Page 1421 – RTO Insider

July 28, 2016

Exelon’s Constellation to Buy Con Ed’s Retail Operation

By Ted Caddell and Rich Heidorn Jr.

NASHVILLE, Tenn. — Exelon’s Constellation Energy Resources unit is buying Consolidated Edison’s retail energy business as it continues its efforts to hedge against falling wholesale power prices.

Constellation’s purchase of the retail division of ConEdison Solutions will give it another 560,000 residential, commercial and business electricity and natural gas customers in Texas, D.C. and 12 states in the Northeast, Mid-Atlantic and Midwest. If completed, it will make Constellation the largest competitive energy supplier in the U.S., with 2.5 million customers. Terms of the deal were not disclosed.

“This agreement provides an opportunity to grow our retail electricity and natural gas business in strategically attractive markets where we’re best suited to match load served with Exelon generation assets,” Constellation CEO Joseph Nigro said. “ConEdison Solutions has a reputation for delivering value to customers, and our combined companies will continue that tradition with a broad array of energy products and services at competitive prices.”

“With their industry-leading position, we are confident that the retail electricity and natural gas business will continue to thrive as part of Constellation,” ConEdison Solutions CEO Mark Noyes said. “This move will enable our company to focus our attention and our resources on making energy services and renewable energy offerings even more competitive and well-positioned for rapid growth.”

Having guaranteed customers for its wholesale generation fleet protects the company from volatility in wholesale prices.

It was the company’s efforts to minimize price risk that also led Exelon to its $6.8 billion purchase of Pepco Holdings Inc. this spring. The addition of PEPCO, Delmarva Power and Atlantic City Electric brought Exelon’s customer base to 10 million.

No More Debt

Exelon CEO Chris Crane gave no hint of the Con Ed deal in an appearance Monday at the National Association of Regulatory Utility Commissioners’ summer meeting.

In an interview with NARUC President Travis Kavulla, Crane said the company would not seek debt-financed acquisitions despite the current low interest rates.

exelon, coned, constellation — Exelon CEO Christopher Crane (L) and NARUC President (and Montana PSC Vice Chair) Travis Kavulla © *RTO Insider*

Independent power producers who seek greater leverage when interest rates are low can find themselves squeezed when rates rise, he said.

“We operate in probably a little bit more conservative way,” he said. “Our focus is actually reducing debt and maintaining a strong capital structure and understanding we’re at a low point in the [interest rate] cycle. It would not be prudent to think that this is a sustainable environment going forward.”

Meanwhile, Exelon is seeking help from state officials to eliminate the losses at its nuclear plants in Illinois and New York.

The company said in June it will close its Clinton and Quad Cities nuclear plants after the Illinois General Assembly adjourned without acting on a bill that would have subsidized the money-losing stations. (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)

Crane said the company wants to preserve the plants’ 4,200 jobs — “The tax base for DeWitt County dries up and goes away if the Clinton plant shuts down,” he said — but can’t continue to absorb the losses.

In New York, where the company has three nuclear plants, it has offered to buy Entergy’s struggling FitzPatrick plant if state regulators complete a plan to subsidize them.

Crane said the company has had a “very productive dialog” in New York, adding that the state’s proposed zero emission credits would create a “level playing field for carbon-free generation.”

“If other states that our … nuclear assets [operate in] want to approach the market like that we would like to do that,” he said. (See Commenters Laud, Blast New York’s Nuclear Subsidy Plan.)

July 28, 2016January 23, 2024

Governance Plan Critics Urge Slowdown of Western RTO Development

By Robert Mullin

Critics of CAISO’s most recent draft proposal of principles for governing a Western RTO contend the ISO is moving too quickly to get a plan to California lawmakers before the close of the current legislative session in September.

Speaking at a joint state agency workshop in Sacramento on Tuesday, multiple industry participants expressed concern that the ISO’s expedited effort to complete a proposal will result in a governance framework that defers too many issues to be resolved in the future.

The workshop — hosted by CAISO, the California Public Utilities Commission and the California Energy Commission — marked the last public forum in which stakeholders could discuss the proposal before it gets forwarded to Gov. Jerry Brown, who is expected to transmit a final version to lawmakers in August. California law requires the legislature to approve the ISO’s transformation into an RTO, a process that would result in the state losing direct authority over the grid operator.

‘One of the Largest Issues’ in CAISO History

“Regionalization is one of the largest issues facing the ISO in its history,” said Carolyn Kehrein, principal consultant for the Energy Users Forum, which represents large energy customers in California. “Unfortunately, the changes [to the original proposal] were made to meet a quick turnaround.”

Among those changes were provisions that clarify the composition and responsibilities of a transitional committee tasked with creating a final governance plan; reaffirm that any such plan must respect individual states’ sovereignty over electricity matters they currently regulate; and set a specific timeframe for the appointment of a final RTO board (See Revised Western Governance Plan Highlights State Authority.)

