Page 1217 – RTO Insider

February 2, 2018

MISO Winter Survey Shows Small Gas Improvements

By Amanda Durish Cook

CARMEL, Ind. — Midwest gas-fired generators have made incremental improvements to ensure fuel supply over the past year, MISO stakeholders learned Thursday.

At a Feb. 1 Reliability Subcommittee meeting, MISO Electric-Gas Operations Coordinator Phil Van Schaack said the RTO’s winter fuel survey shows generators made “modest improvements to fuel assurance” this winter when compared to statistics from the 2016/17 annual survey.

The report indicates that 44% of MISO’s 70.7 GW in natural gas capacity have either access to firm transportation or dual-fuel capability, up from the 40% reported last year.

The RTO’s remaining capacity either relies on a combination of firm transport and interruptible transport (33%) or all interruptible transport (8%). MISO also reported that 17.8 GW of natural gas plants holding firm transportation contracts say their firm transport is shared across multiple generators within their resource portfolios, a small decrease from last year’s results.

Van Schaack also said the number of generators subscribing to flexible pipeline services increased moderately over the last year.

More needs to be done in testing dual-fuel capability ahead of time, he said. Thirty percent of MISO’s dual-fuel generators have tested their backup fuel in the last three months, while 50% have operated on backup fuel within the last year.

Gas-fired facilities with dual-fuel capability account for just under 18 GW (25%) of the gas capacity in the MISO footprint. Approximately 63 GW of MISO’s gas-fired capacity answered the 2017 survey, representing 89% of the capacity registered in the RTO’s commercial model. MISO’s total natural gas capacity accounts for 41% of its total capacity.

Van Shaack said independent power producers and qualifying facilities predominately located in MISO South comprised the remaining 7.5 GW of natural gas generation that did not respond to the survey.

MISO credited its improved gas-electric communication, including the survey, for helping the RTO reliably navigate the cold snap that swept most of MISO in early January. (See MISO Breaks down Recent Cold Snap.) The survey specifically improved situational awareness during the extreme weather, the RTO said.

The survey also revealed that 58% of responding gas-fired generation owners are comfortable that their current pipeline service offerings meet their generation needs, with 11% saying they are dissatisfied and another 18% admitting they could use additional service.

February 2, 2018

WEC Energy’s Yearly Earnings Surpass $1 Billion

By Amanda Durish Cook

WEC Energy Group’s 2017 earnings surged 28% to $1.2 billion, boosted by a late-year cold snap and federal tax cuts.

The frigid temperatures “particularly between Christmas and New Year, added 2 cents/share, and drove us above the top end of our guidance range,” CEO Gale Klappa said during a Jan. 31 earnings call. The company earned $3.79/share.

WEC’s strong performance was key in electronics manufacturer Foxconn’s decision to connect a massive proposed plant to the southeastern Wisconsin grid, Klappa said.

“Our track record of reliability and competitive rates was a factor in the decision by Foxconn Technology Group to invest $10 billion in a high-tech manufacturing campus here in Wisconsin. This is one of the largest economic development projects in American history,” he said.

MISO is expected to render a decision by March on American Transmission Co.’s expedited request to build the interconnection project to link Foxconn’s manufacturing plant to WEC subsidiary We Energies’ supply. The RTO found the project would have a low economic benefit over the next 20 years, making it an unlikely candidate for wider cost allocation. (See MISO Seeks Stakeholder Input on Foxconn Decision.)

Although Milwaukee officials are questioning the impact of the project on residential bills, the Wisconsin Public Service Commission last year approved a settlement that will maintain a flat base rate for WEC’s utilities for the next two years.

“In total, this will keep base rates flat for four consecutive years and essentially gives us our customers’ price certainty through 2019,” Klappa said.

The project is slated to go in service in December 2019.

Klappa also said WEC will continue work on its Peoples Gas subsidiary’s system modernization plan in Chicago, replacing 2,000 miles of at-risk mains and upgrading 300,000 customer services lines over the next three decades, possibly requiring excavation of half the city’s streets. Illinois regulators last month ended a two-year investigation into the $6.8 billion project, which had been criticized for runaway costs and poor management.

WEC Energy 2017 earnings federal tax cuts — WEC Energy Group service map | *WEC Energy Group*

“This program is literally critical to providing our Chicago customers with a natural gas delivery network as modern, safe and reliable,” Klappa said. “For many years to come, we will need to replace outdated natural gas piping — some of which was installed more than a century ago and is rusting — with state-of-the-art materials.” He added that WEC is working with the Illinois Commerce Commission on a “plan to flow savings from the new federal tax law back to customers in Chicago.”

