Tag: Environmental Law

Watt’s New? Michigan Energy Law News – August 2013

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Natural Gas Power Plant Approval Case Gets Started

The first hearing at the Michigan Public Service Commission (MPSC) regarding the application of Consumers Energy to build a 700 MW natural gas-fired power plant (Case U-17429) occurred August 19. Twelve intervenors were granted party status: the Michigan Energy Innovation Business Council; Energy Michigan; Attorney General for the State of Michigan; Association of Businesses Advocating Tariff Equity (ABATE); Midland Cogeneration Venture Limited Partnership; Renaissance Power LLC; New Covert Generating Company LLC; Interstate Gas Supply, Inc.; First Energy Solutions Corp.; Michigan State Utility Workers Council; Sierra Club; National Resources Defense Fund; and Michigan of Environmental Council.  Potential issues to be raised by the interveners include the assumptions in the filed Integrated Resource Plan on:

  • alternative and renewable energy generation availability and costs;
  • the limitations of the customer choice program;
  • the closure of seven coal plants with a total capacity of 950 MW; and
  • the impact of energy optimization and conservation on future load demand.

ABATE has indicated it will be filing a Motion for Summary Judgment seeking the dismissal of the application, asserting that Consumers Energy has not properly shown a need for a new power plant. Assuming the case is not dismissed, a schedule has been set calling for cross examination of witnesses the second week of December, and a decision by the MPSC on or before the 8th of April, the statutory deadline for a decision on the Certificate of Necessity request. See www.tinyurl.com/mpsc-conDeep Water Offshore Floating Wind Turbines Showcased On August 15 Detroit-based Charles Nordstrom, P.E. of Glosten Associates Inc. (naval architects and marine engineers out of Seattle) presented the latest design and deployment plans for the Pelastar floating wind turbine system at the Michigan Alternative and Renewable Energy Center in Muskegon.

Emphasizing the opportunity to locate near load demand, Nordstrom explained the system avoids the difficulties of offshore construction and assembly by allowing the floating platform to be build dockside, with tower, nacelle and blades attached by a land-based crane. The entire assembly is then floated to its location and tethered to the lake or sea bed. The first 6 MW demonstration project, supported by Alstom Wind, NREL, BP, Rolls-Royce, Shell, Caterpillar, and others is targeted for offshore at Cornwall, England, in late 2015. Cost of energy estimates for first generation offshore wind farms is $0.170 per kWh, and below $0.13 in the second generation design for 10 MW wind turbines. The floating platform must be in at least 50m of water depth, and can be deployed at up to 500m depth.

Cellulosic Ethanol Plant Loses Partner

Mascoma Corporation has lost a major funding source in its efforts to build a 20 million gallon ethanol plant in Kinross. Valero Energy Crop has pulled its $50 million investment in the project. An IPO for Mascoma that would have raised $100 million has been placed on hold. The company has stated it will not proceed with the project until all funding is secured.  The total cost for the facility, which has $120 million in public funding pledged, is $232 million.

Anaerobic Digester Opens at MSU

Michigan State University has commissioned an anaerobic digester to create energy for its East Lansing campus. The digester will utilize about 17,000 tons of organic waste to generate 2.8 million kilowatt hours of electricity per year. The organic material used by the system includes cow manure, food waste from several campus dining halls; fruit and vegetable waste from the Meijer Distribution Center in Lansing; and fat, oils and grease from local restaurants. It will take 20 to 30 days to digest the material in the 450,000 gallon tanks. Total cost of the project was about $5 million, and is expected to pay for itself in less than 15 years. MSU is also involved in a similar project in Costa Rica. that will provide power to a local village.

MIchigan Shorts

Orisol Energy US, Inc. of Ann Arbor has been named as one of eight wind developers eligible to participate in the upcoming lease sale of 112,8000 acres of offshore Virginia for commercial wind energy leasing  Ω  DTE Energy plans to construct a 502 kw ground-mounted solar installation in Sigel Township on farm acreage as part of its 15 MW utility-owned solar initiative  NextEnergy has its MATch (Michigan Accelerating Technologies) Energy Grant program to provide matching funds for federal gudning of advanced energy research, development, and demonstration programs

University of Michigan has received a National Science Foundation four-year, $2 Million grant to determine what combinations of algae make the most efficient fuel source Lights Out at Detroit’s Municipal Utility? The Detroit Public Lighting Department (PLD) currently serves 115 customers, including: Detroit Public Schools; Joe Louis Arena; Cobo Hall; the Detroit Institute of Arts; Wayne State University; McNamara Building Federal Building; and the city’s traffic signal system (almost 1300 intersections).

