Who Moved My Cheese?

Posted on August 31, 2016 by Michael Hardy

Spencer Johnson’s classic came to mind when I learned of new plans for the Burger power plant on the Ohio River.  The Burger plant has had a makeover from an electric generating facility to a massive chemical plant feasting on the abundant natural gas in the Marcellus and Utica regions of Western Pennsylvania and Eastern Ohio.

When I returned from active duty, my employer said, you will practice environmental law. Because I was accustomed to taking orders, I said "yes sir". That led me to cooling towers for the Davis Besse and Perry Nuclear plants on Lake Erie. More dramatically, however, it led me to years of dealing with coal-fired generation in Ohio.  Rich with coal and numerous coal-fired plants on Lake Erie and the Ohio River (and other rivers as well), I thought Ohio would supply cheap, coal-fired energy for many people for years.  Unfortunately, I did not predict the obsolescence of coal-fired electric generation or the recent emergence of natural gas as the leading source of fuel for power. I saw clients invest billions of dollars in pollution control equipment only to see the emission reduction goal posts moved beyond reach as regulators adopted progressively more stringent measures to address new national ambient air quality standards, lake breeze fumigation, long range transport, acid rain, regional haze, hazardous air pollutants, and greenhouse gas emissions.

When I started my  practice, virtually all of the Ohio base load units burned coal. And thousands of Ohio miners worked and their families prospered. Barges carried coal down the Ohio River or unit trains took coal to the Lake Erie plants.  I saw Little Egypt take big bites of coal and overburden in southeastern Ohio. I remember when an interstate (77) was closed to let the mammoth excavator proceed to the next seam of coal on the other side.

I have stood on the air pollution control deck of a massive Ohio River power plant that spans a highway. I have wiped the floor with white gloves of a coal fired plant on Lake Erie. I have worked with the dedicated professionals who took pride in maintaining those plants. So it saddens me to read that talented engineers are being laid off from engineering companies in Akron, and major utilities are selling megawatts on the Ohio River.  AEP and First Energy have announced plans to auction generating units.

Some of us remember that our success was measured in jobs retained while reaching a reasonable accommodation with the environment.  I hope my successors have that opportunity .

So with  sadness and regret – but also an appreciation that my career started in 1973, at the beginning of the burgeoning practice of environmental law, when "Coal Was King" and the Burger plant was alive and well – I hope you watch this short video of the demolition of the Burger coal-fired power plant to make way for a natural gas cracker.  Here is the demise of the Burger "tall stack." May Burger rest in peace.  

Energy Generation – A Classic Love-Hate Paradox of Choice and Conflict

Posted on October 31, 2014 by Sheila Slocum Hollis

“Elmer Gantry,” a noir classic novel by Sinclair Lewis and a 1960 film, features a tortured central character with the word “love” tattooed on the knuckles of  one hand and “hate” on the knuckles of the other hand.  The vision of the hands together intertwined as symbols of the dilemma of the conflicted protagonist’s internal battles is evocative of the disconnect between our deep and undeniable thirst for energy and our disdain for the manner by which it is produced and delivered to us.

A History of Options:

Coal fired power plants are coming under heavy fire as the U.S. seeks to significantly reduce air emissions.  Global climate change, health impacts and a series of other negative effects on the ecosystem are cited as bases for accelerated retirements of these generation stations.  No doubt coal mining is a tough and dirty business; yet for two centuries it has provided the backbone of the development of electric power plants and the extraordinary benefits of electric energy.  How to reconcile this history with the current political climate?  How do we transition from coal as a major US fuel source, one that provides domestic supply and multiple benefits in employment, tax base, and economic activity? 

Likewise, hydroelectric generation is enshrined in the transformation of much of the West in the songs of Woody Guthrie, as a magnificent contribution to our development as a nation.  And, the desirability of hydroelectric generation is magnified when the only “issue on the table” is the greenhouse gas impacts of generation.  Yet, the impacts of hydroelectric development have had deleterious effects on fish, landscapes, and water supply.  And, as drought strangles much of the West, there is a struggle over whether to tear down the much admired, in fact almost “loved,” green dams of the New Deal Era.  The question at issue here is which side is good and which is evil, and the answer is “it all depends.”

Another love-hate relationship lies with the nuclear generation fleet.  From the standpoint of greenhouse gas emissions, the nuclear generation fleet is a winner.  Yet to some anti-nuclear interests, the nuclear stations (for the most part, forty years or older) are the devil incarnate, and subject to exorcism.  Yet, these facilities provide nearly 20 per cent of the electric power of the country.  So again, the desire for a clean electric supply and antipathy to the technology clash.  In this case, dealing with the aftermath of closing a nuclear generation station includes the significant and seemingly intractable problem of nuclear waste storage and disposal, leading to more profoundly difficult questions and concerns.

Another emotional “generation war” is centered on the role of natural gas fired generation.  Once again, there are epic clashes over gas.  Gas is ever more obviously abundant and relatively desirable from an environmental standpoint. However, extreme passions have been aroused by gas production-related issues like hydraulic fracturing, new pipeline capacity and fears about safety, and harmful environmental effects from natural gas drilling, production, transportation and distribution.  Despite the fact that natural gas fueled generation has filled approximately a quarter of the nation’s electric generation demand for many years, and is likely to be a major solution to the shift from coal, nuclear and some hydroelectric plants, the heated anti-fracking debate continues.  Thus, the struggle continues between “good,” (by those who see gas as a solution to the need for reliable generation) and “evil” (by those who oppose the drilling, development and delivery impacts of any form of hydrocarbon-related fuel).  Indeed, the politics, sophistication and interest of high profile opponents has elevated the bitter war of words and politics to a new level.

Finally, the role of renewables as a source of generation to replace nuclear, coal and other forms of generation would, superficially, seem to be uncontroversial.  Yet once the specifics of a project become known, opposition to the project grows.  Like politics, all projects are local.  Wind power towers, with associated land use, avian impacts, noise, reliability and transmission-related needs become the object of ire for interests that may not benefit from the projects.  Likewise, solar projects with land use, impact on wildlife water use and other hot-button issues may precipitate other battles.  The beauty of the project is in the eye of the beholder and beneficiary.

            The Paradox Ahead

Overarching all these projects are difficult issues associated with transmission capacity and cost, reliability, taxation, employment and overall local economic dependency.  And uncertainty about the need for new generation makes things worse:  why tolerate potentially disruptive technologies if efficiency increases and other factors means that new generation isn’t needed?  In light of the volatile, complicated, politically charged environment, the struggle for answers and stability will continue.  As long as our society remains conflicted, these issues will continue unabated to be “front page,” and lawyer and politician intensive.  The search for rational solutions to meet the needs of the country for reliable, safe, environmentally acceptable electric generation must continue for the nation to survive and thrive, despite the pain, cost and compromise necessary.  And like the soul of “Elmer Gantry,” we must ultimately cease to be at war with ourselves to survive.  

