Wisconsin Power & Light Offers Emission-Saving Goodies to Make New Coal Plant Proposal Palatable

In an effort to counter opponents of its proposal to expand an existing coal-fired generating station by 300 MW, Wisconsin Power & Light (WP&L) has offered to take several steps to offset the increased greenhouse-gas emissions that would result from the expanded plant's operation.  In a draft environmental impact statement, the Wisconsin Public Service Commission criticized WP&L's proposed use of a circulating, fluidized bed (CFB) boiler, which results in higher CO₂ emission.  In response, rather than abandon CFB, WP&L has offered to retire the oldest coal-fired plant in its fleet, develop an additional 200 MW of wind power above the 300 MW it has already pledged to develop in the next several years, increase the amount of biomass co-firing planned for the new unit, and increase energy efficiency and conservation efforts.  WP&L's estimated cost for these proposed efforts are $500-$550 million. 

Michigan Legislators Consider State RPS, Rolling Back Electric Choice

The Michigan Legislature currently is considering legislation that would enact a renewable portfolio standard (RPS) and that would limit electric choice in the state.  At issue are three bills that have been passed by the state's House of Representatives and are now under Senate consideration. 

House Bills 5548 and 5549 would require the state's utilities to obtain at least 10% of their power from renewable energy resources by 2015.  These bills, however, do not currently propose to allow competitive bidding for renewable resources.  Senate Republicans have indicated they will seek to amend the legislation to require competitive bidding when the Senate takes up the measures. 

H.B. 5524 proposes to impose a 10% hard cap on participation in electric choice programs.  Opponents of the measure say it would effectively end electric choice in the state.  The state's largest utilities, Detroit Edison and Consumers Energy, have supported the bill, asserting that electric choice has limited their ability to secure financing for new power plants and to implement energy efficiency and renewable energy programs.

The Senate Energy Policy and Public Utilities Committee passed all three bills last week, by identical votes of 5-3.  The bills will now come before the full Senate, although it is unclear when they are slated to do so.

Bonneville Holding Transmission Open Season to Speed Interconnections

Transmission providers and customers alike are increasingly complaining about the lengthy queues for interconnecting to the transmission grid.  Scores of generator projects sign up for interconnection service, which is then delayed for years while the transmission provider conducts an array of studies.  To clear backlog on its transmission network, the Bonneville Power Administration is conducting a Network Open Season for transmission service that asks customers to commit to the transmission service they are seeking. 

At present BPA’s transmission queue includes requests by 25 customers for approximately 180 applications for transmission service totaling about 8,500 MW of new capacity, but BPA states that many of these service requests are speculative.  Under its new procedure, BPA will give all customers applying for transmission service by May 15, 2008, a precedent service agreement.  If a customer signs the binding agreement and remits the required financial security by June 16, 2008, BPA commits to providing the service, so long as it can provide the service at its rolled-in rate and complete its environmental study obligations.  BPA also will assume the study costs itself and arrange financing for any required transmission facilities, instead of requiring customers to front these costs.  However, if a customer declines the offer, BPA will withdraw its service requests from the transmission request queue, while allowing the customer to participate in future Network Open Seasons.

In December 2007, the Federal Energy Regulatory Commission held a technical conference focusing on transmission queue logjams.  The interconnection queue process is governed by Order No. 2003, which standardized the agreements and procedures related to the interconnection of large generating facilities based on a first-come, first-served process.  However, the surge of new generation projects, including many based on wind and other forms of renewable energy, have led to long interconnection queues that transmission providers are now debating how to expedite. 

FERC Blesses Midwest ISO Plan for Resource Adequacy

The Federal Energy Regulatory Commission has conditionally accepted a Midwest Independent Transmission System Operator (Midwest ISO) plan for ensuring long-term resource adequacy in the RTO’s 15-state territory.  Most other RTOs and ISOs have spent years grappling with how to ensure sufficient capacity is available to meet peak demand, and contentious FERC proceedings have led to different market models in NYISO, PJM, and ISO-NE.  FERC directed MISO to develop its own resource adequacy plan after having operated for years without one.   The first planning year under the resource adequac plan will start June 2009.

MISO’s responsibilities under the new plan will include determining capacity obligations, monitoring compliance, and assessing penalties to deficient load servers.  Unlike the PJM, ISO-NE, and NYISO models, the MISO plan does not entail a centralized capacity market, but does require any load server in the Midwest ISO region to maintain access to sufficient planning resources, whether generation or demand response.  

CAISO Says It Will Announce MRTU Start in July

It is still unclear when the California Independent System Operator's long-awaited Market Redesign and Technology Upgrade (MRTU) will take effect, but the CAISO recently suggested it will announce the startup date in July 2008. 

Ever since the California energy crisis, the CAISO has worked on designing and implementing a new wholesale power market with features such as locational marginal pricing, financial transmission rights (called congestion revenue rights), and a day-ahead market energy market.  The CAISO filed the MRTU proposal with FERC in February 2006, and proposed a market startup date of November 2007.  Due to technical issues and ongoing administrative litigation over the details of the market design, the proposed startup date has been delayed several times, first to February 2008, then April 2008, and now again to an unknown time.   The latest delay raised the prospect of MRTU not taking effect until next fall, after the high-demand summer season, which the CAISO's latest announcement appears to confirm. 

