Page 1434 – RTO Insider

February 25, 2016

Zibelman: Guaranteed-Savings Rules Meant to Enable Markets

By William Opalka

New York Public Service Commission Chairwoman Audrey Zibelman said that consumer protections approved by regulators Tuesday are meant to combat deceptive practices and boost consumer confidence at a time when more complex energy products are entering the market.

“We found that consumers were paying higher prices by buying from a retailer than they would if they were buying from a utility,” she said in a conference call with media Wednesday.

The PSC held the unusual conference call a day after it approved new rules that drew fire from a national trade group for electric supply retailers. The regulations guarantee savings for retail and small commercial customers who switch to an alternative electric supplier. The rules also provide for tougher enforcement measures against those who prey on vulnerable or uniformed customers (15-M-0127, et al.).

In response, the Retail Energy Supply Association said the rules will only drive energy supply companies out of New York.

Retail Choice ‘Eliminated’?

“The New York State Public Service Commission took the unprecedented action of effectively eliminating retail choice for residential and small commercial customers in New York by substituting the commission’s judgment for that of consumers in determining what energy products offer value,” the group said in a statement.

“Under the commission’s order, retail suppliers would be forced to guarantee savings against a future utility price that, as a monthly variable price, is unknown,” RESA added.

Zibelman said the rules, which are meant to prevent overcharging, are part of the PSC’s plan to provide clear rules for companies and consumers under the Reforming the Energy Vision initiative.

“As we move forward with REV, it’s very important to us that the residential and mass market[s] are able to participate and acquire additional energy services … and in order to do that, we need a great deal of market confidence,” she said.

The commission said “retail energy markets are not providing sufficient competition or innovation to properly serve mass market consumers,” in contrast with markets for large commercial and industrial customers, which it said “are providing substantial benefits … including a wide range of energy-related value-added services that assist customers in managing their energy usage and bills.”

A year-long proceeding under the REV is determining what constitutes a value-added service and how it should be priced, Zibelman said.

The guaranteed-savings rule does not apply to customers opting to buy “green” power. Energy service companies (ESCOs) that offer premium-priced renewable energy will be required to obtain at least 30% from sources eligible under the commission’s Environmental Disclosure Labeling Program, including biomass, biogas, hydropower, solar and wind.

Abuses Cited

The commission is conducting an audit of the 200 ESCOs that operate in New York.

“We have zero tolerance for these unscrupulous companies, whose business model is to prey on ratepayers with promises of lower energy costs only to deliver skyrocketing bills,” Gov. Andrew Cuomo said in a statement. “These actions will root out these bad actors and protect New Yorkers from these unfair and dishonest tactics.”

The commission may impose a “one strike and you’re out” rule for behavior it decides is egregious. It also created a “do not knock” rule for door-to-door solicitations, similar to a “do not call” registry for telemarketers. Violators could be prohibited from operating in the state.

More than 20% of New York’s residential and small commercial customers currently receive energy from ESCOs. There are about 7 million residential electric customers and roughly 4.3 million residential natural gas customers, according to the PSC.

The regulators cited several examples of unacceptable conduct, including four companies in the Hudson Valley that charged more than double Central Hudson Gas & Electric’s price for electricity; a New York City company that charged more than triple Consolidated Edison’s rate for electricity; several ESCOs in upstate New York that charged more than double National Grid’s electric rate; and a company in the Finger Lakes region whose variable rate plan for electricity was eight times what Rochester Gas & Electric charged.

The commission also cited examples of companies falsely representing themselves as local utilities to trick customers into signing inflated contracts. At the Tuesday meeting, commissioners were particularly disturbed by reports of deceptive practices used against customers for whom English is a second language.

February 25, 2016

New Lifeline for FitzPatrick Nuclear Plant

By William Opalka

NEW YORK — In a last-ditch effort the save the James A. FitzPatrick nuclear plant, New York regulators are proposing financial incentives that could be available to the plant’s owners by July.

