Page 1328 – RTO Insider

April 7, 2017

Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix

By Rory D. Sweeney

PJM’s Board of Managers on Thursday ordered a resumption of the Artificial Island transmission upgrades but directed the development of alternative cost allocations to address Delmarva peninsula stakeholders who argue they’re unfairly on the hook for the vast majority of the $280 million project.

The board suspended work on the controversial project last August following years of stakeholder complaints about how the project was scoped, awarded and had its costs allocated, ordering staff to perform a comprehensive analysis. At a special session of the Transmission Expansion Advisory Committee in March, staff announced some modifications to the scope of the project, but remained supportive of the proposal the board had approved in 2015. (See PJM Sticks with LS Power on Artificial Island Project.)

PJM says the DFAX cost-allocation methodology can produce “”anomalous”” results in some projects, such as Artificial Island, in which it assigned 93% of the cost to Delmarva Power & Light ratepayers. All other transmission zones would pay less than 1% each. | *PJM Transmission Expansion Advisory Committee, 3/3/17*

Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate (EL15-95, ER15-2563). Under the DFAX method, 93% of the costs would be borne by Delmarva Power & Light ratepayers, with all other transmission zones paying less than 1% each.

PJM’s signal last month that it would move forward with the project prompted renewed complaints to the board from 12 stakeholders — including the governors of Maryland and Delaware — upset over the cost allocation.

In a letter to stakeholders on Thursday, PJM CEO Andy Ott acknowledged the dispute and called on PJM’s transmission owners to come up with a compromise.

“PJM has stated in past Federal Energy Regulatory Commission proceedings and at a Jan. 12, 2016, FERC technical conference that a solution-based power flow formula (the ‘DFAX methodology’) works fairly and reasonably to identify project beneficiaries for cost allocation purposes in the overwhelming majority of lower-voltage transmission projects considered by the board,” Ott wrote. “But we also noted that application of the DFAX methodology can result in cost allocations that seem anomalous in cases where the engineering rationale or need for the particular project is not one driven by power flows. Indeed, PJM has suggested that the Artificial Island project is unique in nature and that application of the DFAX methodology to a stability or short-circuit problem may not yield clear beneficiaries.”

TOs, not PJM, Responsible for Cost Allocation

Ott said the Federal Power Act makes the PJM TOs responsible for proposing cost allocation methods and prevents the RTO from imposing alternatives. But he also acknowledged that the cost allocation dispute “is so polarized [that] it threatens to impede PJM in discharging its reliability responsibilities.”

As a result, he said, PJM staff “will analyze project beneficiaries from alternate perspectives, including identifying load and the extent of service interruption that could be expected in the case of an uncontrolled stability event at Artificial Island.”

“Importantly, we anticipate this information will still demonstrate the logic supporting an allocation of project costs to beneficiaries located in the Delmarva region, along with beneficiaries in one or more neighboring states,” he added.

He said the analyses will be available “shortly” and will be referenced in its FERC filing on the project.

The board also used in its decision a whitepaper produced by PJM, which stakeholders have complained was not made available for comment and response prior to the board’s decision. Ott said in his letter that the “whitepaper is anticipated for public release in the near future and will offer additional transparency to stakeholders.”

In a news release, the board said it directed staff to publish the alternative allocations because it believes “this data could offer insight to, and a basis for, those states, transmission owners and customers that derive benefit from this project to devise a different cost allocation proposal for stability projects such as Artificial Island.”

At the special TEAC meeting last month, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem nuclear plant to the Hope Creek plant. The analysis also eliminated as unnecessary a static VAR compensator and optical groundwire upgrades.

pjm ls power artificial island — Salem Nuclear Generating Station on Artificial Island

The revised project assigned $146 million of the project work to LS Power, $132 million to Public Service Electric and Gas, and $2 million to Delmarva Power & Light.

April 6, 2017

PacifiCorp IRP Sees More Renewables, Less Coal

By Robert Mullin

PacifiCorp has released a 20-year plan that commits the utility to increased investment in renewable resources and energy efficiency while sharply reducing reliance on the coal-fired generation that currently produces more than half the company’s electricity output.

The 2017 Integrated Resource Plan — filed this week with utility commissions in PacifiCorp’s six-state territory — spells out $3.5 billion in capital spending focused on new renewables, upgrades to the company’s existing wind fleet and the construction of a 140-mile segment of the Gateway West transmission project in Wyoming.

The 500-kV line, slated to be in service by the end of 2020, would advance the company’s strategy for tapping new wind development in Wyoming. While the first segment is intended to serve PacifiCorp ratepayers, other portions of Gateway West are designed to facilitate the flow of wind energy into California, where utilities are required to serve 50% of their load with renewables by 2030.

coal energy efficiency pacificorp renewables — PacifiCorp’s latest IRP calls for a sharp increase in wind investments while reducing the utility’s reliance on coal. | *Windy Flatts in Klickitat County, WA © RTO Insider*

Under the IRP, PacifiCorp would complete construction of 1,100 MW of new wind generation, mostly in Wyoming, by 2020 to take advantage of federal production tax credits. The company would also squeeze out an additional 905 MW of renewable capacity by upgrading its existing wind fleet with larger blades and new technology.

