In a widely anticipated report, EPA said yesterday that fracking has harmed drinking water resources under some circumstances but that data gaps have made it impossible to quantify the scope of the problem.
The agency said it identified cases of impacts on drinking water at each stage in the fracking water cycle: acquiring water for use in fracking; mixing the water with chemical additives; injecting the water and chemicals into the production well to create and increase fractures; collecting wastewater after injection; and disposing or reusing wastewater.
General timeline and summary of activities at a hydraulically fractured oil or gas production well | EPA
“Impacts cited in the report generally occurred near hydraulically fractured oil and gas production wells and ranged in severity, from temporary changes in water quality to contamination that made private drinking water wells unusable,” EPA said.
The report identifies conditions under which impacts can be more frequent or severe, including:
Water withdrawals in times or areas of low water availability, particularly areas with limited or declining groundwater;
Spills of fracking fluids or wastewater involving large volumes or high concentrations of chemicals reaching groundwater;
Injections into wells whose steel casing or cement lacked “mechanical integrity,” allowing gases or liquids to escape;
Injections directly into groundwater resources;
Discharge of inadequately treated wastewater to surface water resources; and
Disposal or storage of wastewater in unlined pits.
“This assessment is the most complete compilation to date of national scientific data on the relationship of drinking water resources and hydraulic fracturing,” Dr. Thomas A. Burke, deputy assistant administrator of EPA’s Office of Research and Development, said in a statement.
Generalized depiction of factors that influence whether spilled hydraulic fracturing fluids or additives reach drinking water resources, including spill characteristics, environmental fate and transport, and spill response activities | EPA
EPA said, however, the report “was not designed to be a list of documented impacts.”
“Data gaps and uncertainties limited EPA’s ability to fully assess the potential impacts on drinking water resources both locally and nationally. Generally, comprehensive information on the location of activities in the hydraulic fracturing water cycle is lacking, either because it is not collected, not publicly available, or prohibitively difficult to aggregate,” the agency said. “In places where we know activities in the hydraulic fracturing water cycle have occurred, data that could be used to characterize hydraulic fracturing-related chemicals in the environment before, during and after hydraulic fracturing were scarce. Because of these data gaps and uncertainties, as well as others described in the assessment, it was not possible to fully characterize the severity of impacts, nor was it possible to calculate or estimate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle.”
Done at the request of Congress, the report was based on a review of more than 1,200 cited scientific sources, new research conducted as part of the study and an independent peer review by EPA’s Science Advisory Board. The board had been sharply critical of a 2015 draft that said the agency “did not find evidence that [fracking activities] have led to widespread, systemic impacts on drinking water resources” in the U.S.
The California Public Utilities Commission on Tuesday ordered Southern California Edison and San Diego Gas & Electric to meet with groups opposed to the commission’s 2014 settlement that saddled ratepayers with 70% of the costs related to the premature closure of the San Onofre Nuclear Generating Station.
Edison retired San Onofre nuclear generating station in 2013 after defective steam generators caused a radiation leak the previous year. | Pharoah Construction
Commissioner Catherine Sandoval reopened the record on the proceeding in light of revelations that former CPUC President Michael Peevey engaged in persistent unreported ex parte communications with SCE during negotiations leading up to the $4.7 billion deal.
“The CPUC’s rules require a level playing field by mandating ex parte disclosures for rate-setting proceedings, such as this one,” Sandoval said in a statement. “The CPUC must ensure the integrity of its processes and that its decisions serve the public interest.”
The CPUC urged the utilities to “carefully consider” changes to the agreement proposed by California’s Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) — both of which withdrew their support for the original deal when Peevey’s activities became public after state investigators seized notes from his home showing that he discussed terms of the settlement with an SCE executive at a Warsaw, Poland, hotel. Peevey had previously served as president of the utility.
SCE expressed disappointment with the Dec. 13 ruling but said it will comply with the directive to meet with the other settling parties by Jan. 31. The utility said it continues to believe that the original settlement represents an “appropriate allocation” of costs.
“SCE has provided or will provide refunds and rate reductions of almost $1.6 billion under the settlement, and this amount may be increased by recoveries from Mitsubishi Heavy Industries, the supplier of the defective steam generators,” the company said in a statement.
