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.

Energy Resources Exports: Good for America? Good for the Environment?

Posted on May 10, 2013 by Sheila Slocum Hollis

Proposals to export liquefied natural gas (“LNG”) produced in large part from shale gas recovered by hydraulic fracturing techniques or “fracing” continue the public debate about the desirability of exports of other energy resources.  This political, regulatory, environmental and trade debate engages powerful politicians, lobbyists, environmental groups, trade associations, developers, producers, state regulatory authorities, consultants, academics, and landowners, and a broad spectrum of the press and public. 

On its face, the notion of substantial exports of LNG to both countries with which the U.S. has free trade agreements (FTA) in place and those it does not, seems highly attractive.  Such exports would improve the balance of trade deficits, create new jobs associated with the production; and produce tax revenue.  And, from the broad environmental perspective, LNG exports would lower greenhouse gas emissions (GHG) in countries with heavy reliance now and in the future on coal or oil for electric generation, or in countries with need for replacement of nuclear facilities.

Query then, what are the factors that engender the impassioned debate on energy resource export policy?  Key are:  (1) fears of massive development of “frac” gas, freighted with concern over impacts on water, air, and use.  Analogous to the Keystone XL battle, another concern is development of the unconventional gas for the benefit of foreign interests, particularly those without an FTA in place with the U.S. (export to those countries with FTA agreements with the U.S. is deemed by law to be in the public interest).  (2) A second issue in contention on LNG is the impact on domestic energy prices if significant LNG exports limit availability of natural gas for domestic industrial and other uses.  (This issue harkens back to the energy crises of the 1970s when natural gas availability was tight and energy prices sky high.) 

So, although not explicitly an environmental-based objection, such opponents of LNG exports  find friendly bedfellows with the environmental objectors and the commercial interests concerned about their ability to rely upon and benefit from increased gas supply.  Industrial interests argue that stopping exports to non-FTA countries, particularly the insatiable Asian markets, will result in an industrial renaissance with jobs and development growing significantly.  And, some opponents of LNG exports to non-FTA countries ironically, (to this blogger at least) express little regard for overall environmental benefit to potential importing countries and thus the globe.  Rather, the impact on the United States from development of unconventionally sourced gas supply has been their focus point.  Yet, LNG is only part of the energy export debate.

Further complicating this analysis is the parallel potential increase in the export of U.S. coal to energy hungry nations, particularly in Asia.  As noted above, there is a broader questioning on the entire topic of U.S. energy resources exports: LNG, oil or refined products and coal.  In addition to the Keystone XL pipeline standoff, many environmentally oriented players (e.g., the Sierra Club) and political leaders have expressed reservations about the export of U.S. coal for two primary reasons – the impact on the U.S. of new infrastructure for storage, transportation and increased mining activities, and the increase in GHG emissions worldwide as a result of heavier coal-fired electric generation.  And in the past months, several proposed coal export projects have been scrapped. This energy export issue makes for a complicated stew of federal, local and regional politics.  What makes the entire public war of words (and the behind the scenes maneuvering) so fascinating is the question of who or what decides where and with what restrictions U.S. energy resources are to be marketed to the world – the federal agencies, the state and local governmental entities, or the market?  The next few months may provide guidance on LNG and perhaps the Keystone XL pipeline, however, the national and international implications of these decisions are so important that it is unlikely that peace will settle on these matters for decades.

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.

Reuse of Contaminated Groundwater- Is It Time To Be More Innovative?

Posted on April 10, 2013 by Charles Efflandt

According to the recent U.S. Drought Monitor, approximately 65% of the contiguous United States is currently experiencing “abnormally dry” to “exceptional drought” conditions. In my part of the country, a recent projection indicates that a reservoir supplying a significant portion of our municipal water supply could dry up within 3-4 years if severe drought conditions persist. Although an “Aquifer Storage and Recovery” program was previously developed to enhance the available supply of groundwater, it is only designed to replenish the drinking water aquifer from excess river flow during flood conditions—a rare occurrence during a severe drought.

I am not capable of allocating percentages of fault for this persistent drought between anthropic climate change and extreme climatic occurrences that are “normal” in the context of geologic time. However, I am persuaded by the argument that “climate change,” by whatever definition you choose to give it, is a problem not only of causation and prevention, but also of adaptation. A previous posting on the need to prioritize adaptation to climate change states the argument well. Is it time we give more thought to groundwater replenishment as an adaptation tool?

