FERC last week accepted network transmission service agreements between SPP and Kansas Municipal Energy Agency (KMEA) and Sunflower Electric Power, pending modifications to address the inconsistent treatment of a generation resource (ER17-889).
KMEA’s Jameson Energy Center | KMEA
The commission directed SPP to make a compliance filing within 30 days to resolve a modeling discrepancy in the power-flow analysis, which failed to account for a 9-MW gas turbine (Garden City 2) at KMEA’s Jameson Energy Center in Garden City, Kan.
SPP agreed to file revisions to KMEA’s service agreement to reflect the additional network resource, with an effective date of March 1, 2017, and to remove a reference to the unit that imposes revenue crediting requirements.
The RTO filed with FERC in January service agreements between it and KMEA as a network customer, and between it and KMEA and Sunflower as a network customer and host transmission owner, respectively. Commission staff tentatively accepted the agreements in March while FERC lacked a quorum.
Sunflower and its Mid-Kansas Electric owner, which also includes five co-ops and a not-for-profit electric company, intervened to point out the initial service agreement with KMEA excluded Garden City 2 but required the unit to pay revenue credits as a network resource. They requested FERC require SPP to remove the unit from the revenue credit payment or add Garden City 2 as a network resource.
SPP acknowledged its mistake and said it performed an additional analysis using updated model information, reposting the results in an aggregate transmission service study in February. It confirmed network service for KMEA used Garden City 2 as a designated network resource, effective March 1.
FERC last week approved cost responsibility assignments for 39 baseline upgrades recently added to PJM’s Regional Transmission Expansion Plan (ER17-2362).
The allocations were filed on Aug. 25. Thirty-five projects will be allocated to the transmission zone in which they are located, including five projects of less than $5 million each. Two projects will address Form 715 local planning criteria, and 28 involve circuit breakers and associated equipment. The remaining four projects are “lower voltage facilities” that are allocated based on the solution-based distribution factor (DFAX) method.
PJM’s control room | PJM
Old Dominion Electric Cooperative challenged two of the DFAX allocations, saying it was unable to replicate PJM’s analysis. It asked the commission to direct PJM to provide the detailed information “for the sake of transparency” and to determine whether the upgrades are appropriately allocated entirely to the American Electric Power zone. ODEC questioned PJM’s 100% allocation of another project to the American Transmission Systems Inc. zone, arguing that the results of the DFAX analysis produce a 1.32% allocation to ATSI.
FERC accepted PJM’s defense of its allocations. The RTO said because only ATSI had a DFAX percentage greater than 1% for project b2898 — reconductoring the Beaver-Black River 138-kV line — that zone was assigned the entire cost of the $20 million project.
PJM said it used “an appropriate substitute proxy” for the baseline projects, reactive power upgrades that can’t be addressed by DFAX analysis, which measures over transmission lines or transformers. PJM developed an “interface comprised of the lines and transformers that surround the entire AEP system,” a localization method PJM often uses “because the majority of reactive power upgrades are intended to provide local voltage support.”
ODEC has also asked the D.C. Circuit Court of Appeals to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. ODEC said the cost allocation for the two Form 715 projects should be subject to the outcome of its challenge.
FERC said last week it didn’t have enough information to decide on complaints that American Electric Power affiliates are raking in unreasonable returns for transmission projects in PJM and SPP, instead establishing hearing and settlement judge procedures.
In PJM, American Municipal Power, Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, Indiana Michigan Municipal Distributors Association, Indiana Municipal Power Agency, Old Dominion Electric Cooperative and Wabash Valley Power Association filed complaints that AEP’s current 10.99% base return on equity is excessive. They requested a base ROE no higher than 8.32% and asked for refunds with interest. The change would save them $142 million annually in transmission costs, they said (EL17-13).
The complainants hired a consultant to develop a peer-group analysis that included 25 utilities similar to AEP. That analysis found a “zone of reasonableness” of between 5.62 and 9.46% and that the median of the values, 8.32%, was more appropriate than the midpoint.
