WASHINGTON — The Supreme Court’s stay of the Clean Power Plan has largely ended the progress states were making toward creating regional frameworks for compliance, says Alexandra Dapolito Dunn, executive director of The Environmental Council of States (ECOS).
But even the most coal-dependent states are pondering ways to reduce their carbon footprints, she told a panel discussion at the Energy Bar Association’s Mid-Year Energy Forum last week.
“‘Carbon-considered’ is [the term used by] states that might have at one time been questioning whether or not there was climate change,” said Dunn, whose organization represents state environmental officials. “They’ve come around now.
“I think states will be more open to bringing renewables into their [generation] mix than they may have been before,” she explained. “There are companies that are located in very coal-oriented states that are already projecting ahead with their boards of directors and their shareholders to bring in a little bit of renewables, a little wind, a little solar, do some research and development in battery technology. You might not have seen that before.”
Two CPP opponents told the EBA forum that even if the EPA rule withstands legal challenges by states and utilities, its implementation will likely be delayed. The D.C. Circuit Court heard arguments on challenges to the rule on Sept. 27. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
“The likelihood of this rule being implemented the way it was finalized in August of last year is getting lower all the time,” said former EPA General Counsel Roger Martella Jr., of Sidley Austin. If the rule is upheld, he said, its 2030 deadlines could be pushed back to 2032 if the court also “tolls” the deadlines to account for inaction during the stay.
Allison Wood of Hunton & Williams, who argued before the D.C. Circuit on behalf of non-state challengers, agreed. Wood said the postponement of the D.C. Circuit arguments, which had originally been scheduled for June, means no Supreme Court review is likely until its next term, starting October 2017.
Dunn said the stay ended discussions among state officials on the technical issues concerning compliance, such as the development of emission trading programs.
“There were some really fantastic forums … where people were really putting their noses to the grindstone and trying to sort out these technical questions,” she said. “I almost wish we were still putting the same level of intensity into sorting out some of these questions that probably will be part of any future … carbon-managed environment.”
While some states are continuing their work and renewable generation is continuing to benefit from technological innovation, she said, “People are definitely following their own playbook at this point.”
The proposed protocol — which would continue on a smaller scale than the New York-PJM-New York flows of the wheel — has attracted criticism from stakeholders, which continued at last week’s PJM committee meetings. The influence and resiliency of phase angle regulators received some scrutiny from Citigroup Energy’s Barry Trayers at the Operating Committee meeting.
| PJM
“In a way you can kind of be picking winners and losers by adjusting [their] flows,” he said, asking how they had been factored into the grid operators’ guidelines for developing the replacement protocol.
“We consider PAR moves just like switching: a non-cost move that we’ll do prior to redispatching generation,” PJM’s Mike Bryson explained. “If we start running up against some of the either daily or monthly PAR adjustments, we’re going to have to take a step back and say, ‘Are we moving them too often? What’s the impact?’”
One challenge for the new protocol: One of the PARs on the 5018 line at Consolidated Edison’s Ramapo facility is not functional, which limits the ability to export power to NYISO. The grid operators have identified 1,800 MW as the maximum that needs to be available for export to NYISO, but the nonfunctional PAR limits PJM’s export capability to 1,400 MW.
While the future of Con Ed’s PAR has received a lot of discussion from other stakeholders, PJM has not received any details on when or if it will be fixed. One plan under review is to compensate by adjusting flows on the western interconnections across the Pennsylvania-New York border.
PJM and NYISO are currently working on updates to their joint operating agreement, which PJM will present upon completion for stakeholder review. NYISO plans to begin its stakeholder approval process at the end of October and complete it by January, which would allow the grid operators to make a joint filing to FERC later that month.
Stakeholders Urged to Submit Unit-Specific Parameter Adjustments
Generation unit operators have until Feb. 28 to submit adjustments to their unit-specific parameters, but PJM is urging them to begin the process as soon as possible because it can take several weeks.
PJM is aiming to have the status of delivery year 2017/18 adjustment requests posted by April 15. Parameters will be implemented in June. Any adjustments that are already approved remain valid, PJM’s Alpa Jani said, and don’t require resubmittal. Requests will receive a case identification number, with which requesters will be able to look up their current status through the RTO’s online member portal.
eDART Improvements Will Slow in Anticipation of Overhaul
PJM’s eDART system is getting an overhaul to incorporate new functionality, including single sign-on. To allow staff the time necessary to develop the new system, refreshes of the current system will be reduced to only those that are operationally necessary.
What won’t be changing are the business rules, the system interfaces or email notifications, said PJM’s Chidi Ike-Egbuonu. “One thing we can agree on is that it’s going to be a multiyear project; it’s not going to happen overnight,” she said.
