Page 1423 – RTO Insider

July 18, 2016

FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence

By Rich Heidorn Jr. and Tom Kleckner

SPP executives had “inappropriate” involvement in the oversight of its Market Monitoring Unit, FERC said in an audit report released Friday that called for changes (PA15-6).

The report said the internal MMU “should strengthen its independence and enhance its separation from” the RTO by barring non-MMU employees from its office and RTO management from its meetings with the Board of Directors’ Oversight Committee.

The audit report raised many of the concerns reported by RTO Insider in a series of articles earlier this year, citing SPP executives’ involvement in the MMU’s budget, performance reviews and salary decisions. The audit also said the MMU’s independence was hampered by the fact that until recently it shared legal counsel with the RTO.

Auditors criticized MMU Director Alan McQueen — though not by name — saying he took actions that “blurred the lines” between the MMU and RTO.

It also said the Oversight Committee should undertake a “closer review of the performance of the MMU” and its director. “In complying with Order No. 719, one of the important steps taken by the MMU to ensure independence was when it structured its accountability process so that it reports directly to the Oversight Committee,” the auditors noted.

But the report did not address SPP’s treatment of former monitors Catherine Mooney and John Hyatt, who say they were fired for raising independence concerns. Nor did it mention their allegations that McQueen pressured them to compromise their positions in order to minimize conflicts with SPP management and stakeholders and that Oversight Committee Chairman Joshua W. Martin III refused to meet with them when they attempted to raise concerns. (See SPP Squelching MMU Independence, Former Monitors Say.)

The auditors said most of their 16 recommendations were already being addressed by the Oversight Committee’s revised December 2015 position statement on the MMU’s independence, which made the committee responsible for all salary and bonus decisions for McQueen and other MMU employees and ensured that the MMU director could meet with the committee in executive sessions without RTO officials present.

The committee approved the statement, which had last been updated in 2012, nine days after Hyatt and Mooney were fired. Martin announced the statement at the Board of Directors meeting in January — also announcing that McQueen would retire by the end of the year.

The audit did not call for replacing the internal unit with an independent monitor, noting FERC Order 719 allowed RTOs to choose their structure.

Aside from CAISO, SPP is the only regional grid operator that does not have an independent market monitor, and SPP officials indicated Friday they intend to keep that arrangement.

“We’re pleased the auditors found no instances in which SPP exerted inappropriate influence on the MMU,” SPP General Counsel Paul Suskie said in a statement. “Neither did FERC conclude the MMU is not independent, nor recommend that SPP’s market-monitoring functions be performed by a third party. As a result, SPP can continue to operate with an internal MMU, and MMU staff will be employees of SPP and participate in our collaborative stakeholder process while remaining independent.”

Joe Bowring, Independent Market Monitors Wouldn’t Have It Any Other Way.)

In a letter appended to the report, McQueen and Suskie agreed with all of the audit’s 16 recommendations, but challenged auditors’ repeated use of the terms “inappropriate” and “improperly.”

“SPP understands that, where the report discussed items that were inappropriate or improper, FERC audit staff is referring to processes, procedures and structures that could potentially result in inappropriate or improper conduct or that could demonstrate an appearance of impropriety,” they wrote. “No such activity took place.”

Suskie and McQueen said the audit was “a valuable process for SPP to assess the continued working relationship between [the] RTO and MMU given the evolution of SPP and its markers and services.”

The audit report was among the topics of conversation at Monday’s Regional State Committee meeting, where SPP CEO Nick Brown defended the RTO’s firing of Hyatt and Mooney. “No one is terminated from SPP without multiple officers concurring,” he said. “The board was very much informed, specifically the Oversight Committee. We were quite cautious, but very firm in our decision. I will say we were unanimous in our decision.”

FERC’s recommendations, Brown added, “really decrease the potential for any inappropriate influence over the independence of the Market Monitoring Unit.”

17-Month Inquiry

During the 17-month inquiry, auditors conducted three site visits and reviewed 30,000 emails of MMU and RTO employees “to understand communications between both groups, with outside parties and internal to the MMU and SPP RTO.”

Although the audit also looked at SPP’s compliance with its transmission-provider obligations, FERC accounting regulations and FERC Form 1 financial reporting requirements, it issued findings on the MMU only.

The auditors said that the independence and separation of function concerns they have regarding the MMU are “similar, in some respects,” to those identified in the commission’s 2008 audit of SPP’s Regional Entity, which is charged with enforcing NERC reliability standards (PA08-2, AD09-3).

RTO Executives at Oversight Committee Meetings

To ensure its independence from SPP management, the MMU is supposed to be under the control of the Board of Directors’ Oversight Committee. But the commission noted that until recently, RTO executives attended the MMU’s meetings with the committee.

“The presence of an SPP RTO executive in these meetings … could result in SPP RTO potentially exercising undue influence during such meetings and inappropriately having access to information associated with MMU operations,” the auditors said.

“Audit staff did not identify evidence of any impropriety in practice (nor has any such impropriety been alleged), and notes that the Oversight Committee can, and during the audit period did, conduct MMU-related meetings in executive session without the presence of the SPP RTO executive, when it deemed it appropriate. However, the presence of the SPP RTO executive in MMU-related executive sessions does not reflect the necessary separation of functions.”

In their letter, McQueen and Suskie acknowledged that the presence of RTO management at OC meetings “could give rise to the perception that there is an insufficient degree of separation between the MMU and SPP RTO.”

Incentive Compensation

The commission also said SPP executives “were inappropriately involved in the performance evaluation of the MMU director, approval of the MMU budget and compensation adjustments for MMU staff.”

“Audit staff is concerned that such involvement by SPP RTO executives creates issues in terms of using incentive compensation to exercise influence over MMU staff not to oppose SPP RTO initiatives,” FERC said.

“Rather than involving SPP RTO executives in the operations of the MMU, the audit staff determined that the Oversight Committee should take a more active role in its oversight of the MMU including performance evaluation of the MMU director as well as the overall performance of the MMU. This would be similar to the manner in which the SPP RE board provides guidance and oversight to the RE.”

