Page 1389 – RTO Insider

October 10, 2016

MISO Market Subcommittee Briefs

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.

7wk2wqosd2lzmamr8nlg_full_congcong-wang-rto-insider-alt-fi — Wang | © *RTO Insider*

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.

MISO-PJM Coordinated Transaction Scheduling Delayed

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.

— Amanda Durish Cook

October 7, 2016

MISO Projects Reordered Following Stakeholder Frustration

By Amanda Durish Cook

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.

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.

October 4, 2016

Luminant, TXU Energy Emerge from Bankruptcy

By Tom Kleckner and Rich Heidorn Jr.

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.

October 3, 2016

Company Briefs

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.

More: Reuters

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.

More: The Montana Standard

PacifiCorp Files to End Dam Operations

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.

More: Herald and News; Klamath River Renewal Corp.

Davis-Besse Plant Recovers From Unplanned Outage

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.

More: The Associated Press

DTE Spending $1.3B For Natural Gas Assets

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.

DTE expects to complete the deals this year.

More: The Associated Press

Decade-Long CAPX2020 Project Finished

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.”

More: WPR News; Star Tribune; CapX2020

PSEG Proposes NJ Data Control Center

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.

More: NJ Advance Media

Competitor Sues SolarCity For Trade Secret Theft

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.

More: The Buffalo News

Duke Acquisition to Aid Transition to Natural Gas

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.

More: Bloomberg

PSEG Quietly Enters Retail Energy Business

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.

More: NJ Spotlight

SunPower Uses Drones To Construct Power Plants

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.

More: ZDNet

EnerNOC Reducing Staff by 15%

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.”

More: The Boston Globe

OGE Energy OKs 10% Dividend Hike

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.”

More: OGE Energy

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.

More: Fuel Fix; Crestwood

DTE to Build Natural Gas-Fired Power Plant

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.

More: The Times Herald

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).

More: Riverstone to Acquire Talen in $1.8B Deal

October 3, 2016

FERC Sets PGE Rate Increase Proposal for Talks

By Robert Mullin

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.

October 3, 2016

SPP Briefs

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.”

– Tom Kleckner

October 3, 2016

CAISO Sees Steady 2017 Revenue Requirement Despite Spending Rise

By Robert Mullin

CAISO expects to hold its 2017 revenue requirement to this year’s level despite a planned $4.3 million increase in spending driven by rising labor costs, the ISO’s chief financial officer said Thursday.

7xhpdkqr42wd8lcq55qh_full_revenue-requirement-and-om-caiso-content — CAISO’s revenue requirement — which tracks closely with the ISO’s operations and maintenance expenses — has remained below $200 million for more than 10 years.

Although next year’s proposed budget is projected to increase 2% to $214.5 million, the ISO is seeking maintain its revenue requirement at $195.3 million for a second straight year, CFO Ryan Seghesio said during a Sept. 29 stakeholder call.

The additional expenses will be offset by revenues from other sources, including money earned from the operation of the Western Energy Imbalance Market.

Although the revenue requirement has increased 0.3% annually since 2007, it is 18% below its 2003 peak, when the ISO’s yearly debt service costs were more than three times as high as today.

“This shows our commitment to a stable revenue requirement,” Seghesio said.

CAISO recovers its annual revenue requirement through grid management charges assessed to market participants based on their use of the transmission system to serve load or deliver exports. Two out of three of those charges are slated to decline slightly next year, while a service charge associated with congestion revenue rights is expected to see an uptick.

Other fixed fees contributing to the requirement — such as those related to bidding into CRR auctions and trades by scheduling coordinators — are expected to remain unchanged.

The ISO’s operations and maintenance budget, which accounts for more than 80% of total spending, is expected to rise 2.5% next year on the back of a $4.6 million (3.8%) increase in salary and benefits expenses. The salary figure includes merit increases for existing staff and plans to hire seven new employees, bringing the total headcount to 600.