Klappa also said subsidiary Minnesota Energy Resources will work the impact of tax reform into a pending rate case before the Minnesota Public Utilities Commission, which seeks to raise natural gas base rates by $12.6 million, or approximately 5%. The PUC has approved an interim rate increase at $9.5 million (3.8%) since late November, and a final decision is expected by the end of the year.

WEC’s 2017 results include earnings from recurring operations of $3.14/share and the net impact of a one-time gain of 65 cents/share from December’s federal tax reform law. This compares to 2016’s year-end earnings of $2.96/share.

For the fourth quarter alone, WEC recorded net income of $432.6 million ($1.36/share), compared to earnings of $194.4 million ($0.61/share) for the fourth quarter of 2016.

February 1, 2018

Utilities File San Onofre Settlement

By Jason Fordney

California utilities and other parties say they have reached a new settlement over the costs of shutting down the San Onofre nuclear power plant, replacing a contested 2014 agreement.

Southern California Edison and San Diego Gas & Electric, co-owners of the plant, said Tuesday that they submitted the agreement for approval by the California Public Utilities Commission, which in December 2016 ordered renegotiations after it came to light that former commission President Michael Peevey had engaged in undisclosed ex parte communications with SCE. The original settlement stuck ratepayers with 70% of the costs related to the early closure of the plant. (See CPUC Orders Renegotiation of San Onofre Settlement.)

SAn Onofre Nuclear Power Plant CPUC — The San Onofre Nuclear Power Plant was retired in 2013

The settlement stipulates that the two utilities would cease rate recovery of $775 million in costs related to San Onofre. It also reduces the regulatory asset value used to calculate recovery by $72 million by applying funds from litigation between the utility and the U.S. Department of Energy over fuel disposal responsibilities. Depending on the commission’s decision on the reduction in asset value, rate recovery would cease on either Dec. 19, 2017, or April 21, 2018.

SCE would retain amounts collected under the prior agreement before the cessation of rate recovery and will keep $47 million from arbitration with Mitsubishi Heavy Industries over the plant’s faulty generators. The utility would also retain the right to keep proceeds from selling nuclear fuel, which “may be significant.”

The proposed agreement also reduces from $25 million to $12.5 million the amount the utilities would spend to fund greenhouse gas reduction programs. SCE said the total after-tax earnings charge from the settlement will be $448 million.

“SCE and plant co-owner, SDG&E, have already returned more than $2 billion to customers under the 2014 settlement, which ensured that customers did not pay for the faulty steam generators, which prompted the closure of San Onofre, from the time this equipment failed,” SCE said.

SCE San Onofre CPUC — The San Onofre Nuclear Power Plant control room in 1968

Elizabeth Echols, director of California’s Office of Ratepayer Advocates, said: “This deal saves SCE and SDG&E customers hundreds of millions of dollars over the next several years. ORA and others worked hard to put together a strong case and succeeded. Now customers won’t end up unfairly paying for many of the costs associated with the [plant’s] premature failure.”

Other parties to the settlement include the Alliance for Nuclear Responsibility, the California Large Energy Consumers Association, California State University, Citizens Oversight, the Coalition of California Utility Employees, the Direct Access Customer Coalition, ratepayer Ruth Henricks, The Utility Reform Network and Women’s Energy Matters.

February 1, 2018

DC Circuit Rejects Appeal of Entergy Bandwidth Decision

By Tom Kleckner

The D.C. Circuit Court of Appeals on Tuesday refused to overturn FERC’s decision to require Entergy Arkansas (EAI) to make $11 million in retroactive payments to its affiliate companies.

The Arkansas Public Service Commission last month appealed FERC’s rejection of its request to exclude EAI from making the backdated 2005 “bandwidth” payments stemming from Entergy’s system operating agreement, which EAI exited in 2013 (EL01-88-013). (See Ark. Regulators Contest Entergy Bandwidth Payments.)

Entergy Arkansas Bandwidth Payments — | *Entergy*

The state regulator contended the agreement made no provision for assessing payments after withdrawal, which meant the utility had no continuing obligation to its sister companies.

A three-judge panel for the D.C. Circuit disagreed with the PSC’s argument, saying EAI’s withdrawal does not mean it “extinguished its obligation to make incurred bandwidth payments” (No. 16-1193).

The court said contract law principles “support FERC’s conclusion that a party’s accrued contractual obligations continue beyond its withdrawal from a contract.” It cited commercial code that provides that “all obligations which are still executory on both sides are discharged” upon a contract’s termination, but “any right based on prior … performance” — that is, any accrued obligation — “survives.”

The PSC “points to no case or authority suggesting otherwise,” the court said.

The judges also disagreed with FERC’s contention that it should refrain from deciding the case because it “lacks the finality and/or ripeness necessary for judicial review.” They said FERC’s earlier decision consummated the agency’s decision-making process and determined EAI’s obligations.

