Category: Energy Law

Energy Storage Conference Offers Lessons Learned and Path Forward

Lewis Roca Rothgerber LLP

The “Storage Week 2015″ summit held in San Diego, CA this week brought together policymakers, regulators, electric utility executives, system vendors, consultants, and other stakeholders to discuss the remarkable progress made in the last few years to deploy and integrate energy storage technologies.  The 8th annual event provided insights and practical advice regarding applications ranging from large-scale, grid-connected energy storage projects, to distribution level and behind-the-meter storage opportunities.  Noteworthy from the beginning of the conference was the fact that a significant percentage of the attendees were project developers and financiers which suggests that the energy storage sector is finally moving away from conceptual discussions and into actual deployment.

Much of the discussion at the conference focused on the efforts to integrate energy storage in organized electricity markets from New York to Texas to California.  Representatives from ISOs, RTOs, utilities, and project developers provided an overview of the progress that has been made in these parts of the country, lessons learned to date, and insights into the continuing evolution and deployment of energy storage.

Given both the location of the conference and recent regulatory and industry developments, energy storage in California figured prominently in the discussion.  California PUC (CPUC) Commissioner Carla Peterman provided the keynote address and discussed the progress made since passage of AB 2514 in 2010 which required the CPUC to adopt energy storage system procurement targets for certain California electric utilities.  Comr. Peterman and many other speakers discussed the market dynamics and industry response associated with the CPUC’s 2013 decision requiring the state’s utilities to work toward acquiring 1.325 GW of transmission-connected, distribution-connected, and behind-the-meter energy storage resources.  These policy-driven changes have enabled California and its utilities and consumers to begin to develop valuable experience with energy storage technologies, contractual arrangements, and regulatory approaches.  Representatives from the CPUC, the California independent system operator (CAISO), utilities, and project developers all emphasized that flexibility is the key at this early stage.  Further developments in California will be guided by this experience as well as CAISO’s Energy Storage Roadmap which focuses on increasing revenue opportunities for energy storage, reducing interconnection costs, and streamlining regulatory processes to improve certainty for energy storage providers and users.

Two key themes emerged throughout the various conference presentations and discussions.

First, the success of energy storage will depend largely on the development of regulatory and market approaches that recognize and reward the multiple benefits that energy storage technologies can provide.  Energy storage can be both a generation asset and a transmission asset.  It can provide grid balancing and stability through power supply management, frequency regulation, and voltage stability.  It can provide demand response and load reduction benefits.  Regulations should accommodate the multi-purpose nature of energy storage.  As one speaker commented, “Regulation should not stand in the way of innovation.”

Second, technology and industry developments will continue to create new opportunities for energy storage.  Declining prices for both renewable energy and energy storage technologies, a changing generation mix due to coal plant retirements and natural gas-fired replacements, and fundamental changes that are driving the utility-customer relationship from the provision of a commodity (i.e., kWh) to the complex, interactive “internet of energy” — these and numerous other factors align well with the multiple roles energy storage can play.

With few exceptions, there was little discussion of the role of and opportunities for energy storage outside of organized markets, particularly in the western United States outside of CAISO.  While the dynamics of organized markets don’t exist in many western states, many of the same operational realities do.  For example, western utilities struggle with the same challenges associated with integrating renewable resources and the now famous (or infamous) “duck curve” – two challenges well-suited for energy storage solutions.

This raises the question, “What is the future of energy storage in the western U.S.  outside of organized markets?”  Will the traditionally fiercely independent West chart its own, unique course for energy storage on a state-by-state basis?  Will western states pursue some form of regional cooperation that facilitates deployment of energy storage?  Or will energy storage continue to evolve in these states on a voluntary, utility-by-utility basis as it essentially has to date?  Whichever course is followed, western states and utilities can take advantage of the learning curve and experiences gained by their colleagues in the organized markets to determine what approach to energy storage will work best for the west and its wide-open spaces.

