FERC last week approved CAISO Tariff changes 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.
Black start refers to the ability of a generating unit to begin operating without assistance from the electric grid. Such units are needed to restart other generation and restore the grid after widespread outages; they have certain requirements under the ISO’s Tariff.
CAISO needs additional black start capability in the San Francisco area
The changes reorganize and consolidate certain black start provisions, create rules for technical requirements and operating tests, and remove outdated provisions. They also designate the cost of incremental black start as a reliability cost and allocate it to the transmission owner in the area where the units are located (ER17-2237).
The new black start provisions entail significant involvement of the affected TO — in this case Pacific Gas and Electric — in drawing up technical specifications and vetting proposals from resources bidding into the solicitation. The ISO would have authority to accept or reject a TO’s recommended resources. PG&E supported the changes and cost allocation method.
Under the new rules, CAISO will use a cost-of-service approach to compensate selected resources, rather than provide a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.
FERC said the revisions improve the reliability and clarity of the Tariff.
“Because individual black start capacity resources do not benefit all parts of the system equally, it is just and reasonable to recover these costs from a participating transmission owner where the resource is located and serves the reliability need,” FERC said. No parties objected to the cost allocation, and the benefits were roughly commensurate with the costs, the commission said.
To comply with CAISO rules, black start generators must make a minimum number of starts, operate in standalone and parallel modes, be able to pick up load during start-up load, produce and absorb reactive power, and have communication and control equipment.
A cool summer and the impact of Hurricane Harvey drove NRG Energy third-quarter earnings sharply lower, but the company still sees bright days ahead, according to CEO Mauricio Gutierrez.
NRG earned $171 million ($0.53/share) last quarter, compared with $402 million ($1.27/share) in the same period last year. Revenues were down 10.9% to about $3 billion.
Gutierrez | NRG
Gutierrez said during a Nov. 2 earnings call that although the company is “on track” to transform itself through cost-saving measures, the third-quarter results led the company to lower its full-year earnings before interest, tax, depreciation and amortization (EBITDA) guidance to $2.4 billion to $2.5 billion from the previous $2.56 billion to $2.76 billion.
“In Texas we saw both a major hurricane and the coolest August since 2004, with cooling degree days 13% below normal, and in the Northeast, cooling degree days were on average 8% below normal for July and August,” Gutierrez said. He noted that ERCOT summer wholesale prices fell 43% below expectations. Mild weather across the East and in Texas eliminated any opportunity to benefit from scarcity pricing.
NRG attributed one-time financial impacts of $40 million to Hurricane Harvey, evenly divided between its generation and retail operations in Texas. About 80% of the company’s baseload generation on the Gulf Coast was available during the worst part of the storm, and 95% has been restored to date.
Brighter Side
NRG’s retail business continues to improve its operating efficiencies, customer acquisition and retention, which partially offset the impacts of milder summer weather, especially in ERCOT, Gutierrez said.
He said certain cost and margin enhancements will start impacting the company’s bottom line next year, as well as the sale of subsidiary NRG Yield and its renewables assets, which is expected to be completed this year and return up to $4 billion. The company continues to use excess cash to deleverage itself, he said.
“Since our second-quarter call, we have taken another $600 million of debt out of our capital structure, completing our 2017 capital allocation,” Gutierrez said.
He also pointed to improving market conditions in Texas as a particular bright spot for the company.
| NRG
“Despite the absence of extreme weather this summer, ERCOT fundamentals remain strong. ERCOT’s 2017 peak load of 69.5 GW was up nearly 2% over the five-year average and came in just shy of the 2016 peak,” he said.
| NRG
The recently announced retirement of more than 4 GW of generating capacity in ERCOT puts further pressure on a market with already strong fundamentals, Gutierrez said. Vistra Energy on Oct. 6 announced plans to retire three aging coal-fired units in East Texas with a combined capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices. (See Vistra Energy to Close 2 More Coal Plants.)
“For summer of 2018, these new retirements and asset delays alone will put ERCOT at the lowest reserve market on record, which is suspected to be somewhere between 10 and 11%,” Gutierrez said. “Other changes, such as delayed new builds and new industrial demand, could lower these numbers even further.”
