March ’10

Peak Uncertainty: Obama Administration Poised to Initiate Carbon Regulation

The Obama administration is moving slowly but steadily toward regulating greenhouse gases even as a last-ditch effort to revive climate legislation in the U.S. Senate appears to be running out of steam.

The effort comes at a particularly odd time in Washington given the amazingly bitter negotiations around health care legislation that have proved so contentious that they threaten the viability of the Democratic majorities in both the House and Senate this fall. Still, the administration continues to pursue seemingly incongruous dual track efforts. Legislative strategists are using the threat of carbon regulation by administrative fiat to spur congressional action. Meanwhile, environmental activists see this as an opportunity to bypass Congress and regulate carbon.

In the next few weeks, the Environmental Protection Agency (EPA) is expected to issue new rules for limiting carbon-dioxide emissions from motor vehicles, and it could start laying the groundwork for regulating stationary sources by spelling out which facilities will need emission permits under the Clean Air Act.

EPA Administrator Lisa Jackson has pledged that the permitting process won’t begin until next year, and CO2 limits won’t be set for large emitters such as coal-fired power plants until late 2011 at the earliest. Jackson also committed to keeping the threshold for regulating emissions to well above 25,000 metric tons per year, which would exclude thousands of smaller plants and businesses, at least in the short term. But EPA’s plans have coal-state senators and others pushing hard to block or delay regulations while they continue working on climate and energy legislation.

Sen. Jay Rockefeller, D-W.Va., is drafting a proposal to postpone regulations for up to a year beyond EPA’s timetable, so Congress would have more time to develop an alternative to using the Clean Air Act to address climate change. Sen. Lisa Murkowski, R-Alaska, also has a resolution to block EPA action that has some Democratic support, reflecting the consensus in both parties that new legislation is preferable to administrative action using existing authorities.

“Congress is the appropriate body to address climate policy,” Murkowski said. “Until the specter of command-and-control regulations goes away, it will remain a counterproductive threat hanging over the work that must be done to find common ground.

“EPA regulation of greenhouse gases will increase consumer energy prices, add greatly to administrative costs for businesses, and create massive new layers of government bureaucracy. Such regulation, even slightly delayed, will endanger job creation, economic growth, and America’s competitiveness,” she added.

The bids to delay EPA regulations have taken on more urgency as Senate negotiations on climate legislation have bogged down. A bipartisan trio of Sens. John Kerry, D-Mass.; Joe Lieberman, I-Conn.; and Lindsey Graham, R-S.C., has been leading the effort to craft a climate bill that could get the 60 votes needed to break a likely filibuster. But Graham is threatening to drop out of the group if Democrats use budget reconciliation to enact health care legislation, a move he says would be “catastrophic.”

Graham’s withdrawal would put climate legislation on its deathbed, with no Republicans on board. Regardless, the chance of action on such a sweeping program is already growing slimmer as the midterm elections draw nearer.

Backers of energy and climate legislation haven’t given up yet, though. President Obama has stepped up pressure in recent weeks, telling 100 corporate leaders on Feb. 24, “we need to put a price on carbon pollution.” The administration also unveiled new incentives for nuclear power, carbon-sequestration technologies and solar energy last month.

Obama met on March 9 with key senators involved in the legislative effort, including a handful of Republicans, and asked for more details on a proposal by Sens. Maria Cantwell, D-Wash., and Susan Collins, R-Maine, to establish a “cap-and-dividend” program, in which most revenues from carbon permits sold to fossil fuel producers would be returned directly to U.S. consumers.

There is general agreement on one thing from all sides in the debate:  The cap-and-trade plan approved by the House last year is a non-starter in the Senate.

While the debate goes on, the administration is pushing ahead with its regulatory scheme, arguing it was forced to act after the U.S. Supreme Court ruled in 2007 that greenhouse gases are covered by the Clean Air Act if it is shown they threaten public health. The EPA issued an endangerment finding last year that went on the books in January, and the stage was set for rules limiting CO2 emissions from vehicles and other sources.

