RTO Insider Top 30: Revenues, Earnings Down in Q2

By Rich Heidorn Jr.

The second quarter wasn’t a great one for most companies in the RTO Insider Top 30, as revenues declined 2% compared with 2015 while profits dropped 15%.

Twelve companies reported increases in revenue, while 15 reported reductions and three were unchanged. The outliers were WEC Energy Group and Avangrid, which saw revenues soar because of acquisitions.

Eleven companies reported an increase in profits while 19 showed declines. FirstEnergy, NRG Energy, Centerpoint Energy and Calpine reported quarterly losses.

It was a really bad quarter for FirstEnergy, which reported a $1.1 billion loss, much of it related to the pending closure of five coal-fired units. The company said it plans to rid itself of its merchant generation and transition to a “fully regulated company.” (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)

NRG said most of its second-quarter net loss of $276 million ($0.61/share) — worse than its $9 million loss a year ago — resulted from impairments and losses on asset sales. (See NRG Continues to Pare Down Businesses, Affirms Guidance.)

Centerpoint, which has utilities in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas, reported a net loss of $2 million ($0.01/share), compared with a profit of $77 million ($0.18/share) in 2015. The company said its results were dampened by a $16 million drop in income from Enable Midstream Partners, a gas gathering and processing limited partnership with OGE Energy. The company has offered to sell its 55.4% stake to OGE. (See CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE.)

Calpine showed a net loss of $29 million ($0.08/share) versus a profit of $19 million ($0.05/share) a year earlier. The company blamed mark-to-market losses resulting from increases in forward power and natural gas prices. It also said increased hydroelectric generation in the West contributed to lower energy margins for its gas-fired fleet, although this was partially offset by an increase in generation in Texas.

The companies showing the biggest revenue declines in the quarter were Calpine, NRG, NextEra Energy and Public Service Enterprise Group, each of which was down more than 10%.

Company	Market Cap. ($ billions)	Revenue Q2 2016 ($ billions)	% change vs. 2015	Net income Q2 2016 ($ millions)	% change vs. 2015
NextEra	58.47	$3.82	-12.4%	$540	-24.6%
Duke Energy	57.23	$5.48	-2.0%	$509	-6.3%
Dominion Resources	47.89	$2.60	-5.5%	$452	9.4%
American Electric Power	33.13	$3.89	1.6%	$502	16.7%
Exelon	32.37	$6.91	6.1%	$267	-58.2%
PG&E	32.20	$4.17	-1.2%	$210	-48.3%
Berkshire Hathaway Energy	NA	$4.12	-7.4%	$545	-3.9%
Sempra Energy	26.78	$2.18	-7.6%	$17	-94.3%
PPL	24.84	$1.79	0.6%	$483	-163.8%
Edison International	24.82	$2.78	-4.5%	$307	-24.6%
Consolidated Edison	24.11	$2.79	0.0%	$232	5.9%
Public Service Enterprise Group	22.31	$1.91	-17.3%	$187	-45.8%
Xcel Energy	21.75	$2.50	-0.8%	$197	-0.1%
WEC Energy Group	19.75	$1.60	61.6%	$182	124.6%
Eversource Energy	18.19	$1.77	-2.7%	$204	-1.8%
DTE Energy	17.38	$2.26	-0.4%	$152	39.4%
Entergy	14.26	$2.46	-9.2%	$573	284.7%
FirstEnergy	14.19	$3.40	-2.0%	$(1,089)	-682.4%
Avangrid	13.58	$1.44	53.4%	$102	827.3%
Ameren	12.39	$1.43	2.1%	$147	-2.0%
CMS Energy	12.31	$1.37	1.5%	$124	85.1%
Centerpoint Energy	9.66	$1.57	2.6%	$(2)	-102.6%
Alliant Energy	9.02	$0.75	4.2%	$86	23.3%
Pinnacle West Capital	8.68	$0.92	3.4%	$121	-1.3%
NiSource	8.05	$0.89	0.0%	$29	-203.2%
Westar Energy	7.57	$0.62	5.1%	$72	13.5%
OGE Energy	6.21	$0.55	0.0%	$72	-18.3%
Calpine	4.61	$1.16	-19.4%	$(29)	-252.6%
Great Plains Energy	4.38	$0.67	9.8%	$32	-27.9%
NRG Energy	3.93	$2.64	-22.4%	$(276)	2966.7%
TOTAL		$70.44	-2.1%	$4,947	-15.4%

NextEra

NextEra said revenues dropped to $3.82 billion in the quarter, a 12% reduction from a year earlier. Its Florida Power & Light saw a 2.5% drop in retail sales, despite adding 65,000 more customers, due to mild weather.

NextEra Energy Resources, the company’s competitive energy unit, saw operating revenue drop to $970 million from $1.27 billion, due in part to hedging losses and the sale of 3,000 MW of natural gas generation in Texas. It also reported lower revenues from wind assets, which it attributed to lower output and reduced state and federal tax credits.

The company said it expects to add about 2,500 MW of contracted renewable generation in 2016, which would boost its renewable portfolio to 16,000 MW.

Last month, the company, which was rebuffed in its effort to buy Hawaiian Electric, reached an agreement to purchase Dallas-based Oncor in an $18.4 billion deal. (See NextEra Reaches Deal for Oncor.)

PSEG

PSEG reported second-quarter net income of $187 million ($0.37/share), a 46% drop from a year earlier. Operating earnings — which exclude the nuclear decommissioning trust, mark-to-market accounting and material one-time items — were flat year-over-year at $289 million ($0.57/share).

Public Service Electric and Gas’ expanded capital investment program goosed its net income of $179 million ($0.35/share), an increase from the $167 million ($0.33/share) for 2015.

Weather-normalized electric sales for the 12 months ending June 30 were down 0.2% versus a year earlier, despite an increase in the number of customers, because of increased energy efficiency and reduced industrial demand.

PSEG’s wholesale power unit, which earned $166 million ($0.33/share) a year ago, had a net loss of $11 million ($0.02/share) as output dropped 6% because of mild weather, low gas prices and a decline in PJM capacity revenues.

PSEG Power also took a hit from an extended refueling outage at the Salem 1 nuclear unit for repairs. The outage dropped the average capacity factor for the company’s nuclear fleet to 83% for the quarter, down from 86% a year earlier.

PSEG’s Peach Bottom nuclear plant, however, increased its output following modifications that increased its capacity by 130 MW.

Output from its combined cycle fleet declined to 4.4 TWh from 4.6 TWh due to mild weather, while low gas prices reduced the dispatch of its coal-fired units, which saw production drop to 0.9 TWh from 1.3 TWh.

CEO Ralph Izzo said the company was maintaining its operating earnings guidance for the year 2016 ($2.80 to $3/share). “However, reaching the upper end of guidance will be difficult even with improvements seen in the power markets, expectations for warm summer weather, normal operations and management of O&M for the remainder of the year,” he said.

Entergy

Entergy had a big earnings surprise, reporting second-quarter net income of $572.6 million ($3.11/share), almost tripling analysts’ expectations of $1.05/share, as polled by Thomson Reuters.

“We continue to make progress toward meeting our objective of steady, predictable growth at the utility while reducing our [Entergy Wholesale Commodities] footprint,” Entergy CEO Leo Denault said.

One step to shrinking that footprint came earlier this month, when the company agreed to sell its FitzPatrick nuclear plant in New York to Exelon for $110 million. The plant, which Entergy had planned to close, had a net book value $143 million. (See Entergy Sells FitzPatrick to Exelon.)

Net revenue was boosted by the company’s acquisition of the 1,980-MW Union Power combined cycle plant in Arkansas, Entergy Arkansas’ rate increase and higher industrial sales. The company cited strong demand from petroleum refiners who “continued to operate at high capacity levels compared to last year.”

Looking forward, the company also noted that it awarded itself contracts to build generation following competitive solicitations for Entergy Louisiana and Entergy Texas.

