MISO said last week that it is ready to begin introducing improved modeling of its combined cycle generating fleet.
The RTO will use a configuration-based combined cycle model that can mimic different combinations of combined cycle units and their dependencies, Yonghong Chen, MISO principal advisor of market development and analysis, said during a Nov. 1 Market Subcommittee conference call.
Currently, MISO’s roughly 40 combined cycle unit “groups” are subject to an aggregate model in which they must either bid as a single generator or bid as separate combustion or steam turbines; dependencies between the units are not modeled. A generator with two combustion turbines and one steam turbine would constitute a “group.”
MISO said the new modeling will increase bid accuracy and prevent infeasible scheduling. Chen said the RTO performed a rough analysis using eight sample cases and found the new model could have saved $47 million in annual production costs in 2014 and $16 million in 2015. The analysis studied MISO’s 20 combined cycle groups with reliable configuration data and assumed other combined cycles would stick to the aggregated model.
Chen said the modeling can be used with the current 40 combined cycle generator groups in MISO’s system, but doubling or tripling the number of groups under the model would create computational challenges.
She also said MISO will look for further improvements and continue to study the benefits of the new modeling throughout 2017 using more updated offer data from resource owners and optimization software from programming firm Gurobi Optimization.
Jeff Bladen, executive director of MISO market services, said the RTO “expects to spend meaningful resources on combined cycle generators” in 2017 given the potential benefits.
MISO May Tweak Emergency Pricing Floors
Following a summertime emergency pricing event that resulted in depressed prices, MISO is considering changing its emergency offer floor calculations to expand the pricing logic to more emergency power.
MISO predicted load would hit 130 GW on July 21 based on a forecast that temperatures would hit a record of 91. The load didn’t materialize because of thunderstorms that lowered temperatures. | MISO
MISO had been monitoring performance of its two emergency pricing floors since July 21, the first maximum generation event since the 2014 polar vortex. Based on a forecast that average temperatures in the footprint would hit a record of 91, load on July 21 was predicted to hit 130 GW. But the load didn’t materialize because of thunderstorms that lowered temperatures. (See “New Emergency Pricing Floors Undergoing Monitoring,” MISO Market Subcommittee Briefs.)
Michael Robinson, principal adviser of market design, said MISO is mulling five possible approaches, all of which require Tariff changes:
Implementing an offer cap to the emergency offer floors, which unlike the other solutions would not require a software change;
Allocating the commitment costs of offline fast-start units into the minimum run time when calculating the offer floor;
Expanding the emergency pricing logic to allow emergency-committed units dispatched at their economic minimum prices to set emergency prices, similar to how fast-start resources can set prices under extended locational marginal pricing;
Applying emergency pricing to non-firm export curtailments; and
Evaluating the need to further compensate deployed emergency resources when LMPs, make-whole uplift and capacity credits are not sufficient.
Robinson said MISO could consider further changes as well. MISO is asking for stakeholder input through Nov. 18.
“We want to make sure we’re sending the right prices to as many generators called up as we can,” Bladen told stakeholders.
New York’s generators have appealed to the NYISO Board of Directors to reject a rule change that would effectively cap capacity payments received by generators in a constrained zone.
| Independent Power Producers of New York
The Independent Power Producers of New York filed its appeal Nov. 1 seeking to overturn the Management Committee’s Oct. 25 vote capping capacity payments in the Lower Hudson Valley and New York City zones to protect consumers from higher prices. (See NYISO OKs Capacity Export Fix Over Generators’ Opposition.)
Responses to IPPNY’s appeal are due Nov. 8; the board is expected to take up the appeal at its next meeting on Nov. 14-15.
Supporters of the rule change concede that the cap is not justified by any analysis done by NYISO staff.
“Because [the cap] is unsupported, will distort market signals, will harm reliability and will set a dangerous precedent that will embolden load interests to use the stakeholder process rather than the competitive markets based on sound and efficient market design to set prices, it cannot be found to be just and reasonable,” the petition says.
The appeal will be a “paper proceeding” unless a party requests oral arguments, NYISO spokesman David Flanagan told RTO Insider on Friday. “No such request has been received at this time,” Flanagan said.
The proposed rule change is in response to FERC’s Oct. 17 order accepting ISO-NE’s changes to its annual capacity reconfiguration auctions. The motion was carried with a 63% vote in favor, above the required supermajority of 58%.
Con Ed’s Astoria Generating Station would be impacted by the cap.
FERC’s ruling allows Castleton Commodities International’s 1,242-MW Roseton 1 generator, located 43 miles north of New York City in NYISO’s capacity import-constrained G-J locality, to supply 511 MW of its capacity to ISO-NE beginning next June for the 2017/18 delivery year.
Appeals of committee motions are rare and reversals are even rarer. According to the NYISO website, there have been 28 appeals since 2000, with 20 being denied, three motions reversed and five sent back to either the committee or staff for further action.
SPP stakeholders are considering the use of incremental long-term congestion rights (ILTCRs) to help solve some of the complexity with the RTO’s Z2 crediting process, a contentious issue that dates back to 2008.
Meeting in Kansas City last week, the Z2 Task Force spent considerable time discussing ILTCRs — a form of financial transmission rights used by most other RTOs and already included in SPP’s Tariff — as part of the transmission-congestion rights market.
The top 10 creditable upgrades represent $89.4 million, more than three-quarters of the total Z-2 assessments. | SPP
In lieu of cash compensation, upgrade sponsors would be eligible to receive ILTCRs as credit for their financial contributions to grid improvements, as the upgrades increase the available transfer capability on the system.
SPP’s outside legal counsel, D.C.-based Wright & Talisman, provided the results of its research on how other RTOs’ Tariffs compensate entities that sponsor network transmission upgrades. CAISO, ISO-NE, MISO, NYISO and PJM all apply some form of compensation through congestion rights or incremental auction revenue rights, according to the report.
“While the terminology, form, amount and duration varies from RTO to RTO,” the report said, “most RTOs provide these incremental ARRs on a long-term basis based on the incremental transfer capability provided by the upgrade.”