The auditors said they met with the full Oversight Committee at its quarterly meeting at the beginning of the audit and later conducted several phone interviews with Chairman Martin. Martin told RTO Insider in an interview May 2 that he met with the auditors once, at the committee meeting in March 2015. He said it “was not an in-depth session where we were looking at specifics.” (See FERC Ended Audit Without Talking to Key Witness.)

Legal Counsel

Until March 2015 — after FERC began the audit — the MMU relied on SPP for legal services because it lacked its own counsel. “The MMU’s reliance on the SPP RTO for legal services and support could be problematic, particularly when the MMU disagreed with an SPP RTO position and desired to make a filing to the commission in opposition to an SPP RTO filing,” the report said. “Difficulties may arise both in terms of allocation of available legal staff as well as possible concerns of conflict of interest.”

RTO Insider reported that, until the last 18 months, the MMU generally filed only testimony packaged with RTO filings. (See SPP MMU Struggles to Find its Voice.)

MMU Shared Staff

The auditors said the lack of “clear separation” between the RTO and MMU staff also resulted from MMU staff’s involvement in RTO activities unrelated to MMU operations, particularly in 2013 and early 2014 when the RTO was racing to launch its Integrated Marketplace.

“This effectively blurred the lines of separation by making resources appear fungible,” the auditors said. “Moreover, SPP RTO rewarded MMU staff in the form of incentive compensation for their efforts on behalf of SPP RTO. This economic incentive further clouded the separation between the MMU and SPP RTO.”

MMU Involvement with Tariff Formation

The audit cited “tension … between the role of the MMU as an independent organization and the role of the MMU as an internal function of SPP, and therefore an integral part of its collaborative process.”

“Central to this tension are the concepts that, as SPP RTO employees, MMU staff should conduct themselves in a manner that promotes the interests of SPP RTO, while as members of the MMU the staff might be engaged in activities and take positions that run counter to what may be the consensus of the SPP members,” FERC said. “However, this inherent tension was latent until a contentious issue arose between the MMU and SPP RTO.”

The issue was the RTO’s attempt to mollify generators who became upset after the Integrated Marketplace opened that the MMU was not including general operations and maintenance in its calculations of cost-based offers. (See SPP MMU Struggles to Find its Voice.)

“At times, the MMU staff acted in a manner to steer the outcome rather than permitting the stakeholder process to arrive at a position that reflected their independent collaboration, consensus development and team-based approach,” FERC said. “It is incumbent on the MMU to advise the RTO and other interested parties of its views regarding any needed rule and tariff changes and the merits of proposed changes, but not to obstruct the SPP RTO’s process.

“The MMU should not disrupt the SPP process when tariff revisions are not acceptable to the MMU; rather, it should intervene when the proposal comes before the SPP board and when it is filed with the commission.”

The auditors criticized McQueen’s decision to join the Mitigated Offer Strike Team, which was created to reach a compromise.

“The MMU director wanted to restore a good working relationship, consistent with the SPP principle of being ‘relationship-based,’” the auditors said. “While the intent to improve relationships might be justified in general principle, audit staff believes that the MMU director’s efforts were counterproductive in this instance.”

Operational Separation

Auditors also raised concerns that the MMU staff works in offices accessible to RTO employees, most in open cubicles. “Audit staff observed that conversations can be overheard and sensitive materials visible to parties outside the MMU. Conversations by MMU staff members may involve discussions of matters such as ongoing investigations and potential referrals to the commission.”

SPP MMU ferc — SPP Headquarters *Source: WER Architects*

The commission said the MMU should consider erecting physical barriers and key card access to ensure the physical separation of MMU staff from other RTO staff, as the commission required in the RE audit.

McQueen and Suskie said the MMU lacks the resources to erect security barriers but said they are “looking into practical solutions” to address the concern.

Compliance Filings

The commission required the RTO to submit a compliance filing within 30 days detailing how it plans to respond to the recommendations, along with quarterly status reports on its progress.

[Editor’s Note: SPP/ERCOT Correspondent Tom Kleckner worked as an SPP spokesman from 2011 to 2015; Editor-in-Chief Rich Heidorn Jr. participated in the 2008 audit of SPP as a member of FERC’s Office of Enforcement.]

July 18, 2016

Panel: New England Will Meet CPP Goals Regardless of Court Outcome

By William Opalka

MARLBOROUGH, Mass. — New England states are moving ahead with their own greenhouse gas reduction programs while EPA’s Clean Power Plan remains in legal limbo.

At the Northeast Energy and Commerce Association Annual Environmental Conference on Wednesday, panelists said that the nine-state Regional Greenhouse Gas Initiative remains on course despite the U.S. Supreme Court’s decision in February to stay the federal plan pending legal challenges.

“We don’t have much in the way of travel to reach the Clean Power Plan targets under the current design of the final rule,” said Patricio Silva, a senior system planning analyst at ISO-NE. (See Northeast on Way to Compliance with Clean Power Plan.)

NECA environmental conference — NECA Environmental Conference © *RTO Insider*

RGGI, which EPA has cited as a model, is currently committed to a 2.5% annual reduction in carbon emissions. But it undergoes program reviews every three years — including one now in progress — that could adjust targets.

The CPP seeks to reduce carbon emissions from the power sector by 32% below 2005 levels by 2030, with interim reductions required in 2022-2029.

new england, clean power plan (cpp), greenhouse gas — Silva © *RTO Insider*

While simple cycle gas turbines are exempt from the CPP, RGGI also includes all fossil units above 25 MW. EPA did not include simple cycle — or peaker — plants, reasoning that they run too infrequently to have a major impact on emission reductions. “That is an important distinction,” Silva said, calling it a sign of the RGGI states’ more aggressive carbon reduction goals.