Among the modifications sought by TURN are the removal of some or all of the $2.17 billion in plant investment currently included in the rate base and a refund to ratepayers of costs related to the failed replacement steam generators that forced San Onofre’s permanent closure.
TURN has also proposed that SCE eliminate $25 million in utility funding for greenhouse gas research at the University California-Los Angeles, a key outcome of the secret talks with Peevey.
Contending that “information has value, as does unequal access to decision-makers,” ORA has proposed that SCE refund ratepayers $383 million for the “quantifiable loss” of ORA’s litigation position — the difference between the settlement amount and what ORA says ratepayers would have negotiated if the agency had equal access to information. The agency is also recommending the utilities issue an additional $408 million in refunds.
The CPUC has set an April 28, 2017, deadline for the settling parties to reach an agreement to modify the original settlement. If no agreement is reached, individual parties will be asked to file a summary of their positions in order to inform further action by the commission.
San Onofre was shut down in January 2012 after detection of a radiation leak from one of the plant’s generating units. Operators soon discovered that the steam generators in both units on the site suffered from excess tube wear, despite having been replaced in 2009 and 2011 at a cost of $671 million. SCE decided to retire the plant in 2013.
Seattle City Light has signed an agreement with CAISO to begin participating in the Western Energy Imbalance Market (EIM) in April 2019.
“Seattle City Light has preliminarily evaluated the Energy Imbalance Market from an environmental, commercial and reliability perspective, and I believe City Light’s participation can deliver benefits to our customers in all three areas,” City Light General Manager Larry Weis said in a statement.
Weis said City Light’s participation in the EIM would represent the best use of the utility’s resources and expertise to support “a clean energy economy” throughout the West.
| Seattle City Light
“This is the first in a number of steps to better integrate large-scale renewable resources in the West, and a new tool in our ‘tool belt’ to address climate change and set the foundation for a cleaner energy future,” Weis said.
With a generating portfolio heavy in hydroelectric resources, City Light stands to benefit from the EIM as an exporter of the flexible ramping capability needed to smooth out intermittent renewables.
City Light’s participation will ultimately be contingent on satisfying concerns of Seattle City Council members who have asked for a more thorough accounting of the costs and benefits of market membership. (See Council OKs Seattle City Light Bid to Explore Joining the EIM.)
In order to support a decision to join the market, Seattle lawmakers have asked City Light to flesh out the findings of an EIM benefits study performed by consulting firm E3 that showed the utility could earn an additional $4 million to $23 million in yearly revenues from the market. Council members Lorena González and Mike O’Brien expressed concerns about the estimated $8.8 million in upfront costs for joining the market and the uncertainty around revenue projections.
“We will continuously evaluate the financial impact of participation in the Energy Imbalance Market,” City Light spokesman Scott Thomsen told RTO Insider. “If at any time we find that participation would not be in the best interests of Seattle City Light’s customer-owners, we can walk away from the agreement with CAISO at no cost.”
The utility is required to report its updated determinations to the council’s Energy and Environment Committee by April 10, 2017.
City Light would become the seventh balancing authority area to join the market after the entry of Portland General Electric in October 2017 and Idaho Power in April 2018.
It would also likely be the first publicly owned utility to participate in the EIM, although its entry could coincide with that of the Sacramento Municipal Utility District. SMUD announced its intent to join the market September and is expected to sign an implementation agreement early next year, according to Jim Shetler, general manager of the Balancing Authority of Northern California, of which the utility is the largest member. (See SMUD to Join EIM in Spring 2019 at the Earliest.)
PJM announced today it has appointed Susan Buehler as chief communications officer to oversee media relations, employee communications and the RTO’s website. She replaces Ian McLeod, who retired last month.
Buehler | PJM
Buehler is a former executive vice president for Bellevue Communications, a Philadelphia public relations firm, where she developed media, public relations and government relations strategies for clients including Citizens Bank, Campbell Soup and McDonald’s.
Before that, she was an Emmy award-winning television news reporter and editor at Fox News and worked in communications for Exelon’s PECO Energy. She holds a bachelor’s degree in broadcast journalism from Syracuse University.
“Susan’s career in strategic communications and broadcast journalism brings a new perspective to reaching our stakeholders,” said Nora Swimm, senior vice president of corporate client services. “Her experience helping large firms achieve their communications goals coupled with her keen awareness of what resonates with audiences will enhance PJM’s approach to communicating.”