ARTICLE BY

Thomas J. Dougherty
OF
Lewis Roca Rothgerber LLP

The President’s FY2016 Federal Budget Request: Programs Relevant to Tribal Energy Development

Lewis Roca Rothgerber LLP

The White House transmitted its Fiscal Year 2016 Budget Request to Congress on February 2, 2015.  Overall, the budget includes over $7.4 billion in funding for clean energy technology programs across the federal agencies.  Most relevant to Indian tribes, tribal utilities, and tribal business are funding requests to continue existing energy and related environmental programs, as well as a few new initiatives, that support clean energy development and climate change resiliency efforts on tribal lands.  Starting with the Department of Energy, the budget requests $20 million for the Office of Indian Energy for financial and technical assistance, capacity building, and deployment of energy, energy infrastructure, microgrids, and energy efficiency projects.  A newly proposed initiative is theTribal Energy Loan Guarantee Program, with a request of $11 million.  The loan guarantee program would provide underwriting and credit subsidies for loan guarantees for tribally owned energy generation projects.

In the Department of Agriculture budget request, the Rural Energy for America Program, which tribes and tribal enterprises are eligible to participate in, maintains a budget request of $10 million to provide grants and loans for deployment of renewable energy and energy efficiency projects.  The Rural Utility Service request includes $14 million for High Energy Costs grants, and $6 billion in additional lending authority to support the deployment of rural utility renewable energy generation, energy efficiency projects, transmission and distribution power lines. Under the USDA Substantially Underserved Trust Areas (SUTA), tribes are now eligible for RUS grants and loans.  Additional USDA budget requests include programs that can be leveraged for energy development and climate change adaptation, such as the Forest Service Stewardship Contracting ($14 million), National Resource Conservation Service Technical Assistance ($1.5 billion), Farm Service Agency Conservation Program ($311 million).

The budget request for the Department of the Interior, which includes the Bureau of Indian Affairs, the Bureau of Reclamation and the Bureau of Land Management, is approximately $140 million for energy development, water energy conservation, and tribal hydro infrastructure improvement.  These programs include the Office of Indian Energy and Economic Development, with a budget request of approximately $50 million for energy, mineral, workforce development and loan guarantee program.  The BIA also proposes $50 million for climate change resiliency efforts on tribal lands.  And, the BIA has requested $27 million for resource management for Indian irrigation and dams that provide power to Indian tribal lands.  The BOR requested $161 million for water energy conservation grants.  Lastly, the Office of Surface Mining has requested $1 billion for states and tribes for reclamation of abandoned mine lands.

The Environmental Protection Agency has proposed a new initiative, with a $4 billion request, called the Clean Power State Incentive Fund.  This Fund would provide financial assistance to states and tribes to support their obligations under the proposed Clean Power Plan.  Tribes also participate in the Indian General Assistance Program, which has a budget request of $96 million.  And, tribes are eligible to participate in the Brownfield Program, a technical assistance program for state, local and tribal governments to determine better uses – including renewable energy projects – for brownfields.  The Brownfield Program request is $110 million.

Additional budget proposals that may be of interest to tribes include a permanent renewable energy production tax credit, which would be expanded to include solar technology and would be refundable.  The President has also proposed a new “Carbon Dioxide Investment and Sequestration Tax Credit” to support the commercial deployment of carbon capture, utilization, and storage technologies.  Finally, the President has proposed the “POWER + Plan” to help communities dependent on coal and fossil energy resources adapt to the changing energy landscape.  Over $55 million is proposed for Department of Labor, Department of Agriculture, EPA, Department of Commerce programs under this effort.

As Congress begins its annual budget and appropriation committee efforts,  tribes and tribal enterprises are encouraged to monitor these efforts.

ARTICLE BY

Pilar Thomas
OF
Lewis Roca Rothgerber LLP

Study Quantifies Agency Costs in Fuel Pass-Throughs

Lewis Roca Rothgerber

A 2015 American Economic Review Paper highlights the higher fuel costs passed through by regulated coal-fired power plants versus their deregulated counterparts. The paper looked at regulated power plants that have become deregulated, and found that the deregulated plants “save about $1 billion a year compared to those that remained regulated . . . because a lack of transparency, political influence and poorly designed reimbursement rates led the regulated plants to pursue inefficient strategies when purchasing coal.” The study attributes the savings to the fact that the deregulated plants have a strong incentive to shop around on price.