The New York Public Service Commission on Tuesday proposed to expedite subsidies to keep the plant operating while a more permanent incentive is crafted on the normal regulatory schedule (15-E-0302). A public comment period will last until May 2.

However, Entergy, FitzPatrick’s owner, again said the state’s plans were too uncertain and too late to save the plant on Lake Ontario. Entergy intends to close the plant on Jan. 27, 2017, when its current fueling cycle ends.

New York’s attempts to prop up its nuclear fleet exclude Entergy’s Indian Point nuclear plant, which Gov. Andrew Cuomo wants to close because of its proximity to New York City.

“If the state is focused on reducing CO₂ emissions, the Clean Energy Standard should apply to Indian Point, which is an essential generation resource critical to the state’s goal of reducing CO₂ emissions,” spokeswoman Tammy Holden told Syracuse.com.

Entergy Vice President of External Affairs Mike Twomey said in a statement that no definitive proposal from New York for FitzPatrick has been received since negotiations broke down last year.

“While we share the NYPSC’s concerns about the loss of nuclear generation, the financial implications of its efforts are too uncertain and this proposal comes too late to save FitzPatrick,” he said.

“Entergy met with New York state officials from the governor’s office and with the PSC repeatedly over the last few years to discuss how the current New York market structure disadvantages nuclear generation, how nuclear power’s carbon-free attributes could be recognized in the market and the financial challenges faced by the FitzPatrick plant. Unfortunately, these discussions resulted in no meaningful progress or policy changes by New York state.”

The PSC is already working to create a new tier of zero-emission credits (ZECs) that would be available to upstate nuclear generators next year. The proposed Clean Energy Standard is meant to help put New York on a path to 50% renewable generation by 2030. Nuclear is seen as a zero-carbon bridge to that plan. (See New York Would Require Nuclear Power Mandate, Subsidy.)

The process gained urgency after NYISO released an assessment finding that New York will be short of generation in 2019 with the closing of FitzPatrick and other plants. (See Fitzpatrick Closure Could Leave NY Generation Short.)

The PSC’s move to expedite subsidies to FitzPatrick “gives the commission the opportunity to act very decisively,” Chairwoman Audrey Zibelman said Tuesday. “We do not want to see a plant retire from [the lack] of a short-term solution.”

The expedited subsidy schedule would enable Entergy to refuel FitzPatrick if the company were to change its mind and continue operating the plant.

The PSC plan is modeled after existing renewable energy procurement practices used by the New York State Energy Research and Development Authority. NYSERDA purchases credits using money made available to it by the commission, including system benefits charges. The ZEC funds would also include other money collected from ratepayers.

As in renewable energy production, each ZEC would be paid for 1 MWh of energy produced. ZEC payments would be no more than the amount necessary above existing revenue streams to cover the ongoing costs of the facility for operations and maintenance, capital expenditures, taxes and other expenses. Sunk costs would be excluded.

Raj Addepalli, the PSC’s managing director of utility rates and service, offered a rough estimate of $15/MWh, using as a benchmark the “very complicated” formula just approved by the commission to keep the R.E. Ginna nuclear plant operating. (See NYPSC OKs Ginna Deal.)

That figure was derived from the payments to Ginna under its reliability support services agreement that will fluctuate from $49 to $52/MWh, minus the recent yearly average wholesale energy price of $35/MWh.

Ginna would be eligible to participate in any ZEC program after its RSSA expires on March 31, 2017.

February 25, 2016

Cayuga Coal Plant in Jeopardy

By William Opalka

NEW YORK — The future of one of New York’s last coal-fired generators is in jeopardy following state regulators’ rejection of a plan to repower it to natural gas and their approval of a transmission alternative (12-E-0577), (13-T-0235).

The 312-MW Cayuga generating plant will soon be one of two remaining coal generators in the state, plants that Gov. Andrew Cuomo recently vowed to close or have converted to natural gas by 2020.