PJM Moving Flat-File Data to Data-Management Tool
Raw data files are becoming too cumbersome and are being retired in favor of access through PJM’s Data Miner 2 tool, the RTO’s Thomas Zadlo explained. The tool will allow access to all data that is currently being stored on flat files, including five-minute settlements. Progress on the transition will be shared with stakeholders through PJM’s new Tech Change Forum.
WASHINGTON — “Pernicious subsidy” or “rough justice”?
Audience members got to decide for themselves how to characterize net metering for rooftop solar generation during a debate at the Energy Bar Association’s Mid-Year Energy Forum last week.
Richard L. Roberts, head of the electric group at Steptoe & Johnson, said it’s unfair that rooftop solar owners are paid retail prices as high as $0.13/kWh for the power they inject into the grid while central station generators are paid wholesale rates of about $0.04/kWh.
As a result, a customer whose solar panels generate energy equal to their consumption for the month “pays nothing for their electric service. They pay nothing for the reserves that they’ve been given. They pay nothing for transmission. They pay nothing for distribution. They pay nothing for public purpose programs, all of which go into retail service.”
Scott Hennessey, SolarCity’s regulatory counsel and vice president of policy and electricity markets, responded by citing a Sept. 30 ruling by the Massachusetts Department of Public Utilities last week that he said found rooftop solar provided more benefits than costs to the state’s grid. (See related story, Regulators Reject DER Surcharge in Rate Case.)
Glick | RTO Insider
He dismissed as a “common trope” the notion that rooftop solar is only for the “wealthy and well meaning.” The introduction of smart inverters allows rooftop solar to provide voltage support and other services to the grid, he said, while the introduction of financing options makes it available to the middle class.
Also participating in the discussion — though not staking a position on either extreme — was Mark Glick, administrator for the State Energy Office in Hawaii, a state that has provided a cautionary tale for regulators as generous subsidies have threatened to overwhelm the islands’ grids with solar generation.
Utility-Scale vs. Distributed Solar
Hennessey | RTO Insider
The session, moderated by Caileen Gamache of Chadbourne & Parke and Matthew R. Rudolphi of Duncan, Weinberg, Genzer & Pembroke, also touched on the virtues of distributed versus centralized solar generation.
“The question of whether or not [rooftop solar is] harmful to the grid or harmful to the average consumer I would turn around,” Hennessey said. “When you have infrastructure purchased by a utility and then spread across the entire rate base — with a fat profit, by the way, for the utility — that is a choice made decades in advance — and I think we’ve seen now, not always with the best of foresight,” he said. “Whereas when you have solar and the other distributed energy resources I’ve mentioned, that’s private investment in infrastructure that then benefits everyone around, with less peaking generation required.”
Hennessy said utilities that want to develop large-scale solar should be required to use a nonutility business unit rather than competing with other developers by using the utility’s low cost of capital and other advantages.
“What we’ve found is that every time they have tried that they have failed and they’ve had to close up shop, as [Arizona Public Service] did in Arizona.”
Jurisdictional ‘Mess’
Roberts | RTO Insider
Roberts said the Supreme Court’s FERC v. Electric Power Supply Association ruling, which preserved FERC’s right to regulate demand response, left a “jurisdictional mess” because the commission has no authority over net metering sales. Such sales should be a FERC-regulated wholesale sale under the Public Utility Regulatory Policies Act (PURPA), he said.
Roberts also cited studies showing utility-scale solar is two to three times more efficient than rooftop solar.
The rush to distributed generation could repeat the kind of mistakes California regulators made with the first retail choice program in the 1990s, which resulted in overpayments to qualifying facilities under PURPA and politicized integrated resource processes, he said.
“The goal of grid modernization should be to allow — without preferences or without predetermining who’s the winner and who’s the loser — equal access to all of these forms of technology to compete against each other and then wait and see where the next innovations come from,” he said.
“Nobody knows what the next big technological breakthrough is going to be. It might be large-scale generation, and if we’ve skewed our investments in the grid toward microgrid or small-scale [generation], we could find ourselves once again looking at investments and wondering why we did that.”
Hawaii’s Glick said “there’s no doubt” that utility-scale solar is cheaper than distributed resources. “But ultimately that will change and we have to allow the market to develop while that change occurs,” he said.
CARMEL, Ind. — Reviving his criticism of MISO’s lenient thresholds for uninstructed deviations, the Independent Market Monitor last week presented new data showing the impact of the RTO’s rules.
Market Monitor David Patton told the Oct. 4 Market Subcommittee meeting that slow-ramping units have too much flexibility to deviate from their dispatch instructions — so much so that generators can essentially ignore dispatch signals and not be penalized under MISO’s rules. Currently, generators are flagged if they deviate more than 8% from dispatch instructions for four consecutive intervals.