The revised proposal defined the makeup of a Western States Committee (WSC), which would consist of state-appointed representatives and two nonvoting members representing publicly-owned utilities and federal power marketing administrations (PMAs). A provision requiring load-weighted voting on the WSC was altered to enable the transitional committee to develop a process that factors in “some form of weighted voting based on load,” such as a supermajority requirement.

An expanded CAISO would first take in PacifiCorp’s service territories, but the ISO is preparing for other transmission owners to join in the near future.

CAISO also added a provision for the RTO to adopt a capacity market at the request of member states, while eliminating a provision for tracking greenhouse gas emissions — a measure the ISO contended was more suited for inclusion in market operations than as a principle in an overarching governance plan. The GHG mechanism would have monitored carbon emissions from all thermal plants participating in the RTO, not just those located in California.

Western States Committee Powers

“Our biggest concern is — how many more revisions will there be before this is final?” said Matt Freedman, an attorney with The Utility Reform Network (TURN), which represents small customers. “This feels like a working draft.”

Freedman said his organization was concerned that the WSC’s powers were reduced in the revised proposal, which now stipulates that the RTO’s board can — in certain circumstances — override the requirement for the committee’s approval for Section 205 filings with FERC.

TURN was also worried about the “watering down” of an earlier prohibition on capacity markets, as well as the removal of the reference to GHG tracking.

Sierra Club staff attorney Travis Ritchie wondered how California would manage its GHG program without making emissions tracking a core principle, saying that the absence of tracking in the Energy Imbalance Market has allowed carbon leakage into the state’s power market.

“We need to agree what our fundamental principles are before opening up this market,” Ritchie said. “We have to set out our clear requirements first.”

Tony Braun, an attorney representing the California Municipal Utilities Association (CMUA), criticized the proposal for deferring the decision to create an RTO market advisory committee to the transitional committee.

“We think the transitional committee scope is too broad,” Braun said. “I don’t think the states are going to go for it.”

He cautioned the ISO not to move too quickly to advance a proposal to lawmakers given the number of “outstanding issues” related to governance.

‘Shouldn’t be Rushing’

“We shouldn’t be rushing forward now. The train is not going to come off the tracks,” Braun said. “Let’s not get embedded in a discussion in the legislature this year.”

“It seems to me that you’re placing a heavy burden on the people in the building just north of this,” said Imperial Irrigation District (IID) General Manager Kevin Kelley, referring to legislators in the nearby state capitol.

Kelley said that his utility, which operates its own balancing authority area in Southern California’s Inland Empire region, is opposed to CAISO’s regionalization because it will require the state to relinquish its oversight over an organization that suffered costly market manipulation during the 2000-2001 Western Energy Crisis. IID last month sued CAISO to force public disclosure of protected information related to the ISO-commissioned studies supporting regionalization.

Kelley suspected the “driver” of regionalization was a “for-profit corporation” — namely, PacifiCorp.

“I would encourage you not to hurry it up because that’s what PacifiCorp wants you to do,” he added.

Supporters Weigh In

The revised proposal also had its supporters.

“We do feel like this process [for creating the proposal] has been very transparent,” said Jennifer Gardner, staff attorney for Western Resource Advocates, an environmental group. “We’ve been pleasantly surprised that recommendations were taken to change the second proposal.”

Gardner called the regional market “the best opportunity to improve business as usual” in the West and said that any proposal taken to the legislature “should be as broad as possible to not tie the hands of the transitional committee.” She said that GHG tracking on a regionwide basis would be important for assessing the environmental benefits of the market.

Jonathan Weisgall, vice president of legislative and regulatory affairs at PacifiCorp parent Berkshire Hathaway Energy, said CAISO’s regionalization studies made it “very clear” that the region’s 2030 GHG reduction goals “won’t happen without a market.”

In the “unlikely event” that regionalization did increase emissions from PacifiCorp’s coal plants, the company would work to mitigate them, Weisgall said.

“In our Midwest utility [MidAmerican Energy], where we’re moving to 80% renewables, we could not do that without a regional ISO,” Weisgall said.

Preserving State Authority

Jan Strack, a transmission planning manager with San Diego Gas & Electric, said his utility has been in favor of expanding the market for a long time. He said the infrastructure for the market is already in place and that it wouldn’t cost much money to expand it. Strack also contended that an expanded market would enable California to achieve its GHG goals at a lower cost.

“We need to avoid some roadblocks [in the governance plan],” Strack said. “The first one is preserving state authority.

“At the same time, we have to recognize that FERC has authority over interstate commerce,” he added. “That’s one area we would be uncomfortable handing over to the Western States Committee.”

“We support regionalization of the ISO and the associated market because, frankly, they work,” said Robin Smutny-Jones, director of California policy and regulations for Avangrid. “That’s why there’s been a proliferation of RTO-like structures across the country and around the world.”

Smutny-Jones acknowledged the RTO would need to work through contentious issues such as transmission access charges and regional resource adequacy, both of which would be left to a newly constituted RTO.

“But other states have done it, and the West can too,” she said.

