Cold weather and a stronger regional economy helped boost WEC Energy Group’s first-quarter earnings above expectations, the company reported Tuesday.
The company also addressed uncertainty in its executive suite and described its near-term plans for more renewable investment.
WEC’s profits totaled $390.1 million ($1.23/share) during the quarter, compared with $356.6 million ($1.12/share) for the same period last year.
CEO Gale Klappa said the “solid results” were driven by a stronger-than-expected demand for electricity and natural gas. “Colder winter temperatures, a strengthening economy and efficiency gains across our system were all positive factors that lifted our earnings above year-ago levels,” Klappa said.
The company’s operating revenue for the quarter slipped from $2.3 billion to $2.29 billion this year.
During a May 1 earnings conference call, Klappa praised the company’s performance and said it has a plan readied in the event that company President Allen Leverett does not return to his post as CEO after being placed on medical leave in October 2017 when he suffered a stroke. Klappa said Leverett is currently undergoing intensive speech therapy and is in “good physical condition.” Should Leverett choose not to resume the role of CEO, WEC will employ a succession plan that would “involve a number of internal promotions,” Klappa said.
“I can assure you that we have a solid Plan B in place if Allen does not assume his previous role. … We would have great continuity going forward, and the board and I are very comfortable with [that],” Klappa said, adding that he and WEC’s board of directors will continue to monitor the situation.
Klappa also said WEC is making multiple renewable energy investments throughout 2018. The company on April 30 signed a $280 million agreement to acquire an 80% ownership interest in the 200-MW Upstream Wind Energy Center, currently being built by Invenergy in Antelope County, Neb. Klappa said he expects the wind farm deal to close in early 2019, pending FERC approval — just as Upstream begins commercial operation.
Early last month, WEC closed on its $80 million partial purchase of the 129-MW Forward Wind Energy Center near Brownsville, Wis. Klappa said WEC now owns 44.6% of the wind farm, which is expected to generate savings for customers.
WEC also plans to file construction requests with Wisconsin regulators by the end of the second quarter to build its first solar farm, Klappa said.
“Over the past few years … utility-scale solar has increased in efficiency, and prices have dropped by nearly 70%, making it a cost-effective option for our customers, an option that also fits very well with our summer peak demand curve and with our plan to significantly reduce carbon dioxide emissions,” Klappa said.
He also said WEC is developing plans to provide natural gas and electric infrastructure to “Wisconn Valley,” the moniker for the future site of electronics manufacturer Foxconn’s $10 billion plant. In February, MISO Fast-Tracks ATC Foxconn Project Review.)
CAISO and PacifiCorp reaped the majority of the Western Energy Imbalance Market’s (EIM) $42.1 million in gross benefits during the first quarter, according to a report released by market operator CAISO.
The ISO earned $14.85 million in EIM benefits over the quarter, followed by PacifiCorp at $10.5 million. Trailing those two market players were Arizona Public Service ($5.9 million), NV Energy ($4.2 million), Portland General Electric ($3.6 million) and Puget Sound Energy ($3 million).
Total quarterly benefits were up nearly 26% from the fourth quarter of 2017 and 31% from the same period a year ago — before Portland General Electric began transacting in the EIM last October. The market has yielded $330.5 million in benefits since it was launched with PacifiCorp in November 2014, the ISO estimates.
| CAISO
The report again illustrated an established pattern with the arrival of spring: that CAISO becomes a net exporter of energy as increasing output from solar resources coincides with modest electricity demand during mild weather in California. (See CAISO EIM Exports Rise with Spring, Report Shows.)
The ISO’s EIM exports surged from 94,769 MWh in January to 325,664 MWh in March, with imports falling from 299,586 MWh to 185,008 MWh, the report showed. First-quarter exports totaled 608,416 MWh, compared with 362,774 MWh the previous quarter.
CAISO said the energy transfers facilitated by the EIM allowed it to avoid curtailment of 65,680 MWh of renewable output during the quarter, up 24% from the same period last year. That was still down sharply from the nearly 113,000 MWh of avoided curtailments in the second quarter of 2016, which the ISO attributed to improved hydroelectric conditions and advancements in how EIM participants are deploying their resources.
The avoided renewable curtailments translated into the displacement of 28,188 metric tons of carbon dioxide, based on an assumed default emissions rate of 0.428 metric tons CO2/MWh from other sources of generation. By avoiding curtailments, the EIM has helped to displace 250,845 metrics tons of CO2 since 2014, the ISO said.
The report also showed that APS and NV Energy functioned heavily as “wheel through” areas during the first quarter, meaning their transmission networks facilitated many transactions for which the utilities received no financial benefits because they were neither source nor sink. (See graph). During February and March, energy volumes wheeled through APS’ territory exceeded the utility’s combined EIM net imports and exports, as significant amounts of energy flowed between the CAISO and PacifiCorp-East balancing authority areas during what is typically a period of low demand in Arizona.