According to the Energy Information Administration, ISO-NE’s carbon intensity was 1,037 pounds of CO₂/MWh in 2015, which is projected to drop to 986 lbs/MWh by 2030, well within the CPP targets (1,305 lbs/MWh for existing fossil fuel-fired electric steam generating units and 771 lbs/MWh for existing natural gas combined cycle units), Silva said.

CPP Arguments in September

Carrie-Jenks-web — Jenks © *RTO Insider*

While the Supreme Court is likely to determine the CPP’s ultimate fate, the legal challenge is currently before the D.C. Circuit Court of Appeals (West Virginia v. EPA, No. 15-1363). In May, the D.C. Circuit rescheduled oral arguments from June 2 to Sept. 27, 2016, skipping an initial review by a three-judge panel and moving directly to an en banc hearing with nine of the circuit’s 11 active judges.

Carrie Jenks, a senior analyst with M.J. Bradley and Associates, said that while the CPP legal challenge may affect some states’ planning, the RGGI states have continued to plan for compliance, leading to key questions.

“RGGI [has to] decide if it would trade with states outside of its region, such as other PJM states, either at the start of the program or at a future date. RGGI states also need to consider what the CPP targets mean for the overall RGGI cap as the states undertake the RGGI program review, and how will such decisions may affect states outside of RGGI,” she said.

Seidman © RTO Insider - new england, clean power plan (cpp), greenhouse gas — Seidman © *RTO Insider*

Nancy Seidman, assistant commissioner at the Massachusetts Department of Environmental Protection, credited EPA for recognizing the emission reductions achieved by the RGGI states. “We’ve done a lot and fortunately EPA considered that,” she said.

“What’s important now is, where do we want to go next? What are our goals for 2030 with or without the Clean Power Plan? And how does that mesh with states’ individual goals?” she said.

July 18, 2016

SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections

By Tom Kleckner

RAPID CITY, S.D. — SPP’s first competitive project under FERC Order 1000, approved by the Board of Directors with some fanfare in April, is being canceled because of falling load projections.

The Markets and Operations Policy Committee last week accepted staff’s recommendation to withdraw the project’s notice-to-construct. The 22.6-mile 115-kV line from Walkemeyer to North Liberal in southwest Kansas was awarded to Mid-Kansas Electric. The board is expected to finalize the decision when it meets next week. (See SPP Awards First Order 1000 Project — But it May Not Be Needed.)

SPP Transmission FERC Order 1000 Demand Projections — Walkemeyer Project Diagram *Source: SPP*

Al Tamimi, vice president of transmission planning and policy for Sunflower Electric Power, which operates Mid-Kansas, said the line was no longer needed because of a drop in forecasted loads from oil and gas exploration. Mid-Kansas officials said they had seen a 27% slide in load forecasts within the project’s region since the initial study was done three years ago.

Mid-Kansas asked SPP to re-evaluate the need for the transmission line when it won the construction bid in April. Staff’s analysis indicated the area’s load projections had dropped from 173 MW to 25 MW. Even when the project is removed from the planning models, staff found there would be no thermal or voltage violations until 2070.

The Walkemeyer project’s noncompetitive first phase, a new 345/115-kV substation and transformer and a 1-mile line to the Walkemeyer 115-kV station, will still be built.

The transmission line “was very dependent on the highest load forecast. We told you this 14, 15 months ago,” Tamimi said. “I don’t care whether it’s a FERC 1000 project or not, if the load is not there, why am I going to do” the project?

Mid-Kansas’ bid was chosen from 11 evaluated by a panel of industry experts, who were compensated for their time.

Millions Wasted?

Bob Burner, director of commercial transmission development for Duke Energy, questioned why SPP issued the solicitation, noting Mid-Kansas’ re-evaluation request came after bidders “had gone through the effort and expense to submit proposals to the [request for proposals], probably at the expense of hundreds of thousands of dollars.”

“Millions,” murmured one stakeholder.

“Developers in a project do accept reasonable risk,” Burner said. “I don’t know the solution, but there has to be something better than what we just went through.”

“I understand that as a participant in this process, I participate at some cost,” Westar Energy’s John Olsen said. “Maybe we can reimburse minimal costs in the future to those who participated in that solicitation.”

Southwestern Public Service’s Bill Grant, chair of the Competitive Transmission Process Task Force, said his group will seek improvements to the competitive process in their future meetings.

“This is a difficult conversation that needs to happen. We will look at whether we can reimburse participants,” Grant said. “Maybe there was a point where we could have raised a caution flag before going through the rest of the process. I don’t know that FERC will allow us to pass those costs on to customers.”

Other Projects

The MOPC also accepted staff’s recommendation to withdraw an NTC for a 115-kV reactor and approve a rebuild of a 138-kV line near Shreveport, La. Staff indicated the reactor would no longer be needed before its break-even point, and that rebuilding the Linwood-South Shreveport line would save $3.55 million without the reactor. American Electric Power will build the project.

However, members rejected a recommendation to replace a 115-kV line in western North Dakota with a 345-kV line as part of SPP’s re-evaluations of the 2016 Integrated Transmission Planning Near-Term assessment.

Basin Electric Power Cooperative requested a re-evaluation of its planned 33-mile transmission line between a pair of substations because of what it called inaccurate models and siting difficulties. Staff recommended replacing the original 115-kV project with a 345-kV line to address a nearby load pocket, but it failed on a roll call vote.

A follow-up motion to approve the 345-kV line, but operate it at 115 kV, was also rejected. The 345-kV project is estimated to cost $63.6 million, the other $50.9 million.

Members did approve a staff recommendation to issue three NTCs and withdraw two NTCs for projects deferred in April, all part of the 2016 ITPNT portfolio.

The withdrawn NTCs included AEP’s 69-kV rebuild in West Texas, estimated to cost $31 million, and Westar’s new 230-kV substation and transformer in Kansas, pegged at $21.7 million. AEP did get NTCs for a pair of 69-kV line rebuilds in West Texas, projected to cost a combined $10.4 million, while SPS received an NTC for a 115-kV line, substation and transformer at $11.6 million.