The Detroit Emergency Manager recently notified DTE Energy Company that PLD will be winding down its electricity distribution and transmission services and requested that DTE provide service to PLD’s customers. The switchover will take five to seven years, as DTE will replace the PLD grid over time. How DTE will recover the costs of the transfer and upgrades has become an issue to be decided by the MPSC in Case No. U-17427. See www.tinyurl.com/mpsc-pld

The Incredible Shrinking Renewable Energy Surcharge

Consumers Energy is asking to eliminate its authorized renewable energy surcharge beginning in July 2014. The residential charge under PA 295, was initially pegged at $2.50/month, then lowered twice to its current $0.52/month charge. Meanwhile DTE Energy has asked the Michigan Public Service Commission to lower its monthly residential renewable energy surcharge from $3/month to $0.43/month. Commercial and industrial surcharge reductions are also being requested by both utilities.

Made in Michigan Microgrid Under Development

In 2006, NextEnergy in Detroit was contracted by TARDEC and the Defense Logistics Agency to develop equipment to provide US-grid quality power in remote locations using renewable and conventional power sources. Although the project was successfully tested, it was too large and too heavy to be deployed in the field, as it required a 20-foot long container for shipping. But the concept of an intelligent management for remote power systems had been proven and the Tactical Modular Mobile Microgrid was born. TM3 Systems of Royal Oak is now working to reduce the size and commercialize the concept. The building blocks for its system are four-foot cubes capable of managing up to 360 kW of generation. By metering and controlling both inputs (generators, solar panels, and battery banks), and outputs (downstream loads), this “microgrid,” is more reliable, efficient, configurable, and controllable than a typical remote power system. It can use dissimilar power sources (fossil fuel generators, solar arrays, and batteries) to reduce fuel consumption while supplying uninterrupted power to critical assets in remote location.

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Could Your Business Qualify for a 179D Green Building Tax Break?

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If your company has built a new facility or upgraded an existing one anytime in the past six years, you might find that you qualify — at least partially — for a tax break of up to $1.80 per square foot under federal tax code section 179D, or the energy efficient commercial buildings deduction. This could be the case even if you had no concrete intention to focus on green building standards at the time.

A couple of great features of this deduction are, first, that you might be able to substantially mitigate your tax burden  as far back as six years and, second, it’s very likely that you will qualify if your facility exceeds 50,000 square feet and it meets current state building codes, according to a business tax writer for Forbes, who spent eight years as the U.S. Senate Finance Committee’s tax counsel.

The 179D tax deduction gives the business an immediate deduction in the current year plus a basis reduction for the value of the facility, which can be anything from a warehouses or parking garage to an office park or a multi-family housing unit. For private-sector projects, the building owner, assuming it paid for the construction or improvements, generally gets the deduction. In public projects, the architect, engineer or contractor can obtain it by seeking a certification letter from the government unit. Nonprofits and native American tribes are not eligible.

The green building deduction was created in recognition of the fact that around 70 percent of all electricity used in the U.S. is consumed by commercial buildings. The deduction, which is up for renewal — and possible expansion — this year, has already proven that efforts to mitigate the tax burden of businesses in a technology-neutral way is an effective way to encourage energy efficiency, according to the Forbes writer.

What improvements must be made to qualify for the green building credit? Currently, the new or renovated building merely needs to exceed the 2001 energy efficiency standards developed by the American Society of Heating, Refrigerating and Air Conditioning Engineers, or ASHRAE — and most state building codes already require this. That means the vast majority of new and improved buildings already meet this requirement.

It’s also possible to partially qualify for the deduction by meeting the standards only for the building envelope itself, which includes HVAC, the hot water system, and the interior lighting system. A building could qualify based upon only one of these systems, or all three.

Source: Forbes, “179D Tax Break for Energy Efficient Buildings — Update,” Dean Zerbe, Aug. 19, 2013

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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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US Government Accountability Office (GAO) Advocates for Increased Attention on Adapting to the Effects of Climate Change

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The US Government Accountability Office (GAO), the federal government’s non-partisan internal auditor, has jumped into the climate change fray, arguing that the federal government must improve how it is addressing the effects of climate change, in addition to and irrespective of any actions taken to prevent or reverse it. In two reports issued earlier this year, the GAO describes shortcomings in federal efforts to address the “significant financial risks” from climate change and recommends both macro and micro level changes to address these risks.

The first of the two reports is the biennial update to GAO’s list of federal programs and operations at “high risk” for waste, fraud, abuse, and mismanagement or needing broad-based transformation (High Risk List).[1] The High Risk List was originally compiled in 1990 and is released at the start of each new Congress to help in setting oversight agendas. An issue is added to the High Risk List if it meets the following four criteria:

  • the issue is of national significance;
  • it is key to government performance and accountability;
  • the associated risk involves public health or safety, service delivery, national security, national defense, economic growth, or privacy or citizens’ rights; and
  • the issue could result in significant impaired service, program failure, injury or loss of life, or significantly reduced economy, efficiency, or effectiveness.