SPP’s TCR “market is still a little bit different than MISO or PJM’s, because SPP models on point of delivery, whereas in other markets it’s financial,” said Denise Buffington, Kansas City Power & Light’s director of energy policy and corporate counsel, and the task force chair.
The task force will continue its discussion with an educational session in Dallas on Nov. 29, during which it will bring in several subject matter experts to help the group examine SPP’s TCR market and its generation interconnection and aggregate study processes, among other items.
“I want more information. I don’t want to go into the weeds, but I want to know the pressure points and how one impacts the other … and begin connecting the dots,” Buffington said. “The problem we still face is an education problem. Every time we talk about [Z2], we learn something new — or about something else that touches it.”
In addition to ILCTRs, the group discussed five other options staff offered to improve the Z2 process:
Base plan funding: All upgrades, regardless of their origin, would be included in the current cost allocation methodology. This would recognize that the regional planning and operational processes will optimize all the available transmission.
Reverse engineering: SPP staff has reverse engineered the Z2 process and its associated data inputs, identifying potential modifications to simplify the process, including annual Z2 billing; revising the Tariff’s transmission payment schedules; removing short-term transmission service requests (TSRs) from the process; using annual transmission revenue requirements for point-to-point credit-payment obligations; posting impact ratios for each TSR; using an alternate source for transmission distribution factors; removing short-term TSRs from stacking; and a hybrid solution combining most of the modifications.
Upgrade sponsor-facilities rider (USFR): Consistent with the current Z2 revenue crediting process, sponsors would retain responsibility for reimbursing the owner that builds the creditable-upgrade facilities and the funds used to compensate the sponsors collected from users of the facilities. The process would be simplified by substituting a USFR in part of the crediting process by recovering the facilities’ engineering and construction costs over a specified number of months. The USFR rate would be an add-on charge applicable only to customers using the creditable-upgrade facilities, and funds would be distributed to the sponsor.
Construction credits: Allows the upgrade’s sponsor to receive credits against its transmission service invoice up to, but not above, the amount of engineering and construction costs paid to the entity that built the upgrade.
Toll-road option: Similar to the approach used to fund toll roads, the funding entity is repaid over time by those who use the upgrade. Staff would calculate transmission impacts on a new facility once it is constructed, and all subsequent customers would be charged a fee for use of the line. The sponsor would receive funding from that use until it recoups to the cost of the facility.
All of the options are still in play. Buffington told her fellow stakeholders she hopes they bring their own proposals or a ranking of those on the table to a January task force meeting before the Markets and Operations Policy Committee meeting. The task force expects to finish its work by April.
In the interim, staff will review the Z2 process to identify FERC-mandated requirements and SPP’s own additions and provide the task force with background on why certain requirements were placed in the Tariff. Staff was also asked to develop an annual cost estimate for ongoing support of the Z2 system and to document how it will model fixes and improvements.
SPP’s Board of Directors formed the task force in July to address Z2 waiver requests from members for directly assigned upgrade costs and to improve the process going forward. SPP has billed members for almost $110 million in regionwide, aggregate net payable historic amounts for Z2 credits and obligations, some of which date back to 2008.
Don Pedro Reservoir Scheduled For Major Refurbishment in 2017
The Don Pedro Reservoir hydrofacility is scheduled for three major refurbishment projects in its Power Tunnel in 2017, costing an estimated $7 million.
| Google
The work will be completed in two phases, each taking about 45 days. The first phase, which will begin before the irrigation season in February, includes the bulkhead gate installation and turbine shutoff valve replacements. The second phase, which is anticipated after the irrigation season in October, includes the fixed wheel gate installation.
The Turlock Irrigation District is hoping to operate the dam for another 50 years after the refurbishments, Assistant General Manager of Power Supply Administration Brian LaFollette said.
SoCalGas Wants to Pump Natural Gas Again After Aliso Canyon Leak
With investigations still pending and wells still shut down, Southern California Gas asked state regulators last week for permission to pump pressurized natural gas again — about one year after the largest methane leak in U.S. history at the Aliso Canyon storage field.
Citing “extensive physical upgrades” and “advanced technologies,” the gas company is seeking permission to resume operations northeast of Los Angeles, at a depleted oil field now used for storage.
State environmental regulators anticipate it will take weeks to decide upon the utility’s request, as state inspections at the field are still pending and utility regulators also must agree with reopening the field.
Option of Up to 100% Renewable Energy Coming to Bay Area Residents
First Solar will sell energy to Bay Area residential customers who are seeking up to 100% renewable energy under a deal with community choice aggregator Marin Clean Energy.
The energy will come from First Solar’s Little Bear project in Fresno County, scheduled for construction in 2019, with commissioning expected in 2020. In the beginning, the project will generate up to 40 MW, with plans to eventually expand to 160 MW.
Customers who opt out can receive Pacific Gas and Electric’s standard service, which is currently 30% renewable.
Katie Dykes was elected last week as chair of the Public Utilities Regulatory Authority by its commissioners. She fills the position left vacant by Arthur H. House, who was appointed by Gov. Dannel Malloy in October to become the state’s new chief cyber security risk officer.
Malloy appointed Dykes as a PURA commissioner on Oct. 27. She previously served as deputy commissioner of the Department of Energy and Environmental Protection.
Dykes currently serves as chair of the Regional Greenhouse Gas Initiative’s board of directors and represents Malloy on the board of managers of the New England States Committee on Electricity.
Group Uses Defunct Guideline To Protest Tx Line Route
A group called the Gateway West Task Force filed a protest last week against the U.S. Bureau of Land Management’s preferred route for the Gateway West transmission line in Cassia and Power counties based upon a federal guideline on sage grouse that is no longer in effect.
The interim guideline prohibited construction near sage grouse habitat on federal land, said attorney Doug Balfour, who represents the group. The now-irrelevant guideline pushed transmission routes onto private land, which affected 40 private landowners in Cassia County, Balfour said.
Since 2015, the state has had its own sage grouse conservation plan that permits the group’s proposed construction route. Although the BLM rejected the group’s preferred route through Cassia and Power counties three years ago, it now has a responsibility to re-evaluate its decision based upon the new information, Balfour said.
