CARMEL, Ind. — MISO set an all-time wind output record and experienced lower demand and prices during a relatively cool October, the RTO said last week.
Load peaked for the month at 89 GW on Oct. 9, and averaged 70 GW, 6 GW lower than in September, beginning the “seasonal transition to cooler weather conditions,” MISO Senior Director of Systemwide Operations Rob Benbow said during a Nov. 14 Informational Forum meeting.
Energy prices averaged $28/MWh in the day-ahead market and $27/MWh in the real-time market for the month, a 10% decline from September. Natural gas prices lingered around $2.84/MMBtu, lower than September’s $2.94/MMBtu average. Real-time make-whole payments fell by more than half, from just more than $13 million to $6.5 million.
| Siemens
Propelled by the windier shoulder season, MISO’s wind energy output spiked during the month, setting a new peak wind output record of 14.3 GW on Oct. 30, 0.6 GW higher than the previous record set in December 2016.
Benbow said the increased output was primarily driven by an increase in installed wind capacity throughout 2017. MISO’s registered wind capacity currently stands at about 16.8 GW.
FERC last week upheld a previous ruling covering transmission cost allocation in the WestConnect planning region, adding further explanation of its reasoning after a federal court remanded the issue back to it for more information.
The issue stems from an October 2012 compliance filing that WestConnect utilities submitted in response to FERC Order 1000, the 2011 rule governing regional transmission planning and cost allocation. The group’s planning region covers Arizona, California, Colorado, Nevada, New Mexico, South Dakota, Texas and Wyoming.
The utilities’ initial compliance filing included a provision stipulating that costs for projects selected in a regional plan would be allocated only to beneficiaries who agreed to participate in those projects. Other WestConnect members participating in the planning process would not be obligated to pay for those projects’ costs, a measure designed to avoid discouraging nonpublic utility transmission providers from participating in planning.
FERC found that WestConnect’s “non-binding” process did not comply with Order 1000, which prohibits any planning participants from claiming an exemption from cost allocation merely by asserting they receive no benefits from the resulting transmission infrastructure. The commission noted that the “fundamental driver” of Order 1000 was to minimize “free ridership” within the system.
In response to FERC’s rejection, the utilities submitted a second compliance filing containing a new proposal to create separate categories of transmission providers eligible to participate in the WestConnect process: “enrolled” transmission owners subject to the entirety of the Order 1000 process, and “coordinating” TOs — nonpublic utility providers — not subject to regional cost allocation but able to participate in planning. FERC denied a rehearing on that plan and two subsequent proposals that the commission found were similarly deficient in meeting Order 1000 cost allocation requirements. In November 2014 and May 2015, El Paso Electric petitioned the 5th U.S. Circuit Court of Appeals to review the compliance orders.
The 5th Circuit remanded the orders in August 2016 for “additional factual findings” on WestConnect’s planning process, saying the commission’s mandates regarding the role of nonpublic utility transmission providers were arbitrary and capricious, and that FERC had not shown its orders would not produce unjust rates.
FERC last week declined to change its original finding, saying it “continues to conclude that the approach it ultimately accepted in the compliance orders satisfies Order 1000 while taking into account the uniquely integrated nature of public and nonpublic utility transmission systems in the WestConnect transmission planning region” (ER1375-011, et al.).
The commission determined that its original decision “appropriately” considered the “unique characteristics” of the WestConnect region when determining how to address the participation of nonpublic utility transmission providers in the region’s planning process. It noted that some public utilities in the region are connected together by transmission wholly or partially owned by nonpublic providers and that regional planning would be “hampered” without the participation of the latter.
“We find no basis in the record to conclude that, if presented with [the] choice, any nonpublic utility transmission provider in the WestConnect region would voluntarily choose to enroll and subject themselves to binding cost allocation,” the commission said. “Their decision not to enroll would mean that, under this approach, WestConnect would not conduct transmission planning to meet the nonpublic utility transmission providers’ transmission needs.”
