Energy Legal Blog

California PUC Loosens Deliverability Requirement for Renewables

To help the state’s investor-owned utilities satisfy the law requiring them to obtain from renewable resources 20 percent of the power needed to service their retail customers, the California Public Utilities Commission (“CPUC”) recently relaxed its former rule that all of that renewable power must be deliverable to the utility’s own service territory if it is to be counted toward the 20 percent.  Now the requirement can be met so long as the utility has a transmission path sufficient to deliver the renewable generation to some point within the larger footprint of the California ISO.  The CPUC ruling is certain to help California’s three investor-owned utilities — San Diego Gas & Electric (“SDG&E), Southern California Edison (“SCE”), and Pacific Gas & Electric — comply with the 20 percent portfolio requirement notwithstanding transmission constraints that limit the deliverability of certain renewable energy resources. 
 
The new approach to deliverability grew out of the CPUC’s review of the current procurement plans through which the California utilities propose to achieve the 20 percent requirement by 2010.  For its part, FERC too recently addressed deliverability in connection with an SCE proposal to change the funding mechanism for a proposed transmission line to major wind resource.  (See FERC Denies SoCalEd Full Approval of Utility's Plan to Add Transmission, Use Wind to Reach RPS Goals, July 14, 2005).   Were Congress to eventually adopt a national portfolio standard, as some Senators have proposed, then this flexible approach to deliverability might also prove necessary beyond California since some of the most abundant renewables, wind generation in particular, but also hydro and solar, are remote from many service territories that are subject to a renewable portfolio requirement and are unable to reach those service territories due to transmission constraints. 

California is out front on considering many of these issues.  In another CPUC proceeding, the CPUC continues to address how transmission costs associated with individual projects should be considered in evaluation of proposals for satisfying renewable portfolio requirements.  (Res. E-3946; Res. E-3935; R.04-04-026) [UPDATE]

Illinois' Newly-Adopted Sustainable Energy Plan Addresses Renewable Portfolios and Energy Efficiency

The Illinois Commerce Commission ("ICC") has adopted a sustainable energy plan modeled largely after the plan that Governor Rod Blagojevich proposed last February.  Illinois joins a growing list of states whose regulatory agencies have implemented Renewable Portfolio Standards ("RPSs"), including neighbors Iowa, Minnesota and Wisconsin.  In addition to the RPS outlined in the Plan, the new measure also contains a complementary Energy Efficiency Portfolio Standard ("EEPS"). 

Supreme Court Decision Backs FCC Ruling Deregulating Broadband Cable Modem Providers that Bundle Telecommunication with Internet Access

In a decision noteworthy for its implicit encouragement of bundling traditional utility network service with competitive goods and services, contrary to the regulatory course charted in recent years for pipelines, local telephone exchanges and electric transmission grids, a divided (6-3) U.S. Supreme Court recently affirmed a Federal Communications Commission (FCC) declaratory rule that exempts from common-carrier regulation providers of broadband cable modem service because of the bundling of the telecommunications component of that service with internet applications.  The majority decision in what will likely become known as the Brand X case (after an internet service provider (ISP) that supported common carrier regulation and opposed the FCC rule) dismissed with virtually no analysis the objection that the FCC rule allows broadband cable providers, such as Comcast, to deny common-carriage access to competing ISPs, while at the same time the FCC takes precisely the opposite approach in its regulation of the other principal media for accessing the internet, dial-up access and Digital Subscriber Line (DSL) service, both of which are required to provide nondiscriminatory common carriage.