LG&E/KU Propose Rate Hike For Funding Advanced Meters
A proposal last week by Louisville Gas and Electric and Kentucky Utilities that would give customers new advanced electric meters comes with a rate hike that would boost LG&E’s electricity service revenue by 8.5% and KU’s revenue by 6.4%.
LG&E’s typical residential electric customers would see a rate hike of $9.65/month, while KU’s would see a $7.16/month increase.
The advanced meters would allow customers to get near real-time information on their energy use, while allowing the utilities to better detect power disruptions and make faster repairs, LG&E/KU spokeswoman Natasha Collins said.
Mohegan Island Group Wants Wind Project to Move Elsewhere
A group of Mohegan Island residents is asking developers to move construction of two 600-foot wind turbines — planned for 3 miles offshore — elsewhere.
The Legislature and the Public Utilities Commission already approved the project, and developer Maine Aqua Ventus anticipates construction will begin in 2019 and the generation system will be in service for the next 20 years.
Travis Dow, a spokesman for the newly formed group, Protect Mohegan, said many of the island’s 50 year-round residents were unaware of the project’s potential scope and timeline when it was approved.
Three separate solar arrays presently being installed on the grounds of Hancock Shaker Village could supply electricity into the Eversource Energy power grid beginning in 2017, while keeping with the living museum’s ideal of environmentally sound use of land.
The project, a partnership between Syncarpha Solar and Renewable Energy Massachusetts, consists of a 1-MW array on the Pittsfield side of the historic village and two 2-MW facilities in Hancock. It will serve customers throughout Western Massachusetts.
The project will provide lease income to Hancock for up to 30 years, while enabling residents of the Berkshires who are Eversource customers to buy net metering credits at a discount.
Baltimore Gas and Electric is crediting a new tree-trimming protocol for its 10,500 miles of overhead power lines with reducing power outages by 35% during the past four years.
The Public Service Commission’s adoption of new electric reliability standards in 2012 prompted BGE to remove more branches that overhang power lines and make other changes aimed at reducing outages.
Minnesota Power Asks for Both Immediate and Future Rate Increases
Minnesota Power is asking state regulators to approve an immediate 8% rate increase for homeowners effective Jan. 1 and a future increase of 10% after a 12- to 18-month contested case hearing process.
The utility said it needs the money to recover hundreds of millions of dollars it invested in its infrastructure in recent years, which includes monies for storm recovery and to “harden” its portion of the grid against extreme weather, and converting from a 95% coal-generated system to a 30% renewable system, Amy Rutledge, Minnesota Power spokeswoman, said.
Residential customers are paying 35% less than what it costs to get electricity into their homes, Minnesota Power officials concluded after a recent study.
South Sioux City, Big Ox Reach Agreements on Sewage Odors
Officials from South Sioux City and Big Ox Energy reached several agreements last week addressing strong sewage odors that forced residents of 15 homes in a five-block area to take refuge in hotels.
Big Ox converts organic waste into methane gas and shares sewer lines with the affected homes.
Among the agreed-to items, Big Ox will shut down its wastewater reception, hire an engineering firm to develop and present a plan to the city to ensure that the problem is not repeated, and provide financial support for impacted residents.
ACE Customers See Rate Drop Courtesy of Most-Favored Clause
Atlantic City Electric’s half-million customers can thank utility regulators in D.C. for a drop in their electric rates.
In 2015, the state approved Exelon’s acquisition of Pepco Holdings Inc., ACE’s parent. The deal, which provided $62 million in credits for ACE customers, also included a most-favored-jurisdiction provision that ensured state ratepayers would receive equal benefits to those negotiated in other states or the district.
The D.C. Public Service Commission negotiated a more lucrative agreement for district residents, forcing Exelon and PHI to add more than $53 million in benefits in New Jersey. The state Board of Public Utilities approved the revised agreement last week.
PSE&G Reaches Agreement for Solar Arrays on Brownfields
Public Service Electric and Gas has reached a tentative agreement with state regulators to build 33 MW of solar arrays costing about $80 million on brownfields and old garbage dumps — a smaller-scale version of its original proposal to spend $275 million to build 100 MW of solar facilities.
The state Board of Public Utilities still needs to approve the tentative agreement, which was reached with its staff, the Division of Rate Counsel and other parties after months of negotiations.
Gov. Chris Christie’s administration supports using former garbage dumps and brownfields as sites for solar farms, rather than undeveloped farmland and open spaces. But consumer advocates, including the Rate Counsel, have voiced concerns about allowing a regulated utility to pass the development costs to utility customers.
Duke Energy imploded the long-shuttered Dan River Steam Station in the final days of October — putting an end to the 276-MW plant where a 2014 coal ash spill led to new state laws and Duke’s guilty plea to federal Clean Water Act violations.
The company used explosives to implode the powerhouse, three boilers and an electrostatic precipitator.
The plant was shut down in 2012, but in February 2014, a storm water pipe running under its main coal ash pond collapsed, sending 39,000 pounds of coal ash into the Dan River. The state adopted the Coal Ash Management Act that summer, and in May 2015, Duke pled guilty to nine misdemeanor violations of federal environmental laws and was fined $102 million.
PSC May Fine Dakota Access for Delayed Notification of Cultural Find
The developer of the Dakota Access Pipeline is facing a possible fine for failing to notify state regulators for 10 days about the discovery of Native American artifacts in the pipeline route.
Dakota Access, a subsidiary of Energy Transfer Partners, was required under its permit to notify the Public Service Commission and to receive its clearance to proceed with construction. It did, however, notify the state Historic Preservation Office and rerouted the pipeline in coordination with the state archaeologist.
The commission can issue a fine of $10,000 per day per violation, or a maximum of $200,000.
FirstEnergy, NOPEC Contract Battle May Impact 500,000 Customers
FirstEnergy Solutions and the Northeast Ohio Public Energy Council (NOPEC) are embroiled in a court battle over changing their long-standing contract. The 500,000 customers that NOPEC represents may lose discounts, but not electricity, as a Jan. 1 switch to a new supplier looms.
Last week, FirstEnergy argued in documents before the Summit County Common Pleas Court that it could not afford the regular fees that it agreed years ago to pay NOPEC. It additionally is seeking to prevent NOPEC from cashing a multimillion-dollar letter of credit that it issued at the start of the companies’ relationship.