July 26, 2016

New York ESCO Order Vacated by Court

By William Opalka

A New York judge has vacated the Public Service Commission’s February “reset order” that sought to overhaul the business practices of retail energy suppliers.

The July 22 order by acting state Supreme Court Justice Henry Zwack said energy service companies (ESCOs) were denied due process by the commission, especially by the strict time frame for compliance (870-16, et al.).

The order bars the PSC from enforcing a requirement that ESCOs guarantee retail and small commercial customers will pay no more than they would for default service (excluding contracts offering at least 30% renewable power) (15-M-0127, et al.).

It also throws out a requirement that ESCOs receive “affirmative consent” from such customers before renewing them from a fixed rate or guaranteed savings contract into one that provides renewable energy but does not guarantee savings.

Zwack left standing language the commission added to its business practices imposing tougher enforcement measures against those who prey on vulnerable or uninformed customers.

While regulators insisted they acted to protect customers from deceptive business practices, ESCOs said the order effectively killed customer choice in New York.

The order “is arbitrary and irrational in that it imposes the unexplained and harsh 10-day implementation period for the order, which amounts to a major restructuring of the retail energy market — or even its collapse,” Zwack wrote in his 26-page opinion. “The court is perplexed that implementation would be so immediate, when by the PSC’s own admission so many questions remain.”

PSC officials said they will address the judge’s procedural concerns promptly.

The commission acted in response to what it said was unscrupulous business practices by some retailers. ESCOs immediately challenged the order in court and also sought a rehearing by the PSC. (See Retailers Ask for Rehearing of NY Guaranteed Savings Order.) A stay was granted in March as the court challenge was pending.

Retail Energy Supply Association spokesman Bryan Lee said the group was “gratified that the court vacated the … order, finding the PSC action to be ‘irrational, arbitrary and capricious’ and failed to offer ESCOs ‘an opportunity to be heard in a meaningful manner and at a meaningful time.’ The court found that ESCOs were ‘stripped of any meaningful opportunity to participate in the promulgation of the reset order.’”

Zwack reaffirmed that the PSC maintains jurisdiction over retail rates, turning aside a challenge from the ESCOs.

“The court’s affirmation that the PSC has legal jurisdiction over ESCOs is an important win for the PSC and millions of consumers in New York,” PSC spokesman James Denn said in a statement. “The procedural flaws highlighted by the court have been addressed, or will be, as we continue to move forward with Gov. [Andrew] Cuomo’s far-reaching plan to protect customers from unscrupulous ESCOs. Make no mistake, we are putting an end to deceptive ESCO practices that harm electric and gas customers.”

Zwack’s ruling does not affect a PSC order earlier this month imposing a moratorium on ESCOs signing up additional low-income customers. Regulators issued the order after a collaborative effort failed to develop a formula under which customers could be guaranteed savings. (See NYPSC Declares Moratorium on Low-Income Sign-ups.)

In a statement released Tuesday, PSC Chair Audrey Zibelman defended the commission’s actions.

“When ESCOs were charging multiple times the prices that utilities charge for energy, and consumer complaints of deceptive marketing practices poured in by the hundreds, the commission took bold action in February to protect consumers,” she said. “Unfortunately, as a result of the litigation, ESCO customers are still paying millions of dollars more every month than they should be paying for electric and gas services. But this injustice will be short-lived. … The commission will easily address the procedural concerns raised by the court and will continue our work to ensure that all electric and gas consumers in New York have the protections they need and deserve.”

July 26, 2016

FERC OKs Settlement, Orders Earlier Refunds in MISO Voltage Cost Allocation Case

FERC last week approved a settlement in a dispute between WPPI Energy and MISO over how to allocate voltage and local reliability (VLR) costs to pseudo-tied load (ER12-678-006).

The commission also granted WPPI rehearing in a related case, ordering MISO to pay refunds from September 2012 rather than July 2014 in a reallocation of costs for revenue sufficiency guarantees paid to resources providing VLR support (ER12-678-004, EL14-58-001).

In 2012, FERC approved MISO’s proposal to allocate VLR costs to all loads in a local balancing authority area (BAA), including pseudo-tied loads — load that is effectively transferred from a source local BAA, in which that load is physically located, to a different host (or “sink”) BAA. In a later order, the commission had reasoned that “the local BAA of the host load is responsible for voltage management in the pseudo-tied local BAA, and therefore MISO’s proposal comports with cost causation.”

FERC reversed course in June 2014, saying it had “erred” in approving MISO’s cost allocation and setting the issue for settlement discussions.

The commission said the settlement resolves the issue of “whether MISO should allocate VLR costs incurred in responding to a localized constraint to a market participant such as WPPI based on its load that is physically remote from the constraint, because that load has been pseudo-tied into the LBA area affected by the constraint.”

The settlement will revise MISO’s Tariff by adding a new term, “internal commercially pseudo-tied load,” and new language requiring submission of meter data by market participants that have such loads. MISO agreed to resettlements of WPPI’s VLR payments as soon as possible after the installation of necessary software changes and WPPI’s submission of required meter data.

