Page 1440 – RTO Insider

May 26, 2016

Dynegy Introduces Bill to Move All of Ill. Into PJM

By Amanda Durish Cook

Dynegy announced Thursday that it would propose legislation with the Illinois General Assembly that would transition the entire state into PJM.

If passed, the Illinois Electric Generation Reliability Act would move the Commonwealth Edison and Ameren service areas in Central and Southern Illinois from MISO Zone 4 into the PJM power market. ComEd, an Exelon subsidiary, also serves load in the Chicago area, which is part of PJM.

Dynegy claims the bill would “provide economic benefits to consumers and help Illinois preserve vital, high-paying power generation jobs.” The company said cost-effective plants in MISO-controlled Southern Illinois “sit idle, or shut down, as they don’t receive any compensation to cover operating costs from MISO.”

Dynegy, PJM, MISO — Dynegy’s Baldwin Energy Complex in Illinois

Dynegy CEO Robert Flexon said a comparison of PJM’s recent Base Residual Auction outcomes alongside MISO’s Planning Resource Auction results in April illustrates the need to combine all of Illinois with PJM, even as two of Exelon’s nuclear generators in PJM failed to clear. (See PJM Capacity Prices Fall Sharply.)

“Illinois legislators have a great opportunity to take control of an issue that is debilitating communities across the state while at the same time bring lower power prices to consumers through a more efficient market design that can exist throughout the state,” Flexon said.

Illinois is the only state in MISO’s territory that fully offers retail choice. (Michigan currently allows 10% of its load to choose their suppliers.) The bifurcated nature of the state has caused controversy.

Zone 4’s high prices in last year’s capacity auction led to accusations by Illinois officials and stakeholders of market manipulation against Dynegy, which serves most of the load in the zone. Dynegy’s proposed legislation comes three months after the company responded to MISO’s request for auction reform suggestions by proposing a separate, PJM-style three-year forward auction for Zone 4. MISO is currently in the thick of contentious debate over this proposal. (See MISO Board Orders Negotiation in Longtime Auction Disagreement.)

According to Dynegy, Illinois legislators and labor leaders, including Senate Majority Leader James Clayborne and two Illinois branches of the International Brotherhood of Electrical Workers (IBEW), support the transition.

Clayborne pointed to MISO’s unpredictable results in the last two annual capacity auctions and said the legislation would remedy the “huge gap” in how generators in different regions of the state are compensated.

The disparity, he said, “is leading to the shutdown of generation in Southern Illinois, which is threatening electric reliability, jobs, taxes and related economic development. This legislation is designed to address this gap, level the playing field and ensure electric generation reliability, jobs and the economy are protected.”

Clayborne said that bringing downstate Illinois into the deregulated fold will bring congruity to the state.

Spokesmen from IBEW 702 and IBEW 51 said the bill would protect customers from high scarcity pricing, uphold statewide electric reliability and preserve jobs by stopping premature plant closures.

Exelon, Illinois’ other power-producing giant, also is seeking relief from state lawmakers. The utility is seeking low-carbon-emissions subsidies for nuclear generators in order to keep its cash-strapped Quad Cities plant operational through 2032, when the plant’s license expires.

The General Assembly’s legislative session ends May 31.

May 24, 2016

UPDATED: PJM Capacity Prices Fall Sharply

By Suzanne Herel and Rich Heidorn Jr.

PJM’s second auction under Capacity Performance rules saw prices drop sharply as new gas-fired generation flooded the market. Exelon’s Quad Cities and Three Mile Island nuclear plants were among the plants that failed to clear, leaving them without any capacity revenue for delivery year 2019/20.

Capacity Performance prices fell in most of PJM by $65/MW-day, or 39%, to $100/MW-day compared with last year.

Prices in Eastern MAAC fell by nearly $106/MW-day, or 47%, to $119.77. Only the ComEd zone held its own, dropping just $12/MW-day, or 6%, to $202.77. Base capacity, limited to 20% of the RTO’s needs, came in at a $20/MW-day discount to CP. There were no locational constraints on base.

The auction will cost load a total of $6.9 billion in 2019/20, compared with $11 billion for last year’s auction for 2018/19.

Prices were depressed by new generation and a 1,200-MW reduction in load requirements as a result of a revised load forecast, said Stu Bresler, PJM senior vice president of markets.

The auction acquired 167,306 MW for delivery year 2019/20. That gives the RTO a 22.4% reserve margin, well above the target of 16.5%.

“Prices were lower than some analysts had expected and lower than last year’s auction results simply because of market fundamentals — changes in supply and demand,” Bresler said. “The load forecast is lower, and there was a large amount of new gas-fired combined cycle generation clearing for the first time in the auction.”

New Generation

In total, 6,543.5 MW (UCAP) of new generation offered into the auction including uprates. About 5,529 MW of the new generation cleared, mostly natural gas combined cycle and combustion turbines.

Based on prior experience most of the cleared new generators will meet their in-service dates. For example, 87% of the 4,575 MW of large, combined cycle units that cleared in the Reliability Pricing Model for 2015/16 are in service and the remainder are expected to be in service by mid-2017.

Cleared external generation dropped by 812 MW to 3,876 MW, a 17% reduction, while internal generation rose 1%. About 71% of the external generation was CP.