But while the retirements are nudging up forward markets, prices are still below what is needed to justify new builds, he pointed out.
Calls to Action on Market Reform
In response to an analyst question about whether NRG would consider selling parts of its Texas portfolio, Gutierriez said, “Right now we’re very comfortable with our Texas portfolio.” He said the capability of NRG’s generation fleet aligns well with its retail loads.
But while the recent retirements are improving market health, ERCOT must do more to strengthen markets and should recognize the locational value of power plants, he said.
“Reliability and resiliency are important attributes to the grid, and we will continue to work with ERCOT to ensure that generators close to load centers are compensated for all the benefits they provide.”
Beyond the positive developments in ERCOT, Gutierrez said NRG sees several other “calls to action” occurring for market reform.
“As the power grid continues to undergo significant change — low gas prices, renewable penetration and attempts for out-of-market subsidies for uneconomic generation — regulatory bodies and other stakeholders are taking note,” Gutierrez said. “These have led to several significant catalysts, from the [Department of Energy] staff report on competitive markets and [Notice of Proposed Rulemaking], to PJM’s proposed market reforms. I cannot recall another time when there has been such urgency and reach across ISOs to improve competitive energy markets.” (See Market Summit Tackles Ongoing PJM Changes.)
Gutierrez said NRG has been optimistic about market developments in PJM, especially around the introduction of Capacity Performance.
Asked to rank the most promising areas for growth, Gutierrez responded that NRG aims to balance its generation and retail businesses and is focused on perfecting an integrated platform.
“A lot of the generation is going to be driven by our retail needs and how we grow retail, and a lot of our retail will be driven by where we have generation,” he said. “We’re still long in generation in PJM. We have a ways to go before we have a balanced portfolio like we have in Texas. … Just in terms of market structure, I would put PJM No. 1, New England No. 2 and New York No. 3.”
Eversource Energy last week reported third-quarter earnings of $260.4 million ($0.82/share), down nearly 2% from the same quarter in 2016. Earnings for the first nine months of 2017 were $750.6 million, up 5% from earnings of $713.1 million in the same period last year.
Lembo | Eversource
“The primary drivers of our [quarterly] results were higher electric transmission earnings being offset by lower electric distribution results,” Eversource CFO Phil Lembo told analysts in a Nov. 2 conference call.
A higher rate base boosted transmission earnings by 10.7% to $99 million, the result of the company investing $600 million in its transmission system this year through September, with just less than $1 billion planned for the full year, Lembo said.
He attributed a 7.4% drop in earnings for the company’s electric distribution and generation division to lower sales reflecting mild weather in July and August. Cooling degree days in Boston were down nearly 34% for the quarter compared with last summer and 8% below normal, he noted.
In addition to lower electric revenues, the company recorded higher property tax, depreciation and interest expense in the quarter, but was able to offset much of the negative impact by controlling costs, Lembo said. Eversource’s natural gas distribution segment posted a net loss of $6.2 million in the third quarter and earnings of $49.1 million in the first nine months of 2017, compared with a net loss of $7 million in the third quarter of 2016 and earnings of $51.9 million in the first nine months of 2016.
“For the long term, we continue to project 5 to 7% [earnings per share] growth,” Lembo said. “We are pleased with our results today and remain comfortable with our 2017 guidance, although I’d like to see some very cold weather in November and December, and that would really help us reach the higher end of our earnings range for ’17.”
Future Developments
Lembo noted that Eversource last month filed with the New Hampshire Public Utilities Commission to sell its remaining 1,200 MW of generation assets in the state for $258 million, and expects the two sales to be completed late this year or in early 2018. On the company’s proposed merger of subsidiaries NSTAR Electric and Western Massachusetts Electric Co., he said state regulators should issue a decision by Nov. 30 on the merger and grid modernization, and a decision on performance-based rate design by Dec. 29, with rates to become effective in January 2018.
| Eversource
Lee Olivier, Eversource executive vice president for business development, said the company’s Northern Pass transmission project achieved an important milestone Nov. 1 when utility subsidiary Public Service Company of New Hampshire filed a settlement agreement on the lease terms for most of the 192-mile route for the line.
