Shale Gas Impacts Cut a Wide Swath, Panelists Say

By Rory D. Sweeney

REV FERC Marcellus Shale Natural Gas — Gutierrez | © *RTO Insider*

HERSHEY, Pa. — From societal benefits to electricity market design concerns to regulatory issues, it’s clear that a decade of shale gas production has had a major impact that extends well beyond Pennsylvania’s borders, panelists said last week during a power industry seminar focusing on the Marcellus shale.

“It only seems appropriate to hold a discussion on competitive markets in a region that has one of the most impactful disruptions in the energy sector in recent history,” NRG Energy CEO Mauricio Gutierrez said at “Decade of Disruption: Marcellus Shale and Regional Energy Markets,” an electricity conference organized by John Hanger, a former Pennsylvania state utility regulator and environmental secretary during the early stages of Marcellus development from 2008 to 2011.

Gutierrez noted that the “shale gas revolution” has “changed the landscape” of the power generation industry and manufacturing in the U.S.

Marcellus Benefits

Philadelphia Gas Works CEO Craig White said one of the biggest advantages of shale gas for his company has been sustained low prices, which have allowed for investment in infrastructure.

“The biggest problem we had [before] is prices would spike above oil,” which reduced demand, White said. Low prices have allowed his gas delivery utility to replace aging distribution pipes while still lowering customer rates.

While shale gas has been an “unequivocal win for retail consumers … it’s also been a win for electric power customers,” said Christina Simeone, director of policy and external affairs for the University of Pennsylvania’s Kleinman Center for Energy Policy. “The electric power sector is really where prices dropped the most.”

Simeone reviewed the findings from her study on shale gas development that showed how a “Pennsylvania gas discount” has expanded low-cost gas-fired generation. (See related story, Study: Pennsylvania ‘Discount’ Spurred Spike in Gas-Fired Generation.)

“The electric power sector is now the natural gas industry’s No. 1 customer both in Pennsylvania and nationally,” she said.

Gas Role in Decarbonization

Increased reliance on gas is leading the power sector down the right path for decarbonizing the country’s economy, according to Risky Business Project research reviewed by the World Resources Institute’s Karl Hausker.

By transitioning energy consumption from fossil fuels to electricity, decarbonizing electricity production, and finally driving through any efficiencies developed along the way, the U.S. can reduce carbon dioxide emissions by 80% by 2050, Hausker said. But generators needn’t worry about betting the farm on renewables. If done correctly, it’s “an incredible growth opportunity for the electric power sector,” he said.

“It’s crazy to shut down a safe nuclear plant if it’s producing at a reasonable cost,” he said. “We are still [projected to be] using a lot of natural gas in 2050. … It is a key bridge fuel.”

While the Risky Business Project plan calls for hundreds of billions per year in infrastructure spending over the next 30 years, Hausker said the impediments are largely political, such as opposition to siting substantially more generation and transmission infrastructure.

“Technologically, we can do this. … Economically, the cost is manageable,” he said. “We really need to put the pedal down hard and really come up with better business models. … If you’re serious about [addressing] climate change, we have to build out the power sector, so please, tamp down the NIMBYism.”

The plan also “needs to be resilient in the face of falling fossil fuel prices,” he said, because International Energy Agency modeling indicates that by 2050, oil and coal prices will drop by 40% and gas by 33% compared to reference prices.

“Whatever we do, we’re going to need to expand the transmission system a lot too,” he said.

While speaking on a separate panel, ISO-NE CEO Gordon van Welie contended that expansion is more a challenge on the pipeline side than the wires side in his region.

“Quite frankly, it’s not likely. We’ve got as much pipe as we’re ever going to see in New England,” he said. “But for the fuel security issue, we’ve actually been a pretty reliable grid. … There’s hardly any congestion left in New England.”

Pennsylvania Public Utility Commissioner Andrew Place supported decarbonizing through the electricity industry. “If we are going to tackle our climate goals … the best way to do that is through our energy markets,” he said.

Decarbonizing the Industry

Who will lead the effort to decarbonize generation remains to be seen. As panel costs have plummeted, solar arrays combined with energy storage systems “can actually beat” gas-fired generators on price alone without factoring in renewable energy credits (RECs), Community Energy CEO Brent Alderfer said. The issue, he said, is getting long-term power commitments. “For some reason,” gas plants have been able to secure long-term investment based on short-term price signals while renewables have not, he said.

“The only folks that have taken a generation facility and turned it into what Facebook wants, which is a 15-year delivered power renewable contract, are cost-of-service utilities.”

Another panel discussion featured a debate on recent state and federal actions to promote large-scale, zero-emission production from nuclear plants.

NRG’s Abe Silverman argued that states, including Illinois, New York and — as of last week — Connecticut, have committed more than $10 billion to support aging nuclear generation that is too expensive to clear energy auctions, while new renewable development could produce the same power for half the price. He called for a process to identify the desired attributes (such as zero emissions) and value it so competitors can develop novel solutions to address them.

