Buying into renewable energy

The results of the 2008 election are in and strongly suggest that the federal government will soon be taking actions that more forcefully promote the development of renewable energy resources and transition the economy away from dependence on coal and imported oil. While the demand for carbon-based energy resources is unlikely to fall significantly in the near-term, the profitability of investments in such resources may well decline as greater and greater amounts of energy produced by alternative resources are brought online.

A number of large multinational oil and gas companies, such as BP and Chevron, have invested billions of dollars in developing alternative energy sources over the past several years. They, as well as others in the oil and gas industry—both large and small—will doubtless be strongly considering further investments in the non-hydrocarbon sources of energy as a means to diversify their business and secure future profitability.

In deciding whether to make investments in non-hydrocarbon based forms of energy and, if so, how to allocate their investment dollars between such forms of energy and more traditional fossil fuels, oil and gas companies must weigh a number of factors, including the impact of renewable portfolio standards that have been enacted in a number of states; the benefits and limitations of the federal renewable energy production tax credit and other federal and state tax incentives and subsidies; the possibility that a federal renewable portfolio standard and cap-and-trade system for carbon emissions will be adopted; a myriad of issues raised by siting decisions, long queues for interconnections, an electric transmission grid that already is capacity constrained; and the role that natural gas, nuclear, clean coal, domestic oil, and carbon capture and sequestration technology will play in the years ahead.

Twenty-six states have adopted mandatory renewable or alternative portfolio standards (RPS) that require a specified percentage of electricity that utilities deliver to come from renewable/alternative resources by a certain date. Several other states have adopted RPS goals or are considering the adoption of mandatory RPS standards.

Among the more ambitious state RPS adopted to date, California will require that renewable resources account for at least 20% of each utility’s retail sales of electricity by 2010 and at least 33% by 2020, including increases of 1% per year; New York will require 25% by 2013 and has issued a proposed rulemaking that would allow utilities to meet those thresholds by purchasing renewable energy credits from eligible facilities; Nevada will require 20% by 2015; Colorado, Connecticut, and Delaware will require 20% by 2020 or earlier; Oregon will require 25% by 2025; Minnesota will require 25% by 2025; New Jersey will require 22.5% by 2021; and Maryland will require 20% by 2022.

Progress toward meeting state RPS standards has been slow to date, and that presents both investment opportunities and risks. It presents opportunities because the existence of enforceable RPS standards should guarantee renewable resources a minimum market share, regardless of whether the price of renewable energy is higher—perhaps even significantly higher—than electricity produced from fossil fuels.

It presents risks because of the possibility that emerging technologies, such as clean coal and carbon capture and sequestration, as well as existing ones, such as combined-cycle natural gas-fired turbines and nuclear, will fill the gap before renewables can, and because states are less likely to enforce RPS standards if utilities are unable to find adequate supplies of renewable energy at prices the market can bear, assuming utilities can find adequate supplies at all. In some areas, the trading of state-issued renewable energy credits may allow fossil fuel-fired generation facilities to retain their current market share, notwithstanding being subject to RPS standards.

The much ballyhooed federal production tax credit (PTC) for renewable energy can significantly mitigate the commercial risks of investing in renewable generation resources. The PTC is, however, subject to a number of limitations that must be considered and appropriately weighed. The PTC provides a tax credit of 1.5 cents per kilowatt-hour for most forms of renewable energy and was extended in October 2008 as part of the Emergency Economic Stabilization Act of 2008.

While history and the 2008 election suggest that the PTC will be extended again in the future, perhaps even for more than one year at a time, the PTC currently in effect does not apply to wind and clean coal plants placed in service after Jan. 1, 2010; to solar, biomass, or geothermal plants placed in service after Jan. 1, 2011; or to marine or hydrokinetic plants placed in service after Jan. 1, 2012. Even if a plant itself can be readied for operations by the applicable cutoff date, the plant may not qualify as being “placed in service” if there is no interconnection with the transmission grid in place over which it can deliver its output.

Even as to generation plants qualifying for the PTC, the credit applies for only a 10-year period and is subject to a mandatory phase-out based on changes in reference prices and inflation. In addition, the amount of PTC is reduced for entities receiving state or federal grants, tax exempt bonds, state or federally-subsidized financing, or other federal tax credits.

Determining whether an investment in renewable resources will benefit from the PTC and, if so, by how much, is an important consideration that should be evaluated in consultation with counsel based on the totality of circumstances surrounding an investment, including its timing, the specific statutory language pertaining to the chosen renewable resource, and relevant Revenue Rulings of the Internal Revenue Service.