Interestingly, however, natural gas power plants in the study that became deregulated did not experience the same drop in fuel procurement costs:

Although power plants that burned natural gas were subject to the exact same regulations as the coal-fired plants, there was no drop in the price paid for gas after deregulation. Cicala attributed the difference to the fact that natural gas is sold on a transparent, open market. This prevents political influences from sneaking through and allows regulators to know when plants are paying too much.

There’s also a lesson about the air-quality compliance choices that utilities face at the margin:

What’s different about the buying strategy of deregulated coal plant operators? Cicala dove deep into two decades of detailed, restricted-access procurement data to answer this question. First, he found that deregulated plants switch to cheaper, low-sulfur coal. This not only saves them money, but also allows them to comply with environmental regulations. On the other hand, regulated plants often comply with regulations by installing expensive “scrubber” technology, which allows them to make money from the capital improvements.

Ultimately, Dr. Cicala draws the correct conclusion:

“Regulations are not created equal. Instead of debating for or against ‘regulation’ in general, it would be more productive to figure out how to separate the good from the bad,” said the author of the study, Asst. Prof. Steve Cicala from the Energy Policy Institute at Chicago. “If we know what forces make a regulation unsuccessful, then we can avoid designing new ones in a similar way.”

What You Need To Know: Boston and Cambridge Energy Use Disclosure Ordinances

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On July 28, 2014, Cambridge, Massachusetts enacted an energy use disclosure ordinance, joining Boston and several other cities.  The Cambridge ordinance is similar to its Boston counterpart, but contains several differences.  Property owners in each municipality should be familiar with these ordinances.

1.  Properties Covered By Each Ordinance

Cambridge:

  • Municipal buildings of 10,000 square feet or larger;
  • Non-residential buildings of 25,000 square feet or larger; and
  • Multi-family residential buildings with 50 or more units.

Boston:

  • City buildings (those the City owns or for which the City regularly pays energy bills);
  • Non-residential buildings (those located on a parcel of land with one or more buildings of at least 35,000 square feet and of which 50% or more is used for non-residential purposes, and which are not City buildings); and
  • Residential buildings (i) (a parcel with one or more buildings with 35 or more dwelling units that comprise more than 50% of the building, excluding parking, or (ii) any parcel with one or more buildings of at least 35,000 square feet and that is not a City building or a non-residential building, or (iii) any grouping of residential buildings designated by the Commission as an appropriate reporting unit).

2.  Obligations of Owners and Tenants of Covered Properties

Both ordinances broadly defined “Owner” to include owners of record or a designated agent, and net lessees for a term of at least forty-nine years.

Cambridge:

No later than May 1st of each year, all covered properties must disclose energy consumed by such property during the prior year, together with other information required by an EPA Benchmarking Tool:  (i) address; (ii) primary use type; (iii) gross floor area; (iv) energy use intensity; (v) weather normalized source energy use intensity; (vi) annual greenhouse gas emissions; (vii) water use; (viii) energy performance score; and (ix) compliance or noncompliance with ordinance.

Tenants (those who lease, occupy, or hold possession) of a covered property must comply with an owner’s request for information within thirty days or risk a fine.

Boston:

No later than May 15th of each year, owner of each covered non-city building shall accurately report previous calendar year’s energy, water use, and any other building characteristics necessary to evaluate absolute and relative energy use intensity of each building through Energy Star Portfolio Manager.

Owners must request information from tenants separately metered by utility companies in January for the previous year, and tenant must report information to owner no later than end of February, though a tenant’s failure to respond does not relieve an owner’s duty to report.

Enforcement and Penalties

Cambridge:

Failure to comply with the ordinance or misrepresentation of any material fact may result in a written warning on the first violation, and a fine of up to $300 per day for any subsequent violation.

Boston:

The Air Pollution Control Commission may issue written notice of violation, including specific delinquencies, to those failing to comply, giving thirty days within which an owner may cure the violation or request a hearing.  The Commission also may seek injunctive relief requiring an owner or non-residential tenant to comply with the ordinance.

Boston provides a sliding scale fine schedule for failure to comply with a notice of violation, depending on the type of property, which ranges from $35 per violation up to $200 per violation.  Each day of noncompliance is a separate violation, but owners or non-residential tenants may not be liable for a fine of more than $3,000 per calendar year per building or tenancy.