Biting Less Than They Can Chew

Posted on June 26, 2014 by Kenneth Warren

The National Environmental Policy Act (NEPA) requires federal agencies to evaluate the environmental effects of their proposed actions.  When a proposed action may cause significant environmental impacts, NEPA requires the agency to prepare an environmental impact statement that evaluates alternatives including measures to avoid or mitigate impacts.  The agency may not divide a single project into separate bites and find that each in isolation would not have a significant environmental impact.  Instead, regulations issued by the Council on Environmental Quality require the agency’s environmental review to encompass connected actions and similar actions.

In Delaware Riverkeeper Network v. FERC, Texas Eastern Pipeline Company sought certificates of public convenience from the Federal Energy Regulatory Commission (FERC) authorizing construction and operation of the Northeast Upgrade Project, one of four projects to improve the Eastern Leg of a natural gas pipeline known as the 300 Line.  FERC evaluated the Northeast Upgrade project separately from the others on the ground that each project was designed to provide natural gas to different customers pursuant to different contracts within different time frames.  FERC concluded that the potential environmental impacts were not significant and terminated its evaluation by issuing a finding of no significant impact.  Environmental organizations petitioned for review of the FERC action on the ground that the four pipeline projects were interrelated and cumulatively would, in their view, clear hundreds of forest acres, fragment habitat and adversely impact wetlands and groundwater in significant ways.  

On review, the Court of Appeals for the District of Columbia held that FERC’s segmented environmental review failed to meet NEPA’s requirements.  The Court reasoned that all four projects involved the construction of a single, physically interdependent pipeline, were undertaken in a close time frame and were financially interdependent.  No customer was a customer of a single pipeline segment and no logical justification existed for the choice of where one project ended and the next began.  Accordingly, the Court remanded the case to FERC to review the pipeline project as a whole, including its cumulative impacts.

FERC now faces the daunting task of determining how to implement the Court’s holding in other situations.  To be sure, in many cases FERC will be able to readily ascertain whether projects involving a single pipeline are physically, financially and temporally interdependent.  But in some areas of the country, transmission pipelines are being installed contemporaneously with natural gas wells, gathering lines physically connecting these wells to the transmission pipelines, and supporting roads, impoundments and other infrastructure.  Whether these arguably related projects are sufficiently connected or similar to trigger joint NEPA review may turn on whether they involve different ownership, distinct functions, separate financing and customers and clear physical divisions.  Resolving these questions may be no easy task, and even then does not necessarily determine whether a full environmental impact statement must be prepared.  When performing an environmental assessment of multiple projects together, FERC may still conclude that the environmental effects are insignificant.  With so many steps in the analysis that may be controversial, a new wave of NEPA challenges is likely on the horizon.

One postscript for practitioners before the D.C. Circuit.  In a punchy concurring opinion, Judge Silberman expressed his dismay at the submission of a brief “laden with obscure acronyms.”  For those of us in the environmental bar for whom use of acronyms has become second nature, beware.  

U.S. EPA Updates Air Standards for Tanks Used in Oil and Natural Gas Sector

Posted on October 4, 2013 by Chester Babst

EPA is still working the kinks out of its New Source Performance Standards (NSPS) for the Oil and Natural Gas Sector, i.e., 40 C.F.R. 60 Subpart OOOO, referred to by many as the “Oil and Gas NSPS” and by some as simply “Quad O”.  EPA first published the proposed Oil and Gas NSPS on August 23, 2011, in conjunction with proposed revisions to three other air regulations affecting various segments of oil and natural gas operations.  The proposal prompted more than 150,000 public comments and kindled a national discussion on emissions at natural gas well sites.  The final Oil and Gas NSPS rule was published in August 2012.  Although the rule is most famous for establishing the first federal air standards for hydraulically-fractured natural gas wells, the rule also set significant volatile organic compound (VOC) standards for “storage vessels” used by the oil and natural gas industries.

Several stakeholders responded to the August 2012 rulemaking by filing petitions for administrative reconsideration of the Oil and Gas NSPS.  On April 12, 2013, EPA published a notice granting reconsideration for a number of issues and proposing revisions to the storage vessel standards, in particular.  Evidently, EPA significantly underestimated the number of storage vessels coming online in the field when it developed the August 2012 final rule, which required individual storage tanks with VOC emissions of 6 tons or more per year to achieve at least 95% reduction in VOC emissions.  Tanks are commonly used at natural gas well sites, for example, to store condensate, crude oil, and produced water.  In light of an updated tank estimate, EPA recognized that additional time would be needed for manufacturers to produce a sufficient number of VOC control devices. 

Most recently, on September 23, 2013, EPA published final revisions to the storage vessel requirements in the 2012 Oil and Gas NSPS.  Per the revised rule, which was immediately effective, an individual tank may be considered an affected facility if its construction, modification or reconstruction commenced after August 23, 2011; it has potential VOC emissions of 6 tons or more per year; and it contains crude oil, condensate, intermediate hydrocarbon liquids, or produced water.  EPA made a number of important adjustments in the revised rule, chief among them an extension of the compliance date to give tank owners and operators more time to purchase and install controls.  For the so-called “Group 1” storage vessels (which were constructed, modified or reconstructed between the August 2011 original proposal and the April 2013 proposal), the deadline to control VOC emissions is now April 15, 2015.  For “Group 2” storage vessels (i.e., vessels that come online after April 12, 2013), the compliance deadline is April 15, 2014.  Notably, pursuant to the revised Oil and Gas NSPS, operators only have until October 15, 2013 to estimate potential VOC emissions of Group 1 storage vessels for purposes of determining whether the rule applies.

Meanwhile, the agency is continuing to evaluate other issues raised in the reconsideration petitions that were submitted in response to the August 2012 rulemaking.  EPA has stated in the past that it intends to address the remaining issues by the end of 2014.