Multiple state agencies intervened to support the complaint, including the Indiana Office of Utility Consumer Counsel, the Office of the Ohio Consumers’ Counsel, the Virginia Division of Consumer Counsel, the Virginia State Corporation Commission and the Indiana Utility Regulatory Commission.
An ad hoc group of large commercial and industrial end-use customers also commissioned an analysis, which found an appropriate zone between 5.64 and 9.44%, recommending a base ROE of 8.22%.
AEP responded with its own analysis that found an appropriate zone between 6.41 and 11.71% and that using the midpoint of the upper half of the range, rather than the median, was consistent with FERC rulings.
FERC found the complaint compelling enough to explore further and called AEP’s argument that the current rate falls within the reasonable zone “unpersuasive.”
“The commission has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE,” the order said, setting a refund effective date of Oct. 27, 2016.
SPP Complaint
FERC also established identical procedures for East Texas Electric Cooperative (ETEC) in its complaint against AEP subsidiaries Public Service Company of Oklahoma (PSO), Southwestern Electric Power Co. (SWEPCO), AEP Oklahoma Transmission and AEP Southwestern Transmission, setting a refund effective date of June 5, 2017 (EL17-76).
The cooperative in June asked the commission to reduce the companies’ 10.7% base ROE to 8.36% within SPP’s AEP West pricing zone. PSO and SWEPCO’s current base ROE derives from a transmission formula rate settlement agreement filed Feb. 23, 2009.
ETEC contends the base ROE is no longer just and reasonable and that its ratepayers are currently overcompensating the AEP West companies by $36.6 million annually.
The companies countered that the 9.53% upper end of an ETEC consultant’s zone of reasonableness falls more than 100 and 80 basis points below the ROE that FERC previously approved for ISO-NE and MISO, respectively.
The commission said it was “unpersuaded” by the argument, saying “the relief [ETEC] seeks here is an ROE that falls well below the current ROE, based on different facts, risks, proxy companies and time periods” than those in previous decisions.
FERC on Thursday approved NYISO Tariff revisions ordering downstate residents to pay 90% of the cost of AC transmission projects stemming from public policy needs (ER17-1310-001).
The projects, which include the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City.
| National Grid
The cost allocation was proposed by the ISO at the direction of the New York Public Service Commission, which said 75% of the costs should be allocated solely to the downstate load zones that will benefit from the congestion relief, with the remaining 25% allocated regionally based on load-share ratio. “According to the New York commission, this method will allocate approximately 90% of the transmission project’s cost to ratepayers in the downstate region, and about 10% to upstate ratepayers,” FERC said.
FERC rejected a protest by four State Assembly members, who said the regional allocation of 25% was too low to account for “some of the financial and societal benefits to ratepayers statewide.”
The commission said the proposed allocation satisfies Order 1000’s requirement that it be “roughly commensurate” with the benefits that the load zones receive, citing a study published by the PSC that found 89.5% of the costs should be allocated to the downstate load zones.
However, the commission added that the ISO’s filing “does not prevent the selected transmission developer from submitting its own proposed cost allocation method for the AC transmission upgrades. The Tariff specifically provides that the selected transmission developer may also file, for the commission’s approval, an alternate cost allocation method or request that NYISO use the default cost allocation method (i.e., load-share ratio).”
ROE Settlement
In a related order, the commission approved a settlement with New York Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — to decide questions regarding their potential compensation for the projects (ER15-572).
The settlement, which will apply only if NY Transco is selected as the developer, includes a 9.65% base return on equity and a 100-basis-point adder that will apply up to the cost cap, which was defined as the capital cost bid plus an 18% contingency and an inflation factor of 2% per year.
The commission said the settlement, which was unopposed and endorsed by both the New York PSC and FERC staff, “appears to be fair and reasonable and in the public interest.”
