Category: Utilities

Federal Energy Regulatory Commission (FERC) Initial Decision Lowers Return on Equity (ROEs) for New England Transmission Owners

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On August 6, 2013, FERC Administrative Law Judge Michael J. Cianci issued an initial decision on the complaint filed against the New England Transmission Owners (NETOs) seeking to reduce their currently effective 11.14% base return on equity (ROE) (FERC Docket Nos. EL11-66-000, et al.). Applying FERC’s traditional discounted cash flow (DCF) analysis to financial data largely for the period May 2012 – October 2012, Judge Cianci would require the NETOs to use a 10.6% base ROE to make refunds for transmission service provided between October 1, 2011 and December 31, 2012. Applying the same DCF analysis to financial data largely for the period October 2012 – March 2013, Judge Cianci would allow the NETOs a 9.7% ROE that would apply prospectively once FERC ultimately issues its order in the case (assuming FERC sustains Judge Cianci’s rulings; see PP* 544, 559-560). These rulings undoubtedly are disappointing both to the NETOs, who opposed any reduction in the 11.14% base ROE, and the complainants, who advocated substantially lower ROEs (8.3% to 8.9%) than Judge Cianci would allow.

On the positive side for the NETOs, Judge Cianci found that reducing utility ROEs below 10% for a prolonged period could be harmful to the industry (P 576). He also resolved virtually all conventional DCF methodological issues in the NETOs’ favor and his 10.6% and 9.7% ROEs were the ROEs developed in the NETOs’ conventional DCF analysis (PP 551, 552, 557). This would suggest that the 10.6% and 9.7% ROEs represent the maximum possible ROEs given the financial market data and the constraints of FERC precedent.

Judge Cianci expressly declined to rule on an issue that was hotly contested by both the NETOs and the complainants. The issue is whether post-2007 financial market conditions cause the DCF method to understate ROE costs and require modification of FERC’s conventional DCF analysis by use of alternative ROE methodologies (e.g., CAPM) to determine the NETOs’ actual common equity costs. A related issue, also hotly disputed by the parties, is whether the billions of dollars of required new transmission investment should also impact the ROE calculus.

The NETOs and the complainants are free to dispute all aspects of Judge Cianci’s decision through the FERC appeal process. The initial appellate briefs (known as briefs on exceptions) are due September 20, 2013, and briefs opposing exceptions are due October 24, 2013. The ultimate FERC ruling in this case will clarify and/or modify FERC’s ROE policy and is likely to be of extreme importance not only to the NETOs and their customers but to all utilities who charge or pay FERC jurisdictional transmission rates.

Two elements of Judge Cianci’s decision merit additional comment.

First, his decision concerned the NETOs collectively with the result that the ROE benchmark was the so-called “mid-point” of the zone of reasonableness (the mid-point is the average of the highest and lowest returns within the zone). The benchmark for an individual utility would be the “median” (the median is the point within the zone of reasonableness where half the returns are higher and half the returns are lower). Under current conditions, the median would be somewhat lower than the midpoint. Thus, other things being equal (they never are), a hypothetical Judge Cianci decision in an individual utility rate case would result in somewhat lower ROEs.

Second, due to the statutory fifteen-month limitation on retroactive refunds, the NETOs will not be required to make Docket No. EL11-66-000 refunds for the period between January 1, 2013 and the issuance date of the final FERC order. However, FERC has not yet acted on a second ROE complaint currently pending against the NETOs (Docket No. EL13-33-000). Although FERC would need to make new ROE findings in the new docket, this second complaint could close the Docket No. EL11-66-000 gap, and expose the NETOs to “back-to-back” ROE refunds for a 15-month period beginning January 1, 2013.

The initial decision is available here.

* “P” refers to the relevant numbered paragraph in the initial decision.

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Mexico: U.S. Natural Gas Savior?

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Much has been made of the exponential growth in natural gas supply within the continental United States due to the horizontal drilling and fracking techniques employed in recent years. The resulting natural gas glut has reversed the conventional wisdom that America would be a net importer of natural gas for most of the 21st century with the expectation now being that America, despite being by far the world’s largest consumer of hydrocarbons, will be a significant exporter of natural gas overseas in the coming years and decades. This development has resulted in a flurry of proposed liquefied natural gas (“LNG”) terminals that hope to export natural gas in order to take advantage of the large spreads between prices in America and those in Europe and Asia. Those price spreads exist because a worldwide market for natural gas doesn’t exist, as opposed to oil where the relatively short-lived Brent-WTI price differential has evaporated in recent months.

However, these export terminals cannot export gas to foreign countries lacking a free trade agreement with the U.S. without permits from the U.S. Department of Energy and the Federal Energy Regulatory Commission (“FERC”). The queue for approval is long with only three facilities (including most recently the Lake Charles LNG Project in Lake Charles, Louisiana) receiving approval from the Department of Energy and only one of those (the Sabine Pass project in Cameron Parish, Louisiana) receiving approval from FERC. Given the long construction lead times for these projects and political pressure from environmentalists and buyers of natural gas who want prices to remain low, it won’t be until 2016 when any significant volumes of LNG are exported from the continental United States. Rival producers such as Qatar, Australia and Indonesia are rapidly signing contracts with Japan, Korea and China to satisfy the long-term needs of those countries as America continues to delay the development of its LNG infrastructure.

