TULSA, Okla. — SPP’s Regional State Committee last week endorsed a policy white paper intended to ensure all net peak demand is carrying the appropriate capacity, as mandated by the RTO’s resource adequacy requirements.
The Distributed Energy Resource Policy addresses whether each DER is treated strictly as a modifier for a load-responsible entity’s (LRE) load or as capacity. Resources identified under the policy do not meet the requirements for firm capacity or deliverable capacity, as defined by SPP’s Tariff.
The paper defines DERs as either “controllable and dispatchable demand responses” (CDDRs) or “controllable and dispatchable” resources (CDRs).
CDDR is a specific program used to reduce LREs’ forecasted peak demand. The resources are not considered as capacity resources, even if they’re registered in the Integrated Marketplace, and can be controlled or dispatched by SPP or the LRE.
CDRs are defined as LRE-controlled or -dispatched resources not registered in the market or not a designated resource. However, they must be able to attest to having firm delivery to load. CDRs cannot be used as a load modifier unless they are non-controllable or non-dispatchable.
The white paper was unanimously endorsed in December by the Cost Allocation Working Group, which reports to the RSC. It has also been endorsed by the Supply Adequacy Working Group, which drafted the paper, and the Markets and Operations Policy Committee. (See “DER White Paper Gains Endorsement,” SPP MOPC Briefs: April 16-17, 2019.)
The white paper will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.
Adam McKinnie, an economist with the Missouri Public Service Commission, told stakeholders that a joint committee of SPP and MISO regulators is reviewing seamstopics for potential development, as suggested by the RTOs’ market monitors.
McKinnie said the SPP RSC-OMS Seams Liaison Committee will have further discussion with the monitors to develop a scope for the work, which the committee expects to finalize in May.
The topics include how transmission planning assumptions limit the ability to identify joint projects; whether rules unique to each market affect seams; whether transaction scheduling/interface pricing can be improved to ensure beneficial market outcomes; and the effectiveness of the RTOs’ market-to-market process.
The committee will likely meet in person during the National Association of Regulatory Utility Commissioners’ July meeting in Indianapolis.
FERC last week ordered settlement judge procedures for four challenges regarding Emera Maine’s proposed transmission rate, summarily deciding on four other challenges and ordering the utility to make a compliance filing within 30 days (ER15-1429).
Emera Maine Service Area | Emera Maine
The commission’s April 30 order accepted in part the challenges to Emera Maine’s annual update filed in May 2018 by the Maine Public Utilities Commission and a customer group. The update proposed transmission service charges to take effect June 1, 2018, under the company’s Open Access Transmission Tariff (OATT) for the Maine Public District, which includes Aroostook County and a small piece of Penobscot County. (Emera Maine provides service under a separate OATT to the Bangor Hydro District: Hancock, Piscataquis and Washington counties and most of Penobscot County.) The customer group included Eastern Maine Electric Cooperative, Houlton Water Co., the Office of Maine Public Advocate, and Van Buren Light and Power District.
The order summarily decided on the correction of certain acknowledged errors in the 2018 annual update, the exclusion of certain costs for land associated with a project not in service, the exclusion of some distribution costs equipment from transmission rates, and the flowback of excess accumulated deferred income taxes (ADIT).
Settlement Issues
The commission said the remaining issues raise questions of material fact that it could not resolve based on the record before it and should be decided at a hearing if not resolved through settlement. The commission directed the chief administrative law judge to appoint a settlement judge within 15 days of the order.
Among those issues are excluding certain regulatory expenses that the complainants say were improperly allocated or directly assigned to Maine Public District transmission customers and excluding costs that may constitute a double-recovery for amortization of merger-related losses.
Two remaining issues are whether to exclude costs attributed to a rebuild of Line 6901 (which opponents say were incurred prior to MPUC authorization and should be considered as a canceled project) and whether some costs attributed to the rebuild should be attributed to other projects.
New Owner
On March 25, ENMAX Corp. announced it had reached an agreement to purchase Emera Maine for $959 million ($1.286 billion CAD) from parent Emera Inc.