But a ratepayer-funded repowering is off the table, the New York Public Service Commission ruled Tuesday. Chairwoman Audrey Zibelman said it would be “unfair” for ratepayers to be saddled with $102 million in additional costs to pay for the repowering. “It would not be in the public interest for New York State Electric and Gas ratepayers to be paying for that,” she said at the meeting. (See Cayuga Power Plant Repowering Opposed.)

She later told RTO Insider that plant owners “are free to repower the plant on their own nickel.”

In a separate order, the PSC signed off on Upstate New York Power Producers’ (UNYPP) sale of Cayuga and the Somerset coal plant outside Buffalo to Riesling Power, a unit of the Blackstone Group (15-E-0580). FERC approved the transaction in January. (See FERC Approves Sale of Doomed New York Coal Plants.)

Over UNYPP’s opposition, the commission also approved a request by distribution utilities NYSEG and Niagara Mohawk to build a two-phase, 14.5-mile project connecting two substations to address reliability concerns in western New York. The $23.3 million Auburn project would use existing rights of ways in Cayuga and Onondaga counties.

Phase 1 was filed as a proposal to build the 115-kV project, with Phase 2 proposed as a supplemental project by the companies to increase its capacity.

A recommended decision in November by an administrative law judge said, “it is uncontroverted that Phase 1 of the project should be constructed as soon as possible to remedy an immediate need to avoid reliability violations and service disruptions, if a major contingent event occurs.”

UNYPP objected to Phase 2, saying that part of the project is not needed if the plant continues to operate. According to the judge’s record decision, both phases are necessary even if the Cayuga units continue to sell into the NYISO market.

The plant is operating under a reliability support services agreement with NYSEG that runs through June 2017 (12-E-0400).

February 24, 2016

Supreme Court Offers Little Support to CPV, Md.

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — Lawyers for Maryland and Competitive Power Ventures got little support from Supreme Court justices during oral arguments in their federal-state jurisdiction case Wednesday.

The justices also interrogated Paul Clement, attorney for Talen Energy Marketing, which challenged Maryland’s deal for CPV’s combined cycle plant now under construction in Charles County as an improper subsidy.

But none gave any indication that they were inclined to reverse in their entirety lower court rulings voiding the contract. Rather, several justices seemed to be wrestling with whether to reject the contract based on “field preemption” — that it was an intrusion into exclusive federal jurisdiction — or a narrower “conflict” ruling — that it undermined FERC policy because its long-term pricing structure includes incentives different from those provided by PJM’s capacity auction. (Hughes v. Talen Energy Marketing (14-614), CPV Maryland v. Talen Energy Marketing (14-623))

In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.

Under the “contract for differences,” CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.

The contract was challenged by Talen Energy’s predecessor, PPL, and other generators.

The U.S. District Court of Maryland ruled with PPL and other plaintiffs in saying the contract violated FERC jurisdiction over the wholesale electric market, a ruling upheld by the 4th Circuit Court of Appeals. The Supreme Court declined to hear two related cases in New Jersey decided by the 3rd Circuit.

Opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.

Chief Justice John Roberts picked up on this argument shortly after Maryland attorney Scott H. Strauss began speaking. “If it doesn’t suppress prices, why did Maryland do it?” he asked bluntly.

Strauss responded that the state saw a need for more generation than the PJM capacity market was providing. He and CPV attorney Clifton S. Elgarten argued that FERC had addressed price-suppression concerns with the minimum offer price rule (MOPR), which sets a floor on bids by new entrants.

Clement said FERC was siding with Talen in the dispute because “MOPR is not some kind of cure-all that is designed to ward off any price-suppressive bid. … It is a coarse screen to deal with the most egregious cost-reducing bids. It also depends on an estimate of cost.

“And here’s why it doesn’t really work for a bid like this,” Clement continued. “One of the most important costs is your cost of capital. Because [CPV is] getting a 20-year guarantee and no one else is … it destroys the ability to do an apples-to-apples comparison. And then the one thing we know for certain here is that this project ended up displacing a project that actually could be built based on the three-year forward price and without a 20-year contract.”