“Let’s compete for carbon production, not just hand it out on a no-bid contract,” he said.

Kathleen Barron of Exelon, the beneficiaries of zero-emission credit (ZEC) programs in Illinois and New York, argued the inverse, calling ZECs “short-term programs designed to bridge the gap” for states to develop carbon policies.

“It’s cheaper to keep the current fleet going than it is to build new renewables,” she said. “They are competitive [in markets] if you factor in the cost of the avoided emissions.”

Van Welie said he supported ZEC programs.

“It’s about jobs. I don’t know how you solve that problem through market design,” he said. “The New England states want to control the speed at which they go down the path of decarbonization. Given all the constraints on the system, that’s a pretty innovative outcome.”

PJM CEO Andy Ott reiterated his RTO’s position that subsidies suppress prices in competitive markets.

Where RTOs Fit

Ott and van Welie mutually opposed any single-solution federal mandates, such as the price supports for coal and nuclear units recently proposed by the Department of Energy. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)

“It’s not going to be productive for us to be forced to work on Andy’s problem or for Andy to be forced to work on our problem,” van Welie said. “We’re not going to build more coal in New England, so having a discussion about building more coal in New England is a pointless exercise.”

“The issues we’re facing are unique to our fleet. The issues Gordon’s facing are unique to his fleet,” Ott said.

The two CEOs agreed that the solution is defining and valuing attributes. PJM has run into problems posting negative prices to reduce wind production when there is oversupply because it harms large, inflexible baseload units dispatched earlier in anticipation of upcoming demand spikes. The RTO has proposed defining a “load following” attribute for the ability to adjust output as necessary and pay units to do so.

“What that does is it opens up that market,” Ott said, to “surgically” address the issue rather than with the “sledgehammer” of negative prices.

Completing Deregulation and the Promise of Technology

Pennsylvania’s deregulation 20 years ago was just the first step, said Jim Steffes, executive vice president for North American corporate affairs at Direct Energy.

“It wasn’t about design in 1997. It was about stranded cost recovery for utilities,” he said.

With consumers now holding increased technological power, such as through smart meters and other ways to monitor and control power use, they are much better equipped to engage directly with their retail supplier. For example, smart thermostats have been shown to reduce usage by 10%, Steffes said, and “it’s not forced conservation.” Yet, incumbent utilities maintain control of the customer interaction.

“Why do we still have this irrational, noncompetitive player in the market?” he asked. “The fact that we don’t know even know if they’re competitors or not creates a barrier.”

FERC Marcellus Shale Natural Gas — Starck | © *RTO Insider*

“We really have to get the utility out of the place of being the gatekeeper,” said Mike Starck, general manager of NRG’s northeastern retail business.

NRG’s Gutierrez had kicked off the conference on that issue, calling for four reforms in Pennsylvania by 2020. He argued that all “business transactions,” such as customer switches and sharing meter consumption data, should be standardized and routed through PJM, and that competitive suppliers should be allowed to compile all fees and send customers a single bill that includes utilities’ distribution charges, an idea known as supplier-consolidated billing. Currently, only utilities have that ability and suppliers must send a separate bill if they want to bill directly.

“It is essential to unlocking innovative payments and bundled products,” he said. “Consumers demand simplicity and convenience. They want a single energy bill that includes not only the energy needed to keep their lights on and houses warm, but also the other products and services that they need provided to them, whether it’s home security or energy efficiency devices.”

Gutierrez also called for defining and valuing necessary generator attributes and adjusting utilities’ tariff structures to prohibit them from offering retail products or generation.

October 31, 2017

Cost Estimates on DOE NOPR: $300 million to $32 billion+

The Department of Energy’s proposal to provide “full recovery” of coal and nuclear plant costs in RTOs with capacity and energy markets was short on details, notably providing no estimate of the cost of such policies.

But PJM’s Independent Market Monitor and several other stakeholders have published estimates ranging from $300 million to more than $32 billion. (See related story, Critics Slam PJM’s NOPR Alternative as ‘Windfall.’)

In its response to the DOE proposal, PJM’s Monitor estimated the NOPR would cost ratepayers in the RTO $3 billion annually — equal to 36% of capacity payments in 2016 — if nuclear and coal units were all paid 25% of current replacement value. (The current replacement value of a coal plant is $1,434/MW-day and that of a nuclear plant is $2,639/MW-day. In contrast, the gross cost of new entry for a combustion turbine is $312/MW-day and a new combined cycle is $406/MW-day.)

The cost would rise to $13 billion — a one-third increase in the total cost of wholesale energy — if nuclear and coal units were paid 50% of replacement value.

If the units received full replacement value, the price tag would rise to $32 billion — an 84% increase in total wholesale energy costs.

Robert Chilton, executive vice president of Gabel Associates and a former New Jersey regulator and consumer advocate, told FERC he calculated the NOPR would result in increased costs of about $7.1 billion annually for the first five years. Gabel mostly represents generators in PJM.

