The D.C. Circuit Court of Appeals last week dismissed the Kansas Corporation Commission’s appeal of a 2015 FERC ruling over formula rates, saying it lacked standing in the case (No. 16-1093, 16-1164).
The KCC argued before the court in November that FERC acted unlawfully by approving formula rates for future public utilities to use in operating electric transmission facilities. The Kansas commission asserted that FERC couldn’t determine that the formula rates for “not-yet-existing entities to implement at some point in the future” are just and reasonable.
D.C. Circuit Courthouse | U.S. Court of Appeals
Writing for the three-judge panel on Feb. 6, Judge Karen Henderson said the KCC had not suffered harm sufficient to establish standing. “A harm that will not occur unless a series of contingencies occurs at some unknown future time is not concrete, particularized, actual and imminent,” she said.
The Kansas commission was appealing a 2015 FERC decision, in which the agency granted Transource Energy’s request for formula rates for future affiliates by replicating approved rates for Transource Kansas. Transource formed the wholly owned subsidiary to compete for Kansas-based transmission projects in SPP and said it expected to create additional subsidiaries in the future.
FERC rejected the KCC’s rehearing request in 2016, ruling that preapproving a formula rate for Transource Kansas, which did not operate any active transmission facilities, was “no different” from preapproving a formula rate for future Transource affiliates.
The KCC’s appeal to the D.C. Circuit also included a similar FERC proceeding involving MPT Heartland Development, which formed Kanstar to compete for Kansas-specific projects. The federal agency in 2015 approved Kanstar’s request for a formula rate for its own use and that of future affiliates and later denied the KCC’s rehearing request.
The court consolidated the two appeals.
In November, the KCC lost another appeal in the D.C. Circuit when it attempted to challenge a 2014 FERC order approving SPP’s merger with the Integrated System. (See Court Rejects Challenge to SPP-Integrated System Merger.)
CARMEL, Ind. — MISO maintained reliable operations in its South region during a record January cold snap that saw the area’s peak loads approach summertime highs, the RTO said last week.
Tim Aliff, MISO director of system operations, provided a post-mortem of the event at a Feb. 8 Market Subcommittee meeting. He recounted that a second blast of arctic air hit MISO South in mid-January, less than two weeks after extreme cold had gripped most of the RTO’s footprint and sent peak demand well above 100 GW. (See MISO Breaks down Recent Cold Snap.)
| MISO
Uncharacteristically frigid weather prompted MISO to initiate a maximum generation alert for the South region for Jan. 17-18, when the region’s peak loads were hovering above 31 GW. With low temperatures averaging 13 degrees Fahrenheit on Jan. 17, MISO South’s peak load hit 32.1 GW, just short of the region’s all-time high of 32.7 GW set in August 2015.
Throughout the day on Jan. 17, MISO South temperatures remained about 20 to 25 degrees lower than normal. MISO committed all available resources in the region, compelling load-serving entities to make emergency energy purchases from neighboring balancing authorities between about 7:25 a.m. and 12:55 p.m., with purchases topping at about 1.1 GW around 8 a.m. Aliff said MISO’s emergency pricing floors worked as designed when initiated on Jan. 17, with average LMPs spiking just above $1,000/MWh during the peak of buying.
| MISO
MISO South analysts also reported about 17 GW of generation outages and derates that day, including nearly 10 GW in forced generation outages, further stressing the region’s system, Aliff said. By then, Louisiana and the Gulf Coast were ensnared in what the Weather Channel would dub Winter Storm Inga.
MISO asked for South utilities to undertake load management measures, prompting Louisiana state regulators to question the need for conservation. (See Louisiana Regulators Question MISO South Max Gen Event.) MISO South has no registered emergency demand response resources within its boundaries.
Aliff said MISO will continue to review the event to determine what process improvements it could make as it heads into summer, when more emergency conditions are likely to occur. He said MISO has yet to analyze the load-modifying resource performance in MISO South during the weather event.
The staff of the Texas Public Utility Commission last week recommended that it require Vistra Energy and Dynegy to divest at least 1,281 MW of generation to secure approval of their merger.
Vistra’s power generation subsidiary, Luminant Generation, challenged the staff recommendation, assuring the PUC that market power would not be an issue (Docket No. 47801).
PUC staff filed the recommendation on Feb. 5, calling for approving the merger conditioned on Vistra and Dynegy divesting themselves of enough Texas generation to stay below the statutory cap of 20% of ERCOT installed capacity.
Staff said the two companies exceeded the limit because Dynegy owns 820 MW of generation in the Eastern Interconnection “capable of delivering electricity to ERCOT” over DC ties. Staff ruled that capacity should be included in Luminant’s market share calculation.