PacifiCorp currently owns or contracts for more than 2,300 MW of wind resources.

Between 2028 and 2036, the company plans to add another 859 MW of wind and build 1,040 MW of new solar capacity.

“These investments will significantly increase the amount of clean renewable energy serving customers and reduce costs at the same time,” Stefan Bird, president and CEO of Pacific Power, the PacifiCorp subsidiary that serves Oregon, Washington and California, said in a statement.

The plan calls for retiring 3,650 MW in coal-fired capacity by 2036 to avoid spending on equipment to comply with EPA’s Regional Haze rules. An Oregon law passed last year that will prohibit the state’s utilities from importing coal-fired power by 2030 also was a factor in the early retirements of the Craig, Jim Bridger, Hayden, Huntington and Naughton coal units located in the inland West. A rollback of EPA’s Clean Power Plan is unlikely to affect the company’s plans, it said.

“This early closure assumption was considered in PacifiCorp’s Regional Haze compliance analysis to account for changes in market conditions, characterized by reduced loads and wholesale power prices,” the IRP said.

By the end of the planning horizon, coal would represent 31% of the company’s resource portfolio, compared with almost 60% today.

The plan foresees the company building 1,313 MW of new natural gas-fired capacity, down 1,540 MW from the 2015 IRP estimate.

“Reduced loads, ongoing investment in energy efficiency programs and increased renewables reduce the need for new natural gas resources in the 2017 IRP,” the company said.

PacifiCorp expects energy efficiency to offset 88% of forecasted load growth over the next 10 years.

Stagnant loads and energy efficiency programs also caused the company to reduce its projections for wholesale power purchases through 2027 relative to a 2015 IRP update released last year, despite relatively low forward prices. Wholesale market purchases are expected to increase in 2028 in concert with the company’s coal retirements.

PacifiCorp said it developed the 2017 IRP through a process that included input from “an active and diverse group of stakeholders, including advocacy groups, regulatory staff and other interested parties.” The company completed the plan after meeting with stakeholders in five states and hosting seven public meetings.

The company delivers power to about 1.8 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming through its Pacific Power and Rocky Mountain Power subsidiaries. The company was the first utility in the West to join CAISO’s Energy Imbalance Market and in 2015 signed a memorandum of understanding to explore becoming a full member of the ISO.

April 5, 2017

EBA Panel: States Acting on CO2 Because Markets Can’t

By Rory D. Sweeney

WASHINGTON — They couldn’t agree on much except for this: today’s electricity markets don’t handle environmental externalities well because they’re not designed to.

That was the rare moment of consensus during an otherwise fractious discussion about the growing pressures of state policy initiatives on FERC-regulated markets at the Energy Bar Association’s annual conference Monday.

FERC EBA panel emissions — Dr. Katherine Spees, The Brattle Group, presents while Jeffrey Dennis, Akin, Gump Strauss, Hauer & Feld observes | © *RTO Insider*

Kathleen Spees of The Brattle Group said that state and provincial actions — such as Ontario’s goal of reducing CO₂ emissions by 80% below 1990 levels by 2050 — will “fundamentally change the nature of our resource mix, how plants are built [and] how they’re operated.”

“Markets today on their own won’t achieve that, and so that’s why we’re seeing states basically taking different policy measures to achieve those objectives,” she said. “But my question is, ‘Can the markets help to support and achieve those ends?’ And I think the answer is, ‘they can.’ I think it will be hard to get there.”

Spees clarified that her perspective was based on economics, rather than the legal issues on which much of the discussion at the two-day conference focused.

Competing with a concurrent session on gas-electric coordination, the panel attracted the majority of attendees, requiring the addition of several rows of extra chairs in the back of the room.

Moderator Jeffrey Dennis, senior counsel with Akin Gump Strauss Hauer & Feld, teed up the discussion by noting that the Supreme Court has ruled that retail and wholesale markets are so intertwined that a state can impact the wholesale market without violating federal jurisdiction. “These markets are not hermetically sealed,” he said.

Nick Martin, a manager of environmental policies with Xcel Energy, opened the discussion by explaining how Minnesota requires his company’s integrated resource plan to factor in two carbon dioxide externality values: one that represents the potential future impact of carbon regulations on Xcel’s system and another that represents the potential future damages from climate change. The first ensures the utility isn’t making infrastructure investments without considering the potential impacts to customers of future regulatory costs, while the second takes a broader view.