Delaying consideration of EAI’s liability “would not ‘permit better review of the issues,’” the court said, “because the issues on review largely revolve around contract interpretation uninfluenced by future events.”

The ruling was issued by Chief Judge Merrick Garland and Circuit Judges Sri Srinivasan and Patricia Millett, who heard oral arguments in December.

The Arkansas commission is evaluating the ruling and considering “the options we may have,” Executive Director John Bethel told RTO Insider. “We want to make sure the Arkansas ratepayers are fairly treated.”

Under the Entergy system agreement, which expired in 2016, low-cost operating companies made annual payments to the system’s highest-cost company. The “bandwidth” remedy was used to ensure that production costs for Entergy’s five utilities were no more than 11% above or below the system average.

February 1, 2018

CASPR Filing Draws Stakeholder Support, Protests

By Michael Kuser

Stakeholders have responded to ISO-NE’s filing of a proposed two-stage capacity auction with a flurry of comments to FERC — many of them opposing the measure.

The vetting process for the Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, and the late changes made by the RTO, left state regulators and stakeholders divided. Vermont, Connecticut and Rhode Island opposed the CASPR proposal filed with FERC, while Massachusetts, New Hampshire and Maine supported it. (See ISO-NE Effort to Accommodate States Leaves them Alienated.)

The proposal (ER18-619) grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.

Bay State Division

The controversy has even split officials within Massachusetts. In separate comments filed Jan. 29, the state’s attorney general urged the commission to reject or change the proposal, while the Department of Public Utilities “strongly” supported it.

Attorney General Maura Healey said in her filing that “the current incarnation of CASPR does not allow for any regular or reliable integration of sponsored policy resources” into the Forward Capacity Market.

Healey asked the commission to reject CASPR “because it will lead to unjust and unreasonable rates for New England consumers, who will pay twice for the same capacity,” and remand it with an order for remedial action to incorporate a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry into the FCM every year for a minimum of 200 MW of sponsored policy resources.

She also suggested the commission could remand the proposal with an order to reinstate the renewable technology resource (RTR) exemption to the minimum offer price rule (MOPR), which CASPR proposes to eliminate.

The DPU, on the other hand, argued that CASPR would “provide a competitive, market-based approach” to allowing policy-driven resource into the FCM and “prevent direct harm to Massachusetts ratepayers and the inefficient development of more generation resources than the region requires, while preserving competitive price formation and nondiscriminatory participation in New England’s FCM.”

Conditional Support

In its Jan. 29 filing, NESCOE said the RTO’s “commitment to monitor CASPR’s performance and to propose appropriate remedies is critical — and a condition of NESCOE’s support.” The group also pointed to the RTO’s pledge to work with stakeholders to “refine or replace” CASPR if it fails to achieve its intended purpose of accommodating state entry over time.

“ISO-NE must revise CASPR if it falls short of its intent to accommodate the participation of state-sponsored resources or if it proves inflexible to the execution of state laws, which are not static,” NESCOE said.

Calpine sided with the New England Power Generators Association in supporting the proposal, calling it “a considered and reasonable compromise to allow state-sponsored new resources into the Forward Capacity Market, while minimizing the impact on competitive market pricing.”

In guardedly supportive comments filed Jan. 19, NEPOOL noted that its Participants Committee failed in December to approve the CASPR proposal, with a 57.75% vote in favor (60% being required to represent substantial approval).

Despite that shortfall in institutional support, NEPOOL said its stakeholder process on CASPR “narrowed, and in many cases resolved, a number of complex and interrelated issues, and certainly broadened the understanding and perspectives of all interests in the region.”

NEPOOL predicted FERC would confront disparate opinions and urged the commission “to exercise caution in parsing through these concerns and their interrelationship with each other.”

Does the FCM Matter?

Consumer advocacy group Public Citizen questioned the RTO’s motives and the overall need for the FCM.

“By prematurely submitting this CASPR experimental rate design against the wishes of its stakeholders, it appears as though ISO-NE is more concerned with preserving its competitive markets from the encroachment of non-market capacity additions, regardless of whether extending a ‘market-based’ mechanism over policy-procured capacity will result in just and reasonable rates,” the group said.

Public Citizen argued that “the question should therefore not be how to force policy-deployed capacity into the … market, but whether the capacity market is needed at all. Because non-market factors are clearly adding adequate capacity for New England.”

In a joint filing, he American Wind Energy Association, Conservation Law Foundation, Natural Resources Defense Council, RENEW Northeast, Sierra Club and the Sustainable FERC Project urged the commission to either retain the current RTR exemption or direct the RTO to provide a sufficient similar, alternative mechanism that would enable state-mandated renewable energy resources to participate in the FCM and make the market account for the capacity contributions of these resources should CASPR fail to do so.