If the contract is dissolved, customers would shift to buying power from Ohio Edison or the Illuminating Co. NOPEC will probably have a new supplier within 60 days, said Chuck Keiper, NOPEC’s executive director.
Rocky Mountain Power’s Subscriber Solar Program 95% Sold Out
Rocky Mountain Power’s Subscriber Solar program is 95% sold out, with residential and business customers purchasing nearly 20 MW of solar power scheduled to come online in 2017.
The utility anticipates that the last few blocks of power will be sold within two weeks. The plant, near Holden, allows customers to use solar energy without installing solar panels.
Wind Farm Vote Money Legal, But Residents Still See It as Bribe
The state Attorney General’s Office has found that a developer’s promise of direct payments to Grafton and Windham residents if they approve an industrial wind farm on Nov. 8 does not violate election laws. But some residents see it as an outright bribe.
For the past four years, Iberdrola Renewables has wanted to construct 16 turbines in Windham and eight in Grafton.
The idea of payments — an estimated $1,162/year to full-time adult residents of Windham and $428 for Grafton residents — came from residents, the company’s representatives said.
Regulators Propose Fining Dominion $260K for 2 Oil Spills
State regulators proposed last week fining Dominion Virginia Power about $260,000 for a 13,500-gallon oil spill in Crystal City and a 9,000-gallon oil spill in Staunton — both of which polluted public waters in January.
A consent order is out for public comment for 30 days, and the State Water Control Board is expected to hear the matter at its December meeting, Department of Environmental Quality spokesman Bill Hayden said. Because of the spills, Dominion was required to monitor its wells for the last two weeks of October and must do so again during the last two weeks of January 2017.
According to Dominion, about 11,120 gallons of oil were recovered from the first spill, and all but 100 gallons were recovered from the second.
Stakeholders last week voiced concerns about CAISO’s annual process for determining which “discretionary” policy initiatives the ISO should pursue in the coming year.
Critics expressed confusion about the criteria CAISO uses to rank the list of prospective initiatives, of which only a few will be ultimately incorporated into the 2017 stakeholder initiatives catalog and potentially become part of the ISO’s longer-term policy “roadmap.”
They also questioned how the ISO values their contributions to the effort, which factors in stakeholder input as a key variable to rank potential initiatives but does not subject proposals to an outright stakeholder vote.
During a Nov. 3 conference call to kick off the process, Neil Huber, an energy trader with XO Energy, noted that he’s provided comments on the initiatives for the past three or four years.
“The answer seems to come back each year that there’s not enough bandwidth to work on a substantial number of projects,” Huber said.
Brad Cooper, market design and regulatory policy lead at CAISO, said the policy initiative process can be broken into two steps.
The first step consists of revising the catalog by adding new proposed initiatives and deleting those that have become obsolete. Initiatives listed for the catalog then become candidates for the roadmap, although there’s no guarantee they will immediately become action items.
In the second step, ISO management and stakeholders rank discretionary initiatives in order to elevate the most popular for development and implementation based on their feasibility and potential benefits.
Benefits include reliability and market efficiency improvements, as well the ISO’s perception of the stakeholders’ desire for the change.
The feasibility category attempts to capture how much money and ISO and stakeholder resources it will take to implement the proposal.
Most initiatives already in the roadmap are considered “nondiscretionary,” meaning that they address “significant” reliability or market efficiency issues, represent previous commitments to stakeholders or the Board of Governors, or have been mandated by FERC.
‘Bandwidth’ Issue Addressed
Just a few discretionary initiatives can be slipped into the ISO’s roadmap each year. Cooper estimates there will be room for two or three next year, depending on the scope of the initiatives selected.
Greg Cook, the ISO’s director of market and infrastructure policy, responded to Huber’s concern about the lack of bandwidth to handle more stakeholder requests for initiatives.
“There’s a lot of resource constraints we take into account,” Cook said, noting that some stakeholders have told the ISO that “they can only handle a certain number of initiatives at any given time.” Smaller stakeholders are particularly constrained because of staff limitations, he said.
CAISO also considers the timeline for implementing a policy when deciding whether to prioritize it.
Some stakeholders questioned the soundness of CAISO’s scoring system for potential policy initiatives. | CAISO
“We don’t want to schedule a policy development on an initiative that we’re not going to be able to implement for a number of years,” Cook said. “Likewise, if there’s an initiative that’s going to have a long time for the policy development that we want to implement by a certain time — that’s going to play in as well.”
Huber countered that — even as a small market participant — he has “bandwidth to work plenty of stuff I’m interested in.” He contended that a bigger issue for his company is that some of the smaller proposals that it requests never make it to the top half of the list of initiatives.
“So it seems like each year — specifically as a smaller entity — I just don’t make much progress,” Huber said.
Stakeholders had questions about the mechanics and philosophy behind the initiative ranking process.
Under the ranking system, the ISO assigns scores — 0, 3, 7 or 10 — to various benefits and feasibility categories of a potential initiative, the sum of which determines an initiative’s place in the overall standings (see chart).
CAISO has already published “first-cut” rankings showing that the current top six initiatives concern real-time market enhancements, generator risk-of-retirement issues, congestion revenue rights auction efficiency, donation of transmission capacity for EIM transfers, multiyear resource adequacy contracts and the altering of export charges.
Stakeholders were not asked to provide their own scores but were given the opportunity to formally comment on the list of potential initiatives — input that the ISO used to inform its formulation of the scores. Some meeting participants were especially curious about one ranking criteria: “desired by stakeholders.”
“Since you didn’t have stakeholders submit rankings prior to you doing your preliminary rankings, what was the input for ‘desired by stakeholders?’” asked Bonnie Blair, a consultant representing the Six Cities municipal utilities — Anaheim, Azusa, Banning, Colton, Pasadena and Riverside. “Was it just impressionistic?”
“We get input from stakeholders all the time,” Cooper responded. “I think we’ve a pretty good sense what’s desired by stakeholders,” adding that the scoring for the category “is based on our impressions of what we hear.”
‘Not That Scientific’
Cook pointed out that the category generally reflects whether an initiative is desired by a majority of stakeholders or just a few.