“They are definitely on a glide path toward regulation,” said Roger W. Patrick, an environmental attorney at Mayer Brown LLP.  “There is a school of thought that it’s a mechanism to put pressure on Congress, but these things tend to take on a life of their own. Once they start down that path it’s pretty hard to put the stopper back in the bottle.”

Overall, the Obama administration is seeking $1.1 billion for EPA’s clean air and global climate change program in its FY11 budget proposal, with $169 million for reducing greenhouse gases.  It proposed substantial increases in several programs, including $4.1 million more for administering its GHG reporting rule (which would bring the program to $20.8 million), $7 million to develop New Source Performance Standards to control GHG emissions from major stationary sources, $6 million to develop regulations for mobile sources, and $5 million to develop guidance for Best Available Control Technologies to control GHGs.

The administration is also moving to require agencies to include climate impacts in all environmental reviews of federal projects, and it seeks $171 million for adaptation initiatives at the Interior Department, an increase of more than $35 million from 2010 levels.

Other agencies are also getting into the act. The Securities and Exchange Commission voted 3-2 in January to provide guidelines for public companies to evaluate the impact of climate-change laws and regulations when assessing what information to disclose to investors.

The pace of the administration’s initiatives has raised concerns, even within the government. The Small Business Administration’s Office of Advocacy wrote the EPA late last year complaining that it failed to conduct a Small Business Advocacy Review for its proposed GHG regulations. “Instead, EPA certified under the Regulatory Flexibility Act (RFA) that each rule would not have a significant economic impact on a substantial number of small entities,” since small emitters would not be regulated for at least six years, wrote the office’s assistant chief counsel, Keith Holman.

“Advocacy believes that EPA’s RFA certifications are improper because they lack a factual basis,” Holman said. “More than 6 million small businesses will be regulated by GHG permitting requirements after the six-year deferral ends, while at least 1,200 small businesses will immediately become subject to GHG permitting. The economic impact on each small entity can be significant, including permitting application costs, delay costs, and consultant’s and attorney’s fees.”

Energy companies are clearly worried about the cost impacts as well, with some already saying the threat of regulations has created enormous investment uncertainty. Karen St. John, director of regulatory affairs for BP America, recently told an environmental conference that permitting requirements could delay many natural gas and refinery projects, or even lead to some new construction being scrapped.

Other delays will be caused by litigation that is certain to follow every EPA action. The Competitive Enterprise Institute (CEI) and several other groups are already challenging the GHG endangerment finding in federal court, and the CEI, a free-market think tank, has raised questions about EPA’s ability to change the threshold level for regulating gases considered harmful under the Clean Air Act.

The National Cattlemen’s Beef Association also filed a petition in the U.S. Circuit Court in December, arguing that EPA climate regulations would hurt large farms. And in February, the state of Texas joined a coalition of groups asking the federal appeals court to review EPA’s endangerment finding, calling it scientifically invalid. “Texas is aggressively seeking its future in alternative energy through incentives and innovation, not mandates and overreaching regulation,” said Gov. Rick Perry, a Republican. “The EPA’s misguided plan paints a big target on the backs of Texas agriculture and energy producers and the hundreds of thousands of Texans they employ.”

Other states have joined the chorus against federal regulations. The Louisiana Department of Environmental Quality wrote EPA in December that efforts to mandate GHG reductions would have a ‘‘devastating economic impact.’’ And Arizona’s Republican Gov. Jan Brewer recently pulled the state out of a regional cap-and-trade market that was organized by California and is scheduled to open in 2012.  Brewer said the program would raise costs for consumers and slow the state’s economic recovery.

Both sides in the climate debate argue that we are entering a period of peak uncertainty which is having a dampening effect on business investment and job creation.

The Heritage Foundation’s Patrick Tyrrell makes this point in The Foundry blog.  “Businesses have to deal with nearly unprecedented levels of uncertainty due to Washington’s inability to give them a clear roadmap of what policy changes lay ahead. A large part of this uncertainty is about the level of future taxes and increased regulations. Businesses are reluctant to hire when they could be facing additional labor costs due to government policies.  This, at a particularly vulnerable time due to the credit crunch and financial crisis, spells a death sentence for many small businesses, and stunts the growth of others.”