The groups encouraged the commission “to re-examine the logic of applying the MOPR to clean energy resources being driven by legitimate state policies, which we believe inappropriately encroaches on state authority while lowering market efficiency and imposing unjust and unreasonable costs on customers.”

January 31, 2018January 22, 2024

Traders Seek Clarity in FERC Enforcement Under New Regime

By Rich Heidorn Jr.

ARLINGTON, Va. — FERC’s enforcement policy is unlikely to shift significantly despite the arrival of four new commissioners, a panel of present and former FERC staffers said Monday. But the commission should consider some process changes and provide more clarity in defining violations, several speakers said.

“I think the fundamentals of enforcement don’t change with any administration,” Tim Helwick, special counsel in FERC’s Division of Analytics and Surveillance, told the EUCI Financial Transmission and Auction Revenue Rights conference. “I think priorities can change with different personalities — it’s not a question of politics, just different personalities.”

Helwick’s comments came at the end of a 90-minute discussion before an audience of about 40 traders, regulators, and others that noted the growth of FERC’s enforcement unit since the Western Energy Crisis in 2000-2001. Once limited to a handful of staffers, FERC’s Office of Enforcement (OE) now numbers more than 200, with greatly expanded power to impose penalties under the Energy Policy Act of 2005.

“I think it’s too early to tell what type of change we’re going to see, and I don’t necessarily anticipate that we are going to see significant change,” agreed attorney Terence Healey, a partner with Sidley Austin and the only one on the panel without a FERC résumé listing. “You’re dealing with an agency that’s 200-plus folks that were there before the current administration. … I wouldn’t expect the fundamentals to change.”

Enforcement Director Larry R. Parkinson was appointed in April 2015, after five years as director of OE’s Division of Investigations.

He noted the commission’s annual enforcement report, released in November, indicated FERC would continue to focus on the same priorities in 2018 as in 2017: fraud and market manipulation; serious violations of NERC reliability standards; anticompetitive conduct; and conduct that threatens market transparency. (See Investigations up Sharply in FY 2017, FERC Report Shows.)

“I would take them at face value on that,” he said. “Whether certain cases on the edge should be brought, I could see changes like that.”

De Novo Procedures

He said the commission might consider changing its processes due to the number of enforcement cases ending up in federal court and because its decision to make early public disclosures about investigations has not worked as intended.

A 2009 policy change gave the Director of Enforcement authority to issue a Notice of Alleged Violations (NAV) that includes the identities of investigation subjects and a description of their alleged misconduct once the subject has responded to staff’s preliminary findings but before it finalizes its findings and the commission issues an order.

Previously, the commission kept investigations and the identities of investigation subjects private until FERC initiated an enforcement action or issued an order approving a settlement. FERC said it hoped the transparency would warn other market participants to steer clear of questionable trades and prompt them to bring evidence to staff.

“Maybe it’s time to rethink that. … because it’s something that’s not really produced what the commission intended it to be, which was to flag [concerns] for the market,” Healey said.

Healey also noted the increasing number of subjects choosing de novo hearings in federal court rather than having an administrative law judge rule on the merits of FERC’s allegations.

“At least six separate district courts have said if you remove [a case] to federal court, you get a trial” with the ability to supplement the administrative record created by Enforcement, cross-examine witnesses, and seek discovery, Healey said.

FERC had sought much more limited court reviews. (See FERC Loses Again on ‘De Novo’ Review.)

Healy said FERC could consider streamlining its process because it is subject to a five-year statute of limitations.

“FERC took the position that they satisfied the five-year statute of limits upon initiating an order to show cause,” he said. “ … We had a decision in the Barclays case that found it is satisfied when you file in federal court, and because of that, one of the respondents had his case tossed out.” (See FERC Settlement Cuts Barclays Market Manipulation Fine.)

The panelists said they saw no indication the new commission would consider licensing power and gas traders as is required of securities traders.

Licensing would be opposed strongly by traders and is “not likely in this administration,” said Chloe Cromarty, compliance manager for Mercuria Energy Trading and a former FERC analyst. “But all it takes is one big case to be a catalyst,” she acknowledged.

‘Vague Standard’

Panel moderator Shaun Ledgerwood, a principal in The Brattle Group and a former FERC economist and attorney, said the commission still has not provided a clear definition of “market manipulation.” Ledgerwood recalled asking for a definition during his job interview at FERC in 2008 and only being told, “You know it when you see it.”

“I thought, ‘Man, that’s a pretty vague standard,’” said Ledgerwood, who specializes in the economic analysis of market manipulation claims, “and as time has gone on, what I’ve seen is that the commission has tried to … show examples of what manipulation is … misrepresentation, gaming, cross-product manipulation … The reality is there is no definition yet of what exactly is manipulation nor — perhaps more importantly — what exactly is legitimate.”

