SPP’s Seams Steering Committee can expect to soon see a final scope of the next planned joint transmission study with MISO.
Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” SPP Seams Steering Committee Briefs.)
“The scope will leverage some of the work we’ve done regionally,” Bell said.
The study is planned for completion in the first quarter of 2017.
SPP staff also told stakeholders it had filed an out-of-time intervention in an interregional planning dispute between MISO and PJM, as approved by the committee in June (EL13-88). (See “Committee Recommends SPP Intervene in FERC’s NIPSCO Docket,” SPP Seams Steering Committee Briefs.)
Staff said a MISO compliance filing removed several limitations that hampered efforts to resolve SPP-MISO seams issues, including the 345-kV and $5 million cost thresholds.
Committee Chairman Paul Malone, of the Nebraska Public Power District, reminded the committee that MISO believes the docket only applies to the MISO-PJM seam. “Why shouldn’t these same principles apply to the MISO-SPP seam?” he asked.
The Delaware General Assembly has passed a resolution opposing PJM’s cost allocation for the Artificial Island project and creating a seven-member Cost Equity Committee to follow the issue through a planned rehearing at FERC.
The Delaware Public Service Commission estimates that under the PJM transmission owners’ distribution factor cost allocation method (DFAX), about $354 million of the projected $410.5 million project cost will be assigned to customers in the Delmarva transmission zone, while the area stands to receive only 10% of its benefits. Following a January technical conference, FERC approved the Artificial Island project’s cost allocation on April 22. On June 21, it agreed to a rehearing. (See FERC Taking a Second Look at Cost Allocation for 2 PJM Projects.)
In addition to giving the new committee the authority to intervene in the rehearing, the measure also grants the group permission to be involved in any related court proceedings.
State and federal legislators representing Delaware, Gov. Jack Markell of Delaware, Maryland Gov. Larry Hogan and various agencies representing Delmarva ratepayers have bombarded FERC and the PJM Board of Managers with letters criticizing the cost allocation. (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)
The upgrade to the New Jersey complex that houses the Salem and Hope Creek nuclear reactors involves sinking a new 230-kV transmission line under the Delaware River to Delaware.
The Long Island Power Authority on Wednesday delayed approving a proposed 90-MW offshore wind farm off the coast of Montauk, N.Y., that would be the largest such project in the U.S.
LIPA executives had expected an easy approval vote from its board of trustees, but they delayed the vote at the request of the New York State Energy Research and Development Authority, which also has a wind farm planned for off the Long Island coast.
The authority “has asked for a brief delay of the LIPA board vote so the project can be examined in the broader context of the Offshore Wind Master Plan, the development of which [NYSERDA] is leading for the State,” NYSERDA spokeswoman Dayle E. Zatlin said.
“The Master Plan and its forthcoming draft blueprint will inform decisions about the best way to manage this valuable resource in an environmentally responsible way and in order to obtain the lowest achievable offshore wind electricity cost for New Yorkers.”
That “blueprint,” she said, should be completed in a few weeks. “Together, these efforts are part of New York’s intent to foster greater renewable energy production, including offshore wind, on Long Island and throughout the state.”
A LIPA spokesman said a few week’s delay in the vote should have no impact on the Montauk project. “We’ve been talking off-shore wind for about 11 years on our island so the few weeks delay, in context, is not a deal breaker.”
LIPA has selected Deepwater Wind, which is already building a 30-MW project off Block Island, R.I., to develop the project.
The U.S. Bureau of Ocean Energy Management has awarded about a dozen leases for commercial wind, but only the Block Island project has begun construction.
Deepwater Wind spokeswoman Meaghan Wims said the Long Island project, to be called the South Fork Wind Farm, is part of a larger lease obtained from BOEM. “We bid 90 MW to LIPA as part of this” request for proposals, she said. “Our total capacity at that site is 1,000 MW, to be built over phases. The South Fork Wind Farm is the first phase.”
View of the Block Island offshore wind project currently under construction by Deepwater, which was selected to build the Montauk project.
Montauk Project to Use 15, 6-MW Turbines
Deepwater will install 15 6-MW turbines about 30 miles off the coast of Montauk. Two 5-MW lithium-ion batteries will replace transmission investments that otherwise would be necessary. If all goes well, construction work could begin by 2021, with an operational date of December 2022, Falcone said.