Michael Tubman of the Pew Center on Global Climate Change argues in his blog post on the Alaskan natural gas pipeline that the lack of a carbon policy is hindering growth.  “Backers of the gas pipeline are excited about its prospects to bring about a new round of growth in the local and national economies.  Yet the project needs regulatory certainty to move forward, and national climate legislation this year is an important step in that direction.  It should be no surprise that major companies involved in discussions over a gas pipeline, including USCAP members BP and ConocoPhillips, are, for a variety of reasons, looking for certainty in climate regulation; without this certainty, investment will almost certainly be stalled.  Congress needs to act this year in order for business to move forward with new projects, innovate, and grow our economy.”

For our part, we continue to believe that climate change legislation is highly unlikely this year, and surely dead if Republicans take control of either chamber in the November election.  We have made this prediction several times in the Report but it has become increasingly clear in recent weeks, even proponents of climate change.

While administrative action might provide some certainty, the EPA has started down the road of no return on carbon regulation.  What started as a strategic tactic to spur Congress to take action on climate change may have turned into its own Don Quixote-like crusade, despite the widespread opposition from Democrats and Republicans in Congress and the statehouses. Given the current melee over health care legislation and lack of legislative success on climate change, the real concern is that the Obama administration’s approach will harden and it will seek to enact its carbon policy through regulation only. Unfortunately, the period of peak uncertainty is here to stay.

Natural Gas: 2009 Watershed Year Likely to Impact Prices and Supply in 2010

Despite the global recession in 2009 and weak natural gas prices in the United States, domestic American natural gas production soared to its highest level in nearly four decades and liquefied natural gas (LNG) imports rose from their sharp drop in 2008.

For 2010, continuing economic improvement could resuscitate domestic demand, particularly in the industrial and commercial sectors, supporting continued strong domestic production.   While U.S. imports of pipeline gas from Canada likely will decline further, LNG imports will increase.

Demand Factors

Domestic demand. The U.S. Department of Energy’s (DOE) Energy Information Administration (EIA) estimates that total U.S. natural gas consumption dropped 1.5 percent in 2009 below the previous year’s usage of 23.2 trillion cubic feet (tcf).  Although lower gas prices enticed higher use of the fuel for electric power generation in 2009, the recession and other factors such as weather more than offset declines in gas consumption in the industrial, commercial and residential sectors. EIA expects consumption in 2010 to rise 0.7 percent to 62.9 bcf per day, but anticipates that higher gas prices will cause the electric power sector to reduce gas use by 2.8 percent, not fully offset by higher industrial, commercial and residential demand as the U.S. economy continues to grow out of the 2008-2009 recession.

International demand. Generally, the worldwide economic slowdown in 2009 was reflected in weakened demand among major gas consuming countries. Asia performed best during the global recession, with key countries such as China and India posting significant economic growth for the year. Their demand for natural gas reflected their economic resilience.  At the end of 2009, India’s Petronet LNG signed contracts for long-term supplies of an additional 2.5 million metric tons of LNG (120 bcf) annually from RasGas of Qatar, making India Qatar’s largest customer. Meanwhile, China plans to open several new LNG import terminals in 2010, and in 2009 China’s Sinopec signed its first LNG agreement.  The deal with ExxonMobil will ship 2 MMT (95 bcf) of LNG annually for 20 years from Papua New Guinea to the import terminal Sinopec expects to complete in 2014 in Shandong.

The shutdown of all seven units of Tokyo Electric Power Co.’s (TEPCO) Kashiwazaki Kariwa nuclear power station, caused by a July 2007 earthquake, continued to boost Japan’s demand for LNG imports, but during 2009 TEPCO began to bring the units back on line. Each of its seven units burns about 90 bcf annually, so TEPCO’s need for spot purchases of LNG will drop as each unit goes back into operation.