Cost Containment
FERC did not rule on state regulators’ proposed cost-containment mechanism, under which ratepayers would be responsible for 80% of any overruns above the estimated cost of the project and retain 80% of any savings.
The commission said it couldn’t rule because the ISO had provided only a description of the risk-sharing proposal without Tariff language. “As such, [the mechanism] is not properly before us,” the commission said. “NYISO states that it plans to file Tariff sheets for the 80/20 risk-sharing mechanism after concluding its stakeholder process.
“In regard to implementing the 80/20 risk-sharing mechanism, because the New York commission recognizes that [FERC’s] policy on cost recovery allows transmission developers to recover costs that are prudently incurred, it proposes to limit the selected transmission developer’s ability to recover costs associated with cost overruns by reducing the allowed return on equity for the transmission project,” FERC added.
Selection Process
NYISO received 16 proposed projects from six developers in response to a February 2016 solicitation for solutions to address the transmission congestion. In a January order, the PSC told the ISO it “should proceed to a full evaluation and selection, as appropriate, of the more efficient or cost-effective transmission solution to meet the” public policy transmission need.
NYISO spokesman Michael Jamison said the ISO hopes to release draft results of its analysis by the end of the first quarter of 2018. “Subsequent to that, the NYISO will select the more efficient or cost-effective project. At that time the NYISO will work out a developer agreement with the chosen party, and that party can initiate actions with the state under the Article 7 transmission siting process.”
WESTBOROUGH, MA — Boston leads large, northeastern cities in economic growth, outpacing both New York and Philadelphia in payroll employment, Moody’s Analytics economist Ed Friedman told the ISO-NE Planning Advisory Committee on Thursday.
| BLS, Moody’s Analytics
According to figures compiled by Moody’s from the U.S. Bureau of Labor Statistics, Boston posted better than 2% growth in payroll employment for the three months ending September 2017, compared to approximately 1.7% growth in Philadelphia and less than 1.5% in New York City.
“The job growth in Boston is quite strong and significantly above the U.S. pace, which is around the 1.5% mark,” Friedman said.
Friedman characterized New England job creation in the aggregate as “slow but steady” at 1% per year and said that housing price gains in the region are mostly keeping up with the national average of just more than 6% for the year ending in August 2017. Of the six states in the region, only New Hampshire and Massachusetts exceeded the national average; housing prices in Massachusetts, where health care remains a strong economic driver, increased by almost 7%.
| BLS, Moody’s Analytics
Both Connecticut and Vermont lost population in the past two years. Nonetheless, Moody’s expects economic growth in the region to continue in 2018 at about 1.3%, with “some deceleration consistent with the demographic challenge” of lost population, Friedman said.
RTO Readies Maine Resource Integration Study
ISO-NE on Thursday presented a draft of its Maine Resource Integration Study to the PAC, its first transmission planning study to employ queue clustering under Tariff revisions approved by FERC Approves ISO-NE Queue Clustering.)
The Northern and Western Maine grid was built to serve the small loads in the area and lacks capacity for the more than 5,800 MW of proposed new resources, mostly wind, that have filed interconnection requests. The 5,800 includes duplicate requests.
The resource integration report will provide the basis for system impact and facilities studies, which will identify the upgrades required for resources that proceed to interconnection and their cost allocations, said Al McBride, ISO-NE director of transmission strategy and services.
Maine 2027 Needs Assessment Moves Forward
The RTO’s draft Maine 2027 Needs Assessment study is ready for stakeholder comment, Jinlin Zhang, ISO-NE lead engineer for transmission planning, told the PAC.
Comments and notifications by proponents of state-sponsored requests for generation should be submitted to pacmatters@iso-ne.com by Dec. 3.
The study identifies reliability-based needs in Maine for the year 2027, considering future load distribution, resource changes in New England based on Forward Capacity Auction 11 results, and 2017 solar and energy efficiency forecasts.
