Energy Legal Blog

Will High Congestion Costs Lead to More Defections from MISO?

Already one set of utilities has withdrawn from the from the Midwest Independent System Operator (MISO) after concluding membership in the regional transmission organization was providing inadequate benefits.  Now another utility has threatened to do the same.  In a recent filing at the Wisconsin Public Service Commission (PSC), Wisconsin Public Service (WPS) suggested that if new interstate power lines are not constructed to relieve grid constraints, it may withdraw from MISO, as did LG&E Energy and Kentucky Utilities [see Kentucky PSC Allows Utilities to Leave Midwest ISO].  

Wisconsin joined MISO based on the existence of temporary congestion cost protections.  As these protections are set to end in 2010, further congestion cost increases now loom for the Wisconsin-Upper Michigan System (WUMS), the most constrained region in MISO.  Due to an inability to import more power from outside of the state, WPS is forced to maintain a reserve margin of 18 percent, in contrast to the reserve margins of 12 to 14 percent maintained by other MISO-area utilities.  In addition, the WUMS experienced 94 hours with prices above $200/MWh in 2005, compared to 83 hours at that level for the rest of the market.  WUMS averages day-ahead and real-time clearing prices 33 percent higher than Minnesota and Chicago and 15 percent higher than Michigan.   

Anticipating NIMBYism, Vermont Regulator Seeks Help from Consultants

Project developers throughout the U.S. frequently must manage resistance to new energy infrastructure from local communities.  In an unusual twist, a state regulator that foresees potential energy shortages, the Vermont Department of Public Service (DPS), is seeking to hire consultants to help manage the ever-present "not-in-my-backyard" sentiment that continues to thwart energy planning in many parts of New England.

Two-thirds of Vermont’s power contracts expire between 2012 and 2017.  These include long-term deals with Hydro-Quebec and the Vermont Yankee nuclear plant.  While Vermont’s utilities are responsible for replacing these resources, the DPS wishes to engage with the public to help prepare a pathway for the eventual energy supply choices for 2012 and beyond.  The DPS’ solicitation is seeking consultants to assist with educating the public about the realities of power supply through measures such as polling, public meetings, web-based communications, and direct information sharing with citizen groups in an effort to discover areas of consensus before advancing an energy supply plan. 

Revised PJM Market Monitoring Plan Continues to Draw Ire

What role the market monitors of RTOs and ISOs should play in investigations and enforcement of market rules continues to be in dispute.  At issue is the perceived lack of accountability of RTOs/ISOs, together with mounting confusion over how much FERC has relied on and wishes to rely on market monitors to police markets.  PJM’s recent modification of its market monitoring plan has brought to the fore numerous concerns about the authority and independence of market monitors.

In May 2005, FERC issued a Policy Statement on Market Monitoring in which it attempted to better define the scope of a market monitors’ authority, and laid out those types of issues the market monitor had to refer to FERC rather than address itself.  Last month, the agency largely approved a PJM proposed tariff amendment that was intended to comply with the Policy Statement.  In the amendment PJM relinquished in favor of FERC any claim to authority to issue demand letters or request that market participants discontinue certain actions. 

However, separate requests for rehearing of FERC’s order were filed by the Pennsylvania Public Utility Commission, the Organization of PJM States, a coalition of state regulatory commissions of most of the states in which PJM operates, and the Indicated Parties — a hodgepodge of various consumer, industrial and municipal interests in the PJM region.  They complained that PJM’s plan (as approved by FERC) fails to grant the market monitors sufficient independence from PJM and market participants and denies them sufficient authority to communicate independently with FERC, state commissions, and  market participants or to fulfill its other responsibilities.  The petitioners echoed the dissenting statement of Commissioner Suedeen Kelly who had called for an investigation into whether certain aspects of PJM’s market monitoring plan were just and reasonable, and argued for greater specificity in the PJM tariff regarding the market monitor’s independence and authority.