“We’ve held a very tough line on headcount for a while, but there’s some stress points [in various departments] that need to be relieved,” Seghesio said, adding that the number of full-time equivalent employees has fallen since 2012.

CAISO expects to reduce expenses related to outside contractors, consultants, training, travel and building leases, while fees to outside professionals such as attorneys are projected to rise.

Next year’s proposed revenue requirement also includes a $24 million cash-funded capital component, of which $20 million will be budgeted for approved projects, with the remainder to be held in reserve.

Debt service costs remain at $16.9 million, a figure Seghesio said will hold steady until 2023, when some of the ISO’s bonds become eligible for refinancing.

Declining transmission usage coupled with a steady revenue requirement will cause CAISO’s pro forma bundled cost per megawatt-hour — a measure of the ISO’s costs per transmission volumes used by market participants — to increase by $0.004/MWh to $0.809/MWh.

Next year’s transmission volumes are forecast to fall by 1.2 TWh to 241.5 TWh, continuing a trend in recent years.

CAISO attributes the decline to California’s extended drought — which has reduced both hydroelectric output and the amount of energy needed to move water supplies throughout the state — and the increased adoption of distributed generation, which is increasingly displacing the state’s reliance on central station power. Recent estimates indicate that rooftop solar now accounts for about 5,000 MW of capacity within the ISO’s balancing area.

Stakeholder comments on the proposed 2017 budget are due by Oct. 6. CAISO will seek board approval for a final budget in mid-December.

October 3, 2016

Federal Briefs

FERC will hold a technical conference Nov. 9 to determine what RTO rule changes may be required to accommodate electric storage. “The subject of the conference will be the utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways, and for multiple services,” the Sept. 30 order said.

More: AD16-25

UN Heritage Monitoring Team Eyeing BC Hydro Project

A United Nations world heritage site monitoring team is taking a closer look at a plan to build a hydro project in British Columbia, concerned about the possible impact on Wood Buffalo National Park and the Peace River in neighboring Alberta.

The team was already examining the effects of two existing dams on the Peace River at the request of the Mikisew Cree First Nation, which says the areas are under threat of development. The U.N. review will now be expanded to include the Site C hydro project, a 1,100-MW project in northeast British Columbia, near Fort St. John.

The tribe is seeking to have the Peace River region declared a world heritage site, and possibly block the dam project. “We’re looking for them to list it as endangered so Canada can really take a more proactive means in managing those impacts and activities,” said Melody Lepine, a tribe spokesperson.

More: The Canadian Press

PennEast Opponents Call for New FERC Review

News that PennEast Pipeline has 33 new changes to the proposed route of the 119-mile pipeline is spurring environmental groups to call for FERC to conduct a new environmental review of the plan.

“These 33 new modifications further demonstrate that the draft [environmental impact statement] released does not even describe, let alone analyze, the pipeline PennEast wants to build,” said Maya van Rossum of the Delaware Riverkeeper Network. “FERC needs to go back to the drawing board and issue a new DEIS and hold a new public process, one that includes real public hearings.”

A company spokeswoman said most of the changes were proposed in an attempt to minimize the environmental impact of the pipeline. “PennEast views the modifications as being responsive not only to constructive feedback provided by landowners, agencies and other stakeholders, but also to recommendations contained within FERC’s draft environmental impact statement.”

More: StateImpact

NRC Won’t Hit Entergy for False Leak Reports

Operators at the Pilgrim Nuclear Power Station allegedly filed two false reports relating to a hydrogen leak, but the Nuclear Regulatory Commission said their regulations don’t cover hydrogen leaks, and therefore plant owner Entergy has nothing to worry about from the commission.

A local fire chief said Pilgrim incorrectly claimed that it had notified fire officials about a hydrogen leak, and then filed another false report saying the notification was made a little while later. Plymouth Fire Chief Ed Bradley said those reports are just two more in a series of incorrect or nonexistent notifications.

