Page 1166 – RTO Insider

May 27, 2018

Capacity Prices Jump in Most of PJM

By Rory D. Sweeney and Rich Heidorn Jr.

Capacity prices increased sharply in most of PJM for delivery year 2021/22, with prices for the RTO rising to $140/MW-day from $76.53 last year, an increase of 83%.

The ComEd zone increased $7 to $195.55/MW-day, while Eastern MAAC dropped to $165.73 from $187.87 last year (-12%). The PSE&G zone, which cleared as part of EMAAC last year, rose to $204.29.

The ATSI zone, which cleared along with the rest of the RTO last year, separated this year, jumping to $171.33. BGE, which was part of MAAC last year, separated at $200.30. MAAC cleared at $86.04 last year. (See Capacity Prices down in Most of PJM in 1st Year of 100% CP.)

The Base Residual Auction procured 163,627 MW for 2021/22, resulting in a 21.5% reserve margin. That was down from 165,109 MW last year and a reduction of almost 2 percentage points from last year’s 23.3% reserve margin. That was still substantially above PJM’s 15.8% reserve requirement. About 192,450 MW offered into the auction, an increase from 189,918 MW that offered in last year.

The RTO obtained 893 MW of capacity from new generation and 508 MW from uprates to existing or planned generation, a 50% drop from the new capacity acquired in the 2017 auction.

“We did see a decrease in offers from new capacity resources. That certainly was not unexpected given the trends we have seen in the last several years,” Stu Bresler, PJM’s senior vice president for operations and markets, said during a news conference Wednesday.

PJM said the higher prices in most locations reflected continued low energy market prices, which causes generators to make higher capacity offers; an increase in the net cost of new entry, reflecting depressed energy revenues; and a drop in cleared capacity and the number of new generators. Partially offsetting those factors was a lower reliability requirement reflecting lower demand forecasts.

The auction, the second under 100% Capacity Performance, also saw increases in cleared demand response, energy efficiency and renewable resources.

DR cleared 11,126 MW, up 3,305 MW, while EE cleared 2,832 MW, a jump of 1,100 MW.

Wind cleared 1,417 MW, an increase of 529 MW. Solar cleared 570 MW, more than quadrupling from 125 MW last year.

Coal generators increased their share by 500 MW, while gas rose by 1,000 MW, including one new combined cycle plant.

Cleared imports totaled 4,052 MW, most from west of the RTO. Deducting 1,320 MW in exports resulted in a net import of 3,405 MW.

Nuclear Decline

Cleared nuclear generation totaled 19,900 MW, a drop of 7,400 MW.

“I don’t think that came as much of a surprise to the market,” Bresler said, noting he had seen estimates of an even higher drop. “We continue to see a good amount of diversity across the system.”

Exelon announced afterward that its Three Mile Island and Dresden nuclear plants, and all but a small portion of the Byron plant, failed to clear in the auction. The company’s Oyster Creek plant, which is set to retire by October 2018, did not offer in the auction.

Robbie Orvis of the clean energy consulting firm Energy Innovation said the trend wasn’t consistent across all zones.

“Not only did a substantial amount of nuclear not clear (a 7.4-GW decline from last year), but capacity prices in regions with a lot of nuclear didn’t necessarily improve much, if at all. In EMAAC, which has roughly 25% of PJM’s nuclear capacity, prices actually dropped by $22.14/MW-day,” he said. “In ComEd, which has about 32% of PJM’s nuclear capacity, prices only increased by $7.43/MW-day. The remaining regions with nuclear capacity saw healthy price increases ranging from $53.96/MW-day to $94.80/MW-day.

“It’s unclear how units might have changed their bidding behavior in response to state nuclear subsidy programs, but given the economic hardships for many nuclear plants in PJM, these results don’t point to any kind of dramatic change in market conditions,” he said.

Jennifer Chen of the Natural Resources Defense Council pointed to a theory that Exelon might have “sacrificed” some nuclear megawatts, effectively holding them out of the auction to maintain a higher price.

Exelon and the Nuclear Energy Institute said the results pointed to the need for changes in market rules to recognize nuclear plants’ contributions to greenhouse gas reductions and grid resilience.

The company said it was the fourth consecutive year that TMI failed to clear, and that the plant, which it has threatened to close in October 2019, has not been profitable for six years.

It said its Quad Cities plant cleared “as a result of” Illinois’ zero-emission credit program.

Dresden and Byron, which have capacity obligations through May 2021 and May 2022, respectively, are not in immediate risk of retirement, the company said.

NEI CEO Maria Korsnick said the results “demonstrate the economic pressures facing well-run nuclear plants” because of “distorted market forces.”

“Energy Secretary [Rick] Perry has been ringing the warning bell that fuel security and resilience are critical to energy security and national security. Only by bringing the capacity and energy markets into better balance will we be able to realize the benefits of a diverse energy supply,” she said.

Coal Increases

Although coal’s share of cleared capacity increased by 500 MW, Bresler said the auction rewarded only some coal units.

“We did see some fairly large plants that had cleared last year that did not clear this year. On the other hand, we saw … increased cleared capability on a lot of existing units. I think what that may speak to is improvements in efficiency at those plants that are making them more competitive. I think they’re real close right now, in some cases, [to] natural gas. Coal plants that have larger capabilities, that can operate efficiently, that have made the environmental upgrades that are necessary … hung in there this year,” Bresler said.

“What this auction showed is — quoting a former colleague of mine — the death of coal has been greatly exaggerated,” he added.

Orvis said the outcome “indicates that these units are doing all right in PJM, and it certainly pours some cold water on arguments in favor of providing subsidies for coal units.”

End to Seasonal Concerns?

