of them, and proceed accordingly. It's difficult to imagine an
energy future that doesn't involve using all of our fossil
resources in as clean and efficient a manner as possible.
Climate legislation that fails to promote, or that is
designed to prevent, the most cost-effective emissions
reductions will threaten Americans with unaffordable energy
prices. We have a duty to protect our constituents against that
risk. We can start by keeping all of our options on the table.
I'm looking forward to a thoughtful discussion this morning
about how we strike that balance between getting the greatest
amount of our emissions reduced for the lowest cost to the
consumer.
With that, Mr. Chairman, I thank you for yet another very
informative hearing on these very important issues.
The Chairman. Thank you very much.
Let me introduce our witnesses. We have a very
distinguished group here. First, Richard Newell, who is the
administrator with the Energy Information Administration.
Welcome back to our committee.
Mr. Lamar McKay, who is the chairman and president of BP
America.
Thank you very much, for being here.
Mr. David Wilks, president of Energy Supply with Xcel
Energy.
Thank you, for being here.
Mr. Edward Stones, the director of Risk--Energy Risk with
Dow Chemical Company.
Thank you for being here.
Mr. Dennis McConaghy, who is senior vice president of
business development with TransCanada Pipelines, in Calgary;
and Mr. Jack Fusco, who is the president and chief executive
officer of Calpine Corporation.
Thank you all very much, for being here.
We'll take your full statements and put them in the record
as if read. If you could take 6 or 7 minutes each and give us
the main points that you think we need to understand about this
set of issues, that would be very helpful to us.
Let's start with you, Mr. Newell, and hear the perspective
of the Energy Information Administration.
STATEMENT OF RICHARD NEWELL, PH.D., ADMINISTRATOR, ENERGY
INFORMATION ADMINISTRATION, DEPARTMENT OF ENERGY
Mr. Newell. Thank you, Mr. Chairman and members of the
committee. I appreciate the opportunity to appear before you
today to discuss natural gas and its role in mitigating climate
change.
The Energy Information Administration is the statistical
and analytical agency within the Department of Energy. By law,
our data, analyses, and forecasts are independent of approval
by any other officer or employee of the U.S. Government, so our
views should not be construed as representing those of the
Department of Energy or the administration.
The main factors to be considered in addressing today's
topic are the supply of natural gas, the outlook for natural
gas demand, absent new policies, and the possible impact of new
policies on natural gas use.
In terms of domestic supply, EIA focuses on three key
measures: production, proved reserves, and estimates of
technically recoverable resources. The major and very positive
story in all three measures is the growing role of
unconventional natural gas sources, particularly gas in shale
formations. Over the past few years, total natural gas
production has significantly increased through the application
of new technologies to these unconventional natural gas
resources. As a result, in , domestic production met 90
percent of dry gas consumption in the United States, with
imports from Canada and imports of liquefied natural gas making
up the balance.
Despite higher production, proved reserves of natural gas
have also been increasing. EIA reported a 13-percent increase
in proved reserves during and will report a further 3-
percent increase when we release reserves data for later
this week. EIA and other experts have also been raising their
estimates of technically recoverable resources, and EIA expects
to incorporate a further increase in gas resources in the
edition of its Annual Energy Outlook, which will be due out at
the turn of the year.
Turning to demand, natural gas currently supplies 23
percent of total U.S. primary energy. Total natural gas use has
moved within a narrow range over the past 15 years. Use of
natural gas in residential and commercial buildings has been
fairly stable, while a significant decline in industrial use of
natural gas has been roughly offset significant growth in the
use of natural gas to generate electricity.
Looking forward, the demand for natural gas in the
electricity and industrial sectors is a key area of uncertainty
in the overall use of natural gas. The price of natural gas and
the rate of growth of the economy in general, and energy--
intensive industries in particular, are critical drivers of
industrial natural gas demand.
In the absence of changes in policy, there are two key
factors that affect the growth of natural gas use for electric
power generation. One is the rate of growth in electricity
demand, which EIA projects will average under 1 percent
annually through . The other is the growth in generation
from renewable energy sources, spurred by incentives in the
recent economic stimulus bill and State-level mandates for
increased use of renewable energy. Given these factors, EIA
expects total natural gas use to be roughly flat in our current
reference case scenario.
Developments in energy and environmental policy can also
influence the prospects for using natural gas, whether focused
on greenhouse gas mitigation or other objectives, such as
diversifying the transportation fuel mix. Actions to reduce
greenhouse gas emissions would tend to increase the
attractiveness of electricity generation using natural gas
relative to conventional coal generation. However, although
generation using natural gas produces less greenhouse gas
emissions than generation using conventional coal, it produces
more emissions than generation using renewable energy or
nuclear power, which are emissions-free.
EIA's analysis of House-passed climate legislation, the
American Clean Energy and Security Act of , considered its
impacts over the next two decades under different scenarios
regarding the cost and availability of international offsets
and low- and no-carbon electricity generation technologies. Our
results suggest that this legislation would likely result in
increased use of natural gas for generation over the next
decade, but the effect over the to period and
thereafter can be either an increase or reduction in natural
gas use relative to our reference case, depending on the
assumptions of the cases used.
Another type of policy proposal that has received recent
attention would provide tax credits or other incentives to
encourage the use of natural gas in the transportation sector
in place of petroleum-based fuels. While natural gas could be
used in many different types of vehicles, the need for the
simultaneous introduction of vehicles and fueling
infrastructure has led many analysts to view centrally-fueled
fleets as being one of the relatively more suitable market
segments for deployment of natural gas vehicles. Local air
pollution concerns and tighter emissions standards for new,
heavy-duty diesel trucks that are now taking effect also tend
to increase the relative attractiveness of natural-gas-fueled
vehicles. However, EIA's reference case projections, which do
not assume new policy-based incentives, do not show significant
market penetration of natural-gas-fueled vehicles.
Mr. Chairman and members of the committee, this concludes
my testimony. I look forward to answering any questions you
might have.
[The prepared statement of Mr. Newell follows:]
Prepared Statement of Richard Newell, Ph.D., Administrator, Energy
Information Administration, Department of Energy
Mr. Chairman, and members of the Committee, I appreciate the
opportunity to appear before you today to discuss natural gas and its
role in mitigating climate change.
The Energy Information Administration (EIA) is the statistical and
analytical agency within the Department of Energy. EIA collects,
analyzes, and disseminates independent and impartial energy information
to promote sound policymaking, efficient markets, and public
understanding regarding energy and its interaction with the economy and
the environment. EIA is the Nation's premier source of energy
information and, by law, its data, analyses, and forecasts are
independent of approval by any other officer or employee of the United
States Government. Therefore, our views should not be construed as
representing those of the Department or the Administration.
To briefly summarize, the main factors to be considered in
addressing today's topic are the supply of natural gas, the outlook for
natural gas demand absent new policies, and the possible impact of new
policies on natural gas use and greenhouse gas emissions.
In terms of domestic supply, EIA focuses on three key measures--
production, proved reserves, and estimates of technically recoverable
resources. The major, and very positive story, in all three measures is
the growing role of unconventional natural gas sources, particularly
gas in shale formations. Over the past few years, total U.S. natural
gas production has significantly increased (Figure 1)* through the
application of new technologies to these unconventional natural gas
resources. Despite higher production, proved reserves of natural gas
have also been increasing. EIA reported a 13-percent increase in proved
reserves during and will report a further increase when we release
reserves data for later this week. EIA and other experts have also
been raising their estimates of technically recoverable resources, and
EIA expects to incorporate a further increase of natural gas resources
in the edition of its Annual Energy Outlook.
---------------------------------------------------------------------------
* Figures 1-7 have been retained in committee files.
---------------------------------------------------------------------------
Turning to demand, natural gas currently supplies about 23 percent
of total U.S. primary energy. Total natural gas use has moved within a
narrow range over the past 15 years. Use of natural gas in residential
and commercial buildings has been fairly stable, while a significant
decline in industrial use of natural gas has roughly offset growth in
the use of natural gas to generate electricity. Looking forward, the
demand for natural gas in the industrial and electricity sectors is a
key area of uncertainty in the overall use of natural gas. The price of
natural gas, the rate of growth of the economy in general and energy
intensive industries in particular, and the rate of growth in
electricity demand are likely to be key drivers of natural gas demand.
Developments in energy and environmental policy can also influence
the prospects for using natural gas, whether focused on greenhouse gas
mitigation or other objectives such as diversifying our transportation
fuel mix. Action to reduce emissions of greenhouse gases, for example,
would increase the attractiveness of electricity generation using
natural gas relative to coal-fired generation. However, although
generation using natural gas produces less greenhouse emissions than
generation using coal, it produces more emissions than generation using
renewable energy or nuclear power, which are emissions-free generation
sources. EIA's analysis of the House-passed climate legislation, H.R.
, the American Clean Energy and Security Act of (ACESA),
considered its impacts over the next two decades under different
scenarios regarding the cost and availability of international offsets
and low-and no-carbon electricity generation technologies. Our results
suggest that this legislation would likely increase the use of natural
gas for generation over the next decade in all of the scenarios we
analyzed, but the longer-run effect can be either an increase or
reduction in natural gas use relative to our Reference Case.
supply of natural gas in the united states
Natural gas is both produced within the United States and imported.
In , domestic production of dry natural gas equaled about 90
percent of dry gas consumption, with imports from Canada (7 percent of
consumption) and imports of liquefied natural gas (LNG) (about 3
percent of consumption) making up the balance. Though I will discuss
both domestic production and imports, the most important recent
developments are in domestic production.
Natural gas production is often classified as either
``conventional'' or ``unconventional,'' although the definition of the
boundary between these categories varies across analysts and over time.
Traditionally, unconventional resources include historically harder-to-
produce supplies embedded in tight sands and shale and in coalbeds. Two
technological advances have made some unconventional resources easier
to produce. Horizontal drilling gives producers access to large,
relatively thin layers of rock without having to drill many traditional
vertical wells. Horizontal drilling for natural gas and oil in the
United States even outpaced traditional vertical drilling this year
(Figure 2). Hydraulic fracturing, or ``fracking,'' shatters rocks that
are not very permeable, allowing embedded natural gas to flow more
rapidly into the well bore. Hydraulic fracturing is a common procedure
in both horizontal and vertical wells in the United States.
These technological changes have led to large increases in
available reserves by expanding the types of resource rock that can be
drilled economically. Most recently, natural-gas-bearing shale that is
located across the entire United States (Figure 3) has been the focus
of attention. So far, the Barnett shale in Texas has been the most
developed, but others, such as Haynesville, may prove more productive
and the Marcellus in the Northeast is much larger.
EIA has traditionally taken a relatively optimistic view of the
unconventional natural gas resource, even at a time earlier this decade
when many other analysts were suggesting that the lack of natural gas
resources in North America would lead to a rapid and inexorable
increase in our reliance on imports of LNG. Recent shale gas
developments suggest that even our perspective was not optimistic
enough. In recent years, EIA and other experts, such as the Potential
Gas Committee (PGC), have raised their estimates of technically
recoverable resources, and EIA expects to incorporate a further
increase in the edition of its Annual Energy Outlook. Most of
these increases arise from reevaluation of shale-gas plays in the
Appalachian basin and in the Mid-Continent, Gulf Coast, and Rocky
Mountain areas. I should note, however, that appraisals of the
``technically recoverable'' natural gas resource potential of the
United States do not take into account the costs of finding and
recovery.
Later this week, EIA will release its year-end report U.S.
Crude Oil, Natural Gas, and Natural Gas Liquids Proved Reserves. Proved
natural gas reserves, a small subset of the technically recoverable
resources, are those volumes that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
In the report, we will show that proved reserves of natural gas rose
from to , not only replacing production of 20.5 trillion cubic
feet (Tcf), but also growing by almost 3 percent over (Figure 4).
The year-end increase follows an increase of 13 percent the year
before, reflecting in part stronger price conditions, which was a
record for the 32 years EIA has collected these data. For both years,
growth was largely due to continued development of unconventional
natural gas from shales.
More recently, some have raised concerns about whether shale can
continue to deliver relatively low-cost supply to domestic customers.
Concerns expressed relate to the relative newness of the large-scale
application of horizontal drilling and hydraulic fracturing
technologies to shales. Shales in different parts of the country are
not the same, and differences in techniques and technology are actively
being developed by the industry. This creates uncertainty in assessing
the overall resource base. Horizontal wells with fracturing to
stimulate the flow of natural gas in shale also tend to deliver their
greatest volumes in the first few years. This raises questions as to
the ability of the industry to continue to drill productively over the
long term, which is necessary to sustain higher, or even constant,
levels of production.
Delivery of most of a well's volume relatively quickly has
attractive financial implications as well, providing producers with a
quicker and more certain return on their investment. In the long term,
the question will be cost. At this point in the development of new
technologies, where possible, producers are likely working with the
easiest, lowest-cost resources they can identify. Continued technology
improvements will tend to reduce costs, while the exploitation of more
difficult resources over time will tend to increase them. How these
costs evolve over time is an important question, though we are seeing
some immediate effects today as, at prevailing prices, development has
slowed significantly in the Barnett shale in Texas, although production
continues to increase rapidly in the Haynesville in Louisiana and the
Marcellus in the Northeast. The direction of prices is also important
to future drilling activity, because it is the difference between price
and cost that determines the profitability of drilling activity. Both
EIA's short-and long-term projections and the futures price curve for
natural gas contracts traded on the New York Mercantile Exchange
support the view that U.S. natural gas prices will rise relative to
their level in the current economic downturn.
The other major concern about long-term development of shale gas
relates to environmental issues. Any new technology is likely to raise
environmental issues, and drilling, particularly in areas that have not
seen much in recent years, raises a set of important local
environmental issues. Drilling requires heavy truck traffic, makes
noise, and changes the landscape. Fracturing to stimulate the flow of
natural gas, though it involves mainly highly-pressurized water and
sand, also involves a relatively small amount of chemical additives.
Some of these environmental issues have been explored over the past few
years in Texas. Much of the Barnett shale lies beneath suburban, and
even urban, Fort Worth. In the case of the Marcellus, the shale lies
below areas predominantly in Pennsylvania, West Virginia, and New York
that have not seen large-scale drilling efforts in a century.
Because of the local nature of the potential environmental effects
of drilling and hydraulic fracturing, and the authority that resides
largely in the States for regulating these environmental issues,
development is likely to be highly dependent on State and local
development policies. Those policies relate not only to access, but
also to regulation of certain development activities that may be
associated with air and water pollution. Formations holding shale gas
resources have very low permeability and typically lie far below
sources of ground water. Therefore, water-related concerns have largely
centered on the amount of water used in the fracturing process and the
need to handle, recycle, and treat fracking fluids, including used
fluids that are returned to the surface as part of the process, in a
manner that addresses the risk of spills that can potentially affect
water quality. These locally-managed environmental issues make
assessing the longer-term role of shale natural gas more difficult.
Depending on overall market conditions, LNG may also continue to
serve as a source of additional natural gas supply. The United States
currently has more than 4 Tcf of annual receipt capacity for imported
LNG. The United States, given its extensive natural gas storage system,
has in effect become the marginal customer in the international LNG
trade, attracting uncommitted supplies when spot prices available in
the United States are higher than international alternatives. In this
sense, LNG can act as a safety valve in the event that spot prices rise
due to unanticipated demand growth or supply shortfalls. Under present
market conditions, where domestic supply has been robust, imports have
averaged much lower than capacity, totaling a little over 0.3 Tcf last
year and up about 20 percent year-to-date in .
demand for natural gas in the united states
Natural gas has long played an important role in meeting U.S.
energy needs, providing about 23 percent of the primary energy used in
the United States, heating more than half of U.S. homes, generating
more than one-fifth of U.S. electricity, and providing an important
fuel and feedstock for industry. About one-third of the natural gas
consumed in was used for electric power generation, one-third for
industrial purposes, and the remaining one-third in residential and
commercial buildings. Only a small portion is used in the
transportation sector, predominately at pipeline compressor stations,
although some is used for vehicles.
The EIA projects and analyzes U.S. energy supply, demand, and
prices through using the National Energy Modeling System and
presenting results in our Annual Energy Outlook. Earlier this year, EIA
updated its Annual Energy Outlook (AEO) Reference Case to
include estimates of the implementation of the American Recovery and
Reinvestment Act (ARRA), which includes significant programs to promote
both energy efficiency and smart-grid technologies. The updated
Reference Case shows a continuing slow growth in natural gas use in
residential and commercial buildings, averaging less than one-third of
a percent annually through . Our estimates reflect both the
increase in the amount of residential and commercial space that uses
natural gas as a primary fuel for space and water heating, which tends
to increase natural gas use, and projected increases in the efficiency
of natural-gas-using equipment and better performance of buildings
subject to tougher codes and standards, which tend to reduce natural
gas use.
Projections of industrial natural gas demand are highly sensitive
to the price of natural gas as well as the level and composition of
economic activity. As noted previously, natural gas use by industry has
declined over the past 15 years. In our Reference Case projections,
industrial-sector natural gas consumption is projected to rebound
slightly after the recession, and then level off as energy-intensive
industries continue to grow at a much lower rate than the overall
economy.
The electric power sector has been the growth market for natural
gas over the last decade. In , notwithstanding a projected 4.6-
percent decline in overall electricity demand, generation with natural
gas is actually expected to grow by 4.1 percent, reflecting a situation
where generation using efficient natural-gas-fired units is less costly
than generation from some coal units in parts of the country.
Looking forward, however, given the projected rise in natural gas
prices relative to coal prices, displacement of existing coal-fired
generation does not persist in our Reference Case, where there is no
implicit or explicit value placed on carbon dioxide emissions emitted
from the combustion of coal in existing plants. In this setting, the
growth in electricity demand and the competition of natural gas with
other electricity sources to serve that growth will determine the
amount of natural gas used for generation.
While the recent decline in demand for electricity is largely
attributable to the current economic downturn, slowing growth in the
demand for electricity has been a long-term trend for more than 50
years. After averaging nearly 10 percent per year in the s, the
annual growth in the demand for electricity slowed to just over 7
percent in the s, less than 5 percent in s, less than 3 percent
in the s, less than 2.5 percent in s, and just over 1 percent
in the first 7 years of the 21st century (Figure 5). The slowing growth
in electricity demand is projected to continue over next two decades,
averaging only 0.9 percent per year in our updated recent projections
through .
With this outlook for electricity demand growth, natural gas
generation in our Reference Case is projected to fall over the next few
years. This occurs because growing renewable generation, stimulated in
part by the extension of production tax credits and the provision of
grants and loans in the recent American Recovery and Reinvestment Act,
together with increased coal generation from new plants already under
construction, crowd out the increased use of natural gas that might
have otherwise occurred. Over the longer term, however, natural gas
generation is projected to grow because few new coal plants beyond
those currently under construction are projected to be added and the
production tax credit for eligible renewable sources currently sunsets
in or , depending on the technology.
Of course there are uncertainties. Chief among these is whether new
electricity-intensive technologies might enter the market to reverse
this trend. The one most discussed today is plug-in hybrid electric
vehicles. While we do see plug-in hybrids entering the market over the
next two decades, we do not expect their penetration to be large enough
by to reverse the slowing electricity demand growth trend. A
simple calculation illustrates the point. One million plug-in hybrid
electric vehicles with an all-electric range of 40 miles (PHEV-40)
taking a 14-kilowatthour charge 365 days a year would add about 5
terawatthours of electricity load on an annual basis. This would
represent slightly more than one-tenth of 1 percent of projected U.S.
electricity demand in . Tens of millions of PHEV-40s could, of
course, make a significant difference to electricity demand, but EIA's
Reference Case does not envision PHEV penetration on this scale over
the next two decades given that the technology has yet to be introduced
commercially, and there are significant challenges in reducing the cost
and improving the performance of batteries to make this technology
competitive in the marketplace without continuing subsidies.
the effect of greenhouse gas mitigation policies on natural gas use
Just two weeks ago, I had the opportunity to appear before you to
discuss the recent EIA analysis of the energy and economic impacts of
ACESA. EIA's analysis of ACESA focuses on those provisions that can be
readily analyzed using our National Energy Modeling System, including
the cap-and-trade program for greenhouse gases and its provisions for
the allocation of allowances, Federal building code updates for both
residential and commercial buildings, and Federal efficiency standards
for lighting and other appliances.
As I noted at the earlier hearing, EIA's analysis shows that the
estimated impacts of ACESA on energy prices, energy use, and the
economy are highly sensitive to assumptions about the availability and
cost of international offsets as well as no- and low-carbon
technologies for power generation. The six main analysis cases
considered in EIA's report reflect a variety of different assumptions
regarding these factors.
EIA's analysis suggests that the vast majority of reductions in
energy-related emissions are expected to occur in the electric power
sector. Across the ACESA main cases, the electricity sector accounts
for between 80 percent and 88 percent of the total reduction in energy-
related carbon dioxide (CO2) emissions relative to the
Reference Case in , even though electricity comprises only 41
percent of such emissions. Emission reductions in the electricity
sector come primarily from reducing conventional coal-fired generation,
which in provided 50 percent of total U.S. generation. A portion
of the electricity-related CO2 emissions reductions results
from reduced electricity demand stimulated both by consumer responses
to higher electricity prices and by incentives in ACESA to stimulate
greater energy efficiency.
There are several reasons for the concentration of emissions
reductions in the electric power sector. First, more than 90 percent of
coal, the fuel with the highest carbon content, is used in the
electricity sector. Second, while coal-fired generation is a major
source of current and projected Reference Case emissions, there are
several alternative generation sources already demonstrated (e.g.,
natural gas, renewables, and nuclear), and others are being developed
(e.g., fossil with carbon capture and storage (CCS)). Third, changes in
electricity generation fuels do not require fundamental changes in
distribution infrastructure or electricity-using equipment.
What does this mean for natural gas use in electricity generation?
In addition to the Reference Case, Figure 6 also shows natural gas
generation from several cases we prepared in our analysis of ACESA. As
shown, the impact on the level of natural gas generation depends on
assumptions about the cost and availability of international offsets
and low-emitting electricity generating technologies like nuclear,
fossil with CCS, and biomass.
In the Basic Case where international offsets are assumed to be
available and the cost assumptions for low-emitting electricity
generating technologies are the same as those in the Reference Case,
natural gas generation rises above the Reference Case through about
, but then falls below it as new renewable and nuclear plants are
brought on line. In the High Cost Case, where new nuclear and CCS
plants are assumed to cost 50 percent more than in the Reference Case,
natural gas generation rises above the Reference Case throughout the
projections. Finally, in the No International/Limited Case where the
availability of international offsets and low-emitting electricity
generating technologies is very limited through , natural gas
generation is well above the Reference Case level throughout most of
the projections, exceeding the Reference Case level by 68 percent.
One question of interest is why companies don't switch from using
existing coal plants to increased use of existing natural gas plants to
reduce their greenhouse gas emissions. The reason is that the dispatch
decision is quite sensitive to the price of natural gas, and it
generally takes a fairly significant greenhouse gas allowance price to
make this switching attractive at projected natural gas prices. Figure
7 provides an illustrative example of this trade-off with three
difference assumptions about natural gas prices. As shown, if delivered
natural gas prices were approximately $5 per million Btu it would make
sense to dispatch a natural-gas-fired combined-cycle plant before a
coal plant when the greenhouse gas allowance price reached a little
over $30 per metric ton of CO2. However, this crossover
point rises to around $60 per ton of CO2 with $7 natural gas
prices and around $100 per ton of CO2 with $10 natural gas
prices. In the Reference Case of our analysis of H.R. , natural gas
prices to electricity generators are just over $7 per million Btu in
and just over $8.30 per million Btu in . If natural gas prices
turn out to be significantly lower than we project, there could be
considerably greater use of gas than indicated in these scenarios.
conclusion
Given strong technologically-driven U.S. supply development,
natural gas is likely to play an important role in domestic energy use
for the foreseeable future, regardless of policy. Clearly, adequacy of
resources and local environmental implications will be important
considerations, but if those concerns prove manageable, it should be
possible for domestic natural gas production to increase well beyond
its current level, which already reflects significant growth over the
last several years. While growth in the domestic use of natural gas may
be constrained by increases in efficiency and relatively slow growth in
electricity demand, its environmental advantages relative to some other
energy options suggest that it could be considered for a policy-driven
role as well.
Mr. Chairman and members of the Committee, this concludes my
testimony. I would be happy to answer any questions you may have.
The Chairman. Thank you very much.
Mr. McKay.
STATEMENT OF LAMAR MCKAY, CHAIRMAN AND PRESIDENT, BP AMERICA,
INC., HOUSTON, TX
Mr. McKay. Chairman Bingaman, Ranking Member Murkowski,
members of the committee, my name is Lamar McKay, and I am
chairman and president of BP America.
I represent the more than 29,000 Americans who work for BP,
the leading producer of oil and natural gas in the United
States and the largest investor in U.S. energy development.
BP is committed to working with the Congress and with a
broad cross-section of energy producers, energy consumers, and
others stakeholders to address the challenges of climate change
in the context of increasing U.S. energy demand.
We appreciate the opportunity to share our views on energy
and climate policy, as well the chance to discuss the major
role natural gas can play in speeding emissions reductions in
the power sector, delivering the greatest reductions at the
lowest cost, using technology that is available today.
BP advocates an all-of-the-above approach, as Senator
Murkowski mentioned. We believe this approach is the best to
tackle climate change, enhance U.S. energy security, and meet
the Nation's growing need for energy. We support policies that
encourage conservation, energy efficiency, and greater
production of domestic energy, including alternatives, fossil
fuels, and nuclear.
Our views on climate policy flow from the fact that a ton
of carbon is a ton of carbon, whether that comes out of a
tailpipe or a smokestack, and the belief that every ton should
be treated fairly and equally. A climate policy that results in
disparate treatment of energy producers and consumers will
result in massive misallocation of capital and insulated
consumption. That will impede, and make more costly, the carbon
reductions that we are all working to achieve.
Now, we support a national climate policy that creates a
level playing field for all forms of energy that produce carbon
emissions. In pending legislation, the playing field is not
level. In spite of its economic and environmental benefits, gas
is being squeezed out of the power sector by mandates for
increased use of alternatives and protection of high-carbon
coal generation. We have long supported transitional incentives
for alternatives. If we can't achieve a level playing field
within the power sector, then we would support transitional
incentives to kick-start the phased retirement of the Nation's
least efficient and most carbon intense coal-fired plants.
Now, we very strongly believe that coal is an absolutely
essential part--essential part--of the Nation's energy future.
We are working on technology to reduce carbon emissions from
stationary sources which could be ready for commercial use by
. Now, because of their--some of these coal plants'
locations and the likelihood of more stringent air quality
standards, many of the very least efficient, most carbon
intense coal plants may not be candidates for carbon capture
and storage. Our analysis shows that the phased replacement of
about 80 of these bottom-tier plants would deliver 10 percent
of the cumulative to emission reduction targets now
being considered by the Congress.
Now, we're not advocating an overnight change. Instead, we
see a steady, smooth transition involving the retirement of
perhaps eight to ten coal plants per year. Over the next
decade, this could create annual incremental gas consumption of
about one Tcf--one trillion cubic feet. We believe the domestic
gas industry can very easily meet that demand. In fact, thanks
to a gas supply picture that has been utterly transformed by
using technology to unlock vast reserves of shale gas, domestic
production increased, here in the U.S., 1.5 trillion cubic feet
just last year. Estimates vary, but the U.S. probably has
between 50 and 100 years worth of recoverable natural gas.
Now, some have expressed concern about the volatility of
natural gas prices. Going forward, we believe natural gas
prices will be less volatile, thanks to a greatly expanded
resource base, ranging from shales to Alaska gas, better
connectivity via significant new pipelines, increased U.S.
storage volumes, and the capacity of U.S. LNG receiving
terminals.
Now, in closing, I want to emphasize again that BP stands
ready to work with this committee and others to reduce the
carbon we put into the atmosphere, meet the Nation's growing
need for energy, and do it at an affordable price for American
families.
Natural gas is clean, abundant, affordable, and American.
We encourage policymakers to provide a level playing field in
which all sources of carbon are treated fairly. If you do, we
believe natural gas will deliver the greatest emissions
reductions at the lowest possible cost using technology
available today.
So, I thank you, and I look forward to your questions.
[The prepared statement of Mr. McKay follows:]
Prepared Statement of Lamar Mckay, Chairman and President, BP America,
Inc., Houston, TX
Chairman Bingaman, Ranking Member Murkowski, members of the
committee, my name is Lamar McKay, and I am the Chairman and President
of BP America.
I appreciate the opportunity to appear before this panel to present
BP's views on the role natural gas can play in mitigating climate
change.
BP has long been a proponent of comprehensive energy policies that
promote energy security at an affordable cost through the development
of both traditional and non-traditional sources of energy, as well as
conservation and efficiency. We have also been a long-time advocate of
taking a precautionary approach to CO2 emissions, and are
committed to reducing the environmental impacts of both energy
production and consumption.
Throughout the 20th century, an abundant supply of low-cost energy
was the driving force behind America's prosperity and development. EIA
projects that US energy demand will grow by 11 percent from to
. Satisfying such demand in a sustainable way is one of our
nation's most significant challenges.
Accomplishing these objectives in the 21st century will require a
more diverse energy mix--increased efficiency, nuclear power, renewable
energy, cleaner coal, oil, and natural gas.
This will require the right combination of policies and market-
based systems to incentivize the transformation of energy use. Getting
there will require all energy participants--consumers, governments,
energy companies and other stakeholders--to work together to build a
sustainable energy future.
If we do that, the result will create new jobs, enhance our
nation's energy security, and mitigate the impacts of climate change.
At BP, we believe that natural gas, which is in abundant supply, is
key to making the vision of a lower-carbon energy future a reality.
As a member of US Climate Action Partnership (CAP), we helped draft
a blueprint for climate change legislation that recommended, among
other things, how cap and trade could work--with equitable treatment
between all sources of carbon as a basis.
Current legislative proposals do not create a level playing field
and, as a result, natural gas is in danger of being squeezed. In spite
of its economic, energy security and environmental benefits, gas is
caught between support for emerging low carbon technologies on the one
hand, and relief for coal generation on the other.
If all sources of carbon are not treated equitably, massive
misallocation of capital and insulated consumption will occur. Our
bottom-line is a ton of carbon is a ton of carbon--whether it comes out
of a tailpipe or a smokestack, it should be treated the same.
bp america
BP has a long history in the US energy market. I represent the
29,000 US employees of BP America. We are not only the largest oil and
gas producer in the United States, but also the company that invests in
the most diverse energy portfolio in the industry. In the last five
years, we have invested approximately $35 billion in the US to increase
existing energy sources, extend energy supplies and develop new, low-
carbon technologies.
Oil & Gas
Offshore and onshore, BP is one of the largest producers of oil and
gas in the United States. From the Alaskan North Slope to the deep
waters of the Gulf of Mexico, we are a leader in providing America's
traditional energy needs. Our recent discovery of the Tiber oil field
in the Gulf is only the latest in a long list of BP investments in
America's energy security.
Wind
We are major investors in wind generation and have amassed a land
portfolio capable of potentially supporting 20,000 megawatts (MW) of
wind generation, one of the largest positions in the country. As of
year-end , we had 1,000 MW of wind generation on-line and expect to
have an installed capacity of 2,000 MW of wind power by the end of
.
Biofuels
We are one of the largest blenders and marketers of biofuels in the
nation. BP has committed more than $1.5 billion to biofuels research,
development and production in response to increasing energy demand and
the need to reduce overall greenhouse gas emissions from transport
fuels. Our cutting-edge research looks to use dedicated energy crops
that will contain more energy and have less impact on the environment
than past generations of biofuels. They will also be more compatible
with existing engines and transport infrastructure, making them less
costly to deploy at scale.
Carbon Management/Carbon Capture and Storage (CCS)
BP is involved in three major CCS projects: active operations in
Algeria; a potential hydrogen energy project in California, and a
planned project in Abu Dhabi.
Solar
BP's solar business has been in operation for over 30 years and
last year had sales of 162 MW globally. This represents an increase of
29% over and further growth is expected.
By investing heavily in the most diverse portfolio of energy
sources in the industry, BP is helping meet America's energy needs
while ensuring a more sustainable and secure energy future.
transition to a lower-carbon economy
The transition to a lower-carbon economy will take substantial
time, investment and technology--spanning decades. While we look to the
future, we can make choices today based on what we know.
In reviewing current climate legislative proposals, we have found
aspects we endorse--such as transitional support for renewables. There
are other areas, however, that cause us concern.
First is the way in which mature energy sources (coal, oil, natural
gas) are treated. Because the utility sector is insulated, the
transportation/refining sectors foot the vast majority of near-and
medium-term costs for the entire energy economy. This results in an
under-allocation of allowances to the refining sector, which puts
further pressure on an industry already facing significant challenges.
Our second concern is the lack of a level playing field within the
utility sector for natural gas--especially over the next decade or so.
To some extent, this may be an oversight, as America's growth in
domestic natural gas reserves is a relatively new story. However, we
have not seen any analysis of legislative proposals which forecast
natural gas growth to .
Indeed, our own forecasts indicate the potential for lower demand,
as natural gas is squeezed over the next decade between growing
renewable mandates and coal. Our analysis indicates legislative
insulation for even the oldest and least efficient coal-fired power
plants.
Having said that, we are pleased that the Senate climate proposal
creates a ``place holder'' to discuss natural gas. We welcome the
opportunity to elaborate on the role natural gas can play in mitigating
climate change.
the potential of natural gas
Natural gas has played a supporting role in America's energy story.
However, we believe it is time for its role to change.
If the necessary technology is applied, within a stable fiscal and
regulatory framework, natural gas can help fundamentally transform
America's energy outlook and emissions profile in the decades going
forward.
Its advantages are many:
Natural gas is far and away the cleanest burning fossil fuel
in the energy portfolio. It generates less than 50 percent of
the CO2 as coal per kilowatt hour and emits
significantly less sulfur dioxide, nitrogen oxide, and
particulate matter. Unlike coal, natural gas does not emit
mercury and generates no waste ash.
It is also the most versatile fuel, because it can be
employed in the transportation sector, for home heating as well
as the electricity/industrial sectors.
Natural gas infrastructure is already in place--with gas
pipelines already criss-crossing the country with more being
built. There is also significant underutilized gas-fired power
generating capacity.
Natural gas generators are also more easily switched on and
off, providing a synergistic compliment to intermittent sources
such as solar and wind.
Finally, natural gas-fired plants can be more easily
expanded and permitted than other sources.
Policies promoting the use of natural gas in power generation hold
the potential to create new American jobs throughout the natural gas
value chain (exploration, production, pipelines and gas plants). We
believe such policies can also help to address concerns around natural
gas supply and volatility.
supply
Over the last few years, a revolution has taken place in America's
natural gas fields. Deposits of shale gas once thought out of reach are
now accessible, thanks to new uses of proven technologies, such as
hydraulic fracturing and horizontal drilling.
These technologies have enabled production in three of BP's key
fields in Texas to more than double between and . Successes
such as these have led to major new discoveries, not only in
traditional oil and gas states, but also in such non-traditional ones
as Pennsylvania, Ohio and New York.
As a result, the US natural gas picture has been transformed. US
gas production increased last year by 1.5 tcf--the largest increase in
the world and the largest in US history. And we can do more of this, if
the right policy framework is put in place to encourage and enable the
use of natural gas.
Estimates vary, but the US probably now has between 50 and 100
years worth of recoverable natural gas which is accessible with
technology available today.
price volatility
Natural gas prices are driven by a combination of short-term and
structural factors. Short-term events, such as cold weather and
hurricanes, will always impact energy markets, and financial tools
exist to help consumers and producers alike manage such risks. Earlier
in this decade, structural factors included availability of domestic
supply and limited LNG import availability.
That picture has changed dramatically. In addition to the increased
domestic supplies of natural gas referenced above, there has also been
significant expansion of LNG import capacity in recent years. These two
factors, we believe, can help contain structural pressures on natural
gas prices in the future. Also, stronger base-load demand will
encourage development of a stronger, more flexible supply base.
Given this positive new supply picture, the question then becomes:
What should we do with it?
options for lowering us carbon emissions
The US has already taken some significant steps toward lowering
carbon emissions. In the arena of transportation, which generated about
2 billion tons of carbon dioxide in , according to the EIA, the
federal government has mandated more fuel efficient vehicles and
increasing use of biofuels.
According to the EPA, electricity generation is the largest single
source of CO2 emissions, accounting for 41 percent of all
such emissions. Therefore, this is an area where we should dedicate
some real focus.
The numbers are well known. Coal provides around half of America's
electricity, but contributes over 80 percent of the CO2
produced via electricity generation.
Virtually all projections show coal playing an indispensable role
in the US energy picture for decades to come--and we agree. Coal, as
well as natural gas plants, can be fitted with carbon capture and
storage (CCS) technology. This involves capturing CO2 and
reverse-engineering and building a gas injection field so that we can
put CO2 back into the ground.
CCS faces challenges of implementation at scale, substantial costs
and specific locational issues. It will take time, perhaps a decade or
more, for the technology to mature.
Nuclear power is carbon-free and should be part of the solution.
However, it is also capital intensive and has long lead times.
Wind and solar are the sources most often mentioned as alternatives
to existing fuels, and BP is an industry leader in both. Wind can be
economically competitive with more conventional sources, which is one
reason it is growing so rapidly--but it still requires subsidies in
today's environment. Solar is higher cost than wind and requires a
greater government subsidy, though costs are coming down.
Both sources, however, face challenges and have limitations of
intermittence and affordability. The development of smart-grid
technology might alleviate some of these challenges, but we're not
there yet.
So where does this lead us?
the role of natural gas in mitigating climate change
We support greater efforts toward energy efficiency and
transitional incentives to encourage the rapid growth of alternatives.
We also think it is important to establish an economy-wide carbon
price, with all hydrocarbon sources treated the same. In that
framework, increased reserves of natural gas mean we can rely on it
more fully to support demand growth in electric power generation.
As we have indicated, current legislative proposals distort that
framework in favor of coal. Either those distortions should be removed,
or alternatively, incremental transitional incentives are needed to
accelerate the retirement of the leastefficient coal-fired generating
capacity.
For example, our analysis indicates that if the least efficient
coal-fired plants are provided with transitional incentives to retire,
the power sector could deliver a significant amount of near-to-medium
term emission reductions at low costs. Approximately 80 plants (30 GW
of generating capacity) fall into the ``least efficient'' category,
having an average efficiency of 27.1 percent versus 32.7 percent for
the average plant. In reality, this means that the least efficient
plants must burn 20 percent more coal to achieve the same amount of
output.
Most of these facilities are not located in areas where CCS is an
apparent option and are not suitable to be retrofitted with CCS. This
is because of their vintage and emission profiles, factors which will
also require significant investment to reduce NOX,
SOX and particulate matter in order to meet new clean air
requirements.
The retirement of these 80 facilities over the next decade (8-10
plants per year) could deliver 10 percent (700 million tons) of the
Waxman-Markey, Boxer-Kerry targets of 7 billion tons of cumulative
reductions from -. If replaced by gas alone, demand would
increase by about 1 TCF per year of natural gas by , or roughly
five percent of the current US market. Given the transformed gas market
conditions, we believe that such an increase in demand can easily be
met by existing reserves--recall that US natural gas production grew
last year by more than this amount.
We are not suggesting that gas be mandated as a replacement for the
retired capacity. It could also be replaced by cleaner, more efficient
energy sources. However, with a level playing field for carbon, we
believe the market will choose gas, because it offers the lowest-cost
option to replace retired coal capacity.
BP believes these important actions will result in a significant
down payment on carbon emission reductions, with minimal costs to
generators and consumers while CCS and alternative energy technologies
mature.
conclusion
In summary, BP is committed to providing the United States with the
energy it needs to grow in coming decades, and doing so in a
responsible and sustainable manner.
We support policies which:
encourage energy efficiency;
provide transitional support to renewable technologies; and
apply a consistent, economy-wide carbon price to all
hydrocarbons.
Failing that we support policies which promote early retirement of
the least efficient sources of electric power generation as a means of
achieving and sustaining significant CO2 emission
reductions. We believe legislation should aim to deliver the greatest
carbon reductions at the lowest cost, with technology that is available
today.
Expanded use of domestic natural gas can help not only the
environment, but also the economy by providing sufficient supplies to
meet agricultural and industrial demand.
BP is eager to join with policy makers, members of the energy
sector, and other stakeholders in order to develop responsible policies
that reduce carbon emissions and promote the use of clean, domestic
sources of energy. Such efforts must not exclude or sideline any
stakeholder.
America is at a critical juncture. If we begin to move now, we can
enable a cleaner energy future for the nation. I don't believe we can
afford to wait.
And with that, I would be happy to take your questions.
The Chairman. Thank you very much.
Mr. Wilks. Go right ahead.
STATEMENT OF DAVID WILKS, PRESIDENT, ENERGY SUPPLY BUSINESS
UNIT, XCEL ENERGY, INC., MINNEAPOLIS, MN
Mr. Wilks. Thank you, Chairman Bingaman and members of the
committee.
My name is David Wilks, and I am president of the Energy
Supply Business Unit of Xcel Energy. I am pleased to be here
today to discuss the potential role of natural gas in reducing
emissions of greenhouse gases by the utility industry.
Xcel energy is an investor-owned electricity and natural
gas company headquartered in Minneapolis, Minnesota. We are one
of the Nation's largest combined electric and gas companies. We
serve approximately 3.3 million electric customers and 1.8
million gas customers. We serve Minneapolis-St. Paul, Denver,
Amarillo, and other communities in southeast New Mexico,
Minnesota, Wisconsin, Michigan, North and South Dakota,
Colorado, and Texas.
In my capacity as president of Energy Supply, I'm
responsible for the construction, operation, and maintenance of
Xcel Energy's power plants, as well as our company's
environment, energy, trading, fuel, and markets functions.
There's more detail in attachment A on Xcel Energy.
Xcel Energy has adopted environmental leadership as a
cornerstone of its corporate strategy. As a result of our
environmental leadership strategy, our company is utilizing a
growing diverse portfolio of clean technologies in its
operations. In particular, the American Wind Energy Association
has ranked Xcel Energy as the number-one wind utility provider
in the Nation. Similarly, the Solar Electric Power Association
ranked us No. 5 amongst U.S. utilities for the amount of solar
power we have in our system. Xcel Energy is America's leading
renewable energy utility, and by we expect our increase of
our renewable energy resources to be 25 percent of our energy
mix.
As a result of this commitment to environmental leadership,
our company is one of the first utilities in the Nation with a
voluntary plan to reduce greenhouse gases and have reduced our
actual carbon emissions by 8 percent since . Our emission
reduction strategy relies on the clean energy initiatives that
I discussed with you above, and the company is also reducing
its emissions by retiring coal-fired plants and replacing them
with natural-gas-fired generation.
We recently completed a voluntary project in Minnesota
called the Metro Emissions Reduction Project, or MERP. This is
a $1 billion effort, which includes the conversion of two of
our older pulverized coal generating units to natural gas. Now,
through this project we reduced our SO2 and
NOX emissions by over 95 percent, and we've also
reduced and accomplished a carbon dioxide reduction of 40
percent. Now, details regarding the MERP are included in
Appendix B to my testimony. We're following a similar strategy
in Colorado.
Although we believe that, in a carbon-constrained future,
utilities must rely on a variety of resources, including coal,
nuclear, and renewable energy, our experience with the MERP
demonstrates that natural gas conversion is an excellent method
of reducing emissions. As a rough rule, natural gas combined-
cycle plants emit about one half has much carbon dioxide as
coal-fired electricity. Natural gas generation is a proven
technology, has a lower capital cost, and is far easier to
permit that some of the other technology options, such as
nuclear energy; unlike renewable energy, a dispatchable and
controllable resource that's easily integrated into a utility
system.
The historic problem with natural gas, of course, has been
the volatility of the price, and the industry's increasing
reliance on natural gas for generation of electricity could
increase customers' exposure to volatile natural gas prices.
For this reason, we join in welcoming the recent technological
developments in the production of new natural gas in the United
States. The development of gas from shale formations has the
potential to provide a long-term stable supply for the
generation of electricity. These new technologies will enable
utilities to make significant short-term emission reductions
while awaiting the development of innovative clean energy
technologies necessary to make significant long-term reductions
in greenhouse gases, and--such as required by the bill of
Kerry-Boxer, Energy Jobs and American Power Act.
To take full advantage of the opportunity created by these
large new natural gas supplies, industry and government
together should consider the following issues:
First, abundant natural gas bodes well for renewable energy
integration.
Second, it's important to continue policies that promote
the development of new clean technologies, regardless of what
happens to natural gas prices. The Nation should continue to
invest in R&D for the next generation of nuclear, clean coal,
energy efficiency, and renewables, and should continue to
promote incentives designed to assure robust markets for these
technologies.
In this regard, Xcel Energy is an advocate of the Renewable
Energy Tax Credit, a tax credit that would encourage utilities
to integrate intermittent renewable energy on their systems.
Such a tax credit would reduce the cost of renewable energy and
promote its wise use, and happens to be--and basically improve
the natural gas prices.
Third, Xcel Energy supports the creation of other
incentives under the Climate Clean Energy Program to promote
the retirement or replacement of aging coal plants with natural
gas. For example, we support the creation of a bonus allowance
pool to provide support for utilities retiring existing coal
plants and replacing them with natural gas. A similar incentive
might make sense under national renewable energy standard or a
clean energy portfolio standard. In any such incentive,
however, it is important that Congress recognize the efforts of
utilities, like Xcel Energy, that have already reduced their
emissions.
Finally, while we're optimistic, we have to remember that
there are other options that have to be created for us. We have
to have all of the--all the choices available, and not just
one. At Xcel Energy, we're excited by the new supply
opportunities created by the natural gas market. With a
balanced use of natural gas and other clean energy sources, we
believe we can continue our progress toward a clean energy
future.
Thanks again for the opportunity to speak with you today.
[The prepared statement of Mr. Wilks follows:]
Prepared Statement of David Wilks, President, Energy Supply Business
Unit, Xcel Energy, Inc., Minneapolis, MN
Chairman Bingaman, Members of the Committee, my name is David
Wilks, and I am President of the Energy Supply business unit at Xcel
Energy Inc. I am pleased to be here today to discuss the potential role
of natural gas in reducing emissions of greenhouse gases from the
utility industry.
Xcel Energy is an investor-owned electricity and natural gas
company headquartered in Minneapolis, Minnesota. We are one of the
nation's largest combined electricity and gas companies. We serve
approximately 3.3 million electric customers and 1.8 million gas
customers. We serve the Twin Cities of Minneapolis-St. Paul, Denver,
Amarillo and numerous other communities in Southeast New Mexico,
Minnesota, Wisconsin, Michigan, North and South Dakota, Colorado, and
Texas. In my capacity as President of Energy Supply, I am responsible
for the construction, operation and maintenance of Xcel Energy's power
plants, as well as our company's environmental, energy trading, fuel
and markets functions. More detail regarding Xcel Energy is found in
Attachment A* to my testimony.
---------------------------------------------------------------------------
* Document has been retained in committee files.
---------------------------------------------------------------------------
Xcel Energy's Environmental Leadership Strategy. Xcel Energy has
adopted environmental leadership as the cornerstone of our corporate
strategy. We are building a clean energy future for our customers and
the communities we serve by investing in advanced technology,
innovating our business and engaging our customers in energy
efficiency.
As a result of our environmental leadership strategy, our company
is utilizing a growing, diverse portfolio of clean energy technologies
in its operations. Xcel Energy is America's leading renewable energy
utility. By we will increase our use of renewable energy resources
to 25 percent of our energy mix. We rely on a broad range of
renewables:
For the past five years, the American Wind Energy
Association has ranked Xcel Energy as the number one utility
wind energy provider in the nation. At the end of the year, we
will have about 3,235 megawatts of wind energy on our system,
and, by , we plan to have 7,000 megawatts.
The Solar Electric Power Association ranks us No. 5 among
U.S. utilities for the amount of solar power on our system. In
Colorado, we already purchase over eight megawatts of utility
scale solar power and are close to completing a process that
will add almost 300 megawatts of additional solar power to our
system by . We also have helped our customers install
nearly 35 megawatts of on-site solar energy with incentives
provided through our Solar*Rewards program.
We are developing new biomass projects and recently proposed
converting an aging coal plant in Wisconsin to one of the
largest biomass plants in the Midwest.
Xcel Energy is also a leader in energy efficiency. Xcel Energy runs
some of the largest demand-side management and energy efficiency
programs in the nation. Since our customers have saved more than
enough electricity to enable us to avoid building more than eleven 250-
MW power plants. Our goal is to double these savings by .
In addition, we are investing in a variety of innovative, clean
technology programs, including developing the nation's first
SmartGridCityTM in Boulder, Colorado. Also, for many years,
we have partnered with the National Renewable Energy Lab (``NREL'') to
research, demonstrate and deploy various clean energy technologies,
including plug-in-hybrid electric vehicles and cutting-edge renewable
energy storage. Last week, as a founding member, we helped break ground
on the Solar Technology Acceleration Center in Aurora, Colorado.
SolarTAC is a world-class facility for the solar industry and research
institutions designed to test and demonstrate advanced technologies for
the emerging solar market.
Natural Gas and Greenhouse Gas Emission Reductions. As a result of
this commitment to environmental leadership, our company is one of the
first utilities in the nation with a voluntary plan to reduce
greenhouse gases. We have already reduced our carbon dioxide emissions
by about 8 percent since . Our emission reduction strategy relies
on the clean energy initiatives I discussed earlier, but the company
has also reduced its emissions by retiring coal-fired plants and
replacing them with natural gas fired generation.
We recently completed a voluntary project in Minnesota called the
Metro Emissions Reduction Project, or ``MERP.'' This one billion dollar
effort included the conversion of two of our older pulverized coal
generating plants to natural-gas combined cycle technology. Through
this project, we reduced our SO2 and NOx emissions from these
facilities by over 95%, and we have also accomplished carbon dioxide
emissions reductions of roughly 40%. Details regarding the MERP are
included as Appendix B to my testimony. In Colorado, Xcel Energy is
pursuing a similar strategy: In the next three years, we will retire
some of our older, less efficient coal plants, and a significant
portion of their energy will be replaced by efficient natural gas-fired
electricity.
Although we believe that, in a carbon constrained future, utilities
must rely on a variety of resources, including coal, nuclear and
renewable energy, our experience with the MERP demonstrates that
natural gas conversion is an excellent method of reducing emissions. As
a rough rule, natural gas combined cycle plants emit about half as much
carbon dioxide as coal-fired electricity. Natural gas generation is
proven technology; unlike carbon capture and sequestration or other
clean technologies that will become important in the future, utilities
can rely on natural gas without reservation today. It has lower capital
cost and is far easier to permit than some of the other technological
options, such as nuclear energy. And, unlike renewable energy, it is a
dispatchable, controllable resource easily integrated into a utility
system.
The historic problem with natural gas, of course, has been the
volatility of the price of natural gas fuel. And, the industry's
increasing reliance on natural gas for generation of electricity could
increase customers' exposure to volatile natural gas prices.
For this reason, we join in welcoming recent technological
developments in the production of new natural gas resources in the
United States. The development of gas from shale formations has the
potential to provide a long-term, stable supply of natural gas for the
generation of electricity. These new technologies will enable utilities
to make significant short-term emission reductions while awaiting the
development of the innovative clean energy technologies necessary to
make the significant long term greenhouse gas reductions that would be
required by bills like the Kerry-Boxer Clean Energy Jobs and American
Power Act.
Considerations for the New Natural Gas Market. In other words,
natural gas can serve as a bridge fuel as we await the development of
the next generation of technology. To take full advantage of the
opportunity created by these large new natural gas supplies, industry
and government together should keep consider the following issues:
First, natural gas found in shale formations must be
transported from the well to power plants for use as fuel. In
other words, the nation will need the right combination of gas
pipelines (to serve gas-fired power plants) and electric
transmission lines (to transmit the electricity generated to
the customer).
Second, abundant natural gas bodes well for renewable energy
integration. Renewable energy resources can vary quite a bit
during a given hour, day or season. Unlike coal and nuclear
plants, utilities can start and stop gas plants quickly when a
wind or solar plant suddenly drops off line or starts back up
as wind or sun conditions change. However, the use of gas for
renewable energy integration comes at a cost--a cost closely
related to the price of natural gas. In particular, utilities
often have additional gas fired units kept below normal loading
levels to provide back up capability should renewable energy
production decline in a particular hour. If the price of
natural gas is lower because of the new production technology,
the cost of renewable energy integration will be
correspondingly lower as well.
Third, although low-priced natural gas assists in renewable
energy integration, ironically it also competes with renewable
energy and other clean energy technologies. Essentially,
because the nation has a limited supply of clean energy
dollars, utilities, customers and policy-makers are more likely
to direct those dollars to natural gas-fired generation if
natural gas is projected to be cheaper and more abundant in the
future. For this reason, it is important to continue policies
that promote the development of new, clean technologies
regardless of what happens to natural gas prices. The nation
should continue to invest in research and development of the
next generation of nuclear, clean coal, energy efficiency and
renewables. It should also continue to promote incentives
designed to assure robust markets for these technologies. In
this regard, Xcel Energy is an advocate of a ``renewable
integration tax credit,'' a tax credit that would encourage
utilities to integrate intermittent renewable energy (wind and
solar) on their systems. Such a tax credit would reduce the
cost of renewable energy and promote its use regardless of what
happens to natural gas prices.
Fourth, Xcel Energy supports the creation of other
incentives under a climate or clean energy program to promote
the retirement and replacement of aging coal plants with
natural gas. Such incentives could help reduce emissions in the
short term, especially emissions from marginal facilities that
would otherwise continue to operate. For example, we support
the creation of a bonus allowance pool to provide support to
utilities retiring existing coal plants and replacing them with
natural gas. A similar incentive might make sense under a
national renewable energy or clean energy portfolio standard.
In any such incentive, however, it is important that the
Congress recognize the efforts of utilities like Xcel Energy
that have already employed natural gas to reduce their
emissions. Xcel Energy and its customers should not be
penalized for their foresight in undertaking projects like our
Metro Emissions Reduction Project or our early adoption of
wind, solar and biomass generation in advance of any climate
mandate.
Finally, while we are optimistic that new gas production
technologies may indeed prove to be ``game changers,'' it is
important to keep in mind that gas remains a historically
volatile commodity. The increased use of natural gas for
electric generation could by itself lead to higher natural gas
prices than anticipated. We should not put all of our eggs in
one basket, even one as promising as natural gas. A continued
reliance on a diverse portfolio of resources remains the
nation's best electricity and energy policy.
At Xcel Energy, we are excited by the new supply opportunities
created in the natural gas market. With a balanced use of natural gas
and other clean energy resources, we believe we can continue our
progress toward a clean energy future.
Thanks again for the opportunity to testify today. I look forward
to your questions.
The Chairman. Thank you very much.
Mr. Stones, go right ahead.
STATEMENT OF EDWARD STONES, DIRECTOR OF ENERGY RISK, THE DOW
CHEMICAL COMPANY
Mr. Stones. Thank you, Chairman Bingaman and members of the
committee. My name is Edward Stones. I'm the director of energy
risk for Dow Chemical.
I follow natural gas so closely that my blood pressure goes
up and down with the price.
[Laughter.]
Mr. Stones. So, Dow uses the energy equivalent of more than
million cubic feet of natural gas every day in our global
operations. Of this total, about half is in the United States.
To put this in a dollars-and-cents perspective, in we
spent $27 billion on energy, and that's up from , when we
spent 8 billion.
The energy Dow uses is primarily naphtha, natural gas and
natural gas liquids, Both as an energy source for our
operations and as a feedstock to make products essential to our
economy and our citizens' quality of life. These products serve
as building blocks for everything from pharmaceuticals to
building insulation, electronic materials, fertilizers, and
much more. In fact, the U.S. chemical industry takes every
dollar of energy we buy and turns it into $8 of high-value
products.