My practice includes representing clients at various hazardous substance release sites, under both state and federal law. The default remedy for contaminated groundwater at many of these sites remains extraction and treatment (commonly using air stripping technology) to both contain and clean up the extracted groundwater to “unrestricted use” quality. At most of these sites, however, treated groundwater is discharged to a ditch, creek or similar conveyance where the value of the groundwater as a critical natural resource is largely lost.

An environmental consultant at one such site recently calculated that, over the period of two years, the pump and treat system had removed and discharged to a nearby ditch approximately 110 million gallons of treated groundwater. During a period of severe drought, the system was depleting a drinking water aquifer by over two feet annually. In addition, it was estimated that the quantity of groundwater being treated, and largely wasted, was equivalent to the water used by 1,850 residents (27% of the population) of the city in which the site is located.

Beneficial reuse of “contaminated” water resources is obviously not a new concept, particularly the reuse of nonpotable water. Examples include the reuse of treated nonpotable water for industrial, municipal and agricultural purposes. Potable water reuse is less common for reasons related to water quality requirements, technical issues, cost and community and regulatory acceptance.

Notwithstanding the obstacles and additional costs, it may now be time for environmental professionals, regulators and attorneys to more systematically and creatively consider potable reuse options at contaminated groundwater sites. This would include an evaluation of discharging treated groundwater through infiltration basins, infiltration galleries and injection wells to replenish the drinking water aquifer from which it was extracted. Consideration should be given to partnering site regulators and responsible parties with nearby municipalities to revitalize drinking water aquifers or supplement other potable water resources. Another issue worthy of discussion is community acceptance, which may be more likely when treated contaminated groundwater is beneficially reused indirectly through aquifer replenishment, rather directly through discharge into water supply pipes.

I submit that all too often we accept without much thought the default option of permitted surface discharge of groundwater that has been treated to “non-detect”. Potable reuse through groundwater recharge and restoration involves significant cost and technical issues. But in our effort to add weapons to the climate change adaptation arsenal, all interested parties should more carefully consider such options notwithstanding the challenges.

Will EPA Expand TRI to the Oil and Gas Extraction Sector?

Posted on March 1, 2013 by Molly Cagle

The Environmental Protection Agency (EPA) is planning a rulemaking to expand its Toxic Release Inventory (TRI) program in March 2013. Will the oil and gas extraction sector be included in the program’s expansion?

As part of the Emergency Planning and Community Right-to-Know Act (EPCRA), the TRI program gathers and makes public information about chemical and waste management activities at a wide variety of facilities. EPA touts TRI reporting as one mechanism to reduce the release of chemicals into the environment. It claims that the information gathered helps companies keep up with competitors’ efforts to reduce and recycle waste, and that the public dissemination of information can lead to citizen and EPA enforcement.

EPA considered including the oil and gas extraction sector in TRI in 1997, but decided against it due to technical issues in determining whether individual wells spread out over large geographic areas would be considered a “facility” under EPCRA. A petition filed by environmental groups claims these technical issues are resolved and points to the basin-level definition of facility in EPA’s greenhouse gas (GHG) reporting rule as an example of how oil and gas production operations can be aggregated. Meanwhile, the GHG reporting rule is still under administrative reconsideration and the definition of facility under that rule is a key point of contention between EPA and industry.

As recently as last week, EPA’s Inspector General “recommend[ed] that EPA develop and implement a comprehensive strategy for improving air emissions data for the oil and gas production sector.” If oil and gas production is included in TRI, how will it affect the sector? Will it be a way to get at chemical ingredients used in hydraulic fracturing that are otherwise protected from disclosure as trade secrets? Will the aggregation of data for TRI purposes spill over into air and waste permitting decisions? At a minimum, TRI would require industry to gather more information on chemicals, wastes and emissions and make it publicly available. Thus, industry should prepare for the corresponding public attention and regulation that may accompany TRI expansion.

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.