While the outcome of WestConnect’s initial approach would comply with Order 1000, it would also “undermine” the order’s goals, the commission said.
The WestConnect utilities included Arizona Public Service; Black Hills Power; Basin Electric Power Cooperative; Powder River Electric Cooperative; Black Hills Colorado Electric Utility; Cheyenne Light, Fuel, & Power; El Paso Electric; NV Energy; and Xcel Energy Services on behalf of Public Service Company of Colorado, Public Service Company of New Mexico, Tucson Electric Power and UNS Electric.
In other decisions last week, FERC:
Western Energy Imbalance Market Participants | CAISO
Accepted APS’ compliance filing for its participation in the Western Energy Imbalance Market (EIM) operated by CAISO. The utility revised its tariff to address directives by FERC in a Sept. 26 order. The commission accepted APS’ proposal to allow external resources to participate in the EIM via dynamic scheduling, subject to a further compliance filing, and the utility’s proposal to reflect payments and charges from CAISO in a future rate proceeding (ER16-938).
Rejected a complaint filed by transmission customers of Pacific Gas and Electric over a proposed rate increase. Complainants said the utility’s stated costs were not justified and argued for a rate decrease, but FERC said they had not met the burden for a complaint and did not introduce any new evidence over the rates approved by the commission in a November 2016 settlement. Complaining parties included the Transmission Agency of Northern California; the city of Santa Clara, Calif.; the M-S-R Public Power Agency; the State Water Contractors; the California Public Utilities Commission; the Modesto Irrigation District; and the Sacramento Municipal Utility District (EL17-59)
FERC on Thursday accepted SPP Tariff revisions replacing the defined terms “head-room” and “floor-room” with “instantaneous load capacity,” effective June 27, 2017 (ER17-1482).
The commission said the changes “more accurately” describe the purpose, scope and functionality of the ramp capacity requirements the RTO needs in order to manage instantaneous load changes that occur during each operating interval.
| GE
Westar Energy and Golden Spread Electric Cooperative protested the revisions. Westar said SPP failed to provide any specific insight on how it accounts for the differences caused by the operational uncertainties, such as generation deviations, load forecast errors, net schedule interchange deviations and erroneous forecasts for intermittent generators.
Golden Spread argued SPP’s addition of the term “operator input” to its reliability unit commitment (RUC) determinations should only apply to extraordinary circumstances. The co-op said instantaneous load capacity should generally be procured by SPP through normal competitive offers based on forecasts.
FERC countered that a degree of operator discretion, “not limitless and consistent with SPP’s existing processes, is inherent in reliability commitment processes.” It dismissed Golden Spread’s and Westar’s remaining comments as being beyond the proceeding’s scope.
The commission did agree with Golden Spread, however, that it had raised issues SPP should consider exploring through its stakeholder process.
FERC last week approved NYISO’s tariff revisions to implement a new reliability-must-run program but directed the ISO to make another filing with certain revisions to the initiative (ER16-120, EL15-37).
NYISO submitted a compliance filing Sept. 20 to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. FERC had accepted an earlier compliance filing but in April 2016 directed NYISO to make further changes.
R.E. Ginna Nuclear Plant
The commission rejected a request by the Independent Power Producers of New York and Electric Power Supply Association to shorten the RMR notice period to 270 days. The groups contended that a full year was unnecessarily long. They also made other requests regarding deactivation time and suggested certain incentive payments as part of the program.
In last week’s order, FERC directed NYISO to make another filing that clarifies that a generator can propose solutions to a reliability need that are not market-based and can involve generators that are already mothballed or in a forced outage.
The ISO will also require generators to repay revenues that exceed going-forward costs for RMR service and allow units receiving an availability and performance rate (APR) to retain other incentives. FERC’s order also asked NYISO to clarify what reliability solutions it will use as its base case to determine reliability needs.
NYISO will also have to “revise the requirement to repay above-market revenues to require repayment of only the above-market revenues that exceed an RMR generator’s going-forward costs for RMR service, and to allow RMR generators that accepted an APR to retain their availability and performance incentives.”