Meanwhile, the historically low natural gas prices created by the production glut are forcing energy companies to find a profitable market for their natural gas in the short to medium term. They appear to have found one in America’s backyard: Mexico. Constructing pipelines to straddle the U.S.-Mexico border entail less regulatory complexities and attract less political attention than LNG exports. With the existing U.S.-Mexico natural gas pipelines almost at capacity, energy companies cannot build border pipelines fast enough, with several new pipeline projects coming online, including Kinder Morgan’s El Paso Natural Gas Co. export pipeline near El Paso, Texas, with a capacity of 0.37 billion cubic feet per day. According to the U.S. Energy Information Administration all of the in-progress pipeline projects on the U.S.-Mexico border could result in a doubling of American natural gas exports to Mexico by the end of 2014.

This new export market should continue to support U.S. shale development in the near-term and medium-term future, especially in Texas, despite low natural gas prices and continued supply growth. Longer term prospects for U.S. natural gas exports to Mexico are also bright as well. Even though Mexico has large hydrocarbon reserves itself, the 1938 nationalization of its oil industry and the subsequent decades of underinvestment have seen Mexican hydrocarbon production steadily decline in the last decade. The Mexican constitution effectively prohibits private investment in hydrocarbon production and the Mexican public firmly believes in public ownership of hydrocarbons. There is widespread agreement among many Mexican politicians that private capital, especially from U.S. energy companies with the expertise to tap offshore and shale hydrocarbons, is needed to reverse the production decline, but whether public opposition can be overcome remains in doubt. Mexican President Enrique Peña Nieto is pushing constitutional reforms to attract foreign capital, but even if those pass Mexico is years away from converting any private capital into increased production. If those reforms do not pass, Mexico will be forced to continue to look to U.S. natural gas producers to provide it with its growing energy needs.

So while a regulatory bottleneck is endangering America’s ability to be a long-term overseas exporter of natural gas, Mexico, with its growing economy and inability to tap its own reserves, seems poised to play an outsized role in a continued expansion of American natural gas production. LNG exports might be the wave of the future, but natural gas exports to Mexico are the here and now.

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Federal Energy Regulatory Commission (FERC) Requires Filing of Additional Oil Pipeline Rate Base Information

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On July 18th, the Federal Energy Regulatory Commission (“FERC”) approved a final rule that makes substantive changes to the components of FERC Form 6, which interstate oil pipelines are required to file each year.[1] The rule requires additional reporting of the figures underlying pipelines’ rates of return and is intended to make it easier for both FERC and oil pipeline shippers to evaluate whether a given transportation rate complies with the law.

The new rule pertains to page 700 of Form 6, which provides information designed to show the pipeline’s cost of service, including O&M expenses, rate base, rate of return, total cost of service, revenues, and throughput. The purpose of this reporting is to provide a preliminary screen for determining whether a pipeline’s rates are “just and reasonable” as required by the Interstate Commerce Act.

In the final rule, FERC added new fields to page 700 that are intended to allow shippers to more easily calculate an oil pipeline’s actual rate of return on equity. The new required information, which FERC anticipates is already being developed in the preparation of the rate base and rate of return information required on existing page 700, is outlined briefly and at a high level below.

Interestingly, the Commission was asked by commenters to include additional changes to Form 6 in this rulemaking, including requiring companies that file Form 6 for multiple oil pipeline systems to file separate page 700s for each segment, service, or rate schedule. The Commission declined to do so in this proceeding as it was beyond the scope, but it should be noted that the consolidated Form 6’s and page 700’s that many companies currently file are alleged to mask the cost of service and rate of return for individual pipelines and services, and the comments in this proceeding suggest that shippers may continue to press FERC to require individualized page 700 filings in the future.

The changes to page 700 will take effect for the annual Form 6 filing for calendar year 2013, which is due April 18, 2014. These changes could enable new scrutiny of pipeline rates and complaints and challenges both to existing rates and to proposed annual rate increases under FERC regulations in the near future.

Outline of Page 700 Changes:

– Rate Base: While current page 700 requires the pipeline to report its rate base for each year, the revised page 700 will require this number to be broken out into three new components: Depreciated Original Cost; Unamortized Starting Rate Base Write-Up; and Accumulated Net Deferred Earnings.  The sum of these three components will equal the rate base number that was already required.

– Rate of Return: The existing rate of return percentage reported on page 700 is a weighted cost of capital; the new page 700 will require reporting of the cost of equity, costs of debt, and capital structure supporting the rate of return.

– Return on Rate Base: Currently, page 700 requires reporting of the return on rate base, combining the real return on equity and the portion of the return allocated to paying the pipeline’s cost of debt.  The revised page 700 requires breaking the return of rate base into separate debt and equity components.

– Composite Tax Rate: The revised page 700 will require pipelines to report the adjusted sum of the pipeline’s applicable state and federal income tax rates.

