UPDATED: MISO Asks FERC to Dismiss IPL Storage Complaint

By Amanda Durish Cook and Rich Heidorn Jr.

MISO asked FERC to reject Indianapolis Power and Light’s complaint over energy storage rules, calling it disruptive to stakeholder proceedings and the commission’s broad rulemaking.

MISO asked the commission to dismiss IPL’s Oct. 21 complaint and let it continue using its stakeholder proceedings and Market Roadmap process as the venues for storage market design. MISO also said it would honor “deliberate commission policy” (EL17-8).

MISO’s response was one of a flurry of comments filed Nov. 10, before the commission issued its Nov. 15 Notice of Proposed Rulemaking outlining requirements that RTOs and ISOs remove barriers to storage and aggregated distributed energy resources. (See related story, FERC Rule Would Boost Energy Storage, DER.)

The RTO said IPL’s request could “distract and detract” from its efforts to work out storage issues with stakeholders and from FERC’s effort to address the issue industry-wide, “rather than within the narrow confines of a single market participant’s complaint in this limited proceeding.”

IPL told FERC that it had no way to receive compensation for the 20-MW battery at its Harding Street Station although the facility has been providing MISO with primary frequency response since May. (See IPL Asks FERC to Force Update to MISO Storage Rules.)

IPL/AES Harding Street Energy Storage - FERC, MISO — Harding Street Energy Storage | *AES*

MISO responded that IPL’s request “improperly circumvents” FERC’s rulemaking on storage compensation and grid integration, a process that continued with a technical conference Nov. 9. (See FERC Panelists Debate Storage Uses, Compensation.)

The RTO also argues that IPL “neither shows any immediate damage to itself from waiting for the outcome of such commission processes” and claims that there is no pressing need for primary frequency response service in the MISO footprint.

MISO also accused IPL of exaggerating and mischaracterizing alleged Tariff shortcomings and said IPL provided no proof of how MISO’s current storage energy resource dispatch protocols would harm the life of the Harding Street battery.

“A number of issues raised in the IPL complaint are already being addressed as part of MISO’s Market Roadmap process and through separate ongoing public stakeholder discussions,” MISO spokesman Jay Hermacinski said. “Stakeholder discussions and the Market Roadmap process are intended to comprehensively evaluate possible changes to MISO’s Tariff necessary to further accommodate various energy storage technologies.”

Others Weigh In

IPL’s complaint won support from the Energy Storage Association, Advanced Energy Economy and a coalition of environmental organizations, including the Sustainable FERC Project and the Natural Resources Defense Council.

The groups said FERC should order MISO to create a separate market product for primary frequency response and to revise its dispatch protocol to one “appropriate for all energy storage technologies.”

Duke Energy Indiana said the commission should order MISO only to conduct a study of — and initiate a stakeholder process on — frequency response. It said the commission should “be cautious about approving that a new product (along with that product’s value suggested by IPL) be added to the MISO [Tariff] without first requiring a thorough vetting by MISO, the MISO transmission owners and other stakeholders.”

Battery maker Alevo USA also urged caution, saying IPL’s statements about the limitations of lithium ion batteries are “not necessarily correct.” It said it supports IPL’s intent to remove barriers to entry for storage. But it said FERC should order MISO to develop a “technology-neutral” market design rather than “pick[ing] winners and losers based on what IPL proposes.”

Also weighing in on the matter was NextEra Energy Resources, which asked the commission to coordinate its response to IPL with its actions in other proceedings, including the commission’s Notice of Inquiry on primary frequency response, in which the commission also took action last week (RM16-6). (See related story, FERC: Renewables Must Provide Frequency Response.)

“NextEra Resources agrees with IPL that MISO’s current energy and ancillary services products are unduly discriminatory with respect to storage resources attempting to provide service. However, the deficiencies with respect to MISO’s regulating service product are not unique to MISO or its regulation product,” NextEra said, adding that it and others had raised such concerns in AD16-20 regarding “a range of products in a number of RTOs/ISOs.”

NextEra also said it was concerned that IPL’s proposed compensation structure for primary frequency response lacks a capacity payment.

“Even when an RTO/ISO imposes particular dead band and droop settings to ensure that resources automatically provide primary frequency response, the resource must maintain sufficient headroom in order to be able to increase output in response to deviations when frequency is low. Yet holding back this capacity to be available to respond to under-frequency conditions comes at a cost. A capacity payment for primary frequency response would compensate resources for this opportunity cost and thereby ensure the resource will be available to respond, and should be a part of any RTO/ISO compensation mechanism for primary frequency response.”

November 15, 2016

State Briefs

Lucerne Valley Residents Oppose SoCalEd Renewable Energy Project

Southern California Edison is attempting to sooth the concerns of Lucerne Valley residents who are seeing red over a project to move renewable energy generated from northern states to the Western region, which requires construction of new capacitors near their homes and a proposed scenic highway.

The Eldorado-Lugo-Mohave Upgrade Project, which will increase power flow through existing transmission lines, includes installation of 250 miles of optical ground wire, resulting in the need to raise lines by 5 to 15 feet in 13 locations and to install several capacitors.