In the related order, the commission agreed with WPPI that refunds from the reallocation should be effective as of Sept. 1, 2012, the date MISO’s original rate proposal went into effect, rather than July 9, 2014, the date FERC originally set.

July 25, 2016

FirstEnergy Closing Largest Coal Plant in Ohio; Bay Shore also in Peril

By Suzanne Herel

FirstEnergy will retire four units at its largest coal-fired power plant in Ohio and sell or deactivate its Bay Shore plant by 2020, the company said Friday, citing “challenging market conditions.”

Together, the units represent 856 MW, of which 136 MW is generated by Bay Shore in the City of Oregon, Ohio. Units 1-4 of the seven-unit W.H. Sammis Plant in Stratton produce 720 MW. The remaining two units there will continue to provide 1,490 MW of baseload generation.

first energy, coal, ohio, bay shore — Sammis Power Plant *Source: Bechtel*

The 78 employees at Bay Shore would be offered jobs elsewhere in FirstEnergy if that plant were deactivated, and the company would work with any potential buyer to arrange their retention. Likewise, the 368 employees at Sammis would be offered other job opportunities, the company said.

Last year, the units headed toward closure or sale generated 4% of the electricity produced by all of FirstEnergy’s plants.

“We have taken a number of steps in recent years to reduce operating costs of our generation fleet,” FirstEnergy Generation President Jim Lash said in a statement. “However, continued challenging market conditions have made it increasingly difficult for smaller units like Bay Shore and Sammis Units 1-4 to be competitive. It’s no longer economically viable to operate these facilities.”

The announcement comes as the staff of the Public Utilities Commission of Ohio has proposed a rider for FirstEnergy that would allow it to recover $131 million annually from customers over three to five years so it may retain an investment-grade credit rating as it struggles to maintain some of its aging, mostly coal-fired plants. (See PUCO Staff Recommends $131M Annual Rider for FirstEnergy.)

FERC in April had ruled that an eight-year power purchase agreement PUCO had approved for FirstEnergy, and another for American Electric Power, would be subject to federal review. The ruling prompted FirstEnergy to return to PUCO with a modified proposal that commission staff said should be rejected in favor of the recommended rider.

FirstEnergy’s announcement was welcomed by environmental advocates who had denounced the company’s power purchase request as a corporate bailout.

“Closing these outdated, dirty power plants not only shows FirstEnergy finally recognizes the market momentum toward coal’s inevitable demise, the decision is great news for Ohio customers, who avoid paying a massive subsidy to keep the units afloat,” said Dick Munson of the Environmental Defense Fund.

According to the Sierra Club, FirstEnergy’s announcement brings the total amount of coal generation that has retired or is set to retire in the state since 2010 to 10,093 MW.

“Today’s announcement is further proof that Sammis is an outdated and costly coal plant that customers should not be forced to prop up,” said Shannon Fisk of Earthjustice. “We will continue to fight efforts that could be used to bail out other FirstEnergy coal units, as now is the time for significant investments in renewable energy, energy efficiency and grid modernization activity that will create jobs and economic development throughout Ohio.”

Bay Shore Unit 1, whose boiler is fueled by petroleum coke, went online in 2000. Units 2-4 were deactivated in 2012 because of environmental regulations.

Units 1-4 at Sammis date to 1959 through 1962. Units 5-7 came online from 1967 to 1971.

According to FirstEnergy, it pays $1.7 million annually in Bay Shore property taxes. The company pays more than $7 million in property taxes on the Sammis plant, making it the largest taxpayer in Jefferson County.

July 25, 2016

FERC, Corps Agree to Streamline Nonfederal Hydro Permits

By Robert Mullin

An agreement between FERC and the U.S. Army Corps of Engineers could help spur the development of privately run hydroelectric resources at the Corps’ unpowered dams.

The two agencies on Thursday signed a memorandum of understanding (MOU) to synchronize their processes to shorten permitting times, provide more certainty in regulatory outcomes and reduce financial risk for nonfederal project developers.

AMP Smithland Project (AMP) - ferc army corps hydro permits — AMP’s Smithland project in Kentucky will divert water from the Corps’ locks and dams to generate 76 MW of electricity.

“The potential for hydropower development in this country is significant, particularly at existing Corps facilities,” FERC Chairman Norman Bay said. “Today’s MOU is a positive step toward the development of these resources.”

A 2012 Department of Energy study identifying 6,900 MW of potential hydroelectric capacity at the Corps’ unpowered dams sparked interest in development at the agency’s water projects, according to Tim Welch, the department’s hydropower program manager.

The Corps is authorized to allow nonfederal entities to develop hydroelectric projects at its facilities provided that the project’s operation is deemed compatible with the purposes of the facility and the federal government has no competing development interest.