Like CP generation, base capacity generation is expected to be available throughout the delivery year, but unlike CP it is subject to nonperformance penalties only during the summer.

About 13,000 MW of new entry was granted an exception to the minimum offer price rule (MOPR), Bresler told the Markets and Reliability Committee on Thursday. No new entry was held to the MOPR.

Quad Cities, TMI Shut Out

Bresler called the results “extremely competitive.” He noted that fewer coal-fired and nuclear resources cleared the auction. Coal was down about 2,600 MW, and nuclear was down more than 1,500 MW, he said.

Exelon said all of its nuclear plants that offered cleared the auction except for Quad Cities, Three Mile Island and a portion of the Byron plant. Oyster Creek, which is scheduled to retire in 2019, did not participate in the auction.

Despite the news, the company said Byron is committed to operate through May 2020. The company has said it would close Quad Cities and the Clinton nuclear plant if it did not win financial support from the Illinois legislature before its session ends May 31. Exelon says the two plants have lost $800 million over the past seven years despite strong operating records.

Although Clinton cleared in MISO’s recent capacity auction, the company said its revenues will not be sufficient to earn a profit.

The company noted this was the second consecutive year that TMI Unit 1 failed to clear the PJM auction. “Although the plant is committed to operate through May 2018, the plant faces continued economic challenges and Exelon is exploring all options to return it to profitability,” the company said.

“The capacity market alone can’t preserve zero-carbon emitting nuclear plants that are facing the lowest wholesale energy prices in 15 years,” CEO Chris Crane said in a statement. “Without passage of comprehensive energy legislation that recognizes nuclear energy for its economic, reliability and environmental benefits to Illinois, we will be forced to close Quad Cities and Clinton.”

Dynegy, meanwhile, said it cleared a total of 9,804 MW at a weighted average price of $134/MW-day, worth $481 million for 2019/20. Dynegy’s PJM fleet cleared 9,187 MW at $137/MW-day and its Illinois Power Holdings will export 617 MW to PJM at $92/MW-day.

FirstEnergy declined to comment on how its plants fared in the auction. American Electric Power also made no announcements.

The two companies have been trying to win above-market purchase power agreements to support their struggling merchant fleets.

In its analysis of the auction results, UBS Securities said the depressed clearing price could spell trouble for generators looking for financial assistance. “As we have noted previously, lower capacity revenues place increased reliance on extra revenues from local customers under [FirstEnergy’s] revised PPA proposal, which could put the plan at higher risk of rejection. Similarly, we expect increased scrutiny of costs in Illinois as the legislature there continues to debate a clean energy credit for [Exelon’s] nukes.”

Demand Response, Energy Efficiency

Cleared demand response dropped to 10,348 MW, down about 7%, while energy efficiency soared almost 22%.

About 70% of the energy efficiency cleared as CP, with the remainder as summer-only base capacity. Only 6% of the DR resources qualified as CP, which must be available year-round.

DY 2019/20 will see a net increase of 84 MW of DR over 2018/19 and 312 MW of EE.

The low percentage of DR that cleared as CP should not be taken as a sign that the resource will struggle to participate in the auction when it moves to all CP in the 2020/21 delivery year, Bresler said Thursday.

“About 4,700 MW was offered that could be CP; it just didn’t clear that way economically,” he said. “I don’t think we should take these results as demand response can’t be CP.”

Renewables

Of the 969 MW of cleared wind resources, 89.4 MW cleared as CP (9%). The 969 MW represents 7,453.8 MW of nameplate capacity based on its 13% capacity factor.

About 335 MW of solar capacity cleared, compared to 184 MW last year, with only 0.4 MW clearing as CP (one-tenth of 1%). Based on its 38% capacity factor, the 335 MW represents 882 MW of nameplate solar. A total of 6,328 MW of new generation will be added in 2019/20, offset by the loss of 2,923 MW for a net increase of 3,405 MW.

Bresler noted that for the first time, one aggregated resource of renewable power offered into the auction, but he didn’t know if it cleared. Because there was only one, he wouldn’t identify it except to say it was in the renewable category, “and that’s bigger than wind and solar, it includes hydro.”

Analysts Predicted Price Drop

Analysts had predicted lower clearing prices for the auction, which began May 18.

Morningstar analyst Jordan Grimes forecast a price of $160/MW-day for the CP product and $180/MW-day in EMAAC and SWMAAC. He predicted base capacity to clear at a discount of $10/MW-day. (See Analysts Expect Lower Clearing Prices in 2019/20 PJM Capacity Auction.)

Julien Dumoulin-Smith of UBS reduced his forecast CP price from $140/MW-day to $125/MW-day. He predicted higher prices in EMAAC, DPL-S, PS-N and PSEG at $200/MW-day and ComEd at $225/MW-day.

Morningstar’s model predicted that Exelon’s Quad Cities nuclear plant would not clear the auction.

The price cap was $448.95/MW-day, compared with $450.86/MW-day for the 2018/19 auction.