Estimated wheel through transfers in Q1 2018 | CAISO
The ISO has “committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits,” the report said.
A CAISO proposal to provide transmission revenue to EIM participants that wheel energy through their BAAs last summer drew stiff opposition from current and future stakeholders concerned about the impact of new charges on the economic dispatch of generating resources. (See EIM Member Wary of Need for Wheeling Charge.)
Edison International CEO Pedro Pizarro said the company is hopeful that several bills working their way through the California State Legislature will ease the financial pressure stemming from hundreds of millions of dollars in wildfire costs.
The company’s main subsidiary, Southern California Edison, is the target of civil lawsuits stemming from the Thomas Fire that began in December 2017 in Ventura County, Calif., burning about 440 square miles and causing two deaths. While the California Department of Forestry and Fire Protection, the Ventura County Fire Department and the California Public Utilities Commission’s Safety and Enforcement Division look into the causes of the fire, the utility is conducting it own investigation, Pizarro said.
During an earnings call Tuesday, Pizarro called for the state to implement wildfire mitigation operating standards to help determine whether a utility properly ran its transmission system prior to a fire.
“An updated standard of liability that considers degree of fault rather than the current standard of strict liability would ensure that there is a fair sharing of the increasing risk of climate change impacts across society,” Pizarro said. He said he was “heartened” by Gov. Jerry Brown’s comments in March about updating utility liability rules for wildfires. Three related bills have been introduced into the legislature: SB 819, SB 901 and SB 1088.
Edison International reported its first quarter earnings this week
The third bill, set for a May 7 hearing at the Senate Committee on Appropriations, would allow utilities to recover wildfire costs if they conform to state-regulated safety plans, but it faces heavy opposition from critics who say it lets utilities off the hook for their contribution to wildfires. (See Calif. Legislation Shields Utilities from Wildfire Costs.)
Wildfire costs and the financial health of the state’s investor-owned utilities have sparked concerns in the capitol about the impact on utility stock prices and the potential for bankruptcies — shades of the electricity crisis of the early 2000s. (See Wildfire Costs Ignite Worry at CPUC, Legislature.)
Edison reported first-quarter net income from continuing operations of $242 million, compared with $392 million in the same quarter last year. Operating revenue was $2.5 billion in the first quarter, and total operating expenses were $2.2 billion. SCE is a waiting for a CPUC decision on its 2018 retail general rate case.
SCE on April 3 filed an application at the CPUC for a Wildfire Expense Memorandum Account to track incremental wildfire costs. The company is in the process of renewing its wildfire insurance for 2018 and 2019 and said the cost of additional insurance may substantially exceed the amount authorized in rates or in the pending 2018 rate case. The utility has proposed a schedule that would see a decision on the account issued by August.
The state’s three utilities have banded together on the wildfire issue after the CPUC last year denied San Diego Gas & Electric’s request to recover $379 million in wildfire-related costs. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)
FERC on Tuesday approved simultaneous transmission import limits for several balancing authority areas in the Southeast, stretching from Kentucky to Florida.
The 16 simultaneous import limits (SILs) were submitted with non-public market power analyses by several transmission-owning companies, including eight subsidiaries each of Southern Co. and Duke Energy; seven NextEra Energy affiliates (including Florida Power & Light); PPL affiliates Louisville Gas & Electric and Kentucky Utilities; Tampa Electric Co.; and South Carolina Electric & Gas. (ER10-1325–008, et al.).
South Carolina Electric & Gas Co. linemen at work | SCE&G
FERC will use the SIL values to evaluate market power analyses submitted by the region’s transmission owners (TOs) and non-transmission-owning sellers.
The limits range from a 10.7-GW import capability during winter in the Tennessee Valley Authority balancing area down to a zero-megawatt year-round import limit in the Florida Power & Light balancing area. The limits were created based on a study period extending from December 2014 to November 2015.
While FERC accepted most of the transmission owners’ own SILs, it said it selected Tampa Electric’s calculated values for a few Florida balancing areas where various TO SIL values conflicted with one another.
The commission commended the TOs for coordinating to create the SIL values but said in the future SIL calculations must follow a commission-ordered procedure.
“The southeast transmission owners generally performed their SIL studies correctly. However, the review of these filings, as well as the review of filings for other regions, leads the commission to conclude that it is appropriate to remind sellers of its expectations, and provide clarification, with respect to the calculation of SIL values,” FERC said.
FERC said TOs should abide by the tariff-approved methodologies to calculate SIL capability and should take into account voltage and stability limits, capacity benefit margins and transmission reserve margins.