Construction is expected to begin in late 2017, with the project expected to be operational and in service by 2020.

More: The Leader

LA Supervisors: SoCalGas Should not Resume Aliso Canyon Operations

Los Angeles County supervisors voted unanimously to press state regulators to deny Southern California Gas’ request to resume injecting natural gas into wells at the Aliso Canyon storage facility, arguing that regulators cannot presently “in good faith” determine whether the facility is safe.

Aliso Canyon was the site of a four-month leak that emitted 109,000 metric tons of methane and displaced thousands of residents.

The utility has since reconstructed the wells to be used for injection or withdrawal with new tubing and steel pipe and added upgrades including around-the-clock pressure monitoring of all wells and an infrared fence-line methane detection system.

More: Los Angeles Daily News

Community Choice Energy Expected in Berkeley

The Berkeley city council is expected this week to approve the city’s participation in a community choice energy program anticipated for Alameda County cities in fall 2017.

East Bay Community Energy will allow member cities to pool resources to purchase cleaner energy at lower prices. Delivery would continue through the Pacific Gas and Electric system, and PG&E would maintain infrastructure and handle billing and customer service.

Neighboring Albany’s council passed a similar ordinance last week.

More: East Bay Times

MAINE

Portland Requires Large Businesses, Buildings to Report Energy Use

speaker_h-_pingree_rep-_j-_hinck_me_statehouse_april_2010 — Hinck (right)

Roughly 225 commercial buildings, 40 municipal buildings and 19 apartment complexes must report their energy usage to Portland officials under a utility benchmarking program passed by the City Council.

The program, the first of its kind in the state, seeks to collect baseline data to gauge trends in energy use and to measure the effectiveness of efficiency upgrades.

Affected property owners will have at least two and a half years before having to comply under an amendment offered by City Councilor Jon Hinck, who chairs the Energy and Sustainability Committee.

More: Portland Press Herald

MICHIGAN

BWL Paid $25K Ransom To End Cyberattack

In a move its general manager called “distasteful and disgusting, but sadly necessary,” the Lansing Board of Water & Light paid a $25,000 ransom last spring to end a cyberattack on its internal communications systems.

The April 25 attack shut down BWL’s accounting and email systems and forced the utility to shut down phone lines, including a customer service line. Electric and water distribution were not affected.

The cost of responding to the breach, including the ransom and technology upgrades, was $2.4 million, BWL General Manager Dick Peffley said. All but $500,000 of the costs are covered by insurance, he said.

More: Lansing State Journal

NORTH CAROLINA

Duke Energy Seeks to Cap Coal Ash at 6 Plants

Duke Energy filed plans last week with state regulators to leave two-thirds of its coal ash in basins drained of water and covered with protective caps, instead of excavating it at six plants.

The plants where Duke plans to cap ash in place are the Allen plant on Lake Wylie, Marshall on Lake Norman, Belews Creek in Stokes County, Mayo and Roxboro in Person County, and Rogers in Rutherford County.

Duke previously was ordered or agreed to excavate ash at seven of its power plants in the state. In October, it reached a court settlement to do so at an eighth plant.

More: The Charlotte Observer

OHIO

NOPEC Reaches Electricity Deal After FirstEnergy Ends Contract

The Northeast Ohio Public Energy Council has reached a three-year deal for a new electricity provider after FirstEnergy Solutions abruptly canceled its deal serving 500,000 customers three years before it was supposed to expire.

Effective in January, NextEra Energy Services — which provided electricity to NOPEC before the FirstEnergy deal — will be NOPEC’s new supplier.

Under the new agreement, customers will receive initial pricing from January through the summer high-demand period, followed by options for a variable rate. Customers automatically will be included under the new contract unless they opt out.

More: The Akron Beacon Journal

Youngstown Voters Reject Fracking Ban for 6th Time

Youngstown voters rejected for the sixth time a Community Bill of Rights that would ban fracking in the city.

The measure was defeated 55% to 45%. Last year’s rejection of the proposal was the closest yet, by 2.5 percentage points.

Jackie Stewart, Energy in Depth’s Ohio state director, called the vote “a huge blow to activist groups.”

More: The Vindicator

Regulators Approve Switching AEP Plant from Coal to Natural Gas

State regulators approved a plan for American Electric Power to transition its Cardinal Plant in Brilliant from coal to natural gas by 2030.

AEP officials said they don’t know what the plan’s impact will be on customer rates. However, regulators said that for the first two years, bills should not increase by more than 5%.

Under the agreement, AEP also will develop over the next four years at least 900 MW of wind and solar energy projects in the state.

More: The Intelligencer

OKLAHOMA

Regulators Shutting Down Disposable Oil Wells Following Earthquake

State regulators are shutting down more disposable oil wells and restricting the volume of others in response to the magnitude 5.0 earthquake that struck last week.

The Corporation Commission’s Oil and Gas Division ordered seven wells within 6 miles of the epicenter to be shut down by Monday.