“The settlement was reached with New Hampshire PUC staff and the Office of Consumer Advocate, the two principal intervenors in the case,” Olivier said. “We expect the New Hampshire PUC approval of the settlement by the end of the year. Taken together, we are very pleased with our current position in the siting process, with significant progress being made in all venues.”
Eversource has also partnered with Ørsted, formerly DONG Energy, to form Bay State Wind for the offshore wind solicitation in Massachusetts.
“We are preparing our bid into the Massachusetts offshore wind [request for proposals], which is due Dec. 20,” Olivier said. “Given the vast experience of Ørsted in European offshore wind and our knowledge of New England markets and transmission, we believe we will be able to submit a highly compelling set of proposals for review by the evaluators.”
MISO predicts the 2018/19 planning year will require a reserve margin just more than 17%, a figure that’s been steadily increasing over the years.
Based on its annual loss-of-load-expectation (LOLE) analysis, MISO expects the planning period to require a 17.1% reserve margin for installed capacity (ICAP) and 8.4% margin for unforced capacity (UCAP), the latter of which represents ICAP minus forced outage rates. The RTO will use the margins along with the latest load forecasts to create its enforceable planning reserve margin requirement before April’s capacity auction.
| MISO
Systemwide, MISO predicts it has about 150 GW of ICAP and almost 139 GW of UCAP to meet a nearly 126 GW expected peak demand for the June 2018-May 2019 period. The RTO’s planning reserve margin assumes the inclusion of 4,764 MW of firm UCAP and 2,331 MW non-firm UCAP from external resources.
MISO’s needed reserve margin has been on the rise since 2013. Last year, MISO predicted 15.8% for ICAP and 7.8% UCAP reserve margin for the 2017/18 planning year, up from 2016/17’s 15.2% and 7.6% values. (See MISO 2017/18 Planning Reserve Margin at Nearly 16%.) All local requirements increased from the 2017/18 planning year, the RTO noted.
Speaking during a Nov. 2 Reliability Subcommittee conference call, MISO senior engineer William Buchanan said the increase is primarily driven by an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO this year added a new modeling step to capture economic load uncertainty that increases the risk associated with high peak loads, also boosting the reserve margins.
Despite the yearly increases, MISO predicts reserve margins will begin to plateau. According to the LOLE analysis, they will largely hold steady because of similar forecasts over the next decade even as peak demand exceeds 129 GW by the 2023/24 planning year. The LOLE analysis found that through 2027, MISO’s ICAP reserve margin will fluctuate between 17.1 and 17.2% while the UCAP reserve margin will oscillate between 8.3 and 8.4%.
Consolidated Edison’s third-quarter earnings fell 8% to $457 million ($1.48/share), a drop the company attributed to changes in its rate plan and regulatory charges, as well as the impact of weather on steam revenues. The new rate plan includes changes in the timing of recognition of annual revenues between quarters.
Con Edison Forecasted Average Rate Base Balances ($ in millions) | ConEd
“This is an exciting time in the energy industry,” CEO John McAvoy said during a Nov. 2 earnings call. “We’re incorporating renewables into the grid at an increasing rate, we’re using data analytics to provide customers with more information about the way they’re using energy and how they can save, and we’re working on programs to increase electric vehicle use and access to charging stations. At the same time, our $1 billion storm hardening program after Superstorm Sandy has made our system more reliable than ever five years later, having already prevented 250,000 power outages due to our investments.”
The company updated its guidance on adjusted earnings per share for 2017 slightly to $4.05 to $4.15/share. The previous range was $4 to $4.15/share.
Con Ed also said it is unable to estimate the amount or range of possible costs related to an April 21 subway power outage in New York City.
ConEd plant on the East River at 15th Street in Manhattan, New York City
After investigating the outage, the New York Public Service Commission in August issued an emergency order requiring the company to inspect electrical equipment serving the Metropolitan Transportation Authority’s system, analyze power supply and power quality events affecting subway signaling services, provide new monitoring and other equipment, and file monthly reports with the commission on all activities related to the subway system. The commission last month approved another order extending the subway outage oversight beyond its original 90-day limit but has not yet issued the second order.