“This synchronized approach will shorten the time it takes the private sector to develop and construct new hydropower and will help us more efficiently use our existing infrastructure,” said Jo-Ellen Darcy, the Army’s assistant secretary for civil works. “It is also advancing our efforts to find alternative ways to finance new infrastructure.”

The synchronized process consists of two overlapping phases in which the Corps’ environmental and engineering reviews occur simultaneously with the commission’s processing of the hydropower license application. The agencies had been conducting their permitting processes sequentially.

During the first phase focused on environmental impact, FERC and Corps staff will collaborate with a project developer to understand the proposal and communicate the agencies’ permitting requirements.

As the lead agency under the National Environmental Policy Act responsible for licensing hydroelectric projects, FERC will direct preparation of the environmental permit for a proposed project, coordinating with its sister agency to ensure that a final document is consistent with the Corps’ statutory obligations. Once the joint environmental impact review is complete, FERC will issue a license.

The second phase will entail a technical, engineering and safety review after the developer has submitted a final project design. The developer will coordinate with the Corps to ensure construction won’t compromise the structural integrity of the agency’s facility. Once those requirements are met and communicated to FERC, the commission will authorize the project’s construction.

The MOU makes explicit that, as a cooperating agency in the process, the Corps is prohibited from later intervening in any FERC proceeding related to a project’s approval.

The commission has licensed nearly 30 nonfederal hydroelectric projects with a combined capacity of 400 MW at Corps facilities since 2007, said Nick Jayjack, deputy director of FERC’s Division of Hydropower Licensing. Five projects rated at about 133 MW are currently under construction, while 18 license applications representing another 500 MW are in the commission’s review pipeline.

July 25, 2016

FERC-SPP Briefs

Non-jurisdictional SPP members that refused to agree to potential refunds of revenues from the RTO’s seams settlement with MISO can be denied distribution of settlement proceeds, FERC ruled last week (ER16-791).

The ruling clarified the commission’s March order accepting SPP’s proposal to distribute to its members $16 million in funds reached in a settlement with MISO over the latter’s use of SPP’s transmission system to transfer power freely between its North and South regions. The order set the docket for hearing and settlement procedures to resolve factual issues in dispute. (See SPP Asks for Clarification on MISO Settlement Order.)

SPP asked the non-jurisdictional transmission owners to promise refunds of the revenues in case the allocation methodology changes as a result of the settlement procedures, but some TOs refused to agree.

The commission said SPP may withhold the settlement revenues from them, but the RTO must pay interest on any amounts withheld once the allocation is final. “SPP has not provided justification for it to withhold the settlement revenues without any interest,” FERC said.

FERC Order Allows SPP to Reduce ARRs

FERC last week accepted an SPP compliance filing that reduces the number of auction revenue rights made available in its annual allocation process (ER16-13).

SPP filed proposed Tariff revisions last October reducing the percentage of available transmission capability used to determine simultaneous feasibility.

FERC responded by asking SPP to modify section 7.3 of Attachment AE in its Tariff, specifying that transmission providers make available 60% of their transmission system capability for the fall, winter and spring seasons (October-May) during the annual ARR allocation process.

The RTO proposed corresponding revisions to the attachment removing references to assumed system capability for June-September to reduce potential ambiguity in the ARR settlement calculations during the annual transmission-congestion rights auction.

SPP to Bill Tri-County, Refund Tx Customers

FERC directed SPP to bill Tri-County Electric Cooperative for the co-op’s annual transmission revenue requirement (ATRR) with interest and to refund the amount to customers affected during a 10 1/2-month period in 2012-2013 (ER12-959).

The action corrects a “legal error” made by the commission in a 2012 docket that concluded with a 2014 affirmative order. Xcel Energy Services petitioned the D.C. Circuit Court of Appeals to review the decision, arguing that the rates at issue were SPP’s rates, not Tri-County’s.

The D.C. Circuit held that FERC failed to justify its decision to allow SPP’s filing to go into effect without a refund commitment by Tri-County, “thus failing to ensure that SPP’s rates would be just and reasonable.” The court found the commission “misapprehended its remedial powers and thus arbitrarily declined to weigh the equities underlying Xcel’s request for retroactive relief.”

FERC said it was remedying the error by directing SPP to bill Tri-County for the amounts of the co-op’s revenue requirement that SPP collected from ratepayers between April 1, 2012, and Feb. 21, 2013, with interest. It also directed SPP to make refunds to ratepayers once it received payment from Tri-County.

The proceeding began on February 2012, when SPP filed Tariff revisions to implement a formula rate in calculating Tri-County’s ATRR as a nonpublic utility participating transmission-owning member in the pricing zone of Xcel’s Southwestern Public Service.

The commission admitted it accepted SPP’s filing and set it for settlement hearings “without following its policy of accepting a rate filing to take effect pending the outcome” of further procedures when Tri-County agreed to refund the difference between the as-filed rate and FERC’s final approved rate.

Tri-County is a non-jurisdictional not-for-profit distribution cooperative with headquarters in Hooker, Okla. It serves approximately 23,000 customers in Oklahoma, Kansas, Texas, Colorado and New Mexico.