Chilton cited cumulative costs of between $35.4 billion ($28.9 billion net present value) and $100.8 billion ($64.1 billion net present value) over a five and 15-year term, respectively. His analysis assumes all fixed and variable costs are recovered by the eligible generators and all incremental net revenues are returned to customers.

Four Scenarios

A separate analysis, by the Climate Policy Initiative and Energy Innovation Policy & Technology, put the nationwide cost of the NOPR at between $300 million and $10.1 billion annually, based on which of four scenarios are used. (Energy Innovation is devoted to supporting policies “that most effectively reduce greenhouse gas emissions.” The Climate Policy Initiative seeks to improve energy and land-use policies to “help nations grow while addressing increasingly scarce resources and climate risk.”)

climate policy initiative PJM DOE NOPR Market Monitor — The upper-band estimate by two clean energy organizations projects coal generators would receive $3.5 billion in out-of-market costs, while nuclear plants would receive $6.6 billion, benefiting a handful of companies. | *Climate Policy Initiative and Energy Innovation Policy & Technology*

Their analysis assumed the NOPR would include PJM, ISO-NE and NYISO, which have mandatory capacity markets, as well as MISO, whose capacity market is voluntary.

The $300 million lower-band estimate assumes units with negative net cash flows (energy and capacity market revenue, minus the sum of fuel, variable and fixed operations and maintenance, and annual capital expenditures) receive uplift payments to bring their net revenue up to zero.

The $10.1 billion upper-band estimate assumes covered units would receive all their fixed operation and maintenance, full recovery of undepreciated past capital expenditures and ongoing capital expenditures, at a guaranteed rate of return, on top of energy and capacity market revenues. It also assumes payments to all coal and nuclear units in the RTOs — not just those with negative cash flows — and that coal plants will increase generation to their maximum output. (Nuclear units generally already run at maximum output.)

Small Number of Winners

About $7.3 billion of the $10.6 billion would be paid by PJM ratepayers, raising the RTO’s total costs by 17%. “Spreading the incremental costs evenly over the 65 million people served by PJM results in an increase of $112 per person per year (though this probably is not how costs would be passed through),” the report said.

In both the high and low scenarios, nuclear plants account for two-thirds of the out-of-market payments.

Under all four scenarios, more than 80% of the coal subsidies would go to five companies, with NRG Energy’s revenue boosted by $40 million to $1.2 billion annually, and FirstEnergy and Dynegy seeing an increase of up to $500 million each.

Exelon would receive half of the nuclear subsidies, as much as $3.6 billion. Other winners would include Entergy and Public Service Enterprise Group.

Depending on the final rule, the NOPR could also bring 2 to 4 GW of recently retired plants back into service, resulting in additional costs of $113 million to $228 million annually. “While costs represented here are annual, they could continue in perpetuity, since generators would now have no reason to retire,” the report said.

— Rich Heidorn Jr.

October 31, 2017

FERC Denies Rehearing on FitzPatrick Nuclear Plant Sale

FERC last week denied Public Citizen’s request for rehearing on Entergy’s sale of the James A. FitzPatrick nuclear plant in New York to Exelon. The commission dismissed as “irrelevant” the group’s concerns about the impact of the state’s zero-emissions credits (ZECs) on either Exelon’s market power or the broader NYISO energy and capacity markets.

FitzPatrick nuclear plan public citizen — James A. FitzPatrick Nuclear Plant

The commission authorized the sale last December over Public Citizen’s protests, saying the issues raised concerned the effects of the ZEC program rather than the impact of the plant sale on competition, rates, regulation or cross-subsidization.

In its rehearing request, Public Citizen argued that the commission had “committed errors of fact by inaccurately reporting the nature” of its protest, which “plainly and repeatedly raised the connection between the proposed transaction and the ZEC” program.

The commission’s Oct. 24 order (EC16-169-001) said that “under commission precedent, issues unrelated to the commission’s analysis of a proposed transaction under [Federal Power Act] Section 203 should be addressed in other proceedings or forums. Further, Public Citizen offers no analysis regarding how the [sale] would affect wholesale markets, with or without the ZEC program.”

— Michael Kuser

October 31, 2017

IMM, Consumers Miffed over PJM Plans for Checking Energy Offers

By Rich Heidorn Jr.

WILMINGTON, Del. — Consumer representatives and the Independent Market Monitor expressed concern Thursday over PJM’s plans for vetting energy offers exceeding $1,000/MWh, with the Monitor seeking manual changes and consumer groups fearing excessive demand response costs.

The issues arose during a discussion at the Markets and Reliability Committee meeting on changes to Manual 11: Energy & Ancillary Services.

PJM FERC Market Monitor Consumers Energy — Tyler | © *RTO Insider*

The manual changes, part of PJM’s implementation of FERC Order 831 (RM16-5), passed with 13 objections and two abstentions after Catherine Tyler, senior economist for Monitoring Analytics, reiterated complaints the Monitor filed with the commission in response to the RTO’s May 8 compliance filing on the order.