Dynegy’s Morro Bay Plant in California
Together, Luminant and Dynegy own almost 18 GW of generation in Texas. Dynegy also owns 21.6 GW outside the state that isn’t deliverable to ERCOT. Including the 820 MW of generation deliverable over the DC ties would give the companies 21.46% of the Texas ISO’s capacity.
Staff said in their memo that Luminant and Dynegy have committed not to import power over the DC ties. However, they said, the arrangement “fails to satisfy the statutory language, because a commitment on [their] part to not import power … does not negate their capability of doing so.”
In its response filed Friday, Luminant asked the PUC to exclude the 820 MW, based on the entities’ commitment to not import power. The generation firm said a “reasonable mitigation” would be acceptance of the companies’ commitment not to import power and allow the transaction to close without any divesting generation.
Luminant’s Forney Plant | Energy Future Holdings
Luminant also requested its 915-MW Lake Hubbard gas-fired plant be excluded from the market power analysis, saying it was grandfathered as part of a 2000 agreement with the PUC (Docket No. 28081).
The company told the commissioners it is working with staff on a proposed order. The PUC has an open meeting Feb. 15, but the agenda has not yet been posted.
In their filing, staff recommended several changes to the proposed transaction:
Divesting the generation should the commission find the combined installed capacity exceeds the 20% cap;
Termination of a 2015 voluntary mitigation plan (Docket No. 44635);
Self-monitoring compliance with the cap;
Filing quarterly compliance reports for two years or until the combined company falls below 18.5% of ERCOT’s total; and
Filing a written report with the PUC within 30 days on noncompliance with the 20% cap.
Vistra announced its $1.7 billion acquisition of Dynegy in October. The all-stock deal will create a generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. The proposed acquisition requires regulatory approvals from FERC, the PUC and the New York Public Service Commission. (See Vistra Energy Swallowing Dynegy in $1.7B Deal.)
Xcel Energy last week reported fourth-quarter earnings of $189 million ($0.37/share), down 16.7% from the same period last year.
But for the year, the Minneapolis-based company reported earnings of $1.15 billion ($2.25/share), up from $1.12 billion ($2.21/share) in 2016.
Colorado wind farm | Xcel Energy
Both quarterly and yearly earnings dropped 5 cents because of a one-time expense related to the federal Tax Cuts and Jobs Act passed in December.
CEO Ben Fowke said during Xcel’s earnings call that the tax bill “provides the opportunity” to lower consumers’ bills and make additional investments “in areas that are important for our customers.”
The company is involved in pending rate cases in several of the states in which it operates, all of which were filed before the new tax legislation was proposed.
“In these cases, and in other jurisdictions, we’re having active discussions and formal proceedings with our regulators regarding the impacts of the Tax Cuts and Jobs Act and how we will provide the expected benefits to our customers,” CFO Bob Frenzel said. “Ultimately, tax reform results in lower taxes, lower deferred taxes and, correspondingly, lower cash flow metrics.”
The company said it expects to “moderate” its five-year capital expenditure plan by $500 million and issue up to $300 million of additional equity. It said it successfully completed CapEx 2020, a 13-year project involving more than 800 miles of transmission lines, $2 billion of investment and working with 11 different utilities.
The American Wind Energy Association’s top utility wind-energy provider for the 12th straight year, Xcel said its “Steel-for-Fuel” strategy — which replaces fossil fuel plants with wind turbines — resulted in regulatory approval for 1,550 MW of new wind resources in the Upper Midwest, a proposed 300-MW wind farm in South Dakota, and settlements in principle for 1,230 MW of wind in Texas and New Mexico during 2017.
Pacific Gas and Electric CEO Geisha Williams said Friday that the utility will fight for the right to recover costs stemming from California wildfires “in the legal, regulatory and legislative arenas.”
San Francisco-based PG&E and other investor-owned utilities are being investigated for causing the devastating fires that wracked the state last year. Investigators for the California Department of Forestry and Fire Protection have not yet found evidence indicating the fires were caused by IOU infrastructure.
Williams said PG&E will seek a rehearing of the California Public Utilities Commission’s decision to deny San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Heavy winds exacerbated the effects of the deadly infernos that swept across the region.
“It’s bigger than just PG&E and the other California IOUs, and much bigger than just this past year’s fires,” Williams said of the wildfires, drawing a link between them and climate change. “This is a collective societal challenge.”
PG&E reported $13 billion in electric operating revenues in 2017 and associated operating expenses of $4.3 billion. Net income was $1.6 billion after taxes, compared with $1.4 billion in 2016 and $861 million in 2015.
