Energy Legal Blog

While climate change legislative proposals and potential energy legislation continue  to muddle in the halls of Congress, individual states keep on creating their own requirements for checking green-house gas emissions and requiring greater use of renewable energy within their borders.  Whether this will lead to a mosaic of disparate standards and obligations or eventual standardization across state lines remains to be seen.

Despite relatively limited renewable energy production potential and a sharply growing population in Florida, Governor Charlie Crist (R) recently issued several executive orders intended to reduce greenhouse gas emissions and increase renewable energy use.  The orders direct the state’s public service commission to initiate a rulemaking intended to achieve a renewable portfolio standard (RPS) of 20%; call for capping utility greenhouse gas emissions at their 2000 level by 2017, reducing them to their 1990 level by 2025, and to 20% of their 1990 level by 2050; and implement other measures such as new interconnection standards, net metering, and requiring state agencies to take additional energy efficiency measures.

Hawaii already has an RPS, and its legislature recently added climate change legislation.  Its objective is to reduce the level of greenhouse gas emissions in the state to 1990 levels by 2020.  New Jersey – a densely populous state with limited renewable energy production – also added climate change legislation to its existing RPS requirements.  Under the new law, greenhouse gas emissions would be reduced approximately 15% below 1990 levels by 2020 and 80 percent by 2050. 

California and Washington already have both an RPS and climate change legislation.  While the mandates of all these states vary, they all push far into the future – 2050 – the most severe level of cuts, a move that may be reflect the technological challenges, but also resonates like a promise to start a diet tomorrow, or later. 

In a July 19 proposed Policy Statement, the Federal Energy Regulatory Commission (FERC) floats the idea of substituting cash distributions that natural gas pipelines, organized as master limited partnerships (MLP), make to their partners for the corporate dividends that the agency uses in discounted cash flow (DCF) analyses to set regulated equity returns for natural gas pipeline companies.  The industry has long requested and anticipated this policy development since, increasingly, natural gas pipelines (like their oil pipeline cousins) have switched from traditional C-corporations to lower-taxed MLPs — from twice-taxed corporate dividends to once-taxed MLP cash distributions that tend to be higher.  If the Policy Statement is adopted, it may also affect equity returns of electric transmission systems, a number of which are considering switching from C-corporations to (MLP-comparable) real estate investment trusts (REIT).  To be considered, public comments on the proposed Policy Statement must be submitted within 30 days of publication in the Federal Register — sometime in late August.  A final Policy Statement is expected before year’s end.

Since corporate dividends distribute a portion of earnings, dividends have traditionally been a dependable indicator of where regulated returns on equity should be set, namely at a level that permits utility investors to earn a reasonable return on investment while also providing adequate funds for future growth.  Use of MLP cash distributions instead of corporate dividends is controversial in that those distributions can, and not infrequently do, exceed earnings and provide not only a return on investment but also a return of investment, which, if used in a DCF analysis, would award higher equity returns to natural gas pipelines, and possibly double recovery of some investments in the form of both equity return and depreciation.    (Presumably the same would be true if the cash distributions of an electric transmission REIT were used in a DCF analysis to set a transmission utility’s equity return.)

To address these concerns, FERC proposes two limitations on the use of MLP cash distributions in DCF analyses.  First, in order to be eligible for use in a DCF analysis, MLP cash distributions would be capped so that they could not exceed the reported earnings of an MLP natural gas pipeline — a return on, but not of, investment.  Second, a proponent of using MLP cash distributions in a DCF analysis would be required to produce and analyze multi-year data on the selected MLPs to show that cash distributions were not excessive and that earnings and growth were sustainable over time.

Among energy initiatives that Congress is considering this summer, one would highlight smart grid technology on the national stage.  In hopes of not only making the U.S. grid more reliable and efficient, but also more secure and independent—often-used phrases in Congressional energy circles—the Energy and Commerce Committee approved one measure that would establish a federal Grid Modernization Commission to implement smart grid technologies. 

The proposed nine-member Commission would monitor smart grid developments, develop common standards and protocols for smart grid technologies, identify barriers to implementation and propose solutions, coordinate federal and state agencies to implement smart grid efforts, and report to Congress biennially on the progress made in modernizing the electric grid system. 

The measure would also create a federal matching grant program, funded with $250 million for 2008 and $500 million for each of the years 2009-2012, to reimburse one quarter of the costs of certain smart grid investments.  The measure would amend section 111(d) of the Public Utility Regulatory Policies Act of 1978 to require states to consider regulatory standards that would allow utilities to include smart grid investments in rates, “decouple” utility profits from the volume of electricity sold, and require utilities to make time-sensitive supply, cost, price, and other information available to consumers to inform their use of smart grid technologies and demand response. 

Finally, the measure also would amend the National Energy Conservation Policy Act to require federal agencies to reduce their peak electricity consumption by 2 percent each year for 10 years, or make that percentage available as demand response, and report to Congress on the results.  The Grid Modernization Commission would also be tasked with developing a national action plan to achieve demand response potential in the U.S.

On May 16, the Department of Energy (DOE) published its Notice of Proposed Rulemaking (NOPR) regarding loan guarantees for projects that would employ renewable energy systems, advanced nuclear facilities, and carbon sequestration units, among other innovative technologies.  In comments on the NOPR, lending and rating institutions slammed the proposal.