While there are a number of other federal, state, and local incentives and subsidies designed to promote the development and use of renewable energy, they are sometimes applicable only to small-scale projects or distributed generation or for only a limited period of time. For example, the federal government provides a business energy tax credit for small wind turbines with a capacity of 100 KW or less.

Colorado has authorized its counties and municipalities to offer property and sales tax rebates to residential and commercial property owners who install renewable energy systems on their property. On the other hand, Florida has adopted a renewable energy technologies investment tax credit of 75% for capital costs, operations and maintenance costs, and research and development costs incurred between July 1, 2006 and June 30, 2010 in connection with hydrogen-powered vehicles and hydrogen vehicle fueling stations, commercial stationary hydrogen fuel cells, and production, storage, and distribution of biodiesel and ethanol.

Before making investments dependent on such incentives and subsidies, companies should obtain confirmation from counsel and/or the relevant government agency as to the applicability of such incentives and subsidies to the proposed project, as well as clarification of any important restrictions or time limitations that may apply.

The possibility that a national RPS and cap-and-trade system will be adopted provides additional opportunities and risks that should be evaluated. Like state RPS standards, a national RPS regime would likely increase the profitability of using renewable resources to generate electricity by locking in a minimum guaranteed demand for such resources while the supply is still comparatively light. However, renewable plants that are in operation or in development at the time the national RPS is adopted may not qualify for carbon credits and, therefore, may not be able to benefit fully, if at all, from a cap-and-trade system.

An additional set of very important issues that must be evaluated carefully with respect to any investment in a power plant that will be run by renewable resources is siting, interconnection, and transmission. Aside from the normal commercial considerations that always must be weighed in choosing a facility site, the siting of a renewable project must be determined in light of the competing subsidies and incentives that are offered by various states, the environmental issues associated with each location under consideration, the availability of adequate transmission capacity in each location, and the length of the interconnection queue with the nearest transmission operator.

At this time, neither federal nor state law provides power plants fueled by renewable resources with expedited or preferential access to interconnections or transmission.

Each of the nation’s regional or independent transmission system operators currently has a substantial backlog of interconnection requests, and the wait for an interconnection can be quite long. As of April 21, 2008, the interconnection queue in the PJM control area consisted of 360 generation projects totaling 84,164 MW; the queue in California consisted of 264 projects representing approximately 77,614 MW; the queue in the Midwest ISO control area consisted of 348 projects totaling approximately 80,000 MW; the Southwest Power Pool had a queue of 106 projects representing approximately 26,811 MW; ISO New England had a queue of 104 projects representing approximately 13,400 MW; New York had a queue of 138 projects representing more than 26,000 MW.

In addition, as of Feb. 21, 2008, ERCOT had a queue of 222 projects representing approximately 100,000 MW.

Nor are renewable power projects exempt from environmental review. The choice of a site that proves highly controversial can severely extend the timeline for environmental review, if not eviscerate a project altogether. The first offshore wind farm proposed in the country illustrates the importance of carefully selecting the site for any renewable energy project. That project, Cape Wind, is a proposed wind farm in Nantucket Sound that has encountered fierce, organized, and well-financed resistance, and has been unable to obtain final environmental clearances despite a six-year effort.

Finally, oil and gas companies must weigh the risks of investing dollars in one or more forms of renewable energy resources when there are other technologies, both renewable and non-renewable, that may end up achieving market dominance and even greater governmental support. Advances in clean coal and carbon capture and sequestration technology could seriously undermine the economics of renewable projects.

In addition, the combination of enhanced recovery of natural gas from tight sands, coal-bed methane, and shale, along with an influx of natural gas from an Alaskan pipeline and liquefied natural gas import terminals, could drive the price of natural gas down to levels with which renewable resources would be poorly positioned to compete.

In short, while it may be wise for oil and gas companies to diversify their businesses by investing heavily in renewable resources and other forms of alternative energy, they should do so with a comprehensive and thorough understanding of the legal and regulatory regimes in which they will be operating. The profitability of such investments will hinge on a number of factors, only some of which are known and can be effectively weighed at this time. But it would be folly to invest in such resources without a complete understanding and careful consideration of the opportunities and risks posed under the current body of laws and regulations.

About the author

Glenn Benson[[email protected]], an attorney in the environment and natural resources practice of Perkins Coie LLP, focuses on providing solutions to regulatory and investment challenges and issues faced by all segments of the oil and gas industries.