DOE Conditionally Approves Second Natural Gas Export License

Posted on May 30, 2013 by Deborah Jennings

On Friday, May 17, the Department of Energy (DOE) announced it had conditionally authorized Freeport LNG Expansion, L.P. and FLNG Liquefaction, LLC (collectively Freeport) to export domestically produced liquefied natural gas (LNG) to countries that do not have a Free Trade Agreement (FTA) with the United States from the Freeport LNG Terminal on Quintana Island, Texas.  This marks only the second time that the DOE has granted a natural gas export license to non-FTA countries, and only the first after DOE ceased action on all applications pending a study of the economic impacts of LNG exports.  The Freeport approval marks a noticeable, but likely incremental shift in US policy towards increased export of natural gas to non-FTA nations, opening up new markets for the boom in domestic natural gas production.

The DOE rejected opponents’ arguments that the project would be inconsistent with the public interest.  Among other reasons, the DOE found that the proposed exports are likely to yield net economic benefits to the US, would enhance energy security for the US and its allies, and were unlikely to affect adversely domestic gas availability, prices or volatility. Accordingly, DOE conditionally granted Freeport’s Application, subject to satisfactory completion of an environmental review pursuant to the National Environmental Policy Act (NEPA) by the Federal Energy Regulatory Commission (FERC) and DOE.  FERC will serve as the lead NEPA review agency. DOE will subsequently reconsider the conditional order in light of the NEPA analysis led by FERC and include the results in any final opinion and order.

Environmental issues will now take center stage as interested stakeholders seek to influence the government’s conclusions in the NEPA review.  In support of its application, Freeport extolled the following environmental benefits of the project:

•    Natural gas, the cleanest burning fossil fuel, would replace coal-fired power resulting in substantial reductions in greenhouse gas and traditional air pollutants. 
•    Compared to the average coal-fired plant, natural gas fired plants emit half as much carbon dioxide (CO2), less than a third of the nitrogen oxides, and one percent of the sulfur oxides. 
•    Natural gas, if used as a transportation fuel, also produces approximately 25 to 30 percent less CO2 than gasoline or diesel when used in vehicles, and is not a significant contributor to acid rain or smog formation.

Opponents of the project, however, are less convinced of its environmental benefits.  These include the Sierra Club, the Delaware Riverkeeper Network (consisting of 80 organizations), NRDC, among others.  Specifically, they assert that LNG exports will increase demand for natural gas, thereby increasing negative environmental and economic consequences associated with fracking, the process used for shale gas production.  They argue that the DOE’s two-part study of the economic impacts of LNG exports, upon which DOE relied in conditionally granting Freeport’s application, failed to consider the cost of the environmental externalities that would follow such exports, which include:

•    Environmental costs associated with producing more shale gas to support LNG exports;
•    Opportunity costs associated with the construction of natural gas production, transport, and export facilities, as opposed to investing in renewable or sustainable energy infrastructure;
•    Costs and implications associated with eminent domain necessary to build new pipelines to transport natural gas; and
•    Potential for switching from natural gas-fired electric generation to coal-fired generation, if higher domestic prices cause domestic electric generation to favor coal-fired generation at the margins.

Sierra Club and other organizations have previously challenged the adequacy of FERC’s and DOE’s NEPA determinations in other LNG export applications.  In the first LNG export license approval for Sabine Pass Liquefaction, LLC (DOE Docket. No. 10-111-LNG), Sierra Club, as an intervener in the FERC proceeding, challenged the adequacy of FERC’s NEPA compliance, and the lawfulness of the FERC’s determination to authorize the Project facilities. The FERC addressed these concerns and found that if a series of 55 enumerated conditions were met, the Project would not constitute a major Federal action significantly affecting the quality of the human environment. 

After FERC authorized the Liquefaction project, Sierra Club filed a motion to intervene out of time before DOE , again challenging FERC’s NEPA determinations.  DOE rejected Sierra Club’s motion, and granted the final order approving the LNG export on August 7, 2012.  Sierra Club subsequently sought a rehearing on the final order which was also rejected by the DOE in a January 25, 2013 order

Similarly, earlier this month, Sierra Club and other environmental organizations objected to the proposed Dominion Cove Point LNG export terminal in Maryland, arguing the project would harm the Chesapeake Bay’s economy and ecology, increase air pollution, and hasten fracking and drilling in neighboring states.  On May 3, 2013, the coalition filed public comments and a timely motion to intervene in the proceedings calling on FERC to conduct a thorough environmental review, or prepare an EIS, of the project.  The proposed terminal will be the only LNG export facility in the east coast, providing foreign markets with access to natural gas from the Marcellus Shale.

Cheap Natural Gas Prices: Prelude to Energy Unreliability and Price Volatility

Posted on May 14, 2013 by Michael Hockley

Cheap gas prices driven by a boom in new shale gas development, coupled with more stringent emissions controls for coal fired plants, are causing a shift from coal to natural gas as the primary source of electric power in the United States.  In the short term, most welcome this shift because natural gas produces significantly fewer greenhouse gas (“GHG”) emissions.  But it appears increasingly certain that in the long run, this shift will result in decreased energy grid reliability and significantly higher electricity costs due to natural gas price volatility.

A recent Duke University study concludes that the cost of compliance with new emissions standards could make almost two-thirds of existing coal fired plants “as expensive as natural gas even if natural gas prices rise.”  This combination of low gas prices and the high cost of coal emissions compliance already has resulted in replacement of many coal plants instead of retro-fitting them with expensive environmental controls.  Add to that the uncertainty of potential future GHG emissions standards, and construction of new coal fired power plants is at a near standstill.  

The Rocky Mountain Coal Mining Institute (“RMCMI”) estimates that these factors will combine to force closure of up to 100 gigawatts of coal plant capacity, or approximately one third of the coal-fired fleet, resulting in a net increase of 32 gigawatts of gas capacity in the next three years. By 2020, RMCMI estimates that gas generating capacity will exceed that of coal, nuclear, and hydroelectric combined.  The RMCMI further projects that the shift to natural gas generation will cause the demand for natural gas to exceed even the most rosy new shale gas production predictions, causing volatile natural gas price swings.  

Grid reliability problems and gas price volatility were highlighted by Gordon van Welie, the head of New England’s power grid, during recent testimony before Congress.  He observed that more than half of New England's electricity is generated from natural gas, which has displaced a more diversified mix of oil, coal, gas and nuclear power over the past ten years.  

He testified that even though natural gas generally is plentiful, New England’s inadequate gas pipeline capacity limits supplies during peak usage.  For example, during a recent extreme cold snap in New England, “natural gas prices in late January spiked to $34/MMBtu, in contrast to prices below $4/MMBtu across most of the country.” The high gas prices caused wholesale electricity price spikes of more than 100% in January and 300% in February 2013 compared with 2012.  There also were “multiple instances where generators could not get fuel to run,” including one instance when more than 6,000 MW were offline due to fuel shortages.  Testimony at 7.  To avoid even worse problems in the future, he urges increased construction of pipeline infrastructure, but construction of gas pipelines will take time.  In the short and intermediate term, he predicts continued price volatility and grid reliability problems during peak usage.  