Both cities are actively developing programs to address climate change and adaptation.  Property owners should monitor these efforts as well as similar initiatives by federal and state agencies.

ARTICLE BY

Jennifer L. Ioli
OF
Sherin and Lodgen LLP

Senate Approves Energy Tax Extenders

Mcdermott Will Emery Law Firm

On Tuesday, December 16, 2014, the U.S. Senate passed the tax extenders bill by a vote of 76-16, extending a number of energy tax incentives through the end of the year.  The Senate’s passage of H.R. 5771 followed the U.S. House of Representatives’ (House) approval earlier this month (see our post on December 8), and the bill is expected to be signed into law by President Obama as early as this week.

The $42 billion bill includes extensions through the end of the year of nearly $10 billion in energy tax incentives, including the New Market Tax Credit in Section 45D, the Production Tax Credit in Section 45 (the PTC), and the bonus depreciation rules in Section 168(k).

Many were disappointed that some of the tax incentives – including the PTC – were extended retroactively only through the end of the year, meaning that tax payers have just a few weeks left to take advantage of them. There would have been far more certainty for companies looking to invest in renewable energy projects if the tax incentives were extended for one or more years beyond the end of 2014.  Several lawmakers suggested that the two week extension was better than nothing, but the short extension period means that Congress has merely punted the need for greater tax reform in this area into 2015.  As it stands, the energy tax incentives extended by this bill will have expired by the time Congress returns to Washington, D.C., on January 6, 2015, following its winter break.  That means that Congress may be in the same place again next year under pressure to pass a year-end bill – instead of focusing on more comprehensive reform and a possible phase-out of the PTC.

ARTICLE BY

Heather Cooper
OF
McDermott Will & Emery

Department of Interior Announces January Auction Date for Martha’s Vineyard Wind Energy Leases

Mintz Levin Law Firm

On November 24th, the Department of the Interior’s Bureau of Ocean Energy Management (BOEM) announced that it would be auctioning off four commercial leases for the Wind Energy Area (WEA) south of Martha’s Vineyard on January 29th. The area to be leased, which is identical to the area proposed in the Proposed Sale Notice published this past June, encompasses more than 1,160 square miles of open water – a tract larger than the state of Rhode Island. The project is slated to become the largest off-shore wind tract in federal waters in the United States.

Martha's Vineyard Wind Energy

If and when it is fully developed, the Martha’s Vineyard WEA has the potential to increase wind generation capacity by four or five Gigawatts (GW). According to the BOEM, which framed the announcement as part of the Obama Administration’s ongoing efforts to curb carbon pollution and mitigate climate change, a fully-developed Vineyard WEA would support 800 turbines and produce enough energy to power 1.4 million homes in the United States. Secretary of the Interior Sally Jewell said the auction will “triple the amount of federal offshore acreage available for commercial-scale wind energy projects,” making it the largest competitive wind energy lease sale to date.

Several advocacy organizations, including the New England Fishery Management Council and the Massachusetts Audubon Society, had previously voiced concerns about possible harm to aquatic and aviary life, but the Bureau’s most recent Environmental Assessment (EA) concluded that “reasonably foreseeable environmental effects associated with the commercial wind lease issuance and related activities would not significantly impact the environment.”

Twelve companies are qualified to bid for the four leases, including Deepwater Wind New England, EDF Renewable Development, Energy Management, Fishermen’s Energy, Green Sail Energy, IBERDROLA RENEWABLES, NRG Bluewater Wind Massachusetts, OffshoreMW, RES America Developments, Sea Breeze Energy, US Mainstream Renewable Power (Offshore) and U.S. Wind. For more information about the auction announcement, please visit the BOEM’s website.

ARTICLE BY

Sahir Surmeli
Jordan M. Collins
OF
Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C.

FERC Approves Fourth Settlement for 2011 Southwest Blackout Against Western Area Power Administration

SchiffHardin-logo_4c_LLP_www

On November 24, 2014, FERC approved a settlement with Western Area Power Administration – Desert Southwest Region  (Western-DSW) related to its involvement in the blackout in the southwestern U.S. on September  8, 2011.  This blackout left more than 5 million people in Southern California, Arizona, and Baja California, Mexico without power for up to 12 hours.  According to FERC’s press release on the Western-DSW settlement, this is the fourth settlement arising out of this blackout.

