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.
PJM planners have begun studying a redesign of the Transmission Expansion Advisory Committee process with the aim of providing more discussion, documentation and transparency through the Regional Transmission Expansion Plan cycle.
“We’re looking at additional ways of doing that [rather] than the monthly meeting,” Steve Herling, vice president of planning, told the Planning Committee.
The discussions — internal for now — stem from an April 29 “Order 1000 Lessons Learned” meeting, in which PJM proposed three tracks: a reliability project process document, an energy efficiency project process document and a TEAC redesign. A fourth track to address upgrade projects also was suggested.
“We will shortly be starting discussions around the market efficiency process and decision-making,” Herling said. “We have been working internally with market folks to put together a draft set of documentation that will serve as a starting point. … Hopefully in another month, we should be getting to a point where we can air some of that with the membership.”
For starters, Herling said, planners are looking at alternatives to the 12-month planning cycle.
New 345-kV Line Proposed for Newark Airport
The most efficient solution to Newark Liberty International Airport’s need for additional energy resources is to introduce a third 345-kV line, PJM told the TEAC last week.
Because it is an immediate need, an RTEP window is not feasible, and all of the projected $43 million cost would be assigned to the local transmission owner, Public Service Electric and Gas, said TEAC Chair Paul McGlynn.
The upgrade is expected to be ready by June 2018, when the airport’s expansion is set to be completed.
The airport’s current load is about 40 MVA, but a planned new terminal will add about 33 MVA. Another 8 MVA is expected to be added by plans to extend the Port Authority Trans-Hudson (PATH) railroad.
Planned upgrades to Terminals B and C will increase the load even more.
Two new 345-kV underground cable circuits, part of the Bergen-Linden Corridor project, will serve the airport’s load. But PSE&G would be unable to restore power within 24 hours if those lines were lost, McGlynn said, necessitating an additional line.
PJM Concerned PSE&G Equipment at the End of its Life
An assessment of the 138-kV circuits on PSE&G’s Metuchen-Edison-Trenton-Burlington Corridor shows that they are at the end of their life and must be addressed, McGlynn told the TEAC.
“It would require expensive foundation work to get them back to where they need to be,” he said, noting that a survey of the transmission lines indicated that 25% of the towers are exceeding their load-carrying design capability; 35% are at between 99% and 100%; and 81% are between 95% and 100%.
“It’s at the end of life, and we need to do something about it,” he said.
The 30 miles of line from Metuchen to Trenton is about 86 years old. The 22 miles from Trenton to Burlington is 75 years old.
Also of concern is PSE&G’s Newark Switch, a 63-year-old substation with a transformer from 1927 and two others dating to 1958.
“If they were to fail, it could potentially take out the entire station,” he said.
Two DOM Projects Change Scope, Boost Cost
Two projects in the Dominion transmission zone have undergone a change in scope, increasing their cost significantly.
The cost of upgrading the overloaded Idylwood 230-kV bus has jumped from $55 million to $80 million following a detailed look at the cost of GIS breakers (gas-insulated high-voltage switchgear), permitting, labor, a security wall and transmission structures.
The project, addressing N-1 and N-1-1 thermal violations, is expected to be in service by Feb. 1, 2020.
Meanwhile, a proposal to expand the Halifax station to address thermal violations on the Halifax-Chase City 115-kV line has been scrapped because the station is located in a flood plain.
The need to build a new switching station outside of the flood plains boosted the price of the project from $26 million to $43.6 million, including the purchase of real estate.
The work is expected to be complete by the end of the year.
Members Endorse Using Same Load Model for IRM study
The Planning Committee unanimously endorsed the same load model PJM used last year for the 2016 reserve requirement study, the 10-year period from 2003 to 2012.
It will reset the installed reserve margin (IRM) for the next three delivery years and create an initial IRM for the first all-Capacity Performance delivery year in 2020/21.
The results of the study are expected to be presented in September, with a vote on the IRM the following month.
Members had endorsed the assumptions for the IRM study, proposed by the Resource Adequacy Analysis Subcommittee, at their last meeting. (See “Installed Reserve Margin Study Assumptions Endorsed,” PJM Planning Committee & TEAC Briefs.)