“The commission emphasizes here that each transmission owner’s SIL values must reflect [transmission reserve margins] and [capacity benefit margins] in the same manner as utilized to calculate and post [available transfer capability] and to evaluate requests for firm transmission service,” FERC said.
FERC on Monday approved settlement agreements among CAISO, Pacific Gas and Electric and Calpine covering reliability-must-run (RMR) contracts for three Northern California gas-fired plants, reducing the revenue they will receive and making them subject to a must-offer requirement.
While the commission said the agreements resolved all issues in dispute in the proceedings and appeared to be “fair and reasonable and in the public interest,” the out-of-market RMR payments are not popular with many CAISO stakeholders and were opposed by the California Public Utilities Commission (CPUC) after the ISO’s Board of Governors reluctantly approved them in November. (See Board Decisions Highlight CAISO Market Problems.) The CPUC in January voted to require PG&E to hold solicitations to replace the agreements with energy storage. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.)
The Metcalf settlement reduces the plant’s annual fixed revenue requirement from about $72 million to $43 million through 2020 if it retains its RMR status and makes the plant operator responsible for routine repairs and capital expenses. Under the agreement, the plant will recover $8 million in 2018 capital items in 12 installments of $675,000 beginning on Jan. 1, 2018. If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement also grants the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.
Calpine’s Feather River Energy Center | Calpine
The Feather River and Yuba City settlements would reduce each plant’s 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020, if the RMRs are renewed.
The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Revisions.)
CAISO Tariff Waivers
In a separate order, FERC also granted CAISO a limited Tariff waiver to permit nine scheduling coordinators (SCs) to submit out-of-time requests to recertify 18 resources for the 2018 resource adequacy compliance year (ER18-857). CAISO said the SCs had failed to renew an exemption related to its Resource Adequacy Availability Incentive Mechanism (RAAIM) program by the Nov. 15, 2017, deadline because of confusion about the recertification process for acquired resources within the program.
FERC said the waiver grants certainty to those resources that they their RAAIM exemption will not be unwound. CAISO replaced its Standard Capacity Product with RAAIM in November 2016. SCs must present an affidavit for each resource adequacy year testifying that each resource meets eligibility for exemption from certain performance incentives.
Energy Crisis Settlement
The Commission also approved an uncontested settlement filed Feb. 6 among CAISO, Wayzata Opportunities, PG&E, Southern California Edison and San Diego Gas and Electric related to the 2000/01 California energy crisis (EL02–18). The agreement ensures the payment of interest to the resource owners who had received delayed compensation for certain power supply contracts because of the default of the California Power Exchange. The filing parties said approval of the settlement would avoid further litigation, eliminate regulatory uncertainty and enhance financial certainty.
ERCOT will have more breathing room as it prepares for record demand this summer after an additional 525 MW of generation recently came online in Texas.
The ISO said Monday it now has 78.2 GW of capacity available to meet an expected peak demand of 72.8 GW, which would break the 2016 record of 71.1 GW. The additional capacity has boosted ERCOT’s planning reserve margin from 9.3% to 11% since the previous seasonal assessment of resource adequacy (SARA) report.
“That definitely improves the situation,” said Pete Warnken, ERCOT’s manager of resource adequacy, during a media call Monday.
The additional generation comes from the 225-MW, gas-fired Denton Energy Center that recently went into service in North Texas and the return of the mothballed 300-MW gas unit at Barney Davis in Corpus Christi.
South Texas Nuclear Generating Station
Warnken said rotating outages are still possible under extreme scenarios, “but that risk has been reduced a little bit with those resources.”
ERCOT has approximately 2.3 GW of capacity available through load-control measures with transmission or distribution service providers. Tight reserves could also trigger the need for the ISO to deploy ancillary services and contracted emergency response service capacity to maintain sufficient operating reserves.
Staff also expects industrial facilities to make voluntary load reductions and increase the power they sell into the market during peak demand.
“We expect the market to respond to scarcity conditions,” Warnken said. “It’s a good bet to expect they’ll be looking at summer conditions and making decisions appropriately before they bring their resources on.”
Dan Woodfin, the ISO’s senior director of system operations, said the grid will also benefit with the completion of the Houston Import Project, a $590 million effort that will allow more power to be imported from the north.
“All the pieces are in service at this point,” Woodfin said. “That will help reduce congestion into the Houston area because it improves the transfer capability.”
ERCOT also released its latest Capacity, Demand and Reserves (CDR) report, which includes planning reserve margins for the next five years. The reserve margin peaks at 12.3% in 2020, before dropping to 8.9% in 2023.
The CDR report adjusts the 2019 summer demand forecast down to 74.2 GW, reflecting a delay in a new industrial facility on the Texas coast. Staff expects the load forecast to eclipse 77 GW in 2023. That number includes the planned integration of Lubbock Power & Light’s customers, which is scheduled to take place in 2021.