“It is part of our goal to attain 400 MW of renewable energy, as part of the New York Clean Energy Standard, by 2023,” LIPA CEO Tom Falcone said in an interview Friday.
“We have an area of our service territory, East and South Hampton, with a lot of load growth, and we needed to address it in some way,” Falcone said. He said LIPA considered a transmission project to address the growing load, but after reviewing responses to its RFP, it determined the offshore wind project fit all the requirements.
“It’s the right project, the right size, and we can land in the right price area,” he said. Falcone said the project will cost a typical residential customer about $1.20/month.
Earlier offshore wind proposals were much more expensive than that, he said. Now, the cost of offshore wind is about the same as utility-scale solar — a resource not suited for crowded Long Island.
“I am not aware of any other utility that has signed a contract on a utility-scale project like this,” Falcone said. “We don’t have many other options” when it comes to renewable energy, he said. “On Long Island, land is constrained. But we have this tremendous offshore wind resource, thousands of megawatts. It is a tremendous resource.”
Lead Time Reduced
Falcone said much of the federal review process necessary for the Montauk project has already been done by Deepwater, which could save up to three years in the lead time for the project. “That was one thing that was particularly attractive” about the Deepwater plan, he said. “They are ready to go.”
Offshore wind projects need to be reviewed by BOEM to ensure they don’t encroach on commercial shipping areas or fishing grounds.
Community opposition has hindered other offshore wind projects on the East Coast. A 468-MW facility proposed off the coast of Massachusetts is tangled up in opposition from residents and no firm construction start date has been set.
Since news of its project got out, said LIPA Spokesman Sid Nathan, the authority has received dozens of messages of support from lawmakers, business owners and labor leaders. “We don’t expect community opposition of the proposal,” Falcone said.
“New York is boldly leading the way on a clean-energy revolution that will transform the nation’s energy future,” Deepwater CEO Jeffrey Grybowski said. “There’s real momentum for offshore wind in the United States, and Long Islanders are leading the charge.”
Currently, the largest offshore wind facility in the world is the 630-MW London Array, a 175-turbine facility off England’s eastern coast, in the outer Thames Estuary. DONG Energy is building tandem wind farms off the Dutch coast that will total 700 MW.
PJM CEO Andy Ott released a letter July 8 defending the RTO’s paper on competitive markets, saying that while it believes its markets are effective in both regulated and competitive retail structures, it did not conclude that any market outcome was superior to cost-of-service regulation.
“Instead, our analysis supports the hypothesis that markets lead to more cost-effective and economically efficient outcomes in managing new entry and exit of resources,” Ott wrote. “But this is purely an economic observation and is not to suggest that markets lead to the ‘best’ or ‘most superior’ outcomes for all parties in all circumstances.” (See PJM Study Defends Markets, Warns State Policies Can Harm Competition.)
Ott also indicated PJM would consider adding multiyear commitments to the capacity market’s current one-year contracts, which are procured three years in advance.
AEP, FirstEnergy Challenge
A coalition of generators led by American Electric Power and FirstEnergy challenged PJM’s analysis in a letter May 19, saying it presented a skewed view of the benefits of competitive constructs compared with the traditional regulated model. (See Generators Rebut PJM Study on Investment in Competitive Markets.)
AEP and FirstEnergy were joined by Dayton Power and Light, Duke Energy Ohio and Kentucky, Buckeye Power and East Kentucky Power Cooperative.
PJM’s Board of Managers commissioned the study after AEP and FirstEnergy asked Ohio regulators, and Exelon asked Illinois legislators, for help in supporting money-losing generators. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)
On July 7, Exelon officially notified PJM of its plan to close its Quad Cities nuclear plant on June 1, 2018, citing a lack of action by Illinois legislators. It also intends to shutter its Clinton station next year.
In his letter, Ott said, “As a threshold matter, we agree that cost-of-service regulation has managed the entry and exit of generation resources in a highly reliable manner over many decades. Indeed, as we noted in Part 2 of the PJM paper, regulated environments offer a forum to balance social, political and environmental interests alongside electricity costs to the consumer. … PJM also believes, however, that markets result in a more cost-effective and economically efficient approach to procuring adequate generating resources.”