Planners look at reliability over a range of generation patterns and transfer levels, how the study coordinates with the New Hampshire Needs Assessment, and all applicable NERC, Northeast Power Coordinating Council (NPCC) and RTO transmission planning reliability standards.
The completed draft report and intermediate study files will be presented to the PAC in the first quarter of 2018.
RTO Begins Zone Planning for FCA 13
ISO-NE has begun assessing transmission transfer capability, generation retirements and new resources to set capacity zone boundaries ahead of FCA 13 for 2022/23.
The process includes evaluation of the zones as determined for FCA 12, McBride said.
| ISO-NE
Each year, the RTO must identify weaknesses and limiting facilities that could impact the transmission system’s ability to reliably transfer energy in the planning horizon. Any new boundaries require a filing with FERC, McBride said.
The process of certifying transmission projects begins in October and is coordinated with that month’s Regional System Plan (RSP) Project List update to ensure consistency. Transmission owners are required to provide models and contingency definitions. The RTO will determine certifications by January; the list of certified projects will be presented at the January Reliability Committee meeting.
Transmission upgrades identified for Southeast Massachusetts/Rhode Island (SEMA/RI) are not expected to change the boundaries of the area. Planners do not expect such upgrades to be fully certified for FCA 13, nor will transfer limits be updated in time for that auction in 2019.
Any major resource retirements received for FCA 13 will be considered in the zone formation process, McBride said. No major retirements were received for FCA 12.
Time-Sensitive Tx Needs Determination
Pradip Vijayan, ISO-NE senior transmission planning engineer, made a presentation on how the RTO identifies time-sensitive transmission upgrades — those required within three years and thus not subject to the competitive solicitation process.
RTO officials consider when an upgrade will be required after identifying improvements in a needs assessment.
Needs identified from a short-circuit analysis are considered time sensitive unless they are driven by future projects that have an in-service date beyond three years of the completion of the needs assessment.
Steady-state needs observed at off-peak load levels are considered time sensitive. Those seen at peak load levels may or may not be time-sensitive.
The RTO will add a document detailing the process to its Transmission Planning Technical Guide, Vijayan said.
Tx Planning Assumptions Update
ISO-NE is continuing to update the probabilistic methodology and minimum load level used in its transmission planning assumptions, Director of Transmission Planning Brent Oberlin said.
The generator dispatches used in base cases in his report showed the potential for a significant number of generators to be simultaneously unavailable, especially in the Eastern Connecticut (ECT) area. ISO-NE said in October that it would revise the scope of its 2027 needs assessments for ECT, Southwest Connecticut and New Hampshire over stakeholder questions about dispatch modeling assumptions. (See “Tx Planners Rethink 2027 Needs Assessment,” ISO-NE Planning Advisory Committee Briefs: Oct. 18, 2017.)
The ECT data showed that up to 488 MW of generation could be unavailable at peak load. The largest generator in the ECT study area is Montville 6 (413 MW), with 13 other generators totaling only 253 MW, which shows that the presence of a single large generator in an area with a low number of smaller generators can skew the results, Oberlin said.
The new methodology solves the issue by recalculating the upper limit of generation outages using the probabilistic method by excluding the large generator for dispatches in which it is assumed in service. By applying this method to ECT, the maximum amount of generation unavailable is limited to 115 MW in cases with Montville 6 in service.
The new methodology lowers the minimum load level to 8,000 MW from 8,500 MW, correcting an error on the handling of Maine mill loads (currently 320 MW) in the evaluations, Oberlin said.
NERC announced Monday that its Board of Trustees had accepted the resignation of CEO Gerry Cauley, effective immediately, following his arrest for domestic abuse.
The organization said General Counsel Charles Berardesco will continue to serve as acting CEO while the board seeks a search firm to recruit a replacement.
“NERC has a talented staff and an experienced leadership team that is well-equipped to continue the forward momentum on key initiatives,” Board Chair Roy Thilly said in a statement. “I am confident we will continue to meet milestones and expectations going forward. NERC remains committed to maintaining the reliability and resilience of the bulk power system.”