The 2017 Tubbs and Pocket Fires in Northern California
The company had earlier announced a suspension of dividends amid uncertainty over its liability associated with last year’s Northern California fires. For the fourth quarter of 2017, GAAP results were $114 million ($0.02/share) compared with $692 million ($1.36/share) for the same quarter in 2016.
No Challenge to Diablo Canyon Decision
PG&E also said it will not contest a CPUC ruling that granted the utility just a fraction of the cost recovery it had requested for retiring the Diablo Canyon nuclear power plant, the last remaining nuke in a state where more than 60 such plants were proposed in the 1970s.
Diablo Canyon Nuclear Power Plant | PG&E
PG&E said “today’s announcement comes after all the parties had the opportunity to confer” following the CPUC’s Jan. 11 decision on the joint proposal agreement. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
CARMEL, Ind. — Market participants have united to develop a trio of alternatives to MISO’s plan to crack down on generators that fail to follow dispatch instructions, while the RTO has softened its position on moving ahead with a nearly final proposal.
Stakeholders representing 13 member companies began meeting to address the issue after MISO last November revealed its plan to tighten tolerances for uninstructed deviations based on a generator’s ramp rate. MISO currently flags generators that deviate from dispatch by more than an 8% over four consecutive intervals.
During a Feb. 8 Market Subcommittee meeting, DTE Energy’s Nick Griffin said informal meetings with MISO staff and the Independent Market Monitor to “brainstorm” on the topic have produced three proposals to curb deviations:
Rely on MISO’s proposal requiring a generator to move at least half its offered ramp rate, but use a more generous ramp rate multiplier;
Use a standard 6% deviation tolerance from dispatch signals; or
Employ an “energy mileage” concept that would set a tolerance based on how much electricity a unit actually moved over a one-hour period compared to how much it was asked to move.
Griffin said all three encourage generators to follow dispatch signals.
“We don’t want units to drag on the system and be paid for dragging on the system,” he said.
However, Griffin said MISO’s solution must consider the “operational limits of resources, including wind forecasting and coal mill and boiler feed pump limits.”
Stakeholders have repeatedly called for a softer uninstructed deviation threshold than what MISO is proposing.
Before this month, MISO was close to wrapping up a final approach on stricter rules using Monitor David Patton’s proposal requiring generators to move at half their offered ramp rate, with a 20-minute grace period before being flagged and possibly losing make-whole payments. Last fall, Ameren Missouri urged MISO to keep the percentage threshold, saying it could be constricted to 7 or 6% over time. The company also asked the RTO to focus only on generators that fail to move for an hour after dispatch instructions. (See Ameren Calls for Milder MISO Response to Uninstructed Deviations.)
MISO staff are now offering two new proposals developed after the informal stakeholder meetings. The first is a slightly modified approach of the RTO’s original proposal, with a cap of 12% of the dispatch level instead of the previously proposed 10%, leaving more tolerance for fast-ramping units.
The second is a performance-based approach similar to the “energy mileage” concept that partly decouples MISO’s uninstructed deviation rules from price volatility make-whole payments, preventing a generator’s deviation from immediately triggering ineligibility for those payments. In those instances, MISO would rely on an hourly price volatility make-whole payment calculation based on generator performance, ensuring that unit owners are incentivized to submit accurate ramp rates and then perform to them. The payments are designed for resources that either fail to cover production costs in the market, or have their day-ahead margins eroded by intra-hour price spikes.
MISO Market Quality Manager Jason Howard said the RTO still plans to have a final proposal readied for filing in time for the April subcommittee meeting, and that he would return to the subcommittee in March after gauging stakeholder reception to the two new proposals. MISO is also considering holding a workshop to ensure stakeholders understand what it is proposing, Howard said, although no date has been set.
CARMEL, Ind. — MISO is scaling back a proposal to develop a multiday energy market, opting instead to create multiday forecasts intended to provide generators more advanced insight into ramping up for future day-ahead commitments.
The change takes the potential for multiday make-whole payments out of the equation.
The proposed effort will forecast price signals a week in advance but leave unit owners the option of whether to abide by them. As a result, MISO has scrapped the idea of providing make-whole payments to units that follow the RTO’s recommended commitment. MISO has also pushed back the target go-live date from 2019 to 2021 but still expects the effort to yield $30 million to $45 million in annual benefits once implemented. (See MISO Researching 30-Minute Reserves, Multiday Commitments.)
MISO Markets System Analyst Chuck Hansen said the RTO will assemble a cost-benefit analysis in 2022 or 2023 that could make or break the case for creating financially binding multiday commitments — after it collects 18 months of data using the multiday forecast.