Methodology

The RTO Insider Top 30 includes the largest companies (by market capitalization) with significant presence in the seven RTOs and ISOs in the U.S. Since initiating the Top 30 in the first quarter, we have added Great Plains Energy and eliminated National Grid, a U.K.-based company that does not report its results quarterly. Expect more shuffling if Great Plains wins regulatory approval for its proposed acquisition of #26 Westar Energy.

August 15, 2016

Monitor: PJM Markets Competitive, but Have Room for Improvement

By Suzanne Herel

PJM’s wholesale energy, capacity and regulation markets were competitive for the first half of the year, but there is room for improvement, according to the second quarter State of the Market Report by Monitoring Analytics. The Independent Market Monitor made new recommendations for the energy, capacity and ancillary services markets.

During periods of high demand, the market’s performance “raised a number of concerns related to capacity market incentives, participant offer behavior in the energy market under tight market conditions, natural gas availability and pricing, demand response and interchange transactions,” the report said.

The report also called efforts to subsidize uneconomic units a “threat” to PJM market design.

The report includes five new recommendations and one modified recommendation. Two are classified as high priority; the others are ranked medium.

One of the high priority items concerns the capacity market. The Independent Market Monitor said that the costs incurred by pseudo-tied units should be borne by the unit and included in its offers into the market.

The other, first reported in 2012, calls for the emergency load response program to be treated as an economic resource that does not only respond after an emergency has been called.

The medium recommendations were:

Energy market: Clearly state the policy on the use of constraint relaxation and price-setting logic.
Capacity market: Re-evaluate mitigation rules for offers by demand resource and energy efficiency resources.
Capacity market: Eliminate the energy efficiency add-back mechanism so market clearing prices are not impacted.
Ancillary services: Eliminate separate payments for reactive capability and have generators recover its cost in the capacity market.

Prices, Demand Down

Lower fuel prices and less demand caused energy market prices to drop significantly over the first half of last year, the report said.

The load-weighted average real-time LMP was $27.09/MWh, a 36% drop from $42.30/MWh in 2015.

Average real-time load dropped 5.3% year over year, from 90,586 MW to 85,800 MW.

Net revenue, a measure of market performance and of the incentive to invest in new generation, decreased in the first six months of the year relative to 2015. Total net revenues, including both capacity and energy, dropped for a new combustion turbine (-50%), combined cycle (-41%), coal plant (-75%), diesel (-81%), nuclear plant (-46%), wind installation (-31%) and solar installation (-44%).

Combustion turbines (CTs) and combined cycle units (CCs) that entered the PJM markets in 2007 in three representative locations did not cover their total costs, including the return on and of capital. CTs and CCs that entered the PJM markets in 2012 did cover their total costs in the eastern PSEG and BGE zones but did not cover their costs in the western ComEd zone.

Mild winter weather, paired with low fuel prices and LMPs, enabled PJM to reduce uplift charges from $240.3 million to $63.9 million, a 73% cut.

Congestion costs dropped from $918.6 million to $479.1 million, a 48% reduction.

The report also said that auction revenue rights were not an effective way to return revenue to load. Together with financial transmission rights, they offset 86.5% of total congestion costs for the 2015 to 2016 planning period.

August 15, 2016

CAISO Refines Cost Allocation Proposal for Expanded BA

By Robert Mullin

CAISO met with stakeholders last week to refine a proposal for allocating costs of new transmission facilities in an expanded balancing authority (BA) that would include areas of the West outside California.

CAISO Plus Pacificorp Map (CAISO) - CAISO Refines Cost Allocation Proposal for Expanded Balancing Authority — The current CAISO footprint and PacifiCorp’s balancing areas would represent separate sub-regions under the ISO’s TAC proposal.

ISO staff laid out options for creating “default” cost allocation provisions, a requirement under FERC Order 1000, at an Aug. 11 working group.

Under CAISO’s proposal, “new facilities” would include new construction, additions and upgrades approved through the transmission planning process for an expanded ISO.

It would apply the transmission access charge (TAC) only to ISO-wide — or “regional” — projects meeting at least one of three criteria:

Receives a rating of 200 kV or more;
Facilitates a connection between two sub-regions; or
Creates, supports or helps increase intertie capacity with a neighboring balancing authority area.

The proposal also creates a new category of “sub-regional” transmission projects excluded from the ISO-wide TAC, including facilities under 200 kV, as well as those constructed or approved before expansion. Costs for those projects would be allocated entirely to the sub-region requiring the project — such as PacifiCorp’s service territory or the current CAISO BA.

Planning Process

CAISO staff told stakeholders that the TAC proposal is predicated on the assumption that the ISO’s current planning process is “a reasonable model” for expansion.

“We redesigned our [planning process] in 2010 and we think it’s a good model,” said Lorenzo Kristov, CAISO principal of market infrastructure and policy. “There’s no reason to think it wouldn’t work with expansion.”

That detail is important because the decision-making approach under the current planning process underpins the framework for the ISO’s proposed default cost allocation scheme.

CAISO breaks down projects into three categories: reliability-driven, policy-driven and economically driven.

ISO transmission planners run a proposed project through three stages of analysis, first determining the project’s reliability benefits, followed by an assessment of how the project helps fulfill state objectives for increased renewable generation. A third stage examines the economic benefits of the project.

Some projects may have more than one driver.

“We want to avoid tagging projects as just being economic or policy — the world doesn’t work that way,” said Neil Millar, the ISO’s executive director of infrastructure development.

Economically driven projects must produce total benefits exceeding the project’s cost — demonstrating a benefit-cost ratio of 1.0 or greater. To calculate those benefits, the ISO relies on the transmission economic assessment model, which considers savings from more efficient dispatch, reduced line losses and congestion and increased resource adequacy.

While the ISO said it weighs economics in its evaluation of any proposed project, reliability- and policy-driven projects don’t have to meet the same threshold as economically driven projects.

“We look at it this way so that people don’t think we can kill a project just for economic reasons, because it might meet a reliability and policy need,” Millar said.

The analytical approach underlying the planning process would inform the ISO’s proposed default cost allocation scheme under a redesigned TAC.

Benefit-Cost Ratio

Under the TAC proposal, costs for a project — including those for a reliability- or policy-driven project — with a benefit-cost ratio of 1.0 or greater would be allocated to sub-regions in proportion to the total economic benefits assessed for each sub-region.

For projects with a ratio less than 1.0, a portion of the cost would be allocated across sub-regions according to financial benefits, under the assumption that even uneconomic projects provide some economic benefits for market participants. Leftover charges — representing the portion of the costs not covered by economic benefits — would be assigned to the sub-region responsible for the reliability need or policy mandate driving the project.

In cases where multiple sub-regions derive policy or reliability benefits, leftover costs would be allocated in proportion to the total internal load for those areas during the year in which the project is placed into service, according to the proposal.

“The economics would be used to allocate the first tranche of needs, and then the incremental policy or reliability needs would be allocated on an incremental basis,” Millar said.

The ISO is also considering a concept by which the avoided costs for a reliability- or policy-driven alternative would be factored into a sub-region’s total benefits calculation for a proposed project.

A potential downside: A sub-region’s TAC allocation could rise based on the assumed cost of a “hypothetical” project.

“Is the avoided cost of a hypothetical sub-regional alternative an appropriate basis for cost allocation?” the ISO asked stakeholders.

Feedback

“This looks good [as] a conceptual idea,” said David Oliver, a managing consultant with Navigant. “But we’re talking about transferring money in sub-regions and that’s often not a fun thing to do.”

LS Power Vice President Sandeep Arora said, “I think this is very encouraging — the entire approach of looking at a transmission project not just fitting into one bucket but looking at the various benefits a project brings.”

The ISO said updating the TAC plan is a “central policy element” in the development of a Western RTO. Utility commissions in five states must grant approval before Portland-based PacifiCorp can join the ISO. The cost allocation scheme is likely to weigh heavily in regulators’ decisions.