Coal Retirements not Unique
Ott acknowledged concerns over generation retirements in PJM, but he said, “The retirement of coal generation and its replacement with combined cycle natural gas power plants is happening across this country; it is not unique to PJM.”
He also combatted generators’ assertion that PJM’s competitive markets owe their success to legacy assets and that it has relied on its pre-existing reserve margin for a decade.
“PJM forward projections indicated installed reserve margins were declining and would fall below 16% in 2008. In order to address these concerns, PJM proposed and implemented the [Reliability Pricing Model] forward capacity construct under which the declining reserve margin trend reversed,” he wrote. “Despite unprecedented forces changing the generation fuel mix in this country, PJM’s forward capacity market has maintained robust installed reserve margins. For the 2019/2020 planning year, PJM is carrying an approximate 22% reserve margin.”
Fuel Diversity
The regulated model, he said, lends itself to sacrificing some of that objective in favor of others, including promoting fuel diversity.
“While the recent investment trends have actually made PJM’s aggregate fuel mix more diverse over the past decade, PJM understands the concern that we need to analyze and quantify any potential operational or reliability challenges that may occur if the PJM region trends toward a very large percentage of gas-fired generation in the future,” Ott wrote. “PJM commits to perform such an analysis and will share results with stakeholders by first quarter of 2017.”
Multiyear Commitments
He added that PJM agrees in concept that the capacity market would be strengthened by the addition of some multiyear commitments.
“On this point, we agree that through bilateral agreements or market design changes, the market would be served by better options to lock-in price [and] manage risk and volatility for at least a portion of the supply portfolio,” he said.
In contrast with the negative reception it received from utilities in Ohio and Kentucky, PJM’s paper was lauded by the PJM Power Providers Group (P3) and a coalition of 16 independent power producers, including Calpine, Dynegy, NRG Energy and Talen Energy in letters last month.
“When markets are allowed to work, and are not undermined by out-of-market interventions or uneconomic new entry, consumers across the region will continue to see highly reliable service at the most efficient price,” wrote the IPPs.
Both P3 and the IPPs noted the new natural gas capacity added or proposed in the past five years.
“The IPP sector continues to lead this new investment, and the competitive PJM market structure has been the enabling platform on which these investment decisions have been made,” the IPPs said. “What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk.”
RAPID CITY, S.D. — The Transmission Planning Improvement Task Force’s recommendations to streamline SPP’s transmission planning process won unanimous approval from the Strategic Planning Committee and the Markets and Operations Policy Committee last week.
If the recommendations win final approval from the Board of Directors next week, SPP will combine the Integrated Transmission Planning (ITP) near-term and 10-year assessments and NERC transmission planning (TPL) assessments into a single 10-year study that will produce an annual transmission expansion plan addressing reliability, economic and policy needs.
The new process will begin in September 2017, with its first results unveiled in October 2019. SPP will complete the 2017 ITP10, the 2017 and 2018 ITPNTs and conduct TPL assessments during the transition period.
NextEra Energy Transmission’s Brian Gedrich, the task force’s chair, said the new process will yield more accurate and forward-looking results.
“It’s a holistic approach, the opposite of the sequential way we do it now,” Gedrich told the SPC. “A lot of manpower resources are spent to provide [transmission-planning] information for you and the board. This will free up time so folks can do analysis … that will actually be actionable.
“No one was happy with the process. Today, all you do is take a 10-year look ahead. How can you possible see what is happening in real time, when all you look out is 10 years?”
Gedrich said building the initial future cases would require two to four additional full-time equivalents and $350,000 to $400,000 in consulting costs, depending on whether staff analyzes two or three futures. The task force recommended two futures.
“What are we getting out of this additional cost?” asked SPP Director Harry Skilton, who chairs the RTO’s Finance Committee. “I hear you say more efficiencies, but what tangible benefits do members get?”
ITC Holdings’ Marguerite Wagner agreed the benefits can be difficult to quantify.
“We spend hundreds of millions of dollars on transmission, and we see congestion in the same areas,” she said. “We expect this new process to be more granular, thus leading to potentially better solutions and outcomes.”
“As you do the same thing over and over, I think you will gain efficiencies. Right now, as we start and stop, you lose a lot of time,” Gedrich said.