DR offered into this year’s auction increased almost 21% to 11,887 MW, nearly 94% of which cleared. Of the 11,126 MW of DR that cleared, 96% cleared as annual CP and 452 MW cleared as summer-only resources that were aggregated with other products to meet CP’s requirement for year-round commitment.

“I was a little bit surprised by the magnitude of the increase in annual demand response that was willing to commit to the [year-round] Capacity Performance requirements in this auction,” Bresler said.

“There’s been a lot of concern expressed in some parts of the stakeholder community about limiting demand response and not allowing that summer-only capability. Frankly, between the increase in aggregation we saw here and the amount of annual that was willing to commit to those Capacity Performance requirements, I have to question whether we still have an issue there.”

In total, 715.5 MW of seasonal capacity resources cleared as part of aggregated packages, an 80% increase from the 398 MW of seasonal resources that cleared last year. This year’s total included 452.3 MW of summer DR, 209.3 MW of summer EE and 53.9 MW of summer intermittent resources, which were packaged with 715.5 MW of winter resources — mostly wind.

Chen and Orvis questioned whether the higher-than-necessary reserve margin made seasonal resources less concerned about potential CP penalties and willing to take the risk to cash in on the auction revenue.

“There’s a structural issue and maybe PJM has a point that there’s always innovation … but the issue is if you have a structural issue, there is the potential for even more seasonal resources to participate and at lower clearing prices,” Chen said.

Orvis speculated that resources might have had trouble aggregating and bid in less megawatts than they have available to leave headroom if a CP assessment occurs in the winter.

“PJM should be careful not to imply that these results mean seasonality is not an important factor, and should think carefully about why the resources participated in the way they did, and how create a more efficient and optimized market down the road,” he said.

Katherine Hamilton, executive director of the Advanced Energy Management Alliance, attributed the increase in DR to “the more reasonable amount of time that providers had to work with their customers in preparation for the new capacity market rules; to improvements in customer-sited technologies; and to investments customers have made in their back-up generators to be compliant with an EPA rule.”

“We have yet to determine the real potential of consumer load response capability, which is expanding significantly this year,” she added. “Consumer participation and choice are critical for managing cost and reliability.”

DR provider EnerNOC said it will collect more than $180 million in capacity payments from the auction.

Vistra Energy said it will receive $559 million in capacity revenue after clearing almost 9,800 MW at a weighted average clearing price of $156.47, including 2,450 MW in ComEd and 6,435 MW in the rest of RTO.

Revenues Still Down

The increase in capacity prices won’t fully make up for lower energy prices, which account for the “vast majority” of wholesale costs, Bresler said. Capacity prices are perhaps 20 to 30% of wholesale costs, while energy revenues make up between 60 and 70%, he said.

“The increase in capacity prices certainly does not outstrip … the reduction in energy prices, however there is a relationship between the two,” he said.

Chen said she was “surprised that the prices increased so much given the oversupply.”

Orvis said the near doubling of prices for most of the RTO is good for generators in general but agreed with Bresler that they don’t represent large increases.

“For a 1-GW nuclear plant running at a 90% capacity factor, a $63.47/MW-day capacity market price increase is roughly equivalent to a $3/MWh increase in the average energy market price. For a 1-GW coal plant running at a 45% capacity factor, it’s roughly equivalent to a $6/MWh increase,” he wrote in an email. “Those are pretty small in the grand scheme of things, especially for nuclear plants.”

He said the “healthy” reserve margin, even with the reduction in nuclear, was “more evidence that Trump administration claims that losing generation will cause a grid disaster are complete nonsense.”

May 25, 2018

Cost Containment Coming to PJM Transmission Bids

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM stakeholders resoundingly endorsed LS Power’s controversial proposal to bring cost-containment measures into the RTO’s transmission planning process following more than two hours of debate before the Markets and Reliability Committee on Thursday.

The proposal will require PJM to evaluate cost commitments — including construction costs, return on equity and capital structure — in its analysis of competitive bids for transmission construction.

PJM Cost Containment LS Power Transmission Bids PJM — PJM’s Markets and Reliability Committee on Thursday approved measures to require PJM to consider cost commitments when comparing competitive bids for transmission construction. | © *RTO Insider*

The approval came after a last-ditch attempt to delay a vote fell short.

TOs, who have been fighting the proposal for months, overwhelmingly opposed the measure, but stakeholders were won over by the chance to inject more competition and transparency into the process.

“We stand for markets. We stand for competition. We believe this … expands competition even further into the PJM processes,” said LS Power’s Sharon Segner, one of the main sponsors of the endorsed proposal.

Amendments

Thursday’s standoff was set in motion at January’s MRC, when stakeholders voted to defer a vote on an earlier LS Power proposal.

While LS Power had been heavily involved in special sessions of the Planning Committee that focused on the issue, the company had not sponsored a full-fledged proposal through PJM’s stakeholder process. It instead focused on attempting to change the RTO’s less comprehensive proposal. On the night before that proposal was set for a vote at the January MRC, LS Power submitted an alternative motion that differentiated between cost estimates and cost commitments and required PJM to weigh guarantees in its evaluation of bids.

When PJM’s proposal failed, TOs scrambled to bury the alternative LS Power proposal, eventually succeeding in having its vote deferred until the May MRC meeting with more special sessions scheduled in the interim for stakeholders to work toward consensus.

As its dispute with the TOs escalated, LS Power found allies among state consumer advocates, who pushed PJM into developing evaluation templates to standardize the bid process. TOs continued to fight the LS Power initiative and rallied behind a new RTO proposal that incorporated the templates but limited consideration of cost commitments to construction costs. LS Power also incorporated PJM’s templates but maintained its wider analysis of all cost guarantees.

At the Planning Committee meeting earlier this month, stakeholders endorsed PJM’s newest proposal, along with a recommendation that the MRC remand the issue back to the PC for further discussion. An effort to strip LS Power’s proposal of being the first voting item on the issue ultimately failed. (See Cost Containment Proposal Survives; Headed to MRC.)

