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.)
FERC on Wednesday accepted transmission calculations submitted by Southwestern transmission-owning utilities in support of their requests for market-based rates in their balancing areas.
But the commission’s approval of the simultaneous import limit (SIL) values provided by the Arizona and New Mexico utilities was accompanied by pointed advice about how FERC expects SIL studies to be performed and reported in the future (ER10-2302, et al.).
| APS
The commission’s Jan. 24 decision directly affects Arizona Public Service, El Paso Electric, Public Service Company of New Mexico (PNM), Tucson Electric Power, UNS Electric and UniSource Energy Development in Arizona and New Mexico. Also included in the order, which included 10 dockets, were Public Service Company of Colorado, Northern States Power and Southwestern Public Service Co., which submitted their SIL analyses at about the same time as the Southwestern companies in an effort to help FERC expedite its approval process for such studies.
PNM’s application for market-based rate authority within its own territory was rejected by FERC in October 2015 in part because of an inadequate SIL analysis. The PNM order was issued at the same time the commission issued a rule to clarify and streamline its MBR program, the first major update to the policy since codifying it in Order 697 in 2007 (RM14-14). (See FERC Refines Market-Based Rate Rules.)
The commission said it will use the accepted SIL values when reviewing updated market analyses submitted by the Southwestern transmission owners, as well as those filed by non-transmission-owning entities in the region.
Order 697 requires a utility to perform SIL studies in order to determine the amount of available transmission capacity that can serve the utility’s home market “under the most limiting normal and single-contingency operating contingencies.” The analysis is designed to determine how transmission constraints will limit energy imports to compete with the utility controlling the area.
The study, which examines transmission links with “first-tier” — or neighboring — balancing authority areas (BAAs), is expected to provide “a reasonable simulation of historical conditions” rather than a theoretical maximum transfer capability between areas.
FERC’s order commended the Southwestern utilities, which in many cases function as first-tier BAAs for each other, for coordinating the preparation of their SIL studies and sharing SIL values with each other.
“Such a coordinated approach leads to more accurate and consistent SIL study results,” the commission said, noting that the submitted studies were “generally” done correctly. “However, our review of the SIL studies and acceptance of the SIL values was hindered and delayed because of various modeling issues and incomplete or ambiguous reporting of results.”
In light of those shortcomings, the commission outlined guidance for submitting SIL studies. FERC said future filers:
Should study system contingences in both the home and first-tier areas that are historically used and identified in the energy seller’s available transfer capability and OASIS practices documentation.
Should furnish documentation showing that the contingency lists provided align with the BAA’s OASIS practices. A “valid” contingency would consider the realistic conditions and operating procedures for the home and first-tier areas.
Must consider that, if a contingency does not solve in a powerflow simulation, it could be difficult proving that the contingency would not cause an overload somewhere within the system. That could affect SIL values, the commission said.
Should ensure the accuracy of transmission line ratings in the home and first-tier areas.
May use historical capacity factors for certain energy-limited resources, such as hydroelectric and wind capacity.
Should explain the reason for changes in SIL values from previous studies and identify significant changes in the system, such as major generation additions or retirements and construction of new high-voltage lines.
ALBANY, N.Y. — Standard utility rate cases in New York can now be expected to include innovative rate designs and programs to encourage energy efficiency and clean energy technologies following Tuesday’s action by the Public Service Commission.
In its approval of the three-year Consolidated Edison rate plan (16-E-0060, et al.), the PSC also passed a companion order that advanced the state’s Reforming the Energy Vision initiative (15-E-0229).
Heat Map of Behind-the-Meter Solar in 2015 and 2030 | NYISO
Con Ed’s March 2016 filing was in compliance with the PSC’s December 2015 Targeted Demand Management Program order, which allow utilities to propose non-wire alternative (NWA) projects that replace or defer the need for transmission and distribution infrastructure through customer-side distributed energy resources or load reductions.
The commission’s latest orders specify the utilities’ incentives for such investments, with most the financial benefits returned to ratepayers.
“This is a big step on the way to implementing REV,” Commissioner Gregg Sayre said at the meeting. “The REV orders only give us a framework and policy guidance on this process, and it’s in cases like this where the rubber meets the road and real progress is made.”
A benefit-cost analysis would be performed for any NWA, with various checkpoints set up through the approval and implementation processes to verify its viability, the order states.
The order adopts Con Ed’s proposed incentive mechanism, but the commission reduced the utility’s proposal of a 50-50 split of the benefits between shareholders and ratepayers. The order provides 30% of the net benefits to shareholders and 70% to ratepayers.
“As the commission articulated in the REV Track Two Order, incentive opportunities should be financially meaningful and structured such that they encourage enterprise-wide attention at the utility and spur strategic, portfolio-level approaches beyond narrow programs,” the order states. “Further, incentive opportunities should be commensurate with the level of financial risk borne by utility shareholders.
| Edison
“The 30% sharing adopted here represents a financially meaningful incentive opportunity that should encourage Con Edison to pursue the innovative portfolio-level approach to implementing NWA projects, while producing significant net benefits to customers and reflecting the financial risk required of Con Edison shareholders,” the order continues.
Commissioner Diane Burman abstained on the Con Ed order, “consistent with my past voting record.”
Burman says she prefers a “holistic approach” rather than deal with these items individually. “I think there’s a lot here that is affecting other items that are still policy decisions that have not had finality, and we will work through that,” she said.