Under the current rules, generators drag by an average of 65 MW five minutes after receiving their dispatch instructions, and the drag worsens to an average of 314 MW when extrapolated to an hour, Patton said.
Generators are “basically being held harmless for poor performance,” Patton said. “We should not be paying you for refusing to turn on a mill.”
Patton has proposed moving to a system based on ramp rate, setting the threshold at half of the unit’s ramp capability with a cap of 10% of the dispatch level to limit gaming. The rules would make it so that units that are not responding to instructions after 20 minutes would be flagged.
“You can be motionless for 20 minutes before you would be flagged for dragging,” Patton explained. “You have to fail for three consecutive dispatch intervals before you are flagged for that hour.”
| Potomac Economics
Patton also said the proposal would eliminate the incentive to understate a unit’s ramp rate. The current 6-MW floor and 30-MW ceiling would remain.
The Monitor’s suggestion is not new: It first appeared in his 2012 State of the Market report, and it’s been brought up every year since, with Patton expressing disappointment that no progress had been made. (See MISO Monitor Debates Capacity Rules with Board.)
Stakeholders countered that it takes a long time to get large, baseload generators running. Operators will sometimes delay starting up units to make sure the dispatch signal is accurate, they said.
Patton responded that the heart of his suggestion is a “tolerance” that would give generators extra time to respond before they are flagged for dragging. But he said he could do more analysis on the reasons behind start delays.
The Monitor also said his team continues to investigate wind resources, which have larger deviations than any other resource type. “We think there may be economic incentives to over-forecast wind, and wind resources may be deliberately over-forecasting to MISO,” Patton said.
Chad Koch, market strategist for WEC Energy Group, said Patton’s proposal may hurt “fast-moving, accurate machines.” While “big resources move slowly and wind resources are up to the whims of Mother Nature, they should not get free rein,” Koch said.
MISO said an analysis against historical real-time data is needed to understand the impacts of the Monitor’s recommendation before it is adopted. In late spring, the RTO said the scope of the project had delayed its target for implementation to next year. (See “Changes to Uninstructed Deviation Thresholds Longer than Anticipated,” MISO Market Subcommittee Briefs.)
MISO’s John Weissenborn said staff would come back to the Nov. 29 Market Subcommittee meeting with its own proposal. Threshold changes, Weissenborn said, would most likely go into effect by the middle of the second quarter.
CARMEL, Ind. — MISO’s mechanism for allocating charges under its settlement with SPP was certified by a FERC administrative law judge last week (ER14-1736).
MISO has been using a temporary miscellaneous charge based on market load ratio share to collect the $1.33 million a month it is paying SPP until February for flows over 1,000 MW passing through MISO’s North-South interface. Under a settlement reached with its stakeholders, MISO will use a new, modified market load ratio share basis to allocate those costs. This method also applies to the $16 million it paid from Jan. 29, 2014, to Jan. 31, 2016, but that amount won’t be subject to resettlements, MISO Director of Market Services John Weissenborn told the Market Subcommittee on Oct. 4.
From Feb. 1, 2016, to Jan. 31, 2021, MISO will use a transitional, hybrid method, with a continuously declining percentage of the costs allocated through the new load ratio share calculation and an increasing amount through a flow-based benefits allocation methodology.
Weissenborn said the RTO will continue to allocate the costs under the current method until FERC accepts the settlement agreement and accompanying Tariff language. After approval, MISO can begin resettlement for costs from Feb. 1, 2016, and beyond.
“We can almost anticipate two resettlements: one to true-up the $1.33 million and another to implement the cost allocation,” Weissenborn said. Weissenborn said payments under a true-up will be a simple calculation, but the new cost allocation will be trickier: “The challenge that we have is that this is another new software change, but we will comply. We will get it done.”
Weissenborn said MISO will hold future stakeholder meetings on two remaining internal cost allocation issues under the settlement: how much entities with firm transmission that reduced the 1,000-MW capacity limit will have to pay and what cost allocation is needed for entities with capacity benefits that raised the Planning Resource Auction limit above 1,000 MW.
IMM Seasonal Review: Pricing Changes Still Needed
Independent Market Monitor David Patton used a review of last summer to continue his push for pricing changes.
Patton said summer’s 44% rise in energy prices over spring’s was due to increased natural gas prices and 1% larger year-over-year demand from summer 2015.
“Because of hot temperatures, we did rely more heavily on peaking resources,” Patton told the Market Subcommittee. The uptick led to more revenue sufficiency guarantee payments, culminating in a peak of almost $1.7 million in payments on July 21, when nearly all of MISO’s generating turbines were committed during a maximum generation event. The day also resulted in 1.6 GW of voluntary load curtailment, which lowered real-time energy prices to $36/MWh, even though the day-ahead price was $78/MWh. (See “IMM Makes Pricing Suggestions Following First Max Gen Event Since Polar Vortex,” MISO Markets Committee of the Board of Directors Briefs.)