We understand the importance of natural gas as a clean
fuel, and that it has a role in climate mitigation; however,
climate policies that legislate an increase in natural gas
demand can negatively impact certain sectors of our economy as
prices rise. For example, from to , U.S. industrial
gas demand fell 22 percent as average annual prices rose 160
percent. The economic term for this is ``demand destruction.''
But, in human terms, it's ``job destruction.''
Over the last 12 years, there have been five significant
natural gas spikes. During this time, these spikes have
contributed to the loss of nearly 4 million manufacturing jobs,
135,000 chemical industry jobs, the permanent loss of nearly
half of the U.S. fertilizer production capacity, and a $1-
billion trade surplus in the chemical industry in , turning
into a deficit over to .
We hope the predictions about increased natural gas supply
are right. But, we think it's too early to declare natural gas
a silver bullet or a bridge fuel solution.
Driving natural gas preferentially into power generation
could further erode our manufacturing economy and increase the
volatility of natural gas, especially for those that remain,
including residential energy users.
If the predictions of increased supply of natural gas turn
out to be true, it would be a greater value to our economy as a
fuel to spur increased manufacturing investment. More
industrial users of natural gas will also help dampen
volatility, as we'll have more price-conscious consumers, not
fewer.
Let me be clear. Dow supports prompt congressional action
on climate and energy bills that achieve environmental results
while maintaining the competitiveness of American
manufacturing. Congress should adopt policies that ensure the
diversity of our energy sources while, at the same time,
reducing demand through robust efficiency efforts. A price on
carbon, in our opinion, will be a sufficient market incentive
for natural gas to aid in the transition to a low-carbon
economy over a reasonable period of time.
In summary, Congress is debating legislation that would
make dramatic changes to the Nation's energy markets. We urge
you to act now and to make policy choices that increase and do
not limit our energy options. We must be careful to avoid a
dash to natural gas. Congress created such a dash in the
Clean Air Act amendments. It then followed with restrictions on
access that disconnected the supply from demand. We cannot
afford to replay that scenario.
Some call natural gas a ``bridge fuel.'' But, if the wrong
policy causes a ``dash to gas,'' it's going to be ``a bridge
too far.''
Thank you, for your time today, and I'd be happy to answer
any questions you may have.
[The prepared statement of Mr. Stones follows:]
Prepared Statement of Edward Stones, Director of Energy Risk, The Dow
Chemical Company
introduction
The Dow Chemical Company appreciates the opportunity to submit
these written comments to the Committee on Energy and Natural
Resources.
Dow was founded in Michigan in and is one of the world's
leading manufacturers of chemicals and plastics. We supply more than
3,300 products to customers in approximately 160 countries, connecting
chemistry and innovation with the principles of sustainability to help
provide everything from fresh water, food, and pharmaceuticals to
insulation, paints, packaging, and personal care products. About 21,000
of Dow's 46,000 employees are in the US, and Dow helps provide health
benefits to more than 34,000 retirees in the US.
Dow is committed to sustainability. We have improved our
performance on greenhouse gas (GHG) emissions, and we are committed to
do even better in the future. Our ambitious sustainability goals
underscore this commitment.
Dow is an energy-intensive company. Dow uses energy, primarily
naphtha, natural gas and natural gas liquids, as feedstock materials to
make a wide array of products essential to our economy and quality of
life. We also use energy to drive the chemical reactions necessary to
turn our feedstocks into useful products, many of which lead to net
energy savings.
This testimony describes the current US energy situation and
recommends specific policies to ensure a sustainable energy policy for
the United States. Particular attention is focused on natural gas
prices, which have and continue to affect the US manufacturing sector.
Dow believes that natural gas will play a critical role in US
policy to control greenhouse gases. Because US manufacturing jobs are
dependent on the US natural gas market, policies that impact natural
gas will have a direct impact on jobs in the US manufacturing sector.
We recommend that Congress consider policies that utilize natural gas
in ways that preserve the competitiveness of US manufacturers.
natural gas in energy and climate policy
Natural gas is a relatively ``clean'' (in terms of GHG emissions
per unit of energy) fossil fuel. Current estimates of the domestic
supply of natural gas are greater than those of just a few years ago.
Therefore, increased use of natural gas could help the United States
reduce GHG emissions and reduce its reliance on foreign sources of
energy. Climate change and energy security are two of the biggest
challenges facing the United States, so policies that affect natural
gas markets impact our collective well being.
natural gas policy is critical to us manufacturers
Major sectors that use natural gas include the power, industrial,
residential, commercial, and transportation sectors. Those sectors in
which demand is most sensitive to natural gas prices are termed price
elastic. The more elastic the demand, the more quickly a sector will
change its demand for natural gas after a change in price. Inelastic
demand occurs when a change in price results in little change in
demand. Of the sectors previously identified, the industrial sector has
the most elastic demand for natural gas. From to , US
industrial gas demand fell 22% as average annual prices rose 167%. Over
the same time, demand for power rose 64% (EIA data). Clearly, a change
in natural gas price will impact industrial sector demand before that
in other sectors.
Both price volatility and the ``average'' price over time have an
impact on the industrial sector and should be addressed by a
comprehensive energy policy.
price volatility in the us natural gas market
Since , there have been five natural gas price spikes, each
caused by lags between price signals and production response. The lag
between changes in drilling and changes in production has been
remarkably consistent, at about six months. This is the time required
to fund drilling programs, site wells, schedule crews, drill and tie
new wells into the grid. When the gas market is over supplied,
producers respond by reducing drilling, leading to a reduction in
supply.
In , as in , and , drilling has declined
dramatically as price has fallen. After each trough, natural gas demand
and price rise once the economy turns, signaling the production
community to increase drilling. During the lag between the pricing
signals and new production, only one mechanism exists to rebalance
supply and demand: demand destruction brought about by price spikes.
Demand destruction is an antiseptic economic term for job destruction.
These price spikes have significantly contributed to the US
manufacturing sector losing over 3.7 million jobs, the chemical
industry losing nearly 120,000 jobs, and the permanent loss of nearly
half of US fertilizer production capacity. The manufacturing sector,
which has limited fuel switching ability, has become the shock absorber
for high natural gas costs.
Although increased supply from shale gas appears to have changed
the production profile, we have seen similar scenarios occur after past
spikes. In , significant new imports from Canada came on line; in
-, there were new supplies from the Gulf of Mexico and in ,
new discoveries in the Rockies were brought into play. In each case,
the initial hopes were too high and production increases were not as
large as initially expected. Some claim that the lag expected for shale
gas will be shorter due to the reduced drilling scope of shale type
wells. However the latest available data show natural gas production
peaked with the same delay from the start of drilling reductions as in
other cycles. The inherent lags between changes in drilling and
production created natural gas spikes over the last ten years, and will
continue to do so after this and every trough.
The next table shows the EIA-estimated levelized cost for new power
plants by fuel type in . This table shows that the levelized cost
of a new power plant is equal across the four fuel types. However, the
variable component of cost for natural gas fired generation is much
greater than for other fuel choices. This means that electricity
consumers served by natural gas will experience the biggest price
shocks. Along with manufacturers who rely on natural gas, consumers of
electricity generated by natural gas are among those who will be most
negatively affected by price spikes in the natural gas market.
We believe that the increased supply of natural gas from shale
plays will be an important resource for the United States over the next
decades. However, as has been demonstrated in previous cycles, this new
production will not end the cyclicality of natural gas markets. Placing
a price on GHG emissions will also not overcome the most important
factors affecting volatility of natural gas prices (e.g., weather).
When it comes to natural gas and climate policy, Congress should
consider policies that minimize the demand destruction that occurs in
natural gas price spikes. This means supporting price elastic consumers
of natural gas and avoiding the disproportionate addition of inelastic
demand.
average price level in the us natural gas market
It is not just price spikes in natural gas that hurt US
manufacturers. It is also the average level of natural gas prices. Much
of the US chemical industry was built when natural gas prices were
below $2/MMBtu. Since , this historic price level has been
exceeded, maybe forever. We do not expect US natural gas prices to
return consistently to this low level in the future.
Because manufacturers that depend on competitive natural gas prices
must make capital investment decisions that span decades, the US faces
stiff competition from abroad. In fact, in our testimony before
this Committee, Dow stated that of the 120 world scale petrochemical
plants proposed to be built, only one was planned for the US.
Should the US enact a price on GHG emissions, the net impact on
supply and demand balances must be considered in cases of both average
and extreme demand. The country's energy supply must be resilient
enough to overcome natural phenomena such as hurricanes, harsh winters,
and arid summers. It must continue to support economic growth, allowing
for high-value job creation in the industrial sector. Without this
resiliency, natural gas price volatility will increase, affecting both
employment in the industrial sector and all electricity users.
EIA modeling of the House-passed energy and climate bill indicate
how to avoid a ``dash to gas'' in the power sector under a cap and
trade program. If new power plants using nuclear, renewable, and coal
with associated carbon capture and sequestration (CCS) are not
developed and deployed in a timeframe consistent with emission
reduction requirements, covered entities will respond by increasing
their use of offsets, if available, and by turning to increased use of
natural gas in lieu of coal-fired generation. Therefore, it is critical
to advance all low carbon emitting energy sources and ensure the
availability of offsets under any cap and trade program.
relationship between the price of carbon and fuel switching
A price on GHG emissions will increase demand for natural gas
relative to other fuels that emit more GHGs per unit of energy. Demand
is also influenced by the relative price of natural gas compared to
other fuels in the absence of a price on GHG emissions. Both these
factors--the relative price differential and the price of GHG
emissions--work together to influence fuel switching. For example, if
the price of natural gas is only slightly higher than the price of
coal, then fuel switching from coal to natural gas will occur at a
relatively low price on carbon. Conversely, if the price of natural gas
is much higher than the price of coal, then it would take a higher
price on carbon to impact fuel switching from coal to natural gas.
In practice, major investment decisions--such as in power
generation--can impact fuel choices for decades. Therefore, investors
project the relative price of natural gas and coal and the expected
carbon price over the entire time period of the investment. Due to the
much higher capital cost of coal-fired power generation plants, greater
uncertainty in price outcomes for power or green house gas emissions
raises the cost of capital for new power projects, and favors natural
gas generation. A well-considered, comprehensive, and timely energy
policy will both lower the cost of power for American consumers and
reduce the impact of implementing policies to address GHG's.
For policy makers, the lesson to be learned is straightforward: The
higher the expected carbon price, the greater the degree of fuel
switching from coal to natural gas in the power sector. Therefore, cost
containment is key to minimizing fuel switching under any climate
policy that places a price on carbon. Under a cap and trade system,
cost containment depends on the reduction schedule over time and on the
availability of offsets (and international offsets in particular).
recommended policies
When it comes to natural gas and climate policy, Dow favors
policies that will avoid the demand destruction that occurs in natural
gas price spikes, along with policies that will allow the US to use all
of its low-carbon resources. Such policies will maintain industrial
competitiveness.
Dow also believes that the US needs a sustainable energy policy.
Climate change is an important component of a sustainable energy
policy, but it is not the only part. We have developed a list of
specific recommendations that, if implemented, would form the basis of
a sustainable energy policy.
First, aggressively promote the cleanest, most reliable, and most
affordable ``fuel''--energy efficiency. Energy efficiency is the
consensus solution to advance energy security, reduce GHGs, and keep
energy prices low. It is often underappreciated for its value. Of
particular importance is improving the energy efficiency of buildings.
Buildings are responsible for 38% of CO2 emissions, 40% of
energy use, and 70% of electricity use. A combination of federal
incentives and local energy efficiency building codes is needed.
Second, increase and diversify domestic energy supplies, including
natural gas. Nuclear energy and clean coal with carbon capture and
sequestration (CCS) should be part of the solution, as should solar,
wind, biomass, and other renewable energy sources. We believe a price
on carbon will advantage natural gas, and further incentives would only
dangerously increase inelastic demand. Therefore, Congress should not
provide free allowances or other incentive payments for the purpose of
promoting fuel switching from coal to natural gas in the power sector.
An estimated 86 billion barrels of oil and 420 trillion cubic feet
of natural gas are not being tapped. History suggests that the more we
explore, the more we know, and the more our estimates of resources
grow. EIA has said that ``the estimate of ultimate recovery increases
over time for most reservoirs, the vast majority of fields, all
regions, all countries, and the world.'' And we have the technology
that allows us to produce both oil and natural gas in an entirely safe
and environmentally sound manner. Any new fossil energy resources must
be used as efficiently as possible.
One way to maximize the transformational value of increased oil and
gas production is to share the royalty revenue with coastal states and
use the federal share to help fund research, development and deployment
in such areas as energy efficiency and renewable energy. Production of
oil and gas on federal lands has brought billions of dollars of revenue
into state and federal treasuries. Expanding access could put billions
of additional dollars into state and federal budgets.
Third, act boldly on technology policy through long-term tax
credits, and increased investment in R&D and deployment. These are
costly but necessary to provide the certainty that the business
community needs to spur investment. We didn't respond to Sputnik with
half-measures. We can't afford to respond to our energy challenges with
halfmeasures, either.
Fourth, employ market mechanisms to address climate change in the
most cost-effective way. There is a need for direct action now to slow,
stop, and then reverse the growth of greenhouse gas levels in the
atmosphere. We concur with the principles and recommendations of the US
Climate Action Partnership (USCAP), of which Dow is a proud member. And
we recognize that concerted action is needed by the rest of the world
to adequately address this global problem. Particular attention must be
paid to cost containment and the availability of offsets (and
international offsets). Also, climate policy should not penalize the
use of fossil energy as a feedstock material to make products that are
not intended to be used as a fuel.
To minimize the downsides of natural gas price volatility, Congress
should adopt policies to increase the number of elastic users of
natural gas, and consider policies to increase US supply of natural
gas. A resilient natural gas market would empower US manufacturers to
create high value jobs as they did from -, during which period
US industrial gas use grew at an average rate of 2.7%/yr. In the event
weather increases natural gas demand, price sensitive exports would be
temporarily reduced, rebalancing the natural gas market with less
disruption.
Under this scenario, price spikes won't be as severe, and won't
cause as much harm when they occur, which is ultimately good for both
industry and all consumers. Under this scenario we can envision a
circumstance in which the chemical industry is once again able to
preferentially invest in the US.
conclusion
Natural gas will play a critical role in US climate policy. US
manufacturing jobs are closely linked to natural gas price and price
volatility. The policy choices Congress will make on natural gas are
therefore critical to US manufacturers. Without industrial gas users,
any disruption in supply or demand must be met by dramatic price
changes.
Energy efficiency should become a national priority. Congress
should enact legislation to create a sustainable energy supply based on
all sources of domestic energy, including nuclear energy. Technology
policy should create powerful incentives for clean energy technologies,
such as CCS. A price on carbon, coupled with appropriate cost
containment measures, would be a large and sufficient incentive to
promote US natural gas demand, which is already growing even in the
absence of a price on carbon.
There is no one silver bullet solution to our energy and climate
problems. All Americans paid a high price for over-reliance on natural
gas in the last ten years. Our country cannot afford to repeat that
mistake. This time we must fashion a comprehensive energy policy which
addresses supply and demand realities, and environmental, security and
economic goals to ensure energy costs in the US remain globally
competitive and avoid economically devastating volatility.
The Chairman. Thank you very much.
Mr. McConaghy.
STATEMENT OF DENNIS MCCONAGHY, EXECUTIVE VICE PRESIDENT,
PIPELINE STRATEGY AND DEVELOPMENT, TRANSCANADA PIPELINES, LTD.,
CALGARY, CANADA
Mr. McConaghy. Thank you, Senator Bingaman. I welcome the
opportunity this morning to discuss TransCanada's perspective
on the opportunity of natural gas in climate change
legislation. It's good to see Senator Murkowski again, and the
other members of the committee.
Just to put into context what TransCanada is, in terms of
the energy infrastructure of the United States, we have more
than 36,000 miles of pipelines that deliver 20 percent of the
natural gas consumed daily in North America. We also own
approximately 370 billion cubic feet of natural gas storage,
enough to meet the needs of nearly 4 million homes each year.
We operate almost 11,000 megawatts of nuclear, coal, hydro, and
wind generation in Canada and the United States, enough
capacity to power 11 million homes.
TransCanada is also a leader in the development of the
Alaska and Mackenzie gas projects, both designed to connect
Arctic reserves of natural gas into the North American Market.
TransCanada's message today can be distilled into three
basic points:
No.1, North America is blessed with an enormous long-term
supply of natural gas. The ability to produce natural gas
supplies efficiently and economically from shale formations has
become a game-changer in terms of how we think about natural
gas availability, supply, and how it can integrate into not
only energy security, also in terms of how consumers can rely
on that supply, but also, and perhaps just as importantly,
climate change legislation.
No. 2, natural gas pipeline industry has constructed, and
will continue to construct, the necessary infrastructure to
deliver these supplies and that goes directly to one of the
concerns related to volatility.
No. 3, greater use of North America's abundant natural gas
resource can make a substantial contribution to tangibly
reducing greenhouse gas emissions in the short and medium term.
Let me elaborate very briefly on these three points:
Robust supply. Contrary to the view of a few years ago, no
one now sees natural gas as a declining resource. DOE and EIA
estimates would suggest that we have enough natural gas to last
for the next 100 years. Shale formations in the Lower 48 alone
are estimated to hold over 650 Tcf of technically recoverable
gas. On the North Slope of Alaska, there are 35 Tcf of proven
reserves and another 200 Tcf of estimated recoverable reserves.
Not only will these supplies--these reserves supply U.S. demand
for years to come, but they will also dampen gas price
volatility and lead to an overall general lower level of prices
than would otherwise have pertained.
In respect to infrastructure, in the natural gas
pipeline industry completed 84 projects, which added nearly 45
Bcf of capacity to the pipeline grid. That--this industry has
demonstrated that we have the capability, in terms of financial
capability, engineering know-how, to deliver this gas as
customers and producers require them.
Presently, TransCanada and its partner, ExxonMobil, are
leading the development of the Alaska gas pipeline project,
which is probably the biggest single delivery opportunity that
is available in the United States. I'm pleased to note to the
committee that we are on schedule to conduct an open season for
that capacity next year and that will be a significant
milestone in advancing that project.
Last, the contribution to mitigating climate change. As has
been noted by others on this panel already, natural gas emits
the lowest of amount of carbon dioxide per unit of generated
electricity of any fossil fuel. We have the ability to
substantially increase the amount of electricity generated from
natural gas. As an example, the current annual average capacity
utilization factor of the installed fleet of natural gas
combined-cycled generation units is 42 percent. If we could
increase that utilization factor to up to 55, we would achieve
a reduction in greenhouse gas emissions of approximately 135
million metric tons and to put this into perspective, the
first-year reduction of greenhouse gas emissions, required
under Waxman-Markey, is 143; so, 135 out of 143. An increase in
the utilization factor of this magnitude will require an
additional 5 Bcf per day of natural gas, an increase well
within the capability of the continental supply available to
us.
Greater use of natural gas offers the U.S. a readily
available economic means of achieving early and genuine
greenhouse gas emissions. I would only point out that, under
the current versions of climate change legislation--and this
has been modeled by the EIA--that the current architecture of
some of that legislation, as currently proposed, may actually
constrain the U.S.'s ability to take full advantage of this
natural gas opportunity and that's one, I think, important
challenge that we can all make a contribution to finding the
best means of increasing natural gas utilization, not just for
energy security and the interests of consumers, but also to
advance climate change. TransCanada is eager to participate in
that process, going ahead.
Thank you very much.
[The prepared statement of Mr. McConaghy follows:]
Prepared Statement of Dennis McConaghy, Executive Vice President,
Pipeline Strategy and Development, TransCanada Pipelines, Ltd.,
Calgary, Canada
Chairman Bingaman, Ranking Member Murkowski and members of the
Committee, thank you for the opportunity to testify today.
introduction
I am pleased to be here on behalf of TransCanada Corporation to
present our views on the role of natural gas in mitigating climate
change. Accompanying me today is Dr. Bill Langford, Vice President,
Pipeline Strategy, TransCanada Pipelines, Limited. Bill is
TransCanada's in-house expert on natural gas supply and demand.
With approximately $40 billion in assets, TransCanada, through its
subsidiaries, is a leader in the responsible development and reliable
operation of North American energy infrastructure including natural gas
and oil pipelines, power generation and natural gas storage facilities.
TransCanada delivers 20% of the natural gas consumed each day in
North America. Our 36,661 mile wholly-owned natural gas pipeline
network taps into virtually every major natural gas supply basin on the
continent. Our vast pipeline network is well positioned to connect new
sources of supply such as shale gas, coalbed methane and offshore
liquefied natural gas as well as supply from the north.
TransCanada also is a leading participant in the Alaska Pipeline
Project and the Mackenzie Gas Project, both designed to connect Arctic
reserves of natural gas to the North American market.
TransCanada is also one of the continent's largest providers of
natural gas storage and related services with approximately 370 billion
cubic feet of capacity--enough to meet the needs of nearly four million
homes each year.
TransCanada is also one of Canada's largest independent power
producers. TransCanada owns, controls or is developing more than 10,900
megawatts of power generating capacity in Canada and the United
States--enough capacity to power 11 million homes. Our diversified
power portfolio includes natural gas, nuclear, coal, hydro and wind
generation primarily located in Alberta, Ontario, Quebec and the
northeastern United States.
This year, TransCanada is serving as the chair of the Interstate
Natural Gas Association of America (INGAA), which represents interstate
and interprovincial natural gas pipeline companies in North America.
However, this testimony is being presented only on behalf of
TransCanada and does not necessarily represent the views of INGAA or
any of its other member companies.
role of natural gas in mitigating climate change
TransCanada believes that increased natural gas utilization can
make a significant contribution to meeting the energy security and
climate change objectives of the U.S., for the following reasons:
Natural gas is a largely domestic resource.
Natural gas is abundant.
Natural gas is the cleanest burning hydrocarbon.
Natural gas has substantial infrastructure in place today to
move and use the supplies.
Natural gas can immediately increase its share of baseload
power to deliver real emission reductions.
Natural gas from international sources can be accessed, if
necessary, through the nation's well-developed liquid natural
gas (LNG) facilities.
TransCanada believes that effective U.S. climate policy should
recognize the significant potential of natural gas in meeting
greenhouse gas (GHG) emission reduction objectives in both the short
and long term.
In the short term, meaningful GHG emission reductions can be
achieved by more fully utilizing already installed natural gas electric
generation capacity. Because of abundant and readily available supplies
of natural gas, these emission reductions can be achieved without a
substantial impact on natural gas prices. In the longer term,
TransCanada believes that North America's abundant natural gas resource
endowment can be one of the foundations upon which United States
climate change policy is built.
supply outlook
Current Department of Energy (DOE) and Energy Information
Administration (EIA) estimates, based in large part on improved
drilling technologies, show that the U.S. has enough natural gas to
last for the next 100 years .
In , the U.S. and Canada together consumed 26.8 trillion cubic
feet (Tcf) of natural gas, with the U.S. consuming 23.2 Tcf and Canada
consuming 3.5 Tcf. Almost all of this gas was domestically produced.
LNG imports accounted for 1% of total U.S. and Canadian supplies in
.
On the supply side, a recently released INGAA Foundation Report
predicted that U.S. natural gas production will increase by 25% (more
than 5 Tcf) in compared to levels. The EIA AEO Reference case
also shows a significant growth in U.S. gas production from -,
albeit somewhat less than the INGAA Foundation's analysis.
While conventional natural gas production is expected to decline,
unconventional\1\ and frontier\2\ natural gas will increase
significantly. It is important to note that the term ``unconventional''
refers to the source of this gas, not its chemical makeup.
Unconventional natural gas has the same combustion characteristics as
gas from other sources, and is fully interchangeable with gas from
other sources. INGAA's analysis forecasts that unconventional and
frontier natural gas supplies will grow from 8 Tcf in to between
16.1 and 22.4 Tcf in . According to the EIA, natural gas production
from unconventional resources in the U.S. will increase 35%, or 3.2
Tcf, between -.
---------------------------------------------------------------------------
\1\ Unconventional natural gas is produced from geologic formations
that may require well stimulation or other technologies to produce. For
more information, see the report ICF International prepared for the
INGAA Foundation in entitled Availability, Economics, and
Production Potential of North American Unconventional Natural Gas
Supplies.
\2\ Frontier supplies include Arctic natural gas production and
production from remote or new offshore areas, such as the deeper waters
of the Gulf of Mexico and the offshore moratorium areas off of the East
and West Coasts and the coasts of Florida.
---------------------------------------------------------------------------
This major increase in North American natural gas supplies marks a
paradigm change for natural gas. Only a few years ago, many industry
observers expected a long-term decline in domestic natural gas supply.
This fundamental change in outlook has resulted from remarkable success
in developing new exploration techniques, particularly extraction of
gas from U.S. shale deposits.
According to the ``Modern Shale Gas Primer'' issued by the DOE in
April , the lower 48 states have a wide distribution of highly
organic shales containing vast resources of natural gas. These shales
include over 300 Tcf of technically recoverable resources, including
some of the following major formations:
The Barnett Shale is located in the Fort Worth Basin of
north-central Texas. With over 10,000 wells drilled to date,
the Barnett Shale is the most prominent shale gas play in the
U.S. Technically Recoverable Resources = 44 Tcf.
The Fayetteville Shale is situated in the Arkoma Basin of
northern Arkansas and eastern Oklahoma. With over 1,000 wells
in production to date, the Fayetteville Shale is currently on
its way to becoming one of the most active plays in the U.S.
Technically Recoverable Resources = 41.6 Tcf.
The Haynesville Shale (also known as the Haynesville/
Bossier) is situated in the North Louisiana Salt Basin in
northern Louisiana and eastern Texas. In , after several
years of drilling and testing, the Haynesville Shale made
headlines as a potentially significant gas reserve, although
the full extent of the play will only be known after several
more years of development are completed. Technically
Recoverable Resources = 251 Tcf.
The Marcellus Shale is the most expansive shale gas play,
spanning six states in the northeastern U.S. (NY, OH, PA, WV,
KY, and VA). Technically Recoverable Resources = 262 Tcf.
The Woodford Shale is located in south-central Oklahoma.
Technically Recoverable Resources = 11.4 Tcf.
The Antrim Shale is located in the upper portion of the
lower peninsula of Michigan within the Michigan Basin. Aside
from the Barnett, the Antrim Shale has been one of the most
actively developed shale gas plays with its major expansion
taking place in the late s. Technically Recoverable
Resources = 20 Tcf.
The New Albany Shale is located in the Illinois Basin in
portions of southeastern Illinois, southwestern Indiana, and
northwestern Kentucky. Technically Recoverable Resources = 19.2
Tcf.
Northeast British Columbia shales, although early in their
development, exhibit potential reserves comparable to the
larger U.S. shale plays.
The robust development of shale plays in the United States has been
due to the improvement in, and successful application of, several
technologies that allow the economic production of natural gas from
shale formations.
The successful application of these improved technologies has
opened up the possibility of accessing an extremely large natural gas
resource. Furthermore, inevitable continued improvement in technology
will, in all likelihood, result in a larger and larger proportion of
existing gas resources--the `gas in place'--being economically
produced. This will allow for continued growth in North American
natural gas production even farther into the future.
In addition to the five key shales in the U.S., shales have also
been identified and drilled in Canada--the Horn River and Montney plays
in Western Canada and the Utica in Quebec. These shales, particularly
the Horn River and Montney plays, have the potential to further support
U.S. demand growth.
Although Lower-48 and Canadian shale production will exhibit robust
growth over the next decade, there will still be a requirement for
substantial volumes of other, non-shale natural gas. Tight gas, coal-
bed methane and conventional gas will remain prominent in the supply
mix in the years to come. This will be true even with only modest
demand growth. More rapid demand growth, perhaps due to the efforts
aimed at reducing GHG emissions, suggest even larger amounts of non-
shale gas will be in the supply mix.
Furthermore, the presence of plentiful and ready opportunities for
natural gas development suggests that gas price volatility will be
dampened, with any price spikes being smaller and of shorter duration.
With respect to natural gas prices, the cost of shale gas will not
`set' the price of natural gas in North America. But the added supplies
will mean that gas is more plentiful and lower cost than it would have
been without it.
pipeline infrastructure
Today, there are over 300,000 miles of large-diameter, high
pressure pipelines in the United States that have the capacity to
deliver in excess of 70 Bcf per day. These pipelines constitute the
interstate highway system of our nation's natural gas infrastructure.
To accommodate the increases in natural gas supply described above, a
continued expansion of the natural gas pipeline infrastructure is
needed. To date, the North American natural gas pipeline industry
successfully has met this challenge. The 84 projects completed in
--the greatest amount of pipeline construction activity in more
than 10 years--added 44.6 Bcf per day of capacity to the pipeline grid.
Those additions cost an estimated $11.4 billion. By comparison,
pipeline expansion in was $4.3 billion for 50 projects that added
14.9 Bcf per day of capacity to the network
This expansion has (1) allowed market access for incremental gas
supplies, notably from the Rockies and shale gas production areas; (2)
moderated regional price differentials and contributed to reducing
natural gas price volatility; and (3) provided greater supply access to
domestic natural gas users, notably the power generation sector.
Infrastructure for Alaska Natural Gas
TransCanada is continuing to invest in infrastructure that will
accommodate growing domestic natural gas supplies. One prominent
example is the Alaska Natural Gas Pipeline. Current proven natural gas
reserves on the North Slope of Alaska are 35 trillion cubic feet. The
US Geologic Survey has estimated yet to be proven reserves in excess of
200 Tcf. As currently contemplated, when the Alaska gas pipeline comes
into service it will add 4.5 Bcf of natural gas per day to the supply
available to consumers. This capacity can be easily expanded to over 6
Bcf per day. No other single source of natural gas has the ability to
increase daily supply by this magnitude.
For more than 30 years, TransCanada has actively sought to bring
the enormous proven and unproven reserves of natural gas from the North
Slope of Alaska to consumers in the lower-48 states, and is leading the
effort today. In December TransCanada Alaska Company, LLC, a
subsidiary of TransCanada Corporation, was awarded a license by the
State of Alaska pursuant to the Alaska Gasline Inducement Act (AGIA).
Under its AGIA license, TransCanada will conduct open seasons for
capacity on the pipeline and prepare and file an application for a
certificate of public convenience and necessity (CPCN) from the Federal
Energy Regulatory Commission (FERC). Consistent with the requirements
of AGIA, TransCanada began the field, engineering, design, commercial
and regulatory work necessary to conduct an initial open season in
. In June, TransCanada reached an agreement with Exxon Mobil to
pursue joint development of the pipeline. We are calling that joint
effort the Alaska Pipeline Project (APP).
TransCanada is on schedule to make an open season filing with the
FERC in late January , and, assuming FERC's timely approval,
conduct a 90 day open season beginning on or about May 1, . This
will be the first open season ever conducted for an Alaska gas
pipeline. As with most open seasons for large pipeline projects, the
bids from potential shippers in the initial open season are likely to
have conditions that need to be satisfied before the shippers make a
binding commitment. Nevertheless, TransCanada and the APP will continue
the substantial work needed to prepare the CPCN application and will
work with the State of Alaska and the potential shippers to resolve
those conditions in a satisfactory and timely manner.
While there are many challenges confronting the Alaska Pipeline
Project, more progress has been made on the project in the last 15
months than at any previous time. If all of the involved parties can
successfully resolve their differences, the APP can deliver North Slope
natural gas into the North American pipeline grid by late in the next
decade.
Pipeline and Supplies Match Power Demand
Today, natural gas fired generation meets about 20% of U.S.
electricity demand on an annual average basis. The U.S. electric power
sector has approximately 400 gigawatts (GW) of installed natural gas
capacity. However, the average capacity utilization factor for natural
gas combined cycle units was only 42% in . These facilities, which
are already connected to the electric transmission grid and to natural
gas supply, constitute a significant inventory of ``ready to be
dispatched'' natural gas fired generation that can make a significant
down payment on meeting GHG emission targets.
For example, if the average utilization factor of these installed
combined cycle units was increased from the current 42% to 55% with a
commensurate reduction in coal generation, the resulting net decrease
in GHG emissions would be on the order of 134 million metric tons. And,
such an increase in utilization would require roughly an additional 5
Bcf per day of natural gas--a volume that can be easily accommodated
from a continental supply perspective considering the contributions
from shale gas and /or Alaska. With electric generation accounting for
a third of all greenhouse gas emissions, burning more natural gas for
electric generation will produce immediate and verifiable GHG emission
reductions.
When new generation capacity is required, natural gas has
significant advantages as a low-carbon generating resource, in that it
is dispatchable, easily scalable, and can be quickly deployed.
Pipeline Capacity and Expanded Supply Moderate Prices
There was a period of time where new gas-fired generation and
drilling projects were outpacing the availability of pipelines. Recent
major pipeline expansions have significantly improved the access of
incremental supplies to markets, contributing to reduced price
volatility and a lower overall price level for natural gas.
The availability of major new shale supplies in parts of the U.S.
that are not as prone to weather-related incidents, like hurricanes in
the Gulf of Mexico, helps reduce price volatility. And, if required,
the current LNG infrastructure provides the option of accessing
international supplies which would further assist in moderating price
volatility.
natural gas as part of the climate change policy
Just as natural gas plays a key role in meeting U.S. energy
demands, it can also play a key part in providing meaningful,
immediate, and verifiable emission reductions. Natural gas emits the
lowest amount of carbon dioxide per unit of generated electricity of
any fossil fuel. Due to its reliability and ease of deployment, natural
gas generation can also serve as a low-carbon backup resource for
intermittent renewable energy sources.
The primary goal of climate change legislation is to reduce
greenhouse gas emissions. Any GHG regulatory regime ultimately
established by the Congress should move power generation choices in the
direction of increased use of lower carbon resources, including natural
gas, by establishing appropriate price signals and other structural
provisions. Additionally, natural gas generation can ensure the
integration of intermittent renewable energy sources into the
electrical grid.
An increase in natural gas usage, as the lowest carbon content
fossil fuel, in a stable investment environment that includes access to
North America's large natural gas resources, both offshore and onshore,
can be seen as the appropriate market response to properly designed
carbon constraint policy.
However, EPA and EIA modeling of H.R. , the Waxman-Markey
climate bill, shows a potentially perverse result. For example, in
EIA's July analysis of the Waxman-Markey bill, natural gas
consumption in drops from a business-as-usual reference case
projection of 22.1 quadrillion BTU to 21.5 quadrillion BTU in the basic
Waxman-Markey scenario and drops even more in from 24.2
quadrillion BTU in the EIA reference case to 21.1 quadrillion BTU in
the basic Waxman-Markey scenario. The only scenario where EIA shows an
increase in the consumption of gas is the so-called ``No International/
Limited Case'' where none of the other low carbon technologies, like
expanded nuclear or carbon capture and sequestration, are sufficiently
available in the relevant time frame and use of international offsets
are constrained.
Consequently further policy adjustments to proposed climate change
legislation are justified and necessary. As the Senate deliberates
climate change and clean energy legislation, it should consider
additional measures to take advantage of the unique potential of
natural gas as a low-carbon power resource. Policy choices available to
promote the use of natural gas would probably requireIn particular, the
Senate should consider mechanisms that encourage the early retirement
of less efficient, less clean power sources. A number of ideas, such as
an auction of 100% of allowances, a climate allowance compliance option
based on avoided coal/increase natural gas use (so-called ``Bridge Fuel
Credit''), cash for coal clunkers, and a broader resource-base clean
energy mandate, have been suggested and should be considered as part of
the climate debate. But, TransCanada also recognizes the need for some
transitional support for the customers and shareholders of these less
efficient, less clean power sources. TransCanada is committed to
working with policymakers to find the best combination of these policy
instruments.
Specific Interstate Pipeline Concerns
With respect to climate change legislative proposals that have a
direct impact on interstate natural gas pipelines, TransCanada endorses
recommendations made by INGAA to address two specific concerns--
performance standards for fugitive emissions and the ability to ensure
recovery of the costs of cap and trade allowances.
H.R proposes command-and-control performance standards on
fugitive methane emissions from natural gas systems, landfills, and
coal mines. Specifically, the proposed Clean Air Act Section 811
directs EPA to promulgate performance standards for new and existing
uncapped sources that individually emit more than 10,000 metric tons of
CO2e per year and collectively emit at least 20% of uncapped
emissions. The Kerry-Boxer bill would delay the promulgation of
performance standards for greenhouse gas emissions until , but
would still permit EPA to impose such standards after that date.
These proposed performance standards will impose heavy costs on the
natural gas industry because of the vast number of small sources of
fugitive emissions and the technological challenges inherent in
capturing their emissions. In addition, these proposed standards would
keep methane sources from qualifying as domestic offset projects--
thereby restricting the supply of domestic offset credits and
increasing the costs of compliance for all sources within the cap.
TransCanada recommends that climate change legislation eliminate EPA's
authority to impose performance standards on uncapped methane sources
under the Clean Air Act, and instead treat methane sources as offset
project opportunities. To provide offset project developers with
greater certainty, the bill should include an explicit list of eligible
offset project types that includes projects that reduce fugitive
methane emissions from natural gas systems. In contrast to a command-
and-control regulatory regime, this approach would give fugitive
methane sources a market-based incentive to begin reducing emissions
from the first day of the cap-and-trade program. Treating methane
sources as offset projects would also give our industry the flexibility
to identify and pursue cost-effective emission reduction opportunities;
generate revenue to fund the installation of emission capture systems;
and increase the supply of domestic offset credits to entities within
the cap, making the entire cap-and-trade program more cost-effective.
pass through cost recovery
Under both the Waxman-Markey and Kerry-Boxer bills, natural gas
pipelines are treated as industrial emitters and will incur significant
costs to comply with the cap-and-trade regime and new Greenhouse (GHG)
Performance Standards. Unlike most other industrial emitters, however,
natural gas pipelines provide a regulated transportation service and
therefore have difficulty passing these costs on to customers.
INGAA strongly urges the Senate to include a provision in its
climate legislation that permits regulated entities to effectively and
efficiently recover new costs imposed due to allowance compliance
obligations as well as new GHG Performance Standards (if they are not
eliminated as proposed above).
INGAA believes that the clear, automatic pass through of climate
legislation-related costs is necessary to ensure timely recovery of
highly volatile costs, which a traditional filed rate process. Such a
pass through provision would also place pipelines on equal footing with
other industrial emitters that have the flexibility to account for new
costs in their pricing.
conclusion
Natural gas plays an important role to U.S. energy and
environmental security. Its benefits as a clean, abundant, available,
and ready source must not be overlooked as part of a climate strategy.
The new supply paradigm and robust infrastructure, both in terms of
pipelines and gas-fired power plants, provide a solid foundation for a
low-carbon energy future.
The Chairman. Thank you very much.
Mr. Fusco, why don't you go ahead. You're our cleanup
witness here.
STATEMENT OF JACK FUSCO, PRESIDENT AND CHIEF EXECUTIVE OFFICER,
CALPINE CORPORATION, HOUSTON, TX
Mr. Fusco. Thank you, Chairman Bingaman, Ranking Member
Murkowski, and the members of the committee. Thank you for the
opportunity to testify today on the role of natural gas in
mitigating climate change.
I'm Jack Fusco, president/CEO of Calpine Corporation.
Calpine is the Nation's largest independent power producer, one
of the largest consumers of natural gas for electric
generation.
Because environmental leadership has been a governing
principle at Calpine for over 25 years, we've been able to
achieve the lowest greenhouse gas footprint in the industry.
Our fleet consists of 62 modern, clean, efficient natural-gas-
fired power plants and 15 geothermal plants, located in 16
States, with the capacity to power over 20 million households.
Additionally, we are the largest cogenerator in the country. We
are a significant supplier to America's industry, producing
steam for refineries, as well as chemical, paper, agricultural,
and plastic manufacturers. We use approximately 3 percent of
all the natural gas consumed in the country and almost 10
percent of that consumed by electric generators. Because we use
existing modern technology and natural gas for fuel, our
natural gas plants emit less than 40 percent less carbon
dioxide than the electric generation industry average,
virtually zero acid-rain-forming sulfur dioxides, less than
one-tenth the industry average smog-producing nitrous oxides,
and no mercury whatsoever.
I'm here today to tell you that the near- and medium-term
solution to our climate change challenge is at hand. Natural-
gas-fired electric generation is a compelling solution. First,
it's far cleaner, with far less impact on our air, our land,
our water resources, than any other form of fossil fuel
generation. Second, the proven technology exists; it's far
cheaper to construct than any other alternatives. Third, it's
critical for the integration the intermittent renewable
resources into the electric grid. Fourth, there is enough
existing underutilized natural gas power plants located in the
United States today to reduce the annual power sector
CO2 emissions by up to 20 percent. Then, last, as
you heard from the others here today, there is an abundant,
secure, and economical supply of domestic natural gas that
should last for decades.
We could, today, simply through the increased use of
existing modern natural-gas-fired power plants, meaningfully
reduce the CO2 emissions of the power sector. The
power would be reliable, available all day and every day, and,
with the right incentives, American businesses will continue to
invest its own capital to build more natural-gas-fired plants
and dramatically greenhouse gas emissions for the long term.
Calpine, I would modestly submit, is the model for a
sustainable future. We use a mix of natural-gas-fired and
renewable generation to achieve the results I just referred to.
The majority of our gas-fired plants use state-of-the-art
combined-cycle technology. A significant portion of the plants
use combined heat and power, or cogeneration technology, to
produce electricity and steam. Cogeneration opportunity--
operations are significantly more efficient and result in less
greenhouse gas emissions than having a standalone boiler at an
industrial site. This is also a very efficient means of serving
industrial production, and is recognized and encouraged by
Federal policies.
We are also a significant contributor to the Nation's
existing renewable generation capacity, with our 725 megawatts
of geothermal power located in northern California. This is the
only currently viable source of baseload renewable electricity,
and our resource provides California with over 25 percent of
its current renewable energy production.
We, at Calpine, continually challenge ourselves to further
increase our corporate commitment to environmental leadership.
For example, we have little impact on our Nation's water
resources by not using once-through cooling at any of our
plants; instead, we utilize treated municipal wastewater or air
for cooling purposes.
Then, finally, we plan to build the Nation's first power
plant with a voluntary limit on greenhouse gas emissions. The
plant will emit less than half the carbon dioxide of even the
most advanced coal-fired generating technologies.
Calpine has been, and continues to be, supportive of the
House and Senate efforts to enact climate legislation. There
are some key issues that I'd like to comment on.
First, we sell steam and power under long-term contracts,
many of which may not be--may not allow us to recover our costs
under a carbon-regulated program. Both the Waxman-Markey and
the Kerry-Boxer proposals would allocate those free allowances
to us and others, which is critical to the continued viability
of those projects. We encourage you to leave those protections
in place. Otherwise, early actors like Calpine will be unfairly
punished.
Then, second, none of the proposals provide incentives to
utilize existing, highly efficient, combined heat and power
technology. We encourage you to add such incentives.
Third, none of the proposals provide incentives to
encourage the full use of the existing modern natural-gas-fired
power plants which could immediately reduce the electric
sector's emissions by over 20 percent.
Then, fourth, both on the climate change proposal --both
climate change proposals unduly favor dirtier generation to the
point that incentives to switch to existing gas generation, or
build new gas generation, are severely blunted. Under the
proposed allowance methodologies, carbon prices would have to
be extremely high for coal-to-gas switching to occur. The
Kerry-Boxer proposal does include some incentives to replace
high-emitting fossil fuel generation with a cleaner generation,
but likely only for owners of high-emitting fossil fuel plants,
and only if the new gas plants emit at levels not currently
achievable by the industry.
In summary, while it's clear that we need a very varied
energy source to meet the challenges of the future, we can meet
our national goal of substantially reducing the electric power
sector's carbon footprint with a policy designed to motivate
greater use of existing, and to construct new, gas-fired power
plants. It's also clear the natural gas supply is as secure and
as abundant as the coal supply.
Thank you all, and I would be pleased to answer any of your
questions.
[The prepared statement of Mr. Fusco follows:]
Prepared Statement of Jack Fusco, President and Chief Executive
Officer, Calpine Corporation, Houston, TX
Chairman Bingaman, Ranking Member Murkowski and members of the
Committee, thank you for the opportunity to testify today on the role
of natural gas in mitigating climate change.
I am Jack Fusco, President and CEO of Calpine Corporation. Calpine
is the nation's largest independent power producer with the lowest
carbon footprint in the industry. In addition to the largest fleet of
natural gas fired plants we have the largest baseload renewable energy
resource in the country. We consume approximately 3% of all natural gas
used in this country and almost 10% of that used to make electricity
and thermal energy. In short we are uniquely positioned to address the
role of natural gas in meeting the climate change challenge. Calpine
has actively supported enactment of climate change legislation for many
years and we have long put our money where our mouth is when it comes
to minimizing our carbon footprint. (Please see appendix for more
detailed background on Calpine.)*
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* Appendix has been retained in committee files.
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I am here today to tell you that we could, today, simply through
the increased use of existing natural-gas fired power plants,
meaningfully reduce the CO2 emissions of the power sector,
immediately and for the foreseeable future. In other words, a near-and
medium-term solution to our climate change challenge is at hand. No
guesswork. No huge spending programs needed. That power would be
reliable--available all day, every day. And if we embrace this solution
with the right incentives, American business would continue to invest
its own capital in existing proven technologies to build even more
natural gas fired plants to dramatically further reduce emissions for
the longer term.
We power American households, businesses and industry with plants
that, compared with other fossil fuel plants, emit only half of the
carbon, almost none of the other air pollutants and virtually no
mercury. We are available now and can quickly build more capacity to
help America grow tomorrow, responsibly and sustainably. Importantly,
as you've heard from the other experts today, there is no security of
fuel supply concern because natural gas supply is as secure as coal
supply.
the calpine model is the model for a sustainable future
I would like to point out a real life example of how private
business can be a leader in creating a sustainable future and reducing
GHG emissions through the use of existing and developing technologies
related to natural gas-fired electric power generation. The best way to
do that is to tell you about what we have done at Calpine because I
deeply believe it is the model for the future.
For better than two decades Calpine has put its money into clean,
highly efficient natural gas plants and renewable energy production.
The majority of our gas-fired plants use state-of-the-art combined-
cycle natural gas-fired technology which capture and use the exhaust
from gas turbines to generate additional energy in a steam turbine.
A significant portion of our generation uses combined heat and
power (CHP or cogeneration) technology. At our cogeneration facilities,
we use natural gas as a fuel to produce not only electricity but also
thermal (steam) energy. The electricity produced is sold either into
the wholesale power market or via a long-term contract to an end user
(typically an electric utility or industrial consumer); the steam is
sold, via contracts, to our industrial host. CHP operations are
significantly more efficient and result in less GHG emissions than
having a stand-alone power plant and a separate stand-alone boiler at
an industrial site. For this reason there are federal policies and
programs which actively support CHP. As the largest independent
cogeneration company we help many of America's chemical, oil refining
and other industrial facilities operate efficiently and cleanly.
While a small percentage of our generation mix is renewable, the
resource we utilize makes it a significant contributor to the renewable
generation capacity in the country. Calpine generates 725 MW of
geothermal power at our Geysers facilities in Northern California. The
geothermal resource is nearly emissions free and is available 24-7-365,
making it the only currently viable source of baseload renewable
electricity. Our geothermal operations provide California with its
largest source of renewable energy.
Our investments in these technologies have made us a very clean
generator, and as I said previously, with significantly fewer air
emissions than the electric sector average. Compared with the
electricity industry average, Calpine's natural gas plants emit 40%
less CO2, less than one-tenth of smog producing
NOX, virtually zero acid rain forming SO2, and
absolutely no mercury (see figure 1).*
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* Figures 1-3 have been retained in committee files.
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Our sense of environmental responsibility extends beyond air
emissions. For example, we invest to reduce or eliminate the impact on
our nation's water resources. At our geothermal facility, we take
treated waste water from nearby counties and re-inject it into our
wells to supplement the steam resources. Further, Calpine has no once
through cooling power plants. We strive to utilize treated municipal
waste water for cooling purposes or air cooling. This is the
sustainable approach.
We continually challenge ourselves to further increase our
corporate commitment to environmental leadership and, to that end, we
recently announced plans to build the nation's first power plant with a
federal limit on emissions of CO2 and other greenhouse
gases, even though there currently is no regulation mandating that we
do so. Our proposed Russell City Energy Center, a 600 MW plant using
advanced combined-cycle technology, will be the cleanest natural gas-
fired plant in the country. At baseload conditions, the plant is
designed to operate at an efficiency rate that results in approximately
800 lbs of CO2 /MWh of power delivered to the grid. This is
less than half the 1,700 lbs of CO2/MWh emitted by even the
most advanced coal-fired generating technologies.
natural gas is key
While the technologies we use are an important component of why we
are so clean and efficient, the major source of our success is our
chosen fuel--natural gas. Natural gas is considerably cleaner than
other fossil fuels. Compared to coal, using natural gas as a fuel for
electricity generation results in nearly 50% less CO2
emissions, about 80-90% less NOx emissions, negligible SO2 emissions,
and no mercury emissions. In addition, gas-fired plants produce a
significantly smaller waste stream, if any, than coal (fly ash) and
nuclear (spent fuel) plants.
There are a number of other advantages natural gas-fired generation
has over other generation sources. Compared to many other generation
sources, natural gas power plants can be permitted quickly and they
have a much smaller footprint. In addition, they can be built more
quickly and cost less to build on a per megawatt of capacity basis (see
figure 2).
Natural gas combined-cycle generation is also an ideal choice for
backing up intermittent renewable electricity sources due to its
ability to quickly ramp up and down. With the push for vastly expanding
the nation's renewable generation capacity, much of the new capacity
that will come on-line to fill this need is likely to be from
intermittent sources. This could have an impact on the reliability of
the electricity system. Americans demand and deserve reliable energy--
when they flip on the light switch, the lights must go on. In the near
term, this will only be achievable if gas-fired plants are there to
provide that reliability.
Increased use of natural gas-fired generation can also have an
immediate impact in reducing carbon emissions. Currently, there is a
significant amount of existing natural gas-fired generation capacity
that is not being utilized. The increased utilization of these existing
facilities in place of older, dirtier power plants would result in near
term GHG emissions reductions of up to 20% without the need for
building new generating facilities (See figure 3).
Calpine continues to believe that natural gas is the right fuel
choice for electricity generation. With the recent forecasts of
substantial domestic supplies for the foreseeable future, natural gas
is the key for providing the clean, efficient, reliable, and affordable
electricity needed to help meet the nation's climate change goals.
comments on existing climate change and clean energy legislative
proposals
Calpine has been very involved in the climate change and clean
energy policy debate in Congress and applauds the legislative steps
underway to address the climate change problem and to move the country
towards the greater utilization of clean, efficient and renewable
energy resources. We supported H.R. , The American Clean Energy and
Security Act of , and we are encouraged to see that S. , The
Clean Energy Jobs and American Power Act, largely follows the same
framework of H.R. ; we also supported components of S. , the
American Clean Energy Leadership Act of , which passed out this
committee. I would like to point out an issue of great importance to us
contained in the climate change bills and some areas of concern in all
of the bills.
long-term contracts
Calpine sells some of our power and nearly all of our steam under
long-term contracts. Many of our existing contracts were entered into
before there was serious consideration of carbon regulations, thus
these contracts do not include provisions to allow for compliance cost
recovery. In general, merchant power generators will have an
opportunity to recover compliance costs via the wholesale price of
electricity and regulated utilities will have an opportunity to seek
recovery of their compliance costs via their jurisdictional state or
local regulatory commission. In our case we remain subject to the terms
of our sales contracts, and it is unlikely we could successfully change
these contracts to allow for cost recovery. Should we be unable to
recover our costs associated with these long-term contracts, we could
face financial harm and the contracts could be put into jeopardy. It is
important to note that many of our contracts are associated with our
CHP facilities.
Calpine believes it is imperative that climate change legislation
provide protection for generators with such existing long-term
contracts for delivery of both electricity and steam. We are very
pleased that both H.R. and S. address this concern by
providing free allowances to eligible generators with long-term
electricity and steam contracts. As the legislation moves forward in
Congress, we implore you to ensure that this provision remains intact.
chp incentives
We know there is established federal policy promoting CHP as an
important form of energy efficiency. Per such policy, we would expect
that there would be policies that promote the utilization of both
existing and new CHP facilities. However, none of the existing
legislative proposals provide real benefits for existing CHP units.
There are many underutilized CHP facilities throughout the country that
could help meet energy efficiency goals. Including credit for these
facilities for the energy efficiency goals in the various bills would
ensure that such existing CHP facilities are efficiently and
effectively used.
natural gas incentives
Real incentives to encourage the greater use of natural gas are
also largely missing from all of the bills. We have heard arguments
that just putting a price on carbon will naturally benefit natural gas,
as this will likely automatically lead to fuel switching from coal to
natural gas; therefore, there is no need to include incentives for
natural gas in legislation. However, both H.R. and S. provide
such broad benefits for dirtier sources of generation and for renewable
energy resources, that the ``natural benefit'' for natural gas will be
seriously blunted. Under the proposed allowances methodology, carbon
prices would have to be extremely high for fuel switching to occur.
S. includes a provision promoted as encouraging the greater
use of natural gas. The intent of the provision is to provide
incentives to displace high GHG emitting electric generating units with
lower emitting sources, which generally would benefit natural gas fired
generation. However, the way the section is written could be
interpreted and implemented in a way that ultimately does not benefit
natural gas, particularly existing natural gas generation. First the
funds would only go to new projects. Second, to be eligible for funds,
the project must reduce emissions below a certain threshold that is
lower than most natural gas fired plants can likely meet.
More work and thought needs to be put into providing true
incentives for natural gas in these legislative proposals.
conclusion
Calpine believes that natural gas is a key resource in helping to
mitigate the effects of climate change. We remain committed to being an
important player in working with you to resolve this problem. While it
is clear that varied energy sources are needed to meet the challenge,
it is equally clear that the greater use of natural gas with its
compelling and distinct advantages has been overlooked. I urge you to
seriously consider natural gas as a solution and to enact policy that
promotes it.
Thank you again for this opportunity to testify.
The Chairman. Thank you. Thank all of you for your
excellent testimony.
Let me start with a few questions and then Senator
Murkowski, and I'm sure all members will have questions.
Mr. Newell, let me start with you. You know, when we
started talking seriously, a couple years ago, about climate
change legislation and putting a price on carbon, I can
remember discussions where people said one of the effects of
this would be to encourage more use of natural gas, since it's
the least carbon-intensive of the various fossil fuels. I
notice--and you commented on it--your analysis of the Waxman-
Markey legislation, that's passed the House, predicts that
natural gas usage would not be significantly higher as a result
of putting a price on carbon, as that legislation proposes to
do. In fact, in some of the modeling scenarios that you have, I
guess you have natural gas usage even lower than in the
reference case.
Could you just explain how--again, maybe you went over this
in your comments, but, to the extent you could elaborate on why
you do not see the enactment of climate change legislation,
such as the House has passed, increasing the use of natural gas
in power generation and other sectors of the economy?
Mr. Newell. Yes. Let me offer a little bit about the
history. I think that one of the main factors that's changed,
depending upon how far back you look, is that natural gas
prices have come up significantly over the last several years,
whereas, if you turn back the clock to a point when people were
discussing, for example, the Kyoto Protocol and so on, at that
point in time gas prices were significantly lower. So, as a
cost-effective means of reducing greenhouse gas emissions,
natural-gas-based generation for electricity looked relatively
more competitive, compared to existing coal, than it does now.
It's kind of a bit of----
The Chairman. The new finds of natural gas have not changed
that perspective, as to what the price of natural gas will be,
relative to other fuels?
Mr. Newell. I think they have, but, again, relative to
historical prices that were down as low as $3, $4 per thousand
cubic feet for many years. The expectation is, even given the
new gas shale developments, that over the next several years
we'll see a gradual increase in the price of natural gas that
would be necessary to balance supply and demand.