The ISO must also revise the repayment periods for capital expenditures and above-market revenues to require repayment either within 36 months or twice the duration of the applicable RMR agreement, whichever is shorter.
NYISO must make an additional compliance filing with further revisions by Dec. 16.
CARMEL, Ind. — MISO will delay until next year its proposal to implement a more open-ended approach to its generator retirement process while it looks into possible modeling implications stemming from the change.
MISO adviser Joe Reddoch last week said the RTO will file the plan with FERC in March instead of by the end of the year, giving it time to evaluate whether the more flexible retirement rules will affect its generator availability modeling assumptions used in planning studies.
Reddoch said the new process is “designed to address both temporary and permanent shutdown scenarios,” and asked for stakeholder opinions on the plan through Dec. 5.
Under the proposal, MISO would announce retirements and rescind interconnection rights only after a generator fails to return from a 36-month suspension period or if an asset owner announces a retirement date before the three years are up, Reddoch said during a Nov. 15 Planning Advisory Committee meeting. Owners will also no longer be required to supply the RTO with an estimated return-to-service date when suspending their units. Suspensions lasting fewer than two months and planned generator outages will not be subject to the new process.
Earlier this year, MISO proposed to reduce its Attachment Y process to a catch-all “economic shutdown” status that no longer recognizes temporary suspensions. The RTO has since dropped that term and tripled the amount of time granted for changing a retirement decision, but it still proposes to combine its separate suspension and retirement procedures into a single process. (See “MISO Moves Toward Singular Attachment Y Status,” MISO PAC Briefs: June 14, 2017.)
The RTO last month received two retirement notices under the existing process, representing more than 1,000 MW of capacity. The RTO typically receives a maximum of four retirement and suspension notices per month, and the combined requests rarely exceed 1,000 MW. MISO has already approved the retirement of 735 MW of capacity for the first five months of 2018. Since 2005, MISO has approved 164 retirement notices and issued 10 system support resource agreements.
BALTIMORE, Md. — While panelists discussing baseload price supports at the annual meeting of the National Association of Regulatory Utility Commissioners last week didn’t find much common ground, they did agree that energy markets should put a price on the attributes the grid needs.
The discussion revolved around the U.S. Department of Energy’s Notice of Proposed Rulemaking, which urged FERC to adopt price supports for generators that can maintain a 90-day fuel supply. The proposal has been criticized for ostensibly focusing on coal and nuclear units, but discussion has not focused on what qualities the grid requires to be reliable and resilient.
“The proposal on the table is a solution in search of a problem,” said Marty Durbin, the executive vice president and chief strategy officer for the American Petroleum Institute, which supports oil and natural gas interests. “We’ve earned the market share that we have.
“The polar vortex keeps coming out, and I want to grab my red challenge flag and throw it on the floor,” Durbin said, referring to arguments that gas-fired units don’t have enough fuel security to maintain the reliability of the grid. The severe cold snap in the winter of 2014 created a reliability scare after as much as 22% of PJM’s generators were unable to run when dispatched and gas prices spiked.
The NOPR referenced that situation as an example of why larger units with onsite fuel are necessary, even if they are uneconomic.
“Wyoming’s interest in the NOPR is really about our customers and our coal, not about coal generation,” Wyoming Public Service Commissioner Kara Brighton said.
Define and Value
“We have never viewed the FERC NOPR as a subsidy for coal,” said Paul Bailey, the CEO of the American Coalition for Clean Coal Electricity. “We view this as a way to value a resilience attribute.”
“We need to decide what’s important and put a value on them,” Durbin said. “That’s really all this is about.”
“This has to be solved holistically,” Herling said. “Infrastructure alone isn’t going to solve the problem. Fuel security alone isn’t going to solve the problem. … Resilience is a rest-of-career conversation.”