The sale is part of Emera’s plan to reduce corporate debt and fund its three-year capital investment plan. Emera said the deal, and the previously announced sale of its New England gas generation portfolio will raise about $2.1 billion CAD.
ENMAX, based in Calgary, Alberta, owns and operates transmission, distribution and generation facilities throughout the province, with 669,000 electricity, natural gas and renewable energy customers.
Entergy said last week the recent sale of its Indian Point nuclear plant completes the final disposition of nuclear assets in its wholesale business, calling it an “important new milestone.”
“We now have definitive agreements to sell all of [Entergy Wholesale Commodities] remaining nuclear assets,” CEO Leo Denault told financial analysts during the company’s May 1 quarterly earnings conference call.
Entergy announced in April it had reached an agreement for a post-shutdown sale of Indian Point to Holtec International. The New York plant’s two remaining units, which have a combined capacity of more than 2 GW and date back to the 1970s, will be shut down in 2020 and 2021. The sale is expected to close in 2021.
Indian Point | Entergy
Denault said Entergy plans to shut down its 688-MW Pilgrim nuclear plant in Massachusetts in May. The New Orleans-based company expects to complete the sale of its 811-MW Palisades plant in Michigan after it is shut down in 2022.
“The sales of these plants are important … they secure our orderly exit from the merchant business in a way that benefits stakeholders by accelerating the decommissioning timeline,” Denault said.
Entergy reported first-quarter earnings of $255 million ($1.32/share), compared with $133 million ($0.73/share) a year ago. Earnings were $0.82/share when adjusted for non-recurring items, missing Zacks Investment Research consensus expectation of $0.94/share.
Entergy’s package of earnings materials included its first analysis on climate change. In the report, the company said it would reduce its CO2 emissions rate by 50% below 2000 levels by 2030.
“The broad consensus of current scientific data on climate change indicates that as an industry we must do more to reduce our footprint and that of our customers and communities,” Denault said. “Entergy sees this not as a choice, but as a responsibility and an opportunity. “For every unit of electricity we generate in 2030, we will emit half the carbon dioxide we did in 2000.”
Entergy’s share price closed the week at $96.63, up 18 cents from its May 1 open.
EWC’s nuclear assets | Entergy
OGE Earnings Down from 2018
OGE Energy on May 2 announced first-quarter earnings of $47.1 million ($0.24/share), a drop from a year ago when earnings were $55 million ($0.28/share).
The Oklahoma City-headquartered company attributed the difference to higher expenses due to the timing of certain projects, additional assets being placed into service, and lower allowances for construction funds as “key environmental assets were placed into service.”
On May 6, Oklahoma regulators will consider an OGE settlement agreement seeking recovery for the addition of scrubbers on its two coal-fired Sooner Power Plant units and converting two coal units at Muskogee Power Plant to gas.
“With our large environmental investments complete, we look forward to continuing to enhance the customer experience through investments in technology and the electric grid,” CEO Sean Trauschke told financial analysts.
OGE’s share price picked up almost a dollar after the earnings release, ending the week at $41.61.
The Texas Legislature on Tuesday passed legislation giving incumbent utilities the right of first refusal (ROFR) to build transmission projects in the state.
The House passed a final reading of Senate Bill 1938 by a 139-5 margin. The bill, which passed the Senate 31-0 on April 17, was substituted for the House’s identical version.
The bill now awaits Gov. Greg Abbott’s signature before becoming law. It would become effective immediately, thanks to an “emergency” rider.
The legislation grants certificates of convenience and necessity (CCNs) to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” (See Texas ROFR Legislation Pits Incumbents, Transcos.)
| Wind Energy Transmission Texas
Rep. Dade Phelan, a sponsor of the bill, told representatives the bill will “ensure the Public Utility Commission, and not the federal government, will have jurisdiction over Texas transmission rates.”
ERCOT is not subject to FERC jurisdiction. However, parts of West Texas and East Texas lie in the SPP and MISO footprints, respectively.