May 24, 2016

PJM Markets and Reliability Committee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage. RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

2. PJM Manuals (9:40-10:10)

Members will be asked to endorse the following manual changes:

Manual 3: Transmission Operations. Updates stem from a periodic review.
Manual 11: Energy and Ancillary Services Market Operations. Resources that cannot reliably provide day-ahead scheduling reserve obligations in real time would be excluded from the process. They include nuclear units, dynamic transfers, run-of-river and self-scheduled pumped hydro units, wind units, solar units and non-energy resources. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)
Manual 13: Emergency Operations. Updates are the result of a periodic review.
Manual 14E: Merchant Transmission Specific Requirements. Reorganizes and updates the manual to reflect changes to the merchant network upgrade process approved in July 2015 by the MRC. Adds a new Section 2 that provides an overview of transmission interconnection customers proposing merchant transmission facilities upgrade projects.
Manual 36: System Restoration. Amendments incorporate lessons learned from the annual restoration drill as well as changes from a periodic review.

3. External Capacity Performance Enhancements (10:10-10:30)

This problem statement and issue charge proposes to study the challenges associated with resources subject to pseudo-tie requirements that participate in the Capacity Performance market. (See “Study of Pseudo-Tie Standards for External CP Deferred,” PJM Markets and Reliability Committee Briefs.)

4. Real-Time Values (10:30-10:45)

Proposed changes to Manual 11: Energy and Ancillary Services Market Operations incorporate real-time values. Updates allow market seller to communicate unit’s actual operating parameters to PJM before and after the day-ahead market closes when the unit cannot operate. Stipulates that real-time values may be used to modify turn-down ratio, minimum run time, minimum down time, maximum run time, start-up time and notification time, and they can be made whole due to an actual constraint.

5. Transmission Replacement Processes Senior Task Force (10:45-11:00)

Members will be asked to approve the proposed charter for the Transmission Replacement Processes Senior Task Force, previously called the End of Life Senior Task Force.

6. Energy Market Uplift Senior Task Force (11:00-11:15)

Revisions to the Energy Market Uplift Senior Task Force charter incorporate a problem statement and issue charge regarding the review of virtual transaction rules.

7. Earlier Queue Submittal Task Force (11:15-11:30)

Members will be asked to approve the recommendations of the Earlier Queue Submittal Task Force. (See “New Project Submittal Process to Require Earlier Filing of Documents,” PJM Planning Committee and TEAC Briefs.)

8. Replacement Resources (11:30-11:45)

The committee will be asked to endorse a proposal by Barry Trayers of Citigroup Energy to add an acceptable reason for early capacity replacement.

9. Seasonal Capacity Resources Senior Task Force (11:45-12:00)

Members will be asked to endorse the draft charter for the Seasonal Capacity Resources Senior Task Force, charged with developing a common definition of “seasonal resource” and how they may best participate as Capacity Performance products. (See Consumer Advocates, Enviros Press PJM on Seasonal Capacity, Artificial Island.)

10. Distributed Energy Resources (12:45-1:00)

Members may be asked to approve clarifications to the previously approved distributed energy resources problem statement. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM Markets and Reliability Briefs.)

11. Joint-owned Resource Communication Model (1:00-1:15)

Members will be asked to approve revisions to Manual 14D Attachment L.

– Suzanne Herel

May 23, 2016

Consumer Advocates, Enviros Press PJM on Seasonal Capacity

By Rich Heidorn Jr.

CAMBRIDGE, Md. — State consumer advocates last week pressed the PJM Board of Managers to change Capacity Performance rules to allow more participation by seasonal resources.

Consumer Advocates PJM Board Meeting Overview (slider) - CAPS PJM Seasonal Capacity, Artificial Island — © *RTO Insider*

At the annual meeting between the board, consumer advocates and environmental groups, the advocates and environmentalists joined in calling for PJM to consider a seasonal capacity construct that would allow more participation by demand response, energy efficiency and solar resources.

The meeting filled a large ballroom at the PJM Annual Meeting. Increased funding for the Consumer Advocates of PJM States (CAPS) allowed more representatives to participate, with 11 of PJM’s 13 states and D.C. attending. (See FERC Approves PJM Funding of Consumer Advocates.) The meeting was also marked by an impassioned plea from Delaware officials for relief from the cost allocation for the Artificial Island transmission project.

The Capacity Performance rules include the option to aggregate summer and winter resources into a single capacity offer. But no aggregated offers were submitted in the first Base Residual Auction with CP last year, for delivery year 2018/19. Base capacity resources, which permitted summer-only DR, will be eliminated with next year’s auction for 2020/21.

Problems with Aggregation

Dan-Griffiths PJM - CAPS PJM Seasonal Capacity, Artificial Island — Griffiths © *RTO Insider*

“Aggregation can work for an owner that has both ends of the seasonal resource,” CAPS Executive Director Dan Griffiths said. “But when you have different owners, you have liability issues and allocation issues that are just frightening. So we have to admit that we do need seasonal resources.”

Brian Lipman, litigation manager for the New Jersey Division of Rate Counsel, said PJM must “find a way to work these resources into the mix so that we’re not paying for the next [generation] unit that’s not only higher in price but more likely more damaging to the environment.”