While the majority decision in large part turned on an evolving and mushy area of the law concerning the extent to which federal courts must defer to the expertise and judgment of a regulatory agency such as the FCC, the ultimate question boiled down to this:  Does a broadband cable provider offer telecommunications service to the public for a fee?  If so, then the provider, like providers of dial-up and DSL, is subject to mandatory regulation as a common carrier and must provide nondiscriminatory access to competing ISPs.  Conversely, if the broadband cable modem provider is deemed not to offer telecommunications service, then it is an information service provider, like an ISP that does not own wires or cables, and escapes common carrier regulation.  Because of the nature of the broadband cable providers' service, which does not offer telecommunications on a stand-alone basis, but instead only uses telecommunications to provide end users with a package of internet applications, the FCC ruled and the Supreme Court affirmed that broadband cable providers do not "offer" telecommunications.  Paraphrasing the majority, evidently incredulous dissenters countered:

[F]or the inputs of a finished service to qualify as the objects of an “offer” . . . , it is perhaps a sufficient, but surely not a necessary, condition that the seller offer separately “each discrete input that is necessary to providing . . . a finished service . . . .”  The pet store may have a policy of selling puppies only with leashes, but any customer will say that it does offer puppies — because a leashed puppy is still a puppy, even though it is not offered on a “stand-alone” basis.

It remains to be seen whether this decision of the high court will have any carryover influence in other network industries with natural monopoly characteristics, such as pipelines, local exchange telecommunications and electric transmission systems.  The direction of these industries has been just the opposite.  In recent years, they have been unbundled from sales of natural gas or oil, long distance and wireless service, and electric energy, respectively, and required to provide competing sellers nondiscriminatory access to their networks and common carriage.   It would be a stunning volte-face if these industries could escape this obligation simply by adopting a policy of bundling network access with other services or products and not offering it on a stand-alone basis.  [National Cable & Telecommunications Association, et al., v. Brand X Internet Services, et al., 545 U.S.--, 162 L. Ed. 2d 820 (June 27, 2005)] [NEW MATTER]

IRS Finally Excludes from Taxable Income Funds that an Interconnecting Generator Advances for Transmission Network Upgrades

With the issuance of a recent Revenue Procedure, the Internal Revenue Service has eliminated a long running source of discord in the negotiation of new (or expanded) generator interconnections.  The new Revenue Procedure creates a “safe harbor” that exempts from taxable income the payments that a generator, pursuant to FERC open-access rules, advances to an operator or owner of the transmission system to which it proposes to interconnect for needed upgrades to the transmission network.  Many transmission utilities treated these advances as taxable income to the utility and would insist that a generator pay the tax on top of the funds it advanced for the network upgrades.  Generators generally thought that this was nonsense since FERC requires that funds advanced to the transmission utility be repaid to the generator with interest within a specified period (formerly 5 years and now 20 years); since the complete value advanced is repaid it should not be treated as income of any kind in the hands of the transmission utility, they argued, and repeatedly sought the concurrence of the Service.  Finally, the Service provided that concurrence, better late than never.

Open-Access Transmission Redux as New FERC Chair Jettisons Controversial Standard Market Design Championed by His Predecessor

In his new capacity as Chair of FERC, Joseph Kelliher has made good on his commitment to improving the existing open-access transmission rules that the agency adopted nearly ten years ago.  In particular, with Kelliher at the helm, FERC appears committed to strengthening the anti-discrimination protections of existing regulation of interstate power transmission.  At the same time, under Kelliher’s leadership, FERC formally interred the Standard Market Design (SMD) Rulemaking proceeding that his predecessor Pat Wood rolled out on Wall Street three years ago, see Special Update (7/31/02), but promptly abandoned after it encountered fierce opposition from utilities in the Northwest and Southeast.   Ironically, neo open-access transmission will likely pursue many of the same transmission goals that SMD sought to achieve and may prove in many respects to be SMD by another name.

First proposed in July 2002, SMD was grounded in the operational separation of power generation from transmission and the operation of the high voltage grid.  The SMD grid operator would be a new Independent Transmission Provider or ITP that, in addition to scheduling uses of the grid, would operate day-ahead and real-time spot markets for energy and ancillary services.  Because all uses of the grid would be subject to the same rules, SMD was rightly viewed as a threat to traditional practices that allowed utilities to prioritize certain transmissions over others irrespective of the customer’s willingness to pay.  Opposition persisted and was never assuaged by a 2003 FERC White Paper that sought to make SMD more palatable by watering down its strict independence and anti-discrimination provision.  SMD had long been a dead letter when, on July 19, 2005, FERC formally terminated the SMD proceeding.  SMD, FERC explained, had been overtaken by the industry's voluntary development independent operators — regional transmission organizations (“RTOs”) and independent system operators (“ISOs”). 