FOLSOM, Calif. — In a move that met criticism from some stakeholders, CAISO’s Board of Governors on Thursday approved two measures intended to prevent the early retirement of unprofitable — but needed — generation in California.
The board approved a reliability-must-run (RMR) contract for Calpine’s Metcalf Energy Center, saying it was an undesirable but necessary measure to maintain electric grid reliability in the Silicon Valley.
Despite the unanimous vote, the board expressed unhappiness about approving the contract, an out-of-market payment to keep the 605-MW natural gas-fired plant from retiring.
Governor Ashutosh Bhagwat said: “I am going to hold my nose very, very hard.” He added that “I understand the problem, but I think this is going to be a recurring issue and we need to come up with a solution.”
Governor Mark Ferron said he was tempted to vote against the RMR “because I am opposed to the process and the situation we find ourselves in.” But, he added, “to vote against this contract is not a risk that we should play with.”
The Metcalf RMR is the third such contract awarded to a Calpine plant this year, sparking concerns among industry participants that the CAISO market and California’s resource adequacy (RA) process are not supporting generation needed for future reliability. Calpine in June told the ISO it planned to remove the plant from dispatch on Jan. 1, 2018. The RMR contract was developed in a relatively short time frame after the ISO determined Metcalf was needed for local reliability. (See Metcalf Reliability-Must-Run Draws Scrutiny.) Metcalf’s designation as RMR follows similar contracts approved earlier this year for Calpine’s Yuba City and Feather River plants. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Representatives from the California Public Utilities Commission, Pacific Gas and Electric and Cogentrix spoke against the agreement at the meeting.
CAISO CEO Steven Berberich told the board that use of RMR “is not at all how we want to handle procurement.” He added that “the RMR is symptomatic of a bigger problem, which is that resource adequacy is no longer able to meet the needs of the system.” He said that the ISO does not want to frequently approve RMR agreements, and that procurement should be done through the RA process.
Board Approves CPM ROR Changes
In addition to the Metcalf RMR, the board approved a separate, broader program that will pay generators to stay in service to meet reliability needs. The Capacity Procurement Mechanism Risk-of-Retirement (CPM ROR) program expands the existing CPM process to include procurement of at-risk capacity needed for the next RA compliance year.
The program includes two application windows each year — in April and November — for three types of ROR designations. As the ISO developed the process, some stakeholders — including the PUC — raised concerns that inclusion of the April window gives resources undue insight into price discovery for the commission’s RA program, which occurs in October. The commission was concerned “that moving a CPM ROR determination to a date prior to the conclusion of the year-ahead procurement process will result in front-running the RA bilateral procurement process.” (See CAISO Participants Question Retirement Program.)
CAISO added the April window based on requests from generation owners, who said they needed the option of a designation earlier in the year for planning reasons. CAISO changed the proposal to require that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds. Some have criticized that the ISO would accept an attestation in that regard.
CAISO Infrastructure and Regulatory Policy Manager Keith Johnson told the board that the PUC’s 2019 RA proceeding is an opportunity to address the issues that have been identified. The ISO will evaluate potential modifications to the RMR construct to better align with the current environment, he said in a presentation to the board.
Keith Casey, CAISO vice president of market and infrastructure development, repeatedly took to the microphone on Thursday to rebut criticisms of both the RMR and CPM ROR. He acknowledged that the state’s RA program and ISO markets need fixes, but there is not enough time to develop them in an adequate time frame.
The ISO would normally let the RA procurement process run its course in October before signing an RMR agreement, but Calpine told it that the normal time frame would not be workable. Calpine also indicated it was not interested in the CPM ROR program, leaving the RMR as the best option, Casey said. “We don’t want to be one wire away from blacking out Silicon Valley,” he added.
“The issue for me is one of timing,” Casey said. Changing the RA construct is going to be a long and difficult process, and with increasing retirements, “we have got to have some tools to ensure that resources that are critical on the system can be retained.”
The board on Thursday also approved modifications to an incentive that is meant to ensure that RA resources can meet their must-offer obligations and provide replacement capacity if the resource has a forced outage. It changes the Resource Adequacy Availability Incentive Mechanism (RAAIM) calculation to separately calculate generic RA used for system load and flexible capacity, among other changes, according to an Oct. 25 letter from Casey to the board.