We have reported on two prior settlements, one involving Arizona Public Service Company on July  7, 2014 and one involving Imperial Irrigation District. A third settlement involved Southern California Edison Company and was approved on October 21, 2014. Two other investigations involving the California Independent System Operator and Western Electric Coordinating Council  remain outstanding.

The settlement with Western-DSW is unique in that it involves no monetary penalty.  This is in keeping with the DC Circuit’s recent decision in Southwestern Power Administration et al. v. FERC, 763 F3d 27 (DC Cir 2014) (SWPA). As we previously reported, the Court in SWPA held that FERC could not impose monetary penalties on a federal power marketing administration for Reliability Standards violations. This is in marked contrast to the $650,000 monetary civil penalty assessed against Southern California Edison Company and the $2,000,000 monetary civil penalty assessed against Arizona Public Service Company.  Similarly, the settlement with Imperial Irrigation District involved a monetary civil penalty of $3,000,000. FERC reached this settlement with Imperial Irrigation District three weeks before the SWPA decision was issued, and it is not clear whether that decision, which was based on federal sovereign immunity precedent, would extend to state public power entities like Imperial Irrigation District. As with the other three settlements, the Western-DSW settlement provided for investment in significant reliability improvements, but unlike the other three settlements, the Western-DSW settlement does not identify a monetary value for Western-DSW’s reliability improvements.

The Western-DSW settlement involved four alleged violations involving three Reliability Standards. These alleged violations arose out of a fault on a major transmission line owned and operated by Arizona Public Service Company and Western-DSW’s inability to handle the resulting increased flows on parallel transmission paths in which Western-DSW owns and operates transmission facilities. These increased flows resulted in voltage deviations and overloads on Western-DSW’s system which in turn required load shedding. After its investigation, FERC and NERC staffs found that Western-DSW had violated the following requirements:

  • TOP-004-2 R1, because Western-DSW did not operate its system within established system operating limits

  • TOP-004-2 R2, because Western-DSW did not operate its system to prevent severe low voltage conditions and loss of load that resulted from the loss of the Arizona Public Service Company line

  • TOP-008-1 R2, because Western-DSW did not operate its system to prevent system operating limit violations by identifying and studying the contingency related to the loss of the Arizona Public Service Company line

  • VAR-001-1 R9 because Western-DSW did not maintain sufficient reactive resources to support its voltage in the event of a contingency related to the loss of the Arizona Public Service Company line

While stipulating to the facts surrounding the September 8, 2011 event, Western-DSW noted in the settlement that it neither admits nor denies that it violated any Reliability Standards.

Although as noted above the settlement does not identify any monetary penalties, the “Remedies and Sanctions” section of the settlement describes at length several reliability improvements instituted by Western-DSW. To improve its operations within established system operating limits, Western-DSW committed to perform seasonal, next-day and real time studies to verify its system operating limits and interconnection reliability operating limits, to coordinate with its neighboring transmission systems and with its reliability coordinator on any areas of concern related to those limits, and to establish alarms, procedures and trainings related to real-time study of these limits. Western-DSW also committed to similar efforts associated with monitoring real-time voltage and reactive power support, and it joined with other facility owners to install a total of 90 MVar of reactive support. As with the other settlements arising out of the September 8, 2011 Southwest Blackout, the Western-DSW settlement included reliability improvements that do not appear directly related to the underlying alleged violations; these improvements addressed areas such as: situational awareness, long term planning, enhancing operational studies to predict system performance within appropriate phase angle limits.

Although the settlement makes clear that many of the reliability improvements committed to by Western-DSW are complete, the settlement provides that Western–DSW will submit status two semi-annual reports to FERC and NERC staffs regarding its mitigation activities and its ongoing compliance with the Reliability Standards.