The stated purpose of the page 700 changes is to better enable the calculation of the actual return on equity of the pipeline, as adjusted for taxes, inflation and depreciation.  The final rule states that this calculation “is particularly useful information when using page 700 as a preliminary screen to evaluate whether additional proceedings may be necessary to challenge rates.”[2]

[1] Revisions to Page 700 of FERC Form No. 6, 144 FERC ¶ 61,049 (2013).

[2] Id. at P 36

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Federal Energy Regulatory Commission (FERC) Orders $435 Million Civil Penalty to Barclays Bank and $1-15 Million to Four Traders

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On July 16, 2013, the Federal Energy Regulatory Commission ordered Barclays Bank PLC to pay one of the largest civil penalties in its history — $435 million, 144 FERC ¶ 61.041 (2013). Four traders were also assessed penalties — $15M for trader Scott Connelly, and $1M each to traders Daniel Brin, Karen Levine and Ryan Smith. The Commission also found that Barclays should disgorge $34.9M, plus interest, in unjust profits. Barclays and the traders had elected FERC procedures that require FERC to assess the penalty without formal administrative adjudication, and then pursue enforcement of its assessment in an action in federal district court. The district court action includes a de novo review of the Commission’s findings. Early reports indicate that Barclays will fight the penalty in court.

These penalties were issued after FERC found that Barclays and its traders violated the Commission’s Anti-Manipulation Rule, 18 CFR §1c.2 (2012). The Commission found that Barclays and the traders manipulated California energy markets from November 2006 to December 2008 at the four most liquid trading points in the western U.S. — Mid-Columbia, Palo Verne, North Path 15 and South Path 15, Order at 2. Specifically, the Commission found that Barclays and the traders built a “significant volume of monthly index or fixed-price physical products” at a trading point “in a direction — long or short — opposite to fixed-for-floating financial swaps they held at that point.” The Commission noted that establishing these positions “had the effect of creating physical delivery or receipt obligations which Barclays was unable to meet in actual practice,” and that Barclays and the traders were able to “flatten” these positions (“achieve zero net physical obligations”) at the end of each day through the use of next-day fixed-price or cash physical products traded on the Intercontinental Exchange platform. FERC found that the trading activity at issue was “intended to move the Index rather than respond to market fundamentals and was generally uneconomic.” Order at 4.

The Commission further concluded that Barclays and the traders not only engaged in this manipulative trading scheme, but “they did so with the intent to commit fraud.” The Commission identified seven facts found during its investigation to support its conclusions:

  1. Barclays’ and the traders’ consistent pattern of building substantial positions directionally opposite their large swap positions and the subsequent flattening which would tend to move prices to benefit those swap positions;
  2. how the trading behavior in the “Manipulation Months” differed from months where there was no alleged manipulation;
  3. traders’ communications which discuss and describe the fraudulent scheme;
  4. Barclays and the traders responding to certain allegations, but completely failing to respond to FERC Office of Enforcement staff allegations regarding the building of positions as a manipulative scheme;
  5. the uneconomic nature of the trading;
  6. inconsistency in trader testimony and trader explanations presented in submissions;
  7. the failure of economic, statistical and legal analysis provided by Barclays and the traders to otherwise explain or defend the positions, swaps or trading.

In addition, FERC noted that it “considered various evidence to reach its conclusion concerning intent,” and provided examples of some of the compelling “speaking” evidence that it found demonstrates that the traders understood that they were making the trades to “drive price,” “protect” their positions and ”move” or “affect the Index.”

The parties have 30 days to pay the civil penalties assessed after which, the Commission can pursue enforcement of its assessment in federal district court. The parties continue to have the opportunity to settle the matter with the Commission. Absent a settlement, and unlike the DC Circuit’s decision in Hunter v. FERC, 711 F.3d 155 (D.C. Cir. 2013), this case may produce the first fully-adjudicated case on the merits of the Commission’s market manipulation theories.

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Study: Diluted Bitumen Poses No Greater Risk of Release from Pipelines than Conventional Crude Oil

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A new study released June 25, 2013, has found that diluted bitumen – a thick blend of Canadian crude oil derived from oil sands, a/k/a “dilbit” – presents no heightened risks of transport through pipelines in comparison to other types of crude oil. The study, conducted by the National Academy of Sciences (NAS) and sponsored by the Pipeline and Hazardous Materials Safety Administration (PHMSA), comes in the wake of a Congressional mandate to study whether the pipeline transportation of dilbit carries an increased risk of release (no doubt relative to consideration of the Keystone XL Pipeline project).

Opponents of pipeline transmission of dilbit have claimed that dilbit is more corrosive to pipelines than conventional crude oil and is therefore more prone to cause a pipeline failure and oil release. However, the new NAS study “did not find any causes of pipeline failure unique to the transportation of diluted bitumen” nor did it “find evidence of chemical or physical properties of diluted bitumen that are outside the range of other crude oils or any other aspect of its transportation by transmission pipeline that would make diluted bitumen more likely than other crude oils to cause releases.” Specifically, the NAS study’s three key findings are:

  1. Diluted bitumen does not have unique or extreme properties that make it more likely than other crude oils to cause internal damage to transmission pipelines from corrosion or erosion.
  2. Diluted bitumen does not have properties that make it more likely than other crude oils to cause damage to transmission pipelines from external corrosion and cracking or from mechanical forces.
  3. Pipeline operations and maintenance practices are the same for shipments of diluted bitumen as for shipments of other crude oils.