Until then, the RTO sees comparable value in producing seven-day forecasts to influence generator commitment decisions without pressure, Hansen said. Market participants likewise sought to have the multiday market forecast before attaching financial commitments to it.
“There’s an opportunity here from a MISO fleet perspective to improve commitment decisions,” Hansen told stakeholders at a Feb. 8 Market Subcommittee meeting.
MISO’s current day-ahead market construct is not designed to forecast economic commitments beyond the next day, leaving units that have long leads or high start-up costs unable to economically commit in the market. Hansen said only 22% of the RTO’s capacity is economically committed in the day-ahead market, with the remaining 78% committed before the day-ahead market on a must-run basis, creating a prime opportunity to improve commitment decisions made before the day-ahead run. He also said a multiday forecast could be useful in scheduling weekend natural gas purchases and scheduling pumped storage resources.
| MISO
Hansen added that MISO does already complete a multiday reliability look-ahead, but it’s solely focused on reliability and ensuring sufficient capacity and does not make suggestions based on economics.
MISO will begin working on conceptual design of multiday forecasts in 2019, Hansen said.
MISO’s Independent Market Monitor is seeking to use the RTO’s recent refiling of its resource adequacy construct to force a FERC ruling on changing its capacity demand curve.
In an out-of-time Feb. 8 protest, the Monitor contends MISO’s use of a vertical demand curve in its annual Planning Resource Auction is a “critical design flaw” that results in “inefficient, unjust and unreasonable prices” (ER18-462).
| Potomac Economics
On Dec. 15, MISO pre-emptively refiled its entire resource adequacy construct — Module E of its Tariff — following a D.C. Circuit Court of Appeals ruling that FERC overstepped its jurisdiction when prescribing revisions to PJM’s minimum offer price rule. MISO made the filing out of concern that a future ruling could undo some of its resource adequacy rules that were enacted in response to FERC’s suggestions. (See MISO Seeks FERC Reapproval to Keep RA Rules Intact.)
The filing provided the IMM a venue for forcing a FERC ruling on the sloped demand curve, a change Monitor David Patton has been unable to persuade MISO officials to adopt. Patton asked the commission to accept MISO’s filing for the 2018/19 PRA while initiating a proceeding under Federal Power Act Section 206 to force the RTO to make the changes for the 2019/20 PRA.
In 2011, FERC accepted MISO’s current resource adequacy rules, which replaced a monthly capacity auction with an annual auction using coincident peak demand forecasts to establish planning reserve requirements (ER11-4081).
FERC directed MISO in 2011 to remove proposed MOPR provisions from its capacity auction construct and instead use a peak load contribution methodology as its default for assigning capacity obligations.
The Monitor said that had MISO relied on sloped demand curve in its 2017/18 PRA, the auction would have cleared at about $115/MW-day instead of the $1.50/MW-day price in all zones. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.) The higher price would have properly valued the reliability of the capacity, the Monitor claims.
The Monitor said the $1.50/MW-day clearing price offers suppliers less than 1% of revenues needed to break even on investment in a new peaking resource in MISO. The auction’s unreasonably low prices, Patton said, cannot support new investment “at levels that would satisfy the one-day-in-10-years reliability standard.”
“The commission relies on well-designed competitive markets to produce prices and market outcomes that are just and reasonable. No objective analysis of the MISO capacity market could demonstrate that the outcomes under the current Module E are just and reasonable by any appropriate standard. In fact, the flawed design of the market precludes it from producing just and reasonable prices. … Further, MISO made no attempt to provide evidence that its capacity market has produced reasonable outcomes or that it is an economically sound market design,” the Monitor wrote.
The Monitor also pointed to MISO’s unsuccessful 2017 filing to implement a partial forward market and downward-sloping demand curve for its retail choice areas — in which the RTO admitted that its capacity market has not produced efficient prices. During stakeholder meetings on the design proposal, Patton often repeated the need for a systemwide sloped demand curve. (See MISO Won’t Seek Rehearing on Auction Redesign.)
The Monitor’s protest came almost four weeks after the Jan. 12 deadline for filing responses to the RTO’s refiling. It said the commission should permit its out-of-time filing, contending it will not prejudice any party in the proceeding because it has not yet acted on MISO’s refiling.
In early January, the Electric Power Supply Association also protested MISO’s refiling, claiming that the RTO’s existing construct is “fundamentally flawed and has failed to support resource adequacy in the region because it lacks critical capacity market elements the commission has approved (or required) for other ISOs/RTOs.” EPSA said MISO should require capacity auction participation by all supply and demand resources, implement a downward-sloping demand curve with auctions held at least three years ahead of time and enforce a MOPR. Those three elements, EPSA argued, would create a “sustainable forward capacity market” in the footprint.