The ISO’s target planning reserve margin is 13.75%. Warnken said staff is studying an economically optimal reserve margin, which would balance the amount of generation needed to maintain reliability with its cost.
The next CDR report will be released in early December.
A recently passed New Jersey law could lead to the state subsidizing nuclear plants outside its borders, Public Service Enterprise Group (PSEG) CEO Ralph Izzo said during his company’s first-quarter earnings call Monday.
“The bill simply says that New Jersey wants 40% of its power supplied by nuclear energy and it does not limit it geographically,” Izzo said.
Izzo made the statement in response to a question from Morningstar’s Director of Energy Research Travis Miller, who said he thought nuclear plants outside New Jersey could be eligible for the zero emission credits (ZECs) authorized by the legislation.
PSEG head Ralph Izzo says NJ Gov. Phil Murphy supports the jobs at the Hope Creek nuclear plant. | NRC
In addition to the Salem and Hope Creek nuclear plants that PSEG operates in Salem County, N.J., Izzo said the Peach Bottom nuclear plant in Pennsylvania, of which PSEG is half owner, could compete for ZECs. So, he added, could two other Pennsylvania nukes: Talen’s Susquehanna and Exelon’s Limerick.
The ranking system the legislation encourages the New Jersey Board of Public Utilities (BPU) to use in determining which plants get ZECs is driven by their impact on the state’s air quality, Izzo said.
Gov. Phil Murphy has not signed the legislation, which was passed April 12. He has 45 days from then to sign it into law; veto it, which both houses of the legislature could override with two-thirds majorities; conditionally veto it, which amounts to sending it back to the legislature with changes requiring majority approval; or not sign it, in which case it would become law after the 45 days pass. (See NJ Lawmakers Pass Nuke Subsidies, Boosted RPS.)
Izzo declined to opine on what he thinks Murphy will do — “You never, ever want to pretend to be constraining your governor,” he said — but he also said the governor has been outspoken about nuclear power being a bridge to a future with much more renewable generation capacity and supportive of the jobs at PSEG’s two nuclear plants in the state.
As for PJM’s efforts to improve its capacity market, Izzo said PSEG supports the RTO’s two-stage capacity repricing proposal over the Independent Market Monitor’s plan to expand the minimum offer price rule. PJM earlier this month filed both plans with FERC, asking it to choose one and outline what aspects of it should be revised. (See PJM Capacity Proposals to Duel at FERC.)
Izzo said PSEG prefers the status quo to either option because it doesn’t interfere with the ability of states to price attributes that markets aren’t currently pricing, which, in PSEG’s case, are the emissions-free generating capabilities of its nuclear fleet.
PJM’s two-stage approach would at least continue to allow states to value carbon-free generation,
but what’s really needed is a price on carbon, he said.
“The market’s just got these inherent inconsistencies built into it,” he said. “If we could get a price on carbon … capacity markets could do what they’re supposed to do.”
PSEG CFO Dan Cregg addressed the company’s recent agreement to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years. (See PSEG to Pay $39.4M to Settle FERC Investigation.) He said PSEG’s Power unit recorded an incremental $5 million pretax charge to income in the first quarter that will conclude the issue.
“We do not believe the order will have any ongoing impact” on PSEG Power, he said.
PSEG earned $558 million and $1.10/share in the first quarter, up from $114 million and $0.22/share in the first quarter of last year. Last year’s results included costs related to the early retirement of the Hudson and Mercer generating stations and a reserve for the impairment of leveraged leases.
As part of his effort to promote renewables, Gov. Murphy issued an executive order that began moving the state towards a solicitation of 1,100 MW of offshore wind capacity.
Izzo said PSEG has a lease and a partner, which he didn’t name, for offshore wind development, but said since his company has no experience in that area, it “would be interested in the transmission component as much as, if not more than, the actual wind farms.”
PJM wants to take a more holistic look at how the grid’s supply chain works and factor the findings into its markets.
The RTO announced a plan Monday it thinks will help ensure the reliable delivery of both electricity and the fuel necessary to generate the electricity. The three-phased approach will analyze fuel security throughout PJM’s footprint to identify vulnerabilities, develop criteria to address them and include those criteria in the models used for capacity auctions.
The result would be constraints on the grid that trigger clearing price differences in affected locational deliverability areas (LDAs) in the same way deliverability constraints already trigger price separation in base residual auctions (BRAs). Those price differences would signal opportunities for developers to build new infrastructure.
PJM hopes to have the process in place for the 2022/23 BRA in May 2019.