And Spain, which in recent years has bid up spot LNG prices to cover hydroelectric shortfalls, will see the completion in early 2010 of the Medgaz Pipeline that will carry 280 bcf of Algerian gas to meet its needs.

Supply Factors

Domestic supply. The United States produced 22.045 tcf of natural gas in 2009; the first time domestic marketed production has exceeded 22 tcf since 1973. The boost in homegrown gas pushed America ahead of Russia as the world’s leading natural gas producer.

Unconventional gas production lies behind the reversal in the decline of American gas production, especially shale gas. Over the last decade coalbed methane has accounted for 6-9 percent of domestic gas production, but shale gas has been the headline story, rising from a negligible amount 10 years ago to 2 tcf or more than 10 percent of domestic production in 2008. Initial estimates place 2009 U.S. shale gas production at around 3 tcf—a 50 percent leap over 2008 production.

The entry of the oil majors into shale gas was the big energy story of 2009. Small independent producers such as Chesapeake Energy, XTO Energy, Devon Energy and Southwestern Energy led the exploration and development of shale gas plays such as Marcellus in Pennsylvania, Barnett and Haynesville in Texas and Louisiana, Fayetteville in Arkansas, and Devonian/Ohio between Kentucky, Virginia and West Virginia.  As gas prices plummeted from their peak of more than $12 per million British thermal units (MMBtu) in mid-2008 to less than $3/MMBtu early in 2009, the independents were forced to shut some production and scramble for cash.

ConocoPhillips was among the first majors to move, purchasing a leading position in Texas’s Eagle Ford shale before the stampede and also buying into Haynesville Shale. In 2008, British giant BP PLC and Norway’s Statoil struck deals with Chesapeake Energy Corp. for part of its U.S. holdings. In 2009, Italy’s state oil company Eni SpA paid $280 million for a Barnett Shale stake owned by Quicksilver Resources Inc. And at the end of 2009, ExxonMobil agreed to pay $31 billion for Fort Worth gas producer XTO.  By January 2010, French oil company Total SA announced a $2.25 billion deal for a 25 percent stake in Chesapeake Energy Corp.’s Barnett Shale, the largest U.S. gas field by production. The two companies also were considering joint shale gas ventures in Texas and Canada.

As a result of the activity in shale gas, the Potential Gas Committee in Colorado last year revised its outlook for American gas supply upward by 35 percent in just two years.

In its Short-Term Energy Outlook (STEO), EIA projects a 2.7 percent reduction in marketed natural gas production in 2010 over 2009, due to the sharp drop in working natural gas rigs in production last year, but sees production increasing by 1.1 percent in 2011.

U.S. LNG Imports by Source

International supply. Although shale gas remains primarily a North American story, the phenomenon is spreading.

Terminal capacity

China National Offshore Oil Corp. (CNOOC) brought its second LNG terminal online in March 2009 in Fujian province, and its third came online in September in Shanghai, raising its total LNG import capacity to about 400 bcf annually.  CNOOC intends to bring two additional terminals, in Zhuhai province and Hainan, online in 2010. Rival PetroChina plans to commission two LNG import terminals next year, one in eastern Jiangsu province and the other in northeastern Liaoning province, while China’s third major petroleum company—Sinopec—expects to open its Guangxi LNG terminal this year. Taiwan’s China Petroleum Corp. opened a 140-bcf/y terminal at Taichung in 2009 to accommodate its contract with Qatar’s RasGas.  Elsewhere in Asia, companies in India, Pakistan and the Philippines plan to open LNG terminals in 2010.

In Europe, the Adriatic LNG terminal in Italy, Fos Cavaou in France, South Hook in Wales, and Dragon LNG in the United Kingdom began operation in 2009, adding more than 1.1 tcf of annual capacity.  Phase 2 of the South Hook facility should come on-stream in the spring of 2010.