A NERC spokeswoman declined to comment when asked whether Cauley would receive any severance payment. “Any personnel action is confidential,” she said.
NERC CEO Gerry Cauley (center) and General Counsel Charles Berardesco (to Cauley’s left) attend a NERC board meeting in New Orleans Nov. 9, hours before Cauley’s arrest for domestic abuse. Also pictured are Board Chair Roy Thilly (to Cauley’s right), and board members Jan Schori (left) and Frederick W. Gorbet (foreground). | NERC
NERC had placed Cauley on a leave of absence after his arrest for battery, a misdemeanor, for allegedly assaulting his estranged wife in the early morning of Nov. 10. The police report documenting his arrest states that his wife, Jean Cauley, sustained bruises and scratches and was experiencing a great deal of pain in her back.
Jean, a former probation officer and child abuse investigator for the state of Florida, posted a comment about the incident on her LinkedIn page Sunday: “Who knew that when I married a CEO — and me with a background in law-enforcement — [I] would be a victim of a violent crime by her husband to the point of a back being broken,” she wrote. “It shows that no one is exempt from domestic violence and that we should all support each other as women.”
Cauley, 64, had served as NERC CEO since January 2010, and was often the face of the reliability agency in hearings before FERC and Congress. By Monday afternoon, however, his biography and photo had been removed from the web page listing the organization’s management.
Pacific Gas and Electric has signaled it will challenge a California administrative law judge’s recommendation that the utility be granted only about 10% of the $1.8 billion in recovery it requested for the retirement of the Diablo Canyon nuclear plant in San Luis Obispo County.
The California Public Utilities Commission has scheduled final oral arguments for Nov. 28 over a joint settlement agreement filed by PG&E and interest groups regarding the plant, which the utility has proposed to shut down when its federal operating licenses expire in 2024 and 2025. PUC Administrative Law Judge Peter Allen on Nov. 8 approved the retirement plan but proposed that PG&E be allowed to recover about $190 million of the nearly $1.8 billion in requested rate recovery detailed in the settlement. Allen’s decision has no weight until voted upon by the five-member commission.
“While the proposed decision preserves several elements of the joint proposal, it differs in regards to certain key areas, including the employee, community and energy replacement programs,” PG&E said in a Nov. 8 statement, adding that it “strongly disagrees with these proposed adjustments.”
The utility said it thinks the proposed settlement is appropriate, and “we look forward to advocating for this in our comments back to the CPUC and during final arguments at the end of November.”
PG&E first filed the settlement it forged with environmental, labor and anti-nuclear groups in August 2016. It would replace output from the 2,240-MW facility with a portfolio of renewable resources, energy efficiency measures and energy storage. (See PG&E Files Diablo Canyon Shutdown Request.)
The utility requested approval to recover $1.3 billion for energy efficiency procurement, $363 million for employee retention and retraining, $85 million to mitigate impacts on the local community, $19 million for license renewal activities, and unspecified canceled capital project costs.
Allen’s proposed decision rejected the energy efficiency money and approved $172 million for employee retention and retraining, $19 million for license activities, and a portion of canceled project costs. He recommended that issues related to the procurement of replacement capacity be handled in an integrated resource planning proceeding.
The judge sided with the Office of Ratepayer Advocate (ORA) and Energy Producers and Users Coalition (EPUC), which noted that state policy already requires PG&E to first meet its resource needs through all available energy efficiency resources. PG&E has proposed to increase its approved energy efficiency goals by more than 53% for 2018-2024, which ORA and EPUC indicated would only be possible by lowering PUC’s cost-effectiveness threshold.
“ORA and EPUC make a good point — it is not clear that PG&E could actually procure over 50% more energy efficiency than a goal that is already supposed to include all cost-effective energy efficiency (unless PG&E procures energy efficiency that is not cost effective),” Allen said. “There is no reason to approve a $1.3 billion rate increase for a proposal that will most likely either fail to achieve its goal or will achieve a goal not worth reaching.”