Speaking for the Public Interest and Environmental Organization User Group, Jennifer Chen, of the Sustainable FERC Project, praised PJM for its new load forecasting methodology but also called for capacity rule changes, noting that only 13% of cleared DR in last year’s auction qualified as CP.

The Seasonal Capacity Resources Senior Task Force has been meeting since early April to discuss the issues. (See “Seasonal Resources in the Capacity Market to be Studied,” MRC & Members Committee Briefs.)

The task force’s problem statement said the inquiry was necessary because of the elimination of base capacity and changes to measurement and verification for non-summer CP demand resources. “Through these two changes, demand resources, energy efficiency, solar and other resources that are either exclusively or primarily available in the summer season may no longer be able to meaningfully participate in PJM’s capacity market,” it said.

Andy-Ott,-PJM; PJM, CAPS, seasonal capacity — Ott © *RTO Insider*

PJM CEO Andy Ott said creating separate summer and winter capacity products would require changes to how capacity costs are allocated, which is currently based on five coincident peaks. Changing the methodology, he said, would concern industrial customers and other loads.

But Ott said he has asked staff to consider “where the rules need to evolve for demand response. There has been at least a two-year period of significant uncertainty.” That ended with the Supreme Court’s ruling in January upholding FERC jurisdiction over DR in wholesale markets. (See Supreme Court Upholds FERC Jurisdiction over DR.)

Pairing up Resources

Ott said PJM also is considering modifying the aggregation rules in a way that would not force summer or winter resources to enter into contracts and share risks. “Some type of mechanism where we pair them up and assign their value,” he explained.

At a later “Year in Review” session, Independent Market Monitor Joe Bowring said PJM could consider a seasonal or even monthly capacity product. But, he cautioned, “if it’s going to be done it should be done comprehensively — not for a single product.”

At the same session, Stu Bresler, senior vice president for market operations expressed concern that a two-season construct could “undermine long-term price signals.”

That brought a retort from Marji Philips of Direct Energy: “Come on, New York is a month, guys!” — a reference to NYISO’s monthly capacity auctions.

MISO ‘Not Going Along’

Left to right: Price, Bonar © RTO Insider; PJM, CAPS, Seasonal capacity — Left to right: Price, Bonar © *RTO Insider*

At the earlier session, New Jersey’s Lipman also expressed concern over the handling of external capacity resources, saying that consumer representatives supported tightened rules knowing it would likely increase prices. “At this time, we now understand that MISO is not going along with the plan [the way] we thought they would,” he said. “We hope both regions will come together and find a way to resolve this issue.” (See “Ready for Pseudo-Tie Switchover,” MISO/PJM Joint and Common Market Meeting Briefs.)

Jackie Roberts, director of the West Virginia Public Service Commission’s Consumer Advocate Division, said PJM could help consensus-building efforts by appointing formal facilitators independent of the RTO and with no stake in the outcome of deliberations.

“The PJM folks who are trying to facilitate in the stakeholder process do have a stake in the outcome, so that makes it very difficult,” she said. “Traditionally what people do is those that like PJM’s proposal all line up with PJM to talk about options, and those that don’t don’t have anyone to talk to.”

‘Bankrupting’ Delaware

Howard Schneidor (L) and Andy Ott (R) ; PJM, CAPS, seasonal capacity — Left to right: Schneidor, Ott © *RTO Insider*

Delaware Public Advocate David Bonar and Deputy Advocate Ruth Ann Price called on PJM to provide their state — PJM’s smallest — relief from the more than $100 million bill it faces from the Artificial Island stability project. A PJM study found that the Delmarva Peninsula — Delaware and the eastern shores of Maryland and Virginia — would pay about 89% of the project’s costs while receiving little more than 10% of the annual load payment savings from the upgrade.

“It’s vitally important to our state that this project be as inexpensive as it possibly can,” Bonar said. “Some of my ratepayers are looking at 30% increases in their rates and that to me is unconscionable.”

The costs “are on the verge of devastating,” Price said.

“As I keep telling my CAPS members, there’s a transmission project coming to you and it may also affect you in the same way,” she said. “None of us want to see a headline that says ‘PJM Bankrupts Delaware.’”

PJM Chairman Howard Schneider responded that “we’re not trying to build a gold-plated grid. We’re trying to get a grid that is reliable and responsive at the least possible cost — and we are cognizant of those costs,” he said.

But Schneider said the cost allocation “is an issue which is really out of our hands.” In a 3-1 decision in April, FERC approved the use of the distribution factor cost allocation (DFAX) on the project. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)

“It’s at FERC,” Schneider said. “That’s where the issue needs to be raised and re-raised.”

May 23, 2016

SPP, AECI Endorse Scope for 2016 Joint Planning Study

By Tom Kleckner

SPP, Associated Electric Cooperative Inc. (AECI) and their stakeholders Friday unanimously endorsed the scope for the entities’ biennial joint system planning study.

The SPP-AECI Interregional Stakeholder Advisory Committee (IPSAC) reviewed and discussed changes to the scope document, which was first unveiled in April. (See “SPP, AECI Begin Biennial Joint-Study Process,” SPP Briefs: State of the Market, Study w/ AECI.)

