CAISO and Pacific Gas and Electric are opposing the terms of a reliability-must-run agreement for two California natural gas-fired plants that Calpine submitted with federal regulators early this month, complicating an arrangement set to take effect at the beginning of next year.
The ISO and PG&E filed separate protests with FERC over the terms of the RMR agreement for the Yuba City and Feather River plants, filed with the commission Nov. 2 by Calpine subsidiary Gilroy Energy Center. CAISO designated the units as RMR in March, but the ISO told FERC that Gilroy had not supported provisions related to scheduling coordinator charges, greenhouse gas emissions and gas prices.
Yuba City power plant | Calpine
CAISO is increasing its use of out-of-market RMR payments to keep units online, raising concerns that its market is not producing the price signals sufficient to support units needed to provide reliable electric service. The ISO’s Board of Governors early this month approved the third RMR of this year, for Calpine’s Metcalf Energy Center. (See Board Decisions Highlight CAISO Market Problems.) Costs are borne by utility ratepayers such as those of PG&E.
Map identifying the need for Yuba City and Feather River plants | CAISO
CAISO in its protest did not ask FERC to reject the application but to set it for settlement before the effective date of Jan. 1.
“There are also technical issues with the inputs to the other rate schedules as well, which the CAISO anticipates can be addressed through the exchange of information during settlement discussions and through further informal exchanges between the parties,” the ISO said.
PG&E said FERC should approve the RMR rates for Jan. 1, subject to refund, and launch a separate proceeding “under Section 206 of the Federal Power Act to examine whether the RMR program in the CAISO tariff is unjust and unreasonable.” The utility said “the RMR designations were premature” and will increase costs.
PG&E also noted the increased use of RMR units in recent years.
“After years of decreasing use, such that a minimal number of facilities were designated as RMR units, the CAISO has designated three new RMR units in PG&E’s service territory for 2018 alone,” PG&E said.
California ethics officials have obtained new evidence of apparent back-channel communications between Pacific Gas and Electric and the state Public Utilities Commission in the wake of the fatal San Bruno gas pipeline explosion.
The disclosure comes as the CPUC is poised to consider a proposed $86.5 million settlement agreement over previously disclosed improper communications between commissioners and PG&E, the pipeline operator blamed for the 2010 accident that killed eight people.
The CPUC is poised to approve an $86 million settlement between PG&E, its enforcement staff and other parties
Kennedy | Linkedin
Jay Wierenga, spokesman for the California Fair Political Practices Commission (FPPC), confirmed to RTO Insider that the agency is seeking communications since 2012 between the CPUC and Susan P. Kennedy, a former commissioner and aide to former Gov. Arnold Schwarzenegger. He provided no further details on the probe, which was first reported by The San Diego Union-Tribune.
But in late September, KNTV, the San Francisco Bay Area’s NBC affiliate, quoted a 2013 email in which one commissioner urged PG&E to take a tough stand during secret settlement talks over the San Bruno explosion, which killed eight people. In April 2015, the CPUC ordered the company to pay $1.6 billion in fines and penalties for safety violations.
CPUC spokesperson Terrie Prosper confirmed the agency is responding to an Aug. 21 data request from the FPCC. PG&E said it had no comment on the investigation.
New Violations?
A spokesperson for The Utility Reform Network (TURN) told RTO Insider last week that the newly disclosed emails should be considered separately from the settlement proposed by a CPUC administrative law judge on Sept. 1, which is awaiting action from the commission. TURN is a party to the settlement, negotiated over the past two years between PG&E, CPUC enforcement staff, the cities of San Bruno and San Carlos, and the Office of Ratepayer Advocates.
“The commission needs to take a look at these new ones that appear to show more violations,” TURN spokesperson Mindy Spatt said. “PG&E may well think ‘you’ve seen one email, you’ve seen them all,’ but each of these emails involve separate violations.”
ALJ Robert Mason approved most of the settlement, which includes $63.5 million in foregone revenue requirements for 2018 and 2019; a $10 million penalty to be amortized in the company’s next general rate case cycle; and $6 million each to San Bruno and San Carlos. But the judge said the commission rejects a $1 million fine to the state general fund as too low.