Oklahoma v. Texas Water Wars Continued

Posted on January 9, 2013 by Linda Martin

In my August 24, 2010 submission, I discussed the water wars between Oklahoma and Texas, summarizing the lower court holding in Tarrant Regional Water District v. Herman, et al.  The gist of the dispute is that a Texas water district wants to buy Oklahoma water, but Oklahoma isn’t selling, and has passed laws that effectively preclude the sale. The Tarrant Regional Water District (“TRWD”) cried foul, but the District Court did not agree with TRWD that Oklahoma’s refusal to sell water across state lines was a violation of the Commerce Clause.  Judgment was entered on July 16, 2010, and the case appealed to the Tenth Circuit shortly thereafter.  The Tenth Circuit affirmed the District Court.  656 F.3d 1222 (10th Cir. 2011).

The Appellate Court decided that Oklahoma statutes which precluded water being sold to users in Texas did not violate the Commerce Clause because the Red River Compact preempted it. Recall that the Red River Compact (signed by Texas, Oklahoma, Louisiana and Arkansas in 1978 and approved by Congress) divided the water from the Red River and its tributaries among the states involved.  The Compact has general language that gives the signatory states authority over the water allocated to them within their borders.  The Tenth Circuit held Texas to its bargain on the Compact and agreed with Oklahoma that the refusal to sell Oklahoma water to Texas users does not violate the Commerce Clause. 

Now, the United States Supreme Court will weigh in on the subject, as it granted certiorari on January 4, 2013.  Stay tuned.

MONTANA SUPREME COURT REJECTS CONSTITUTIONAL CHALLENGE TO LARGE STATE COAL LEASE

Posted on January 2, 2013 by Stephen R. Brown

Montana’s state constitution contains what is arguably the most stringent environmental protection clause of any state.  Article II, Section 3 of the Montana Constitution guarantees all persons “the right to a clean and healthful environment.”  This provision is paired with Article IX, Section 1, which says the “state and each person shall maintain and improve a clean and healthful environment in Montana for present and future generations.”  Although these clauses have been in the state constitution since 1972, they rarely have been applied by the Montana Supreme Court to invalidate legislation, overturn state action or to provide a private remedy.  In October, 2012, the Montana Supreme Court rejected the latest attempt to apply these provisions.

Montana is a coal-rich state.  The State of Montana owns significant quantities of this coal.  The State Land Board controls the leasing of state-owned coal.  In 2010, the land board approved a massive lease to Arch Coal.  Montana received an $85 million bonus payment for this lease. 

In addition to the environmental-protection provisions of the state constitution, Montana has a state environmental policy act, structured similarly to the National Environmental Policy Act (NEPA).  The Montana Environmental Policy Act (MEPA) contains a number of exemptions from environmental review that would otherwise be required.  One of these provisions exempts the land board from the obligation to undertake environmental review at the leasing stage, so long as a lease contains a provision stating that actual mining is subject to further environmental permitting.  The land board relied on this exemption to issue leases to Arch Coal without first undertaking MEPA review.

Several environmental groups challenged the land board’s leasing action, arguing that the application of the MEPA exemption violated the Montana Constitution on an as applied basis.  They argued that the leasing decision opened the door to the mining and burning of large quantities of coal without environmental review.  A state district court found that mining and burning coal could exacerbate global climate change, which in turn could adversely affect water, air and agriculture in Montana.  Based on this finding, the district court declined to dismiss the case, but it also refused to grant summary judgment to the NGO plaintiffs on the constitutional claim.  The district court concluded that the State retained sufficient environmental protection mechanisms at the mine permitting stage to meet its constitutional obligations.

The NGO plaintiffs appealed the case to the Montana Supreme Court.  In Northern Plains Resource Council v. Montana Board of Land Commissioners,  the Supreme Court upheld the district court and rejected the constitutional challenge.  Although the Supreme Court confirmed the fundamental right to a clean and healthful environment and acknowledged potential global climate change implications of further coal development, the Court held that it was not required to apply a strict scrutiny analysis to the statutory exemption from MEPA.  The Court concluded that “the act of leasing” did not interfere with the exercise of a fundamental right requiring “demonstration of a compelling State interest.”  Instead, the Court applied a “rational basis” test to conclude that the potential for additional environmental review at the permitting stage was sufficient.  On that basis, the Supreme Court held that the exemption from MEPA review did not violate the Montana Constitution.

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.