By Nov. 21, 16 wells within 10 miles of the epicenter must reduce volume by 25% of their last 30-day average, and 31 wells within 15 miles will be limited in volume to their last 30-day average.

More: The Associated Press

PENNSYLVANIA

PECO Withdraws Plans for $35M Microgrid Project

PECO Energy withdrew plans to build a $35 million self-sustaining microgrid in Delaware County after drawing strong opposition from customer advocates.

The proposed microgrid included 10.5 MW of natural gas and solar-power generators and 200 kW of battery storage. During a widespread outage, it could operate independently of the regional power grid.

Customer advocates questioned whether it was proper for the utility to re-enter the power-generation business it had been forced to spin off under the 1996 Electricity Generation Customer Choice and Competition Act. They also questioned whether all PECO customers would benefit from the project as the utility proposed rate surcharges to all customers to cover its cost.

More: The Philadelphia Inquirer

SOUTH DAKOTA

Green Energy Candidate Loses PUC Election

Red Cloud | Lakota Solar Enterprises — Red Cloud | *Lakota Solar Enterprises*

Oglala Sioux green energy entrepreneur Henry Red Cloud, a Democrat, was defeated by Republican incumbent Chris Nelson for a seat on the state’s Public Utilities Commission.

Nelson said he would try to keep utility rates as low as possible. Red Cloud, a first-time candidate, ran on a green energy platform.

More: The Associated Press

WISCONSIN

Regulators Reduce Return On Equity for MG&E

State utility regulators voted last week to reduce the return on equity that Madison Gas and Electric can earn from its present 10.2% to 9.8% in 2017.

The new profit level is the lowest since the 1970s, according to Public Service Commission data, and could signal that rates of return for other utilities may be scrutinized to drop again.

The reduction is the result of persistently low interest rates and declining return rates for utilities around the country, PSC Chairwoman Ellen Nowak said during the commission’s meeting.

More: Milwaukee Journal Sentinel

November 15, 2016

Company Briefs

Low natural gas prices make the competitive electricity industry’s future look bleak in the near them, according Moody’s Investors Service’s yearly outlook report.

Moody’s identified Illinois Power Generating and FirstEnergy Solutions as utilities with negative credit ratings because of gas’ displacement of coal-fired and nuclear generation, leaving the utilities exposed.

The credit agency also anticipates anemic demand because of slow economic growth, advances in energy efficiency and growth in distributed generation. It noted that both PJM and ERCOT have cut their load growth forecasts.

More: Moody’s Investors Service

PSEG Solar Source Purchases 16.8-MW Facility from Ecoplexus

PSEG Solar Source purchased a 16.8-MW solar energy facility in Martin County, N.C., from Ecoplexus — marking the second project the two companies have collaborated on.

Ecoplexus will operate the facility, which will use about 50,000 mono-crystalline Trina solar panels with power electronics inverters. The facility has a power purchase agreement with Virginia Electric and Power.

The two companies also worked together on the PSEG Meadows Solar Center, also in Martin County, which went online in June.

More: Product Design and Development

NIPSCO Looking to Do $399M Coal Ash Containment Projects

Northern Indiana Public Service Co. wants to take on $399 million in environmental protection projects aimed at containing coal ash.

The utility has submitted its request to Indiana regulators to undertake the work, which is needed to comply with new federal mandates designed to prevent groundwater and other pollution from coal ash. The utility wants to bill customers for 80% of the cost.

Much of the work would be done at the Schahfer Generating Station, where NIPSCO has transported coal ash from other power plants for more than a decade, spokesman Nick Meyer said.

More: The Times of Northwest Indiana

DTE Energy’s Fermi 2 Shut Down for Maintenance Again

DTE Energy’s Fermi 2 nuclear power plant was shut down last week for repair of a main unit transformer — marking the second time in 2016 that the Newport, Mich., plant was closed for maintenance.

Last week’s closure was not related to the plant’s change in the sodium pentaborate concentration in October when DTE officials had to notify the Nuclear Regulatory Commission, spokesman Stephen Tait said.

The company has not said when the reactor will return to full capacity.

More: The Monroe News

AEP Names Satterwhite President, COO of Kentucky Power

American Electric Power has named Matthew J. Satterwhite president and chief operating officer of Kentucky Power, effective Dec. 9. He replaces Gregory G. Pauley, who is retiring after 42 years of service at AEP.

Satterwhite, who previously served as senior counsel since 2008, will be responsible for distribution operations serving 169,000 customers in eastern Kentucky, as well as the operating unit’s safety, customer service, marketing, communications, community affairs, governmental affairs and regulatory functions.

More: American Electric Power

University Groups Challenge Duke’s Natural Gas Plant

A 21-MW natural gas plant that Duke Energy has proposed for Duke University’s campus has sparked opposition by students, faculty and other environmentalists.

The company and the university are trumpeting the $55 million combined heat-and-power project as a means to reduce carbon emissions while providing steam power for the school.

Claire Wang, student organization officer for the two-year-old Duke Climate Coalition, said faculty at the university’s Nicholas School of the Environment calculated that emissions would only be reduced by 2 to 4% — not the 24% claimed by the university.