“Sometimes, those are divergent,” Martin said. “These are both values used in planning. Neither of them represents a carbon price that would go directly into wholesale markets at the RTO level.”

Xcel is currently seeking regulatory approval to update those externality values, Martin said, but the 2007 regulatory commission order under which the utility operates values carbon emissions between $9 and $34 per short ton. The valuations help determine which planning alternatives are the best fit for Xcel’s 15-year outlook.

He contended that the valuations aren’t like the zero-emissions credits recently approved in Illinois and New York because they don’t impact FERC-regulated electricity markets.

“They won’t directly pay a higher price to our nuclear plants, but they will strengthen the rationale for retaining nuclear, retiring coal plants [and] adding renewables,” he said.

Exelon’s David Dardis later argued on the panel that ZECs also don’t impact RTO markets. He pointed to FERC’s 2012 ruling regarding the Western Systems Power Pool, which concluded that stated renewable energy credits are separate commodities from capacity and energy (ER12-1144).

“So long as the REC is unbundled or sold independent of wholesale electric energy, the RECs are not payments in connection with wholesale sales and therefore fall under state jurisdiction,” Dardis said. “ZECs are clearly sold independent of energy and capacity.”

NRG Energy’s Abe Silverman disagreed, arguing that the credits intrinsically intrude on FERC’s jurisdiction over wholesale energy sales. He noted that 95% of the time, all the units needed for wholesale dispatch are receiving a state-promulgated rate different from the FERC-regulated market. NRG has joined in lawsuit challenging the legality of the ZECs. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.)

“The fact that the state was trying to engage in the most noble of causes, in this case fighting climate change, does not — at least in my view — escape pre-emption,” he said. “What does it mean for FERC to regulate wholesale rates if states take increasingly large amounts of generation out of the market?”

Spees said Ontario is a prime example of what happens when the market is marginalized. The Canadian province has reduced its carbon by more than 6% below 1990 levels through resource- and technology-specific out-of-market contracts — and closing all of the province’s coal-fired generation — but Spees said the costs are now escalating.

“It’s really turned into a big challenge,” she said. “Those do tend to be higher cost. They don’t enable that competition and innovation that we really probably want in the system. … [Markets] become much less important to the system and much less valuable in terms of achieving some of these benefits that you can get through competition and innovation.”

They can also have unintended consequences of suppressing prices, which can squeeze out other clean technologies. As a result, the province faces a major redesign of its system to re-engage the power of the market, she said.

Silverman said New York’s and Illinois’ ZECs were an ill-conceived and potentially expensive means of limiting carbon emissions.

“Nobody would remodel their kitchen without getting a couple of bids. Here we have $10 billion of ratepayer capital committed to two states without ever testing it to see if it was actually the least-cost source of carbon abatement,” he said. “If all we’re doing is relying on ratepayer capital, we’ll never get it done. We need that shareholder private capital to come into the market as well.

“If you are terrified of backsliding in year 1, 2 or 3, then … nuclear is probably the best way to go,” he said. “But if you’re looking at a lifecycle analysis and really thinking about 2050, we need to go not just from coal to gas — which is probably what would happen if the nukes retire — but we need to go from coal to clean, which means FERC really needs to step up and create the kind of markets and really get markets to address the carbon problem.”

April 5, 2017

MISO Introduces Distributed Energy Future for 2018 Tx Planning

By Amanda Durish Cook

MISO is recommending the addition of a fourth future to its 2018 transmission planning to reflect localized carbon reduction efforts and battery storage.

In addition to futures for “limited,” “continued” and “accelerated” fleet change, the RTO is proposing a distributed and emerging technologies scenario to inform its 2018 Transmission Expansion Plan.

Under the new distributed and emerging technology future, fleet evolution is driven by local and state policies and the adoption of emerging technology. Renewable additions are economically propelled by technological advancements and state renewable portfolio standards. Renewables, which are expected to provide 15% of total MISO energy by 2032, are sited within state jurisdictions for local energy use.

The future also predicts commercial mass production of energy storage devices. MISO envisions that natural gas reliance increases with more electric vehicles on the road, the need to support intermittent renewables and to replace retiring capacity. Natural gas prices stay consistent with long-term forecasts, with the RTO using the NYMEX for the first two years to forecast prices and an average of the U.S. Energy Information Administration and Wood Mackenzie forecasts for the remaining years. MISO also expects a surge in demand-side management programs.

MISO’s 2017 futures include an existing fleet future, policy regulations future and an accelerated alternative technologies future. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.) Using stakeholder feedback, the RTO will now use MTEP 17 definitions as “outlines” for MTEP 18, “but completely refresh forecasts.”

“Given trends, low gas price forecasts, member-stated plans and renewable potential, MISO feels it is necessary to consider fleet changes beyond those in the MTEP 17 policy regulation future,” the RTO said.

