CARMEL, Ind. — MISO’s Steering Committee last week advanced three topics for discussion: the RTO’s settlement with SPP, a potential cost recovery defect and potential cost-sharing for customer-funded upgrades.
The committee decided that the Market Subcommittee will discuss a possible cost recovery gap, an issue raised by Entergy. The gap arises when MISO decommits or manually redispatches a resource to offline status, the utility contends.
“If the resource is later brought back online to fulfill the remainder of an existing commitment period or to meet a subsequent commitment period, the resource is not guaranteed start-up cost recovery,” Entergy said.
The company wants the RTO’s Tariff revised “to provide incentive for resources to follow MISO instructions and to ensure that a resource owner is not forced to choose between following MISO instructions and incurring an uncompensated cost, and disregarding MISO instructions.”
A discussion on generator-funded upgrades that benefit other interconnection customers was assigned to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG), despite a request by EDF Renewables that the topic be directed to the Interconnection Process Task Force (IPTF). The company wants such projects to receive some reimbursement through MISO, EDF said.
Jeff Webb, MISO director of planning, said the IPTF would be appropriate if project costs were only to be shared among interconnection customers, but he doubted that cost-sharing would be that limited. He suggested that the RECBWG first discuss the potential scope for cost allocation.
A stakeholder discussion on metrics used for the SPP-MISO transmission cost allocation settlement will initially be assigned to the Resource Adequacy Subcommittee for an examination of possible capacity benefits.
Jesse Moser, MISO director of seams relations and strategy, said internal decisions on the metrics belong in the RECBWG, which is already considering broader cost allocation changes. Still, some stakeholders contended that the issue should first move into the RASC for exploration of potential capacity benefits from the settlement.
The settlement requires MISO to “conduct a stakeholder discussion regarding the use of capacity benefits as an alternative way to allocate costs” of the joint operating agreement (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.)
Madison Gas and Electric’s Megan Wisersky said she was surprised to learn MISO would delve into a cost allocation discussion before assessing the resource adequacy impacts of the settlement.
Indiana Utility Regulatory Commission staffer Dave Johnston said the topic should be discussed in the RASC.
“To me, RECBWG is for transmission projects,” Johnston said. “This is not what this is. This is a settlement between parties with a bucket of money.”
WILMINGTON, Del. — PJM must determine how to handle different rules for new and existing pseudo-ties after stakeholders vetoed a package of reforms for external resources at Thursday’s Markets and Reliability Committee meeting but then agreed on applying the updated rules only to new pseudo-tie requests.
The package appeared headed back to the drawing board after failing to reach the 3.33 out of 5 necessary in a sector-weighted vote. But Exelon’s Jason Barker immediately motioned for a vote on an “alternative” package that excluded existing pseudo-ties from the new requirements, saying it would “move toward something that we think is an improvement over the status quo.”
The original proposal, developed through the Underperformance Risk Management Senior Task Force, called for making deliverability requirements uniform for resources within and outside of PJM’s footprint and requiring confirmatory feasibility studies for all pseudo-ties. Existing pseudo-ties would have had until delivery year 2022/23 to conform to the deliverability standards for internal resources. (See No End in Sight for PJM Capacity Market Changes.)
By Oct. 1, 2018, PJM would notify external resource owners whether their pseudo-tie is operationally feasible. Owners of resources that fail would be required to perform the required upgrades or would be declared ineligible to offer capacity.
Stakeholders balked at the implication that their units might become nonviable if the transmission owner — over which neither they nor PJM has authority — declined to meet the new standards.
“It’s their system; they can do things their way,” said Mike Borgatti of Gabel Associates.
PJM’s Adam Keech acknowledged, “We’re not in a place where we can require someone to upgrade to our standards.” He estimated there is roughly 3,500 MW of external generation pseudo-tied to PJM.
Joe Bowring, PJM’s Independent Market Monitor, called the original proposal “a significant step forward” but still inadequate because imported capacity remains an inferior substitute for internal capacity resources and suppresses market prices.
“If units don’t meet the rules and requirements, they don’t meet the rules and requirements. That should be the end of the story,” he said.