SPP and AECI will focus their efforts on “pre-determined problem areas” in Oklahoma and Missouri. Those areas include Northeast Oklahoma, where SPP’s 2016 Integrated Transmission Plan Near-Term assessment identified voltage and thermal violations, and the Brookline area west of Springfield, Mo.

SPP’s interregional coordinator, Adam Bell, said the RTO’s regional studies have resulted in projects that could fix the problems in Oklahoma but that the joint study would determine whether interregional transmission projects would be more efficient “than what we or Associated would have done on [our] own.”

Staff revised the scope to add language addressing overloads in the Brookline area when there is little or no hydropower available, generally in the morning or early afternoon hours.

Staff from City Utilities of Springfield said they felt the addition met their needs but that “there are more discussions to be had.”

SPP and AECI staff will now develop system models and begin evaluating the targeted areas in September. The IPSAC will next meet in October, with a final report to be delivered in January.

“We’re not holding ourselves to that schedule,” Bell said. “If we can work faster, we will.”

The two entities have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. The 2014 study identified 463 potential needs along the SPP-AECI seam, but it resulted in no joint solutions.

AECI, based in Springfield, Mo., is owned by and provides wholesale power to six regional generation and transmission cooperatives.

May 23, 2016

Aliso Canyon Gas Restrictions Cloud CAISO Summer Outlook

By Robert Mullin

New generation and a rebound in hydroelectric capacity mean healthy operating reserve margins for California this summer but impending restrictions on the Southern California gas pipeline system could result in load sheds, CAISO warned in its 2016 Summer Loads and Resources Assessment last week.

ISO, SP26 and NP26 Monthly Peak Demand (CAISO) - aliso canyon gas — Figure shows CAISO system peak – as well as peaks for Northern and Southern California – over 2006-2015.

As a result of the pipeline restrictions — stemming from the closure of the Aliso Canyon gas storage facility — the situation confronting the state this summer is far from normal. (See CAISO Seeks Rapid Response to SoCal Gas Restrictions.)

“We’re immediately faced with running the system in a way that it’s never been run before,” Rob Oglesby, executive director of the California Energy Commission, said at the California Energy Summit in Santa Monica earlier this month.

The ISO’s annual summer reliability report, which outlines its preparedness for California’s peak consumption season, describes a largely favorable situation.

Load in the CAISO balancing area is forecast to peak at 47,529 MW, up just 0.8% from last summer’s peak, due to modest economic growth. At the same time, the ISO has brought on 1,951 MW of net qualifying capacity — or deliverable generating output — over the past year, outpacing the projected growth in peak load.

Operating reserve margins are forecast to remain “well above” the threshold for firm load shedding under the most extreme scenarios. That analysis applied systemwide, as well as generally in the ISO’s NP26 (North) and SP26 (South) regions, although it does not break out reserves for specific load zones. The ISO also sees no shortage in flexible capacity and meet spikes in demand.

Hydroelectric conditions have improved significantly compared with the dire drought conditions seen last spring throughout California and up into the Northwest. Statewide snow water content was at 87% of the historical average as of March 30. While snowmelt is advancing more rapidly than normal, CAISO says the situation is “not significant enough” to require a revision of its hydro assumption in the summer assessment. In addition, water levels behind The Dalles Dam — a benchmark for the federal Columbia River system of hydroelectric plants — stand at 101% of average.

“There are no concerns with Pacific Northwest hydroelectric generation,” CAISO said, indicating the winter-peaking region should be able to provide California with significant generation during the summer.

CAISO’s summer concerns instead focus on Aliso Canyon’s impact on the gas system serving 9,500 MW of gas-fired generation located in CAISO’s southern region and the balancing area of the Los Angeles Department of Water and Power, the state’s largest municipal utility.

The ISO notes that its assumed summer reserve margins do not account for the risk of gas curtailments, which could translate into the depletion of reserves in SP26, an area largely served by Southern California Edison and San Diego Gas and Electric.

Even more significant: Curtailments could be large enough to interrupt electricity service to millions of Southern California customers on as many as 14 days during the summer. The ISO attributes that risk to potential mismatches between gas schedules and gas burn, outages on pipelines and at other gas storage facilities, and prolonged heat waves that could drive increased power demand.

“The natural gas issues facing Southern California this summer will require deft management, particularly during hot days when power plants fueled by natural gas are needed to meet peak demand,” ISO CEO Steve Berberich said in a statement.

CAISO’s Board of Governors earlier this month approved a plan to mitigate the effect of gas curtailments through improved gas-electric coordination with pipeline operator Southern California Gas, new market measures incorporating a gas usage constraint and a provision for reserving transmission capacity into Southern California ahead of potential gas emergencies. (See CAISO Board Approves Aliso Canyon Market Response.)

Officials from CAISO, the Energy Commission, Southern California Edison, LADWP and Peak Reliability presented their summer outlooks to FERC at last week’s monthly commission meeting. CAISO has asked FERC to approve the gas contingency plan by June 1, the start of summer electricity operations in California.

May 23, 2016

Texas PUC OKs Undergrounding Tx Line; City Agrees to Foot Cost

By Rory Sweeney

AUSTIN, Texas — More than three years after it was initially conceived, a short but expensive transmission line to address expected growth in the suburban areas of Denton County, Texas, finally received state regulatory approval last week.