In a final special session, just days before the MRC, LS Power teamed with Erik Heinle of the D.C. Office of the People’s Counsel to add several “friendly amendments” to the proposal. The revisions removed consideration of operations and maintenance cost guarantees but pushed for additional transparency and instructed PJM to work with its Independent Market Monitor to develop “comparative frameworks” for analyzing cost commitments versus cost estimates.

One would focus on construction costs, while the other would analyze ROE and capital structure commitments. While the friendly amendments were motioned and endorsed, opponents complained the repeated revisions subverted the stakeholder process.

“Once again, we haven’t followed the full process to vet the alternative motion,” Exelon’s David Weaver said.

LS Power attorney Mike Engleman of D.C. firm Engleman Fallon stridently refuted that argument, calling it “absolutely not true.”

The PC’s recommendation to remand the issue received substantial discussion at the MRC on Thursday, but supporters of the LS Power proposal opposed the delay, saying they feared it might never return for a vote.

“We are asking for a vote on the LS Power proposal, and we are strongly opposed to this notion of remanding this back to the PC,” Segner said. “Maybe it will get a vote at the PC, and maybe it won’t be based on how [the remand proposal was] drafted.”

“I think we have very different philosophical views, and I think we do need to vote” on the proposal, Heinle said. “Some things we’re not going to solve in the [stakeholder] process.”

Weaver said forcing a vote “will give an impression that the [stakeholder] process was a waste of time.”

“We do feel like that it’s not intractable,” he said, noting that TOs endorsed the templates. “But we do feel strongly that we do need time to understand impacts … so we can make sure that all stakeholders’ interests in cost containment are brought forward.”

Susan Bruce, who represents the PJM Industrial Customers Coalition, expressed “grave misgivings” with deferring the vote again, saying she felt the stakeholder process had worked. The conversation during the meeting was “very reasonable … but I worry,” she said.

“I’ve seen the conversations at the PC. I’ve read the letter,” she said, referring to a letter send by TOs to the Board of Managers requesting it order the MRC to not vote on the proposal. “With that lens, it’s a tough thing to be asked to defer this again.”

Several stakeholders, including the Monitor, urged members to reject the remand, which received a 1.95 sector-weighted vote, far short of the 3.335 threshold necessary for approval.

Following the vote, PJM’s Steve Herling said the proposals share many aspects and that while he “obviously … would have preferred” the RTO’s proposal, he was confident LS Power’s proposal is feasible.

“We believe we can implement their proposal, so at the end of the day, we’ll implement whatever is approved,” he said. “We have concerns, but we believe we can implement it.”

TOs’ Letter to Board

The sides then argued the legality of the LS Power proposal. Just a day before the meeting, 10 PJM TOs sent the board a letter arguing the proposal would infringe on the TOs’ rights under the Consolidated Transmission Owners Agreement, the Tariff and Section 205 of the Federal Power Act.

Proponents of the proposal disagreed, saying it only created a framework for PJM to evaluate bids that include cost guarantees, and that it doesn’t require TOs to include such guarantees in their bids. Heinle described the proposal as a “three-legged stool”: transparency through the evaluation templates; cost caps on ROE and capital structure; and comparative analysis informed by the Monitor.

“If incumbent transmission owners don’t choose to make a cost guarantee they don’t have to, but if they do, this puts some parameters around it,” Engleman said.

“At the end of the day, PJM looks at all relevant factors — cost just being one of them — and decides which is the right one to move forward with,” Segner explained.

American Municipal Power offered another friendly amendment, which added several small clarifications and confirmed that “neither PJM, the designated entity [winning bidder] nor any stakeholders are waiving any of their respective FPA Section 205 or 206 rights through this process.” An additional clarification on whether agreements between PJM and the winning bidder, known as designated entity agreements, would be filed at FERC was removed after PJM noted legal concerns. The remaining amendments were approved by LS Power and the proposal’s other sponsors.

PJM’s board did not respond to the TOs’ letter before the LS Power proposal was brought to a vote, where it received 92 votes in favor versus 17 votes opposed, or 3.79, well above the 3.335 threshold needed for approval.

The RTO must now work with the Monitor to develop the comparative frameworks, the first of which on construction costs is expected to be introduced in September and endorsed at the MRC on Dec. 6. It would be effective for long-term transmission proposal submission window, which runs from November to March. The second framework comparing ROE and capital structures is expected by May 1, 2019, to be effective for all submission windows going forward.

May 25, 2018

Westar-Great Plains Merger Wins Final Approval

By Rich Heidorn Jr.

Kansas and Missouri regulators on Thursday approved Great Plains Energy’s merger with Westar Energy, the final hurdles in a stock-for-stock merger of equals with an equity value of about $15 billion.

Shareholders of Kansas-based Westar will own 52.5% of the combined company, with Missouri-based GPE, the parent of Kansas City Power & Light, controlling 47.5%.

The new company, to be called “Evergy,” will have about 964,000 Kansas and 611,000 Missouri customers. The new company’s board will initially be composed of an equal number of directors selected by Westar and GPE.

Westar Great Plains Merger — | *Great Plains Energy*

The Kansas Corporation Commission approved the deal Thursday afternoon after the Missouri Public Service Commission cleared it in the morning.

“We appreciate that regulators and shareholders recognize the value in combining the companies,” said GPE Chairman and CEO Terry Bassham, who will be president and CEO of Evergy. Initially, the company will continue to serve its customers as Westar and KCP&L.

The Kansas commission approved the merger based on a March 2018 settlement agreement among commission staff, the Citizens’ Utility Ratepayer Board, Sunflower Electric Power, Mid-Kansas Electric, the Kansas Power Pool, Midwest Energy and solar developer Brightergy (18-KCPE-095-MER).