Lastly, the board voted to increase its retainer compensation to $40,000/year, which CAISO said is well below the retainers paid to the governing boards of the nation’s other RTOs/ISOs.
ISO-NE has barred Invenergy’s planned Clear River Energy Center Unit 2 from offering into February’s capacity auction because of permitting delays resulting from local opposition to the natural gas-fired plant in Burrillville, R.I.
Clear River Energy Center project rendering | Invenergy
Invenergy publicized ISO-NE’s decision for Forward Capacity Auction 12 for 2021/22 in a filing Wednesday to the Rhode Island Energy Facility Siting Board.
The board was scheduled to hold its final evidentiary hearings on the $1 billion project this week but postponed them until December after calling for additional public comment hearings on the plant’s water plan. The plant will have two 485-MW natural gas units with fuel oil backup.
In September, the company announced it had reached agreements with the Narragansett Indian Tribe and water trucking company Benn Water & Heavy Transport to serve as supplemental water suppliers for the plant if it needs more than the primary supplier, the Town of Johnston, R.I., can provide. State regulators had required the company to identify the backup suppliers following a lawsuit by the Town of Burrillville and the Conservation Law Foundation challenging the Johnston supply contract.
The company said the plant will need about 15,000 gallons of water daily, which it says is “90% less than similar plants in the region.”
Invenergy said ISO-NE cited the permitting problems and delays in ordering equipment, although the company said the current schedule would still have allowed it to begin operations by 2021.
“Although Invenergy considered appealing this decision to [FERC], Invenergy could not dispute that there have been permitting delays, and as such, the likelihood that the FERC would overturn ISO-NE’s FCA qualification decision was determined to be remote,” the company said.
Jerry Elmer, senior attorney with the Conservation Law Foundation, told the Providence Journal that “this shows that even the ISO agrees that [the plant] is not needed.”
But in its filing with the siting board, Invenergy included an updated report from PA Consulting Group asserting that the need for the plant is unchanged. The company also said the RTO has told it that Unit 2 is eligible to participate in FCA 13 in 2019.
The report, which assumed a one-year delay in Unit 2’s online date to June 1, 2022, said the delay had no impact on the four findings by the Rhode Island Public Utilities Commission indicating need: Unit 1’s clearing of FCA 10; a significant amount of capacity at-risk for retirement; the state’s location in an import-constrained zone; and the need for capacity above the RTO’s net installed capacity requirement.
Unit 1 is scheduled for commercial operation no earlier than June 2020.
The tax bill introduced by House Republicans on Thursday would trim the wind production tax credit by more than a third and eliminate the credit for electric vehicles while maintaining the tax credit for Southern Co.’s troubled Vogtle nuclear project.
The proposal would repeal the inflation adjustment for the PTC, effectively reducing the PTC from 2.3 cents/kWh in 2016 to 1.5 cents for projects begun after Nov. 2.
| AWEA
The American Wind Energy Association complained that the proposed Tax Cuts and Jobs Act “reneges” on the deal Congress made in 2015, which would phase out the PTC completely over five years.
AWEA CEO Tom Kiernan said the bill is “a retroactive tax hike” that would “pull the rug out from under 100,000 U.S. wind workers and 500 American factories, including some of the fastest growing jobs in the country.”
Under the 2015 legislation, wind projects that started construction in 2015 and 2016 receive the full PTC of 2.4 cents/kWh. Projects that begin construction in 2017 receive 80% of the credit, with those beginning in 2018 reduced to 60% and those in 2019 getting 40%. The credit would be eliminated for projects begun in 2020 and beyond.
Eliminating the inflation adjustment would boost tax receipts by $12.3 billion through 2027, according to a summary released by Republicans on the House Ways and Means Committee.
AWEA also said the law would unfairly change what constitutes the start of project construction. “Investors who put billions of dollars into factory orders and construction contracts cannot go back in time to meet the revised requirements,” it said.
Under current rules, a project is deemed to have commenced construction when it has passed a “physical work” test or shown that 5% or more of the total cost of the facility was paid or incurred. The physical work test is met by activities such as the beginning of excavation for turbines’ foundations or work on step-up transformers.