A total of 55 candidates were studied. Two other models came close: the 12-year period from 2002 to 2013 and the 10-year span from 2004 to 2013.
The tie-breaker was determining which period achieved world load diversity, PJM’s Tom Falin said.
New Shickshinny 500-kV Switchyard Proposed in Northeast Pa.
PPL is revising its transmission line designations as a result of the new Shickshinny switchyard for Moxie Energy’s 850-MW gas-fired Freedom station outside of Wilkes-Barre, Pa. The existing Susquehanna-Lackawanna 500-kV line will be split into the Susquehanna-Shickshinny line (5067) and the Shickshinny-Lackawanna line (5062).
Citing an analysis by The Brattle Group, MISO has decided to stick with its original forward design in its capacity auction overhaul, rejecting the hybrid prompt auction proposal it had negotiated with the Independent Market Monitor.
Jeff Bladen, executive director of MISO market services, said the forward proposal was the “best fit” to address price formation and encourage entry by new resources.
“This is the best chance of seeing real improvement,” Bladen said during a special conference call of the Resource Adequacy Subcommittee Thursday .
Brattle Analyst Kathleen Spees Source: The Brattle Group
According to Brattle’s analysis, a forward model would reduce price volatility by 35 to 37% compared to the current Planning Resource Auction. The hybrid prompt proposal, Brattle analysts said, would reduce volatility by 25 to 28%. Brattle said a forward proposal paired with a broader and more gently sloping demand curve could reduce price volatility by 44 to 48%.
Bladen said MISO is still “fine-tuning” the curve shape and could incorporate Brattle’s recommendation.
Brattle analysts said that while the forward model attracts an additional 1,800 MW of merchant supply when compared to the status quo and “substantially” improves reliability, it still falls “somewhat” short of redesign objectives.
A wider demand curve could bring 2,200 MW in merchant supply, meeting the one-day-in-10-years loss-of-load expectation. Brattle said the prompt hybrid proposal supports an additional 1,200 MW of merchant supply and that, although reliability improves under the model, it is “still substantially short of reliability objectives.”
Not Surprised
Patton criticized Brattle’s analysis, saying it measured volatility and reliability but ignored efficient pricing that allows generators to recover costs. Patton insisted that some volatility was natural.
“Volatility is a secondary metric at best,” he said.
Patton said he wasn’t surprised by MISO’s decision to move ahead with its own proposal.
“Fundamentally, I never felt like we reached a compromise because MISO never agreed to do the prompt proposal. They always had a strong preference for a forward proposal. I think it’s a mistake,” he said.
Despite that, Patton said he did not feel that working with MISO on the prompt proposal was a “charade.”
Bladen said the forward proposal minimized Tariff changes and is the best choice when considering reliability and FERC precedent. Patton countered that the legal hurdles to implementing a prompt proposal “weren’t nearly as daunting as MISO makes it seem.” He also said instituting the two-stage prompt auction would not undermine the current PRA, although it may lower prices.
Several stakeholders questioned Brattle’s Monte Carlo analysis, a probability simulation using repeated sampling. Brattle analysts noted that “findings may change with future refinements, particularly to assumptions in how utilities participate in forward auctions.”
“That’s a pretty big caveat,” Dynegy’s Mark Volpe said.
Brattle analyst Kathleen Spees said the forward analysis carries substantial uncertainty “simply because there’s not as much evidence on how utilities will behave. In the prompt proposal, we have much more empirical evidence.”
Bladen said the Monte Carlo analysis took “thousands” of scenarios into account.
Volpe asked if Brattle supported MISO’s decision to move ahead with the forward proposal.
Brattle Analyst Sam Newell Source: The Brattle Group
“Look, nothing is going to be perfect or perfectly predictable in this environment,” Brattle analyst Sam Newell said. “That said, the elements of this proposal are clearly better that the status quo and better than other alternatives, including the prompt proposal.”
Newell said the forward proposal “achieves an economic efficiency that the alternative does not” and is the best proposal to provide reliability at least cost. Newell also said the forward proposal is “unambiguously” better than the current construct.
In response to stakeholder questions, Newell and Spees said their study did not consider scenarios assuming supply from MISO South, reduced demand or a case focusing on renewable growth.