Westar and KCP&L retail electric customers in Kansas will receive one-time bill credits of $30.5 million and annual credits of $11.5 million from 2019 through 2022. Following their 2018 rate cases, KCP&L and Westar will be subject to a five-year base rate moratorium assuming their authorized return on equity is at least 9.3%.

The Kansas commission imposed an additional requirement that the companies develop an integrated resource plan process to “ensure the merger maximizes the use of Kansas energy resources,” it said in a press release.

The new company will maintain headquarters in both Topeka, Kan., and Kansas City, Mo., with the Topeka headquarters guaranteed for at least 10 years. There will be no involuntary severances because of plant closings, and the company’s 5,000 employees will receive compensation and benefits at current levels for at least two years.

The Kansas commission approved the deal over the objections of Kansas Electric Cooperative, which said the settlement did not address all its concerns.

Earlier in the day, Missouri regulators approved the deal, which provides initial bill credits of $29 million for their retail ratepayers.

“The merger will create a stronger combined company, with more customers, more geographic diversification, no transaction debt to complete the merger, and the prospect for higher earnings growth rates than either GPE or Westar would be able to achieve on a stand-alone basis,” the Public Service Commission said in its order (EM-2018-0012).

Kansas regulators last year pushed back on GPE’s original plan to buy out Westar, forcing the companies to recast the transaction as a “merger of equals.”

“It’s been a circuitous route to get here,” the Topeka Capital-Journal quoted PSC Chairman Daniel Hall as saying. “We had to fight through the jurisdictional issues, then we had to dismiss the case when our sister jurisdiction ruled it was not in the public interest and start all over again with this one.”

FERC approved the merger on Feb. 28 (EC17-171). (See FERC Greenlights Great Plains-Westar Merger.)

The deal is expected to close in early June. The company expects to rebalance its capital structure by repurchasing about 60 million shares of its common stock over a two-year period.

Great Plains stock closed Thursday at $19.75/share, up 1%. Westar shares ended the day at $54.58, an increase of 0.66%.

May 25, 2018

Steering Committee Advances MISO Market Improvement Ideas

By Amanda Durish Cook

MISO’s Steering Committee this week submitted eight new possible market improvement ideas to the Market Subcommittee for stakeholder discussion.

During a May 23 conference call, Steering Committee Chair Tia Elliott said all new Market Roadmap ideas will receive more in-depth discussion at the subcommittee, which could assign them to other stakeholder committees. MISO will also hold a stakeholder workshop on June 7 to discuss the new ideas.

MISO Market Roadmap Steering Committee — MISO Steering Committee in March 2018 | © *RTO Insider*

Originated by the Independent Market Monitor and stakeholders, the suggestions include:

Creating financial incentives for members that provide frequency response service, as suggested by Indianapolis Power and Light.
Allowing dispatchable intermittent resources to provide regulation service, a suggestion Xcel Energy submitted with the support of several other market participants.
Evaluating the feasibility of implementing a day-ahead market on a 15-minute basis rather than on an hour-to-hour schedule under MISO’s market platform replacement project. Monitor David Patton claims that a more specific schedule would reduce make-whole payments.
Removing transmission charges from coordinated transmission service transactions with PJM, another Monitor suggestion. MISO currently applies transmission charges to these transactions when they are offered, not just when they are scheduled, and the Monitor said the charges discourage CTS offers and “undermine the potential for substantial savings.”
Expanding modeling to include equipment operating characteristics and constraints of other types of generation resources, much like MISO is improving modeling for combined cycle generators, as suggested by Ameren Missouri.
Requiring that the installed capacity of planning resources be guaranteed as deliverable through firm transmission service, as suggested by the Monitor.
Allowing load-modifying resources and emergency-only resources to receive Planning Resource Auction capacity credit “if they are expected to be reasonably available in an emergency,” according to the Monitor.
Creating a look-ahead dispatch tool for generators. DTE Energy said MISO’s current practice of publishing the next dispatch instructions on a five-minute basis “can lead to inefficiencies with generators who need to bring on or off equipment to meet this dispatch.” DTE said it has support from several other market participants on the idea.

MISO Senior Manager of Market Strategy Mia Adams said that, after the workshop, the RTO and stakeholders will begin to rank the ideas in order of importance to determine when — if at all — MISO will begin to propose market changes to address them.

The Steering Committee has the authority to veto Market Roadmap improvement ideas before they reach the Market Subcommittee if they do not fit the definition of market improvements — although it cannot discuss the merits of the ideas — but it has never exercised that power.

May 25, 2018

Environmental Group Sees More Ill. Renewables, Bailout Bids

By Amanda Durish Cook

Illinois is advancing toward a cleaner energy future thanks to two decades of policy and market developments, and new efforts could accelerate the trend, a Midwest environmental advocacy group said Thursday.

Speaking during a May 23 webinar on the evolution of Illinois’ energy market, Brad Klein, senior attorney for the Environmental Law and Policy Center, said last year’s Future Energy Jobs Act, coupled with increasingly competitive renewable generation prices, will continue to sway the state toward clean energy. The law set renewable and energy savings goals for utilities, created community solar programs and restructured the state’s renewable target process and $200 million annual budget.

The ELPC predicts that by 2020, the FEJA will boost Illinois’ solar capacity from 84 MW today to 2.8 GW by 2022, and also add 1.3 GW to its current 4.3-GW wind portfolio.

However, Klein said he predicted “growing pains and bottlenecks” in the interconnection process to get the projected amounts of solar generation online.

Klein said although he expects Illinois will be able to meet its minimum new build targets for renewable resources by about 2020, the state will probably need to continue building renewables to meet its 25% use target in the Commonwealth Edison and Ameren territories by 2025.