MISO’s Board of Directors last week unanimously passed a $239.1 million operating budget and a $29.9 million capital spending plan for 2017. (See “MISO Predicts Budget Increase in 2017, Introduces 5-Year Business Plan,” MISO Advisory Committee Briefs.)
The RTO had proposed a $238.6 million budget before the board’s Human Resource Committee approved a 3.5% increase in the salary budget, as recommended by human resource consulting firm Mercer.
The firm’s review of MISO’s compensation recommended a 3% increase in merit-based compensation and a 0.5% increase for employees’ promotional increases.
“We looked at things like GDP and inflation rates; we looked at anecdotal things,” Director Paul Bonavia said at the committee’s Dec. 6 meeting.
MISO CEO John Bear said he consulted with the CEOs of 11 member companies on the proposed increase.
“The range we have in mind is in line with their thinking,” Bear said. He said a key concern among the CEOs was the aging workforce and attracting younger staff.
MISO expects to exceed its $225 million 2016 operating budget by $600,000, resulting in a maximum 0.3% possible overrun.
The RTO has spent $187.9 million of the $188.6 million allowed to date, leaving less than 0.3% of the budget untouched, acting Vice President of Finance Tony Guisinger said at MISO’s Dec. 8 board meeting.
MISO anticipates between $30.5 million and $31.5 million in capital spending for the year, potentially exceeding its $31 million budget.
Guisinger also said MISO hopes to procure financing in 2018 for technology needs and said talks will begin in early 2017 on the amount it will request.
MISO to Welcome 3 New Board Members, Thanks Departing Directors
Board Chair Judy Walsh and Directors Michael Evans and Paul Feldman will exit MISO at year-end, replaced by former ERCOT CEO H.B. “Trip” Doggett, former Calvert Investments CEO Barbara Krumsiek and Todd Raba, who is leaving Twenty First Century Utilities and has served as CEO of both GridPoint and Berkshire Hathaway’s Johns Manville.
During the meeting, Senior Vice President of Compliance Services Steve Kozey confirmed election results and said all three candidates received sufficient votes in the electronic voting process. “No lapse in security; no Russian hackers,” he joked.
Former MISO Director Eugene Zeltmann called in to congratulate the trio of departing board members.
“You certainly presided over an incredible transformation of an extraordinary organization,” said Zeltmann, who left the board a year ago.
“We couldn’t have done this without you,” Walsh replied to Zeltmann.
Organization of MISO States President Sally Talberg called the three directors a “bedrock” for MISO.
“In my first meeting, we had two directors that had been thrown out, we had hostile stakeholders and cost overruns. At that time, it was a dicey deal indeed to see if MISO would succeed in becoming an organization,” Walsh said. She felt the board was being left in “very good hands,” she said.
The board also adopted two motions pertaining to itself — the elimination of post-service restrictions and a pay raise.
MISO will make a FERC filing by the end of the year to eliminate the post-service restriction and trim the pre-service restriction, leaving it with only a one-year pre-service restriction. Directors cannot have served as “a director, officer or employee of a member, user or an affiliate of a member or user engaged in the electric utility industry or participating in wholesale electricity markets” during that period.
“MISO was the only RTO in the nation with a post-service restriction,” Director Tom Rainwater said. Rainwater said MISO was having trouble attracting new board members with its two-year pre- and post-service prohibitions from utility and wholesale energy market participants. (See Board OKs Pay Hike, Change to Independence Rules.)
Rainwater said the board and MISO discovered that the Transmission Owner’s Agreement subjects “key” MISO employees to a 12-month “cooling off” period after leaving the RTO, during which they cannot have “any involvement … on behalf of any parties other than MISO with regard to any matters in which they were substantially involved when serving for, or employed by, MISO.” Bear has agreed to compile a list of employees that would be subject to a restriction for board approval.
The board also adopted a $4,000 annual pay increase for directors. Rainwater said the changes will up the yearly retainer from $55,000 to $89,000 but eliminate meeting fees for the first six scheduled board meetings and two annual strategic retreat meetings. (See Board OKs Pay Hike, Change to Independence Rules.) A typical MISO director who attends those eight meetings and serves on three committees is expected to earn about $116,000 annually.