FOUR CENTURIES OF FUEL FORAGING IN PENNSYLVANIA

Posted on October 4, 2012 by Joseph Manko

For four centuries Pennsylvania has been at the epicenter of America’s search for growth-sustaining fuel, but not without paying an environmental price.  In the 18th century, Pennsylvania’s (literally “Penn’s Woods”) abundant forests supplied wood to fuel America’s expansive westward development.  In denuding its forests, however, Pennsylvania experienced enhanced erosion and sedimentation and other environmental detriments.

In the 19th century, 1859 specifically, oil was discovered in Oil City. Pennsylvania (and America) turned its attention from wood to oil.  Although primary oil production shifted eventually to the Gulf states, nevertheless, Pennsylvania, as an oil producer, enjoyed the benefits and suffered the environmental detriments created by laissez faire, unregulated drilling and transportation of petroleum.

By the 20th century, coal was king in Pennsylvania.  The residual impacts from coal mining, especially strip mining, remain to this day in the form of scarred landscapes, acid mine drainage and air emissions, albeit the impacts are now monitored amid a focus on environmental enforcement efforts.

In the 21st century coal remains a force in energy production in Pennsylvania, but again nature has put the state in the national discussion over domestic fuel protection as it has become a national leader in developing the natural gas entrapped in the Marcellus Shale underlying large portions of southwest, north central and northeastern Pennsylvania.  Natural gas extracted from the Marcellus Shale has become Pennsylvania’s (and increasingly, America’s) fuel of choice for the 21st century.  Will the environmental legacy be different this time?

In February, 2012, Pennsylvania enacted The Oil and Gas Act Amendments of 2012, known as Act 13, in an attempt to adapt Pennsylvania’s longstanding Oil and Gas Act to issues unique to the technique used to fracture layers of shale and release natural gas, commonly known as “fracking.”  The Amendments raise a number of new legal issues:

1.    By offering shale gas fees to host municipalities who are willing to accept them, the Act preempts accepting municipalities from enacting zoning ordinances to regulate fracking.  A recent Commonwealth Court decision held such preemption unconstitutional.  An appeal by the State is pending before the Pennsylvania Supreme Court.  Briefs have been filed and oral argument is scheduled for October 17 in Pittsburgh.

2.    Despite mandatory setback distances from wells, required by the Amendments, instances of citizens claiming that or suing because their water supply was contaminated as a result of the recovery of shale gas, either through leakage, spillage, or other events will need to be resolved.

3.    Pennsylvania’s Department of Environmental Protection has differed with EPA and the Delaware River Basin Commission regarding how much authority these agencies should have to regulate operations associated with Marcellus Shale gas production. 

4.    In a victory for the shale gas industry, the District Court for the Western District of Pennsylvania invalidated a 2009 U.S. Forest Services Agreement with environmental groups that would have required the preparation of a NEPA environmental assessment prior to drilling in U.S. forests. 

5.    Some property owners who have leased their subsurface drilling rights for Marcellus Shale gas recovery have found themselves unable to refinance their mortgages.  Although the property owners argue that their land has become more valuable because of the potential recovery of fees from the Marcellus Shale gas recovery, some banks have refused to refinance claiming that the fracking lowers the value of the property because of the potential of pollution and/or the location of drilling rigs and other heavy equipment on the property, thereby making foreclosure more difficult. 

6.    Pennsylvania’s Public Utility Commission (PUC) is the collector under Act 13 of the “impact fees” from natural gas well operators – which have to date exceeded $200 million and will be distributed in large part to “accepting” host municipalities.  In accordance with Act 13, the PUC has also begun issuing advisory opinions on the legality of local zoning ordinances.  The Pennsylvania Supreme Court’s decision on the Commonwealth Court’s invalidation of the preemption issue could affect how the PUC approaches these matters going forward. 

While the sources of fuel and the techniques for obtaining it have changed much over the centuries in Pennsylvania, fuel production from forests, coal mines, oil rigs and fracking wells share a common legacy, initially attracting often environmentally insensitive wild catters, raising issues of local control versus the need for statewide uniformity, and creating the risk of potentially permanent environmental impacts if state-of-the-art environmental protections are not implemented.  In sum, notwithstanding changes in preferred fuel sources over the past four centuries, the issues, impacts and challenges remain similar; the need to balance energy production and environmental protection, or, as they say – “the more things change, the more they remain the same”.  Rather than be resigned to repeating history, however, the Commonwealth should rise to the challenge and use its acquired knowledge to inform our discussion as to how to utilize its resources, including natural gas, to provide energy solutions going forward.

