Industry analysts take stock
by Nancy Spring, managing editor
When the Energy Policy Act was signed into law in August 2005, analysts hailed it with a mixture of celebration and relief. The first energy bill in nearly 13 years, it included an Electricity Title that encouraged generation fuel diversity, granted new authority to federal agencies to help ensure bulk power system reliability, and altered the M&A landscape in hopes of encouraging new investment in transmission and generation.
The implementation list for FERC was a long one indeed, with deadline after deadline, and by all accounts, the Commission was up to the task. The Department of Energy came through too, completing its assigned congestion study, the first step toward designating, if needed, national interest electric transmission corridors, and NERC played its role to the hilt, too, becoming the country’s first Electric Reliability Organization, ready to develop mandatory reliability standards with the authority to enforce them.
In our coverage of the Act in the September/October 2005 issue, we wrote, “Whether the long-awaited legislation brings the sea change many were hoping for or just another watered-down affirmation of the status quo remains to be seen.” Eighteen months later, we have invited four industry analysts to help assess progress so far. We’ll keep tracking the story, too, because recent changes in Congress portend a few tidal waves of their own.
Leveraging Tax Incentives and Credits
The Energy Policy Act of 2005 recently celebrated its first anniversary, yet few companies have taken advantage of the tax incentives and credits it offers to promote much-needed energy investments. While the incentives and credits alone are not likely to alter a company’s plans, it is a missed opportunity not to fully leverage them.
As utility-related capital investments grow rapidly in the coming years, and companies expand generation, transmission and distribution and make environmental improvements, it will be important to fully understand the opportunities and leverage the benefits afforded by the Act. These include $14.6 billion in tax incentives over a 10-year period for investments in infrastructure reliability, environmental controls and diversification of the nation’s electric supply.
The August 2003 blackout in the Northeastern United States demonstrated the immediate need to modernize and expand the aging North American electric transmission grid. The North American Electric Reliability Corporation (NERC) projects 5,600 miles of transmission lines will have to be built by 2008, with another 5,000 miles by 2013.
Many of the expenditures for new transmission lines will qualify for incentives outlined in the Act. Twenty-one percent or $3.12 billion of the tax incentives outlined in the Act are specifically allocated for reliability. Reliability incentives include shortened recovery periods for electric transmission lines (15-year Modified Accelerated Cost Recovery System) and natural gas distribution lines (7-year MACRS); favorable net operating loss carryback rules for taxpayers with qualifying investments in new electric transmission or pollution control assets; and the extension, until 2008, of the beneficial income deferral rules for qualified electric transmission transactions.
The electric power industry is expected to invest $50 billion to comply with more stringent air pollution emissions controls outlined in the Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR).
California is leading the way by becoming the first state to tackle greenhouse gas (GHG) emissions. Much like the EPA’s successful acid rain program to limit SO2 and NO2, California’s “cap and trade” system would pair a state-wide cap on GHG emissions with a robust emissions trading exchange where emission sources could buy and sell credits necessary to comply with the new lower emissions levels. Other states are likely to follow. Although there are no tax incentives specifically identified with GHG emissions allowances, in conjunction with SO2 trading, the IRS issued a ruling indicating that such allowances were eligible for like kind exchange treatment.
To comply with regulations, including those relating to New Source Review provisions of the Clean Air Act that were upheld by the courts last summer, many utilities have announced capital investment programs to install pollution control facilities. Many of these investments may qualify for incentives or expensing for federal and state income tax purposes. Section 169 of the Internal Revenue Code was amended to allow accelerated amortization (84 months) for certain atmospheric pollution control facilities placed in service after April 11, 2005.
Electric Supply Diversification
Nuclear energy remains controversial and many companies have shied away from the investment due to the financial risk. To encourage the development of a next-generation nuclear plant, the Act appropriates $1.25 billion for the development of a prototype next-generation nuclear power plant to produce electricity, hydrogen or both.