Committee for a Study of Pipeline Transportation of Diluted Bitumen, et. al., “TRB Special Report 311: Effects of Diluted Bitumen on Crude Oil Transmission Pipelines” (2013).

The study’s release comes on the heels of a petition to initiate rulemaking by a coalition of environmental groups urging the PHMSA and EPA to enact a host of sweeping pipeline regulations for dilbit. The Petition of Appalachian Mountain Club, et al., filed with the PHMSA and EPA on March 26, 2013, argued that dilbit should be regulated differently than other crude oils because it is more volatile and corrosive than conventional crude. The environmental groups urged the agencies to adopt regulations that would create significant economic and operational burdens on dilbit pipeline operators.

The study seemingly supports pipeline operators’ interests in the face of the Appalachian Mountain Club petition. For instance, many of the proposals are premised on the assumption that dilbit is more corrosive than conventional crude oil. Such proposals include the imposition of stricter safety standards, more burdensome reporting requirements, and rigorous pre-operation reviews unique to pipelines carrying dilbit. Also, the petition proposed a moratorium on expanding any transportation of dilbit until such regulations were imposed. Now, with credible scientific evidence pointing to no increased risk of pipeline releases associated with dilbit, these proposals likely face an uphill battle.

Additionally, the study comes at a crucial time for supporters of the proposed Keystone XL Pipeline, as the federal government is expected to make a decision on the project’s next phase as early as this summer. The Obama Administration has delayed approval of the project over those same concerns that dilbit is inherently more corrosive than conventional crudes, among other reasons. The study will strengthen Keystone advocates’ arguments that the 1,700-mile pipeline will be advantageous for the economy while posing no greater risk of release than a conventional crude oil pipeline.

However, some questions remain. Environmental groups are quick to point out that the study did not examine the potential differences in the environmental impact of a release involving dilbit compared to the release of conventional crude. Instead, the study only concerned a dilbit pipeline’s probability of failure, not the environmental consequences associated with a dilbit release. A finding that dilbit presents heightened environmental risks if released could reignite the push to regulate dilbit more aggressively, although PHMSA has not commissioned a study of dilbit’s environmental risks at this time. Still, for pipeline operators, the study provides strong support that dilbit pipelines do not require distinct regulatory scrutiny and can be protected by industry-standard integrity management programs.

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No Implied Duty to Develop Particular Strata in Pennsylvania (e.g. Marcellus Shale)

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On June 21, 2013, the Superior Court of Pennsylvania (the “Court”) held that a lessee does not owe a duty to a lessor to develop each and every “economically exploitable strata” under an oil as gas lease in Pennsylvania.

In early 2012, Terry L. Caldwell and Carol A. Caldwell, husband and wife (“Plaintiffs”) sued Kriebel Resources Co., Range Resources—Appalachia, LLC and others (“Defendants”) regarding an oil and gas lease executed between the Plaintiffs and Defendants on January 19, 2001 (the “Lease”). The Lease provided for a primary term of twenty four (24) months and so long thereafter as oil or gas was being produced. The Defendants drilled a number of shallow wells on the property that Defendants alleged held the entire property under the terms of the Lease. Plaintiffs brought suit against the Defendants in early 2012 alleging that, among other things, Defendants breached the implied duty to develop the property by not drilling deeper wells to exploit the valuable Marcellus Shale and, based on such potential unexploited value, the current production did not amount to production in paying quantities. The trial court sustained certain preliminary objections raised by the Defendants that resulted in a dismissal of Plaintiffs’ claims. In Terry L. Caldwell et al. v. Kriebel Resources Co. et al. (1305 WDA 2012), the Court affirmed the trial court’s dismissal of the case.

Regarding the duty to develop, Plaintiffs argued that without direct Pennsylvania case law on topic the Court should follow a Louisiana case, Goodrich v. Exxon Co., 608 So.2d 1019 (La. App. 1992), which held that Exxon’s duty to develop as a reasonably prudent operator included the obligation to develop valuable oil-producing sands underlying the leased premises. Based on this rationale, Plaintiffs alleged there is an implied duty to “develop all strata, not simply to extract shallow gas . . .” The Court rejected the application of the Goodrich rationale and held that the specific terms of the Lease were to control. Therefore, because the Lease provides for the continued validity of the Lease upon production of gas and allows for the guarantee of delay rentals if no gas is produced, the Court found that it was “not compelled to follow Louisiana law.” The production from various shallow wells was found to be sufficient to hold the entirety of the leased estate.