In addition to distributed technology scenario, the 15-year futures for 2018 are:

A limited fleet change future assumes 8 GW of age-driven coal fleet retirements by 2032. Low demand and low prices for both natural gas and energy curb new energy generation technologies and keep renewable additions limited to current renewable portfolio standards, making up 10% of MISO resources by 2032. The low natural gas prices, however, drive an increase in industrial production along the Gulf Coast in MISO Zone 9.
A continued fleet change future presumes the rate of fleet evolution remains as it has since about 2005. The assumed 16 GW of coal retirements is based on plant shutdowns at age 55-60, with natural gas additions largely replacing them. New renewable resources continue to exceed RPS requirements and serve 15% of MISO energy by 2032 because of continuing public interest, economics and future policy regulation.
An accelerated fleet change hinges on a “robust” economy that drives demand and energy production. Natural gas prices rise as a result of demand, and carbon regulations aiming for a 20% reduction from current emissions levels are introduced. Coal retirements would surpass the “continued” future’s 16 GW, with natural gas sources stepping up to replace the lost capacity and provide a steady backup to renewable resources, which exceed RPS targets and make up 26% of MISO resources. High gas prices hinder industrial production along the Gulf Coast.

“It’s still very early” in the planning process, MISO engineer Stuart Hansen reminded stakeholders at an April 4 special workshop. “I think we’ve incorporated what makes sense, but we want to hear your ideas.”

Hansen said MISO will still model a future federal carbon emissions policy for the 2018 batch of transmission projects in the accelerated fleet change future by modeling 20% additional emissions reductions by 2030. “We know that the [Clean Power Plan] is no longer a hot topic, but to provide an adequate bookend … we’ll continue to model federal policy in the accelerated fleet change future.”

Some stakeholders expressed appreciation for the fourth future, saying even with the CPP no longer relevant in the near term, MISO will still need to capture a decreasing carbon trend led by economics, local efforts, state policy and corporate initiatives rather than federal policy.

Richard Seide of Apex Clean Energy asked if MISO planned to model utilities’ green tariffs and corporate purchasing of renewable power. Ann Benson, of MISO’s policy studies group, said the RTO could include renewable types and prices into the futures’ expected renewable portfolios.

Sean Brady of Wind on the Wires asked MISO to consider modeling future nuclear plant closings, especially in Illinois. In all MTEP 18 futures, nuclear units are assumed to remain online through their current operating licenses. The RTO also assumes 16 GW of natural gas and oil unit retirements by 2032 across all four futures.

More discussion on MTEP 18 futures development will take place at MISO’s monthly Planning Advisory Committee meetings through August.

April 5, 2017

Millstone No Dead Weight for Dominion, Says Opponents’ Study

By Michael Kuser

The Millstone nuclear power plant has earned at least $3 billion in profits for Dominion Energy since the company bought it and will likely earn an additional $2.2 billion in after-tax income from now through 2030, according to a study released Wednesday by opponents of legislation that could boost the plant’s finances.

Millstone dominion nuclear power plant — Millstone Nuclear Power Plant | *NRC*

The Stop the Millstone Payout coalition commissioned consulting firm Energyzt to analyze the finances of Millstone, for which Dominion does not release profit or loss figures.

The coalition’s sponsors include competing New England generators Calpine, Dynegy and NRG Energy, as well as the Electric Power Supply Association, all of whom oppose Connecticut legislation that would allow Millstone to bid into the state procurement process now reserved for renewable energy resources.

Dominion indicated last month that the plant will compete in ISO-NE’s Forward Capacity Auction next year, meaning the company expects it to continue operations into at least 2022. Dominion purchased the 2,111-MW facility in 2001 for $1.28 billion. (See Millstone to Enter FCA 12; No Closure Likely Before 2022.)

Tanya Bodell, executive director of Energyzt, said that if Senate Bill 106 is enacted, “Connecticut ratepayers will be on the hook for $330 million per year, or a 15% increase in their electric rates.”

Bodell said that Dominion bought Millstone at an “opportune time” because high natural gas prices increased power prices in New England, enabling the company to earn back the purchase price in five years. The report estimated that Millstone has generated at least a 25% return on equity for Dominion’s shareholders.

The analysis used Chicago Mercantile Exchange monthly futures prices to establish base-case energy prices in assessing the financial situation of Millstone through 2021. For the nine years after 2021, she based long-term energy prices on ISO-NE’s recent FERC filing for Forward Capacity Market parameters. Under these projections, the report said Millstone can be “anticipated to earn close to $400 million in after-tax income over the next five years, or $80 million per year. Thereafter, ISO-NE’s … price projection results in closer to $200 million per year in after-tax income through 2030.”

‘Gross Assumptions and Preposterous Claims’

The legislation would make Millstone the only eligible nuclear generator in Connecticut’s competitive bidding process and award it a five-year contract if its bid is lower than competing renewable resources. The bill sets an annual limit on nuclear energy purchases at 8.3 million MWh, equivalent to half of Millstone’s output.