CAISO planners initially expected to wrap up the TAC proposal in time to present it to the ISO’s board of governors in late August, in concert with a push to submit an RTO governance plan to California lawmakers before the end of this summer’s legislative session. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.)

The ISO got more breathing room after Gov. Jerry Brown’s Aug. 8 decision to postpone efforts to win legislative approval to expand the ISO until early 2017. (See Governor Delays CAISO Regionalization Effort.)

“Last time we had a meeting on this topic … we were still contemplating taking this to the board at the end of August, as ridiculous as that sounds,” CAISO’s Kristov said.

Instead, the ISO is likely to continue work on the proposal for the rest of the year, Kristov said.

August 15, 2016

State Briefs

Report Advocates a More Aggressive RGGI

A new Acadia Center report suggests the Regional Greenhouse Gas Initiative (RGGI) should adopt more aggressive emissions targets aligning it more closely with those of some member states. The climate-change advocacy organization also recommends extending the RGGI caps to 2031 to coincide with the proposed federal Clean Power Plan.

“RGGI continues to prove itself as an effective means of reducing carbon emissions and supporting economic growth,” said Daniel L. Sosland, Acadia Center president. “Now, Northeast and Mid-Atlantic states have an opportunity to build on RGGI’s success and lead the country by taking the steps necessary to meet state and federal climate requirements.”

RGGI states have committed to reducing emissions by about 40% across their economies by 2030. In addition, eight of the nine participating states have established 2050 requirements for 80% reductions.

More: Acadia Center

Del. Officials Say W.Va. Plant is Polluting Their Air

Delaware officials are asking federal regulators to take action against a coal-fired West Virginia plant they say is contributing to pollution in the First State.

The Department of Natural Resources and Environmental Control says emissions from the Harrison Power Station near Haywood exceed federal standards. The plant is 245 miles west of the Delaware border.

The move is the latest effort by state officials to battle emissions produced in Maryland, Pennsylvania and other states that they say are making it impossible for Delaware to meet EPA air quality standards.

More: Delaware Online

CALIFORNIA

Watchdog Says Energy Companies Influenced California Democrats

A public interest group said Gov. Jerry Brown and California Democrats have received more than $9.8 million in campaign contributions from energy companies during the past eight years.

In a report titled “Brown’s Dirty Hands,” Consumer Watchdog alleges that the donations coincided with the companies’ winning political favors — including a deal between Southern California Edison and the state’s Public Utilities Commission that allowed the utility to charge ratepayers with most of the cost of shutting down the San Onofre nuclear generating station.

“The report really paints a troubling picture,” said Jamie Court, the group’s president. A spokesman for the governor called the report “cuckoo.”

More: Pasadena Star-News

Pilot Program to Generate Power from California Highways

The California Energy Commission is initiating a series of pilot programs next year that will attempt to generate electricity from sensors in the roadway triggered by cars driving along the state’s freeways.

The project will rely on piezoelectric technology, which involves installing tiny sensors beneath the road surface to capture energy produced by vibrations of passing cars. Gov. Jerry Brown vetoed a bill, introduced by Assemblyman Mike Gatto, to fund the project, but the commission expressed interest in the technology shortly after.

“As an engineer, I could just see that vision of all these people driving down the roads and all that energy that’s sitting there and goes nowhere,” said Michael Gravely, a commission deputy division chief.

More: KCRA

DISTRICT OF COLUMBIA

OPC Takes Exelon Merger to Appeals Court

The Office of the People’s Counsel (OPC) is asking the D.C. Court of Appeals to examine the Public Service Commission’s order approving the Pepco/Exelon merger. (See Exelon Closes Pepco Merger Following OK from DC PSC.)

“Judicial review is critical not only because the decision impacts this case but all cases going forward in terms of the process and procedures the commission uses in making its decisions,” said Sandra Mattavous-Frye of the OPC. “It concerns the amount of process, or lack thereof, afforded to all parties, and the manner in which settlements are decided.”

Mattavous-Frye said the OPC also is opposing Pepco’s $85 million rate increase request.

More: Office of People’s Counsel

ILLINOIS

Lawmakers Urged to Follow NY’s Lead

A group of pro-nuclear Illinois mayors and community leaders have urged Illinois lawmakers to follow the lead of New York State policymakers, who arranged a nuclear bailout, expediting Exelon’s decision to buy and operate Entergy’s James A. FitzPatrick nuclear station.

In a letter sent to Gov. Bruce Rauner and lawmakers, the local leaders praised New York’s Clean Energy Standard, which includes subsidies for nuclear stations. “New York’s Clean Energy Standard is a road map for effective policy in Illinois,” said Tim Followell, city administrator of Clinton, Ill., which is home to one of the two nuclear stations Exelon says it will be closing because it is losing money due to low wholesale prices.

Followell and others have been pushing for passage of an Illinois version of a bill that would provide credits for nuclear stations. Critics have tagged that proposal, called the Next Generation Plan, a bailout.

More: Quad-City Times

AG Settles Case with Ethical Electric

Attorney General Lisa Madigan has reached a settlement with competitive retail energy supplier Ethical Electric requiring the company to refund up to $3 million for misleading customers.

Ethical Electric touted its power as being generated exclusively by renewable energy sources, when, in fact, it was sourced from a variety of generators paired with renewable energy certificates.

It also falsely promoted its fees as comparable with Commonwealth Edison’s rates, when they were more expensive.

More: Energy Manager Today

IOWA

Landowners File Yet Another Motion Against Dakota Access

A group of 14 landowners has filed a motion in Polk County District Court seeking to halt construction of the $3.8 billion Dakota Access Pipeline, asking the court to review the Iowa Utilities Board (IUB) ruling that the pipeline could use eminent domain.

“The landowners believe that Dakota Access is not a public utility and should not have the ability to use eminent domain to forcibly access Iowa landowners’ property to build a private pipeline,” Bill Hanigan, an attorney for the property owners, argued in a motion. He said the IUB misinterpreted Iowa law in calling the pipeline a public utility.

The 1,168-mile pipeline, parts of which are already under construction, will carry Bakken crude oil from North Dakota to terminals in Illinois.

More: The Gazette

KANSAS

Regulators Outline Standards for Upcoming Acquisition Dockets

The Corporation Commission said last week its members will consider whether Great Plains Energy’s proposed acquisition of Westar Energy will “promote the public interest” when it votes on the deal next year. Commissioners adopted merger standards for the Westar/Great Plains union and two other unrelated mergers to ensure the KCC takes a “consistent approach.”

The criteria the commission will consider include the merger’s effects on consumers, the environment and state and local economies and to the utilities’ communities.

The KCC is expected to hear the Westar Energy and Great Plains acquisition docket sometime between Jan. 3 and March 30. The two other acquisitions in front of the KCC are the purchase of Empire District Electric Co., of Joplin, Mo., by Liberty Utilities (Central) Co., a subsidiary of Algonquin Power & Utilities Corp., and a proposal for ITC Holdings to become an indirect, majority-owned subsidiary of FortisUS with minority ownership by GIC Ventures.

More: The Topeka Capital-Journal (Kan.)

KENTUCKY

LG&E Awarded Customer Charge for Clean Up

The Kentucky Public Service Commission has approved a request by Louisville Gas & Electric Co. (LG&E) to assess a new monthly charge for customers to pay for the cleanup of coal ash ponds. The commission approved the charge of 30 cents a month for this year for the typical residential customer, which will increase to $2.08 a month in 2024.

The commission approved a similar charge for LG&E’s sister company, Kentucky Utilities (KU), which was set at 30 cents per month and will later increase to $3.12 a month. The charges were approved after the two companies requested $994 million to meet new federal coal-ash cleanup rules. LG&E said it will spend more than $300 million in cleanup efforts. KU said it will spend about $675 million.

More: Louisville Courier-Journal

MICHIGAN

State Preps for Higher Rates In Face of Supply Shortage

Some consumers in the state are expecting electricity price increases in the coming years because of DTE Energy’s decision earlier this year to shut down seven coal-fired plants.