“Before we conclude that the markets aren’t supporting these resources, we should ask the question: ‘Do we have the right market rules?’” said Kathleen Barrón, senior vice president for competitive market policy at Exelon, the nation’s largest nuclear operator. “What are the risks that we’re facing, both from manmade and natural sources, to those sources of fuel supply? We probably should get some input from [federal departments] that are experts in security … and have those organizations provide input to the RTOs.”
The Public Utility of Commission of Texas on Friday welcomed Arthur C. D’Andrea, who replaced longtime Commissioner Ken Anderson as its third member.
D’Andrea was appointed by Texas Gov. Greg Abbott on Nov. 14 to a term expiring Sept. 1, 2023. He joins Chair DeAnn Walker, who, like D’Andrea, worked in Abbot’s office before joining the commission.
Brandy Marquez, DeAnn Walker (l-r) welcome Arthur D’Andrea to the Texas PUC
“It seems natural for him to be on the same floor now,” Walker said after calling Friday’s meeting to order.
Brandy Marty Marquez, now the PUC’s longest-tenured commissioner with four years of experience, is the only member to have been appointed by former Gov. Rick Perry. She said it felt “weird” as she sat in Anderson’s chair.
“It feels like I’m in a totally different room. Who are all you people?” said Marquez, greeting D’Andrea as the “Brazilian bad boy.”
Anderson, whose latest term expired in August, joined the commission in 2008, making him its longest serving member ever.
Brandy Marquez praises former Commissioner Ken Anderson.
Marquez shared several thoughts on Anderson with the commission and its audience, teasingly saying he is a “very snazzy dresser” and “likes to rock a winter beard.” She also called Anderson “the consummate gentleman, who’s not afraid to kick a little hindquarters now and then,” and the “ultimate protector of our energy-only market.”
Marquez said she had recently read an article that referred to parents as the “original gangsters, because they tell you like it is to your face, and behind your back, they compliment you wildly.”
“That’s pretty gangster,” she said. “Commissioner Anderson never missed an opportunity to compliment his staff, to compliment the staff of the commission, and to compliment the bar that argued before it. He always said that the quality of the folks that came before this commission was his favorite part of the job.”
D’Andrea
D’Andrea wasted little time in making himself at home, spending nearly 30 minutes questioning parties to a Southwestern Electric Power Co. (SWEPCO) rate case (Docket 46449). The PUC decided to take up the case again at its Dec. 14 meeting over requests by intervenors to be granted additional time to conduct discovery after SWEPCO added late expert testimony.
D’Andrea was an assistant general counsel in the governor’s office (2015-2017) and an assistant solicitor general for the state’s attorney general (2009-15). He received a bachelor’s degree in chemical engineering in 1998 and a law degree from the University of Texas.
PUC to Ask MISO to Create Texas Local Resource Zone
Picking up on an issue Anderson followed for several years, the PUC has requestedMISO seek FERC approval to create a separate local resource zone (LRZ) that would “better align the costs and benefits” of market efficiency projects (MEPs) for the portions of Texas within the RTO’s footprint.
The commission asked for an effective date no later than Dec. 6, saying it would lead to a “more granular estimation” of transmission projects’ costs and benefits. Staff told the PUC that Texas currently pays 18% of the costs while receiving 70% of the benefits, and that a Texas LRZ would still have the state “bearing less of the costs than the benefits.”
The action came after Walker attended an Entergy Regional State Committee (ERSC) meeting in place of Anderson, who was the PUC’s liaison to MISO.
At their Dec. 7 meeting, MISO’s Board of Directors will consider the $129.7 million, 25.5-mile West of the Atchafalaya Basin 500-kV economic project in southeast Texas, which is being submitted as a market efficiency project. Texas will receive 72.1% of the production cost benefits from the project and be responsible for 17.9% of the costs, while Louisiana will receive 27.7% of the benefits but be responsible for 70% of the costs.
Walker said ERSC members discussed four proposals to address the issue, one of those being a separate LRZ within MISO that would contain only its Texas territory for cost-allocation purposes.