The MOPC also unanimously approved staff’s recommendation to re-set the baseline cost for a pair of projects outside the bandwidth. A Westar 69-kV rebuild and a Mid-Kansas 138-kV line are both more than 20% under budget.

July 18, 2016

MISO Duff-Coleman RFP Deadline Passes; RTO Reviewing Bids

MISO closed its request for proposals on the Duff-Coleman 345-kV transmission project in Southern Indiana on July 6, saying it was pleased with the response.

Priti Patel, MISO North regional executive, said MISO was satisfied with the “robust” number of proposals on its first competitively bid project, but she didn’t disclose the number of proposals received or which developers submitted them. Patel said the RTO will post the list of developers that submitted complete proposals by Aug. 19. In the meantime, proposals are under review to determine their eligibility. Forty-eight developers qualified to submit bids to MISO.

“The broad interest from transmission developers demonstrates confidence in MISO’s competitive processes,” Patel said in a statement.

Per its original timeline, MISO expects to announce its transmission developer pick on the $67.4 million project by Dec. 30. The RFP window opened in January for the work, which includes the construction of two substations and a 28.5-mile line linking them. (See MISO Seeks Bids on Duff-Coleman Project.)

— Amanda Durish Cook

July 18, 2016

Berkshire Contests Market-Based Sales Restriction in West

By Robert Mullin

Berkshire Hathaway Energy is contesting FERC’s June decision to revoke the ability of the company’s subsidiaries to sell power at market-based rates in four neighboring balancing authority areas in the West.

The commission’s June 9 order prohibited Berkshire-owned utilities PacifiCorp and NV Energy — as well as 19 other affiliates — from offering power at market rates in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern areas based on concerns about horizontal market power. (See Berkshire Market-Based Rate Sales Restricted in 4 BAAs.)

In a request for rehearing and clarification filed July 11, Berkshire argued that the commission failed to make a “definitive finding” that the company possesses market power in the four regions before revoking market-based rate authority, as required under FERC Order 697 (ER10-2475).

“[The commission] did not provide sound reasoning, nor did it show a path to how it arrived at its decision,” the company said. “But, nonetheless, the commission moved ahead and revoked market-based rate authority and imposed cost-based rates.”

‘Moving Target’

Berkshire contended that it was denied due process after FERC failed to notify the company of the commission’s “newly announced standards for determining market power” ahead of the company’s initial “change in status” filing — standards it said the commission “articulated for the first time” in the June 9 ruling.

The company’s utilities “have repeatedly demonstrated their willingness to comply with any guidance that the commission has provided,” Berkshire said. “They should not be penalized for failing to hit a constantly moving target.”

Berkshire also sought clarification on whether its affiliates can use their own “case-specific” cost-based rates for sales in the four areas, or must rely on the commission’s default cost-based rates — requesting rehearing if it is the latter.

The June ruling stemmed from Berkshire’s 2013 acquisition of NV Energy, which put Warren Buffett’s conglomerate in control of 19 GW of generating capacity in the West — enough capacity to fail the “pivotal supplier” and “wholesale market share” indicative screens for market power in the four areas.

Delivered Price Test

Generation owners that fail the screens can disprove the presumption of market power by performing a more thorough delivered price test (DPT). The DPT factors in the native load commitments and generating capacity of all suppliers in a region in order to determine each supplier’s “available economic capacity” over 10 different seasons and load conditions.

The commission ruled that the DPT analysis submitted by the Berkshire companies was insufficient to rebut the presumption of market power, having failed to include “inputs, assumptions and facts appropriate to the unique characteristics of each balancing authority area when studying that particular area.”

The ruling pointed to an instance in which Berkshire’s analysis erroneously listed Idaho Power as a competing supplier during periods when that utility would “likely not” be positioned to provide competition.

Berkshire countered the finding that its tests were unreliable, saying that each of its 57 “unique” DPT analyses “was prepared in accordance with the commission’s previously announced requirements and each was similar in form and substance to” analyses the commission had previously approved.

FERC identified five alleged deficiencies in the tests, the company said.

“On that basis [the commission] concluded that ‘we are unable to validate the results of the [Berkshire companies’] DPT analysis and are unable to rely on the DPT analysis,’” Berkshire said.

Berkshire also questioned the commission’s use of its own “undisclosed analyses using alternative assumptions or data that yielded different results than those provided by” the company, saying that the commission failed to include the results of those analyses in the proceeding.

The company further contended that the “purported deficiencies” in the DPTs were the “sole basis” for the commission revoking market-based rate authority, rather than any alternative analyses or evidence submitted by intervenors or the commission itself.

“By its own admission, the commission’s decision was not ‘based on the results of the DPTs’ and does not purport to have made any finding based on the DPT results or any other substantial evidence that the [Berkshire companies] have market power in any of the mitigated markets,” the company said.

July 18, 2016

FERC Orders Investigation of Logging on Pipeline Route

By William Opalka

FERC on Wednesday directed staff to begin an investigation of alleged illegal tree-cutting along the New York section of the Constitution Pipeline route despite a finding that state officials’ demands for a stay and sanctions were “procedurally deficient” (CP13-499).

The order was in response to New York Attorney General Eric Schneiderman’s complaint in May that the pipeline’s developers allowed tree-cutting in defiance of a FERC prohibition in New York. Constitution denied the allegations and asked FERC to dismiss the complaint. (See Constitution Asks FERC to Dismiss New York Complaint.)

“While procedurally deficient as a complaint and petition, the May 13 filing may constitute a valid request for investigation,” FERC wrote. “Accordingly, the commission construes it as such and refers this matter to commission staff for further examination and inquiry as may be appropriate.”

Schneiderman alleged there is “a reasonable basis to conclude that Constitution expressly or tacitly authorized, encouraged and/or condoned the tree and vegetation cutting, clear-cutting and other ground disturbance activities” within the pipeline’s 99-mile right of way in New York. Tree cutting had been allowed by FERC in the approximately 25-mile section in Pennsylvania.