More: Charlotte Business Journal

Rocky Mountain Power Seeks Rate Hike for Solar Customers

Rocky Mountain Power has filed a proposal with the Utah Public Service Commission that would raise a typical net-metering customer’s electric bill from $55/month to $74.

Ratepayers who do not have solar panels currently subsidize net-metering customers by $400 annually — and the new rate schedule seeks to have net-metering customers pay their fair share, said Gary Hoogeveen, senior vice president of Rocky Mountain.

Solar advocates fear a rate increase will impede development of rooftop solar in Utah.

More: The Salt Lake Tribune

Tony Clark Joins Telecom, Energy Law Firm as Senior Advisor

Former FERC Commissioner Tony Clark has agreed to join law firm Wilkinson Barker Knauer as a senior advisor on Jan. 3.

Clark, who served on the commission for four years before leaving at the end of September, will split his time between the firm’s D.C. and Denver offices. The firm specializes in telecommunications, media and energy law.

Clark’s “expertise, along with his sharp intellect and warm collegiality, makes him a perfect fit for our firm.,” said Bryan Tramont, WBK managing partner.

More: Wilkinson Barker Knauer

November 15, 2016

Tucson Electric Could See Loss of Market Rate Authority in its BAA

By Robert Mullin

Tucson Electric Power could become the latest Western utility to lose its authorization to sell electricity at market-based rates within its own balancing authority area (BAA).

FERC last week said it will commence a Section 206 proceeding to determine whether the Arizona utility’s market-based rate authority (MBRA) remains “just and reasonable” within its service territory in the southwestern corner of the state.

tucson electric balancing authority area baa — Tucson Electric Power primarily serves the city of Tucson, but its balancing authority area occupies the southwestern corner of Arizona. | *Tucson Electric Power*

The commission’s review was triggered when the utility failed a key market test designed to demonstrate whether an electricity seller wields too much market power within a specific geographical area (ER10-2564, et al.).

Tucson Electric, along with its parent company UNS Energy, are now faced with making the case for why the commission should not revoke its MBRA. Absent that, the utility could provide a proposal to mitigate its market power. It could also adopt FERC’s cost-based rates — or propose other acceptable cost-based rates.

The order comes less than a month after Tucson Electric filed a “change in status” notice indicating that the utility passed FERC’s “pivotal supplier” and “wholesale market share” screens for so-called “first-tier,” or neighboring, balancing areas but failed the market share screen covering its own territory.

While the commission acknowledged the delivered price test (DPT) analysis submitted by Tucson Electric to rebut the presumption of market power stemming from the failed screen, it also said the utility should not expect it to postpone instituting the proceeding — which establishes a refund date for utility customers — while it examines supplemental information.

The DPT factors in native load commitments to capture a detailed picture of an electricity supplier’s “available economic capacity” — energy available for offer in the open market — over multiple seasons and load conditions. The analysis must also consider the load commitments for, and available supply from, other generators in the region.

“In addition to the previously filed delivered price test, sellers may present alternative evidence such as historical sales and transmission data to rebut the presumption that they have the ability to exercise horizontal market power in the Tucson Electric balancing authority area,” the commission wrote.

If Tucson Electric does lose its MBRA within its balancing area, it won’t be the first major Western utility to see FERC restrict its selling power in some way this year.

In a sweeping June order impacting NV Energy and PacifiCorp, the commission revoked MBRA for Berkshire Hathaway Energy subsidiaries in four neighboring BAAs in the West. (See Berkshire Market-Based Rates Restricted in 4 Western BAAs.)

Closer to home, an August FERC ruling conditioned Arizona Public Service’s EIM membership on a requirement that each of the utility’s generating units offer into the market at or below default energy bids (ER10-2437). The commission rejected the argument that CAISO’s own mitigation measures would be sufficient to keep the utility in check. FERC noted that APS did not even attempt to file indicative screens or a DPT to rebut the presumption that it exercised market power within its own portion of the EIM.

Tucson Electric is also exploring the possibility of joining the EIM. The utility plans to release a study outlining the potential benefits of market membership later this month.

Arizona is coming off a contentious political campaign in which APS spent more than $4 million to elect three of the utility’s favored candidates to the Corporation Commission. All five members of the commission are now Republicans, including incumbent Bob Burns, who earned APS’s financial support despite the fact that the utility is suing to prevent him from subpoenaing records of the company’s political contributions.

“I think [the high spending] just puts a bad taste in the public’s mouth,” Burns told public radio station KJZZ, noting that he could do nothing to prevent the spending in support of his election because of federal election laws.

In an additional twist, Burns benefited from campaign spending by a coalition of solar companies that also heavily backed Democratic candidates Bill Mundell and Tom Chabin. The coalition, which includes Solar City, was attempting to counter what it considers to be a regulatory bias that favors APS in disputes with supporters of rooftop solar.

November 15, 2016

Federal Briefs

Coal and natural gas production are falling, while national wind capacity is rising, according to the Department of Energy.