In the United States, ExxonMobil’s 2-bcf/d Golden Pass terminal at Sabine, Texas is due to come online in the second half of 2010, bringing LNG from Qatar.  The first of two 450-mmcf/d expansions at El Paso’s Elba Island, Ga., LNG terminal is due for completion in mid-2010. Terminal capacity is hardly a restraint to U.S. LNG imports. The existing nine U.S. terminals used, on average, about 12 percent of their 3,900 bcf of capacity in 2009. Declining demand for LNG imports in the U.S. led both Sabine Pass LNG, La., and Freeport LNG, Texas, in 2008 to request authority to re-export LNG.  DOE granted their requests for a period of two years.

Stocks

Working gas in underground storage in the continental United States at the end of 2009 was 3,123 billion cubic feet.  This was 286 bcf higher than the same period in 2008 and 316 bcf or 11 percent above the five-year average, despite above-normal withdrawals the final week of 2009 due to colder weather.  Gas storage exceeded 3800 bcf throughout the month of November.

Pricing

Like oil prices, natural gas prices peaked in mid-2008 and dropped throughout the rest of that year. But unlike oil prices, which then turned up throughout the spring of 2009, leveling at $70-80 per barrel for the second half of 2009, gas prices continued to drop. Weekly futures prices for gas peaked at $13.46/MMBtu in early July 2008 and then steadily declined to less than $6 per MMBtu in 2008. The crash continued in 2009 with prices bottoming at less than $3/MMBt in August. Prices did not significantly recover, topping $5/MMBtu, until the second week of December 2009. With significantly colder weather in January, prices approached but did not reach $6/MMBtu at Henry Hub.

For 2010, the EIA projects less volatility in Henry Hub spot gas prices than in 2009, with prices moving between $5 and $6 per MMBtu and averaging $5.17 for the year, ultimately rising to an average of $5.65 in 2011.

While both oil and gas prices suffered from the recession, the link between oil and gas prices appears permanently broken. Unlike in Europe and Asia, where imported natural gas prices are linked to oil, although with a six- to nine-month lag, in the U.S. gas imports compete against domestic gas.  The sharp increase in domestic gas production—led by the boost from shale gas discoveries—combined with weakened demand, especially in the industrial and commercial sectors, has led to a growing divergence.  The traditional rule of thumb—based on energy equivalence—was that oil prices per barrel were about six times natural gas prices per million British thermal units. Thus, with natural gas prices at about $6/MMBtu, one would expect oil to trade at roughly $36 per barrel.  As the graphic illustrates (converting oil prices to MMBtu equivalents), this relationship held very strongly through 2006, comparing the U.S. average acquisition cost for oil to the average annual price for natural gas.  The far lower U.S. price for gas, compared to oil—and thus to European and Asian LNG imports—has made the U.S. the last choice for LNG exporters since 2006.

US Oil and Gas Prices

This divergence between oil and gas prices led several European gas importers to suggest last year that it was time to revise their long-term gas contracts with Russia and other suppliers to make gas more competitive with other fuels, including spot market gas. In mid-February 2010, Paolo Scaroni, CEO of Italy’s Eni SpA, announced that Eni had reached an agreement with Russia’s Gazprom OAO to make contract gas import prices more flexible. At the same time, in a press conference, Gazprom Deputy Chairman Alexander Medvedev reported said that while Gazprom had renegotiated its European gas contracts to take “into account the trends in the European market and the [economic] crisis,” that the “base principles” of the long-term contracts remained.

Conclusion

When we look back, we may consider 2009 to have been a watershed year in global and U.S. gas markets. The huge surge of U.S. shale gas production fundamentally changed perceptions of U.S. gas supply prospects and may alter future gas production prospects in Europe and Asia as well. The combination of rising shale gas production in gas-importing countries with a glut of capacity in LNG exporting countries finally may break the long-term, oil-linked pricing model for pipeline gas and LNG export contracts, one that has been maintained since the 1970s.  Finally, more attractive gas pricing, along with increasing pressure to lower greenhouse gas emissions, could boost gas markets in the industrial, power and even transportation sectors worldwide.

Analysis by Abraham Energy Report Contributing Editor Robert S. Price