The Energy Policy Act of 2005 (EPAct 2005) authorizes DOE to guarantee loans “not to exceed an amount equal to 80 percent of the project cost of the facility.”  In the  NOPR, however, DOE proposed to guarantee up to only 90 percent of a particular loan rather than 100% of a loan covering 80% of project cost.  DOE’s proposal also prohibited selling off or “stripping” the guaranteed portion of the debt instrument because DOE wishes (1) to preclude the guaranteed portion of the loan from being sold and (2) to ensure that the lender and later debt holders maintain the same level of financial risk in the project as when the debt was issued in order to spur continued due diligence.

Credit Suisse, Lehman Brothers, Goldman Sachs, Merrill Lynch, Morgan Stanley, and Citigroup expressed concern that the proposed rule “is not workable” because it relegates 10 percent of project debt to an un-guaranteed, deeply subordinated tranche, and, by barring stripping, prevents marketability of the debt instrument.  The “hybrid instrument” created by the NOPR, they explained, has no natural market, and “the higher costs associated with financing [it] would deter sponsors from moving forward . . . [or] increase the risk of default.”  Goldman Sachs also submitted very similar comments separately.

Standard & Poor’s echoed concerns over the 90 percent guarantee limit and prohibition against stripping.  S&P cautioned that the “rating associated with a partially guaranteed obligation will be substantially lower than the ‘AAA’ rating of a fully guaranteed instrument” and will result in “a significantly higher cost of debt for the project than if it was fully guaranteed.”  A 100 percent debt guarantee and/or removal of the no stripping requirement would lower the cost of debt and is likely essential to “the early commercial use of innovative technologies.”

Banc of America Securities, LLC concluded that EPAct itself made clear that 100 percent of the loan is to be backed by the full faith and credit of the United States and the NOPR’s proposal is consequently inconsistent with the statute.   The Electric Power Supply Association echoed this congressional intent argument when it urged DOE to guarantee 80 percent of the total project cost and up to 100 percent of the amount borrowed.  The Public Service Commission of Florida agreed, adding that the loan guarantee program “was intended to support the deployment of new technologies that reduce, avoid or sequester greenhouse gas emissions by providing a [100 percent] guarantee for up to 80 percent of project costs,” not 90 percent of 80 percent of project costs.

In the wake of higher natural gas prices and the perceived impact of a large hedge fund (now-collapsed Amaranth Advisors) on gas prices, various Congressmen continue efforts to increase oversight of over-the-counter (OTC) natural gas trading.  Most recently, a bipartisan bill, introduced by Representatives Sam Graves (R-MO) and John Barrow (D-GA), would require that all large gas trading positions — whether futures or OTC — be reported to the Commodity Futures Trading Commission (CFTC).

At present, the CFTC does not have jurisdiction over OTC trading on electronic exchanges such as the high-volume Intercontinental Exchange (ICE).  The CFTC does regulate futures contract trading on exchanges such as the New York Mercantile Exchange (NYMEX), but not OTC contracts.  The House bill also would require traders on all exchanges to keep records that could be reviewed by regulators.  Approval of this or other similar legislation would likely have a significant impact on ICE, which operates under less regulatory scrutiny than futures exchanges. 

Sen. Carl Levin (D-MI) has also been a vocal proponent of increasing regulatory oversight of OTC natural gas trading and co-sponsored legislation to do so.  As Chair of the Senate's Permanent Subcommittee on Investigations, he presided over hearings on price volatility in natural gas markets.  Sen. Levin and others have focused on the collapse of Amaranth, which was very active in gas futures markets, and whose precipitous collapse prompted calls generally for more oversight of energy trading.  Yet, to date, no one has conclusively linked volatility in natural gas prices to gaps in the regulatory regime. 

The Cogeneration Association of California and the Energy Producers and Users Coalition and the Midland Cogeneration Venture Limited Partnership have sought rehearing of FERC’s Order No. 696, which overhauled regulations governing small power production and cogeneration by eliminating previous exemptions of qualifying facilities (QFs) from compliance with the mandatory reliability standards of new section 215 of the Federal Power Act.

The rehearing requests contend that Order No. 696 discriminates against QFs by neglecting to assure QFs that they will be able to recover their costs of complying with the new standards.  In contrast, FERC did provide that assurance to traditional public utilities that own generation.  “[B]y saddling [QFs] with significant new reliability compliance costs without also providing a cost recovery mechanism,” argue the challengers, the Commission is actually discouraging energy efficient cogeneration and renewable small power production technologies that FERC otherwise has a duty to promote under the Public Utility Regulatory Policies Act of 1978, section 210 of the Federal Power Act, and the Energy Policy Act of 2005.

The parties to the rehearing requests represent the interests of approximately 20 individual companies, including the likes of the El Paso Corporation,  BP West Coast Products, Inc., Chevron U.S.A. Inc., ConocoPhillips Company, ExxonMobil Power and Gas Services Inc., Shell Oil Products US, Kern River Cogeneration Company, Salinas River Cogeneration Company, and other additional small QFs in California.