The Public Service Commission’s five-year outlook anticipates electric supply shortfalls through summers 2017 and 2020. The Lower Peninsula is expected to see a 270-MW shortage next year, an improvement over the 520-MW shortage that the PSC previously predicted. MISO’s Midwest region is predicted to fall short of the reserve margin requirement by 2018.

Tim Arends, executive director of Traverse City Light & Power, said the municipal utility’s annual power prices nearly doubled to $850,000 this year. The utility recovers the cost through a user fee.

More: Traverse City Record-Eagle

Consumers Installing More Safety Buoys Near Hydroelectric Dams

Consumers Energy in installing more safety buoys across rivers below its Michigan hydroelectric dams to warn swimmers and boaters of the dangers of swirling water released from impoundments.

The utility is working with the Michigan Department of Natural Resources to keep swimmers and boaters out of “potentially unsafe areas immediately downstream of hydroelectric dams.” Consumers will place buoys at 10 dams on five rivers statewide during the year.

Last year, Consumers installed buoys at three dams on two northern Michigan rivers.

More: Post-Bulletin

MISSOURI

PSC Could Quash Westar-KCP&L Merger

The Public Service Commission’s claims of jurisdiction over the $12.2 billion acquisition of a Kansas utility by Great Plains Energy could have significant impact on the deal. Commission staff says job cuts and possible outsourcing spurred by the proposed acquisition could harm existing customers of Great Plains’ subsidiary, Kansas City Power & Light.

The staff claims Great Plains violated a 2001 agreement with the commission, in which it agreed not to acquire any public utilities without commission approval.

Great Plains argues that combining Westar and KCP&L would benefit customers on both sides of the state line. Moreover, it says the commission’s complaint is a moot point because Westar isn’t a public utility under state law, and, therefore, Great Plains doesn’t need the state’s approval to buy Westar.

More: The Wichita Eagle (Kan.)

NEW MEXICO

Regulatory Examiner Recommends 67% Slash to PNM Rate Increase

A state hearing examiner has recommended a 67% reduction to Public Service Company of New Mexico’s (PNM) rate increase request, from $123.5 million a year to $41.3 million a year. The recommendation would result in a 6.4% increase for the average customer, compared to 14.4% under PNM’s request.

The hearing examiner rejected the $152.8 million PNM spent to purchase power from the Palo Verde Nuclear Generating Station in Arizona, which was disputed in a separate commission matter. The examiner also disallowed a $52 million investment in pollution controls at the San Juan Generation Station, which PNM did at the behest of the EPA, but some felt it was unnecessary. The examiner also reduced PNM’s requested rate of return from 10.5% to 9.575%.

PNM can file exceptions to the examiner’s findings, after which the regulatory commission’s general counsel will present a draft order to the Public Regulation Commission (PRC). According to the current schedule, the PRC must make a final ruling in the case by Aug. 31.

More: Albuquerque Journal (N.M.)

NEW YORK

Storage Provider Demand Energy Wins Load Relief Auction

Demand Energy was a successful bidder in Consolidated Edison’s first-ever auction to provide load relief on peak power days in New York City.

Demand Energy will soon begin installing several megawatts of energy storage in Brooklyn and Queens, controlled by the company’s Distributed Energy Network Optimization System (DEN.OS) intelligent software. The project is part of Con Ed’s Brooklyn-Queens Demand Management program.

The energy storage project, which will come online in 2017, will delay the need for a new $1.2 billion substation. The program will use demand-side resources such as energy storage, energy efficiency and demand response. The project is a prototype for New York State’s Reforming the Energy Vision initiative to encourage the use of more distributed resources.

More: Demand Energy

NORTH DAKOTA

Tribe Blocks Access to Dakota Access Crews

Members of Standing Rock Sioux Tribe blocked crews working on the $3.8 billion Dakota Access pipeline that is to carry crude oil from North Dakota to terminals in Illinois.

Although the pipeline developers have received the necessary permits from state and regulatory agencies, they face continuing legal and political challenges. One was by the Standing Rock Sioux Tribe, which sued federal regulators in July, claiming the pipeline runs too close to sacred land and the tribe’s drinking water supplies. Tribe members blocked a road near their 2.3-million-acre reservation, backing up a line of 45 construction vehicles.

Work has already started on the 1,168-mile pipeline in other places in North Dakota, South Dakota and Illinois.

More: Associated Press

OKLAHOMA

Drop in Number of Earthquakes Could be Result of Regulation

Oklahoma has experienced a decline in earthquakes compared to last year, and some geophysicists believe that more stringent regulation of underground injection of wastewater from oil and gas drilling operations may deserve some of the credit.

According to the U.S. Geological Survey (USGS), Oklahoma experienced 448 magnitude 3.0 or greater earthquakes as of Aug. 10, compared to 558 for the same period last year. Robert Williams, with USGS, said the increased restrictions on wastewater injection and disposal could be one reason for the decrease, as well as the drop in oil and natural gas exploration.

More: USA Today

City Tests Smart Meters Before Making the Switch

City of Edmond officials in Oklahoma are conducting a pilot program to help determine whether the city should install smart meters for all 35,000 electric customers and 32,000 water customers. The pilot program could last from six months to a year before a decision is made.

In a 2011 feasibility study, consultants told city officials a total system, with all the possible extras, could cost $36 million over 15 years.

About 1.7 million smart meters were installed across Oklahoma in 2014.

More: The Oklahoman

PENNSYLVANIA

PUC Reliability Report Dings Penelec

A report by the Public Utility Commission says Penelec customers saw more power failures last year compared with consumers of electricity from other large companies in the state.

The report relies on data from quarterly and annual reliability reports submitted by electric distribution companies and details four benchmarks.

Penelec failed to meet any of the benchmarks but expects to improve reliability by 2018.

More: The Bradford Era

August 15, 2016

PGE Files Diablo Canyon Shutdown Request

By Robert Mullin

Pacific Gas and Electric filed with California regulators last week to shut down the state’s last remaining nuclear power plant by the end of 2025.

The application also asks the state Public Utilities Commission to approve a joint proposal that the utility forged with environmental, labor and anti-nuclear groups to replace output from the 2,240-MW Diablo Canyon facility with a portfolio of renewable resources, energy efficiency measures and energy storage.

Pacific Gas and Electric Files Diablo Canyon Shutdown Request — Diablo Canyon *Source: PG&E*

PG&E announced the closure in late June, saying the plant’s full output would no longer be needed in light of dramatic changes in California’s energy market, which increasingly is putting a premium on flexible resources over inflexible baseload generation. (See: PG&E to Shut Down Diablo Canyon, California’s Last Nuclear Plant).

In its filing, the utility also pointed out the uncertainty of its future supply needs, with customer demand being undercut by improvements in building efficiency, increased adoption of rooftop solar and the growth of alternative energy suppliers such as community choice aggregators (CCA).

“As a result of the rapidly changing California energy landscape, Diablo Canyon will not be needed at the end of the license period,” the utility wrote.

The joint proposal accompanying the filing includes three tranches to procure energy efficiency and greenhouse gas-free resources between 2018 and 2045.

The first tranche is intended to reduce load before Diablo Canyon retires through a competitive solicitation to add 2,000 GWh worth of energy efficiency to PG&E’s service territory by 2024. The company is seeking PUC authorization to recover $1.3 billion to administer the program over seven years through a “public purpose program” rate component.

Included in the second tranche is a solicitation for 2,000 GWh of carbon-free energy to be delivered between 2025 and 2030, with renewable resources, energy efficiency and other technologies eligible to bid. PG&E is seeking to recover part of the costs associated with this tranche from a “clean energy charge” allocated to the utility’s bundled electric and direct access customers as well as to CCA customers. Renewable procurement costs would also be recovered from an additional fee assessed on customers who depart from PG&E.

The third tranche includes PG&E’s voluntary commitment to increase its renewable portfolio standard to 55% over the 2031-2045 period — five percentage points above the current 2030 mandate.

The joint proposal also includes provisions for PG&E to recover costs related to winding down Diablo Canyon’s operations.