Western Farmers’ 10.87% ROE Approved

The commission accepted revisions to SPP’s Tariff adopting a formula rate for Western Farmers Electric Cooperative’s transmission service, while also sending the case to a settlement judge to address questions regarding the co-op’s return on equity and depreciation rates.

FERC’s order approved Western Farmers’ request for a return on equity of 10.87%, including a 50-basis-point adder for participation in SPP on top of its 10.37% base ROE (ER16-1774).

The commission noted that while Western Farmers is not within its jurisdiction under Section 205 of the Federal Power Act, it was “appropriate to apply the just and reasonable standard … to SPP’s proposed rates filed on behalf of Western Farmers.” That allows the utility to receive the same overall ROE “as that used by the applicable transmission zone’s dominant transmission owner.”

The commission said the case would be more appropriately addressed in settlement proceedings because Western Farmers’ proposed ROE is based on an average of other SPP transmission owner ROEs, which is not a FERC-approved methodology. FERC also said the utility proposed unsupported depreciation rates and failed to ensure wholesale customers will not be charged for capitalized construction funds and work in progress.

Western Farmers is a rural electric cooperative that provides wholesale power to 21 distribution cooperative member-owners in Oklahoma and New Mexico, as well as Altus Air Force Base.

NPPD Allowed to Terminate QF Contracts

The commission largely granted the Nebraska Public Power District’s application to terminate a requirement that it enter into new obligations or contracts with qualifying facilities with net capacities of more than 20 MW (QM16-1).

FERC said it terminated the mandatory purchase requirement because QFs in NPPD’s territory have “nondiscriminatory access” to wholesale markets. NPPD had argued that as an SPP member, it had satisfied its regulatory requirements under the Public Utility Regulatory Policies Act and was not subject to the commission’s authority under the FPA.

The order made an exception for NextEra Energy’s Cottonwood QF, which initiated a proceeding before NPPD’s board of directors “that may result in a legally enforceable obligation.” The commission grandfathered the Cottonwood contract because the facility sent a purchase request to NPPD last November, before the utility’s original Feb. 12 application to FERC. It found Cottonwood’s letter had established “a contract or legally enforceable obligation.”

NextEra was among a handful of SPP members and QFs that intervened, saying it had three self-certified QFs in NPPD’s service territory. NextEra did not challenge NPPD’s assertion it had satisfied PURPA’s requirements, but it said NPPD failed to acknowledge two letters seeking the utility’s purchase of the output from two of its QFs.

FERC found that the second letter, sent by Sholes Wind on the same day NPPD filed with the commission, was not filed prior to Feb. 12, and thus was not grandfathered.

— Tom Kleckner

July 25, 2016

Commenters Laud, Blast New York’s Nuclear Subsidy Plan

By William Opalka

New York’s proposal to subsidize upstate nuclear power plants was blasted as a corporate giveaway and embraced as an economic lifeline and necessity to reduce carbon emissions in comments filed last week with regulators (15-E-0302).

The state Public Service Commission closed the comment period Friday on the cost of the plan’s zero-emission credits. (See NYPSC Extends Comment Period on Nuclear Subsidy.)

Although it was the first time commenters had the opportunity to respond to the projected price tag of the subsidy, the arguments were familiar.

The subsidy was proposed earlier this year as part of the larger Clean Energy Standard. The original proposal pegged the nuclear subsidy as the difference between the average wholesale price of electricity and the operating cost of the nuclear plant. (See New York Would Require Nuclear Power Mandate, Subsidy.)

On July 8, the PSC staff released what it called a “responsive proposal” that calculated ZECs based on estimates of the social cost of carbon. The PSC said that would be $17.48/MWh for qualifying nuclear power generators in the first two years of the 12-year program, or about $965 million.

Staff also modeled the eligibility determination to take into account the costs and benefits of other clean energy alternatives. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)

A coalition of environmental groups — including the Alliance for a Green Economy, the Council on Intelligent Energy & Conservation Policy, the Nuclear Information and Resource Service and the Sierra Club’s Atlantic Chapter — continued its opposition.

“After claiming the nuclear tier would cost only $270 million over 12 years, the new ‘responsive proposal’ outlined a plan that will cost nearly $1 billion in just the first two years, with costs escalating to total approximately $7.6 billion. The program will likely cost more than $10 billion if Indian Point gets included,” they wrote.

The Brattle Group, which had done a study last year for New York labor groups, said the subsidy is cost-effective, estimating that electricity costs would rise by an average of $1.7 billion a year between 2015 and 2024 without the nuclear plants. “Although customers would pay for ZECs, they would avoid a power price increase that is larger than the ZEC cost. This means that customers actually pay less overall for power than if the upstate nuclear plants were to shut down.”

Upstate Energy Jobs, a coalition of municipal, business, labor, education and economic development leaders, said it supports the ZECs to keep the plants operating during the transition to clean sources. “Furthermore, renewable energy sources are not being constructed at a pace that makes replacing nuclear power with renewable power a realistic approach at this time.”