“Commissioner Anderson … spent lot of time on this. This was his preference,” Walker said. “After delving into it, I think it’s the best answer.”
When Entergy joined MISO in 2013, a MISO South sub-region was created that included two LRZs. A third was created in 2015 to incorporate the portions of Mississippi in the MISO footprint.
Rulemaking Would Require Periodic Rate Reviews for IOUs
The PUC adopted a proposed rulemaking requiring investor-owned utilities operating solely inside ERCOT to make periodic filings for rate proceedings, as required by the recent Texas Legislature’s Senate Bill 735 (Project 47545).
The rulemaking would require each electric utility in ERCOT’s footprint to file for a comprehensive rate review within 48 months of its most recent rate order.
The ruling applies to AEP Texas, CenterPoint Energy, Cross Texas Transmission, Electric Transmission Texas, Lone Star Transmission, Oncor, Sharyland Utilities and Sharyland Distribution Services, Texas-New Mexico Power, and Wind Energy Transmission Texas.
In a memo to Marquez and D’Andrea, Walker said she found it “unacceptable” that some non-investor-owned transmission service providers have not had a rate review in more than 20 years. The commissioners agreed with Walker’s proposal that schedules for the non-investor-owned transmission providers be considered in a separate docket (Project 46393).
The commission is accepting comments on its proposed rulemaking. It is facing a June 1 deadline under state law to complete the rulemaking.
Commission to Intervene in EDF FERC Complaint
Following an executive session, the commissioners voted to intervene EDF Renewable Energy’s Section 206 complaint against MISO, PJM and SPP (EL18-26).
In its Oct. 30 complaint, EDF asked FERC to order the grid operators to amend their Tariffs and joint operating agreements to provide more information regarding the treatment of “affected systems” — areas that neighbor RTOs hosting new generation.
The complaint has drawn 10 intervenors from a wide range of the industry.
Order 2003 and the RTOs’ tariffs and JOAs require the host and neighboring RTOs to “coordinate.” But EDF said interconnection customers in MISO, PJM and SPP “have no idea what ‘coordination’ means because of the lack of detail in the Tariffs and JOAs.”
The company said the RTOs should file revisions providing details on the timing of affected systems studies; the base models used in the analyses; cost allocation of generation projects on either side of transmission seams; and whether the studies will use the energy or network resource interconnection service standard.
WASHINGTON — Protesters interrupting FERC’s monthly open meetings over the commission’s approval of natural gas pipelines has become a regular occurrence, but it’s not every day they include an Academy Award-nominated actor.
Actor James Cromwell protesting at FERC | ProtectOrangeCounty.net
James Cromwell — known for his roles in films such as “Babe,” “Star Trek: First Contact” and “L.A. Confidential,” among many others — was one of three protesters who interrupted the commission’s open meeting Thursday. The 77-year-old actor stood after two other protesters had interrupted FERC Chairman Neil Chatterjee as he began to give his closing remarks. He lambasted the commissioners for destroying the environment as he was led out of the meeting room, and could be heard chanting “FERC doesn’t work” as he was led out of the building.
Cromwell, of Warwick, N.Y., later told reporters he had traveled to D.C. with fellow Orange County resident Pramilla Malick to protest the commission’s approval of the Valley Lateral Project, a 7.8-mile extension of the Millennium Pipeline through the county. The lateral would serve the 680-MW Valley Energy Center being built in Wawayanda by Competitive Power Ventures.
FERC’s approval was especially controversial because it ruled that the New York Department of Environmental Conservation had waived its authority to issue or deny a water quality certification by failing to act under the one-year time frame required by the Clean Water Act. (See Environmentalists Denounce Millennium Pipeline Ruling.) Construction of the lateral project has been stayed by the 2nd U.S. Circuit Court of Appeals pending a Dec. 5 hearing by a three-judge panel to review New York Attorney General Eric Schneiderman’s petition to overturn FERC’s decision.