“It’s not that scientific,” Cook said.
Blair maintained that scoring of the category seemed vulnerable to skewing, particularly for initiatives representing the interests of a vocal minority — such as export charges.
Carrie Bentley, a consultant representing the Western Power Trading Forum, questioned how the ISO would adjust its rankings based on stakeholder input.
“We were envisioning this year people just submitting where they differed from us on our scores, just submitting written comments on how they think the scores should be revised and then providing the rationale for why,” Cooper said.
Bentley wondered whether the ISO would change the “desired by stakeholder” number just based on what people comment on.
“For example, if I don’t really want something and think it’s stupid, should I comment on it and say it’s stupid and do a zero, or should I just not say anything at all?” Bentley asked.
“Comment on it, say it’s stupid and do a zero, and we might have other people that agree with you and revise our score down,” Cooper said.
David Oliver, a managing consultant at Navigant Consulting, wondered why the ISO hadn’t chosen a simpler 1-4 scoring scale.
“I don’t recall exactly where the scale came from, but it’s just something we’ve been using,” Cook said. “This was just trying to have a little more separation in the rankings.”
Michael Rosenberg, principal trader for ETRACOM, asked whether the input of the ISO’s Department of Market Monitoring would be given more deference than that of other stakeholders.
“We don’t give more weight to one stakeholder over another,” Cook said. “We weight it by how well the arguments are stated.”
The ISO is seeking stakeholder comments on its initiative rankings by Nov. 17. An updated roadmap will be presented to the board Feb. 15, 2017.
In what may be one of its last earnings reports as an independent company, Westar Energy said it improved its third-quarter earnings over 2015 while falling two pennies short of Zacks Investment Research’s consensus forecasts at $1.09/share.
The Topeka, Kan.-based company reported net income of $155 million in the quarter, besting last year’s showing of $138 million ($0.97/share).
Westar Energy’s Jeffrey Energy Center | Westar
Westar said the rise was due to rate increases granted by the Kansas Corporation Commission this spring and an increase in corporate-owned life insurance income. (According to its 10-K filing for 2015, Westar reports as income increases in the cash surrender value and death benefits of its policies.)
Year-to-date earnings are $40 million above the $253 million earned through the same period third quarter of 2015. But the company said the higher revenue was “partially offset by a Southwest Power Pool assessment and higher expenses due to improving long-term grid reliability.”
Westar did not host a quarterly conference call because of its pending sale to Great Plains Energy. The company said it would not hold any future earnings conferences before the deal closes. (See Great Plains Energy, Westar Shareholders OK $12.2B Deal.)
The earnings announcement comes two weeks after Kansas regulators warned that they might block the merger because of staff’s conclusion that the companies’ filing lacked information on costs savings and what operations would continue in Westar’s Topeka headquarters (Docket No. 16-KCPE-593-ACQ).
A spokesperson for the two utilities said they did not expect the commission’s concerns to alter the merger’s spring completion target. The companies filed for joint application reconsideration Nov. 2, adding testimony from two Great Plains employees attesting to future customer savings and the reasonableness of the purchase price. However, Great Plains staff said the allocation of savings as a result of the merger is unknown and no final determinations have been made on what departments will remain in the Topeka office.
Great Plains recently struck a compromise with the Missouri Public Service Commission that requires the company to keep its capital structure and credit ratings isolated from Westar’s. The agreement also bans Great Plains from seeking increases in retail rates or capital spending because of the purchase. Great Plains initially maintained that the Missouri PSC had no jurisdiction over the sale.
CARMEL, Ind. — MISO will continue its current treatment of the sub-regional transfer limit in the Planning Resource Auction, both in deciding the initial limit and subtracting firm transmission reservations, RTO officials told the Nov. 2 Resource Adequacy Subcommittee meeting.
Under that same approach, the preliminary limits for the 2017/18 PRA are 984 MW for South to North and 3,000 MW for North to South, MISO Director of Forward Operations Planning Kevin Sherd said.
The RTO said it believes its approach — which deducts firm reservations from 2,500 MW for flows South to North and 3,000 MW for North to South — curbs the curtailment risk that use of non-firm contract paths could introduce.
Some stakeholders had argued for changing the value used in the initial limit and possibly reassessing the deduction of firm flows from the limit, saying the current approach was overly conservative as not all firm reservations are used.
MISO is also at the center of a FERC complaint filed by its transmission customers, which argue the limit is too strict and traps capacity in MISO South, driving up clearing prices. (See MISO Recommends No Change to Transfer Limits.)
The RTO is expected to publish the final sub-regional import and export limits before March 1. Sherd said MISO plans to continue to evaluate the sub-regional limit methodology for future auctions.
WPPI Energy engineer Steve Leovy said MISO should still consider alternatives to the calculation of the limit.
RASC liaison Renuka Chatterjee said subtracting firm reservations in the sub-regional limit is consistent with the treatment of other capacity import and export limits. Leovy said the treatment was not equitable since the RTO considers pseudo-ties in capacity import and export limits and does not model pseudo-ties in the sub regional limit.
No Change to External Resource Treatment, Either
MISO also is electing not to change the PRA’s treatment of external resources any earlier than other auction changes set for the 2018/19 planning year.
MISO Manager of Resource Adequacy John Harmon said after careful consideration, the RTO will not introduce a locational construct in the 2017/18 PRA. Instead, MISO is seeking a permanent solution as part of a larger bundle of auction changes, including a seasonal construct and separate forward auction, in time for the 2018/19 planning year. The RTO had suggested that it could roll out six new external zones in the capacity auction next year. (See “MISO to Move Ahead with Brattle Demand Curve for Forward Auction,” MISO Resource Adequacy Subcommittee Briefs.)
“We feel strongly that changes regarding a locational construct should be part of a larger reform and not a one-off change,” Harmon said. He added that MISO is looking to do its due diligence on a more comprehensive solution and avoid the “whiplash” of adopting one interim solution then distancing itself from the temporary solution by the time it formulates permanent rules.
Dynegy’s Mark Volpe said that while he appreciated the RTO’s desire to develop a permanent solution, external resources should not be on equal footing with resources in zones inside the RTO’s footprint.