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

FERC Orders Review of Sellers Using WSPP Agreement Demand Charge in Markets where They Lack Market-Based Rate Authority

Last week, following an investigation under Federal Power Act section 206, FERC issued an order finding it is unjust and unreasonable to allow power sellers to keep using the WSPP-wide "up to" demand charge as a ceiling rate in markets where the seller does not have market-based rate authority, unless the seller can justify that rate based on its own costs.  Under the WSPP Agreement, sellers may charge "up to" a cost-based ceiling rate, which consists of a seller's forecasted incremental cost plus an "up to" demand charge based on the costs of a sub-set of 18 of the original parties to the WSPP Agreement.  In its February 21 order, FERC directed sellers that wish to continue transacting under the WSPP demand charge in markets where they do not have market-based rate authority or where they are presumed to have market power to make a filing by April 21 justifying continued use of the rate.  FERC emphasized that this affects only some, and not all, sellers that use the WSPP Agreement.  In a statement issued along with the order, Chairman Joseph Kelliher stated that allowing sellers to continue to use the WSPP demand charge without justifying the rate based on their own costs would "effectively let those sellers sidestep the more rigorous market-based rate test that we have put in place in recent years."

FERC began its review of the widespread use of "up to" demand charge rates under the WSPP Agreement last year as part of its rulemaking proceeding examining sellers' market-based rate authorizations.  In Order No. 697, FERC explained that it had accepted the use of the WSPP Agreement "up to" rate as a mitigation measure by several different sellers that had failed the indicative screens for market power and were found or presumed to have market power.  FERC expressed concern that use of the WSPP rate was no longer just and reasonable for such sellers because it appeared that many sellers used the rate without showing any relationship to their actual costs.  FERC thus began the investigation into whether WSPP rates can be used by sellers that are found or presumed to have market power or that lack market-based rate authority in certain markets.

FERC Allows Duquesne to Exit PJM, but with Conditions

FERC on January 17 conditionally approved Duquesne Light's request to withdraw from the PJM Interconnection and join the Midwest Independent System Operator.  Last November, Duquesne filed an application with FERC seeking approval to leave PJM over rising capacity costs as a result of PJM's new forward capacity market.  In comments and protests filed in December, PJM and other PJM market participants asked FERC to hold Duquesne be held to its financial commitments to the market and ensure that its withdrawal would not harm other market participants financially.

In the January 17 order, FERC agreed to hold Duquesne responsible for its commitments in the PJM forward capacity market.  FERC conditioned Duquesne's right to exit PJM upon the utility honoring commitments for all forward capacity auctions in which its load had been included.  This means that Duquesne will be liable for forward capacity costs through May 2011.  (Duquesne had asked FERC to make its withdrawal from PJM and termination of its obligations in the capacity markets effective May 31, 2008.)  FERC also directed Duquesne to submit further information on its remaining obligations, including how many and what its continuing obligations to PJM are, what its allocated share of costs for the PJM regional transmission planning process is, and how it will be integrated into the Midwest ISO.

Maryland Energy Administration Calls for Efficiency and More Local Generation

The Maryland Energy Administration (MEA) released its Strategic Electricity Plan on January 14 in an effort to help customers lower their energy bills.  The plan, focused on conservation, efficiency and local new generation, also came in response to Maryland Governor Martin O'Malley's recent warning that the state could face serious power shortages in the near future.

The plan aims to reduce both electricity consumption and peak demand by 15% by the year 2015 and require the state's utilities to implement performance-based programs to help meet these goals.  The MEA predicts that if these goals are met, electricity consumption in the state would fall by 25 billion kilowatt-hours and consumer charges fall by over $2 billion in 2015 and by over $4 billion in 2020.

The plan comprises four central elements.  First, financing would come from a Strategic Energy Investment Fund of revenues earned from the state's sale of carbon allowances as part of Maryland's participation in the Regional Greenhouse Gas Initiative (RGGI), a 10-state initiative that aims to reduce greenhouse gases.  Second, the plan would implement energy efficiency programs, including incentives and rebates for consumers to purchase efficient appliances and have home energy audits, as well as installing interruptible load (cycling) devices on their air conditioners.  Third, the plan calls for increased investment in new generation within the state, particularly investment in sources of renewable energy, including by improving grant programs for the development of solar and geothermal energy, encouraging long-term contracts for new generation, and evaluating the need to require utilities to build or purchase new generating capacity to meet peak summertime demand.  Finally, the MEA asks for additional resources to help it produce biennial state energy plans, encourage regional transmission planning, and stimulate clean energy within Maryland.

Maryland retail customers have in recent years faced significant increases in their electric bills, following the expiration of retail rate freezes on the state's utilities.  Moreover, Governor O'Malley has predicted that by 2011 the state will face electricity shortages during peak periods.

Final Skirmishes in Enron Contract Wars Draw to Close

Resolving the last remaining claims against Enron stemming from the 2000-2001 California energy crisis, over the past week, FERC approved two settlements involving Enron:  one with the Port of Seattle, Washington (Port), and the other with Public Utility District No. 1 of Snohomish County, Washington (Snohomish).  The Port receives a $500,000 unsecured claim against Enron in its bankruptcy proceeding, while the Snohomish will pay Enron $18 million out of the $180 million that Snohomish allegedly owes Enron in termination fees arising from Snohomish's cancellation of contracts it entered into with Enron during 2001.  FERC's approval of these settlements puts an end to rancorous litigation between the parties and dismisses Enron from the various California refund proceedings.

The Enron-Port settlement continued the debate among the current Commissioners with respect to the Mobile-Sierra "public interest" standard of review for contract modifications.  Commissioners Kelly and Wellinghoff each filed separate opinions to the order approving that settlement, expressing disagreement with FERC's approval of the public interest standard.  Both Commissioners have consistently criticized FERC orders approving the inclusion of the public interest standard in settlement agreements, arguing that the Commission should not bind itself to the that standard, which allows unilateral changes to an agreement only if required by the greater "public interest" ― a singularly demanding burden of proof.  Instead, Commissioners Kelly and Wellinghoff have argued, FERC should approve modifications to settlement agreements so long as they are "just and reasonable," which is considered a less rigorous analysis and makes it easier for agreements to be modified in the future.

