Posted on October 23, 2012
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- EPA issued draft guidance proposing to regulate hydraulic fracturing under the UIC program.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.
Posted on October 4, 2012
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.
Posted on September 18, 2012
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).
Posted on September 13, 2012
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.”
Posted on August 17, 2012
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.
Posted on June 21, 2012
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.
Posted on May 23, 2012
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.
Posted on April 3, 2012
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).
Posted on February 6, 2012
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.