MISO Still Undergoing FERC Audit
A little over a year later, MISO is still undergoing a FERC compliance audit, Chief Compliance Officer Joseph Gardner told the board. Gardner said it is not unusual for RTO audits to last 18 to 24 months. He said FERC staff has been on-site at MISO headquarters for two visits during the audit.
“No big concerns that I’m aware of have come up,” Gardner added.
The PJM Board of Managers last week approved almost $260 million in transmission reliability projects.
The projects in the 2016 Regional Transmission Expansion Plan include:
New baseline reliability upgrades ($158.1 million);
Changes to previously approved upgrades (net increase of $47.3 million); and
Facilities, network upgrades and withdrawal of canceled facilities related to the interconnection queue (net increase $54 million).
With the board’s action, PJM has approved more than $29 billion in transmission additions and upgrades since the first RTEP in 2000.
Dooms – Valley 500 kV Line Project | PJM
The board also approved an installed reserve margin of 16.6% for 2017/18. The IRM approval includes associated parameters for each of the next four delivery years.
FERC last week upheld its February 2016 ruling that projects solely addressing a transmission owner’s local planning criteria are not eligible for regional cost allocation, rejecting rehearing requests from Dominion Resources and others.
“Cost allocation is not an exact science, and there may be ‘multiple just and reasonable rates’ on the same set of facts. Here, whether the allocation proposed by the PJM transmission owners is the best allocation method is not the issue; the issue is whether it is a just and reasonable method, and we find that it [is] just and reasonable based on the supporting data,” the commission said (ER15-1387-002).
The commission directed PJM to make a compliance filing ensuring that the costs incurred after the May 25, 2015, effective date of its February order for projects included in the Regional Transmission Expansion Plan solely to address Form 715 local planning criteria be allocated to the zones of the individual TOs. PJM must also rebill for any costs for such projects allocated incorrectly for the period.
FERC also denied rehearing in two cases applying the 2016 ruling and making Dominion solely responsible for the cost of its 500-kV Cunningham-Elmont (RTEP project b2582) (ER15-1344) and Cunningham-Dooms rebuilds (b2665) (ER16-736, EL16-96-001).
Elmont-Cunningham 500kV Rebuild | PJM
Dominion argued that the projects have regional benefits, unlike most Form 715 projects, which deliver only local benefits. Old Dominion Electric Cooperative, LSP Transmission Holdings and ITC Mid-Atlantic Development also had sought rehearing. (See Dominion: Tx Project Should be Regionally Allocated.)
Commissioner Cheryl LaFleur repeated her earlier partial dissents in the three dockets, saying that “high-voltage transmission lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation, and those benefits exist regardless of the underlying need that drove the project.”
The commission also denied Public Service Electric and Gas’ request to reconsider an order assigning its zone all of the costs of its Sewaren upgrade to replace aging infrastructure and provide storm hardening (ER14-1485). PSE&G said the Sewaren projects (b2276, b2276.1 and b2276.2) addressed both aging infrastructure and short-circuit issues. It will convert the two 138-kV circuits from Sewaren–Metuchen to 230 kV and make related changes.
SPP says it has successfully implemented system changes required by FERC Order 809, which ordered RTOs to improve the alignment of their market schedules with those of interstate gas pipelines (RM14-2). SPP’s changes took effect Sept. 30.
“After roughly two months of operational experience, it appears it’s successful so far,” SPP legal counsel Joe Ghormley told a meeting of the Gas Electric Coordination Task Force last week, where he shared the draft of an informational report to be filed with FERC.
The report says “the changes have improved coordination between the SPP markets and natural gas nomination cycles while taking into account stakeholders’ price formation concerns as well as the relative immaturity of SPP’s market and the resulting need for an incremental approach to market system changes.”
SPP described “a year of transition” involving the revised market schedule and the development of system changes for the RTO’s enhanced combined cycle system initiative, the subject of proposed Tariff changes filed with FERC in November (ER17-358). The report also details “extensive efforts” to reach out to and train members and stakeholders. SPP said it is only aware of one resource that has reported potential problems with gas availability, which occurred after a pipeline was taken out of service last December for repairs. When the line was returned to service, it operated below capacity because of reductions mandated by the Pipeline and Hazardous Materials Safety Administration.
“SPP continues to work … to identify cost-effective ways to further compress its market system solve times without jeopardizing the [Integrated Marketplace’s] fundamental functions … or its upcoming enhancements to commitment and dispatch of gas generators utilizing the most efficient configuration of components.”