Developers are required to make “continuous progress” toward completion once construction has begun and must complete the project within four calendar years after the year in which it began construction. The new bill would eliminate the 5% “safe harbor,” disqualifying projects “unless there is a continuous program of construction.”
The wind industry is just one of the potential losers in the bill, which also eliminates the $7,500 tax credit for purchasers of electric vehicles. That would be more bad news for Tesla, which on Wednesday reported a $619 million quarterly loss and said it would not meet its goal of producing 5,000 Model 3 cars per week in 2017. Tesla shares dropped 6.8% Thursday.
The bill also would eliminate the permanent 10% investment tax credit for commercial-scale solar and geothermal power.
But there are also some energy winners.
The Treasury Department would forgo $1.2 billion through 2027 by “harmonizing” the expiration dates and phase-out schedules for ITCs on solar, geothermal, fuel cell, microturbines, combined heat and power system and small wind facilities.
In addition, the bill would remove a 2020 deadline for nuclear plants to claim the 1.8 cents/kWh nuclear production tax credit, a change needed to allow Southern’s overbudget and behind-schedule Vogtle Units 3 and 4 to claim it.
The credit applies to the first 6,000 MW of new nuclear capacity. Because the Vogtle project totals 2,200 MW, and South Carolina Electric & Gas’ V.C. Summer Units 2 and 3 have been canceled, it “will leave a significant amount of remaining capacity that future small modular or advanced reactor projects will be able to access,” the Nuclear Energy Institute said.
LITTLE ROCK, Ark. — SPP’s Regional State Committee will later this month begin taking a lead role in Mountain West Transmission Group’s integration into the RTO, with the first of what will likely be many calls and meetings on the subject.
SPP has identified the RSC as one of the key stakeholder groups in Mountain West’s pursuit of membership. The committee has primary responsibility for cost allocation, financial transmission rights, resource adequacy and remote resources planning within the RTO’s current 14-state footprint.
“This is a wonderful strategic opportunity for SPP,” CEO Nick Brown told RSC members Oct. 30. “Expanding our market and lowering our administrative rates both carry significant benefits to SPP members and significant benefits to the Mountain West Transmission Group.
“Now’s the time to engage … please stay that way,” Brown implored. “The next couple of months will be critical.”
SPP will use a commissioners’ forum to work through several policy issues as the integration process moves into more open forums. Some work will still take place behind closed doors, with the Strategic Planning Committee holding executive sessions Nov. 21 and Dec. 4. (See SPP, Mountain West Integration Work Goes Public.)
Mountain West has asked SPP to expand the RSC to include a group consisting of just the Western states, resulting in a single committee with two regional divisions. It has also proposed a Westside Transmission Owners Committee that would have decision-making authority over cost allocation, zonal changes and transmission revenue requirements in what would become the west side of the RTO.
SPP Vice President of Operations Bruce Rew told the RSC that the Integrated Marketplace continues to work “very well,” despite the growing influence of wind energy in the RTO’s footprint.
Rew said wind will likely become the No. 2 fuel source for 2017, behind only coal. Coal has accounted for 46.9% of the RTO’s fuel mix year-to-date, with wind averaging 22.0% and gas 19.4%, respectively.
Almost 16.7 GW of wind energy is installed and operational in SPP, with another 690 MW registered but not yet operational.
Rew said the RTO came close to setting new records for both wind production and summer peak demand during the third quarter. Wind production peaked at 13.32 GW on Sept. 21, just short of the record of 13.34 GW set in April. On Sept. 22, SPP averaged just more than 12 GW of wind energy for the entire day, Rew said.
Wind penetration during the quarter peaked at 49.41% of system load on Sept. 8. SPP’s record is still 54.47% wind penetration, set in April.
Summer demand peaked at 50.57 GW in July, not far off the all-time peak of 50.62 GW set in 2016.
| SPP
Rew said 197 market participants are currently active in the markets. Of those, 130 are classified as financial-only and 67 as asset-owning. He said the day-ahead market was delayed from posting once in the last 12 months, and the real-time balancing market has successfully solved 99.87% of all intervals.