The Court also rejected Plaintiffs’ claim that the concept of “paying quantities” should be based on all potential gas strata underlying the Lease and should impose some obligation relating to good faith. The Court quickly dismissed this claim and made clear that “paying quantities” in Pennsylvania merely requires the well to “consistently pay[] a profit, however small.” It is of no legal effect that the extent of the profit produced from these shallow wells is “not to the extent appellants desire.” Due to the continued production in paying quantities and the Court’s failure to impose a duty on Defendants to develop all potentially economic strata, the Court chose not to terminate Defendants’ Lease.

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Financial Innovation for Clean Energy Deployment: Congress Considers Expanding Master Limited Partnerships for Clean Energy

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Technological innovation is driving renewable energy towards a future where it is cost competitive without subsidies and provides a growing share of America’s energy. But for all the technical progress made by the clean energy industry, financial innovation is not keeping pace: access to low-cost capital continues to be fleeting, and the industry has yet to tap institutional and retail investors through the capital markets. This is why a bipartisan group in Congress has proposed extending master limited partnerships (MLPs), a financial mechanism that has long driven investment in traditional energy projects, to the clean energy industry.

Last month Senators Chris Coons (D-DE) and Jerry Moran (R-KS) introduced the Master Limited Parity Act (S. 795); Representatives Ted Poe (R-TX), Mike Thompson (D-CA), and Peter Welch (D-VT) introduced companion legislation (H.R. 1696) in the House of Representatives. The bills would allow MLP treatment for renewable energy projects currently eligible for the Sec. 45 production tax credit (PTC) or 48 investment tax credit (ITC) (solar, wind, geothermal, biomass, hydropower, combined heat and power, fuel cells) as well as biofuels, renewable chemicals, energy efficient buildings, electricity storage, carbon capture and storage, and waste-heat-to-power projects. The bill would not change the eligibility of projects that currently qualify as MLPs such as upstream oil and gas activities related to exploration and processing or midstream oil and gas infrastructure investments.

MLPs have been successfully utilized for traditional fossil-fuel projects because they offer an efficient means to raise inexpensive capital. The current total market capitalization of all energy-related MLPs exceeds $400 billion, on par with the market value of the world’s largest publicly traded companies. Ownership interests for MLPs are traded like corporate stock on a market. In exchange for restrictions on the kinds of income it can generate and a requirement to distribute almost all earnings to shareholders (called unitholders), MLPs are taxed like a partnership, meaning that income from MLPs is taxed only at the unitholder level. The absence of corporate-level taxation means that the MLP has more money to distribute to unitholders, thus making the shares more valuable. The asset classes in which MLPs currently invest lend themselves to stable, dividend-oriented performance for a tax-deferred investment; renewable energy projects with long-term off-take agreements could also offer similar stability to investors. And since MLPs are publicly traded, the universe of potential investors in renewable projects would be opened to retail investors.

The paperwork for MLP investors can be complicated, however. Also, investors are subject to rules which limit their ability to offset active income or other passive investments with the tax benefits of an MLP investment. Despite the inherent restrictions on some aspects of MLPs, the opportunities afforded by the business structure are generating increasing interest and support for the MLP Parity Act.

Proponents of the MLP Parity Act envision the bill as a way to help renewable energy companies access lower cost capital and overcome some of the limitations of the current regime of tax credits. Federal tax incentives for renewable energy consist primarily of two limited tools: tax credits and accelerated depreciation rates. Unless they have sizeable revenue streams, the tax credits are difficult for renewable project developers to directly use. The reality is only large, profitable companies can utilize these credits as a means to offset their income. For a developer who must secure financing though a complicated, expensive financing structure, including tax equity investors can be an expensive means to an end with a cost of capital sometimes approaching 30%. Tax credits are a known commodity, and developers are now familiar with structuring tax equity deals, but the structure is far from ideal. And as renewable energy advocates know all too well, the current suite of tax credits need to be extended every year. MLP treatment, on the other hand, does not expire.

Some supporters have noted that clean energy MLPs would “democratize” the industry because private retail investors today have no means to invest in to any meaningful degree in clean energy projects. Having the American populace take a personal, financial interest in the success of the clean energy industry is not trivial. The initial success of ‘crowd-funded” solar projects also provides some indication that there is an appetite for investment in clean energy projects which provide both economic and environmental benefits.

Sen. Coons has assembled a broad bipartisan coalition, including Senate Finance Energy Subcommittee Chair Debbie Stabenow (D-MI) and Senate Energy and Natural Resources Ranking Member Lisa Murkowski (R-AK). Republican and Democratic cosponsors agree that this legislation would help accomplish the now-familiar “all-of-the-above” approach to energy policy.

However, some renewable energy companies that depend on tax credits and accelerated depreciation are concerned that Republican supporters of the legislation will support the bill as an immediate replacement for the existing (but expiring) suite of renewable energy tax credits. Sen. Coons does not envision MLP parity as a replacement for the current production tax credits and investment tax credits but rather as additional policy tool that can address, to some degree, the persistent shortcomings of current financing arrangements. In this way, MLPs could provide a landing pad for mature renewable projects as the existing regime of credits is phased out over time, perhaps as part of tax reform.