So, we see that price increasing, over the next several
years, to the $5 range, and, over time, to $6, $7, potentially
$8 per thousand cubic feet as you go out a couple of decades.
If you think about comparing natural-gas-based generation
versus existing coal, we find that the level of carbon price
that would be necessary to make natural gas switch out for coal
in existing plants depends what you assume about the natural
gas price, again. So, at $5 per Mcf, we estimate, roughly, that
it would take a $30-per-ton-of-CO2 price to
encourage switching from a typical existing coal plant--
conventional coal--to natural gas. If the price of natural gas
is $7 per thousand cubic feet, it would take something like a
$60-per-ton-of-carbon-dioxide allowance price to encourage
switching among existing plants.
So, as one thinks about the results that come out of EIA's
analysis of the Waxman-Markey bill, the key issue is that--in
terms of the role that gas plays relative to other
technologies--in the near term we find that gas tends to
increase. The reason is that the competiting low-emission
generation technologies, such as nuclear, renewables, and coal
with carbon capture and storage, are on a longer-term
development plan. But, in the longer term, as you get toward
, , zero- to low-carbon technologies, like nuclear
power, renewable energy, and coal with carbon capture and
storage, start looking relatively more competitive compared to
natural gas. So, that's why, over the long run, we actually
see, in many of our cases, a reduction in natural gas use
relative to the reference case.
Is that----
The Chairman. Yes, that helps. Let me ask one other
question----
Mr. Newell. Yes.
The Chairman [continuing]. Before my time expires, here.
Mr. McKay, you talk about the importance of--or the idea
that we might essentially provide incentives to shut down some
of the least efficient nuclear plants--coal-fired plants--and
have those replaced with natural gas.
Could you just elaborate on that proposal, or your
suggestion there, as to how that could be accomplished? To what
extent government should be telling companies what to replace
coal-fired plants with, if we did that? Or, to what extent we
should incentivize it?
Mr. McKay. Yes. Let me just expand on that a little bit.
What we've looked at, and believe, is that some of the most
inefficient coal plants--the oldest coal plants --are going to
face increased environmental air standards, here, in the near
future, and will have to do upgrades--sorry--will have to do
upgrades of a fairly sizable proportion. So, we took about 80
plants that we think are in that category, and we said, ``OK,
those could be potentially upgraded and still working as they
are. Or, would it be an opportunity to look at, if there's a
way to retire those plants, what would be the climate benefit,
in terms of CO2 emitted, if other alternatives were
used?'' So, you could theoretically go to all wind, you know,
if it would work. We looked at natural gas. We believe, you
know, at a very low cost, natural gas could replace that
capacity with very low effective carbon-mitigated price.
In other words, if you take a current coal plant, look at a
new-build gas plant, we think it would add about 1 cent per
kilowatt-hour to that coal plant. If you take that 1 cent per
kilowatt-hour for those 80 coal plants, over the period of
to that would be about a $5-billion dollar increment. OK?
But, that's from current coal to brand new natural gas
generation.
One of my colleagues here today has said there's a lot of
excess capacity, so it would be lower cost if we use excess
natural gas generating capacity. OK? So, this is about new
build. If you did that, you would mitigate about 100 to 125
million tons a year, per year, as I indicated in my remarks, as
you phase eight or ten of these out a year. So, over the period
of to , that would be about 700 million tons, we
believe, of CO2 mitigated, if you switched these to
natural gas. The cost of that mitigation, if you take my $5
billion and that amount of CO2, is about $13 a ton.
So, we think it's an efficient way to at least look at it
as an option, if these coal plants need a lot of work, to start
with. That's where we're coming from.
The Chairman. Thank you very much.
Senator Murkowski.
Senator Murkowski. Thank you, Mr. Chairman.
Thank all of you for your testimony this morning.
I think, without exception, the comments have been that we
have an available, secure supply of natural gas that can last
for 100 or 150 years, but a considerable source. Mr. Stones, I
appreciate the concerns that you have raised.
But, I want to ask you, Mr. McConaghy, you've actually used
the term ``game-changer,'' that the shale that we're finding,
whether it's the Marcellus or the Barnett or wherever in the
country, that this is a game-changer for us, in terms of
identifying a vast resource, and the availability.
Can you explain to me and the other members of the
committee a little bit more about Alaska's gas resources and
its relevance as a long-term source of supply, given what we're
seeing in the Lower 48 and the prospects that we're seeing with
the gas shale? Does Alaska still play in the North America
market for the long term?
Mr. McConaghy. Thank you, Senator.
The short answer is, we very much do believe that Alaska,
as a supply component to the North American fuel mix, is
absolutely part of that future. One of the reasons that we have
that view is that the price level that's going to have to
pertain, over the back end of this decade, in order to ensure
that the level of gas consumption that the United States will
require for, not just carbon reasons, but for all the other
applications that natural gas is used for, is going to be a
price level --and our own view would be that that price level
is likely somewhere in the range of $6 to $8--would tell us
that the cost structure that it's going to take to bring Alaska
into the market can still make that a totally economic
contribution to the supply mix. So, we very much are of the
view that Alaska is a component of this, notwithstanding the
significant, quote, ``game-changing'' advent of the shale gas
resource, so that it's very much a case that we need both of
these resources coming into the U.S. supply mix. Of course, in
the case of Alaska, it is going to take us probably most of the
rest of the next decade to realize that. But, we certainly do
not ascribe to a view of crowding out. We don't take that view
with respect to Mackenzie, either.
Thank you.
Senator Murkowski. Mr. McKay, do you care to comment?
Mr. McKay. I think I generally agree with that. I mean,
it's a world-scale resource. It's a long way from market, and
it needs to compete into the U.S. market, but we--but I would
agree, generally, with his comments, yes.
Senator Murkowski. Good.
Let me ask a followup because you mentioned the price. You
anticipate that natural gas prices are going to be holding
somewhere between $6 to $8. That certainly helps TransCanada,
as you look to build this out. It certainly helps BP and the
other producers that are involved. You need that higher price
for the natural gas. Given that right now the consumers are
experiencing and enjoying a lower price, what does this do? How
much of a pinch is this to the consumer? It helps to build out
the project, but ultimately, what is the impact to the average
household?
Mr. McConaghy, you can comment, or anyone else.
Mr. Stones, you can go ahead.
Mr. Stones. I mean, one of the things that we've seen over
the last several years is, you know, we had a spike in , in
, in , in , and . We believe spikes will
continue. We are enjoying low prices now. As a result, gas
production is actually falling, per EIA data, in this country,
at present. There will be a time lag between the resumption of
it, and that's likely to lead to a spike.
These higher prices are going to continue, and they're
going to be volatile, going forward. That's why we've ended up
losing so many jobs in manufacturing. I disagree, respectfully,
with Mr. McKay, that there's a need to drive demand to gas.
Right now, over the last, say, 6 to 12 months, the United
States has actually moved, by most accounts, 2 to 3 Bcf of
electricity--2 to 3 Bcf of gas consumption's worth of
electricity consumption from coal plants to gas plants, without
any need for an incentive. We believe that there is enough
incentive in the market, just left alone, to drive the
replacement of these coal power plants, as was testified to by
the members of the panel. They've already replaced them. Why do
we need an additional incentive?
Senator Murkowski. Mr. Chairman, my time is expired, but
hopefully we'll have time for a second round.
The Chairman. Senator Menendez.
Senator Menendez. Thank you, Mr. Chairman.
Mr. Newell, I'm concerned both about climate change, as
well as our complete reliance on oil for virtually all of our
transportation needs. When the economy fully rebounds, there
are few, I think, who do not believe we'll see, again, a spike
in oil prices. That's why, along with my colleague, Senator
Hatch and the majority leader, Senator Reid, and Senator
Murkowski, we introduced the Nat Gas Act, which is a bill that
extends and increases important tax incentives to jump-start
the national--natural gas vehicle industry and allow us to
diversify our transportation fuel mix and also reduce carbon
emissions.
Now, the Energy Information Administration seems to have
some quite conservative estimates for oil price rises, and it
did not predict the incredible volatility in oil prices we've
experienced in recent years. So, my question is, Has the EIA
done any work to explain this volatility or to examine how
expanding the use of other fuels for transportation, such as
natural gas or electricity, might help U.S. consumers from such
volatility?
Mr. Newell. Yes, Senator, we have. In September, we
launched what we're calling the Energy and Financial Markets
Initiative, the purpose of which is to increase EIA's
information base and our analytic capacity for understanding
and explaining the wide variety of factors that influence oil
and other energy prices. There are a number of different
elements to the initiative, some of which are reflected in
previous legislation that has actually passed out of this
committee, so we're taking action on a number of those things
already. It includes increasing information collection on
various things, also increased cooperation with other Federal
agencies that are, you know, involved in the issue of analyzing
energy and financial markets. We're also undertaking analysis
of various types.
One of the things that we have started doing in our short-
term forecast, which is our Short-Term Energy Outlook, is that
as of October, we now include uncertainty bands around our
price forecasts, to better show that there is wide range of
uncertainty on where oil prices and natural gas prices could
go. If you look at that, based on the analysis we've done,
there's a significant range around which oil and natural gas
prices could be within the next couple of years.
Within our long-term projections, we have a central case
for an oil price. We also have a high and a low price case. The
high price case goes as high as $200 per barrel of crude oil.
So, we are trying to better articulate the broad range of
possible future prices for oil and natural gas in our work.
Also----
Senator Menendez. Have you looked at expanding the use of,
for example, natural gas or electricity for transportation
costs as something----
Mr. Newell. We have not specifically analyzed that, and we
haven't been asked to.
Senator Menendez. OK. Let me ask you one other question.
Many of my colleagues continue to promote the view that if we
drill for more oil on the Outer Continental Shelf, we will soon
drill our way into energy independence and low oil prices. The
fact of the matter, the United States has 2 to 3 percent of the
world's oil reserves. According to the EIA's report, even if we
opened up all of our shores to drilling, quoting from your
agency's report, quote, ``the impact on average wellhead prices
is expected to be insignificant.'' That's the end of the quote.
Has there been any recent developments that would make you
change that conclusion in your report? Is there any reason to
believe that any change that would open up everything to U.S.
oil production would have a different impact on wellhead
prices, as the agency has previously said, that it would be
insignificant?
Mr. Newell. No.
Senator Menendez. No? That's a succinct answer. Rarely
achieved here.
[Laughter.]
Senator Menendez. Let me ask one last question.
Mr. McKay, with reference to that Nat Gas Act that I was
referring to, transitioning our vehicles to natural gas would,
of course, offer the dual accomplishment of mitigating
emissions and reducing dependency on foreign oil.
What do you believe that companies like your own are
willing to be, in terms of a partner, in bringing more natural
gas vehicles to market, if the incentives are there?
Mr. McKay. Let me just first say that I do think there will
be increased penetration of natural gas vehicles, because--for
all the reasons you said, and primarily around centrally fueled
fleet and commercial vehicles.
We actually, as Amoco--and I'm a former Amoco employee,
before we merged with BP--we did this, and tried this, in the
s, and it works. We didn't have the customers at the time.
The infrastructure is the issue. So, we will be continuing to
watch this to see if it's an opportunity. But, there's
experience with it. This has gone on for decades, and still
going on in places we put it in, like Egypt, believe it or not.
So, yes. We'll be watching this very----
Senator Menendez. My time is up, but we'd appreciate
hearing from you as to what it would take to have companies
like your own be fully engaged, if we could incentivize it to
do so.
Thank you, Mr. Chairman.
The Chairman. Senator Brownback.
Senator Brownback. Thank you, Mr. Chairman. I appreciate
that.
I appreciate the panel. It's been excellent information on
a good topic.
Mr. Newell, I want to provide you with a little
information, just on a local level. You were talking about some
of the cost of the pending legislation on cap-and-trade. A
couple of my utilities in my State have done some projections.
Kansas City, Kansas, Board of Public Utilities says the first-
year cost to their ratepayers would drive electric rates up 25
percent if the cap-and-trade legislation that's passed the
House were to pass. Kansas City Power and Light is projecting a
4-percent increase--now, that's on their high-end projections--
by . So, to just to give you some real-world perspective.
I'm sure you're familiar with how sensitive people are about
electric rates going up. So, I hope you also track the
projections on those--and I presume that you are--about what
would happen--if you put these requirements in place, what
happens to real people that are struggling in the economy
presently, and driving up these sort of costs.
Mr. McKay, I want to ask you, if I could--Mr. Stones seems
to have a legitimate question about--it's going up now, on
natural gas demand through the electric power sector. I'm happy
to see that. I toured, recently, in a new gas-fired power-
generating unit in my State. Small footprint. Good unit. Seems
to really go in well. Why the additional incentives for
something that's growing presently?
Mr. McKay. Let me first acknowledge Mr. Stones' viewpoint,
because one of their largest costs is feedstock cost, to do
what they do.
Senator Brownback. Right.
Mr. McKay. Natural gas is their feedstock. So, I totally
understand the concern, and they're one of our customers.
However, natural gas is used for a lot of different things,
not just the chemical industry. It's used for power. It's used
for other industrial demand, natural gas vehicles, et cetera.
One fundamental thing that has changed recently, that I
think we shouldn't underestimate, is the structural change in
the gas resource base, and that has changed tremendously. Even
over the last 3 years, that's gone up, by our estimates and, I
think, EIA's estimates, 40 percent in the last 3 years. So, the
resource base has enlarged and the pipeline infrastructure has
enlarged. So, we're connecting a bigger resource base to the
markets in a better way. I think this--things like this will
help the volatility and help Mr. Stones.
I do also think that when you look at the power sector, as
we're here today, natural gas does have the biggest role to
play in the cheapest reduction of carbon dioxide emissions. I
think what we're really balancing, then, is the usage of--I
don't think we should reserve natural gas usage for one sector,
and it has to play across the sectors. What we're trying to do
is balance the right thing.
Let me just make one clarifying comment. What I said, to
start with, is, we believe in a level playing field. We don't
believe the playing field is level in the proposed legislation.
If it's not level, then we would say, ``Could we look at this
as a way of a smooth transition?'' That's our logic.
Senator Brownback. That's a good thought.
I just--Mr. Chairman, I think these are interesting ideas,
particularly Mr. McKay's, about, maybe that--the bottom-end
coal-fired power plants and providing some support for
transitioning. But, I don't want to create the situation that
hurts the manufacturing sector, which we're desperately trying
to bring back and to stimulate. This is my own pet peeve, or
pet project, maybe, for my State, in Kansas, but if we could do
things that combined the renewables, particularly wind, with
natural gas as a way to maybe help in assisting those bottom-
end coal-fired power plants--that may be too complicated by
half, but might be fairly simple and----
We've got to do it in a cost-effective way. We can't drive
utility rates up. Can't do that, because they just--people
won't stand for that. We don't need to do it that way. I think,
if we're wise enough, we could keep from doing that. So, I hope
we can be balanced on this, without hurting people, and, at the
same time, reduce our CO2 emissions.
Thanks, Mr. Chairman.
The Chairman. Thank you very much.
Senator Stabenow.
Senator Stabenow. Thank you very much, Mr. Chairman, for an
excellent hearing.
I first want to welcome Mr. Stones, from my native Michigan
company, and also----
Mr. Stones. Glad to be here.
Senator Stabenow [continuing]. Mr. Wilks, for being a part
of the Michigan economy, as well. So, it's great to see
Michigan represented.
I guess I would go back to what Senator Brownback just
asked, in terms--and what Mr. Stones asked--and that relates
to, Why do we need additional incentives? If you look at
natural gas and the incentives that come with it automatically,
in terms of the environment, terms of what's happening now, the
current cost incentives in moving--Mr. McKay, as you said--
moving your plants, and so on--I think a basic question for us
is, Is there enough incentive in the market place right now to
be able to make things happen? That would be one question.
Then, second, it is of, obviously, great concern to me that
we balance our natural gas policies. Clearly, natural gas is
part of a low-carbon future for us. Critical. Important. We
have large amounts of natural gas--very important for us--that
that is a part of the mix, as I think we need to make sure
everything is a part of the mix. But, we also have to balance
that with our manufacturing policies. I'm deeply concerned, in
the short run. Mr. Newell, you were talking about nuclear and
CCS and other things becoming more viable by . What happens
in the meantime? I don't want to be losing jobs offshore until
in manufacturing until those things happen. So, the key
question really relates to cost, right now, and what this does
for manufacturing, and, in fact, is there a necessity for
additional incentives in an area of energy that already has, I
think, a great deal of appeal and incentives to it.
Mr. Newell, I would ask you a question. You had indicated,
in your testimony, that recent appraisals of technically
recoverable natural gas does not take into account the costs of
finding and recovery of supplies in previously unknown sources,
such as shale. So, I wonder if you might talk a little about
the cost of shale production. At what price do the supplies
start to become viable?
Mr. Newell. Yes. I think that that part of the testimony
was drawing the distinction between technically recoverable
resources and proven reserves. The reserve concept takes into
account the cost of drilling and extracting those reserves, as
well as the price that one could get in the market, whereas
resources is more about the physical resource base. So, we've
seen significant expansion of the physical resource base, most
of it associated with shale technology development.
In terms of the price levels for natural gas that would be
necessary to continue expansion of shale production, there's a
range. It depends on which shale play you're talking about, how
mature it is. There's a range of estimates, some as low as $3
per thousand cubic feet for shale to be profitable. With other
shale plays you need $7 per thousand cubic feet to make those
profitable. So, there's a range.
In terms of looking forward, the price levels that we think
are necessary to balance supply and demand are going to be
moving up from the $5 to $6 to $7 range. But, you know, some
plays will be relatively more profitable under those scenarios,
and others will be just on the edge.
Senator Stabenow. OK. Thank you.
So, given that, I'm wondering, Mr. Stones, at what prices
does your business model start to change when we look at this
whole picture?
Mr. Stones. Let me say a couple of things. You know, one of
the things we've talked a lot about is average price. You know,
what we've seen over the last 5 years or more is that 80
percent of the time the price is lower than the average price.
The issue is the other 20 percent of the time. How do we get
through to the other side? These are the spikes. These are
the--what actually causes us to shut down. So, when you have a
5 to 8--what--3 to 8, or whatever the number was, $6 to $8
dollar range, it can often be, for short periods of time,
maybe, but out of that, for a period of time long enough to
cause real significant job destruction and job losses.
The second thing, you know, I would talk about, that's
important for us to think about, is, as we build more power
demand and more natural gas vehicle demand, these are inelastic
resources. These are people who will pay any price to get their
fuel. We will not be cold, we will not be dark, we will drive
our car to work. What manufacturing provides is a buffer and a
way to minimize those spikes.
So, we're very excited. We hope that there is this new
resource. But, it seems to us a very large risk to take, to pin
everything on this and assume that the gas will follow.
Mr. McConaghy. Senator, if I could make one--just one
comment?
Senator Stabenow. Yes.
Mr. McConaghy. Yes. Just in--respectfully, on the issue of
volatility, which has been raised this morning, I would just
emphasize there are, I think, two significant structural
differences, and one is the fact that the shale gas resource is
a different kind of gas resource. It is a resource that is
more--almost akin to a manufacturing process of its own,
because it's got less geological risk, its process is to just
get the amount of necessary drilling done, to get it done.
That's a significant difference than what was done previously,
when geology was a much bigger issue, as to how you can ramp
up.
Second, the pipeline infrastructure today, and most notably
some of the infrastructure that's been created to bring Rockies
gas to the midcontinent, the laterals that have been connected,
some of the existing shales, whether it's Barnett,
Fayetteville, et cetera--the infrastructure that will help
reduce volatility is significantly better now than it has been
before.
So, I'd respectfully make the point that the concern about
volatility has changed and that, I would just register, is
something that there can be, you know, honest debate about how
extreme that is. But, I do think there have been,
fundamentally, structural improvements that reduce that
concern. I would just register that.
Senator Stabenow. I appreciate that. I guess the question--
I know my time is up, Mr. Chairman--is, As we look at this new
technology, are we at a point yet where it's cost effective
even though there's great opportunities through that? I think
that's probably something we'll have to further talk about.
So, thank you, Mr. Chairman.
The Chairman. Thank you.
Senator Sessions.
Senator Sessions. Thank you.
To follow up on Senator Stabenow's question, Mr. McConaghy,
perhaps, I've heard that one company is--drilled 4,000 wells in
shale and not had a dry hole yet. Is that correct? Is----
Mr. McConaghy. I could----
Senator Sessions [continuing]. Are those numbers realistic?
Are----
Mr. McConaghy. I could believe that. I can't, obviously,
attest to what you've just referred to. But, it is a
fundamentally different kind of production process than what
was formerly known as conventional wildcat drilling.
Senator Sessions. The amounts of it indicate pretty
clearly, Mr. Newell, that we have 100 years-plus of supplies of
this shale oil, would you not agree--I mean, shale gas--or
natural gas in America, maybe is better way, including the
shale gas, discoveries that have added to the supply.
Mr. Newell. Exactly how many years, you know, depends--
there is the resource base, and then you divide by something
like current production, but certainly well above 50 years. I
think there's a pretty broad consensus, whether it's 80 or 100
or a bit above 100. I think there's more there. The Gas
Committee roughly doubled their estimate of the resource base,
over the last 4 years.
Senator Sessions. Did they do it in terms of how many years
of supply exist? Do you recall what those numbers were?
Mr. Newell. It basically went from roughly 50 years to
roughly 100, yes.
Senator Sessions. That's proven reserves, right?
Mr. Newell. No, this is resources.
Senator Sessions. Resources?
Mr. Newell. Yes.
Senator Sessions. Now, with regard to the emissions, it's
about--natural gas would get the same energy BTU production at
about 40 percent less CO2. Is that correct?
Mr. Newell. Yes, that's correct.
Senator Sessions. It seems to me that this is a dramatic
development. The increase in supply of natural gas is just
stunning, and a great development. It's cleaner. If it can be
connected to the pipelines, it's very transportable.
I would think that one of the things we would like to see--
and suspect it will happen naturally, but perhaps we could
accelerate it--would be to utilize more natural gas for
transportation in our fleets, which--mean buses here in
Washington, DC, use natural gas, and other cities --and into
larger vehicles. That's the--essentially what Mr. Boone Pickens
has proposed, and I think, essentially, with the new
discoveries, that makes sense to me, because--several things.
It will pay for itself, will it not? Would anybody like to
comment on that, in terms of at least vehicles?
Mr. Fusco.
Mr. Fusco. Not so much on vehicles, Senator. But, if I
could, just to clarify, you know, a conventional coal plant,
which is what the U.S. has, has an efficiency of around 30
percent. That's the thermal efficiency. So, for the same BTU,
in one of my modern gas plants you're going to get over 50-
percent efficiency. You're actually get more megawatt hours, as
well as lower emissions, than----
Senator Sessions. So, compared to coal, it's even better.
Right.
Mr. Fusco. Then, last, you know, on incentives, right? The
reason we need incentives is--my company had the benefit of
seeing coal-to-gas switching in our southern and southeastern
fleet this past year. It's only when gas prices get around the
low $3 in MMBTU, so extremely low, that incentivizes the coal
guys to shut their units down. OK? With the current forecast of
$6 to $8, it's going to be more of the same. There will be no
switching. You will not get the--any environmental benefits. We
need environmental regulations in this country.
Senator Sessions. We can make anything happen, Mr. Fusco,
with enough subsidies. So, it's the question of how to do it.
I'd like to not burden the American consumer any more than we
possibly can.
With regard to current prices of natural gas, I have been
informed that, even though a natural gas vehicle, like a bus or
a truck, that travels many miles--Mr. McKay, I guess BP might
know this--that it would pay for itself at current prices, the
extra cost, if you used natural gas and had the infrastructure
to utilize natural gas, as opposed to diesel fuel.
Mr. McKay. Yes. I think, at current natural gas prices,
that would be true. We do believe there will be increased
penetration or more natural gas vehicles. We do agree with
that.
Senator Sessions. It would seem to me, as a matter of
national policy, we should favor natural gas, because, in many
ways, it's cleaner to produce, and secondly, it's almost all
American. So, it eliminates the balance-of-trade deficits that
we have when we import 60 percent of gasoline and diesel fuel.
So, we import all of this, send American wealth abroad, when we
could produce 40 percent less CO2 and create a cost-
effective substitute for at least fleets, I would think, if not
every individual automobile. If we could figure a way to expand
that, then we've not burdened the economy and we've reduced our
balance-of-trade deficit and we've reduced, significantly,
CO2 emissions. Am I off base on that?
Mr. McKay. No.
Senator Sessions. I see most of you agree with that?
I would just say, Mr. Newell, we've got to watch the
objections over the production. I mean you drill--my
understanding is, most of the shale gas is about 2 miles deep,
and your water level is 600 feet or less, where water exists.
So, it's unlikely that anything injected to help get the gas
out would impact our water supply, it seems to me. So, I really
think that can be a problem that's--would cause some concern.
You mentioned it, I think, in your written testimony. I hope we
can work on it and make sure that we're not causing any
pollution. But, I don't think, what we've seen so far, we're
seeing a pollutant effect from natural gas production.
The Chairman. Senator Shaheen.
Senator Shaheen. Thank you, Mr. Chairman.
Thank you all for your testimony.
I would actually like to follow up a little bit on the
Senator's question about the pollution and water, because there
has been concern expressed about potential results of the new
fracturing technology and what that might mean, in terms of
polluting water supplies. So, I'd like to hear your thoughts
about that, whether you've seen that to be a concern.
Senator Casey has introduced a bill, called the Fracturing
Responsibility and Awareness of Chemicals Act, which would
repeal the safe drinking water exemption, which was--is
provided to hydraulic fracturing, and require a public
disclosure of chemicals used in the process. So, I guess I'd
like to also hear, those of you who are producers and users of
natural gas, whether you think that's legislation that you
could support.
Mr. McKay. Let me just address your original point, first.
On FRAC, fracking is not a new technology. It's 50 years old,
and there's been over 1 million fracks done in the U.S. So,
that technology is not new. What's new in shale is that--you--
we drill horizontal wells, maybe 5,000 feet, and do multiple
fracks on those--on that lateral. That's the new part.
So, the fracking has been around--I mean, I worked on it
when I first started. The fracking technology is --and the
protection for groundwater--is very robust and very solid. Of
those million frack jobs, there's very few that--I don't know
of any that have had any surface water issues. So, I don't----
Senator Shaheen. I was thinking more of groundwater----
Mr. McKay. That's what I----
Senator Shaheen [continuing]. That would affect wells.
Mr. McKay. Sorry. That's what I mean by surface water--near
surface water, groundwater. I didn't mean really on the
surface. That's a----
Senator Shaheen. OK.
Mr. McKay [continuing]. Industry term. So, groundwater--
there haven't been groundwater issues.
We have physics working on our side. When you frack
underground at 10,000 feet or 5,000 feet, the horizontal
stresses are what are relieved, and it propagates horizontally,
it doesn't propagate up.
It's a solid technology. I do understand your fluids point
about--the disclosure of what's in fluids, I think, was in your
second point.
Senator Shaheen. Right. That's part of this proposed
legislation.
Mr. McKay. We believe that fracking needs to be regulated
at the State and local level. We believe that State and local
regulation can include disclosure of what's in those fluids. We
would support that. We have been working very hard to make sure
the footprint of fracking, or any issues around fracking, is
minimized and would be--Colorado's got a good plan that they've
put in place and I think is a model that States could look at.
So, State and local--because everything is different--geology,
water, everything--at a local level. The technology is robust.
Senator Shaheen. So, you wouldn't support a repeal of the
exemption to the Safe Water----
Mr. McKay. I would not.
Senator Shaheen [continuing]. Drinking Act?
Mr. McKay. I would not.
Senator Shaheen. Is there anybody here who would support
that legislation?
[No response.]
Senator Shaheen. Mr. Fusco--I want to change the subject a
little bit at this point--you testified about Calpine's use of
combined heat and power and----
Mr. Fusco. Yes.
Senator Shaheen [continuing]. The additional efficiencies
that are created as the result of that. I know that a number of
us on this committee believe that that's an important way to
use power and improve the efficiency of our energy sources. So,
as you think about what we might do to encourage that use of
combined heat and power, are there incentives that you could
suggest, or other ways that you would urge us, to better
support combined heat and power?
Mr. Fusco. Yes. Thank you, Senator.
I think, you know, currently there aren't any incentives
for existing combined heat and power plants, in either of the
bills. So, I think the first thing would be to try to
incentivize those of us who have it to expand those facilities.
Most of these gentlemen at the table are either a customer or a
supplier, or both, in most instances. So, I believe in combined
heat and power, mostly because when we talk about the
efficiency of a combined heat and power plant, it exceeds 50
percent. It's in the mid-55-percent range, compared to the
conventional plants that are 30 percent. But, I do think
there--you know, and we're happy to work with you all to figure
out the right mechanisms that need to be put in place for that.
Senator Shaheen. Thank you.
I'm almost out of time, so I'll try and ask this question
very quickly.
Mr. Newell, I understood you to say that, despite
incentives in the current legislation, that we wouldn't see our
natural gas use increase in the future. Am I correct?
Mr. Newell. It depends on the scenario. In our reference
case, which is absent the climate policy that's been discussed,
we see a drop in natural gas consumption over the next several
years, because new renewable energy for electricity and some
coal installations are coming in. But, over the longer term,
natural gas use comes up a bit and is roughly flat over the
next 20 years, in our reference case. Once you layer on top of
that a bill like the Waxman-Markey bill passed out of the
House, depending upon the availability of other options for
reducing greenhouse gas emissions--such as the availability of
international offsets, and the cost and availability of nuclear
power, and coal with carbon capture and storage, which are
close to emission-free, or emission-free--if those are not
available, natural gas could actually increase substantially,
we find. If those are available, which is what our Basic Case
and some of our other cases assume, natural gas does not
compete with those technologies as a cost-effective greenhouse
gas compliance option, given the other incentives that are in
the system. There's also --and I think this gets back to one of
the questions Senator Bingaman asked earlier--State renewable
portfolio standards which are moving renewables into the mix.
In the Waxman-Markey bill, we also have bonus allowances for
carbon capture and storage, which are also part of what's
driving that technology. So, it's not just the carbon price,
per se. There are other policies and incentives that are in
place. Is that----
Senator Shaheen. Thank you. My time is up.
Thank you, Mr. Chairman.
The Chairman. Senator Cantwell.
Senator Cantwell. Thank you, Mr. Chairman. Thank you for
holding this important hearing.
Gentlemen, thank you for being here and to talk about this
larger issue of future energy supply.
I'm somebody who, even though we have a hydro system that
is about 71 percent of our electricity grid, certainly want to
see the U.S. electricity grid diversify and to have more
natural gas. I mean, if we're at 23 percent today, I'm hoping
that we can grow that significantly in the future. We have many
farmers in our State that the supply of natural gas does really
affect the price of product that we have. People think of
Washington State as, you know, software and airplanes, but
agriculture is still the number-one employer. So, diversifying
is really important.
Mr. McKay, you talked about a level playing field and how
important that was, not to pick winners and losers and to have
the market continue to do that. I wondered if you could comment
a little bit more on how you think the House bill treats that--
I get a sense that you think it distorts the market--and what
you think would happen as a result of that.
Mr. McKay. So, in the--if we use Waxman-Markey as a --as
something as a--to talk about, there's two fundamental, we
think, nonlevel playing fields. First is, the transportation
sector is sort of a paying sector, and the utility sector--
roughly, roughly--a nonpaying sector, in terms of the price of
carbon, because free allowances are given. That's the first
dislocation.
The second one within the utility sector is that we think
alternatives are effectively mandated or encouraged, which--you
know, we support transitional incentives, reasonable ones.
Coal, we believe, is insulated. The consumers of coal are
insulated, for sure. Some of the generation of coal is
insulated through credits, allowances, funding for CCS with
coal, not with natural gas, these type of things. Therefore, we
think the price of carbon will not be--not flow easily to make
changes in investment decisions about whether you should use
coal or natural gas.
Senator Cantwell. Basically, you're saying they're going to
help pump up the price of--or support a lower price of coal and
cause a----
Mr. McKay. I think it's insulation, primarily. So, what
we're saying is, if you could strip all the insulation back and
get to a really pure playing field, we're fine with that.
Absolutely fine. If you can't strip the insulation back, how do
we smooth the transition in the period of time when we're
trying to get to lower carbon future?
I just want to say one thing about the demand or
production. Industrial demand has dropped tremendously. The
projections that we see, going forward, we don't even get back
to last year's production until , or later. So, this idea
about, you know, natural gas production ramping up is not--
every projection I've seen, after this drop, we barely get back
to the level we were at last year. So, there's plenty of supply
to do that, is all I'm saying.
Senator Cantwell. So, definitely not a level playing field,
as far as natural gas is concerned.
Then, on the sequestration issue, the same dilemma? The
House-incented----
Mr. McKay. Yes.
Senator Cantwell [continuing]. Carbon sequestration, but
not any natural gas sequestration? Is that your read of it?
Mr. McKay. Yes, I think natural gas is a great clean
utility player that's being not let on the field.
Senator Cantwell. That what?
Mr. McKay. Not being let on the field fully.
Senator Cantwell. OK.
Mr. McConaghy. Senator, if I could just also add one
comment to your question, I would--I understand that the bill
that you have sponsored, in terms of a different approach than
Waxman-Markey, to how one would design a cap-and-trade bill--I
would--by my review of it, it comes the closest to establishing
a level playing field, because it really starts with a full
auction and that would clearly be responsive to the notion of
a--setting a carbon price that would be without the distortion
between the different alternatives and that should be,
probably, all things being equal, advantageous to natural gas.
So, I do make that observation.
But, given that we are reacting to what is currently in
play, I endorse the comments that have just been made, quite
eloquently, that, in fact, you have an insulation of coal,
through the allocation of free allowances, you have the
increasing phenomenon of renewable portfolio requirements
growing, squeezing out the most benign, from a carbon
perspective, of the hydrocarbons. Ultimately, the point of this
exercise is to do something about carbon, despite the fact
there are other collateral considerations, which others have
talked about. So, I just wanted to make that acknowledgment
of--you know, a different kind of carbon bill design could also
level the playing field.
Senator Cantwell. Thank you. No, I definitely agree. I
think a level playing field and predictability is critical for
moving forward.
So, I know I'm out of time, Mr. Chairman. I'll try to stay
for a second round.
The Chairman. All right. Thank you.
Senator Landrieu.
Senator Landrieu. Thank you, Mr. Chairman.
I think this hearing has been exceptional and one of the
best, and I really appreciate you putting panel together.
I want to associate myself with the remarks of Senators
Sessions and Senator Cantwell as we move forward. But, I did
want to comment--Senator Menendez, our colleague, has slipped
out of the room, but I did want to comment on one of his
points. Since I am, proudly, one of the leaders of more
domestic oil and gas production in the Nation, I want to point
out a couple of things and then get to two questions.
One, I've never heard anyone in the U.S. Senate say that
they thought we could drill our way to national security. What
I have said, and what I've heard others say, is, there's
generally a lot more oil and gas, domestically, than we
acknowledge. We fail, sometimes, to realize the dynamic and
exciting changes in the industry that are providing more
supply. I want, one more time --I've done this three times, but
I'm going to do it again, for the record--this is what we
thought was in the Gulf of Mexico, in : 5 billion barrels
of oil. Is this only oil, Tom?
Voice: That's right.
Senator Landrieu. Now, it's gone up, in , to 30
billion. Meanwhile, we have been using and producing all of the
oil between 5 billion and 30 billion barrels. We still have 30
billion. So, the fact of the matter is, if you look for it, you
might find it.
No. 2--or you usually find it--and number two, we can
extract it with a much smaller environmental footprint than
ever before. I'm going to submit again, for the record, that
the natural seepage of oil into the ocean is much greater than
oil from spilled production.
No. 2, for gas--and I want to get this straight on the
record. Drilling-related spills are less than 1 percent of
spills in the ocean. Tankering of oil is a 4-percent. Run-offs
from boats and jet skis is 20 percent. Natural seepage is 73
percent.
So, yes. I am an unabashed advocate for more domestic
drilling of oil and gas, not because I think it solves any
problem, but because I think the American people have a right
to benefit from resources that they own. I think Americans are
tired and feel like it is really embarrassing and downright
shameful to ask OPEC to produce more, when we won't, ourselves.
So, I'm going to continue to be a fierce advocate for more
onshore and offshore natural drilling--I mean, production.
This is the gas resources, which is a good picture to show
what these gentlemen have said, Mr. Chairman, that the gas
resources--it really has been a game-changer, in terms of
outlying projections. The great news is, is because we
deregulated the natural gas pipelines, we've built 11,000 miles
of pipelines pretty efficiently throughout this country, which
is contrary to what we've been able to manage in electricity
lines, which we're having a big fight over, now, and we can not
only find gas in more places, but move it more quickly. So,
there is not only a greater supply, a very clean supply, but it
is almost in every corner of the country, which is not true of
hydro. It's located--or it's not true of coal, or it--well,
maybe coal is a different exception--not true of oil, maybe;
not true of hydro; not true of other parts. But, natural gas
has some really wonderful qualities.
So, my question is, I think, Mr. McKay, to you. Your
comment about the distortions in Waxman-Markey are, I think,
particularly telling. We don't have to go over that; it's
fairly obvious. But, when you talked about the utilities being
relatively insulated, or the electricity sector being
insulated, what about the transportation sector and refineries?
Could you talk a bit about that and see, maybe, is there an
alternative that you might suggest, in the transportation
sector?
Mr. McKay. So, in the transportation sector, that sector is
about--let's just say 40 percent of the emissions--
CO2 emissions in the country, and needs to--for
products and their own emissions--and needs to buy the
allowances, under Waxman-Markey, out of a--basically, a 15-
percent government auction pool. So, it worries us, about how
the transportation sector is going to cope with that.
Refineries within the transportation sector are very trade-
exposed industries. Those refineries all around the country are
exposed, in the sense they've got to scramble for their
emission credits, under Waxman-Markey, and imported products
don't, from refineries overseas. So, it's a trade-exposed
industry that was left out of the trade-exposed industries in
Waxman-Markey, is the fundamental point.
Senator Landrieu. I know my time is expired, but it's a
real problem, Mr. Chairman, in the current framework of Waxman-
Markey, because if we aren't careful, what little refining
capacity we have left in this country, we will potentially
eliminate if we don't do this correctly. Then, instead of
importing unrefined products in and being reliant, as we are on
unrefined products, we're now going to become reliant on
refined products, which is worse, in some ways. So, I just
really caution us. I know the chairman is sensitive to this.
My final point is, I do believe that natural gas, while we
cannot be over-reliant on any one source of energy, and we want
to be--have a multiple of clean-burning fuels, or clean-burning
sources, I do believe that it is something that we potentially
have overlooked. I hope, as we move forward, we can be more
sensitive to it.
I'm pleased to be leading in that effort with Senator
Chambliss on the new Natural Gas Caucus.
Thank you.
The Chairman. Thank you.
Senator Murkowski, you had some additional questions.
Senator Murkowski. Thank you, Mr. Chairman.
I'll direct this to you, Mr. Fusco and Mr. Wilks. You both
have spoken within Calpine and within Xcel, regarding business
judgment decisions that have moved you from coal to natural
gas. As Congress considers the various policies that are at
play here, I'm very concerned about how we have this tendency
to pick winners and losers within the industry. We have
discussed level playing fields. As we discuss the policies that
business really needs to provide for a level of certainty, and
I assume you're making some business judgment decisions, based
on the environmental considerations and the price
considerations, but you never really know what we may do next.
The next favored child within the energy sector may be algae,
and you're out. What do you need from Congress to give you that
level of certainty to make these long-term investments in your
businesses?
Mr. Wilks, you can go first, and then we'll ask Mr. Fusco.
Mr. Wilks. Thank you, Senator Murkowski.
I'll just say that we do State-level resource planning in
all of our States. All those States have different rules that
apply in resource planning. From my standpoint, you know, the
clarity on what we want to do, and the country needs to do, on
carbon reduction, and how that's to be allocated--is
allocated--that kind of clarity is what's going to support
long-term investment in the infrastructure from power
generation perspective.
Senator Murkowski. So, let me just clarify. Do you want to
see that specific 20-percent reduction by ? Is it
definitely part of a cap-and-trade proposal? Does that give you
business certainty?
Mr. Wilks. That's--what you described to me is a very good
example of the clarity that we need. So, I think having that
clarity will allow you to do, then, the long-term resource
planning. Most of our assets are 30-year lived. So, when you
make that kind of investment, you have to have certainty that
the profile, the game plan, the economics that you're planning
on, in fact, do unfold themselves for the future. So, that kind
of certainty is very important.
Senator Murkowski. Mr. Fusco.
Mr. Fusco. Yes. I would just add to the ``level the playing
field,'' because I think that's extremely important, when you
think through this legislation, as well as--I would also say,
don't harm the good actors. We have been a leader. We never had
coal generation at Calpine. We've stuck with natural gas and
geothermal. We've been a good actor. We've designed plants that
are ahead of their time, as far as environmental emissions,
rules, regulations, and laws. We went from being excited about
the potential of the bill, to being defensive, just trying to
protect our current business. That's just not the way it should
be here in America. I think the clarity would be helpful.
Then, last, when we look at the investment decision, what
could be potentially harmful is, the people with the dirtier
generation could potentially get favored to build the new units
of the future. My investors, my shareholders, my board, expects
growth. If that's not crafted right, you're going to favor
those folks, or you're going to force me to have to buy old,
dirty coal units so I can trade the credits in and build new
units. Neither of those are the right answer.
Senator Murkowski. Let me ask the rest of you----
Mr. Stones. Could I make a comment----
Senator Murkowski. Mr. Stones? Yes.
Mr. Stones [continuing]. As well, too? I mean, we support--
--let's be clear--we support congressional action on a climate
bill, and we--promptly--that supports a diversified portfolio,
because what we need to be sure of is that we don't end up with
another ``dash to gas.'' So, our fear is that if it's not a
comprehensive bill that keeps manufacturing competitive, that
we don't know what the playing field is, just like these guys
don't.
Senator Murkowski. So, when you say ``comprehensive,'' I'm
assuming you would include nuclear----
Mr. Stones. Absolutely.
Senator Murkowski [continuing]. As a robust component and
all of the others?
Mr. Stones. Right. We need to make sure that the options
for energy generation in America grow and become more flexible,
not less flexible. That helps the consumers, because one of the
concerns I have is, if flexibility in the natural gas market
goes down, all of a sudden, when it gets cold, everybody has to
buy at the same time and nobody can afford not to. So, gas
prices will go higher and lower, and you'll get much more
volatility. So, we need--you know, we agree, there's a
potential to take a real step forward, here. But you need a
balanced approach that covers supply, demand, energy policy,
security, climate, manufacturing. All of those things need to
be considered.
Senator Murkowski. Thank you.
The Chairman. Senator Cantwell, did you have additional
questions?
Senator Cantwell. Yes. Thank you, Mr. Chairman.
I wanted to ask Dr. Newell--obviously, we were talking
earlier about level playing fields. Let's assume a level
playing field exists and that, because of that level playing
field, renewables have the easier way to the marketplace by
having a more accurate price on carbon. Is your assessment
that--is EIA's analysis that there would be a likely use of
natural gas as a backup to renewable power? So, the fact that
renewables will be out there in the marketplace in a bigger
way, that they have to--you know, there's this symbiotic
relationship between natural gas and renewables for reasons of,
obviously, consistency, and so, this will help pull more
natural gas in the market? Is that what your analysis shows?
Mr. Newell. Depending upon the circumstances, there can be
a symbiotic relationship, with natural gas backing up
intermittents, like renewable power. On a net basis, though, in
most of our climate analysis cases, except when various options
are very limited, we see the net generation from natural gas
going down after . So, there's a certain amount of natural
gas that's symbiotic, but, overall, after some initial period
of increase, it's going down somewhat, except if nuclear power,
international offsets, and other technological options that
compete with gas are off the table, then natural gas expands
significantly. But, it's not primarily due to the renewable,
natural gas complementarity; it's due to other factors.
Senator Cantwell. Mr. McKay, did you want to comment on
that?
Mr. McKay. No. I think it's right. If alternatives come in
at the speed we all would like and think they possibly could,
then I think natural gas does get squeezed in that piece. If
there's insulation, as I've said--and I know you don't want to
go here--but, insulation, that I've said before, in the coal
sector, then natural gas is getting squeezed in the middle. I
just want to say that I think the supply side of this is
fundamentally changed and can handle and lower volatility than
it's been in the past.
Mr. McConaghy. Senator, if I could----
Senator Cantwell. Yes.
Mr. McConaghy [continuing]. Just add this comment, because
I think there are some practical considerations. Even if we
hypothesize a level playing field that provides a transparent
carbon price that's applicable to all the hydrocarbons, there
are real constraints in how much incremental nuclear we could
ever install, from today for the next--within the next 15 to 20
years, realistically.
Second, the cost of doing CCS is still, in some of our
judgment, going to be much more expensive than is anticipated.
As an actual, practical option, it's going to take longer to be
available as a practical consideration.
So, when you look at the medium and short term--and by
that, I'll say within the next 5 to 20 years--if we do have,
quote, ``a level playing field,'' I do believe that is going to
require a greater utilization of gas, if the objective is to
actually reduce carbon emissions and that's just going to be
the case.
It is also the case that, regardless of what is done on
carbon, natural gas prices are going to have to rise, simply
because of the amount of loss of initial production from the
conventional source, not withstanding the very welcomed
addition of shale gas.
So, I'd just underscore, there are some practical
constraints that--when we look at these other technologies.
That's even accounting for a significant contribution from
renewables. So, I do think it points, in the context of a level
playing field, for a greater reliance on natural gas, if the
objective is to achieve carbon goals.
Senator Cantwell. I think the symbiotic relationship
exists. We've already had to get very smart, in the Northwest,
about hydro and wind and the balance with natural gas, because
that, along with efficiency and Smart Grid technology--this is
about how you make all those resources work together. I just
think we need to work harder and--on this focus in research--of
how to make all these resources work together. I think there's
a sweet spot, here, as it relates to driving down cost and
utilization, getting the best out of each of these energy
sources, and putting that mix onto the grid. But, it's clear
that natural gas is going to be a part of that.
Mr. Fusco. Senator, if I may, you know, we have seen, in a
massive increase in the utilization of our quick-starts and
ramping capabilities at Calpine, for our customers here--Mr.
Wilks would be a prime example of that at Xcel, in Colorado. I,
a few weeks back, was in Colorado at our power plant called
Rocky Mountain. The plant was sitting at a 20-percent loading.
Immediately the pedal goes to the metal. These are very
sophisticated pieces of equipment. Ramps up. Hits 80 percent
output. We call the Xcel dispatcher, our customer, and say,
``What happened?'' He said, ``The wind stopped blowing in
Wyoming.'' That's the value we've added. We just negotiated
five contracts with Pacific Gas and Electric because of that,
because of the location of our plants and the ability to ramp
quickly, start quickly, and manage that wind and solar
intermittent loads.
Senator Cantwell. Thank you.
Mr. Fusco. It's been extremely valuable for us.
Senator Cantwell. Thank you. You made my point for me.
Thank you very much.
Mr. Stones. From our perspective, that's exactly right. Gas
is going to grow dramatically. It did in--after the Clean
Air Act. We don't know--you know, we've heard this story about,
``There's lots of gas,'' before. You know, it was the Gulf of
Mexico, it was Canada, it was the Rockies, and now it's shale
gas. We are very hopeful that it's there. But, what we would
urge is caution, moving forward, to ensure that we have a broad
portfolio of ideas and ways to do it, like both of you said.
Senator Cantwell. Thank you.
Thank you, Mr. Chairman.
The Chairman. Thank you.
Senator Sessions, did you have additional questions?
Senator Sessions. Just briefly.
Substituting natural gas for coal has environmental
CO2 benefits, but it's considerably more expensive.
Coal is essentially an American-produced, domestic-produced
fuel, so we don't gain on our balance of trade. But,
substituting natural gas for--in vehicles that utilize gasoline
and diesel fuel, 60 percent of which is imported, also reduces
the environmental impact substantially and helps us
economically, and, as a matter of price, is no more expensive
that diesel and gasoline.
So, I guess, Mr. McKay, I'll ask you, Are there things that
we can do, at reasonable cost to the American citizenry, that
will help us utilize more natural gas in vehicles--in
particular, fleets and long-distance trucking? Anyone else who
would like to comment on that, I'd like to hear.
Mr. McKay. I think the scale of the resource base opens
up--effectively opens up confidence in what price is going to--
--the resource base expansion allows confidence, I think, in
people to feel that natural gas prices are not going to get too
far out of line. Therefore, we do believe natural gas vehicles
are going to accelerate and it--there is infrastructure in
place that can allow that. So, I don't think it needs a big
infrastructure project, I just think that confidence needs to
grow. We're seeing that growing. It already is.
Boone Pickens has recommended certain things. Those are big
infrastructure things. That's an option that can be looked at.
But, we think it's mostly about centrally fueled commercial
fleets and that can grow naturally, I think.
Senator Sessions. You mean like fleets that operate within
a given city?
Mr. McKay. Buses. Yes. Buses, heavy haulers, those kind of
things, that centrally fuel and use a depot.
Senator Sessions. What about long-distance trucking?
Mr. McKay. Potentially. Potentially. But that's where you--
Senator Sessions. You'd have to have interstate supplies
and--
Mr. McKay. That's where you've got to have infrastructure
and filling stations and things like that. Which is possible,
but that's another step of a process.
Senator Sessions. But, not exceedingly expensive, to
achieve that.
Mr. McKay. I don't personally know the cost, but it
probably wouldn't be exceedingly expensive, no.
Senator Sessions. Thank you, Mr. Chairman.
The Chairman. Thank you.
Senator Landrieu.
Senator Landrieu. Yes, just two questions.
I think this has been gone over, but just to be clear, Mr.
Newell. Our objective is to clean the environment and to do it
in a very cost-effective manner. Would you believe that natural
gas meets those two goals? Could you comment about that?
Mr. Newell. Yes, I think it does. Under the wide variety of
different scenarios we've looked at, based on greenhouse gas
legislation, natural gas continues to be a competitive part of
the energy portfolio, looking forward as far as we can see.
Senator Landrieu. OK.
Let me ask Dow Chemical--and, of course, I'm in an
interesting position, Mr. Chairman, as you know, because my
State is a--one of the number of top producers of natural gas,
but we also consume a great deal. Dow is in Louisiana----
Mr. Stones. We are.
Senator Landrieu [continuing]. In a big way. So, I'm
extremely sensitive to this price issue, as well.
But, let me ask you--describe, just very briefly, how you
use natural gas in your process and what Dow Chemical or other
companies in your situation have done to diversify your own
sources, so you're not over reliant, regardless of the price,
of one source for your production.
Mr. Stones. Right. So, we use natural gas as a feedstock.
We make power from it, and from that we create--you know, get
the chlorine chain and plastics. The production of natural gas
is how ethane comes out of the ground, and that becomes
plastics--and all the other things we make. So, it's a big
feedstock for us.
We've taken a number of different approaches. One of the
things we haven't spoken much about in this room, but we've
spend a lot of time on efficiency. We've saved trillion
BTUs, since , on efficiency. So, certainly when we consider
climate change--and, you know, supporting energy efficiency is
one of the things that we would, you know, think is
appropriate.
We've also established an alternative feedstock group. So,
for example, at present, we're looking at different ways to
make plastics and chemicals from algae, coal, petroleum coke,
sugarcane. We're trying to bring what we do best, which is
bring technology to the party, as well. We've also looked at
gasification in various stages.
So, we have a kind of an efficiency and also a--diversify
the types of things we move. We have built a broad portfolio.
As you know, our crackers in Louisiana can use multiple fuels,
depending on what's most economic.
Senator Landrieu. But, Mr. Chairman, I don't want to
underestimate the importance of our manufacturing base either
being incentivized--not that they aren't already--but, for us
to be mindful that--I guess, as Senator Cantwell said, the
sweet spot is a wide variety of choices of clean fuels, with
competition in the marketplace, so that it will eliminate, by
the--if we can price carbon appropriately--eliminate these
price spikes, create lots of jobs, more predictability in the
market. We all have a responsibility to move in that direction.
So, I just wanted to say that I understand the ``dash to
gas.'' We've lived through--the people of Louisiana and Texas,
and, to some degree Mississippi and Alabama, along the Gulf
Coast,--these wild spikes in energy prices that--you know, when
the price goes too high, we get criticized by everyone else;
when it goes too low, we go bankrupt. So, you know, the people
in the Gulf Coast, you know, have not had a very good comfort
over the last 20, 25 years. We'd like to find a better place
for all of us, both producers and our users.
So, I think that's important for manufacturers, like
yourself, to be looking aggressively for other sources, so that
if gas is in--more in demand to be the bridge to the future,
that you can perhaps use sugarcane, which we have a lot of----
Voice: Understand.
Senator Landrieu [continuing]. As you know.
So, thank you, Mr. Chairman, you've been very generous.
The Chairman. Thank you.
I thank all the witnesses. It's been a useful hearing,
useful testimony. Thank you very much.
That will conclude our hearing.
[Whereupon, at 12 p.m., the hearing was adjourned.]
APPENDIXES
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Appendix I
Responses to Additional Questions
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Responses of Jack Fusco to Questions From Senator Bingaman
Question 1. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what timeframe could that potentially
occur on?
Answer. Under the current House and Senate climate change
legislative proposals, the allowance allocation structure is such that
large-scale switching to natural gas will not take place, particularly
in the near to mid-term timeframe, based on EPA's CO2 price
forecast. Providing allowances to coal-fired generators based on an
updating emissions basis for a long time period dampens the incentive
to switch to cleaner burning resources. Under this structure, our
analysis shows that it will take a carbon price of well over $100 to
motivate switching from coal to natural gas.
Using current projected gas and coal prices, sub-bituminous coal
becomes comparable to gas at a carbon price of $30 per metric ton and
bituminous coal becomes comparable to gas at a carbon price of $25 per
metric ton. This number would increase if a coal facility receives
allowance allocations that are linked to output.
The EPA forecast CO2 allowance prices of $13 in its
June analysis of H.R. . Thus, the EPA's analysis does not suggest
that a ``dash to gas'' would occur (at least initially). Electricity
price increases would be driven by CO2 costs, not by
switching to gas. Switching to gas would actually be electricity price
neutral if CO2 prices reach $25.
Question 2. Reducing the volatility in the price of natural gas is
an important goal if we are to lean more heavily on this resource. For
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce
pricing volatility. Could you describe your willingness to enter into
such long-term contracts, and what obstacles may stand in the way of
them?
Answer. Calpine is willing to enter into long-term contracts for
gas supply. One of the main obstacles standing in the way of long-term
contracts is the regulatory uncertainty for carbon emissions.
Question 3. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. As currently structured, the advanced CCS bonus allocations
are only available for coal-fired generation and qualifying industrial
operations. Additionally, you point out that only a small percentage of
the bonus allowances are available for industrial operations. The
structure of this provision is unfair to natural gas-fired generation.
Preferences should not be given to coal over natural gas or any other
resources. While much cleaner than coal-fired generation (roughly 50%
less CO2), natural gas generation does have carbon emissions
and should benefit from CCS technologies. The provision should be
available equally to coal fired generation, natural gas fired
generation and other industrial operations.
Question 4. You mentioned that you use treated municipal wastewater
at your natural gas fired power plants in the cooling towers. What are
the economic differences between treated waste water and using the
water available through the municipal water supply?
Answer. In general, water from municipal supplies requires less
treatment to be suitable for use in our plants than wastewater sources.
Thus, while cost savings can be obtained by using municipal wastewater,
any savings are site specific. In addition to being economically
viable, the use of recycled wastewater also has a positive
environmental impact--the wastewater is not released into the local
waterways, local freshwater resources are preserved for other
beneficial uses, and there are no fisheries impacts from the use of
recycled wastewater. Our proposed Russell City Energy Center will use
100% reclaimed water from the City of Hayward's Water Pollution Control
Facility which will prevent four million gallons per day of treated
water effluent from being discharged into San Francisco Bay.
