CARMEL, Ind. — MISO will likely add new details to its monthly operations reports as a result of an annual review, engineer Oluwaseyi Akinbode told the Nov. 29 Market Subcommittee meeting.
Akinbode said MISO will add a market efficiency metric based on the alignment of the financial transmissions rights, day-ahead and real-time markets. (FTR shortfalls plus real-time excess congestion funds divided by FTR target credits.)
Market efficiency is expected to maintain a 12-month rolling average of at least 94%. If the rolling average falls to 92% or lower, or the monthly average falls below 87%, the issue will be flagged for review by MISO staff.
Jeff Bladen, executive director of market services, said the metric will help the Board of Directors understand the reasoning behind future proposals for market improvements. “It’s intended to be a broad indicator and not a surgical tool to identify improvements with,” he said.
WPPI Energy economist Valy Goepfrich said the new metric is difficult to understand and asked how MISO calculates FTR shortfalls.
Akinbode also said MISO will add charts depicting transfer trends between the RTO’s North and Central regions and MISO South. He asked for comments through mid-December and said MISO would respond to stakeholder suggestions in January.
| MISO
Run Reason Requirement Shelved
MISO has canceled plans for a mechanism to track the reasons behind commitment decisions because of a lack of stakeholder interest.
The mechanism would have tracked information including start and stop times, run reasons and sources of commitments. A similar project was shelved in 2012. At that time, MISO’s market communication system provided the information, but it is no longer “the system of record,” the RTO said.
Constellation Energy requested the tracking mechanism in May 2016. But Bladen said MISO’s request for feedback on the possible data collection yielded only four stakeholder responses, half of them expressing low interest and the other half asking the project not be taken up.
“So, on the basis of that, we are not pursuing this item,” Bladen said. He added that stakeholders may raise the topic again using the Steering Committee’s issues introduction process.
The initiative is expected to be closed at the December Steering Committee meeting.
CARMEL, Ind. — MISO will continue its efforts to improve gas-electric coordination in 2017, revealing a plan for the year that includes more data sharing, modeling and outreach.
The top 2017 goals include disclosing generators’ hourly gas usage profiles to gas system operators and improving modeling to identify future electric transmission and pipeline expansion needs. The RTO also plans on continuing to issue market updates to stakeholders and communicate with gas industry officials and regulators.
Pipelines | MISO
Other tasks include creating a gas generator database and NERC studies on gas contingencies, MISO strategy adviser Scott Wright told the Resource Adequacy Subcommittee on Nov. 30.
MISO will launch a pilot project to share two or three generators’ day-ahead gas usage profiles with gas system operators. The RTO will use its day-ahead clearings to forecast hourly gas usage. Wright noted that FERC Order 787 enables sharing of nonpublic operational information with gas pipelines for “reliability and operational planning.”
Indianapolis Power and Light’s Lin Franks said the RTO has done “a fine job” so far in getting pipeline and gas resource owners to communicate, such as providing real-time pipeline restrictions and notifications.
But she cautioned the RTO against involving itself in fuel contracts between gas suppliers and generators and said MISO’s gas role should be limited to providing operational data transparency and not influencing new products or rules.
“None of these contracts are exactly alike,” Franks said. “Managing our fuel supply is our obligation, not MISO’s. We’ve got to be very careful here that MISO doesn’t insert itself in our ability to manage our fuel supply. It is our job to ensure adequate supply to our generation. This one seems to be ripe for a fight on jurisdiction.”
Wright said the main thrust behind the coordination is fuel assurance. “By no means [are we] thinking that we’re going to get in between a generator and its pipeline. It’s, ‘Are there ways to unlock efficiencies in the gas coordination market?’”
Wright said he didn’t understand stakeholder concerns that gas was being treated differently than coal in terms of fuel assurance. “Why gas and not coal? I find it befuddling the references to the coal pile,” Wright said. “Gas is different. All of these pipelines are FERC-regulated. Coal is off by itself.”
MISO houses about 200 gas-fired generators and more than 30 pipelines. Gas resources, which currently comprise 42% of its generation fleet, will rise to 50% in the coming years, according to the RTO.
In October, gas was 12.8% of the dispatched generation fuel mix in MISO’s Central Region, versus 5.4% of the mix in MISO North and 63.4% of that in MISO South.
“The outlook of gas is it will grow, and in some ways MISO is catching up. There’s going to be a lot of gas demand growth in MISO North and Central,” predicted Wright.