In two recent decisions currently before the Supreme Court (the so-called Long-Term Contracts decisions), the US Court of Appeals for the Ninth Circuit questioned whether the public interest standard applies where a buyer challenges a contract price as being too high.

Incentive Rates to Support Transmission from Midwest Wind Projects

The Federal Energy Regulatory Commission (FERC) granted Xcel Energy Services, Inc.’s request for incentive transmission rates as part of Xcel’s plan for a $1 billion upgrade of its transmission grid inside the territory of the Midwest Independent Transmission System Operator (Midwest ISO).  The upgrades will help Xcel’s utilities meet state renewable electricity standards and serve increased power demand in the Upper Midwest.

Reflecting concerns that the Nation's transmission grid was not being adequately maintained and expanded, the Energy Policy Act of 2005 directed FERC to develop incentive-based rate provisions for transmission projects.  FERC did so in a later rulemaking, establishing numerous rates incentives comprising cost recovery, accelerated depreciation, and higher rates of return on equity for assets operated by ISOs/RTOs.  Utilities can establish eligibility for these incentives by demonstrating a relationship between the incentive sought and the transmission investments being made.   

Xcel proposed changes to its transmission rate formula under the Midwest ISO tariff to avail itself of two of the incentive rates.  FERC approved the proposal, which will grant Xcel (1) recovery of return on 100% of prudently incurred construction work in progress and (2) recovery of prudently incurred costs of transmission facilities that are canceled or abandoned for reasons beyond the control of Excel and its parent, the NSP companies.  FERC stated that the transmission upgrades will help bring renewable energy projects on-line, in compliance with various state renewable energy procurement requirements.  Xcel Energy has stated that it is seeking to build transmission to accommodate between 300 and 700 MWs of wind power.

No Free Pass for Absconding Duquesne Light, Say PJM and Capacity Suppliers

In December 4, 2007 pleadings to FERC, PJM Interconnection and several PJM member utilities and power suppliers did not oppose Duquesne Light's right to exit PJM’s organized market, but did ask the agency to impose conditions on Duquesne’s withdrawal.  Among those conditions, they asked that Duquesne be required to hold other PJM participants harmless and satisfy all of its PJM contractual agreements, including its existing forward capacity obligations. 

Rising capacity costs were one of the primary reasons Duquesne sought to leave PJM in the first place.  Duquesne applied to FERC in early November for approval to leave PJM and to join the Midwest Independent Transmission System Operator (MISO).  In its filing, Duquesne explained that PJM's reliability pricing model (RPM) has drastically increased its capacity costs—from the $1-$5/MW-day range to over $100/MW-day.  Duquesne also asked that FERC confirm that the utility will not be liable for any RPM-related costs for deliveries that occur after it leaves PJM.

In its December 4 response, PJM argued that Duquesne should be required to “uphold the commitment and obligations it has assumed and [ensure] that other parties do not unfairly shoulder the cost of those obligations.”  PJM also laid blame on Duquesne itself for the Western Pennsylvania utility's unhappiness with the new capacity market, suggesting that Duquesne had relied solely on PJM's capacity auction instead of contracting bilaterally for other sources of capacity.  The Pennsylvania Office of Consumer Advocate asked FERC to ensure that Duquesne's departure does not injure other PJM load servers.  Others, including several PJM capacity suppliers, attacked Duquesne's filing as inadequately supported to justify the drastic measure of leaving PJM. 

No Common Denominator on Capacity Markets

While organized energy market operators generally agree on locational marginal pricing (LMP) as the basic framework for valuing energy, no similar consensus attends capacity markets.  The New York Independent System Operator (NYISO) presently is retooling its capacity market for New York City in response to a FERC order, and the California Independent System Operator (CAISO) continues to wring its hands over the issue of capacity markets. 

Even though Consolidated Edison divested most of its New York City generation when the NYISO was created in 1999, ownership of in-city generation remained concentrated, requiring rules to mitigate installed capacity (ICAP) prices.  When talks about revising the ICAP rules broke down last July, FERC announced its expectation that the NYISO, working with market participants, would develop market rules that ensured long-term reliability without overcompensating generators.  In response, the NYISO proposed to continue to use auctions and a demand curve for pricing capacity, but also to add features such as must-offer obligations for larger suppliers, as well as an offer ceiling and price floors based on a percentage of the cost of new entry, in order to mitigate seller and buyer market power.  The market's response has been mixed.  Some have urged the use of forward capacity markets in the NYISO.  PJM and ISO-NE have adopted variations of that model, which entails procurement of capacity several years in advance, rather than only several months in advance.

Meanwhile, the CAISO continues its stakeholder process to develop a capacity market.  None will be in place as of the commencement of the CAISO’s LMP market in the spring of 2008.  This won’t be unique for organized market operators.  The Midwest ISO has no centralized capacity market, but instead relies on utility compliance with reliability obligations imposed by the applicable states and reliability organizations.  The Electricity Reliability Council of Texas likewise operates an energy-only market.  Concern by the CAISO and state authorities, however, have driven analysis of a potential capacity market in this energy-import dependent state.   But in November the CAISO’s market surveillance committee (MSC) recommended holding off on development of specific capacity market rules.  It pointed out that capacity market rules typically emphasized generator must-offer obligations, whereas the California’s needs tended to be more specific due to its environmental and renewable energy mandates, and reliance on imports, hydropower and intermittent resources.  Generator interests responded to the MSC’s opinion by pointing out capacity market rules were needed to help promote infrastructure development. 

