By Rich Heidorn Jr.

While PJM stakeholders were meeting last week to consider yet more changes to the Reliability Pricing Model, public power representatives took their case to Congress, telling the House Energy and Commerce Committee on Tuesday that they should be released from participating in the increasingly complicated capacity construct.

American Municipal Power and Old Dominion Electric Cooperative told the committee that FERC should allow public power utilities to fill their needs through bilateral contracts or self-supply instead forcing them to participate in mandatory capacity markets. AMP — which provides power supply and other services to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia — also complained that PJM’s Capacity Performance rules undervalue the company’s new hydropower facilities.

AMP Senior Vice President and General Counsel Lisa McAlister and ODEC CEO Jack Reasor testified along with representatives from independent power producers NextEra Energy and Calpine, utilities Public Service Enterprise Group and Duke Energy, and demand response provider EnerNOC.

The two-hour hearing, titled “Examining the State of the Electric Industry through Market Participant Perspectives,” covered many issues. Rep. John Shimkus (R-Ill.) and ranking member Frank Pallone (D-N.J.) said the testimony would help them decide whether the Federal Power Act is in need of revisions.

PSEG made a pitch for financial support for its New Jersey nuclear plants, which Calpine and NextEra strongly opposed. Duke asked for reforms to the Public Utility Regulatory Policies Act and a “shot clock” for regulatory approvals of pipelines and other infrastructure projects.

Former FERC Chairman Joseph Kelliher, now executive vice president for NextEra, also offered his company’s answers for the questions that Energy Secretary Rick Perry asked in commissioning a study of renewable resources’ effect on the reliability of the grid. It is market fundamentals — not public policies, he said — that are the primary drivers of “baseload” plant retirements, and there is “no evidence” that those retirements are threatening reliability.

No RTOs or ISOs were represented in the hearing. They will get their chance to speak before the committee in a second hearing on July 26. But PJM was invoked frequently, and generally not favorably.

PJM Capacity Market under Fire

McAlister’s 21-page written testimony — more than twice as long as any other witness’ — reiterated public power’s longstanding complaints with PJM’s capacity construct, calling it a “complex rules-driven administrative mechanism” that “relies on such distinctly non-market features as an artificial demand curve, price caps and minimum offer price requirements, and obstacles to competition from certain types of resources.

“RPM is a ‘market’ in name only,” she continued. “And, as time has gone on, fewer and fewer PJM market participants use that term to describe it.”

ODEC also criticized RPM, saying its experience “has been mixed at best.”

Reasor quoted from FERC’s April 2006 order approving RPM. “After [load-serving entities] have had the opportunity to procure capacity on their own, it is reasonable for PJM to procure capacity in an open auction at a time when further delay in procurement could jeopardize reliability,” FERC said, adding, “This, however, should be a last resort.”

Although the annual capacity procurement is still called the Base Residual Auction, “repeated and significant design changes have made RPM more complex and costly and have undermined the ability of load-serving entities to use their resources to meet their capacity obligations,” Reasor said.

The 2016 BRA was the first PJM capacity auction with no rule changes from the prior year, following 24 significant FERC filings to revise RPM between 2010 and 2016, Reasor said, quoting PJM. The last major change, the introduction of Capacity Performance, imposes “onerous performance requirements” on capacity resources, he said.

New Hydro Dissed by CP

McAlister also complained about CP, saying it undervalues the $3 billion AMP spent to install 300 MW of hydroelectric facilities on existing dams on the Ohio River because the projects cannot guarantee continuous, yearlong operation. “This is the case because AMP cannot control the river flows and cannot practically back up the hydroelectric plants with an alternative generation resource,” McAlister said. “In making PJM’s capacity construct less flexible, CP also has made it less capable of integrating the diversity of resources that may be an element of implementing important state policies.”

McAlister said PJM “needs a resource adequacy construct that is robust enough to withstand the effect of external events without the need to adopt another set of complex rule changes in response to each event.”

She and Reasor said LSEs should be permitted to fulfill most or all of their capacity needs through bilateral contracts, with the BRA relegated to a truly residual auction to fill any shortfalls. (See related story, PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)

As a “second-tier alternative,” McAlister said, public power’s ability to self-supply their own loads should be restored by reducing the role of the minimum offer price rule (MOPR).

Transmission Costs

AMP also complained about transmission costs, saying four of its members’ transmission zones have seen annual revenue requirements double or triple between 2009 and 2016.