When the measure failed and Barker proposed applying the updated standards to new pseudo-ties, Bowring questioned whether Barker intended for existing pseudo-tied units to then be grandfathered in perpetuity. Stakeholders agreed that the alternative proposal would be silent on existing pseudo-ties and that portion would be sent back to the task force for further consideration. The measure was endorsed, receiving 3.97 in favor on a sector-weighted vote. The same proposal was later approved during the Members Committee meeting with 3.88 in favor.
PJM Senior Vice President of Operations and Markets Stu Bresler said there will need to be a discussion with the Board of Managers on having separate rules for similar groups. “We certainly can’t live that way for very long,” he said.
Work on Uplift Moves Forward Despite NOPR
In three decisive votes, stakeholders swiftly moved forward on efforts to address uplift.
The action was a far cry from last month, when PJM’s Dave Anders explained that the Energy Market Uplift Senior Task Force had only been successful in half of its goals. The task force endorsed two proposals to reduce uplift and volatility. However, it considered more than a dozen proposals to address cost allocation issues and couldn’t find majority agreement on any of them. The MRC instructed the task force to revote on the top five.
Earlier this month, the task force endorsed a package for the MRC to consider on Thursday. The proposal would maintain much of the status quo but include up-to-congestion transactions in the allocation of day-ahead and balancing operating reserves in the same way incremental offers and decremental bids are included. It would also remove the ability for internal bilateral transactions to offset deviation charges.
However, with FERC having issued a Notice of Proposed Rulemaking on uplift and UTCs on Jan. 19, PJM staff assumed stakeholders might want to postpone action on the issue until receiving clear direction from the commission. (See FERC Proposes More Transparency, Cost Causation on Uplift.)
Not so. “I think that PJM has shown in a lot of studies that UTCs do impact commitment and decommitment … and that’s a cause of uplift,” FirstEnergy’s Jim Benchek said. “If down the road that NOPR results in rulemaking actually happening … then we’ll deal with that rulemaking at that time. My final comment is let’s vote today.”
So they did: The Phase 1 proposal was approved with a sector-weighted vote of 4.1 out of 5. It largely maintains the status quo, except that it includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues.
The proposal to postpone voting on Phase 2 for one year was opposed by 3.8 out of 5 in a sector-weighted vote, and a vote on the package succeeded with 4.01 out of 5. The proposals will go for a vote before the Members Committee at its Feb. 23 meeting to approve the Operating Agreement revisions and endorse revisions to the addendum to Attachment K of the Tariff. The Tariff revisions will then need to be approved by the Board.
Separately, stakeholders also approved a problem statement and issue charge to reconsider historical practices and provisions in the Operating Agreement and Manual 33 restricting the sharing of data that is considered confidential or market sensitive. Changes could result in more transparency on transmission constraints, the reliability assessment commitment process and conservative operations in day-ahead and real-time operations.
Stakeholders OK Manual Changes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Revisions to Manuals 11 and 12 to account for the updated regulation requirement developed by the Regulation Market Senior Issues Task Force. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
Revisions to Manual 27 developed as part of an annual review.
Revisions to Manual 38 developed as part of a periodic review to provide more clarity on outage coordination.
Revisions to Manual 40 that, among other things, reduce the grace period for completing operator training. (See “Manual 40 Revisions Approved with Exelon’s Addendum,” PJM Operating Committee Briefs.)
Revisions proposed by the Governing Document Enhancement & Clarification Subcommittee to clean up definitions in the Tariff, Operating Agreement and Reliability Assurance Agreement.
Members Committee
Members Approve Charter for Security Committee
Despite stakeholder inquiries about its non-decisional status, the Members Committee endorsed by acclamation the charter for a new Security & Resiliency Committee.
American Municipal Power’s Ed Tatum asked what purpose the group would serve if it didn’t make any decisions. PJM staff said it would operate in an advisory capacity like the Transmission Expansion Advisory Committee. Exelon’s Gloria Godson clarified that the group was not formed at the behest of transmission owners.
“This was not a [Transmission Owners Agreement-Administrative Committee] idea,” she said. “In fact, a lot of TOA-AC folks have an issue with this idea.” (See “Preview of Security Committee Receives Tepid Response,” PJM Markets and Reliability and Members Committees Briefs.)