FERC said Schneiderman’s filing was deficient because it “does not include any specific facts to support such allegations, but instead relies upon speculation.”

The New York Department of Environmental Conservation in April denied a water quality permit, effectively stopping the project. Constitution has appealed in federal court. (See Constitution Pipeline Appeals Rejection of Water Permit.)

While ruling that the New York complaint was insufficient, FERC said that Constitution could “face potential sanctions” if it failed to comply with its regulations.

The pipeline, intended to bring Pennsylvania shale gas into New York and New England, is being developed by Williams Partners, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings. It received FERC approval in December 2014.

July 18, 2016

ERCOT Seeks Alternatives to Houston-Area RMR Unit

ERCOT is soliciting must-run alternatives (MRAs) to the reliability-must-run agreement it recently extended to NRG Texas Power’s Greens Bayou Unit 5 in the Houston area.

The Texas grid operator issued a notice to market participants July 13, saying it is seeking “lower-cost, effective alternatives” to the RMR agreement, its first in five years.

ERCOT in June executed the agreement through September to strengthen transmission stability in the Houston region. Its Board of Directors later extended the RMR through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)

ERCOT NRG greens bayou houston reliability must run agreements — Greens Bayou *Source: NRG*

Under the agreement’s terms, the 371-MW gas-powered unit must be available during summer months, between July 2016 through June 2018. ERCOT must pay $3,185/MWh year-round and an incentive factor of as much as 10% to reserve the unit’s capacity.

Qualified scheduling entities, representing generation and demand response resources, have until Aug. 24 to submit proposals. ERCOT says it will consider individual and aggregated options that provide reliability benefits comparable to the RMR unit, while providing cost savings.

ERCOT staff has said it expects that the $590 million Houston Import Project, scheduled to be completed by summer 2018, will help solve the area’s transmission concerns.

The ISO’s protocols authorize it to replace an RMR agreement with an MRA agreement if the MRA resource:

Provides an acceptable solution to the reliability concern the RMR unit currently addresses;
Provides at least $1 million in annual savings over the projected net annualized costs for the RMR unit; and
Satisfies objective financial criteria demonstrating that the MRA resource’s provider is reasonably able to fulfill its performance obligations.

– Tom Kleckner

July 18, 2016

Company Briefs

Using internal records, private emails and recorded conversations provided by a whistle-blower, The New York Times published a lengthy investigation July 5 into the delays and costs overruns at Southern Co.’s Kemper coal-gasification plant.

The Times found that the plant’s owners understated its costs and repeatedly tried to conceal its multitude of problems. Southern is under investigation by the Securities and Exchange Commission, and the Occupational Safety and Health Administration told the company in March that it violated federal whistle-blower protections when it fired Brett Wingo, an engineer who was the Times’ primary source for the article.

In response, Southern released a statement the same day as the article’s publication, calling Wingo’s claims “unsubstantiated” and insisting that the newspaper took quotes from recordings out of context. “Rather than educate readers on the worldwide benefits of this cutting-edge, first-of-its-kind facility, today’s New York Times article on the Kemper project provides a negative recap of previously disclosed developments that have already been addressed,” the company said.

More: The New York Times; Southern Co.

Duke Increases its Quarterly Dividend

Duke Energy increased the quarterly dividend payment on its common stock by 3.6%, payable Sept. 16.

The dividend was set at $0.855/share, an increase of $0.03.

“For 90 consecutive years, Duke Energy’s dividend has been as reliable as the energy we provide,” CEO Lynn Good said.

More: Duke Energy

Ameren Asks for Rate Increase, 7th in a Decade

Ameren Ameren filed for a $206 million rate increase with Missouri regulators in early July, the seventh request for a rate review in a decade. A final determination is due at the end of May 2017.

The company says the increase equates to an average 7.8% rate boost for consumers. Missouri’s Office of Public Counsel says the increase is actually closer to 8.3% for residential customers, who will bear more of the cost burden than other customer classifications.

Warren Wood, Ameren Missouri’s vice president of external affairs and communication, said the increase serves to recoup some of the $1.4 billion in investments the company made since its $122 million rate increase two years ago. He also said the company is also coping with the bankruptcy of Noranda Aluminum smelter, its largest consumer.

More: St. Louis Post-Dispatch

Cube Hydro Buys 215 MW of NC Hydro

Cube Hydro Partners said it will buy and upgrade four hydropower units along North Carolina’s Yadkin River from Alcoa Power Generating, a subsidiary of aluminum smelter Alcoa. The transaction, for an undisclosed sum, will add 215 MW to Cube’s current 126-MW portfolio.

Alcoa developed and operated the four hydro units along a 38-mile stretch of the Yadkin for nearly 100 years as part of its aluminum smelting operation at Badin Works. Alcoa closed the plant in 2010.

Cube, based in Bethesda, Md., currently owns and operates 14 hydro plants in New York, Pennsylvania, Virginia and West Virginia.

More: Salisbury Post

Duke Providing $1.5M for EV Charging Ports in NC

Duke Energy announced last week that it is providing North Carolina municipalities subsidies to help construct electric vehicle charging stations. The company said it would provide $1 million for EV charging stations and $500,000 for electric bus stations.

The company said that would increase by 30% the number of charging stations throughout the state, where it said there are currently about 700 stations operating and about 4,700 plug-in EVs registered.

“Over the past decade, Duke Energy has supported the development of several hundred electric vehicle charging stations in North Carolina,” said David Fountain, Duke’s North Carolina president. “Adoption of EVs depends on a robust infrastructure for consumers.”

More: Duke Energy

Duke’s Solar Farm on Ind. Naval Base Gets Nod

The Indiana Utility Regulatory Commission has given final approval to Duke Energy’s proposed 17-MW solar farm on a naval base.

The 76,000-panel project will be situated on 145 acres at the Crane naval station in southwestern Indiana and begin selling power early next year. The project, the second solar installation partnership between Duke and the Navy, would be the second-largest solar plant in the state.

