State regulators and transmission customers of Southern California Edison last week urged FERC to reject the utility’s requested rate hike for 2018, saying it is excessive and unwarranted.
The California Public Utilities Commission on Nov. 17 filed a protest after SCE last month asked FERC to approve a $1.2 billion revenue requirement, including an increased return on equity, enhanced depreciation rate and an adder for its membership in CAISO.
“The CPUC opposes SCE’s proposed formula rate, which eliminates the minimal ratepayer protections contained [in] its current rate and only benefits the company’s shareholders,” the PUC said. “This proposed formula will result in unjust and unreasonable rates in 2018 and beyond and should be rejected.”
Southern California Edison asked FERC to approve an increased return on equity for its transmission facilities.
SCE requested a return on equity of 11.57%, calculated from a base ROE of 10.3%, compared with its current base ROE of 9.3%. The PUC said the utility did not provide evidence that the hike is needed and argued that its return should actually be reduced.
The state commission also disputed SCE’s claim that California is a risky investment environment, and said the 0.5% adder for participating in CAISO is a “windfall” for investors. The utility is required to be in the ISO by state law, the PUC noted.
In its application to FERC, the utility cited the growth of distributed energy resources as a challenge, and said growth in renewables — particularly at the distribution level — has driven the need for new transmission service. It also proposed an increase in its depreciation rate from about 2.54% currently to 2.73%.
“Integrating distributed generation with SCE’s transmission system is capital intensive and complicated, but it is necessary to achieve operational flexibility,” the utility said. “This energy revolution provides great opportunities but also presents a significant amount of uncertainty.”
Also asking FERC to reject the rate hike was a group representing 27 public agencies that hold contracts with the California Department of Water Resources to supply water for drinking, commercial, industrial and agricultural purposes. The group challenged SCE’s “proxy group” — a collection of similarly positioned electric companies — used to determine fair rates, as well as the base ROE.
California water agencies are protesting Southern California Edison’s proposed transmission rate hike.
The state water contractors said that a large number of the capital investments for which SCE wants to recover costs “have been unilaterally approved by SCE management in contravention of the requirements of [FERC] Order No. 890 to develop local transmission plans in an open and transparent planning processes.”
The group asked FERC to establish hearing and settlement procedures over SCE’s request.
The Los Angeles Department of Water and Power filed a separate protest saying the ROE is “dramatically overstated.” The ROE should be no larger than 8%, the agency argued in its protest. The department also protested that the utility’s proposal allows for executive bonuses to derive from transmission rates.
Other parties opposing the rate hike include the DWR; the City of Santa Clara and MSR Public Power Agency; and the cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside.
ALBANY, N.Y. — The planning for pricing carbon into NYISO’s markets should be more clearly defined, stakeholders told ISO and New York state officials Monday.
A good starting point: clarify the charter for the state’s Integrating Public Policy Task Force (IPPTF), some stakeholders contended.
“The problem we’re trying to solve is related to the Clean Energy Standard and trying to get 50% of [electricity] consumption from renewables, and one component of that is to incentivize clean generation. That’s what carbon pricing is doing,” said Anthony Fiore, director of energy regulatory affairs for New York City. “The other part is then to actually get that generation where the load is, which I think would be solved by a different set of tools.”
Carbon Pricing Process | NYISO
Stakeholders shared their views Nov. 20 at a third public hearing stemming from carbon pricing proposals set out in The Brattle Group report, and the second meeting of the IPPTF, a joint effort established by NYISO and the New York Public Service Commission in October to explore the carbon pricing issue. About 60 people attended the meeting, including PSC Commissioner Diane Burman. (See New York Stakeholders Question Carbon Pricing Process.)
Co-chairing the session was Nicole Bouchez, NYISO’s principal economist of market design, who said the purpose of the IPPTF is “to facilitate dialogue on market design alternatives” able to harmonize the ISO’s markets with the state’s carbon policies.
“That’s the goal. It is not a broader review of the [CES]. It is a fairly defined topic for the task force,” Bouchez said.
Fiore had a more expansive take of the IPPTF’s possible role.
“I understand that we can narrowly focus this task force, but I think it’s a mistake and a missed opportunity if we don’t lay out what the bigger issue is that lies behind this, because this is not the whole thing,” he said.
Erin Hogan of the Utility Intervention Unit at New York’s Department of Public Service shared Fiore’s concerns.
“If we had a defined goal of what we are trying to achieve, it would help develop the criteria to have an alternative analysis of the market design concepts,” she said. “As an analogy, in western New York, we had various transmission proposals and one party was advocating that their larger carbon reduction was a better option than the lower-priced transmission and also increased operability. So by not having those clearly defined criteria, it’s going to make it a little challenging to evaluate the alternative market design concepts.” (See Public Policy Tx Project Wins Key NYISO Endorsement.)