The report will be filed with FERC on Thursday. The commission required SPP to file an annual report on its compliance with Order 809 for the next three years.
SPP, AECI Narrow Target Areas to Southern Missouri
SPP and Associated Electric Cooperative Inc. have whittled a list of five target areas under consideration for joint transmission projects down to one.
SPP and AECI staff told the Interregional Planning Stakeholder Advisory Committee on Friday that they are still narrowing down different transmission solutions to address high voltages and overloads in the Brookline area of southern Missouri. Planners intend to issue a draft report for the IPSAC’s review early next year.
The two entities currently use an operating guide to manage their seam, but the cost is becoming too big to ignore. Staff said it is considering the use of transmission reactors around Brookline instead of using the operating guide to control voltages. Any final solutions will be coordinated with SPP’s 2017 Integrated Transmission Planning’s 10-year assessment.
SPP and AECI determined three other target areas can be managed without joint projects. The fifth target area, in Northeast Oklahoma, was removed from consideration because a change in transmission ownership shifted facilities to AECI’s management.
Based in Springfield, Mo., AECI is owned by six regional generation and transmission cooperatives.
M2M Payments Flow Back to SPP
Market-to-market payments between SPP and MISO reverted to previous form in October, with MISO paying SPP almost $2.2 million for 871 binding hours on 34 flowgates along the seam.
MISO paid more than $2.2 million for 27 temporary flowgates, while SPP sent about $29,000 to MISO for seven permanent flowgates.
SPP had paid its counterpart for binding flowgates the previous three months, but MISO has sent about $10 million to SPP since the two RTOs began the process last year.
CARMEL, Ind. — FERC has extended the comment period on MISO’s proposed forward capacity auction to Dec. 14 (ER17-284).
The extension — requested by the Public Utility Commission of Texas and not opposed by MISO — should not affect the RTO’s ability to implement the auction in time for the 2018/19 planning year, said Richard Doying, executive vice president of operations and corporate services.
At the Board of Directors’ Markets Committee meeting on Dec. 6, Independent Market Monitor David Patton told the board he was preparing a filing for next week to express his ongoing concerns with the proposal. (See MISO Files Forward Capacity Auction Plan with FERC.)
Director Phyllis Currie asked if MISO had given thought to a contingency plan if FERC takes longer than expected to decide. Doying said MISO is holding off on releasing alternate plans for now.
MISO Awaits FERC Queue Decision
MISO expects a decision from FERC on its queue reform proposal by year-end, Vice President of System Planning and Seams Coordination Jennifer Curran said.
Curran predicted gradual queue improvement in 2017 as the new rules are phased in.
At the September board meeting in St. Paul, Minn., Curran said MISO is hoping to build more certainty into the process that would reduce restudies and the amount of time it takes for projects to clear the queue. “It’s currently a two- to three-year process and is challenged by restudies,” she said.
FERC rejected MISO’s first proposal in March, saying the RTO improperly assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). (See MISO: Stakeholders Behind 2nd Queue Reform Attempt.)
LITTLE ROCK, Ark. — SPP’s Board of Directors last week approved a 13.2% increase in the RTO’s administrative fee and a 6.6% boost in its budget for 2017. The approval came Dec. 6 after a unanimous vote by the Members Committee.
The vote means the fee will rise from 37 cents/MWh to 41.9 cents/MWh in 2017, based on a net revenue requirement (NRR) of $160.5 million, a $9.9 million increase over 2016.
| SPP
The RTO projects annual fee increases for the next five years, reaching 49.9 cents/MWh in 2021.
SPP is projecting an under-recovery of $5.9 million from the 2016 NRR. Other factors contributing to the NRR’s increase are a $3.5 million increase in maintenance expenditures and a $2.7 million increase in personnel costs.
SPP Director Harry Skilton, chair of the Finance Committee, said a decline in load growth led to the administrative fee’s increase. SPP had budgeted 407.2 million MWh in billable energy but revised that down to 393.9 million MWh. It is budgeting 383 million MWh through 2021.
“That reduction in load has set us up for an under-recovery that carries on to the next year,” Skilton said.
SPP budgeted a net loss of $35 million this year but has upped that to a $41.6 million loss given the under-recovery.