The Public Utility Commission approved a somewhat unusual “settlement stipulation” that committed the City of Frisco to paying more than half of the bill for a hybrid above/below-ground route. The 2.9-mile 138-kV project, which received more than 3,000 comments in protest of various above-ground proposed alternatives, was approved with the stipulation that more than 90% of it be installed underground. Built and operated by the Brazos Electric Power Cooperative, the line will run west along Frisco’s Main Street from an existing Oncor line tap to a new Stonebrook substation.

Based on its projected $24.5 million cost, the commissioners were reticent to approve the more expensive burying options, but they relented because Frisco agreed to pay more than $12 million to get its specified, mostly underground option approved. The agreement will allow the line to be laid underground as part of a widening and water line installation project the city had already planned for the street.

Combined with the existing $6 million cost credit for the route the PUC had been prepared to approve, Brazos will be able to recoup $12 million through transmission cost of service recovery. Should Frisco fail to make its payments, the agreement allows Brazos to revert to the all-overhead route.

State Sen. Jane Nelson, who represents the area as the state’s highest-ranking Republican, wrote a letter to the PUC in support of the agreement, saying there were few other viable options because both the Texas Department of Transportation and the U.S. Army Corps of Engineers denied use of their land. Overhead lines would have eventually conflicted with infrastructure needs for street widening and water lines, she said.

She also applauded Frisco for contributing more than 50% of the total cost and more than 67% of the incremental cost to bury the lines. The commissioners joined Nelson is noting that Frisco’s commitment is “far exceeding” that of other municipalities in similar situations.

The additional costs still didn’t sit well with commissioners, despite arguments that it was a better plan for expected future growth. “I have concerns with uplifting any underground costs to ratepayers,” Commissioner Brandy Marty Marquez said.

“There’s a heavy burden to prove that the undergrounding needs to take place because it’s so much more expensive than placing the lines above ground,” Commission Chairman Donna L. Nelson said at last week’s meeting.

But they had also heard from many citizens near the route, who had organized themselves into a group called Bury the Lines. The city acknowledged that the above-ground routes were “universally opposed” by the community.

The agreement requires that Frisco have its widening and water line project awarded within 15 months of the PUC’s final order.

May 23, 2016

Company Briefs

American Electric Power has named Judith Talavera president and chief operating officer of AEP Texas. Talavera replaces Bruce Evans, who has been named to AEP’s newly created position of senior vice president and chief customer officer, effective June 1.

Talavera, 42, the company’s first female president, will report to Venita McCellon-Allen, president and CEO of AEP Southwestern. Talavera was previously director of regulatory services for AEP Texas and began her career with the company in 2000 as manager of governmental affairs.

In his new position, Evans will oversee customer services, marketing and distribution, as well as regulatory services, business development and infrastructure and business continuity.

More: Corpus Christi Caller-Times

Xcel Lays Out Options for Improving Reliability in ND

Xcel Energy officials last week outlined millions of dollars in options for improving electric service in North Dakota and told state regulators that its Fargo system is fundamentally sound despite a recent rash of power outages.

Company officials met with the state’s Public Service Commission May 18 for an informal hearing on reliability after Xcel experienced eight outages in Fargo between April 22 and May 13, affecting more than 24,000 customers.

Xcel officials laid out options that include accelerating its schedule to replace the unjacketed cable that faulted in Fargo at a cost of $4 million, retrofitting certain utility poles to make them less prone to fire and installing more switches that automatically reroute power from unaffected areas during outages. Commissioners said Xcel would likely have to front the costs and seek to recover them from customers later, as the company is barred from seeking a rate increase until 2018.

More: Forum News Service

Enel Begins Construction On 150-MW ND Wind Farm

Enel Green Power North America has begun building the 150-MW Lindahl wind project in North Dakota. The project is designed to generate about 625 GWh annually to meet the electricity needs of more than 50,000 households.

Enel will sell the project’s power and renewable energy credits to SPP member Basin Electric Power Cooperative under a bundled, long-term power purchase agreement. This is Enel’s fourth U.S. project this year, after beginning construction on wind farms in Kansas, Minnesota and Oklahoma.

More: Energy Business Review

RES Eying Upper Peninsula For 150-MW Wind Project

Renewable Energy Systems is considering a 121-turbine, 150-MW wind energy project on the Michigan Upper Peninsula that would be roughly five times larger than the only wind farm on the peninsula, according to documents obtained by Midwest Energy News using a Freedom of Information Act request.

The Federal Aviation Administration is reviewing the plans because of the height of the proposed towers, and MISO confirmed that the project is in the system planning and analysis phase. RES wouldn’t confirm the project, saying only that it is “actively developing projects in Michigan and across the region.”

More: Midwest Energy News

Duke Plant Opponents Balk At $10 Million Appeal Bond

Opponents to a Duke Energy plan to build a $750 million natural gas-fired plant near Asheville are asking an appeals court to waive a requirement that they post a $10 million bond if they appeal regulators’ approval of the project.

Environmental groups NC WARN and The Climate Times said the North Carolina Utilities Commission based its bond requirement on unproven statements provided by Duke that an appeal would ultimately fail and the delay would cost the company millions of dollars.