More: Charlotte Business Journal

Duke Consolidates Renewable, Distributed Energy Divisions

Duke Energy consolidated its renewables and distributed energy businesses following the departure of 14-year veteran Greg Wolf, president of its Commercial Portfolio unit.

The Commercial Portfolio, which oversees Duke Energy Renewables, will be combined with its Distributed Energy Resources wing, now headed by Rob Caldwell.

Caldwell, an 18-year Duke veteran, will become president of the new division: Duke Energy Renewables and Distributed Energy Technology. Some functions of the old divisions will be pooled, while others will remain separate, according to the company.

More: Charlotte Business Journal

Westar Shareholders Allege Execs Undervalued Company

A group of Westar Energy stockholders has filed a class action suit in Kansas alleging that executives undervalued the company in its $12.2 billion sale to Great Plains Energy in May.

Under the sale agreement, shareholders will get $60/share: $51 in cash and $9 worth of Great Plains stock. The plaintiffs, however, think that is too cheap. They say that Westar’s stock price rose 55% in the year before the sale, but the $60/share total offered shareholders is only a 13% increase.

“Westar stockholders, who stand to receive a portion of the merger consideration in Great Plains stock, will also be burdened with the onerous debt Great Plains will be taking on,” according to the lawsuit. “The proposed transaction will almost triple Great Plains’ debt.”

More: The Topeka Capital-Journal

NextEra Subsidiary Begins Construction on Wind Farm

Kingman Wind Energy has signed a $26.4 million agreement with Kansas’ Kingman County to begin construction on a 200-MW wind farm later this year.

Kingman is a subsidiary of NextEra Energy Capital Holdings, and it has a 20-year contract to sell the power to Westar Energy. The agreement was signed late last month.

More: The Wichita Eagle

EDF Sells Half its Stake In Kansas Wind Farm

EDF Renewable Energy said last week it has sold half of its Slate Creek Wind Project in Kansas to a consortium led by Axium Infrastructure. EDF will continue to own the other half and provide part of the operations and maintenance.

The 150-MW project began operations in December. Its power is sold to Kansas City Power & Light on a 20-year, fixed-price power purchase agreement.

More: The Wichita Eagle

KCP&L Opens 1st Solar Plant, Producing 4,700 MWh Annually

Kansas City Power & Light last week opened its first commercial-scale solar power facility, capable of generating more than 4,700 MWh of energy annually. The 12-acre plant has 11,500 solar panels at KCP&L’s Greenwood Energy Center, south of Kansas City.

“Solar technology is constantly getting better and more efficient,” said Chuck Caisley, KCP&L’s vice president for marketing and public affairs. “We are investing in solar because of its relatively quick construction and our commitment to a sustainable future.”

More: The Kansas City Star

Dominion Wins Smart Grid Tech Patent Suit

Alstom Grid infringed on a patent for energy efficiency technology used in Dominion Resources’ “Edge” products, a federal jury found, awarding $489,000 to subsidiary Dominion Voltage.

The company uses the app in substations to stabilize and slightly reduce voltage in areas where smart meters are installed, resulting in lower electricity bills. The software is used by 12 U.S. utilities.

The ruling, out of the U.S. District Court for the Eastern District of Pennsylvania, said Alstom had willfully violated the patent and convinced one of its utility customers to use it.

More: Richmond Times-Dispatch

JCP&L Completes $48M Transmission Upgrade

Jersey Central Power & Light has finished the last phase of a $48 million transmission project to bolster reliability for customers in the New Jersey counties of Mercer, Middlesex and Monmouth.

The project involved constructing a new 8-mile, 115-kV transmission line and upgrading an existing 230-kV line along a 3.5-mile right of way.

The utility installed more than 200 new wood utility poles, five new steel monopoles and more than 174,000 feet of new wires. A new transformer and circuit breaker upgrades also were installed at the substation in Highstown.

More: FirstEnergy

KCP&L Files for 7.5% Rate Increase with Missouri PSC

Kansas City Power & Light has filed a 7.5% rate increase request with the Missouri Public Service Commission. If approved, the increase would go into effect in April 2017.

KCP&L said in a news release the request is “needed to recover money spent upgrading the company’s infrastructure, adding regional transmission lines and complying with environmental and cybersecurity mandates.” The average customer’s bill would increase by $9/month.

The increase will affect customers in the KCP&L Missouri service area, which encompasses the Kansas City area. KCP&L asked for an 8.2% rate increase in February for a different territory in Missouri previously served by Aquila before its 2008 acquisition.

More: The Kansas City Star

Hawaii PUC Rejects NextEra-HEI Deal

The Hawaii Public Utilities Commission rejected NextEra Energy’s $4.3 billion takeover of Hawaiian Electric Industries, finding that the deal was not in the public interest.

The companies have elected not to challenge the decision in court, and NextEra will pay HEI $95 million in break-up fees.

The PUC said the companies failed to demonstrate benefits for Hawaii residents and a commitment to the state’s clean energy goals. The commission voted 2-0 to reject the deal. Commissioner Thomas Morak, recently appointed by Gov. David Ige to replace outgoing Commissioner Michael Champley, abstained from voting, but he said he supported the commission’s decision.

More: Honolulu Star-Advertiser

July 18, 2016

SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill

By Tom Kleckner

RAPID CITY, S.D. — More than five hours of presentations and stakeholder discussions over two days last week did little to resolve SPP’s albatross of Z2 credits, but they did potentially add more than four years to the crediting project’s timeline and increase the possibility that it will result in litigation.

Faced with an approximate bill of $848.8 million for 158 creditable transmission upgrade projects over the last 10 years (up from last summer’s staff estimate of $750 million), the Markets and Operations Policy Committee voted to give companies five years to pay off their Z2 bills, up from the 10 months approved by the Board of Directors in April. (See “Board Approves Z2 Level Payment Plan,” SPP Board of Directors Briefs.)

The board will take up the recommendation during its quarterly meeting next week. If approved, the change will require a filing at FERC.