“The problem with this is these are megawatts outside of MISO’s control,” Patton said. “You’re incurring an awful lot of costs just to turn these generators on. You’re certainly forcing the system to accept a lot of high-price energy. It makes it difficult to price the energy. …There are some things MISO could take a look at, and MISO is taking the process very, very slow.”
Patton repeated his suggestion that increasing the number of generators allowed to set prices under extended locational marginal pricing would temper erratic pricing.
“Procedures that say ‘turn everything on’ are not efficient, especially when there’s a more surgical” method, Patton said.
Jeff Bladen, executive director of MISO market services and liaison to the MSC, said the RTO will need to work with individual states and load-serving entities to improve the visibility of demand response. But he stood by the July 21 decision to issue the alert.
“What drove the over-commitment was not self-deployment. It was very much about the weather. Had the [stormy] weather in the forecast materialized, we would have absolutely needed the commitments,” Bladen said. Patton said he didn’t completely agree with that assessment.
Patton also said summertime outages that impacted constraints had a hand in increasing real-time congestion to $463.4 million in summer 2016 from $342.2 million in summer 2015.
MISO to Expand ELMP Price Setting, but not to IMM’s Specs
MISO Market Design Engineer Congcong Wang said the RTO is willing to expand ELMP to online resources with a one-hour start-up time without software changes.
The RTO says the possible expansion “captures a majority of peaking resources.”
Wang said the Monitor’s original recommendation that online price setting be spread to all resources with a two-hour minimum run time is neither cost effective nor beneficial with MISO’s current software. “The full expansion to two-hour minimum runtime will require software changes,” Wang said. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.)
MISO’s path forward would increase eligible peaking resources from 8% to 58% on a capacity basis. Wang said the expansion without software changes captures about 60% of the Monitor’s recommendation “in terms of real-time commitment.”
With the addition of one-hour start-up units, ELMP price setting, which currently includes about 45 10-minute start-up units with a combined capacity of 1.2 GW, would increase to 179 units at 8.4 GW. The Monitor’s advice to include two-hour minimum runtime units would bring the number to 256 units at 14.4 GW.
However, MISO is not willing to budge on removing offline units from price setting in ELMP, another Monitor suggestion. Wang said MISO’s research shows that offline fast-start resource participation can address shortages. MISO said it “will work with its IMM to continue monitoring offline participation and will exclude a resource from pricing if it is found infeasible.”
Wang said MISO would likely make a final decision on resource pricing under ELMP at the December Market Subcommittee meeting.
If the RTO decides to go with the option that does not require a software change, Wang said implementation could begin in the first quarter of 2017.
The introduction of coordinated transaction scheduling with PJM will be delayed from March to next October, Bladen said during a Market Subcommittee liaison report.
Bladen said the date change is needed while MISO waits on PJM to complete market improvements and staff training. He added that joint filings will be made soon to update FERC on the later implementation date.
David Sapper of Customized Energy Solutions asked how stable CTS will be given that MISO is also trying to implement interface pricing rules with PJM. (See “No Consensus on Interface Pricing,” MISO/PJM Joint and Common Market Meeting Briefs.)
Bladen said while there is a relationship between the two market improvements, they aren’t related to a degree that would prevent them from being introduced independently.
“There’s no premise that you have to have one before the other,” he said. “They’re not intrinsically tied. They’re relative improvements of the same process.”
CTS is intended to reduce uneconomic flows between the two RTOs. The new product would allow traders to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeds a threshold set by the bidder.
MISO Considering Moving Reserve Buy-Back into RSG
MISO is investigating a way to make up lost revenue for resources committed in real time that have previously cleared day-ahead offline supplemental reserves, said Jason Howard, MISO manager of market quality.
Currently, generators that commit in the real-time markets have to buy back their supplemental reserves.
MISO is considering providing make-whole payments to such generators through revenue sufficiency guarantee payments, Howard said. He said the proposal, which would require a Tariff change, would ensure that those units aren’t operating at a loss.
MISO looked at four years of historical data and found the average cost for buying back supplemental reserves amounts to $1 million per year across the RTO, Howard said.
CARMEL, Ind. — MISO’s Market Roadmap projects have been rearranged following stakeholder complaints over the lack of transparency behind the RTO’s reasoning for how it ranked them.
Stakeholders first raised their concerns over the rankings, and how MISO’s ordering was merged with stakeholders’ classification preferences, during the August Market Subcommittee meeting. The projects in the Market Roadmap, a work plan for market issues, were originally supposed to be ranked by early August.