In addition to pressures from increased usage of natural gas in the United States, there also is increasing support within the Obama Administration to side with those seeking to export liquefied natural gas because prices in foreign markets are much higher.  If the export of natural gas becomes a reality, then domestic gas prices likely will increase even more.  

Although the vast shale gas reserves are fueling a shift to natural gas power generation with a corresponding reduction in GHGs, over-reliance on natural gas will almost certainly have the unintended consequence of causing grid reliability problems and volatile price spikes.  This likelihood argues for a more balanced energy portfolio with a broad mix of power from renewable, hydropower, coal, oil, nuclear, and natural gas.  To insure future stable energy prices and reliable energy production, electric utilities and state and federal regulators should take a long term view when deciding whether to shift to natural gas generation and decommission existing coal and nuclear plants.

Decommissioning Power Plants: A Process Without a Standard Regulatory Framework

Posted on May 7, 2013 by Pamela Giblin

The confluence of aggressive new EPA regulations targeted at coal-fired power plants and low natural gas prices has made the decommissioning of older coal-fired plants substantially more likely in the coming years. Decommissioning a plant does not occur within a specific regulatory framework. In many cases, unless there is a suspected public health threat, potential environmental conditions at the plant do not have to be reported to government agencies. For that reason environmental remediation of a plant site is often addressed in the property sale and redevelopment process.

But the shut down and decommissioning of power plants nonetheless has significant regulatory implications, and the reality is that analysis of regulatory obligations and advance planning, including a proactive strategy for interacting with agencies and other stakeholders, is essential. Understanding obligations requires review of existing permits and the underlying regulatory landscape. And that landscape may shift under your feet – for example, new regulations for coal combustion residuals on the horizon may implicate the closure of certain waste management units.

The regulatory landscape may also provide opportunities to maximize value. There are a wide variety of emission credit programs that vary by jurisdiction. Identifying and capturing emission credits brings value to the table. Similarly, water rights, to the extent they are marketable in a particular jurisdiction, could be a source of revenue.

On the practical front, laying out a smooth decommissioning path through careful planning may help avoid stoking the fire of agency, local or public ire. The agency may have a formal role to play depending on the permit conditions or applicable regulations, but there may also be extensive agency oversight exercised through pursuit of enforcement actions. Particularly where community interest is high, local, state or federal agencies may have a heightened interest and enforcement provides them an avenue for involvement in the site that might not otherwise exist. So it is important to recognize the key stakeholders early and to understand how their interest may translate to pressure on an agency to leverage any violations.

If the site is one with good redevelopment potential, finding and working with a credible and savvy purchaser may keep the focus on the end game and allow for appropriate risk-based standards to be deployed against a more concrete vision for the future of the site. Once there is a well-developed understanding of the regulatory obligations associated with the particular plant and the overall objective for the site after decommissioning, it may be the moment to reach out to the state and federal agencies, and perhaps key stakeholders, with early, accurate and contextualized information.

Because there is not a standard regulatory framework to apply, experience over the coming years as plants come offline will be telling – it is that experience that will provide useful frameworks for up front, comprehensive analysis and strategic outreach for a smooth path through decommissioning.

FRACKING FRACAS IN A LOCAL LABYRINTH

Posted on February 19, 2013 by David Buente

Oil and gas development has traditionally been regulated by the states, and the majority of the states with viable shale reserves have adopted laws or regulations that directly address hydraulic fracturing.  However, several local governments have responded to concerns over potential health and environmental impacts by banning hydraulic fracturing within their jurisdictions.  To date, local bans have been enacted in Colorado, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, and West Virginia.  In several cases these local bans have been challenged as being preempted by comprehensive state regulation of oil and gas development.  While there is very little appellate case law addressing the legality of local bans, two preemption cases are currently on appeal in New York.  Norse Energy Corp. USA v. Town of Dryden, No. 2012-1015 (N.Y. App. Div.); Cooperstown Holstein Corp. v. Town of Middlefield, No. 2012-1010 (N.Y. App. Div.).  In each case, the local trial court upheld a local ban on hydraulic fracturing, finding that preemption language in the state’s Oil, Gas, and Solution Mining Law (“OGSML”) did not apply to local land use regulations. 

Appellant natural gas developers rely primarily on the OGSML’s preemption provision, arguing that its broad language was intended to preempt all local ordinances and regulations related to oil and gas development unless they are directed toward local roads or real property taxes.  They also emphasize the broad scope of DEC’s oil and gas regulations which go beyond regulating how oil and gas development is conducted and also address spacing requirements and other limitations on where oil and gas development can occur.  Thus, they assert that any local ordinance that limits where hydraulic fracturing can occur is superseded by the OGSML.  The natural gas developers also argue that under implied preemption principles and New York’s constitutional limits on home rule authority, local governments cannot prohibit hydraulic fracturing because such regulations are in direct conflict with the OGSML’s provisions that dictate where oil and gas development can occur.  Finally, the natural gas developers argue that the trial court’s reliance on supersedure provisions from other statutes was misplaced due to key differences in the language of the supersedure provisions as well as the relatively broader scope of DEC’s regulatory authority under the OGSML.   

In contrast, the towns of Dryden and Middlefield assert that local prohibitions on hydraulic fracturing can be harmonized with the OGSML and its preemption provision.  They argue that the local bans on hydraulic fracturing were not enacted for the purpose of regulating natural gas development, but instead are part of comprehensive land use plans designed to protect the public health, safety, and general welfare of the local community.  Because the purpose of the prohibitions are not to “regulate” natural gas development, the towns contend that the prohibitions are not subject to the OGSML’s preemption provision.  Instead, they argue that such local bans can be harmonized with the OGSML by limiting the OGSML’s well spacing and setback provisions to those areas where oil and gas development is otherwise permitted.  Further, the towns argue that the trial court properly relied on earlier cases interpreting the supersedure provisions of the Mined Lands Reclamation Law (“MLRL”).  The towns assert that the supersedure provisions in the MLRL and OGSML are substantially similar and, therefore, should be given similar effect.  Thus, the towns assert that the prior cases that upheld local ordinances banning mining practices that were subject to regulation under the MLRL are binding precedent here. 