AMP’s and ODEC’s complaints regarding the transmission owners’ handling of supplemental projects — those not required for compliance with PJM’s reliability, operational performance or economic criteria — prompted FERC last August to issue an order to show cause finding that the TOs’ procedures were not in compliance with FERC Order 890 (EL16-71).

FERC said the evidence indicated that some TOs are “identifying — and even taking steps toward developing — supplemental projects before providing any opportunity for stakeholders to participate in the development of those projects through the PJM [Regional Transmission Expansion Plan] process.”

The order resulted in a hiatus in a stakeholder initiative, the Transmission Replacement Processes Senior Task Force, pending the TOs’ response. Although the TOs insisted they are in compliance with Order 890, they proposed a Tariff amendment providing additional detail on supplemental projects. FERC didn’t rule on the TOs’ response before losing its quorum in February.

Stakeholders last month voted to end the hiatus, with task force meetings schedule to resume July 28. (See Load Blocks TO Effort to Delay PJM Tx-Replacement Talks.)

“AMP supports appropriate transmission infrastructure build-out to replace aging infrastructure,” McAlister told the House committee. “However, there needs to be more transparent transmission planning, equitable treatment, better oversight to ensure the most cost-effective and efficient grid expansion, and rates of return that reflect current economic conditions and risks.”

AMP asked Congress for “enhanced” oversight of FERC “to ensure that [the commission] is responsive to the real needs of consumers” by making low costs “a central part of the RTO mission, in addition to promoting electric system reliability.”

McAlister also said Congress should ensure that RTO governing boards “are truly representative and open [and] transparent” with open board meetings. While the boards of MISO, SPP, ERCOT and CAISO meet in open session, PJM’s board meets in private, as does ISO-NE’s and NYISO’s.

Nuclear Subsidies

The hearing also considered proponents and opponents of subsidizing nuclear plants. Tamara Linde, PSEG’s executive vice president and general counsel, repeated the company’s threat to retire its 3,500-MW Salem and Hope Creek nuclear plants in southern New Jersey. The plants, which are licensed until at least 2046, produce about 45% of the state’s electricity.

Linde said FERC should order PJM and other RTOs to “immediately” change their market rules to “preserve the diversity and resiliency of the nation’s electric generation resource mix.”

“Markets weren’t designed to drive to fuel diversity as an outcome, because fuel diversity in the generation fleet was always presumed,” she said.

Linde also said the U.S. nuclear supply chain should be considered “critical infrastructure, just as we regard our national highway system, electric grid and drinking water.”

Opposing nuclear subsidies were NextEra’s Kelliher and Calpine’s Steve Schleimer, senior vice president for government and regulatory affairs. Schleimer said competitive markets are threatened by both the zero-emission credits for nuclear plants in New York and Illinois, and New England states’ long-term procurement of renewables.

“If not addressed, out-of-market subsidies will undermine competition, investment will dry up, and these states will be back in the business of mandating when, where and what type of new generation will be built through long-term ratepayer guarantees, which is exactly the structure we moved away from several decades ago,” he said.

“A ‘hybrid’ market, where a state relies in part on the competitive wholesale electricity market to meet its resource needs, but also retains the right to select and subsidize preferred generation resource types to meet certain public policy goals, does not work and destroys all new competitive investment,” Schleimer said.

CAISO’s Lesson

He said the risk is playing out in CAISO, where he said the state’s “long-term contracting practices have decimated the competitive market.”

“It has led to the paradox that while retail rates are amongst the highest in the country as a result of these contracting mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources acquired or built when the market was competitive) is increasingly threatened.”

Alex Glenn, Duke’s senior vice president for state and federal regulatory legal support, had five requests to Congress, including swift confirmation of FERC nominees; the retention of the federal income tax deduction for interest expenses; “a reasonable ‘shot clock’ for actions on permit applications” for critical infrastructure projects; and a rewrite of PURPA to eliminate above-market must-take purchase obligations.

Glenn also said Congress should amend the SAFETY Act “to expressly include cyberattacks, and improve the process to obtain a security clearance so that we can increase the information-sharing capabilities between public and private entities.” Including cyberattacks under the third-party liability protections in the act would allow utilities and first responders to help recovery from an attack without the threat of “of protracted lawsuits in multiple jurisdictions,” he said.

In contrast to Duke’s lengthy wish list, Kenneth D. Schisler, vice president of regulatory affairs for EnerNOC, had only one request. Schisler thanked federal policymakers for removing market barriers to DR and said “it is vital” that FERC find a way to maintain competitive markets while respecting state policies. “Our only ask here today is that you continue to recognize demand response and its importance to our national energy strategy,” he said.