Opponents of the legislation argue it would undercut competition in the state, making it illegal for anyone other than incumbent utilities to build new transmission and eliminate the Texas Public Utility Commission’s authority to license new entrants to build transmission assets and provide transmission services.
“We are confident that the transmission industry is moving toward more competition,” GridLiance spokesperson Vera Carley told RTO Insider. “It is clear that ratepayers will increasingly advocate for more competition in the transmission industry once they see the effect of competition on costs.”
GridLiance cited a Brattle Group study it commissioned that indicated competitive projects under FERC Order 1000 have come in at an average of 40% below initial estimates. The study noted 15 projects have been selected through ISO/RTOs’ competitive processes, but none of the projects have yet to be completed.
The bill’s passage also means NextEra Energy Transmission will likely lose its winning bid for the Hartburg-Sabine Junction 500-kV project in East Texas, which it received last year from MISO. The PUC has yet to grant the project a CCN.
Among those voting against the bill was Rep. Travis Clardy. His inquiry to the Department of Justice’s Antitrust Division resulted in the DOJ filing comments expressing its concern the legislation would limit competition, potentially raise electricity prices and lower the quality of service.
In arguing against the bill, Clardy warned of “protractive” private litigation and potential federal legislation in response to the law.
“There is no urgency or haste. There is no reason to pass this bill now,” he said. “This bill, I don’t believe, has been properly vetted.”
Legislators voting for the bill painted it as a victory for the Texas economy and large power users.
A U.S. senator is urging FERC to support MISO’s proposal to transfer interconnection rights for existing generators that have been retired, demolished or replaced with new generation.
Tina Smith (Facebook)
Sen. Tina Smith (D-MN) filed comments with FERC early this month, urging the commission to consider that MISO’s generator replacement proposal — currently pending before FERC — stands to benefit renewable generation and could nudge owners of high-emitting generators to make cleaner upgrades (ER19-1065).
In her comments to FERC, Smith said the plan could support the goals behind Minnesota’s Next Generation Energy Act of 2007, which requires the state to reduce its 2050 greenhouse gas emissions to 80% below a 2005 baseline.
“For the electric sector, meeting that goal will require the replacement of high-emitting generators and a continued rapid expansion of low- and non-emitting generators,” she said. “MISO’s proposal will remove incentives for the owners of current high-emitting generators to put off upgrading to low- and no-emission generators by enabling replacement of legacy generating equipment in a manner that avoids significant additional costs.”
Under MISO’s proposal, interconnection customers wishing to replace their generation under the same interconnection agreement would send a request and a $60,000 study deposit to MISO. Over the following 180 days, MISO would conduct a generator replacement impact study similar to its existing material modification study, as well as a reliability assessment similar to its current reliability study for generation retirement.
Upon a finding of no adverse impact from the replacement, MISO would give the customer 30 days to decide to proceed with the replacement project. MISO would then have 90 days to conduct an interconnection facility study, if needed. After that, a replacement project proceeds to negotiation of a draft or amended generator interconnection agreement.
If MISO does find adverse impacts from the study, it would require the interconnection customer to “submit all necessary requirements for a new interconnection request” to begin the definitive planning phase anew. Adverse impacts include increases in thermal loading, a degradation in voltage, a degradation in stability performance and increases in short circuit contribution.
Smith said the proposal will benefit existing wind and solar generators, “ensuring they can continue to replace aging generating equipment with more efficient new equipment as technology improves, also without facing such additional upgrade costs.”
The proposal “facilitates reuse of existing infrastructure, supports state environmental initiatives and helps keep customer costs low,” Smith said, also noting the plant has the support of the American Wind Energy Association and the Clean Grid Alliance.
MISO plans to implement the replacement process by the third quarter of this year. The RTO said the proposal has widespread stakeholder support.
Michigan regulators are stepping into a dispute over how to classify a contested interconnection project included in MISO’s 2018 Transmission Expansion Plan (MTEP).
In a FERC complaint filed last month against MISO and Michigan Electric Transmission Co. (METC), Consumers Energy argued METC’s $21-million, 138-kV Morenci line near the Michigan-Ohio border has more in common with a distribution project than a transmission project and should be classified as such (EL19-59).
