Energy Legal Blog

In early September, Entergy asked FERC to confirm that if Entergy stops paying itself for reactive power, then the New Orleans-based utility can refuse to pay non-affiliated generators for reactive power.  A generator is obligated to maintain reactive power within a specified bandwidth as a condition of its interconnecting with the transmission provider's system, and is not owed any compensation so long as Entergy does not pay itself or its affiliates for providing the same service.  Unanswered is why Entergy until now has paid itself and its affiliates for reactive power.

Apparently expecting a favorable answer from FERC, together with its petition, Entergy filed papers to eliminate prospectively all compensation to Entergy and its affiliates for reactive power.  [FERC Docket No. EL05-149] [NEW MATTER]

FERC recently issued a notice of inquiry asking for ideas on how to close the existing regulatory loophole that allows offshore natural gas gatherers to escape regulation.  Under current law, these gatherers fall outside of FERC's jurisdiction once they are spun off from interstate pipelines, as many were during 1990s.  Nor are these spun-off gatherers subject to state regulation.  Over the past few years, FERC has invoked various legal theories and statutes, including provisions of the Natural Gas Act and the Outer Continental Shelf Lands Act, to impose regulated rates on gatherers.  But the courts uniformly have balked.  The current notice asks for industry feedback on a 1994 order, Arkla Gathering Service Co., which set forth criteria for asserting jurisdiction over pipelines' unregulated gathering affiliates, and poses 13 detailed questions relating to the assertion of jurisdiction over these facilities.  Comments on the notice of inquiry are due 60 days after publication of the notice in the Federal Register.

FERC's primary concern in issuing the notice was the monopoly rents that offshore gatherers facilities are able to charge their customers without fear of regulatory intervention.  FERC Chair Joe Kelliher observed that some shippers have been charged “multiples, multiples” more for service on unregulated gathering systems than on the regulated pipelines they feed into, and concluded, “[i]f the law permits monopoly rents, [then] its time to change the law.”  FERC was also concerned that the current laissez-faire approach enables gatherers to shut in offshore gas production at critical times, such as the recent emergency following Hurricane Katrina. [Criteria for Reassertion of Jurisdiction Over the Gathering Services of Natural Gas Company Affiliates, 112 FERC ¶ 61,292 (2005)] [NEW MATTER]

Concurrently with the issuance of the notice, Chair Kelliher and Commissioner Suedeen Kelly publicly asked Congress for new legislation granting FERC's regulatory authority over natural gas gatherers.  Some speculate that Congress may be primed to take up new energy legislation later this fall to address oil and natural gas production and conservation issues, at least partly in response to the price-gouging allegations that have arisen in the wake of Hurricanes Katrina and Rita.

Last week FERC Chair Joe Kelliher announced that his agency will soon explore ways to induce transmission investment.  The Domenici-Barton Energy Policy Act of 2005 (“EPAct 2005″) directs FERC to issue a rule establishing transmission incentive rates within one year of EPAct 2005's August 8 enactment.  The investment initiative will proceed “in tandem” with FERC's just-announced proposal to update its Order No. 888 open-access transmission tariff.  [See FERC to Reprise Open Access Nearly Ten Years after Its Launch].  It would be the latest iteration of an evolving approach to FERC's transmission policy that began with its incentive pricing policy first introduced in January 2003.

An earlier initiative undertaken in January 2003 would have tied increased earnings on transmission investments to the transmission owner's participation in an independent RTO, but that proposal never made it beyond an extended comment period.  Other than a narrow policy statement issued last June addressing the passive ownership of Independent Transmission Companies (“ITCs”) [See FERC Takes a Second Look at the Independent Ownership and Operation of Power Transmission Systems], the issue of investment incentives has languished.   But with the EPAct 2005 directive and a change in leadership, FERC now appears poised to tackle the issue.

According to Kelliher, the 2003 transmission policy placed too much emphasis on participation in RTOs rather than on providing transmission investment incentives.  Noting that more transmission investment has occurred in areas that did not engage in regional planning, Kelliher made the surprising observation that RTOs can be “barriers” to open-access transmission.  While FERC has authorized the incentives suggested in the 2003 transmission policy in individual cases, Kelliher foresees broader use of transmission incentives under EPAct 2005.  He predicted that the agency's policies going forward would be more flexible and could confer higher earnings on the transmission investments of affiliated transcos as well as ITCs.  But he ruled out the use of performance-based rates because, in areas with disaggregated transmission ownership, it would be too difficult to ascertain which owner was responsible for improved performance.  [NEW MATTER]

In a September 19 order FERC rejected as “inadequate” Southwest Power Pool's (“SPP”) proposal to implement a real-time energy imbalance market, along with its market monitoring and market power mitigation plans.  FERC was primarily concerned that the imbalance market was not designed or would not be monitored properly to ensure stable market operation and laid out guidance for SPP in several critical areas.  FERC also rejected SPP's attempts to justify various tariff revisions as the result of its stakeholder process, saying that “SPP is ultimately responsible for the stable operation of its market and must provide justification for its proposal to show that the market will operate reasonably and provide just and reasonable rates.” 