The MOPC also rejected all five requests from the so-called Group B members — American Electric Power, the City of Chanute, Kan., Golden Spread Electric Cooperative, Kansas Electric Power Cooperative (KEPCO) and Westar Energy — to have their $42.6 million in charges allocated to the base plan and included in regional and zonal charges under SPP’s Tariff, rather than being directly assigned to the companies.

Still unclear is when the amounts owed and due become final, how to handle sponsoring customers who are no longer customers and what happens when companies go to state regulators to recover their costs.

‘Lawyered Up’

McAuley © RTO Insider — McAuley *© RTO Insider*

Dogwood Energy’s Rob Janssen suggested members were flying blind and said they should take a “rational” look at their options before going to FERC.

“No one knows the real impact of voting to transfer funds when we don’t know what the funds are. We need more facts on the table,” he said. “I don’t know if everyone is lawyered up enough to understand the implications, but I strongly suggest everyone do so before the next board meeting.”

“I feel like now that the numbers are higher than some people expected, they want to change the rules of the game,” said Greg McAuley of Oklahoma Gas & Electric. “I don’t think that’s the right way to do business.”

“We’re likely headed to a complaint at FERC because of the magnitude of the [Z2] numbers,” SPP CEO Nick Brown told the Regional State Committee on Monday. “The last thing I want to do is spend an inordinate amount of time before an administrative law judge in D.C.”

The Group B waiver requests were deferred by the MOPC, the board and the Cost Allocation Working Group in June. At the same time, those groups approved the Group A waiver requests to allocate their $56.4 million in obligations to the base plan. (See SPP Z2 Project Faces Further Hurdles, Possible Delay.)

Group A members — AEP, Arkansas Electric Cooperative Corp., the Northeast Texas Electric Cooperative and the Oklahoma Municipal Power Authority — are point-to-point transmission customers with Z2 obligations whose waiver requests were endorsed by SPP staff. Group B members are transmission customers that SPP said didn’t qualify for waivers, and Group C are those who didn’t request waivers.

McAuley grew visibly irritated as the discussion over Z2 waivers wore on. The OG&E settlement zone’s base-plan funding obligation of $31.7 million dwarfs every other zone, except AEP’s $29.9 million, and the company is waiting to learn its customers’ point-to-point claw-backs and credits for sponsored projects.

Grant © RTO Insider — Grant *© RTO Insider*

“We have retail customers who have waited patiently to be paid. Now, all of a sudden, we’re being told, ‘No, it’s too much,’” McAuley said. “We voted on how we were going to deal with the issue. People had expectations, and now we’re going to change it again. Everyone’s been impacted by this one way or the other, but now it’s time to settle accounts.”

“I raised the issue before that we were putting the payment plan in before we knew the impacts,” said Bill Grant, whose Southwestern Public Service’s zone faces a $10.4 million obligation. “SPP has some ownership in this, because they said this wasn’t going to be a big amount. Now we have some numbers and they’re not small. I think a lot of the people in this room would vote differently now. It is a pretty substantial number to some zones, and to some zones, that’s a pretty substantial number to recover for our customers.”

‘But For’

Ross © RTO Insider — Ross © *RTO Insider*

Attachment Z2 of SPP’s Tariff details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP has struggled for years to perform a proper accounting of the bills and credits and who owes what to whom.

AEP’s Richard Ross opened the second day of the MOPC discussion Wednesday by proposing the payment plan’s extension to five years.

Ross also proposed waiving all of Group B and Group C’s directly assigned upgrade costs, but that motion was rejected in a separate roll-call vote.

“You’re going to think I’m up to something, but the most important thing is that top line … spreading things out over five years,” Ross said, pointing to the language on the projector screen. “The second thing is, whatever we do, my customers will pay the same. I fear this will end up in FERC or the courts or somewhere. … I’m not interested in that.”

“If we can agree on this, I’d like to encourage we get behind this and have no further delays,” Grant said. “Let’s get this filed [at FERC], so we can have certainty around the issue. This has gone on way too long. It’s a concern for people who owe money, it’s a concern for people owed money. Our major concern is the impact to customers, and this five-year plan helps us address it.”

Staff assured members that interest on the debts would only apply to the initial balance and not accrue during the five-year payment plan. (Members can still choose to pay everything up front.) The revised payment plan cleared the MOPC with four votes in opposition and five abstentions.

The committee then rejected five individual waiver requests by either voice or roll-call votes. KEPCO argued unsuccessfully to have $6.1 million in revenue credits applied to the base plan, saying four service requests ranging between 7 MW and 25 MW should not have been aggregated together. As a result of the aggregation, KEPCO exceeded the Tariff’s resource-load ratio rule — limiting customers’ transmission service requests to 125% of their projected system-peak responsibility.

Evans © RTO Insider — Evans *© RTO Insider*

“If you apply the Tariff the way we interpret it, we don’t believe we exceeded our 125% limit,” KEPCO COO Les Evans said.

Midwest Energy’s Bill Dowling noted FERC distinguishes between discrimination and undue discrimination. “The Tariff discriminates between parties who are not similarly situated,” he said. “I consistently got the message from SPP [that] you can’t change something after the fact because you didn’t like the way it turned out. If we [grant the request], we’re sort of opening the door to other requests.”

KEPCO’s waiver request failed to come close to the 67% threshold, not even clearing 50% in positive votes. The four requests that followed — from AEP, Chanute, Golden Spread and Westar Energy — all met the same fate.

The rejections did not faze Westar’s John Olsen when his company’s time came up. Asked whether he wanted to proceed with a vote after having seen the previous results, Olsen sighed with resignation, “Oh, hell yes. Why not?”

“I continue to reflect on how can we do business this way based on what’s happened here this morning,” said McAuley, who opposed all five requests.

“We all have FERC attorneys. My suggestion is pay your FERC attorney and go to FERC and solve this,” OG&E’s Jake Langthorn told members. “If we want to come up with a fix to the Tariff, it’s going to take a lot more work than we can do this morning.”

FERC Ruling

The lawyers have already been active.

