Public Power Magazine

Reforming Electric Markets


From the November 2013 issue (Vol. 71, No. 8) of Public Power

Originally published October 16, 2013

By Alice Clamp
October 16, 2013


The year was 2004. The setting: The American Public Power Association’s annual conference in Seattle, Wash.

“We had a session on RTOs―regional transmission organizations,” said Joe Nipper, APPA’s senior vice president for government relations. The room was packed, he recalled. “I was struck by the volume and pitch of member complaints about the RTOs, which were relatively new.”

“We had been early supporters of RTOs, which we believed would benefit our members by providing nondiscriminatory access to transmission, non-pancaked rates and generalized dispatch of generation,” Nipper said. “So we were stunned to learn that our members were upset and angry about start-up costs and their limited role in decision-making.”

The central concerns expressed about RTO-operated markets included high and volatile prices, difficulties obtaining long-term contracts, problematic governance processes and the complexity of these expanding markets. As a result of that session, he said, APPA realized it needed to act. The result was the Electric Market Reform Initiative.

APPA’s Executive Committee initiated EMRI about 21 months after that Seattle meeting, in March 2006. During its first year, APPA staff conducted a series of briefings for congressional staff to educate them about the changing electric utility industry and EMRI funded a series of in-depth studies aimed at analyzing the nascent RTO-managed markets. The findings of those studies informed EMRI’s subsequent work to educate policymakers about the problems engendered by RTO markets and to develop proposed reforms to those markets. Money to support those studies and other efforts over the past seven years has come from contributions from more than 500 public power utilities throughout the nation.

Recent EMRI focus

Over the past two years, EMRI has focused attention on two issues: RTO-operated capacity markets and proposals for the creation of an energy imbalance market in the West, said EMRI Manager Elise Caplan.

Capacity markets. APPA has participated in a number of dockets at the Federal Energy Regulatory Commission. One involved a complaint by a group of merchant generators and request to create barriers to entry by tightening the minimum offer price rule, or MOPR, for new natural-gas-fired generation in PJM’s capacity market. The MOPR is intended to mitigate “buyer-side market power” and instead simply serves to limit new supply and increase prices. PJM proposed similar rule changes, most of which were approved by FERC in April 2011. As a result, a previously existing exemption for generation built or contracted for self-supply was removed from the rule.

“Now, new natural gas–fired plants could be required to submit higher prices in an auction, making it less likely such plants will clear the auction,” said Caplan. “The generators are using complicated rules to prevent entry.” And, she added, these rules raise concerns about the ability of APPA members to supply their own load. “It’s a major issue for public power.”

The MOPR changes are being reviewed by the Third Circuit Court of Appeals, and EMRI funds are contributing to the legal costs of APPA, the National Rural Electric Cooperative Association and several publicly owned utilities that are participating in the court proceeding.

In the New England ISO, FERC ordered the development of a MOPR through the stakeholder process. The proposal filed by the ISO and later approved by the Federal Energy Regulatory Commission applies to all generation and demand-side resources, not just natural gas, and includes generation procured for self-supply purposes. APPA protested the proposal in a joint filing with the Northeast Public Power Association and NRECA.

In another case, APPA filed a request for rehearing of a “highly problematic” FERC ruling on the New York City capacity market. The ruling involved the sale of power by a new generating facility to the New York Power Authority under a long-term agreement. FERC determined that the generator cannot use its actual cost of capital when determining whether it is subject to buyer-side mitigation because this cost is “too low.”

After the Midcontinent ISO, known as MISO, proposed the creation of a centralized capacity market, including a MOPR, APPA filed a protest, along with a request―as was done in the PJM MOPR docket―that FERC initiate a full investigation of the capacity markets. In its June 2012 order, FERC ruled that the MISO capacity market would not be mandatory and would not include a MOPR, a partial victory. But this past August, FERC agreed to accept briefs on the question of whether a MOPR is needed in the MISO market.

In addition to FERC dockets, APPA has participated in state efforts, including submitting comments and testifying at hearings held by state public utility commissions. APPA staff also has worked to educate members of Congress on the problems of RTO markets. One outcome of these efforts was a request from several members of Congress for a Government Accountability Office analysis of the impacts of RTO-operated markets on demand response and energy efficiency programs as well as on the availability and use of bilateral contracts to support new generation. APPA staff has provided extensive material to GAO to help in this study.

In 2012, APPA released three papers highlighting the ineffectiveness of the capacity markets in promoting the construction of new capacity.