But the commission said it was going to take no action against Entergy. “We have not identified any regulatory requirement on our part that they do these notifications of hydrogen releases to the fire department,” an NRC spokesman said. “As far as the NRC is concerned, that is not a regulatory issue.” Bradley said plant officials have promised the communication problem will be rectified.

More: Old Colony Memorial

Lobbyists Prominent Among Trump Energy Advisers

Despite his complaints about Washington’s “rigged system,” Republican presidential nominee Donald Trump is relying on D.C. lobbyists representing utilities and coal, oil and gas companies on his campaign and transition teams, The Washington Post reported.

The head of Trump’s energy transition team, Mike Catanzaro, is a former staffer with the Senate Environment and Public Works Committee who later handled government relations for PPL. He is now a partner at the lobbying firm CGCN, which has represented Noble Energy and Talen Energy.

Other Trump advisers include Jeffrey Wood, a partner at Balch & Bingham and a registered lobbyist for Southern Co.

More: The Washington Post

Study: Bio-Energy Creates Environmental Tradeoffs

Increased demand for bio-energy as an alternative to fossil fuels is leading to less forested land and less habitat for wildlife, according to a multiyear study by researchers at North Carolina State University and the U.S. Geological Survey.

Tradeoffs that come with bio-energy production include risks to species that rely on a single, mature habitat and exacerbation of habitat loss for species already losing ground to increased urbanization, said researcher Nathan Tarr.

“None of the biomass sources that we looked at were good or bad for all species, nor was a single mix of biomass sources consistently the best or worst for all species,” Tarr said.

More: Coastal Review Online

Report: Energy Efficiency Key to Cutting Carbon Emissions

Industrial energy efficiency could cut carbon emissions by 175 million tons nationwide in 2030, according to new research by the Alliance for Industrial Efficiency.

“Process efficiency improvements, boiler upgrades, replacing chillers, insulation, even things as simple as lighting,” said Jennifer Kefer, executive director of the group. “Our report demonstrates very clearly that one can cut carbon while saving money.”

More: Public News Service

October 3, 2016

7 Sites Eyed for MISO-PJM Targeted Market Efficiency Projects

By Amanda Durish Cook

MISO and PJM have nearly completed their work on joint operating agreement and tariff language to create the new targeted market efficiency project (TMEP) type, and the RTOs have singled out seven congestion-relieving candidate projects.

Four of the possible TMEPs are located at flowgates in Indiana, while one is in northern Illinois, one is on the southeastern Michigan-Ohio border and another is in central Ohio. The projects, produced from a joint RTO analysis that originally studied 12 candidates, range from 138 kV to 345 kV with total costs of $19 million and benefits of $117 million:

The Burnham-Munster 345-kV project on the northern Illinois-Indiana border:
- Benefit-cost ratio: $32 million/$6.5 million
- Cost allocation: PJM 88%/MISO 12%
The Bayshore-Monroe 345-kV project on the southeastern Michigan-Ohio border:
- $17 million/$1 million
- PJM 89%/MISO 11%
The Michigan City–Bosserman 138-kV project in northern Indiana:
- $29.6 million/$2.3 million
- PJM 90%/MISO 10%
The Reynolds-Magnetation 138-kV project in north-central Indiana:
- $14.5 million/$150,000
- PJM 41%/MISO 59%
The Roxana-Praxair 138-kV project in northeastern Indiana:
- $6.5 million/$4.5 million
- PJM 24%/MISO 76%
The Klondike-Purdue 138-kV project in north-central Indiana:
- $6 million/$4.2 million
- PJM 4%/MISO 96%
The Marysville-Tangy 345-kV project in central Ohio:
- $12 million/“minimal” cost
- PJM 98%/MISO 2%

“We’re pretty excited about this. This is exactly what we were hoping for,” PJM engineer Alex Worcester said during a Sept. 30 meeting of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC). “These aren’t projects that are just squeaking by; these are very significant cost-benefits.”

miso, pjm, targeted market efficiency projects — Twelve flowgate projects were initially considered in MISO and PJM’s TMEP analysis.