According to PJM, the new committee will serve as a forum to discuss threats and hazards and offer case studies, solutions or other best practices. To avoid compromising company security, the committee won’t include any Critical Energy Infrastructure Information in meetings and the news media will be barred. It will password-protect its minutes and only allow external partners by invitation. Corporate nondisclosure agreements will be used as needed.
Consent Agenda Endorsed
The committee also endorsed:
Operating Agreement revisions associated with residual auction revenue rights enhancements.
NextEra Energy boosted its adjusted earnings by 5% in the fourth quarter and 11% for all of 2016, despite falling short of investor expectations on both measures.
The Florida-based company Friday reported fourth-quarter adjusted earnings of $566 million ($1.21/share) and full-year adjusted earnings of $2.88 billion ($6.19/share), missing the Zacks consensus estimates of $1.29/share and $6.22/share, respectively.
Investors rewarded the company with a $2.07 increase in its stock price, from $119.30/share to $121.37/share.
Adjusted earnings exclude the mark-to-market effects of some hedging, non-temporary impairments, operating results from a solar project in Spain and expenses related to its proposed acquisition of Texas-based Oncor. Also excluded from the 2016 results were gains from the sale of natural gas generation facilities.
Subsidiary NextEra Energy Resources’ investments provided much of the growth. It commissioned about 2,500 MW of new wind and solar projects — the most wind and solar megawatts ever added by a single company in North America, NextEra said. It has signed contracts for another 540 MW of wind and 100 MW of solar energy since its third-quarter call.
“I remain as enthusiastic as ever about our future,” NextEra CEO Jim Robo told financial analysists during a conference call. He said the company’s performance reinforces “the overall strength and diversity of our growth prospects.”
Central to NextEra’s future is completing its $21 billion acquisition of Oncor, the largest transmission and distribution provider in Texas. The deal has FERC’s approval, but it next faces a Public Utility Commission of Texas review scheduled for Feb. 21-24. (See FERC OK in Hand, NextEra Faces More Questions on Oncor Deal.)
The PUC has until April 29 to act on the acquisition or it will be automatically approved.
“We see an opportunity to make two already great companies even stronger,” Robo said. “We believe we have the ability to bring real value to Oncor stakeholders, and in turn find attractive investment opportunities to create long-term shareholder value.”
Robo reminded analysts that NextEra will use its A– credit rating and balance sheet — “One of the strongest in the sector,” Robo said — to save Oncor customers “hundreds of millions of dollars by removing the debt that hangs over Oncor right now.”
He said intervenors have raised questions that could result in NextEra being immediately downgraded once Oncor’s debt is moved by either prohibiting the company from appointing a majority of the Oncor board or placing restrictions on dividends and approval of budgets.
“We are unwilling to compromise our A- corporate credit rating as a result of any transaction,” Robo said. “We need to address these issues in order to avoid being downgraded, so we can close the transaction.”
CARMEL, Ind. — MISO has named a business executive with almost two decades of experience in the energy industry as its new chief financial officer.
Brown | MISO
Melissa Brown most recently served as CFO for Atlanta-headquartered Drax Biomass, a wood pellet manufacturer with locations throughout the southeastern U.S.
The new hire comes just over six months after former Vice President of Finance Jo Biggers left abruptly in mid-August and the RTO opened a candidate search. (See Vice President of Finance Biggers Exits MISO.)
MISO spokesperson Jay Hermacinski said Brown will assume all the responsibilities that Biggers held in her role.
Since Biggers’ departure, corporate service tasks were delegated to Senior Vice President of Compliance Services Steve Kozey. Finance and corporate planning responsibilities were handled by Vice President of Strategy and Business Development Wayne Schug.
MISO CEO John Bear said Brown’s financial experience coupled with her energy background make her an ideal fit for the position. “Grid reliability and value-creation are our two top priorities at MISO. We need leaders like Melissa who will help MISO stay ahead of the constant changes we face in the energy industry,” Bear said.
Brown was Drax’s CFO from March to November and worked as an energy consultant for seven years with consulting firm Alix Partners.