Oral argument has been scheduled for March 21, 2013 and a final decision is not expected for several months, at the earliest.  However, these cases will be closely watched in other jurisdictions where local bans on hydraulic fracturing have been enacted and where additional litigation is expected.  Given the diversity among state laws addressing both home rule authority and oil and gas development, the legality of local bans on hydraulic fracturing is likely to remain a hotly debated issue for several years to come, particularly as oil and gas development using hydraulic fracturing continues to expand to new shale reserves around the country.

Pennsylvania Considers the Use of Mine Influenced Water in Oil and Natural Gas Operations: The First Step Toward a Potentially Economical and Environmentally Beneficial Practice

Posted on January 23, 2013 by Chester Babst

On January 9, 2013, the Pennsylvania Department of Environmental Protection (PADEP) issued a final White Paper addressing the use of “mine influenced water” (MIW) in oil and natural gas operations.  For purposes of the White Paper, MIW is characterized as “water contained in a mine pool or a surface discharge of water caused by mining activities that pollutes, or may create a threat of pollution to, waters of the Commonwealth” and “may also include surface waters that have been impacted by pollutional mine drainage.” The White Paper outlines (1) the process for reviewing proposals to utilize MIW, (2) options for storing MIW (i.e. impoundments, tanks, etc.) prior to being used for oil and natural gas well development, and (3) possible solutions to long-term liability issues.

PADEP Secretary Mike Krancer deemed the use of MIW as a “win” for Pennsylvania’s environment and economy.  According to PADEP, more than 300 million gallons of water are discharged from Pennsylvania mines each day.  The water discharged, after being introduced to sulfides and other minerals occurring naturally within the mine, can be harmful to the receiving streams.  The natural gas industry uses between 3-5 million gallons of fresh water, typically withdrawn from surface waters and groundwater sources, for each well completion operation.   MIW use provides natural gas companies an alternative source of water for hydraulic fracturing operations with the potential to both lessen the natural gas industry’s dependence on freshwater sources and divert polluted water from watersheds.  

While the use of MIW in natural gas production operations can be an economical and environmentally beneficial practice, certain issues, particularly long-term liability, may require additional regulatory or legislative action before the practice becomes a viable option for the natural gas industry.  For example, under the current interpretation of Pennsylvania’s Clean Streams Law, an operator’s act of pumping water from an abandoned mine pool could create a legal obligation to treat the resulting discharge.  PADEP’s White Paper suggests two options for reducing a MIW user’s long-term liability: 1) obtaining protection from civil liability by qualifying for a “water abatement project” under Pennsylvania’s Environmental Good Samaritan Act; and 2) entering into a Consent Order and Agreement with the state.  Unfortunately, neither of these options guarantees protection from all potential liabilities under federal and state law for conditions associated with abandoned mines.

Notwithstanding certain concepts that require further consideration, PADEP’s White Paper serves as a platform for Pennsylvania and other states to promote the responsible production of coal and natural gas and, at the same time, to address some of the environmental challenges associated with both.  It is hoped PADEP’s White Paper will stimulate discussions regarding the use of MIW for natural gas production in other states with large reserves of coal and natural gas like Ohio, West Virginia, and Wyoming.  With additional input from stakeholders across various states, anticipated environmental and economic benefits of this practice may become a reality.

EVOLVING CONCERNS OVER THE PRODIGIOUS VOLUMES OF WATER USED IN HYDRAULIC FRACTURING

Posted on October 31, 2012 by Michael Hardy

When hydraulic fracturing “exploded” in Pennsylvania and Ohio to unlock the huge reservoirs of natural gas buried thousands of feet below surface in the deep shale formations, the initial environmental concerns focused on the potential for contamination of drinking water supplies from the “fracking” fluids and methane, and from the induced seismicity from the disposal of the waste brines into the underground injection wells.

While those concerns remain, new issues have surfaced.  In Ohio’s Utica shale play, the deep wells typically consume 5,000,000 or more million gallons of water for the hydraulic fracturing and well completion.  Beginning in June, a number of political subdivisions and water districts saw the energy industry’s needs for water as a wonderful business opportunity.  For example, the Muskingum Watershed Conservancy District, whose eighteen counties cover 20 percent of Ohio, reportedly contracted with one exploration and production company to sell millions of gallons of water from one of its reservoirs in eastern Ohio.  The City of Steubenville signed a five year contract to supply as much as 700,000 gallons a day from a reservoir that holds water from the Ohio River.  Newspaper reports at the time mentioned monthly payments to Steubenville on the order of $120,000.  The Buckeye Water District enjoyed a seven-month windfall of $24,000 per month for sales of water to a large drilling firm. Even the Ohio Department of Natural Resources weighed possible plans to grant drilling companies access to state-held reservoirs, lakes and streams.

But the public announcement of these water supply contracts produced significant public backlash.  The reaction to the plans of the Muskingum Watershed Conservancy District, for example, prompted a reversal of the sales, and lead to a moratorium pending completion of an independent water availability study by the U.S. Geological Survey and an updating of the District’s water supply plan with input from the new study.  Low stream flows in the Susquehanna River watershed in Pennsylvania lead the Susquehanna River Basin Commission to suspend 57 approved water withdrawals by gas drillers and other industrial users.

Perhaps in response to the public outcry over the potential impact on water resources, the Ohio General Assembly passed wide-ranging legislation to deal with the growth of shale gas exploration in Ohio.  One of the features of that bill requires drillers to disclose their water source and the likely volume of water for well completion.

The link to that legislation is here: 
http://www.legislature.state.oh.us/bills.cfm?ID=129_SB_315

In another piece of legislation, the Ohio General Assembly adopted a measure to regulate the withdrawal of water from the Lake Erie watershed, effectively precluding the use of Lake Erie watershed waters for hydraulic fracturing in the counties where the drilling is occuring because they are outside the watershed.

The legislation on the use of Lake Erie water can be found at this link:
http://www.legislature.state.oh.us/bills.cfm?ID=129_HB_473

Even with these safeguards, groups like the National Wildlife Federation urge the adoption of even stronger rules on the use of water for hydraulic fracturing.  With the projected exponential growth of shale gas drilling, there will be continuing efforts to regulate the use of water, and the encouragement for water recycle and reuse, for hydraulic fracturing.

Fracking on Election Eve

Posted on October 23, 2012 by Robert Kirsch

The technique known as hydraulic fracturing (“fracking”), especially in the context of developing natural gas, continues to generate controversy, legal fees and emotion.  The question remains as to whether the technique itself presents any unusual risk to the environment or natural resources.  What is clear, however, is the political significance of fracturing and the challenges that our polarized, political dialog presents to achieving a rational result in or from  the fracturing debate.