So would the clean energy industry utilize MLP structures if Congress enacts the MLP Parity Act? The immediate impact may be hard to predict, and some in renewable energy finance fear MLP status will be less valuable than the current tax provisions. This is in part because the average retail investor would not be able to use the full share of accompanying PTCs, ITCs, or depreciation unless Congress were also to change what are known as the “at-risk” and “passive activity loss and tax credit” rules. These rules were imposed to crack down on perceived abuse of partnership tax shelters and have tax implications beyond the energy industry. Modifying these rules is highly unlikely and would jeopardize the bipartisan support the bill has attracted so far. But other renewable energy companies believe they can make the structure work for them now, and industries without tax credits — like renewable chemicals, for instance — would not have the same concerns with “at-risk” and “passive activity loss” rules. Furthermore, over the long term, industry seems increasingly confident the structure would be worthwhile. Existing renewable projects that have fully realized their tax benefits and have cleared the recapture period could be rolled up into existing MLPs. Existing MLP infrastructure projects could deploy renewable energy assets to help support the actual infrastructure. Supporters of the legislation see the change as a starting point, and the ingenuity of the market will find ways to work within the rules to deliver the maximum benefit.

The future of the MLP Parity Act will be linked to the larger conversation in Congress regarding tax reform measures. The MLP Parity Act is not expected to pass as a stand-alone bill; if it were to be enacted, it would most likely be included as part of this larger tax-reform package. Congress currently is looking at ways to lower overall tax rates and modify or streamline technology-specific energy provisions. This has many renewable energy advocates on edge: while reform provides an opportunity to enact long-term policies (instead of one-year extensions) that could provide some level of stability, it also represents a chance for opponents of renewable energy to exact tough concessions or eliminate existing incentives. As these discussions continue in earnest this year, the reintroduction of the MLP Parity Act has already begun to generate discussions and mentions in policy white papers at both the House Ways and Means Committee and the Senate Finance Committee. Whether a highly partisan Congress can actually achieve such an ambitious goal as tax reform this year remains uncertain. But because of its bipartisan support, the MLP Parity Act certainly will be one of the many potential reforms Congress will consider seriously.

Is Regulation of Greenhouse Gases Through the Clean Air Act Becoming “Too Big to Fail”?

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In a much-publicized decision in 2007, the Supreme Court ruled that the United States Environmental Protection Agency (USEPA) is authorized to regulate greenhouse gases (GHGs) through the Clean Air Act. Massachusetts v. EPA, 549 U.S. 497 (2007). A slew of recent cases have rejected plaintiffs’ attempts to assert common law claims for damages based on the consequences of past emissions of GHGs. The courts generally have found that USEPA has occupied the role of regulating GHGs, and challenges to the agency’s actions must be brought through the appropriate administrative channels. As the Supreme Court weighs whether to grant certiorari in the Coal. for Responsible Regulation, Inc., et al. v. EPA, No. 09-1322 (D.C. Cir. June 26, 2012), the case that addresses four USEPA GHG rules, the Supreme Court may have difficulty in changing course from the idea that GHGs should be regulated pursuant to the Clean Air Act.

Comer v. Murphy Oil et al., No. 12-60291 (5th Cir. May 14, 2013).

In the aftermath of Hurricane Katrina, Mississippi Gulf residents sued numerous energy companies, alleging that the defendants’ emissions of GHGs exacerbated the severity of and damage caused by the Class 5 hurricane (hereinafter Comer I). The claims ranged from public and private nuisance, trespass and negligence, to fraudulent misrepresentation and conspiracy. The district court dismissed Comer I with prejudice, finding that the plaintiffs had no standing to bring these claims and the claims were non-justiciable because they involved a political question.

Comer I became mired in technical details and procedures, and ultimately the plaintiffs tried to refile the case to bring an entirely new lawsuit, Comer II. The Fifth Circuit dismissedComer II because the plaintiffs brought the same claims they alleged in Comer I, and the district court had already dismissed those claims on the merits. The court applied the doctrine of res judicata, which bars parties from litigating the same claim a second time, and, consequently, Comer II was barred by the district court’s original dismissal in Comer I. Because Comer I held that plaintiffs have no standing to challenge GHG emissions through common law claims, it supports the idea that GHGs should be regulated through the Clean Air Act, rather than addressed through litigation.

Native Village of Kivalina v. ExxonMobil Corp. et al., No. 09-17490 (9th Cir. Sept. 21, 2012).

Kivalina is a village located on the far northwest shore of Alaska. The village had long been protected by the winter ice that persisted and protected the land mass itself. Due to melting icebergs and rising sea levels, the village land mass is eroding, and remains unprotected by the ice wall for much of the year. The village almost certainly will be either eroded into nothingness or inundated by the Arctic Ocean in the next twenty years. Kivalina sued a large group of energy companies, alleging that the GHGs emitted by them resulted in global warming and their village’s imminent destruction. Under a theory of common law public nuisance, the village sought damages to allow the relocation of the community.

The District Court held that political questions such as those raised by the allegations were not justiciable. Further, the court held the plaintiffs lacked Article III standing because they could not show that the named defendants likely caused the injuries, nor could the injuries be traced to an act of any of the defendants.