Towns and legislative members from western New York also focused on the plants’ economic impact. Comments from the Town of Scriba, which is the site of three nuclear plants, Nine Mile Point 1 and 2 and James A. FitzPatrick, were typical.

“More than any other community in New York state, we are most affected by the potential closure of these facilities should a reasonable and workable solution to the current financial difficulties facing our upstate nuclear-powered electric generators not be realized in a timely manner.”

fitzpatrick reliability - new york nuclear subsidy plan nypsc entergy exelon — Fitzpatrick Nuclear Plant *Source Entergy*

Exelon is the owner of three nuclear power plants on Lake Ontario, with two in Scriba, and is in negotiations to acquire a fourth. (See Entergy in Talks to Sell FitzPatrick to Exelon.) FitzPatrick has been scheduled to close early next year by its current owner, Entergy. Exelon said it would close Nine Mile Point 1 and R.E. Ginna early next year if a contract is not in place by the end of September.

“Time is of the essence,” Entergy reiterated in its comments.

A group representing large commercial and industrial customers complained that the July 8 proposal is an entirely new formula that is considerably more expensive than what was discussed in earlier proceedings. “In New York’s apparent haste to appease the owners of selected nuclear generation facilities to ensure the continued operation of those facilities, customers are being exposed to potentially 12 years of artificially inflated and excessive subsidy obligations,” it wrote.

Likewise, the National Energy Marketers Association said the proposal interferes with the development of the retail market. “The proposed purchasing and pricing mechanism under which [load-serving entities] will be required to purchase ZECs will have an adverse impact” on energy service companies, it said.

NYISO emphasized the environmental and reliability attributes of the plants. “The state’s nuclear power stations are non-emitting resources that already contribute significantly to the state’s production of clean energy and supply 30% of New York’s energy requirements.”

The Pace Energy and Climate Center supports the ZEC program by emphasizing it as a temporary bridge until renewable energy is built at scale, a point also emphasized by Exelon’s Constellation Energy Nuclear Group.

“While the long-term goal for New York should be to replace the state’s existing nuclear fleet with renewables that are additional to the CES target, over the next 12 years, the governor’s plan to support the state’s nuclear fleet will ensure that New York is able to achieve its carbon emissions targets while making rapid progress towards the CES goal,” Pace wrote.

The American Petroleum Institute proposed an expansive definition of credits for carbon reduction. “The NYPSC must create a level playing field by making emissions credits available to all technologies and energy sources that can reduce net GHG emissions from the electricity sector, including … energy efficiency measures, and other forms of electricity generation that can help achieve compliance with state emission reduction goals, such as natural gas, [combined heat and power], biomass, and waste heat power,” it said.

The PSC could act on the CES at its next regular meeting on Aug. 1.

July 25, 2016

CAISO: Forecasting Challenges Drove Increased Regulation Requirements

By Robert Mullin

CAISO last week provided an explanation of its decision to increase regulation requirements in response to the growing variability on its system.

The ISO’s Department of Market Monitoring last month called attention to the sharp rise in costs from the requirements, prompting the California Energy Commission to ask the ISO to justify the move. (See CAISO Regulation Costs Quadruple as Price, Procurement Jump.)

During a Market Performance and Planning Forum last week, CAISO said it doubled its frequency regulation service requirement from late February to mid-June in response to recurring short-term generation forecasting errors stemming from variable wind and solar resources during late winter and spring.

Regulation-Requirements---February-through-June-2016-(Source-CAISO)---content — CAISO’s regulation procurement ramped up sharply ahead of spring, but was backed down with the more predictable summer weather patterns.

The forecasting problem is mostly isolated to spring, when high renewable output often coincides with periods of low loads in California. At the same time, weather patterns tend to be more erratic, often making it especially difficult to predict renewable output on a moment-to-moment basis.

Regulation prices more than doubled shortly after the ISO increased its daily regulation procurement from 400 MW or less to as much as 800 MW in late February. Daily payments to regulation service providers surged from $100,000 to more than $400,000, the ISO’s Monitor found last month.

The ISO rolled back regulation requirements to previous levels for summer because of more predictable weather patterns.

Further compounding the spring forecasting issue is the increasing adoption of residential rooftop solar, which is subject to the same variability as utility-scale projects. The ISO estimates it has nearly 5,000 MW in rooftop solar in its balancing area, with new installations added daily. Variability in behind-the-meter rooftop output complicates matters by causing loads to skew from forecasts depending on whether the sun is shining.

The problem “happens more in the off-season — with more of the clouds coming in,” said Amber Motley, CAISO short-term forecasting manager. “Timing and forecasting of [generation] ramps are very difficult. Forecasting cloud coverage is difficult.”

Variable wind production can also be a factor, with cold fronts making it difficult to predict the timing of wind ramps and changes in wind direction causing intermittency.