On the federal side, the Administration has taken steps in order to represent to voters that the President has done what he could to see that hydraulic fracturing occurs in a manner that does not threaten the environment.  Concrete steps are taking place in three Agencies.

-    BLM has issued draft regulations relating to fracturing activities taking place on federal lands.  The proposal drew thousands of comments and no action is likely until well after the election.

-    EPA issued draft guidance proposing to regulate hydraulic fracturing under the UIC program.  This proposal also resulted in thousands of comments, all but precluding any chance that EPA will be in a position to act until well after the election.

-    EPA is continuing its study into the possible connection between hydraulic fracturing and underground sources of drinking water.  A partial report reflecting some retrospective analysis is due before year end, but the meat of the report will not be available until 2014.

-    EPA continues to pursue its general investigation into the way fracturing occurs through its investigation into 9 fracturing companies.  EPA has proposed to publish information reflecting well densities and chemical use relatively soon. 

-    EPA has reviewed and is continuing to review petitions filed by environmental organizations seeking to force the Agency to take steps to regulate fracturing under various regulatory programs, including TSCA.  EPA has denied some of the relief sought, but is collecting information under some and beginning its evaluation of others.

-    At the regional level, EPA has engaged in studies when citizen pressure has suggested a connection between fracturing and contaminated drinking water.  This has proven to be an area where EPA has not maintained consistency or scientific integrity.  The agency’s work at Dimmock, Pavillion and elsewhere has resulted principally in controversy and criticism, and has done little to advance the state of knowledge about fracturing.

-    DOE Secretary Chu has been an Administration spokesman for White House efforts to coordinate the many federal entities that seem to be working on fracturing issues.  His role has been above the weeds and the fact that a Secretary charged with overseeing national energy policy, if there is one,  is the Administration’s front man, appears to be a bone to those suggesting the sole interest of the President is in making energy development more difficult.

-    Within DOA, the Forest Service has sent mixed signals with respect to whether fracturing is viewed as posing risks to other resources.  While several forests have adopted plans anticipating the development of resources within their jurisdiction, including by fracturing, the George Washington National Forest plan remains under review, having proposed to ban fracturing in its initial draft release.

-    The USGS recently has entered the fray in connections with published concerns linking fracturing and increased seismic activity.  Preliminary indications suggest the true focus of such efforts may be long term injection wells, rather than transient fracturing activities, but there is more to follow on this topic.

The federal role in the fracturing debate also has occurred in courts.  Environmental interest groups recently have begun to raise fracturing activities in a number of lawsuits challenging the adequacy of the environmental reviews conducted in connection with federal leases.  Many  such cases are making their way through the courts, and are being watched for the decisions..

In his public statements, the President, of course, has been careful to promote the safe development of natural gas resources, including by fracturing.  He has offered what generally have been viewed as favorable statements in his state of the union address, and more recently in his remarks at the Democratic National Convention.  Of course none of those favorable comments has slowed any of the developments noted above, nor were the President’s remarks necessarily inconsistent with such action.

There is much resistance to the above federal efforts from states, and from industry which has had decades of experience accommodating state regulators in connection with drilling and developing wells.  States too have been active, to varying degrees, with some devising thoughtful programs balancing the needs of developers with the concerns of some members of the public.  The politicization of the issue also has reached the states, however, and nowhere is it more in evidence than in the glacial SGEIS process that has been under way for years, with no regulations on the horizon. There also have been intrastate efforts directed at fracturing by the Susquehanna River and Delaware River Basin Commissions, with the former moving forward with water management programs while the latter has, by default, banned fracturing until a compromise is agreed upon among the member sovereign constituencies.

And – don’t expect the controversy and misunderstandings surrounding fracturing to disappear soon.  In addition to a small scale advocacy film last year, Hollywood is entering the fray with a major film slated for release in the not-too-distant future.  Television already has managed to capitalize on the drama fracturing offers in more than one series.

Things will change after the election.  Stay tuned to find out how.

Defining a Stationary Source: How Much Aggregation is Too Much Aggregation?

Posted on September 13, 2012 by Theodore Garrett

One company may own a variety of “functionally related” facilities that are located on various contiguous and non-contiguous parcels of land, spread out over many square miles.  May all those “functionally related” facilities be considered “adjacent” and thus deemed to be one single major stationary source for Clean Air Act Title V permitting purposes?

A Court of Appeals recently weighed in on this issue.  On August 7, 2012, the Sixth Circuit vacated EPA’s determination that Summit Petroleum Corporation’s natural gas sweetening plant and gas production wells located in a 43-square mile area near the plant were “adjacent” and thus could be aggregated to determine whether they are a single major stationary source for Title V permit purposes. Summit Petroleum Corp. v. EPA, 2012 WL 3181429 (6th Cir., Aug. 7, 2012). The majority held that EPA’s position that “functionally related” facilities can be considered adjacent is contrary to the plain meaning of the term “adjacent,” which implies a physical and geographical relationship rather than a functional relationship.  The court also found EPA’s interpretation to be inconsistent with the regulatory history of Title V and prior EPA guidance.  The case was remanded to EPA for a reassessment with the instruction that Summit’s activities can be aggregated “only if they are located on physically contiguous or adjacent properties.”

Encouraging the Use of Abandoned Coal Mine Drainage for Hydraulic Fracturing in Pennsylvania through a Good Samaritan Statute

Posted on June 21, 2012 by Chester Babst

The development of natural gas shale formations, such as the Marcellus and the Utica in Pennsylvania, Ohio and West Virginia, requires reliable sources of water for hydraulic fracturing that makes gas extraction from tight shale possible.  In Pennsylvania―a state with relatively plentiful ground and surface water sources―there are water sourcing challenges presented by various regulatory frameworks as well as withdrawal limitations in sensitive headwater areas of the state that coincide with current oil and gas activities. 

One alternative to using fresh water for hydraulic fracturing is the use of water supplies affected by acid mine drainage (AMD), which are also plentiful in Pennsylvania.  While the use of AMD by the oil and gas industry offers many potential benefits, operators are reluctant to become entangled in long-term liabilities created by the current legal framework for such pre-existing contamination.

Recognizing the need to encourage the treatment of abandoned AMD, Pennsylvania adopted the Good Samaritan Act, 27 Pa. Cons. Stat. §§ 8101 et seq., in 1999 to provide liability relief for various stakeholders, volunteers and watershed groups to undertake cleanup efforts of pre-existing contamination from AMD.  One recent legislative proposal would amend the Act to allow relief from liability for the use of mine drainage, mine pool water, or treated mine water for the development of a gas well.  This amendment, which has bi-partisan support in the Pennsylvania legislature, provides relief from third party claims as well as enforcement under various liability schemes.