“We think we’re going to hit the minimum thresholds for new wind and solar build-out in the early 2020s … but we’re not on track yet to meet that 25% by 2025. We expect that this will be a long-term and sustainable effort over time,” Klein said.

He also forecasts more future bailout attempts by nuclear and coal generation operators, particularly Dynegy, which is now owned by Vistra Energy.

Klein said the FEJA favors energy efficiency, renewable energy and nuclear generation, and the final version of the law excluded draft provisions for coal bailouts, demand charges and support for microgrids. He also said FEJA notably lacked any provisions on EV and energy storage, markets he’d like to see developed in Illinois.

There are opportunities for Illinois to develop municipal aggregation programs, which are currently “stagnant,” he said. “I’m hoping we’ll see a new wave of aggregation.”

The Path to FEJA

Klein said the ELPC expects more renewable and decarbonization policies to take hold incrementally in Illinois, as other energy-related state policies have in the past.

“It seems to follow a pattern: Every 10 years or so, there’s major legislation,” he said.

He noted that Illinois began to restructure its market with 1997’s Illinois Electric Service Customer Choice and Rate Relief Law, which cut rates by up to 20% and froze them for 10 years while introducing retail competition in the state.

Klein said the state’s next wave of change came in response to the 2006 reverse power auction that saw residential prices jump 20 to 50% after the decade-long price caps expired. The auction sparked a public backlash against utilities and power marketers.

“It led to a political situation that created the next major piece of legislation,” he said, referring to the 2007 creation of the Illinois Power Agency, an independent state agency that procures power for utilities, and the state’s first renewable portfolio standard.

The 2007 RPS fell short of the state’s goals, and utilities became “increasingly hostile” to distributed resources, Klein said, leading to 2017’s FEJA.

The IPA said last year that Illinois’ first RPS, combined with retail choice, meant customers could toggle between utility service and alternative suppliers, “leading to budget and target uncertainties.” As a result of the FEJA, Illinois today uses a single RPS, rather than administering separate rules for customers using alternative suppliers.

May 24, 2018

Mass., R.I. Pick 1,200 MW in Offshore Wind Bids

By Michael Kuser

Massachusetts and Rhode Island on Wednesday awarded procurements for 1,200 MW of offshore wind energy from what will become the two largest offshore projects in the U.S.

ISO-NE Offshore Wind Vineyard Wind — | *Vinyard Wind*

Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, won the contract to supply Massachusetts with 800 MW of offshore wind energy, while Rhode Island selected Deepwater Wind to build the 400-MW version of the company’s Revolution Wind proposal.

Financial details for the fixed-price bids have not been disclosed.

“With today’s landmark decisions, Massachusetts and Rhode Island are ready to pioneer large-scale offshore wind development that will light the way for our industry and nation,” American Wind Energy Association CEO Tom Kiernan said in a statement. “With world-class wind resources, infrastructure and offshore energy expertise, the U.S. is primed to scale up this industry and lead it.”

Also on Wednesday, New Jersey Gov. Phil Murphy signed legislation codifying his commitment to build 3,500 MW of offshore wind by 2030, surpassing New York’s target of 2,400 MW. (See related story, Gov. Signs NJ Nuke Subsidy, Renewables Bills.)

Fast Start

“Vineyard Wind is proud to be selected to lead the new Massachusetts offshore wind industry into the future,” company CEO Lars Thaaning Pedersen said Wednesday. “Today’s announcement reflects the strong commitment to clean energy by Gov. [Charlie] Baker and the Massachusetts legislature.”

The Vineyard project will lie about 15 miles south of Martha’s Vineyard and include a transmission component linking back to the ISO-NE grid.

The company plans to begin construction in 2019 and start operating the first 400-MW section of the project by 2021, with the second half slated for completion in 2022. It got a head start on its rivals in the solicitation by beginning state and federal permitting processes in December and submitting the project’s draft environmental impact statement with state regulators on May 1.

Vineyard has said its project would generate 3,600 jobs, including 1,500 coming with the start of onsite construction. The company has also promised the project will yield significant CO₂ reductions, displacing 1.25 million metric tons per year upon full operation in 2022.

Massachusetts Sierra Club Director Emily Norton called Wednesday’s announcement “terrific news” but said it is only the beginning.

“With the cost of offshore wind falling precipitously, we can transition much more quickly to 100% clean energy than anyone thought possible, and there is no time to lose,” Norton said.

“This is such an important milestone. Rather than drilling for oil and gas off of the New England coast, we will find our energy future blowing in the wind,” U.S. Sen. Ed Markey (D) said on Twitter.

In December, three developers — Vineyard, Deepwater and Bay State Wind — submitted bids in the request for proposals (83C), which called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determined that a larger proposal was both superior to other proposals and “likely to produce significantly more economic net benefits to ratepayers.”

All three developers purchased renewable energy leases off the coast from the U.S. Bureau of Ocean Energy Management.

Massachusetts’ 2016 Act to Promote Energy Diversity mandated the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — to sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. All three utilities had a hand in the selection, and an independent evaluator monitored and assisted the bid evaluation process.

Transmission Backbone

Deepwater Wind’s 400-MW project will connect to land at the Brayton Point substation in Somerset, Mass., and the company partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)

The Revolution project will firm its output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.

vineyard wind offshore wind iso-ne — Interior of Northfield Mountain pumped storage facility | *Northfield Mountain*

The company’s bid said its grid-scale storage and expandable transmission system would “result in energy market savings of $75 million annually for Massachusetts ratepayers, without counting the benefits of economic development or emissions reductions.”

Deepwater developed the first offshore wind farm in the U.S., the 30-MW Block Island project in Rhode Island, which began commercial operation in December 2016.