“Given the flagrant and pervasive nature of PG&E’s actions that were not only illegal, but tainted the commission’s regulatory process and undermined public confidence in the integrity of the commissioners and their staff, the commission has determined that a larger fine should be imposed,” Mason wrote.
“This proceeding shall remain open pending the resolution of whether PG&E shall agree to pay the increased fine of $12 million to the state of California General Fund,” Mason wrote.
Kennedy, a longtime member of the California political elite, is a partner in San Francisco-based Caliber Strategies, a public affairs consulting team, and founder of Advanced Microgrid Solutions (AMS), an energy storage company whose investors include Schwarzenegger.
Aside from a broad request for all communications from 2012 to present, the FPPC data request specifically seeks correspondence between the PUC and Kennedy and others at Caliber Strategies that mention PG&E, the pipeline explosion “or any related legal, legislative or regulatory actions that resulted from said explosion.”
The FPCC also requested communications between Kennedy and former Commissioner Catherine Sandoval; former CPUC Executive Director Paul Clanon; current CPUC Communications Advisor Lester Wong; current CPUC Director of Planning Marzia Zafar; former CPUC President Michael Peevey; Carol A. Brown, Peevey’s former chief of staff; and Brigadier General Emory “Jack” Hagan, former director of the CPUC’s Consumer Protection and Safety Division.
The document seeks “any and all verification applications, including all supporting documents, submitted to or through The Supplier Clearinghouse,” a company that certifies minority- and women-owned businesses under a CPUC diversity program.
The FPPC was created by the state’s Political Reform Act of 1974, and its enforcement division has power to take civil actions, not criminal prosecutions, which are under authority of local district attorneys or state attorneys general.
A veteran of the California political scene, Kennedy has worked as chief of staff for Schwarzenegger, cabinet secretary to former Gov. Gray Davis, communications director for U.S. Sen. Dianne Feinstein and executive director of the California Democratic Party.
Kennedy’s spokesman James C. Harrison told RTO Insider in a statement last week: “Ms. Kennedy is aware of the information request and is providing the Fair Political Practices Commission with all of the necessary information regarding the inquiry.”
Kennedy Discusses Peevey with PG&E
The newly disclosed emails reveal Kennedy, then a PG&E consultant, discussing the San Bruno case with PG&E Vice President of Regulatory Relations Brian Cherry in 2013. PG&E said in January 2015 that it had provided 65,000 emails to the CPUC, fired executives including Cherry and implemented new compliance programs to address the improper ex parte contacts.
The site of the 2010 PG&E gas pipeline explosion in San Bruno, California
KNTV reported in September that PG&E had made a regulatory filing stating that it discovered additional emails in response to a search requested by an “unspecified government agency.”
In a Jan. 9, 2013, email, Kennedy discusses meeting with Peevey and recounts his criticism of the CPUC’s “mishandling” of the San Bruno case.
“He hopes [Hagan] can bring something home — but that the crazies are so far out there it may not be possible. Blamed most of the craziness on the locals in [San Bruno] and his personal prosecutor, Jerry Hill. Sounds like a settlement was highly unlikely but not completely off the table.”
Kennedy discusses a “second date” with Hagan in Los Angeles to see a Schwarzenegger movie and that “if I can bring it up without it pushing him the wrong way, I will.”
Hill, now a state senator representing San Bruno, last December questioned why an investigation launched in 2014 by then-Attorney General Kamala Harris into Peevey’s private communications with PG&E was never resolved.
Peevey, appointed president of the CPUC in 2002 by Davis, and reappointed by Schwarzenegger in 2008, stepped down from the CPUC on Jan. 1, 2015.
The FPPC data request also sought communications of Manal Yamout, a partner with Kennedy in Caliber Strategies who is also senior vice president of policy and markets for AMS. The request seeks Yamout’s communications with the San Francisco-based ride-sharing company Lyft.