Healey agreed: “We’re still struggling to try to understand what … FERC is going to view as manipulation. As of yet, we don’t have a district court that has actually opined on some of the back and forth on what fraud means.”

The lack of clarity creates headaches for compliance officials, Cromarty said.

She said her company runs its trades through screens to identify transactions that may trigger an investigation — for example, comparing proposed virtual transactions against financial transmission rights (FTR) positions or flagging trades involving new products or a marked increase in trade volumes.

“As a major FTR [financial transmission rights] trader, at any given time, we may hold more than 200,000 paths. Expecting one trader to know another trader’s position is not practical,” she said.

“One trader may hold an FTR position where another trader wants to execute some virtual trades — and we may be flowing physical power across that path as well,” she explained. “We’re making the decision to prohibit one trader from transacting — in my opinion, legitimately — in order to avoid tripping the [FERC] screens because any revenue we make from transacting in that way is not significant enough to justify the potential regulatory risk that we’re facing. From my perspective, I think that’s having a negative impact on liquidity.”

Ledgerwood agreed. “You know if you get involved in the [investigative] process, it’s likely to be protracted. Not only is that expensive, it also takes a lot of psychic energy away from traders and the companies and their compliance personnel.”

Healey and others said they recommend traders put their plans in writing when they adopt a new strategy or engage in a particularly complex transaction. “It’s not a silver bullet, but it does provide a contemporaneous account for the intent of the trader at the time,” Healey said. “So long as it’s truthful and contains all the information — otherwise it’s problematic for obvious reasons.”

RTO Officials Discuss FTR Changes

In an earlier discussion Monday, ERCOT’s Carrie Bivens, MISO’s Blagoy Borissov, and PJM’s Brian Chmielewski talked about how their regions addressed revenue shortfalls in their FTR markets, while a CAISO official acknowledged “revenue adequacy continues to be a challenge” in California.

Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, said the problem is a “misalignment” between CAISO’s congestion revenue rights auction and its day-ahead market.

CAISO has said that ratepayers receive only 52 cents in auction revenues for every dollar the ISO pays out to FTR holders. (See Market Monitors Bring FTR Complaints to Congress.)

[Editor’s Note: RTO Insider Editor Rich Heidorn Jr. worked for the FERC Office of Enforcement between 2002 and 2010.]

January 31, 2018

Tax Breaks Spur Dominion Deleveraging

By Rory D. Sweeney

Dominion Energy CEO Thomas Farrell expressed confidence Monday that his company’s lobbying in Connecticut and Virginia are on track to benefit the company.

Executives speaking during the company’s fourth-quarter and year-end earnings call also outlined strategies to take advantage of the recently enacted federal tax breaks and spoke about the political uncertainty surrounding the company’s bid to take over SCANA, the South Carolina utility beleaguered by a failed nuclear project.

The company announced it performed right in the middle of its guidance for 2017, reporting operating earnings of $3.60/share. Mild weather throughout the year reduced earnings by $0.10/share, though weather-normalized electric sales for the year increased 1.7% over 2016, led by growth and sales to data centers and residential customers.

Unadjusted earnings were $4.93/share for the year, thanks primarily to tax reforms that created a $988 million gain from adjustments to a deferred tax liability. Revenues increased 4% for the year to $3.21 billion but fell short of a consensus forecast of $3.47 billion.

Regulatory Progress and a Mystery Bill

“We have worked with the regulatory agencies, including the sharing of confidential financial information, to convey the actual cost of operating two dissimilar units in a high regional labor market,” Farrell told analysts, referring to this month’s preliminary report from Connecticut state agencies that determined the profitability of Dominion’s Millstone nuclear facility in Waterford, Conn., can’t be confirmed without additional financial disclosures from the company.

Dominion Energy — Dominion expects Connecticut state agencies to acknowledge the financial instability of its Millstone nuclear generation station. | *NRC*

The report, jointly developed by the state Department of Energy and Environmental Protection and Public Utilities Regulatory Authority, recommends a statewide procurement of carbon-free electricity from new and existing sources. Without additional information proving Millstone’s instability, its bids would be analyzed on price alone. With that information, the bids could be evaluated on broader criteria. A final draft of the report is expected Feb. 1.

“We are looking forward to the opportunity to compete with other non-emitting generating resources in a state-sponsored solicitation for zero carbon electricity,” Farrell said.

Paul Koonce, who heads Dominion’s generation arm, sounded eager to shut down any speculation about how Millstone might be bid into the solicitation. After misinterpreting a question about whether the plant would be bid into the process as an inquiry into the amount of its bid, Koonce declined to specify, calling the information “obviously competitively sensitive.” He said the state’s final report will likely lead to a request for proposals issued around May “and then we will submit our bid as any others.”