The RTO will brief stakeholders on the plan and discuss the study scoping document at a special Markets and Reliability Committee meeting from 9:00-12:00 EDT on May 8. The RTO apologized for scheduling it on a “no meeting day,” saying there were no other available times on the committee meeting calendar in May.
In announcing the plan, CEO Andy Ott repeatedly reiterated that, while PJM’s grid is currently reliable and has no fuel security issues, problems could materialize if current trends continue for too long. The percentage of gas-fired generation has been growing quickly in PJM’s fleet. The RTO determined last year it wouldn’t have reliability concerns even with a high percentage of gas generation, capping its analysis at 86% of the fuel mix because the current 14% share of demand response and hydro and biomass production is not likely to change, but the analysis didn’t address the security of the gas plants’ fuel supplies. Because they are beholden to gas pipelines, gas plants can have — and pay for — a wide range of contracts, from receiving uninterruptable service to being cut off first if there’s not enough gas in the pipeline. Other plants maintain backup supplies of liquid fuel, such as oil or liquified natural gas (LNG), onsite or are connected directly to Marcellus shale gas wells. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
Ott called the plan a “narrow” portion of the resiliency initiatives going on at PJM and throughout the nation. He pointed to pipeline constraints in ISO-NE as justification for the plan to get “ahead of those issues in a timely manner.”
“At some point in the future, we may be overdependent on one pipeline or one set of fuel-delivery infrastructure,” he said. “Our approach is to develop these criteria to make sure that we’re monitoring those trends.”
Plan Mechanics
It’s unclear how the mechanics of the plan will work, as the transmission-constraint pricing it would be modeled on raises prices in areas that have issues. That would suggest the price signals would also reward fuel-insecure units within those LDAs.
Natural gas pipeline | Ohio Power Siting Board
“If we see a fuel security problem, the price would elevate in that area,” Ott confirmed in his Monday morning briefing.
PJM spokespersons said the question is beyond RTO staff’s current analysis, but Robbie Orvis of the clean energy consulting firm Energy Innovation predicted it might be designed as a shadow price that calculates what the price would be without the insecure resources and offers them as an adder for secure ones.
Ott appeared to corroborate that in describing the price separation as an “adder.”
“The increased cost to fix that would be adding more onsite fuel tanks or other types of fuel-secure resources,” he said. “The idea is not to give units more money. The idea is to look at the exposure that we have.”
He noted wind, solar and batteries could qualify as fuel secure, but a renewable resource alone “would probably [qualify at] a much smaller amount than its nameplate capacity” in capacity auctions.
Impact
PJM said part of the study is to determine what, if any, new construction is necessary and where. Orvis added it’s unclear whether it would create demand for new coal and nuclear units, but “it seems rather unlikely” given the net revenues for those technology types calculated by PJM’s Independent Market Monitor in its 2017 State of the Market Report are “well below” their respective costs of new entry calculation.
“Given just how short these units would be on revenue recovery, it would take a very high price from some kind of new market product for fuel security to cause new coal and nuclear builds,” he said. “It’s worth noting that those low revenues are consistent across zones, so it doesn’t look like there are even any specific constrained areas where those plants are especially attractive.”
The adder would make the threshold easier to reach but require significant additional action.
“Over time, with a high enough price, large retirements, and in constrained zones, it is possible that some kind of fuel security price adder could tip the scales and incent new capacity, but it would take a significant deviation from today’s prices,” Orvis said. “PJM’s high reserve margins in the near- and medium-term, based on its cleared capacity in the capacity market, indicate that it’s unlikely there will be a capacity shortfall to push capacity market prices up.”
Orvis noted the modeling parameters PJM plans to use will likely underestimate the generation fleet and therefore might indicate a fuel delivery constraint when there are actually many more resources available.
“It is possible PJM will charge its customers for a service or attribute that is not needed. It would be better if they modeled the system based on what is actually expected to be available rather than their required reserve margin since they have in the past and will in the future continue to come in well above that reserve margin,” he said.
Reaction
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity, praised PJM’s action and urged other grid operators to follow suit. “We are also encouraged that PJM is following a work plan consistent with the urgency necessary to address lack of fuel security,” he said. “Over the next three years, more than 6,000 MW of fuel-secure coal-fueled generating capacity in PJM are expected to retire.”
Meanwhile, NRG Energy spokesman David Gaier noted PJM on Monday also said that FirstEnergy’s announced retirements of its Davis-Besse, Perry and Beaver Valley nuclear plants will not cause reliability problems.
“Units can retire as scheduled” PJM said in a presentation for the May 3 Transmission Expansion Advisory Committee meeting. “Operational flexibility allows [us] to bridge any delays with the transmission upgrades.”
Gaier said the RTO’s analysis undermines FirstEnergy’s request that the Department of Energy declare an emergency to keep the plants running. “Clearly, the attempt by FirstEnergy to keep open its uneconomic nuclear plants on the backs of ratepayers is a subsidy in search of a crisis — one that doesn’t exist,” Gaier said.