Kansas’ Albrecht Elected as RSC’s 2018 President
The RSC unanimously elected the Kansas Corporation Commission’s Shari Feist Albrecht as its president for 2018, replacing Missouri Public Service Commissioner Steve Stoll. Albrecht currently serves as the committee’s vice president.
South Dakota Public Utilities Commissioner Kristie Fiegen will become the committee’s vice president next year, with Dennis Grennan of the Nebraska Power Review Board replacing Fiegen as the RSC’s secretary and treasurer.
The committee also approved a 2018 budget of $370,500, with the understanding that $50,000 to $150,000 could be allocated for consulting expenses for its Mountain West work.
PacifiCorp and NV Energy can sell power into the Western Energy Imbalance Market (EIM) at market-based rates, FERC has ruled, reversing a previous finding that had restricted the companies to submitting only cost-based offers (ER17-2934).
The commission imposed the restrictions in late 2015 after finding the two Berkshire Hathaway Energy affiliates had failed to prove that they wouldn’t exercise horizontal market power within the market. At the time, the EIM comprised only the CAISO, PacifiCorp-East (PACE), PacifiCorp-West (PACW) and NVE balancing authority areas (BAAs). It now includes Arizona Public Service, Puget Sound Energy and Portland General Electric.
FERC’s decision goes a long way in relieving PacifiCorp’s market restrictions in the interior West. The utility can now sell into the PacifiCorp-East and PacifiCorp-West areas at market-based rates, and will be able to do the same in Idaho Power’s territory starting next April when that utility joins the EIM | WECC
In their August joint filing with FERC, PacifiCorp and NVE said that the bidding restrictions were “no longer appropriate” because both companies now meet conditions for EIM participation set out in previous FERC orders. They also contended that reliance on cost-based bids ran “contrary to organized market design” and presented the risk of unrecovered costs during some market intervals. (See Berkshire Companies Request EIM Rate Authority.) The utilities contended that the restrictions have created inefficiencies in how they manage hydroelectric resources and respond to intraday fluctuations in natural gas prices.
The companies also provided FERC with analysis by Charles Rivers Associates (CRA) demonstrating there has been little congestion between EIM BAAs since the entry of NVE into the market, supporting the argument that member BAAs should not be considered submarkets subject to market power — a key concern for FERC.
The CRA analysis examined EIM price data from December 2015 to November 2016 to determine the frequency of price discrepancies between CAISO and other EIM BAAs — an indicator of transmission constraints that could warrant concerns about local market power.
CRA’s conclusion: In the 15-minute market, transmission paths appeared to be congested enough to create price separation only 0.7 to 2.4% of the time depending on the BAA; the five-minute market experienced congestion during 0.3 to 6.2% of all intervals, with the higher percentage representing periods when prices deviated by just 1 cent/MWh, what FERC called a “conservative” threshold to test for price separation.
In its Oct. 30 ruling, FERC said it had corroborated those findings.
“We have reviewed this analysis and determined the methodology to be acceptable for an EIM submarket analysis,” the commission wrote. “The commission has previously found that binding constraints in 2.2% of all study hours during an 18-month study period is insufficient evidence to support the existence of a submarket. The price separation instances in this case, which are used here as an indication of binding constraints, are generally in the 2% range, which would indicate a lack of a submarket.”
The commission additionally determined that, having demonstrated the lack of submarkets in the EIM, the two companies have prepared their pivotal supplier and wholesale market share screens consistent with FERC requirements.
“Accordingly, we find it appropriate to lift the default energy bid restriction and allow the Berkshire EIM sellers to bid into the EIM at market-based rates without restriction,” the commission said.
FERC’s decision should help relieve the two companies’ broader market restrictions in the interior West. Last year, the commission also revoked authorization for 21 BHE affiliates, including PacifiCorp and NVE, to sell power at market-based rates in the PACE, PACW, Idaho Power and NorthWestern Energy BAAs. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)
While that order still stands, the two companies will immediately have a freer hand to effectively bid power into PACE and PACW through the EIM, and will gain similar access to Idaho Power’s territory starting next April when that utility joins the market.