Yamout is a former top adviser to Schwarzenegger and Gov. Jerry Brown. She also has served as California’s assistant secretary for international Trade, and special assistant to former First Lady Maria Shriver.
Yamout was the topic of a November 2014 report by the U.S. Department of the Interior’s inspector general regarding her romantic relationship with former DOI Senior Counselor Steven Black when she was a lobbyist for Florida-based NextEra Energy. The U.S. Attorney’s Office for the District of Columbia declined to prosecute the case. Black recused himself from matters involving NextEra and resigned from the department in May 2013.
Both Black and Yamout were members of the Renewable Energy Policy Group, created in 2009 by Schwarzenegger and Interior Secretary Ken Salazar, under whom Black served. The group was formed to improve federal-state coordination in siting renewable energy projects.
Yamout did not respond to a request for comment regarding the investigation.
Strong Growth for Advanced Microgrid Solutions
AMS has grown into a major player in California’s burgeoning energy storage market since its founding in 2013. Kennedy started the company with the late Jackalyne Pfannenstiel, a former PG&E executive who also served on the CPUC and the California Energy Commission.
AMS is not mentioned in the FPCC information request.
The company and Macquarie Capital have teamed up to deploy a 50-MW fleet of energy storage batteries in the service territory of Southern California Edison.
Last year, Macquarie announced a $200 million investment to fund AMS projects in California. The company is also funded by Southern Co.; DBL Partners; GE Ventures; AGL Energy, Schwarzenegger; and an investment firm named Energy Impact Partners.
Energy Impact Partners’ Advisory Board counts among its members Steven Chu, secretary of energy under President Barack Obama; Spencer Abraham, secretary of energy under President George W. Bush; and Rodney Slater, secretary of transportation under President Bill Clinton.
The RTO Insider Top 30 saw improved profits in the third quarter over 2016, but revenues fell, and more than half of the companies saw their top and bottom lines shrink.
| company filings
Net income grew $563.7 million (5.3%) to $11.1 billion as all 30 companies turned a profit, indicating that their problems weren’t strong enough to overcome the seasonal strength of the quarter that includes the year’s two hottest months. Still, 17 companies saw their income fall.
Revenue fell $1.36 billion (1.6%) to $85.4 billion, with 18 companies posting revenue declines, in some cases because of unfavorable weather.
Company
Market Cap ($ billions)
Revenue Q3 2017 ($ billions)
% change vs. 2016
Net Income Q3 2017 ($ millions)
% change vs. 2016
AEP
$37.67
$4.10
-11.77%
$544.7
-171.1%
Alliant
$10.22
$0.91
-1.91%
$168.8
31.5%
Ameren
$15.27
$1.72
-7.32%
$288.0
-22.0%
Avangrid
$15.79
$1.34
-5.43%
$99.0
-9.2%
Berkshire Hathaway Energy
NA
$5.28
3.75%
$1,068.0
3.1%
Calpine
$5.42
$2.59
9.81%
$225.0
-23.7%
CenterPoint Energy
$12.56
$2.10
11.06%
$169.0
-5.6%
CMS Energy
$13.93
$1.53
-3.78%
$172.0
-7.5%
Consolidated Edison
$26.87
$3.21
-6.03%
$457.0
-8.0%
Dominion Energy
$52.87
$3.18
1.50%
$665.0
-3.6%
DTE Energy
$20.20
$3.25
10.83%
$270.0
-20.1%
Duke Energy
$62.04
$6.48
-1.43%
$954.0
-18.9%
Edison International
$26.11
$3.67
-2.52%
$470.0
11.6%
Entergy
$15.41
$3.24
3.81%
$398.2
2.6%
Eversource Energy
$20.22
$1.99
-2.51%
$260.4
-1.9%
Exelon
$40.13
$8.77
-2.59%
$824.0
68.2%
FirstEnergy
$15.23
$3.71
-5.18%
$396.0
4.2%
Great Plains Energy
$7.39
$0.86
0.05%
$3.4
-97.4%
NextEra Energy
$73.00
$4.81
0.06%
$847.0
12.5%
NiSource
$9.11
$0.92
6.47%
$14.0
-48.5%
NRG Energy
$9.25
$3.05
-10.87%
$171.0
-57.5%
OGE Energy
$6.97
$0.72
-3.64%
$183.4
-0.1%
PG&E
$27.72
$4.52
-6.09%
$550.0
41.8%
Pinnacle West Capital
$9.98
$1.18
1.41%
$276.1
5.0%
PPL
$24.83
$1.85
-2.33%
$355.0
-24.9%
PSEG
$26.03
$2.26
-7.63%
$395.0