PJM Test for Mitigating Scarcity Prices to Be Tested in Hearing

Engaging the nettlesome issue of scarcity, FERC convened an inquiry into whether the PJM Interconnection needs scarcity pricing and, if so, how a generator’s potential to exercise market power during periods of scarcity should be mitigated.  FERC’s attention to these issues in PJM may herald for the MidAtlantic numerically exact mitigation price triggers, similar to what has already been established for other organized RTO and ISO markets.

The current inquiry grows out of a proceeding in which FERC explored compensation due generating units needed to run for reliability reasons.  In PJM, reliability generators are generators in load pockets that are offer capped, i.e. paid their marginal costs plus 10% when there are transmission constraints, and also those generators wishing to deactivate but cannot because they are needed for reliability.  PJM had proposed to FERC a new “no-three pivotal supplier test” to exempt generators from mitigation when generators able to serve a load pocket do not have market power.  A pivotal supplier in PJM is one whose output is required to meet load, and PJM proposed that when four or more pivotal suppliers are considered competitive (or there are no pivotal suppliers), competitive conditions exist and mitigation is not warranted.  PJM asserted that this test was consistent with the delivered price test that FERC uses when it evaluates market power resulting from proposed mergers and acquisitions.  But FERC disagreed.  The agency decided additional justification was required and set for hearing the appropriate test for market power in PJM load pockets.  [PJM Interconnection, LLC, 112 FERC ¶ 61,031 (2005)] [NEW MATTER]

North Carolina’s Highest Court Validates Local Regulator’s Assertion of Veto Over Proposed Wholesale Power Contracts

The North Carolina Supreme Court ruled July 1 that the North Carolina Utilities Commission ("NCUC") can exercise veto power over certain wholesale power contracts — contracts that would confer on wholesale customers a higher priority than accorded to a Tar Hill State utility’s retail native-load customers.  In so ruling, the court rejected the argument that FERC's exclusive jurisdiction over wholesale sales preempted the state commission’s assertion of this veto power.
 
The case arose out of a 1998 plan by Carolina Power & Light (since renamed Progress Energy Carolinas) to build two plants to meet its incremental need for power and to provide wholesale power to customers in the Carolinas.  The NCUC approved the plan, but then in an order approving the merger between Carolina Power & Light and Florida Progress, the NCUC imposed the condition that the NCUC be given a 20-day advance notice to review and possibly reject any proposed power wholesale sales that would provide the buyer with priority equal to native-load priority to ensure the deals would not affect retail customers.  A N.C. Appeals Court found that FERC’s Federal Power Act jurisdiction preempted NCUC's advance-notice condition.  The July 1 Supreme Court decision reversed, however.  It did so based on the dubious proposition that NCUC review was not preempted because it sought to review the contracts before they were filed with FERC and before FERC took any action on them.  Moreover, the NCUC was not seeking to set wholesale rates, inquire into the prudence of proposed contracts, or overrule a FERC action.  According to the court Congress intended states to oversee matters of local concern, such as generating facilities and local supply adequacy and reliability issues, just the type of matters that NCUC's proposed review would take into consideration.