The 2013 High Risk List adds climate change to the list of now 30 issues that meet these “high risk” criteria.[2] According to the GAO, the federal government allocates greater sums of money each year to climate change adaptation activities, but it is “not well organized to address the fiscal exposure presented by climate change, partly because of the inherently complicated, crosscutting nature of the issue.” In particular, the GAO is concerned that the federal government is exposed to “significant financial risks” from climate change: (1) as a property owner of extensive infrastructure; (2) as an insurer through the National Flood Insurance Program; (3) as an investor in infrastructure projects that state and local governments prioritize and supervise; and (4) as a provider of emergency aid in response to natural disasters.

In determining the scope of its policy recommendations, the GAO considered whether to focus on responses to prevent or reverse climate change or responses to adapt to the effects of climate change. In choosing to focus on adaptation strategies, GAO cites research from the National Research Council (NRC) and the United States Global Change Research Program (USGCRP) concluding that greenhouse gases already in the atmosphere will irrevocably alter the climate system for many decades.[3] The resulting policy recommendations advocate for key entities within the Executive Office of the President, including the Council on Environmental Quality (CEQ) and the Office of Science and Technology Policy, in consultation with federal, state, and local stakeholders, to develop “a government-wide strategic approach with strong leadership and the authority to manage climate change risks that encompasses the entire range of related federal activities and addresses all key elements of strategic planning.” The GAO anticipates that this centralized approach will increase efficiencies in these efforts and take advantage of economies of scale. Private entities that operate in the infrastructure sector, and in related industries, should monitor the executive and legislative responses to these broad-based recommendations.

The second report centers on one of the areas of concern from the climate change addition to the High Risk List — the federal government’s role in supporting state and local governments in their efforts to strengthen infrastructure vulnerable to the effects of climate change.[4] In it, the GAO examines (1) the impacts of climate change on infrastructure; (2) the extent to which climate change is incorporated into infrastructure planning; (3) factors that enabled some decision makers to implement adaptive measures; and (4) federal efforts to address local adaptation needs, as well as potential opportunities for improvement. Similar to the recommendations made in the climate change portion of the High Risk List, GAO advocates for a centralized system of information and data, as well as streamlined access to that data for local infrastructure decision makers, as one of the primary means to increasing and improving climate-related adaptions in infrastructure planning. Of the specific projects that GAO studied in order to prepare the report, those that had easy access to climate data and expertise to help interpret that data were more likely to incorporate adaptions to address the effects of climate change into their plans.

Furthermore, the GAO specifically recommends that CEQ finalize its 2010 guidance on how federal agencies should consider the effects of climate change in their evaluations of proposed federal actions under the National Environmental Policy Act (NEPA). Until the guidance is final, it is “unclear how, if at all, agencies are to consistently consider climate change in the NEPA process, creating the potential for inconsistent consideration of the effects of climate change in the NEPA process across the federal government.”[5] Therefore, entities involved in projects that fall under NEPA’s purview should monitor CEQ’s activities on this issue and consider submitting comments on any resulting guidance or regulation.

[1] GAO, High-Risk Series: An Update, Report No. GAO-13-283 (Feb. 2013)

[2] Id. at 61-76 (“Limiting the Federal Government’s Fiscal Exposure by Better Managing Climate Change Risks”).

[3] Id. at 63 (“[L]imiting the federal government’s fiscal exposure to climate change risks will present a challenge no matter the outcome of domestic and international efforts to reduce emissions”).

[4] GAO, Climate Change: Future Federal Adaptation Efforts Could Better Support Local Infrastructure Decision Makers, Report No. GAO-13-242 (Apr. 2013).

[5] Id. at 87. 

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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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On Heels of European Raids, Energy Companies Face U.S. Class Actions

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White Oaks Fund LP, an Illinois private placement fund, filed a class action suit last week against BP PLC, Royal Dutch Shell PLC and Statoil ASA in the Southern District of New York.  White Oaks Fund v. BP PLC, et al., case number 1:13-cv-04553.  The complaint alleges that the energy companies colluded to distort the price of crude oil by supplying false pricing information to Platts, a publisher of benchmark prices in the energy industry, in violation of the Sherman and Commodity Exchange Acts.  Plaintiffs claim that defendant companies are sophisticated market participants who knew that the incorrect information they provided to Platts would impact crude oil futures and derivative contracts prices traded in the U.S.

This action follows at least six civil litigations that have been filed against BP, Shell and Statoil after the European Commission (EC) and Norwegian Competition Authority raided the companies in May.  The London offices of Platts were also searched.  After the surprise raids, the EC has stated that it is investigating concerns that the companies conspired to manipulate benchmark rates for various oil and biofuel products and that the companies excluded other energy firms from the benchmarking process as part of the scheme.  In addition, at least one U.S. Senator has requested that the U.S. Department of Justice look into whether any of the alleged illegal behavior occurred in the U.S.

The private actions filed against these energy companies in the U.S. on the heels of an investigation by the European Commission are not uncommon.  Any company that transacts business in the U.S. and undergoes a raid or investigation by a foreign competition authority should prepare to face these civil litigations and defend itself against similar allegations.

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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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