Duke said the bond follows established law.

More: Charlotte Business Journal

DTE Opens Energy Center For Renewable Operations

DTE Energy has opened a facility in Bad Axe, Mich., that will serve as an operations center for its renewable energy operations.

The Huron Renewable Energy Center has offices, garages, a maintenance shop and warehouse, out of which about 25 employees will manage the company’s wind and solar projects in the region. It also has a 3,000-square-foot space available for community services that will be available in 2017.

DTE has four wind facilities and three solar arrays in Huron County, and two more wind facilities and 23 more solar arrays in other parts of the state.

More: The Associated Press

Archaeological Discovery Could Delay Pipeline

Energy Transfer Partners has started construction of the Dakota Access pipeline in three of the four states that the 1,150-mile pipeline will cross, but a discovery of a site in Iowa that may be culturally significant to Native Americans could delay approval there and force rerouting.

Work has started in North Dakota, South Dakota and Illinois. The company is awaiting action by Iowa regulators to allow construction to begin in that state. Last week, the state’s archaeologist said he was reviewing a potentially historically significant site near the pipeline’s route.

The project is also awaiting U.S. Army Corps of Engineers approval to cross the Missouri and Mississippi rivers.

More: The Associated Press

Puget Sound Bond Buyback Deal Getting Investor Pushback

A plan by Puget Sound Energy to buy back bonds at a discounted rate isn’t going over well with some of the bond’s owners, who say they deserve better terms. Puget Sound wants to retire $250 million in 6.974% bonds that aren’t due until 2067 as a way to lighten its balance sheet.

But some of the bond owners don’t think the price offered by the company is fair. The company proposed to buy the bonds back at 85 cents on the dollar. But since the company announced the buyback plan, the price of the bonds jumped 6 cents to the 85 cents the company is offering.

The company said it is going to go forward with the buyback plan despite complaints from some bondholders. “We believe it’s a fair offer,” CFO Daniel Doyle said. “I respect the right of our bondholders to make a decision whether it makes sense for them or not. We will respect their decision and go forward.”

More: Bloomberg

May 23, 2016

Restructuring Roundtable Marks 150th Meeting

By William Opalka

BOSTON — The New England Electricity Restructuring Roundtable met for the 150th time on Wednesday to celebrate some successes and discuss ways to continue moving the nation to a low-carbon future.

Tierney © RTO Insider - Restructuring roundtable new england — Tierney © *RTO Insider*

The meeting has grown from the small group of stakeholders that met in 1995 in the early days of electric industry restructuring. Last week’s session, organized by Raab Associates, filled a hotel ballroom with about 300 attendees.

Among the successes of the last 20 years: the growth of energy and capacity markets and an increasing reliance on clean energy sources and energy efficiency.

Attendees also expressed disappointment over challenges they thought would now be in the rearview mirror.

“We need to put a meaningful price on carbon. We can’t do anything unless we do that and it has to show up on” bills, said Susan Tierney, senior advisor at Analysis Group.

Howe © RTO Insider — Howe © *RTO Insider*

John Howe, senior advisor to Poseidon Water and former chairman of the Massachusetts Department of Public Utilities, agreed. “The single biggest failure was not to put a price on carbon,” he said.

While New England has cut emissions through the Regional Greenhouse Gas Initiative, the record is mixed.

“RGGI is a signal accomplishment,” said Richard Cowart, director of European programs for the Regulatory Assistance Project. “This is something that will be a lesson for the world — that carbon revenue is just as important as carbon pricing,” because it can be a source of investments to lower carbon emissions through energy efficiency programs and clean energy technologies.

RGGI’s trading prices have been far below EPA’s estimated “social cost of carbon,” however, and revenues from the program have been used to fill state budget shortfalls — not solely to support lower emissions.

Cowart © RTO Insider — Cowart © *RTO Insider*

Even if prices were higher, RGGI would be only a piecemeal solution, said William Hogan, the Raymond Plank professor of global energy policy at the Harvard Kennedy School.

“The scope of the [climate change] problem is enormous. And it’s worldwide. If you’re not doing it everywhere, you’re wasting your time,” he said. While the recent Paris Agreement shows some global movement, enacting a carbon tax in the U.S. to further its goals is “politically impossible,” he said.

William Hogan, Harvard Kennedy School — Hogan © *RTO Insider*

But Hogan sees hope in some movement for more comprehensive tax reform in Washington. “On that day, they’re going to be doing 50 things that are politically impossible, individually, and I want to make sure a carbon tax is one of the 50.”

Despite some frustrations, Peter Fox-Penner, professor in the Questrom School of Management and director of Boston University’s Institute for Sustainable Energy, said there is promise in the future. “New England’s emphasis on renewable energy and energy efficiency shows industry is poised to meet the challenge of decarbonizing the sector while retaining reliability and affordability.”

Fox-Penner © RTO Insider — Fox-Penner © *RTO Insider*

But the role of natural gas as a “bridge” fuel to that future is a question, as carbon emissions in New England have ceased to fall. The potential loss of the region’s nuclear power fleet also could harm efforts to arrest climate change.

“The dash to gas was appropriate at the time … but the time is at hand to cross that bridge and now is the time to get to cleaner and more sustainable solutions,” Howe said.