Dominion spokesman Ken Holt blasted the Energyzt report as “loaded with gross assumptions and preposterous claims, with no real data. They say the cost under S.B. 106 would be $85/MW, but the standard offer now is $81. Why would we bid higher when four regulators oversee the bidding, none of them with any incentive to see consumers pay higher rates?”

The study assumed a contract price of $85/MWh based on the cost of large-scale renewables procured in 2016 and estimated Millstone needs to earn $40 to $45/MWh to cover its operating costs and debt payments.

Holt added that Millstone is more expensive to operate than other two-unit nuclear plants because its two units are of different designs. “That means that an operator on one unit cannot work on the other, and that we need to have two separate training programs,” he said. “The others can benefit from economies of scale.”

EPSA said in a statement on Wednesday that the Energyzt report shows that the “intent and effect of these [legislative efforts are] to distort wholesale markets for all other power suppliers needed to provide reliable, competitively priced electricity.”

April 5, 2017

OMS-MISO Survey Moves Ahead with New Calculation

MISO and the Organization of MISO States have begun distributing their annual joint resource adequacy survey with a new calculation method some stakeholders believe is overly conservative.

resource adequacy oms-miso survey — Landstrom | © *RTO Insider*

In addition to counting as available capacity all generation projects with signed interconnection agreements — as in the past — this year’s survey will also count 35% of those in the definitive planning phase of the queue, Darrin Landstrom, MISO resource forecasting adviser, said during an April 5 workshop on the survey.

The surveys, which were sent to load-serving entities on March 31, will ask for the queue project number as well as status. Responses are due April 30.

Some MISO stakeholders maintain the 35% estimate is too conservative, resulting in unnecessarily alarming results and exaggerating a possible capacity shortfall. Last month, Resource Adequacy Subcommittee Chair Chris Plante notified the RTO’s Board of Directors of the disagreement. (See Differences Persist over OMS-MISO Survey Improvements and “OMS-MISO Survey Dispute Revisited,” MISO Advisory Committee Briefs.)

The surveys continue to use the “high-” and “low-certainty” descriptors, although MISO said it will convert those terms to “committed” and “potential” when the RTO and OMS present results in June.

— Amanda Durish Cook

April 4, 2017

NYISO Management Committee Briefs

RENSSELAER, N.Y. — The NYISO Management Committee voted Wednesday to recommend that the Board of Directors authorize a fix to address an inconsistency between the ISO’s current Tariff provisions governing transmission constraint pricing and how its software applies the rules.

The change is in response to an error discovered last year, which led the ISO to declare a “Market Problem” in November and to seek a waiver from FERC, allowing it to continue using the current software until revisions to the Tariff and software are approved. The commission has not acted on the Jan. 6 request (ER17-758).

transmission constraint pricing nyiso management committee — NYISO Transmission Constraint Pricing Revision | *NYISO*

The graduated transmission shortage cost rules, which took effect in February 2016, establish limits on the shadow prices that the ISO’s security-constrained unit commitment and dispatch algorithms use to resolve transmission constraints.

The ISO presented an analysis of its proposed changes to the transmission constraint pricing logic and a consumer impact analysis to the Market Issues Working Group in January and February.

The fix would remove the feasibility screen and apply the graduated transmission shortage cost method to all constraints with a non-zero constraint reliability margin (CRM). A single $4,000/MWh cap would continue to apply for all facilities and interfaces with a zero CRM.

In addition — because the ISO has determined that it was unnecessarily concerned about forgoing dispatch to secure transmission constraints when all eastern reserve locations and eastern reserve products are short — the second step of the method would be reduced to $1,175/MWh from $2,350/MWh.

“The $1,175/MWh value will continue to support moving resources that can effectively secure the transmission constraint before utilizing the 15 MW of relief available from the second step” of the shortage cost method, the ISO said. “The $4,000/MWh [cap] still acts as a backstop to ensure that resources are dispatched for constraints with larger overloads.”

The board will be asked to approve a FERC filing outlining the software and Tariff changes required to implement the fix.

“We will not update the transmission software without FERC approval,” said Jennifer Boyle, NYISO energy market design specialist.

The motion prompted no discussion from stakeholders at the meeting.

The ISO said it will begin a discussion with stakeholders about additional improvements to transmission constraint pricing in the third quarter.

Replacing Bernard Dan

CEO Brad Jones prefaced his monthly report with comments on how the grid operator may replace Director Bernard W. Dan, who resigned March 21 after less than one year on the board. Jones said the board already has issued a solicitation for an executive search firm to find a replacement for Director Robert Hiney, who will reach his term limit in April 2018.

“The process may take a few months, say late summer, and if that happens we may have a combinatorial [selection process],” Jones said. “But the board has not decided.”