The order doubled the “hard” offer cap for day-ahead and real-time markets from $2,000/MWh — a response to the 2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs. Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum offer eligible for setting LMPs; approved offers over $2,000 are eligible for uplift payments.

The Monitor said PJM’s plan does not follow the order’s requirement that RTOs build on existing mitigation processes in verifying that offers above $1,000 are based on actual or expected costs and does not mention the Monitor’s role in that process.

“We will review offers over $1,000,” said Tyler. “The manual should make that clear.”

The Monitor told FERC that PJM instead “proposes to create a new cost-based offer verification process,” does not provide a way for verifying cost-based offers that fail its automated screen and lacks a process for verifying DR offers over $1,000. It said the commission should require “a new proposal that builds on existing cost verification processes, including the Market Monitor’s cost verification process and fuel cost policies.”

Greg Poulos, executive director of the Consumer Advocates of PJM States, requested the vote on Manual 11 be conducted separately from three other manual changes, saying the Monitor should have joint approval with PJM of energy offers over $1,000.

It was the DR issue that concerned Susan Bruce, of the PJM Industrial Customers Coalition. She said although her group is “a big supporter of demand response … we’re concerned we don’t have the same rigor” in ensuring the cost inputs in DR offers as for generation.

The lack of rules creates “opportunities for strategic behavior,” Bruce said.

PJM’s Pete Langbein said that although the RTO has considerable experience in verifying generation offers, “we’re a little bit in uncharted territory” for DR. He said PJM wants to analyze “what costs we see from DR in the next six to 12 months” before creating rules.

Bruce agreed it would be difficult to guess what costs DR providers will file but said that during the interim, “customers will be vulnerable” to potentially inflated and improper costs.

Langbein said PJM will address the issue in the stakeholder process and deal with offers in the interim on a “case-by-case basis.”

Bruce Campbell of CPower said he supported the RTO’s approach. “It’s difficult for me to imagine a standard that would be workable at this point beyond what PJM has outlined.”

PJM’s Chantal Hendrzak added that the RTO wants to wait for FERC’s response to its compliance filing before implementing standards. The rules will not go into effect until the RTO receives the commission’s response, she said.

Manual 11 also had been the subject of debate at the Market Implementation Committee meeting earlier in the month. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

The New Jersey Board of Public Utilities filed comments supporting the Monitor, saying, “PJM’s filing appears to be yet another attempt by PJM to minimize the role of the IMM.” The Delaware Public Service Commission called on FERC to reject PJM’s filing, saying its formulaic screen is unsupported and would result in higher prices than verifying all offers above $1,000.

PJM responded to the Monitor’s comments in June, reassuring FERC that all cost-based offers must be in accordance with the market seller’s RTO-approved fuel-cost policy, “including the IMM’s review of such policies.” The RTO said the proposed screen is “an additional safeguard” to ensure only legitimate generation offers greater than $1,000 are eligible to set LMPs.

October 31, 2017

PJM Grilled on Price-Responsive Demand Rule Changes

By Rich Heidorn Jr.

WILMINGTON, Del. — State and consumer representatives grilled PJM officials Thursday over proposed changes to price-responsive demand (PRD) bids, with the head of the Organization of PJM States Inc. accusing the RTO of flouting the 2005 Energy Policy Act.

PJM says PRD bids should be available year-round, the same as generation resources under Capacity Performance rules. But OPSI argues they should be allowed the option to make only seasonal contributions because PJM’s summer peak loads exceed winter peaks by more than 20,000 MW.

“What problem are you trying to solve?” asked OPSI Executive Director Gregory Carmean at Thursday’s Markets and Reliability Committee meeting. “The states obviously would like to see the effectiveness of their demand-side programs reflected in PJM’s load forecasts.”

PRD — a program that lets customers agree to reduce their loads in response to energy prices in exchange for reduced capacity requirements — was developed during 2010-12, before CP rules changed the requirements for demand response. It requires dynamic retail rate structures and advanced metering. PRD providers — electric distribution companies, load-serving entities or curtailment service providers — must be able to remotely curtail load when a PJM maximum emergency event has been declared and LMPs exceed trigger prices.

Because PJM approved its first PRD plans for the 2020/21 delivery year, it must now bring the rules in line with CP, the RTO says.

Thursday’s discussion came during a first reading of three proposals developed by the Demand Response Subcommittee.

The RTO’s proposal would extend DR’s annual requirements to PRD. A second proposal would limit the triggers for assessing CP penalties to just penalty assessment intervals. The third, from DR-participant Whisker Labs, would extend the existing PRD rules to the winter, create a summer-only product and allow it to be aggregated with a winter resource for an annual CP resource.