The Ninth Circuit agreed but expounded on the role of federal common law in pollution cases. The Court noted that federal common law has developed to fill gaps arising in cases of transboundary pollution and that those cases generally arise as nuisance claims. Despite its acknowledgement that nuisance claims can be used to regulate pollution, the Ninth Circuit explained that where a statute directly addresses the underlying issue, developing a federal common law was not necessary to address the issue. Accordingly, because the Supreme Court found that Congress acted through the Clean Air Act to address GHG pollution inMassachusetts v. EPA, filling the gap with federal common law (or public nuisance claims) was not necessary. Furthermore, the Ninth Circuit found that federal common law does not fill a gap solely based on the type of relief requested. In other words, the plaintiffs inKivalina sought damages rather than emission reduction, the latter being the type of relief afforded by the Clean Air Act. Although the plaintiffs’ requested relief was not available under the Clean Air Act, the Clean Air Act still displaced federal common law and prevented plaintiffs from seeking damages through a common law claim (such as public nuisance).

Consequently, Kivalina, like Comer, supports the idea that USEPA is charged with regulation of GHGs through the Clean Air Act.

Public Trust Doctrine Cases

Along a similar avenue, a number of public trust doctrine cases have been filed on behalf of children since 2011. In these cases, the plaintiffs allege that children’s futures are being affected by the lack of action to regulate GHGs, and they request that the various agencies cited in the lawsuits — primarily USEPA and Department of the Interior — take immediate action to reduce GHGs. These cases use the public trust doctrine as the basis of the complaint by alleging that the atmosphere is a common resource that must be managed for the public good and the agencies have failed to properly manage that resource. These cases have generally been dismissed for failure to state a claim for which relief can be granted.See Alec L. v. Perciasepe, No. 11-cv-2235 (D.D.C. May 22, 2013); Sanders-Reed v. Martinez, No. D-101-cv-2011-01514 (D.N.M. July 14, 2012); Alec L. v. Jackson, No. 1:11-cv-02235 (D.D.C. May 31, 2012); Loorz v. Jackson (D.D.C. April 2, 2012); Filippone v. Iowa Dep’t of Natural Resources, No. 2-1005, 12-04444 (Iowa Ct. App. Mar. 13, 2013); Aronow v. State, No. A12-0585 (Minn. Ct. App. Oct. 1, 2012).

In general, cases arising under the public trust doctrine face two challenges. First, the Supreme Court held in PPL Montana, LLC v. Montana, No. 10-218 (2012), that the public trust doctrine is a matter of state, not federal, common law and so a federal claim is not justiciable in federal court. Second, in AEP v. Connecticut, No. 10-174 (2011), the Supreme Court held that the role of regulating GHGs, and any consequence(s) of GHGs, has been occupied by the Clean Air Act and therefore challenges to the regulation of GHGs should be brought through the Clean Air Act rather than through a common law claim. Again, these cases are important for the future of GHG regulation because they affirm the agency’s role as the regulator of GHGs through the Clean Air Act.

Montana Envt’l Info. Center v. U.S. Bureau of Land Mgmt., No. cv-11-15-GF-SEH (D. Mont. June 14, 2013).

In another case affirming the role of the Clean Air Act in regulating GHGs, environmental groups claimed that the Bureau of Land Management (BLM) failed to adequately consider climate change, global warming, and the emission of GHGs in violation of the National Environmental Policy Act (NEPA) before approving oil and gas leases on federal land in Montana in 2008 and 2010. The environmental groups argued that BLM’s failure to follow NEPA procedures would result in emissions of methane gas from the oil and gas leases at issue. The release of methane gas would cause global warming and climate change, which would present a threat of harm to their aesthetic and recreational interests in lands near the lease sites by melting glaciers, warming streams, and promoting the destruction of forests through the proliferation of plagues of beetles.

The district court dismissed the lawsuit because the environmental groups lacked standing to bring the claim. The court found that the environmental groups failed to demonstrate that BLM’s alleged failure to follow proper procedure created an increased risk of actual, threatened, or imminent harm to their recreational and aesthetic interests in lands near the lease sites. Although the environmental groups had local recreational and aesthetic interests at heart, the court found that the effects of GHG emissions are diffuse and unpredictable, and the groups presented no scientific evidence or recorded scientific observations to support their assertions that BLM’s leasing decisions would present a threat of climate change impacts on lands near the lease sites. Furthermore, the environmental groups did not show that methane emissions from the lease sites would make a meaningful contribution to global GHG emissions or global warming. The court therefore found that the environmental groups failed to establish injury-in-fact and causation. As a result, the court foreclosed another potential avenue for litigating claims surrounding GHG emissions, and potential plaintiffs now seem to be left only with direct challenges to USEPA’s regulations (or lack thereof).

Conclusion

The Court would mark a dramatic shift if it moved away from these cases. By the time the Supreme Court has the opportunity to review climate change regulation again, the Obama administration may have set a “too big to fail” bar with its climate policies. Regardless of what happens in the future, however, as of today, the Court’s decision in Massachusetts v. EPA appears to have had a pronounced impact, acceding to USEPA the authority to regulate GHGs through the Clean Air Act, and denying common law remedies for impacts tied to climate change.