Hiney was appointed to a four-year term in 2006; under NYISO bylaws, a director may serve no more than three full terms. Dan’s replacement will fulfill the remainder of his term, expiring in 2020. (See NYISO Board Member Resigns After Less Than a Year.)

Members OK Change to Emergency Energy Pact with ISO-NE

The Management Committee also voted Wednesday to recommend the board approve rewording the ISO’s coordination agreement with ISO-NE on emergency energy transaction charges to reflect the RTO’s move to five-minute settlements. ISO-NE made the change to comply with FERC Order 825, which required RTOs and ISOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them.

NYISO said it wanted to clarify the emergency energy settlements formula in the agreement to better align with real-time intervals and ISO-NE’s change. “For both RTOs, we are clarifying that the emergency energy charge is the sum of the charges for each real-time interval for the duration of the emergency energy transaction,” NYISO said.

The locational-based marginal pricing (LBMP) in a settlement interval will be increased to $0 if it is negative.

Change OK’d for Start-Up Bid Rules

The committee also approved a recommendation that the board revise the Tariff to allow all generators to increase start-up bids in real time.

NYISO said generators committed for day-ahead energy or regulation service have been able to “inappropriately” increase their start-up bids in real time, while generators scheduled for reserve services in the day-ahead market have been improperly prevented from doing so.

Under ISO rules, generators can submit two types of start-up bids: a single point bid, which specifies the cost to start the generator as part of hourly offers, or a multi-point bid, which sets the start-up cost based on how long the generator has been offline and how long it takes to start. If both types are submitted, the single point bid takes priority.

The ISO’s Tariff prohibits generators scheduled in the day-ahead market for energy or regulation from offering a higher start-up bid in real time for any hour in which the generator was scheduled.

The proposed amendment to Tariff Attachment J would specify that when a day-ahead-scheduled generator that is available for real-time commitment increases its real-time start-up bid, it becomes ineligible for a day-ahead margin assurance payment for the hour in which it increased its bid as well as the two hours before and afterward — an approach consistent with the current treatment of incremental energy bids.

The ISO says allowing generators to increase start-up bids in real time regardless of the day-ahead commitments would result in more efficient real-time scheduling decisions.

Impact of Shorthanded FERC on Fate of Con Ed-PSEG ‘Wheel’

Before adjourning the meeting, Management Committee Chair Scott Leuthauser, a consultant to Hydro-Quebec Energy Services, took a question from Howard Fromer of PSEG Power New York, who asked what would happen to NYISO’s joint operating agreement with PJM to end the 1,000-MW Con Ed-PSEG wheel absent FERC action. (See NYISO Members OK End to Con Ed-PSEG Wheel.)

Jane Quin of Consolidated Edison followed Fromer’s question by asking what would happen if the protocols of the agreement were delayed by inaction from FERC.

The commission lost its quorum when former Chairman Norman Bay resigned in February, leaving the remaining two commissioners short of a quorum to act on contested matters.

NYISO COO Rick Gonzales answered that the filing specifically states that the agreement “can go into effect within 60 days without action from FERC. … Unless we hear different, we will implement what we have filed jointly with PJM,” he said.

– Michael Kuser

April 4, 2017

MISO Names Duke Exec as South Region External Affairs Director

Former Duke Energy executive Kent Fonvielle will lead MISO South’s external affairs division, MISO announced Friday.

MISO south external affairs — Fonvielle | *Duke Energy*

Fonvielle, who began his career as an engineer at Duke’s Oconee Nuclear Station, served for the last 11 months as the company’s director of regulatory affairs, overseeing its regulatory strategy, filings and rate cases in North Carolina and South Carolina.

MISO said Fonvielle will be the primary liaison for MISO South members and stakeholders. He will begin work April 3 from the RTO’s Little Rock offices.

MISO South Vice President Todd Hillman said that Fonvielle’s role is a newly created position that “reflects the importance of the South region as part of the MISO market.”

At Duke, Fonvielle’s prior duties included managing large industrial accounts and wholesale energy contracts and doing fuel and renewable planning.

“It is a privilege to continue my career with an organization dedicated to helping ensure reliable energy and increased value for the people of the South region,” Fonvielle said.

Fonvielle’s hiring comes less than a year after MISO named former Indiana Utility Regulatory Commissioner Kari Bennett as the RTO’s executive director of external affairs. (See MISO Names 3rd External Affairs Director in 5 Years.)

— Amanda Durish Cook

April 4, 2017

Texas PUC Briefs

The Public Utility Commission of Texas last week approved an ERCOT request to share confidential generator-specific information with Lubbock Power & Light as the municipal utility determines how to integrate its load with the ISO.