MISO will continue discussion of external zone creation in 2017.
DALLAS — Having finally chased down Oncor, a quarry it has been after for two years, NextEra Energy has embarked on a charm offensive to ensure it successfully completes its acquisition.
The Florida-based company sent Senior Vice President Mark Hickson barnstorming across Texas last week to spread the message that Oncor is a perfect fit for NextEra’s focus on regulated investments and long-term power contracts. (See NextEra, EFH Seek to Reassure Texas PUC on Merger Deal.)
Speaking at the first of three Gulf Coast Power Association luncheons 48 stories up the Dallas skyline Wednesday, Hickson said Oncor has a lot in common with NextEra’s Florida Power & Light subsidiary.
“FP&L is part of the reason we’re one of the most admired companies for nine of the last 10 years,” Hickson said, pointing to the utility’s repeated listing among Fortune’s “Most Admired Companies.”
“We have the highest reliability [measures] and our bills are lower. Oncor shares those same commitments. The two of us coming together and sharing best practices is going to further our ability to provide that kind of service.”
Hickson also spoke before GCPA gatherings in Houston and Austin last week. Hickson’s tour followed the company’s Oct. 31 earnings announcement, in which it reported a 14% drop in third-quarter earnings.
Reducing Debt
Hickson said NextEra’s financial strength and access to Oncor’s cash flows will allow it to “reduce to zero” the utility’s nearly $11 billion debt and improve its credit ratings, thereby decreasing the cost of borrowing money, said Hickson, who heads the company’s corporate development and strategy functions.
FP&L already enjoys credit ratings of A or above from the three major ratings agencies. Oncor, which has been enmeshed in parent Energy Future Holdings’ bankruptcy since 2014, saw Moody’s bump its senior secured credit rating from Baa1 to A3 on the news of NextEra’s proposed acquisition. (See NextEra Reaches Deal for Oncor.)
Moody’s, Standard & Poor’s and Fitch Ratings have all since issued positive outlooks for Oncor.
“As our operations get less risky, the rating agencies aren’t so fussy about how much debt we have,” Hickson said.
NextEra announced in late July it had reached an agreement to acquire EFH’s 80.03% interest in Oncor for $18.4 billion. On Oct. 31, it announced an affiliate — created through a web of holding companies — would acquire the other 19.75% from Texas Transmission Holdings Corp. (TTHC), composed of a pair of private-venture funds, for an additional $2.4 billion. It has also acquired the remaining 0.22% interest owned by Oncor Management Investment.
That same day, NextEra and Oncor filed an application with the Public Utility Commission of Texas seeking its approval of the merger (Docket No. 46238). The companies expect the deal to close in the second quarter of 2017.
The application quickly drew intervention filings from an organization of Oncor cities and the Office of Public Utility Counsel. The PUC has placed the application on its Nov. 10 open meeting agenda.
Texas Investments
Hickson emphasized NextEra’s substantial investment — $8 billion over 15 years — in Texas through NextEra Energy Resources (NEER), its competitive energy subsidiary. The company’s Texas holdings include 26 wind farms (3,000 MW), 569 miles of natural gas pipelines in South Texas and 330 miles of transmission in western North Texas through subsidiary Lone Star Transmission.
Among the commitments NextEra has made, Hickson said, is to consolidate Lone Star with Oncor’s assets once the transaction is completed. Oncor, which already owns 119,000 miles of transmission and distribution lines and has more than 3 million meters, will keep its name and brand.
Oncor’s current ownership structure (L) and the organization chart under NextEra Energy’s proposed acquisition (R). | NextEra
“Oncor is a very sizeable company, but it will end up being 20% of” NextEra, Hickson said. The Texas utility’s addition will increase NextEra’s customer connections to 8.6 million and its regulated assets from $82 billion to $102 billion, he said.
“The trick in bankruptcy is to try and get as many creditors as you possibly can onboard with the transaction,” he said. “The easiest way to do that is to come as close as you possibly can to providing $11 billion of value.”
Under the merger agreement’s terms with TTHC, NextEra will pay 100% of the consideration in cash, leaving no debt at TTHC upon the merger’s close.
NextEra has been interested in acquiring Oncor since 2014, when EFH announced its bankruptcy. EFH and its creditors first supported Texas-based Hunt Consolidated’s bid for the utility in 2015, but that deal fell apart earlier this year when the PUC required conditions that changed the economics for investors.
NextEra says it will continue to maintain a ring fence around Oncor, not allowing it to incur additional debt and setting up a separate board that includes seven independent directors. Oncor CEO Bob Shapard will become the board’s chair, and E. Allen Nye Jr., the utility’s general counsel, will become CEO. Nye is the son of Erle Nye, the long-time CEO of TXU Corp. before EFH’s leveraged buyout.
NextEra also says there will be no “involuntary reductions” at Oncor, labor agreements will be honored and the utility’s operations will not conflict with NextEra’s other businesses.
Hawaii Setback
NextEra is hoping to burnish its image after failing to win Hawaii regulators’ approval in July for the acquisition of the state’s largest utility. The company also has come under criticism from clean energy advocates in its home state over a ballot initiative they say would block solar competition.
Hickson noted former Oncor sister companies Luminant and TXU Energy maintain larger shares of the ERCOT market than do NextEra’s other subsidiaries. He said Luminant accounts for 18% of ERCOT’s generation compared to NextEra Energy Resources’ less than 1%, and retailer TXU Energy has a 12% share of customers compared to NextEra’s 3%.
“Not only do we have a low market share of generation, we don’t have any generation currently interconnected to Oncor,” he said, going on to note the utility will seek the commission’s approval before connecting to any NextEra generation.
Hickson said Oncor and FP&L will operate independently of each other and there are no plans to grow Oncor outside of Texas.
“The thing we surprisingly found — the customer growth, the economic growth — was equal to, if not better than, that of Florida,” Hickson said. “We think there are a lot of opportunities for Oncor to grow within ERCOT.”
TCEH Rebrands Itself as Vistra Energy
On Friday, meanwhile, TCEH Corp., the parent of TXU Energy and Luminant, announced that it has rebranded itself as Vistra Energy. The company emerged from Chapter 11 bankruptcy as a tax-free spinoff from Energy Future Holdings. (See Luminant, TXU Energy Emerge from Bankruptcy.)