Consumers says the seven-factor test laid out in FERC Order 888 supports its contention because the line would be radial in nature. The company asked FERC to determine MISO “cannot approve or mandate the construction of a local electric distribution facility as part of its annual transmission planning process.”
Michigan Public Service Commission | Google Maps
MISO included the Morenci project in its 2018 Transmission Expansion plan over Consumers’ objection, saying it had no authority to address the complaint and the matter should be decided between FERC and the transmission owner. (See MISO Board OKs Full MTEP 18over Stakeholder Complaints.)
But Consumers said MISO’s view that “it is irrelevant whether its transmission expansion plans might include local distribution projects … is unacceptable to Consumers Energy, and it should be unacceptable to FERC, because it is a form of agnosticism with very real consequences.” MISO should vet the classification of its transmission projects — especially contested ones, the company said, asking FERC to remind the RTO of its “inherent obligation” to classify transmission projects.
Consumers argued MISO didn’t attempt the seven-factor transmission test when it should have, but MISO countered it followed both its Tariff and Transmission Owners Agreement, which stipulate the seven-factor transmission test be performed by “appropriate regulatory authorities.” The RTO asked FERC to dismiss the complaint in a May 3 response.
Last week, the Michigan Public Service Commission intervened to claim jurisdictional authority, opening its own case to apply the seven-factor test and scheduling a prehearing conference for June 4 (U-20497). METC, along with affected generator Wolverine Power Supply Cooperative and co-op member Midwest Energy and Communications, have requested FERC delay a decision on the complaint until the Michigan PSC rules in the dispute.
The PSC has also suggested FERC order a modification to the MTEP process to allow state entities with jurisdiction to apply the seven-factor test before a project makes it to the MTEP list.
However, Wolverine Power has argued it has a “time-sensitive need” for a transmission upgrade to deliver wholesale power and said the case is not the “appropriate proceeding to revise the MISO Tariff or to expand the scope of MISO authority to include facility classifications.”
Consumers has said it will suffer “concrete harm” if the line is built, saying it will have to pay for the line in METC’s transmission rates and be prevented from constructing an alternative distribution project to serve Midwest Energy’s anticipated load growth.
Consumers also contends a FERC determination that the line is distribution should be “uncontroversial.” “Federal law does not give MISO the power to approve or compel construction of local distribution facilities, or to regulate such facilities directly,” the company said.
ALBANY, N.Y. — Two environmental advocates from the Sierra Club were the only commenters Monday at the first public hearing on New York’s proposed restrictions on NOx emissions from peaking power plants.
Administrative Law Judge Molly T. McBride was accepting comments and statements for the state’s Department of Environmental Conservation (DEC) at the first of three hearings planned this month on proposed revisions to the agency’s Clean Air Act regulations.
Ona Papageorgiou, an engineer with the DEC Division of Air Resources, said the addition of Subpart 227-3 to Title 6 of the official compilation of state codes and regulations is meant to lower allowable NOx emissions from simple cycle and regenerative combustion turbines (SCCTs) during the ozone season.
The new regulations are proposed to go into effect May 1, 2023, with “initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen,” Papageorgiou said. Generator compliance plans will be due March 2, 2020.
The DEC plans to submit the regulatory text to EPA as a revision to the state’s Clean Air Act implementation plan. It worked with NYISO, the New York State Energy Research and Development Authority and the state’s Department of Public Service on the proposal, which would apply to resources with a nameplate capacity of 15 MW or greater that bid into NYISO’s wholesale energy markets.
EPA designated the New York metropolitan area (NYMA) as a “marginal” nonattainment area for the 2008 eight-hour ozone National Ambient Air Quality Standard but last year proposed to reclassify the area to “serious” nonattainment.
NOx Table: As demonstrated in the table, on high ozone days newer SCCTs produced 64% of the electricity generated from SCCTs while emitting only 4% of NOx emissions from these sources. | NY DEC
An ‘F’ for Air Quality
“We would like to take this opportunity to applaud the effort and hope it will lead to the closure of many of these aging, inefficient and polluting electric energy generating facilities,” Roger Downs, conservation director of Sierra Club Atlantic Chapter, said at the hearing.