Allen’s Nov. 8 proposed decision also took issue with a settlement provision that would replace the property tax paid to San Luis Obispo County with $85 million in ratepayer money, arguing that PG&E has no obligation to pay the taxes once the facility shuts down and that utility rates should be used for utility — and not government — services.
PG&E proposed shutting down both units at Diablo Canyon by 2025.
PG&E has proposed to replace Diablo Canyon with greenhouse gas-free resources in three tranches: 2,000 GWh of energy efficiency; 2,000 GWh of energy efficiency and renewables; and a voluntary 55% renewables commitment from PG&E. The utility said additional resource procurement could be required to replace Diablo Canyon, the two units of which began operating in 1985 and 1986. The plant is used as a system resource and not for local reliability, and its output is exported on the bulk transmission system.
The settlement is supported by the Natural Resources Defense Council, Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.
Protests against the settlement were filed by California Large Energy Consumers, Californians for Green Nuclear Power, EPUC, several cities, the Sierra Club, Shell Energy North America, SolarCity, public interest groups and others.
After a 25-day public comment period, the ALJ’s proposed decision will be forwarded to the PUC. PG&E has requested that the commission reach a decision on the settlement by the end of the year.
MARLBOUROUGH, Mass. — ISO-NE is “in the final throes” of a stakeholder process to reach agreement with the New England Power Pool on a two-settlement market construct to integrate state-sponsored renewable energy resources into its wholesale market, CEO Gordon van Welie said last week.
Speaking at the Northeast Energy and Commerce Association’s Power Markets Conference on Nov. 14, van Welie said, “We plan to bring this to a vote at the upcoming NEPOOL [Participants Committee] meeting in December and then are going to file it [with FERC] in the December time frame.” He referred to the conference as a “quasi NEPOOL meeting,” considering that most attendees also participate in the organization’s stakeholder meetings.
As part of NEPOOL’s Integrating Markets and Public Policy (IMAPP) process begun in 2016, the RTO this year came up with a two-tier market concept called Competitive Auctions with Sponsored Policy Resources (CASPR). (See “CASPR May Exclude New Resources from Substitution Auction,” NEPOOL Markets Committee Briefs.)
Van Welie said CASPR “is creating the opportunity for existing resources that have capacity obligations and that wish to retire to trade out their obligation with incoming state-sponsored resources in a manner that doesn’t affect price formation in the primary auction.”
“As much as the states would like to see that their renewable contracts get automatic credit in the Forward Capacity Market, that would run counter to the other objective that we have (aside from reliability), which is to maintain price formation in the capacity market,” van Welie said. “CASPR will tend to accelerate the retirements of the marginal units, with significant payout opportunities for some of the older resources that wish to retire.”
Seeking Broad Consensus
Sebastian Lombardi, an attorney with Day Pitney who serves as counsel to NEPOOL, said, “We’re hoping for consensus because NEPOOL can’t have an affirmative institutional position without some broad agreement being reached. Broad agreement has not been reached yet.”
The NEPOOL Markets Committee considered a number of modifications to CASPR, he said.
“Although some of those proposals were close to getting broad support, at this stage none of them have reached the requisite support needed for NEPOOL approval, but sometimes three weeks is a lifetime in a stakeholder process,” Lombardi said. “Folks have been discussing this for a long time and we’re now getting to the endpoint and folks are going to have to make some hard decisions.”
Christopher Geissler, an economist at ISO-NE, said that while a number of stakeholder amendments did not pass at the Markets Committee, they could be voted on again by the Participants Committee. For context, he said, stakeholder support in this scenario means a 60% vote by the committee.
“We’ve made a number of changes to our design on the basis of stakeholder feedback and we continue to elicit and evaluate stakeholder ideas,” Geissler said. “However, while stakeholder support is important, we also feel that the design has to meet the objectives that we set out at the beginning of the process, so just because something receives stakeholder support doesn’t mean that it’s something the ISO will support. It also has to be good market design.”