The U.S. Department of Energy’s National Renewable Energy Laboratory reports that about 430,000 customers now participate in green power initiatives, up 20 percent from 2004. While renewable energy remains a miniscule part of the nation’s power supply, the combination of improved economics and growing demand is creating traction in new renewable investment. To aid the momentum, the Act outlines $3.16 billion of incentives to promote investment in renewable and clean energy.
The Act also sets aside $2.95 billion for clean coal, accounting for 20 percent of the tax incentives outlined in the Act. In addition, the Clean Coal Power Initiative allocates $200 million in funding annually between FY2006 and 2014 for projects that promise to markedly increase the efficiency, environmental performance and cost competitiveness of current coal technologies. The centerpiece of this incentive is the investment tax credit for the construction of integrated gasification combined cycle projects and advanced coal-based generation (Section 48A) and qualifying gasification projects (Section 48B). The credits earmarked for these projects total $1.95 billion.
The Act supports the expansion and diversification of the U.S. energy supply, promoting much-needed investment in U.S. energy infrastructure and advocating efficiency improvements and conservation strategies. While the Act’s tax incentives alone are not likely to spur investment in these areas, it would be irresponsible of companies not to take full advantage of these credits where capital investments are needed or required.
It is presumed that a Democratic-controlled Congress will bring a stronger environmental agenda and perhaps a mindset to nudge companies to take advantage of the incentives to build energy infrastructure and develop new, cleaner energy sources. With continued increases in the price of oil and natural gas, our dependence on foreign energy sources and the related environmental concerns around fossil fuel emissions and GHGs, we can expect to see another round of energy legislation in the next session of Congress.
Is Progress Too Slow?
EPAct was a significant policy achievement, but what progress has been made to benefit consumers and the utility industry as a whole? Our assessment focuses on three primary goals of the Act: diversifying fuel supplies, increasing capital investment, and improving electric reliability.
The Act intended to drive fuel supply diversification to increase U.S. energy independence, reduce the effects of fuel price spikes, and help speed the shift toward a more environmentally friendly generation portfolio. Tax incentives provided by the Act help improve the business case for investing in new fuel and generation sources, but alone they are not sufficient.
For example, while nuclear power generation is widely regarded as a key to achieving greater fuel diversity, major questions on the storage of spent nuclear fuel remain unresolved, resulting in continued caution on the part of investors and utilities. The Act also provided incentives for innovation in clean coal technologies and called for state standards for fuel sources and generation efficiency, but there has been limited action at the state level in these areas, slowing progress in fuel diversity.
The Act reduced restrictions on utility ownership to drive more flexibility in utility company structures and business models. These changes were expected to make the industry more attractive to both traditional and non-traditional investors, driving M&A activity and resulting in efficiencies from consolidation and business model innovation.
While such activity has in-creased, some recent M&A proposals have been withdrawn, at least in part because of issues related to varying state approval requirements and because some states are demanding aggressive concessions before approving deals. With the resulting uncertainties about business model flexibility and industry consolidation, new investment in the industry is not increasing as quickly as anticipated.
The Act has several provisions designed to increase reliability, including mandated standards and incentives for grid improvements. A clear intent of the Act was to move from the old paradigm of making investments to build the rate base to making efficient investments that increase reliability.
But little progress has been made in this area, even though technology advancements are enabling an intelligent grid that can increase reliability and efficiency and provide greater capacity. Utilities remain reluctant to invest in these innovative grid improvements because of concerns about investment recovery, public opposition to new transmission projects, and insufficient regulatory coordination among the states.
The Act was an excellent first public policy step in improving U.S. energy reliability, independence and efficiency, but consumers and the utility industry have not yet seen sufficient benefits. An important next step at the federal level would be to end the uncertainty about spent nuclear fuel storage. At the state level, implementation would improve with more coordination among state regulators, a longer-term view on the benefits of merger and acquisition activity, and incentives for development of the intelligent grid, improving reliability and efficiency.