“Rhode Island pioneered American offshore wind energy, and it’s only fitting that the Ocean State continues to be the vanguard of this growing industry,” said Deepwater Wind CEO Jeffrey Grybowski. “We applaud Gov. [Gina] Raimondo for her bold commitment to a clean energy future.”

May 24, 2018

NY Task Force Examines Carbon Pricing Impacts

By Amanda Durish Cook

New York’s adoption of a carbon charge will likely increase the state’s wholesale energy prices, decrease prices for zero-emission credits and boost energy revenues for new “Tier 1” renewable resources supported by renewable energy credits, industry stakeholders heard Monday.

NYISO is aiming for its carbon charge to be “reasonably transparent and predictable,” ISO staffer Nathaniel Gilbraith told a May 21 meeting of the Integrating Public Policy Task Force, which is examining the impact of carbon pricing on New York’s wholesale market. The charge should also “avoid distorting dispatch decisions away from grid power that can create emissions leakage,” he said.

Public Policy Task Force NYISO Carbon Pricing — A meeting of the Integrating Public Policy Task Force (IPPTF) in late 2017 | © *RTO Insider*

The ISO earlier this month proposed to incorporate the carbon costs into its market by deducting a uniform carbon emissions charge from each energy supplier. (See NYISO Floats Carbon Pricing Straw Proposal.) Resources with zero point-of-production carbon emissions — including nuclear, conventional hydro, wind and solar generation — would not be assessed a carbon charge.

Existing Policy Interaction

A Brattle Group analysis, released at the meeting, shows that NYISO’s proposal would increase wholesale energy prices but decrease ZEC prices “on a dollar-for-dollar basis.”

Brattle also concluded the charge would increase energy revenues for new Tier 1 renewables (resources supported by RECs), thereby driving down REC prices on an equivalent basis, although it cautioned that the offset could be lower because RECs are solidified in contracts while the carbon charge is subject to revision. But the proposal would not reduce prices for fixed-price REC contracts already in place, the group said.

The report also speculated that the Regional Greenhouse Gas Initiative may already be causing a leakage of allowances and emissions to other states not under the mandatory program. To combat leaks from a future New York program, Brattle suggested the state impose border charges and reduce the number of allowances it offers.

NYISO staff acknowledged that potential changes to RGGI make it difficult to predict exactly how New York’s carbon pricing will interact with the program. A new RGGI cap is set to take effect in 2020, and New Jersey and Virginia are both contemplating joining the program.

Consumer Impacts

The impact of a carbon charge on consumers is even less clear at this point.

NYISO Manager of Economic Planning Timothy Duffy said the ISO is working with Brattle on a consumer impact analysis that will study 2020, 2025 and 2030 using a reference case scenario from its annual Congestion Assessment and Resource Integration Study. The study assumes the existence of 250 MW of offshore wind and attainment of New York’s Clean Energy Standard by 2030, and also incorporates the latest large-scale renewable procurements issued by the New York State Energy Research and Development Authority.

The ISO will also study impacts on locational-based marginal pricing and other metrics in 2030 using a model assuming 2,400 MW of offshore wind coming online by 2030, and another scenario in which the R.E. Ginna nuclear plant and Unit 1 of the Nine Mile Point Nuclear Station retire by 2029. The NYISO/Brattle study will use NYMEX futures and prices in the U.S. Energy Information Administration’s Annual Energy Outlook to project natural gas price estimates.

Duffy said more assumptions for the analysis will be presented in early June.

Weekly Reporting

NYISO is also considering requiring generators to self-report emissions data on a weekly basis for billing, with true-ups occurring against reported emissions in a trusted database, such as those maintained by EIA or EPA.

Gilbrath pointed out that the “vast majority” of New York’s fossil-fuel suppliers are already subject to emissions reporting through RGGI. NYISO’s 140 generators over 25 MW and 18 cogeneration plants are required to report under the program, leaving 114 generators representing 98 GWh of net generation in 2017 without existing reporting obligations.

NYISO’s carbon pricing would cover “burner tip” carbon emissions directly attributable to wholesale energy and ancillary services, including start-up times and no-load levels, GIlbraith said, but he asked stakeholders for other suggestions about how the ISO should manage emissions reporting.

Gilbrath said NYISO will not charge upstream carbon emissions, emissions associated with compressing natural gas for use in power plants or other greenhouse gasses, including methane and nitrous oxide. He said excluding those emissions would help keep carbon pricing predictable and gives suppliers certainty.

May 23, 2018

Indiana Court Favors Duke in Cost Recovery Suit

By Amanda Durish Cook

An Indiana appeals court ruled Monday that Duke Energy can recover from its ratepayers the cost of damages associated with not fulfilling the terms of a wind energy purchase agreement.

The court said it found sufficient evidence to let stand the Indiana Utility Regulatory Commission’s (IURC) original approval of the recovery plan (93A02-1710-EX-2468).

In 2006, Duke and Benton County Wind Farm in Indiana entered into a power purchase agreement for which the IURC authorized full cost recovery from Duke ratepayers. However, in 2013 Benton sued Duke in federal court over what it claimed was a breach of contract when Duke failed to purchase energy from the facility. Benton interpreted the agreement to mean that Duke was responsible for lost production costs in addition to the power Benton delivered.

IURC PPAs Duke Energy — Benton County wind turbines | *Huw Williams*

The U.S. 7th Circuit Court of Appeals ruled that Duke was obligated under the PPA to “pay for power not taken,” and the parties settled for $29 million, with the IURC deciding last year that the money should be recovered from Duke’s ratepayers over a 12-month period.

The IURC “recognized that Duke would be incurring significant costs in connection with the PPA,” the U.S. appeals court found. “Consequently, in order to further the commission’s policy of encouraging the development of renewable resources, the commission authorized Duke to recover all of its PPA costs from ratepayers for the entire 20-year term.”