Themes in Recent Changes to Offshore Oil and Gas Regulations

Posted on September 18, 2012 by Pamela Giblin

By Pam Giblin and Amber MacIver, Baker Botts L.L.P.

The regulatory landscape for the offshore oil and gas industry has been subject to rapid change in the two years following the Macondo Incident in the Gulf of Mexico.1   Two primary themes have emerged in the new and revised regulations:  (1) increased agency oversight, and (2) requirements for third party certification.  The regulations are relatively recent, but operators can expect to feel the impacts over the next year.

Increase Agency Involvement
The Mineral Management Service (MMS) oversaw many of the revenue collection, leasing, permitting and enforcement functions for the offshore industry prior to the Macondo Incident.  Following that event, the MMS was restructured into separate agencies in part to enable increased agency involvement and oversight.2  The three new agencies are:

(i)    the Bureau of Ocean Energy Management (BOEM), which has the leasing functions;
(ii)    the Bureau of Safety and Environmental Enforcement (BSEE), which has responsibilities for permitting and enforcement; and
(iii)    the Office of Natural Resources Revenue (ONRR), which has revenue collection.

The new agencies, and in particular BSEE and ONRR, have demonstrated a trend of increased agency involvement.  With respect to the ONRR, in just the past year, it has issued penalties that represent an increase in excess of three times the previous yearly average under MMS.3   This increased enforcement is a trend we expect to continue.
 
BSEE’s increased oversight is seen in the numerous regulations it has issued in the past two years.  Many of those new rules require additional agency intervention in offshore oil and gas operations.  For example, Section 250.456(j) of the Drilling Safety Rule requires that before an operator may switch from heavy to light drilling fluid, the operator must receive approval from BSEE.  The Workplace Safety on Safety and Environmental Management Systems (SEMS) rule requires operators to submit their self-audit plans to BSEE for review, BSEE may make changes to the plan, and it has the option to participate in the audit.4   In addition to formal changes in the regulations, both the former director of BSEE and the current director have indicated a potential shift in enforcement policy that would add contractors to the scope of BSEE’s enforcement actions, contrary to former MMS policy, further expanding the agency’s oversight of the industry.  We have not seen an example of this yet, but would expect that contractors could see enforcement in the near future.

These changes, among others, illustrate a trend of increased agency oversight of the offshore oil and gas industry.  It is a trend we expect to see continue at least during the next year.

Third Party Certification
BSEE has issued new regulations and amended others, adding dozens of new rules and requirements for offshore oil and gas operations.  The trend that runs through many of these changes is a requirement for certification by a third party.  For example, the Drilling Safety Rule requires that operators have a professional engineer independently certify that the casing and cementing program is appropriate for the purpose for which it is intended under expected wellbore pressure.5    Although the current SEMS rule allows for self-audits to be conducted either by designated qualified personnel (DQP) or third party auditors, the proposed SEMS II rule would eliminate the option to use DQP, requiring all self-audits to be performed by independent third party auditors.6

The likely outcome of the changes that result from these two overarching themes, increased agency involvement and third party certification, is additional enforcement and red tape.  Operators may face difficulty in scheduling operations when they have to rely on outside parties to certify their work or agency approval to make changes.  Enforcement actions are likely to increase as agency oversight increases.  Operations that have not been subject to scrutiny in the past are likely to face additional hurdles and possibly enforcement under the new regulations.  Offshore oil and gas operators need to closely follow the evolving regulatory scheme to stay in compliance with the rules and avoid costly enforcement actions.