Clyde Loutan, ISO senior advisor for renewable energy integration, said weather changes can occur too quickly to incorporate revised forecasts into the real-time market run. He also pointed out that forecasting errors are not covered under the ISO’s real-time contingency dispatch process, which sets aside generation to allow the system to recover from major disturbances.

“So you have to rely on regulation,” Loutan said.

“Seems like it’s more a failure of the forecast,” said Dan Williams, CAISO markets analyst at Portland General Electric. “And that should be changed by changing the market rather than rolling it into regulation.”

Loutan countered that he didn’t know of any forecaster that could reflect the intermittency in the five-minute market.

“When you think about how these markets were designed, they were really designed for conventional units,” he said.

Loutan also pointed to a clear financial incentive driving the ISO’s increased requirement.

“Back in January we had some pretty bad days when we didn’t control the frequency well enough,” he said. “For 11 hours, we had a hard time controlling the system. We found out that we were running out of regulation.”

If the condition had persisted longer than 30 consecutive minutes, the ISO would have been subject to as much as $1 million in NERC penalties, he said.

Carolyn Kehrein, principal consultant for the Energy Users Forum, suggested that increased regulation costs should be allocated to intermittent resources if the forecasting problem continued and the ISO didn’t develop new tools to deal with it. She said increased costs for intermittency should encourage the “right kind” of renewable development, such as geothermal.

Wei Zhou, senior project manager with Southern California Edison, agreed with applying the cost-causation principle to the problem.

“This is something that we’re looking at long-term,” said Loutan, referring to the forecasting issue at large. “But for now we just wanted to explain why we increased our regulation procurement.”

July 25, 2016

PUCT Asks ERCOT, SPP to Coordinate on Lubbock PL Move

By Tom Kleckner

Staff from ERCOT and SPP began discussions last week to determine how to work together on Lubbock Power & Light’s planned move to the ERCOT grid.

The grid operators conducted a staff-only call July 21 at the behest of the Public Utility Commission of Texas, which has bifurcated LP&L’s application to join ERCOT into two cases: one involving the move itself and the other involving a cost-benefit analysis of on ratepayers. (See Texas PUC Takes Slow Approach with LP&L Integration.)

PUC Chair Donna Nelson last week filed a memo describing the information the commission will be looking for from the grid operators’ studies on LP&L’s migration (Docket No. 45633).

“A joint study between ERCOT and SPP on the tangible costs and benefits could mitigate the issues that arise when studies are conducted by different parties,” Nelson wrote.

Commissioner Ken Anderson agreed with Nelson during the PUC’s July 20 open meeting, saying it is important the two entities know how they’re going to proceed.

“The question I will have for SPP and ERCOT … if they can agree on the same method to analyze not just the options of how to, but the more important one of the costs and benefits,” he said. “Then, finally, the costs that stranded ratepayers in SPP would have as a result, if any. I’m not conceding there are [some] now, but how do you think about the impact on Texas ratepayers outside of Lubbock?”

“In my mind, the key component here is so you can interpret the information, and not having a situation where you’re comparing apples to oranges,” Warren Lasher, ERCOT’s director of system planning, told Nelson. “I don’t feel at this time we have to do a joint study, but what we can do is ensure you have the information you can translate between the two studies.”

SPP’s principal regulatory analyst, Sam Loudenslager, told the PUC the RTO staffs would file a preliminary draft study scope before the commission’s next open meeting on Aug. 18.

LP&L announced last September it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy, ERCOT Board of Directors Briefs.)

Nelson and her fellow commissioners are also concerned about other companies that may be looking to join ERCOT. Rayburn Country Electric Cooperative, an ERCOT-turned-SPP member with 85% of its load in the Texas grid, has asked the ISO to conduct an integration study as it considers rejoining.

“I’m inclined to think we deal with Lubbock as a one-off,” Anderson said. “It’s a much smaller deal for Rayburn. The question becomes the precedent” it sets.

The commissioners agreed to discuss a rulemaking for new ERCOT members at its next meeting.

“I favor initiating the production of pertinent studies now while concurrently determining whether we need a rule for a clear framework for similar requests in the future,” Nelson said in her memo.

Nelson also stressed the importance of maintaining ERCOT’s independence from federal oversight. “Of import to us all, we need to ensure that Lubbock’s move into ERCOT will not invoke federal jurisdiction over ERCOT,” she said.

In her memo, Nelson provided additional issues she felt were “specific to the matter at issue:”

The impact to the ERCOT and SPP systems’ reliability and operational costs;
The costs of any facilities that would be required or that could be avoided on the ERCOT and SPP systems;
The benefits or challenges that the subject loads would provide or impose on each system;
The impact on wholesale and retail customers, markets and market participants;
Whether LP&L’s status as a municipal utility should be considered in the cost-benefit analysis; and
The length of time the no-harm standard — making LP&L liable for added costs passed on to customers — should be applied to the utility for its admission to ERCOT.

Nelson said she would also like to see analysis of alternative or gradual paths for entry into ERCOT “that are prudent for us to consider” under the cost-benefit analysis.