Question 5. All of the natural gas discussed at the hearing will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales.
There has been some discussion here in Congress that the Safe
Drinking Water Act exemption for hydraulic fracturing should be
reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. Calpine is in the wholesale electricity generation
business, not the natural gas production business, so we are not in a
position to give an informed opinion on this question.
Question 6. What is the marginal cost of Combined Cycle Gas Turbine
(CCGT) electricity vs. that generated with pulverized coal? At what
price for gas is it lower for CCGT?
How do these numbers compare for old, relatively inefficient coal
plants vs. new gas plants?
Answer. Assuming a $5.00 per MMBtu gas price, a typical CCGT with a
heat rate of 7.0 and a variable operations and maintenance expense
(``VOM'') of $1.05/MWh can generate electricity at approximately $37/
MWh. Assuming a sub-bituminous coal (e.g. Powder River Basin coal)
price of $1.81 per MMBtu and a bituminous coal (e.g. Appalachian coal)
price of 2.71 per MMBtu, a modern sub-bituminous coal plant with a heat
rate of 10.2 and VOM of $2.00/MWh can be used to generate electricity
at approximately $21/MWh and a modern bituminous coal plant with a heat
rate of 9.1 and VOM of $2.75 can be used to generate electricity at
$28/MWh. A CCGT would be more competitive with an older, less efficient
coal plant.
Question 7. How much does conversion from coal to CCGT cost per
megawatt?
Answer. The Energy Information Association (the ``EIA'') does not
provide any guidance on the costs associated with converting a coal-
fired plant to a CCGT; and it is difficult to approximate a generic
cost for switching from coal-fired to gas-fired due to numerous site-
specific issues, including, but not limited to, variances in the
amounts and types of equipment that can be salvaged, obtaining
transportation of gas to the coal plants, and costs associated with
cleaning up the coal plant.
We understand, however, that Xcel Energy recently converted its
Riverside plant in Minnesota from coal-fired to gas-fired for
approximately $536 per kilowatt. For reference, the EIA has calculated
that a typical CCGT costs approximately $ per kilowatt.
In terms of converting the generation stack from coal-fired to gas-
fired, which we have the existing capacity to do, and assuming a $6.00
per MMBtu gas price, gas-fired plants will begin to displace coal on
the generation stack when carbon allowance prices reach $25/ton, and
gas-fired plants will be more economical than almost all coal plants
when carbon allowance prices reach $40/ton.
Question 8. What is the primary obstacle to CHP?
Answer. One of the primary obstacles to CHP is the lack of partners
to contract with for the full power generated from the facilities.
Without a PPA for the surplus electricity it is difficult to get
financing for large-scale CHP projects. In addition, many industrial
facilities already have on-site boilers to produce steam and although
CHP would emit far less CO2, contracting with a new CHP
facility could be more expensive than using an existing boiler. Thus,
incentives are needed to encourage the industrial facilities to make
the switch.
Responses of Jack Fusco to Questions From Senator Murkowski
Question 1. You may know that Senator Menendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports, and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. Because Calpine is in the wholesale electricity generation
business, not the transportation business, we do not have an informed
opinion on this issue.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or, for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. We refer to the testimony of the production experts who
expressed the view that the resource is plentiful and production is far
less difficult than current drilling methods.
Question 3. What would be your opinion about a Low Carbon
Electricity Standard that would allow electric utilities to use a
variety of alternatives to reduce greenhouse gas emissions, including
renewables, natural gas, nuclear and hydroelectric?
Answer. Calpine would support a Low Carbon Electricity Standard
that includes a variety of low and zero GHG emitting resources. As we
move towards a low carbon future, the federal government should be
encouraging the use of all low and zero emitting resources--we can meet
our energy needs by focusing only on renewable resources. Including
natural gas in a Low Carbon Electricity Standard is an excellent means
to encourage the greater use of this resource.
Question 4. To the extent that deliverability of natural gas to
markets has been an issue in the past, should recent improvements in
pipeline infrastructure, as well as prospects for additional projects
coming online, serve as any comfort to those with concerns about spikes
in natural gas prices?
Answer. Yes, the discovery of vast reserves of shale gas as well as
improved infrastructure for bringing gas to the market should dampen
the volatility in natural gas prices.
Question 5. Please give me a sense of the relative challenges in
choosing fuel investments from the perspective of a regulated versus a
non-regulated utility--I understand Xcel is the regulated utility.
Answer. At Calpine we base our investment decisions on customer
electric requirements and the contractual payments needed to provide an
adequate return on investment. We expect to continue to focus our
attention on developing power plants fueled by natural gas and
geothermal energy given our view of environmental responsibility as
well as our knowledge regarding their operation and maintenance. As
noted in my testimony, natural gas fired generation is significantly
cleaner than coal fired generation, In addition, compared to many other
generation sources, natural gas power plants can be permitted and built
more quickly and they have a much smaller footprint. Our expectation is
bolstered by the likelihood that gas-fired capacity will continue to be
the most cost effective form of new, reliable capacity for our
customers.
Question 6. I was interested in Mr. Wilks' testimony about
SmartGrid City in Boulder, Colorado, as well as the solar work that
Xcel is doing in Colorado. Can you talk about why natural gas is so
important as a backup, or baseload generator, for intermittent solar or
wind power?
Answer. The increasing utilization of intermittent electricity
generation resources could have a tremendous impact on the reliability
of the electricity grid. As I noted in my written testimony, Americans
demand and deserve reliable energy; they expect the lights to go on
when they flip the light switch. In the near term, this will only be
achievable if gas-fired plants are there to provide that reliability.
Natural gas power plants are versatile and are designed such that they
can be started quickly and placed into service instantly to meet demand
when the wind stops blowing or the sun stops shining.
Responses of Jack Fusco to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source?
Answer. No comment.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. One of the greatest incentives to enhance the use of
natural gas is to put a price on carbon. Tighter regulations on other
pollutants (e.g. NOX, SO2, mercury, coal ash,
etc.) will also have an impact. Other regulatory changes that could be
implemented to enhance natural gas usage are generation performance
standards and low carbon energy standards. All of these incentives and
regulatory changes will only be effective, however, if the playing
field remains level in terms of incentives and allowance allocation
structures for all fossil fuels.
We do not know what the exact costs associated with the switch
would be, however, switching to gas would actually be electricity price
neutral if CO2 prices reach $25.
Responses of Jack Fusco to Questions From Senator Cantwell
Question 1a. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years, from $5.90 up to $10.82 and then back down to
around $3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what would
actually happen in the real world with regard to fuel mix, energy costs
and investment under this kind of price volatility?
Answer. We believe that natural gas price volatility referenced in
your question was driven in large part by concern of the long-term
availability of domestic natural gas resources. The recent discovery of
vast reserves of shale gas and the improved gas infrastructure should
mute the volatility in natural gas prices.
Question 1b. Could a well-designed price collar mitigate this sort
of volatility?
Answer. A well-designed price collar in a carbon cap-and-trade
regulatory program could mitigate price volatility.
Question 2a. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities.
But an upstream cap for natural gas seems like it could achieve the
same broad coverage much more simply, by regulating less than a
thousand entities. What is the most efficient point of regulation to
achieve broad coverage of fossil carbon for natural gas?
Answer. Calpine believes that an upstream cap on natural gas is the
most efficient point of regulation. By regulating upstream, the cost of
reducing emissions from natural gas combustion is borne by all users of
this resource and the compliance costs are internalized within the
price of natural gas. Upstream regulation also simplifies allowance
allocation distribution as fewer entities are regulated under such a
program. Further, because the number of regulated entities will be much
smaller than regulating at the point of combustion, the cost of
overseeing compliance will be far less.
Question 2b. Are there any problems with mixing upstream caps for
some fossil fuels and downstream caps for others? Does an upstream cap
on all fossil fuels help to promote a consistent, economy-wide carbon
price signal necessary to transition to a low-carbon economy?
Answer. While Calpine believes that an upstream cap on all fossil
fuels is the best and most efficient point for regulation, we do not
think there would be problems with mixing upstream and downstream caps
for different fossil fuels. Because natural gas is used in many diverse
ways (electricity generation, direct home use, industrial processes,
etc), regulating upstream ensures that emissions from all uses are
captured and the compliance costs are lower and spread broadly. Oil is
similar to natural gas with the added factor that it is difficult to
regulate at the tailpipe for all mobile sources, so capping upstream
definitely makes the most sense for oil. Coal, however, is primarily
used for electricity generation so regulating downstream is just as
practical as regulating upstream. Coal-fired power plants are already
under regulation for a variety of air emissions and thus have
experience with complying with emissions reduction programs.
Question 3. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental implications of
the use of technologies such as hydraulic fracturing to produce
unconventional shale gas resources. What are the implications of shale
gas production for ground water and drinking water quality? How do
these environmental risks compare to those of other energy sources?
Also, from an economic perspective, at what price is shale gas
production viable for the industry? Would the price certainty of a
carbon price floor be necessary for shale gas to be economic? How do
the two prices--the natural gas price and the carbon price--interrelate
and affect shale gas production?
Answer. Calpine is in the wholesale electricity generation
business, not the natural gas production business, so we are not in a
position to give an informed opinion on this question.
Question 4. Since natural gas has the lowest carbon content among
fossil fuels, I would expect that a carbon price would not lead to a
decline in the natural gas industry. But over the longer term, as the
economy decarbonizes, there will be pressure on gas-fired utilities, as
with coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial scale
carbon capture and sequestration with natural gas?
Are the economics of CCS likely to be comparable for gas and coal
consumers?
Could reimbursements in the form of allowances in excess of the cap
for the amount of carbon captured and sequestered make CCS economic?
And would this framework treat both coal and natural gas fairly?
Answer. Calpine has not investigated the use of carbon capture and
sequestration (``CCS'') for natural gas generation. However, we are of
the opinion that CCS for combined-cycle natural gas plants is feasible,
in fact potentially more feasible and less expensive than for coal
plants. It will likely be easier to reform natural gas on the front end
into hydrogen (primarily for newer projects). On the back end, the
lower flows and cleaner overall condition of exhaust gas will make it
easier to remove carbon so the per megawatt cost will be less. Most
coal applications will need entirely new facilities. If the playing
field is level, natural gas CCS will be competitive with coal CSS.
As noted, Calpine has not given much consideration to CCS for
natural gas generation so we have not thought through needed incentives
or allowances. However, it is important that CCS incentives and
allowances for coal and natural gas be fair and equal.
Response of Jack Fusco to Question From Senator Lincoln
1. As you know, several recent studies have projected that our
natural gas supply is much larger than previous estimates. For example,
the Potential Gas Committee estimates that the U.S. now has a 35%
increase in supply estimates from just two years ago, which is enough
they say to supply the U.S. market for a century. The Energy
Information Agency (EIA) has also predicted a 99-year natural gas
supply. I am proud that the Fayetteville Shale in Arkansas is already
producing over one billion cubic feet of natural gas per day, while
only in its fifth year of development. What role do you believe the
improvement in drilling technologies such as horizontal drilling and
hydraulic fracturing played in the estimated increase in natural gas
supply?
Answer. Calpine is in the electricity generation business, not the
natural gas production business, so we do not have an informed opinion
this question.
Response of Jack Fusco to Question From Senator Udall
Question 1. It was mentioned that some coal utilities are already
switching over to gas without incentive in place, could you elaborate
on this dynamic? Does low gas price and region play any role in some of
these changes?
Answer. Low gas prices and increasingly stringent environmental
rules have contributed to fuel switching. Last Spring, for instance,
our Southeast plants produced 60% more MWh than during the same period
of . This demonstrates that fuel switching (and corresponding
emissions reductions) is feasible, even in the absence of
CO2 regulations. Although gas prices have been lower than we
expect going forward, the introduction of CO2 regulations
would contribute to fuel switching even at higher gas prices if
structured properly. However, the allowance allocation structure in the
current House and Senate climate change legislative proposals dampens
the incentive to switch to cleaner burning resources, particularly in
the near to mid-term timeframe. Our analysis shows that by providing
allowances to coal-fired generators based on an updating emissions
basis for a long time period, it will take a carbon price of well over
$100 to motivate switching from coal to natural gas.
______
Responses of Dennis McConaghy to Questions From Senator Bingaman
Question 1a. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what timeframe could that potentially
occur on?
Could you please give us a sense of at what carbon price using
natural gas to generate electricity becomes comparable in cost to coal
generation?
Answer. TransCanada has examined a wide range of gas prices and
coal plant efficiencies to arrive at the following general conclusions.
For existing combined cycle and coal plants, with no consideration
of the fixed costs of such plant, gas-fired generation will be lower or
comparable in cost to coal generation when natural gas prices are in
the $6--$8/mmBtu range and carbon prices are in the $20--$40/ton of
CO2 equivalent range. At the low end of the CO2
price range, gas-fired generation becomes higher cost than the more
efficient coal plants.
For new combined cycle and coal plants, with the full cycle costs
of the investment factored in, gas-fired generation still is lower or
comparable in cost to coal generation when natural gas prices are in
the $6--$8/mmBtu range and carbon prices in the $20--$40/ton of
CO2 equivalent range, In the low end of the range of
CO2 prices, gas-fired generation becomes higher cost than
coal when gas prices go beyond $8/mmBtu.
Question 1b. What is the likelihood of a large-scale transition to
natural gas, and what timeframe could that potentially occur on?
Answer. The gas combined cycle fleet in most US markets is the
swing electricity producer and currently operates at approximately 42%
utilization of installed capacity. All other factors being equal,
carbon prices in the $20--$40/ton of CO2 equivalent range
and gas prices in the $6-$8/mmBtu range would result in more of this
capacity being used. For example, if the average utilization factor of
these installed combined cycle units was increased from the current 42%
to 55% with a commensurate reduction in coal generation, demand for
natural gas would increase by an additional 5 Bcf per day--a volume
that can be easily accommodated from a continental supply perspective
while maintaining gas prices in the $6--$8/mmBtu range.
The likelihood of this transition and the timeframe in which it
could occur largely depends upon what the Congress enacts by way of
climate change and energy legislation. If that legislation establishes
a transparent price on carbon that is applied equally to all emitters,
then the transition is likely to occur in relative short order. On the
other hand, if the legislation insulates coal-fired electric generation
from the true costs of controlling greenhouse gas (GHG) emissions the
transition will be much slower and may not occur at all.
Question 2a. One area of concern about depending on our natural gas
resources is that gas has been prone to strong price spikes over the
past decade. The most recent one was just in , with prices soaring
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned
that the expanded reserves and greater ability to receive LNG shipments
could mitigate future price spikes. Please comment on the factors that
resulted in the price spike and other recent spikes. Is the supply
situation now such that we will be insulated from such volatility in
the future? Are there policy options we could pursue to reduce price
volatility?
Please comment on the factors that resulted in the price spike
and other recent spikes.
Answer. The Federal Energy Regulatory Commission (FERC) has
prepared one of the most detailed analyses of that price spike in its
State of the Markets Report, released in August . See http://
www.ferc.gov/market-oversight/st-mkt-ovr/-som-final.pdf. In
general, FERC concluded that, while physical fundamentals of gas supply
and demand can explain why natural gas prices rose during the first
half of , none of the physical fundamentals alone were extreme
enough to explain the high level that natural gas prices reached.
From a study of this FERC report, TransCanada would make the
following observations.
Changes in the physical fundamentals of the market--supply
and demand--are the main drivers of volatility, however,
commodity market activity can, at times, increase the amplitude
of price movements. .
Increased levels of buying interest, easy access to capital,
strongly rising commodity prices in general and trend trading
by financial players all helped push prices higher during the
first six months of .
During the last six months of , reduced levels of buying
interest, lowered liquidity, generally falling commodity prices
and selling pressures all were financial factors that drove
prices down.
In the first half of market perceptions were very
bullish and the market tended to ignore the emerging signs of
unconventional gas supply growth, whereas in the second half,
perceptions became very bearish and the market completely
disregarded the serious impact of the two hurricanes on gas
supply.
With respect to the physical fundamentals in the first half
of , a mildly bullish stance was perhaps justified because
of gas storage levels below recent years due to cold weather
and moderate gas demand growth.
A more bearish stance due to the impact of the spreading
recession on gas demand and the clear evidence of a building
over-supply of domestic gas was certainly appropriate for the
second half of the year.
Question 2b. Is the supply situation now such that we will be
insulated from such volatility in the future?
Answer. TransCanada believes that the robust supplies of natural
gas from shale formations and the Arctic combined with expanded
pipeline, storage, and LNG regasification infrastructure will moderate
price volatility in the future.
Price volatility caused by the physical fundamentals of the market
can be of two types. There is price volatility driven by temporary
imbalances in continental supply and demand. This type of volatility
affects the general level of gas prices across the continent and is
reflected in higher prices at Henry Hub. A second type of volatility is
regional, as opposed to continental. For example, prices in areas of
the U.S. Northeast may spike for periods when storage facilities and/or
transportation facilities are operating at full capacity and are unable
to keep up with demand.
Increased transportation infrastructure out of the Rockies and out
of the key shale plays (supply-connecting pipelines) help ameliorate
continental price volatility by ensuring greater access to more gas
supply.
Increased transportation infrastructure connecting supply pipelines
to markets (market-connecting pipelines), on the other hand, help
reduce regional market price volatility by ensuring that supply reaches
the ultimate consumer.
The natural gas pipeline industry is increasing substantially the
transportation infrastructure needed to help reduce volatility. In
through the first 9 months of miles of pipelines and 39.2
Bcf/day of capacity were added to the nation's pipeline grid.
In addition, substantial increases in gas storage over the past
three years should reduce seasonal volatility in prices. Total U.S. gas
storage capacity has increased by 187 Bcf or 55 per cent over this
period.
It is equally true that the newly important shale gas resource and
the increased investment in pipelines and storage will not eliminate
price volatility. As with other commodities, natural gas will continue
to exhibit price volatility characteristic of well-functioning markets
reflecting supply and demand fundamentals. Natural gas prices will
continue to respond to seasonal changes in demand, hurricane-related
disruptions in supply, unanticipated changes in the demand for natural
gas fired electricity as well as overall demand due to general economic
conditions, and, to reactions of speculative commodity traders to these
events.
TransCanada believes, however, that the size and nature of the
shale resource together with the development of vast Alaskan and
Canadian reserves over the next decade will assure sufficient supplies
to assist in maintaining supply-demand balance for decades to come.
These additional supplies together with sizeable new investments in
pipelines and storage will continue to moderate price volatility in
natural gas markets in the years to come.
Although substantial increases in gas demand over the next decade
will mean somewhat higher prices (compared to a scenario without
durable demand increases), TransCanada believes that the natural gas
industry's continued development of conventional resources together
with distant Alaskan and other Arctic supplies will, together with the
``game-changing'' shale gas resource, mean that prices remain at
reasonable levels and volatility will be moderated.
Question 3. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. As a general proposition, TransCanada questions the
efficacy of using free allowance allocations to provide incentives for
CCS research and development. We recognize the considerable capital
expense required for CCS research and development, but we believe that
a mechanism that establishes a transparent price for carbon combined
with direct subsidies for CCS research and development will be more
effective and economically efficient. Such an approach will allow all
emitters of GHG to determine the best means to control GHG emissions
through CCS technologies and / or fuel-switching and will not mask or
skew the true price of carbon.
If, however, the Congress decides to pursue a program of free
allowances to promote CCS technology, TransCanada recommends that the
current proposals should be modified to create a level playing field
for all fossil fueled facilities that emit GHG.
The Kerry-Boxer and Waxman-Markey bills reserve 85% of the CCS
bonus allowances for coal-fired power plants. This bias in favor of
clearly will discourage other industrial CO2 emitters from
attempting to deploy CCS at their facilities.
In certain situations, facilities other than coal-fired power
plants present more cost-effective and energy-efficient opportunities
to capture and sequester CO2 than coal-fired power plants.
The exhaust streams from natural gas processors and hydrogen producers,
for example, have a higher concentration of carbon dioxide than most
coal-fired power plants--meaning that it is less expensive and less
energy-intensive on a per unit of CO2 to capture
CO2 from these facilities than from a coal-fired power
plant. From an environmental perspective, a ton of sequestered
CO2 is just as beneficial whether it is emitted from a coal-
fired facility or from a facility utilizing natural gas for an
industrial process.
If the CCS bonus allowance program is artificially restricted to
coal-fired facilities, it could end up needlessly spending more
resources to achieve fewer emission reductions than it would absent the
restriction.
Question 4. All of the natural gas we're discussing here today will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales. There has been some discussion here in Congress that
the Safe Drinking Water Act exemption for hydraulic fracturing should
be reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. TransCanada transports natural gas through its pipelines
and consumes natural gas in its electric generation facilities. We are
not involved in the production of natural gas. As such, TransCanada has
had no experience with the regulation of hydraulic fracturing and will
defer to views of BP and other natural gas producers on this issue.
TransCanada does believe, however, that the environmental impacts
of natural gas extraction from tight sands and shale formations can be
managed effectively and efficiently without unduly limiting the
production potential of these sources. To ensure this is the case, the
regulatory process for managing environmental risks must be guided
fundamentally by scientific and technical considerations and must yield
expeditious and predictable results.
Responses of Dennis McConaghy to Questions From Senator Murkowski
Question 1. You may know that Senator Menendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports, and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. TransCanada believes that North American natural gas
reserves are sufficient to support an increase in demand created by a
policies designed to advance the use of natural gas both in the
transportation sector and, more importantly, in the power sector.
Particularly in the short and medium term, TransCanada believes
that emission reductions can be most effectively achieved by moving
from high emission power resources, like coal, to lower emission
resources, like natural gas, nuclear, and renewables. One approach that
TransCanada supports to achieve these reductions is a Low Carbon
Electricity Standard, described in Murkowski Question #3.
With respect to natural gas as a transportation fuel, TransCanada
supports appropriately designed federal policies designed to increase
the use of natural gas as a transportation fuel because such fuel
switching will result in less dependence on crude oil from overseas and
reduced GHG emissions. However, TransCanada strongly recommends that
such policies be limited to the government, commercial and industrial
fleets components of the in the transportation sector. The necessity
for specialized fuel storage and handling equipment in natural gas
vehicles and refueling stations, makes conversion of large numbers of
private automobiles unlikely and prohibitively expensive. By
comparison, incentives and/or mandates targeted at fleet operators are
likely to result in the greatest level of vehicle conversions from
petroleum based fuels to natural gas.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or, for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. TransCanada believes the goals of energy / climate change
legislation should be to reduce the overall level of greenhouse gas
emissions and lessen dependence on fossil fuels imported from overseas
in a manner that is environmentally and economically sound. To
accomplish these goals, it is necessary that the U.S. embrace energy /
climate change policies that allow maximum use of all domestic North
American energy resources as well as encourage greater conservation and
efficiency.
Development and production of energy resources, whether renewable
or fossil fueled, should not be limited arbitrarily. The U.S. energy
industry consistently has demonstrated that it possesses the technology
and experience to effectively and efficiently manage the environmental
risks posed by energy production. The starting point for any debate
over access to and development of a particular area or resource should
be whether the risks posed by such access and development can be
appropriately managed and mitigated. If it is determined that they can,
access and development should be permitted. TransCanada is confident
that if the process for making access and development decisions is
based on sound scientific and technical analysis and designed to yield
expeditious and predictable results, such a process will lead to a
fundamentally well-balanced energy / climate change policy.
Question 3. What would be your opinion about a Low Carbon
Electricity Standard that would allow electric utilities to use a
variety of alternatives to reduce greenhouse gas emissions, including
renewables, natural gas, nuclear and hydroelectric?
Answer. TransCanada believes that if Congress is to pursue a clean
energy mandate either as a stand-alone policy or as a complement to a
cap-and-trade framework, a Low Carbon Electricity Standard (LCES) is a
better policy approach than a standard devoted solely to renewable
energy sources. A broad mandate, like an LCES, provides certainty that
there will be a credible and significant substitution of clean
resources in place of higher emission sources.
Unlike current Renewable Electricity Standard (RES) proposals,
which focus only on achieving a specified percentage of renewable
electricity each year, the LCES would provide an opportunity for a
meaningful down payment on GHG emission reductions by relying on a full
menu of clean energy options, including energy efficiency; renewable
energy; new and incremental nuclear; new and incremental
hydroelectricity; coal with CCS; and high-efficiency natural gas
generation. Any credible climate strategy must include an explicit role
for natural gas. Natural gas is the cleanest domestic fossil fuel. The
carbon content of natural gas is almost 50% less than coal, and it can
be used at substantially greater thermal efficiencies. Natural gas
produces less SOX, NOX, mercury, and particulate
matter than coal. Recent major additions to natural gas reserves mean
that domestic gas will be abundant, affordable, and available for
electric generation.
If Congress cannot reach a consensus on a cap-and-trade climate
change bill, adoption of the LCES would provide a path to increased
energy and environmental security through power resource
diversification. With its broader base of eligible resources, the LCES
would yield more GHG emission reductions and within a shorter time
horizon than an RES due to the difficulties of renewable energy sources
to reach meaningful scale in any near or intermediate term. The LCES
would also provide retail suppliers greater compliance flexibility than
and RES, which in turn would help keep power prices lower in comparison
to an RES. While an RES may point us in the right direction, the LCES
would actually achieve tangible progress in our efforts to address
climate change while also advancing development of renewable energy.
In the context of a cap-and-trade bill that allocates a significant
percentage of free allowances, an LCES would provide all the benefits
described above plus act as a meaningful balance to free -allowance
incentives to continue to burn higher emission resources like coal.
Free allowances not only minimize the incentive to reduce emissions,
but they also distort the price of carbon. In the early years of a cap-
and-trade program with a large distribution of free allocations, it is
likely that allowance prices may not be high enough to encourage
deployment of low-carbon generation. Without the additional policy
determinations embodied in the LCES, it is unlikely the electric power
sector will have the economic motivation to make the investments in low
carbon technology necessary to address in any significant way actual
reductions in carbon emissions; an RES alone would only partially
address this risk.
If the primary goal of energy and climate legislation is to
increase security and reduce GHG emissions, then adoption of a low
carbon standard will make a real down payment on a clean energy future
by weighting technologies by their carbon content. Limiting that down
payment to a subset of only a few renewable clean power choices, such
as with an RES, would be short changing and unnecessarily delaying our
clean energy future.
Question 4. To the extent that deliverability of natural gas to
markets has been an issue in the past, should recent improvements in
pipeline infrastructure, as well as prospects for additional projects
coming online, serve as any comfort to those with concerns about spikes
in natural gas prices?
Answer. The past and projected expansion of natural gas pipelines
certainly plays an important role in reducing price volatility by
improving the deliverability of additional supplies into major
consuming markets. Indeed, the multi-billion dollar expansion of the
Nation's pipeline infrastructure underscores the confidence of the
natural gas markets in the ``game changer'' character of the shale
reserves as well as the prolific Rocky Mountain reserves. Even with
expanded pipelines, however, not all volatility can be eliminated.
Price volatility caused by the physical fundamentals of the market
can be of two types. There is price volatility driven by temporary
imbalances in continental supply and demand. This type of volatility
affects the general level of gas prices across the continent and is
reflected in higher prices at Henry Hub. A second type of volatility is
regional, as opposed to continental. For example, prices in areas of
the U.S. Northeast may spike for periods when storage facilities and/or
transportation facilities are operating at full capacity and are unable
to keep up with demand.
Increased transportation infrastructure out of the Rockies and out
of the key shale plays (supply-connecting pipelines) help ameliorate
continental price volatility by ensuring greater access to more gas
supply.
Increased transportation infrastructure connecting supply pipelines
to markets (market-connecting pipelines), on the other hand, help
reduce regional market price volatility by ensuring that supply reaches
the ultimate consumer.
The natural gas pipeline industry is increasing substantially the
transportation infrastructure needed to help reduce volatility. In
through the first 9 months of miles of pipelines and 39.2
Bcf/day of capacity were added o the nation's pipeline grid.
In addition, substantial increases in gas storage over the past
three years should reduce seasonal volatility in prices. Total U.S. gas
storage capacity has increased by 187 Bcf or 55 per cent over this
period.
Although new gas supplies and expanded infrastructure will moderate
price volatility, TransCanada believes that it is equally true that
they will not eliminate price volatility. As with other commodities,
natural gas will continue to exhibit price volatility characteristic of
well-functioning markets reflecting supply and demand fundamentals.
Natural gas prices will continue to respond to seasonal changes in
demand, hurricane-related disruptions in supply, unanticipated changes
in the demand for natural gas fired electricity as well as overall
demand due to general economic conditions, and, to reactions of
speculative commodity traders to these events.
TransCanada believes, however, that the size and nature of the
shale resource together with the development of vast Alaskan and
Canadian reserves over the next decade will assure sufficient supplies
to assist in maintaining supply-demand balance for decades to come.
These additional supplies together with sizeable new investments in
pipelines and storage will continue to moderate price volatility in
natural gas markets in the years to come.
Although substantial increases in gas demand over the next decade
will mean somewhat higher prices (compared to a scenario without
durable demand increases), TransCanada believes that the natural gas
industries continued development of conventional resources together
with distant Alaskan and other Arctic supplies will, together with the
``game-changing'' shale gas resource will mean that prices will remain
moderate and that volatility will also exhibit characteristics of
moderation.
Responses of Dennis McConaghy to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source?
Answer. TransCanada believes that North American natural gas
reserves are sufficient to support an increase in demand created by a
policies designed to advance the use of natural gas both in the
transportation sector and, more importantly, in the power sector.
Particularly in the short and medium term, TransCanada believes
that emission reductions can be most effectively achieved by moving
from high emission power resources, like coal, to lower emission
resources, like natural gas, nuclear, and renewables. One approach that
TransCanada supports to achieve these reductions is a Low Carbon
Electricity Standard, described in Murkowski Question #3.
With respect to natural gas as a transportation fuel, TransCanada
supports appropriately designed federal policies designed to increase
the use of natural gas as a transportation fuel. Greater use of natural
gas as a transportation fuel will also reduce the United States'
dependence on crude oil imports and the level of emissions of
greenhouse gases from the transportation sector. The degree to which
these reductions occur will depend upon the level of vehicle
conversions that occur.
TransCanada strongly recommends that policies promoting the use of
natural gas for vehicle use be limited to government, commercial and
industrial fleets components of the in the transportation sector. The
necessity for specialized fuel storage and handling equipment in
natural gas vehicles and refueling stations, makes conversion of large
numbers of private automobiles unlikely and prohibitively expensive. By
comparison, incentives and/or mandates targeted at fleet operators are
likely to result in the greatest level of vehicle conversions from
petroleum based fuels to natural gas.
With respect to increased gas demand for fleet vehicle use,
TransCanada believes that such an increase in natural gas demand is not
sufficient to have a material impact on gas prices. Although any
increase in gas demand, other things equal, will increase price, the
volumes in this instance will be small to modest and slow to build as
infrastructure is added and vehicles replaced. Consequently, the
increase in price related to more use of natural gas by fleets should
be insignificant.
As noted above, in the absence of an increase in supply of natural
gas, any policy that increases demand will result in an increase in the
price of natural gas. However, TransCanada believes that the
significantly improved methods of economically and efficiently
producing natural gas from shale formations, complemented by the likely
introduction of Arctic reserves, have fundamentally changed the
continental natural gas supply outlook. These robust supplies will
support and respond to a substantial increase in natural gas demand
that is driven by policies designed to advance the use of natural gas
as a transportation fuel without greatly affecting the price of natural
gas. As we testified at the hearing, TransCanada believes that a
natural gas price in the $6--$8/mmBTU range is likely to achieve
equilibrium between ensuring development and production of natural gas
supplies and increasing demand.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. TransCanada has not conducted any direct study or analysis
of regulatory barriers to increasing use of natural gas in the
transportation sector and therefore is not in a position to offer any
recommendations in that regard. Similarly, TransCanada has not invested
any resources in exploring potential incentives to enhance the use of
natural gas in the transportation sector.
Responses of Dennis McConaghy to Questions From Senator Cantwell
Question 1. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years, from $5.90 up to $10.82 and then back down to
around $3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what would
actually happen in the real world with regard to fuel mix, energy costs
and investment under this kind of price volatility?
Could a well-designed price collar mitigate this sort of
volatility?
Answer. TransCanada acknowledges that extreme volatility in energy
prices can cause hardship for businesses and households. However, all
commodity markets--no matter how well-regulated--are susceptible to
some degree of volatility, and the natural gas market is no exception.
Rather than engage in a futile attempt to stamp out volatility in
energy markets, sound energy policy should seek to ensure that prices
reflect genuine forces of supply and demand and well-functioning
competitive markets. Without taking any position here on pending
legislation, TransCanada notes that both the Senate and the House of
Representatives have been actively pursuing legislation--in addition to
the market manipulation provisions you spearheaded in the Energy Policy
Act of --to prevent misconduct in the commodity derivatives
markets. If properly designed, such legislation should provide
additional transparency in a well-functioning market in energy
commodities, including natural gas.
In addition, as discussed elsewhere in these responses, recent
developments in natural gas supply and transportation infrastructure
should avert a recurrence of the rapid increase in natural gas prices
observed from -. Indeed, the key to moderating volatility is
maintaining reasonable balance between supply and demand. The
referenced price run-up was caused in part, not by a lack of supply,
but by a lack of pipeline capacity to satisfy growing demand for
natural gas during this period. Since , the natural gas supply and
delivery situation has changed dramatically.
The unprecedented expansion of the U.S. gas pipeline network in
, and the simultaneous expansion of U.S. gas reserves, should
moderate price volatility in the gas markets with supply being
delivered to consuming markets and should reduce the chance of a
similar supply constraint in the foreseeable future. Of course, the
recent dramatic decline in prices in and is due in part to
increased supply hitting the market at the same time demand has been
weakened by the general economic situation.
TransCanada submits that most observers believe that the natural
gas markets are well-functioning and that periods of price volatility
have been of relative short duration and a function of supply-and-
demand situations that generally correct quickly either with resolution
of supply interruption, break in a cold snap or greater supply
responding to greater demand as reflected in price increases.
TransCanada interprets the question regarding the efficacy of a
price collar as applying to a price collar on carbon prices; we assume
that it is not a reference to price collars on natural gas. TransCanada
believes that any attempt to regulate the price of natural gas, whether
through a price collar or otherwise, would lead to extreme disruptions
in the market.
TransCanada does believe that price predictability in carbon
pricing is warranted and deserves closer scrutiny by the Congress. If
the cost of purchasing CO2 emission allowances in a cap-and-
trade program is reflected in the unit price of energy delivered to
consumers, then volatility in the CO2 allowance market has
the potential to add to overall volatility in energy markets generally.
A ``price collar'' mechanism that places a firm ceiling and a firm
floor on allowance will help mitigate or avoid this additional
volatility in energy prices, by reducing volatility in the component of
energy prices that is attributable to emission allowances. TransCanada
strongly supports efforts to provide type of stability and
predictability to any carbon price.
In TransCanada's opinion, which is shared by a number of economists
and industry participants, a carbon tax that sets a specific price for
carbon would be the most efficient method to address GHG emissions. If
the paramount goal is to set a clear price on carbon to induce
behaviors that reduce GHG emissions, then a carbon tax would arguably
be the clearest path to achieving that goal. A properly set and
maintained carbon tax would incent GHG reductions, provide businesses
certainty, and would not create the degree of administrative difficulty
that can be anticipated under a that a cap-and-trade / offsets program
regime.
Question 2. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities.
But an upstream cap for natural gas seems like it could achieve the
same broad coverage much more simply, by regulating less than a
thousand entities. What is the most efficient point of regulation to
achieve broad coverage of fossil carbon for natural gas?
Are there any problems with mixing upstream caps for some fossil
fuels and downstream caps for others? Does an upstream cap on all
fossil fuels help to promote a consistent, economy-wide carbon price
signal necessary to transition to a low-carbon economy?
Answer. The optimal point of regulation in a cap-and-trade program
is one that (a) covers an adequate proportion of greenhouse gas
emissions, (b) affects a manageable number of carbon-regulated
entities, and (c) transmits an appropriate price signal to consumers of
carbon-intensive fuels and products. There is no reason to believe that
the best point of regulation will be the same for all fossil fuels,
given that each fuel has a different supply chain and market structure.
Indeed, both the Waxman-Markey and Kerry-Boxer climate change bills
recognize the need for a nuanced point of regulation by specifying an
``upstream'' point of regulation for some fossil fuels (such as
petroleum-based liquid fuels) and a ``downstream'' point of regulation
for others (large users of coal and natural gas).
In the case of natural gas, TransCanada believes that a
``downstream'' point of regulation (at the point of emission) is
generally most appropriate. Making upstream producers of natural gas
accountable for GHG emissions from gas combustion would introduce
several significant problems. First, there are several hundred thousand
facilities that produce natural gas in the United States, making an
allowance requirement difficult to administer at the point of natural
gas production. Second, natural gas has substantial uses (as a chemical
feedstock, for example) that do not result in GHG emissions--meaning
that an ``upstream'' point of regulation would require a supplemental
mechanism for thousands of natural gas users to claim a rebate for non-
emissive uses of natural gas. Pipelines are an inappropriate point of
regulation for the same reasons, but also because the complexity of
pipeline networks makes it difficult to define a pipeline point of
regulation that would avoid double-counting (or under-counting) natural
gas emissions.
By contrast, a ``downstream'' point of regulation for natural gas
would still affect a limited number of large entities (such as power
plants and large industrial users of natural gas), while ensuring that
non-emissive uses of natural gas do not fall under the cap. For the
numerous residential and commercial consumers of natural gas, the most
efficient point of regulation is probably at the local distribution
company (LDC). This is more or less the approach taken in the Kerry-
Boxer and Waxman-Markey bill, and--according to a recent study by the
Pew Center on Global Climate Change\1\--would cover 95% of
CO2 emissions from natural gas while affecting a reasonable
number of facilities.
---------------------------------------------------------------------------
\1\ Joel Bluestein, Coverage of Natural Gas Emissions and Flows
Under a Greenhouse Gas Cap-and-Trade Program (Pew Center on Global
Climate Change, December ) http://www.pewclimate.org/docUploads/
NaturalGasPointofRegulation09.pdf.
---------------------------------------------------------------------------
In the case of natural gas markets, however, regulation of large
emitters of combusted natural gas does present some significant issues
for regulated entities to recover allowance costs and to avoid
duplicative, diverse state programs. Thus, while a purely upstream
point of regulation for natural gas may avoid some of the recovery
issues for downstream regulated entities, TransCanada believes these
transition issues can be address with a clear statutory provision
directing regulators to all for tracking of carbon allowance compliance
costs as well as a strong pre-emption provision which preempts not only
individual state efforts to further regulate carbon emissions but also
preempts the EPA from any further regulation of carbon emissions under
the Clean Air Act or any other federal statute or regulation.
Question 3. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental implications of
the use of technologies such as hydraulic fracturing to produce
unconventional shale gas resources. What are the implications of shale
gas production for ground water and drinking water quality? How do
these environmental risks compare to those of other energy sources?
Also, from an economic perspective, at what price is shale gas
production viable for the industry? Would the price certainty of a
carbon price floor be necessary for shale gas to be economic? How do
the two prices--the natural gas price and the carbon price--interrelate
and affect shale gas production?
Answer. TransCanada transports natural gas through its pipelines
and consumes natural gas in its electric generation facilities. We are
not involved in the production of natural gas. As such, TransCanada has
had no experience with the regulation of hydraulic fracturing and will
defer to views of BP and other natural gas producers on this issue.
TransCanada does believe, however, that the environmental impacts
of natural gas extraction from tight sands and shale formations can be
managed effectively and efficiently without unduly limiting the
production potential of these sources. To ensure this is the case, the
regulatory process for managing environmental risks must be guided
fundamentally by scientific and technical considerations and must yield
expeditious and predictable results.
There are many different shale plays in the US and across the
continent. These plays differ in their production economics. Even
within individual plays there are substantial differences in the cost
of production depending on exact location. Furthermore, some shale
formations (e.g. the Marcellus) are closer to market and, consequently,
receive higher net back prices than other, more remote shales.
TransCanada believes that at a gas price of $6 to $8/mmBtu range
shale gas will make a large and growing contribution to US and
continental supply over the next decade and beyond. We also believe
that this price range generally can be maintained in the absence of
very high carbon prices.
It is not clear that a carbon price, by itself, will improve the
economics of shale gas or natural gas in general. Indeed, TransCanada's
assessment is that the Waxman / Markey bill does not increase the
demand for gas and therefore does not improve the economics of gas.
This is because, under the bill, alternatives to natural gas either
receive substantial incentives or are insulated from true carbon
prices, or both, leaving little or no scope for increases in natural
gas demand.
The interplay between carbon prices and natural gas prices is both
direct and indirect. First, the carbon price as it applies to natural
gas increases the gas price to the consumer but not for the producer.
Second, there can be an indirect affect. Institution of any system that
results in carbon prices of $30 per ton or more, if applied to all
fossil fuels completely and equally, have the potential to cause
switching of natural gas for coal. The extent of switching will depend
primarily on the price of natural gas and the magnitude of the carbon
price.
Question 4. Since natural gas has the lowest carbon content among
fossil fuels, I would expect that a carbon price would not lead to a
decline in the natural gas industry. But over the longer term, as the
economy decarbonizes, there will be pressure on gas-fired utilities, as
with coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial scale
carbon capture and sequestration with natural gas?
Are the economics of CCS likely to be comparable for gas and coal
consumers?
Could reimbursements in the form of allowances in excess of the cap
for the amount of carbon captured and sequestered make CCS economic?
And would this framework treat both coal and natural gas fairly?
Answer. TransCanada has been actively involved in the study and
development of CCS projects for the past 5 to 6 years. Our involvement
has included front end development on both pre-combustion capture and
post combustion capture plants fuelled with varied grades of petcoke
and coal. TransCanada has also been involved in a number of industry
and government committees and initiatives which focused on CCS
technologies, costs and policy.
TransCanada's experience in developing pre-combustion capture of
CO2 through proven gasification technology indicates that in
order to recover costs on the CO2 capture portion of a
facility in today's markets, carbon prices in the range of $90 to $150
per ton would be required. The range of cost is related to the
technology employed, whether the facility produced a single product
(e.g. electricity or hydrogen--$150 pre ton) or multiple products (i.e.
polygeneration--$90 per ton) and the market price for natural gas. The
current natural gas price forecasts of $6-8/mmBtu push the carbon price
very high as natural gas pricing has an inverse effect on the price of
carbon. The reason for this is that the outputs from gasification (e.g.
electricity, hydrogen, synthetic natural gas) are currently produced
using natural gas as the primary feedstock and output from a
gasification process would be required to compete with the prevailing
market price of natural gas.
TransCanada's experience in developing post-combustion capture of
CO2 is gained through our exposure to the capture of 20%
CO2 from an existing sub-critical coal plant in Alberta. Our
work indicated that carbon prices in the range of $150-$200 per ton
would be required in order to recover costs on post combustion
CO2 capture facilities. The higher carbon price over
gasification based technologies is required due to the lower pressure
and less concentrated CO2 stream leaving a post combustion
plant. This requires larger equipment and more compression horsepower
over a gasification facility. Our carbon costs also account for
parasitic electrical and steam load loss from the base plant.
There has been some discussion regarding utilizing captured
CO2 for application in enhanced oil recovery (EOR)
operations. The total cost of carbon required does not change in this
application but the economic value attached to CO2 for EOR
application can offset a portion of the total carbon price required.
The following table demonstrates some key comparative carbon cost
findings TransCanada has made as part of our CCS experience. This shows
that the lowest cost of emissions reduction results from the
utilization of natural gas itself without carbon capture. Natural gas
based power production will result in an emission reduction of
approximately 60% compared to a coal plant utilizing sub-critical coal
with no capture.
------------------------------------------------------------------------
Capture Cost
Plant Carbon Natural ($/ton
reduction Gas Price captured)
------------------------------------------------------------------------
SubCritical Coal (Baseline) baseline $6-8 N/A
------------------------------------------------------------------------
Add on 20% Post Combustion 20% $6-8 $150-$200
Capture
------------------------------------------------------------------------
New Natural Gas Combined Cycle 60% $6-8 $0
------------------------------------------------------------------------
Polygeneration/IGCC with 90% 90% $6-8 $90-$150
Capture
------------------------------------------------------------------------
With respect to the question regarding the use of allowances for
CCS, TransCanada questions the efficacy of using free allowance
allocations to provide incentives for CCS research and development. We
recognize the considerable capital expense required for CCS research
and development, but we believe that a mechanism that establishes a
transparent price for carbon combined with direct subsidies for CCS
research and development will be more effective and economically
efficient. Such an approach will allow all emitters of GHG to determine
the best means to control GHG emissions through CCS technologies and /
or fuel-switching and will not mask or skew the true price of carbon.
If, however, the Congress decides to pursue a program of free
allowances to promote CCS technology, TransCanada recommends that the
current proposals should be modified to create a level playing field
for all fossil fueled facilities that emit GHG.
The Kerry-Boxer and Waxman-Markey bills reserve 85% of the CCS
bonus allowances for coal-fired power plants. This bias in favor of
clearly will discourage other industrial CO2 emitters from
attempting to deploy CCS at their facilities.
In certain situations, facilities other than coal-fired power
plants present more cost-effective and energy-efficient opportunities
to capture and sequester CO2 than coal-fired power plants.
The exhaust streams from natural gas processors and hydrogen producers,
for example, have a higher concentration of carbon dioxide than most
coal-fired power plants - meaning that it is less expensive and less
energy-intensive on a per unit of CO2 to capture
CO2 from these facilities than from a coal-fired power
plant. From an environmental perspective, a ton of sequestered
CO2 is just as beneficial whether it is emitted from a coal-
fired facility or from a facility utilizing natural gas for an
industrial process.
If the CCS bonus allowance program is artificially restricted to
coal-fired facilities, it could end up needlessly spending more
resources to achieve fewer emission reductions than it would absent the
restriction.
Response of Dennis McConaghy to Question From Mark Udall
Question 1. You mentioned that the new gas shale resources would
provide a more stable resource than traditional natural gas resources,
thereby reducing the volatility in gas prices. Specifically you
mentioned that gas shale is a different kind of resource and that
geology is less of an issue. Could you please elaborate more on this?
Answer. TransCanada does believe that the natural gas industry will
be able to develop sufficient natural gas supplies to support increased
use of natural gas in the electricity sector as well as the
transportation sector. This supply will come from continued
technological developments which will support production of both
conventional and unconventional supplies.
Shale production, in particular, is a ``game changer'' in terms of
natural gas supplies. Because producers generally know where shale
reserves are located they are not confronted with the same ``finding''
risk that exists in the case of conventional natural gas reserves.
Rather, the limitations on shale gas supply are ``production'' risks.
In this regard, production of shale gas is similar to a ``manufacturing
process''. A vertical well is drilled into a shale formation and then
the formation is drilled horizontally. This technique permits multiple
perforations along a horizontal axis as opposed to conventional
vertical perforations through gas bearing formations. With horizontal
drilling and horizontal completions, the odds of increasing production
are dramatically higher.
With non conventional gas, specifically shale gas, vast amounts of
resource have been identified. If prices spike, increased drilling can
occur immediately (i.e. additional ``manufacturing'' assembly lines can
be added) and result in timely increases in gas supply. With horizontal
drilling, the exploration process at the front end is not required.
Responses of David Wilks to Questions From Senator Bingaman
Question 1. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what timeframe could that potentially
occur on?
Answer. With the imposition of a CO2 allowance price,
the costs to operate all fossil resources will increase, but to varying
extent depending on each fuel's carbon intensity (emissions per MWh).
Efficient combined cycle natural gas has approximately half or less of
the emissions per MWh of typical pulverized coal-fired power
generation. Thus, although the cost of gas generation will increase
with the cost of CO2, the CO2 cost impact on coal
generation will be approximately twice as much.
The CO2 allowance price at which using natural gas to
generate electricity becomes comparable in cost to coal generation is
intuitively the price at which all costs--capital, O&M, fuel, and
carbon costs--sum to the same $/MWh for coal and gas. Natural gas tends
to have lower capital, higher fuel, and approximately half the carbon
costs of coal. In theory, at a high enough CO2 price, gas
could push coal out of the dispatch order even though gas also must
hold allowances. The exact carbon price at which this substitution
could occur is hard to predict, and will depend on a variety of
factors, including (1) the projected cost of natural gas; (2) the
projected cost of coal; and (3) the efficiency and operating costs of
existing coal facilities and any replacement natural gas facilities.
For specific carbon values at which the cost to generate
electricity with natural gas is equivalent to coal fired generation,
the time frame needs to be considered. In the near-term, coal to
natural gas switching would occur through the re-dispatching of the
existing generation fleet and would occur economically (when it is less
expensive to generate electricity from natural gas rather than coal)
with a CO2 cost of roughly $45/ton depending on specific
plant characteristics and assuming, among other things, $7.00/MMBtu
natural gas.
In the intermediate term, when new construction is required to meet
electricity generation needs, capital costs and utilization of the
plant must be considered in the natural gas vs. coal assessment. In a
scenario where natural gas generation displaces coal generation, the
utilization of each plant type would change from current levels and by
extension the cost per unit of electricity would change as the fixed
costs are spread over greater (gas) or fewer (coal) units of
electricity. The amount of potential displacement would vary depending
on capital costs, fuel costs and the details of the system in which the
plant operates. Using current utilization rates the break-even
CO2 cost for new natural gas generation vs. new coal
generation is roughly $25/ton assuming, among other things, $7.00/MMBtu
gas.
In both examples, the CO2 ``break-even'' cost is
sensitive to natural gas prices where a $1 increase in natural gas
prices would add roughly $10--$12/ton to the CO2 ``break-
even'' cost.
As I testified, the retirement of at least some coal plants and
increased reliance on natural gas for electricity generation is an
inevitable result of a cap and trade program. The likelihood and timing
of a large-scale transition to natural gas for baseload power
generation, however, depends on many factors other than the price of
CO2 allowances. Recent advancements in unlocking shale gas
will increase economically recoverable supplies and could reduce gas
price volatility; however, at the moment, there are a number of
regulatory uncertainties as well as uncertainty about what gas price is
needed to incentivize shale gas exploration and production. Expanded
use of natural gas for power generation, vehicles, intermittent
renewable energy balancing, and other demands will put upward pressure
on prices. Under CO2 regulation it seems likely that there
will be increased reliance on natural gas for power generation in the
early years of the program, particularly if carbon offsets are in short
supply,\1\ but beyond natural gas generation could again decrease
as carbon capture and storage (CCS) technologies for coal become
commercial and with possible investments in new nuclear generating
capacity. Also, achieving CO2 emission reductions of around
80% by will not be possible even by replacing all coal generation
with gas. Thus, increased natural gas power generation appears to be a
``bridge'' strategy that would begin immediately and continue through
or , and the magnitude of this change will probably depend on
the availability and timing of carbon offsets, CCS and other low-and
zero-carbon generation technologies. At the same time, as our own
experience with the Minnesota Emission Reduction Program demonstrates,
state policies can promote earlier retirement of coal and replacement
with natural gas in some circumstances independent of any federal
climate change strategy.
---------------------------------------------------------------------------
\1\ As suggested in the USDOE Energy Information Administration's
analysis of the energy market and economic impacts of H.R. , the
American Clean Energy and Security Act of . See http://
www.eia.doe.gov/oiaf/servicerpt/hr/index.html. Only in EIA's
scenarios in which offsets and technology are constrained did the
electric sector use significantly more gas and less coal than in the
reference case by .
---------------------------------------------------------------------------
Question 2. One area of concern about depending on natural gas
resources is that gas has been prone to strong price spikes over the
past decade. The most recent one was just in , with prices soaring
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned
that the expanded reserves and greater ability to receive LNG shipments
could mitigate future price spikes. Please comment on the factors that
resulted in the price spike and other recent spikes. Is the supply
situation now such that we will be insulated from such volatility in
the future? Are there policy options we could pursue to reduce price
volatility?
Answer. There have been three significant price spikes in the past
decade. The first one occurred in December when NYMEX prices
spiked to just under $10.00 per million British thermal units (mmBtu).
This price spike was a result of an extremely cold start to the winter
heating season and below average storage levels. The second price spike
occurred in the fall of when the combination of hurricanes Katrina
and Rita disrupted a significant amount of production in the Gulf of
Mexico and NYMEX prices spiked as to just over $14.00 per mmBtu. The
third spike occurred in June and July of when prices spiked to
over $13.00 per mmBtu. However this one was unique as there was no
obvious underlying disruption in the natural gas market that would
account for the price spike.
The expanded reserves associated with shale gas and the ability of
the nation to receive larger quantities of LNG should insulate the
market from extended periods of extreme volatility, but they cannot
eliminate the possibility of price spikes altogether due to the lag
times associated with drilling activity in order to access the expanded
reserves and the global market forces that drive the pricing of LNG.
Below are four policies that could reduce natural gas price
volatility:
First, Congress should encourage practices by state
regulators and large players in the natural gas market that
result in a more stable, predictable price. In addition to
ensuring that companies that trade in natural gas markets do
not engage in abusive trading practices, Congress should
encourage utilities to use, and state regulators to allow,
prudent and appropriate hedging strategies.
Second, as I testified, climate policy will inevitably rely
in part on repowering of existing coal plants to natural gas. A
volatile carbon dioxide allowance price could exacerbate the
volatility of natural gas prices. In designing climate policy,
Congress should use price collars and other mechanisms to
control the volatility of the price of a carbon dioxide
allowance. Such mechanisms will assist in controlling the
volatility of natural gas prices.
Third, adopting a policy that would encourage the
development of additional storage facilities or the expansion
of existing facilities would have the potential to limit future
price volatility. The development of additional storage
capacity would provide a supply buffer to help offset periodic
disruptions of supply or periods of increased demand and in
addition it could act as balancing mechanism for the physical
market during periods of excess production.
Finally, the best way to avoid volatility of natural gas
prices is to assure a stable supply and reduce the barriers to
development of new natural gas resources. Even with expanded
supply options, sudden changes in demand for natural gas could
result in a significant short-term increase in natural gas
prices unless natural gas supply can rise to meet that demand.
Congress should avoid creating unnecessary permitting barriers
to the development of both conventional and shale gas, as well
as pipelines and other supporting infrastructure.
Question 3. Reducing the volatility of the price of natural gas is
an important goal if we are to lean more heavily on this resource. For
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce
pricing volatility. Could you describe your willingness to enter into
such long-term contracts, and what obstacles may stand in the way of
them?
Answer. Long-term commitments for gas supply at a fixed price could
alleviate concerns related to fuel price changes over the long term for
a generating unit or group of units. Fixed price contracts eliminate
the opportunity for upside market price movement for the seller and the
benefit of lower market prices for the utility. State regulated
utilities must be prudent in fuel purchase decisions and utilities
would need the support of regulators to commit to long-term contracts
that could be priced above the spot market in the future. Long-term
contracts would need to address security issues related to financial
performance through collateral or margin posting as well as the
commitment of both parties to perform operationally. If satisfactory
contractual and regulatory arrangements could be implemented, Xcel
Energy would be interested in long term fixed price contracts for
natural gas.
Question 4. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. In our opinion:
The advanced bonus allocations under the Kerry/Boxer bill
are enough to jumpstart the deployment of CCS, and such a
provision is an important feature of any policy to address
major emission sources of CO2. However, the key
phrase of the question is ``broad deployment.'' Kerry/Boxer's
incentives and advanced allocation will increase certainty, buy
down the cost of CCS, and help make fossil-fueled facilities
with CCS more competitive, but only within the limits set in
the bill regarding percentage of allowances provided, economic
value of the bonus to an individual project, and overall
capacity threshold. The larger issues are (1) whether the
support provided to CCS is sufficient considering the cost of
sequestration and regulatory requirements yet to be
established, and (2) whether the support is sufficient to
create the impetus for CCS technological advances that will, in
time, make CCS economically viable beyond the scope of the
bonus program. These issues remain to be determined and will
require continuing evaluation and possible adjustment to the
program in the future.