20.8%
Sempra Energy
$29.82
$2.68
5.44%
$57.0
-90.8%
WEC Energy Group
$21.54
$1.66
-3.21%
$215.4
-0.7%
Westar Energy
$7.96
$0.79
3.88%
$158.3
2.3%
Xcel Energy
$25.66
$3.02
-0.76%
$492.1
7.5%
Totals
$669.2
$85.4
-1.57%
$11,146.8
5.3%
American Electric Power posted by far the largest increase in net income — $1.31 billion — but that was largely due to its 2016 performance, when it lost $765.8 million because of a $2.3 billion write-down on the value of its competitive wind farms, coal generators and coal-related properties. (See AEP Turns Away from Generation to Transmission, PPAs.) AEP earned $544.7 million in the just-ended quarter, but its adjusted earnings per share of $1.10 missed the Zacks consensus estimate of $1.19 and were down from $1.30/share — excluding the impairment — a year ago.
After releasing its earnings, AEP said it plans to invest $18.2 billion from 2018 through 2020, 72% of which will be focused on its transmission and distribution operations. That includes $1.8 billion in new renewable generation, but excludes the $4.5 billion Wind Catcher project in Oklahoma, which is dependent on regulatory approvals in 2018. (See AEP to Spend $4.5B on Largest Wind Farm in US.)
Exelon had the largest percentage increase in net income, 68.2% ($824 million), primarily due to increased profits at Commonwealth Edison ($152 million) and its generation unit ($69 million). Company executives also said its utilities were performing better than planned.
| company filings
Exelon’s bottom-line success hasn’t stopped it from pushing for subsidies for its nuclear generation fleet, which is the largest in the nation. In its third-quarter earnings call, CEO Chris Crane said the company was encouraged by Energy Secretary Rick Perry’s Notice of Proposed Rulemaking, which, if adopted by FERC, would give a financial boost to Exelon’s nuclear plants (RM18-1). (See CEOs See Dollar Signs in ZECs, PJM Price Formation.)
After Exelon released its earnings, its Texas merchant generation business, ExGen Texas Power, filed for bankruptcy protection to offload most of a $675 million loan due in September 2021. The company plans to relinquish four Texas natural gas plants to lenders and pay $60 million to keep a fifth plant in response to what the company called “historically low power prices” in Texas. (See Exelon Gives up 4 of 5 Plants to Lenders in Chapter 11 Filing.)
Sempra Energy had the largest decrease in net income, dropping $565 million to $57 million, because of a California Public Utilities Commission administrative law judge’s decision denying subsidiary San Diego Gas & Electric’s request to recoup losses stemming from wildfires a decade ago. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.) Although the PUC hasn’t decided whether to accept its ALJ’s ruling, accounting rules require Sempra to reflect the decision in its results. The PUC is slated to decide on the matter at its Nov. 30 meeting. Sempra has said it will appeal the decision if it’s not allowed to recover the costs.
Great Plains Energy had the largest percentage decrease in net income, falling 97.4% to $3.4 million, because of the $162.9 million it spent in its attempted acquisition of Westar Energy. Great Plains recast the deal as a “merger of equals” in August after the Kansas Corporation Commission blocked an earlier version of the deal in April. (See Great Plains, Westar File Revised Merger Plan.) Shareholders for both companies approved the revised deal on Nov. 21.
DTE Energy had the largest revenue gain, jumping $317 million to $3.25 billion, largely because of a $392 million increase in operating revenue from the non-utility operations of its energy trading unit. In percentage terms, however, DTE’s 10.8% revenue increase, was second to the 11.1% increase by CenterPoint Energy, which saw its revenue grow to $2.1 billion because of a $257 million revenue increase at its energy services segment.