Parties Submit Joint Settlement of Pacific Intertie Dispute

On November 21, PacifiCorp, Pacific Gas and Electric Company (PG&E), the California Independent System Operator (CAISO), and several others proposed to FERC an uncontested settlement that would resolve disputes over a 94-mile segment of the Pacific AC Intertie (PACI) transmission line between Oregon and northern California.  Uniquely, the 94-mile line at issue is jointly owned by two utilities, one, PG&E,  inside the CAISO, and the other, PacifiCorp, outside of it.  Under the proposed settlement, PacifiCorp and PG&E agreed to share equally the transmission capacity over the PACI between Malin, Oregon and Round Mountain, California, with PacifiCorp eventually providing service on its portion of the line under its open-access transmission tariff (OATT).

The dispute over the PACI began earlier this year.  The two 500 kV lines that comprise the PACI are co-owned by several parties.  PacifiCorp owns the northern half of the 94-mile segment on the eastern line, and PG&E owns the southern half of that segment and has turned operational control of its capacity over to the CAISO.  Since 1967, PacifiCorp had leased its share of the capacity for a low, fixed amount to several California utilities under a 40-year agreement.  Those utilities, in turn, placed PacifiCorp's portion of the line, along with PG&E's portion of the line, under the CAISO's operational control. 

With the capacity lease set to expire by its terms in July 2007, PacifiCorp filed a notice of termination in May, and informed FERC that it intended to begin to offer service over its 47-mile segment under its OATT.  This filing drew opposition from California utilities, the California Public Utilities Commission, and the CAISO.  PG&E in turn proposed revisions to the operating agreements for the line.  In July, FERC ruled that neither PacifiCorp's nor PG&E's proposals had been shown to be just and reasonable and convened a paper hearing to sort out the details. 

With the December 31 end of the suspension period fast approaching, the parties agreed that PacifiCorp and PG&E would "swap" portions of the capacity each owns under a 20-year agreement, such that each party will have rights to half of the capacity on the entire 94-mile path.  PacifiCorp also agreed to lease a portion of its capacity back to PG&E for a ten-year period, with some capacity becoming available under PacifiCorp's OATT beginning in 2012.  PacifiCorp and the CAISO also filed a joint operating agreement for PacifiCorp's share of the line, which continues to provide for CAISO operation of the capacity.  Other agreements relating to the operation of the California-Oregon Interface were also modified to reflect the settlement arrangements, and changes were made to PG&E's Transmission Owner tariff to implement cost recovery under the ten-year lease.  The settlement will thus compensate PacifiCorp for use of its portion of the line, while keeping the capacity within the CAISO's operational control.  The Commission has yet to act on the settlement agreement, and will need to do so by the end of the year in order for the new arrangements to take effect when the existing arrangements expire.

Demand Response Developments: Promotion and Quantification

Utilities and their regulators are increasingly taking steps to foster reductions in electricity demand — whether through improved efficiency in applications or demand management — based on a combination of economic, reliability, and, increasingly, environmental reasons.

FERC's recent creation of an Energy Innovations Sector (EIS) within the newly renamed Office of Energy Market Regulation (OMER) (formerly the Office of Energy Markets and Reliability) is intended to highlight and respond to the growing complexity and potential of demand response in U.S. electric power markets.   The EIS will focus on five areas—demand response, renewables, distributed generation, global warming and advanced technologies—and will be tasked with performing independent assessments of developments in each of these areas as well as serving as an in-house technical advisor on issues regarding the integration of these resources into FERC's traditional concerns of wholesale markets, reliability, transmission planning and resource adequacy. 

Regional collaborative efforts to encourage demand response are also gaining traction in the form of the Pacific Northwest Demand Response Project and the Midwest Demand Response Initiative in the last year.  In addition, the California Independent System Operator (CAISO) plans to open a demand response laboratory this month in an effort to educate consumers on the potential for and importance of demand response.  The lab will feature exhibits and information on the latest demand response technologies, ranging from thermostats that respond to FM radio signals to adjust air conditioning and other residential applications to an automated direct response programs for commercial and industrial clients.  The latter allows utilities and other demand response aggregators to bid in MW blocks of demand reduction at certain prices and allocate the revenue as they wish.  Increasing numbers of utilities are using programs such as these to meet supply.  Finally, the addition of third-party demand response providers to the mix further expands the range of demand response options. 

FERC's Assessments of Demand Response and Advance Metering, issued in August 2006 and again in September 2007, demonstrate, according to FERC Commissioner Wellinghoff, that implementation of demand response programs has shifted from a question of "whether" to a question of "how."  FERC plans to issue another report in 2008 and follow up every two years thereafter, with information updates in the intervening years. 

Other nationwide efforts are also underway to quantify and verify demand response resources.  Quantification can prove difficult since reliability-based demand response resources, such as direct curtailments or interruptible services, are easier to track than are economically induced resources that depend on variable levels of customer participation.  Both NERC and NAESB have undertaken efforts to calculate demand response potential in the U.S.  Also, the US Demand Response Coordinating Committee (DRCC), a group composed of utilities and other energy companies, is working to develop methods for verifying the contribution of demand response resources.

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

Duquesne Complaint Dismissed in Time for October 1 PJM Capacity Auction

The Federal Energy Regulatory Commission (FERC) dismissed Duquesne Light Company's (Duquesne) complaint seeking to avoid participating in  the PJM Interconnection's (PJM)  scheduled October 1 Reliability Pricing Model (RPM) auction in which load servers are obligated to secure capacity reserves, and ultimately to withdraw from the regional transmission organization.

Among many deficiencies in Duquesne's complaint, FERC found that Duquesne failed to address "'the practical, operational, or other nonfinancial impacts . . . including, where applicable, the environmental, safety or reliability impacts of' PJM's exclusion of the Duquesne Zone load from the October 1 auction," as well as how reliability will be maintained if the load in its Zone is removed from the October 1 auction.