Skilton seemed satisfied with the responses. “If in the judgment of the membership it will get better results, address congestion in the near term and improve the planning process … that’s a helluva accomplishment,” he said.
The task force’s other recommendations included:
Standardizing the ITP’s scope and developing a streamlined assumptions document;
Developing a single, base reliability powerflow model that will be used for all planning processes;
Adding accountability with mechanisms designed to promote timely data exchanges, reviews and approvals; and
Limiting the initial 2019 study scope to two study futures to help facilitate the move to the new planning process.
Export Pricing Task Force Given the Go-Ahead
The committee unanimously accepted staff’s recommendation to create an export-pricing task force to research SPP’s Tariff and FERC policy and evaluate how best to take advantage of the RTO’s abundant variable energy resources.
The task force would make recommendations on establishing “equitable and nondiscriminatory” rates to address recovering incremental transmission and facility costs needed to export and import electricity, and “how to avoid paying for it on the back of SPP ratepayers — which will be difficult to do,” said Sam Loudenslager of SPP’s regulatory staff.
Loudenslager said the SPP region currently has 22,000 MW of variable resources in its queue and not yet in service.
SPP’s Corporate Governance Committee, which doesn’t meet until late August, will have to approve the task force’s formation.
Dogwood Energy’s Rob Janssen suggested the task force’s representation include members experienced with life on the seams.
“We have to remember we have members with loads on both sides of the border, who move power any given day or time,” he said.
“If you can’t get the money right, you can’t get anything done,” SPP Director Phyllis Bernard said. “This is one of those task forces focusing in on how to get the money right. There are genuine legal problems here, and absent federal direction, export pricing has to be the solution.”
Asked by SPC Chairman Mike Wise of Golden Spread Electric Cooperative whether the task force would develop a marketing campaign to “advertise our energy,” Loudenslager responded, “I’m not a marketing guy.”
PJM and the Retail Energy Supply Association want a say in Dayton Power and Light’s plan to keep its coal-fired plants running.
Both organizations have filed motions to intervene in DP&L’s “electric security plan” application before the Public Utilities Commission of Ohio. If their past actions are any indication, they will voice objection to the plan, much as they did in similar cases involving FirstEnergy and American Electric Power, which are Ohio’s two largest electric utilities. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)
DP&L’s application proposes a 10-year reliable electricity rider (RER), which would help parent company AES continue operating its fleet of coal-fired plants. Under the rider, DP&L would agree to acquire generation from the shares another AES subsidiary owns in the Ohio Valley Electric Corp. and the Conesville, Killen, Miami Fort, Stuart and Zimmer plants — all baseload coal-fired facilities DP&L used to own but was required to sell under its current ESP.
The rider would further stipulate that the difference between the revenue requirements of each plant and its expected revenue would be calculated annually. Depending on the outcome of the calculation, customers would receive a credit or a charge.
Kyger Creek Power Plant
In announcing the application, DP&L estimated that, if approved, the first year of the rider in 2017 would result in an additional $1.21 charged to each monthly bill but “contribute an estimated $26.5 billion in positive economic benefits for Ohio.”
In their filings, PJM and RESA said approval of the plan would have market-wide impacts.
“The commission’s decision in this matter will affect the viability of the competitive retail electric market in DP&L’s service territory,” RESA said in its filing.
“The nature and extent of PJM’s interest is to ensure DP&L’s RER proposal will not negatively impact PJM’s ability to administer efficient and competitive wholesale energy, ancillary service and capacity markets, and maintain the reliability of the transmission system in the PJM region,” PJM’s filing stated.
DP&L’s plan has drawn criticism from environmental groups, including the Ohio Environmental Council and the Environmental Defense Fund. Both groups are also contesting similar proposals from FirstEnergy and AEP.
The companies are “cherry-picking some of their worst plants, and they’ll put those in a package and they’ll say that the state of Ohio needs these for jobs and economic development,” said John Finnigan, a lead attorney with EDF.
“It’s a subsidy for these plants. These plants are out of the money.”
Under its current ESP, DP&L was required to divest its generating assets. AES decided in 2014 to retain the Dayton-area power plants, which were nearly 3,500 MW at the time. The generation was sold to another AES subsidiary, AES Ohio Generation.