She has also worked in different management roles at major utilities, including corporate treasurer and senior vice president of strategy and financial planning and analysis at Calpine; executive director of business development at NRG Energy; and manager of corporate financial analysis at AES. The RTO said Brown has a combined 19 years of experience in power generation, fuel supply and public utilities.
“I am excited to join this dedicated team of professionals and look forward to helping the organization be the most reliable, value-creating RTO,” Brown said.
Biggers’ predecessors include Mike Holstein, who served from 2001 to 2011, and James Torgerson, who served from 1999 to 2001.
FERC on Wednesday approved the Atlantic Bridge Project, which will expand natural gas delivery capacity in New York and New England (CP16-9).
In issuing a certificate of public convenience and necessity for the project, the commission accepted an environmental assessment released last spring that found “no significant impact.” (See Atlantic Bridge Environmental Assessment Released.)
“We agree with the conclusions presented in the EA and find that the project, if constructed and operated as described in the EA, and in compliance with the environmental conditions in the appendix to this order, does not constitute a major federal action significantly affecting the quality of the human environment,” FERC wrote.
The project will expand Spectra Energy’s Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems by 132,700 dekatherms/day to serve the New England and Canadian natural gas markets.
The $452 million project would replace existing pipelines and add new or expand existing compressor stations in New York, Connecticut and Massachusetts.
Six miles of existing pipeline in New York and Connecticut would be increased from 26 inches to 42 inches. A 7,700-horsepower compressor station would be built in Weymouth, Mass., along with numerous infrastructure improvements.
The commission said “the vast majority” of public comments concerned the Weymouth station, but it said that facility did not require an additional environmental impact statement. Concerns were adequately addressed by conditions set out in the order, it said.
FERC turned aside opponents’ claims that excess project capacity will be used to export LNG outside of North America.
“We note that while there are currently several proposals to export liquefied natural gas from the United States and Canada to overseas countries, there is no evidence that the applicants are constructing the Atlantic Bridge Project for this purpose. The project shippers receiving gas in Canada are industrial and commercial users of natural gas within Canada, not companies involved in the export of LNG,” the commission wrote. “We also note the commission does not have jurisdiction over the export or import of natural gas as a commodity. Such jurisdiction resides with the U.S. Department of Energy (DOE), which must act on any applications for natural gas export and import authority. Thus, the issue of whether the export of LNG will cause economic harm is beyond the commission’s purview.”
Spectra said the pipelines’ capacity was fully subscribed by five local distribution companies, two manufacturers and a municipal utility during its open season in 2014 and 2015.
The expansion project has a proposed in-service date of November 2017.
WILMINGTON, Del. — Following months of debate on the scope of the undertaking, a coalition of load-serving stakeholders won approval at Thursday’s PJM Markets and Reliability Committee meeting to review the capacity market construct.
Overcoming what had appeared to be strong opposition, the problem statement and issue charge were endorsed with a sped-up timetable revised to make potential changes in time for the 2018 Base Residual Auction.
The initiative cites the aborted power purchase agreements for FirstEnergy and American Electric Power in Ohio and the zero-emission credits approved for nuclear plants in Illinois as examples of the impacts public policy initiatives may pose to price formation in the capacity market. It notes a pending complaint by Calpine asking FERC to impose the minimum offer price rule (MOPR) on existing generation. (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)
Illinois Statehouse | Illinois Asset Building Group
“The failure to successfully anticipate these occurrences resulted in important policy debates circumventing the PJM stakeholder process and going directly to litigation at FERC,” the problem statement says. “The sponsors of this problem statement believe the stakeholder process forum is the appropriate place for these discussions. It is apparent to the problem statement sponsors that each state may take actions to meet its environmental, political and policy objectives that could affect” the Reliability Pricing Model.
The coalition, which includes Old Dominion Electric Cooperative, American Municipal Power, the Delaware Municipal Electric Corp., the PJM Public Power Coalition and the Public Power Association of New Jersey, has been asking since August for approval to review the RPM.