Coal is the major source of CO2 emissions and
directing 85% of the advance allocations toward coal appears
sensible. Moreover, the experience gained and technology
improvements achieved applying CCS to coal will also be of
significant value in enabling CCS in the gas industry and other
industrial stationary source emitters.
Question 5. All of the natural gas we're discussing here today will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales. There has been some discussion here in Congress that
the Safe Drinking Water Act exemption for hydraulic fracturing should
be reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. Xcel Energy is not involved in the natural gas extraction
industry. We have no direct experience with the hydraulic fracturing
and production of natural gas from conventional or unconventional
resources. We have no experience to allow us to comment on the impact a
repeal of the Safe Water Drinking Act hydraulic fracturing exemption
may have on the natural gas extraction industry. As a significant
participant in the purchasing of natural gas, however, we are concerned
that any change to the regulations governing the development of
unconventional gas may create significant and sustained challenges to
the production of natural gas from shale formations. These in turn may
have an impact on the volatility of the market price for natural gas.
Consequently, we encourage Congress to consider whether the
environmental benefits of additional regulation of hydraulic fracturing
would outweigh the lost environmental and potential economic
opportunity associated with expanded gas production.
Question 6. What is the marginal cost of Combined Cycle Gas Turbine
(CCGT) electricity vs. that generated with pulverized coal? At what
price for gas is it lower for CCGT? How do these numbers compare for
old, relatively inefficient coal plants vs. new gas plants?
Answer. The term marginal cost is typically used to describe the
cost to operate an electric generating plant which includes the cost of
fuel and certain operations and maintenance (O&M) costs. The CCGT
plants operating on Xcel Energy's systems today would typically
generate electricity in the neighborhood of $50/MWh to $55/MWh (burning
$7.00/MMBtu natural gas). In comparison, Xcel Energy's pulverized coal
plants typically generate electricity in the range of $12/MWh to $20/
MWh depending on coal type. In both the CCGT and pulverized coal values
above, approximately 90% of these costs are associated with the fuel
and the remaining 10% are related to O&M. Note that these costs do not
include the capital cost required to construct the plants nor do they
include any cost for CO2.
When the capital costs to construct new generating plants are
factored into the pricing (creating an ``all-in'' cost), the CCGT costs
are in the $80-$85/MWh range (at 50% capacity factor) with pulverized
coal falling in the range of $55/MWh to $65/MWh (at 90% capacity
factor). These pricing estimates assume the capital cost of a new CCGT
to be in the range of $800-$/kW of nameplate generating capacity
and a new pulverized coal unit (without carbon capture) to be in the
range of $-$/kW of nameplate generating capacity.
These $/MWh ``all-in'' cost estimates are heavily dependent on how
often the unit is utilized. The basic cost characteristics of thermal
generation resource technologies are illustrated in the following
table.
------------------------------------------------------------------------
Gas Turbine
Costs (GT) CCGT Coal
------------------------------------------------------------------------
Capital Costs Low Mid High
------------------------------------------------------------------------
Operating Costs High Mid Low
------------------------------------------------------------------------
Intended Use Peaking Intermedia Baseload
te
------------------------------------------------------------------------
Hours of Use Low Medium High
------------------------------------------------------------------------
The figure* below provides an illustration of how the general cost
characteristics of GT, gas CCGT, and coal generators might compare with
one another based on how they are utilized (i.e., peaking,
intermediate, or baseload) on the system. The figure shows that the
``all-in'' cost of electric energy per MWh depends highly on the number
of hours a unit is operated, (i.e., the unit's capacity factor). The
``all-in'' cost curves decline as the fixed costs (capital and fixed
O&M) are distributed over more hours of operation.
---------------------------------------------------------------------------
* Graph has been retained in committee files.
---------------------------------------------------------------------------
Assuming the mid-point of $60/MWh for the ``all-in'' cost from a
new pulverized coal plant described above, a new CCGT with capital
costs of $900/kW and operating at a 50% capacity factor would have an
``all-in'' cost of $60/MWh at a gas price of approximately $4.00/MMBtu.
While older coal plants may be relatively inefficient compared to
newer coal plants, the capital cost to construct the older coal plants
was often significantly lower than the $-$/kW cost range
estimated for construction of a new coal plant today. These older coal
plants can have ``all-in'' costs for electricity in the $40/MWh to $50/
MWh range since the lower capital costs more than offset the lower
efficiencies. The gas cost needed to make a new CCGT plant have a $45/
MWh all-in cost is approximately $1.80/MMBtu.
Question 7. How much does conversion from coal to CCGT cost per
megawatt?
Answer. Although general information regarding the cost of
conversion of a coal plant is discussed above, the actual cost is very
case specific. The cost depends on several factors including how much
of the existing coal plant facilities can be utilized by the CCGT
plant. For example, it is often possible for the CCGT facility to reuse
the coal plant's steam turbine. While the reuse of certain components
results in a savings of capital dollars to the CCGT facility, there can
be additional design and construction costs that erode a portion of
these capital savings. Furthermore, a CCGT plant that uses an existing
steam turbine is often less efficient than a CCGT that utilizes a steam
turbine that has been specifically engineered and designed to be used
in a combined cycle application. The loss in efficiency results in
higher operating costs which can also erode a portion of the capital
savings. The end result can be a converted CCGT plant that has
essentially the same ``all in'' cost as a new CCGT facility that does
not utilize components from an existing coal plant.
Question 8. What is the primary obstacle to CHP?
Answer. CHP technology has some very good applications, but for
Xcel Energy there are some recognized obstacles including a process
need (for the heat) and a power need that must be at the same location.
The economics of the project decline as the distance between the
process and power needs increase. It is also a technology better suited
for an industrial site, not a residential or commercial site thus
further limiting suitable locations. Most of our industrial customers
have already taken advantage of CHP in the form of cogeneration. Hence
the likelihood that CHP could be a big contributor to carbon reduction
is remote.
Responses of David Wilks to Questions From Senator Murkowski
Question 1. You may know that Senator Mendendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. The technology exists to reduce the use of petroleum in the
transportation sector through either natural gas vehicles or electric
vehicles among other developing technologies. Both technologies require
significant investment in infrastructure to be successful. There are
very good uses for both of these types of transportation fuel
technology. For the automobile sector electrified transportation is a
technology solution that has the additional benefit of providing an
off-peak load for electric utilities and the ability to support off-
peak renewable energy generation and storage. We are supporting the
development of transportation electrification through our commitment to
the Edison Electric Institute industry-wide pledge to the full scale
deployment and commercialization of an electrified transportation
sector as illustrated in the industry pledge attached as Exhibit 1.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or, for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. To make the transition to a low-carbon, clean energy
future, the utility industry must rely on a diverse portfolio of clean
energy resources, including natural gas, clean coal, nuclear, renewable
energy and energy efficiency. At Xcel Energy, we have already begun to
reduce our emissions and have plans in place to achieve a 15% reduction
in CO2 across the system by , relying on almost all of
these clean resources. Our strategy today shows how the industry will
likely respond to the challenge of federal climate legislation
tomorrow. However, the success of that strategy depends on unfettered
access to capital, steel and other construction materials, and, of
course, coal, natural gas, and uranium fuels.
Question 3. What is your opinion about a Low Carbon Electricity
Standard that would allow utilities to use a variety of alternatives to
reduce greenhouse gas emissions, including renewables, natural gas,
nuclear and hydroelectric?
Answer. Xcel Energy has long been an advocate of such a standard.
Several years ago, in an effort to break the logjam on climate and
energy policy, Xcel Energy became a proponent of a Clean Energy
Portfolio Standard, or CEPS. Under CEPS, utilities would have been
required to derive a portion of the electricity provided to their
customers from clean energy resources, which would have included
renewables, new nuclear, clean coal and energy efficiency. EIA analyzed
the policy and found it to be a very cost-effective method of promoting
new technologies and reducing emissions. Although we designed CEPS
prior to the recent shale gas discoveries, the policy can easily be
modified to accommodate natural gas repowering as a clean energy
alternative. More information regarding CEPS is attached as Exhibit 2.
Question 4. To the extent that deliverability of natural gas to
markets has been an issue in the past, should recent improvements in
pipeline infrastructure, as well as prospects for additional projects
coming online, serve as any comfort to those with concerns about spikes
in natural gas prices?
Answer. The pipeline improvements that have recently been completed
or are in the process of being permitted and constructed have or will
alleviate a number of regional pricing anomalies including many of the
spikes seen over the last 3-5 years. The improvements that are complete
have resulted in a number of regional markets that are functioning and
falling more inline with national pricing trends. Geographic changes to
the natural gas producing areas, like the new shale basins
(Pennsylvania shale vs. Wyoming traditional production), as well as the
geographic changes to the market demand for gas caused by power
generators moving from coal or other fuels to natural gas could result
in regional pricing differentials becoming greater than they are now.
These regional production and demand shifts may again cause gas
pipeline constraints that could result in regional price spikes.
The continued development and use of natural gas storage in and
around the market demand areas has the potential to reduce the short
duration impacts of increased natural gas demand by allowing for the
efficient use of the pipeline infrastructure. Natural gas storage can
help the natural gas generator avoid short duration price spikes by
having storage gas available rather than going to the market during
periods of high gas demand and the corresponding price increases.
Natural gas storage does not have a significant impact on long term
price trends as storage must eventually be refilled after it has been
consumed.
Question 5. Please give me a sense of the relative challenges in
choosing fuel investments from the perspective of a regulated versus
non-regulated utility-I understand Xcel is the regulated utility.
Answer. In selecting fuel investments, a non-regulated entity must
choose the project only after considering the needs and desires of its
stakeholders (e.g. shareholders, customers and policy makers). The
decision is made based on a number of factors, including the impact of
the investment on the environment, its consistency with state policy,
its feasibility and risk, additional transmission and other supporting
infrastructure associated with the investment, its community acceptance
and, of course, its cost.
A regulated utility in selecting fuel investments has to work
within the rules of its federal, state or local regulatory construct
and in some cases receive regulatory approval of the need for such fuel
investment. These rules may require the utility to follow a certain
bidding process, allow interested third parties to intervene and/or
mandate a preference for certain types of projects (i.e. renewables),
in addition to meeting the needs of its stakeholders.
Question 6. I was interested in Mr. Wilks' testimony about
SmartGrid City in Boulder, Colorado, as well as the solar work that
Xcel is doing in Colorado. Can you talk about why natural gas is so
important as a backup, or baseload generator, for intermittent solar or
wind power?
Answer. We are very proud of SmartGridCity and believe that it will
allow us to test a variety of new ways to run a utility. We believe
that the Smart Grid will be an important tool to help us integrate
renewable energy onto our system.
As your question implies, natural gas is important as a backup to
intermittent solar or wind power because of the unpredictable nature of
those generation resources. Renewable energy ``integration'' refers to
those ancillary activities necessary to absorb increasing penetration
of intermittent renewable generation while maintaining overall electric
system stability and reliability. To support this integration Xcel
Energy relies heavily on natural gas fired power plants, which can be
brought online with fairly short notice. However, integrating the
renewable resources into our system with the help of the back up
natural gas resources inevitably imposes additional costs on our
customers. These costs are variable, but studies of utilities across
the country conclude that these costs can exceed $5.00/MWh for
utilities like Xcel Energy with high levels of renewable energy
penetration.
To help reduce the burden of these costs on our customers, Xcel
Energy is encouraging the adoption of new federal renewable tax
incentive policies. These policies should recognize that integrating a
substantial amount of renewable generation-in particular wind and
solar-on the grid imposes significant burdens on the utilities that
transmit and distribute electricity from such resources to customers.
To account for these burdens and encourage utilities to make necessary
system upgrades and ongoing integration expenditures, including those
in SmartGrid technology, Congress should enact a ``Renewable
Integration Credit'' (RIC). The RIC would provide utilities with a tax
credit based on the kilowatt hours of ``intermittent renewable
electricity'' generated on the system. Unlike the production tax
credit, the RIC would be directed toward defraying the integration
costs incurred by the utility system. More detail regarding the RIC is
attached as Exhibit 3.
Responses of David Wilks to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source.
Answer. Fleets vehicles which consume a consistent daily amount of
fuel will be the early users of natural gas as transportation fuel.
These vehicles return to their terminal every evening and can utilize
the large central natural gas fueling facility. The use of natural gas
as a motor fuel by the general public is expected come later as there
would be a need for a significant change in the fueling infrastructure
and the increase in the availability of factory built natural gas
vehicles.
Each MMBTU of natural gas used by vehicles will displace
approximately 8 gallons of gasoline and reduce carbon emissions by 20-
30%. The use of natural gas by the transportation sector will increase
natural gas consumption which may place upward pressure on natural gas
pricing similar to any increase in consumption.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. At the present time there are no major restrictions on the
use of natural gas as a fuel in any economic sector, in contrast to the
s when such restrictions were in place. Economic considerations
tend to dominate decisions about the use of natural gas, along with the
fuel's physical availability (tied to the deployment of delivery
infrastructure). Natural gas has some inherent advantages in terms of
its handling and combustion characteristics, so if cost is close to
even natural gas is often a preferred choice. Policies to incent fuel
switching in the electric utility sector include:
credit for early action if a switch is made prior to a new
GHG regulatory program;
allowance trading for other air emissions, as natural gas
has lower or no emissions of SO2, NOX or
mercury or particulates, but such reductions may not be valued
in a `command and control' regulatory system;
enhanced regulatory support for regulated utilities in terms
of accelerated rate recovery, higher allowed return on invested
capital, etc.;
robust support for storage and delivery infrastructure
including positive tax treatment for investment, streamlined
siting and permitting processes, and a consistent safety and
inspection regime; and
properly regulated commodity markets in order to ensure
price discovery, product innovation, and access to risk
management mechanisms such as hedging.
Responses of David Wilks to Questions From Senator Cantwell
Question 1. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years from $5.90 up to $10.82 and then back down to around
$3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what
would actually happen in the real world with regard to fuel
mix, energy costs and investment under this kind of price
volatility?
Could a well designed price collar mitigate this sort of
volatility?
Answer. With regard to natural gas price volatility, we agree that
recent years have seen significant ups and downs. In that context there
has nonetheless been strong investment in new natural gas power plants.
Thus, even without CO2 regulation and with natural gas
prices remaining volatile, we expect trends would be similar to recent
years: utilities will continue to invest in gas generation to meet peak
demand and increasingly as a resource to balance higher levels of
intermittent renewable power. The national energy mix would likely
transition incrementally toward renewables with natural gas, and
incrementally away from coal, but this transition would be gradual.
With volatile gas prices and CO2 regulation, one recent
analysis--EIA's analysis of the American Clean Energy and Security Act
of --suggests that natural gas power generation and natural gas's
share of the national energy mix would increase; however, differences
from the reference case are only significant if offsets and low-carbon
technologies are constrained. In this scenario investment in new
natural gas generation could increase significantly during a transition
period in which utilities use gas as a ``bridge'' strategy until
offsets, CCS or new nuclear become available. Otherwise, EIA describes
a future in which emissions are in decline, even without changes in the
fuel mix, due to energy efficiency and a slow economic recovery, and in
which many of the reductions needed for compliance come from offsets
rather than internal abatement.
Xcel Energy believes a well-designed carbon dioxide allowance price
collar could mitigate CO2 allowance price volatility. A
price collar would establish a ceiling and floor on the prices
regulated entities pay for allowances, with the ceiling designed to
avoid economic harm and the floor designed to ensure an adequate price
to incentivize carbon reductions and energy efficiency. A price collar
would provide some cost certainty for regulated entities, reduce price
volatility and market manipulation. A carbon dioxide price collar would
by extension help reduce the potential volatility of natural gas prices
under a cap and trade program.
Question 2. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities.
But an upstream cap for natural gas seems like it could
achieve the same broad coverage much more simply, by regulating
less than a thousand entities. What is the most efficient point
of regulation to achieve broad coverage of fossil carbon for
natural gas?
Are there any problems with mixing upstream caps for some
fossil fuels and downstream caps for others? Does an upstream
cap on all fossil fuels help to promote consistent, economy
wide carbon price signal necessary to transition to a low-
carbon economy?
Answer. Natural gas does pose special issues in terms of point of
regulation for GHG emissions. Natural gas is a uniquely pervasive fuel,
ranging across economic sectors from electric utilities, to heavy
industry, to large commercial and small residential end users. In
general, given this usage profile, an upstream point of GHG regulation
for natural gas seems preferable and easier to administer. However, it
would also be possible to regulate large stationary sources at the
point of use, while regulating the remainder of natural gas upstream.
GHG and regulatory accounting systems can be used to facilitate either
approach.
Nearly all proposals for a GHG cap and trade system have used a so-
called `hybrid upstream-downstream' approach to the point of regulation
issue. While sectoral definitions and entity size criteria vary, these
hybrid approaches all make the common assumption that any problems that
may arise from combining upstream and downstream approaches will be
more manageable than the problems that could result from imposing an
inappropriate point of regulation on some major portion of the economy.
In practice, we simply don't know much about the real tradeoffs
underlying this policy decision. Both upstream and downstream
approaches serve to limit GHGs and thus create price signals; it does
not appear to be necessary for all fossil fuels to be regulated in the
same manner for this price (scarcity) signaling to have an economic
effect.
Question 3. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental
implications of the use of technologies such as hydraulic
fracturing to produce unconventional shale gas resources. What
are the implications of shale gas production on ground water
and drinking water quality? How do these environmental risks
compare to those of other energy sources?
Also, from an economic perspective, at what price is shale
gas production viable for the industry? Would the price
certainty of a carbon price floor be necessary for shale gas to
be economic? How do the two prices-the natural gas price and
the carbon price-interrelate and affect shale gas production?
Answer. Reliable and environmentally beneficial energy production
is in the public interest. Whatever the implications are for ground
water associated with hydraulic fracturing, they need to be balanced
with whatever environmental risks are associated with other energy
sources. As indicated above, we support policies that allow for the
responsible development of clean energy options such as unconventional
natural gas.
Since Xcel Energy is not a producer we do not have the necessary
insight into determining at what price shale gas production is viable.
The interrelation of natural gas and carbon prices can affect shale gas
only to the extent that carbon prices positively or negatively impact
the underlying price of natural gas, which in turn impacts the economic
viability of shale gas production.
Question 4. Since natural gas has the lowest carbon among fossil
fuels, I would expect that a carbon price would not lead to a decline
in the natural gas industry. But over the longer term, as the economy
decarbonizes, there will be pressure on gas-fired utilities, as with
coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial
scale carbon capture and sequestration with natural gas?
Are the economics of CCS likely to be comparable for gas and
coal consumers?
Could reimbursements in the form of allowances in excess of
the cap for the amount of carbon captured and sequestered make
CCS economic? And would this framework treat both coal and
natural gas fairly?
Answer. We believe that with current CCS technology, CCS with
natural gas is technically feasible but significantly less economical
than with coal, primarily because of the lower concentration of
CO2 in the exhaust gas from a natural gas facility. In terms
of cost-effectiveness with respect to both investments and the impact
of CCS allowance incentives, we therefore feel CCS should be supported
on behalf of coal consumers, at least in the short and mid-term. The
experience gained and technological advance achieved in applying CCS to
coal will also be of significant value to gas consumers going in the
future.
Response of David Wilks to Question From Senator Lincoln
Question 1. As you know, several recent studies have projected that
our natural gas supply is much larger than previous estimates. For
example, the Potential Gas Committee esimtates that the U.S. now has a
35% increase in supply estimates from just two years ago, which is
enough they say to supply the U.S. market for a century. The Energy
Information Agency (EIA) has also predicted a 99-year natural gas
supply. I am proud that the Fayetteville Shale in Arkansas is already
producing over one billion cubic feet of natural gas per day, while
only in its fifth year of development. What role do you believe the
improvement in drilling technologies such as horizontal drilling and
hydraulic fracturing played in the estimated increase in natural gas
supply?
Answer. Improved drilling technology has played a very significant
role in the increase in natural gas supply. According to America's
Natural Gas Alliance, advances in geoscience, drilling and well
completion technology as well as 3-D seismic technology now allow
production companies to ``see'' the resource and to tap underground
reservoirs with less surface disturbance. The development of the
Fayetteville Shale (and the benefits it provides to Arkansas and the
people of the United States) and other unconventional formations is
made possible by this new technology.
Response of David Wilks to Question From Senator Mark Udall
Question 1. It was mentioned that some coal utilities are already
switching over to gas without incentive in place, could you elaborate
on this dynamic? Does low gas price and region play any role in some of
these changes?
Answer. In our experience, state legislatures may create programs
that offer cost recovery and other incentives to encourage utilities to
reduce emissions in part by retiring older coal plants and replacing
them with natural gas generation. Senator Udall himself cosponsored
legislation creating such a program in Colorado when he was a state
legislator in . These programs are designed to achieve different,
state specific goals, including improving air quality, promoting
economic development, or helping to achieve the state's own greenhouse
gas reduction goals. As indicated in my testimony, at Xcel Energy, we
have undertaken retirement and gas replacement programs in Minnesota
(the MERP) and are in the process of implementing a similar plan in
Colorado.
In our experience, however, these programs do not give utilities
unlimited discretion to undertake such projects. Instead, they require
the state public utilities commission to oversee the projects and
approve them only if they have reasonable cost and customer benefits.
In evaluating these projects, state commissions must evaluate the
potential cost of the project, including the potential cost of fuel.
Thus, lower projected gas prices will make these projects less costly
and thus more likely to be approved by the state commissions. In other
words, lower gas prices encourage states and utilities to undertake gas
replacement projects.
Exhibit 1.--News Release From Edison Electric Institute, October 21,
industry-wide plug-in electric vehicle market readiness pledge
DETROIT--EEI member companies are committed to making electric
transportation a success. At the center of these efforts is the
industry-wide pledge to plug-in electric vehicle market readiness. The
pledge represents a culmination of efforts by EEI member companies to
survey the current state of electric transportation initiatives among
utilities, evaluate how those initiatives fit in with the overall goal
of advancing transportation electrification and determine what more is
needed. There are five areas of focus:
1. Infrastructure: Utilities pledge to proactively work with
their state regulatory and legislative bodies to assess and
address any potential system impacts from fueling large numbers
of plug-in vehicles from the electrical grid. Further,
utilities will work collaboratively with state and local
officials, public/private entities, automakers, and other
stakeholders to help develop a comprehensive local charging
infrastructure deployment plan.
2. Customer Support: Utilities pledge to assure that a robust
customer service process is in place that can scale up to
support large numbers of plug-in vehicle customer service
requests ranging from charging infrastructure installations to
utility-specific rate options and incentive plans. Utilities
will work with stakeholders to facilitate a streamlined
charging installation process.
3. Customer and Stakeholder Education: Utilities pledge to
collaborate with state and local officials, public/private
entities and automakers to help implement a broad nationwide
education program highlighting the benefits of electric
transportation (energy security, reduction in greenhouse gases
and air pollutants); the benefits of electricity as an
alternative fuel; the creation of public-access charging
infrastructure; steps cities and individual customers need to
take to get plug-in ready; and the importance and benefits of
off-peak charging.
4. Vehicle and Infrastructure Incentives: Utilities pledge to
work with federal, state and local stakeholders to help develop
purchase and ownership incentives (monetary/non-monetary)
supporting both vehicles and infrastructure deployment.
Incentives could include purchase incentives, tax rebates, off-
peak charging rates, preferential and/or free parking, and
grants for charging infrastructure installation, all designed
to encourage a significant penetration of electric
transportation solutions.
5. Utility Fleets: Utilities pledge to develop new
sustainable fleet acquisition and operations plans, helping
drive development and significant deployment of electric
transportation solutions in light-, medium-and heavy-duty
utility applications. These efforts could include development
of industry-wide vehicle specifications by weight class;
industry-wide fuel economy requirements; fleet user education
programs; and industry-wide best practices, all designed to
help achieve a significant increase in fleet fuel efficiency
and a commensurate decrease in GHG and other emissions.
Exhibit 2.--National Clean Energy Portfolio Standard
a climate change and energy policy for the utility industry
Climate change is of significant interest and concern to our
customers, the states we serve and our nation. How our country deals
with this issue is critical to achieving real environmental improvement
while keeping electricity affordable for all consumers.
We propose a clean energy approach through a Clean Energy Portfolio
Standard (CEPS). A CEPS is an increasing requirement for a utility's
energy sales to come from non-CO2-emitting generation.
Utilities would meet a 25 percent CEPS requirement in by choosing
from a portfolio of eligible technologies. The policy sets later
technology targets to achieve -level CO2 emissions.
CEPS
Reduces utility CO2 emissions at low cost.
Encourages clean technology and transforms the utility
industry.
Promotes national energy security.
Reduces natural gas consumption.
Manages cost through flexibility and resource diversity.
Rewards early action.
Protects economic growth and national competitiveness.
CEPS Specifics
10% by ; 17% by ; 25% by of energy sales.
Post-, the CEPS targets are adjusted to achieve
emissions levels by , levels by , and levels
(2 billion tons per year) by .
Compliance occurs through tradable Clean Energy Credits
(CECs).
--Credit for renewable energy or ``low emission'' generating
facilities
--Acquisition of CECs from national trading market
--Purchase of ``safety valve'' CECs from Department of Energy (2.5
cents/kilowatt-hour (kwh), indexed for inflation)
Early credit beginning in for renewable resources
Three-year borrowing forward allowed
Cost recovery for:
--Clean energy generation or CECs
--Ancillary costs (firming, shaping, backup) for intermittent
resources
--Transmission and distribution
State opt-out provision for excessive cost
------------------------------------------------------------------------
-------------------------------------------------------------------------
CEPS eligible technologies and values:
Renewable energy = 1 CEC/kwh
Advanced fossil w/ carbon capture = 1 CEC/carbon-free
kwh
New nuclear = 1 CEC/kwh
Energy efficiency/conservation investments = CECs
awarded at safety valve price
Carbon offsets--carbon sequestration, plant efficiency
improvements, other offsets = CECs per ton of CO2, with
limit at 10% of compliance
------------------------------------------------------------------------
Exhibit 3.--Utility Renewable Energy Integration Cost Recovery
Mechanisms--Based upon Xcel Energy's Three Operating Companies: PSCo,
NSP and SPS
Renewable energy ``integration'' refers to those ancillary
activities necessary to absorb increasing penetration levels of
intermittent renewable generation while maintaining overall electric
system stability and reliability. Integration does not include project
costs incurred by developers of intermittent renewable energy (capital,
O&M, etc.), but rather the additional costs of incremental electric
production and incremental gas supply to account for the renewable
energy on a utility system. These costs are borne by utilities through
four primary activities: load following, unit commitment, generating
facilities for balancing, and increased operations and maintenance
costs for existing plants.
These costs are variable, but studies of utilities across the
country conclude that these costs exceed $5.00/MWh on average. Only the
highest levels of intermittent generation requiring over 20% of retail
sales coming from solar or wind generation would be eligible for $5.00/
MWh credit. At least 4% renewable generation would need to be achieved
to earn $1.00/MWh credit.
1. Load Following--this activity includes adjusting
generation to follow the changes in total customer demand
versus the variability in wind output as well as regulation of
the output of generation units to maintain system frequency.
Cost Recovery: Resulting increased fuel costs are passed
through directly to customers through periodic fuel cost
adjustments. Additional load following costs resulting from
less than optimal system operations and higher power production
costs are also incurred by the customer through increased
electric rates.
2. Unit Commitment--the process of determining which
generators should be operated each day to meet the daily demand
of the system including maintaining adequate reserve capacity.
Cost Recovery: The cost of forecasting and planning for the
daily expected wind generation is incurred by utility customers
through adjustments to their electric cost of service. More
accurate wind forecasting will be critical to successfully
integrate higher levels of wind and this will increase the unit
commitment costs.
3. Investments--Utilities may need new quick-start natural
gas generating facilities, and supporting natural gas
infrastructure, storage and fuel, in order to balance the
intermittency of renewable generation.
Cost Recovery: Investments in generation are recovered
through rate increases if approved by state utility
commissions. If additional generation is acquired through
purchased power, those costs are passed through to customers
through periodic electric cost adjustments and base rate
increases.
4. O&M--Increased O&M costs for existing coal and gas plants,
due to more frequent changes in operating rates to balance
renewable generation.
Cost Recovery: The increased costs of O&M are borne by the
customer once included in approved rate increases. Increased
electric costs that result from purchasing electricity when
company owned units are out of service for maintenance are also
passed through to the customer. This cost can increase
substantially when power must be purchased to fulfill our
reserve requirements in addition to meeting load.
renewable energy tax credits
Utility commissions set utility rates based so that the utility
recovers the cost of operating its system plus a reasonable rate of
return. These costs include the cost of taxes imposed on the utility;
utility rates are set to assure that the utility can recover its tax
liability. As a general rule, if the utility receives a tax benefit,
such as a tax credit related to renewable energy, the value of those
tax credits are passed through to customers.
For example, when Xcel Energy constructed the Grand Meadow Wind
Farm in Minnesota, it reduced its charge to customers by the value of
the wind production tax credit (see attached, page 12). The Renewable
Integration Credit would be subject to similar regulatory treatment.
______
Responses of Lamar McKay to Questions From Senator Bingaman
Question 1. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what timeframe could that potentially
occur on?
Answer. The price at which natural gas competes with coal in
electricity generation is dependent on the relative price of coal and
gas and the relative efficiencies of the respective coal-and natural
gas-fired power plants under consideration. For electricity dispatch
from the existing coal generation fleet, based on a coal price of
$40ton and using the thermal efficiency of representative US coal-and
natural gas-fired (combined-cycle gas turbine) power plants, new
natural gas plant capacity would be competitive with coal at prices
around $4/Mmbtu. With a CO2 price of $20/ton, natural gas
prices of around $6/Mmbtu would be competitive (holding all other
factors constant).
Any large-scale change in the nation's energy use would take
decades to play out, given the long lead times needed to invest in new
equipment to both produce and consume energy. Based on this, coal will
continue to play the dominant role in US electricity generation for
decades to come. The proposals I discussed in my testimony were more
modest but quicker to have an impact: the incremental natural gas
demand that could potentially deliver 10% of the carbon savings
required by proposed legislation by are about 1 Tcf per year--less
than the increase seen in US natural gas production alone. And
this could be done partially by using existing natural gas-fired power
generating capacity.
The switching from coal-fired generation to gas provides a material
option in the short/medium term which has the added benefit of
contributing carbon emissions reductions while CCS technologies on both
coal and gas are fully demonstrated. However, whether the option is
actually realized will ultimately depend on the relationship between
coal, gas and carbon prices, which may be different from those
illustrated.
Question 2. One area of concern about depending on our natural gas
resources is that gas has been prone to strong price spikes over the
past decade. The most recent one was just in , with prices soaring
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned
that the expanded reserves and greater ability to receive LNG shipments
could mitigate future price spikes. Please comment on the factors that
resulted in the price spike and other recent spikes. Is the supply
situation now such that we will be insulated from such volatility in
the future? Are there policy options we could pursue to reduce price
volatility?
Answer. Prices for all forms of fossil fuels increased in the first
half of . Central Appalachian coal spot prices, for example, rose
from about $58/short ton at the beginning of to $140/ton by August
and now stand near $55/ton. (Source: US DOE/EIA) Even as natural gas
prices in the US rose in the first half of last year, they remained
well below oil prices (when compared on a comparable basis).
To a large extent, these increases were due to a period of strong
economic growth--not just in the US, but around the world--that pushed
prices for energy and many other commodities to record levels by the
middle of . And the recession that has followed has led to lower
prices for all forms of fossil fuels as well as many other commodities.
So the primary driver of natural gas--and other fossil energy--price
increases up to mid- was a strong economy. In the face of strong
demand, investment lags and government policies that constrained the
ability of producers to respond to higher prices hindered the supply
response, resulting in higher prices (through the middle of last year).
As noted in my testimony, US natural gas supply has undergone a
quiet revolution in recent years. Technological innovation has allowed
resources previously deemed to be ``unconventional'' to play a larger
role, with the result being that US-proved reserves of natural gas over
the past decade have increased by 45% at a time when proved reserves of
oil have increased by just 7%. So we now have the domestic resource
base to grow supply substantially if demand increases--and if
investment is permitted to occur.
In addition, natural gas demand in the US has a much more
pronounced seasonality to it--which has historically been a key driver
of greater natural gas price volatility. For example, looking at the
range of demand from month-to-month in , oil consumption varied by
18%, coal by 25%, and natural gas by a massive 87%. This is a key
reason why unusually cold weather--or other unexpected disruptions such
as hurricanes--can have an out-sized impact on natural gas prices. If
natural gas consumption increased for power generation (since power
demand tends to peak in the summer for air conditioning, rather than in
winter), it would tend to reduce the seasonality in domestic natural
gas demand and could therefore help to reduce seasonal price
volatility. It would have a smoothing effect.
Any market is uncertain--and we can never insulate ourselves
completely from unexpected events that cause price volatility--but we
at BP believe that government does have tools to help limit price
volatility and to help market participants manage their exposure to
unexpected changes in price. First, an expanded diversity of supply
options has the potential to improve energy security and reduce price
volatility; thus, measures to permit industry access to potential
domestic gas resources, while developing those resources in an
environmentally sound manner, would help. Similarly, as Energy
Information Administration (EIA) Administrator Newell has noted, access
to international LNG can help to limit price spikes by allowing US gas
consumers access to global suppliers. At the same time, we should
encourage US power producers to maintain a diverse set of power-
generating facilities, to allow a greater degree of competition between
energy sources. Finally, regulators should allow both producers and
consumers (including utilities) to manage short-term price risk by
hedging in (appropriately regulated) forward markets.
Question 3. Reducing the volatility in the price of natural gas is
an important goal if we are to lean more heavily on this resource. For
producers, independent generators, and utilities to enter into long-
term contracts for gas supply would seem to be one way to reduce
pricing volatility. Could you describe your willingness to enter into
such long-term contracts, and what obstacles may stand in the way of
them?
Answer. This question has long involved a chicken and egg
discussion. The incorporation of long-term supply contracts in a fuel
portfolio can indeed help to mitigate overall volatility, but wholesale
market participants are often reluctant to engage in them because of
the perceived volatility.
Because natural gas demand is weather-sensitive in both winter and
summer, with limited opportunity for on-site storage, it has been, and
will likely remain, susceptible to some degree of price volatility. BP
and other suppliers do offer hedging and risk-management services,
however, to help ensure competitive fuel price certainty. While these
options may not eliminate volatility, they can serve to insulate
customers from their exposure to it. Innovative gas recovery techniques
have significantly expanded the U.S. resource base and hopefully will
serve to mitigate these concerns going forward. Nonetheless, the longer
the term, the greater the market risk, and potentially the need for
additional policy incentives to secure additional market receptivity.
For instance, utility companies often find it prudent to rely more
on market-indexed commodity pricing for their customers, since
regulatory pass-through of these costs might not otherwise be assured.
Another barrier tends to be the increased credit requirements and
rating thresholds associated with longer-term transactions.
Another factor contributing to shorter-term transactions is the
reliance on fuel for limited peaking needs and power dispatch. Peaking
units tend to buy their fuel and transportation capacity on an ``as-
needed'' basis only via interruptible transportation. Longer-term deals
often result in the perceived sunk cost of un-used transportation
capacity.
Question 4. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. The Kerry/Boxer bill should provide enough financial
incentives to help initiate and illustrate the potential of large-scale
deployment of CCS. Under the bill, Section 780, ``Commercial Deployment
of Carbon Capture and Permanent Sequestration Technologies,'' will
provide an average of 90 million allowances (1 allowance = 1 metric ton
of carbon dioxide equivalent emissions) from through for CCS
incentives. Between - this will increase to an average of 240
million allowances. These allowances are in addition to the $1 billion
per annum provided by Section 125, ``Carbon Capture and Sequestration
Demonstration and Deployment.'' Assuming $20/ton carbon allowance
price, this should be sufficient funding for approximately 30 coal-
fired projects with CCS and 5-7 gas-fired projects, assuming that 15%
of the allowances are provided for gas-fired technologies. This should
be enough to prove the CCS concept and spur further efforts to deepen
its application in the power sector.
The 15% limitation for the allowance pool under Section 780 will
limit the application to natural gas-fired power generation. Ideally,
all power sources would compete for funding based on the lowest cost of
abatement balanced against the overall cost to electricity consumers.
On a carbon abatement cost basis, coal-fired CCS has the potential to
lower emissions at lower incremental costs compared to gas-fired CCS
($55/ton vs. $110/ton for coal and gas CCS, respectively) primarily
because of much smaller inherent CO2 emissions by natural
gas to begin with. However, from an overall cost per kilowatt hour,
gas-fired CCS will cost less to the consumer ($95/MWh for coal vs. $81/
MWh for gas assuming $2/mmbtu for coal and $6/mmbtu for gas). While the
current level of allowances could be sufficient for the gas industry,
5-7 projects, an equal playing field in gas generation will ensure that
both coal and gas compete in both abatement costs and overall cost to
consumers.
We are encouraged that Section 182, ``Advanced Natural Gas
Technologies'' has been included in the bill. It provides funding for
natural gas end-use technologies, and including funding for CCS
technology for natural gas-fired power generation.
Question 5. All of the natural gas we're discussing here today will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales.
There has been some discussion here in Congress that the Safe
Drinking Water Act exemption for hydraulic fracturing should be
reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. Repealing the current exemption of hydraulic fracturing
from being defined as underground injection under the Safe Drinking
Water Act (SDWA) would have a dramatic negative effect on natural gas
development in the US. The repeal would result in the permitting
requirements of the SDWA being applied to hydraulic fracturing
operations which would result in significant delays (up to a year) and
preclude the highly efficient drilling/stimulation operations and
practices necessary to access and produce unconventional resources,
such as shale and tight sand gas, in a cost efficient manner. The
increased costs coupled with permitting delay will raise the cost of
developing these resources and make much of the unconventional gas
resource uneconomic at a natural gas price the economy can afford. All
of this will occur in an environment where the country should be using
more natural gas to reduce greenhouse gas and other air pollutant
emissions.
A more appropriate approach would be for the States, who currently
effectively oversee and manage hydraulic fracturing operations, to
adopt other State and industry best practices into their programs.
These might include:
a. Well construction standards to ensure aquifer protection--
including:
Setting the well bore surface casing below the lowest
drinking water aquifer and cementing it back to surface.
Pressure testing the casing/well head to confirm that there
are is no annular communication or leaks.
Running cement bond logs to confirm that the cement is
bonded to the well steel casing and re-cementing any voids.
b. Testing of drinking water wells within a \1/4\ mile radius
of the proposed well before drilling and again after completion
(hydraulic fracturing).
c. Using lined pits and steel tanks on the surface to prevent
hydraulic fracturing fluids at the surface from contaminating
soils or groundwater.
Question 6a. What safeguards do you currently undertake in your
upstream gas recovery to protect ground and surface water resources
during and after utilization of hydraulic fracturing? Do you have any
modifications or improvements that you are planning to implement in
this area?
Answer. BP employs a variety of methods and practices in our
overall operations, and during hydraulic fracturing, to protect soils,
groundwater, and the environment. These include:
Conducting various tests to verify well integrity.
Where appropriate, conducting routine annular pressure
testing to identify any pressure build-up and verify casing and
well-head integrity.
Routinely running and evaluating cement bond logs (test
results from the drilling process) to confirm that the cement
in the well is properly adhered to the well casing and that the
annulus is properly filled.
Groundwater monitoring
Protecting wellbores, pipelines and tanks to prevent
corrosion of equipment where appropriate.
Using infrared camera and other optical gas imaging
technology to scan pipelines and identify small leaks before
they could become big leaks.
Providing adequate containment for tanks and equipment
Quickly responding to and cleaning up any spills or leaks
which do occur along with determining and fixing the causes.
Using tanks for produced water handling.
Using ``closed loop'' drilling fluid systems where
appropriate
Properly constructing and lining reserve pits used for
handling of drilling cuttings and fluids where these are used.
Injection disposal, in UIC permitted Class 2 wells, of
produced water rather than surface discharge.
Properly handling, treating and disposing of wastes
generated during the development and operation of our fields
and facilities.
Question 6b. In the last few years, BP has focused their company
image on being good environmental citizens. As such, have you begun to
apply this to your subsurface operations? More specifically, what (if
any) technological advancements have you invested in or started to use
in your operations, to address the issues of managing or reusing
flowback water and the use of non-potable water for hydraulic
fracturing fluid?
Answer. Reducing and re-use of both flow-back (hydraulic
fracturing) and produced fluids (water) is a priority for BP. Examples
of activities underway:
Reducing the amount of fresh water used during drilling and
hydraulic fracturing by using produced water in lieu of fresh
water where possible.
Recycling/re-use of drilling and fracturing fluids.
Active field testing of on-site water/fluid treatment
technologies to allow beneficial reuse of water.
Piloting advanced technologies to reduce water usage.
Question 6c. Additionally, several groups have been discussing the
use of ``green frac'ing fluids''. This would imply that the frac'ing
fluids currently being used in the industry are perhaps unsafe to the
environment and public health. It has come to my attention that it is
required that employees at a site are entitled to know what chemicals
are being used in the process of fracturing, but the public is not
entitled to the same information (more specifically, material safety
data sheets). What are you doing to address these concerns, are you
making your chemical data available for public inquiry? Or are you
considering a switch to ``green frac'ing fluids''? I would hope that
with the growing concerns around fresh water availability that the
industry, more broadly, would routinely make this information available
to the public (at a minimum) and start to look for other ``greener''
fluids for the gas extraction process.
Answer. BP strongly supports measures to ensure that agencies and
medical professionals have timely access to chemical products
information to facilitate responses to and potential environmental
incidents and medical emergencies, subject to appropriate safeguards
for proprietary information consistent with federal laws. Operators
presently comply with a range of federal chemical recordkeeping and
reporting requirements, including the OSHA Hazard Communication
Standard, and requirements under SARA Title III, and CERCLA. These
regulations require operators to maintain plans and processes for the
safe handling, storage and transportation of chemical products in order
to protect employees, the general public and environmental resources.
These regulations also contain reporting and disclosure requirements
(including maintaining MSDS sheets for chemicals) to make chemical
information available in a timely manner to employees, contractors and
emergency responders.
Regarding green fracturing fluids, BP will continue to encourage
our hydraulic fracturing contractors to reduce the toxicity and volume
of the chemicals used. We believe progress has been made in the past
with this objective and will continue as we work with our contractors.
Responses of Lamar McKay to Questions From Senator Murkowski
Question 1. You may know that Senator Menendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports, and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. BP expects compressed natural gas application in light-duty
vehicle service will grow but be limited due to a number of factors.
Specifically, the incremental cost of the vehicle relative to
conventional cars and hybrids; NGV driving range being only 50-60% of a
gasoline vehicle, reduced storage capacity in the vehicle (trunk space)
due to use of compressed natural gas tanks, the lack of wide spread
natural gas retail distribution infrastructure and the incremental cost
of fuelling infrastructure to provide natural gas at the high pressures
required for refueling.
For these reasons, natural gas is more suitable for short range
fleets, such as buses and delivery vehicles, which can re-fuel at a
dedicated natural gas compression and storage facility at a central
fleet depot. Short range urban fleets, such as buses and commercial
delivery vans, can overcome many of the passenger NGV disadvantages due
to this larger scale that enables efficient cost spreading and
amortization.
A large compressor and storage system at a depot will benefit from
economies of scale resulting in per ``gallon'' CNG costs that are 50-
60% less expensive than those expected from residential/home units.
Because of high vehicle miles traveled, CNG fueled fleets will realize
fuel cost savings versus those expected from gasoline or diesel fuel
use. However, a significant number of miles (approx. 300,000) must be
traveled in order to recoup the infrastructure associated with NGVs.
On an equivalent tail pipe emission basis, NGVs emit 65-70% of the
CO2 as a conventional vehicle. However, NGVs also emit fewer
tail pipe criteria pollutants such as CO (carbon monoxide),
particulates and NOX.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or, for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. Access to domestic energy resources is fundamental to
meeting society's energy demands while enhancing the domestic economy,
jobs, and energy security. Congress is uniquely positioned to take a
leadership position to ensure access to domestic resources remains
achievable while ensuring that the appropriate and needed environmental
safeguards are in place. While we cannot comment on the challenges that
the coal mining industry faces, we do have ideas for actions Congress
should take to enhance the ability of American business to access
domestic oil and gas resources in a responsible and cost effective
manner:
Maintain exclusion of hydraulic fracturing stimulation from
the Safe Drinking Water Act permitting: The ability to
artificially stimulate the non traditional fuel reservoirs,
which are the bulk of new domestic oil and gas resource
potential, through fracture stimulation is critical to
production of oil and gas from these resources.
Open areas excluded from leasing, such as the OCS waters,
for additional leasing and potential development.
Perform regional analysis of rural and high country ozone:
Regional analyses of rural and high country ozone, particularly
in the Western US, by the EPA will inform sound policy
regarding the lowering of the current National Ambient Air
Quality standard for ozone.
Air quality evaluation of offshore development: A
comprehensive air quality analysis by the EPA, with the
participation of relevant stakeholders, of the potential for
offshore development to impact onshore air quality and public
health prior to imposing CAA permit and control programs to
offshore development.
Cost ceiling for CO2 reductions: A cost ceiling
per metric ton of CO2 equivalent reduction could be
used in the economic reasonableness analysis under the Clean
Air Act; Prevention of Significant Deterioration (PSD); Best
Available Control Technology (BACT) requirements.
Reform the implementation of the National Environmental
Policy Act: Steps can be taken to bring the implementation of
the National Environmental Policy Act back to its original
purpose of informing decision making and to streamline the
analysis process.
Question 3. What would be your opinion about a Low Carbon
Electricity Standard that would allow electric utilities to use a
variety of alternatives to reduce greenhouse gas emissions, including
renewables, natural gas, nuclear and hydroelectric?
Answer. BP believes pricing carbon is fundamental and has a
preference for an economy-wide cap and trade system that, if equitably
designed, would expose all energy sectors to a uniform carbon price.
This approach, we believe, will deliver the most certain environmental
outcome, at the least cost to the economy. Depending on how they are
structured, standards, mandates and obligations are likely to imply a
higher carbon price in sectors where they are used than in the rest of
the economy, and a higher carbon price for some fossil fuels within
those sectors. BP does support transitional standards for emerging low-
carbon technologies, like renewables, that have significant potential
for future cost reduction and carbon savings, but are not yet
commercial-scale. Such standards, and the implied higher carbon price,
can be justified in these cases to provide transitional support for
innovation and deployment but not permanent support for carbon
reduction per se. Carbon reduction should be achieved through an
economy-wide carbon price.
Question 4. To the extent that deliverability of natural gas to
markets has been an issue in the past, should recent improvements in
pipeline infrastructure, as well as prospects for additional projects
coming online, serve as any comfort to those with concerns about spikes
in natural gas prices?
Answer. All facets of the natural gas industry have been actively
engaged in mitigating customer price risks. In addition to the producer
supply activities mentioned previously, there have been significant
pipeline and storage capacity additions in response to the resource
additions and infrastructure constraints witnessed in recent years--and
these investments are continuing at all levels. Natural gas inventories
will hit a new record high before the withdrawal season begins a few
days from now. According to the EIA, this level was made possible by
recent capacity additions that have brought the total available
inventories for the heating season to almost 4 Tcf.
Completion of the eastern leg of the new Rockies Express pipeline
in time for this winter will further extend access to less-expensive
resources in the intermountain West that were previously out of reach
for many. The pending Ruby pipeline will extend those benefits further
west into northern California--and these are just two examples of the
significant investments that are being made by the pipeline industry to
ensure consistent and reliable service to new and existing markets.
From a policy perspective, continuing to provide access to the most
economic resources will be a key factor, as will regulatory willingness
to consider and accept the initial or periodic premiums associated with
any expansion of longer-term supply deals.
Question 5. In your written and oral testimony, you appear to have
a level of confidence about the U.S. resource base. Can the U.S.
continue to be about 90% independent for its natural gas purposes?
Answer. We are confident that the US has the resource base to
support much higher production for decades to come. As discussed in an
earlier answer, US proved reserves of natural gas have increased by 45%
over the past decade--to 238 Tcf--largely due to technological advances
that have allowed the industry to develop ``unconventional'' resources
cost-effectively. Based on these same innovations, the Potential Gas
Committee earlier this year revised its estimate of the US potential
gas resource--resources in addition to the proved reserves mentioned
earlier--up by 39%, to 1,836 Tcf.
International natural gas markets also have been rapidly
developing. While we support robust efforts to increase domestic
production, it also stands to reason that US consumers could benefit by
tapping into abundant global resources of natural gas.
Question 6. Why do you believe natural gas can play such an
important role in mitigating climate change when it is, in reality,
still a fossil fuel?
Answer. Natural gas can be a key component in mitigating GHG
emissions. Natural gas is the cleanest burning fossil fuel in the
energy portfolio; delivering 50% less CO2 than coal per
kilowatt hour when used for electrical generation. Increasing the use
of natural gas in power generation provides an affordable, efficient,
and immediate step towards reducing CO2 emissions from the
power generating sector today. Additionally, natural gas powered
generation lowers emissions of NOX by 85%+; virtually
eliminates emissions of SOX, and particulate matter; and
eliminates mercury emissions and ash waste. These attributes make
natural gas a key component of the US energy mix that can help mitigate
climate change, especially within the power sector, in the most
efficient and cost-effective way.
Question 7. We have heard a great deal about how unless the United
States passes one of the current cap and trade bills under
consideration, China and other nations are going to outpace us in
renewable energy development. But China certainly doesn't have any
carbon laws on the books. My question is, do we truly require more
mandates to drive us to a lower carbon economy?
Answer. Without the appropriate policy mechanisms in place, there
is little expectation that the economy will see significant efforts to
reduce carbon emissions in China or the US. China does not have
comprehensive climate legislation, but, driven by security and economic
as well as climate objectives, China has undertaken a number of
domestic carbon reduction initiatives, including setting renewable
energy and energy intensity reduction targets, and is building
institutional capacity for lower carbon technologies.
Existing mandates here in the US, at both state and federal levels,
focus mainly on renewable fuels and power, and vehicle efficiency.
Renewable standards will help new low-carbon technologies become
commercial and compete without support in the future but will make only
a small contribution to carbon reduction today. Vehicle efficiency
standards are very important by reducing carbon at a relatively low
cost. However, the best and least-cost way to kick-start a move to a
lower carbon economy is to put a price on carbon--potentially through a
well-designed, equitable economy-wide cap and trade system,
supplemented by efficiency mandates across a range of demand-side
activities that do not fit within a cap and trade market.
Responses of Lamar McKay to Questions From Senator Cantwell
Question 1a. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years, from $5.90 up to $10.82 and then back down to
around $3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what would
actually happen in the real world with regard to fuel mix, energy costs
and investment under this kind of price volatility?
Answer. While greater price volatility--that is, greater
uncertainty--can impact the investment decisions of both producers and
consumers, it's important to note that investments, and therefore,
ultimately the fuel mix tend to be based on long-term expectations--and
long-term price expectations are considerably less volatile than spot
prices. The equipment employed to produce and consume energy tends to
be long-lived, and to have long lead-times.
Accordingly, long-term relative price expectations are what really
matters. For example, when BP considers investments, we are more
concerned with the price of natural gas relative to other, competing
energy sources. Both producers and consumers can limit their exposure
to short-term price volatility through well-regulated futures markets.
All fossil fuels and many other commodities have seen volatile spot
prices in recent years, due in large part to an unusually strong global
economy. Central Appalachian coal spot prices, for example, rose from
about $58/short ton at the beginning of , to $140/ton by August and
now stand near $55/ton. (Source: US DOE/EIA)
Question 1b. Could a well-designed price collar mitigate this sort
of volatility?
Answer. In principle, BP would prefer to allow markets to operate
with minimal constraints to promote efficiency. In practice, especially
during the early phase of operation of carbon allowance markets, when
uncertainty is greater, measures can be used to reduce price risk of
various kinds. However, such measures should be designed to work with
the market, rather than against it, and can be seen as addressing three
related, but different issues: allowance price level; volatility; and
transparency.
Price level.--High carbon prices can provide a powerful incentive
for low-carbon investment, innovation and energy conservation. But if
there is a concern about carbon prices above a certain level, or the
effects of carbon prices on demand and price for conventional fuels,
there are several market-compatible means of addressing the concern.
For example, the concern can be addressed by making multiple
alternative compliance units such as offsets available or by
introducing extra compliance units into the market if the allowance
price reaches a certain level. If extra units are borrowed from the
future or compensated by purchasing international offsets (as in the
strategic reserve) the cap does not need to be compromised. Less
desirable, because it introduces uncertainty and compromises the
environmental goal, the target can actually be lowered (cap raised) if
the price goes too high. Or a buy-out price can be used, which sets a
firm price cap and raises revenues for government, but this inhibits
the market and also risks compromising the cap.
In all cases in which some kind of price cap or buy-out price is
employed, it is preferable for it to be set quite high, as a kind of
safety valve, or it will effectively become a tax that has high
transaction costs, and will reduce the incentive for low carbon
investment and innovation and energy conservation.
To guard against allowance prices falling too low, and removing the
incentive for obligated parties to invest in carbon reduction
activities, a floor price can also be established.
Allowance price controls or allocation mechanisms may also be used
to address the competitive disadvantage that occurs when domestic
industries are competing with the same industries in countries without
a carbon price.
Price volatility.--Price volatility can be addressed by different
market instruments, including banking of allowances and limited
borrowing of allowances from future years, provided the long-term
targets are not eroded. Further mitigation of price volatility is
possible by linking emission trading schemes together.
Price transparency can be achieved in several ways, ranging from
the regular publication of allowance auction prices to a daily price
index for allowances traded via an exchange.
Problems of price level, volatility and transparency can all be
reduced by good, fundamental cap and trade system design. This should
include:
Eventually, the widest feasible coverage across the economy
A cap that starts high and declines slowly, to provide time
to adjust
The creation of a deep and liquid market for allowances,
with multiple participants regularly engaged in trading. Note
that the free distribution of allowances to entities that are
not covered in the cap and trade system accomplish this goal.
An accurate assessment of emissions from all sectors
included in the program to determine the baseline and
understand the market scope.
An accurate assessment of the availability and cost of
emission reduction opportunities to reduce the risk of
unacceptable/surprise sustained high prices
Allocation/compliance periods that are set to allow adequate
investment lead time for emission reductions to come online.
Question 2a. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities.
But an upstream cap for natural gas seems like it could achieve the
same broad coverage much more simply, by regulating less than a
thousand entities. What is the most efficient point of regulation to
achieve broad coverage of fossil carbon for natural gas?
Answer. The optimal point of regulation is the physical point of
emission (i.e. where the combustion of the fossil fuel occurs), because
information and opportunities to reduce emissions are greatest, and
supply chain distortions smallest. Also, combining the economic signal
with active participation in the trading scheme will provide the
greatest catalyst for action.
However, practicalities and transaction costs currently limit the
number of entities that can be directly regulated. If these policy
considerations lead to a shift in the point of regulation, it should
still be kept as close as possible to the physical point of emission,
subject to reducing the number of regulated entities to a manageable
level while still preserving a liquid market with multiple
participants. Selection of a point of regulation should also limit the
potential for double counting or missing fuel borne emissions and not
disrupt the supply chain.
Using the example of emissions from the use of oil products (such
as gasoline and diesel), this balance point is logically the fuel
supplier, providing that liability for the emissions is not attached to
the supplier, and the costs of the regulation continue to be borne by
the true emitter. Key considerations in this regard will be to ensure
that, for example, imported and domestically produced or refined fuels
are treated in exactly equivalent ways and that an adequate supply of
allowances will be available in the market for the supplier to meet the
requirement at a well defined price. Moving the point of regulation any
further upstream than is necessary is likely to magnify distortions in
the supply chain, distort economic signals to the emitter, reduce
incentives and opportunities for carbon abatement, and reduce the
number of participants in the market.