Carmean said PJM was acting in “direct contradiction of Congress’ intent” in the Energy Policy Act of 2005, which said that DR “shall be encouraged” and “unnecessary barriers to demand response participation in energy … markets shall be eliminated.”

PJM MOPR Demand Response PJM Insider — Langbein | © *RTO Insider*

“I have not gone back to read the law,” said PJM’s Pete Langbein, who presented the proposals, which the RTO plans to bring to an MRC vote next month. But he said PJM had made modifications to its monitoring and verification rules and expanded regions to ease requirements for DR. “We are continuing to work on this in the seasonal task force,” he said, referring to the group being created as a result of a problem statement and issue charge approved by the MRC in August.

Greg Poulos, executive director of the Consumer Advocates of PJM States, said he shared Carmean’s concerns. “Residential customers can no longer participate in this program,” he said. “Customers are kind of getting the short end [of the stick].”

“It seems to be a different product now,” added Morris Schreim, senior adviser to the Maryland Public Service Commission.

Carmean said the changes could mean “stranding hundreds of millions spent on [advanced metering infrastructure] meters. … OPSI believe the PRD program as it exists today should be allowed to continue.”

Earlier this month, OPSI drafted a resolution calling on PJM to postpone the imposition of annual resource requirements on PRD “until it has implemented an improved mechanism for summer seasonal resource participation in excess of winter seasonal resource participation, or until such time that winter reliability requirements equal or exceed summer reliability requirements.” (See “OPSI, PJM at Odds over PRD,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

On Friday, PJM CEO Andy Ott responded with a letter to OPSI. “PJM agrees demand response resources are valuable, and we seek ways to have them receive compensation in accordance with their contribution to reliability,” Ott said. “For seasonal resources that do not participate as Capacity Performance resources, the new stakeholder group will explore measures to value their contribution to grid reliability.”

October 31, 2017

PJM MRC/MC Briefs 10-26-17

Markets and Reliability Committee

Stopgap Balancing Ratio OK’d Despite Questions

WILMINGTON, Del. — PJM members approved a Tariff revision setting 78.5% as the balancing ratio to be used in calculating the default market seller offer cap (MSOC) for the 2021/22 Base Residual Auction next May.

PJM said the change was a stopgap measure required for next year’s BRA because there have been no penalty assessment hours (PAHs) since 2015. PAHs are one factor used to calculate MSOC for Capacity Performance resources. (See “Give me a B…,” PJM MRC/MC Briefs.)

The Tariff change passed with no opposition but 10 abstentions.

default market seller offer cap pjm — Greiner | © *RTO Insider*

The MSOC is the product of the net cost of new entry (CONE) and the average of the balancing ratios for the three years preceding the delivery year. PJM proposed using 78.5% because it was used for the 2020/21 BRA earlier this year.

“I’m not sure how you got here,” said Gary Greiner of PSEG Energy Resources & Trade. “I do know 78.5 is not the right number.”

Susan Bruce of the PJM Industrial Customers Coalition agreed that the stopgap number was not correct. “I think there’s something to be said for the fact that there have been no performance assessment hours. That should be telling us something, but that’s part of a larger conversation,” she said.

default market seller offer cap — Tyler | © *RTO Insider*

The Independent Market Monitor’s Catherine Tyler also criticized the number as incorrect. She said PJM should instead rely on its avoidable cost rates, which she said is “already well defined in the Tariff.”

With one abstention, members also approved a problem statement and issue charge to develop a long-term solution. The issue was assigned to the Market Implementation Committee with a target of developing a solution in time for the 2022/23 BRA.

Bruce asked that PJM make clear in its FERC filing that the 78.5% balancing ratio is “not to be precedential in any fashion.”

DER Subcommittee Charter Sent Back to MIC

The MRC postponed voting on a draft charter to transfer all work on distributed energy resources into a subcommittee because of a disagreement over a proposed amendment by FirstEnergy.

The charter would create the Distributed Energy Resources Subcommittee, reporting to the MRC. It arose from concerns that the current problem statement and issue charge on DER is overly narrow and inhibited discussions that should include markets, operations and planning implications. The talks had been taking place in special sessions of the MIC.

FirstEnergy sought to add an amendment saying “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).” (See “Amendment on DER Charter Sparks Debate,” PJM MRC/MC Briefs.)

MRC Secretary Dave Anders said that some stakeholders thought the amendment had been considered in the draft that came out of the MIC-DER group and others did not. The MIC did not formally vote on the measure.

As a result, the charter will be returned to the MIC, which will vote on versions with and without the amendment, with the winner brought to an MRC vote next month.

MRC OKs Sharing Generator Data for Restoration Planning

Members approved Operating Agreement revisions governing PJM’s sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)

The changes will allow PJM to provide confidential generator data for any unit:

that is or will be modeled in TO energy management system; and
that is or will be identified in a TO restoration plan.

The second reference to “or will be” was added as a correction between the first read and Thursday’s vote. The corrected version was endorsed with no objections or abstentions.