Both AES Ohio and DP&L are overseen by DPL, another AES subsidiary. Today, DPL serves (through DP&L) approximately 515,000 customers in 24 counties throughout West Central Ohio and operates (through AES Ohio) 3,066 MW of generation, 2,078 MW of which is coal-fired.
DP&L said it was reviewing the petitions to intervene. “Once a thorough review is complete, we will explore all options for our next steps,” said spokeswoman Mary Ann Kabel.
FERC last week approved Transource Kansas’ settlement with the Kansas Corporation Commission, under which the company will receive a 9.8% base return on equity for any transmission facilities in SPP (ER15-958).
The company will earn a total of 10.3%, including a 50-basis-point adder previously approved by the commission for participation in an RTO.
FERC trial staff supported the settlement in an April 27 filing but noted that the agreement was silent on the top end of the discounted cash flow (DCF) zone of reasonableness. “Therefore, if Transource Kansas (or its affiliates) makes a future request seeking additional ROE incentive rate adders for a specific transmission project, the commission’s approval of this settlement will not eliminate the need for the applicant to make a Section 205 filing that includes a two-step DCF analysis establishing a zone of reasonableness, the top of which will cap any total ROE,” staff said.
Transource Kansas is a subsidiary of Transource Energy, a joint venture between American Electric Power and Great Plains Energy.
FERC accepted PJM’s cost responsibility assignments for 33 of 34 baseline upgrades, ordering the RTO to change the billing for one Dominion Resources project and revise its Operating Agreement to address inconsistencies (ER16-736, EL16-96). PJM’s Board of Managers approved the projects in December as additions to its Regional Transmission Expansion Plan.
The commission rejected the cost assignment on Dominion’s 500-kV Cunningham-Elmont rebuild project (b2665), saying it should be funded solely by Dominion ratepayers rather than spread across the region.
FERC said PJM’s proposal was inconsistent with its February order that transmission owners should pay all of the cost of projects that solely address a TO’s local planning criteria. (See FERC Does 180 on Local Tx Cost Allocation in PJM.)
The commission gave PJM 30 days to submit a compliance filing “to reflect the appropriate cost responsibility assignment” — allocated to the transmission owners’ zones via the solution-based distribution factor (DFAX) method.
PJM had proposed the DFAX method for 30 other low-voltage projects addressing local planning criteria. Costs of the three other projects — involving 500-kV or double-circuit 345-kV lines — will be allocated 50% on a regionwide, postage-stamp basis and 50% via DFAX.
Commissioner Cheryl LaFleur dissented on the b2665 decision, noting it involved a 500-kV line. “High-voltage lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation,” she said.
She also reiterated concerns she’s noted previously that incumbent TOs may be delaying action on transmission upgrades until the projects become immediately necessary and therefore no longer subject to competitive bidding under Order 1000.
“It is important that incumbent transmission owners report their transmission needs to PJM in a timeframe that allows PJM to meet them in a timely manner, and open them to competitive bidding requirements if they are not in fact immediate,” she wrote. “If it appears over time that incumbent transmission owners may be postponing identification of transmission needs to avoid competitive bidding, further action may be needed to ensure that customers receive the intended benefits of Order No. 1000 planning processes.”
OA Inconsistencies
The commission also ordered PJM to correct inconsistencies in its Operating Agreement.
The agreement requires that the transmission owner be the designated entity when 100% of the project costs are allocated to the transmission owner’s zone, as in Form 715 projects. However, another section of the Operating Agreement appears not to exempt Form 715 projects from the competitive proposal process. FERC required PJM to clarify that exemption and the process the RTO will follow in these situations.
The second inconsistency involved determinations for how proposals qualify as “immediate-need” reliability projects. The commission found it “proper” for PJM to use the date a reliability need must be addressed rather than the expected in-service date and said the agreement needs to reflect that.
FERC gave PJM 30 days to submit revisions or explain why such changes are unnecessary. Parties interested in intervening must file notices within 21 days.
The commission expects to file a final order on this proceeding with 180 days from publication in the Federal Register.
VALLEY FORGE, Pa. — Two 345-kV lines that were knocked out when a tornado leveled four transmission towers in Commonwealth Edison territory on June 22 were back online as of July 12, PJM’s Chris Pilong told the Operating Committee last week.