For these reasons, BP supports striking a practical balance between
downstream and upstream regulation and would not support a move to
upstream regulation only.
Question 2b. Are there any problems with mixing upstream caps for
some fossil fuels and downstream caps for others? Does an upstream cap
on all fossil fuels help to promote a consistent, economy-wide carbon
price signal necessary to transition to a low-carbon economy?
Answer. The principles described in the previous answer apply
economy-wide, so moving the point of regulation further upstream from
the physical point of emission than is necessary for any sector is
likely to diminish the effectiveness of the overall system. To the
extent that commodity fuel prices and competition, both domestic and
international, inhibit a clear carbon price signal to the decision
making consumer, and upstream cap does not provide incentives for lower
carbon decisions.
For these reasons, we see no problem with hybrid downstream and
upstream regulation, with the balance struck on pragmatic grounds.
Question 3a. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental implications of
the use of technologies such as hydraulic fracturing to produce
unconventional shale gas resources. What are the implications of shale
gas production for ground water and drinking water quality? How do
these environmental risks compare to those of other energy sources?
Answer. Hydraulic fracturing has been done for decades on
approximately one million wells in the US with, to my knowledge, no
case documented where contamination of groundwater was conclusively
linked to hydraulic fracturing operations. In the very few known
complaints of groundwater contamination made by individuals, it appears
that the contamination occurred due to loss of well integrity from
corroded well pipes, spills of chemicals and products at the surface,
or leaking surface facilities (pits, tanks, piping and hoses)--
unrelated to hydraulic fracturing.
Question 3b. Also, from an economic perspective, at what price is
shale gas production viable for the industry? Would the price certainty
of a carbon price floor be necessary for shale gas to be economic? How
do the two prices--the natural gas price and the carbon price--
interrelate and affect shale gas production?
Answer. There are a variety of industry, academic and government
estimates for the breakeven price for shale gas production depending
upon the particular basin (Barnett, Fayetteville, Woodford, Marcellus,
etc.). However, most of these ranges are in the $4/mmbtu to $7/mmbtu
range, with the average between $4 and $5/mmbtu. However, this is based
on today's technology and today's pipeline transport and storage
infrastructure. As both technology and infrastructure continue to
improve, these breakeven costs could drop over time--similar to the
decrease in development and production costs of coal-bed methane and
tight sand gas over the last decade.
Given the current view of shale development economics, a carbon
price will not be required to make this exciting new source of natural
gas available.
Natural gas and carbon price are interrelated to the extent that a
carbon price makes natural gas more attractive for power generation vs.
coal. It is difficult to place any firm numerical relationships to
carbon and gas price and the details of specific policies will affect
the overall relationship between the two prices.
Question 4a. Since natural gas has the lowest carbon content among
fossil fuels, I would expect that a carbon price would not lead to a
decline in the natural gas industry. But over the longer term, as the
economy decarbonizes, there will be pressure on gas-fired utilities, as
with coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial scale
carbon capture and sequestration with natural gas?
Answer. With sustained technology development efforts, commercial
scale carbon capture and sequestration for both coal and natural gas
could be available for wide-scale deployment after . It is more
expensive, on a dollar per metric ton basis, to capture and sequester
carbon from natural gas-fired power than from coal-fired power
(primarily due to lower inherent CO2 concentration).
However, on a total cost of electricity basis, natural gas CCS should
be less expensive than coal with CCS. Both of these factors will play
in to the timing of commercial scale deployment of both coal and gas-
fired CCS.
Question 4b. Are the economics of CCS likely to be comparable for
gas and coal consumers?
Answer. It is more expensive, on a dollar per metric ton of
CO2 captured basis, to capture carbon from natural gas-fired
power than from coal-fired power. However, depending upon coal and gas
prices, gas-fired CCS should be less expensive on a total cost of
electricity basis. The following table shows the comparison of total
electricity costs for gas with CCS and coal with CCS for a variety of
gas prices:
------------------------------------------------------------------------
$ per MWh Natural Gas Prices ($/mmbtu)
------------------------------------------------------------------------
$4 $6 $8 $10
------------------------------------------------------------------------
Coal w/ CCS ($2/mmbtu cost) 95 95 95 95
------------------------------------------------------------------------
Gas w/ CCS 67 81 96 110
------------------------------------------------------------------------
Question 4c. Could reimbursements in the form of allowances in
excess of the cap for the amount of carbon captured and sequestered
make CCS economic? And would this framework treat both coal and natural
gas fairly?
Answer. Both the Waxman-Markey and Kerry-Boxer bills allow for a
significant amount of domestic and international offsets. Providing
credit from this offset pool to CCS projects on the basis of carbon
captured and permanently sequestered could help make CCS economic,
without increasing the cap for the entire economy. Allowing all CCS
projects to compete for these offset credits will provide a level-
playing field for CCS incentives.
Responses of Lamar McKay to Questions From Senator Mark Udall
Question 1. You mentioned that the new gas shale resources would
provide a more stable resource than traditional natural gas resources,
thereby reducing the volatility in gas prices. Specifically you
mentioned that gas shale is a different kind of resource and that
geology is less of an issue. Could you please elaborate more on this?
Answer. First, gas shale is known as a ``resource play'' in
contrast to an ``exploration play.'' A resource play carries low
geological risk of not finding natural gas. The limiting factor is
economics. The application of hydraulic fracturing and horizontal
drilling has made shale gas economically viable and now allows the US
to tap the enormous potential of the shale basins.
The production volumes from a shale gas well can be higher than a
``good'' conventional well allowing a quicker response to demand.
Evidence of this is the ability of the industry to produce record
volumes of gas with fewer rigs. Historically, rig count served as a
good indicator of expected gas volumes but the gas shales have changed
this dynamic and a new index is being developed taking into account
where rigs are drilling.
Finally, many of the basins for shale gas are located near large
gas markets or in areas with existing pipeline infrastructure--giving
shale gas resources an ability to respond quickly.
Question 2. It was mentioned that some coal utilities are already
switching over to gas without incentive in place, could you elaborate
on this dynamic? Does low gas price and region play any role in some of
these changes?
Answer. Through July of this year, net US electricity generation
has fallen by 5.4% compared with the same period last year. (Source: US
DOE/EIA) Electricity generated by coal has fallen by 13.1%, while
electricity generated by natural gas has grown by 1.7%. This has been
primarily due to lower natural gas prices relative to coal prices:
Through July, average coal prices paid by US power generators rose by
13% compared with the same period last year, while natural gas prices
paid by US power generators fell by 52%. (In fact, US natural gas
consumption has fallen in other sectors of the economy this year due to
the recession, but has increased slightly in power generation.)
As you note, it is important to recognize that both natural gas and
coal prices vary widely by region. In the case of natural gas,
transportation costs are the key driver of regional price
differentials; in the case of coal, both transportation costs and coal
quality vary significantly by region.
A final factor to consider when assessing the competition between
natural gas and coal in power generation is the efficiency of the
respective power plants, which also varies widely.
Question 3. Do you believe that a transparent, market price for
carbon will help reduce volatility in the natural gas market?
Answer. A robust, economy wide carbon price could help to reduce
the volatility of natural gas prices by increasing and stabilizing gas
demand for power, the more important drivers of lower volatility will
be the game-changing gas reserves picture, significant amount of LNG
re-gas capacity (approximately 20% of current US gas demand in next few
years will be available) and gas pipeline and storage projects due to
come on line in the next few years.
A robust, economy-wide price for carbon should naturally advantage
natural gas over coal-fired power generation. In this scenario, natural
gas could play a greater role in providing electricity, allowing for
different contract structures that could bring volatility in line with
that of coal.
Response of Lamar McKay to Question From Senator Lincoln
Question 1. As you know, several recent studies have projected that
our natural gas supply is much larger than previous estimates. For
example, the Potential Gas Committee estimates that the U.S. now has a
35% increase in supply estimates from just two years ago, which is
enough they say to supply the U.S. market for a century. The Energy
Information Agency (EIA) has also predicted a 99-year natural gas
supply. I am proud that the Fayetteville Shale in Arkansas is already
producing over one billion cubic feet of natural gas per day, while
only in its fifth year of development. What role do you believe the
improvement in drilling technologies such as horizontal drilling and
hydraulic fracturing played in the estimated increase in natural gas
supply?
Answer. The use of horizontal drilling and hydraulic fracturing
technologies enables the commercial production of natural gas from
shale reservoirs. These improvements in drilling and completion
technologies have had a substantial effect on the amount of recoverable
natural gas in the US. Shale gas alone is responsible for approximately
40% of the increase in US natural gas reserves. Hydraulic fracture
stimulation of the other non-conventional gas resources (tight sands
and coal beds) is also necessary to enable commercial natural gas
production. Collectively, these non-conventional resource plays
represent most of the potential future domestic gas supply for the US.
This supply is only accessible utilizing techniques such as horizontal
drilling and hydraulic fracturing.
Responses of Lamar McKay to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source?
Answer. BP believes that the US has the domestic resource base to
support much higher levels of domestic production over the next several
decades. How that incremental supply will be used within the US economy
is best sorted by the domestic market, which has proved efficient in
directing gas supply to end-uses that have the highest value-added.
To date, transportation has not been a large consumer of natural
gas. In , about one-tenth of one percent of US natural gas
consumption was for vehicle transportation. To reduce US oil imports by
1 million b/d (net imports were 11.1 Mb/d in ) would require just
over 5 bcf/d of natural gas--or nearly 2 Tcf per year--just under 10%
of consumption.
By converting one half of America's commercial and municipal fleets
(e.g. delivery services, municipal utility services, buses and
corporate fleets) to CNG, the US could reduce oil imports by 500,000 b/
d. This would require an additional 2.5 bcf/day, or 1 Tcf/year, or 5%
of current gas production. It would reduce US emissions by 0.5%, or 30
Mt/year.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. BP believes that with a level playing field and uniform
carbon price for all fossil fuels, natural gas will be able to compete
effectively in the power sector. In lieu of a level playing field, BP
believes that targeted incentives to retire the least efficient coal-
fired generation are needed. With a level playing field for carbon, we
believe the market will choose gas to replace the retired capacity
because it offers the lowest-cost option. However, to incentivize the
conversion to natural gas via the bonus of award of carbon allowances
would cost approximately $5bn-$10bn over three years, assuming a $20/
ton carbon price. This conversion has the potential to reduce emissions
by 700 million tons between and , or $15/ton.
In the transport sector, tax incentives for the conversion of
vehicle fleets (buses, long-haul trucks) could support conversion to
natural gas over gasoline. Targeted investments in infrastructure for
natural gas transport may also be required to support the switch.
______
Responses of Edward Stones to Questions From Senator Bingaman
Question 1. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what time frame could that potentially
occur on?
Answer. The price of carbon at which using natural gas to generate
electricity becomes comparable in cost to that from coal generation
depends on three factors:
1) The price of natural gas
2) The price of coal
3) Capital costs required to maintain or build new coal power
plants relative to natural gas fired generation.
Although many projections assume increases in natural gas prices,
few project changes in coal prices. This is despite the fact that the
most likely coal power plants to be displaced by new gas fired
generation facilities use Appalachian coal, which has traded between
$42/ST and $142/ST over the last eighteen months. We believe that coal
fired power generation has been displaced by gas generation for most of
the period since August, . Said another way, during this period,
the cost of carbon at which using natural gas to generate electricity
was comparable or better than that from coal was zero.
The cost of generating electricity from coal is driven to a large
extent by the capital costs required to build and maintain highly
capital intensive coal fired power generation plants. Dow believes the
carbon cost which will force construction of gas fired generation
plants in place of coal fired power plants is between $10/MT of
CO2 and $25/MT of CO2 over the period -.
Testimony by Xcel Energy suggested the cost of carbon at which gas
fired generation displaces coal is zero today, at least for the
marginal plants, as they have shut down three coal facilities
(producing more than a Gigawatt of electricity) and replaced them with
natural gas fired generation. Similarly, Calpine states: ``Compared to
many other generation sources, natural gas power plants can be
permitted quickly and they have a much smaller footprint. In addition,
they can be built more quickly and cost less to build on a per megawatt
of capacity basis.''
Given widely proclaimed attractive economics for natural gas fired
power generation, high capital costs and uncertain costs for carbon
mitigation from coal fired generation, we believe there is a high
likelihood for a continued large scale transition to natural gas in the
power generation sector. If 80 coal fired power plants were shut down
(as advocated by other witnesses), approximately 1.8 Trillion Cubic
Feet (TCF)/yr of additional gas demand would be created. This is but
one third of the increase in gas for power consumption expected over
the period -, however. Natural gas burned for electric
generation grew from 4.3 TCF in to 6.8 TCF in (a change of
2.5 TCF/yr), a cumulative growth rate of 4.84)/01yr. Over the same
period, power generation from coal increased from 1,795,000 GWH in
to 1,994,000 GWH in , which would require the equivalent of almost
1.4 TCF/yr more gas for power generation to displace. Factoring all
three likely causes for increased gas demand for power generation (i.e.
5.8 TCF/yr), increases in gas use for power could exceed 28% of the
current natural gas supply by .
Question 2a. One area of concern about depending on our natural gas
resources is that gas has been prone to strong price spikes over the
past decade. The most recent one was just in , with prices soaring
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned
that the expanded reserves and greater ability to receive LNG shipments
could mitigate future price spikes.
Please comment on the factors that resulted in the price spike
and other recent spikes.
Answer. Since , there have been five natural gas price spikes,
each caused by lags between price signals and production response. The
lag between changes in drilling and changes in production has been
remarkably consistent, at about six months. This is the time required
to fund drilling programs, site wells, schedule crews, drill and tie
new wells into the grid. When the gas market is over supplied,
producers respond by reducing drilling, leading to a reduction in
supply. The reduction in supply eventually leads to a price spike as
demand increases.
Question 2b. Is the supply situation now such that we will be
insulated from such volatility in the future?
Answer. No. In , as in , and , drilling has
declined dramatically as price has fallen. After each trough, natural
gas demand and price rise once the economy turns, signaling the
production community to increase drilling. During the lag between the
pricing signals and new production, only one mechanism exists to
rebalance supply and demand: demand destruction brought about by price
spikes.
Some claim that the lags between price signals and drilling
response expected for shale gas will be shorter due to the reduced
drilling scope of shale type wells. However the latest available data
show natural gas production peaked with the same delay from the start
of drilling reductions as in other cycles. Clearly, the new shale gas
production was unable to mitigate the spike, which occurred less
than 18 months ago. LNG may mitigate very high gas price spikes, but
only if US gas prices are higher than elsewhere in the world. During
the spike, LNG prices in Asia and Europe were $1-2/mmbtu higher
than in the US. As a result, LNG imports in (during the spike)
were less than 50% of those in (when gas prices were more normal).
The inherent lags between changes in drilling and production created
natural gas spikes over the last ten years, and will continue to do so
after this and every trough.
Finally, weather shocks (be they hurricane damage, very cold
winters, or very warm summers) will continue, and will continue to
stress test our energy markets. Growth in supply is important, but the
best chance for reductions in volatility lie in building a flexible
demand sector (see below).
Question 2c. Are there policy options we could pursue to reduce
price volatility?
Answer. When it comes to natural gas and climate policy, Dow favors
policies that will avoid the demand destruction that occurs in natural
gas price spikes, along with policies that will allow the US to use all
of its low-carbon resources. Such policies will maintain industrial
competitiveness.
Dow also believes that the US needs a sustainable energy policy.
Climate change is an important component of a sustainable energy
policy, but it is not the only part. We have developed a list of
specific recommendations that, if implemented, would form the basis of
a sustainable energy policy.
First, aggressively promote the cleanest, most reliable, and most
affordable ``fuel''--energy efficiency. Energy efficiency is the
consensus solution to advance energy security, reduce GHGs, and keep
energy prices low. It is often underappreciated for its value. Of
particular importance is improving the energy efficiency of buildings.
Buildings are responsible for 38% of CO2 emissions, 40% of
energy use, and 70% of electricity use. A combination of federal
incentives and local energy efficiency building codes is needed.
Second, increase and diversify domestic energy supplies, including
natural gas. Nuclear energy and clean coal with carbon capture and
sequestration (CCS) should be part of the solution, as should solar,
wind, biomass, and other renewable energy sources. We believe a price
on carbon will advantage natural gas, and further incentives would only
dangerously increase inelastic demand. Therefore, Congress should not
provide free allowances or other incentive payments for the purpose of
promoting fuel switching from coal to natural gas in the power sector.
An estimated 86 billion barrels of oil and 420 trillion cubic feet
of natural gas are not being tapped. History suggests that the more we
explore, the more we know, and the more our estimates of resources
grow. EIA has said that ``the estimate of ultimate recovery increases
over time for most reservoirs, the vast majority of fields, all
regions, all countries, and the world.'' And we have the technology
that allows us to produce both oil and natural gas in an entirely safe
and environmentally sound manner. Any new fossil energy resources must
be used as efficiently as possible.
One way to maximize the transformational value of increased oil and
gas production is to share the royalty revenue with coastal states and
use the federal share to help fund research, development and deployment
in such areas as energy efficiency and renewable energy. Production of
oil and gas on federal lands has brought billions of dollars of revenue
into state and federal treasuries. Expanding access could put billions
of additional dollars into state and federal budgets.
Third, act boldly on technology policy through long-term tax
credits, and increased investment in R&D and deployment. These are
costly but necessary to provide the certainty that the business
community needs to spur investment. We didn't respond to Sputnik with
half-measures. We can't afford to respond to our energy challenges with
half-measures, either.
Fourth, employ market mechanisms to address climate change in the
most cost-effective way. There is a need for direct action now to slow,
stop, and then reverse the growth of greenhouse gas levels in the
atmosphere. We concur with the principles and recommendations of the US
Climate Action Partnership (USCAP), of which Dow is a proud member. And
we recognize that concerted action is needed by the rest of the world
to adequately address this global problem. Particular attention must be
paid to cost containment and the availability of offsets (both domestic
and international). Also, climate policy should not penalize the use of
fossil energy as feedstock materials to make products that are not
intended to be used as a fuel.
To minimize the downsides of natural gas price volatility, Congress
should adopt policies to increase the number of elastic users of
natural gas, and consider policies to increase US supply of natural
gas. A resilient natural gas market would empower US manufacturers to
create high value jobs as they did from -, during which period
US industrial gas use grew at an average rate of 2.7%/yr.
Finally, the country must advance all low carbon emitting energy
sources and ensure the availability of offsets under any cap and trade
program. EIA modeling of the House-passed energy and climate bill
indicate how to avoid a ``dash to gas'' in the power sector under a cap
and trade program. New power plants using nuclear, renewable, and coal
with associated carbon capture and sequestration (CCS) must be
developed and deployed in a timeframe consistent with emission
reduction requirements. Otherwise, covered entities will respond by
increasing their use of offsets, if available and by turning to
increased use of natural gas in lieu of coal-fired generation.
Question 3. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. Dow supports the recommendations of the US Climate Action
Partnership (USCAP) with respect to advancing CCS, which are listed in
the USCAP Blueprint for Action (www.us-cap.org). Although many of these
recommendations focus on CCS at coal-fired power plants, other
recommendations cover CCS at industrial facilities. USCAP has not,
however, developed a recommendation regarding the allocation of CCS
bonus allowances between coal-fired power producers and other
stationary sources.
Question 4. You mentioned that you utilize natural gas as a
chemical feedstock Will the shift towards a more gas intensive energy
economy impact the availability of the resource for yours and others
chemical industries? If there is a large impact to your business
structure, is there another viable feedstock alternative for your
chemical business?
Answer. There are currently no other viable feedstock materials
commercially available at the scale that our company and industry
requires. Dow is exploring alternative feedstocks via both biochemical
and thermochemical (gasification) routes. For example, Dow plans to
operate a world scale polyethylene plant in Brazil using ethylene
feedstock derived from sugar cane ethanol. In exploring possibilities
for this feedstock in the US we found that the domestic sugar cane crop
and more limited growing season can not support such a plant. Dow
testified before this committee in that coal gasification could
produce feedstocks at sufficient scale to substitute for natural gas
liquids. However, the capital cost of such technology is prohibitive. A
$19 Billion US chemical industry trade surplus in became a deficit
from - as resources became economically unavailable for
industry. Over this period, nearly 135,000 jobs were lost in our
industry. If the economy becomes more gas intensive without a carefully
considered plan to foster a resilient supply and demand balance, spikes
will continue, our business structure will require relocation to other
areas, and US manufacturing will continue to deteriorate. The key to
continued manufacturing competitiveness is a well executed,
comprehensive energy policy which addresses supply and demand, energy
security, and environmental objectives.
Question 5. All of the natural gas we're discussing here today will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales.
There has been some discussion here in Congress that the Safe
Drinking Water Act exemption for hydraulic fracturing should be
reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. We support the environmentally sound production of domestic
supplies of natural gas. However, history has shown that Congress has a
proclivity for legislating policies that increase natural gas demand
while at the same time constraining access to adequate supply. We are
not convinced that all of the natural gas that has been identified as
recoverable can overcome local resistance and other obstacles to full
production of this valuable resource. This is a major reason why we
believe that proposals to legislate incentives for increased natural
gas demand are misguided. The key to continued manufacturing
competitiveness is a well executed, comprehensive energy policy which
addresses supply and demand, energy security, and environmental
objectives.
Responses of Edward Stones to Questions From Senator Murkowski
Question 1. You may know that Senator Mendendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports, and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. History has shown that consumption of transportation fuels
is largely unresponsive to price inputs. As a result, the consumption
of natural gas for vehicles will be largely unaffected when prices
spike--potentially exacerbating shortage conditions. The key to
continued manufacturing competitiveness is a well executed,
comprehensive energy policy which addresses supply and demand, energy
security, and environmental objectives.
Dow believes there are other more prudent approaches to reduce our
dependence on foreign sources of transportation fuel while reducing GHG
emissions. For example, a combination of more efficient use of gasoline
engines (higher fuel economy), and electrification of the vehicle fleet
would be a better plan. If we built a smart electric grid which could
optimize charging plug-in electric vehicles when power was available
from base-load power (i.e. new clean coal or nuclear) or could take
advantage of the wind/solar power if available, then plug-in vehicles
could greatly reduce the reliance on oil while simultaneously reducing
the volatility of power prices. Dow is applying its long history in
electrochemistry in support of the development of an advanced
automotive battery manufacturing infrastructure in the U.S. Dow and its
Dow Kokam joint venture are beneficiaries of federal and state
incentives to help develop this new industry. We would in effect, build
an interruptible source of energy which could store solar/wind power in
a usable form while not creating a huge need for additional peaking
power. The key is the development of the advanced battery systems, a
smart grid and the increased base-load power from coal and nuclear. In
this scenario, we should also increase home energy efficiency, and by
so doing would free up base-load power for plug-in hybrids.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. It is important to note that the share of new electricity
generation capacity from natural gas is growing. It is also true that
CCS technologies are being developed and moving toward
commercialization. A policy that imposes a price on carbon would hasten
these trends.
History has shown that Congress has a proclivity for legislating
policies that increase natural gas demand whil at the same time
constraining access to adequate supply. We are not convinced that all
of the natural gas that has been identified as recoverable can overcome
local resistance and other obstacles to full production of this
valuable resource. This a major reason why we believe that proposals to
legislate incentives for increased natural gas demand are misguided.
Nonetheless, Dow believes it is important for the US to enhance its
energy security by increasing the diversity and supply of all domestic
energy sources. With respect to oil and gas exploration in the Outer
Continental Shelf, Dow believes Congress can impact the domestic energy
supply through these actions:
Congress should not re-impose the moratoria on offshore
drilling, but create a statutory construct under which drilling
can go forward in a safe and effective manner.
Any offshore energy access policy should be flexible enough
to assure that coastal views are protected and that access is
provided in areas expected to offer the greatest prospect for
productive oil and gas wells. It makes no sense to establish a
50-mile ban that closes off a huge natural gas held 35 miles
from shore.
States should share in the revenue from offshore energy
production. Given the current fiscal strain on state budgets,
offshore oil and gas revenue sharing can be of enormous benefit
to state economies if used prudently.
The granting of states the right to opt-in to offshore
drilling should be explored. This must be balanced against the
national energy security imperative and the fact that the
energy off our shores is federal land and the resource belongs
to all of the American people
The federal share of royalty and bonus bid revenues should
be dedicated to promoting energy efficiency, renewable energy
and other low-carbon technology development.
Question 3. What would be your opinion about a Low Carbon
Electricity Standard that would allow electric utilities to use a
variety of alternatives to reduce greenhouse gas emissions, including
renewables, natural gas, nuclear and hydroelectric?
Answer. If Congress imposes a federal portfolio standard on
electricity utilities, then the standard should emphasize energy
efficiency, which is the quickest, cheapest and often the easiest way
to improve the U.S. energy situation. Therefore, any low-carbon
electricity standard should allow energy efficiency to meet a
significant share of the target/goal, and that the energy efficiency
share should be beyond business as usual''.
Questions 4 and 5a. To the extent that deliverability of natural
gas to markets has been an issue in the past, should recent
improvements in pipeline infrastructure, as well as prospects for
additional projects coming online, serve as any comfort to those with
concerns about spikes in natural gas prices? I am sensitive to the
concept of our domestic industries losing global competitive advantage
under a climate bill so I want to get a sense of how your realities
play with the facts we're hearing about supply.
Answer. In general, infrastructure limitations are not the source
of spikes which affect the manufacturing industry. In the short term,
improved pipeline infrastructure within the lower 48 states may help
mitigate price disparities caused by regional shortages for gas,
especially in Northeast consuming markets. They will do little to
offset the cyclical nature of the gas market, however, which is
fundamentally inherent. Since , there have been five natural gas
price spikes across all US markets, each caused by lags between price
signals and production response. The lag between changes in drilling
and changes in production has been remarkably consistent, at about six
months. This is the time required to fund drilling programs, site
wells, schedule crews, drill and tie new wells into the grid. When the
gas market is over supplied, producers respond by reducing drilling,
leading to a reduction in supply. The reduction in supply eventually
leads to a price spike as demand increases.
In the longer term, projects such as the Alaska Pipeline would
provide a more robust energy supply to the United States, and as such,
would help reduce concerns about natural gas spikes. Dow would support
tangible action to bring this project on line.
Question 5b. Do you have reason to disagree with any of the
increased natural gas supply figures cited by the witnesses today?
Answer. We believe that all sources of supply for the North
American market are important, and that trends in the more traditional
sources of natural gas, which constitute 83% of consumption, bear
increased scrutiny.
While we acknowledge that production of shale gas looks encouraging
today, other plays have looked highly encouraging only to disappoint
later. In , EIA data show that gas produced from shale supplies
less than 10% of total consumption. We share the concerns expressed in
Dr. Newell's testimony:
More recently, some have raised concerns about whether shale can
continue to deliver relatively low-cost supply to domestic customers.
Concerns expressed relate to the relative newness of the large-scale
application of horizontal drilling and hydraulic fracturing
technologies to shales. Shales in different parts of the country are
not the same, and differences in techniques and technology are actively
being developed by the industry. This creates uncertainty in assessing
the overall resource base. Horizontal wells with fracturing to
stimulate the flow of natural gas in shale also tend to deliver their
greatest volumes in the first few years. This raises questions as to
the ability of the industry to continue to drill productively over the
long term, which is necessary to sustain higher, or even constant,
levels of production.
Long term, the natural gas supply for the United States will depend
on domestic conventional and unconventional production, and imports.
Although production from unconventional sources such as shales has been
increasing, gas recoveries from some conventional sources have been
declining dramatically. Marketed production from the Gulf of Mexico has
been declining since , and now is close to half the level in those
years.
Similarly, natural gas imports from Canada have declined
dramatically, and YTD (through August) imports are down 15% from
those in the same period in . Imports are likely to decline further
in and beyond as drilling in Canada has fallen dramatically and
consumption for oil sands converters increases. Similarly, over the
same period, LNG imports are down 50%.
While we agree recent developments in shale gas are encouraging, we
believe caution is warranted for the overall supply picture.
Question 6. You have cited in your testimony serious concerns with
the increased use of natural gas for power generation. Does that
concern extend to increased use of natural gas as a backup source to
renewable fuels? Does it extend to increased use of natural gas as a
vehicle fuel?
Answer. If electric power generation by renewable fuels with
natural gas as a back up reduces the overall demand for natural gas, we
are supportive of its use there.
Dow is concerned about the implementation of plans to use natural
gas as a vehicle fuel. Poorly executed plans might greatly increase
demand for natural gas and could, in the absence of increased supply,
drive up prices for manufacturers. As discussed in the testimony, price
spikes due to sudden increases in demand due to weather events already
occur. The use of natural gas as a vehicle fuel would likely further
amplify natural gas volatility during weather events like cold winters,
hot summers or supply disruptions unless concerted effort were made to
increase the flexibility of demand from other applications (such as the
implementation of smart grid technologies or the development of
industrial demand based on competitive and stable natural gas pricing).
A comprehensive policy approach must consider all sources of demand in
the context of both normal and extreme situations to ensure the market
is resilient to both supply and demand shocks.
It is possible that successful development of advanced energy
storage technology could provide a superior long term alternative to
natural gas as a backup source for renewables. Dow envisions its work
on advanced automotive batteries to include applications for stationary
energy storage.
Question 7. I understand that under the Kerry/Boxer bill, owners of
natural gas liquids, or NGLs like propane and butane extracted from
natural gas, are required to buy allowances as though 100% of those
NGLs are actually combusted. In practice, however, I'm told about 50%
of those liquids are used by petrochemical companies in the manufacture
of things like plastics where they aren't burned, so no emissions ever
occur. I also understand that petrochemical companies would get
compensated in the form of free allowances for liquids used in these
processes where there is no combustion. Is my understanding accurate?
Answer. The Kerry Boxer bill defines a covered entity to be any
stationary source that produces a natural gas liquid (ethane, propane,
butane, isobutene, and natural gasoline), the combustion of which would
emit 25,000 tons or more of carbon dioxide equivalent. These NGLs can
and are used as a feedstock material by the chemical industry, and many
of these NGLs are also used to produce transportation fuel. We do not
know the percentages, but it varies by NGL. (For example, ethane is
used almost entirely as a feedstock material for chemical companies).
The Kerry Boxer bill provides compensatory allowances for the non-
emissive use of NGLs as a feedstock, if allowances or offset credits
were retired for the GHGs that would have been emitted from their
combustion.
Question 8. If Congress were to enact legislation that somehow
promoted natural gas use, and natural gas was available at a consistent
$6-8 dollar per MMBtu range, how would that impact your
competitiveness?
Answer. US petrochemical competitiveness depends on a multitude of
factors, such as the relative cost of energy (including crude oil,
coal, etc.), the relative cost of new facility construction, the
strength of the economy in each global area, and the extent to which
local industry is protected by local government policies. In general,
we believe that if crude were in the $75-$100 range, and natural gas
were available at a consistent $6-$8 dollar per MMBtu range, US
petrochemical facilities could be globally competitive. We believe the
best way to achieve consistent natural gas pricing is to adopt a
comprehensive policy approach which considers all sources of demand in
the context of both normal and extreme situations to ensure the market
is resilient to both supply and demand shocks. This presumes there are
enough price-sensitive (demand-elastic) natural gas users to assure
minimal volatility. We cannot effectively plan major long term
petrochemical investments in the U.S. if the historical pattern of
natural gas price spikes persists.
Responses of Edward Stones to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source.
Answer. History has shown that consumption of transportation fuels
is largely unresponsive to price inputs. As a result, the consumption
of natural gas for vehicles will be largely unaffected when prices
spike--potentially exacerbating shortage conditions.
As part of the a comprehensive plan, Dow believes there are other
more prudent approaches to reduce our dependence on foreign sources of
transportation fuel while reducing GHG emissions. For example, a
combination of more efficient use of gasoline engines (higher fuel
economy), and electrification of the vehicle fleet would be a better
plan. If we built a smart electric grid which could optimize charging
plug-in electric vehicles when power was available from base-load power
(i.e. new clean coal or nuclear) or could take advantage of the wind/
solar power if available, then plug-in vehicles could greatly reduce
the reliance on oil while simultaneously reducing the volatility of
power prices. Dow is applying its long history in electrochemistry in
support of the development of an advanced automotive batter
manufacturing infrastructure in the U.S. Dow and its Dow Kokam joint
venture are beneficiaries of federal and state incentives to help
develop this new industry. We would in effect, build an interruptible
source of energy which could store solar/wind power in a usable form
while not creating a huge need for additional peaking power. The key is
the development of the advanced battery systems, a smart grid and the
increased base-load power from coal and nuclear. In this scenario, we
should also increase home energy efficiency, and by so doing would free
up base-load power for plug-in hybrids.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. We believe that current market incentives already support
the transition of demand historically supplied by coal and diesel to
natural gas, as evidenced by the shut down of coal fired generation
plants described in the testimony of Xcel Energy. A price on carbon
will also accelerate fuel switching to natural gas. As a result, we
believe no further incentives are necessary.
The cost of too rapid a transition to the use of natural gas in
power generation and transportation (a ``dash to gas'') would
dramatically increased prices and volatility for natural gas and demand
destruction in the industrial sector, as was seen in the period -
, when nearly 4 million US manufacturing jobs were lost.
Responses of Edward Stones to Questions From Senator Cantwell
Question 1. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years, from $5.90 up to $10.82 and then back down to
around $3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what would
actually happen in the real world with regard to fuel mix, energy costs
and investment under this kind of price volatility?
Could a well-designed price collar mitigate this sort of
volatility?
Answer. Pricing volatility increases the uncertainty of investment
returns, and therefore, the cost of borrowing money and the required
returns for energy projects. As a result, total investment decreases,
fewer projects are built, and average costs for energy increase as
demand continues to grow.
The volatility cycle is made worse because projects with lower
capital costs (i.e. natural gas fired power generation) but higher
variable costs are favored over those with higher capital costs (coal
and/or nuclear based generation) and lower variable costs. Over time,
only gas fired generation is built, worsening the impact of weather
events on the power market, further increasing the volatility in both
natural gas and power markets. Consumers pay the price through more
volatile and higher cost power and natural gas.
Price collars can help reduce volatility, but they introduce
significant additional costs to energy consumers which would be reduced
if volatility were more muted, and are available to only the largest
users. Since natural gas is a market in which daily prices are below
the mean 80% of the time, the strike price of purchased calls (which
protect consumers) are further from the underlying price than the
strike price of sold puts (which potentially obligate consumers to pay
higher than market prices). For example, on November 9th , one can
purchase a $7/mmbtu call for and sell a $4.50/mmbtu put to fund
it. The underlying price for this period is $5.46/mmbtu, so the call is
about $1.50/mmbtu from the expected price, whereas the put is less than
one dollar lower. The costs to consumers are even higher if one
considers the shape of the forward curve, which is higher over time
(i.e. in contango). Natural gas for delivery on the morning of November
10th cost $3.78/mmbtu at Henry Hub. So, a consumer would incur the
obligation to purchase gas at a price $0.75/mmbtu higher than current
cost to protect against prices rising to almost double current costs
($7/mmbtu). Executing hedges in financial markets requires a trained
staff to manage volatile energy market positions, significant
accounting expertise to comply with complicated Financial Accounting
Standard Board (FASB) requirements, and large amounts of capital to
cover margin requirements.
Large consumers can, and do, incur these costs to reduce volatility
to levels at which they are able to stay in business. Smaller
industrial, commercial and residential consumers are unable to
participate in the financial energy markets. The best solution is to
obviate the need for these ``Band Aid'' management tools by
establishing a comprehensive energy policy which addresses both supply
and demand for energy in both the short and long term, and has a
sufficient number of price-sensitive consumers. If both energy supply
and demand become resilient to shocks, volatility will be reduced.
Financial instruments will become more affordable for those who need
them and unnecessary for most.
Question 2a. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities
But an upstream cap for natural gas seems like it could achieve the
same broad coverage much more simply, by regulating less than a
thousand entities. What is the most efficient point of regulation to
achieve broad coverage of fossil carbon for natural gas?
Answer. Policymakers should consider several factors when
determining the point of regulation for a program to control GHG
emissions, including coverage, administrative complexity, equity, and
efficiency. Dow supports the recommendations of the US Climate Action
Partnership (USCAP) regarding the point of regulation for an economy-
wide cap and trade program: on transportation fuel providers, on Local
Distribution Companies (LDCs) for natural gas, and on large stationary
sources.
Question 2b. Are there any problems with mixing upstream caps for
some fossil fuels and downstream caps for others? Does an upstream cap
on all fossil fuels help to promote a consistent, economy-wide carbon
price signal necessary to transition to a low-carbon economy?
Answer. Dow supports the USCAP recommendation of a hybrid (i.e.,
combination of upstream and downstream) point of regulation for fossil
energy, as described previously. However, an ``upstream'' point of
regulation runs the risk of covering fossil energy that is used in non-
emissive ways, such as a feedstock for chemical production. Dow
believes there should not be a price signal for fossil energy used as a
feedstock material, where the carbon is embedded in a manufactured
product not intended for use as a fuel. Any such price signal could be
avoided by either (1) an exemption from coverage or (2) the awarding of
compensatory allowances.
Question 3a. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental implications of
the use of technologies such as hydraulic fracturing to produce
unconventional shale gas resources. What are the implications of shale
gas production for ground water and drinking water quality? How do
these environmental risks compare to those of other energy sources?
Answer. We support the environmentally sound production of domestic
supplies of natural gas. We defer to others with more expertise on the
environmental impacts of hydraulic fracturing to answers these
questions.''
Question 3b. Also, from an economic perspective, at what price is
shale gas production viable for the industry? Would the price certainty
of a carbon price floor be necessary for shale gas to be economic? How
do the two prices--the natural gas price and the carbon price--
interrelate and affect shale gas production?
Answer. We believe the current natural gas market dynamics suggest
that many shale gas resources are economic at the current (or slightly
higher) pricing levels. We are concerned that proposed policies will
require higher cost increments be produced, and expect volatility to
continue. In either case, we do not believe that a carbon price floor
is necessary for shale gas resources to be economic.
Question 4a. Since natural gas has the lowest carbon content among
fossil fuels, I would expect that a carbon price would not lead to a
decline in the natural gas industry. But over the longer term, as the
economy decarbonizes, there will be pressure on gas-fired utilities, as
with coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial scale
carbon capture and sequestration with natural gas?
Answer. It is as feasible as commercial scale carbon capture and
sequestration for coal. Capture will be more difficult due to the lower
concentration of CO2 (3-4% vs. 11-12% for coal fired plants)
in the effluent from natural gas power plant turbines. However, capture
for natural gas will not have to deal with some of the impurities (fly
ash, Hg, sulfur, etc.) associated with pulverized coal. Once capture is
accomplished downstream unit operations will be similar for natural
gas.
Question 4b. Are the economics of CCS likely to be comparable for
gas and coal consumers?
Answer. Yes they are comparable. See H. de Conninck, Cost and
Economics of CO2 Capture & Storage, ECN & Princeton, Near
Zero Emissions Coal workshop, Beijing .
Question 4c. Could reimbursements in the form of allowances in
excess of the cap for the amount of carbon captured and sequestered
make CCS economic? And would this framework treat both coal and natural
gas fairly?
Answer. Dow supports the USCAP recommendations for deployment of
CCS. These recommendations call for a wide variety of policies. It is
unclear what is meant by ``allowances in excess of the cap''. If it
means ``offset'', then Dow believes it will not be sufficient to drive
rapid, cost-effective deployment of CCS as there are other barriers to
CCS (see USCAP recommendations) that must also be addressed.
Question 5a. With an upstream cap on fossil carbon, industries that
use fossil fuels as feedstocks will see an increase in input prices.
Does it make sense to reimburse these industries for the fossil carbon
that they embed into their products and prevent from emission into the
atmosphere?
Answer. YES.
Question 5b. Do these reimbursements in the form of allowances in
excess of the cap make sense?
Answer. Yes it makes sense in that the net effect (of covering
feedstock fossil energy and providing compensatory allowances) should
be the same as not covering feedstock fossil energy and not providing
compensatory allowances.
Response of Edward Stones to Question From Senator Lincoln
Question 1. Mr. Stones, in your testimony you state that natural
gas price spikes have contributed to manufacturing job losses,
including a significant reduction in jobs related to the U.S.
fertilizer production capacity. How do you believe that the fertilizer
industry, and other industries that use natural gas as a feedstock,
will respond to potential price increases in natural gas?
Answer. Raising the price of energy for energy-intensive, trade-
exposed manufacturers will hurt their ability to compete against
manufacturers in countries that do not have policies to control GHG
emissions. History has shown that when faced with high and volatile
domestic process, these industries shut down and/or move to countries
with lower energy and feedstock costs. Dow is an example, wherein high
US natural gas prices in this decade have resulted in our decision to
preferentially invest in projects in Brazil, China, Kuwait, Saudi
Arabia and Libya. However, if the projections of abundant U.S. natural
gas are accurate and the gas is not forced into inelastic uses such as
power generation and transportation, we can envision the U.S. once
again as a preferred location for world scale petrochemical
manufacturing investment.
Dow believes that any climate policy that puts a price on carbon
will need to prevent carbon leakage by energy-intensive, trade-exposed
(EITE) manufacturers. We support a set aside of sufficient allowances
for EITE manufacturers until there is a globally level playing field.
Ultimately, the solution is to garner an international effort by all
major-emitting countries to reduce GHG emissions.
Responses of Richard Newell to Questions From Senator Bingaman
Question 1. I continue to hear concerns that placing a price on
carbon through climate legislation will result in significant fuel-
switching, or what has been referred to as a ``dash to gas''. The
implication is that fuel-switching will result in sharp increases in
electricity prices. Could you please give us a sense of at what carbon
price using natural gas to generate electricity becomes comparable in
cost to coal generation? What is the likelihood of a large-scale
transition to natural gas, and what timeframe could that potentially
occur on?
Answer. In our analysis of H.R. , we found that in most cases
the major compliance options were the use of international offsets and
increased investment in low-emitting electricity generating
technologies such as nuclear, fossil with carbon capture and storage
(CCS) and biomass. However, we did see a large increase in projected
natural gas use in cases where these offsets and low-emitting
electricity generation are either unavailable or very costly.
The attractiveness of natural gas versus coal as a fuel for
electricity generation depends heavily on the level of future natural
gas prices and the price of greenhouse gas emission allowances. If
natural gas prices were approximately $5 per million Btu it would make
sense to dispatch an existing natural gas combined cycle plant before
an existing coal plant when the greenhouse gas allowance price reached
a little over $30 per metric ton of CO2. However, this
crossover point rises to around $60 with $7 natural gas prices and to
around $100 with $10 natural gas prices. In the Reference Case in our
analysis of H.R. , natural gas prices to electricity generators are
just over $7 per million Btu in and just over $8.30 per million
Btu in ( dollars).
Under market and policy conditions that favor displacement of
generation from existing coal-fired plants to gas-fired generation, a
transition could occur quite rapidly, given the potential to increase
the supply of natural gas from unconventional resources, including
shale resources. Existing natural gas combined-cycle power plants can
be operated at higher utilizations rates. Experience in the first seven
years of this decade, when nearly 142 GW of new natural gas combined
cycle capacity was added in the United States, also suggests an ability
to quickly add significant amounts of new gas-fired capacity.
Question 2. One area of concern about depending on our natural gas
resources is that gas has been prone to strong price spikes over the
past decade. The most recent one was just in , with prices soaring
to about $13 per million BTU. In Dr. Newell's testimony, he mentioned
that the expanded reserves and greater ability to receive LNG shipments
could mitigate future price spikes. Please comment on the factors that
resulted in the price spike and other recent spikes. Is the supply
situation now such that we will be insulated from such volatility in
the future? Are there policy options we could pursue to reduce price
volatility?
Answer. The Henry Hub natural gas spot price peaked at a monthly
average of $12.69 per million Btu in June , an increase of over $5
from the average of $7.35 in June . Over the last 10 years similar
price spikes occurred in October because of hurricanes Rita and
Katrina, and in December and February because of very cold
weather combined with lower-than-normal natural gas inventories.
Physical fundamentals that contributed to higher natural gas prices
during the first half of included relative inventories, high
consumption, and uncertainty about future supply growth. End-of-winter
(March 31) natural gas working inventory in was 2.1 percent below
the 5-year (-07) average for that time, 22 percent below the end-
of-March level in , and the lowest winter-exit level recorded since
. Weekly natural gas inventories remained below their corresponding
5-year average levels until natural gas consumption began to fall in
August . A large increase in natural gas consumption in the
electric power sector, which was 18 percent above the 5-year average
during the first half of , was driven in part by the surge in coal
spot prices, which more than doubled between January and July .
While the supply response to lower inventories and higher consumption
over this period is clear in retrospect, there was tremendous
uncertainty about the supply potential at the time-particularly for
domestic production. Although EIA expected domestic natural gas
production to increase in , the extent of the growth in supply was
initially underestimated.
As noted in the Federal Regulatory Commission (FERC) State of
the Markets report, a review of natural gas markets in is not
complete without an analysis of financial market developments.
According to FERC, the two key financial fundamental drivers of natural
gas prices during the first half of were the large influx of
passive investments into commodities and technical trading strategies
based on trading around the prevailing market momentum. As EIA has
noted in response to earlier inquiries from Congress, the rapid
increase in natural gas prices during the first half of paralleled
movements in the prices for a wide range of commodities including crude
oil, corn, and metals. EIA's Energy and Financial Markets Initiative,
launched in September , builds upon EIA's traditional coverage of
physical fundamentals, such as energy consumption, production,
inventories, spare production capacity, and geopolitical risks, to also
assess other influences such as speculation, hedging, investment and
exchange rates, as we seek to fully understand energy price movements.
The natural gas supply situation today is noticeably different from
that of early . Natural gas inventories at the start of the -
winter season were at record levels. Improved technology and
increased efficiency have enhanced the supply capabilities and lowered
the marginal costs for production from shale, tight gas, and coal-bed
methane formations located in States such as Texas, Louisiana,
Oklahoma, Pennsylvania, and Wyoming. Furthermore, while U.S. liquefied
natural gas (LNG) import capacity utilization was below 10 percent in
, LNG imports represent an additional option for increased natural
gas supplies to the United States, particularly as new LNG supply
projects are brought into service around the world. While periods of
significant price volatility cannot be ruled out due to uncertainties
associated with weather and economic growth, sustained periods of high
prices should be mitigated by the enhanced capability to develop
domestic supply. Price volatility would tend to be lowered by
increasing the responsiveness of supply and demand to prices changes,
and by dampening forces that may amplify price changes.
Question 3. Is it your opinion that the advanced CCS bonus
allocations in the Kerry/Boxer bill are enough to jumpstart broad
deployment of CCS? I've noticed that only a maximum of 15% of the
advance allocations can be given to projects that do not employ coal.
Do you think that this will potentially restrict other industrial
CO2 emitters from being able to deploy CCS at their
facility? Are the CCS allocations enough, in your opinion, to
incentivize the gas industry to try and deploy this technology? If not,
how would you improve the CCS bonus allowance to open up the field to
all industrial stationary source emitters?
Answer. We have not analyzed the CCS provisions of the Kerry/Boxer
bill and how these may accelerate or expand carbon capture at
industrial facilities and power plants.
A broad deployment of CCS at certain industrial facilities is
included in the AEO reference case to supply CO2 for
enhanced oil recovery (EOR) operations to produce crude oil. This
activity occurs under current laws and regulations without the
enactment of the proposed legislation, and is motivated by the current
state of the technology and the projected level of crude oil prices.
The cost of carbon capture is dependent on the particular industrial
process being employed, distance from suitable EOR opportunities,
quantity of CO2 produced, capability and willingness to
invest in an existing or planned industrial facility and other factors.
We are aware that a few such projects are already in operation or are
being considered by industry, but it remain unclear as to how bonus
allocations might incentivize additional projects.
In our analysis of H.R. , the American Clean Energy and
Security Act of , we did find that the CCS provisions could lead to
significant investment in that technology by . Approximately 69,000
megawatts of new coal plants with CCS were projected to be built by
in our Basic Case. However, the cost and pace of development of
commercial-scale CCS projects are very uncertain. As a result,
alternative cases which assumed higher costs and/or limited
availability of the technology through were also prepared. The
total additions of coal plants with CCS through varied from 2,000
megawatts to 69,000 megawatts in the main cases in our report. While
some new natural gas plants with CCS were also added in our analysis of
H.R. , the additions were generally much smaller than those for
coal-based plants. In our modeling and analysis of that legislation, we
did not explicitly represent the CCS credit to industrial sources, but
did find that its provisions also lead to an increase in CO2
from industrial sources for enhanced oil recovery.
Question 4a. ICF: ANGA Climate Policy Analysis: Has EIA had an
opportunity to review the ICF International analysis of the policies
proposed by ANGA ( America's Natural Gas Alliance--large independents)
Can you provide comments for the hearing record?
Question 4b. LNG Terminals/ Gas prices: Eight terminals (7 import
and 1 export) are already operating on the East Coast, Gulf Coast,
Puerto Rico and Alaska (export). Also a terminal in Mexico serving
California markets. There are about 40 LNG terminals that are either
before FERC or being discussed by the LNG industry for North America.
What is EIA's estimate of how many LNG terminals will be in operation
by . If domestic gas prices spike in the future, under what
conditions can LNG imports act as a safety valve to moderate prices?
Answer. 4a. EIA has seen a summary presentation of the ANGA
analysis, which does not provide sufficient detail to comment,
particularly regarding their ANGA Gas Supply Case. EIA would need more
information and would have to conduct its own analyses of the proposed
policy scenarios to provide a basis for commentary on the
reasonableness of the results.
Answer. 4b. The LNG capacity existing and under construction is
more than adequate to handle EIA's projected LNG import levels through
. Our projections suggest that LNG terminal capacity will not be
fully utilized as a ``baseload'' source of natural gas supply. Rather,
imports of LNG are expected to vary with conditions in the global LNG
market. So far, LNG import increases have not coincided with U.S. gas
price increases, but rather with events elsewhere in the world. There
may be future circumstances, however, where relatively high United
States gas prices induce additional LNG volumes.
Question 5. All of the natural gas we're discussing here today will
come from both conventional and unconventional extraction methods. A
major stake of the gas future sits in extracting natural gas from tight
gas sands/shales.
There has been some discussion here in Congress that the Safe
Drinking Water Act exemption for hydraulic fracturing should be
reconsidered. Do you think a repeal of this exemption would
dramatically affect the future of natural gas extraction of these
unconventional gas sources?
Answer. Virtually all natural gas production from unconventional
resources, and a significant amount of production from conventional
resources, relies on the application of hydraulic fracturing
techniques. The impact of a repeal of the Safe Water Drinking Act
(SWDA) exemption for hydraulic fracturing would depend largely on the
specific provisions of that repeal and any subsequent regulatory action
that might be taken.
Question 6. To your knowledge, are there any reliable ``life-cycle
analyses'' of greenhouse gas emissions from current and anticipated
future natural gas development in the United States? By ``life-cycle
analyses'' I mean GHG emissions from all sources that accompany the
exploration, development (ex., diesel exhaust from compressor
stations), and production (ex., fugitive methane emissions from
production activities) of natural gas resources, as well as the
combustion of nature gas in boilers and other uses.
Answer. In , a study entitled ``Life-Cycle Assessment of
Electricity Generation Systems and Applications for Climate Change
Policy Analysis,'' was prepared by Paul J. Meier at the University of
Wisconsin. This study takes into consideration the factors you mention
above. Based on that study, when only combustion is taken into account,
natural gas generation has 50 percent of the GHG emissions of coal.
When the full life cycle is taken into consideration, natural gas
generation has 60 percent of the emissions of coal. However, while EIA
has not reviewed this study in detail, it appears that the results do
not fully account for the thermal efficiency advantage (lower heat
rate) of natural gas combined cycle generators relative to existing
coal plants.
Question 7. A recent published analysis of the life-cycle
greenhouse gas emissions of the natural gas industry indicates that,
``The natural gas supply chain is the second largest source of
greenhouse gas emissions in the U.S., generating around 132 million
tons of CO2 equivalents annually.'' (EPA ``Inventory of US
Greenhouse Gas Emissions and Sinks: -,'' Office of Global
Warming, , quoted in Jaramillo, et al., ``Comparative Life Cycle
Emissions of Coal, Domestic Natural Gas, LNG, and SNG for Electricity
Generation,'' ) Has EIA performed any similar analyses of life-
cycle GHG emissions from the development and use of natural gas as
compared to coal? If so, please share such analyses with the Committee.
Answer. EIA has not conducted a formal life-cycle analysis of
greenhouse gas emissions from natural gas. However, the latest EIA and
EPA data do not appear to support the quote cited in your question. For
example, according to EIA's greenhouse gas (GHG) emissions
inventory, total U.S. greenhouse gas emissions in were 7,282.4
million metric tons of carbon dioxide equivalent (MMTCO2e).
Total carbon dioxide emissions from combustion of fossil fuels were
5,990.9 MMT in , with oil, coal and natural gas accounting for
2,579.9 MMT, 2,162.4 MMT, 1,237.0 MMT, respectively. According to EPA,
emissions from the natural gas supply chain encompassing production
processing, transportation, and distribution but excluding end-use
consumption were 133,4 MMTCO2e in . The natural gas
supply chain excluding combustion is clearly a much smaller GHG
emissions source than combustion of any of the three fossil fuels. By
way of comparison, EPA reports that non-combustion emissions from coal
mining were 57.6 MMTCO2e in , all of which consisted of
methane. That estimate does not include emissions from the
transportation of coal. In , coal was roughly 40 percent of total
freight rail ton-miles in the United States. Using this share to
allocate a portion of total freight rail fuel use to coal, coal
transport by rail is estimated to account for an additional 17.5 MMT of
carbon dioxide emissions, for a total of at east 75.1 MMT.
Responses of Richard Newell to Questions From Senator Murkowski
Question 1. You may know that Senator Menendez and I are both on a
bill to promote the development of natural gas vehicles. NGV advocates,
myself included, have pointed out that natural gas as a transportation
fuel reduces carbon emissions, offsets petroleum imports, and provides
an economic boost here at home by using natural gas in place of
imported petroleum. Given the recent findings concerning the increased
availability of natural gas supplies in North America and here in the
U.S. should we be doing more to advance the use of natural gas as a
transportation fuel?
Answer. The EIA does not advocate policy. However, our prior
analysis has shown that market forces alone would not be sufficient to
increase natural gas use in the transportation sector. For light-duty
vehicles, impediments to increased market penetration include a lack of
natural gas vehicle (NGV) offerings by vehicle manufacturers, less
driving range, less cargo capacity, higher vehicle costs, and an actual
and perceived lack of refueling infrastructure. While natural gas use
has increased significantly in transit buses, success in other heavy
truck applications has been limited due to the reasons stated above.
Incentives that reduce the net cost of NGVs or NGV refueling
infrastructure to potential purchasers would tend to increase the rate
of NGV penetration.
Question 2. Currently there are serious regulatory obstacles
positioning in front of domestic energy development. Particularly,
surface coal mining rules are under serious assault and offshore oil
and gas development is facing increasing scrutiny from at least three
different federal agencies. Can the panel speak to how we ever get to a
point of more natural gas power plants or., for that matter, clean coal
if, despite policies encouraging the advancement of these new and
exciting power sources, we simply can't access and produce the basic
resource?
Answer. While EIA takes no position on the appropriate regulatory
treatment for approving the development of natural gas and coal
resources, in EIA's projections both of these fuels play an important
role in energy markets in the Nation for many years. In , coal
accounted for 49 percent and natural gas accounted for 21 percent of
total electricity generation. Despite growth in the use of other fuels,
coal and natural gas accounted for 84 percent of the increase in
electricity generation between and . Analysis of specific
proposed limitations would be required to assess their possible
impacts.