But given the low price of gas and wide availability, political and cultural shifts may be needed to resist that temptation.

“The discipline to keep the natural gas in the ground is going to be one of the great challenges of the next generation,” Cowart said.

May 23, 2016

FERC Rulings in Brief: Week of May 19

Below is a summary of rulings issued by FERC last week.

FERC Finalizes Hold-Harmless Rules

FERC issued a policy statement finalizing rules regarding the use of hold-harmless commitments to protect customers from rate increases resulting from utility mergers (PL15-3).

The commitments — agreements not to seek recovery of transaction-related costs in rates unless they are offset by transaction-related savings — have become a common feature of merger applications under Section 203 of the Federal Power Act, but the commission hadn’t defined the costs with specificity, leading to inconsistencies.

The commission:

Clarified the scope and definition of the costs that should be subject to hold-harmless commitments;
Identified the types of controls and procedures that applicants offering hold-harmless commitments must implement to track the costs involved;
Clarified that an applicant may be able to demonstrate that the transaction will not have an adverse effect on rates without making any hold-harmless commitment; and
Declined to adopt its proposal to no longer accept hold-harmless commitments that are limited in duration. (See FERC to Tighten Policy on Hold Harmless Merger Commitments.)

Reliability Standard Wins Preliminary OK

FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to approve NERC reliability standard BAL-002-2 (Disturbance Control Standard — Contingency Reserve for Recovery from a Balancing Contingency Event). The rule requires applicable entities to balance resources and demand, and return their area control error (ACE) to defined values following a disturbance. The commission required NERC to modify the standard to address concerns over extensions or delay of the periods for ACE recovery and contingency reserve restoration. It also directed NERC to address a reliability gap regarding power losses above the most severe single contingency (RM16-7).

Constellation’s Reactive Payments Cut Due to Retirements

The commission accepted a petition from Constellation Power Source Generation to reduce its revenue requirement for reactive supply and voltage control service by almost $225,000 as a result of the retirements of Riverside Unit CT 6 (June 1, 2014), Perryman Unit CT 2 (Feb. 1, 2016) and Riverside Unit 4 (planned for June 1, 2016). The commission also ordered hearing and settlement judge procedures to determine whether the company’s reactive power rate for its remaining fleet in the Baltimore Gas and Electric zones should be reduced further (ER16-746-001, et al.). (See Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants.)

SoCalEd Can Recover Abandoned Tx Project Costs

FERC ruled that Southern California Edison may recover abandoned plant costs for the canceled Coolwater-Lugo transmission project but set settlement and hearing judge procedures to determine how much of the $37 million claimed by the company was prudently incurred. The project was no longer needed after the retirement of NRG Energy’s 636-MW Coolwater Generating Station and three other generators. The Los Angeles Department of Water and Power and the M-S-R Public Power Agency challenged the $8.51 million in overhead costs that SoCalEd included in its claim, saying the company provided little documentation for how overhead costs were allocated to the project (ER16-1025).

Settlement on SSR Units OK’d

The commission approved an uncontested settlement reached among several Illinois companies and MISO that changes Illinois Power Holdings’ annual revenue requirement for the operation of Edwards Unit 1, a 90-MW coal-fired steam boiler in Peoria, Ill., designated as a MISO system support resource. The new annual revenue requirements will be $7 million for 2013, $11.1 million for 2014 and $6.5 million for 2015 (ER14-2619-004, et al.).

Rehearings Denied

The commission also:

Denied rehearing but granted clarification of its October 2015 ruling in Order 816, which amended its regulations governing market-based rate authorizations (MBRA). (See FERC Refines Market-Based Rate Rules.)

The commission clarified that qualifying facilities in RTOs and ISOs are exempt from reporting requirements on long-term firm energy and capacity purchases. The commission also said that it did not intend to change the definition of long-term firm transmission reservations: those longer than 28 days. It also offered clarifications regarding the definition of a seller’s relevant geographic market and said MBRA applicants and sellers will not have to comply with the corporate organizational chart requirement until the commission issues an order at a later date (RM14-14-001).

Denied rehearing of its October ruling exempting American Transmission Systems Inc. and Duke Energy companies in Ohio and Kentucky from certain MISO multi-value project (MVP) transmission charges. MISO and MISO’s Transmission Owners sought rehearing to assign a usage fee to ATSI and Duke for MVPs approved before the companies moved from MISO to PJM in 2011. In the rehearing denial, FERC pointed out that MISO’s MVP cost allocation on withdrawing members was instituted in 2012 and said charging the companies would violate its rule against retroactive ratemaking. The commission also rejected arguments that MISO’s Tariff at the time of ATSI’s and Duke’s exits could be interpreted to allow for MVP-related financial obligations (ER12-715-004).
Denied El Paso Electric’s request for rehearing of a November 2015 order that required prior approval for utilities to engage in simultaneous exchange transactions involving their marketing affiliate and its affiliated transmission provider’s system (EL10-71-002).
Denied rehearing of a September 2015 order allowing future affiliates of Kanstar Transmission to use the same formula rate and incentives approved for Kanstar (ER15-2237-002).

– Rich Heidorn Jr. and Amanda Durish Cook