AUSTIN, Texas — The Public Utility Commission (PUC) of Texas on Friday orally approved Southwestern Public Service Company’s (SPS) request to build a wind farm in West Texas, clearing the way for a 1.23-GW project that will provide renewable energy and economic benefits to SPS customers in the Lone Star State and New Mexico.
Walker and Arthur D’Andrea requested additional information from SPS during the commission’s April 12 meeting, expressing doubts as to whether they had a “legal basis” to grant an application for new generation when the company already has sufficient capacity. (See Texas Regulators Seek More Details on SPS Wind Project.)
“I’m sorry if we kind of freaked out, but it’s a big question, and we don’t have a ton of time to review it,” D’Andrea told SPS representatives and the consumer groups with whom they had reached a unanimous settlement.
“I think you’ve done a nice enough job … for the ratepayers,” D’Andrea said. “You’ve certainly done a great job of getting everyone’s finger on the trigger.”
SPP staff had also previously stamped its approval on the SPS proposal.
Walker instructed staff to reflect Friday’s several minutes of discussion in its draft order. The final order will be approved during the PUC’s May 10 meeting (Docket No. 46936).
“It’s been a very cooperative effort, with both local stakeholders and statewide stakeholders,” SPS President David Hudson told RTO Insider after the April 27 open meeting. “This project will bring tremendous economic value to the region for three decades.”
Xcel will use Vestas turbines on its wind farms | Xcel Energy
The commission’s approval allows SPS parent Xcel Energy to proceed with construction of a 478-MW wind farm near Plainview, Texas, and a 522-MW facility near Portales, N.M., both in SPP’s footprint. Xcel will begin construction on the Texas facility in June and in New Mexico next year.
The company, which will own both facilities, will also purchase 230 MW of energy from two NextEra Energy Resources in Texas.
SPS received approval for the New Mexico portion of the project from the state’s Public Regulation Commission in March.
Xcel says the project will save customers hundreds of millions of dollars in production costs over a 30-year period. SPS will receive 100% of the available production tax credits for 10 years, passing the savings directly to its customers.
Xcel also expects the project to generate more than $150 million in local property tax payments over the next 25 years in Texas and New Mexico.
PUC Lowers CenterPoint Energy’s Tx Rates
The commission also approved CenterPoint Energy’s request to revise its wholesale transmission rates to reflect the reduction of the federal income tax corporate rate from 35% to 21%, thanks to the Tax Cut and Jobs Act of 2017 (Docket No. 48065).
The revision reduces CenterPoint’s transmission rate base from $2.11 billion to $2.08 billion and its wholesale transmission revenue requirement from $389.5 million to $347.8 million. Its interim wholesale transmission rate drops from $5,753.91/MW to $5,138.64/MW.
KANSAS CITY, Mo. — SPP’s Board of Directors was last week forced to table the appeal of a rejected revision request, cutting short the discussion when they realized the supporting documentation was not included in the background materials.
The Tariff change (MWG-RR272) requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period. It failed to receive the Markets and Operations Policy Committee’s (MOPC) endorsement by a handful of votes. (See Vote to Make Variable Resources Dispatchable Falls Short at MOPC.)
However, additional information on the measure was not part of the 638 pages of background material for the Apr. 24 meeting, leading Director Phyllis Bernard to move to table the measure “until we have further background information in front of the Members Committee before we vote.”
The Members Committee agreed with Bernard. Oklahoma Gas & Electric abstained from the vote.
The rejection was appealed by members, SPP staff and the Market Monitoring Unit (MMU).
Director Larry Altenbaumer, in one of his final comments before assuming the board’s chairmanship, told directors and members to plan on making a decision during their next meeting in July.
“If you have ideas to improve the process, you’ve got a quarter to make that decision,” he said.
In bringing forward the revision request, the Market Working Group said it would increase reliability and market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints.
The proposal applies to about 6 GW of NDVERs, which are generally older wind resources. However, it exempts about 2 GW of resources that don’t have direct interconnection agreements with SPP or are registered as qualifying facilities under the Public Utility Regulatory Policies Act (PURPA).
MMU Executive Director Keith Collins argued for the change, saying it’s a “global market efficiency issue” and would help reverse the recent growth of negative real-time pricing in SPP’s markets.
“To the extent resources are not flexible and capable of availing themselves to the system, we see an increase not only in frequency but [also] the magnitude of prices when we are unable to dispatch those resources,” Collins said. “Operators have to skip over the NDVER and find another resource.”
He pointed out that recent SPP analysis has found that dispatchable resources classified as non-dispatchable have “significant effects on the market congestion we’re seeing.”