Con Ed is already using demand management in a pilot program, the Brooklyn-Queens Demand Management program. It deferred a $1.2 billion substation with a combination of energy efficiency, DERs and demand response. (See Overheard at the NYISO Distributed Energy Resource Workshop.)
A new, “expedited” CAISO initiative seeks to establish a process for selecting and procuring black start resources, needed to restore segments of California’s transmission system in the event of regional outages.
The effort will follow an ambitious timeline: The ISO hopes to present a plan to its Board of Governors for approval in May.
The initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.
The ISO decided to explore the procurement issue after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area.
CAISO’s black start procurement initiative was prompted by the need to better prepare the transmission-constrained San Francisco area for system restoration. | SF Travel
“This need is the impetus for this stakeholder initiative,” Scott Vaughan, CAISO lead grid assets engineer, said during a Jan. 24 call to kick off the effort.
CAISO staff have determined that, unlike in Southern California, where black start resources are more evenly distributed near major load centers and can provide more rapid restoration, resources serving the Bay Area are relatively far from population centers.
Under current practice, ISO and transmission owner restoration plans rely on black start resources either owned by a utility or acquired through a long-term contract. For a TO plan, a utility is able to recover the costs for resources through retail rates. Generation providing black start capability under the ISO’s plans are subject to a three-party agreement among the ISO, the applicable TO and the generator for a zero-price term.
Still, CAISO’s Tariff allows it to enter into black start service contracts for payment. If specific costs are not outlined in a contract, then the resource will be paid as exceptional — or out-of-market — dispatch and is entitled to bid cost recovery. The Tariff also outlines that scheduling coordinators can be required to pay for the service.
The new initiative would likely modify the current approach to procuring black start capability by ensuring that costs are spread beyond just the transmission-owning utility.
“Any such procurement would benefit all transmission customers in the area, yet may not result in the allocation of costs to all transmission customers if procured by the investor-owned utility,” said an ISO issue paper, released Jan. 17, in reference to the Bay Area’s specific need. “For instance, non-bundled customers taking service from a community choice aggregator, electric service provider or municipal utility in the area that rely on the black start capability may not face any cost allocation.”
CAISO has floated two ideas for cost allocation. The first would have the ISO enter black start contracts and charge all scheduling coordinators, rather than specific TO areas, for incremental black start capability. The other idea would entail it shifting cost allocation to local transmission access charge areas and recovering the costs from TOs as reliability service costs.
The Bay Area, however, poses unique challenges for black start procurement. One is the lack of eligible resources there.
“The ISO has said that there is a relatively small set of units from which this service could be procured,” said Brian Theaker, director of market affairs at NRG Energy. “Will the ISO disclose what that subset of units is?”
CAISO staff were reluctant to wade into that aspect of the issue before laying out a framework for procurement.
“At this point, we were not planning on getting into any more of the details around the specific requirement in the area or how we would go about procuring,” said Neil Millar, CAISO executive director of infrastructure development. “The goal right now is to land on the cost allocation process and the procurement process itself that would set out how we would go about doing this.”
Robert Jenkins of Flynn Resource Consultants picked up on Theaker’s theme.
“I was looking for what kind of characteristics is the ISO valuing in identifying this small number of units,” Jenkins said. “Is it geography? Is it size? Is it connectivity” to the ISO’s system? He added that he would be interested in learning more about the scope of the market when that information became available.
Millar responded by offering some qualifications, pointing out that CAISO wanted stakeholders to consider the procurement issue within the context of the relatively small number of resources eligible to participate in the market.
“It’s not a case of any generator located anywhere in the system,” Millar said. “Location does matter very much and there’s a relatively small subset, so that could affect people’s input on how we should go about planning this procurement process to pick a couple of units out of a relatively small subset.”
Bonnie Blair, a consultant representing the “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, pressed the ISO on the importance of the location of the resources.
Millar explained the “piecemeal” approach of restoring a part of the system after a blackout. The ISO starts by first bringing up a black start resource, then energizing individual transmission lines and “picking up other generators, a bit of load, more generators, then more load” to reach into the affected areas.
“So as you keep considering sources further and further away, you quickly get to where the time it would take to do all those steps wipes out the benefit of getting the resource in the first place,” Millar said.
Paul Nelson, electricity market design manager at Southern California Edison, wanted more specifics on the timeframe for acquiring the resources.
“Is this something that needs to be done in 2017, 2018?” Nelson asked. “Because that impacts the approaches for procuring it.”
“We’d like to have some sort of contractual arrangement by the beginning of 2018 or end of 2017,” Vaughan replied, adding that the small set of potential resources are not identified as black start capable and would likely require upgrades.
Theaker questioned whether the ISO schedule for completing the initiative was realistic, given the need to deal with issues of “compensation, context, structure and cost allocation,” as well as to draw up a straw proposal.
“It’s highly aggressive, but I think it is realistic,” Vaughan responded.
“Then I’d encourage you to identify some near-term milestones in terms of what has to be in place [and] when, in order to get this ready — not only for the board meeting in May, but also lay out the milestones for getting [resources procured by January 2018], as we’ve just discussed,” Theaker said.
Comments on the issue paper must be submitted to CAISO by Jan. 31. The ISO will publish a straw proposal Feb. 14.