Importantly, FERC relied on both the PJM Transmission Owners' Agreement and the Reliability Assurance Agreement provisions that require that a load-serving entity seeking to withdraw from PJM must make a filing with the Commission under section 205 before that withdrawal becomes effective.  FERC ultimately found that it was the "necessary section 205 filing, rather than this complaint requesting relief on an emergency basis, [that] is the appropriate vehicle for resolving all of the issues related to Duquesne's withdrawal from PJM."  It remains to be seen whether Duquesne will make the withdrawal filing since avoiding participation in the October 1 RPM auction is no longer a motivating consideration.

Rising Capacity Costs Prompt Duquesne Light to Divorce PJM

Duqesne Light Company wants to sever ties with the PJM Interconnection regional transmission organization (RTO).  Duquesne cites the increased capacity costs resulting from PJM’s implementation of the new reliability pricing model (RPM) for capacity sales, and is asking FERC to allow it to withdraw before PJM’s next capacity auction that will cover 2009 deliveries.  PJM responded that it is too late to exclude Duquesne from that auction, and that numerous questions must be resolved, including how Duquesne would resolve it reliability requirements.  A number of others have likewise objected to Duquesne’s precipitous withdrawal. 

Duquesne has stated it intends to join the Midwest ISO, which it already borders from its location in Western Pennsylvania.  Of course, PJM is not the only organized market where member dissatisfaction has led to withdrawal.  Stating that a cost-benefit analysis compelled the conclusion, Louisville Gas & Electric and Kentucky Utilities left the Midwest ISO in 2006.  And due to unhappiness with capacity markets that mirror Duquesne’s complaint against PJM, the State of Maine has threatened to withdraw from NEPOOL and thereby ISO-New England. 

While utility membership in organized markets is voluntary, it is clear that withdrawals raise vexing issues of allocating costs to a shrunken customer base as well as long-term planning.  With the complex RPM market finally in operation, market participants are already being forced to examine a new twist, the impact of a utility’s withdrawal on capacity procurement and reliability.

Southeastern Group Undertakes Regional Transmission Planning

A group of utilities in the southeast ― where utilities have to date resisted forming regional transmission organizations ― have announced a proposal to develop an interregional transmission planning process.  Under the plan to be released September 14, the utilities will work jointly to collect data, coordinate planning assumptions, and address stakeholder study requests.  The coordinated efforts will provide a centralized information source for transmission users, who will no longer have to consult each transmission owner separately.  The effort answers FERC's Order No. 890, which mandated broader regional coordination of transmission planning. 

Involved in the efforts are several major utilities, including Duke Energy Carolinas, Entergy, Progress Energy Carolinas, South Carolina Electric & Gas, Southern Company, and the Tennessee Valley Authority, as well as a number of municipal transmission providers and electric coops.  The effort will build upon a few small regional planning groups that already exist in areas of the southeast, such as the North Carolina Transmission Planning Cooperative, but will allow broader information sharing and cooperation across the entire region.

New York Commission Pushes Utilities to Decouple Revenue from Sales

The New York Public Service Commission (NYPSC) has ordered New York State Electric & Gas to develop plans for "decoupling" revenue from sales volume for both its electricity and gas service.  This is the State’s latest push to promote energy conservation, efficiency and diversification, but requires regulators to tackle the thorny issue that arise when utilities lose money if sales fall.

Increasing energy efficiency holds great promise for reducing the nation’s energy demand.  Efficient energy use may reduce energy production, lessens greenhouse gas emissions, and save fuel and infrastructure costs.  Utilities, however, typically profit in proportion to the volume of their sales. Consequently, efficiency that reduces consumption is not in a utility's financial interest.  Indeed, few industries, if any, tout a reduction in sales as a viable business model.

North Carolina Brings Southeast to RPS Table; Illinois & Delaware Expand RPS Laws

Various states around the country have recently created or expanded their renewable portfolio standard (RPS) requirements.  The combination of traditional RPS requirements with complimentary initiatives, including cost recovery incentives, energy efficiency directives and voluntary green power programs, characterize these recent additions to the nation's RPS goals.

With its recent enactment of a Renewable Energy and Energy Efficiency Portfolio Standard (REPS), North Carolina has become the first southeastern state to join the ranks of RPS states.  The REPS will be phased in beginning in 2012; it requires that by 2021 all investor-owned utilities within the state meet 12.5% of their 2020 energy needs from renewable energy resources or energy efficiency measures.  A reduced requirement of 10% applies to rural electric cooperatives and municipal electric suppliers.  Until 2018, up to 25% of the requirement may be met through energy efficiency efforts, including combined heat-and-power systems powered by non-renewable fuels.  After 2018, 40% of the standard may be met by energy efficiency strategies.  Other noteworthy facets of the new law are its provisions (1) permitting utilities to recover certain incremental costs incurred to comply with the REPS, to fund renewable energy or energy efficiency research, or comply with any future federal RPS mandate, (2) requiring electric power suppliers to implement demand-side management and energy efficiency measures and providing for cover recovery for those measures, and (3) extending rate recovery to construct costs associated with out-of-state generating facilities.   

Building on its previous voluntary renewable portfolio goal of 8% by 2013, Illinois recently enacted a new law that creates the Illinois Power Agency (IPA) and charges it with developing electricity procurement plans for state utilities serving over 100,000 customers and then competitively procuring energy according to those plans.  The IPA's procurement activities must also meet an expanded and now-mandatory RPS of 25% by 2025, beginning in 2008 with a 2% requirement.  A minimum of 75% of the renewable energy must be produced from wind.  The new law also requires that utilities establish annual energy savings goals in order to meet a percentage of their energy delivery requirements through efficiency efforts. 