Gas Generators Ready for Winter
Gas system operators reported a “high level” of winter preparedness in The RTO’s third winter generator fuel survey. MISO Electric Gas Operations Coordinator Mark Thomas said 174 gas-fired facilities (representing 63,600 MW, 87% of the RTO’s gas-fired capacity), participated in the survey.
Fuel Survey Results | MISO
The survey reported connections to more than 30 gas systems in the footprint, with approximately 46,550 MW, or 65% of MISO gas capacity, connected directly to intrastate and interstate pipelines. About 70% of MISO North/Central gas capacity is connected to just five pipelines through direct connect or local distribution companies. MISO found 40% of gas-fired capacity (28,900 MW) had firm transportation and/or dual-fuel capability. “Though an increase from the previous survey, questions remain as MISO expects gas reliance to grow,” the RTO said.
The RTO also found that 42% of responding capacity (30,850 MW) subscribes to no-notice services and 37% of capacity (27,340 MW) has access to firm or interruptible storage.
However, Thomas said 11% of responding generators said they did not have a detailed weatherization plan, including insulation, wind breaks and equipment shelters. He said it was “surprising” that so many did not have a plan in place and wondered whether the question was worded clearly enough.
The third quarter was a good one for the RTO Insider Top 30, as companies reported a 4% increase in revenues over a year earlier and a 22% increase in net income.
Six companies — Avangrid, Calpine, CenterPoint Energy, DTE Energy, Exelon and Great Plains Energy — reported at least a 10% increase in year-over-year revenue. Centerpoint and Entergy rebounded from losses a year earlier.
American Electric Power, which wrote down the value of its Ohio merchant generation by $2.3 billion, was the only company to report a loss for the quarter. (See related story, AEP Ohio Rate Plan Excludes Merchant Generation.)
Consolidated Edison, Pinnacle West Capital, NextEra Energy, FirstEnergy, Entergy, Public Service Enterprise Group and NRG Energy all reported drops in revenue.
NRG reported a six-fold increase in net income despite a nearly 11% drop in revenue, thanks largely to a $266 million gain on sale of assets in the third quarter. Excluding the sale, and $263 million of impairments in the third quarter of 2015, net income declined $203 million because of lower energy margins and increased debt costs, the company said. (See NRG Continues to Pare Down Businesses, Affirms Guidance.)
Sempra Energy and Avangrid each saw profits more than double over 2015.
Company
Market Cap ($ billions)
Revenue Q3 2016 ($ billions)
% change vs. 2015
Net income Q3 2016 ($ millions)
% change vs. 2015
NextEra Energy
54.15
4.81
-3.01
789.00
-10.54
Duke Energy
51.05
6.82
5.21
1181.00
26.31
Dominion Resources
46.57
3.13
5.42
690.00
16.36
American Electric Power
31.57
4.65
4.98
(765.80)
-247.67
Exelon
30.74
9.00
21.63
526.00
-16.38
PG&E
29.59
4.81
5.71
391.00
26.13
Berkshire Hathaway Energy
NA
5.09
0.45
1047.00
18.44
Sempra Energy
26.80
2.54
2.18
622.00
150.81
Edison International
23.54
3.77
0.11
449.00
0.22
PPL
23.48
1.89
0.59
473.00
20.36
Consolidated Edison
22.95
3.42
-0.76
497.00
16.12
Public Service Enterprise Group
21.18
2.45
-8.85
327.00
-25.51
Xcel Energy
20.90
3.04
4.79
457.80
7.35
WEC Energy Group
18.90
1.71
0.81
217.30
19.07
Eversource Energy
17.19
2.04
5.51
267.20
12.36
DTE Energy
16.81
2.93
12.70
325.00
23.11
FirstEnergy
14.08
3.92
-5.00
380.00
-3.80
Entergy
13.74
3.12
-7.32
388.17
-153.69
Avangrid
12.91
1.42
35.31
109.00
101.85
Ameren
11.93
1.86
1.42
369.00
7.58
CMS Energy
11.72
1.59
6.80
186.00
25.68
CenterPoint Energy
10.00
1.89
15.89
179.00
-145.78
Alliant Energy
8.72
0.92
2.86
131.00
-28.22
Pinnacle West Capital
8.46
1.17
-2.69
263.03
2.30
Westar Energy
8.04
0.76
4.34
158.55
12.80
NiSource
7.78
0.86
5.40
27.20
-655.10
OGE Energy
6.31
0.74
3.35
183.60
65.11
Great Plains Energy
5.88
0.86
9.65
133.60
5.36
Calpine
4.54
2.36
20.89
301.00
7.89
NRG Energy
3.54
3.95
-10.87
402.00
509.09
TOTAL
$87.51
3.9%
$10,704.64
21.6%
NOTE: Net Income figures include minority interests; exclude income not available to common shareholders.