The issue of federal vs. state jurisdiction over wholesale power contracts that impact resource adequacy issues has recently been on the forefront of electric power news, with tensions between federal and state regulators running high, and the decision comes just as FERC and state commissioners are attempting to establish an informal joint working group to discuss resource procurement and adequacy issues.  The impact of the N.C. high court’s decision on this debate remains to be seen.  Investor-owned utilities and competitive power suppliers argue that the decision can and should be overturned by the federal courts.  [State ex rel. Utils. Comm'n v. Carolina Power & Light Co., 359 N.C. 516  (July 1, 2005)] [NEW MATTER]

FERC Denies SoCalEd Full Approval of Utility's Plan to Add Transmission, Use Wind to Reach RPS Goals

In a July 1 order, FERC denied Southern California Edison's (SCE) request that the agency recognize a new "trunkline" category of transmission line the cost of which could be "rolled" into SCE's transmission revenue requirement (rate base) and recovered in transmission charges to all users of the Golden State's transmission grid.  FERC's refusal is significant since without "rolled in" cost recovery it is questionable whether this type of "trunkline" project can or will be financed.

The transmission line in question, Segment 3 of the SCE's Antelope Project, would connect to the California transmission system an undeveloped but wind-resource rich are of Tehachapi at the base of the Sierra Nevada Mountains.  California directed SCE to construct Segment 3 so that it would be available to interconnect future wind generation projects that the state will require to fulfill its ambitious renewable energy portfolio standard.   Before undertaking the costly project, however, SCE sought FERC's guarantee that the Segment 3 and two other transmission lines (Segments 1 and 2) would be eligible for complete cost recovery in transmission charges.  A split (3-1) FERC balked and denied "rolled in" treatment of Segment 3 on the ground that it was not a generally beneficial upgrade to the transmission grid, but was instead only a generator lead line for use exclusively by the future developers of wind projects in Tahachapi.  Outgoing FERC Chair Pat Wood dissented, arguing that the Segment 3 project benefited all users of the California transmission grid by "provid[ing] access to significant and diverse supplies of energy that help meet network grid customers' electricity needs."  Commissioner Nora Brownell also expressed reservations over the decision concerning the treatment of Segment 3, but nevertheless concurred in the majorities' decision.      

Despite rejecting SCE's proposals concerning Segment 3, FERC seemed to leave open another avenue for achieving SCE's objectives.  The agency implied that that it might grant the requests with respect to Segment 3 if the request came from the regional transmission grid operator, the California ISO, instead of from SCE.

SCE received more favorable results from FERC with respect to Segments 1 and 2 of the project.  FERC determined that SCE could roll those segments into transmission rate base, and could recover prudently incurred Segments 1 and 2 costs in transmission charges, regardless of whether the potential wind generation is ever brought on line.  FERC deferred making an advance determination of the prudence of the Segments 1 and 2 costs until such time as SCE has received from the state all of the necessary certificates for their construction. [Southern California Edison Company, 112 FERC ¶ 61,014 (2005)] [NEW MATTER]

Duke Forfeits Market-Pricing Authority for Wholesales in Home Control Area; FERC Initiates Further Investigation into Entergy's Ability to Exercise Market Power

In its first order revoking a utility's market-pricing under authority of its interim market power screen tests that became effective in April 2004, FERC found that Duke Power ("Duke") has the ability to unfairly influence the price of wholesale power in its home control area. 

After failing the initial indicative market-power screens, Duke filed a more thorough analysis of its market power in its home control area using FERC's Delivered Price Test ("DPT").  Duke's second filing claimed that it satisfied FERC's standards regarding pivotal suppliers using both the DPT economic capacity measure and the DPT available economic capacity measure.  FERC disagreed.  Instead, the agency found that the results of Duke's economic capacity DPT showed that the North Carolina utility owns approximately two-thirds of the generation in its home control area, that the results of its available economic capacity DPT showed that it possesses a market share in excess of 25 percent in almost all seasons and load conditions, and that the Duke home control area is a highly concentrated market.  As a result, Duke must now implement by July 30 revised tariff prohibiting sales at market-based rates and providing for sales at cost-based rates, along with the data necessary to support its cost-based rates.