The department predicts a 17% decrease in coal production by the end of 2016, followed by a 3% increase in 2017. Natural gas production will decline in 2016 for the first time since 2005, but is expected to rise slightly in 2017.

National wind capacity, which was 72 GW in 2015, is expected to rise by 8 GW in 2016 and 9 GW in 2017.

More: Fuel Fix

Spiker Named as Senior Advisor at Bureau of Reclamation

The Bureau of Reclamation has named Max Spiker as senior advisor for hydropower and electric reliability officer.

His duties will include coordinating implementation of corporate partnership efforts involving the bureau’s power functions and serving as liaison on intergovernmental initiatives associated with hydropower delivery. He also will oversee compliance with FERC reliability standards.

Spiker has been with the bureau for 28 years, most recently as power resources manager since 2013.

More: Bureau of Reclamation

Large Solar Facility Planned For California Naval Air Station

The Department of the Navy and Recurrent Energy expect to begin construction in 2017 on a 167-MW facility at Naval Air Station Lemoore in Kings County, Calif.

The project, which is expected to be completed by 2019, will be situated on 930 acres of land — making it the largest solar facility on Defense Department land.

The Navy is seeking to develop 1 GW of renewable energy by 2020.

More: The Business Journal

Leasing Program to Boost Solar, Wind Energy Development

logo The Interior Department announced a final rule last week creating a leasing program on public land to boost development of solar and wind energy.

The program, which could be scrapped when President-elect Donald Trump takes office, encourages development in areas where it would have fewer effects on the environment, while generating millions of dollars.

President Obama has sought to create renewable energy projects that generate 20,000 MW of power on public land by 2020.

More: The Associated Press

TVA Achieves Highest Earnings in 83 Years During Power Sales Drop

The Tennessee Valley Authority saw its net income rise 11% to more than $1.2 billion for fiscal year 2016 — the highest level in the utility’s 83-year history.

The rise came while power sales decreased by 3.4% because of relatively stagnant demand and a slight drop in rates.

TVA also cut its operating and maintenance expenses in the past year by about $800 million and used the money generated by the savings for debt reduction, TVA Chief Financial Officer John Thomas said.

More: Times Free Press

Atlantic Sunrise Completion Delayed to Mid-2018

The completion date for the Atlantic Sunrise expansion project has been delayed to 2018 while the project awaits a final environmental impact statement, which FERC is expected to issue on Dec. 30.

William Partners expects part of the natural gas pipeline to be in service during the second half of 2017.

By mid-2017, Williams hopes to have all regulatory approvals to begin construction of the pipeline between the northeastern part of Pennsylvania and the state’s border in Lancaster County.

More: PennLive

November 15, 2016

MISO Readies Updated Pseudo-Tie Rules

By Amanda Durish Cook

MISO will ask FERC to approve new rules on how it manages pseudo-ties next year, officials said during a Nov. 8 special conference call of the Reliability Subcommittee.

The proposed rules would establish a pseudo-tie Business Practices Manual, an implementation process and a written agreement for MISO-based generators that intend to sell their capacity or electricity outside the region.

The agreement serves as a contract between MISO and pseudo-tie owners and ensures “appropriate metering is in place” before pseudo-ties are granted, the RTO said. MISO Corporate Counsel Michael Blackwell said the agreement would be filed as a pro forma attachment to the RTO’s Tariff. Executed pseudo-tie agreements would be filed with FERC through MISO’s electronic quarterly reports.

The process will require market participants to maintain long-term firm transmission service requests from source to sink for the life of the pseudo-tie. New transmission service requests would be subjected to system impact studies. Currently, units pseudo-tied into MISO require transmission service from the external transmission owner, and units pseudo-tied out require transmission service from MISO.

The BPM will include a step-by-step guide to implementing a pseudo-tie, which involves pre-assessment and transmission service evaluation before conditional approval and registration. (See “Pseudo-Ties to Require System Impact Studies; Would be Barred from Sink Switching,” MISO Planning Subcommittee Briefs.)

MISO would require a one-year notification for generators wishing to pseudo-tie. Kyle Abell, of MISO’s modeling and engineering division, said neighboring RTOs — such as PJM, with its three-year forward market — may require more notification time for generators looking to be controlled and dispatched by a neighboring balancing authority.

The process also includes a new requirement that all parties — generators and RTOs — agree on a plan for congestion management prior to approval of new pseudo-ties. That could require the creation of new flowgates and modeling improvements.

Senior Director of Regional Operations David Zwergel said modeling needs to be sufficient to accurately calculate transmission flows and avoid overwhelming the system.

Abell said MISO hopes to file the new process early in the first quarter of 2017, implementing it before the next batch of pseudo-tied generators withdraw their capacity from MISO in June.

“It’s our goal to strike the right balance between brevity and clarity,” Abell said.

Current pseudo-ties with long-term transmission service can continue to use the granted requests. Abell said existing transmission service requests will be honored under the same rules, but some existing requests not used for pseudo-ties could be subject to restudies to ensure they meet new criteria.