LP&L has said it will transition about 430 MW of its load from SPP to ERCOT in June 2019. LP&L and the two grid operators are each conducting studies on how the move will affect their systems and stakeholders. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)

As part of its study, LP&L asked ERCOT for data the ISO is only authorized to give to transmission or distribution service providers. ERCOT asked the commission to approve a confidentiality agreement so it could provide the information to LP&L (Docket 45633).

ERCOT texas puc ERS local blackouts — Anderson | © *RTO Insider*

“I think the process ERCOT has proposed is not only acceptable, but the right thing to do,” Commissioner Ken Anderson said during an open meeting Thursday.

ERCOT said LP&L’s planned move creates “unique” procedural questions that are not clearly defined in any rule or protocol. It concluded “it would be appropriate to provide generator-unit specific data to certain LP&L representatives in advance of the anticipated contested case because this is data that ERCOT is using in preparing its commission-requested study, and thus would likely be necessary to any similar study conducted by LP&L.”

The Texas ISO’s legal counsel, Chad Seely, told the commissioners that ERCOT will file a market notice informing all resource entities of the discussion before the PUC and asking for their feedback on the draft confidentiality agreement.

The PUC has delayed a decision on who will pay for studies related to the planned move. LP&L requested the delay, saying study costs shouldn’t be assigned until ERCOT and SPP finish their separate cost-benefit studies, which are expected to be finalized by midyear. (See Texas PUC Delays Assignment of LP&L Study Costs.)

An ERCOT analysis completed last June indicated it will cost $364 million and take 141 miles of new 345-kV transmission to incorporate LP&L into the Texas grid.

PUC Chair Donna Nelson referenced the March 23 announcement by LP&L and Xcel Energy subsidiary Southwestern Public Service that they had agreed to a two-year extension of a 400-MW power purchase agreement through May 2021. The contract would have expired May 31, 2019.

“Not that we should slow our process down,” Nelson said pointedly.

The announcement followed months of negotiations and more than a year of research by LP&L management to secure a “seamless transition” beyond the current PPA’s expiration. Utility officials said the extension allows the city more time to evaluate its future options and “not be pressured by the calendar.”

The “transition contract … is an important step in securing affordable and reliable power for our customers as we work toward achieving our long-term power supply goals,” said David McCalla, LP&L’s director of electric utilities, in a statement.

LP&L has been a total requirements customer of SPS since 2004, with 100% of its power purchased from SPS through the West Texas Municipal Power Agency. The utility will replace that contract with capacity and energy through a 170-MW partial-requirements wholesale contract signed with SPS in 2010; a 100-MW wind contract through its membership with the West Texas agency; 114 MW of LP&L-owned generating plants; and the 400-MW transition contract, according to the Lubbock Avalanche Journal.

Lubbock Mayor Dan Pope called the extension an “important milestone” for the city, saying it would provide “a stable and cost-effective source of power for LP&L customers while we work to join the majority of Texas as participants in the ERCOT market.”

LP&L is the third largest municipal utility in Texas, behind Austin Energy and CPS Energy, with a peak load of about 605 MW. It serves more than 104,000 meters and owns and maintains 4,936 miles of power lines and three power plants in and around the city.

Entergy Texas Compliance with MISO Control Order Nearly Complete

The PUC accepted staff’s recommendation to close one docket (Project 40979) and focus on another (Project 46397) related to Entergy Texas’ transfer of operational control of its transmission assets to MISO.

Staff told the commissioners Entergy Texas has met almost all of the commission’s material requirements from a 2012 change-of-control order approving the company’s MISO membership. Staff opened Project No. 40979 to track the utility’s and MISO’s compliance with the order.

Entergy Texas is working on the final requirement, a cost-benefit analysis of the first five years of MISO membership. The PUC’s Margaret Pemberton said a draft study is expected in August, with the final version to be filed in November.

The utility will perform two types of analyses: backward-looking, to assess actual benefits from participation in MISO, and forward-looking, to assess the project benefits of remaining in MISO rather than leaving after the first five years.

Anderson said he hopes staff looks “very carefully” at the study’s assumptions, which include comparisons with membership in SPP.

“We need to test the assumptions … in SPP and what requirements, if any, there are on load-serving entities to maintain a particular reserve margin … and how that’s enforced,” Anderson said.

PUC Approves ERS, RMR Rulemakings

The PUC approved two rulemakings related to emergency response service (Project 45927) and reliability-must-run contracts (Project 46369).

The ERS amendment will allow those resources to participate in must-run alternative (MRA) arrangements, replacing RMR generation resources.

The commission decided not to allow ERS resources to be used in local transmission emergencies. The commissioners asked staff in early March to revise the rulemaking, saying it did not favor expanding the program to prevent local load-shed events. (See Texas PUC Wary of Using ERS to Avoid Local Blackouts.)

The RMR rulemaking adjusts the notice requirements and complaint timeline applicable to suspending a resource’s operation. It also gives ERCOT the discretion to decline to enter into an RMR agreement based on the economic value of lost load, requires ERCOT approval of RMR and MRA agreements and requires refunds in some instances for capital expenditures related to those agreements.