The board approved a budget with $194.1 million in income and $196.4 million in expenses for 2017. The 2016 spending plan had $176.2 million in income and $217.8 million in expenses.
The budget sets SPP’s headcount at 610 employees, an increase of one from 2016.
Besides a few questions on SPP’s practice for depreciating expenses, members quickly accepted Skilton’s report and recommendations.
Michael Desselle, SPP vice president and chief compliance and administrative officer, told the board and members that the RTO sent out nearly double the usual amount of stakeholder satisfaction surveys, but that the final results were not significantly different than previous years.
Desselle said the annual survey’s average satisfaction scores dropped for every service except one, by a difference of 0.12 points (out of 5) or less. Training was the lone exception, rising by 0.03.
Stakeholders identified the Z2 revenue crediting process as a repeat theme in their comments. One stakeholder said “the ‘Z2 Monster’ has been an unqualified disaster … I tip my hat to SPP management’s ability to skirt their contribution to the situation,” while another dinged SPP staff for “allowing too many years to transpire before implementing Z2.”
“Last year, [the concern] was the transparency of the Z2 process,” Desselle said. “This year, it was the expediency of the Z2 process.”
As in past years, Desselle said staff will prioritize the comments and address them. He said staff has closed 71 of last year’s 76 comments.
Among the positive comments were many praising the staff’s professionalism, responsiveness and communication efforts. Criticisms included the lack of detailed settlement reports in the Integrated Marketplace portal and what one called the “patronizing attitude” of staff and board members. One critic called for an external market monitor, saying there are “way too many conflicts of interest with an internal” monitor. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
SPP distributed 4,597 survey invitations to organizational group members, market participants and other individuals who had interacted with the RTO during the previous 12 months, either through meetings, training, customer relations or other exchanges. Staff received 716 responses, for a response rate of 16%, up one percentage point from last year (410 responses) and four points from 2014 (181 responses).
Desselle also said auditing firm KPMG issued an unqualified opinion with no exceptions following its Statement on Standards for Attestation Engagements (SSAE) No. 16 audit. He said auditors found “no disagreements with management” and that “no illegal acts came to their attention.”
Stakeholders Again Give Organizational Groups High Marks
SPP’s annual survey of its organizational groups matched that from 2016, with stakeholders rating groups’ overall effectiveness at 4.2, out of a possible 5.
The scores reflected the average response to “Please rate the overall effectiveness of this group.” The individual group scores ran from 3.5 for the Event Analysis Working Group to 4.8 for the Human Resources and Oversight committees and the System Protection and Control Working Group.
SPP CEO Nick Brown said he was pleased with the survey’s 71% response rate, and he assured the board and members that SPP “is not just gathering this data and doing nothing with it.”
Ciesiel Pleased with RE Survey Results
Regional Entity General Manager Ron Ciesiel said he was happy with the RE’s stakeholder satisfaction survey, which produced scores of 3.9 to 4.4 on a 5-point scale for customer service and responsiveness, and 3.2 to 3.6 for how well the program meets expectations.
Ciesiel noted RE staff is seen as responsive, knowledgeable, professional and personable and that members see the RE’s workshops on reliability issues as “valuable.”
“Here’s the good news: We’re not having the events we need to do analysis on. We’re not really getting events,” he said. “I’ll take this every day, because it’s good news across the board, not only here, but in North America.”
Ciesiel said the RE is considering a spring workshop and including sessions on new standards. It will also use the RE’s newsletter to focus on the top 10 violated standards.
Paul Malone, Todd Fridley Approved as MOPC Chairs
The board and members unanimously approved the Nebraska Public Power District’s Paul Malone as the incoming chair of the Markets and Operations Policy Committee. Malone, NPPD’s transmission compliance and planning manager, replaces SouthCentral MCN’s Noman Williams, whose term expired.
Todd Fridley, vice president at Transource Energy, was approved as the committee’s vice chair.
The board and members also approved revisions to the Corporate Governance Committee’s charter to formalize bylaw revisions that added committee seats for federal power marketing agencies and independent transmission companies. Bob Harris (Western Area Power Administration-Upper Great Plains) and Brett Leopold (ITC Great Plains) currently fill those respective seats.
Also approved was a charter change for the Seams Steering Committee. It changes the committee’s scope of review and guidance activities from “existing seams agreements” to “new or existing seams agreements.”