      1The “Macondo Incident” refers to the April 20, 2010 explosion from the Deepwater Horizon drilling rig, in the Macondo prospect, Mississippi Canyon Block 252. 
      2See DOI Secretarial Order No. 3299 (May 19, 2010) (issued in May 2010 and gave the Assistant Secretary- Land and Minerals Management and the Assistant Secretary -- Policy, Management and Budget 30 days to develop a schedule to implement the Order).
     3See, e.g. ONRR Press Release, April 30, 2012, http://www.onrr.gov/about/pdfdocs/20120430.pdf, last visited July 9, 2012 ($1.9 million civil penalty against Cabot alleging inaccurate records); ONRR Press Release, March 29, 2012, http://www.onrr.gov/about/pdfdocs/20120329.pdf, last visited July 9, 2012 ($1.7 million civil penalty against Merrion for late royalty payments); ONRR Press Release, July 11, 2012, http://www.onrr.gov/about/pdfdocs/20120711.pdf, last visited August 30, 2012 ($1.2 million civil penalty against QEP resources for  maintenance of inaccurate reports).
     430 C.F.R. § 250.1920(b).
     530 C.F.R. §§ 250.418(h), 250.420(a)(6).
     676 Fed. Reg. 56683 (Sept. 14, 2011).

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.”

EPA Issues Draft Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels

Posted on August 17, 2012 by Linda Bullen

In an effort to inject (no pun intended) regulatory certainty into the permitting of underground injection wells used in oil and gas hydraulic fracturing (HF) operations, on May 10, EPA issued draft guidance for HF operators utilizing diesel fuels in their injection process.  EPA did not initially consider HF to be covered by its Safe Drinking Water Act (SDWA) Underground Injection Control (UIC) program.  EPA's view changed as the result of a number of court decisions which concluded that HF activities are subject to that program.  In 2005, the Energy Policy Act revised the SDWA definition of underground injection was modified to exclude from UIC regulation the underground injection of fluids or propping agents other than diesel fluids used in HF operations related to oil, gas and geothermal production activities.  This exclusion has, understandably, proven to be controversial, at least in part because there is no one definition of what constitutes "diesel fuel".  The EPA draft guidance attempts to bring clarity to the definition of what constitutes a diesel fuel, by examining whether the injectate is included in one of six identified chemical abstracts and whether the fluid is commonly referred to as "diesel fuel".  The draft guidance also  touches upon other issues associated with HF operations including which activities are covered by  the UIC program and the management of wells over their operational lifetime.

The comment period for the draft guidance closed on July 9, and the guidance, when finalized, will apply only to those jurisdictions in which the EPA directly implements the UIC program (fourteen states and territories and most tribal lands).  The guidance, along with proposed requirements for HF on public lands published almost contemporaneously (77 Fed. Reg. 27691; May 11, 2012), signal an intention of the federal government to bring certainty to a very uncertain and controversial issue, and to impact a rapidly expanding industry which has previously been subject primarily to state and local regulation.

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.

SHALE GAS FRACKING: PREVENTING THE NEXT DEEPWATER HORIZON

Posted on May 23, 2012 by David Ullrich

There has been a dramatic increase in shale gas and oil extraction over the past several years that is presenting an interesting mix of technical, legal, policy, and environmental issues.  These appear to be playing out differently in each state, and with additional twists in Canada relative to the oil sands in Alberta and shale gas in Quebec.  Although the flow of gas and oil has increased dramatically during this time, there appear to be continuing questions about the impacts on groundwater, the relationship to earthquakes, the nature of the chemicals used in the water injected, how the residual water should be treated, and many more.  The matter of the Keystone pipeline has generated significant controversy between the United States and Canada, and the role of non-government organizations in this process has drawn the attention and concern of the Government of Canada.  If this practice is not managed and regulated effectively, we are likely asking for serious environmental consequences like those we have experienced in the past when we have not thought through carefully what could happen as a result of our actions.

With the many issues to address, one in particular is the focus of this discussion, and that is the appropriate roles of federal, state, local, provincial, tribal, and first nation governments in the process of approving the siting, construction, and operation of the wells, in addition to the handling of the residues and the product.  It appears a bulk of the responsibility is in the hands of state and provincial governments, but that may not be the best allocation of jurisdiction.  Local governments have the primary responsibility of providing safe drinking water to their populations, and may be adversely affected by the fracking operations.  Also, local wastewater management facilities are being looked to for treatment of the residual water from the process, which includes unknown chemicals and contaminants from the product.  In some instances, local governments are being excluded from the approval process.  It does not appear that tribal and first nation governments have been consulted to any great extent.  On the federal level, U.S. EPA is not regulating the activity, although it is doing an extensive study of the potential impacts of fracking and related activities.  Environment Canada has been engaged in the oil sands matter primarily through the evaluation of the environmental monitoring program undertaken by Alberta and the companies involved.