Strauss insisted Maryland ratepayers would not be providing a subsidy. “Maryland concluded that this was going to be a better deal for ratepayers,” he said. At a time when the generation mix is changing, he said, “the last thing the court should do is to limit state options.”

Boston Pacific, a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told a FERC technical conference later: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”

FERC’s Position

After the 4th Circuit upheld the lower court’s ruling, CPV filed the contract with FERC, asking the commission to find it just and reasonable. The company had hoped this would nullify the courts’ findings, but FERC said it wouldn’t review a contract that had been ruled invalid.

Strauss and Elgarten, however, maintained that the commission would have found it just and reasonable.

“I don’t understand your position,” Justice Samuel Alito told Elgarten sharply. “You’re arguing that FERC does not think this adversely affects the [capacity] auction? Why has FERC filed a brief arguing the opposite? You’re arguing as if they’re not even here.”

Alito was referring to Ann O’Connell, an assistant to the Solicitor General who argued for FERC. O’Connell made clear the commission’s position in her opening argument.

“In the government’s view, the Maryland generator order is preempted because by requiring the state-selected generator to bid into and clear the PJM capacity auction in order to receive the guaranteed payments provided in the contract, the Maryland program directly intrudes on the federal auction, and it also interferes with the free-market mechanism that FERC has approved for setting capacity prices in that auction,” she said.

“I understood why they were making the MOPR argument at the early stages of this litigation before FERC filed the brief,” Clement said. “But I am a little mystified why, at this late stage of the game, after FERC filed three briefs saying that the MOPR is not sufficient to eliminate price-suppressive bids, that they’re still saying ‘We win because FERC’s on our side.’”

Skeptical Justices

The justices questioned whether the contract would have been legal had it not been tied to the auction and simply subsidized by Maryland.

“It does seem to me important what the kind of state action is,” Justice Elena Kagan told Clement. “If the state had just said ‘we need another power plant’ and had delivered a load of money to CPV and said ‘go build a power plant,’ you’re not saying that that would be preempted, are you?”

“It would depend,” Clement responded. “The way you just described it, [it is] not preempted.”

Roberts posed the same question to O’Connell.

“If the state just paid to build a power plant, that’s not directly targeting what’s happening in the PJM auction,” she said. “Sure, it’s adding supply to the market. But as long as the state is staying within its sphere under the Federal Power Act, that’s fine.”

Some of the justices confessed that they were confused by the details of the PJM capacity auction, something that Elgarten pointed out in his arguments.

“All of the conflict preemption issues should be addressed to FERC,” Elgarten said. “They are not really for this court — which is obviously having trouble conceptualizing how this all works — to resolve.”

This remark did not seem to faze the justices, however. “Truer words were never spoken than ‘I am not quite on top of how this thing works,’” Justice Stephen Breyer said later.

“I’m a little bit like Justice Breyer on this,” Justice Sonia Sotomayor said. “I’m not quite sure how everything is working.”

February 23, 2016

FERC Likely to Eliminate Must-Offer Rule for West

By Robert Mullin

FERC last week proposed eliminating a market transparency rule imposed on the Western Electricity Coordinating Council (WECC) region during the height of the California energy crisis of 2000-2001, citing a decade of advances designed to protect state’s organized electricity markets from price manipulation.

The commission on Thursday ordered a Section 206 investigation into whether its West-wide must-offer obligation is still necessary in light of a progression of technical and structural developments that have improved the resiliency of California markets. But the wording of its order made clear the commission intends to end the 15-year-old policy (EL16-27).

“Due to the passage of time and significant changes to California’s wholesale markets, the must-offer obligation established for the WECC in 2001 appears to have outlived its usefulness,” FERC said.

FERC implemented the must-offer rule in June 2001 in response to what it called “serious market dysfunction” in California — the concerted effort by some of the region’s generators to withhold power supplies to drive up prices in the now-defunct California Power Exchange.