ARTICLE BY

Joel G. deJesus
OF
Schiff Hardin LLP

The UK 14th Onshore Oil and Gas Licensing Round

Andrews Kurth

At the end of July 2014, the UK government published application criteria and terms for the 14th onshore oil and gas licensing round. This will be key to the aspirations of would-be shale gas developers in the UK. Onshore licences are available in areas including the Bowland Shale in the north of England (where the British Geological Society estimates a potential gas-in-place resource of 1,329 trillion cubic feet (tcf) alone) and the Midland Valley in Scotland.

Applications for new licences under the 14th round can be made until 2:00 p.m. 28 October 2014. This is the first round of onshore licensing in the UK for six years, and the resultant final licence awards are expected to be announced in the next 12 to 18 months. The level of interest expressed in these new licences will be a good barometer of how the industry regards the steps which the UK government has been taking to promote the growth of shale gas in the UK.

Additionally, new model clauses for onshore licences have been issued in the Petroleum Licensing (Exploration and Production) (Landward Areas) Regulations 2014, which came into force on 17 July 2014. These model clauses are intended to promote unconventional oil and gas exploration and production and include several new provisions which are aimed at affording greater flexibility to licensees – these provisions relate to “drill or drop” elections, the term of the licence (with revised focus on extensions and retention areas) and splitting horizontal layers on surrenders.

The new model clauses recognise the different attributes of shale gas exploration and production programmes and that shale gas deposits typically have a much wider geographic footprint when compared to conventional oil and gas resources. Whilst greater flexibility is given to licensees under the new model clauses, there are also tighter controls over proposed project activities and timescales, with the intention of accelerating the outturns of planned exploration and production plans. 

The new model clauses are also intended to promote the findings of the recent Wood Review relating to maximising economic recovery.

There is also a new requirement for a detailed Environmental Awareness Statement (“EAS”) to be submitted with licence applications. The EAS is intended to demonstrate a licence applicant’s understanding of the environmental sensitivities relevant to the area proposed to be licensed. This requirement is intended to promote a successful interface with ecological sensitivities.

The UK government has taken a number of other steps to promote shale gas development in the UK, including introducing localised fiscal incentives to support the development of shale gas exploration pads. However, significant other issues still remain to be addressed by would-be shale gas developers, including obtaining planning permission to drill and hydraulically fracture test wells and managing often vociferous local public opposition to shale gas development. We have previously considered how UK onshore shale gas developments might be structured (see Notes From The Field – Issues 3 and 6).

Many challenges still lie ahead. Oil & Gas UK, the trade association that represents the interests of the UK’s offshore oil and gas industry, has given a cautious welcome to these new developments:

“There are a number of synergies between the offshore oil and gas industry and the onshore sector. Many of the techniques and some of the services required to recover land based unconventional shale gas already exist in the offshore oil and gas sector and should be readily transferable. There is scope for making these learnings and expertise from the offshore sector quickly transferable to operators developing onshore oil and gas resources. The new Oil and Gas Authority, which will govern both onshore and offshore industries, should ensure consistency of approach wherever applicable.”

ARTICLE BY

Peter Roberts
 
OF 
Andrews Kurth

Energy and Environmental Law Update: Week of 8/25/2014

Mintz Levin Law Firm

Now that summer is drawing to a close, let’s check in on one important bill that lost momentum just as the summer was beginning. Remember the Senate Finance Committee’s tax extenders package (S. 2260), which the committee marked up on a bipartisan basis in mid-May? The one that was poised to pass the Senate but that surprisingly failed to reach cloture after Senate leadership blocked Republican amendments on the bill? At the time, congressional staff and lobbyists—and even Majority Leader Harry Reid (D-NV) —suggested that the extenders package would come up again in the lame duck session after the November election. The House was not expected to vote on an extenders package before then anyway, so the Senate delay would not really impact the timing of final passage of this two-year extension of more than 50 tax provisions.