Lombardi added that New England has a unique set of rules and governance arrangements whereby “if NEPOOL were to support something that was different from what the ISO wants to file, more than one proposal could be teed up to FERC on equal legal footing, which would provide FERC some optionality.”
Not So Fast
Brett Kruse, vice president of market design for Calpine, gave the NEPOOL talks a 30 to 40% chance of success and described some of the obstacles to reaching an agreement.
For example, the current renewable technology resource exemption is being challenged in federal court, with briefings due Jan. 12, 2018. Kruse said only a couple generators support the CASPR proposal as is, but more would support it if it was modified to protect price formation. He suggested that Calpine’s bid shading amendment might win ISO-NE support, particularly as it is already supported by the RTO’s internal and independent Market Monitors.
In addition, generators do not support an amendment proposed last week by the New England States Committee on Electricity for a 200-MW “backstop” allowing entry of sponsored resources around CASPR in perpetuity.
“I look at CASPR as an interim solution; I think that’s the way the ISO has talked about it,” Kruse said. “I’m not that positive on the long-term outlook for markets here in New England. Now will that be five years, 10 years? I can’t see it getting to 20 years. But even if we get something like this done, I think all that we’ll be able to do is slow down the convergence.”
Although Calpine is expanding its retail and commercial load-serving business in New England, the company is not looking to develop any new generation other than wind because of Massachusetts’ solicitation for thousands of megawatts of clean energy.
“The fundamental stuff shifted because we tend to take the state at their word,” Kruse said. “A goal is one thing, a mandate is another, a law is something else. A lot of people I talk to believe there’s no way they’re going to be able to build that much offshore wind — it’s crazy, it will cost way too much money. But when the legislature puts it in a law and the governor signs it, we believe. So we believe all that stuff’s going to come in that shifts all the underlying fundamentals.”
Regulatory Risk Perceptions
Todd Schatzki, vice president of Analysis Group, said the region’s desire to transition to a low-carbon future is driving the market. “But moving from desire to developing market designs and public policies that send effective price signals — we’re not there yet. Now we have the dilemma of legislators entering the markets through the back door,” he said.
Dan Dolan, president of the New England Power Generators Association, which represents 80% of the region’s generating capacity, said regulatory risk is what he hears about most from his members.
“It’s the uncertainty of what’s next: What is the next large-scale procurement coming from a state?” Dolan said. “It’s those issues that then make investing in the tens of billions of dollars in assets that we have here very challenging. … I challenge you to find another sector of the economy that does not have guaranteed rate recovery and a rate of return investing any multiple close to that in new infrastructure in New England. We are the last major manufacturers in New England.”
Darren Matsugu, senior manager for market design and integration at the Independent Electricity System Operator in Ontario, said his ISO has only 8% natural gas-fired generation, compared to nearly 50% in New England. The Canadian province’s Legislative Assembly voted in 2003 to phase out coal, and the last coal plant there closed in 2014.
“The majority of our system’s installed capacity comes from very low marginal cost resources, whether it’s from hydro resources, from nuclear, or from solar and wind,” Matsugu said. “Along with the impact of lower natural gas prices, we’ve seen a significant decrease in the level of our wholesale energy prices. Often at the shoulder periods we fluctuate in the $0 to $10/MWh range.”
Beth Garza, director of ERCOT’s Independent Market Monitor and vice president at Potomac Economics, provided some perspective for the New Englanders struggling to achieve or accommodate the public policy goals set forth by the region’s six states.
“Unlike other areas that have centralized clean energy goals, Texas has not had that, but the markets are responding as if we did,” Garza said. “Texas has become a leader in wind generation simply because the zero-cost resource offers investors a good chance to make a profit.”