“There were obviously some differences between what MISO and its stakeholders thought were priorities,” said Mia Adams, a senior market strategy analyst. Now, the four high-priority Market Roadmap projects are:
Aggregating load to meet minimum participation limits, which was previously ranked as a low priority by MISO;
Automatic generation control enhancement for fast-ramping resources, which was ranked high priority by stakeholders; MISO revised the priority from “low” in June to “high” in a second draft of the work plan in August;
Behind-the-meter storage aggregation under Type II demand response resources, which MISO previously gave a low priority; and
Introduction of multiday financial commitments, voted high priority by both MISO staff and stakeholders.
| MISO
With the reorder, MISO’s goals of developing additional short-term capacity reserve requirements and incorporating DR, emergency DR and boiler-turbine-generator deployment during capacity emergencies moved from high to medium priority. In addition, a pricing structure for voltage and local reliability commitments moved to low priority despite solid accord for a medium-priority ranking from the RTO and stakeholders.
The reorder provoked little discussion, as MISO almost completely aligned its prioritization with the stakeholders’ opinions.
MISO’s power marketers sector advocated that a virtual spread product be given high priority, but Adams said the RTO would need technological upgrades before it could complete the project. The issue was ranked low priority.
Of the 17 issues identified in the Market Roadmap process at the beginning of the year, five — including coordinated transaction scheduling with SPP — were placed in “parking lot” status, meaning they aren’t going to be given attention anytime soon.
MISO will unveil the final project prioritization in December.
Energy Future Holdings reached a major milestone in its Chapter 11 reorganization Monday, completing its tax-free spinoff of Luminant and TXU Energy into a new standalone company, TCEH Corp.
TCEH issued 427.5 million shares of common stock and other assets to the “pre-emergence” first-lien creditors of Texas Competitive Electric Holdings Co. It will trade on the OTCQX market under the ticker symbol THHH.
Luminant is Texas’ largest electric power generator with almost 17,000 MW of generation, including 2,300 MW of nuclear power, 8,000 MW of coal and 6,000 MW of natural gas. TXU Energy, a competitive retail electricity provider, has 1.7 million business and residential customers in Texas.
TCEH appointed as its CEO Curt Morgan, a consultant for the first-lien creditors and a former operating partner at private equity firm Energy Capital Partners. Also appointed to the board of directors were Gavin Baiera, Jennifer Box, Jeff Hunter, Michael Liebelson, Cyrus Madon and Geoffrey Strong.
In a statement Tuesday, Morgan said the company emerged from bankruptcy “with a strong balance sheet and the potential for stable earnings and significant cash generation,” having eliminated more than $33 billion of debt and other obligations and reduced its leverage to a low 2.3 times of gross secured debt to cash flow.
EFH said it was continuing its efforts to complete its reorganization with its sale of its 80% interest in Oncor, Texas’ largest transmission and distribution utility.
NextEra, EFH Seek to Reassure Texas PUC on Merger
Last week, EFH and NextEra Energy sought to assure Texas regulators they won’t be constrained in their review of NextEra’s agreement to purchase Oncor, which includes a $275 million termination fee.
During an update hearing Sept. 26 on EFH’s emergence from Chapter 11 bankruptcy (14-10979-CSS), Judge Christopher S. Sontchi said he had filed a joint letter from EFH and NextEra addressing the Public Utility Commission of Texas’ concerns.
PUC Commissioner Ken Anderson said during a Sept. 22 open meeting that the termination fee “appears to be an effort to really tie the commission’s hands in the proceeding,” as it would allow NextEra to cancel the deal if the commission imposed “overly burdensome” conditions. Anderson also called the fee an “improper attempt to constrain the commission.” (See Texas PUC Expresses Doubts over NextEra-Oncor Deal.)
NextEra has proposed buying Oncor for $18.7 billion.
According to the letter, “NextEra is not entitled to a termination fee under the merger agreement if NextEra Energy terminates the merger agreement because the commission either approves the merger agreement transaction with ‘burdensome conditions’ … or does not approve the merger agreement transaction.”
NextEra and EFH said the termination fee would be triggered only if EFH or Energy Future Intermediate Holding Co., Oncor’s direct parent, terminate the merger agreement. The companies wrote they “would like to make clear that, in any event, NextEra will not seek to collect any portion of the termination fee contemplated by the merger agreement in the event it terminates the agreement.”
Sontchi opened Monday’s hearing by quoting from the transcript of the PUC meeting.
“I believe [the] letter addresses the concerns raised by Commissioner Anderson,” Sontchi said. He said any possible triggering of the termination fee is “an issue for the bankruptcy court, and not for the PUCT and ratepayers.”
The PUC’s approval is just one of several favorable regulatory rulings NextEra and EFH must secure before closing the deal.