The twister hit near LaSalle, in North-Central Illinois, around 10 p.m., he said, tripping the Plano 0101 and Plano 0102 lines.
In response, a number of generators in the ComEd zone and other PJM areas manually reduced their output.
The effect of the eight-day outage was localized, with only minimal congestion of $136,000, Pilong said.
“There were no emergency procedures, nothing too crazy,” he said.
On June 30, the Plano 0101 was restored using a temporary structure while the other line remained out of service. On July 10, Plano 0101 was moved onto a permanent structure, Pilong said. By the end of July 12, both lines had been restored.
EKPC Forecast Errors Puzzle Operators
In other reports on operations, Pilong noted that the Eastern Kentucky Power Cooperative zone has been showing an unusually high percentage of peak load forecast errors.
“There is something going on there. We’re trying to dig into it and nail down who’s high — is it just one entity?” he said. EKPC has 16 member cooperatives.
“It is a cause for concern, but it doesn’t violate NERC criteria,” Committee Chairman Mike Bryson said. “When we see a significant change like that, we want to understand what’s causing it and see if we have to make any adjustments.”
The average RTO-wide load forecast error performance for June was 2.57%, within the goal of 3%. EKPC’s was highest, at 3.6%, down from 4.7% for the first quarter of the year.
CP Units to be Ineligible for Winter Testing; May Choose to Self-Schedule
Generators that have cleared as Capacity Performance will be ineligible to participate in the PJM-scheduled cold weather tests beginning this winter under changes to Manual 14D that the OC will be asked to endorse next month.
Non-CP resources will be eligible for testing and will be compensated as a pool-scheduled resource on their cost-based schedule.
CP resources may elect to self-schedule tests, enabling them to be compensated as a self-scheduling resource according to the Tariff.
Regardless of how the tests are performed, PJM wants to keep track of the results and is asking that they be submitted within five days of testing.
“When it included all units, there were a number of unit owners that told us they were testing outside of the program,” Bryson said. “That’s one of the things we’re trying to capture.”
The changes came after generators last month opposed a proposal to keep CP units in the testing but end their compensation. All capacity resources will be required to be CP beginning in the 2020/21 delivery year. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)
VALLEY FORGE, Pa. — The Market Implementation Committee last week endorsed changes to Manual 18 clarifying rights and responsibilities under auction-specific bilateral transactions.
The trades — which are intended to be physical, not merely financial — are expected to become more popular under the tougher Capacity Performance rules, PJM said.
Members had asked for clarification on issues such as which party is entitled to bonus payments, which is responsible for performance and whether members would be indemnified if a party to a bilateral deal defaults. (See “PJM Proposes Clarifications to Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
To ensure the physicality of such deals, PJM offered the following clarifications: The rights and title to cleared capacity go to the buyer; the seller remains obligated to perform and to pay for any deficiencies; and the buyer will indemnify PJM Settlement if the seller defaults on its performance obligations. There were four abstentions.
Members to Study Ways to Prevent Black Start Billing Delays
The committee also approved a problem statement and issue charge to study annual revenue requirements for black start units.
The issue arose after a large number of such units entered service before their billing requirements were approved, leading to billing delays and large retroactive charges. Many were replacing retiring units. (See “Retroactive Black Start Billing Charges Focus of Proposed Study,” PJM Market Implementation Committee Briefs.)
Current Tariff language does not clearly define the review process for the costs of new units entering black start service outside of the annual revenue recalculation period.
“Basically, what we’re looking for is to put language in the Tariff and minimize the potential of billing delays,” PJM’s Tom Hauske said. “We’ve also added transparency for billing to the issue charge.”
The issue will be worked by the full MIC and is expected to take six months.
Members Debate Ways to Release Excess Capacity into Incremental Auction
The MIC heard three proposals for how to release excess capacity into the third incremental auction for the 2017/18 delivery year, to be held in February.
PJM must file its plans with FERC by November. The RTO’s proposal mirrors its approach for the 2016/17 third incremental auction. In that auction, PJM released 4,556 MW of capacity at an average price of $4.79/MW-day, netting $21,827/day. That reduced the RTO’s total reliability charge by 0.103%.