CARMEL, Ind. — MISO is proposing to set limits on the amount of time its members have to initiate alternative dispute resolution measures, but stakeholders are saying the RTO might not be leaving them enough room to research and raise settlement issues.
The RTO is recommending market participants have a 30-day time limit to request either an informal or formal alternative dispute resolution, John Weissenborn, director of market services, told a Feb. 8 Market Subcommittee meeting. Settlement disputes and corrections would be wrapped up within one year from the operating day in question under the proposal, he said.
The process is used in place of a lawsuit or FERC complaint when parties seek to negotiate contractual disputes over settlements. The RTO’s current Tariff doesn’t contain provisions that “categorically bar settlement disputes raised after a long time,” according to MISO.
MISO plans to revise Attachment HH of its Tariff — which governs such disputes — to provide market participants with 30 calendar days from the RTO’s denial of a settlement dispute to ask for an informal alternative dispute resolution, then another 30 days after that to request a formal dispute resolution if the informal request is denied by MISO.
Weissenborn said the deadlines will apply to both transmission and market settlements. The deadlines will promote “market certainty, prevent stale claims and facilitate accuracy in corrections of settlement statements,” he said.
MISO is aiming to file the plan with FERC by May, with the deadlines imposed by July.
Weissenborn said other RTOs have time limits ranging from five months to three years. Both SPP and PJM impose a two-year cutoff, while CAISO follows a three-year limit. NYISO employs the shortest cutoff at five months.
“There is precedent for this type of thing,” Weissenborn said. “It will encourage market participants to file their claim in a timely manner.”
Northern Indiana Public Service Co.’s Bill SeDoris and Dynegy’s Mark Volpe both asked how MISO’s one-year limit will line up with other RTOs’ disparate time limits should disputes involve inter-RTO matters, such as pseudo-ties and coordinated transaction scheduling, and which timeline MISO market participants should follow.
Weissenborn said MISO looked into such transactions and concluded that alternative dispute resolution would be separate for each RTO’s settlement.
Other stakeholders cautioned that the 30-day limit to research and initiate a dispute resolution may be too tight, asking instead for 60 or 90 days to initiate a dispute.
Weissenborn asked for more stakeholder comments over the next two weeks and said the comments could influence the final draft of MISO’s plan.
Lubbock’s City Council and Electric Utility Board last week both approved a settlement agreement with all parties involved in Lubbock Power & Light’s effort to move 470 MW of its load from SPP to ERCOT.
The agreement, with intervenors from both systems, was approved unanimously in separate votes. Following the board’s vote, LP&L on Thursday filed the stipulation and proposed order with the Public Utility Commission of Texas for its consideration. The PUC is scheduled to take up the issue during its Feb. 15 open meeting (Docket No. 47576).
LP&L power plant | LP&L
Under the agreement’s terms, LP&L will make a $24 million hold-harmless payment to Southwestern Public Service, which serves the utility’s load through a pair of long-term contracts, upon the transition’s effective date (targeted for June 1, 2021). The utility will also make five annual payments of $22 million, credited to ERCOT’s transmission customers in compensation for integration costs, and has committed to opting into the Texas ISO’s competitive market.
Preferred Option 4OW for Integrating LP&L | ERCOT
LP&L said it expects to achieve annual savings exceeding the two payments.
“The agreement … sets Lubbock on the best possible path forward that saves their ratepayers money and opens the door to retail electric competition in Lubbock,” the utility said in a statement.
The only issue left to decide is what entity will build the transmission facilities linking LP&L with ERCOT. The parties signing on the settlement agreement, which include PUC staff, SPS and several consumer groups, have recommended moving forward with a project already identified by ERCOT. A pair of independent transmission companies, Cross Texas Transmission and Wind Energy Transmission Texas, are urging the PUC to open the construction to competitive bidding.
ERCOT in 2016 said its preferred solution was “Option 4ow,” a $364 million project that would result in 141 miles of new 345-kV lines. Staff last week said a competitive bidding process would “consume time and commission resources” not needed if the PUC simply followed ERCOT protocols, which provide “a suitable guide in this unique situation.” (LP&L is not yet registered in the ISO and therefore not covered by its protocols.)
| ERCOT
Cross Texas said it envisions a competitive bidding process, conducted by the PUC, that could be accomplished in about 90 days.
LP&L formally announced in September its intention to move after one of its SPS contracts expires in 2021. A second SPS deal that expires in 2044 serves the remaining 130 MW of its load.