PJM Consulting with Chinese on Real-Time Market

PJM REV Market Monitor market seller — Daugherty | © *RTO Insider*

PJM Chief Financial Officer and MRC Chair Suzanne Daugherty informed members that the RTO’s consulting subsidiary, PJM Technologies, has signed a contract to help the Chinese province of Zhejiang develop a real-time energy market.

Daugherty declined to share financial details of the contract but said it will involve three to four full-time equivalent PJM staffers for 18 months. The province, south of Shanghai, has a load equal to almost half of PJM’s.

For security, the PJM employees will be working on dedicated computers separate from the RTO’s network, Daugherty said.

IRM, Manuals Endorsed

The Markets and Reliability Committee unanimously approved the 2017 installed reserve margin (IRM) study results. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

The IRM dropped nearly 1 percentage point, from 16.6% to 15.8%, for delivery year 2021/22, thanks largely to an anticipated fleet-wide EFORd (equivalent forced outage rate – demand) reduction from 6.59% to 5.89%. EFORd measures the probability a generator will fail completely or in part when needed.

The reduced EFORd is the result of 7,150 MW in planned retirements with a 14.56% weighted average EFORd, and the anticipated entry of 16,980 MW of new generation with a 4.42% EFORd.

The IRM will be 16.1% for 2018/19 and 15.9% for 2019/20.

The MRC also endorsed the following proposed manual changes with one abstention and no objections:

Manual 11: Energy & Ancillary Services. Revisions, which also include changes to the OA and Tariff, were developed to address capping of intraday offers. The current rule offer caps units that fail the three-pivotal-supplier test, but prohibits reapplying the cap during the unit’s day-ahead commitment or minimum run time. The changes would re-evaluate capped units when offers are updated. The changes would also apply to self-scheduled resources. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
Manual 14B: Regional Transmission Planning Process. Revisions developed to add information related to contingency definitions.
Manual 19: Load Forecasting and Analysis. Clarifies when load drop estimates are produced and includes updates from a periodic review of the manual. (See “Cleared PRD Forces Manual Revisions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

Members Committee

The Members Committee unanimously approved the IRM study results, the Tariff changes for the balancing ratio, and changes to Manuals 11, 14B and 19 approved earlier by the MRC. (See descriptions in MRC briefs above.)

The committee also approved Tariff and Operating Agreement revisions to clarify definitions, as recommended by the Governing Document Enhancement & Clarification Subcommittee.

— Rich Heidorn Jr.

October 31, 2017

Unanswered Questions Force Special PJM Session on OVEC Integration

By Rich Heidorn Jr.

WILMINGTON, Del. — PJM will hold a special meeting from 3 to 5 p.m. Nov. 7 to address stakeholder concerns over how the proposed integration of the Ohio Valley Electric Corp. into the RTO would affect existing members.

RTO officials agreed to schedule the meeting after being unable to quell stakeholder concerns during a presentation by OVEC’s Scott Cunningham at Thursday’s Markets and Reliability Committee meeting.

Stakeholders expressed apprehension over the future of OVEC’s generation and costs of potential upgrades to its double-circuit 345-kV transmission network, most of which dates to the 1950s.

OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service roughly 2,000 MW of load from a uranium enrichment plant near Piketon operated by the defunct Atomic Energy Commission.

Ohio Valley Electric Corp OVEC PJM — Clifty Creek Power Plant Complex | *Crowezr*

The company’s two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — are already pseudo-tied into PJM, and its eight “sponsors” can sell their portions of the output into the RTO’s markets. The generation would become internal to PJM following membership, eliminating the pseudo-ties.

MRC Chair Suzanne Daugherty said PJM had conducted operational and planning studies to ensure the integration would not harm reliability. General Manager of System Planning Paul McGlynn said testing also ensured the generation is deliverable.

But Steve Lieberman of American Municipal Power said stakeholders have not seen any analysis on the financial implications of adding OVEC. “There’s just a lot of things we don’t understand,” he said.

Six of OVEC’s eight sponsors — American Electric Power, Buckeye Power, Duke Energy, FirstEnergy/Allegheny Power, Wolverine Power Cooperative and Dayton Power and Light — are PJM members. Another sponsor, Vectren, is a MISO member. The final sponsor, PPL’s LG&E and KU Energy, does not belong to an RTO.

Cunningham said there had been “very little incentive” for OVEC to join PJM in the past because of the sponsors’ “different philosophy” and split between RTOs.

“All that has changed over the years,” he said. “For a small entity like ours, we have struggled with meeting compliance obligations.”

Direct Energy’s Marji Philips said the addition of OVEC’s 2,200 MW of 1950s vintage coal-fired generation is “very significant,” coming at a time when FERC is considering Energy Secretary Rick Perry’s proposal to grant coal plants cost-of-service rates. (Philips said PJM officials later informed her that 90% of OVEC’s power already flows into PJM, with 10% flowing to LG&E/KU.)