The rule required most generators serving California to offer all capacity not already committed under bilateral agreements into the state’s real-time market. The rule also required public and non-public utilities to post a daily log of available capacity on their websites, as well as to a site hosted by the Western Systems Power Pool (WSPP).

The must-offer and posting obligations were originally set to expire in September 2002, but a second commission order extended both requirements until “long-term market-based solutions” could be fully implemented in California.

In March 2015, WSPP sent a letter to then-Chairman Cheryl LaFleur, asking the commission to clarify whether the obligation was actually still in effect, given that the event precipitating the rule — the Western energy crisis — no longer existed.

In last week’s order, FERC said the rule no longer was necessary and that the posting requirement “may have become burdensome.”

The commission said California has met the standard for long-term solutions, spelling out “significant changes” implemented in the CAISO balancing area since the must-offer requirement was instituted. Those changes include LMP-based day-ahead and real-time energy markets, ancillary services markets, a day-ahead residual unit commitment process and local market power mitigation measures.

The order also notes that California’s ambitious renewable portfolio standard (RPS) and resource adequacy program have reduced the state’s reliance on spot markets, ameliorating a flaw in the previous market that left the state’s load-serving entities exposed to short-term price spikes. FERC credited the RPS and CAISO’s improved generation interconnection process for producing “robust” reserve margins, and said that a recent build-out in WECC has been adequate for all western subregions to meet reserve margin targets for the 2014-2024 period.

“[G]iven the significant improvements in CAISO’s market design and infrastructure outlook in the West, we believe that it may be appropriate at this time to eliminate the West-wide must-offer requirement and the related requirement to post available capacity on the WSPP website or on the utilities’ own websites,” FERC wrote.

A CAISO spokesperson said Friday the grid operator was still reviewing the FERC order. The California Public Utilities Commission did not respond to a request for comment. Broad must-offer requirements have already been eliminated from the CAISO tariff with the adoption of longer-term resource adequacy provisions.

One Pacific Northwest utility analyst familiar with regional compliance issues said the rule’s termination should have little effect on operations at her company.

“It won’t change anything except a requirement to post a number on OASIS every day that nobody looks at,” said the analyst. “So it’s good news.”

FERC asked interested parties to submit comments on the termination of the must-offer requirement within 30 days. The commission expects to render a decision on the issue by June 18.

February 23, 2016

FERC: PSEG Can Recover Costs if Artificial Island Project is Canceled

By Suzanne Herel

FERC on Thursday approved an incentive filing by PJM that will allow Public Service Electric and Gas to recoup all of its costs if the Artificial Island reliability project is canceled due to reasons beyond the company’s control.

“PSE&G contends that the permitting, construction, coordination and procurement risks greatly increase the chance of delay and cost increases, thereby increasing the chance that the A.I. project could be canceled after PSE&G has invested time and money,” the order said (ER16-619).

The project’s crossing of the Delaware River alone will necessitate nearly 50 federal, state and local permits, it said.

PSE&G called the proposed work “unique,” requiring it to design and order materials and equipment that could not be used readily if the project is canceled.

ferc — Salem Nuclear Generating Station on Artificial Island (Source: Wikimedia)

The project consists of building a 230-kV transmission line from the New Jersey nuclear complex housing the Hope Creek and Salem reactors to Delaware to resolve stability issues. PSE&G competed to win the full project, but the bulk of the work was awarded to LS Power, with PSE&G and Pepco Holdings Inc. assigned the necessary connection facilities. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)

PSE&G’s portion of the project involves expanding the Salem substation and building a static VAR compensator (SVC) upgrade at New Freedom, estimated to cost $31 million to $38 million at the time PJM recommended the project.

The FERC order quotes a $126 million estimate from PSE&G.

American Municipal Power asked FERC to require PSE&G to submit a filing detailing any costs sought to be recovered in customers’ rates in the event the A.I. project is scuttled. FERC included the requirement in its ruling that PSE&G be able to fully recover “prudently incurred” expenses.