PUCT Approves Increased Bid Cap, Disclosure Requirements for ERCOT

In order to encourage the development of new generating capacity and to make the Electric Reliability Council of Texas's (ERCOT) operations more transparent, on August 10 the Public Utility Commission of Texas (PUCT) unanimously approved a wide-ranging PUCT staff proposal to address the projected decline of generation reserve margins in ERCOT.  To encourage investment in new generating facilities, the PUCT plan proposes to gradually increase ERCOT's energy bid cap to $3000/MWh (up from $1000/MWh) by 2009, after ERCOT implements a nodal pricing market.  In addition, during the development of the proposal, PUCT staff considered establishing formal capacity markets, but rejected that approach in favor of an energy-only market, after determining that installed capacity markets do not offer market-based incentives for investment and would impose an unwanted layer of regulation.  The PUCT also cited the high costs of capacity markets to consumers, a fight that is currently being played out in other regions of the country [See, e.g., Capacity Market Redesign: New England Settlement Approved, PJM Proceeding Continues].

Related to the increased bid cap, the PUCT plan also increases and expedites the amount of market information that is publicly disclosed.  In approving the plan, the PUCT expressly linked increasing publicly available information with the increase in the bid cap.  The PUCT expects greater transparency in information flows will help police market power abuses that may accompany the increased bid cap.

The PUCT plan also adds several other features to the ERCOT market, including a definition of the term "market power" consistent with the definition commonly used by courts, and a requirement for more frequent reports from ERCOT on supply and demand issues.

Massachusetts Governor Issues Energy Plan Long on Conservation and Renewables

Massachusetts Governor Mitt Romney has issued a "Next-Gen" long-term energy plan that calls for a "negawatts" market in which utilities would pay customers for increased efficiency and reduced energy use when those payments are cheaper than constructing new power generation facilities.  In addition, the plan advocates market-based retail prices ― consumers would pay more for running appliances and other electrical devices at peak periods, while paying less at off-peak times.  Real-time pricing would apply to industrial consumers, while small business and residents would pay time-of-day rates.  The plan would also create a conservation lottery that would award prizes to customers who purchase energy-efficient equipment.   In addition, public buildings will become subject to new heightened efficiency standards, and tax incentives will be offered to encourage purchases of fuel-efficient vehicles. 

To promote renewable energy, the plan focuses on biomass energy, clarifying biomass's qualification under Massachusetts' Renewable Portfolio Standard, and expediting select wind project permitting (the plan supports several specific wind projects, but does not include the controversial Cape Wind project).   

To address lack of infrastructure, the plan seeks to encourage on-site generation by reducing the "standby" rates charged by utilities for backup service for companies that install their own on-site generation facilities, with a goal of 250 MW of new peak demand supplied by on-site generation by 2010 and 500 MW by 2014.   

California Comes Closer to Renewable Energy Tracking

The California Energy Commission (CEC) has taken another step toward meeting the California Legislature's mandate to create a tracking system to monitor compliance with the state's renewable portfolio standard (RPS).  Last week, CEC approved a contract with the Western Electricity Coordinating Council (WECC) that supports the Western Renewable Energy Generation Information System (WREGIS).  WREGIS is a voluntary, independent renewable energy registry and tracking system for the Western Interconnect that will be used to verify retail sellers' compliance with the California RPS.  WREGIS should ensure that renewable generation will be counted once only for purposes of meeting the RPS and will verify retail product claims in California and other states.  WECC will serve as the institutional home for WREGIS. 

WECC and the CEC expect WREGIS to be up and running by mid-2007.  While initially funded by California ratepayers, once WREGIS is operational it will charge user fees to recover its operating costs. 

Colorado, Oregon, Nevada, New Mexico, and Arizona are also considering requiring the use of WREGIS to ensure compliance with each of their renewable energy policies.  While the contract supporting WREGIS acknowledges that the tracking system could be used in other states, California is focusing on meeting its own accelerated RPS goal of 20% renewable energy by 2010; other states may need to work with WECC individually to tailor the product to their own needs.