Malick, who was also removed from the meeting for interrupting, was among the petitioners whose request for rehearing of the decision was denied by FERC on Thursday (CP16-17).
She was joined by several other Orange County landowners who argued that the extension is unneeded, in part because the power plant is unlikely to be finished. Malick cited the federal corruption and bribery accusations against a CPV executive and state officials in connection with the state’s approval of the plant. (See CPV Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)
FERC, however, was unpersuaded. “None of the materials relating to the investigation submitted by Ms. Malick indicate that state approval of the Valley Energy Center is subject to the outcome of any investigation,” the commission said. It noted that the facility was 85% complete and on schedule to begin operations by February 2018.
| Millenium Pipeline
“The whole process has been corrupted,” Cromwell told reporters outside FERC headquarters after the meeting. “It should be grounds for stopping the project and having an investigation into how” it was approved.
Malick had argued that FERC violated the National Environmental Policy Act in its environmental assessment by improperly segmenting the pipeline project from Millennium Pipeline Co.’s compressor station in Minisink.
In its Thursday decision, FERC said, “There is no evidence that the Minisink Compressor Station included any facilities to accommodate the future Valley Lateral Project.” It pointed out that the station went into service in June 2013, and Millennium first applied for the lateral in November 2015, demonstrating that they weren’t connected actions under NEPA.
Cromwell’s ejection from FERC is only the latest in a long list of acts of civil disobedience. He madeheadlines this summer for serving prison time after he refused to pay a fine for a 2015 sit-in at the CPV plant construction site. Days after he got out, he was arrested at SeaWorld San Diego for interrupting a show.
“I’ve been thrown out of a number of meetings,” Cromwell said. “It doesn’t matter where it is; it’s the same process. They don’t listen.”
A MISO Board of Directors committee has advanced a $2.7 billion transmission development package that includes 353 new projects — including one divisive line proposed for Texas.
The System Planning Committee of the Board of Directors last week allowed MISO to move ahead in recommending its 2017 Transmission Expansion Plan for full board approval in early December, with RTO staff acknowledging that the plan’s only market efficiency project and competitive bidding candidate has drawn stakeholder ire.
MISO Vice President of System Planning Jennifer Curran said the $129.7 million, 500-kV line and substation in southeastern Texas underwent additional vetting to address concerns about the project’s costs. The RTO hired an additional consultant who verified its estimate, she said.
“As a result, we’re comfortable with the cost estimate for the competitive transmission process,” Curran told the committee during a Nov. 16 conference call.
| MISO
MISO’s Transmission Owners sector last month submitted an unsuccessful motion asking for a six-month delay of the project — one of the priciest in MTEP 17 — until the RTO addresses late modeling changes and a shifting cost estimate on the project. (See MISO Sectors Mull Texas Project Delay for MTEP 17.)
Xcel Energy had questioned the process behind the cost estimate, while Entergy submitted comments expressing concern about MISO overstating the benefits of the project and questioning modeling assumptions used to determine generator commitments in future system planning models.
“We disagree with the comments and continue to recommend that the project go forward,” Curran said. She added that the RTO would have risked reliability issues if it granted a delay of the project. The project is meant to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area straddling Texas and Louisiana.
Director Todd Raba asked what recourse Xcel and Entergy have available after MISO rebuffed their concerns. Curran said the companies could approach the board with their concerns and can pursue the RTO’s dispute resolution process.
MISO South Getting More Attention
Curran said more than half the projects in MTEP 17 are baseline reliability projects, most of which are concentrated in MISO South.
“Some of it is just the general lumpiness of upgrades … based on when projects need to be undertaken. Some of it is the continued load growth in the South that is not happening in other parts of our footprint,” Curran said.
BALTIMORE — More than 1,300 regulators and other stakeholders attended the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting and Education Conference at the Hilton Baltimore Inner Harbor, where the theme was “Infrastructure, Innovation and Investment.” The National Association of State Utility Consumer Advocates (NASUCA) attracted more than 200 to its annual meeting at the same hotel.