This past September, FERC held a day-long technical conference on the capacity markets. In her written statement, Sue Kelly, APPA’s senior vice president for policy analysis and general counsel, and one of the selected panelists at the conference, told FERC that the capacity constructs administered by RTOs should be voluntary, not mandatory. They “should be redesigned to act as residual markets in which both [load-serving entities] and resource providers can obtain and lay off capacity resources on the margin,” she said. Kelly also recommended that the commission restore the ability of public power utilities in the three eastern RTOs to self-supply their own loads with their own resources.

Another panelist at the conference, Jim Jablonski, executive director of the Public Power Association of New Jersey, in his statement urged FERC to consider the impacts of the centralized capacity and other RTO markets on end-use customers and the economy. He called for “a balance between the costs to achieve RTO/ISO goals―including resource adequacy―and the interests of those who pay those costs.”

FERC continues to explore issues through technical conferences, said Patrick McCullar, president and CEO of the Delaware Municipal Electric Corp. “But there has been no significant action by FERC addressing existing problems.”

Western energy imbalance market proposal. The impetus for an energy imbalance market in the West came was a proposal by two committees of the Western Electricity Coordinating Council, or WECC, had for the establishment of an EIM in the portions of WECC that are not part of the California or Alberta ISOs. The market would be a sub-hourly, real-time, centrally dispatched energy market that would provide for the purchase and sale of imbalance energy or deviations from expected supply and demand.

The rationale is to help to integrate variable resources by providing for the dispatch of energy and access to transmission over a wider geographic area. WECC agreed to commission a cost-benefit analysis of the proposal, which showed net costs in some scenarios. The primary forum for discussions of an EIM has since shifted to the PUC EIM, a taskforce established by the Western Governors Association and comprised of state public utility commissioners who are supportive of an EIM.

A number of APPA members are concerned that an EIM is the beginning of a path to a FERC-jurisdictional RTO and that any benefits would be outweighed by internal infrastructure and staff costs and harm to consumers as a result of higher prices. Other members are carefully considering the costs and benefits of an EIM.

APPA is working with members in the region to communicate the high costs and risks of the market’s implementation.

The formation of an EIM―originally included as one of a number of recommendations for the Power Marketing Administrations―was dropped from the final recommendations of a joint Western Area Power Administration-Department of Energy team. But the concept is still moving forward.

The main EIM activity at present is the California ISO and PacifiCorp proposal to create an EIM by October 2014 that would be operated by the CA ISO. Additional entities will be invited to join this EIM in 2015. In addition the Northwest Power Pool is also in the process of analyzing an EIM as well as interim measures to integrate renewable energy in the region that do not entail a full EIM.

“There’s a fairly organized effort to push an [energy imbalance market],” said Nipper.

Different regions, different priorities

Member views of RTO markets can vary from region to region―and even within a region. One explanation may be the evolution of an issue. Capacity markets, for example, are well-established in the East, relatively new in the Midwest and under discussion in the West. Other concerns, such as benefits to the end-use customer and market complexity, are common to most RTO markets.

PJM Interconnection. There are definite benefits to the market created by PJM, said Delaware Municipal Electric Corp.’s McCullar. “But the design of those markets needs a lot of work. We are of the opinion that PJM is inherently biased toward the needs and wants of the legacy transmission and generation owners.”

As one of the load-serving entities, he said, “we’re the guys writing the checks and we need to be given equal consideration and treatment in all market operations. I don’t feel we’ve achieved that yet.”

McCullar identified two areas of major concern: the right of first refusal granted to legacy transmission owners, which can inhibit robust investment in transmission development, and the capacity market, known in PJM as the reliability pricing model, or RPM. “The RPM rules lean toward the legacy generators, not the load-serving entities wanting to self-supply or new generation investment,” he said. “The minimum offer pricing rule [MOPR] is anticompetitive and keeps new, efficient and competitive generation, including LSE self-supply generation, from entering the market. These barriers to entry must be addressed either by FERC or Congress.”

There is a need for a minimum capacity market, said McCullar. “But the RPM generates prices well above those needed to sustain generation.”

New York ISO. The state-wide concept of open access to transmission provided by the NYISO is a positive aspect for the village of Rockville Centre, said Paul Pallas, electric utility superintendent. “We’re a transmission-dependent utility, so that’s important to us.”

Pallas, who also serves as president of the New York Association of Public Power, said the ISO governance isn’t perfect. “But it probably allows for fairly significant participation on the part of public power and customers generally.”