“If this is a billion-dollar business, why so many simplifications?” asked Indianapolis Power and Light’s Ted Leffler.
Newell responded that the lack of historical evidence prevented a more definitive study.
“MISO has looked exhaustively at the prompt hybrid proposal. We simply didn’t believe we could move forward with the hybrid prompt proposal,” Bladen said.
FERC Filing Next Month
MISO expects to file its proposal with FERC sometime next month. Bladen said MISO would “act without undue delay,” as directed by its board.
Source: MISO
Draft Tariff language and revised Business Practices Manuals are expected to be posted by July 20; stakeholder discussions regarding the language is planned at the Aug. 3-4 RASC meeting. MISO will make another presentation regarding Tariff language on Aug. 8 before the Markets Committee of the Board of Directors.
Volpe said that MISO excluded stakeholders by not presenting the Advisory Committee with both proposals for review before announcing a decision.
Bladen said it wasn’t MISO’s intention to subvert the stakeholder process and pointed to the year and a half of discussion on auction redesign. He agreed the Advisory Committee could hold a special meeting on the auction design proposals or even recommend a delay in filing.
“We don’t want to stand in the way of the Advisory Committee coming together to debate,” Bladen said.
Marcus Hawkins, an engineer with the Public Service Commission of Wisconsin, responded that for the first seven months of the discussion, stakeholders had only an issues statement from MISO.
IMM Critical of Analysis
In his own presentation, Patton said prices in the forward proposal are “heavily dependent on decisions that regulated and external entities make to offer” and would result in annual price fluctuations exceeding $500 million, resulting in poor price signals to competitive suppliers.
“There is no way to predict where this market will clear year-to-year,” Patton said. He said MISO’s forward proposal fails to ensure auction clearing prices are consistent with the marginal value of reliability.
Patton said MISO’s forward proposal is not comparable to forward markets in other RTOs. “This is the first time that I’ve seen a model where the demand does not reflect the requirement,” he said.
Patton also said Brattle did not properly model the prompt proposal, including a much steeper demand curve than recommended. He said Brattle’s Monte Carlo analysis carried too much uncertainty because of assumptions regarding the demand curve and participant behavior. “I don’t envy The Brattle Group,” Patton said.
Stakeholders Split
Before Thursday’s meeting, stakeholders provided feedback on the two proposals.
Two members of the Michigan Legislature wrote a letter in support of a forward auction. “The three-year forward proposal provides long-term pricing signals that we feel are critical to attract new generation capacity to Michigan,” Sen. Mike Shirkey (R-Jackson) and Rep. Gary Glenn (R-Larkin Township) wrote.
Northern Indiana Public Service Co. and Alliant Energy asked that MISO and the Monitor take more time to explain and vet their proposals with stakeholders. Likewise, Duke Energy, Big Rivers Electric, Hoosier Energy and Southern Illinois Power Cooperative said they required more information before backing a proposal.
Illinois Industrial Energy Consumers and DTE Energy said neither proposal was acceptable.
Wolverine Power Cooperative called for a footprint-wide three-year forward auction instead of a proposal that blends a regulated prompt auction and a retail-choice forward auction.
American Electric Power also said it preferred at least a three-year advance auction for the entire footprint.
“This provides a price signal to the resource owner in time to budget and plan for maintenance, upgrades, fuel supplies, development of new resources, etc. It also would allow loads, both retail switching and wholesale, sufficient time to develop, evaluate and budget for supply offerings, with known auction result prices,” AEP said.
The Organization of MISO States said it needed more information before it selected a proposal to support, but it also added that it had “mixed opinions as to whether each proposal will promote generation investment.”
Dynegy also said it supported the prompt proposal. “At this point, it is abundantly clear that the hybrid prompt proposal may result in a clearer price signal for supporting restructured competitive retail markets,” Dynegy wrote.
Consumers Energy said the forward proposal is the better option but wanted revisions to Safe Harbor provisions for not entering generation into the auction and wanted the cost of new entry raised “to better incent new generation in shortage situations.”
Main Line Generation asked for the addition of a minimum price offer rule in both proposals.