PJM’s internal “kick-off” discussion on integration was held June 6, according to spokesman Ray Dotter — nearly four months before Perry announced the proposed rulemaking.

Philips noted that the generators have been the subject of proceedings before the Public Utilities Commission of Ohio seeking to put them into the rate base. In March, for example, Duke Ohio asked PUCO to bill ratepayers for the costs of its 200-MW share of the plants, warning that “premature closing of the OVEC generating plants would have an immediate adverse impact on the communities in which these plants are located” (17-0872-EL-RDR).

“We do not anticipate them retiring any time soon,” said Cunningham, who said they had received “considerable” investments in environmental upgrades. “Those [subsidy requests] were made by the sponsors. We have never acknowledged that they were not economic.”

Delaware Public Service Commission staffer John Farber asked PJM for an estimated cost per mile for upgrading OVEC’s 345-kV transmission.

Vice President of Planning Steve Herling was reluctant to offer a number, saying “it would really depend” on the nature of the upgrade.

“Is it safe to assume it would be substantial?” persisted Farber, attending his last meeting before retirement. (See related story, Delaware PSC’s Farber Retires — Again.)

“I’m not jumping into that one,” Herling demurred.

October 30, 2017

AEP Falls Short of Q3 Expectations, Remains Optimistic

By Tom Kleckner

American Electric Power on Thursday said the mildest weather conditions since 1992 led its third-quarter sales to fall 12.8% from a year ago, down to $4.1 billion.

The Columbus, Ohio-based company reported a quarterly profit of $544.7 million, a vast improvement over last year’s loss of $765.8 million for the same period. A one-time $2.3 billion impairment charge in 2016 related to the value of competitive coal plants, wind farms and coal-related properties accounted for much of that loss. (See AEP Turns Away from Generation to Transmission, PPAs.)

But the company’s adjusted earnings per share of $1.10 missed the Zacks consensus estimate of $1.19. It was also down from $1.30/share — which excluded the impairment — a year ago. Its year-to-date earnings are $2.82/share, down from $3.25/share in 2016.

During an earnings call, CEO Nick Akins, a drummer in his spare time, drew inspiration from the progressive rock group Dream Theater’s song “Another Day” in reaffirming 2018’s guidance range of $3.75 to $3.95/share, built around a 5 to 7% growth rate. He recited the song’s lyrics to analysts: “Live another day, climb a little higher, find another reason to stay.”

“Because of our efforts to overcome the weather and other obstacles, we’ll finish out the year 2017, we’ll live for 2018, and continue on our path,” Akins said. “The fundamentals of our business plan remain secure, and we’re confident going into 2018.”

AEP narrowed its guidance range for 2017 to $3.55 to $3.68/share. Akins said the company will make up lost ground by “driving efficiency, eliminating expenses where practical and with negligible movement of expenses to 2018.” The company also expects to benefit from continued economic growth in its footprint.

Akins said AEP now has procedural schedules in the four state jurisdictions — Arkansas, Louisiana, Oklahoma and Texas — with regulatory oversight of the company’s proposed $4.5 billion Wind Catcher Energy Connection Project, a 2-GW wind farm in the Oklahoma Panhandle. Hearings will be held January in Oklahoma and Texas, February in Louisiana and March in Arkansas. The company has requested approvals by April 30.

“At this point, I should figuratively drop the microphone,” Akins said, “but we’ll let the facts — $4.5 billion invested, $7.6 billion in customer savings, substantial infrastructure development and great use of wind resources — speak for themselves.”

AEP also has $603 million in pending rate cases before five state regulatory commissions.

October 30, 2017

CPUC Bolsters Demand Response, Pans Resiliency NOPR

By Jason Fordney

SACRAMENTO, Calif. — California regulators voted Thursday to extend the life of a state demand response pilot project, saying they hope it could lead to a permanent program to help meet the state’s clean energy goals.

FERC CPUC Demand Response extended LMP — California PUC staff present their comments on the U.S. Department of Energy’s grid resiliency pricing rule proposal to the commission. | © *RTO Insider*

The California Public Utilities Commission heard from the public about several matters at the meeting, held across the street from the state capitol. The five commissioners were also predictably unified in their opposition to any possible FERC-proposed grid resiliency pricing rule as a result of the U.S. Department of Energy’s Notice of Proposed Rulemaking calling for financial support for nuclear and coal-fired power plants.

DRAM Extended

The PUC unanimously approved extending the Demand Response Auction Mechanism (DRAM) pilot program into 2018, against the recommendation of its administrative law judges.

“There were a lot of things that really led me to this decision to see the merit of continuing with this an additional year,” Commissioner Martha Guzman-Aceves said. The program has grown in terms of new participants, including low-income residents, “to levels that are really quite outstanding and different from the [investor-owned utility] programs.”

In the DRAM program, third-party sellers bid aggregated DR directly into the CAISO day-ahead energy market. Utilities acquire the capacity but do not receive revenues winning bidders might gain from the market. In the 2017 DRAM, third-party providers could bid in as both local and flexible resource adequacy, not just system resource adequacy.