“We’ll take a look at it to see how it was studied. … If we find it meets the [new] criteria, you’re good to go,” MISO’s Paul Muncy said. Rollover rights on transmission service requests will continue to be honored, Muncy added.

“It’s not MISO’s goal to retroactively revise pseudo-ties. We’re focused on new pseudo-ties moving forward,” Abell said.

Proposed pseudo-ties can be rejected and existing pseudo-ties can be rescinded if a market-to-market flowgate is not within 2% of MISO and the neighboring market’s generator-to-load distribution factor. Such determinations will rely on the past 24 months of flowgate data.

Pseudo-ties to non-market areas, such as the Tennessee Valley Authority, will be modeled as network-and-native load under NERC’s transmission loading relief curtailment standards and be subject to manual dispatch. Abell said the provisions apply to new pseudo-tie requests and not to pseudo-ties already in place.

Ameren’s Ray McCausland asked how the sub-regional power balance constraint would factor into the granting of MISO’s pseudo-tie requests. MISO staff said they would investigate that aspect.

Abell asked for stakeholder comment by Nov. 22. MISO will hold another conference on the pseudo-tie rules and consider possible revisions during a special Dec. 12 meeting of the Reliability Subcommittee.

November 15, 2016

ISO-NE Capacity Requirement Shows Flat Demand, More Solar

By William Opalka

The installed capacity requirement ISO-NE filed with FERC last week shows a continuing trend of slightly declining load growth and a greater reliance on behind-the-meter solar power (ER17-320).

New England’s ICR for the upcoming 11th Forward Capacity Auction (delivery year 2020/21) is 34,075 MW. That represents a capacity need of 35,034 MW minus 959 MW of Hydro-Quebec Interconnection Capability Credits.

In FCA 10 earlier this year, ICR resources of 35,126 MW were required.

“There was a small drop in ICR, due primarily to a lower load forecast, and that was due to the growing impact of behind-the-meter PV and energy efficiency measures,” ISO-NE spokeswoman Marcia Blomberg said.

The RTO said the requirement was reduced by 720 MW (ER17-321). In FCA 10, ISO-NE successfully defended at FERC its inclusion of 390 MW of behind-the-meter solar that was not based on historical loads. (See FERC Accepts ISO-NE’s Solar Count over Protests.)

ISO-NE said it used coincident hourly load and PV production data from 2012-2015 and information from utilities to compile its requirement.

The RTO said it qualified 150 new capacity resources, totaling 5,958 MW for FCA 11. The identities of the new resources are confidential.

ISO-NE has three capacity zones for the auction, which will be held Feb. 6: the import-constrained Southeast New England zone (SENE), including Rhode Island and southeastern and northeastern Massachusetts; export-constrained Northern New England (NNE), which includes Vermont, New Hampshire and Maine; and Rest of Pool, which includes central and western Massachusetts and Connecticut.

The RTO’s filing said five renewable energy projects in northern Maine, a landfill gas facility, a wind farm and three hydropower projects, totaling more than 22 MW, were disqualified because of insufficient transmission capacity. The Orrington interface in eastern Maine, critical to unlocking wind energy potential from the northeastern areas of the state, is the subject of a study now underway by ISO-NE planners. (See ISO-NE Planning Advisory Committee Briefs.)

Following a contentious multiyear stakeholder process that FERC essentially ended over the summer, FCA 11 will be the first time ISO-NE uses sloped demand curves for its constrained zones. (See FERC Accepts ISO-NE Sloped Zonal Demand Curves.)

ISO-NE received two retirement delist bids, totaling 27.3 MW, from resources in northeastern Massachusetts and Maine. They were confidentially identified to RTO officials in July.

Protests challenging the ICR are due Nov. 23. The RTO wants FERC to accept the filing by Jan. 7.

November 15, 2016

PJM Market Monitor’s Q3 Report Finds Markets Competitive

By Rory D. Sweeney

PJM’s capacity and regulation market results were “generally competitive” in the first nine months of 2016 but remain vulnerable to stress, according to the Independent Market Monitor’s third-quarter State of the Market Report.

The report by Monitoring Analytics added five new or modified recommendations on uplift, the capacity market and demand response.

The load-weighted average real-time LMP was $29.32/MWh in the first nine months of 2016, lower than for any corresponding period since 2000, reflecting both lower fuel prices and lower demand. It was 25% lower than the first nine months last year.

pjm market monitor — | *Monitoring Analytics*

If all things, including fuel and emissions costs, had remained constant in 2016 from 2015, the load-weighted LMP would have been $31.67/MWh, still below the 2015 mark of $38.94/MWh. PJM’s average real-time load in the first nine months of 2016 decreased by 1.4% from the first nine months of 2015, to 90,599 MW.

The structures for all but the aggregate energy, day-ahead schedule reserve and financial transmission rights markets were uncompetitive, the report said. The PJM region and all locational deliverability areas in almost every market have failed the three pivotal supplier market power test for almost every auction since at least 2007.