Because the units run to meet electrical loads during periods of peak electricity demand, their operations tend to correspond with hot summer days and associated high ozone levels when heavy use of air conditioning strains the capacity of the grid, Downs said.
“The resulting air quality degradation and increased NOx profoundly affects the health of those living near these peaking plants, exacerbating the asthma, heart attacks and other respiratory ailments that contribute to tens of thousands of hospital visits annually and dozens of deaths in New York’s nonattainment regions,” he said.
DEC assessed 99 high ozone days between 2011 and 2017 and said if the older sources were replaced with newer sources, total NOx emissions from those older sources on those days would drop from the reported 1,849 tons to between 40 and 60 tons, depending on efficiency.
The resulting 1,800-ton decline in emissions over those days — an average reduction of 18 tons per ozone season day — would represent a more than 10% reduction in metro area NOx emissions from electricity generators and an overall 3.5% reduction from all sources, the agency said. Analysis showed that, on high ozone days, newer SCCTs produced 64% of the electricity generated from SCCTs while emitting only 4% of NOx emissions from these sources.
Gail Pisha, representing the Sierra Club’s Lower Hudson Group, said EPA designates Rockland and Westchester counties as nonattainment areas for ozone, and the American Lung Association rates Rockland, Westchester and Hudson counties’ air quality with an ‘F’ for ozone pollution.
The Sierra Club also “anticipates that this new regulation will facilitate better water management, as many of the ageing peaking plants also use egregious amounts of water for cooling,” Downs said. “The billions of gallons of water a day required to cool Ravenswood and Astoria Generating and other facilities drawing from New York waters also contain hundreds of millions of larval fish in eggs that are entrained and entrapped in the industrial intake structures.”
Downs said it is also important to ensure the closed plants’ generating capacity be replaced by renewable energy, and to that end the Sierra Club remains uncomfortable with some language in the regulations that could allow for more lenient air quality rules if the peaking facility accommodates onsite energy storage.
“Energy storage serviced by the same dirty fuel sources significantly undermines the overall climate and air quality goals of this regulation,” Downs said.
Alliance Energy Group’s 55-MW Hillburn Power Plant in Hillburn, N.Y., is a two-on-one simple cycle twin pack plant burning kerosene and natural gas, and is in the process of being permitted to burn biodiesel. | Alliance Energy
DEC will hold its second hearing May 13 at 11 a.m. on the SUNY campus in Stony Brook and the third hearing May 14 at 11 a.m. at the state Department of Transportation in Long Island City.
Requests for information and comments related to the SIP revision may be obtained from Robert D. Bielawa, DEC Division of Air Resources, at (518) 402-8396 or air.regs@dec.ny.gov. Written statements may be submitted until May 20.
NRG Energy said last week it expects to return to service an inactive Texas gas plant in time for summer, giving ERCOT additional capacity to play with.
ERCOT enters summer with a historically low reserve margin of 7.4%. The 385-MW Gregory plant will give the grid operator much needed extra capacity.
Gregory, located just outside Corpus Christi, was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. It is expected to return to service as a combined cycle facility in early June.
In a statement released after NRG’s first-quarter earnings call Thursday, CEO Mauricio Gutierrez said the Texas Public Utility Commission’s recent actions to strengthen the ERCOT market “reinforced our decision to return Gregory to service ahead of summer.” (See related story, NRG Energy Earnings Drop on ERCOT Hedges.)
The PUC in recent months has worked to improve coordination between electric utilities and pipeline companies and ordered tweaks to ERCOT’s operating reserve demand curve price adder.
ERCOT will release its final resource adequacy assessment for the summer on Wednesday.
TULSA, Okla. — SPP’s Holistic Integrated Tariff Team (HITT) last week shared with stakeholders the result of a year’s worth of work: a draft report of high-level recommendations addressing the footprint’s many challenges.
Now comes the hard part: taking action on the recommendations.