Vistra combines the vision of “an energy company preparing for the future” and the tradition of “an energy company whose lineage dates more than a century,” the company said.
“The Vistra Energy brand is intended to capture the full opportunity set before us, backed by a proud history, the industry’s best team of professionals, stellar operating assets and a strong balance sheet,” said Vistra’s recently installed CEO, Curt Morgan, a former operating partner at private equity firm Energy Capital Partners.
Long known as Texas Utilities and then TXU, the company was acquired in 2007 by EFH and its consortium of private-equity investors through a leveraged buyout. The deal went sour when energy prices collapsed, and EFH filed for bankruptcy in April 2014.
Vistra retains Luminant, the largest generator in the ERCOT market with 17,000 MW, and TXU Energy, the No. 1 retailer with about 1.7 million residential and business customers.
NextEra Shares Drop Following Q3 Earnings Release
NextEra announced Oct. 31 that profits fell 14% in the third quarter compared to last year amid higher overall expenses and declines at NEER.
The company reported net income of $753 million ($1.62/share) down from $879 million ($1.93/share) the year prior. Revenue decreased 3% for the quarter, down to $4.81 billion.
FP&L reported its earnings rose 5.3% to $515 million. However, earnings fell 19% to $307 million for NEER.
CEO Jim Robo said he was not concerned with NEER’s third-quarter decrease.
“There is no one in this industry that has the greenfield capabilities that we do,” he said. “Being in the wind business, 70% or 80% of the value creation is in the … greenfield development of those projects. No one in the industry has the pipeline that we do, that has the team that we do and the year in and year out track record. I worry about a lot of things, but [NextEra’s clean-energy development] is very low in my list of things that I worry about.”
NextEra shares, which have risen 22% in the past 12 months, closed Friday at $123.18, down $3.42/share after the earnings announcement.
VALLEY FORGE, Pa. — Members endorsed PJM’s 2016/17 winter weekly reserve targets, but not without first questioning if they could be reduced.
Part of PJM’s reserve requirement study, the winter targets are used by the Operations Department to coordinate generator maintenance outages in the cold months. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)
Stakeholders asked why the winter loss-of-load expectation needs to be near zero given that few zones within PJM are winter peaking. PJM’s Patricio Rocha-Garrido explained to the Operating Committee that the annual LOLE target of 0.1 — one day every 10 years — is cumulative throughout the year, so maintaining a near-zero level in the winter provides more leeway in the summer when load is higher.
“If we were to allow for a large risk in the winter, we would need a lower risk in the summer, which would require a larger reserve margin,” Rocha-Garrido said.
The targets will leave PJM with between 24 and 30% of its available reserves between December and February.
PJM Considering Changes to System Operations Report
After walking through the operations report for October, staff outlined ideas for redesigning the report to address additional topics. Among the subjects being considered for inclusion are topology changes, weather trends and seasonal comparisons.
Topology changes considered in the Operations Assessment Task Force’s winter 2016/17 preparedness study. | PJM
Stakeholders requested PJM increase its focus on reducing load-forecasting errors by providing more granularity about what factors are driving errors, such as how many and how often generating units are brought online in response to specific reliability contingencies. Staff said their ability to release information on specific units is limited because of the need to protect market-sensitive data.
“We’re talking about that internally,” PJM’s Joe Ciabattoni said.
Committee Endorsements and Recommendations
The OC made the following endorsements without objections or abstentions:
The 2017 day-ahead scheduling reserve requirement, which will be incorporated into Manual 13.
Updates to the TO/TOP matrix, an index between the PJM manuals and NERC reliability standards that specifies assigned and shared tasks for PJM and transmission owners. The changes, which the OC recommended be approved by the Transmission Owners Agreement-Administrative Committee, add new standards and delete inactive ones.
‘Cover to Cover’ Manual 13 Changes Better Reflect Reserve Requirements
PJM’s Chris Pilong presented a first read of extensive changes to Manual 13: Emergency Operations, on which the RTO will seek endorsement at the December committee meeting. Many of the changes are to clean up and streamline language regarding capacity and transmission emergency procedures.
“There are a lot of changes in here,” he said, but he acknowledged that many aren’t substantive. The biggest changes were the inclusion of more accurate Mid-Atlantic Dominion (MAD) reserve requirements. “The obligation can be met with non-MAD resources … if they’re deliverable,” he said.
Manual 14D Changes to Facilitate Periodic Surveys
PJM will be seeking endorsement at the December committee meeting on changes to Manual 14D: Generator Operational Requirements. The changes include the renaming of the section on fuel limitation reporting — now fuel and emissions reporting — a new section on periodic reporting and updates to the provisions on seasonal reporting. PJM’s Augustine Caven said the intention is to begin doing generating-unit surveys more often. “We definitely utilize [the survey] pretty heavily for operations purposes as we head into the winter,” he said.
Audit Goes Well
NERC and ReliabilityFirst Corp.’s planning and operations audit, which reviewed PJM’s compliance with 21 reliability standards and 48 requirements, concluded with no violations, two areas of concern and nine recommendations. There also were two open enforcement actions, PJM’s Srinivas Kappagantula said.
PJM is awaiting a draft audit report and will let stakeholders know about any changes it decides to make.
Kappagantula commended the transmission owners for their assistance in the process. “I wanted to think the TOs because we’ve reached out to you … for some of the data-sampling evidence that we requested,” he said. “That kind of reduced the onsite burden for us and the audit team … because they didn’t have to go through a bunch of documents onsite.”
OATF Study Finds No Major Concerns
While several major generation additions are coming online this winter, the Operations Assessment Task Force’s preparedness study found no significant concerns from its base case and N-1 analyses.
It found that off-cost generation redispatch and switching will be required to control local thermal or voltage violations in some areas. Networked transmission voltage violations were controlled by capacitors and all other voltage violations were caused by radial load, PJM officials said.
Stakeholders were concerned, however, that the study used hypothetical values in its calculations rather than real-world results.