FERC last week approved two requests by FirstEnergy Solutions (FES) to sell power to Potomac Edison and West Penn Power. All three companies are subsidiaries of FirstEnergy (ER17-1267, ER17-1272, ER17-1559). The agreements are retroactive to June 1.
FES won the bids through competitive solicitations from the affiliates to serve customers who do not take service from competitive retail suppliers. Potomac serves customers in Maryland and West Virginia; West Penn’s customers are in western Pennsylvania.
FERC uses standards set out in its 1991 Edgar Electric Energy (ER91-243) and 2004 Allegheny Energy Supply rulings (ER04-730) to prevent utilities from self-dealing. The commission determined that the affiliate deals met the four criteria of transparency, definition, evaluation and oversight.
CARMEL, Ind. — MISO will next month submit two filings with FERC to further refine its new generation interconnection process, while a third filing early next year will seek to facilitate connections for merchant HVDC lines, the RTO said last week.
MISO Manager of Resource Interconnection Neil Shah said the two near-term filings — one to limit the amount of time interconnection customers can change their megawatt values and the other to update the interconnection request form — serve as a “clean up” to implement details the RTO missed in its filing to redesign the queue.
The first revision would shorten the period for generation owners to change the capacity volume associated with network resource interconnection service (NRIS), moving the final selection to the second decision point in the queue rather than just before MISO begins an interconnection facilities study.
The second change would update the interconnection request form that prospective generation owners fill out upon entering the queue to include options for external NRIS and MISO’s fast-track request option for small generating facilities.
Shah said he did not expect the filings to elicit protests from stakeholders, who offered no public comment on the changes during a Nov. 15 Planning Advisory Committee meeting.
Wind on the Wires’ Natalie McIntire said she hoped the filings were as harmless as Shah characterized. “It’d be nice to finally have some queue changes that are uncontested,” she joked.
The apparently benign queue changes come as some stakeholders are already calling for a fundamental reconsideration of the interconnection queue not even a year after the RTO rolled out a redesign of the process.
Earlier this month, EDF Renewables asked MISO to consider a two-stage queue instead of the RTO’s selected three-stage design, while FERC denied a request to rehear its approval of the new design, which generation developers said should include a fast-tracked queue for vetted projects. (See EDF Asks MISO to Revisit Queue Overhaul.) EDF will return to the Steering Committee in January to make its case for a streamlined queue.
HVDC Interconnection
Another interconnection-related filing in January or February would revise MISO’s Tariff to allow merchant HVDC lines to inject energy into the RTO’s transmission system at certain points of connection. Under the proposed rules, merchant HVDC would advance through the queue much like other interconnection customers and earn injection rights. However, MISO would draw a distinction between “injection rights” and “interconnection rights.” A merchant HVDC owner could only secure injection rights, and its associated generator must also line up in the queue and reference the HVDC injection rights. MISO would then convert the injection rights into interconnection rights for the generator without further queue studies. Only then would the rights be usable to offer energy or capacity into the MISO markets.
In response to a question by Indiana Utility Regulatory Commission adviser Dave Johnston, Shah said there are currently HVDC projects on hold in the queue, most of which are requesting injection rights into MISO.
WOW consultant Rhonda Peters said it’s still unclear how MISO will treat a merchant HVDC line wishing to withdraw from the system and inject into another balancing authority.
“As of now, these procedures are not supported,” Peters said.
Shah said some existing Tariff provisions would allow for withdrawal. “There’s some work needed, but it’s mostly educational in my mind,” he said.
Peters countered that the “thousands of megawatts” that HVDC lines are able to move is “unprecedented” and MISO’s current $4,000/MW upfront fee for the definitive planning phase is prohibitively high and will hinder the connection of projects. She asked for MISO to consult with other RTOs about their merchant HVDC interconnect policies.
Shah said he would take those suggestions into consideration and asked stakeholders to provide other input by Dec. 1. More discussion on merchant HVDC interconnection procedures is planned for the December PAC meeting.