“There’s a heck of a lot of work that’s left,” HITT Chair Tom Kent said during SPP’s April 29 joint quarterly stakeholder briefing. “The working groups will have a lot of effort to put these [recommendations] into actual action.”
Kent, COO for Nebraska Public Power District, said the HITT report makes 21 recommendations in four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study.
The big-ticket cost-allocation recommendations include decoupling Schedule 9 and Schedule 11 transmission pricing zones and allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones. The HITT proposes that if the Regional State Committee adopts a policy to reallocate existing costs within the new pricing zones, it should be done over a five- to 10-year transition period to mitigate cost shifts.
The HITT is also recommending SPP determine whether transmission projects below 300 kV can be fully allocated on a regionwide basis; use incremental long-term congestion rights instead of Attachment Z2 credits as compensation for new sponsored upgrade projects; and evaluate whether it can establish cost allocation and rates under the Tariff for energy storage resources.
The team also recommends SPP continue to improve the Integrated Marketplace by including fast-start resource logic, ramping capability and a multiday, longer-term market product, and to continue developing a market mechanism to hedge load against congestion charges.
Kent said the report is a “tribute to the team working hard and working together, and coming to a strong consensus on the recommendations.”
HITT’s recommendations | SPP
A proposed action plan assigns the recommendations to various stakeholder groups. A timeline anticipates the work being completed by mid-2021.
Larry Altenbaumer, chair of SPP’s Board of Directors, called the HITT’s work “an example of the very best of SPP.”
“We fully recognize 85% of the work is in front of us,” he said. “It’s an exciting beginning of a very important next step for us. I think HITT’s going to be a good thing for us.”
“The industry is changing as rapidly as many of us who’ve been around for a long time have seen it change,” said HITT member Dennis Grennan, a commissioner with the Nebraska Power Review Board. “We must prepare for major changes coming in the next five to 10 years. It’s a real challenge, but it needs to be done so that our consumers back home truly benefit from belonging to SPP and all that comes with it.”
Kent promised a final report by the end of June and said that a final product will be brought to the July stakeholder meetings. He said it will be discussed in detail with the Strategic Planning Committee during its May 9 planning retreat.
The RSC has scheduled in-person meetings with the HITT on May 30 and June 24, and Altenbaumer asked for a workshop to be scheduled where stakeholders can participate in a “top-to-bottom” discussion of the report.
The SPP board charged the HITT with developing recommendations for holistic improvements within the system. The team is composed of 15 board members, state regulators and SPP members. (See SPP’s Tariff Team Begins Carving up the Elephant.)
FERC is re-evaluating how its 2018 decision on transmission owners’ return on equity might affect Entergy Arkansas’ unit power sales tariff from 2013.
The commission April 30 said it could determine a new ROE for Entergy Arkansas and issued an order directing submission of briefs and additional written evidence (ER13-1508-001).
| Entergy Arkansas
The issue dates back six years, when Entergy Arkansas decided to leave the Entergy System Agreement and join MISO. As a result, Entergy Arkansas created a unit power sales tariff that passed through MISO’s ancillary and uplift charges and credits, along with the RTO’s 11% ROE for TOs. Both the Louisiana Public Service Commission and the city of New Orleans protested Entergy Arkansas’ use of the rate. Using the 2014 Opinion 531 that set the ROE for transmission owners in New England, an administrative law judge in 2015 found that 9.01% was reasonable in Entergy Arkansas’ case.
But with Opinion 531 vacated in 2017 and no longer serving as precedent, FERC wants a fresh look at Entergy Arkansas’ ROE. As of last year, the commission said it will no longer rely only on the discounted cash flow (DCF) model, instead using a combination of DCF and the capital asset pricing, expected earnings and risk premium models. (See FERC Changing ROE Rules; Higher Rates Likely.)
“Accordingly, we direct the participants to this proceeding to submit briefs regarding the proposed new methodology for determining just and reasonable ROEs … and whether and how to apply it to the unit power sales tariff,” FERC said.
The commission added that participants in the case “are free to present evidence supporting the proposed new methodology or supporting a different or revised new methodology.” Briefs are due in two months.