Landmark Illinois Agreement Reduces Greenhouse Gas Emissions

In a divided vote last week, the Springfield, Illinois City Council approved a fist of its kind plan, an enforceable agreement with the Sierra Club, mandating reductions in the city's carbon dioxide emissions.  The agreement, between the Sierra Club and Springfield City Water, Light and Power (SCWLP) requires carbon dioxide emissions to be cut by 25 percent, the equivalent of taking 103,000 cars off of the roads, by 2012.

Under the agreement, SCWLP will close its oldest and dirtiest coal-fired power plant and replace it with a modern pulverized coal-fired 200 MW plant that meets Illinois' stringent air quality standards.  SCWLP will also reduce mercury emissions from new and existing coal plants by 90 percent by 2009 and reduce sulfur dioxide emissions from its new and existing coal plants by 75 percent by 1012. Further, SCWLP will construct 120 MW of new wind turbines, to be purchased by the City of Springfield, doubling Illinois' installed wind capacity.  In return, the Sierra Club pledged not to challenge the forthcoming issuance to SCWLP of an Illinois Environmental Protection Agency air permit for SCWLP's proposed 200 MW coal-fired generating project.  However, if any other environmental group appeals the air permit, then the Sierra Club/SCWLP agreement will be voided. 

FERC Reports Dismal Progress in Availability of Demand Response

Pursuant to a directive in the Energy Policy Act of 2005, FERC reported to Congress on August 7 that demand-response programs and technologies are "not widespread," detailing the state of advanced metering and demand response programs across the country.  The report, including its understated conclusion, summarizes a nationwide FERC survey and a technical conference that FERC convened in Washington, DC in January. 

According to the report, only about 5% of customers are currently enrolled in demand-response programs such as rate structures that vary based on time of use.  Only about 6% of electric meters make use of advanced metering technology capable of tracking the cost of power generation over time.  Despite these low numbers, FERC reported that interest in demand response is growing and noted a number of pilot programs. 

It is not from lack of interest that demand response initiatives suffer, FERC explained.  Rather, regulatory barriers in the US stymie demand response.  In particular, FERC noted the disconnect between retail prices that are often fixed and wholesale prices that fluctuate with the market, shielding retail customers from the true costs attributable to their demands for power.  Offering demand response is also counterintuitive for many utilities, since effective demand response programs would result in lower costs to consumers and thus lower revenues for the utilities.  One possible solution to this problem is to decouple utility profits from sales volume, which has been implemented in California and Oregon and is being examined in several other states.  Utilities are also hesitant to spend the money necessary to install the advanced metering technology that is needed to offer demand response programs.  There are also more formal state regulatory barriers, such as laws in several states that restrict the ability of regulators to implement critical peak pricing and other forms of time-of-use rates, and state policies on disbursement of societal-benefit charge funds.  Current retail and wholesale market rules can also limit participation in demand response programs; for example, RTOs and ISOs typically delay processing and disbursement of payments for demand reductions by at least 60 days—a time delay that can create cash flow problems for customers and service providers.

To overcome these problems, FERC's staff recommended that the agency continue to study the issue and work with state regulators to develop a coordinated regulatory approach to encourage demand response and eliminate regulatory obstacles.  The staff also recommended that FERC study how to better accommodate demand response in wholesale markets.

Solar Advocates Challenge PG&E Price Reduction

Spotlighting the challenges of balancing utility rates and renewable energy incentives, the California Solar Energy Industries Association (CALSEIA) has protested Pacific Gas & Electric Co.'s (PG&E) proposed revisions to its residential time-of-use electric rates.  According to CALSEIA, lowered summer rates will remove incentives for customers to go solar.   

Lower peak summer rates will protract the time required for solar voltaic customers to recoup their investment made in voltaic technology.  Among PG&E's filed rate revisions, which became effective in May, is a residential time-of-use service tariff that lowers summer peak rates by between 10 and 25 percent, while increasing off-peak winter rates by between 14 and 35 percent.  CALSEIA argues that the lower summer peak rates increase from 10 years to 13 years the period required for solar customers to recoup their investment, extending the payback time for solar photovoltaic systems by about 25 percent.   