Calpine’s David “Scarp” Scarpignato noted that units with dual-fuel capabilities weren’t differentiated from those without for pipeline failure contingencies. “This thing has a point to it, and I think you [should] set up the base case as accurate as possible,” he said.
PPL improved its third-quarter performance by 20%, reporting $473 million($0.69/share) in earnings, compared to $393 million ($0.58/share) for the same period last year. The company attributed the increase to higher rates for its Pennsylvania and U.K. operations and warm weather, which boosted demand.
PPL raised the bottom end of its 2016 earnings guidance by 5 cents to $2.30-$2.45/share based on slightly stronger-than-expected performance at its Pennsylvania and Kentucky utilities. The company, whose Pennsylvania utility benefited from a rate increase in January, intends to file rate hike requests in November for Kentucky Utilities and Louisville Gas and Electric.
With the exchange rate for the British pound falling in the wake of the U.K.’s decision to leave the European Union, PPL mitigated the financial impact on its U.K. operations by restriking its currency hedges.
“We remain confident in our ability to deliver on our long-term growth projections,” PPL CEO Bill Spence said during a conference call. “We expect to achieve 5% to 6% compound annual earnings growth from 2017 to 2020 and are targeting annual dividend growth of about 4% over the same period.”
Lagging Coal Units Drag down PSEG
Public Service Enterprise Group’s third-quarter earnings of $327 million ($0.64/share) were down 26% compared to the same period last year, when it reported $439 million ($0.87/share) in 2015. However, the company’s adjusted operating earnings of $444 million ($0.88/share) were up 10% year-over-year from $403 million ($0.80/share) in 2015.
The retirement of two coal-fired plants in New Jersey, a reduction in the value of its lease of two coal-fired plants in Illinois and lower hedges accounted for the difference, the company said.
“Net income was impacted by our decision to retire the Hudson and Mercer coal-fired generating stations in 2017,” said PSEG CEO Ralph Izzo.
Mercer Generating Station | PSEG
Warm summer weather staved off an even greater drop in the company’s performance, but it wasn’t enough to offset poor performance year-to-date thanks to unfavorably warm conditions during the winter. Izzo announced the company was shaving the top end of its 2016 guidance by 5 cents to $2.80-$2.95/share.
Its Public Service Electric and Gas subsidiary has reached a settlement with key parties for an extension of its existing landfill/brownfield solar program. The settlement provides for an investment of approximately $80 million to construct 33 MW of grid-connected solar generation over three years.
The PSEG Power generation subsidiary incurred $67 million ($0.13/share) in one-time charges related to the early retirement of the Hudson and Mercer generators.
Reduced energy hedges caused by lower fuel prices were partially offset by lower load-serving costs, but they still reduced net income by $0.02/share, the company reported.
The PSEG Enterprise/Other business group reported a net loss of $67 million ($0.13/share) after recalculating the residual values of its leases of two coal-fired plants in Illinois. The company recorded an after-tax impairment of $86 million on the leases “as a result of current and expected future market conditions.”
Unit Retirements, Tax Ruling Dampen Exelon’s Performance
Exelon’s third-quarter earnings fell 22% to $490 million ($0.53/share), down from $629 million ($0.69/share) in 2015. Adjusted earnings were up 11% year-over-year to $841 million ($0.91/share) from $757 million ($0.83/share).
While the company benefited from substantially better hedging and reduced nuclear decommissioning trust fund payments, those positives were outweighed by an unfavorable tax ruling, costs from the Pepco Holdings Inc. merger and plant retirements.
In September, the U.S. Tax Court ruled against the company in a $1.45 billion tax-shielding dispute with the Internal Revenue Service that stemmed from Exelon’s $4.8 billion sale in 1999 of six coal-fired plants in Illinois. The buyer, Edison Mission Energy, eventually sold four of the plants out of bankruptcy to NRG Energy, which leases two of them to PSEG.
While Exelon hasn’t decided whether to appeal the ruling, it is required to post a bond for the payment anyway. The company accounted for $199 million of the bill in the third quarter.
The quarter saw a shuffling of Exelon’s nuclear fleet as well, with the company announcing the early retirement of the Clinton and Quad Cities facilities and the purchase — pending regulatory approval — of Entergy’s James A. FitzPatrick station in New York.
Overall, earnings were bolstered by regulatory rate increases and favorable weather but partially offset by decreased capacity revenue, increased income taxes from a decrease in the domestic production activities deduction and increased nuclear decommissioning amortization, the company said.
Even with the write-downs, CEO Christopher Crane was bullish, announcing that the company was raising its 2016 guidance from $2.55/share to $2.75/share. The revision was based on improved performance of its Commonwealth Edison and recently acquired PHI utility subsidiaries.
Dominion Improves Finances
Dominion Resources had a good Monday last week, announcing both strong third-quarter results and the redistribution of its Questar acquisition that allowed the parent company to retire debt.
The company earned $690 million ($1.10/share) for the third quarter, compared with $593 million ($1/share) for the same period in 2015. It amounted to a 16% increase that the company partially attributed to favorable weather, lower capacity expenses, revenues from regulated growth projects and a lower tax rate. The performance was offset by share dilution and the absence of a farmout transaction, the assignment of part or all of a natural gas interest to a third party, which contributed $27 million to earnings a year earlier, the company said.
Dominion reported an operating earnings increase of 17% to $716 million ($1.14/share), compared to $611 million ($1.03/share) last year. The principal difference in the adjusted earnings was related to transaction costs associated with its acquisition in February of the pipeline company Questar.
The deal expanded Dominion’s service territory to Utah, where the natural gas deliverer has about 1 million customers. The sale closed in September, and by the end of October, Dominion had “dropped down” Questar to Dominion Midstream Partners, its master limited partnership, in a $1.7 billion deal that will allow the company to retire debt.
With investigations still pending and wells still shut down, Southern California Gas asked state regulators last week for permission to pump pressurized natural gas again — about one year after the largest methane leak in U.S. history at the Aliso Canyon storage field.
A group of Mohegan Island residents is asking developers to move construction of two 600-foot wind turbines — planned for 3 miles offshore — elsewhere.
Vistra combines the vision of “an energy company preparing for the future” and the tradition of “an energy company whose lineage dates more than a century,” the company said.