Southern California Gas said more wells at its Aliso Canyon underground storage facility passed safety inspections, but there is still more work to do before natural gas injections can begin. SoCalGas shut the storage facility down after a massive leak spewed methane for almost four months until it was finally capped in February.
Aliso Canyon is the largest of the four facilities owned by SoCalGas’ parent company, Sempra Energy. It has 114 wells, and each one must be tested and passed by the state Division of Oil, Gas and Geothermal Resources before the facility can be used again.
NorthWestern Energy Names Government Affairs Director
David Hoffman has joined NorthWestern Energy as director of government affairs for Montana. He will work with corporate counsel John Alke and Art Noonan on the Montana government affairs team.
Hoffman served in the Montana Legislature before joining the Montana Public Service Commission in 2001. He worked with PPL Montana from 2002 through 2015.
He replaces John Fitzpatrick, who will retire at the end of the year.
PacifiCorp has filed an application with FERC to transfer its licenses to operate four hydroelectric dams in California and Oregon to the Klamath River Renewal Corp. (KRRC) — a nonprofit corporation whose purpose is to oversee removal of dams on the Klamath River (P-2082-062).
In a separate application, KRRC has asked FERC to approve the decommissioning and removal of the dams, which have a total capacity of 6 MW (P-2082-063). The organization says it will be the largest dam removal project in U.S. history.
The applications were filed pursuant to a settlement agreement earlier this year between PacifiCorp and other parties. If FERC approves the applications, KRRC will oversee dam removals beginning in 2020, while PacifiCorp continues to operate the dams until they are decommissioned.
First Energy’s Davis-Besse nuclear plant returned to full power last week after an unplanned outage that lasted nearly 12 days.
On Sept. 10, rainwater entered the plant’s turbine building through an unclosed roof vent during a heavy storm, damaging electrical controls and causing the generator to shut down.
The plant synchronized to the region’s electric grid last Thursday, utility spokeswoman Jennifer Young said.
DTE Energy announced last week its plans to spend $1.3 billion for natural gas assets in Pennsylvania and West Virginia.
DTE will purchase from M3 Midstream all of its Appalachia Gathering System in Pennsylvania and West Virginia and 40% of Stonewall Gas Gathering in West Virginia. The company also will purchase 15% of Stonewall Gas Gathering from Vega Energy Partners.
Utility officials last week celebrated the completion of the fourth of five legs of the CAPX2020 project, a 345-kV line from Hampton, Minn., to La Crosse, Wis.
The completed sections now span 725 miles across Minnesota, North Dakota, South Dakota and Wisconsin. The final project in eastern South Dakota is scheduled for completion next year.
The project — the largest new transmission development in the Upper Midwest in 40 years — is a collaboration among municipal, cooperative and investor-owned utilities. “It has been unprecedented for 11 utilities of quite varying types to be able to come together under a common purpose and then stay together,” said Teresa Mogensen, senior vice president of transmission at Xcel Energy. “Working in cooperation, we were able to do much more together than any one of us could have done individually alone.”
Public Service Enterprise Group is seeking to build a 74,950-square-foot data center in Bridgewater, N.J., to manage its electric and gas distribution operations.
The proposed center would serve as a backup to PSEG’s Newark, N.J., facility and would be located next to a substation built after Superstorm Sandy.
Local officials will review PSEG’s proposal on Oct. 6.
SolarCity is being sued by a competitor who claims the company stole trade secrets pertaining to the development of high-efficiency shingled solar panels.
Cogenra Sola and its majority shareholder, Khosla Ventures, filed suit last week alleging the trade secret theft occurred after a series of meetings between the two companies in 2010 and 2014.
SolarCity issued a statement saying it is “confident the court ultimately will reject Cogenra’s claims, which are factually and legally baseless.” SolarCity said Cogenra filed its lawsuit after SolarCity discovered earlier in September that a former employee took “highly valuable trade secrets” to SunPower, which acquired Cogenra law year. SolarCity said it filed its own suit against its former employee and SunPower.
Duke Energy has closed its $4.9 billion purchase of Piedmont Natural Gas, which the utility said is central to its transition from coal- to gas-fired generation.
Since 2008, Duke has reduced coal’s share of its generation from about 60% percent to about one-third.
Duke CEO Lynn Good is preparing for the day when coal is no longer part of Duke’s business model. “I think we’ll still be operating coal in 2030,” Good said. “Whether we will be in 2040 I think is a question, or in 2050,” she said.
Public Service Enterprise Group is creating a retail energy business to sell electricity and gas to commercial and industrial customers.
The new unit, called PSEG Energy Solutions, will provide a hedge to PSEG Power, which owns more than 18,000 MW of capacity.