Market design received a “mixed” evaluation. Although the Reliability Pricing Model design and Capacity Performance modifications have “many positive features,” the report said, several features “still threaten competitive outcomes.” Among them: the definition of DR, which allows “inferior” products to substitute for capacity; the definition of unit offer parameters; and the inclusion of imports as substitutes for internal capacity resources.

The Monitor also raised concerns over replacement capacity, recommending against allowing retroactive replacement capacity transactions.

Market performance and participant behavior during high-demand hours raised several concerns, the report said, including potential economic withholding.

“In particular, there are issues related to aggregate market power, or the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage,” it explained.

In addition to its suggestion on replacement capacity, the Monitor added four other new or amended recommendations.

First, it recommended that PJM initiate a stakeholder process if it plans to modify its price-setting logic — a software change the RTO made in 2014 to reduce uplift by selecting as marginal any unit committed by PJM to provide reactive services, black start or transmission constraint relief if that unit would otherwise run with an incremental offer greater than the LMP.

The recommendation was one of several that the Monitor said could have reduced the uplift rate paid by decrement bids in the Eastern Region by 93% — to $0.032/MWh instead of $0.446/MWh — in the first nine months of 2016.

The Monitor also recommended that capacity released by PJM in incremental auctions should be offered at the Base Residual Auction clearing price or not have the offer price revealed at all to avoid suppressing the IA price. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)

Energy efficiency resources shouldn’t be included on the supply side of the capacity market, the Monitor concluded. “PJM’s load forecasts now account for future EE, but did not when EE was first added to the capacity market. If EE is not included on the supply side, there is no reason to have an add back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”

Finally, the Monitor also recommended not removing any defined subzones and maintaining a public record of all created and removed subzones.

November 15, 2016

Texas PUC Sets Hearing Schedule for NextEra-Oncor Merger

By Tom Kleckner

The Public Utility Commission of Texas last week scheduled hearing dates on NextEra Energy’s proposed acquisition of Oncor.

PUCT Commissioner Ken Anderson | © RTO Insider — PUCT Commissioner Ken Anderson | © *RTO Insider*

The commission set a prehearing conference for Friday at the commission’s offices in Austin. The parties will discuss the docket’s (No. 46238) procedural schedule, pending motions and any other matters “that may assist” in the proceedings.

The order also set Feb. 21-24 as potential hearing dates before the commission. That would keep the merger on course to receive PUC approval by the end of the second quarter.

The commissioners could have assigned the case to the State Office of Administrative Hearings (SOAH), but they chose to keep it within their jurisdiction instead. However, a SOAH administrative law judge will be responsible for conducting discovery in the case.

“I would have preferred SOAH, because I don’t think it’s that complex,” Commissioner Ken Anderson said. “Maybe we just start holding our holidays in Oncor’s headquarters in Dallas.”

NextEra announced in late July it had reached an agreement to acquire an 80% interest in Oncor; on Oct. 31 it announced it would acquire the remaining 20%.

Other Matters

The commission punted most of the other meaty issues on its agenda to its next open meeting on Dec. 1.

The PUC debated jurisdictional issues related to distributed generation interconnection agreements, before agreeing to resume the rulemaking’s discussion in December (No. 45078).

Citing a “gut instinct,” Chair Donna Nelson said she was reluctant to rule against staff’s opinion that interconnection agreements do not give the PUC jurisdiction over customer complaints.

PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © RTO Insider — PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © *RTO Insider*

“When I read the comments,” Anderson said, “a lot of the [market] participants who staff believe we would not have jurisdiction over have said they don’t mind the jurisdiction.”

“That’s what I struggle with,” Nelson responded. “I met with some companies, including solar companies, who said ‘we think the interconnection agreement, where we’ve agreed to be subject to your jurisdiction, gives you jurisdiction,’ but staff doesn’t agree with that.”

Nelson said she was concerned solar customers would come to the commission seeking redress from potential “bad actors” but that it would be unable to take up the matter.

“To that end, if we did adopt this with staff’s language, we’ve got a bunch of stuff out there that says we don’t have jurisdiction, and we’re asking the Legislature to potentially give us jurisdiction,” Commissioner Brandy Marty Marquez said. “Waiting until the next meeting to make a final decision is a prudent idea, but it kind of sounds like this might be something we need to pull down until we get through the legislative session.” The Texas Legislature’s next session begins Jan. 10.

The commission also decided to take more time to review a report on alternative ratemaking mechanisms that’s due to the Legislature in January (No. 46046), giving the commissioners an opportunity to agree on any recommendations.

“I got a call from a legislator who asked what recommendations were going to be made,” Anderson said. “I said, ‘I’m not sure I have any. We did the report you asked for.’”

“I’d like to see if there’s a recommendation we can make regarding appropriate reforms,” Nelson said.

The PUC also took no action on Lone Star Transmission’s proposal to cut its transmission costs by $6 million, providing the company files its settlement agreement by the end of the year. The settlement will negate the need for a rate case (No. 45636).

The commission approved a rehearing over the City of Garland’s request to amend a certificate of convenience and necessity for a 345-kV line in East Texas, allowing it to “tackle the merits” after the holidays, Anderson said.

November 15, 2016

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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 in RTO Insider.