Farrell also addressed the potential benefits of a bill advancing through the Virginia legislature but offered scarce details.

“Virginia moves legislation through in a very rapid pace normally, and I don’t think this will be an exception,” he said. “We think there are some very good things in it. There are some things that we will have to accommodate ourselves to, but overall we think it’s a constructive piece of legislation for our state and our customers.”

Farrell said it was “premature” to speak about it in any more detail because “there is still lots of work to be done on it,” but he assured analysts that “we’ll be in a position to talk about it, I think, more thoroughly on the next call” in three months.

Dominion’s executives said it’s hard to assess the impact of the federal tax cuts because the company operates in seven states. The company is assuming that the benefits will be passed through to customers for all of its state-regulated entities but acknowledged the improved profitability for all non-regulated and long-term-contracted businesses. However, the changes create “strong credit headwinds” for accrual-basis taxpayers like Dominion, and some of the benefit will be offset by delays in Dominion’s Cove Point LNG plant becoming operational, said Mark McGettrick, Dominion’s chief financial officer. He estimated the cuts will increase the company’s 2018 earnings by between $0.10/share and $0.15/share.

Tax Windfall

McGettrick confirmed that the federal tax breaks have allowed Dominion to begin plans to deleverage the holding company and clear away $800 million in debt. The cuts offset the delayed start at Cove Point, so the company could still issue $500 million in new shares earlier this month and reduce its capital expenditure budget by $1 billion while remaining committed to its current credit ratings, he said. He announced plans to increase the company’s credit facilities to $6 billion, which is in addition to a $500 million credit line being put together for its Dominion Energy Midstream Partners subsidiary in order to replace its existing credit line with the parent company.

“We’re committed to the ratings that we have. We will take the steps necessary to support that, and we took advantage of taxes to get a jump start,” he said.

While the credit expansion will increase liquidity, McGettrick assured the new shares were not issued to help finance the proposed SCANA takeover, which the company announced Jan. 3. The company will maintain a 6% to 8% growth rate through 2020, he said, and the SCANA deal could bump it above 8%.

“So with or without SCANA, we’re in terrific position with one of the best growth rates we believe in the industry and one of the highest dividend growth rates as well, but certainly SCANA would be a positive result for us,” he said.

Farrell said he expects SCANA’s shareholders to approve the deal in May and shrugged off what appeared to be a hostile hearing with South Carolina legislators earlier this month.

“We are optimistic that our proposal will be viewed favorably by lawmakers and regulators, and we can complete the transaction later this year,” he said.

Despite delays, executives were also upbeat about developments at Cove Point in Calvert County, Md. Construction is complete at the natural gas liquefaction plant, and the process to bring the cooling infrastructure online is underway. The plant will be in service by early March, Farrell said.

The company is also completing work on the $1.3-billion, 1,588-MW Greensville County Combined Cycle Power Station. The plant was 73% complete at the start of the year, with all major equipment in place, including the primary natural gas line. Metering and regulation controls are awaiting final approval, and the plant is expected to begin operating near the end of the year.

January 31, 2018

Solar Developer Contests Michigan PURPA Freeze

By Amanda Durish Cook

A solar developer is attempting to block a Michigan utility giant’s effort to halt its energy purchases under the Public Utilities Regulatory Policy Act (PURPA) for the next 10 years.

The conflict pits Cypress Creek Renewables against Consumers Energy, which supplies electricity to more than half of Michigan.

Consumers Energy in December asked the Michigan Public Service Commission (PSC) for permission to decline purchasing capacity from PURPA-eligible facilities, contending that it will not need any new generation over the next decade (U-18491). The company also requested that the PSC reset the value of Consumers’ avoided capacity cost to match MISO’s Planning Resource Auction price for all new PURPA-qualifying facilities’ offers to sell capacity. PURPA requires utilities such as Consumers Energy to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation.

In its filing, Consumers pointed to a 2017 case in which the Michigan commission ruled that the PURPA purchase obligation does not exist “if no additional capacity need is forecasted.” The company included a 10-year capacity proposition with its application.

But Cypress Creek this month filed in opposition to the plan, arguing that Consumers did not satisfy the grounds for a stay of PURPA obligations because the company could not prove it would be damaged in the absence of the waiver. The renewables developer also said a PURPA stay for Consumers would harm the public interest by hindering small solar development. Under PURPA’s implementation in Michigan, projects 2 MW and smaller are guaranteed a 20-year, fixed-price contract.

Cypress Creek’s complaint also contends that Consumers has itself admitted that it will need an additional 625 MW of renewable energy capacity to comply with Michigan’s 15% renewable portfolio standard.