AEP posted the largest revenue decrease in dollars and percentage terms, falling $547 million (11.8%) to $4.1 billion, because of what it called the mildest weather conditions in 25 years.
In a Nov. 16 memo to Commissioners Brandy Marty Marquez and Arthur D’Andrea, Public Utility Commission Chair DeAnn Walker said a pair of recent developments could place the electrical separation between ERCOT and the rest of the country “in jeopardy” by allowing energy to flow between Texas and other states through Mexico’s national grid. ERCOT has several synchronous (alternating current) and asynchronous (direct current) ties with the Mexican grid.
Walker pointed to Nogales Transmission’s application for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). The project would consist of a 150-MW substation in Tucson Electric Power’s service territory, capable of being expanded to 300 MW; a 138-kV transmission line on the Arizona side near the city of Nogales; and a 230-kV line across the border that would connect to the Mexican grid. Nogales Transmission is a subsidiary of Dallas-based Hunt Power.
| Mexico Ministry of Energy
Walker also is concerned about an HVDC line linking the Mexican state of Baja California with the country’s central grid. That project, in the advanced planning stage, would provide a major tie between Mexico and California, which already has two connections with Baja California with a total capacity of 800 MW. In addition, California’s Imperial Irrigation District (IID) signed an agreement with CENACE, Mexico’s grid operator earlier this year, to study the exchange of up to 600 MW of energy with Baja California. IID has said the two have plans for a pair of interties to be completed in 2019 and 2020.
The Baja California system is part of the Western Electricity Coordinating Council (WECC) and not interconnected with the rest of Mexico. Sempra Energy also has a presidential permit that allows it to import renewable energy from Baja California, helping make up for the loss of the San Onofre Nuclear Generating Station.
“Those are issues that will occur outside of the United States for which the [Texas] commission will likely have no notice or participation opportunities,” Walker told Marquez and D’Andrea.
The chairwoman said FERC staff contacted the PUC “to convey concern” that the Nogales interconnection could affect FERC’s jurisdiction over ERCOT. A FERC order in 2007 noted that electricity generated within ERCOT and transmitted across a Sharyland Utilities DC tie to Mexico could not flow into WECC territory “because the Baja California system is not interconnected with the national Mexico grid,” she said.
“I’m very, very concerned about it,” Walker said. “Even if they take care of the issues in Arizona, I still have concerns about the impacts in California. We need a solution. This isn’t something we’re going to sit back and wait for it to happen.”
Nogales Transmission has asked the Department of Energy to delay processing its presidential permit until it can obtain “the necessary FERC disclaimer” of jurisdiction, Walker said.
Walker noted in her memo that FERC could exert its jurisdiction over ERCOT through the Commerce Clause of the U.S. Constitution “if the commingling of power between ERCOT and the rest of the United States occurs.”
Because ERCOT administers the Texas Interconnection — located solely within the state and not synchronously interconnected with the rest of the U.S. — FERC generally does not have jurisdiction over the ISO. There are several DC lines between Texas and other U.S. states; developers of these lines must seek a declaratory order from FERC saying they will not affect ERCOT’s independent status.
Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines.
Walker has already met with the leadership of AEP Texas, CenterPoint Energy, Oncor and Sharyland to discuss the situation. AEP and Sharyland own the state’s three DC ties with Mexico.
Walker noted the Nogales project would transmit from Arizona to the Mexican transmission system, to which Sharyland is already connected. “The change of circumstances suggests that Sharyland, ERCOT and other market participants should seek an order from FERC that they will retain their nonpublic utility status” under the FPA, Walker said.
ERCOT’s independence “is not only a source of pride, but it makes our market work so well,” Marquez said during the commission’s Nov. 17 open meeting. “We have to explore every opportunity to preserve and protect our jurisdiction.” She said she would be working with ERCOT staff to see “what types of mechanisms we can use” to protect the ISO’s independence.
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.