Question 3. What would be your opinion about a Low Carbon
Electricity Standard that would allow electric utilities to use a
variety of alternatives to reduce greenhouse gas emissions, including
renewables, natural gas, nuclear and hydroelectric?
Answer. Without a specific proposal it is difficult to speculate on
possible impact. A low-carbon electricity standard, like a greenhouse
gas cap-and-trade program or carbon tax, would provide an incentive to
electricity producers to increase their use of low-to zero-emitting
technologies. However, an output-based low-carbon electricity standard
might not provide as large an incentive to electricity consumers to
invest in energy efficiency because it would generally lead to a
smaller increase in electricity prices than would a comparable
greenhouse gas cap-and-trade program or carbon tax.
Question 4. To the extent that deliverability of natural gas to
markets has been an issue in the past, should recent improvements in
pipeline infrastructure, as well as prospects for additional projects
coming online, serve as any comfort to those with concerns about spikes
in natural gas prices?
Answer. Natural gas price spikes occur for a number of reasons, one
of which involves limitations imposed by pipeline infrastructure.
Pipeline-induced price spikes are generally the result of insufficient
capacity into a region experiencing particularly cold temperatures.
Pipeline constraints tend to raise prices at the receiving end and
lower them at the supply source to enable markets to balance.
EIA estimates that natural gas pipeline capacity additions totaled
approximately 45 billion cubic feet per day (Bcf/d) in , roughly
triple the amount of capacity added in and the greatest amount of
pipeline construction activity in more than 10 years. While EIA expects
another sizeable increase in pipeline capacity in , it likely will
be smaller than the increase recorded in . Recent natural gas
pipeline expansion has created enhanced connectivity between regions
that have historically been net sellers, producing more than they
consume, with those that have been net buyers of natural gas. For
example, the Rockies Express (REX) pipeline, which provides 1.8 Bcf/d
of transport service between Wyoming and Ohio, now offers a crucial
outlet for previously constrained production in Wyoming, Colorado and
Utah. As pipeline infrastructure has expanded and bottlenecks have been
removed, regional price differentials (known as ``basis spreads'') have
narrowed and in some eases prices have been reduced.
However, despite the robust increase in pipeline capacity in recent
years, temporary periods may persist when demand exceeds available
supply in some regions due to local limitations in the pipeline
network. This is particularly relevant for the Northeast, where peak
winter heating demand can reach 30 Bcfld on extremely cold days
(Northeast natural gas consumption averaged 10.9 Bcf/d during the
summer of ). While pipeline infrastructure is extensive in the
Northeast, and capacity additions continue, the regional network
remains vulnerable to constraints that result in high prices when
demand temporarily surges during the coldest periods in winter.
Responses of Richard Newell to Questions From Senator Sessions
Question 1. If the transportation sector moves towards natural gas,
how will this affect the price of natural gas, the United States' crude
oil imports, greenhouse gas emissions, other energy sectors that
currently use this energy source?
Answer. Any increase in natural gas demand would be expected to
increase natural gas prices. Since increased natural gas use in
transportation would likely displace petroleum, which currently
provides 96 percent of all energy used for transportation in the United
States, imports of petroleum would be apt to decrease. Since natural
gas has a lower carbon content per unit of energy than oil, the direct
effect would be to reduce greenhouse gas emissions in the
transportation sector.
Recent experience suggests that the electric power sector would be
the most responsive to changes to natural gas prices, potentially
inducing an increased use of coal, nuclear, as well as renewable
sources. As such, the potential impact on greenhouse gas emissions in
the electric power sector is hard to assess without a clearer
definition of market and/or policy changes.
Question 2. What incentives or regulatory changes are necessary to
effectively enhance the use of natural gas over coal, diesel, or
gasoline? And the cost associated with the switch?
Answer. Key impediments to significant increases in natural gas use
in the transportation sector are the lack of refueling infrastructure,
the higher cost of natural gas vehicles (NGVs), limited vehicle
offerings by manufacturers, reduced driving range, and reduced cargo
capacity. Incentives that reduce the net cost of NGVs or NGV refueling
infrastructure to potential purchasers would tend to increase the rate
of penetration of natural gas into the transportation sector.
EIA's previous analyses have shown that placing an implicit or
explicit value on carbon dioxide emissions tends to dissuade the use of
coal in the electric sector. However, such policies do not necessarily
increase the amount of generation fueled by natural gas in the long
term given the combination of a projected reduction in total
electricity consumption and the possibility of increased supply from
non-fossil generation sources such as nuclear and renewables. Energy
and Natural Resources.
Question 3. Could you please explain in further detail why the
increase in natural gas and oil production off the Outer Continental
Shelf would have no impact on the price of these commodities?
Answer. The increase in natural gas and oil production would likely
have a small impact on the price of these commodities. The fact that
the production change for both crude oil and natural gas is modest and
gradually introduced to the market over a 20-year period limits the
price impact. For crude oil, the main factor is that the market is
global and one for which the projected increase of 0.54 million barrels
per day in production by from OCS areas that were under moratoria
until late represents a 0.5 percent increase in projected global
world oil supply. According to EIA analysis included in the Annual
Energy Outlook (AE) this amount of additional supply would
result in about a $1.33 decline in the world oil price, from $131.76
per barrel to $130.43 per barrel (in dollars). Crude oil producers
could also react to this level of increase by delaying the production
of other fields that are similar in size around the world, which would
lessen the price impact.
For natural gas, the 0.6 trillion cubic feet increase in OCS
production expected by in EIA's AE analysis represents a 2.6
percent increase in projected domestic gas production, resulting in a
decline in that year's projected price of $0.21 per thousand cubic feet
(Mcf), from $8.61 per Mcf to $8.40 per Mcf (in dollars).
Responses of Richard Newell to Questions From Senator Cantwell
Question 1. I think it is very important that we ensure that
climate policy doesn't introduce unnecessary volatility into markets
for oil and natural gas. We've seen gas prices fluctuate sharply over
the past two years, from $5.90 up to $10.82 and then back down to
around $3.40 where we are now. I think we all agree that this sort of
uncertainty isn't good for energy producers or consumers.
What do modeling results and forecasts tell us about what
would actually happen in the real world with regard to fuel
mix, energy costs and investment under this kind of price
volatility?
Could a well-designed price collar mitigate this sort of
volatility?
Answer. Price volatility has the effect of inducing uncertainty in
producer and end-user investments in long-lived capital assets. In
EIA's analysis of H.R. , it is assumed that allowance prices will
rise smoothly at the rate of return that investors would require. Our
analysis does not address the volatility in allowance prices that might
occur in the actual market. A well designed price collar could dampen
the volatility in prices that might otherwise occur.
Question 2. In thinking about alternative approaches to climate
change policy, one important consideration is the point of regulation,
especially with regard to an emissions cap. Both the House and Senate
bills propose downstream caps by regulating thousands of emitting
entities.
But an upstream cap for natural gas seems like it could
achieve the same broad coverage much more simply, by regulating
less than a thousand entities. What is the most efficient point
of regulation to achieve broad coverage of fossil carbon for
natural gas?
Are there any problems with mixing upstream caps for some
fossil fuels and downstream caps for others? Does an upstream
cap on all fossil fuels help to promote a consistent, economy-
wide carbon price signal necessary to transition to a low-
carbon economy?
Answer. An important characteristic of any cap-and-trade system is
how comprehensively it covers all sources of emissions. The point of
regulation decision is generally made to ensure comprehensive coverage
while also minimizing the number of reporting entities and the burden
placed on them. For natural gas this can be difficult because natural
gas can take so many paths between production wells and the end-users.
Any single point of regulation--i.e., wellhead, re-gasification plants,
processing plants, pipelines, or local distribution companies--would
not be comprehensive because some portion of the natural gas consumed
does not pass through each point. As a result, comprehensive coverage
of natural-gas-related greenhouse gas emissions may require a mix of
regulatory points.
Question 3. With the recent advances in drilling technology in the
gas industry, domestic gas reserves shot up by more than 35 percent
this year, which of course is terrific news for the gas industry and
potentially for our efforts to address climate change by reducing
greenhouse gas emissions.
But I'm wondering about the broader environmental
implications of the use of technologies such as hydraulic
fracturing to produce unconventional shale gas resources. What
are the implications of shale gas production for ground water
and drinking water quality? How do these environmental risks
compare to those of other energy sources?
Also, from an economic perspective, at what price is shale
gas production viable for the industry? Would the price
certainty of a carbon price floor be necessary for shale gas to
be economic? How do the two prices--the natural gas price and
the carbon price--interrelate and affect shale gas production?
Answer. In June of , the Potential Gas Committee (PGC)
estimated that, as of the end of , the total natural gas resource
base of the United States was 2,074 trillion cubic feet (Tcf)--35
percent more than the PGC had estimated as recently as . EIA has
reported that end-of-year proved reserves of natural gas not only
covered production, but increased 13 percent in and a further 3
percent in , largely as a result of the recognition of shale gas
resources. Proved reserves are a relatively small subset of the
ultimately recoverable resource base. They are those volumes of natural
gas that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Technically recoverable
resources are less certain, can be uneconomic, and include estimates of
undiscovered volumes.
Extraction and use of any energy source involves local
environmental concerns. For natural gas from shale, these concerns have
centered primarily on water.
Observers have raised several water issues related to hydraulic
fracturing:
fracturing fluids might enter ground water and fresh water
aquifers from a well bore during the hydraulic fracturing
operation itself;
waste water might enter ground water because of improper
treatment and release of fluids that return up the well bore
after the treatment; and
the volume of water drawn for the treatment might stress an
area's resources, or the returned waste water overwhelm local
water treatment capabilities.
Leakage directly from the fractured shale into groundwater is
unlikely. The major shale gas plays range in depth from 5,000 feet to
13,000 feet. Most fresh water aquifers lie at much shallower depths--
typically, less than 1,000 feet. It is unlikely that hydraulic
fracturing of shale would force fracturing fluids through thousands of
feet of rock up into a fresh water aquifer.
Leakage is possible if a well's integrity were compromised through
a variety of mechanisms, including casing leaks, tubing leaks,
insufficient cementing, or surface casing set too shallow, in which
case fluids could circulate up the outside of the casing and into an
aquifer (or other groundwater formations). Operators can minimize these
risks through inspection and testing of the well and downhole equipment
before high-pressure pumping of the fracturing treatment begins. Under
current law, State and local authorities manage the likelihood of such
incidents through regulation and enforcement of well construction,
including the casing and cementing program.
After operators finish a fracturing job on a well, some of the
injected fluid flows back to the surface. This returned fluid, though
mainly water and sand, includes small amounts of added chemicals
(typically less than 1 percent of the total volume) and can include
contaminants leached from the shale formation. Operators can address
wastewater problems in several ways: by treating and recycling produced
fracturing fluids for use in other fracturing treatments, by injecting
this wastewater into deep underground disposal wells, or by
sufficiently treating the wastewater making it suitable for release
back into the natural environment. Where central treatment or disposal
facilities do not have the capacity to deal with large volumes,
operators can and do use mobile treatment and recycling systems.
Nonetheless, surface spills are possible through careless handling of
materials and equipment, poorly trained personnel, and poorly
maintained equipment. Operators generally have an incentive to avoid
such spills, which can be costly.
With regard to the second part of the question, development of
natural gas from shales through horizontal drilling and hydraulic
fracturing is still a relatively new technological development, and
each shale play in the United States has different individual
characteristics. Few shale plays (other than the Barnett in Texas) have
seen substantial development, so the price at which shale development
will be economically viable in a given shale play is extremely
difficult to assess with any degree of confidence.
That said, prevailing prices in , which dropped at the Henry
Hub in Louisiana below $5 per million British thermal units (MMBtu)
early in the year and averaged only about $4, did have significant
effects on drilling although they did not impact shale plays to the
same degree. Our most recent review of the available literature
regarding breakeven costs for major U.S. natural gas shale plays shows
a range from the relatively lower-cost Haynesville play (about $3 to a
little over $4 per MMBtu) to the relatively high-cost Woodford shale (a
little over $4 to about $7 per MMBtu). The well-developed Barnett play,
and the Fayetteville play, range from about $4 to about $5 per MMBtu
and the Marcellus play in the Northeast is at a little below $4 per
MMbtu. These estimates, collated from Deutsche Bank, Ross Smith Energy
Group, Bentek Energy Consulting, and Range Resources do not necessarily
reflect the same assumptions about ultimately recoverable reserves, up-
front capital cost, or return on investment. Furthermore, financial
factors such as hedging could allow producers to lock in a rate of
return and maintain production activities even if prices fall.
From a technology-application perspective, as a play develops,
costs tend to decline and well performance tends to increase as
companies figure out what works and what doesn't in that particular
play. This would suggest a lower economically viable price. On the
other hand, the initial wells reported in the literature will tend to
be drilled on the best prospects or in the best areas, and so the gas
price required for economic viability could ultimately be higher for
the average well in the play. There often is a significant economic
difference between the core and non-core areas of any natural gas play.
Shale gas price and carbon prices are likely to be interrelated to
the extent that natural gas can be used in combined-cycle power plants,
which benefit from improved efficiency and reduced CO2
emissions when compared to coal-fired power plants. Significant carbon
prices are likely to discourage the use of coal for electric power
generation. The availability of domestic shale gas resources, combined
with significant carbon prices, could encourage the use of natural gas
as a substitute for coal, especially if renewables, nuclear power,
carbon capture and sequestration, and offsets are either too costly or
otherwise unavailable for use to comply with a cap and trade program.
Question 4. Since natural gas has the lowest carbon content among
fossil fuels, I would expect that a carbon price would not lead to a
decline in the natural gas industry. But over the longer term, as the
economy decarbonizes, there will be pressure on gas-fired utilities, as
with coal-fired ones, to adopt carbon capture and sequestration
technologies.
What is your assessment of the feasibility of commercial
scale carbon capture and sequestration with natural gas?
Are the economics of CCS likely to be comparable for gas and
coal consumers?
Could reimbursements in the form of allowances in excess of
the cap for the amount of carbon captured and sequestered make
CCS economic? And would this framework treat both coal and
natural gas fairly?
Answer. In our analysis of H.R. , we found that in most cases
the major compliance options were the use of international offsets and
increased investment in low-or zero-emitting electricity generating
technologies like nuclear, fossil with carbon capture and storage
(CCS), and biomass. However, if these options were less available than
expected we did see a large increase in natural gas use. The reason
that we did not project a large increase in natural gas use in most
analysis cases is that it generally takes a fairly significant
greenhouse gas allowance price to make that attractive, and other
options can become economical at a lower allowance price. The
attractiveness of natural gas versus coal depends heavily on what
happens to future natural gas prices. We find that if natural gas
prices were approximately $5 per million Btu it would make sense to
dispatch a natural gas combined-cycle plant before a coal plant when
the greenhouse gas allowance price reached a little over $30 per metric
ton of CO2. However, this crossover point rises to around
$60 with $7 natural gas prices and to around $100 with $10 natural gas
prices. In the Reference Case in our analysis of H.R. , natural gas
prices to electricity generators are just over $7.00 per million Btu in
and just over $8.30 per million Btu in ( dollars).
While we have not analyzed the CCS provisions of the Kerry/Boxer
bill, in our analysis of the H.R. we did find that the CCS
provisions could lead to significant investment in the technology by
. Approximately 69,000 megawatts of new coal plants with CCS were
projected to be built by in our Basic Case. However, the cost and
pace of development of commercial scale CCS projects are very
uncertain. As a result, alternative cases which assumed higher costs
and/or limited availability of the technology through were also
prepared. The total additions of coal plants with CCS through
varied from 2,000 megawatts to 69,000 megawatts in the main cases in
our report. While some new natural gas plants with CCS were also added
in our analysis of H.R. , the additions were generally much smaller
than those for coal-based plants because of the higher price of natural
gas relative to coal.
Question 5. I was intrigued that a price on carbon did not
necessarily result in fuel switching from coal to natural gas. When the
carbon price is high due to limited availability of offsets for
example, however, EIA projects substantial fuel switching.
Are there factors, other than international offset
availability, that can lead to similar fuel switching?
If the cap were to decline at a substantially slower rate
than the House-passed bill initially, would such a policy
provide sufficient lead time to avoid or mitigate such a risk
of rapid fuel switching and premature retirement of existing
power plants in the near term?
Answer. As noted in the previous answer, the attractiveness of
natural gas versus coal depends heavily on future natural gas prices.
We find that if natural gas prices were approximately $5 per million
Btu it would make sense to dispatch a natural gas combined-cycle plant
before a coal plant when the greenhouse gas allowance price reached a
little over $30 per metric ton of CO2. However, this
crossover point rises to around $60 with $7 natural gas prices and to
around $100 with $10 natural gas prices. In the Reference Case in our
analysis of H.R. , natural gas prices to electricity generators are
just over $7.00 per million Btu in and just over $8.30 per million
Btu in ( dollars).
Since fossil fuels account for virtually all of the greenhouse gas
emissions in the electric power sector, the emissions reductions in the
House bill cannot be achieved without substantial switching to low-or
zero-carbon options such as nuclear and renewables. Taking account of
differences in the carbon content of coal and natural gas and the
greater efficiency of modern gas-fired generators, the emission rate
for natural gas is about 40 percent of the corresponding rate for coal
so the potential emissions reductions due to switching from coal to
natural gas are not sufficient to meet the specified long term caps.
Furthermore, the carbon prices add considerably to the cost of all
fossil-fired generation so that these plants are less economic compared
to nuclear and renewables. However, a slower emissions cap trajectory
would decrease the required emissions reductions in the near term and
likely necessitate fewer retirements of existing plants and less
switching out of fossil fuels during that initial period. The higher
caps during that period would also decrease the corresponding carbon
prices and lessen the impact on the generation costs for fossil-fuel
capacity. EIA, however, has not evaluated any scenarios that assumed
differing levels of greenhouse gas caps than those specified in the
legislation.
Response of Richard Newell to Question From Senator Lincoln
Question 1. According to your testimony, the EIA estimated that
about 1/3rd of the natural gas consumed in was used for electric
power generation, 1/3rd for industrial purposes and the remaining 1/3rd
in residential and commercial buildings. However, only a small portion
is used in the transportation sector, predominantly at compressor
stations, although some is used for vehicles. How do you view the use
of natural gas in our transportation sector changing or increasing in
the future, particularly with heavy duty or fleet vehicles?
Answer. The AE projects modest growth in natural gas use in
highway vehicles, increasing from 0.02 quadrillion Btu in to 0.08
quadrillion Btu in . The majority of this growth occurs in heavy-
duty vehicles, but incremental vehicles costs, lack of retail refueling
infrastructure, and costs associated with installation of on-site
natural gas refueling impede significant gains in market share. Without
significant increases in natural gas refueling infrastructure and
reductions in incremental vehicle costs, market penetration will likely
be limited to fleet applications where the economic benefits of natural
gas can be captured by owners, or to fleet applications legislatively
required to use alternative fuels like natural gas.
Response of Richard Newell to Question From Senator Mark Udall
Question 1. It was mentioned that some coal utilities are already
switching over to gas without incentive in place, could you elaborate
on this dynamic? Does low gas price and region play any role in some of
these changes?
Answer. The key factor in recent fuel switching from coal to
natural gas has been the dramatic fall in natural gas prices that has
occurred during the economic downturn as industrial demand for natural
gas has fallen. For a brief time in recent months, average spot natural
gas prices actually fell below $3 per thousand cubic feet. At these
prices, modern natural gas combined-cycle plants can operate at a lower
cost than many coal plants. However, since natural gas prices to
electricity generators are projected to exceed $5 per million Btu in
and reach just over $7 per million Btu in and just over $8.30
per million Btu in ( dollars) in our latest Reference Case, we
expect that it will soon become cheaper to dispatch coal plants ahead
of combined-cycle plants fueled with natural gas when both types of
units are available for use.
Appendix II
Additional Material Submitted for the Record
----------
Statement of the Interstate Natural Gas Association of America
Mr. Chairman and Members of the Committee: The Interstate Natural
Gas Association of America (INGAA) asks that this written testimony be
included in the record of the hearing held on October 28th, . The
members of INGAA appreciate the Committee conducting a hearing on
natural gas and its role in reducing greenhouse gas emissions. As the
Senate develops climate change policy, we ask that the Committee keep
in mind that natural gas is available now, and will be available in the
coming decades, in sufficient quantity to play a major role in reducing
greenhouse gas emissions in the Unites States.
Mr. Chairman, INGAA represents the interstate and interprovincial
natural gas pipeline companies in North America. Our members operate
approximately 220,000 miles of large-diameter, natural gas transmission
pipeline in the U.S. alone. This infrastructure continues to grow,
especially in response to recent development of supplies of
unconventional natural gas. According to the Energy Information
Administration (EIA), almost 4,000 miles of new natural gas
transmission pipeline was completed in --a level of construction
that EIA has called ``exceptional.'' Much has been said about the
dramatic increase in natural gas supply in recent years. It is also
worth noting that natural gas infrastructure, especially new gas
transmission pipeline capacity, has increased dramatically as well.
Given the prospects for continued growth in unconventional natural
gas supply (principally, shale gas), INGAA believes that billions of
dollars in additional investment in pipeline, storage and other
midstream infrastructure will be required through . The INGAA
Foundation recently released a study, Natural Gas Pipeline and Storage
Infrastructure Projections Through , which uses multiple market
scenarios to estimate the range of infrastructure investment that will
be needed in coming decades. The key findings of this report include:
A range of between $133 and $210 billion will need to be
invested in midstream natural gas infrastructure over the next
20 years (between $6 and $10 billion annually), primarily to
attach increased domestic natural gas production from
unconventional shale basins and tight sands to the existing
pipeline network.
The U.S. and Canada will need to construct between
approximately 29,000 and 62,000 miles of additional natural gas
transmission pipelines, and between 370 and 600 billion cubic
feet (Bcf) of additional storage capacity.
In the Base Case projection, annual natural gas consumption
in the U.S. and Canada is projected to grow from about 26.8
trillion cubic feet (Tcf) in to 31.8 Tcf by , which
equates to total market growth of 18 percent, or an annual
growth rate of 0.8 percent. The two alternative cases, High Gas
Growth and Low Electric Load Growth, bracket reasonable ranges
of future natural gas consumption.
About three-fourths of the market growth will occur in the
power sector. The growth rate of natural gas consumption in the
electric generation sector is the predominant determinate of
the growth rate of the entire natural gas market. Electric load
growth, the timing and development of renewable generation
technologies, the deployment of clean coal with carbon capture
and storage, and the expansion of nuclear generation are areas
of uncertainty.
Interregional transmission pipeline capacity between major
areas in the U.S. and Canada currently is approximately 130 Bcf
per day. By , the need for interregional natural gas
transport is likely to increase by between 21 and 37 Bcf per
day, which will drive the development of additional pipeline
and storage capacity. Interregional natural gas transport
capacity will be needed even without a growing North American
natural gas market due to shifts in the location of natural gas
production. The need for laterals to access new production and
deliver natural gas to new customers, such as new gas-fired
power plants, also will drive investment.
The record of natural gas supply AND infrastructure development in
recent years provide a strong foundation for policymakers to move
beyond to old assumptions about natural gas. Today, natural gas is
domestically abundant, reliable and cost effective. The pipeline
industry continues to attract billions of dollars in private capital to
expand infrastructure, due in large part to the stable regulatory
environment for natural gas pipelines. The Federal Energy Regulatory
Commission process for reviewing, approving and siting natural gas
infrastructure generally works well in supporting the construction of
necessary infrastructure on a timely basis. The ability to develop
natural gas infrastructure on a timely and efficient basis reduces
natural gas price volatility and creates additional competitive
opportunities for natural gas consumers. In short, the natural gas
model works well for the nation. And given its environmental attributes
as the cleanest fossil fuel, natural gas can and should play a larger
role in achieving compliance with climate change mandates than is
suggested by the economic modeling of the climate bills introduced to
date.
Two issues regarding natural gas pipelines and climate change
legislation bears specific mention to this Committee:
First, both S. (the Clean Energy, Jobs and American
Power Act) and H.R. (the American Clean Energy and
Security Act, as passed by the House) define FERC-
jurisdictional interstate natural gas pipelines as regulated
industrial entities, and therefore require pipelines to
purchase emission allowances and incur other compliance costs.
These pipelines, however, would be the only regulated
industrial entities that could not unilaterally adjust the
price of their product or service to reflect the cost of
compliance. Instead, these pipelines must seek approval from
the Federal Energy Regulatory Commission (FERC) to recover such
costs in the rates charged for pipeline transportation service.
Traditional rate case proceedings are ill-suited to addressing
these costs, because such costs are likely to be unpredictable
and are likely to vary from year to year. In addition,
pipelines will be price takers in the allowance market and will
have little practical ability to control the magnitude of such
costs. What's more, the current market environment for pipeline
transportation service has been one in which many pipelines and
their customers have negotiated rates or settlements wherein
the pipeline has contractually agreed not to seek a rate
adjustment for years into the future. In fact, many of the new
pipelines built to transport unconventional natural gas
production to consumers are premised on negotiated rate
contracts with terms that last a decade or more. This
legislation would add a significant new cost that was not
anticipated when such contracts were entered. Yet, if these
compliance costs cannot be recovered by the pipelines, their
ability to meet investor expectations and attract capital in
the future would be negatively impacted.
INGAA urges the Congress to clarify this situation by
directing the FERC to create a rate ``tracker'' that would
allow pipelines to recover the costs associated with a cap-and-
trade program, notwithstanding current contractual
arrangements. Without such a tracker mechanism, many pipelines
could face financial stress not of their own making, as a
result of a change in national policy. This would be an
unintended consequence that requires Congressional action as
climate change legislation moves forward.
Second, INGAA members operate pipeline systems that span
multiple states and often multiple regions of the country. A
hodge-podge of state or regional greenhouse gas regulations
would undermine the cost-effective management of these pipeline
systems and ignores the inherently interstate nature of our
facilities and this commerce. To provide an effective response
to what is, after all, a global issue, INGAA believes that
federal climate change policy must preempt state and regional
cap-and-trade systems, greenhouse gas reporting requirements,
and greenhouse gas reduction performance standards. S. ,
unfortunately, goes in the wrong direction by encouraging
states to develop their own greenhouse gas programs and
regulations. INGAA hopes that you will support a federal
response that includes clear federal preemption of duplicative
state regulations and that also supersedes any inconsistent
regulations adopted pursuant to other federal statutes.
Mr. Chairman, thank you for the opportunity to submit written
comments on this important set of issues. Please let us know if you
have any questions.
______
Statement of the American Public Gas Association
The American Public Gas Association (APGA) appreciates this
opportunity to submit testimony and commends the Committee for holding
this important hearing on the role of natural gas in mitigating climate
change.
APGA is the national association for publicly-owned natural gas
distribution systems. There are approximately 1,000 public gas systems
in 36 states and over 720 of these systems are APGA members. Publicly-
owned gas systems are not-for-profit, retail distribution entities
owned by, and accountable to, the citizens they serve. They include
municipal gas distribution systems, public utility districts, county
districts, and other public agencies that have natural gas distribution
facilities.
APGA remains extremely concerned in regard to the potential impacts
climate change legislation will have on public gas systems. Climate
change legislation will certainly have a significant impact upon the
natural gas industry as well as on the price of natural gas.
Natural gas is the cleanest, safest, and most useful of all fossil
fuels. It is also domestically produced, abundant and reliable. The
inherent cleanliness of natural gas compared to other fossil fuels, a
growing domestic supply and superior wells-to-wheels efficiency of
natural gas equipment, means that substituting gas for the other fuels
will reduce the emissions of the air pollutants that produce smog, acid
rain and exacerbate the ``greenhouse'' effect. For these reasons, it is
logical to assume that natural gas will play a critical role in the
reduction in greenhouse gas emissions.
Natural gas is the lowest CO2 emission source per BTU
delivered of any fossil fuel. National policy should facilitate the use
of natural gas instead of other more carbon-intensive fuels where
appropriate. For example, using gas-fired water heaters for homes
instead of electric resistance water heaters ultimately reduces
greenhouse gas emissions by one-half to two thirds. Simply put,
increasing the direct-use of natural gas is the surest, quickest and
most cost-effective avenue to achieve significant reductions in
greenhouse gases and therefore should be a critical component of any
climate change legislation.
In June, APGA, the Interstate Natural Gas Association of
America and others released a study conducted by the Gas Technology
Institute (GTI) entitled ``Validation of Direct Natural Gas Use to
Reduce CO2 Emissions''. A copy of the study is attached to
this testimony. The study analyzed the benefits of increased direct use
of natural gas as a cost-effective means to increase full fuel cycle
energy efficiency and reduce greenhouse gas emissions. Using the
National Energy Modeling System (NEMS), the study concluded that the
increased direct use of natural gas will reduce primary energy
consumption, consumer energy costs, and national CO2
emissions. A win-win-win for U.S. environmental and energy policy.
The study demonstrated, among other things, that using revenues
such as allowances from a cap-and-trade program to provide incentives
for original natural gas end-use applications and conversions to
natural gas appliances from their electric counterparts will provide
substantially higher and immediate return values in energy efficiency
and carbon output reductions than an equal investment in electric
applications. Another finding of the study was that subsidies provided
to increase the direct use of natural gas, together with increased
efforts in consumer education and R&D funding, would provide the
following benefits by :
1.9 Quads energy savings per year;
96 million metric tons CO2 emission reduction per
year;
$213 billion cumulative consumer savings;
200,000 GWh electricity savings per year; and
50 GW cumulative power generation capacity additions
avoided, with avoided capital expenditures of $110 billion at
$2,200/kW.
Unfortunately, APGA is concerned that over the years federal
policies have moved toward an all-electric society and have not
recognized the benefits of the direct-use of natural gas. One example
of this can be found in the manner in which the Department of Energy
(DOE) calculates appliance efficiency. The DOE measurement takes into
account energy solely consumed at the ``site'', measuring the energy
used by the product itself.
The site-based measurement of energy consumption ignores the energy
spent in production, generation, transmission and distribution. For
example, according to DOE's point of use consumer disclosure labels for
appliances, an electric water heater may appear to consumers to be over
60% more efficient than a gas water heater despite the fact that
current national generation, transmission and distribution efficiency
for central station electricity is, according to the U.S. Energy
Information Agency, only 29.3% efficient while the transmission and
distribution of natural gas directly to the consumer is 90.1%
efficient. Ignoring these energy losses makes electric-resistance
heating appliances appear more efficient (allowing them to receive a
superior DOE efficiency rating).
This site-based measurement has placed natural gas appliances at an
unfair marketing disadvantage and as a result there has been a marked
increase in shipments of electric water heaters and a decrease in
shipments of natural gas water heaters. This increase in electric water
heaters will come with an increase in greenhouse gas emissions given
that electric water heaters emit 2.5 times the amount of greenhouse gas
emissions as natural gas water heaters given the current make up of the
sources of U.S. electric generation today. Renewable energy generation
is poised to grow in the future, but makes up less than 2% (excluding
hydro-electric) of generation today. Conversion from electric to
natural gas appliances will provide a more immediate emissions
reduction strategy than the many years it will take for large scale
deployment of wind, solar and other renewable technologies.
Rather than a site-based measurement for energy consumption, APGA
has advocated a ``source-based'' or ``total energy'' analysis that
measures energy from the point at which energy is extracted through the
point at which it is used. A total energy analysis provides a more
accurate assessment of energy use, efficiency, as well as greenhouse
gas emissions.
In May, the National Academies of Sciences (NAS) completed a study
that recommended that DOE move to a full-fuel-cycle measurement of
energy consumption stating that this measurement would ``provide the
public with more comprehensive information about the impacts of energy
consumption on the environment, the economy, and other national
concerns. . .'' APGA strongly supports this recommendation and looks
forward to working with the Committee towards its adoption.
Another recently completed study from the Potential Gas Committee
(PGC) shows the largest ever recoverable domestic resource base for
natural gas at nearly 2,100 TCF. This is a 35% increase from the
previous finding released two years ago and largest ever estimate from
the PGC. Federal policy should seek to maximize every BTU of this
domestic and low-carbon fuel by encouraging greater direct use into our
homes and businesses for heating and cooking and other appropriate
uses. Direct use into the home is the highest and best use of this
country's precious natural gas resources.
APGA appreciates this opportunity to submit comments and looks
forward to working with the Committee towards fully utilizing the
benefits of the direct-use of natural gas in efforts to reduce
greenhouse gas emissions.
______
Statement of the American Gas Association
executive summary
Natural gas is America's clean, secure, efficient, and
abundant fossil fuel.
Residential natural gas consumers, who use the fuel for
essential human needs, have a 30-year record of reducing
consumption and greenhouse gas emissions, and have shown the
critical role that natural gas can play in addressing climate
change.
Natural gas, because it has the smallest carbon footprint of
any fossil fuel is part of the energy efficiency and climate
change solution.
Natural gas has the potential to make major contributions to
attaining the nation's climate change goals, and these
contributions will be maximized if they nation makes the right
policy choices, including:
--Making efficiency and resource decisions based upon full-fuel-
cycle data that gives a complete picture of resources used
and carbon emissions
--Requiring carbon-footprint labeling on appliances so that
consumers realize the consequences of their choices
introduction
The American Gas Association (AGA) represents 202 local energy
utility companies that deliver natural gas to more than 65 million
homes, small businesses, and industries throughout the United States.
AGA member companies deliver gas to approximately 170 million Americans
in all fifty states. Natural gas meets one-fourth of the United States'
energy needs.
AGA commends the Committee for exploring the role of natural gas in
mitigating carbon emissions and climate change. In the conversations on
these important topics that have occurred over the last two years in
both chambers of Congress the critical role that natural gas can play
has been largely overlooked. In recent months the importance of natural
gas has at last been recognized, but it has focused on the role of
natural gas in generating electricity. AGA believes that increased
focus is necessary on the ways that the direct use of natural gas--in
furnaces, hot water heaters, and kitchen stoves--can reduce the
nation's carbon footprint--not twenty years from now but today. The
irony is that this 19th Century technology is available to solve a 21st
Century problem.
natural gas is america's clean, secure, efficient, and abundant fossil
fuel
Natural gas is America's cleanest and most secure fossil fuel.
Natural gas is essentially methane, a naturally-occurring substance
that contains only one carbon atom. When burned, natural gas is the
most environmentally-friendly fossil fuel because it produces low
levels of unwanted byproducts (SOX, particulate matter, and
NOX) and less carbon dioxide (CO2) than other
fuels. Upon combustion natural gas produces 43% less CO2
than coal and 28% less than fuel oil. Moreover, almost all of the
natural gas that is consumed in America is produced in North America,
either in the United States or Canada, with the vast majority of that
being produced in the United States. Only a small portion--1 to 2%--is
imported from abroad as liquefied natural gas.
Natural gas is also the most efficient of the fossil fuels.
Approximately 90% of the energy value of natural gas is delivered to
consumers. In contrast less than 30% of the primary energy involved in
producing electricity reaches the consumer. Additionally, natural gas
is an abundant fuel. Recent prodigious discoveries of shale gas have
significantly added to this abundant resource base. As the Potential
Gas Committee recently reported, gas reserves have grown nearly fifty
percent in the last several years. Indeed, America has at least 100
years of natural gas in the ground in North America. Moreover, changes
in economics and technology will continue to increase our resource base
estimates in the future, as they have consistently done in the past.
Natural gas is used to meet essential human needs for small-volume
customers. The majority of the homes in this country use natural gas,
and in this sector 98% of all gas is used for space heating, water
heating, and cooking, while the remaining 2% is used for clothes drying
and other purposes. This fuel is, therefore, used for essential human
needs rather than for luxuries. Natural gas is, therefore, an essential
fuel for America.
There are two important facts about natural gas that are either
little known or often overlooked:
America's residential natural gas customers have led the
nation in reducing their consumption of natural gas--and their
greenhouse gas emissions--over the last 30 years and can
continue, with appropriate policies, to reduce consumption
further. It takes less natural gas to serve 65 million homes
today than it took to serve 38 million homes in .
Natural gas is not part of the climate change problem;
rather, it is part of the climate change solution because it
offers an immediate answer to reducing greenhouse gas emissions
with existing technology, and it has the smallest carbon
footprint of all fossil fuels.
residential gas consumers have demonstrated that the direct use of
natural gas can lead the way in reducing america's greenhouse gas
emissions
Residential natural gas customers provide a sterling example of the
role natural gas can play in addressing climate change. This group has
consistently reduced its per-household consumption of this fuel--and
the carbon emissions resulting from its use--for more than 30 years. On
a national basis, residential customers have reduced their average
natural gas consumption by approximately 30% since . The success of
residential and commercial natural gas consumers is illustrated by the
fact that they have reduced their per-household consumption so
dramatically that there has been virtually no growth in sectoral
emissions in nearly four decades despite an increase in natural gas
households of over 70%. Stated another way, total annual residential
natural gas consumption is lower today than it was in the s,
despite the fact that the number of natural gas households has
increased more than 70% from 38 million to 65 million. Consumption of
natural gas in the residential sector, on a national average basis, is
shown in the following graph:*
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* Graph has been retained in committee files.
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Both research and anecdotal evidence make clear that there are
proven drivers for reducing natural gas consumption and the carbon
emissions associated with natural gas consumption--increased appliance
efficiency and increased building efficiency, supplemented by a variety
of education and incentive programs. AGA believes that continuing to
pursue appliance efficiency and building efficiency policies is the
optimal means to achieve further reductions in consumption in this
sector. This admirable record of reducing consumption can continue by
employing an intensive focus upon energy efficiency and building codes
and standards measures, which for three decades have led to
dramatically reduced natural gas consumption (and emissions).
The reductions in consumption per household experienced over the
past three decades are largely attributable to tighter homes and more
efficient natural gas appliances. These factors will undoubtedly
provide the foundation for continued future reductions in consumption
and, hence, greenhouse gas emissions. Moreover, natural gas utilities
are aggressively promoting decoupled rate structures that allow them to
promote conservation and efficiency consistent with shareholder
interests. Nearly 40% of all residential natural gas customers are
served by gas utilities that have decoupled rates or that are engaged
in state proceedings that are presently considering decoupled rates.
Rate decoupling is important to energy efficiency because it breaks the
link between utility revenue recovery and customers' energy
consumption.
using natural gas in homes and businesses is art of the energy
efficiency and climate change solution
Many misguidedly believe that because natural gas is a fossil fuel
it is one of the causes of greenhouse gas emissions and, as result, a
contributing factor to climate change. In fact, however, natural gas is
part of the climate change solution. As mentioned previously, natural
gas is a fuel that emits low levels of traditional pollutants such as
NOX and SOX. With regard to greenhouse gas
emissions, natural gas, because it has only one carbon atom, emits less
carbon when consumed than any other fossil fuel. As a result, natural
gas has the potential to be a vehicle to move the nation toward its
greenhouse gas reduction goals. For the same reasons, natural gas is an
essential element in the push for optimizing our natural resources and
increasing our energy efficiency.
There are significant differences in efficiency between natural gas
and electricity. Approximately 90 percent of the energy value in
natural gas is delivered to the home. With electricity less than 30
percent of the primary energy value reaches the customer. The largest
difference in efficiency for electricity is lost as waste heat at the
generating station, as well as line losses in transmission and
distribution. These radically different efficiencies produce the
significant differences in both efficiency and carbon emissions between
electric and natural gas appliances.
The full potential for natural gas efficiencies is demonstrated
most dramatically by the carbon footprint of the natural gas water
heater. The average natural gas water heater emits approximately 1.7
tons of CO2 per year. In contrast, the average electric
water heater results in more than twice as much--3.8 tons per year. The
difference between the two could not be more dramatic, and it becomes a
multiple of three when the comparison is made between a high-efficiency
natural gas water heater and a high-efficiency electric water heater.
These numbers are based on national averages, and, as a result, actual
differences will vary from area to area.
The same differences in efficiency and emissions follow when
comparing an all-electric home with a natural gas home. A typical all-
electric home on average produces 10.8 tons of CO2 per year,
while an all-natural-gas home produces 7.2 tons of CO2 per
year. Again, these numbers reflect national averages, and actual
experience will necessarily differ, but the order of magnitude of
difference remains.
The plain consequence is that the nation can improve its overall
energy efficiency as well as reduce its carbon footprint by opting for
appliances that use natural gas in direct applications (i.e., where the
natural gas is used to heat air, water, or food). There is the
opportunity, on a national basis, to improve efficiency dramatically
and reduce carbon emissions by millions upon millions of tons if we
utilize more natural gas directly in homes and businesses as the fuel
for the future.
Converting small-volume customers to high-efficiency natural gas
applications is one of the best ways available today to leap forward in
efficiency and reduce greenhouse gas emissions. As the example above
demonstrates, converting electric resistance water heaters to natural
gas can increase efficiency and reduce greenhouse gas emissions by one-
half to two-thirds. Doing so would have the benefit of reducing overall
energy consumption, costs, and the need to construct new electricity
generating plants--a critical problem in a carbon-constrained
environment--and electric transmission lines.
Encouraging the direct use of natural gas by consumers is,
therefore, an important tool to meet the nation's greenhouse gas goals.
In other sectors of the energy industry, the steps necessary to reduce
greenhouse gas emissions are years or decades away--e.g. deployment of
additional nuclear generating stations or carbon capture and
sequestration. In contract, natural gas is here today to reduce
greenhouse gas emissions in the immediate future. It is not only the
increased use of natural gas for electricity generation (which is not
an issue central to AGA) that promises reductions in greenhouse gas
emissions, but also the increased usage of natural gas in home heating,
water heating, and cooking that has the potential to bring near-term
reductions in greenhouse gas emissions.
measuring energy efficiency and consumption on a ``full-fuel cycle''
asis will maximize natural gas as a potent climate change tool
This spring the National Academy of Sciences completed a study
under contract with the U.S. Department of Energy as required by the
Energy Policy Act of . The study was to determine whether the more
appropriate means of measuring energy efficiency was ``sited-based'' or
``source-based'' measurement of consumption and efficiency. The former
looks only to the site of the appliance consuming energy. The latter
looks to the full fuel cycle--in the case of natural gas from the
wellhead to the burner tip. In the case of natural gas, site-based
analysis looks to the relative efficiency of a particular appliance.
Source-based analysis instead looks to see how much of the energy taken
from a gas well does productive work at the site of the appliance. In
essence the source-based analysis leads to the conclusion that in the
case of natural gas 90% or so of the primary energy results in
productive effort while in the case of electricity only 30% or so of
the primary energy results in productive effort.
The report of the National Academy of Sciences concludes that,
where different fuel sources can be utilized for a particular appliance
(e.g., hot water heaters), the full-fuel-cycle (or source-based)
analysis is most appropriate because it presents the most complete
picture of the relative usage of primary resources. With today's focus
on reducing greenhouse gas emissions, the results of the National
Academy Study take on particular relevance because carbon (greenhouse
gas) emissions in a particular application closely parallel the full-
fuel-cycle analysis. (A copy of the National Academy of Sciences report
is attached.)
If the nation establishes a goal of reducing its carbon emissions,
it is essential that the nation's policy decisions be based on
information that will promote that goal. Site-based measurements of
energy usage and energy efficiency will not lead to maximum reductions
in carbon dioxide. Those will only be achieved by measuring energy
usage and energy efficiency on a source, or full-fuel cycle basis.
Congress here faces a fork in the road--one way leads down the
traditional path, which will result in erroneous decisions. The other
way leads down the path of new and fresh analysis that maximizes carbon
reductions.
A simple example illustrates the point. Let us look again at water
heaters. If we compare water heaters on a site basis, we can see that a
natural gas water heater and an electric water heater are each 90%
efficient. This comparison ignores, however, the modest energy losses
in delivery for natural gas and the major losses (70%) for electricity.
This picture, even using source-based energy, gives only the efficiency
comparison. As noted previously, when one looks at it from a carbon
perspective it is starker--the electric water heater is responsible for
twice as much carbon dioxide as the natural gas water heater. If
Congress does not change the nation's course on this very fundamental
issue it will have missed a historic opportunity to do the right
thing--from both an efficiency and a carbon perspective.
Attached is a short piece of legislative language that would
implement this important change in approach for both energy efficiency
policy and carbon policy.
carbon footprint labeling for appliances will promote carbon reductions
Currently major home appliances bear labels, called EnergyGuide
labels, that show the yearly estimate operating cost of an appliance.
For simplicity, these labels are based upon national averages for
energy prices. The EnergyGuide label allows the consumer to compare the
relative annual operating costs of the various appliances from which he
or she might chose. The purpose of the EnergyGuide label is to give the
consumer relevant information on the comparative operating costs and
first-costs of the appliances available so that he or she can make an
optimal decision.
H.R. , the American Clean Energy and Security Act of ,
passed by the House on June 26, (the Waxman-Markey climate change
bill takes the Energy Guide labels one step further in the dawning
carbon-reduction age. Section 234(h) of the Waxman-Markey bill requires
that EnergyGuide labels be expanded to include the carbon emissions
associated with appliances. For an American public increasingly
interested in climate change issues and that will, as we move forward,
be increasingly attentive to carbon emissions, providing this
additional information will be more than useful. Consumers will be able
to assess the carbon consequences of their appliance purchases. They
will, for the first time, be able to balance relative carbon emissions
with first-costs.
Mandating this additional information will provide useful
information to consumers. Doing so will undoubtedly result in carbon
reductions. Moreover, requiring carbon labeling will not impose costs
on either manufacturers or consumers. The necessary data for creating
these labels is readily available, and the requisite calculations are
not unduly complex. As the labels are already required, it is simply a
matter of adding one data point to the labels. AGA urges the Committee
to embrace the carbon labeling provision found in the H.R. .
______
Statement of the American Trucking Associations, Inc
The American Trucking Associations (ATA) appreciates the
opportunity to submit written testimony concerning the use of natural
gas in over the road trucking fleets. ATA is a federation of motor
carriers, state trucking associations, and national trucking
conferences created to promote and protect the interests of the
trucking industry. ATA's membership includes trucking companies and
industry suppliers of equipment and services. Directly and through its
affiliated organizations, ATA encompasses over 7,000 companies and
every type and class of motor carrier operation.
For the reasons set forth below, natural gas currently is not a
viable solution for most long-haul trucking operations; however,
natural gas could be an acceptable fuel alternative for certain short-
haul applications within an industry as diverse as trucking.
background
The trucking industry is the lynchpin of the transportation system,
hauling nearly 70% of all the domestic freight transportation tonnage
in the United States and accounting for more than 80% of the nation's
freight bill. Over 80% of the communities in the U.S. receive their
goods exclusively from trucks. Trucking also accounts for over 70% of
the value of trade between the U.S. and Mexico and Canada. Simply put,
without the trucking industry, the U.S. economy would come to a
grinding halt.
Diesel fuel is the lifeblood of the trucking industry. The trucking
industry consumes 39 billion gallons of diesel fuel each year. For most
companies, diesel fuel is the second highest operating expense after
labor. As the price of diesel fuel has increased, the trucking industry
has searched for ways to increase its fuel economy andvhas pursued
several alternative fuel options. The search continues, as we have not
found viable alternative to diesel fuel; although the industry
continues to experiment with using natural gas in certain applications.
Natural gas is a fuel comprised mostly of methane, with small
amounts of propane, ethane, helium and water. Like certain other
alternative fuels, natural gas could be an acceptable fuel choice for
specific applications within an industry as diverse as trucking.
Natural gas engines can either be spark ignition or compression
ignition with pilot injection (i.e., using a 5% diesel injection to
initiate combustion), with the later retaining the general properties
of a diesel engine but requiring a dual-fueling system.
Natural gas may be used as a transportation fuel in its compressed
form (CNG) or liquefied form (LNG). Because of low energy density, CNG
is not practical for long distance, heavy-duty truck applications. CNG
is being successfully used in shorter range, heavy-duty applications
such as refuse trucks, concrete mixers, and municipal buses.
LNG may present a viable alternative for certain trucking
applications. LNG is cryogenically liquefied (i.e., converted to a
liquid by reducing its temperature to approximately -260F) and has
higher energy content per volume than CNG (although still significantly
lower than diesel). LNG's energy density makes it more acceptable for
longer routes, although the lack of a competitive refueling
infrastructure suggests that this alternative is not currently viable
for long-haul applications.
discussion
As with most alternative fuels, natural gas has certain advantages
and disadvantages compared to diesel fuel. We discuss each of these in
more detail below.
A. The Economics of Natural Gas
One of the biggest obstacles to using natural gas in the trucking
industry is the cost of a natural gas truck. Natural gas trucks sell at
a premium to heavy duty dieselngines for Class 8 trucks ($40,000--
$70,000 more).\1\ Federal (and state) tax incentives are available to
purchasers of natural gas trucks to narrow the price differential
between diesel and natural gas trucks; however, these incentives are
not sufficient to completely offset the natural gas truck price
premium.
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\1\ There are currently two natural gas engine classes: (1) a spark
ignition, 320 horsepower version that sells at a $40,000 premium to its
diesel counterpart; and (2) a 450 horsepower, compression ignition
version that sells at a $70,000 premium to its diesel counterpart.
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The trucking industry is incredibly competitive. There are more
than 600,000 companies registered with the U.S. Department of
Transportation and 96 percent of them are small businesses that operate
fewer than 20 trucks. In an industry with operating expenses that often
exceed 98% of collected revenue, trucking companies cannot afford to
increase their capital expenses by purchasing natural gas trucks that
cost significantly more than the trucks that their competitors are
operating.
LNG fuel tanks are constructed from \1/4\'' thick stainless steel
and add significant weight to the truck, which may negatively impact
truck productivity.\2\ For example, two 119 gallon tanks weighing
approximately 1,000 pounds would reduce the payload of a cargo tank
truck carrying ethanol by over 150 gallons. Thus, more trucks would be
required to haul an equivalent amount of product, which negatively
impacts fuel consumption, emissions, and the cost of transporting
freight. It should be noted that many trucking operations do not
operate at the maximum legal weight and the productivity of these
operations would not be adversely impacted by the weight penalty
associated with natural gas trucks.
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\2\ A 119 gallon tank weighs approximately 500 lbs., while a 72
gallon tank weighs approximately 270 lbs.
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One positive economic aspect of natural gas trucks is that natural
gas currently sells at a significant discount to diesel fuel on a
diesel gallon BTU equivalent basis. While both diesel and natural gas
prices fluctuate, through LNG sold at a significant discount to
ultra low sulfur diesel fuel (i.e., approximately 75 cents to $1/gallon
cheaper). Natural gas trucks, however, are less fuel efficient than
their diesel counterparts. Spark ignited natural gas engines have a
reduced fuel economy of 7% to 10%, while compression-ignition natural
gas engines have about a 1% fuel economy penalty. As a result, some of
the economic benefit of less expensive natural gas is given up in the
form of lower fuel efficiency.
Notwithstanding the fact that natural gas is less expensive than
diesel fuel, the additional capital cost associated with purchasing
natural gas trucks compared to diesel trucks makes natural gas a
challenging economic alternative for most trucking companies. Due to
the competitive nature of the trucking industry, significant financial
incentives would be required to address the higher cost of natural gas
trucks, before they can be considered a viable alternative to diesel
trucks.
B. Infrastructure Concerns
The second major obstacle to the use of natural gas as an
alternative fuel for the trucking industry is the lack of a competitive
refueling infrastructure. Most long-haul trucks are not centrally
refueled and do not travel regular routes. Running out of gas on the
side of the road is a significant challenge, as LNG mobile refueling is
not an option and the truck would have to be towed to a refueling
station. The ubiquitous nature of diesel refueling stations
accommodates that uncertainty. Unfortunately, it is virtually
impossible for over-the-road fleets to find LNG fueling outlets.
LNG trucks must be refueled at specialized stations that are
configured for the specific truck. Putting aside the issue of refueling
compatibility, many of the natural gas fuel stations in this country
are owned and operated by municipalities, and prior contractual
arrangements would have to be made before commercial trucks could use
these municipal LNG refueling stations. Since the product is dispensed
at -260 degrees Fahrenheit, employee training and the provision of
personal protective equipment also may be necessary.
Building out an LNG refueling infrastructure will take time and an
enormous amount of money. An LNG filling outlet with a refill
capability that is comparable to the time necessary to refuel a diesel
truck costs over $500,000. There also may be permitting challenges
associated with the construction of an LNG refueling system, as
government officials and permitting authorities have limited exposure
to LNG refueling stations.
It is not sufficient to have a single LNG vendor with stations
built at strategic locations along key freight corridors. Absent a
competitive refueling infrastructure, trucking companies could face
unreasonably high prices at individual retail LNG stations that have no
competition in a particular geographic area. While competition exists
in the natural gas industry, the high barriers to entry for retail LNG
refueling stations may slow the development of a competitive refueling
infrastructure. A competitive LNG refueling model would require the
presence of multiple entities selling LNG in the same geographic area.
C. Operational Challenges
Using LNG as an alternative fuel also creates operational and
maintenance challenges for the trucking industry.
LNG On-Board Tanks.--Some fleets have experienced significant
problems with LNG fuel tanks. These tanks are double-walled
construction with a vacuum between the two walls (like a giant thermos
bottle). The vacuum serves as a temperature barrier. In some cases,
fleets reported a loss of the vacuum due to tank manufacturing issues
that manifest themselves months and even years after being placed into
service. The vacuum can be replenished, but the process is costly and
is not a permanent solution. Impacting a tank (such as during a
collision or accident) can also result in a lost vacuum. As vacuum
pressure decreases, fuel temperature rises, causing internal tank
pressure to rise. The pressure relief valve built into the tank vents
natural gas into the atmosphere, which affects the amount of fuel
available for use and offsets the environmental advantages of using
LNG.
Operating Range.--An LNG truck equipped with two 119 gallon tanks
has an operating range of approximately half of the typical diesel
long-haul truck. These tanks are extremely heavy and negatively impact
truck productivity for those fleets that haul freight at the truck's
legal weight limit.
Maintenance Costs.--A natural gas engine may require injectors to
be replaced more frequently than a diesel engine, which increases
operating expenses. For spark-ignition natural gas engines, replacement
of spark plugs, ignition modules and various sensors also add
additional maintenance costs.
On the positive side of the maintenance expense ledger, natural gas
engines require fewer oil changes. Oil change intervals for LNG trucks
are three times longer than diesel engines.
Training.--Natural gas engines operate differently than diesel
engines and in-house mechanics will require approximately 60 hours of
specialized training. Finding a qualified natural gas mechanic is more
difficult than finding a diesel mechanic. The local truck dealer may
not have the requisite experience, tools or parts to quickly perform
repairs. As a result, some fleets have reported that the downtime for
repairs is significantly longer for natural gas engines.
Methane Exposure.--Maintenance shops that will work on natural gas-
fueled vehicles should include a methane detection system and a methane
evacuation system. Recommendations on the safe operation and
maintenance of natural gas vehicles are available from the National
Fire Protection Association and the Society of Automotive Engineers.
One ATA member reports spending over $150,000 on infra-red sensors,
modified lighting and electrical systems, and an air evacuation system.
D. Environmental Implications
Particulate matter (PM) and nitrogen oxide (NOX)
emissions from LNG-fueled trucks are similar to diesel trucks
manufactured in compliance with EPA's diesel emission standards.
Lifecycle carbon emissions from a natural gas engine compare
favorably to diesel engines. Depending upon the source of the natural
gas and the liquefaction efficiency rate, natural gas can reduce
CO2 emissions by 15%-23%. Note, however, that methane is 20-
times more potent than CO2 as a greenhouse gas. As LNG in
fuel tanks warms, methane is released to the environment through a
pressure relief valve. In fact, depending upon ambient temperatures, an
LNG truck could vent most of its fuel over a 7-10 day period. The
venting of methane from trucks parked over an extended period could
result in a net increase in greenhouse gas emissions compared to diesel
fuel.\3\
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\3\ While trucking companies strive to improve utilization rates of
their capital equipment, the current low demand for freight
transportation services provides an immediate example of circumstances
where trucks may be parked for an extended period of time.