Transmission Investment Incentives
A reliable electric transmission and delivery system is crucial to our nation’s infrastructure. Recognizing this need and in part reacting to the blackouts that occurred in summer 2003 that exposed certain frailties in the nation’s transmission system, Congress as part of the Energy Policy Act of 2005 sought to help ensure that the electric transmission grid would be expanded and that such expansions would be funded, as well as reliably operated. The Federal Energy Regulatory Commission and the Department of Energy have taken steps to implement these provisions. Where do we now stand in these implementation efforts?
We examine two of the key provisions that FERC and DOE are implementing as part of the transmission incentives contained in the Act. First we review the status of FERC’s expanded authority to site interstate electric transmission facilities and then discuss the status of the transmission funding incentives. (The reliability provisions of EPAct are beyond the scope of this article.)
Siting of Interstate Electric Transmission Facilities
Congress was concerned that in some cases electric transmission facilities were not being constructed due to opposition at the local or state level. Unlike FERC’s authority under the Natural Gas Act, prior to the enactment of the act, FERC did not have statutory authority to site electric transmission lines under the Federal Power Act. Under the Act, FERC may issue permits for siting new electric transmission facilities under certain circumstances where the interested party has been unable to obtain the necessary local or state permits. However, DOE must first conduct a study of transmission congested areas and then issue a report designating certain areas of the country as “national interest electric transmission corridors” (National Corridors). DOE issued its first report in August 2006, which, among other things, identified congestion areas.
In November 2006, FERC finalized its electric transmission siting rule for applying to FERC for permits to construct facilities within National Corridors. Significantly, FERC’s rules bar both initiation of prefiling as well as a formal application for a construction permit in the first year of a state proceeding so that the state siting agencies have one clear year to site electric transmission facilities in National Corridors. More controversial, FERC’s rule interprets the scope of its authority to act when a state siting body has “withheld approval” for a year to encompass both state failure to act and denial of an application.
FERC may only issue permits for construction or modification of transmission facilities within National Corridors under certain conditions. FERC, for example, must find that the state does not have the authority, delayed approval or conditioned approval in such a way that would significantly reduce transmission congestion, and is not otherwise economically feasible.
Once FERC has issued a permit, if the permit holder cannot acquire the necessary rights of way from the affected landowners, the permit holder may obtain such right of way with the exercise of a new federal right of eminent domain. DOE will act as lead agency to coordinate all authorizations of environmental reviews. States are permitted to enter into interstate compacts establishing regional transmission siting agencies to facilitate coordination among the states for the purpose of siting future transmission facilities. As of this time, no permit has yet been sought from FERC.
It is still too early to tell whether project developers will apply for permits from FERC to site new transmission facilities within the National Corridors. That will in part depend upon whether they have run into roadblocks at the federal or state level.
Transmission Infrastructure and Investment
Besides granting FERC expanded authority to site transmission lines, Congress also believed it necessary to establish financial incentives for transmission service rates, in order to spur development of new interstate transmission facilities by jurisdictional public utilities. Congress in fact included some very specific details regarding the types of incentive rates that FERC was to establish as part of a new rulemaking. Among other things, FERC’s new rules must (i) provide for rates of return that will promote more capital investment in expanding and improving the nation’s transmission system, (ii) encourage deployment of new technologies in the sector and (iii) allow for recovery of prudently incurred costs related to transmission infrastructure investment.
FERC has issued its Final Rule to implement the incentive rates. On Dec. 21, 2006, the Commission issued its Rehearing Order, addressing various issues raised by parties in the rulemaking proceeding.
It remains to be seen how FERC will implement its new rules on these incentive rates and whether these new rules, in conjunction with FERC’s new siting authority, will lead to construction of new facilities that otherwise would not have been built without incentive rates. Indeed, roughly 80-90 percent of a public utility’s rates are set by state commission, not by FERC, and states still play an important role in many areas of the country in initially reviewing the need for and siting of new transmission lines.