Puget Sound Energy (PSE) and Talen Energy reached an agreement with environmentalists to shut down Units 1 and 2 at the coal-fired Colstrip power plant in Montana by July 2022.
Under the July 12 settlement filed in the U.S. District Court in Missoula, the Sierra Club and the Montana Environmental Information Center (MEIC) agree to dismiss their lawsuit against the plant’s owners for alleged violations of the federal Clean Air Act. PSE and Talen will also be required to reduce sulfur dioxide and nitrous oxide emissions from the units ahead of retirement (Case 1:13-cv-00032-DLC-JCL).
The agreement also stipulates that the environmental groups will drop legal action against Colstrip Units 3 and 4, which are jointly owned by PSE, Talen, Portland General Electric, Avista, PacifiCorp and NorthWestern Energy. Those coal-fired units were built in the mid-1980s and have a combined net generating capacity of 1,480 MW.
“PSE believes this settlement is in the best interest of our customers by avoiding the potential need for the installation of additional pollution control equipment for Units 1 and 2 due to future regulatory requirements,” the company said in a statement.
Environmental Rules, Competitive Pressures
Competitive pressures stemming from low natural gas prices factored into PSE’s decision to close the units. The company also cited “shifting policies and regulations on the federal and state levels,” EPA’s regional haze rule and the Clean Power Plan as additional reasons.
“Our customers expect PSE to be good stewards of the environment and to keep energy costs reasonable,” CEO Kimberly Harris said. “The eventual closure of Units 1 and 2 at Colstrip without the risk of further legal proceedings or additional significant investments in the units to meet regulatory requirements enables us to accomplish both of these goals.”
Colstrip Power Plant Source: Talen Energy
Built in the mid-1970s, the two units can produce 614 MW of electricity, most of which is supplied to consumers in Washington and Oregon. Earlier this year, Washington lawmakers passed a bill that would enable PSE to recover its share of the costs for shutting down the units from ratepayers, while Oregon established a mandate requiring PacifiCorp and PGE to become coal-free by 2030 and 2035, respectively.
In May, Pennsylvania-based Talen notified Colstrip’s other five owners that it planned to cease functioning as the plant’s operator in May 2018. As the plant’s only merchant owner, the company is unable to recover its costs from a rate base and is especially exposed to low power prices on the open market.
The move was part of a broader strategy to withdraw from Montana by the company, which last month agreed to be acquired by Riverstone Holdings. (See Riverstone to Acquire Talen in $1.8 Billion Deal.)
Opportunity for Wind?
Colstrip’s owners collectively own the two 250-mile, 500-kV transmission lines that connect the plant with the Bonneville Power Administration’s transmission network and load centers in the Pacific Northwest. Renewable energy advocates have eyed Colstrip’s transmission as a possible boon for wind development in Montana, a state that the American Wind Energy Association ranks as third in the U.S. for wind potential.
“[The] decision [by PSE and Talen] marks an opportunity to use Colstrip’s existing transmission system to build out more clean energy and export it to Washington and other states,” the Sierra Club said in a statement.
“We want to work with the power plant owners, the community of Colstrip and Montana to plan for a transition that maximizes employment in clean-up, remediation and new renewable energy development in the Colstrip area,” said Mike Scott, a Sierra Club senior organizer.
Montana Gov. Steve Bullock (D), who faces a re-election campaign this fall, was less enthusiastic about the immediate prospects for the region.
“I stand with the workers and the community of Colstrip in being angry about this settlement outcome,” Bullock said. “The parties of this lawsuit took care of themselves. I am going to work to take care of the employees and their families.”
CAISO’s expansion into a multistate, regional electricity market could save California ratepayers as much as $1.5 billion annually while helping the state to meet or exceed its 2030 emission-reduction goals, according to a study commissioned by the ISO.
California’s Clean Energy and Pollution Reduction Act — the 2015 law that established the state’s 50% by 2030 renewable portfolio standard — required CAISO to perform an analysis of the economic, environmental and reliability impact of regionalizing the Western grid.
The study modeled three 2030 scenarios: one in which California meets its RPS without expansion and ones with a regionalized market with state- and regionally focused procurements. The last scenario offered the most significant benefits, according to the analysis, which was conducted by The Brattle Group, Energy and Environmental Economics, Berkeley Economic Advising and Research and the Aspen Environmental Group.