Focus Tightened
Since then, the measure’s focus has been revised and repeatedly pared down. AMP’s Ed Tatum, the coalition’s spokesman, noted on Thursday that Direct Energy and Dominion Virginia Power have withdrawn as sponsors. As recently as last month’s MRC, stakeholders remained hesitant to investigate the potential impacts of any governmental action on CP, concerned the implications could be too disruptive to the market, which is still digesting the rule changes under Capacity Performance. (See “Stakeholders Remain Skeptical of Campaign to Revisit CP,” PJM Markets and Reliability Committee Briefs.)
The sponsors returned on Thursday focused just on state actions and explained that they had taken pains to limit the scope, despite suggestions to broaden it in certain ways. The effort still nearly faltered, as stakeholders remained concerned it inappropriately targeted states. Bob O’Connell of Panda Power Funds suggested focusing on “out-of-market actions” instead.
“Panda Power Funds has no interest in picking a fight with states. Our biggest focus is on price formation,” he said. “I’m indifferent to who pushes the wheelbarrow with money into the room. I’m just concerned about the money in the room.”
Alex Stern of Public Service Electric and Gas voiced support for O’Connell’s efforts to focus on market design, but Tatum said “out-of-market” doesn’t have a specific definition. Tatum also clarified that the focus had changed to not target the states for taking actions they deem necessary. Others agreed, including Dan Griffiths of the Consumer Advocates of the PJM States (CAPS) and Susan Bruce of the PJM Industrial Customer Coalition, who called it a “rabbit hole.”
External ‘Forces’
John Farber of the Delaware Public Service Commission praised the sponsors’ acknowledgment that state actions can be “manifestations” of external “forces” applying pressure on government, not necessarily internally motivated. Ruth Ann Price, Delaware’s deputy public advocate, was mild in her criticism, merely echoing a request to “soften” the language that had been made by other stakeholders during previous discussions. Tatum responded, as he has in the past, by asking for suggestions.
With the state advocates indicating interest in finding consensus, a small group huddled to craft mutually acceptable language.
In the meantime, Neal Fitch of NRG Energy pointed out that the issue’s scope had been reduced, yet its timeline for results had been extended into late 2018. He said it seemed likely the issue could be resolved in time for the 2018 BRA in April.
A vote on the measure was deferred until after lunch to incorporate the updated language. When it finally came time to vote, the package referred to “state public policy initiatives” and anticipated results by the end of the year. PJM Senior Vice President of Operations and Markets Stu Bresler confirmed this left enough time for it to be incorporated in the planning criteria for the BRA.
EnerNOC’s Katie Guerry questioned the continued focus on state actions, but Price defended the language, saying that local initiatives would not impact PJM’s markets. Despite opposition from most of the Transmission Owner sector, the revised problem statement passed a sector-weighted vote with 3.95 out of 5, with the End Use Customers and Electric Distributors unanimously in support.
The issue charge assigns the initiative to a new Capacity Construct/Public Policy Senior Task Force (CCPPSTF) reporting to the MRC. It will identify the “objectives and characteristics” of a well-functioning capacity market and “identify areas where state actions and the current RPM capacity construct may not be aligned.”
The group will seek to address the conflicts with potential changes to the PJM Operating Agreement, Tariff, Reliability Assurance Agreement and manuals.
Calling 2016 “very successful” and predicting 2017 will be “another transformational year,” American Electric Power CEO Nick Akins paid tribute to the late television icon Mary Tyler Moore during a Thursday conference call with financial analysts.
“In respect to the passing of Mary Tyler Moore, I will just say, we are going to make it after all,” Akins said during the company’s fourth-quarter and year-end report. “This has been a year of repositioning and de-risking the company. … We have come through with flying colors, but as a premium energy regulated company, our work is far from done.”
Akins’ optimism is fueled by the pending sale of four competitive power plants for $2.2 billion, the company’s hopes for restructuring Ohio’s electric market and possible corporate tax reform under the Trump administration.
The company reported fourth-quarter operating earnings of 67 cents/share, up almost 40% from a year earlier, which beat the Zacks consensus estimate of 55 cents/share. For the year, operating earnings were $3.94/share, up from $3.69/share a year ago. Its transmission segment contributed 54 cents to earnings for the year, an increase of more than 38%. AEP reaffirmed its 2017 operating earnings guidance range of $3.55 to $3.75/share.