On a parallel track, the Pennsylvania Department of Environmental Protection (PADEP) has been investigating means by which it could encourage the use of AMD by oil and gas operators.  See PADEP’s draft White Paper: Utilization of AMD in Well Development for Natural Gas Extraction, November 2012.  PADEP is engaging in ongoing discussions with stakeholders regarding possible processes and solutions for the treatment, storage, and liability issues associated with such an undertaking. 

At the federal level, the United States Environmental Protection Agency (EPA) has developed a Good Samaritan Initiative to protect volunteers from liability for the remediation of drainage from abandoned hard rock mines.  EPA’s program, however, does not encompass coal mine drainage, which is the primary source of AMD in Pennsylvania.  Short of legislative changes to the Clean Water Act or CERCLA to protect operators from potential liability, an expansion of EPA’s initiative to encourage the use of AMD for hydraulic fracturing in Pennsylvania would provide greater confidence to the oil and gas industry that both state and federal agencies are willing to provide appropriate relief to encourage the use of AMD.

While it seems like a win-win-win for the environment, industry and the Commonwealth, it remains to be seen if workable solutions will be found to encourage the use of AMD while limiting long-term liability related to that use.

CAN A TOWN BAN NATURAL GAS DRILLING USING LOCAL ZONING ORDINANCES?

Posted on April 3, 2012 by Eileen Millett

For anyone who thought New York State was galloping toward exploration, development and regulation of drilling for natural gas, and for anyone who wondered how and when you’d see the brakes applied, two towns did just that during the third week of February. Using local zoning ordinances, the towns of Dryden and Middlefield banned drilling for natural gas within their geographic boundaries.  How they did so, whether they are on solid legal ground for their bans, and what, if anything, the state can or should do to further enhance the development of natural gas are important questions.

Drilling for natural gas, which has gone on for decades in the west, has expanded rapidly in the east in recent years, largely due to a technique known as hydraulic fracturing or hydrofracking.   For property owners, leasing land for gas drilling has created an economic boon, and with it the potential for bringing jobs to a portion of the state that has long been economically depressed, along with the prospect of lessening the nation’s dependence on foreign energy sources.  At the same time, hydrofracking has heightened concerns about contamination of well water, air pollution, and the generation of hazardous waste, as well as other environmental concerns. 

For now at least, it appears that towns in New York State may ban gas drilling within their borders if they choose to do so.  Two statutes in particular – aided by judicial interpretation – support bans like those enacted by the Town of Dryden and the Town of Middlefield.  In regulating oil and gas development, the Oil, Gas and Solution Mining Law (OGSML), set forth in Environmental Conservation Law (“ECL”) Article 23, Title 3, and the Mined Land Reclamation Law (“MLRL”), set forth in ECL  Article 23, Title 27, come into play. 

On February 21, 2012, in Anschutz Exploration Company v. Town of Dryden, Index No. 2011-0902, Tompkins County Supreme Court Justice Phillip Rumsey ruled that the OGSML does not preempt local restrictions that ban gas drilling within the geographic boundaries of the municipality.  Similarly, on February 24, 2012, in Cooperstown Holstein Corp. v. Town of Middlefield, Index No. 0011-0930, Otsego County Acting Supreme Court Justice Donald F. Cerio ruled that the OGSML does not preempt a local municipality from enacting a land use regulation within its geographic jurisdiction, and that a local municipality may permit or prohibit gas drilling in conformity with statutory authority.

The New York State Court of Appeals reached a similar decision in Frew Run Gravel v. Carroll, 71 N.Y.2d 126 (1987) with respect to a comparable provision of the MLRL that empowers the New York State Department of Environmental Conservation (“NYDEC”) to regulate mining and the reclamation of mined lands.   The Frew Run court held that zoning ordinances were not the type of regulatory provision that the legislature foresaw as being preempted by the MLRL and made a distinction between the regulation of how property may be used, i.e., the local zoning ordinance, and the regulation of mining activities.  Just 11 years later, the Court of Appeals again examined the supersession claim clause of the MLRL in In the Matter of Gernatt Asphalt Products, Inc. v. Town of Sardinia, 87 N.Y.2d 668 (1996) and likewise concluded that zoning ordinances were not the type of regulatory provision that the legislature foresaw as being preempted by the MLRL.

The Town of Dryden and the Town of Littlefield decisions relied on these authorities, and thus are on solid legal footing.  As a result, a municipality in New York State is free to ban operations related to oil and gas production within its borders just as towns are free to use zoning ordinances to ban mining activity, even recognizing an incidental effect on the oil, gas drilling or mining industry. 

What does this mean for gas drilling in New York State?  Dryden and Middlefield are but two towns in upstate New York that have taken action. Whether these towns are outliers or the start of a trend remains to be seen.  Many citizens of New York long have said that towns should have the authority to block natural gas drilling within their boundaries.  However, towns may forego bans on gas drilling because of the perceived economic benefits.  

The development of natural gas drilling in New York is in its early stages.  During the early run-up to exploration and development of natural gas, the NYSDEC Commissioner, with one stroke of a pen, banned natural gas drilling in the entire New York City watershed, as well as in the City of Syracuse watershed.  The Commissioner’s action alleviated concern that hydraulic fracturing might harm pristine drinking water for those two major cities.  Such environmental concerns could be the subject of sharp debate in other towns where gas drilling is proposed. 

NYSDEC is still six months to a year or more away from adopting a final environmental impact Statement regarding drilling, and ultimately, it may not even be up to New York.  The Environmental Protection Agency has empowered a team of experts to examine the technology and the science of hydraulic fracturing, and to make recommendations that could include extensive federal regulation.  When New York is ready to look at permit applications, the NYSDEC can evaluate the legal landscape to determine how the courts have handled the fracking cases.  As for the New York legislature, assuming that the bans on natural gas drilling are upheld, its willingness to tackle an issue as controversial as natural gas drilling will depend on the price of natural gas, the economic landscape, and the will of the State Executive branch.  For those of you keeping score, for now, it is towns, two, New York State, zero.