PG&E is asking the PUC to approve a two-way balancing account to implement yearly rate adjustments to recover the costs and allow the plant’s book value to be depreciated to zero by the time it closes. The utility is also seeking have ratepayers cover $53 million in costs previously incurred in efforts to renew the plant’s operating license beyond 2025.

PG&E has requested a decision by the CPUC by June 2017.

August 15, 2016

PJM Market Implementation Committee Briefs

Excess capacity expected to be released in the third incremental auction for the 2017/18 delivery year in February would likely clear at $0 under current rules, PJM’s Jeff Bastian told the Market Implementation Committee Wednesday.

To avoid that, PJM presented a proposal that would release excess capacity on an upward trajectory, ranging from 0 MW at $10.74/MW-day to all 10,017 MW being available at $144/MW-day or 1.2 times the Base Residual Auction clearing price.

That is, the RTO would retain more capacity at lower prices but be willing to release more at a higher price.

PJM must file its plans for releasing the capacity with FERC by November. Because of that time constraint, some members suggested advancing the PJM proposal to the Markets and Reliability Committee for a first read.

Among them were Jeff Whitehead of Direct Energy and Mike Borgatti, representing NextEra Energy. Both said they would be willing to forego their companies’ alternate proposals to support PJM’s solution.

At the July MIC meeting, Direct Energy had proposed using a sloped offer curve to create a price floor that would prevent supply resources from being able to cheaply buy out of their obligation at load’s expense. NextEra proposed PJM’s sell offer equal the transitional incremental auction adder that the RTO charges to load. (See “Members Debate Ways to Release Excess Capacity into Incremental Auction,” PJM Market Implementation Committee Briefs.)

Bastian said all three approaches are intended to preserve value for load.

“If the clearing price is zero, then you are releasing capacity commitments with no benefit going back to load,” he said.

The PJM proposal contains three parts. The first retains the status quo for how PJM determines the quantity and price at which it procures or releases MW in an incremental auction due to changes in load forecast or reliability requirements.

The second part, however, would release the 10,017 MW separately, according to the upward-sloping price curve.

Lastly, any of those separately released MW that did not clear would not be included in the determination of excess commitment credits.

“We would exclude this uncleared quantity from the quantity included in the first bullet,” Bastian explained.

Katie Guerry of EnerNOC said she was surprised by PJM’s new proposal, given that in July it had presented a plan to release capacity into the 2017/18 year using the same method FERC had approved for the 2016/17 delivery year, which yielded $4.79/MW-day.

“To hear PJM changing [its] position after the conclusion of that second incremental auction, after what we’ve been hearing from PJM for months now, is a little confusing,” Guerry said, adding that she was not comfortable with the issue being advanced yet to the MRC.

“PJM’s thinking has evolved,” Bastian said. “I wouldn’t say we had a position here. When we brought this forward again, we brought it forward as a discussion item. Our intent at this point would be to release it. We could go forward using the same method as last time. But if we use the same method, we’re likely to clear at zero, and that didn’t seem to make sense.”

Whitehead said PJM’s new proposal should not be a surprise, as the committee has been debating different approaches for several months.

“I feel this has been vetted here. I understand that you may not be happy with the outcome, but the opportunity for dialogue certainly occurred,” Whitehead said to Guerry.

“There’s a reliability tradeoff for these sales,” he said. “It is critical to recognize that we have the potential to sell back 10,000 MW of capacity. To do that and to know there’s a distinct possibility that most of those MW could clear close to zero … it’s counter-intuitive that in one auction we’re valuing capacity at $150, and, in the next instance, we’re valuing it at zero. The reduction in load’s cost is 1%, while giving up 5% of reliability — that should be concerning.

“It’s a lot of capacity, and my company’s position is we need to make sure we are putting the right value on those sales,” said Whitehead.

Independent Market Monitor Joe Bowring repeated his position that PJM should not buy more capacity than it needs and should not sell it back for less than it paid. But, he said, the PJM proposal goes in the right direction.

Still, Bowring said, “There’s no cap. There is no limit. There’s no reason not to hold onto that capacity, which was purchased for a higher price.”

In the end, committee Chair Chantal Hendrzak declared the item an official first read for the group.

Order 825 Progress

PJM staff announced their preliminary plans for implementing five-minute interval data for load, generation and shortage pricing.

For generation, PJM would use existing estimated or telemetry data and create five-minute profiles that correspond to hourly revenue-quality meter data already submitted. The five-minute telemetry data would be average and combined with a scaling factor for each five-minute interval profile associated with five-minute LMPs. The total of the 12 intervals would equal the hourly revenue-quality data. This is a protocol other ISOs are using, PJM’s Adam Keech said.

Order 825 doesn’t require load to provide five-minute data, so PJM plans to use flat profiling over the 12 intervals in an hour and associate that with five-minute pricing to determine load pricing. Demand response is also submitted hourly, so PJM would prorate such resources by interval for curtailments of less than an hour. PJM doesn’t have the granularity to use state estimator data for discrete DR, Keech said.

PJM wants to continue using megawatt-hour values and augment them with five-minute LMPs for pricing. The plan hasn’t yet been discussed with other RTOs, though, and stakeholders expressed concern that differences in each RTO’s plan might impact their interaction.

For shortage pricing, PJM introduced a problem statement to develop new curves that are complementary with the rules of Order 825.

While the order allows more time for initiating shortage pricing, PJM wants to implement it jointly with the load and generator changes because of concern that five-minute pricing could distort hourly prices, Keech said. PJM has been discussing this with other RTOs, particularly ISO-NE, and have come up with similar solutions.

Currently, PJM’s four curves are very similar and all have the same $850 penalty factor. The RTO currently addresses transient shortages — those expected to last a very short time —by easing reserve requirements slightly until expected supply arrives. Order 825 prohibits PJM from doing this, so the RTO wants to develop new demand curves that complement the requirements of the order.

Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters

The MIC will be asked at its September meeting to endorse one of two proposals on whether and how to “un-nest” operating parameter definitions to separate soak time from start time (see table).

The definitions are contained in Manuals 11, 15 and 28. (See “Members OK Operating Parameters but Urge Refinements,” PJM Markets and Reliability and Members Committees Briefs.)

NYISO to be Consulted on Changing Spot-in Service Allocation Methods

Joe Wadsworth of Vitol presented further discussion on how to improve the process of allocating spot-in transmission for energy imports from NYISO.

In April, the committee approved a problem statement and issue charge on the subject. (See “Allocating Spot-in Service for NYISO Imports to be Studied,” PJM Market Implementation Committee Briefs.)

Currently, the free but limited service is allocated on a first-come, first-served basis with no priority for participants who have cleared the NYISO market.

Wadsworth proposed removing PJM’s limit on requests for spot-in service and relying on NYISO’s real-time economic evaluation to determine which importers get spot-in service. He also proposed modifying some rules and timelines for the NYISO/PJM interface.

Wadsworth said talks are planned with NYISO and he would present their feedback at the next meeting.

Although no similar concerns have been expressed regarding the MISO seam, Bowring suggested the committee consider expanding the proposal to apply to all of the neighboring RTOs.

— Suzanne Herel and Rory D. Sweeney

August 15, 2016

Energy Wildcatter Hopes to Make His Mark in Emerging Mexican Market

By Tom Kleckner

With its electricity demand projected to grow 3 to 4% annually, the expected retirement of 10 to 15 GW of fossil plants, a commitment to add 1 GW of wind power annually and off-peak prices as high as $65/MWh, Mexico presents an appealing target to generation developers.

And Mannti Cummins wants a piece.

A certified public accountant by training, Cummins now calls himself a wildcat wind-energy developer, having developed more than 1,000 MW and $2.2 billion worth of wind projects in the U.S. and Mexico.

“Get in early, get in cheap,” he said in describing his strategy. “Hopefully, it’ll be a good market position with relatively few dollars spent.”

For now, however, Cummins and other developers are finding that a lack of transparency and uncertain rules are making their efforts anything but a sure bet.