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conclusion
Natural gas is a plentiful, domestically-produced energy source
that could help to reduce our dependence on petroleum imports. There
are numerous hurdles that must be overcome, however, before LNG trucks
become a truly viable alternative for mainstream trucking. The most
significant obstacles to LNG are the enormous purchase price premium
associated with a natural gas truck compared to an equivalent diesel
truck and the lack of a competitive LNG refueling infrastructure. If
Congress enacts financial incentives to ensure that the price of an LNG
truck is equivalent to a diesel truck and that cost-effective LNG
refueling facilities can be constructed, then LNG trucks may be a
viable alternative for the small segment of the industry that is
centrally-refueled.
For LNG to achieve greater penetration in the trucking industry,
additional incentives are necessary to ensure the development of an
adequate competitive refueling infrastructure.
ATA appreciates this opportunity to discuss potential to increase
the use of natural gas in the over the road trucking fleets. If you
have any questions concerning the issues raised in this statement,
please contact Richard Moskowitz at (703) 838-.
______
Statement of Hon. Sean Parnell, Governor, State of Alaska
Dear Chairman Bingaman and Ranking Member Murkowski,
The State of Alaska commends the Senate Committee on Energy and
Natural Resources for its recent hearing on the role of natural gas in
mitigating climate change. We wish to comment on this and other topics
related to the Clean Energy Jobs and American Power Act (S. ). S.
, which aims to drastically modify U.S. fossil fuel consumption,
stimulate greater use of renewable energy resources, and address the
challenges of climate change adaptation, involves some of the most
important issues facing the State of Alaska.
Alaska supports the transition to lower-carbon and renewable
energy. However, as a major exporter of carbon-based energy, producing
approximately 13 percent of the nation's oil supply and receiving more
than 80 percent of its unrestricted general fund revenues directly from
oil and gas operations, the State cannot ignore the potential economic
consequences of a ``cap-and-trade'' system. We are currently preparing
analyses that assess the possible impacts of this legislation on State
revenues, the economic viability of our oil refineries, and future
construction of an Alaska natural gas pipeline. The State fears this
act may disadvantage domestic fossil fuel producers and shift
production overseas, resulting in lost revenues and jobs while reducing
our nation's energy security.
While climate change legislation could pose economic threats to our
state, Alaska is also primed to help lead a clean energy economy. In
the Alaska natural gas pipeline, the State of Alaska offers a promising
low-carbon energy option, which could provide a vital bridge to other
clean energy alternatives. Alaska also holds vast renewable energy
potential, from hydropower, to biomass, wind, geothermal, solar, and
ocean power.
In the area of adaptation, Alaska is already facing a host of
serious developments related to climate change. This includes
addressing the impacts to critical infrastructure associated with
accelerated coastal erosion, increased storm effects, sea ice retreat,
and permafrost melt. Efforts to protect and relocate Alaskan
communities are already underway and the State values the partnerships
we have formed with many federal agencies and other entities. More
resources, however, are needed along with a designated federal agency
lead to coordinate the federal efforts.
Coupled with climate change impacts are opportunities, including
the potential for increased marine access to Arctic waters and the
resources they contain. The United States is slowly waking to the fact
it is an Arctic nation and the importance of the Arctic in general. It
is imperative that this legislation not foreclose possible
opportunities in the Arctic.
Enclosed you will find the State's analysis of provisions in S.
. This document identifies key priorities for Alaska and a number
of areas for improvement. Some of the items the State advocates for in
this bill include:
Adequate funding for climate change adaptation: the State
supports sufficient funding to address Alaska's pressing
adaptation needs on various fronts, including protecting
critical and valuable infrastructure.
Measures to preserve domestic refineries: Alaska calls for
provisions aimed to protect Alaska's refineries, which are
essential to our economy and cold weather fuel needs, as well
as uniquely vulnerable to increased costs posed by cap-and-
trade legislation.
Fair allocations for Alaska: the State is concerned that the
Environmental Protection Agency (EPA) has underestimated
emissions in Alaska, based on estimates provided to Senator
Feingold by EPA. This could disadvantage the state as a whole
in the distribution of allowances.
Avoidance of unfunded mandates: Alaska opposes burdensome
and unrealistic unfunded mandates that may be created through
new climate change programs.
Respect for states' rights: the State supports the
protection of states' rights and notably recognition of the
State of Alaska's role as primary trustee over fish and
wildlife.
Exclusion of problematic broad policy statements: Alaska
opposes broad policy statements that open the door to stricter
enforceable regulations and future litigation.
Emphasis on domestic production: the State supports
expanding access and incentives for responsible domestic
onshore and offshore oil and gas exploration as part of a
strategy for creating a secure energy future.
Promotion of the natural gas pipeline: the State seeks to
promote the Alaska natural gas pipeline as a clean and reliable
fuel source which would provide significant economic benefits
for the nation, consistent with the Alaska Natural Gas Pipeline
Act of (P.L. 108-324, 118 Stat. ).
Carbon capture and sequestration incentives: Alaska supports
the commercial deployment of carbon capture and sequestration
(CCS) technologies, and in particular, sequestration as a
result of Enhanced Oil Recovery (EOR) projects.
Program flexibility: The State believes that effective
mitigation and adaptation programs must acknowledge regional
differences. Alaska has particular concerns regarding the
proposed natural resources adaptation framework.
Focus on monitoring and research: Alaska supports
collaborations among federal, State, and other partners in
monitoring and research that will lead to better decisions in
the management of land and marine resources.
Exclusive role of climate change legislation: We believe
climate change legislation should be the sole instrument for
addressing climate change mitigation, not the strained use of
existing statutes such as the Endangered Species Act or the
Clean Air Act.
We respectfully request that this material be included in the
hearing record and appreciate the opportunity to share our views.
attachment.--state of alaska comments on clean energy jobs and american
power act (s. )
senator boxer's chairman's mark
introductory notes
This document describes the positions of the State of Alaska on
notable elements of Senator Barbara Boxer's Chairman's Mark of the
Clean Energy Jobs and American Power Act (S. ), which was
introduced by Senators John Kerry and Barbara Boxer. The Alaska
Departments of Environmental Conservation, Fish and Game, Law, Natural
Resources, Revenue, Transportation and Public Facilities, and the
Governor's Washington, DC office contributed to the analysis of this
bill.
While particular design elements of ``cap-and-trade'' legislation,
like S. and the American Clean Energy and Security Act of
(H.R. ), raise broad concerns about the economic interests of
Alaska, this document focuses instead on specific provisions of S.
. The State is currently preparing separate analyses of the
possible impacts of this legislation on State revenues, the economic
viability of Alaska's oil refineries, and future construction of an
Alaska natural gas pipeline.
In many ways, Alaska is ground zero for obvious and costly climate
change impacts. Alaska is currently experiencing coastal erosion,
increased storm effects, sea ice retreat and permafrost melt. The
villages of Shishmaref, Kivalina, and Newtok have already begun
relocation plans and the U.S. Army Corps of Engineers has identified
over 160 additional rural Alaskan communities threatened by erosion.
The effects of climate change are expected to occur most rapidly
and be most pronounced at higher latitudes. Thus, no discussion about
climate change is complete without recognition of the issues facing the
Arctic. Surprisingly, in the 925-page bill, offered as a U.S. response
to climate change, the word ``Arctic'' appears only once.
The State of Alaska strongly encourages that the following key
components be incorporated in any climate change legislation:
Mitigation and adaptation strategies that account for
regional differences and avoid a ``top-down'' approach, likely
to produce inflexible and inefficient policy;
avoidance of broad policy statements that open the door to
stricter enforceable regulations and future litigation;
an effort to spare states from burdensome and unrealistic
unfunded mandates;
emphasis on climate change legislation as the sole
instrument for addressing climate change mitigation, rather
than the strained use of existing statutes, such as the
Endangered Species Act or the Clean Air Act;
incentives for a diverse spectrum of clean energy
alternatives;
respect for states' rights, and notably recognition of a
state's role as primary trustee over fish and wildlife;
a focus on studying the Arctic climate and environment;
appropriate funding for adaptation efforts in Alaska where
there is a pressing need to respond on numerous fronts,
including the protection of critical infrastructure;
aid for consumers burdened by climate change-related
regulations;
provisions aimed to protect Alaska's refineries, which are
essential to our economy and cold weather fuel needs, as well
as uniquely vulnerable to increased costs posed by cap-and-
trade legislation; and
promotion of Alaska's natural gas pipeline as a clean,
reliable, long-term fuel source.
In the remainder of this document, the State considers how S.
addresses these and other priorities important to Alaska.
State Positions and Analysis of S.
section 1. short title; table of contents
Findings. (Sec. 2)
Alaska Natural Gas Pipeline Projects. The State supports the
addition of a finding, that the completion of the Alaska
Natural Gas Transportation Projects is vital to the country to
provide a clean fuel alternative to coal and petroleum as a
bridge to power generation that does not involve the combustion
of fossil fuels. This finding would be consistent with the
Alaska Natural Gas Pipeline Act of (P.L. 108-324, 118
Stat. ).
Arctic Impacts. The State supports the addition of a finding
that the impacts of climate change are expected to occur first
and be most severe in the Arctic and in the higher latitudes,
creating unique adaptation needs in these areas.
Division A--Authorizations for Pollution Reduction, Transition, and
Adaptation
title i--greenhouse gas reduction programs
Subtitle A--Clean Transportation
Greenhouse Gas Reductions through Transportation Efficiency;
Transportation Greenhouse Gas Emission Reduction Program
Grants. (Sec. 112-113)
Funding. The State fears Section 112 would create a
substantial unfunded mandate and shift resources away from
Alaska's transportation priorities. S. would amend Title
VIII of the Clean Air Act to require the EPA Administrator, in
consultation with the Alaska Department of Transportation and
Public Facilities (DOT), to establish national greenhouse gas
(GHG) emission reduction goals. States and metropolitan
planning organizations (MPOs) would, in turn, be required to
develop targets consistent with the national goals. The State
would need to perform extensive data gathering and modeling,
compute baseline emissions, and develop new strategies and
programs to meet their goals. Section 113, which outlines a
grant program for transportation GHG reduction, does not
clearly provide funding to states for planning. If Alaska is
unable to secure sufficient funding, it would be forced to
divert resources from other programs, such as transit and road
improvements, in order to absorb the new costs. The State
supports a funding mechanism that will ensure adequate
assistance to states working to comply with this new mandate.
Adequate Time Frame. The State has concerns about the time
requirements for data production and analysis. Adequate time is
necessary to produce data on local conditions. Default national
data does not accurately reflect Alaska's environmental
conditions and emissions. The State believes this legislation
should contain provisions ensuring states have sufficient time
to collect and incorporate local data.
The State also supports inclusion of a statutory process to extend
State target deadlines should federal agencies fail to meet
deadlines or should there be legal changes to models or
methodologies. New standardized models and methods adopted may
differ from those used to establish the emissions
reduction baseline. If this is the case, analysis would be
necessary to properly compare new results with the
baseline. If EPA and DOT lag in making this adjustment, it will
shorten the timeframe states have to meet their deadlines.
Furthermore, the State fears the timeline for new regulations in
this section is not realistic. Regulations must be proposed
within 12 months and promulgated within 18 months of enactment.
Preparing regulations and completing the public process for
adopting the regulations can take months under ideal
circumstances. If the regulation process is not completed on
schedule, states and MPOs would be left with insufficient time
to achieve emission reduction targets.
Authority. The State also questions whether states possess
the requisite authority to carry out their new duties under
this section. State transportation programs generally do not
operate transit, rail, or intercity bus systems, control land
use, or regulate the amount of driving or method of vehicular
propulsion. This authority is traditionally reserved for local
government planning and zoning departments. Yet it will be
impossible to meet ambitious emissions targets without
regulating these activities. Furthermore, Section 112 holds
MPOs to a lesser standard than states, though MPO emission
plans are central to meeting state targets.
Public Health. The State also has reservations about use of
the term ``public health,'' which has certain connotations
within the Clean Air Act. A provision may be necessary to
ensure the term does not invoke actions related to the Clean
Air Act Section 109(b)(1), which directs EPA to set ambient air
quality standards to ``protect the public health'' and allow
for an adequate margin of safety. Recent EPA actions have shown
an increased propensity for moving beyond the agency's
traditional authority.
Surface Transportation. The State believes the language of
this section should be clarified to describe ``surface''
transportation-related greenhouse gas emissions reduction
targets in all cases. Further, the term ``surface
transportation-related'' should be defined to specifically
exclude maritime (except ferries), rail, and off-road vehicles.
Lead Planning/Modeling Agency. The State supports
establishing the U.S. Department of Transportation, not the
EPA, as the lead agency regarding the development of
transportation planning and modeling tools. S. does this.
Vehicle Miles Traveled. The State is concerned by provisions
creating goals for reduced ``vehicle miles traveled.''
Construction of the natural gas pipeline may create large
short-term increases in vehicle miles traveled, but will
generate benefits that far outweigh these increases. The State
supports an exception for large construction projects promoting
clean energy.
Clean Air Act Incorporation. Section 112 also raises concern
because of its incorporation into the Clean Air Act. The
provision could subject planning and activities to burdensome
Clean Air Act statutes and regulations.
Subtitle F--Energy Efficiency and Renewable Energy
Renewable Energy. (Sec. 161)
Grants for Renewable Resource Programs. The State supports
the nation's transition to increased reliance on renewable
energy. Alaska possesses vast renewable energy potential,
including hydro, biomass, wind, geothermal, solar, and ocean
power. S. authorizes EPA grants for projects that increase
the quantity of energy that a state uses from renewable
resources, with priority to applicants in states with a binding
Renewable Portfolio Standard. The State approves of the
provision's goal.
The State, however, has concerns about the definition of
``qualified hydropower,'' used in Section 102. It appears
hydropower can be considered ``qualified'' in two ways. First,
incremental gains or capacity additions to projects in place
before are considered qualified hydropower. Second, energy
produced from capacity added after to a dam that was
originally in place for reasons other than power generation
qualifies. This narrow definition would exclude large portions
of existing hydropower, making it difficult for Alaska to meet
a Renewable Portfolio Standard and compete for grants under
Section 161, despite having an abundance of hydropower. The
definition would also leave out new hydro projects. The State
supports the expansion of the definition of ``qualified
hydropower.''
Energy Efficiency in Building Codes. (Sec. 163)
National Building Codes. The State opposes setting national
energy efficiency building codes. S. would create national
codes for residential and commercial buildings, in order to
meet national energy efficiency targets. The EPA Administrator
would publish an annual report on energy efficiency building
code adoption and compliance by states. Though penalties for
noncompliance are not defined in S. , Alaska opposes the
existence of national standards in this area. A federally
mandated, universal energy code is a poor fit for a state with
Alaska's vast size and varied conditions.
Subtitle H--Clean Energy and Natural Resources
Clean Energy and Accelerated Emission Reduction Programs. (Sec. 181)
Clean Energy Incentives. The State supports Section 181,
which rewards companies that switch from power sources with
higher emissions than the power sector average to cleaner
fuels, including natural gas, and Section 182, which would
establish a new federal grant program encouraging investment in
advanced natural gas technologies.
title iii--transition and adaptation
Part 1--Domestic Adaptation
Subpart A--National Climate Change Adaptation Program
National Climate Change Adaptation Program. (Sec. 341)
Existing Programs. The State supports the inclusion of
language to clarify that the proposed National Climate Change
Adaptation Program (NCCAF) will not replace existing federal
programs already providing state and local governments and
tribes with funds for projects that will assist in adaptation.
The NCCAF should be a supplemental source of funding that
prioritizes meeting urgent needs.
Climate Services. (Sec. 342)
Coordination. The State believes a lack of specificity in
the bill's natural resources adaptation strategy could hamper
coordination and produce a duplication of efforts. In this
section, the Department of Commerce (NOAA) is tasked with
developing a National Climate Service. Section 365 creates a
Natural Resources Climate Change Adaptation Panel, chaired by
the Council for Environmental Quality. Section 367 establishes
a National Climate Change and Wildlife Science Center. These
provisions leave ambiguity as to how the bodies will interact.
At the State level, federal agencies have competed for
leadership and funds in the climate change arena. The vagueness
in these provisions could produce a similar dynamic.
Subpart B--Public Health and Climate Change
National Strategic Action Plan; Advisory Board. (Sec. 353-354)
Public Health. The State supports the inclusion of a section
dedicated to addressing public health. However, the bill calls
for development of a Health Impact Assessment. The requirement
that Health Impact Assessments be conducted by the federal
government within the National Environmental Policy Act (NEPA)
process has produced challenges in Alaska. Additionally, no
funding mechanism is provided to develop these assessments or
the strategic plan called for by the bill. The section also
lacks a mandate for State or Native representation on the
Advisory Board.
Subpart C--Climate Change Safeguards for Natural Resources
Conservation
Natural Resources Climate Change Adaptation Plan; Natural Resources
Climate Change Adaptation Strategy; Natural Resources
Adaptation Science and Information. (Sec. 365-367)
Mission of Panel. The State believes the purpose of the
Natural Resources Climate Change Adaptation Panel should be
expanded to address other forms of adaptation, such as
infrastructure. As introduced, the bill lacks a strategy for
coordinating federal policy on climate change effects outside
of the natural resources area.
Federal Natural Resource Agency Adaptation Plans; State Natural
Resources Adaptation Plans. (Sec. 368-369)
Flexibility. The State fears the natural resource adaptation
framework in S. , like that in H.R. , is too top-down
driven for success. The bill calls for each federal agency to
develop a natural resource adaptation plan, with which
subsequently-formed state plans must be consistent. Climate
impacts, however, differ regionally and locally, requiring
maximum flexibility. Development of a national plan will
hamstring local identification and prioritization of issues and
associated strategies to address them, stifle innovation, and
prevent the local ``buy-in'' vital to effective implementation.
A national focus also impedes the development of regional
strategies.
States should be allowed to negotiate cooperative natural resource
agreements with the federal government on a state-by-state
basis with maximum flexibility. In the face of significant
intrusion by the federal government on a state's authority to
regulate fish and game, states may reasonably prefer departing
from the national strategy. If a state does so, however, it
will be penalized through denial of funding under programs in
this subtitle and potentially other federal programs. The
scenario is counterproductive and could be alleviated with
greater flexibility.
Competing Interests. The State fears efforts to assist
species in adapting to climate change and ocean acidification
will require controlling human activities to reduce other
stressors on these species. Large new conservation units may be
carved out and human activities in migration corridors could be
substantially limited. The bill does not state how the
adaptation strategy and planning called for is to be reconciled
with human population growth, resource development, commercial,
and other human activities. With this approach, other competing
interests of importance to the people of Alaska will be
marginalized.
National Resources Climate Change Adaptation Account. (Sec. 370)
Other Statutes. The State believes the bill should
specifically de-link existing statutes, such as the Endangered
Species Act (ESA), from the climate change policy process. The
State opposes use of the ESA as a vehicle for carrying out
climate change policy. Section 370 provides for an expansion of
ESA programs, which, without further guidance, could result in
significant increases in listings that provide little benefit
to those species. The bill should include language affirming
that climate change legislation is the appropriate instrument
for responding to climate change and that ESA should retain its
traditional role of conserving species most at risk.
Corps of Engineers. The State also believes this section
should be modified to explicitly grant the U.S. Army Corps of
Engineers the authority to use Natural Resources Climate Change
Adaptation Account funding for coastal erosion reduction
projects and infrastructure adaptation.
Funding Allocation. The State appreciates that, of the funds
made available to states in this account, a portion (six
percent) is set aside for coastal agencies. Coastal states will
have unique adaptation needs. To ensure adequate funding where
climate change impacts are most severe, though, the State
advocates for a separate allocation for Arctic adaptation
efforts.
National Wildlife Habitat and Corridors Information Program. (Sec. 371)
State's Role. The State fears this section undermines the
State's role as primary trustee over fish and wildlife. The
proposed National Fish and Wildlife Habitat and Corridors
Information Program centers around developing Geographic
Information System (GIS) databases and maps to support
decision-making in this area. The State approves of this
approach. The stated purpose of the effort, however, is to
allow the Secretary of the Interior to recommend how the
information developed ``may be incorporated'' into relevant
State and federal plans that affect fish and wildlife including
land management plans, and the State Comprehensive Wildlife
Conservation Strategies. Further, the Secretary is granted
authority to ``ensure that relevant State and federal plans
that affect fish and wildlife (1) prevent unnecessary habitat
fragmentation and disruption of corridors; (2) promote the
landscape connectivity necessary to allow wildlife to move as
necessary to meet biological needs, adjust to shifts in
habitat, and adapt to climate change; and (3) minimize the
impacts of energy, development, water, transportation, and
transmission projects and other activities expected to impact
habitat and corridors.'' The State is leery of this expansion
of federal authority. To be successful, adaptation efforts must
respect the primary roles and authorities of State fish and
wildlife agencies in managing fish and wildlife and be built on
this precept.
Landscape Conservation Planning Programs. The relationship
of this program to existing landscape conservation planning
programs (such as the Landscape Conservation Cooperatives)
should also be clarified.
Subpart D--Additional Climate Change Adaptation Programs
Coastal and Great Lakes State Adaptation Program. (Sec. 384)
Funding Formula. The State approves of this program's focus
on coastal states. By factoring in the proportion of shoreline
miles, the formula also acknowledges that a state's amount of
coastline is an important consideration in assessing adaptation
needs. Once again, however, the State feels the formula should
account for the unique needs experienced in the Arctic and high
latitudes.
Division B--Pollution Reduction and Investment
title i--reducing global warming pollution
Subtitle A--Reducing Global Warming Pollution
Reducing Global Warming Pollution. (Sec. 101)
``International Offset Credits.'' (Clean Air Act [CAA] Sec.
744)
International Offsets. The State supports the inclusion of
international offsets (the ability for companies to reduce
emissions outside the U.S. and have it count towards domestic
reductions). Like H.R. , S. allows international
offsets, though the portion of overall offsets comprised by
international offsets is smaller in S. than in H.R. .
Definitions. (Sec. 102)
``Definitions.'' (CAA Sec. 700)
Alaska Refineries. Alaskans are uniquely dependant on in-
state refineries for their fuel needs. Alaska has limited fuel
storage and is located thousands of miles from the nearest non-
Alaskan refinery. The state's refineries are particularly
vulnerable to increased costs because they are relatively
simple on the Nelson Complexity Index, meaning they operate at
lower levels of economic efficiency than more sophisticated
refineries which can extract more refined product from a barrel
of crude oil. If Alaska's refineries are disadvantaged to the
point of closing, it would likely produce a wide range of
negative consequences across the state. These may include
higher costs associated with importing fuel by tanker and
building storage tanks in addition to increased economic
burdens on Alaska's rural communities.
The Chairman's Mark includes provisions granting small business
refiners additional time to comply with the Pollution Reduction
and Investment program and distributes additional allowances to
small business and medium refineries. These provisions could
help Alaska's refineries, but may not be sufficient to protect
them from substantial costs.
The State would support an exemption for certain domestic
refineries to prevent regional market failures and promote the
interest of regional energy security. One way of achieving this
is through modifications to the definition of ``covered
entities'' in the Clean Air Act. First, the language in S.
could be amended to match the corresponding language in H.R.
, requiring that a stationary source producing petroleum
products do so in ``interstate commerce'' to be covered under
CAA Section 700(13)(B). Second, CAA Section 700(1)(F)
subsection (viii) for ``petroleum refining'' could be removed.
These modifications would exempt refineries, like those in
Alaska, that sell virtually all of their saleable product in-
state.
Embedded Emissions, Direct Emissions, and Fossil Fuel Based
Carbon Dioxide. The State supports adding definitions for
Embedded Emissions, Direct Emissions, and Fossil Fuel Based
Carbon Dioxide to clarify that natural gas produced at the
wellhead or flowing through a pipeline will not be burdened
with the requirement of emission allowances for the carbon
dioxide that may one day be produced when the natural gas is
burned.
Natural Gas Liquids. The State seeks clarification on this
section, which differs from H.R. in its definition of
natural gas liquids as being ``ready for commercial sale or
use.'' This change raises concern given the value natural gas
liquids bring in a major gas sale scenario.
Disposition of Allowances for Global Warming Pollution Reduction
Program. (Sec. 111)
Fair Allocation of Allowances. The State is very concerned
about the disposition of allowances for Alaska under a cap-and-
trade regime. An EPA memo provided to Senator Feingold
indicated that the agency drastically underestimated emissions
in Alaska. The document gave the false impression that Alaska
would be sufficiently accommodated through the provision of
free allowances under H.R. . EPA's estimates for capped
emissions in appear to have been based exclusively on
Alaska's electric generation, primarily electricity generated
for retail electricity sales, leaving out all facilities that
generate their own power, such as oil and gas fields and some
military bases. As a result, EPA estimated the state's
emissions at three million tons per year (MMt/yr). For the same
year, the State's models estimated capped emissions at 24.2
MMt/yr. This inaccuracy could substantially disadvantage Alaska
in the distribution of allowances.
Emission Allowances for Alaska Natural Gas Transportation
Projects. The State supports specific free emission allowances
for the operation of Alaska Natural Gas Transportation
Projects. The 1,700 mile Alaska Gas Pipeline will be a source
of substantial CO2 emissions, estimated to be
between 20-50 percent of total Alaskan capped emissions.
``Electricity Consumers.'' (CAA Sec. 772)
Regulatory Commission Approval. This section describes an
allocation process for allowances to electric utilities with a
requirement that applicants first seek approval from the
Regulatory Commission of Alaska. This requirement could create
a costly unfunded mandate for the State as regulatory
proceedings have become contentious and expensive.
Hydropower Projects. See discussion for section 161.
``Home Heating Oil and Propane Consumers.'' (CAA Sec. 774)
Heating Oil Allocation. CAA Section 774 addresses
allocations to states based on domestic oil and propane
consumption and, as written, is unfavorable to Alaska. Free
allowances for heating oil and propane would be allocated to
the states based on each state's relative share of total
domestic heating oil and propane consumption. Alaska consumes a
significant amount of oil due to heating degree days and the
prevalence of heating oil use across the state. Heating oil and
propane, however, appear to be weighted equally. Thus, states
like California and Texas that may consume more propane for
barbecue grills and hot tubs than Alaska consumes heating oil,
would receive larger shares. The State believes heating oil and
propane should be separated for allocation purposes.
Exchange of State-Issued Allowances.'' (CAA Sec. 777)
State-Issued Emission Allowances. Although Alaska is only an
observer of the Western Climate Initiative (WCI), it supports
WCI's position that the work of the states should be integrated
into a new climate regime, rather than completely preempted.
This bill would integrate state efforts by exchanging regional
allowances for federal allowances.
``Commercial Deployment of Carbon Capture and Sequestration
Technologies.'' (CAA Sec. 780)
CCS in High-Cost Locations. The State supports the
commercial deployment of carbon capture and sequestration (CCS)
technologies, and in particular, sequestration as a result of
Enhanced Oil Recovery (EOR) projects. CCS is afforded special
treatment through the ``bonus allowance value,'' which is
essentially a subsidy when compared to the value of purchased
or freely distributed allowances.
The State supports EOR activities in Alaska, especially on the
North Slope. This activity produces multiple benefits.
Sequestration of CO2 in a known, well-defined
hydrocarbon reservoir and trap is inherently safer than in
those that are less defined. Furthermore, increased production
due to EOR will lengthen oil field life. Since a gas pipeline
from the North Slope is economically dependent on the oil field
facilities, increasing oil field life improves the economics of
a gas pipeline. Gas, as a fuel source, is more environmentally
friendly than other carbon fuel sources.
The costs of CCS on the North Slope may still be prohibitive,
however, even with a boost from these allowances and incentives
through carbon costs. Costs have been found to be significantly
higher for CCS on the North Slope than the averages published
for the Lower 48, primarily due to the North Slope's location
and weather. The State supports inclusion of provisions that
account for greater expenses in high-cost locations in order to
make CCS economically feasible in these areas.
Ensuring Real Reductions in Industrial Emissions. (Sec. 141)
``Definitions; Eligible Industrial Sectors.'' (CAA Sec. 762,
763)
Foreign Competition for Domestic Refineries. These sections
protect certain manufacturing industries from ``off-shoring''
and foreign competition, but specifically exclude domestic
refineries. The State believes domestic refineries should be
protected as well.
title ii--program allocations
State and Local Investment in Energy Efficiency and Renewable Energy.
(Sec. 202)
Allocation Formula. The allocation method in this section
unfairly disadvantages Alaska. While 30 percent of the
allowances are granted to states on an equal basis, 30 percent
is allocated based on population and another 40 percent is
allocated based on state energy consumption as a share of total
domestic consumption. By these standards, Alaska would receive
fewer allowances than almost any other state. This proposal is
unfair to Alaska because the state has more heating degree days
and thus Alaskans use more energy on average than residents of
other states, costs are highest in rural Alaska where incomes
are typically lowest, and switching to other fuel sources is
not possible or cost effective in most cases for rural
Alaskans. The State would support an increased percentage
distributed equally among states, measuring energy consumption
per capita rather than as a share of total consumption, or
allocating some allowances based on energy costs as a share of
per capita income using Census data.
Indian Tribes. In addition, the State supports Section 202,
which provides for the distribution of allowances to Indian
tribes, which may benefit some rural areas of Alaska.
Additional Issues
Domestic Production.--The State believes S. should be modified
to expand access and incentives for responsible domestic onshore and
offshore oil and gas exploration and production. The U.S. Department of
Energy's recent forecast for growth in the energy sectors shows demand
for fossil energy continuing to increase in the nation, and to remain
above 80 percent of the total portfolio of energy supply through
and beyond. Therefore, it is clear that fossil fuels will be needed as
a bridging fuel in the coming decades, and access to domestic
production, and specifically clean-burning natural gas, is imperative.
Increased domestic production, carbon mitigation, expanded development
of renewables, and long-term nuclear energy planning is the only viable
path to a secure energy future.
OMB Funding Criteria.--The State believes the Office of Management
and Budget should be tasked with developing common criteria federal
agencies can use to prioritize funding to state and local governments
and tribes for infrastructure and other projects addressing climate
change vulnerabilities. Existing funding criteria may not be
appropriate for this purpose. For example, in sparsely populated but
more vulnerable areas like western Alaska, federal assistance may be
withheld despite great vulnerability if the primary criterion for
funding is the number of people or the dollar value of infrastructure
at risk.
EPA Limitation Provision.--S. does not include important
language related to the Environmental Protection Agency that appeared
in H.R. . The House bill contains language preventing the EPA from
requiring performance standards on stationary sources under the federal
cap. The State feels limitation language like that in the House bill
should be included in S. and that EPA officials should not set
climate change policy.
Adaptation Priorities.--The State has identified the following as
high priorities and areas of need with respect to adaptation:
Changing Risks. The State supports collaboration between the
states, federal agencies, and academia to challenge traditional
assumptions on weather and climate. This effort should focus on
data collection and analysis, forecasting models, hydrology,
flood plains and inundation, coastal and riverine erosion,
critical infrastructure, and related topics.
Community Profile. The State believes the initial focus and
study on adaptation should be on Alaskan coastal and riverine
communities. These communities are currently threatened due to
climate change and cannot relocate without extreme disruption
and costs.
Evacuation Routes. The State seeks federal assistance in
identifying, designing, constructing, and maintaining all-
weather evacuation routes from endangered communities to safe
havens from approaching storms.
Safe Havens. The State seeks federal assistance in selecting
and equipping safe havens near the endangered communities, with
full consideration of the hydrology, geology, and current and
more accurate digital mapping. These safe havens should be
outfitted with sufficient housing, water and fuel sources, and
communications capabilities.
Shoreline Protection and Stabilization. The State supports a
program of shoreline protection and stabilization and considers
such projects as the most effective means of protecting against
the sudden onslaught of storms.
Science, Analysis, and Informed Decisions. The State calls
for creating and sustaining a program of coordinated,
collaborative scientific examination and study of the Arctic
climate and environment.
Other Key Areas. Alaska's needs will also encompass other
key areas such as consequences to natural resources, national
security, infrastructure, emergency response capacity, etc.,
resulting from climate change impacts due to diminishing Arctic
sea ice and from ocean acidification.
______
Statement of Daimler Trucks North America
Daimler Trucks North America (DTNA) appreciates Chairman Bingaman
and Ranking Member Murkowski for holding an important hearing on the
role of natural gas in mitigating climate change. DTNA is a leader
among US truck manufacturers in introducing natural gas technology in
its lineup of trucks. We strongly believe that natural gas,
particularly in the truck sector, is a viable solution to reducing
greenhouse gas emissions, lowering diesel consumption, and reducing
fuel costs.
Earlier this year Daimler's Freightliner brand introduced its first
natural gas-powered truck. The Freightliner Business Class M2 112 NG is
ideal for port operations, utilities, and municipalities and other
short and medium-haul trucking applications. By next year Freightliner
will offer natural gas technology in 90 percent of its truck
applications.
Daimler is committed to natural gas because of its inherent
advantages over petroleum-based fuel. For example, it produces lower
fuel costs both today and for tomorrow. Today diesel averages $2.54/
gallon whereas CNG averages $1.73/gallon. And annually, natural gas
technology can save an estimated $10,000 in fuel and operating costs
per truck. Freightliner's natural gas trucks are cleaner too. Our
trucks already meet the Environmental Protection Agency's (EPA)
standards with 85 percent lower NOX emissions than its
diesel counterpart. Most importantly, the United States has an abundant
supply of natural gas that may allow natural gas vehicle operation for
years to come. According to the Energy Information Administration,
proven reserves in the US are continuing to increase.
Natural gas powered trucks are perfect for short and medium-haul
trucking. Today's natural gas trucks are ideally suited for 300 miles a
day usage. For companies that rely on short and medium-haul distances,
for example at ports and in local municipalities, natural gas is both
economical and efficient.
Although natural gas trucks have distinct advantages, we recognize
challenges continue to exist, particularly for long-haul trucking. The
lack of a national network of natural gas stations is the leading
obstacle facing natural gas long-haul trucking. Less than 1,000 natural
gas stations exist in the US. By comparison, there are over 120,000 gas
stations. Technology costs still remain high too. The incremental cost
of a typical natural gas truck is $45,000 more expensive than a
comparable truck with a conventional diesel engine. Engine technology
is still a work in process, especially for long-haul heavy trucks that
need a lot of power and must meet EPA emissions standards.
Daimler Trucks believes these challenges can be overcome in a
relatively short period of time given the right mix of vehicle, fuel,
and infrastructure incentives. The alternative motor vehicle tax credit
and natural gas refueling property credit are both important tools for
stimulating demand. New grant opportunities for natural gas vehicle and
engine development are also critical to natural gas' future.
Daimler Trucks urges the Congress is support natural gas technology
and recognize its value as a clean, abundant, domestically-produced
fuel in the debate over climate change.
______
Statement of NGVAmerica
i. introduction
NGVAmerica appreciates the opportunity to provide the following
statement concerning the role of natural gas in mitigating climate
change. NGVAmerica is a national organization dedicated to the
development of a growing and sustainable market for vehicles powered by
natural gas, biomethane and natural gas-derived hydrogen. NGVAmerica
represents more than 100 member companies, including: vehicle
manufacturers; natural gas vehicle (NGV) component manufacturers;
natural gas distribution, transmission, and production companies;
natural gas development organizations; environmental and non-profit
advocacy organizations; state and local government agencies; and fleet
operators.
On October 28, , the Senate Energy & Natural Resources
Committee conducted a hearing to review the role of natural gas in
mitigating climate change. A number of industry representatives were on
hand to discuss the potential positive impact of increased natural gas
use. NGVAmerica's statement specifically addresses how the increased
use of natural gas vehicles (NGV) can play an important role in
reducing greenhouse gas emissions from the transportation sector and
provide other important benefits.
One of the most important points to consider when assessing the
potential role of natural gas in mitigating climate change associated
with the transportation sector is the recent findings concerning the
increased availability of domestic natural gas supplies. This point is
critical because, in the past, questions have been raised about whether
the U.S. has sufficient domestic resources to support the increased use
of natural gas as a transportation fuel. Those concerns have now been
dispelled given the recent extraordinary expansion of the U.S. natural
gas resource base. Over 85 percent of natural gas used in the U.S.
today in produced in the U.S. (most of the rest is produced in Canada).
By , the U.S. Energy Information Administration forecasts that 97
percent of the natural gas used will be produced in the U.S. Therefore,
the U.S. natural gas resource base could easily support a growing NGV
market. Increasing the use of NGVs will help reduce greenhouse gas
emissions and lessen reliance on foreign oil imports.
Natural gas is widely recognized as a low-carbon fuel, the cleanest
of all the fossil fuels. Extensive analysis indicates that the natural
gas when used as a transportation fuel reduces carbon dioxide
equivalent emissions by 20--30 percent compared to gasoline and diesel.
These benefits are based on full-fuel cycle analyses that have been
conducted by federal and state environmental authorities. In addition,
natural gas when used as a transportation fuel is quite competitive
with the current generation of renewable fuels and is capable of being
blended with renewable fuel or sourced completely from renewable
feedstocks (e.g., landfill methane gas). Renewable natural gas
currently is the cleanest transportation option available anywhere. The
benefits of renewable natural gas often are overlooked due to the focus
on liquid biofuels. NGVs also provide benefits in terms of reductions
in criteria pollutants as well, a point underscored by the fact that
some of the cleanest internal combustion engines in the world are
fueled by natural gas.
In addition to the public policy advantages, NGVs are a proven
technology that is available today. In fact, in most areas of the
world, NGV use is growing at a rapid pace. In the U.S. the market is
growing but at a much slower pace than elsewhere. Because the
technology is available now, NGVs can help offset greenhouse gas
emissions, and petroleum imports immediately without delay.
Accelerating the use of natural gas for transportation will lead to
increased economic activity associated with increased production of
domestic natural gas, installation of fueling infrastructure and
vehicle development. Natural gas sells as a considerable discount to
petroleum motor fuels and all other alternative fuels, so its use can
help businesses save money. With the right policies in place, the U.S.
could rapidly accelerate the use of NGV.
Congress already has taken a number of steps to encourage greater
use of natural gas and other alternative transportation fuels. These
steps were enacted as part of the Energy Policy Act of and
SAFETEA-LU. These incentives include tax credits for alternative fueled
vehicles, alternative fuel infrastructure and alternative fuel use.
Consumers and businesses alike are benefiting from the congressional
action that was taken to encourage the increased use of alternative
fuels. However, much more must be done if the U.S. is going to address
climate change and reduce its reliance on petroleum. This effort will
require sustained and significant federal support since the risks
associated with this effort are simply too great for private industry
to undertake alone in the timeframe needed. Moreover, this effort will
require a mix of different transportation fuels to fill the void
provided by petroleum, since no one single fuel appears likely to
supplant petroleum. Natural gas in particular can play an important
role in fueling medium- and heavy-duty vehicles and high fuel use
passenger car and light truck fleets.
Summary of Recommendations
1. Extend the current tax incentives for natural gas as a
transportation fuel. These incentives were adopted as part of
the Energy Policy Act of and SAFETEA-LU . Most of
these incentives are set to expire at the end of . The NAT
GAS Act of (S. ) would extend these incentives and
improve on them by making certain modifications. We urge the
Senate Energy & Natural Resources Committee members to support
enactment of this law.
2. Encourage the production of renewable natural gas by
providing a tax credit for renewable energy projects that
inject renewable natural gas into the natural gas pipeline
system.
3. Provide appropriate treatment for NGVs in the climate
change bill. Previous versions of the bill have encouraged
electric-drive vehicles and liquid biofuels over all other
alternative fuel options. There are many reasons to support the
increased use of electric vehicles and liquid biofuels.
However, transportation policy also should include a strong
role for NGVs. That means ensuring that federal R&D efforts aid
in improving the next generation NGVs and developing hybrid
vehicles that use natural gas engines. Moreover, it is
important to adopt policies that encourage public utilities to
play a role in development the market for NGVs.
ii. u.s. domestic supply of natural gas
The U.S. is fortunate to have a significant resource base of
natural gas. As recently as several years ago, there was concern that
U.S. and North American production would soon start to decline due to a
rapidly dwindling resource base. However, the past year has seen an
almost complete turn around in the outlook for natural gas. Energy
analysts from across the spectrum are now heralding the new age of
natural gas production here in the U.S. and possibly elsewhere in the
world as shale gas production is now economically feasible. Many now
point to the Colorado School of Mines' Potential Gas Committee's
report\1\ issued in June to highlight the changing outlook. Based on
the figures published by the PGC, the U.S. now has a 90-plus year
resource base of natural gas instead of the 65 year resource base
believed to exist in .
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\1\ See Potential Gas Committee Press Release--http://
www.mines.edu/Potential-Gas-Committee-reports-unprecedented-increase-
in-magnitude-of-U.S.-natural-gas-resource-base.
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MIT's Technology Review devotes its November/December cover page
story to discussing the remarkable turn of events here in the U.S.\2\
The article describes how some analysts think the assessments of the
production capabilities of the northeast's Marcellus Shale are much
larger than estimated by PGC. The article describes how the Marcellus
could be the second largest natural gas field in the world, second only
to a massive offshore field shared by Iran and Qatar. Daniel Yergin and
Robert Ineson, of the respected Cambridge Energy Research Associates,
recently authored an article for the Wall Street Journal, entitled,
``America's Natural Gas Revolution--A `shale gale of unconventional and
abundant U.S. gas is transforming the energy market.'''\3\ The article
claims that the biggest energy innovation of the decade is the
development of unconventional natural gas. The article also indicates
that ``shale gas plays around the world could be equivalent to or even
greater than current proven natural gas reserves.'' The conclusion of
this article is that natural gas is likely to play a much larger role
in the world's energy mix in future years.
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\2\ ``Natural Gas Changes the Energy Map'', MIT Technology Review
(November/December ).
\3\ WallStreet Journal (November 3, ).
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With abundant domestic supplies, natural gas use in transportation
becomes increasingly attractive. Policy makers should no longer be wary
about whether we have the natural gas supplies to support its use as a
transportation fuel. To put the potential in perspective, consider that
we currently use roughly about the same amount of total energy for on-
road transportation as we do for all natural gas purposes (e.g.,
electric generation, commercial, residential). Therefore, replacing 10-
20 percent of transportation fuel use with natural gas would increase
natural gas use by only 10-20. The U.S. natural gas vehicle industry is
focusing its marketing efforts on capturing an increased share of the
medium-and heavy-duty market and a share of the light-duty high-fuel
fleet market. Since 30 percent of the petroleum used for transportation
is diesel fuel and since NGVs are the only alternative fuel that can
capture a significant share of the diesel market, the industry's
strategy makes sense for the NGV industry and public policy.
iii. climate change benefits of natural gas vehicles
Natural gas is a recognized low-carbon fuel. In the past several
years, extensive analyses have been conducted to determine the full
fuel cycle emissions impact of NGVs. These reports indicate that
natural gas reduces greenhouse gas emissions by up to 30 percent when
compared with gasoline and diesel fuel. The most recent reviews have
been conducted by the California Air Resources Board (CARB), which
conducted an exhaustive review of different transportation fuels as
part of its effort to develop the nation's first low-carbon fuel
standard.\4\ This standard requires a 10 percent reduction in carbon
intensity of transportations fuels by . CARB has determined that
natural gas exceeds the requirements of the program and, therefore, has
exempted it from the regulatory requirements. Businesses that supply
natural gas for the transportation market, however, are free to become
regulated entities if they wish to earn credits under the program.
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\4\ See CARB Low Carbon Fuel Standard--http://www.arb.ca.gov/fuels/
lcfs/lcfs.htm. CARB's website includes numerous documents detailing the
greenhouse gas impacts of different transportation fuels including
assessments of LNG, CNG, and renewable natural gas. The renewable
natural gas papers include assessments of CNG and LNG from biomethane.
The California Energy Commission similarly has published an extensive
review of the well-to-wheel analysis of different transportation fuels.
The results of the CEC analysis are contained here: http://
www.energy.ca.gov/publications/CEC-600--004/CEC-600--004-
REV.PDF.
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The LCFS assigns a carbon intensity factor to different fuels based
on a full fuel cycle analysis, i.e., well-to-wheels. According to CARB,
the carbon intensity of natural gas is 68 gCO2e per mega-
joule (MJ). The carbon intensity for gasoline and diesel fuel is 95.85
and 94.71, respectively. Thus, natural gas is estimated to be 29
percent less carbon intensive when compared with gasoline. Natural gas
is estimated to be 20 percent less intensive than diesel fuel when used
in medium or heavy duty vehicles; CARB currently assumes a 10 percent
fuel efficiency penalty for heavy-duty NGVs, thus the reason for the
reduced carbon benefits. The carbon intensity of renewable natural gas
(i.e., biomethane produced from organic waste) is estimated to be 11-13
gCO2e per MJ. At 11.25 gCO2e/MJ, renewable CNG
from landfill gas has the lowest of any fuel reviewed by CARB--even
lower than biodiesel (unadjusted for indirect land-use) at 13.70
gCO2e/MJ. The reductions for renewable natural gas are
nearly 90 percent when compared with gasoline and diesel fuel. To
highlight the viability of renewable natural gas, a short summary of
existing projects involving biomethane is provided below.
The greenhouse gas emission benefit of NGVs is expected to continue
to improve in the future as new automotive technologies become
available. In fact, a recent National Academy of Science (NAS) report,
entitled Hidden Costs of Energy: Unpriced Consequences of Energy
Production and Use\5\ includes some very positive findings concerning
natural gas vehicles. The report, which analyzed vehicle technologies
as of and , essentially projects that with further expected
improvements in vehicle technology and fuel efficiency, natural gas
powered vehicles will provide superior benefits in terms of criteria
pollutant reductions and greenhouse gas emissions compared to nearly
all other types of vehicles, even electric and plug-in electric
vehicles. The report's findings include an assessment of the full fuel
cycle benefits of different transportation fuels and vehicles, and
include an assessment of the energy and emissions associated with
producing motor vehicles. The NAS report's assessment of natural gas
calculates the emissions in terms of grams of CO2-equivalent
per mile, not per mega-joule. The total emission reduction benefits
projected in the NAS report are more modest than those reported by
CARB, which did not include emission associated with vehicle
production. The NAS report indicates that natural gas vehicles
currently provide about an 11 percent reduction in CO2-
equivalent emissions compared with gasoline passenger vehicles, but it
projects that this benefit will grow to 21 percent by with
improvements in fuel efficiency.
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\5\ National Academy of Science (October ): http://www.nap.edu/
catalog/.html
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Natural gas also can be used to provide hydrogen for fuel cell
vehicles. Nearly all of the hydrogen used in the U.S. today is reformed
from natural gas. We previously have provided statements to Congress on
the role natural gas can play in accelerating the introduction of
hydrogen fuel cell vehicles. We would be happy to provide such
information to the committee if it is interested.
iv. example of renewable natural gas transportation projects
While the number of renewable natural gas projects in the U.S.
remains small, it is worth highlighting several of these projects to
show that this fuel has real potential.\6\
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\6\ One of primary reasons that the number of biomethane projects
in the U.S. is growing slowly is that the federal government provides a
significant tax incentive from producing electricity from biogas on
site, but no incentive for producing and using biomethane. The size of
the tax incentive has skewed the use of biogas toward on-site
electricity generation. Legislation has been introduced in the House
and the Senate (HR and S. 306) to provide a more level playing
field for biomethane production.
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The McCommis Landfill in Dallas, Texas is currently supplying 4.5
million cubic feet of natural gas per day. This is the energy
equivalent of producing 35,000 gallons of gasoline per day. The
biomethane is currently being injected into the natural gas pipeline
system nearby. However, Clean Energy, a major provider of natural gas
for transportation use, owns the rights to the natural gas and has
plans for someday using this fuel as a transportation fuel.
In California, Waste Management, North America's largest waste
management company, and Linde North America, recently began producing
LNG at the Altamont Landfill near Livermore, California. The LNG will
be used to fuel hundreds of refuse collection trucks. Waste Management
and Linde have said the facility is expected to produce up to 13,000
gallons a day of LNG.
In Texas, manure from dairy farming operations is being converted
into methane at the Huckabay Ridge facility. The facility is capable of
processing manure from up to 10,000 cows. According to published
reports, this facility produces 650,000 million BTU a year, which is
equates to a gasoline gallon production rate of almost 14,000 gallons
per day. The biomethane at this facility is sold as pipeline-grade
natural gas.
In Ohio, the Solid Waste Authority of Central Ohio (SWACO) is
currently producing biomethane from landfill waste and converting it to
CNG. The fuel is then used to fuel a small number of vehicles at the
company's Green Energy Center. The production at this facility
currently is only about 250,000 gallons per year, much smaller than
other facilities identified. However, SWACO plans to expand its
operations, and will have the capability of annually producing 5--10
million gasoline gallons. SWACO currently plans to sell the biomethane
to local utility pipelines.
Prometheus Energy and the Bowerman Landfill in Orange County,
California have partnered to turn landfill gas into LNG. The fuel is
being used to fuel local transit buses and garbage trucks. The plant
installed at the site is currently producing about 1,000 gallons of LNG
per day, but is expected to increase daily production to 5,000 gallons.
In Europe, biomethane for transport is catching on much faster than
in the U.S. In fact, Sweden currently estimates that fifty-five percent
of the natural gas used in vehicles in that country is biomethane. To
facilitate the use of biomethane, several European countries also have
policies that require pipelines to accept the transport of biomethane.
An excellent summary of developments in Europe was prepared by the
Goteborg Business Region and Biomethane West.\7\
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\7\ See Fueling the Future; http://www.businessregiongoteborg.com/
download/18.ae10ceae/
BiomethaneV_FuelingTheFuture.pdf.
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The U.S. Department Office of Energy Efficiency & Renewable Energy
recently prepared a white paper on the potential of using renewable
natural gas.\8\ The document provides an excellent overview of the
benefits and potential for renewable natural gas.
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\8\ Renewable Natural Gas: Current Status, Challenges, and Issues
(Sept. ); http://www1.eere.energy.gov/cleancities/pdfs/
renewable_natural_gas.pdf.
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v. enact incentives that encourage the use of natural gas vehicles
In order to achieve the potential benefits of increased natural gas
use, NGVAmerica urges the Finance Committee and Congress to enact the
NAT GAS Act (S. , HR ). In addition, we also would urge the
Congress to enact legislation supporting the production of renewable
natural gas.
NAT GAS Act
Both the House and Senate have introduced legislation to advance
the use of NGVs. The bills, S. and H.R. , are very similar.
Importantly, both would extend the current incentives for natural gas
users that have been in place since . The bill's also modify and
expand the incentives to make them more effective. These incentives are
about to expire at the end of this year (in the case of the credit for
sale of CNG or LNG) and next year (in the case of the incentive NGV
purchases and fueling infrastructure development). The bills also
include federal authority to carry-out much needed research and
development (R&D) necessary to improving the quality and performance of
the next generation of NGVs. Extending the effective dates of these
expiring provisions would help continue the progress made by natural
gas fueled vehicles in displacing gasoline and diesel. Extending the
effective date also would send a clear message to fleets and other
vehicle owners that Congress supports the use of alternative fuels like
natural gas as an energy security and climate change strategy for the
mid-and long term. Adoption of these incentives is critical to ensuring
that the U.S. takes advantage of the significant opportunity provided
by its large natural gas resource base. NGVs are a solution that can
have an immediate impact on petroleum imports, economic activity and
greenhouse gas emission reductions. For all these reasons, it is
imperative that the Congress enact the NAT GAS Act.
Renewable Natural Gas Legislation
S. 306, the Biogas Production Incentive Act, introduced by Senator
Nelson (D-NE), would establish a $4.27 per MMBTU tax credit for the
production of renewable gas. Representative Higgins (D-NY) also has
introduced similar legislation in the House (H.R. ). The U.S.
Congress currently supports the expanded use of domestic renewable
resources through a variety of tax incentives and other programs. Up to
this point, Congress has focused primarily on measures that support the
production of renewable liquid transportation fuels or renewable
electricity. In the U.S., however, natural gas represents 23 percent of
the energy consumed. Natural gas is the fuel of choice to provide
residential and commercial heat for space and hot water in most
applications and is used to produce steam in a variety of commercial
and industrial applications.
Natural gas is also the fuel that provides the energy to
manufacture many industrial products including aluminum, steel, glass,
chemicals, fertilizer, and ethanol. Incentivizing the production of
renewable gas from sources that include animal manure, landfills,
renewable biomass and agricultural wastes will support expanding the
role of renewables into this existing energy sector, where little
opportunity exists today. It will also create another business
investment prospect for renewable project developers and the potential
to expand rural economies while supporting existing industrial jobs and
dramatically reducing carbon emissions.
Renewable natural gas is a versatile form of bio-energy. It can be
used directly at the site of production, or placed in the pipeline to
support a variety of residential commercial or industrial applications.
Renewable natural gas produced from renewable sources, including animal
manure, landfills, renewable biomass and agricultural waste, can be
produced at high efficiencies, ranging from 60-70 percent.
Additionally, all of the technology components to produce renewable gas
from this variety of sources exist today. Renewable natural gas can be
delivered to customers via the existing U.S. pipeline infrastructure.
It can provide a renewable option for many heavy industries, which
could save existing industrial jobs in a carbon constrained economy--
while creating new rural green jobs. As noted earlier, renewable
natural gas also can be an excellent transportation fuel. Renewable
natural gas production in digesters provides the agricultural sector
additional environmental benefits by improving waste management and
nutrient control.
For all the reasons discussed here, the Congress should adopt a new
tax credit specifically encouraging the production of renewable natural
gas.
vi. climate change legislation
The Congress currently is considering a number of proposals to
address climate change. At this point, it is difficult to determine
which proposals likely will be enacted into legislation. However, we
offer the following comments in regards to some of the major themes
that have been put forward. Several of the introduced proposals call
for accelerated introduction of more fuel efficient vehicles and
specifically encourage efforts to commercialize electric vehicles. We
support such efforts but believe that the legislation should be
expanded to specifically include NGVs. As noted above, the Congress
should extend the current tax incentives for NGVs. This would
accelerate their introduction and deliver immediate greenhouse gas
emission reductions. Some climate change proposals also would allocate
a portion of the proceeds from carbon allowance sales to the Department
of Energy or Environmental Protection Agency for advanced vehicle
research. These proposals again have largely focused on the role of
electric vehicles and their contribution to reducing greenhouse gas
emissions. Such efforts also should include NGVs. There also have been
proposals to encourage electric utilities to facilitate the development
of electric charging infrastructure. Natural gas utilities also could
play a major role in facilitating the use of low-carbon fuels and their
infrastructure. Legislation should encourage natural gas utilities to
make investments in natural gas fueling infrastructure and upgrades to
their distribution systems that will enable greater use of natural gas
vehicles and use of renewable natural gas.
Climate change legislation also should not discourage businesses
from selling more natural gas for transportation purposes. Natural gas
is a low-carbon fuel and its use should be encouraged, not discouraged.
As described above, substituting natural gas for petroleum provides
significant climate change benefits. Therefore, cap-and-trade
provisions should not include natural gas sales for transportation when
capping utilities sales of natural gas. If sales of natural gas for
transportation are included in the cap imposed on utilities, gas
utilities will have no incentive to grow new markets for natural gas as
this will only increase their burden to obtain offsets so that they can
continue to serve their traditional customers (e.g., residential,
commercial). Rather than working to facilitate a transition to greater
natural gas use in transportation, climate change legislation, if not
correctly drafted, could result in utilities viewing increased use of
natural gas for transportations as a burden to them.
vii. conclusion
NGVAmerica appreciates the opportunity to provide this statement.
We look forward to working with the committee as it crafts legislative
proposals to address climate change and energy security in ways that
will diversify the mix of fuels used in transportation.
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