PURPA michigan solar Consumers Energy Cypress Creek — Consumers Energy Campbell plant | *Michigan Building Trades Council*

Cypress Creek is joined in its arguments by the Environmental Law and Policy Center, which objected that Consumers’ 10-year capacity assumption “rests on faulty assumptions ― including an inadequate analysis of coal-plant retirements.” The environmental non-profit said Consumers failed to conduct a cost-benefit analysis on retirement of existing coal units, simply assuming that two units apiece at its Karn and J.H. Campbell plants will stay online through 2030. Consumers retired seven of its oldest coal plants in 2016, representing about 30% of its generating capacity.

$3 Billion, 700 MW

Cypress Creek said it has more at stake than Consumers in the debate over PURPA.

“The harm to Cypress Creek and other interested parties from granting a stay exceeds any harm to Consumers if a stay is not granted,” Cypress Creek said. The company said it is ready to invest $3 billion in low-cost, solar energy in Michigan through its affiliates, which already have approximately 700 MW of solar capacity under development in Consumers’ service area.

“These projects will be out on indefinite hold if Consumers’ request for a stay is granted,” the company said.

The company also alleged that Consumers’ timing of its application was opportunistic because the utility didn’t file for the waiver until after the Michigan PSC had set new avoided costs to file its application.

The PSC in November approved Consumers’ avoided cost rate at $117,203/megawatt year or $140,505/MISO zonal resource credit year (U-18090) but put the ruling on hold on Dec. 20, anticipating petitions for rehearing. A day later, Consumers filed its request for a stay.

“Consumers waited until after the Commission set new avoided cost rates to now claim that it does not have a capacity need,” Cypress Creek said.

Consumers maintains that PURPA will require it to purchase an additional 300 MW per year from qualifying facilities, burdening its customers “with up to $519 million of added expense over the next 20 years for a commodity that is unnecessary to serve their demand.”

Cypress Creek has found itself in a similar row over challenges to PURPA rates in Montana. The company has filed suit in both state and federal courts over the Montana PSC’s 2016 decision to first suspend, then slash PURPA rates and contract lengths offered to small solar producers. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)

January 31, 2018

IPPNY Unveils New Look, 2018 Priorities

By Michael Kuser

ALBANY, N.Y. — The Independent Power Producers of New York (IPPNY) rang in the new year Monday with a barbecue, a list of priorities, and a new logo.

Packed House for IPPNY’s annual Open House | © *RTO Insider*

“Topping the list regarding New York’s wholesale electricity market is the issue of pricing carbon,” said IPPNY CEO Gavin Donohue.

Donohue said IPPNY would work closely with the carbon pricing task force set up by NYISO and the state’s Public Service Commission (PSC) “[to monitor] the process for fair and open competition in the wholesale electricity market for all solutions, especially generation, transmission, and energy storage — and the viability of existing investments operating in the competitive market.”

IPPNY has sai d it “strongly supports” a carbon pricing approach that would add a carbon value to a resource’s commitment and dispatch costs based on its emission rate, with the price-per-ton set by the PSC.

IPPNY NYISO 2018 NYSERDA — Cusick | © *RTO Insider*

A number of elected state officials attended the Jan. 29 reception, including Sen. Joseph A. Griffo, (R-Rome), chairman of the Senate Energy and Telecommunications Committee, and Assemblyman Michael Cusick (D-Staten Island), chairman of the Committee on Energy.

PSC Commissioner Diane Burman also attended the event, which took place just hours after Gov. Andrew Cuomo released the state’s master plan for developing offshore wind. (See NY Offshore Wind Plan Faces Tx Ch a llenge.)

Entering his fourth year as chairman of his committee, Griffo said he looked forward to working with IPPNY on free market issues — and the state’s master plan for offshore wind could “conflict with” the philosophy of free enterprise. He questioned the wisdom of the proposal to put a state agency — the New York State Energy Research and Development Authority (NYSERDA) — in charge of contracting for the energy output of offshore wind farms.

IPPNY 2018 NYISO — Griffo | © *RTO Insider*

Griffo also said it was unlikely that he or IPPNY members would accept any form of utility-owned generation, which was one of seven market structure proposals in NYSERDA’s comments filed with the commission on Monday.

Cusick said he had “a good working relationship” with Griffo on several non-energy issues and looked forward to working together on energy.

“I just hope I’m not being set up here,” Cusick said, “but that’s just the instinctive reaction of a kid from Staten Island.”

Donohue said IPPNY was established in 1986 and last year he and other board members pondered “ways to breathe fresh life into the organization.”

The new logo was a product of that effort.

“Now at least we don’t look like a waste management company,” he said.