‘Compelling Message’
The benefits estimated in the study are in addition to those expected from CAISO’s expanded Energy Imbalance Market.
Development of a regional market could generate up to 19,300 new jobs for the state by 2030, more than half of which would be related to construction of renewables, the study found. Other jobs would be the indirect result of realigned consumer spending based on reduced energy costs.
Real income in California is expected to increase by $4.1 billion to $7.9 billion annually, while state tax revenues would rise by $600 million to $1.6 billion.
The study’s findings provide a “pretty compelling and simple message,” CAISO CEO Steve Berberich said.
“The electric industry in California is at an inflection point,” Berberich told reporters during a call Tuesday to discuss the report. “I think the state has the ability to enable a new paradigm where clean energy and economic growth become one.”
The study analyzed two regional market footprints: one including only CAISO and PacifiCorp and a second including all of the U.S. portion of the Western Electricity Coordinating Council except the two federal power marketing agencies there, the Bonneville Power Administration and the Western Area Power Administration. “These footprints are hypothetical and are designed to capture a plausible range of impacts,” the study notes. “We understand that the individual utilities and states will have to conduct their own evaluations of the benefits and trade-offs of joining a regional entity and to decide whether or not to join one.”
Regionalization would provide the ISO the ability to optimize generation over a larger footprint, allowing California “to go beyond” its 50% RPS, Berberich said. The study included the costs of storage and transmission needed to integrate renewables.
Fear of Curtailments
Without expansion, the ISO predicts periodic renewable curtailments of up to 13,000 MW — even with the expected closure of Pacific Gas and Electric’s Diablo Canyon nuclear power plant in 2025.
“Absent a regional market, we’re very concerned that we could see a lot of renewable energy curtailed because there isn’t an adequate market to sink the power,” said Keith Casey, ISO vice president for market and infrastructure development.
Casey noted that other RTOs in the U.S. are facilitating the development of “non-RPS” renewables — renewable projects built based on cost-competitiveness rather than in response to mandates. “For example, since 2000, wind generation accounted for 80% of 44,000 MW of non-RPS-related renewable generation additions nationwide, and 80% of these non-RPS-related wind generation investments (over 28,000 MW) took place in six states (Texas, Iowa, Oklahoma, Kansas, Illinois and Indiana), all of which are in ISO-operated market areas,” the report said.
CAISO’s study found that a regional market could eventually save California ratepayers as much as $1.5 billion a year.
“We think this [expanded CAISO] market will provide a platform for renewable development to flourish,” Casey said.
Other highlights of the study:
By 2030, the market would help California reduce electric sector CO2 emissions by 4 million to 5 million metric tons per year — 8 to 10% below a scenario with no regional market. That would represent a 58% decline from 1990 levels.
Land use for building new wind and solar developments to meet California’s RPS would be reduced by up to 71,300 acres inside the state and 31,900 acres elsewhere in the West because of more efficient resource expansion. The study projects increased transmission construction outside California to support out-of-state projects.
A regional market would reduce water use by combined-cycle gas units in California and gas and coal plants in other areas of the West as a result of the more efficient dispatch of renewable resources.
The market’s larger operational footprint would allow for improved renewable integration through centralized control and increased awareness of neighboring areas. Lower requirements for load-following resources, operating reserves and planning reserves would lower costs for maintaining reliability.
WASHINGTON — The Senate voted overwhelmingly last week to enter conference committee negotiations on energy legislation after Republicans agreed to drop provisions in a House bill that President Obama has promised to veto.
Sen. Lisa Murkowski (R-Alaska), chairwoman of the Energy and Natural Resources Committee, speaks before the Senate approved a conference committee on energy legislation. Source: C-SPAN
“I will reiterate my personal commitment to a final bill that can pass both chambers and be signed into law by the president,” Sen. Lisa Murkowski (R-Alaska), chairwoman of the Energy and Natural Resources Committee, said on the Senate floor July 12 before the upper chamber voted 84-3 to name conferees.