NOTE: The meetings this week will NOT be in Wilmington, Del., as is customary. They will be held at PJM’s Conference and Training Center in Valley Forge, Pa. RTO Insider will be there covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

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

Members will be asked to endorse the following manual changes:

A. Manual 3: Transmission Operations. Revisions, the result of a periodic review, include updating voltage control at nuclear stations, certain special protection scheme references and the BC/PEPCO operating procedure.

B. Manual 14A: Generation & Transmission Interconnection Process. Revisions resulting from special Planning Committee sessions, set new service request cost allocation and study methods. To ensure manual language allows cost allocation to occur for all projects, the word “interconnection” is replaced with “new service” in section B.2 of Attachment B.

C. Manual 14B: PJM Region Transmission Planning Process. Revisions will update the Capacity Import Limit calculation procedure. Starting with the 2020/21 delivery year, the CIL will no longer be applied as part of the Reliability Pricing Model. As part of new long term firm transmission service study procedures approved earlier this year, the CIL will be considered during interconnection studies associated with new transmission service requests.

D. Manual 15: Cost Development Guidelines. Revisions will implement updates the fuel-cost policy procedures, part of PJM’s compliance filing on hourly offers, which is awaiting FERC action (ER16-372-002). Major changes include an annual review of the policies, reasons for updating a policy outside of the annual review and a process for submitting undefined costs. (See “Fuel-Cost Policy Revisions Approved,” PJM Market Implementation Committee Briefs.)

E. Manual 18B: Energy Efficiency Measurement & Verification. Revisions, the result of a periodic review, include updates to incorporate the implementation of Capacity Performance.

F. Manual 21: Rules and Procedures for Determination of Generating Capability. Revisions, the result of a periodic review, include clarifications to testing rules and terms.

G. Manual 28: Operating Agreement Accounting. Revisions made to align with recent Manual 1 revisions clarify metering language and define a “fully metered EDC” as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.” The changes were developed in response to a stakeholder request.

3. Day Ahead Scheduling Reserve Requirement (10:10-10:25)

Members will be asked to endorse the 2017 day-ahead schedule reserve requirement. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)

4. Manual 35 Retirement (10:25-10:35)

Members will be asked to endorse the retirement of Manual 35 and receive an update on its proposed replacement, the new Glossary section of PJM’s website. (See “PJM to Retire Manual 35,” PJM Planning Committee Briefs.)

5. Underperformance Risk Management Sr. Task Force (URMSTF) (10:35-10:50)

Members will be asked to endorse a package of revisions and updates to address underperformance risks. (See No End in Sight for PJM Capacity Market Changes.)

6. Base Capacity Extension (10:50-11:05)

Members will be asked to endorse a proposed one-year extension of Base Capacity made by Jeff Whitehead of Direct Energy. (See No End in Sight for PJM Capacity Market Changes.)

7. Excess Capacity Release Problem Statement/Issue Charge (11:05-11:20)

Members will be asked to approve a problem statement and issue charge presented by Jeff Whitehead of Direct Energy regarding PJM’s sell back of excess capacity in the incremental auctions. (See No End in Sight for PJM Capacity Market Changes.)

8. Combined Cycle Modeling Problem Statement (11:20-11:35)

Members will be asked to approve a problem statement presented by Bob O’Connell, of PPGI Fund A/B Development, regarding combined cycle unit modeling that was developed in the Combined Cycle User Group.

9. Winter-Season Resource Adequacy and Capacity Requirements Problem Statement/Issue Charge (11:35-11:50)

Members will be asked to approve a problem statement and issue charge presented by James Wilson on behalf of the Maryland Office of the Peoples’ Counsel regarding requirements for resource adequacy and capacity needs in the winter. (See No End in Sight for PJM Capacity Market Changes.)

10. Pumped-Storage Hydropower Tariff/OA Revisions (11:50-12:00)

Members will be asked to endorse Tariff and Operating Agreement revisions recommended by the Governing Document Enhancement & Clarification Subcommittee regarding the day-ahead scheduling of pumped-storage hydropower.

11. Revisions to Manual 18 Regarding Replacement of Capacity Obligations (12:00-12:15)

Members will be asked to endorse revisions presented by Barry Trayers of Citigroup Energy (and an accompanying friendly amendment from PJM) proposed for Manual 18: Capacity Market regarding the immediate replacement of capacity obligations.

Members Committee

Consent Agenda (2:20-2:25)

Members will be asked to endorse:

2016 Installed Reserve Margin study results. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)

Proposed clarifying updates to the credit policy in Tariff Attachment Q. (See “Credit Policy Changes Approved,” PJM Markets and Reliability and Members Committees Briefs.)

1. Elections (2:25-2:40)

Members will be asked to elect new representatives for the Finance Committee, sector whips and the vice chair of the Members Committee for 2016-17.

2. Fuel Cost Policy and Hourly Offers (2:40-3:00)

Members will be asked to endorse revisions to Manual 15: Cost Development Guidelines. See MRC item 2.D. above.

— Rory D. Sweeney