The measure found resistance from stakeholders with renewable interests who said the rule change would add costs to existing power purchase agreements.
“If we can address the rule change, we’re taking a negative from the system, and that has a lot of global benefits,” Collins said. “We don’t deny some resources will face increased costs, but we believe the whole market can benefit from that.”
SPP Operations Vice President Bruce Rew said the rule would lead to a more efficient market through better management of congestion.
“It’s a much smoother operation for us to be able to dispatch those resources that may be down at the time, rather than the generator making that decision when to come on and off,” Rew said.
While the board was forced to table one voting item, it took another one off the table when it approved a sponsored upgrade of an OG&E transmission line that MOPC was unable to take action on.
OG&E requested MOPC delay a vote until it could address its concerns about the upgrade with SPP. The project is sponsored by EDF Renewable Energy, which wants to upgrade terminal equipment and rebuild an 11-mile, 138-kV line near Ponca City and its 154-MW Rock Falls wind farm, which became operational in December. (See “OG&E Raises Concerns over Third-party Tx Line Upgrade” in SPP Markets and Operations Policy Committee Briefs: April 17, 2018.)
SPP answered all 23 of the questions submitted to it by OG&E, but the utility said it still has questions about the project’s cost allocation and asked for additional time to get answers.
“This is a small project, in and of itself. It’ not going to break the bank for anybody,” OG&E’s Greg McAuley said. “The precedent here is what some of the [transmission owners] are concerned about. If you had a $100 million to $200 million project, you would see a much different amount of concern. We’re continuing to work to close the gaps in the Tariff we think exist, so we still ask for additional time to get those questions answered.”
EDF has said it will seek cost recovery through SPP’s Attachment Z2 revenue crediting or incremental long-term congestion rights. Attachment Z2 of SPP’s Tariff assigns financial credits and obligations for sponsored transmission upgrades, with directly assigned Z2 network upgrades allocated to SPP’s base plan.
“A project like this, if it just remains between EDF and OG&E, I don’t think it will have impacts,” said Nebraska Public Power District’s Paul Malone, who chairs the MOPC. “But to the extent this project qualifies for Z2 credits, we’re all going to end up paying for that. Thus, the vested interest.”
Attorney Dan Simon represented EDF and said he saw no legal reason for members to delay their endorsement of the project.
“We’ve gone through the process as dictated by the Tariff and the staff,” Simon said. “We understand OG&E has a number of important questions,” but “all of those questions are things that are already dictated by the current language in the Tariff,” and therefore do not provide a justification to delay the request.
Simon said EDF worked with OG&E to develop a cost estimate before it submitted its official upgrade request to SPP, noting OG&E did not raise concerns until the MOPC meeting.
“It’s been based on that information that we’ve continued to proceed through the transmission process to submit this request. We don’t think it’s appropriate to allow these questions coming so late in the process to delay our upgrade request,” he said.
“This project is time-sensitive. The sooner this gets placed into service, the sooner it will relieve congestion, and we all realize economic benefits from that,” Simon said.
The measure passed the Members Committee by a 14-3 margin, with OG&E, American Electric Power and the Omaha Public Power District voting in opposition. The Oklahoma Municipal Power Authority abstained.
MMU Shares Draft of State of the Market Report
Collins shared the MMU’s draft of its annual State of the Market Report with the board and members. He declared the market to be “competitive and efficient,” citing low energy prices, declining mitigation and make-whole payments, along with declining levels of excess online capacity and the alleviation of a congestion bottleneck.
Collins said total market costs last year approximated $24/MWh, a 7% increase from 2016, driven by a 14% rise in natural gas prices. As an example, the MMU pointed to the Panhandle hub, where the average gas price increased from $2.32/MMBtu in 2016 to $2.65/MMBtu in 2017.
Wind resources accounted for about 70% of the SPP footprint’s 2.2 GW increase in nameplate generation capacity last year, but the rate of new additions has declined significantly. SPP added about 11.4 GW of generation in 2015 and 3.9 GW in 2016.
“Even so, wind generation continued to increase as it represented almost 23% of system generation, up from 18% in 2016 and 14% in 2015,” the MMU said. In contrast, coal-fired units saw their share of total generation continue to slide, from 55% or more before 2016 to 46% last year.
Collins said SPP has a reserve margin of about 30%. “That can contribute to the high levels of competition we see,” he said.
He noted several issues that bear watching in the months ahead:
Self-commitment has declined but is still high overall.
Wind generation is under-scheduled in the day-ahead market.
The frequency of negative prices has doubled.
Real-time price volatility has increased.
Congestion has increased significantly.
Very few resources are being retired.
The final report will be released later in May.