CPUC to Consider Innovative Energy Efficiency Incentives for State's IOUs

The California Public Utilities Commission (CPUC) will soon consider an innovative incentive program to encourage the state's investor-owned utilities (IOU) to meet energy savings goals.  Based on an August 9 proposed decision by CPUC Commissioner Dian Gruenich and Administrative Law Judge Meg Gottstein, the proposal would pay the IOUs -- include Pacific Gas & Electric Co., San Diego Gas & Electric Co., Southern California Edison Co., and Southern California Gas Co. -- up to $323 million over three years if they exceed the base targets.  If utilities satisfy these goals, the plan would purportedly save California ratepayers $2.4 billion and cut about 3.4 million tons of carbon dioxide emissions in 2008.  Conversely, if the utilities fail to meet the base targets, the plan would impose monetary penalties on them.  The proposal caps both potential earnings and losses for shareholders at $500 million.

Commissioner Gruenich, the plan's chief proponent, argued that the proposal would provide "both a meaningful level of shareholder earnings and an estimated return of over 100 percent on ratepayers' investments in energy efficiency as the utilities reach toward and exceed our 2006-2008 energy savings goals."  The proposed decision is on the CPUC's agenda for its September 20 meeting.

Western Climate Initiative Seeks 15 Percent Reduction in Greenhouse Gas Emissions

Achieving one of the goals set for itself at its inception, the Western Climate Initiative (WCI) has pledged to reduce aggregate regional greenhouse gas emissions to 15 percent below 2005 levels by 2020.   

Initially composed of Washington, Oregon, Arizona, New Mexico and California, the WCI was established in February 2007 with the goal of collaborating on climate action initiatives across the Western U.S., Canada and Mexico.  Since that time, Utah and the Canadian provinces of British Columbia and Manitoba have joined.  Several other states and provinces have signed on as "observers" to the WCI, including Sonora, Mexico; Wyoming; Colorado; Kansas; Nevada; and Ontario and Quebec, Canada. 

According to the Statement of Regional Goal that WCI issued last week, the regional 15 percent goal reflects the cumulative emission reduction goals of the "partner" states and provinces, and does not replace those partners' existing reduction goals, some of which — such as California's — are more aggressive than the WCI goal.   

Connecticut Blocks Pipeline Across Long Island Sound

A US District Court vindicated Connecticut´s opposition to construction of a pipeline across Long Island Sound, ruling that the US Secretary of Commerce's decision to overrule the state's opposition to the pipeline was arbitrary and capricious.  Barring a reversal at some future stage of the case, Connecticut thus prevailed in the latest of its numerous high-profile energy disputes, which in recent years have included opposition to a direct-current transmission cable across Long Island Sound and disputes over electric power prices and market rules.  The case is of further interest because it involves litigation under the Coastal Zone Management Act (CZMA), a statute intended to balance decisional authority between state and federal agencies.

The Islander East Pipeline, which is jointly owned by Spectra Energy and Keyspan Energy, proposes to lay a 45-mile pipeline from Long Island to Connecticut.  To proceed, the project requires the go-ahead from the Federal Energy Regulatory Commission under the Natural Gas Act, but is also subject to the CZMA.  Under the CZMA, a state may develop a coastal management plan to help manage infrastructure and activities along its coast.  Connecticut determined that the Islander East Pipeline project was not consistent with is coastal management plan.  The Secretary of Commerce overruled the State, finding no alternatives to a project that met the CZMA requirement of advancing a national interest that outweighed local harms. 

Following an appeal by the State, the Court found shortcomings in the Secretary's analysis regarding the harm from the project and the potential for alternatives.  In particular, the Court found that the Secretary had failed to consider adequately the environmental impact of constructing the pipeline, including on shellfish habitat.  The Court further concluded that the Secretary had not considered adequately alternatives such as expansion of the Iroquois Gas Transmission System pipeline, which already crosses the sound, or placement of Islander East along that corridor. Following the Court's remand, the Department of Commerce will now reconsider its decision.

Illinois Rate Settlement Bill Awaits Governor’s Approval

Following months of contentious litigation and recriminations, Illinois power companies, politicians, and regulators have negotiated legislation to settle to the state’s retail electricity pricing dispute.  The settlement package would extend for four years, provide $1 billion in rate relief, and revise how utilities procure power going forward.  However, the tense uncertainty has not yet fully abated as Gov. Rod Blagojevich is reportedly studying the bill and has not yet decided to sign it.

The origins of the crisis extend back to the 1997 Illinois Electric Service Customer Choice and Rate Relief Law (Restructuring Law), which forced the state’s utilities to sell their generating units, although purchasers included the utilities’ independent merchant generation affiliates.  The Restructuring Law also reduced retail rates by 20 percent and froze electricity rates for bundled retail customers until 2006. 

Predictably, when the rate freeze expired, power prices spiked, consumers kvetched, and everyone pointed accusing fingers at the politician authors of the Restructuring Law and the power companies.  In March 2007, the state’s attorney general alleged sellers had manipulated 2006 auctions through which utilities bought power for resale to consumers for the period following the rate freeze.  In a complaint to FERC, the Attorney General asked FERC to order refunds and even revoke the market-pricing authority of some of the energy vendors who sold into the auction.  In response, wholesale sellers as well as ComEd and Ameren point out that the rate freeze had kept the retail electricity rates artificially low, and that increased fuel costs and inflation ― not manipulation ― were the main cause for the higher power prices. 

The most interesting part of the rate settlement is the method to be used for wholesale power procurement going forward.  In a move reminiscent of California's creation of a state power purchaser in 2001, a new state agency, the Illinois Power Agency, will oversee power procurement by utilities, and may even build generators and sell their output to municipal utilities and cooperatives.

States Pursue Cleaner, Sustainable Energy, but not Too Quickly

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. 

Missouri Legislature Dips Toe into Renewable Standards Pond

In late June the Governor of Missouri signed S.B. 54 that calls upon utilities to supply 11% of their retail load from renewable energy sources by 2020.  While Missouri's standards are a far cry from the ambitious efforts of states such as California (requiring 20% by 2010), New Mexico and Hawaii (requiring 20% by 2020), and Minnesota (requiring 25% by 2025), Missouri is well ahead of many others in the nation by establishing any goals at all for using renewables.