Investors reacted to the news by driving AEP’s share price up 40 cents to $62.97 at Friday’s close.
Under Generally Accepted Accounting Principles (GAAP), the company reported 2016 earnings of almost $611 million, a $1.4 billion drop from 2015 that reflected its $2.3 billion write-down on its Ohio competitive generation assets in the third-quarter, as well as a federal tax audit settlement over the sale of its commercial barge operations and mark-to-market impact of hedging activities.
Akins said AEP expects to close its sale of three natural gas plants, with 2,533 MW of capacity, and the mammoth 2,665-MW Gen. James M. Gavin coal plant to Lightstone, a joint venture between The Blackstone Group and ArcLight Capital Partners, “sometime in 2017.”
AEP’s Gavin Power Plant. | AEP
Three of the gas plants are in Ohio, and the fourth, the 1,186-MW Lawrenceburg Generating Station, is just across the state line in Indiana. Akins said the company was continuing a “strategic review process” for the remaining merchant generation units.
“This was a year of reducing risk and volatility of earnings for the company in the future and reinforcing our balance sheet to provide a strong platform for future growth,” Akins said.
The CEO said the company is discussing with other utilities and stakeholders its proposed legislation to restructure Ohio’s competitive market and expects a bill to be introduced as early as the second quarter.
“AEP will not invest in new generation in Ohio unless we have a clear path to recovery of our investment, so enabling legislation is critical,” he said. “There’s already drafts of legislation that are circulating around, and we just need to make sure all the parties are comfortable with that.”
Though AEP saw signs of an improving economy in its service territory in the fourth quarter, Akins called the growth “minimal.” He said the company will continue to watch the economy closely under the new administration’s “pro-growth agenda.”
“President Trump’s focus of enhancing the ability for manufacturing industries to thrive and produce jobs … well that’s AEP’s service territory,” he said. “AEP should prosper, and we are very much looking forward to working with the Trump administration to bring prosperity and jobs back to this country.”
ALBANY, N.Y. — Audrey Zibelman was brought from Pennsylvania to New York in 2013 to lead Gov. Andrew Cuomo’s Reforming the Energy Vision initiative. But as she prepares to leave, Zibelman insists the ambitious program will survive her departure.
Zibelman surprised the state’s energy industry when her new employer, the Australian Energy Market Operator, announced her hiring a week ago. (See NYPSC Chair to Head Australia Grid Operator.)
At a news conference after the New York Public Service Commission’s Tuesday meeting, she said the offer was made barely a week before the meeting. She will preside over two more commission sessions, with her more than three-year tenure ending after the March 16 meeting.
Zibelman said she had no intention of leaving the PSC but was instead recruited by the Australian grid operator.
“This job, as chair, is a fantastic job for someone like me, who loves these industries and is always looking for ways to make things better,” she said.
She is most closely associated with the state’s ambitious REV initiative. She praised Cuomo for making tough policy decisions that will lead to a new organizational structure in the industry.
“I feel very strongly that REV is on the right track. Almost all of the key policy decisions that were needed to really start moving the industry in the direction that REV contemplates have been made,” she said, citing orders issued last week as examples. “We have really moved away from the policy conception to the implementation.” (See related stories, Con Ed Rate Order Moves REV Forward with Shared Savings and NY PSC OKs New Rules to Break Solar Interconnection Logjam.)
What Zibelman will leave behind is at least a dozen open dockets that deal with aspects of REV. These include the Clean Energy Standard and the zero-emission credits for nuclear plants, the Distribution System Implementation Platform, distributed generation compensation and several others.
On top of that, there are company- or issue-specific dockets that either predate REV and now include it, or have added REV components as they have progressed.
The PSC’s years-long grappling with how to combat alleged abuses by energy service companies is an example of the former. Its just-approved rate case with Consolidated Edison with several provisions for distributed generation, demand management and utility investment incentives were features of the latter.
But Zibelman said incumbent commissioners Gregg Sayre and Diane Burman and a strong staff would ensure no loss of momentum.