The Delaware Public Service Commission submitted comments saying PSE&G had not adequately justified the need for an abandonment incentive.

Separately, Delaware and Maryland regulators and consumer advocates have opposed the allocation of the project’s cost, nearly all of which has been designated to customers on the Delmarva Peninsula. FERC accepted but suspended PJM’s Tariff changes involving the project’s cost assignment pending additional review (EL15-95).

At a Jan. 12 technical conference ordered by the commission, stakeholders debated cost allocation based on the solution-based distribution factor (DFAX) method. (See DFAX: ‘Poison Pill or ‘Best Method’ of Cost Allocation?)

FERC last week set a March 9 deadline for filing post-technical conference comments.

February 23, 2016

PJM MRC and Members Committee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:20)

Members will be asked to endorse the following manual change:

Manual 18: Capacity Market. Changes conform with FERC’s Dec. 22 order accepting for filing revisions to the Reliability Assurance Agreement (ER16-333). They address the circumstances under which fixed resource requirement (FRR) entities aren’t mandated to meet the percentage of internal resource requirement, how such entities may terminate their five-year minimum commitment period and alternative election dates for new FRR entities. (See IMEA Reaps Limited Relief from Capacity Rule Change.)

3. End-of-Life Transmission Projects (9:20-9:35)

Ed Tatum of American Municipal Power will present a problem statement and issue charge that would develop uniform PJM-wide criteria and guidelines for assessing end-of-life transmission facilities. The work is not intended to address any cost allocation issues and is expected to be completed by the end of the third quarter.

4. Governing Documents Enhancement & Clarification Subcommittee (GDECS) (9:35-9:45)

The committee will be asked to approve various cleanups, corrections and clarifications of terms included in the governing documents.

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to approve Tariff revisions exempting some reliability projects below the 200-kV threshold from the proposal window process. (See Low-Voltage Projects to be Exempted from Competitive Window Process.)
The committee will be asked to approve updated definitions and a cleanup of governing documents developed by the Governing Documents Enhancement & Clarification Subcommittee Group

— Suzanne Herel

February 23, 2016

Avangrid Posts Profit in First Earnings Results

By William Opalka

Avangrid, the result of the U.S. arm of Spanish conglomerate Iberdrola acquiring UIL Holdings, released its first-ever earnings results Monday, showing net income of $267 million for 2015.

The company, which was created on Dec. 17 when regulators approved the $3 billion acquisition, said that with only two weeks of UIL units included, there was no meaningful comparison to the prior year’s results. (See Divided PURA Approves Utility Takeover.)

But Avangrid said the combined net income of Iberdrola USA and UIL for the full year — excluding $71 million in merger costs and UIL’s $130 million in earnings prior to the acquisition — was $468 million, compared with $538 million in 2014. Iberdrola’s wind assets reported lower income due to the effects of El Nino and warm winter weather impacted electricity sales.

The company had not posted a full earnings report showing operating revenue, expenses and fourth-quarter results as of press time.

“In 2015, we successfully completed our merger transaction on target, obtaining all regulatory approvals and closing within 10 months of our announcement,” CEO James P. Torgerson said in a statement. “In 2016, we will rapidly conclude our transition planning within the first quarter, focus on executing our capital expenditure plan in all of the businesses and proceed with our important initiatives.”

Avangrid includes eight gas and electric distribution utilities in New York and New England, and renewable energy operations in 25 states coast-to-coast, primarily wind farms. The company is the second-largest operator of wind facilities in the U.S.

In a presentation to Wall Street analysts on Monday, Torgerson said, “We are now a large energy company with regulated businesses and investments in clean energy. Ninety percent of our generation is totally emissions-free, so we can focus very much on the renewable business.” The CEO said about two-thirds of its assets are in fixed, long-term power purchase agreements that create predictable earnings.

Avangrid projects earnings of $1.65/share for its distribution business, 40 cents/share for its renewables business and a 5-cent loss from corporate operations and its gas storage and transportation business.