On the other hand, Pallas points to locational marginal pricing, or LMP, as a negative feature. “We’re in a horribly congested region and conceptually, LMP-based pricing is not a good idea. It doesn’t serve to control pricing.” He noted that, fourteen years after the NYISO began operation, sufficient transmission has not been built to relieve congestion into southeast New York.

The capacity markets are generally problematic, said Pallas. Part of that has to do with the lack of transmission to make capacity deliverable state-wide. “Because of the way in which the locational capacity market is administered, I’m required to own or have contracts or capacity for virtually all of my peak load located on Long Island,” he said. “We’ve always had some generation, but not enough for full load.”

There’s another problem, too, he said. That’s reliance on the short-term market, the spot market, the day-ahead market rather than bilateral contracts. “The perception that the NYISO markets are the only game in town and that bilateral contracts are a distortion, is a direct assault on our business model”, said Pallas.

Asked if the benefits of the RTO managed markets outweigh the disadvantages, Pallas replied: They don’t come close.

“The ISO market is a direct assault on our business model. It pushes us away from self-supply,” he said.

Midcontinent ISO. The market in the Midwest was without transparency before MISO, said Jay Bartlett, president and CEO of Prairie Power Inc., an Illinois-based generation and transmission cooperative. Before assuming his current position, Bartlett served for two decades as chief executive of City Water, Light & Power in Springfield.

The MISO market’s risk management tools are a benefit, Bartlett said. As an example, he mentioned the ability to bid in virtual load or virtual generation in the day-ahead market.

“In MISO, all entities―large and small―can participate in the creation of rules and business practices. There’s democracy in the stakeholder process.”

The first drawback that comes to mind, he said, is the relative immaturity of some markets. “We would like to see further development of the capacity market. Right now, the capacity market doesn’t seem to be sending the right price signals to prospective power plant owners.”

He thinks reform and change in the capacity markets are needed. “What we have now isn’t working, and in my opinion it extends across MISO and PJM.”

Still, in Bartlett’s view, the benefits of MISO outweigh the negatives “by a vast margin.” Initially, he was skeptical of RTO markets. “But as they evolved, we learned how to take advantage of their features to the benefit of our members. It leveled the playing field between us and larger utilities in the market.”

One challenge is the steep learning curve involved, said Bartlett. “It’s difficult in the beginning, and the time and effort required to stay current are ongoing.”

Eric Hobbie, chief utilities engineer at City Water, Light & Power in Springfield, Ill., said the greatest benefit of the MISO market has been transmission revenue for the municipal utility. “Much of the generation is in the southern part of the state and a lot of megawatts flow north through our system,” The CWLP system, he said, is an important interconnection in central Illinois. “Before MISO, we didn’t receive any revenue for the transmission flow. Now we do.”

And from the public power perspective, MISO has increased the liquidity of the market, Hobbie said. “The market provides a nondiscriminatory method of buying and selling power.”

On the other hand, the market’s complexity demands an appropriate amount of institutional knowledge, he said. “We would need a large staff just to stay current on all the new rules, rule changes and to voice our concerns. That’s very difficult for a small utility.” So CWLP, and other municipal utilities, partner with the Energy Authority, a non-for-profit corporation that provides risk management services for public power utilities. “The Energy Authority acts as an extension of our staff, using its collective store of knowledge to help municipalities participate in the market,” Hobbie said.

“In the beginning, MISO was an advantage for us,” he said. “But when we look down the road, I’m not sure.” Hobbie acknowledged that the utility doesn’t have much choice. “We’re surrounded by MISO market entities, so we have to participate.” Hobbie is most concerned over future generation capacity needs within the market.  “With increasing regulatory pressure and aging units, many plant closures are planned over the next several years and the current prices of energy and capacity do not provide nearly enough financial incentive for new generation to build in a free market.  It could be a bumpy ride for utilities and the consumer over the next 5 or so years.  CWLP owns enough generation to cover our load, but those on the buying side could face scarcity pricing.  The market is not structured to effectively deal with this problem.”

California ISO. Some benefits of the California ISO are theoretical and some are actual, said John DiStasio, general manager and CEO of the Sacramento Municipal Utility District, known as SMUD. “In theory, and perhaps in reality, a larger footprint for coordination of generation assets improves their efficiency and reliability,” he said. “A common tariff has made it easier for generator transactions.” But, he added, “it’s a double-edged sword and no one size fits all.”

Among the drawbacks, he said, is increasing complexity―and benefits are not commensurate with that complexity.”

The California ISO is good at allocating costs, DiStasio said, but it’s not very good at reducing them.