Her departure, the pending retirement of Commissioner Patricia Acampora and a two-year-long vacancy means the PSC will have three openings for new members in short order.
“At this point, the momentum is in the [energy] market. They’re leading and we’re following as they tell us where they need to go,” she said.
The decision to leave was made harder by having her husband on the other side of the world, Zibelman said. She is married to former PJM CEO Phil Harris, who for several years has led the Tres Amigas “superstation” project in New Mexico that would link the Eastern and Western Interconnections.
“It’s a personal decision we’re making, but he will continue at Tres Amigas, and we’re going to work it out,” Zibelman said.
ALBANY, N.Y. — The New York Public Service Commission last week updated interconnection rules for solar projects larger than 50 kW in an effort to break a logjam in utilities’ queues (16-E-0560).
The order sets deadlines and payment schedules for system upgrades to cull inactive projects from the queues and free up space for those projects further along in their development cycles.
The projects covered by the new rules are from above 50 kW to 2 MW. The PSC said more than 2,000 projects in that category were filed with the state’s utilities from April through December 2016. Many of those projects are community shared solar developments, intended to expand the benefits to customer pools who are unable to install solar generation on their own properties.
“These new requirements will help determine whether a proposed solar project is viable and should move forward to construction,” commission Chair Audrey Zibelman said in a statement. “Every proposal requires a lengthy, in-depth analysis to determine whether it is feasible and, too often, unrealistic projects have been getting in the way of workable proposals.”
Although it did not cite statistics, the PSC said that multiple developers have filed interconnection requests for the same projects, exacerbating the logjam.
The utilities filed a joint proposal in September that was endorsed in whole or in part by 20 stakeholders.
The new rules include fixed decision deadlines and cost-sharing requirements for the required system upgrades. Developers must prove they have exclusive permission or a land-use agreement from a property owner for a specific project.
To remain in the queue, projects with a completed coordinated electric system interconnection review must pay 25% of the system upgrade costs to the utility and execute a standard interconnection agreement.
The rules would apply to those projects currently undergoing the interconnection review along with newer projects that have had only a preliminary review. Projects that fail to comply would be removed from the queue.
Projects that have been delayed by municipal moratoria can hold their positions by either paying the 25% system cost upgrade or executing an interconnection agreement.
The order also includes an interim cost-sharing mechanism in which the first developer in an affected area pays 100% of the system upgrade costs and is reimbursed by later projects that enjoy the same benefit.
PSC staff will work on a more permanent solution, the commission said.
The plan updates the standard interconnection requirements first adopted in 1999. The requirements have been updated several times since, including last March (15-E-0557), but the queue continued to pile up.
“The interconnection queue backlog presents a serious challenge to the commission’s goals for increased solar installations, renewable power, and creating efficient markets for distributed energy resources, as contemplated in the [Reforming the Energy Vision] proceeding,” the PSC wrote.
The six investor-owned utilities — Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange & Rockland Utilities and Rochester Gas and Electric — must file tariff amendments and updated interconnection requirements that would become effective on March 1.
FERC last week denied requests for rehearing on a formula rate it approved in April for Northeast Transmission Development’s construction of a transmission line across the Delaware River (ER16-453).
A graphical depiction from PJM of the proposed line across the Delaware River
Both NTD and the Delaware Municipal Electric Corp. had requested rehearing of the order, though for opposing reasons. NTD argued the commission erred in denying it a 50-basis-point risks and challenges return on equity adder in its initial order, while DEMEC argued the commission erred in granting NTD a 50-basis-point adder for joining PJM and turning over operational control of the line to the RTO upon completion.
DEMEC had also argued that FERC erred in allowing any of NTD’s affiliates or subsidiaries to use the rate. The commission also denied this, clarifying that it applies to any affiliates or subsidiaries that may be formed in the future as well.
The efforts might all be for nothing though, as NTD’s line is part of the Artificial Island project, which has been mired in years of delay. The project — PJM’s first competitive solicitation under FERC’s Order 1000 — is undergoing reanalysis and scope changes that won’t be known until at least April. (See PJM Analysis on Artificial Island Project Delayed Again.)