New York City Deputy Director for Infrastructure Susanne DesRoches said, “Our comments to the charter speak to needing to fully identify what the parallel processes are. For instance, how does transmission play into this conversation? We don’t want to be in a position to be pricing power in one part of the state higher than the other because we can’t get low-carbon power to the downstate region.
“Before we can go to the granular level of the questions on the table, we need consensus around what is the objective that we are trying to solve and how our other processes get us to that resolution as well.”
IPPTF co-chair Marco Padula, DPS deputy director for market structure, said, “You should identify those other processes and we should add them to this list. If you believe there are other processes that need to be studied, please, let’s add them.”
Preventing Leakage
The hearing’s agenda listed 15 recommended topics, starting with carbon leakage and resource shuffling.
Carbon leakage is defined as an increase in emissions in states parallel to one reducing them. Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emission caps, while letting heavier polluters simultaneously serve customers in neighboring regions.
Bouchez emphasized the task force was looking more for questions than answers at this point, and that it would address the leakage issue more fully at a Dec 11 technical conference.
She identified questions arising from the group’s prior hearing, which included:
How would a carbon charge be applied to interregional transactions?
Should specific charges be applied to each neighboring region, or should the same charge be applied to all?
Would crediting the carbon charge on exporting interregional transactions create incentives to sell power out of state?
Will the biggest emitters see this as an incentive to export more energy from New York?
Mark Younger of Hudson Energy Economics said the question of whether to apply a carbon charge to resources under 25 MW or to any fossil-fuel backed distributed energy resource also has leakage implications.
“In other words, not applying to those examples is a form of leakage,” Younger said. “You can take a relatively efficient wholesale generator, and because you’re adding a carbon charge to it, [you’re] making it look like it’s [more] desirable to run a sub-25-MW, much-less-efficient resource rather than take power from there. And that’s the same thing we’re talking about with external areas as well.”
Miles Farmer of the Natural Resources Defense Council said that leakage is a retail — as well as wholesale — market issue. “As we’ve heard, there’s DER leakage, potentially, leakage to other sectors, and then I think there’s also a role for DPS in setting the policy in regard to leakage that then NYISO could implement,” he said. “To some extent, that’s a substantive question that I imagine different stakeholders will have different views on.”
Pricing Carbon Affects Everything
Stakeholders said many of the topics were interrelated, such as whether locational-based marginal prices should transparently reflect carbon charges, how to apply the cost of carbon to generator emission rates ahead of delivery, how to allocate carbon revenues, and the possible effects of a carbon price on the capacity market.
NYISO Senior Manager for Market Design Michael DeSocio said, “If you take a DER that is a combination of renewable and non-renewable, I’m not sure when we aggregate those two pieces up to a single resource that we will know exactly how to apply that cost of carbon, but we certainly know after it runs what it did and how much to charge it.” He said the carbon charge might be an opportunity cost-based process in which a resource will be charged after the fact but will need to determine beforehand what cost to incorporate into its offer.
“Or do we need to figure out all the permutations of every configuration of every facility to then apply a cost up front directly into the offer?” he said. “There are some pros and cons to both sides. We first start to think about this with generator fuel blends, but then you take it down the path where we had discussions this morning about DERs, and it gets even more complicated.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that pricing carbon would not change the dynamics of New York’s grid, where lopsided load balances create transmission constraints between upstate and downstate, particularly around New York City and Long Island.
“Thinking about changes and what’s needed in the capacity market, we’ve said look at what New England has been talking about and what PJM has been talking about,” Joseph said. “They’re talking about moving towards a two-tiered clearing market where you have resources that are brought on because of state policy, and that’s highly likely to continue here even if you price carbon because of this transmission issue. … Even if we price carbon, what we do in the capacity market has to be a big part of this discussion.”
Howard Fromer, director of market policy for PSEG Power New York, asked how the sector will determine the social cost of carbon.
“We can’t have a situation where we define the problem at $45 but our solutions are multiples of that,” Fromer said. “I don’t know how you sell that to the public and explain to them why you should pay more than what you said the problem is worth. That doesn’t work too well.”
DeSocio said NYISO planned to use a Dec. 5 joint Market Issues Committee and ICAP Working Group meeting to brief stakeholders on what other RTOs are doing to integrate public policy in wholesale markets.
Bouchez said the task force would hold a technical conference Dec. 11, but that it was unclear whether it would be necessary to hold the public hearing scheduled for Dec. 18, given its proximity to the holidays. Regardless of what meetings take place in December, the task force still plans to issue an initial work plan to stakeholders by the end of January, she said.
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.”