Cummins, who grew up near the Gulf of Mexico, has made his home in Mexico for the past decade and speaks Spanish fluently enough to have completed a course in energy law from Mexico’s Escuela Libre de Derecho law school. He helped develop that country’s first two managed health care insurance firms and served as their CEO.

In his spare time, Cummins has been an avid surfer. He’s also been known to play Billy Idol’s “White Wedding” on his accordion.

Having made his mark in industries on both sides of the border, Cummins has jumped headlong into the Mexican energy market, which opened to national and international wholesale competition earlier this year.

Focus on Renewables

For the time being, much of the market’s focus is on renewable energy. Mexican President Enrique Peña Nieto in June joined President Obama and Canadian Prime Minister Justin Trudeau in pledging to generate half his country’s power from clean-energy sources by 2025, accelerating its 2013 pledge to produce 35% of its energy from renewable sources by 2024.

Cummins notes that Mexico’s definition of “clean-energy sources” does not include natural gas or nuclear energy. The Ministry of Energy’s National Electricity System Development Program projects Mexico will need more than 20,000 MW of clean energy over the next 15 years, part of an estimated $62.5 billion in private investment in the energy industry by 2018.

“Every year, Mexico has … to add 1,000 MW of wind power,” said Cummins, currently director of Energia Veleta, S. de R.L. de C.V. (which translates as wind vane energy) in Monterrey, Mexico.

Market Phase-In

Mexico’s wholesale market will be implemented in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, financial transmission rights auctions, a capacity-balance market and the 20-year clean-energy certiﬁcates — instruments equivalent to 1 MWh of energy from clean sources — market that Cummins and other developers have their eyes on.

In the first clean-energy auction in March, about 80 firms offered more than 200 bid packages, with contracts awarded to Enel Green Power, Acciona, Jinko Solar and other players.

Cummins said state-owned Comisión Federal de Electricidad (CFE), Mexico’s only utility, saw some solar projects bid as low as $40/MWh, lower than the utility had expected. All told, CFE awarded 5.38 million MWh of contracts, with almost 75% of those going to solar developers. A second auction will be held in September.

Because bidders were required to have a financial guarantee of about $40,000/MW to participate, Cummins lamented, the wildcatters were priced out.

“I wanted to bid in March, but I couldn’t find anybody to put up the guarantee,” Cummins said. “That would have required about $2 million, which I ain’t got.”

Cummins was riding in a Mexico City taxi as he spoke, on his way to a meeting with a fourth-level executive in the country’s energy department to discuss timetable issues. The man he was going to meet “is the guy that turns the crank,” the person who implements policy directives, Cummins said.

In order to place financial guarantees for the September auction, Cummins needs an interconnection, which requires a bond guaranteeing that upgrade costs will be paid, and a generation permit from Mexico’s Energy Regulatory Commission. And he must be ready to turn in reams of paper.

“Coordinating calendars for other permits … makes it tricky,” Cummins said. He planned to complete the paperwork by Aug. 29. “The [first official] deadline is Sept. 1. That’s a slim margin for error.”

It may not matter. Cummins said in a subsequent email exchange that an “unexpected change” in the auction’s evaluation criteria “most likely knock[s] us out as contenders in this auction as well.”

Growing Pains

Growing pains are to be expected in any immature market, but those pains have been amplified by Mexico’s emergence from a state-run monopoly. Vertically integrated CFE has long been the country’s only electric utility, much as Pemex controls the country’s oil industry. It is only now being restructured into generation, transmission and distribution firms.

“The market is open, and it has a single participant … CFE, which was the single participant before it opened,” Barbara Clemenhagen, Customized Energy Solutions’ vice president of market intelligence, explained at an Infocast conference in March. “If the statements for the initial 48 days are indicative, there’ s not much transparency and liquidity in the market.”

Clemenhagen said CFE is participating as both a buyer and a seller in the clean-energy auctions, covering the demand of its regulated clients and load centers. The utility was the only buyer for capacity, energy and clean-energy certificates in the last two auctions but was not allowed to sell because its generation companies do not exist yet.

El Centro Nacional de Control de Energía (CENACE), the grid operator, was an operating division of CFE, the vertically integrated national electric utility. CENACE became an independent system operator in August 2015.

CFE is also being restructured into different generation, transmission and distribution firms.

“The same guys who are on the CFE payroll in the morning are with CENACE in the afternoon,” Cummins said. “The independent part needs some time to set, since most CENACE folks were transitioned from similar posts in CFE.”

Grupo Fenix, which works with rural communities in Nicaragua to promote renewable energy, reforestation and sustainable development, also qualified as a market participant but has chosen not to participate.

“They pulled this thing together so fast, all the loose ends aren’t tied up,” Cummins said. “How long did it take ERCOT to get [its competitive market] going? The Senate bill passed in 1999 and it took 10 years to decide what was up.

“Wildcatter guys like us, we don’t mind navigating in an uncertain environment. But when you start putting hundreds of millions of dollars down, you better have everything locked up pretty good.”

Cummins said he would like to see more clarity in the market’s interconnection rules, the source of many of his current headaches.

“There needs to be coordination between the auction process and the interconnection process,” he said. “In ERCOT, you file your study and ERCOT comes in with theirs. There’s a date certain your study has to be done. Not in Mexico. That process and the auction timetables sometimes just don’t line up.”

The wildcatter would also like to see clean-energy generators create bilateral contracts outside the auction process with consumers, who will be required by Mexican law to buy 5% of their load from clean-energy sources in 2018.

“The rules in that market are uncertain and not definable for the amount of risk [involved],” Cummins said. “Those rules have not been ironed out.”

Compounding the problem, Cummins said, is the lack of a mechanism to balance load with generation and the requirement that private-generation companies purchase clean-energy certificates — even though clean-energy projects have yet to be built.

Clemenhagen said even when the rules are finalized, a lack of transparency makes it difficult to know who changed the rules and why. As of this spring, only 13 of 30 expected operating procedures and manuals had been released, and only one (the long-term auctions market) had been ﬁnalized.

“She’s not the only one [who feels that way],” Cummins said. “There are inconsistencies in the rules, gaps in the rules, downright confusion in the rules. The sheer volume of the rules … you have to have a person, or two or three, just to read the darn documents on a daily basis.

“It’s a haul, especially in a market like Mexico’s, where you have plenty of unknown unknowns,” he said.

Still, Cummins is making a go of it. His 148.5-MW Tres Mesas wind farm in the state of Tamaulipas, owned and operated by Oak Creek de México, is scheduled to be operational by the end of the year.

mexico energy — Tres Mesas *Source: Manti Cummins*

He also has four other projects in development in four states, Baja California Sur, Jalisco, Sonora and Zacatecas. That includes a 50-MW wind farm in Baja Sur, an island grid where all generation is supplied by fuel oil.

“We’re in so deep now,” Cummins said, “we don’t have a choice but to accomplish the goal.”

August 15, 2016

ERCOT Board of Directors Briefs

ERCOT will rely on its stakeholders to improve its reliability-must-run (RMR) practices after a second rejection last week of a protocol change that would allow the economic dispatch of RMR units.

The ISO’s Board of Directors on Aug. 9 rejected NRG Texas and Reliant Energy Retail Services’ appeal of a nodal protocol revision request (NPRR) addressing how RMR units are priced and dispatched. The appeal was shot down by an 11-3 vote, with one abstention.

The two companies also lost an appeal in July to the Technical Advisory Committee (TAC) after the revision request failed to clear the Protocol Revision Subcommittee (PRS). (See “Pricing Change on RMR Units Rejected, Appealed to ERCOT Board,” ERCOT Technical Advisory Committee Briefs.)

NRG drafted NPRR 784 earlier this summer as ERCOT was in the process of issuing and extending into 2018 an RMR contract for the company’s Greens Bayou Unit 5, a 371-MW gas plant near Houston. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)

Greens Bayou - ERCOT board of directors - reliability must run (RMR) — Greens Bayou

The protocol change would have allowed security constrained economic dispatch (SCED) of RMR units to relieve transmission congestion, after all other capacity available for transmission congestion relief had been exhausted. It would have applied only when generator offers are mitigated due to inadequate competition.

RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50 to $60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the proposed change.

The revision request would have required all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.

NRG’s Bill Barnes said the proposed change raised a pricing policy question that is fundamental to the energy-only market design. “The energy-only market requires effective pricing, and it does so all the time,” he said.

“It sends a signal for existing resources to remain in the market or exit if they’re uneconomic. Second, it provides incentives for new investment. Locational price signals are equally important as systemwide price signals.”

Air Liquide’s Phillip Oldham advocated TAC’s position by urging the board to reject NRG’s appeal, given the “important stakeholder input” provided by its failure at TAC and PRS. He reminded the directors that RMR protocols are currently being reviewed and asked they let the process play out.

Barnes © RTO Insider, ercot, board of directors, reliability-must-run — Barnes © *RTO Insider*

“We believe [784] is inconsistent with market principles that have been in place,” Oldham said. “We fundamentally disagree, even at the most basic levels, about what an RMR is. It is not a generation issue. It’s a transmission issue.”

Oldham said the revision request doesn’t support resource-adequacy objectives, noting Greens Bayou Unit 5 is an RMR for local reliability, not systemwide capacity. He also pointed to the $590 million Houston Import transmission project as the RMR “exit strategy” for the Houston area, a position later supported by ERCOT’s COO, Cheryl Mele.

“Using the RMR to set high prices in Houston between now and 2018 will not incentivize new resources because a transmission solution is already in process,” Oldham said.

ERCOT Director Nick Fehrenbach, the City of Dallas’ manager of regulatory affairs and utility franchising, said he had received calls from his consumer market segment members worried about the revision request’s consequences.

“They’re concerned about the impact this could have on load in the Houston area,” he said. “It’s simply a short-term solution before we get the Houston Import project built. I don’t think this is a smart move.”

ERCOT’s RMR contract with Greens Bayou requires the ISO to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the unit’s capacity.

“As you saw in the debate … there’s some sense of urgency around looking at this,” said ERCOT CEO Bill Magness when the smoke had cleared. “[RMR] is an important reliability tool, but it’s a relatively blunt instrument. It is a large bundle of issues, but one that we believe, with a lot of effort and focus from stakeholders and staff, we can get some items to the board for consideration fairly soon.”

TAC Chair Randa Stephenson of the Lower Colorado River Authority was reminded her committee had predicted NPRR 784 would be a “hot topic” six months ago. She said stakeholders have been “digging into the protocols” and existing parameters as they try to improve the RMR process.

At a workshop in May, stakeholders identified 18 RMR-related issues, giving priority to the following three:

A timeline on notifications suspending operations;
Studies, processes and criteria used to identify whether a resource is needed for RMR service; and
Capital contributions to an RMR unit.

Several NPRRs are currently being developed that address the RMR process, timeline and notice. Stephenson said the timing of a staff-drafted revision request modifying the current RMR process has yet to be determined, but other NPRRs will bubble up through the stakeholder request during the next six months.

Last month, ERCOT also issued a request for must-run alternative resource proposals that offer more cost-effective solutions (defined as more than $1 million in savings) than Greens Bayou. Responses are due Aug. 24, with any agreements to be announced Oct. 7.

IMM Notes 26% Drop in Real-Time Prices

The Independent Market Monitor reported that the growing abundance of Texas’ wind resources helped cut load-weighted real-time prices 26% in the first half of 2016 compared with 2015.

IMM Director Beth Garza said ERCOT’s real-time prices have averaged $20/MWh through June, compared with $27/MWh for the same period last year. She called the number “momentous” but said prices will increase “as you factor in the effects of last month and going into August.”

Garza said ERCOT’s wind fleet has grown so much that in June there was never less than 3,500 MW available. She said average capacity factors and energy totals have been higher per MW of nameplate capacity this year, thanks to ERCOT’s recent transmission buildout.

“And the preliminary data in July shows the wind will be higher than it was in June,” she said. “ … People are building more of it, so we get more energy.”

ERCOT’s generation-interconnection status report shows more than 10,000 MW of wind generation due to come online through 2018.

Garza’s report also noted that ERCOT’s ancillary service (AS) costs at mid-year have increased $0.05/MWh over 2015, even though the ISO is procuring fewer such services. She said the IMM will continue to monitor the AS market to determine the cause of the increase.

Magness Reports Favorable Financials to Board

Magness said August’s searing temperatures are expected to make up for milder conditions earlier in the year. The ISO’s net revenues were $4.9 million over budget through June, despite being $2.5 million behind on administration fees. Those numbers are currently projected to finish $7.5 million and $0.5 million over budget, respectively.

The president’s report also addressed the July 7 Energy Management System (EMS) outage and TAC’s concerns that ERCOT did not communicate quickly enough with the market. (See “Committee Discusses July 7 System Outage,” ERCOT Technical Advisory Committee Briefs.)

“It’s always a balance of not wanting to speak until we know what’s going on, but that’s something we’re working on,” Magness said. “It was a human error event, and we took responsibility for that. We’ve changed the process to make sure that is not an error we’re going to see again.”

Magness also took time to recognize the 170-person team behind ERCOT’s recent EMS upgrade. The four-year project went live June 16 following 84,000 person-hours of work, coming in under budget and ahead of schedule.

“The EMS upgrade was one of those processes that’s described as performing brain surgery on the pilot while he’s flying the plane,” he said.

Board Approves 8 Protocol Revisions, 2 Other Changes

The board approved seven NPRRs, a system-change request (SCR) and revisions to the Planning Guide (PGRR) and the Resource Registration Glossary (RRGRR). NPRRs 696 and 738 were the only two revision requests that received any opposing votes.

NPRR696: Establishes price corrections following a SCED failure by correcting prices for settlement intervals corresponding to the active watch period, giving market participants transparency to known prices that reflect the last good SCED execution.
NPRR738: Excludes intervals from performance calculations when an emergency response service generator is unable to meet its obligations due to transmission or distribution service provider (TDSP) outages.
NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities for voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for including startup costs in the make-whole payment calculation.
NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary services capacity monitor.
NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises to avoid transactional, billing and out-of-sync issues.
NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbance events by specifying a process for developing geomagnetically-induced system models.
RRGRR009: Adds three categories of data to the Resource Registration Glossary: Voltage limits for transmission level equipment at generator substations; geomagnetically-induced currents and the presence of blocking devices to allow identification of vulnerabilities due to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
SCR789: Updates the network model management system topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.

— Tom Kleckner

August 15, 2016

SPP Briefs

SPP says it is on track to go live as scheduled with the new gas-day timeline in October and enhanced combined cycle (ECC) software in March.

Testing on SPP’s gas-day system began Aug. 1 and concludes Aug. 29.

The first operating day will be Oct. 1, when participants must submit bids and offers by 9:30 a.m. instead of 11 a.m. SPP requested a one-day extension of the first operating day from Sept. 30, which FERC granted last week.

“There’s no real system changes for members,” Jodi Woods, SPP’s day-ahead market manager, told the Gas Electric Coordination Task Force last week. “We’re using this opportunity to go through the processes and make sure they can meet their deadlines.”

The gas-day timeline changes are a result of FERC Order 809, which moved the RTO’s timely nomination cycle deadline for gas supplies to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle.

Last July, SPP’s Board of Directors approved timeline changes that post day-ahead market results at 2 p.m. CT, up from 4 p.m., and shorten the reoffer period to 45 minutes, with reliability unit commitment offers due at 2:45 p.m. and results posted by 5:15 p.m. (See “Board Approves Gas-Electric Timeline Change,” SPP BoD/Members Committee Briefs.)

Enhanced Combined Cycle Project

Testing the enhanced combined cycle (ECC) project’s software, which involves more than a dozen systems and interfaces, is scheduled to begin in December, with a projected March 1, 2017 go-live date. The project is expected to provide more sophisticated modeling to capture combined-cycle plants’ flexibility.