“It can’t be the House product necessarily, or the Senate product necessarily,” she added. “It has to be something that both chambers can agree on and that the president can sign into law.”
Sen. Maria Cantwell (D-Wash.), the committee’s ranking member, said the Republicans’ promise was enough to keep Democrats working toward a compromise.
“What we were most concerned about was pursuing an agenda that definitely couldn’t get past the White House, and veto threats, and certainly wanted to look constructively at how we got a package on some issues that we knew if we couldn’t get resolved, it wouldn’t get resolved,” Cantwell told reporters.
The Senate passed its bipartisan Energy Policy Modernization Act of 2016 (S.2012) in April, with support of all but a handful of Republicans. It authorizes increased spending on energy research, improves cybersecurity protections and encourages more efficient buildings and vehicles. It also adds taxpayer protections to the Energy Department’s loan guarantee program and streamlines federal approvals of electric transmission, pipeline, hydropower and LNG facilities.
Obama, who has expressed support for most provisions in the Senate bill, singled out several House proposals as nonstarters, including ones that would limit funding for the National Science Foundation and the federal government’s influence over local building codes. The administration also objected to measures that would halt implementation of an efficiency rule for gas furnaces and reverse existing law phasing out fossil fuels from federal buildings. (See Energy Bill Faces Tight Calendar, Partisan Divide in House.)
House Republicans have balked at the Senate bill’s permanent reauthorization of the Land and Water Conservation Fund.
The Senate acted before Congress began a seven-week recess, during which staffers are expected to work toward a bill both houses can approve. If enacted, it would be the first major energy law in almost a decade.
In addition to Murkowski and Cantwell, the Senate conferees are Sens. John Barrasso (R-Wyo.), Jim Risch (R-Idaho), John Cornyn (R-Texas), Ron Wyden (D-Ore.) and Bernie Sanders (I-Vt.). The House has named 24 Republicans and 16 Democrats to the committee.
Interest Groups React
Alliance to Save Energy President Kateri Callahan said that while reaching agreement will be difficult, “focusing first on those pieces — like the energy efficiency provisions that have strong bipartisan support and broad public appeal — will help the conferees to move together.”
Senator Maria Cantwell Source: C-SPAN
The League of Conservation Voters praised Murkowski and Cantwell for reaching a compromise to ensure negotiations continue. “However, we are concerned that many controversial items still remain in the scope of the energy bill conference and that the measures being debated will not amount to the true overhaul our energy sector needs,” Vice President of Government Affairs Sara Chieffo said in a statement.
The American Petroleum Institute praised the Senate’s action, saying its bill would ensure “that American natural gas has a dominant place on the world market.”
The Union of Concerned Scientists said the conferees could produce a bill that is a “modest step in the right direction on issues such as energy efficiency and clean energy infrastructure.”
“Both parties have a lot invested and aren’t interested in wasting their time,” Rob Cowin, director of government affairs for UCS’s Climate and Energy Program, said in a statement.
“Although much better than the partisan House bill, the bipartisan Senate bill contains a worrisome provision categorizing the burning of biomass for electricity as carbon-neutral. This is not only scientifically inaccurate but could also undercut EPA’s current efforts to determine the proper role for biomass in the Clean Power Plan and potentially lead to increased carbon pollution.”
Entergy said Wednesday it may sell its troubled James A. FitzPatrick nuclear plant to Exelon if New York approves the proposed Clean Energy Standard, which would provide large subsidies to nuclear stations.
If New York cannot agree on those subsidies, Entergy said, it will go forward with its plans to cease operations by January.
“In keeping with our corporate strategy to move away from merchant power markets and toward a company operating exclusively as a utility in regulated markets, we are working with Exelon to come to commercial terms on a sale transaction that depends largely on the final terms and timeliness of the New York State Clean Energy Standard,” Entergy Wholesale Commodities President Bill Mohl said. “We thank New York Gov. Andrew Cuomo for his leadership in promoting the Clean Energy Standard.”
Cuomo called the possible sale “welcome news.”
“My administration has been working closely with both companies to find a way to keep this vital energy resource operating,” Cuomo said in a statement. “While there remains much work to be done, I am pleased that significant progress is being made.