Well, that was then. Today, almost two months before the mid-term elections, the future of the clean energy provisions in an extenders package—particularly the production tax credit (PTC) and investment tax credit in lieu of the PTC—depends a great deal on which party wins control of the Senate. Republicans are more confident that they can win the necessary six seats to take back the top chamber; and if they do, they will have more leverage in the lame duck about what the contents of an extenders package would be. The $84 billion EXPIRE Act of 2014 not only extends the PTC by two years but also extends key clean energy depreciation benefits and tax credits, including a $1-per-gallon credit for biodiesel and a 50-cent-per-gallon credit for alternative fuels. Senate Democrats strongly support the clean energy provisions. Certain Republicans, such as Chuck Grassley (R-IA), remain staunch supporters of the PTC and biodiesel credits, but many other Republicans are eager to eliminate or scale back the PTC and other clean energy provisions. If Senator Orrin Hatch (R-UT) learns he will be chairman of the Finance Committee next year in a Republican chamber, he has less of an incentive to work with current Chairman Ron Wyden (D-OR) and Democrats during the lame duck session. He can simply hold out and put forward his own extenders bill next year with popular provisions like the research and experimentation (R&D) credit and without clean energy incentives.

The extension of a handful of relatively popular and less controversial business and individual extenders such as the R&D credit and bonus depreciation are more assured. House Republicans, as part of a “tax-reform-lite” effort, have passed several bills making select provisions such as these permanent. For clean energy advocates, they have to cling to the more popular parts of the overall package and make sure their provisions are not trimmed away when Congress eventually takes it up. The business community, which wants many of the non-energy provisions in the EXPIRE Act extended, also must be much more vocal if the bill is to rise to the front of the agenda.

If Democrats do manage to hold onto control of the upper chamber, they very likely will be dealing with a reduced majority, and that too will give Republicans more leverage. With all the competing priorities in a very short legislative period, it will be difficult for the package to be enacted before the end of the year. Another retroactive extension in early 2015 could be possible. Congress has let the PTC lapse several times since 1992 before renewing it again. While it’s hard to avoid feeling a feeling of déjà vu when faced with another “will-they-or-won’t-they” end-of-year extension, this time also seems different. Many legislators thought the previous PTC extension would be the last one, so the stakes are high. Anti-PTC campaigns financed by conservative groups and utilities ratchets up the pressure on lawmakers. One possible way to blunt some Republican opposition would be to modify the PTC and either reduce the amount of the credit or include a deadline by which projects must complete construction—or both.

Several scenarios exist where even a change of control in the Senate would not preclude the passage of a tax extenders package. A short-term extension would give lawmakers some breathing room to debate tax reform. Some Republicans from wind-friendly states might prefer the clean energy provisions to pass under a Democratic watch rather than under Republican leadership in the new Congress. In this optimistic scenario, the lame duck session could mirror the productive session of 1980.

Ironically, election results in any one of three bio-energy and wind states–Colorado, South Dakota, and Iowa—could help decide the balance in the Senate and the fate of clean energy tax credits.

ARTICLE BY

Bryan M. Stockton
 
OF 
Mintz, Levin, Cohn, Ferris, Glovsky and Popeo, P.C.

SEC Brings Fraud Charges Against Oil and Gas Company and Its CEO

Katten Muchin Law Firm

On August 4, the Securities and Exchange Commission instituted cease-and-desist proceedings against Houston American Energy Corp., an oil and gas exploration and production company, and John F. Terwilliger, its CEO, for making fraudulent claims about the company’s oil reserves. According to the SEC, during late 2009 and early 2010, Houston American raised approximately $13 million in a public offering and saw its stock price increase from less than $5 to more than $20 per share after fraudulently claiming that a Colombian exploration concession, in which Houston American owned a fractional interest, held between one billion and four billion barrels of oil reserves that would be worth the equivalent of $100 per share to investors. The SEC alleged that those estimates lacked any reasonable basis and were falsely attributed to the concession’s operator, who actually had much lower estimates. The SEC order charged Houston American and Mr. Terwilliger with violations of Section 10(b) of the Securities Exchange Act of 1934 (Exchange Act); Rule 10b-5, Section 20(b) of the Exchange Act; and Section 17(a) of the Securities Act of 1933. The SEC seeks a civil penalty and disgorgement from Houston American, and to prohibit Mr. Terwilliger from acting as an officer and director of the company.

Matter of Houston American Energy Corp. et al, Admin. Proceeding No. 3-16000 (Aug. 4, 2014).

ARTICLE BY

Michael S. Gordon
Ashley H. Jones
Of
Katten Muchin Rosenman LLP