Worcester also said both RTOs were surprised with how evenly the cost allocation was shared among the total projects.

The RTOs used a joint survey to decide on some details of the TMEP process.

For example, the RTOs will not subtract congestion hedges in calculating project benefits. PJM said not excluding the hedge is “consistent with TMEP goal of simple, efficient metrics easily reproduced by stakeholders.” A majority of 27 survey respondents preferred not to include congestion hedges in the benefit calculation.

Worcester said there’s nothing to prevent congestion hedges being counted in the regional cost allocation, however.

A majority of 22 respondents supported using the last three years of historical congestion data in benefit calculations. Other stakeholders wanted the highest historical congestion data from two of the past three years used, while others wanted the past two years of congestion data used.

Exelon’s Sharon Midgley said the number of respondents seemed “incredibly low.” Worcester said there was “a reasonable cross-section of stakeholders” even though more MISO stakeholders responded than PJM stakeholders.

“This is what we’re going forward with now. In a couple of years from now, we’re open to revisiting this and improving it,” Worcester said.

PJM Manager of Interregional Planning Chuck Liebold said that there are internal RTO cost allocation details that need to be fleshed out in the draft JOA and respective tariff language. “But we have everything we need to know for the interregional benefit calculation and cost allocation,” Liebold said.

PJM and MISO staff said intra-RTO cost allocation rules are being worked out in PJM’s Transmission Owners Agreement-Administrative Committee and MISO’s Regional Expansion Criteria and Benefits Working Group.

MISO’s Adam Solomon said MISO and PJM will file JOA and tariff changes at the same time. In spite of unfinished cost allocation details, the RTOs plan to file the JOA changes sometime in October and recommend project candidates to their boards by December.

A first draft of the JOA language was released at the July IPSAC. (See MISO, PJM Unveil JOA Process for ‘Targeted’ Market Efficiency Projects.)

October 3, 2016

ERCOT Asks for Conservation Measures in Rio Grande Valley

ERCOT is asking consumers in the Lower Rio Grande Valley region to limit or reduce their electricity use where possible through Tuesday, especially during the 3-7 p.m. peak demand hours.

ERCOT control room Source: ERCOT Rio Grande Valley — ERCOT control room *Source: ERCOT*

“With some unplanned electric generation outages, combined with high temperatures in the region, we expect tight conditions during peak demand hours over the next few days,” Dan Woodfin, ERCOT’s director of system operations, said in a statement released Monday.

Woodfin said the 524-MW Frontera combined cycle plant’s recent withdrawal from the ERCOT system has complicated the task of meeting demand along the U.S.-Mexico border during tight conditions. Frontera’s owners, Viva Alamo, a subsidiary of The Blackstone Group, is dispatching energy into the Mexican market.

ERCOT said the conservation request is limited to the Lower Rio Grande Valley, and that it is not experiencing any systemwide issues at this time.

ERCOT has asked consumers to reduce demand during peak hours by:

Turning thermostats up 2-3 degrees during the peak hours;
Setting programmable thermostats to higher temperatures when no one is home;
Using fans inside homes;
Scheduling pool pumps to run in early morning or overnight hours, and shutting them off from 4-6 p.m;
Limiting the use of large appliances (dishwashers, washers, dryers, etc.) to morning hours or after 7 p.m.;
Use a microwave or slow cooker; and
Closing blinds and drapes during the late afternoon.

“We believe these voluntary actions by consumers can help limit the need for further action, such as rotating outages, to maintain overall reliability in the valley,” Woodfin said.

ERCOT in June unanimously approved two transmission projects to improve reliability concerns in South Texas. (See ERCOT Board OKs Rio Grande Valley Fixes.)

– Tom Kleckner