Fitzpatrick Nuclear Plant Source Entergy
“I have directed various state entities to continue working with the parties involved to finish the job. I am hopeful that a definitive agreement will be reached to ensure these benefits to New Yorkers are realized.”
The proposed nuclear subsidies are a recent addition to the state’s Clean Energy Standard. The clean energy blueprint would mandate use of renewable energy for half of the state’s electricity by 2030.
According to a July 8 report by the staff of the New York Public Service Commission, the nuclear subsidies would total $965 million over the first two years while providing economic and environmental benefits through carbon reductions, supply cost savings and property tax benefits of about $5 billion (Case 15-E-0302).
Initial cost estimates for the nuclear subsidies were $59 million to $658 million through 2023, with net benefits of about $1 billion. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
Three plants in the state — FitzPatrick and Exelon’s Nine Mile Point and R.E. Ginna — would be eligible for the subsidies. Cuomo wants to exclude Entergy’s Indian Point, which he wants shut down because of its proximity to New York City.
When the nuclear subsidies in the Clean Energy Standard were first announced, Entergy said they would have no effect on its plans to close FitzPatrick. But the company said Wednesday that its decision to seek a sale to Exelon is “consistent with Entergy’s commitment to consider any viable option that would allow FitzPatrick to remain in operation.”
Exelon spokeswoman Lacey Dean confirmed the talks on Wednesday, saying a deal would be “subject to several firm conditions.”
In addition to approval of the Clean Energy Standard, Dean said, the conditions were a guaranteed long-term revenue stream for the plant and an immediate positive impact on Exelon’s earnings.
She declined to say how long the talks had been in progress or if a purchase price had been discussed.
Fighting a PJM proposal to impose uplift costs on up-to-congestion trades, the Financial Marketers Coalition last week enlisted one of the intellectual pioneers of electricity markets in its defense.
Presenting the conclusions from his white paper on virtual trading, Harvard economist William Hogan told the Energy Market Uplift Senior Task Force that PJM should eliminate uplift costs from all financial transactions rather than extending them to UTCs.
Hogan said PJM’s October 2015 paper, which recommended charging UTCs, was too narrowly focused and failed to acknowledge some of virtual transactions’ benefits, including countering market power, improving market efficiency and hedging real-time market risks.
“Uplift can arise for many reasons. … The focus on deviations, which are used for allocating uplift costs, do not go hand in hand with added uplift costs,” said Hogan, the Raymond Plank Professor of Global Energy Policy at Harvard’s John F. Kennedy School of Government. “We want to be careful about using [deviations] as a measure of failure of the system and then using that to allocate a subcategory of the costs.”
He suggested exempting virtual trading from uplift charges and allocating the costs instead to the “real-time gluttons” — consumers who won’t respond to even the most extreme price signals.
It’s “foolish,” he said, to think that the costs could be allocated anywhere other than consumers. “In the end, in equilibrium, the load’s gotta pay,” he said. “Aggregate efficiency should be the standard.”
‘Reversal of the Conventional Wisdom’
Hogan’s stature — Public Utilities Fortnightly has called him “the chief architect of wholesale electric market design in the United States” — makes him a valuable ally. Among his other clients have been numerous utilities, MISO, ISO-NE and the Electric Power Supply Association, which enlisted him in its unsuccessful bid to eliminate FERC oversight of demand response. He was also among the experts who defended Richard and Kevin Gates’ Powhatan Energy Fund in their high profile campaign against FERC market manipulation charges.
Hogan conceded that his position on virtual trading represents a “reversal of the conventional wisdom.” He rejected arguments by those who contend that virtual bidding provides no significant benefits and thus extracts money via what a 2015 paper by Massachusetts Institute of Technology economist John E. Parsons and three FERC analysts termed “parasitic” profits.
At this year’s EBA Annual Meeting left to right: Greg Lawrence, William Hogan, David Patton, Sam Newell and Joe Bowring
He highlighted two studies — one focused on California and the other on ISO-NE — that concluded virtual transactions increased price convergence between the day-ahead and real-time markets and reduced dispatch costs. While “not a dramatic number — a single-digit percentage of improvement” — the studies showed how virtual transactions help smooth out the “lumpiness” of unit commitment costs, Hogan said.