Ross’ proposal was made possible by FERC’s July 7 approval of an SPP request to waive the one-year limit for adjusting payment obligations and revenue distributions (ER16-1341). SPP’s request drew at least 18 protests or interventions.

FERC’s order also allowed transmission customers to request exemptions on safe-harbor cost limits.

“We note that it has been eight years since the commission accepted SPP’s Tariff provisions to implement revenue crediting. In the intervening years, SPP has experienced multiple delays in implementing the crediting Tariff provisions,” FERC said.

“Upgrade sponsors who have been negatively affected by SPP’s delay will finally, through this order, get the appropriate relief. We remind SPP of the need for transparency and timeliness when implementing commission-accepted Tariff provisions, especially in matters that so directly impact market participants and customers and are completely under the control of SPP.”

Project Progressing

The Z2 crediting project itself is progressing. The software system is partially complete and scheduled to deliver revenue crediting reports in September.

OG&E’s David Kays, chairman of the Regional Tariff Working Group, told the committee that staff has completed the historical calculations for long-term credit obligations for network service. He said base-plan funding adjustments and detailed settlements for historical data are still underway.

The final historical results are scheduled to be available for stakeholder review prior to the quarterly MOPC and board meetings in October, with the Z2 settlement invoices expected in early November.

“Everything seems to be trending along in a manner that is anticipated,” Kays said.

As the two-day conversation devolved into the minutia of the Z2 calculations, transmission-service and point-to-point requests, rate schedules, claw-backs and threshold limits, an exasperated Paul Malone of the Nebraska Public Power District almost threw his hands up in surrender.

“I need a program,” the MOPC vice chairman said. “I feel like I’m in a game of cricket, and I don’t know any of the rules.”

MOPC Chairman Noman Williams, of South Central MCN, was sympathetic.

“I want to thank everyone for wandering through the mud here,” he said as he closed the agenda item. “I guess it could have been done differently, but it had to be done.”

July 18, 2016

Utah Bill Would Require Legislative OK for PacifiCorp RTO Membership

By Robert Mullin

Utah lawmakers plan to draft a bill requiring PacifiCorp to gain legislative approval before joining an RTO based on an expanded CAISO.

Members of the Public Utilities, Energy, and Technology Interim Committee approved a motion to create the proposed law July 13 after listening to more than 90 minutes of testimony from power industry participants — most of whom were wary about the state’s participation in a regional integration effort driven by California.

Specific terms of the legislation were left unclear.

Utah sits squarely inside the PacifiCorp East (PACE) balancing authority area, which also extends into portions of Idaho and Wyoming. It is served by PacifiCorp’s Salt Lake City-based Rocky Mountain Power subsidiary.

Western Interconnection Balancing Authorities (WECC) - pacificorp rto membership utah legislation — The entire state of Utah is contained within the PacifiCorp East (PACE) balancing authority area, which the utility hopes will become part of an expanded CAISO.

“This potential issue is significant from both a policy perspective and a financial perspective,” said Thad LeVar, chair of the Utah Public Service Commission.

LeVar noted that PacifiCorp must go before his agency for a ruling once it makes a determination to join an expanded regional grid. The decision “shouldn’t fall solely to the regulatory arena without some guidance from the legislators in the state,” he said.

Governor Skeptical

Laura Nelson, director of Gov. Gary Herbert’s Office of Energy Development, said the office was skeptical about an RTO but still engaged in the process related to its development.

“Our consistent message has been that any participation in the [CAISO] must protect Utah’s long-term interest and authority over its power system,” Nelson said, citing the state’s role in protecting ratepayers, maintaining system reliability and choosing the generating resource mix.

Nelson told the committee that the state needs to perform an “exhaustive” study to determine if PacifiCorp’s membership is in the best interest of ratepayers. “Any recommendations about joining CAISO are not yet fully informed,” she said.

Ratepayer protections were foremost among the concerns of Michele Beck, director of the state’s Office of Consumer Services. While Beck acknowledged that there are technical benefits to participating in a more centrally operated grid, she questioned who would enjoy them.

“Do the benefits accrue to customers, or will they accrue to just select elements within the industry?” she said. “Are the benefits reasonably distributed across the footprint? Are the modeled benefits durable?”

She said that membership in an expanded CAISO should be conditioned on a demonstration that it has greater benefits than the Western Energy Imbalance Market, in which PacifiCorp currently participates.

“We’re struggling to document that all the benefits of the EIM that have been stated and have been published have been realized,” Nelson said.

Chris Parker, director of Utah’s Division of Public Utilities, said he was concerned about risks as well as benefits — namely the state’s risk in giving up control over its utilities to an RTO, whose backstop authority would be FERC.

Fear of California Dominance

Parker also cited the risk of an RTO being dominated by California interests, saying his agency would seek assurances that policy changes would require the unanimous support of participating states. He said CAISO’s latest RTO governance proposal — which would initially provide California with numerical voting superiority — was unacceptable. (See Governance Plan Fails to Dispel Western RTO Concerns.)

Rocky Mountain Power CEO Cindy Crane called the development of an independent governing structure a “threshold” issue for her company in its decision to participate in an expanded CAISO.

“What we are not doing is joining the California ISO,” Crane said. “We are working to transform an existing operating entity into something that could be a regional operating entity.”

Crane said the requirement that an RTO deliver “risk-balanced” net benefits to PacifiCorp customers in each of its six states was a second condition for the utility.

“If it’s not going to deliver benefits for our customers, there is no reason for us to advance,” she said, adding that regulators in each PacifiCorp state will have the authority to decide whether the utility joins.

Watching California’s Legislature

A few witnesses testifying before the committee said the fate of a Western RTO is now in the hands of California lawmakers, which are slated to begin considering legislation in August that would loosen the state’s authority over CAISO.

“We’re at the point where we’re waiting to see what the California legislature is willing to give up,” said Parker, referring to the concerns about California’s dominance in a governing structure. “If they’re willing to give up enough, then it may be worth it.”