Missouri state lawmakers elected to set benchmark targets for public utilities to meet (4% by 2012; 8% by 2015; and 11% by 2020) and directed the Public Service Commission to develop standards for measuring electric companies' progress in meeting the targets.  The bill credits utilities for such diverse renewable technologies as yard waste in municipal landfills converted to methane gas, plasma arc technology, and other more traditional renewables such as wind and solar generation.  In addition, the bill requires retail electric suppliers to make net metering available to customers who have their own electric generation units powered by renewable energy resources.

While Missouri should be commended for recognizing the potential for renewables development in the region, the bill's benchmarks are modest.  Other states' renewable portfolio standards typically credit primarily new generation, but Missouri's new law credits all pre-existing renewable generation that remains in use.  In addition, the bill takes into consideration a utility's "good faith efforts" to meet the goals and will take into account that the utility is not financially harmed by those efforts.

Market Monitor Continues Lobbing Shells at Defensive PJM Management

The recriminations between PJM management and its market monitor have reached a crescendo.  In a June 12 multi-volume response to FERC's investigation regarding PJM Interconnection's (PJM) alleged interference of its market monitoring unit (MMU), Dr. Joseph Bowring, PJM Market Monitor, supplemented allegations made in an April 5 statement that PJM management violated the MMU’s independence and compromised other objectives of the PJM tariff.  Among the specific allegations, Dr. Bowring charges that PJM management: (1) refused to prosecute a unit's exercise of market power that resulted in costs to market participants to the tune of $20 million; (2) pressured the MMU to modify its position on mitigating market power in the new RPM capacity market; (3) authorized confidential procedures that gave PJM management preferential review authority over MMU reports effectively modifying Attachment M to PJM's tariff, which contains PJM's Market Monitoring Plan; (4) ordered the Market Monitor to remove a central conclusion from its 2005 State of the Market Report; (5) sought to change or delay the release of four MMU reports from 2004 to the present. (6) ordered the MMU in 2005 not to post minutes of a recent Market Monitoring Advisory Committee (MMAC) meeting and in 2006 ordered the MMU to remove the discussion of a recent FERC Order regarding market monitoring form the MMAC meeting agenda; (7) prevented the MMU from analyzing the BGS auction for the New Jersey Public Utilities Commission in December 2006; and (8) replaced the Market Monitor with the VP of Markets at PJM as the Chairperson of the Cost Development Task Force, a group responsible for developing, reviewing, and recommending standard procedures for calculating costs of products or services for cost-based rates analysis .

Concurrently PJM submitted its own two-volume response to the FERC, dismissing Bowring’s criticisms.  Contrary to Dr. Bowring, PJM contends that “there is no factual basis for any claim that PJM has violated its tariff."  According to PJM, no one has alleged "that the MMU was ever prevented from performing any of its tariff-defined functions or reporting to the Commission any instances of market manipulation or other inappropriate conduct in the PJM markets."  Furthermore, PJM concluded that no evidence has been presented to demonstrate "that the market monitor was prevented from bringing to the Commission's attention matters of concern regarding the markets."  

Dr. Bowring also disclosed information he claimed points to PJM management's interference with MMU staffing, including targeting specific MMU employees for PJM Markets Division openings and threatening to eliminate MMU control over its data and data management.  According to PJM, however, it has provided the MMU with all appropriate staff to "carry out its tariff-defined functions," including maintaining its reliance on contract labor and adopting an especially aggressive and enhanced retention plan to encourage current MMU employees to remain with the MMU during the review period associated with the Complaint and this investigation.  

Regulators and market participants, particularly consumer groups, remain anxious about the MMU’s independence and effectiveness pending resolution of the charges and counter charges.

Oregon's RPS Will Apply Broadly but with Large Gaps

Oregon became the last state along the west coast of the continental U.S. to enact a renewable portfolio standard (RPS) law.  It will require all retail providers in the state to obtain a certain percentage of their energy from renewable sources – up to 25% for the largest utilities – but the law also has numerous exceptions for cost and other factors. 

Under the RPS, utilities with at least 3% of Oregon's total retail electric sales must procure 5% of their energy from renewable resources by 2011, followed by 15% by 2015, 20% by 2020, and 25% by 2025.  Smaller utilities (1½ to 3% of all sales) must achieve 10% renewable energy procurement by 2025, with no interim targets.  The smallest utilities (less than 1½% of all sales) would need to procure only 5% of their power from renewables by 2025, with no interim targets.  Retail marketers would abide by the procurement levels of the utilities in the ESS' individual customer areas.  The law does not make clear whether existing renewable energy purchases count towards RPS compliance.

For sales under the RPS, generators that became operational on or after January 1, 1995 are eligible if they use hydropower (outside certain protected areas), wind, solar, wave, tidal, ocean thermal, geothermal, or a wide range of biomass except for trash or wood that is treated with chemical preservatives.  Older generators are eligible to the extent of capacity or efficiency upgrades or if they have been certified as low-impact hydro facilities.  Any renewable energy sold by the Bonneville Power Administration also qualifies under the law.  Eligible generators must be located in the U.S. portion of the Western Electricity Coordinating Council (WECC), but generators in the Canadian or Mexican portion of WECC can sell unbundled renewable energy credits (REC).

There are a number of exceptions in the law.  A utility is excused from the RPS to the extent that its compliance would cause it to:  spend more than 4% of its revenue requirement, as determined by the Oregon PUC on complying with the RPS; displace a consumer-owned utility's purchases of firm Federal Base System preference power rights from BPA; force a utility to purchase power beyond its needs in a given year; cause displacement of a utility's use of a non-fossil fueled resource; displace low-price hydropower from power contracts with Mid-Columbia River dams until those contracts could not be renewed or replaced.  In addition, a utility can make alternative compliance payments instead of procuring renewable energy.