“The inclusion of the convergence bidding and the virtual bidding made the whole system operate more efficiently,” he said. “Neither of these studies go all the way, but they are very suggestive.”
Hogan also took on PJM Independent Market Monitor Joe Bowring, who contends that UTC transactions are increasing shortfalls in FTR funding and that PJM should consider NYISO’s model, which limits virtual transactions to zones or hubs. (See PJM Ponders Changes to Virtual Trades, DA Market.)
Hogan said new recommendations contained in Bowring’s 2015 State of the Market report would result in the “undoing [of] financial transmission rights.”
“Forgetting … the larger context linking the market design economics to engineering principles can result in analyses and recommendations that can neglect the requirements of efficient electricity market design and recreate problems already solved,” Hogan wrote. (See “Financial Transmission Rights,” Bowring Urges Return to ‘Fundamentals’.)
Hogan was more conciliatory toward PJM’s 2015 paper, which he credited as “generally supportive of the contribution of virtual transactions as improving overall market performance” despite being issued “in a context where virtual bidding is under attack.” (See PJM Suggests Changes to Virtual Transactions.)
But he said the examples cited in PJM’s report “do not provide a framework for evaluating the overall cost and benefits of virtual transactions,” a task he acknowledged “is not easy.”
“The limited available analyses from other regions indicate that the benefits are material and outweigh the costs, but no available studies cover all the relevant issues.”
Focus on Deviations
PJM’s uplift charges totaled $314.2 million in 2015, down from $960.5 million in 2014, when costs spiked as a result of the polar vortex.
PJM UTC trading volumes fell by 85% after FERC said it might make the transactions liable for uplift assessments.
Because LMPs do not cover all production costs, uplift payments — or “residual” charges — are required to make generators whole. The biggest component of PJM’s uplift charges is the balancing operating reserve (BOR), the costs of which are allocated based on real-time deviations from day-ahead schedules.
Hogan said allocating uplift costs according to the deviations is inappropriate and “particularly problematic for virtual transactions, which by design involve a 100% deviation.”
He also said PJM’s cost allocation “does not arise from any fundamental model … [implying] that the allocation method is more an administrative compromise than the product of a principled analysis.”
Some deviations are expected and inevitable, Hogan said, citing the “lumpiness” of unit commitment costs. As an example, he described a generator being priced too high to clear the day-ahead market but clearing during the later reliability run.
Because uplift is a result of residual costs, attempting to figure out the cost causation “is a fool’s errand,” Hogan said.
“The important question is the aggregate net benefit of virtual transactions, not the residual cost. If virtual transactions increase the net benefits in the market, then there is no incentive-based reason to assign additional costs to virtual transactions.
“Allocating the uplift costs to network connection charges would be better than adding to a so-called ‘uplift’ charge on load billed per megawatt-hour,” he continued. “If an uplift charge is necessary, it should be allocated to the least price-responsive loads. If a nondiscriminatory uplift charge is required, it should be spread across the widest possible base of loads that cannot bypass or avoid the charge.”
Hogan said the “principal problem” PJM identified with virtual transactions is a “computational burden that would be only indirectly affected by uplift allocations and could be addressed through other means with fewer negative consequences for the broader market design, such as by continuation of bidding budgets that allowed flexibility in the choice of virtual transactions.”
Recommendations, FERC Action
In addition to calling for an end to uplift charges, Hogan identified two other recommendations that differed from PJM’s:
Analyze the impact of virtual trading on unit-commitment decisions rather than assume differences between day-ahead and real-time conditions. “The PJM analysis refers to the importance of commitment decisions throughout the report but does no explicit analysis of those commitment decisions,” Hogan said. “The absence of the analysis undermines the PJM conclusions.”
Increase the number of locations at which virtual transactions may be placed.
FERC is long overdue to issue a ruling in its Section 206 inquiry. In opening the docket, FERC said it would rule within five months after it receives comments following a technical conference. The conference was held in January 2015 with follow-up comments due at the end of May.
However, the commission may be delaying action to see what emerges from PJM’s stakeholder process. The task force, which has been discussing the issues since July 2013, is scheduled to meet next on Sept. 1.