At the time that PJM received permission from its members and FERC for a Tariff change to release the capacity for the 2016/17 incremental auction, it did not address the subsequent auction because the Supreme Court had not yet ruled on whether demand response resources would remain in the wholesale energy markets. (See Supreme Court Upholds FERC Jurisdiction over DR.)
Last week, stakeholders who said they felt the released capacity was worth much more presented alternate proposals.
One came from Direct Energy, which proposed a sloped offer curve for the sale of an estimated 10,000 MW. This price floor would help prevent supply resources from being able to cheaply buy out of their obligation at load’s expense. (See “Price Floor for Incremental Auctions?”, PJM Market Implementation Committee Briefs.)
“We’re reducing reliability for everyone with little financial benefit in exchange,” Direct Energy’s Jeff Whitehead said. “In the 2016/17 third incremental auction, PJM sold excess capacity for nearly $5 [per MW-day] when the price in the rest of the RTO was $60.”
With a similar premise, Michael Borgatti of Gabel Associates presented a proposal on behalf of NextEra Energy that would make PJM’s sell offer into the existing third incremental auction equal to the transitional incremental auction adder that the RTO currently charges to load.
He provided an example showing that selling all 10,017 MW of excess capacity would produce $284,698/day in incremental revenue using the current charge of $28.42/MW-day. Selling the same capacity at $5.02/MW-day would bring in $50,285/day.
Even selling just half of that capacity at the higher price would bring in more money — $142,349 — than PJM could reap selling 10,017 MW at the $5.02/MW-day price.
Dave Mabry, of the PJM Industrial Customer Coalition, likened the release of excess capacity at $4.79/MW-day to a “fire sale,” suggesting that PJM consider keeping the capacity.
Added Steve Lieberman of Old Dominion Electric Cooperative: “I do believe there is a break-even point where we’d rather have the megawatts than the money.”
Independent Market Monitor Joe Bowring, who had to leave the meeting before the presentations, weighed in on the issue, saying simply, “You should not buy more capacity than you need. You should not sell it back for less than the price paid for it. It’s bad for customers.”
While the proposals addressed only the upcoming auction, Whitehead said he would be drafting a problem statement to study the issue on a long-term basis.
Special Session Planned on Fuel-cost Policy Development
The MIC will hold a special session July 27 to further detail PJM’s requirements for developing fuel-cost policies.
In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.”
It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submission of cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).
PJM is required to make a compliance filing in the docket by Aug. 16. (See “Members Delay Endorsement of Manual 15 Changes Regarding Definitions, Fuel Cost Policy,” PJM Market Implementation Committee Briefs.)
“We want to improve the process so that from a compliance perspective, PJM does not feel as exposed as we do today, given the way the process currently operates,” said Stu Bresler, senior vice president of market operations.
Participants prodded PJM to move more quickly and be more definitive with its rulemaking process.
Lieberman expressed concern over being forced to draft policies in compliance with manual changes that are only in draft form and not yet approved.
He explained after the meeting that, with approval targeted for mid-October and implementation likely in December, the timeline creates a “narrow” window to make and get approval for any necessary policy-submission changes prior to the compliance deadline. FERC’s order for a PJM compliance filing on the issue further complicates the situation, he said, because the commission’s ruling on that could come as late as mid-October and may require further filings from PJM.
“A member faces a lot of uncertainty prior to the start of winter and not a lot of time for resolution,” he said.
Bresler acknowledged that the timeframe is “compressed.”
Carl Johnson, who represents the PJM Public Power Coalition, pressed for adding clarity on the process to the Tariff, including expected review periods and potential remedies for unapproved submissions. He said his members want to know “what it is they need to supply to PJM and be sure that once they’ve done that, they’re going to get an approved policy.”
Bresler acknowledged the comments and reminded participants that they need to retain enough documentation to validate the input to the cost-based offer they submit. He confirmed that once a policy is approved and a cost-based offer submitted, if additional market-power issues arise, they will go before FERC.
Bowring said his staff has developed a policy template for every fuel type. He said his interest is market-power mitigation. PJM ultimately approves or rejects the policies, and the Monitor reviews them beforehand to determine if they are consistent with not exercising market power, he noted.
Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” SPP Seams Steering Committee Briefs.)
The company will earn a total of 10.3%, including a 50-basis-point adder previously approved by the commission for participation in an RTO.