January 29, 2018

NY Offshore Wind Plan Faces Tx Challenge

By Michael Kuser

A new plan released by the New York State Energy Research and Development Authority on Monday details how the state plans to develop 2,400 MW of offshore wind by 2030.

But a separate policy paper by the same agency outlines the challenges in meeting that goal — including the limited amount of transmission available to interconnect offshore wind during the program’s initial solicitations for 800 MW of capacity over the next couple years.

NYSERDA NYISO offshore wind — Block Island Wind Project | *Deepwater Wind*

The state’s master plan projects that the full deployment of offshore turbines by 2030 would reduce greenhouse gas emissions by more than 5 million short tons, or approximately one-third the expected reductions from new renewable energy projects developed to meet the 50% renewable electricity target under the state’s Clean Energy Standard. (See New York Seeks to Lead US in Offshore Wind.)

“While the federal government continues to turn its back on protecting natural resources and plots to open up our coastline to drilling, New York is doubling down on our commitment to renewable energy and the industries of tomorrow,” Gov. Andrew Cuomo said.

Lisa Dix, New York senior representative for the Sierra Club, said the master plan “shows that a commitment to a steady stream of projects over the next decade” will create thousands of jobs while increasing the state’s economic.

“But the state must act swiftly this year to issue a procurement and establish an enforceable long-term program, with a guarantee projects are built every year, the governor’s targets are met and the climate, economic, manufacturing and jobs benefits are realized,” she said.

In a Jan. 29 filing with the Public Service Commission, NYSERDA detailed how the wind energy areas available to compete for offshore wind procurements in 2018 and 2019 “are limited, dispersed and not readily expandable.”

The agency said that an expandable “backbone” transmission system would offer the benefit of economies of scale and reduced barriers to entry, but it could also lead to overbuilding and stranded asset costs. A transmission system custom-built for a single offshore facility, the “direct radial” model, costs more and is limited in scope.

The real limit, however, is the industry’s nascent stage of growth. The federal government has so far leased only one area off New York City, the April 2017 lease to Statoil, which is capable of hosting approximately 1,000 MW. However, the policy paper said that wind projects off Rhode Island, Massachusetts and New Jersey could conceivably interconnect directly to New York or interconnect within an adjacent control area with energy delivered to NYISO, which would make them eligible for procurement under the Clean Energy Standard.

“Offshore wind developers are ready to help New York meet the governor’s goals, and are particularly interested in when and how they can compete for contracts and invest in New York,” Anne Reynolds, director of the Alliance for Clean Energy New York, said in a statement. “The Offshore Wind Policy Options Paper lays out these procurement options. Nailing down these procurement details needs to be New York’s next step.”

Market Approaches

NYSERDA assumes that offshore wind deployments will be funded through a purchase obligation placed on load-serving entities and that procurement will be conducted through separate offshore wind solicitations, using a similar competitive process to that used for large-scale renewables under the state’s Renewable Energy Standard Tier 1 procurements.

The agency offered several market-based approaches to procurement, including fixed renewable energy credits, bundled power purchase agreements, utility-owned generation and split PPAs. It also floated three varieties of offshore wind RECs (ORECs): market, index and forward.

For procurements during the first phase of the offshore wind program, NYSERDA expects ORECs to be more expensive than RECs sourced from other Tier 1 projects because of the higher capital costs for offshore. And while the fixed REC process is well-established, the price premium for offshore RECs could leave the agency financially exposed because it would act as the central procuring agency for the certificates.

“To the extent that this premium would not be addressed through co-incentives, NYSERDA’s blended REC price would increase — likely significantly — compared to its REC resale price without offshore wind,” NYSERDA said. As a result, the agency might not be able to recover its costs through the sale of RECs and resort to the utility “backstop” funding obligation of the CES. The risk would be exacerbated by a fall in power prices.

How LSEs Could Pay

NYSERDA also said the PSC could employ an allocation mechanism that set LSE compliance obligation levels according to actual production from offshore wind projects. Like New York’s zero-emission credits, these ORECs would be non-tradable and allocated to LSEs based on load.

The NYSERDA paper concluded that “under the allocation structure, the design of the dedicated offshore wind obligation could be set to achieve a much greater match between REC supply and target. Perfect alignment between REC supply and target could be achieved by setting the target for each period upon conclusion of the period to match exactly the available offshore wind REC volume.”

While that approach would address NYSERDA’s exposure to REC price differentials, it would foreclose the possibility of developing spot market price signals for ORECs, the agency acknowledged. Still, it did not consider that a big drawback given that offshore projects are not likely to respond to market signals for a long time because of their risk profiles.

NYSERDA will host two public webinars Feb. 13 to provide an overview of the Offshore Wind Master Plan and the next steps that New York will take to develop offshore wind.