Concurrently FERC also set for further hearing the issue of whether Entergy Corp. possesses market power.  Entergy had filed its DPT results with FERC after failing one of the indicative generation market-power screens, and FERC found that Entergy passed the DPT in its control area using the available economic capacity measure, but failed to show that the New-Orleans-based utility does not have market power using the DPT economic capacity measure.  Entergy's sales at market-based rates will remain subject to the refund effective date previously established in the proceeding.  [Duke Power, 111 FERC ¶ 61,506 (2005) & Entergy Services, Inc., 111 FERC ¶ 61,507 (2005)] [NEW MATTER]

Thumbs up for Three LNG Terminals, Down for Another

            In late June FERC approved the construction and operation of three new liquefied natural gas (“LNG”) terminals that jointly will be able to import up to four billion cubic feet per day of LNG into the United States.  Weaver's Cove Energy and Mill River Pipeline, affiliates of Hess LNG, proposed one of the projects, which will be located in Fall River, Massachusetts.  The other project, proposed by Golden Pass LNG Terminal and Golden Pass Pipeline, subsidiaries of ExxonMobil, will be constructed in Texas and Louisiana.  These projects, together with the Vista del Sol LNG Terminal LP that FERC approved earlier, are the latest in a slew of LNG proposals intended to address the countries’ growing natural gas supply deficit.  See UPDATE (06/30/04).

The Weaver's Cove project includes a new terminal and two affiliated pipelines that would connect the terminal to the Algonquin Gas Transmission system and intrastate pipelines.  The project has met with great opposition from local interests, but FERC said that with appropriate conditions the project should be authorized.  It is the first LNG terminal in the current onslaught approved for the Northeast U.S.  The Golden Pass LNG terminal will be constructed at the Port Arthur ship channel in Texas and Louisiana.  Over 120 miles of new pipeline will connect the terminal with existing interstate and intrastate pipeline systems.

On the same day that it approved the Weaver's Cove and Golden Pass projects, FERC denied an application submitted by KeySpan LNG and Algonquin Gas Transmission to convert an existing LNG facility in Providence, Rhode Island into a new LNG import terminal.  FERC cited the applicant's failure to show that the facility would meet current construction and safety standards as its basis for the denial.

The Vista del Sol LNG Terminal LP and Vista del Sol Pipeline LP are also sponsored by ExxonMobil, and would be located in San Patricio County, Texas.  The past few months have seen FERC authorize the construction and operation of numerous other new LNG terminals in the Gulf region.  More approvals are likely in the pipelines as FERC endeavors to increase U.S. capacity for importing LNG.  Initial approval is no guarantee that proposed projects will successfully navigate the difficult path to completion and operation. [Weaver's Cove Energy, LLC, 112 FERC ¶ 61,070 (2005), Golden Pass LNG Terminal LP, 112 FERC ¶ 61,041 (2005), KeySpan LNG, L.P., 112 FERC ¶ 61,028 (2005) & Cameron LNG, LLC, 111 FERC ¶ 61,490 (2005)] [UPDATE]

Senate Votes in Favor of Energy Bill, Tumultuous Conference Awaits

          In what some have described as the easy first step down what will surely be a long and difficult road, on June 28, 2005, the Senate voted 85-12 to pass its version of the energy bill (H.R. 6), which has an estimated price tag of up to $35 billion.  The Senate's version would benefit the power industry in several key ways, but it also addresses energy conservation and development of clean energy alternatives.  Despite drawing praise from President Bush for its bipartisan support, the bill still faces an iffy future in a Senate-House conference that is sure to be contentious.  There are substantial differences between the Senate version and the earlier House version, which was passed April 21, 2005.  See UPDATE (04/30/03).  The President has said he wants a bill from Congress by August 1, before Congress recesses, leaving lawmakers a short window in which to iron out differences.  Given Congress's recent record of failure on passing comprehensive energy legislation, this could prove to be a tall order.

The Senate bill is encompassing.  Democrats were especially pleased with the inclusion of a Renewable Portfolio Standard, which will require utilities to generate ten percent of their electricity from renewable sources by 2020.  The bill also repeals the Public Utility Holder Company Act ("PUHCA") of 1935.  In lieu of PUHCA’s regulatory protections against holding company abuses, the bill would expand FERC’s authority to review utility mergers.  The Senate version also grants to FERC exclusive siting authority for liquefied natural gas ("LNG") facilities, an issue that has caused serious friction between FERC and various state governments that want more control over the siting of LNG facilities.