1Using water at high pressure, hydrofracking can break rocks deep underground.  In using this technique, drilling begins vertically and is then done horizontally, opening a larger land area to well placement and allowing for the extraction of more product.
 2The OGSML contains the following statement:  “The provisions of this article shall supersede all local laws or ordinances relating to the regulation of the oil, gas and solution mining industries; but shall not supersede local government jurisdiction over local roads or the rights of local governments under the real property tax law.” ECL 23-0303(2) (emphasis added).
 3In Frew Run, the Court of Appeals examined the supersedure provision of the MLRL, which at that time provided:  “For purposes stated herein, this title shall supersede all other state and local laws relating to the extractive mining industry; provided, however, that nothing in this title shall be construed to prevent any local government from enacting local zoning ordinances or other local laws which impose stricter mined land reclamation standards or requirements than those found herein.” ECL 23-2703(2) (emphasis added).

When Do EPA BACT Requirements "Redesign the Source"? Not When EPA Says They Don't

Posted on January 7, 2010 by Seth Jaffe

Shortly before the holidays, EPA Administrator Jackson issued an Order in response to a challenge to a combined Title V / PSD permit issued by the Kentucky Division for Air Quality to an Integrated Gasification Combined Cycle, or IGCC, plant. The Order upheld the challenge, in part, on the ground that neither the permittee nor KDAQ had adequately justified why the BACT analysis for the facility did not include consideration of full-time use of natural gas notwithstanding that the plant is an IGCC facility. 

The Order may not be shocking in today’s environment – all meanings of that word intended – but the lengths to which the Order goes to avoid its own logical consequences shows just what a departure this decision is from established practice concerning BACT. BACT analyses have traditionally involved the proverbial “top-down” look at technologies that can be used to control emissions from a proposed facility. In other words, EPA takes the proposal as a given, and then asks what the best available control technology is for that facility

In EPA’s own words – from its New Source Review Workshop Manual (long the Bible for BACT analysis):

Historically, EPA has not considered the BACT requirement as a means to redefine the design of the source when considering available control alternatives. For example, applicants proposing to construct a coal-fired electric generator, have not been required by EPA as part of a BACT analysis to consider building a natural gas-fired electric turbine although the turbine may be inherently less polluting per unit product (in this case electricity).

Apt example, don’t you think? (In case you are wondering, EPA’s decision does not discuss or refer to this text from the NSR Manual.)

What was the basis for EPA’s decision here? Largely, it is that the IGCC facility will be designed to burn natural gas as well as syngas and the permittee specifically stated that it planned to combust natural gas during a 6-12 month startup period. On these facts, EPA concluded that the permittee and KDAQ had to do a better job explaining why full-time use of natural gas should be considered “to redefine the design of the source.”

As noted above, EPA went to great lengths to minimize the scope of the decision. It states that the Order:

should in no way be interpreted as EPA expressing a policy preference for construction of natural-gas fired facilities over IGCC facilities.

should not be interpreted to establish or imply an EPA position that PSD permitting authorities should conclude … that BACT for a proposed electricity generating unit is … natural gas.

does not conclude that it is not possible or permissible for the permit applicant … to develop a rationale which shows that firing exclusively with natural gas would “redefine the source.”

EPA does not intend to discourage applicants that propose to construct an IGCC facility from seeking to hedge the risk of investing in … IGCC technology by proposing … utilizing natural gas for some period….

Methinks EPA doth protest too much. If I may say so, this is a freakin’ IGCC facility. Isn’t it obvious that one doesn’t plan or build an IGCC facility if one plans to burn natural gas? Don’t you think that EPA could have taken administrative notice of what IGCC technology is?

All of EPA’s protestations about the Order’s limits may be designed to mollify IGCC supporters, but what does its rationale mean for all of the existing facilities – coal and oil – that are already capable of firing on natural gas? Next time they are subject to NSR/PSD review, must they evaluate the possibility of switching completely to natural gas? As I’ve said here before, yikes!

When Do EPA BACT Requirements "Redesign the Source"? Not When EPA Says They Don't

Posted on January 7, 2010 by Seth Jaffe

Shortly before the holidays, EPA Administrator Jackson issued an Order in response to a challenge to a combined Title V / PSD permit issued by the Kentucky Division for Air Quality to an Integrated Gasification Combined Cycle, or IGCC, plant. The Order upheld the challenge, in part, on the ground that neither the permittee nor KDAQ had adequately justified why the BACT analysis for the facility did not include consideration of full-time use of natural gas notwithstanding that the plant is an IGCC facility. 

The Order may not be shocking in today’s environment – all meanings of that word intended – but the lengths to which the Order goes to avoid its own logical consequences shows just what a departure this decision is from established practice concerning BACT. BACT analyses have traditionally involved the proverbial “top-down” look at technologies that can be used to control emissions from a proposed facility. In other words, EPA takes the proposal as a given, and then asks what the best available control technology is for that facility

In EPA’s own words – from its New Source Review Workshop Manual (long the Bible for BACT analysis):

Historically, EPA has not considered the BACT requirement as a means to redefine the design of the source when considering available control alternatives. For example, applicants proposing to construct a coal-fired electric generator, have not been required by EPA as part of a BACT analysis to consider building a natural gas-fired electric turbine although the turbine may be inherently less polluting per unit product (in this case electricity).

Apt example, don’t you think? (In case you are wondering, EPA’s decision does not discuss or refer to this text from the NSR Manual.)

What was the basis for EPA’s decision here? Largely, it is that the IGCC facility will be designed to burn natural gas as well as syngas and the permittee specifically stated that it planned to combust natural gas during a 6-12 month startup period. On these facts, EPA concluded that the permittee and KDAQ had to do a better job explaining why full-time use of natural gas should be considered “to redefine the design of the source.”

As noted above, EPA went to great lengths to minimize the scope of the decision. It states that the Order:

should in no way be interpreted as EPA expressing a policy preference for construction of natural-gas fired facilities over IGCC facilities.

should not be interpreted to establish or imply an EPA position that PSD permitting authorities should conclude … that BACT for a proposed electricity generating unit is … natural gas.

does not conclude that it is not possible or permissible for the permit applicant … to develop a rationale which shows that firing exclusively with natural gas would “redefine the source.”

EPA does not intend to discourage applicants that propose to construct an IGCC facility from seeking to hedge the risk of investing in … IGCC technology by proposing … utilizing natural gas for some period….

Methinks EPA doth protest too much. If I may say so, this is a freakin’ IGCC facility. Isn’t it obvious that one doesn’t plan or build an IGCC facility if one plans to burn natural gas? Don’t you think that EPA could have taken administrative notice of what IGCC technology is?

All of EPA’s protestations about the Order’s limits may be designed to mollify IGCC supporters, but what does its rationale mean for all of the existing facilities – coal and oil – that are already capable of firing on natural gas? Next time they are subject to NSR/PSD review, must they evaluate the possibility of switching completely to natural gas? As I’ve said here before, yikes!