For comparison going forward, the company is using the combined operations of Iberdrola USA and UIL from 2014 as the base in projecting future earnings of 8 to 10% per year. It gave an estimate of consolidated earnings of $2/share for 2016. The company’s board of directors declared a quarterly dividend of $0.432/share on its common stock.

New York Rate Case

Company officials announced that a settlement had been reached in New York for its two electric and gas distribution utilities, New York State Electric and Gas and Rochester Gas & Electric.

A joint proposal with numerous stakeholders — including regulatory staff, large commercial and industrial customers, and consumer and environmental representatives — was filed with the New York Public Service Commission on Friday (15-E-0283).

Depending on the year and segment of the three-year proposed settlement, the increases range from 1 to 7%. In aggregate, the total in incremental revenue is $390 million. Also included in the settlement is the recovery of $262 million over about seven years for storm-related costs in the NYSEG territory, primarily related to Superstorm Sandy.

The company expects public hearings to begin in April, PSC consideration in May and rates effective on June 1.

February 23, 2016

FERC Grants 12.28% Rate in GIA for Illinois Wind Farm

FERC last week approved a revised generation interconnection agreement proposed by MISO to link the Hoopeston wind project in rural Illinois to Ameren’s transmission.

FERC accepted MISO’s option A GIA, which proposed a 12.28% fixed charge rate on network upgrades, and rejected option B, which proposed a 12.82% rate. The restated GIA bears an Aug. 15, 2013, effective date.

The order (ER13-2157) approved in part MISO’s December 2014 compliance filing and denied Ameren’s October 2014 rehearing request.

Apex Clean Energy’s Hoopeston Wind consists of 49 wind turbines spread across east-central Illinois farmland. The wind company disputed Ameren’s proposed cost recovery for network upgrades, which stipulated that upgrade costs be subject to participant funding only if an interconnection customer offers up-front funding for the work.

MISO presented the two GIA options in response to an order directing the RTO to revise the restated Hoopeston GIA “so that the self-fund option does not include the recovery of costs other than the return of and on the capital costs of the network upgrades.”

— Amanda Durish Cook

February 23, 2016

Entergy Granted Waiver in New Orleans 15th Ward Transfer

By Amanda Durish Cook

FERC last week granted Entergy permission to use a one-time load adjustment in the transfer of transmission facilities in New Orleans’ 15th Ward, Algiers, from Entergy Louisiana to Entergy New Orleans.

The order (ER15-1922) grants a limited waiver to include an estimate for the Algiers load in the historical Entergy New Orleans calculation and subsequent removal from the Entergy Louisiana calculation to avoid discrepancies. Without the waiver, the transfer would require a responsibility ratio calculation and a phase-in period that would occur over a year, the company said. Responsibility ratios, used to allocate costs in the Entergy intra-system bill, are calculated as a rolling 12-month average.

Entergy said the Algiers asset transfer required immediate, not gradual, cost allocation and asked for a “one-time reset of the Entergy New Orleans and Entergy Louisiana responsibility ratios to complete the Algiers asset transfer.”

Entergy sought the asset transfer in December 2014 because Entergy Louisiana had been subject to retail jurisdiction of the New Orleans City Council in addition to the Louisiana Public Service Commission. Entergy Louisiana serviced Algiers as well as customers outside the city. Entergy New Orleans delivered electricity to all of the city except Algiers.

In April 2015, FERC approved the transfer, and in September, approximately 8.3 miles of 115-kV and 230-kV transmission lines and two transmission substations were passed to Entergy New Orleans, ending Entergy Louisiana’s dual jurisdictions. As a result, 1.84% of the capacity from Entergy Louisiana’s existing generation portfolio moved to Entergy New Orleans.

The commission determined that the historical load estimate Entergy developed was thorough, relying on “load research sample interval data, sample and total class billing kilowatt-hours, sample strata weighting factors and monthly Entergy system peak demand times.”