The two projects have an estimated implementation cost of $7.7 million, the bulk of which is related to the more complicated ECC software.

Task Force Suggests Minimum Threshold for Competitive Projects

The Competitive Transmission Process Task Force last week made official its support for a minimum threshold for competitive projects under FERC’s Order 1000. However, the group rejected the idea of instituting a $2.5 million threshold, asking staff to return with additional analysis before its next meeting Wednesday.

The threshold was one of five issues the task force was assigned to study by the Strategic Planning Committee.

The SPC directed the group to base any process improvements on lowering costs for the end customer — rather than simplifying the process for staff — and to report back with recommendations in October.

MISO currently has a $5 million threshold for market-efficiency projects and a $20 million hurdle for its multi-value projects. An SPP staff review of more than 300 highway/byway high-priority projects dating from 2010 found that only 34 projects receiving notices-to-construct (NTC) had costs under $10 million, with 18 under $5 million.

The task force is also considering whether to: seat the industry panel evaluating competitive bids earlier in the solicitation process; develop a region-wide formula rate; report proposal costs as an incremental cost or as an average for each respondent; and move from the current competitive model to a sponsorship model.

The task force also approved developing Tariff language that allows for the re-study of approved competitive projects before an NTC is issued. The action was a result of last month’s cancellation of SPP’s first competitive project under Order 1000. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

MOPC Fills Out Z2 Task Force

On Friday, the Markets and Operations Policy Committee (MOPC) closed its solicitation for members interested in participating on a task force to address unresolved issues concerning the Z2 crediting process.

The Board of Directors created the task force last month to address complaints of members being charged for costs that were not identified in service agreements after declining to address the members’ waiver requests. (See Board Approves Z2 Timeline Extension, Creates Task Force for Further Study.)

Bruce Rew, SPP’s vice president of operations, told members the task force would review the waiver requests, with the intention of “expeditiously” conducting a study and finding an “acceptable solution” before the October MOPC and board meetings. Rew said the full scope of work is still being developed, but the group may also be asked to work on improving the Z2 payment process.

The task force is expected to be “highly engaged” for at least six months, Rew said.

– Tom Kleckner

August 15, 2016

PJM Planning Committee and TEAC Briefs

VALLEY FORGE, Pa. — A reliability analysis identified no adverse impacts on the PJM system from closing the 1,819-MW Quad Cities nuclear plant, which Exelon plans to deactivate on June 1, 2018.

Exelon announced the closure in June after failing to convince Illinois legislators to act on a bill that would help subsidize its money-losing stations. (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)

It also plans to shutter the 1,065-MW Clinton station next June 1.

Meanwhile, PJM is wrapping up analyses on FirstEnergy’s plans to close its W.H. Sammis and Bay Shore plants — a combined 856 MW — in Ohio.

Those studies did indicate some issues, said Paul McGlynn, senior director of planning, but they are in areas where PJM already has identified needs for baseline Regional Transmission Expansion Plan (RTEP) upgrades.

“We’re just making sure those previously approved upgrades will meet the needs,” he said.

In July, FirstEnergy announced the retirement of Sammis, its largest coal-fired plant in Ohio. At the time, it said it would deactivate or sell its Bay Shore plant by 2020. (See FirstEnergy Closing Largest Coal Plant in Ohio, Bay Shore also in Peril.)

Third RTEP Window of 2016 Set to Open in September

PJM expects to open the third RTEP window of the year in mid- to late September, McGlynn told the Transmission Expansion Advisory Committee (TEAC) on Thursday. Its scope will be short circuits and 2021 winter and light load reliability.

McGlynn also provided an update on the second proposal window, which closed July 29. (See “PJM to Open FERC Order 1000 Proposal Window in Late June,” PJM Planning Committee and TEAC Briefs.)

PJM received 87 proposals from 13 entities in a dozen transmission zones to address N-1 and N-1-1 thermal and voltage issues and load and generation deliverability problems.

Of those, 46 involve greenfield projects, ranging in cost from $5 million to $224 million; 41 were transmission owner upgrades estimated at $30,000 to $125 million.

PJM said it cannot provide details on the projects until after cost analyses are submitted. They were due Aug. 15.

PSE&G End-of-Life Price Tag: $1.15B

McGlynn presented $1.15 billion in proposed solutions to end-of-life issues involving Public Service Electric and Gas equipment. (See “PJM Concerned PSE&G Equipment at the End of its Life,” PJM Planning Committee and TEAC Briefs.)

Planners are considering replacing the double 138-kV circuits on the Metuchen-Edison-Trenton-Burlington corridor with 230-kV lines in three sections: Metuchen-Brunswick ($125 million), Brunswick-Trenton ($327 million) and Trenton-Burlington ($349 million).

The 30-mile Metuchen-Trenton span is about 86 years old; structures in the 22-mile Trenton-Burlington section average 75 years old. About 81% of the towers are at 95 to 100% of their load-carrying capacity and as much as 30% of the structures require extensive foundation rehabilitation or replacement.

“We don’t have time to put [the projects] through a [competitive] window,” McGlynn said.

An alternative would be to rebuild the corridor with the existing double-circuit 138-kV configuration, an option that would be about 20% cheaper, McGlynn said.

PJM staff also recommend the existing Newark switch station be demolished and a new one constructed adjacent to that site at a cost of $353 million.

PJM Creates System Planning Modeling and Support Group

PJM has created a new planning department called the System Planning Modeling and Support Group.

The reorganization, which will take effect next month, is intended to streamline case-building, PJM’s Jason Connell explained. The effort is time-consuming, and PJM is seeing an increase in required cases, he said.

The unit will report to McGlynn, along with Interconnection Analysis, headed by Aaron Berner, and Transmission Planning, led by Mark Sims.

Planners are reaching out to transmission owners about the change, Connell said.

PJM Poised to Exempt TO Upgrades from Order 1000 Process

PJM is waiting until FERC accepts its deficiency filing related to exempting low-voltage facilities from the Order 1000 process before it files a similar request involving transmission-owner upgrades.

PJM’s Mark Sims said the commission is expected to act by Aug. 26, and the Planning Committee likely will be asked to endorse the proposal at its September meeting. If approved, the exemption would go into effect for the 2017 RTEP cycle.

The proposal would exclude typical transmission substation equipment upgrades from competitive windows unless there’s an indication that the problem could yield a greenfield project. (See “PJM Beefing up Details of TO Upgrade Exemption Proposal,” PJM Planning Committee and TEAC Briefs.)

Such upgrades would include short-circuit violations and fixes to substation terminal equipment such as wave traps, current transformers and capacitors.

In February, members approved revisions to the Operating Agreement exempting transmission reliability projects of less than 200 kV from the competitive proposal windows. (See “Low-Voltage Projects to be Exempted from Competitive Window Process,” Markets and Reliability and Members Committees Briefs.)

FERC responded by ordering PJM to make a compliance filing addressing concerns such as how stakeholders would comment on exempted projects (ER16-1335).

PJM Staff Continues to Scrutinize Planning Process

PJM staff is continuing to review the RTEP planning cycles and the TEAC’s communications and processes, Fran Barrett told the Planning Committee.

Preliminary discussions are being held internally, but Barrett assured members that no action would be taken without being vetted by the stakeholder process.

Cross-departmental teams are mapping out current processes and identifying areas for improvement.

“We want to take a picture of today, project it to the future and you tell us what’s right about that picture and what needs to change,” said Barrett.

For example, he said, while some stakeholders do business within PJM only, others are involved in transmission planning projects in other RTOs as well. One idea: provide members an ESPN SportsCenter-like “highlights reel” from various RTOs’ planning committees.

“We’re trying to improve workflow and do it more efficiently,” said Barrett. (See “PJM Starts Process of Redesigning TEAC,” PJM Planning Committee and TEAC Briefs.)

— Suzanne Herel