The Senate bill's tax incentives total $18 billion over the next ten years, offset by $4 billion in revenue-generating measures.  Forty percent of these tax incentives are geared toward renewable energy, conservation, and energy-efficient buildings.  The House's tax package, in contrast, provided only $8 billion in tax incentives.  Both exceed the Administration's proposal for only $6.7 billion in tax breaks.

The Senate bill also includes a voluntary plan for reducing greenhouse gases, along with a sense-of-Senate provision putting that branch of government on lonely record in support of action on global warming.  Although non-binding and unlikely to emerge from conference, this sense-of-Senate provision represents the first time that a branch of the federal government has officially acknowledged that greenhouse gases cause global warming.

Other key provisions include: an ethanol mandate of 8 billion gallons by 2012 (as compared with the House's mandate of 5 billion gallons); an oil savings provision requiring the President to reduce demand by 1 million barrels per day by 2015; a provision granting FERC new authority to approve the location of electrical transmission lines; mandatory electric reliability standards to improve operation of the nation's high-voltage transmission system and prevent blackouts; a call for an inventory of the oil and gas resources in the outer continental shelf; and a federal loan guarantee program to commercialize new technologies for fuel cells, coal, nuclear, carbon sequestration, and other advancements, including government-backed loans for power plants that create electricity from cleaner-burning coal and facilities that turn coal into natural gas.

Supporters of the Senate version, including Senate Energy and Natural Resources Committee Chairman Pete Domenici (R-NM) and Ranking Minority Member Jeff Bingaman (D-NM), acknowledge that the bill will not have an immediate impact on high gasoline, natural gas, or electricity prices.  High power prices are a keen political issue since oil prices peaked at a record high in June of $60/barrel and gasoline averaged $2.00/gallon nationwide.  In lieu of short-term benefits, the bill's supporters instead emphasized the long-term impact of the Senate bill, which they hope will increase domestic energy production by increasing renewable energy and alternative fuels, improving electricity transmission reliability, and reducing demand and the need for more power plants by boosting energy conservation and efficiency programs.  Senator Domenici did say, however, that the bill might offer some short-term relief for U.S. manufacturers from skyrocketing natural gas costs.

The main sticking point in the upcoming conference committee will likely be the insistence by House Republicans that the energy bill include a waiver of liability for manufacturers of the gasoline additive MTBE, which has polluted water supplies in many parts of the country.  Other contentious areas are likely to be the House provision authorizing oil and gas drilling in the wilderness of the Arctic National Wildlife Refuge, which is absent from the Senate bill, the differing tax packages included in each version, and the Senate's Renewable Portfolio Standard.  (H.R. 6) [UPDATE]

FERC Provides More Guidance on Status Changes that Power Sellers with Market-Pricing Authority Must Report

FERC relented in June to market participants’ demands and provided additional examples of those types of changes in status that, if not reported to the agency, could cause a power seller to forfeit its market-pricing authority. 

 The resulting message was a classic example of a regulator seeking to point those it regulates in a salutary direction, while at the same time striving mightily not to fence itself in through overly descriptive examples of applicable conduct.  FERC provided several illustrations of the types of contracts and events that would and would not trigger the reporting requirement, but also sought to protect its flexibility to demand reporting of new contractual arrangements by reiterating that it would not further specify what constitutes “control” of generating capacity. 

FERC stated that events and contracts that would trigger the reporting requirements include the testing of new generation facilities (subject to a 100-MW cumulative threshold), acquisitions of ownership or control of natural gas storage or intrastate pipelines, and obtaining generation capacity credits that transfer control.  In contrast, events not triggering reporting include becoming affiliated with an interstate pipeline and upgrading a utility’s own transmission network to increase total transfer capability.  [Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate Authority, 111 FERC ¶ 61,413 (2005)]  [UPDATE]