Thursday’s decision requires Pacific Gas and Electric and Southern California Edison to procure $6 million of DR in their territories in a 2018 auction for 2019 delivery, while San Diego Gas & Electric must acquire $1.5 million. DR companies bid for the contracts on a pay-as-bid basis.

The program also created two new working groups: one to define new DR programs, and one to study barriers to DR.

Commissioner Liane Randolph said, “It is helpful for us to continue these pilot projects until the evaluation is complete, and we decide whether we are ready to adopt the DRAM as a permanent program.” By keeping the auctions going and modifying the guidelines, “we encourage market participants to continue to invest in this new type of DR,” she said.

Commissioner Carla Peterman said there are limited opportunities for DR.

“I do think it is important to continue our momentum in this area,” Peterman said. She noted the auction will use the same procurement guidelines as a permanent auction. “I think it will be a good opportunity to see how those guidelines work in practice,” she said.

Commission Encourages CCA, Direct Access DR

The commission’s decision also moves forward the process of enabling community choice aggregators (CCAs) and direct access (DA) providers to create DR programs to compete with those of IOUs.

California’s CCA program allows local governments to aggregate retail electric customers and secure electricity supply contracts to serve them, while the DA program allows some nonresidential customers — such as agricultural, commercial and industrial, and small business — to choose alternative electricity suppliers.

The decision allows CCAs and DA suppliers to file with the PUC to determine whether their DR programs are similar to those of utilities. The measure takes steps to implement the “Competitive Neutrality Cost Causation Principle,” which defines what constitutes a similar program and adopts a four-part process make a final determination. If a CCA or DA provider proves its case, competing utilities must cease cost recovery for DR from customers that sign up with the third-party programs.

Chairman Michael Picker said he supports the proposal, but he is concerned that by moving existing DR customers out of the rate base of regulated utilities into the rate base of the CCAs, “we are frustrating the second promise of the CCAs, which is that they will create competition. Here we are actually hindering competition.”

Picker added that it will be important to carefully analyze the applications for DR programs. “The practice has not always met the theory in CCA world; they have been uneven in actually expediting our drive for clean energy sources,” he said.

But he said he strongly support the continuation of the DRAM because it has created unique products, not just opportunities to arbitrage.

Strong Opposition to DOE NOPR

The commission also endorsed comments developed by staff in opposition to the DOE NOPR. Comments on the proposal were due to FERC on Oct. 23.

The approved comments state that “this rushed effort erodes trust in U.S. wholesale electric markets and undermines the role of the FERC as an independent body. If the energy crisis has taught us anything, it is that diversification of resources is critical for resiliency and reliability planning.”

Instead of narrowing the choice of resources that qualify as “resilient,” the PUC said there should be “a wide range” of tools to meet reliability needs, including energy storage, flexible demand and distributed energy technologies.

Picker said that while any such rule would have little immediate impact in California, it could in the long term, and it has aroused concern in neighboring states. He said it was a signal that the Trump administration does not “care to observe a series of long-held conventions on wholesale markets.” The parties creating the rule “don’t have their act together to actually come up with a reasonable argument” and “they have a prescription that is looking for a problem,” Picker said.

Commissioner Clifford Rechtschaffen said “this rule did what was otherwise unimaginable,” noting that it united petroleum, natural gas and renewable energy interests in opposition. “It is so beyond the pale,” he added, saying that PUC staff had devised a strong mix of legal and policy arguments against the rule.

October 30, 2017

Entergy Profits up as Company Continues Merchant Gen Exit

Entergy last week reported a third-quarter profit of $398.2 million ($2.21/share), up from $388.2 million ($2.16/share) a year ago.

“We now expect to finish the year in the top half of our utility, parent and other adjusted earnings guidance range,” CEO Leo Denault said in a statement.

The New Orleans-based company affirmed its 2017 operational earnings guidance range of $6.80 to $7.40/share, and its utility, parent and other segment adjusted guidance range of $4.25 to $4.55/share. Operational earnings do not include non-routine expenses, such as the costs to close or sell the company’s merchant nuclear power plants.

Denault said Entergy will work with regulators to recover $85 million to $120 million in Hurricane Harvey restoration expenses, and that the company expects $3 million to $5 million in unbilled revenue for 2017.

entergy profits q3 — Palisades plant | *Entergy*

The CEO also said Entergy’s recent decision to extend a power purchase agreement with Consumers Energy regarding the Palisades nuclear plant does not mean the company is staying in the merchant nuclear business. (See Entergy Abandons Palisades PPA Termination.)

“Our strategy to exit the merchant business and become a pure-play utility remains unchanged,” Denault told analysts in an earnings call last Tuesday. “This decision to continue to operate the plant will preserve value for our owners while extending our exit from the merchant nuclear business by only a year.”

— Tom Kleckner