Two ratepayers, Michael Mullett and Patricia March, appealed the IURC’s decision, arguing that its order was “contrary to law because the damages are ‘liquidated’ and ‘hypothetical’ and amount to impermissible retroactive ratemaking.”

But state court Judge Cale J. Bradford on Monday said there was no caselaw to support the appellants’ claim that “purely hypothetical” liquidated damages prevent Duke from ratepayer recovery for the PPA.

The Indiana court also noted that the $29-million settlement “is no more than customers would have paid had a different offer been submitted to MISO from March 2013 through June 2017, and is less than what potentially could have been awarded has [sic] a settlement not been reached.”

Bradford also found no merit that the recovery would amount to retroactive ratemaking. “The fact that the damages arose from a past dispute regarding a contract interpretation does not automatically make the commission’s order contrary to law,” he wrote. He added that although the case was not a rate case, even rates “are subject to subsequent reconciliation after historical costs have become known.”

Bradford also noted that paying lost production costs under wind farm PPAs is consistent with past cases involving Indianapolis Power and Northern Indiana Public Service Co.

May 23, 2018

CAISO Moves to Optimize Short-Term Unit Supply

By Jason Fordney

CAISO is proposing to quadruple the number of hours in its time horizon for short-term commitment of generation units to better address load peaks that occur later in the day when solar output drops off the grid.

Extending the “short-term unit commitment” (STUC) horizon to 18 hours from 4.5 hours will better recognize morning, afternoon and evening peaks, CAISO said when it introduced the proposal Tuesday. The ISO described the need for a longer unit commitment horizon in a May 15 issue paper/stra w proposal.

caiso stuc short term unit commitment duck curve — Limitations in short-term unit commitment (STUC) planning horizon in relation to the “duck curve.” | *CAISO*

“The purpose of the STUC modifications is to provide earlier notification to resources that are needed to meet the evening peak, which increases the probability these resources will be available, and better optimize the use of resources with limited starts over the entire day,” the proposal said. These changes will increase market efficiency and reliability.”

The STUC is the procedure run about 52.5 minutes before a trading hour to commit medium-start units for delivery within a forward-looking horizon — currently 4.5 hours. The STUC produces a unit commitment solution for every 15-minute interval within the horizon and issues binding start-up instructions based on units’ start-up times.

According to a CAISO presentati o n, the grid operator is currently “unable to make informed commitment and optimization decisions” because the current process considers only short- or medium-start resources and has limited resources for the real-time market.

Under current rules, a resource might be committed to a morning peak when it should be used for the evening peak, CAISO said. Resources with a start-up and minimum run time greater than 4.5 hours cannot be committed by the current STUC process.

With the proposed changes, generation resources will have earlier notification regarding meeting the evening peak, leading to increased efficiency and reliability “by better equipping the real-time market to meet system needs,” the ISO said.

CAISO floated the initiative in part because it foresees below-average hydro resources this summer, contributing to a tight supply situation. CEO Steve Berberich discussed some of the issues last week at the ISO’s Board of Governors meeting. (See CAISO Board Approves Forecast Error M e asures.) California mountain snowpack was at 51% of the normal April 1 average, the grid operator said. There is a 50% probability of a Stage 2 emergency for at least one hour this summer, when operating reserves drop below 5% after dispatching all resources, including demand response.

The proposed new changes will improve the efficiency of the real-time market by optimizing resource dispatch and dealing with “the duck curve,” the load profile that shows how the system is affected by large amounts of solar output. By 2020, the ISO predicts the generation ramping need on a typical spring day will grow to about 14,000 MW (from about 12,000 MW in 2017) between early afternoon and about 9 p.m. The “belly” of the duck curve is getting deeper each year as rooftop solar proliferates during mid-day hours, requiring a steeper ramp-up of resources in evening hours as solar generation goes offline. The ISO does not have visibility into rooftop solar but still must manage its effect on the grid.

Aside from expanding the STUC to 18 hours, CAISO plans to revise real-time market bid cost recovery for long-start units and extend EIM non-financially binding base schedule and bid submission requirements to 20 hours from the current 6 hours.

CAISO management has prioritized the initiative for implementation by fall of this year. Comments on the proposal are due by May 29, with review by the Energy Imbalance Market Governing Body and CAISO Board of Governors set for July.

May 23, 2018

Gov. Signs NJ Nuke Subsidy, Renewables Bills

By Rich Heidorn Jr.

New Jersey Gov. Phil Murphy (D) on Wednesday signed legislation to subsidize the state’s nuclear generating fleet, raise its renewable generation targets, boost storage and offshore wind, and revamp its solar program.

In a press conference staged in front of solar panels in South Brunswick, N.J., Murphy signed Senate Bill S2313, which will create zero-emission certificates for three of Public Service Enterprise Group’s nuclear generators, and Assembly Bill 3723, which will raise the state’s renewable portfolio standard to 35% by 2025 and 50% by 2030. Murphy also signed an executive order to update the state’s Energy Master Plan with a goal of 100% “clean” energy by 2050.

new jersey nuclear subsidy renewable generation — N.J. Gov. Phil Murphy, speaks at bill signing at New Jersey Resources’ New Road solar installation in South Brunswick, N.J., surrounded by New Jersey Resources’ CEO Laurence M. Downes, left, and Senate President Stephen Sweeney, right. | *New Jersey Office of the Governor*

The state’s previous RPS requirement targeted 24.39% renewables for the “energy year” ending May 31, 2028, according to the North Carolina Clean Energy Technology Center’s Database of State Incentives for Renewables & Efficiency.

Murphy said the new targets represent “one of the most ambitious renewable energy standards in the country.”