“The focus is on wholesale transactions and generators,” he said. “There’s no accountability to end-use consumers.” When costs are thrown into a pool and allocated, their impact tends to be muted. There’s a certain amount of economic discipline in bilateral agreements, said DiStasio. “But there’s less discipline when costs are spread like peanut butter across all market participants.” Because of significantly higher costs and fewer customer benefits, SMUD has only limited interaction with the ISO market, he said. 

Complexity also is a concern, and it works against efficiency. “When the market started, there were about 300 pricing nodes for congestion,” DiStasio said. “Now there are 3,000 congestion nodes.”

Although SMUD transacts limited business in the California ISO, it is not a member. But the Northern California Power Agency, a joint action agency with 14 members, is.

For NCPA, one benefit of the ISO is the transparency of its operation, said David Dockham, the agency’s assistant general manager for power management. “There are more than enough stakeholder processes to get issues addressed,” he said. The downside is the number of processes―more than 50―which creates volume and complexity issues. “That makes it difficult for small entities to participate.”

 Some utilities in the Western Area Power Administration service area are working toward implementation of an energy imbalance market, Dockham said. “There’s clearly interest among investor-owned utilities in the Northwest and the Southwest.” It wouldn’t affect the way NCPA schedules or purchases electricity, he said. “But it would have a more insidious effect on us. Some of the design features may shift costs to Californians within the ISO. We’re keeping an eye on that.”

Studies of an EIM to date indicate a relatively small benefit for such a market, said SMUD’s DiStasio. “It’s less than 1 percent across the entire Western Interconnection. And there’s high uncertainty about the costs of establishing and maintaining an [energy imbalance market].”

EMRI’s value

“I’ve been a fan of EMRI since day one,” said Jim Pope, NCPA’s general manager. “The beauty is in the eye of the beholder, but you can find examples of EMRI’s tenets mirrored in an RTO, including what’s happening in California.”

And when studies conducted during the first phase of EMRI were delivered to the Federal Energy Regulatory Commission, it was so well done that the commissioners didn’t know what to do with it, he said. “So they asked APPA to go back and develop a plan for solving the problem.” APPA did so and took its carefully crafted Competitive Market Plan plan to FERC in 2009.

The plan made the commissioners stop and reflect, said Pope. “EMRI got their attention. It said: Think about the consequences of going too far, too fast.”

SMUD’s DiStasio called EMRI “terrific.” It created a repository of objective work and recommendations, “studies that we rely on.” And it has helped to shine a light on RTO markets, he said. “It’s been very helpful in advocating for objective metrics. How do we measure the effectiveness of these markets? There’s been no good effort on behalf of FERC to undertake this oversight.”

APPA has made a strong commitment to the EMRI process, said NYAPP’s Pallas. He points to a cooperative relationship between the national association and regional groups. “APPA gets directly involved in some issues because of EMRI, bringing those issues to a higher level,” he said. “NYAPP talks regularly with our congressional delegation, but we coordinate with APPA on issues.”

EMRI sponsored a summit on capacity markets for public power systems in California, said Jane Cirrincione, assistant general manager for legislative and regulatory affairs at NCPA. “We could tap into that expertise and learn from the mistakes and successes of other regions, learn how to participate in capacity market development in California,” she said. “That was an important contribution by EMRI.”

The markets exist and must be made to work, said NCPA’s Dockham. “EMRI provides the best design elements to make them work,” he said. “EMRI has armed us with the tools to put those designs in place.”

It’s difficult to measure the success of EMRI and its Competitive Market Plan, said NYAPP’s Pallas. “We can’t show that something didn’t happen,” he said. “Progress is a relative thing. But if we hadn’t created EMRI, things could be worse.”

APPA’s Nipper agrees. “We operate on the ‘but for’ principle. But for what we’re doing, things would be a lot worse.”

But he noted that the work managed by Caplan, especially the studies and articles, has been widely used and cited by others. “We frequently meet people who thank us for doing all this work.”

Going forward

EMRI is now in a continuous monitoring phase, with ongoing studies and communication, said Caplan.

“EMRI needs to go forward,” said NYAPP’s Pallas. “Keeping the Competitive Market Plan up to date is a necessary piece of EMRI’s effort.” He also suggested reaching out to other groups, such as advocates for residential customers, and getting them to focus on these issues.

DEMEC’s McCullar, too, wants to see EMRI’s work continue. “It’s an effective way to push the issues of concern to us.”

EMRI is APPA’s hallmark, said NCPA’s Cirrincione. “We’ve always had a strong voice in Washington, D.C., and EMRI is a great way to use that voice.”

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