“We remain interested in retail for our defensive purposes — managing basis risk — and not as a significant growth opportunity by any stretch of the imagination,” CEO Ralph Izzo said.
Solar cell manufacturer SunPower will use drones and software when it starts construction of new “Oasis” power plants in North America and China during the next several weeks.
The drones will fly over a site to collect data, which the software will use to recommend the best design options.
“Oasis can take advantage of unused irregularly shaped areas and slopes up to 10 degrees to generate up to 60% more energy than conventional technology installed at the same site,” CEO Tom Werner said in a press announcement.
EnerNOC is cutting its global staff by about 15%, shedding more than 200 jobs primarily from its energy software business.
The company is seeking to focus its software business on sectors that are best equipped to use its energy management software, such as manufacturing and commercial real estate.
“We’re still committed to [the software] business, but what we need to do is reduce our cost structure significantly in light of where the market is today,” CEO Tim Healy said. “We’ve overbuilt a little bit. We need to recognize that fact.”
OGE Energy has approved a 10% dividend increase effective with the fourth quarter of 2016.
The increase from $0.275/share to $0.3025 equates to $1.21/share annually.
“We are pleased to reaffirm our commitment to a 10% dividend growth annually through 2019,” CEO Sean Trauschke said. “We realize many of our shareholders count on our dividend for income and we are proud to be one of a select group of utilities that has never reduced our dividend since going public in 1947. That is 69 years of consecutive dividend payments.”
Crestwood to Build, Operate Permian Gas-Gathering System
Crestwood Energy Partners announced last week that it had entered an agreement with SWEPI to build a $180 million natural gas-gathering system in Texas’ Permian Basin.
SWEPI agreed to provide 100,000 acres and gathering rights in Loving, Ward and Reeves counties in Texas. Crestwood will own and operate the system, which is projected to be in service by July 2017. Shell, SWEPI’s parent company, has the option of buying a 50% equity in the system by September 2017.
DTE Energy last week announced plans to build a natural gas-fired power plant in China Township, Mich., near the Belle River.
The new plant will be adjacent to the St. Clair Power Plant, a coal-fired facility that DTE intends to close by 2023. The announcement came in a meeting with St. Clair County officials, who expressed relief that tax revenue would not be lost because of the closure.
The company said it may build several natural gas plants worth between $1 billion and $1.5 billion by 2023, but a spokesman said the St. Clair plant, with a capacity of about 1 GW, is the only one that has been sited so far.
FERC Claws Back Reactive Power Payments on Talen Generators
FERC last week approved a settlement reducing Talen Energy’s reactive service payments for its generators in the PPL zone of PJM for May through December 2016 by more than $654,000 (ER16-277). The settlement ends a Section 206 proceeding the commission ordered in March to determine whether the reactive power rates were just and reasonable due to the “degradation” of the units’ reactive capability compared to the original values used to calculate the proposed rates in 1997.
But in a separate docket, the commission opened a new Section 206 case to determine the reactive rates going forward under Riverstone Holdings’ proposed acquisition of Talen (EL16-116).
FERC last week accepted Pacific Gas and Electric’s filing for a proposed rate increase under the utility’s transmission owner tariff, but the commission suspended implementation of the increase for five months out of concern that the proposed rates could yield “substantially excessive revenues.”
The utility’s filing raised “issues of material fact” that would be better addressed through further proceedings, the commission said in its Sept. 30 order (ER16-2320).
The new rates will become effective March 1, 2017, but they remain subject to a refund based on the outcome of settlement and hearing proceedings.
In its filing, PG&E proposed a 10.9% return on equity for 2017 — composed of a 10.4% base return plus a 50-basis-point incentive adder for its continued participation in CAISO. The utility said its transmission rate base will jump 29% to $6.71 billion, while its retail network transmission service revenue requirement is projected to increase 15.4% to $1.718 billion.
Opponents of the rate increase, which include the California Public Utilities Commission, contend that the utility should be required to calculate its ROE based on the median of its own discounted cash analysis, which would reduce the base rate to 8.65% and lower the revenue requirement by about $114 million.
Those opponents also argue that PG&E’s proposed 3.26% depreciation rate is excessive and represents an unjustified increase from its currently authorized depreciation rate of 2.52%.
The commission denied a CPUC request that it not approve PG&E’s 50-basis-point adder based on the fact that the justification for the adder is the subject of a proceeding before the 9th U.S. Circuit Court of Appeals. The CPUC contends the adder is unnecessary because PG&E is required to be a member of CAISO under California law.
“While we recognize that appeal is pending, such an appeal does not operate as a stay of the commission’s consideration of this issue here,” FERC said.
The commission will appoint a settlement judge on the matter later this month, but it encouraged PG&E and opponents to settle their disputes before the start of settlement proceedings.