The relative complexity, delayed implementation and numerous exceptions in the Oregon law may support arguments in favor of a national RPS with uniform standards rather than a patchwork of state laws that may fragment the renewable energy market.

Arizona Regulators Reject Cross-Border Transmission Line

The Arizona Corporation Commission (ACC) recently rejected an application by Southern California Edison Company (SCE) to construct a new transmission line from Devers, California to Palo Verde, Arizona.  The proposed Devers-Palo Verde No. 2 line ― a 230-mile, 1200 MW line estimated to cost approximately $600 million ― had already won approval of the California Public Utilities Commission (CPUC).  According to the CPUC, the line would serve as an important means of reducing the substantial congestion in southern California by expanding the transmission capacity into the area and allowing California utilities to import significant amounts of power from Arizona.  The ACC, on the other hand, dismissed the project as essentially allowing California to plug a "230-mile extension cord" into its generation supply, something the ACC found untenable at a time when Arizona's own population is growing rapidly. 

With both SCE and the CPUC considering appeals, the ACC's decision potentially sets up a fight under provisions of the Energy Policy Act of 2005 that allow FERC to site transmission facilities in certain Department of Energy (DOE)-designated National Interest Electric Transmission (NIET) Corridors for which state regulators have "withheld" approval for more than a year.  In a rulemaking issued late last year, FERC interpreted the word "withheld" in the statute to also mean "denied," thus potentially allowing transmission developers to bypass recalcitrant state regulators in favor of federal regulators.  In May, DOE proposed to designate an area encompassing the Devers-Palo Verde No. 2 line as a NIET corridor.

FERC to Investigate Claims of PJM Management Interference in Market Monitoring

Progress Energy Plan Will Encourage Conservation, Delay Plant Construction

Confronted with burgeoning demand, Progress Energy Carolinas (Progress) has set a goal of reducing demand by 2,000 MW through demand-side management efforts and energy efficiency programs.  The announcement comes less than a month after Duke Energy (Duke) filed a request with the North Carolina Utilities Commission (NCUC) to compensate the company for investments in energy efficiency and new technologies to meet its own growing demand. 

Progress has not yet proposed a similar compensation plan to the NCUC.  Its plan, however, seeks to double the approximately 1,000 MW being saved with programs currently in effect.  With these savings, Progress commits to postpone any plans for new coal plants, and delay consideration of a new nuclear reactor for two years while it evaluates the effectiveness of its stepped-up conservation efforts.  These efforts include the conversion of Progress' own buildings, plants and distribution and transmission systems to new, more efficient technologies, partnering with commercial, industrial and government consumers, including the military — a significant Progress customer — to help these consumers reduce their demand, and offering new energy efficiency programs to residential customers, including installation of latest-generation programmable thermostats, and increased residential HVAC maintenance. 

Qualifying Facilities No Longer Generically Exempt from Reliability Standards

On May 18, FERC made good on its promise to extend reliability standards to Qualifying Facilities (QF).  Order No. 696 overhauls regulations governing small power production and cogeneration facilities by eliminating previous exemptions of QFs from compliance with section 215 of the Federal Power Act.  According to the final rule, FERC believes "there is not a meaningful distinction between QF and non-QF generators that warrants a generic exemption of QFs from reliability standards."  QF generators, FERC explained, affect the bulk-power systems as much as non-QF generators and should therefore be similarly subject to new mandatory reliability standards that become effective on June 4, 2007.  

Commenters during the Notice of Proposed Rulemaking process for Order No. 696 urged FERC to consider a number of factors in its evaluation.  FERC was not persuaded and denied generic exemptions, including exemptions for QFs below a certain size or ones serving only behind the meter load.  FERC instead directed that North American Electric Reliability Corporation (NERC) or Regional Entities could consider factors warranting specific exemptions when an individual QF is evaluated for registration (the general procedures for registration are outlined at Section 500 of NERC's Rules of Procedure).   FERC explained that, in this regard, Order No. 696 puts QFs and non-QFs on equal footing "to not be subject to reliability standards" since the registration process is designed to determine applicability of the standards on a case-by-case basis.  FERC also pointed out that QF's still have the opportunity to appeal to the agency if the QF believes its registration was in error.

New Hampshire Commits to a Renewable Portfolio Standard of 25% by 2025

The New Hampshire Senate passed unanimously and will send to Governor Lynch House Bill 873, a renewable portfolio standard intended to promote fuel diversity, lower regional dependence on fossil fuels, reduce and stabilize energy costs, keep energy investment in the state, reduce greenhouse gases, improve air quality, and stimulate investment in renewable technologies.  Governor Lynch expressed his commitment for the RPS' ability to "help create jobs right here in New Hampshire by expanding uses for our wood products, in building clean power plants, and in research and development."

The legislature established four classes of renewable energy in its RPS.  Class I includes new (after January 1, 2006) electricity production from wind, geothermal, biomass and methane fuels, ocean thermal, wave, current or tidal energy, and energy displacement by end-users.  Class II includes new (after January 1, 2006) production of electricity from solar technologies.  Class III includes electricity production from existing (prior to January 1, 2006) small biomass and methane gas operations.  Class IV includes the production of electricity from existing (prior to January 1, 2006) hydroelectric energy.

Those utilities without renewable energy generation can purchase certificates in order to meet the requirements of the RPS.  Although certificates are to be purchased on the open market, they may be subject to price caps that vary according to the energy source.  In addition to setting target percentages by 2025, the legislature also established benchmark percentages for each classification in each year between implementation and 2025.