In particular, FERC found SPP's proposal lacking because it proposed a voluntary sellers' market and a mandatory buyers' market, “but no way to bridge the gap if the offers are insufficient, short of implementing emergency procedures.”  SPP's proposal was also lacking because it failed to detail its market monitoring plan, market mitigation measures, and sanctions for violating market rules.  SPP also failed to clarify the different responsibilities of SPP's market monitoring unit and its independent market monitor (“IMM”).  FERC directed SPP to specify in its market monitoring plan what corrective steps the IMM would take if it were to determine that the SPP markets are not producing just and reasonable prices or are failing to induce sufficient investment in infrastructure.  FERC also instructed SPP to amend its tariff language to clarify that FERC, and not the market monitor, has enforcement power.

Authorized as a regional transmission organization (“RTO”) since October 1, 2004, SPP filed tariff amendments to implement the imbalance market and market monitoring and mitigation plans in response to FERC's order addressing its RTO application.  SPP had hoped to begin trials of the imbalance market in June 2005, with the market going live by October 2005.  Reliability concerns caused SPP to postpone implementation until March 2006.  In light of the current order, the imbalance market has no start date.  [Southwest Power Pool, Inc. 112 FERC ¶ 61,303 (2005)]  [NEW MATTER]

A California Public Utilities Commission judge issued a draft decision conditionally approving the respective plans of the state’s three investor-owned utilities to implement the California Renewable Portfolio Standard (RPS) program, but required them to supplement their plans with further information on issues such as transmission planning and contingency planning. 

California has the nation’s most ambitious RPS program.  It requires the utilities to achieve a 20% RPS goal by 2010.  Moreover, the judge cited the PUC’s plan of working toward Governor Schwarzenegger’s declared goal of procuring 33% of the state’s electricity from renewable resources by 2020.  This focus on renewable energy presents a stiff test for Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric (SDG&E), and their long-term procurement plans were found lacking in many respects by the judge.   

Connecting areas where resources such as wind can be harnessed with load centers into which power must be delivered is often costly and a major challenge for renewable energy development.  Not surprisingly, because of that challenge each of the California utilities discussed the need for transmission in their plans, but the judge found their plans for new transmission insufficient and ordered that they be supplemented.   The utilities are required to supplement their long-term plans by early October. 

The Domenici-Barton Energy Policy Act of 2005 repeals the venerable Public Utility Holding Company Act of 1935 (’35 Act) and, effective February 8, 2006, replaces it with a 2005 Act bearing the same name (PUHCA 2005).  The earlier act’s structural limitations that confined holding companies to “a single integrated public-utility system, and to such other businesses as are reasonably incidental, or economically necessary or appropriate to the operations of such integrated public-utility system” are supplanted in PUHCA 2005 with what FERC in a recent rulemaking proposal calls “primarily a books and records access” statute.  Not surprisingly, in its notice of proposed rulemaking (NOPR) on how it should implement PUHCA 2005, FERC sets out how it proposes to exercise its new authority to ensure public — and particularly state regulatory — access to the books and records of future public utility holding companies.  To be considered, comments on the NOPR must be received by FERC 21 days after the NOPR is noticed in the Federal Register, which will likely occur in late October. 

While much of the NOPR addresses itself to record keeping obligations and exemptions from those obligations, it also raises more economically significant issues dealing with FERC’s new authority under PUHCA 2005 to review and authorize the pricing of and allocation of costs and revenues from non-power goods and administrative or management services that an associate company within a holding company provides to regulated public utilities within the same holding company.  In many respects, FERC proposes simply to adopt and continue the accounting rules and practices that the Securities and Exchange Commission (SEC) had developed under the ’35 Act for these intra-holding company transactions.  But in one critically important respect, FERC’s and the SEC’s approaches conflict and are not resolved in the NOPR.  That respect turns on how non-power goods and administrative or management services are priced and reflected in the public utility purchaser’s regulated rates.  The SEC’s historical practice was to set the price at cost — that is, equal to the cost that the associate company incurred in providing the non-power good or service.  But FERC, for its part, has applied a more consumer-oriented rule that sets price equal to the lower of cost or market.  For many players in the power and related services industries, perhaps the most important issue on which FERC invites public comment in the NOPR is “whether the Commission should apply [its own] lower of cost or market standard for the allocation of costs for non-power goods and services, or if [it] should instead adopt the SEC ‘at cost’ standard.”  [Repeal of the Public Utility Holding Company at of 1935 and Enactment of the Public Utility Holding Company Act of 2005, 113 FERC ¶ 61,248 (2005) NEW MATTER]