US Appeals Court Balloons Seller Refund Exposure on California Sales during 2000-01 Energy Crisis

Nearly one year after ruling that FERC lacks jurisdiction to order governmental utilities to refund proceeds on their sales into the California Power Exchange (PX) and ISO markets during the 2000-01 energy crisis [see Court Limits FERC's Jurisdiction as Bonneville, Munis Escape Refund Liability in California Energy Crisis Case], the same panel of the US Court of Appeals for the Ninth Circuit ruled August 2 that the potential refund liability of other sellers — primarily investor-owned public utilities, independent generators and marketers — could go far beyond the parameters that FERC initially set. 

In addition to making refunds on sales into the PX and ISO single-price auction markets, the court ruled that sellers subject to FERC jurisdiction could also be required to make refunds on (1) out-of-market or OOM sales to the ISO for load balancing, (2) sales made during non-emergency hours when power supply was sufficient to meet demand,  (3)  bilateral block-forward sales to the PX, (4) exchange sales where power would be delivered to the ISO in one time period and repaid in kind plus a premium at a later time,  and (5) sleeve sales in which the seller was actually an intermediary between the PX or ISO and another seller who couldn’t or wouldn’t transact directly with the PX or ISO due credit concerns.  In each of these rulings, the court deferred to and upheld each FERC decision requiring refunds of charges in excess of a mitigated price, irrespective of how poor FERC’s reasoning or inadequate its evidence.  Conversely, the court was at pains to overturn any limitation that FERC placed on sellers’ refund liabilities (as in the case of block forward and exchange sales).  The only exception was the court’s reluctant affirmance of FERC’s decision that long-term bilateral sales to the California Department of Water Resources were not properly at issue in this case involving only sales to the PX and ISO; but even in so ruling the court hastened to add that California buyers “argue, with considerable force” that prices in those bilateral sales were unlawful and “may be the subject of other challenges.” 

Even more stunning than the panel’s single-minded drive to expand the universe of sales subject to refund was its directive to FERC that it expand the time frame of remedies by allowing California buyers to prosecute anew allegations of tariff violations for which refunds would not be confined to a period following a refund effective date no earlier than 60 days following the filing of a complaint.  FERC had confined refunds to sales occurring after October 2, 2000 — the refund effective date set when San Diego Gas & Electric’s lodged its August 2 complaint against sellers to the PX and ISO.  That limitation was wrong, according to the court, because FERC should have allowed the California complainants to seek refunds on earlier sales most, if not all, of which FERC itself had already investigated for tariff violations (including alleged violations of the ISO’s Market Monitoring and Information Protocols) and in many instances entered into settlements requiring the sellers to disgorge revenues back to California.  Although far from a paragon of clarity, the panel’s decision seems to direct FERC to permit the California complainants to seek further refunds on top of those FERC already exacted on some of the same sales to the PX and ISO.

Federal Agency Versus Federal Agency: FERC takes on TVA

FERC ratcheted up the rhetoric in its showdown with the Tennessee Valley Authority (TVA) over an interconnection agreement between TVA and a cooperative wishing to interconnect with its transmission system.  According to FERC, the agreement is discriminatory and TVA must fix it or face sanctions.

In 2005 FERC ordered TVA to interconnect with East Kentucky Power Cooperative to enable East Kentucky to sell power to TVA wholesale customer Warren Rural Electric Cooperative at rates lower than those charged by TVA.  In a January 2006 order FERC found that the interconnection agreement that TVA proposed inappropriately contained transmission charges for alleged loop flows on its transmission system as well as other discriminatory interconnection and coordination service terms and charges.  FERC ordered them removed.  But TVA refused to comply, resubmitting a replacement agreement that still contained inappropriate transmission charges.  In its latest order on TVA’s putative compliance filing, FERC reprimanded TVA for continuing to treat the interconnection service as transmission service and admonished the federally owned utility that it cannot persist in disregarding the Commission’s clear directives "simply because it does not agree with the Commission’s findings."

FERC advised TVA that it could appeal FERC’s directives to the federal courts, but that in the meantime it cannot ignore the Commission’s directives.  FERC then threatened that, absent a court-ordered stay, TVA's continued failure to submit a compliant interconnection agreement could result in FERC assessing civil penalties.