SPP stakeholders have recommended the RTO’s leadership reject $114 million in remaining waiver requests for Z2 transmission upgrades.
The Z2 Task Force voted 8-4 Friday with four abstentions to “follow the Tariff” and reject all Group B and C waivers. SPP has calculated that Group B transmission customers (those that SPP said didn’t qualify for waivers from paying their Z2 bills) owe $36.9 million in directly assigned upgrade costs and Group C members (who didn’t request waivers) owe $77 million.
SPP staff made the same recommendation to the Board of Directors and Markets and Operations Policy Committee in July, but the board did not adopt the recommendation and created the task force to find a “more rounded solution” to a problem that dates back to 2008. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
The task force reviewed additional data from staff and discussed six options it had developed during its previous meeting. The “follow-the-Tariff” option was a clear favorite, with accepting the waivers and regionalizing the costs drawing half as much support.
The recommendation now moves forward to the MOPC and the board later this month. The task force plans to make itself available to help improve SPP’s Z2 processes following the October meetings.
“We’re the only RTO that allows third-party impacts to these types of upgrades,” said Bill Grant, director of strategic planning for Southwestern Public Service, referring to transmission customers making service requests that affect previous upgrades. “This is a convoluted mess. It’s going to cost us money going forward. Now that we’ve seen it, and how complicated the whole [Z2] process is, why wouldn’t we change that?”
Under Attachment Z2 of the SPP Tariff, staff was to assign financial credits and obligations for sponsored upgrades. Years of incorrectly applied credits have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.
SPP Vice President of Operations Bruce Rew said his staff has held internal discussions on how to improve the Z2 process and developed a couple of alternatives that can be presented in the future.
“One thing that has to be key is that [the process] has to be simpler than it is,” Rew said. “We’re concerned about how we manage this 10, 20, 30 years from now. It’s got to be simpler in terms of what we have, both on our side and on the visibility side, so that you can see it.”
In a related matter, FERC on Friday approved SPP’s request for Tariff waivers to allow it to offer a payment plan to transmission customers owing Z2 bills (ER16-2330).
SPP Goes Live with New Gas-Day Timelines
SPP’s Integrated Marketplace instituted its new FERC-ordered timelines for gas-day nominations Oct. 1.
Phillip Bruich, SPP’s director of markets, said the transition went “very smoothly” and thanked market participants for being prepared.
“Our market participants … were well prepared, ready for the changes and able to submit their bids and offers on time the first day,” Bruich said. “This is a … step toward better coordination and efficiencies between the electric and gas markets.”
The SPP market now closes the day-ahead market at 9:30 a.m. CT and posts the results at 2 p.m., moving the timelines up from 11 a.m. and 4 p.m., respectively. The day-ahead reliability unit commitment reoffer period opens at 2:45 p.m. and closes at 5:15 p.m., a shift from 5 p.m. and 8 p.m., respectively.
The changes are a result of FERC Order 809, which required RTOs to coordinate their day-ahead operations with the natural gas market. The commission says this change will “better ensure the reliable and efficient operations of our interstate natural gas pipelines and our electricity systems.”
Aliso Canyon is the largest of the four facilities owned by SoCalGas’ parent company, Sempra Energy. It has 114 wells, and each one must be tested and passed by the state Division of Oil, Gas and Geothermal Resources before the facility can be used again.
David Hoffman has joined NorthWestern Energy as director of government affairs for Montana. He will work with corporate counsel John Alke and Art Noonan on the Montana government affairs team.
PacifiCorp has filed an application with FERC to transfer its licenses to operate four hydroelectric dams in California and Oregon to the Klamath River Renewal Corp. (KRRC) — a nonprofit corporation whose purpose is to oversee removal of dams on the Klamath River (
First Energy’s Davis-Besse nuclear plant returned to full power last week after an unplanned outage that lasted nearly 12 days.
DTE Energy announced last week its plans to spend $1.3 billion for natural gas assets in Pennsylvania and West Virginia.
Public Service Enterprise Group is seeking to build a 74,950-square-foot data center in Bridgewater, N.J., to manage its electric and gas distribution operations.
SolarCity is being sued by a competitor who claims the company stole trade secrets pertaining to the development of high-efficiency shingled solar panels.
Duke Energy has closed its $4.9 billion purchase of Piedmont Natural Gas, which the utility said is central to its transition from coal- to gas-fired generation.
Solar cell manufacturer SunPower will use drones and software when it starts construction of new “Oasis” power plants in North America and China during the next several weeks.
OGE Energy has approved a 10% dividend increase effective with the fourth quarter of 2016.
FERC last week approved a settlement reducing Talen Energy’s reactive service payments for its generators in the PPL zone of PJM for May through December 2016 by more than $654,000 (