The very successful model used in the U.S. for air, water, toxics, and hazardous waste since 1970 that has a strong Federal presence that establishes a legal framework and minimum protective standards across the county, with the option for states to receive delegation and implement programs with more stringent requirements if they wish, should be used for shale gas and oil extraction.  In addition, there need to be specific opportunities for local and tribal governments to participate in the process in a way that protects their interests.  Also, there must be ample opportunity for public participation.  This is the best way to reduce the likelihood of another very costly disaster down the road.

Resource extraction has always presented significant challenges to finding the right economic, social, and environmental balance in managing an activity for the broader good of the country.  In the context of the continuing concern about serving the energy needs of the United States, Canada, and the rest of the world, the question is what makes sense and is good public policy?  Perhaps we are still early enough in the history of this issue to make  changes to help prevent  serious and expensive  problems in the future.

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).

LNG Import or Export—Should the Public Care Which?

Posted on February 6, 2012 by Richard Glick

Just a few years ago, the price of natural gas was high enough to encourage development of liquefied natural gas (LNG) import terminals to receive LNG from foreign gas producers and then “re-gassify” such gas before sending it to existing interstate pipelines.  Three such facilities were proposed in Oregon, after a failed attempt to site an LNG terminal in California.  The presumption had been that due to the high capital cost of the terminal and related pipeline, and because of market constraints, there would be but one terminal on the West Coast. 

That dynamic has shifted with discovery of abundant domestic shale gas deposits and attendant lowering of gas prices, and LNG terminal developers are thinking “export,” instead of import.  Should this change in the LNG business model matter to anyone?

Of the proposed Oregon projects, two remain: at the Port of Coos Bay and on the Skipanon Peninsula in Youngs Bay, at the mouth of the Columbia.  The projects have generated controversy, with opponents asserting public safety concerns (i.e. uncontrolled “blast zones”), harm to aquatic habitat, creation of a terrorist target, usurpation of land owner rights along the pipeline route, and all apparently with no benefit to Oregon because the gas may only be shipped to our evil sister to the south, California.  Of course, these are all issues that the FERC and state permitting reviews are designed to uncover, assess and prescribe mitigation for and those processes are incomplete.
 
Natural gas prices have come down to the point that an LNG import facility may no longer make sense.  On the other hand, demand for natural gas in Asia is high, particularly in Japan following the Fukushima nuclear disaster, which in turn raises prices.  Thus, the two remaining Oregon LNG projects are actively considering conversion to export facilities, and there is enough global demand—and plenty of surplus Canadian and U.S. natural gas—that more than one would be needed to make much of a dent in that surplus.  This result has enraged environmental activists, as though it is somehow unfair to change the economic model on which a proposed project is based.

There is nothing about a LNG export facility that is so different—either in form or impact on land or resources—such that it should affect how the public views LNG.  The two concepts have approximately the same footprints, and to the untrained observer, would look the same.  In the case of the Skipanon Peninsula project, tanks are the most prominent structures; import and export tanks are identical, except that an export facility would require only two, whereas an import terminal requires three.  The dock/pier arrangements for import or export facilities are identical.  The two concepts have very similar (and very limited) environmental impacts, all of which will be reviewed in detail in the various state and FERC regulatory processes.  In addition, an LNG export facility would provide four times as many construction jobs (about 10,000 man-years) and almost twice the amount of long-term employment originally anticipated from the project.  The project represents a $5 billion investment in a region with no apparent industrial development alternatives on the horizon, and with property tax rates right around 1%, such a project would infuse approximately $50 million in local annual tax assessments.

There are some who suggest allowing exports of LNG would raise domestic natural gas prices and thereby place the U.S. economy at a disadvantage.  But of course the U. S. participates in a global economy and gas prices are driven by global market conditions.  A commodity will find a market, seeking the highest prices available, wherever it originates.  The U. S. exports approximately 50 million metric tons of grain every year and that probably raises U.S. domestic food prices a little, but would anybody seriously argue that we should stop grain exports?

Markets will determine whether a shift to exporting LNG makes economic sense.  Environmental effects and other public interest issues related to an LNG export terminal and related pipeline projects should be judged on their merits by the federal and state agencies charged to do so.