FERC Commissioner Robert Powelson said it will take a while for the commission to move forward on rulemakings that languished during its six months without a quorum.
Powelson and Neil Chatterjee joined Cheryl LaFleur on the commission in August, restoring a quorum. Two other commissioners, Kevin McIntyre and Richard Glick, are waiting to be sworn in after being confirmed by the Senate on Nov. 2.
“It’s kind of hard to calibrate around some of these high-level decisions that need to be made. It’s critical that people have a little bit of patience as we get back up and running,” he told NASUCA.
Powelson said he expects FERC to act on its November 2016 Notice of Proposed Rulemaking on electric storage within the next three months. (See FERC Rule Would Boost Energy Storage, DER.)
Powelson said he is using the Department of Energy’s NOPR for coal and nuclear plants as an “inflection point to see what’s working and what’s not working in the organized markets. What I know is working hyper-efficiently is wholesale power prices have dropped and that’s a darn good thing. … Let’s not screw that up.”
The commissioner said he also wants to explore “friction” between RTOs and their market monitors, an issue he said was raised by Virginia State Corporation Chairman Mark Christie at a recent conference.
Christie said in an interview later that he was raising a “structural issue that applies across all RTOs.” (See Order 719: FERC Balanced MMU Independence Against RTO Autonomy.) “What constitutes truly independent market monitoring?” Christie asked. “As the regulator of RTOs, FERC is the appropriate forum to tee up the issue and air it out.”
“I don’t want to go back to the old days,” Powelson said. “I really believe in the independence, and protecting the sanctity of that compact for these independent market monitors. I think they should have the ability to file [with FERC]. And I get a sense that Big Brother RTO wants to say, ‘Yeah, you can be seen and heard when it’s appropriate.’ That’s not a good thing in this world of transparency that we live.”
Powelson expressed skepticism that Order 1000 has resulted in competitive transmission development, saying it is another subject worthy of a “conversation” to determine “what’s working and not working” under the order. “I’m not saying we’re going to amend FERC Order 1000, but I think we owe it to ourselves to have that conversation,” he said.
Stefanie Brand, director of New Jersey’s Rate Counsel, asked Powelson if he was aware of concerns by industrial customers and others about the rising cost of supplemental transmission projects, which are not required by FERC or NERC reliability rules. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“Yes, it is something we’re looking at,” Powelson confirmed without elaboration.
Resolutions on Solar Tariffs, Tax Policy OK’d
NARUC’s Committee on Electricity approved a resolution urging the U.S. Trade Representative “to carefully weigh the harm that could result to energy customers from increasing the costs of solar inputs across the country, and the potential challenges to achieving state renewable energy and greenhouse gas goals that may result from higher solar energy prices.” (See Federal Trade Panel Recommends Solar PV Quotas.)
It also approved a measure asking Congress not to restrict state regulators’ ability to determine how any reduction in corporate income tax rates are addressed in utility rates. The resolution said any reductions in taxes on state-regulated investor-owned utilities “should result in a direct benefit to customers, so long as it is captured in the state ratemaking process.”
NARUC members formally elected Connecticut Public Utilities Regulatory Authority Vice Chair John W. “Jack” Betkoski III as its new president for a one-year term. Betkoski has been serving as president since August, when Powelson, a former Pennsylvania regulator, vacated the post to join FERC.
Ellen Nowak, chair of the Wisconsin Public Service Commission, was elected first vice president, and Edward S. Finley Jr., chair of the North Carolina Utilities Commission, as second vice president.
NARUC also named Andreas D. Thanos, of the Massachusetts Department of Public Utilities, the winner of the 2017 Terry Barnich Award. The award, which recognizes commissioners and staff who promote international cooperation among utility regulators, is named for the former chairman of the Illinois Commerce Commission, who was killed in 2009 while working for the U.S. State Department in Iraq. Thanos was named in recognition of his work in Europe, Latin America and elsewhere.