Director Josh Martin, who chairs the Oversight Committee that oversees the MMU, said the monitor is fully staffed “for the first time in a long time.” The MMU added CAISO’s Adam Swadley as its lead economist to reach its full staffing level.
Finance Committee Looks to Engage Stakeholders
Finance Committee Chair Larry Altenbaumer told the board and members the committee has been studying a recovery mechanism that “appropriately” reflects the administrative fee as it tries to maintain a simple rate-design structure.
The committee has determined membership’s “full engagement” is necessary, Altenbaumer said, and will work with MOPC’s leadership in July to involve a broader stakeholder group.
The board unanimously approved three recommendations from the Finance Committee:
Accepting BKD’s 2017 financial audit, which noted “no issues or material/significant weaknesses.”
Engaging BKD to perform the 2018 financial audit and Thomas & Thomas to audit the employee benefit plan’s financial statements.
Taking out an $80 million bank loan with a 5-year maturity and floating rate pricing on outstanding balances under the guidance line.
SPP RE Tying Up Loose Ends
“As you all know, we’re going out of business,” said Dave Christiano, chairman of the SPP Regional Entity’s board of trustees, as he delivered what is likely to be the final RE update to the board.
Christiano said the RE will cease its compliance and enforcement activities by the end of June and be officially dissolved by September. The RE has already successfully transferred 25% of its data to NERC, the Midwest Reliability Organization and the SERC Reliability Corporation, he said, but it still has a number of loose ends to resolve.
“It’s pretty complicated, as you can guess,” Christiano said
SPP said last July it would dissolve the RE, ending a reliability oversight role that has been a source of concern at NERC and FERC. NERC approved the dissolution in February. (See NERC Board Approves Dissolving SPP Regional Entity.)
The RE’s staff of two dozen has dwindled to 17 employees, with all but five either having already found work within the RTO and other organizations or having decided to retire.
Christiano also recommended members read a joint report from the FBI and Department of Homeland Security, “Russian Government Cyber Activity Targeting Energy and Other Critical Infrastructure Sectors.”
SPP’s 2017 Annual Report: ‘Focus’
As it does every April, SPP handed out copies of its 2017 annual report during the meeting.
The report, titled “Focus,” highlights the “people, milestones, accomplishments, and challenges that made 2017 another exceptional chapter in [SPP’s] story.”
SPP’s 2017 Annual Report | SPP
The report includes comments from a broad section of SPP staffers and how they work with their members.
Last Board Meeting for Westar’s Harrison
The board meeting was the last for Westar Energy’s Kelly Harrison, who represents public transmission-owning members on the Members Committee.
Harrison, who is nearing 60 years of age, said he is taking advantage of the Westar-Great Plains merger to take retirement. He said he would miss the SPP meetings, as well as the people who attend the meetings — who treated Harrison to a standing ovation.
“I, for one, am extremely appreciative of the care and the intellect Kelly has brought to the Members Committee,” Brown said, singling out Harrison’s financial acumen and participation on the Oversight Committee. “I couldn’t begin to count all the task forces and working groups Kelly has worked on over the years. Thank you, Kelly, from the bottom of my heart.”
Members unanimously approved the consent agenda, which included the re-baselining of a Nebraska Public Power District 69-kV and 161-kV project from $37.8 million to $27.5 million; a sponsored upgrade with the addition of a second 161/69-kV transformer at City Utilities of Springfield’s (Mo.) James River Power Station; funding the SPP retirement and post-retirement healthcare plans; and seven revision requests.
GIITF RR267 eliminates the “standalone scenario,” which considers each interconnection request by itself, from the definitive interconnection system impact study process. This will free SPP resources to focus on binding cluster study results, permitting their earlier availability. Staff will provide the standalone equivalent study models through existing confidentiality provisions to customers seeking to conduct a standalone scenario of their own.
MWG RR252 assigns an out-of-merit energy (OOME) cap and/or floor, allowing staff to economically dispatch the resource down or up within the ranges.
MWG RR259 modifies the market settlement posting and dispute timelines being implemented with the new settlement system, reducing the number of resettlement postings and manual processes resulting from revisions to meter and bilateral settlement schedules.
MWG RR273 automates several of the market settlement system’s charge types that are not yet part of revenue neutrality uplift processing, resulting in rounding/residual amounts that must be manually processed and distributed through miscellaneous charges. The new system is scheduled to go live in May 2019.
ORWG RR268 clarifies or removes outdated language from the operating criteria, improving SPP’s ability to perform reliability coordinator, balancing authority, transmission service provider and reserve sharing group functions.
ORWG RR269 clarifies language and removes antiquated and redundant language in SPP’s operating criteria and describes the existence of multiple standalone documents.
ORWG RR270 converts the operating criteria Appendix OP-2 to a standalone document, clarifies language and adds formatting improvements.