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California’s Future Uncertain as U.S. Bureau of Land Management (BLM) Postpones Oil and Gas Lease Auctions

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Recently, the U.S. Bureau of Land Management (BLM) announced that it would postpone all oil and gas lease auctions in California until at least October 2013.  The agency cited the toll of litigation and other costs as factors behind the decision.

Many attribute the postponement to an April 2013 federal district court ruling in Center for Biological Diversity, et al. v. Bureau of Land Management, et al., United States District Court for the Northern District of California, Case No. 11-06174 PSG, in which the court held that BLM violated the National Environmental Policy Act by failing to analyze potential environmental impacts of “fracking” on 2,700 acres of federal lands in Monterey and Fresno Counties before leasing the lands to oil companies.  Hydraulic fracturing, or fracking, involves injecting high-pressure mixtures of water, sand or gravel, and chemicals into rock to extract oil.  The technique has been used for decades in California, and is also used in other states to recover natural gas.  However, fracking has recently been under increased scrutiny, amid concerns that the practice could contaminate groundwater.

The court’s decision in Center for Biological Diversity does not void the leases that were the subject of the case, but requires BLM to go back and take a closer look at the potential impacts of fracking.  The ruling is largely limited to the specific facts that were before the court, and the case is unlikely to have sweeping application as a legal precedent, but it marks a victory for environmental groups attempting to stop, or at least delay, fracking in California.

BLM’s decision to postpone oil and gas lease auctions in California coming on the heels of the Center for Biological Diversity decision suggests that policy impacts of the case may be more widely felt.  BLM announced this month that it will put off a previously scheduled late May auction for leases to drill almost 1,300 acres of public lands near the Monterey Shale.  The Monterey Shale is one of the largest deposits of shale oil in the nation, containing an estimated 15.4 billion barrels of recoverable oil.  Another auction for about 2,000 acres in Colusa County was also put on hold.

“Our priority is processing permits to drill that are already in flight rather than work on new applications,” Interior Secretary Sally Jewell told reporters in Washington.  The decision to postpone leasing doesn’t mean that drilling on existing leases will stop, but it does raise questions about what BLM will do in the fall, when the postponement expires, and how the postponement decision will impact oil and gas production more broadly.

California accounts for 6 percent of the 247 million acres under BLM control, and oil and gas drilling on BLM lands has been on the rise as advances in horizontal drilling and fracking have made hard-to-reach deposits recoverable.  The impact of litigation such as the Center for Biological Diversity matter on BLM, and on the industry as a whole, is therefore significant.

For California at least, the future is uncertain.  “We want to get the greenhouse gas emissions down, but we also want to keep our economy going,” said Governor Jerry Brown (D, California), during a March 13 press conference.  “That’s the balance that is required.”  Amid budget concerns, financially strapped government agencies may be increasingly risk-averse when it comes to potential litigation, leading to decisions like the California postponement that have industry-wide implications.

As published in Oil & Gas Monitor.

Bridge to Prosperity: New Bridge Between U.S. and Canada Approved

Varnum LLP

Michigan farmers are among legions of organizations expressing gratitude now that a new bridge between the U.S. and Canada has been approved by the Obama Administration, setting the stage for a sharp increase in trade between Michigan and Canada.

The presidential permit awarded by the State Department April 12 clears the way for construction to begin in Michigan on the New International Trade Crossing Bridge.  The new span  will “serve the national interest,” the State Department said in granting the permit.

Michigan is Canada’s largest trade partner, with trade in 2011 exceeding $70 billion. That’s nearly 11.7 percent of the total U.S. trade with Canada. More than 8,000 trucks currently cross the Detroit-Windsor border daily.

Called “Michigan’s Bridge to the Future,”  the New International Trade Crossing Bridge will be built near the existing Ambassador Bridge that links Detroit with Windsor. Michigan voters in November overwhelmingly rejected a ballot proposal spearheaded by Ambassador Bridge owner Matty Moroun to require voter approval for any bridge built between the U.S. and Canada.

Under a deal struck last year between Michigan Gov. Rick Snyder and Canadian Prime Minister Stephen Harper,  Canada will pay for the bridge, with construction costs repaid by Canada through tolls.  Snyder said in a statement the crossing will create jobs and get Michigan-made products to market quicker.”

From the standpoint of Michigan agriculture, this additional transportation capacity is vital to streamline and expand our access to markets in Canada,” Michigan Farm Bureau Legislative Counsel Matt Smego said in prepared remarks.

Construction has already started on the Canadian side. Michigan Gov. Snyder said he hopes for groundbreaking on the Detroit side within the next two to three years. Construction is expected to take seven years.

The city of Windsor, meanwhile,  on May 28 asked Michigan officials for more information regarding the Michigan Department of Transportation’s recommendation to open the existing Ambassador Bridge to trucks carrying hazardous materials for the first time in its 83-year history. The recommendation excludes the transportation of explosives.

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