— Tom Kleckner

April 4, 2017

Millstone to Enter FCA 12; No Closure Likely Before 2022

By Michael Kuser

The Millstone nuclear power plant will bid into ISO-NE’s 12th Forward Capacity Auction next year, indicating owner Dominion Energy expects it to continue operations into at least 2022.

Despite questions about Millstone’s profitability, Dominion did not inform ISO-NE by the March 24 deadline of its intent to retire the plant. Assuming Millstone clears the auction, it would be obligated to operate through May 2022, the end of the 2021/22 planning year.

Dominion’s decision has implications both for New England’s wholesale market — the plant’s delisting would have created upward pressure on capacity prices — and the company’s hope for support from Connecticut lawmakers.

In March, Connecticut legislators unveiled a bill that would allow Millstone, the state’s only nuclear generator, to bid into the state procurement process now reserved for renewable energy resources. (See Connecticut Moves Closer to Equating Nuclear with Renewables.)

Matt Fossen, spokesman for the Stop the Millstone Payout coalition, said Dominion’s failure to file a delist bid by the March 24 deadline undermines the claims of Dominion lobbyists who “make it sound like there is a dire, impending threat to the plant’s existence.” This could not be true, he said, if the plant can continue operating for the next five years.

“Dominion will always meet its obligations in the markets in which we operate, but we do have the ability, within the current market rules, to cease operations if a facility is no longer economically viable,” responded Kevin Hennessy, Dominion’s state policy director for New England. “The dirty fossil fuel generators who oppose CT Senate Bill 106 are threatened by the state smartly choosing to purchase power from clean, reliable, carbon-free sources of electricity like Millstone. Connecticut consumers pay the highest retail electric rates in the country. SB 106 would reduce those rates by cutting out the middle man and allowing the state to buy directly from Millstone.”

ISO-NE spokesman Matt Kakley wanted no part of the dispute. “As the administrator of the region’s competitive markets, the ISO does not comment on the business decisions of individual market participants,” he said.

Is Millstone Profitable or Not?

Hennessy said Dominion does not release profits or loss data on individual units. But in its earnings call for the fourth quarter of 2016, CFO Mark F. McGettrick indicated Millstone, which will have two refueling outages this year, would be a drag on earnings and that it will be “challenging” for the company to meet its historical earnings growth rate. “Now that we have hedged most of Millstone’s 2017 expected output, we estimate a $10 to $12/MWh reduction in realized energy prices versus last year, impacting 2017 earnings by about 15 to 20 cents/share,” he said, according to a transcript by Seeking Alpha.

The company, which had operating earnings of $3.80/share in 2016, is projecting $3.40 to $3.90/share for this year.

However, in projecting operating earnings for 2018, McGettrick said that the Connecticut nuclear power station would likely contribute to earnings, as only “one fuel refueling outage at Millstone should add another 10 cents/share to year-over-year results.”

The company said the net capacity factor for its six units was 93% last year, the highest since 2013 and the second highest since Millstone was acquired in 2001 from Northeast Utilities for $1.28 billion.

Greg Gordon, head of power and utilities research at investment advisory firm Evercore ISI, asked officials on the call to confirm whether Dominion “did not contemplate any change in regulatory scheme in Connecticut or Massachusetts, as it pertains to clean energy credits for Millstone.”

McGettrick responded that the “only thing we’ve factored into our growth rate and for 2018 is a very modest increase in power prices in the Northeast just because we think they’re extraordinarily low right now. It was not a reflection of any legislative effort that would be out there, but just … a normal slow recovery in the Northeast on power.”

Michael Weinstein, a broker at Credit Suisse Securities, asked about the possibility for Massachusetts legislation to support nuclear and what form it might take.

CEO Thomas F. Farrell said, “What we’ve heard is more through the regulatory process in Massachusetts, but yes … all of this is in development. … It would be a similar approach to what Connecticut is considering. … It is an opportunity for us to fit into their clean energy program and compete with other clean energy sources.”

Angie Storozynski, an analyst for Macquarie Capital, asked how much the Connecticut legislation and other state efforts supporting nuclear would add to earnings. “Are we talking, I don’t know, 5 cents, are we talking 20 cents? I mean, just a rough estimate.”

“We have no estimate to give you,” McGettrick responded. “The legislation is not even out of committee. And the exact structure is still evolving, I think, so we don’t have any estimate or even a probability at this point whether there’ll be success in Connecticut. We would hope there would be, but we don’t have a number today at all.”

At 2,111 MW, Millstone is New England’s largest power plant, producing more than half of the electric power used in Connecticut and about one-seventh of New England’s. Unit 2 (883 MW) is licensed to operate through 2035, while Unit 3 (1,228 MW) is licensed through 2040.