“Today, we’re taking another step forward in rebuilding New Jersey’s reputation as a leader in the development of clean energy sources while fulfilling a critical promise to foster our state’s energy future,” said Murphy, who took office in January. “Signing these measures represents a down payment to the people of New Jersey on the clean energy agenda I set forth at the beginning of my administration.”

Murphy replaced Republican Chris Christie, who had balked at plans to develop offshore wind and withdrew the state from the Regional Greenhouse Gas Initiative. Murphy, who has pledged to rejoin RGGI, noted that the legislation codifies his goal of 3,500 MW of offshore wind by 2030 and reinstates tax credits for offshore wind manufacturing that expired during Christie’s term.

The bills were approved by the Legislature on April 12. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)

ZEC Program

The ZECs, which are expected to cost up to $301 million annually, will be funded by a 0.4 cents/kWh tariff on retail distribution customers.

The legislation requires the state Board of Public Utilities to issue an order implementing the ZEC program within 180 days. The BPU will award ZECs to nuclear plants licensed through at least 2030 that can demonstrate they are at risk of closure within three years.

PSEG’s Salem Unit 1 (licensed to operate through Aug. 13, 2036) and Unit 2 (licensed through April 18, 2040) and Hope Creek (licensed through April 11, 2046) are eligible. Exelon’s Oyster Creek nuclear plant, scheduled to be retired in October 2018 under a prior agreement with the state, is not eligible. Exelon also is part owner of the Salem plant.

nuclear power new jersey nuclear subsidy renewable generation — Salem & Hope Creek Nuclear Power Plants | *Green Delaware*

The plants selected will initially receive ZECs for three years and the balance of the first energy year following selection. They will be subject to review by the BPU for additional three-year periods.

Out-of-state nuclear plants also could seek ZECs, but their approval may be dependent on a premature retirement of one of the remaining in-state plants because the bill caps ZEC eligibility at 40% of the state’s total electric usage. In 2016, according to the U.S. Energy Information Administration, the combined generation of the Salem and Hope Creek plants was 25.3 million MWh, 33.6% of the state’s 75.4 million MWh usage.

The state’s Office of Legislative Services calculated that the 0.4 cents/kWh tariff would generate $301.4 million based on 2016 consumption, translating to a ZEC cost of about $10/MWh.

Storage, Renewable Provisions

The Assembly bill requires the BPU to adopt energy efficiency and peak demand reduction programs and a community solar pilot program, and to revise the solar renewable energy certificate (SREC) program.

By Jan. 1, 2020, 21% of the state’s electricity must come from Class I renewable sources. The bill requires the BPU to begin a proceeding to reach the 2025 and 2030 RPS goals and caps the cost of the RPS program — excluding the costs of the offshore wind — at 9% of total costs to consumers in 2019 and 7% afterward.

This bill also requires the BPU, in consultation with PJM, to conduct an analysis determining the amount of energy storage to be added in the state over the next five years to provide the maximum benefit to ratepayers. The analysis will identify the optimum points of entry into the electric distribution system for distributed energy resources and include recommendations for financial incentives that may be required.

The BPU must submit a report on the storage findings within one year; six months after that, it must initiate a proceeding to add 600 MW of storage by 2021 and 2,000 MW by 2030.

The bill also requires electric power suppliers and basic generation service providers to increase the share of solar power in their portfolios to 5.1% by energy year 2021 before gradually reducing the percentage through 2033. The bill also reduces the solar alternative compliance payments beginning in energy year 2019 through 2033. Future solar RECs will be for 10 years, down from the current 15.

Electric customers would be able to participate in solar energy projects remotely located from their properties under the “Community Solar Energy Pilot Program,” which is to be converted to a permanent program within 36 months.

Utilities will be required to adopt energy efficiency measures to reduce electric usage by 2% and natural gas consumption by 0.75%.

The bill provides a tax credits for qualified wind energy projects in an eligible wind energy zone and requires the state to establish job training programs to develop a workforce for the manufacture and servicing of offshore wind equipment.

Reaction

The NJ Coalition for Fair Energy — funded by the Electric Power Supply Association and independent power producers Calpine and NRG Energy — criticized the nuclear subsidies and hinted it will seek to overturn them in court. Challenges by EPSA and others to ZEC programs in Illinois and New York are pending in the 7th and 2nd U.S. Circuit Courts of Appeals.

“While PSEG shareholders just became more prosperous, the reality is New Jersey consumers now have to confront higher electric bills for no reason other than to bail out PSEG management’s bad business decisions,” spokesman Matt Fossen said. “We wish officials would’ve waited to make a decision until after the results of PJM’s capacity auction were announced, which will be literally only hours after the governor’s signing. But this issue is not over — and it’s unfortunate the courts may be necessary to bring a dose of reason to the debate.”

Environmental activists and solar energy industry groups celebrated the renewable and DER provisions.

“It has never been more important for leaders to stand up for clean energy jobs, local investments, and clean air and climate progress in our communities. We are encouraged that in the face of rollbacks in Washington, Gov. Murphy is stepping up with bold action,” said Pari Kasotia, Mid-Atlantic director for Vote Solar.

The Energy Storage Association said the storage mandates put New Jersey in league with California, New York, Massachusetts, Oregon, Nevada and Arizona as states encouraging the technology.

Sean Gallagher, the Solar Energy Industries Association vice president of state affairs, said the bill will give “many more New Jersey residents, businesses and communities … access to solar energy.”

“If properly implemented, this legislation will create access to solar energy for consumers and businesses across New Jersey for the first time,” said Brandon Smithwood, policy director for the Coalition for Community Solar Access.

“Thanks to this important legislation, New Jersey residents who rent, live in apartments or can’t afford the upfront cost to install solar panels will now be better able to get their power from the sun,” said Luis Torres, senior legislative representative for Earthjustice.