Aliso Canyon Injections by Year-end?
Sempra reported third-quarter 2016 earnings of $622 million, up from $248 million a year earlier. Its California utilities saw earnings rise by $21 million, primarily because of higher margins.
San Diego Gas & Electric won state regulators’ approval to own and operate 37.5 MW of energy storage expected to enter commercial operations in the first quarter of 2017.
The company said its Southern California Gas unit “has made significant infrastructure technology and safety enhancements” to the Aliso Canyon gas storage facility and hopes to win regulators’ approval to resume injections by the end of the year.
Avangrid Adding 2,350 MW of Wind Capacity
Avangrid, formerly Iberdrola USA, said it earned net income of $109 million versus $54 million a year ago ($76 million if the costs of the company’s merger with UIL Holdings are excluded.)
CEO James P. Torgerson credited the improvement to “solid earnings” in its networks and renewables businesses, thanks to a rate settlement in New York, higher wind production and the “extension of the useful life of certain wind assets.” The company’s networks unit includes electric and gas utilities in New York, Maine, Connecticut and Massachusetts. Its renewable unit owns 53 wind farms with 5,643 MW of capacity in 18 states.
The company said it will purchase equipment for up to 2,000 MW of additional wind generation and more than 350 MW to repower existing wind turbines by the end of the year to obtain the full value of production tax credits.
“Also, we are contracting additional power purchase agreements as we continue to manage our merchant exposure,” Torgerson said.
WESTBOROUGH, Mass. — A transmission project intended to release bottled wind resources in Maine may not be cost-effective, according to a draft report issued at the ISO-NE Planning Advisory Committee meeting last week.
The needs assessment for the Keene Road market efficiency transmission upgrades showed relatively small annual savings in energy production costs of $1.35 million to $1.38 million (2015 $) if the export limits were raised from the current 165 MW to 195 MW.
Detail of Keene Road Constrained Area | ISO-NE
An additional increase to 225 MW would save another $100,000 to $180,000. No additional savings are realized if the limit is further raised to 255 MW. The assessment measured the four export limits for the years 2020, 2025 and 2030.
A preliminary economic study from last year estimates the project could save ISO-NE ratepayers $1.4 million to $5.7 million by allowing additional wind development in the area and displacing more expensive hydropower.
“This has the look of providing a de minimis benefit, so you have to ask if it’s worth doing,” said Bob Stein of Signal Hill Consulting Group, who represents Hydro-Quebec and other power generators.
Michael Henderson, ISO-NE’s director of regional planning and coordination, said those were “questions more properly dealt with at a later date.”
The RTO has not released any estimates on the cost of the upgrades, which would be eligible for competitive bidding under FERC Order 1000.
Rollins Wind Farm in Maine | Reed & Reed, Inc.
Under the RTO’s Tariff, the cost of a market efficiency project must be less than the resulting production cost savings. “If the ISO does issue a request for proposals and no developer provides a proposal that meets this cost threshold, then no regionally funded transmission project would move forward,” ISO-NE spokeswoman Marcia Blomberg told RTO Insider on Thursday.
A final discussion of the results will be held at the December PAC. In January, the committee will discuss whether to move toward a competitive solicitation for bids from potential developers.
Eighteen years after opening retail electric and gas choice, New York regulators concluded Friday that the initiative has failed, launching a proceeding that could bar energy service companies (ESCOs) from operating in the state.
“After considerable experience with the offering of retail service to mass-market customers by ESCOs, the [New York Public Service Commission] has determined that the retail markets serving mass-market customers are not providing sufficient competition or innovation to properly serve consumers,” the commission wrote in its notice (98-M-1343). “Despite efforts to realign the retail market, customer abuses and overcharging persist, and there has been little innovation, particularly in the provision of energy efficiency and energy management services.”
The commission has attempted to revamp consumer protections in the program, including a guarantee of savings for customers not enrolled with green energy suppliers, but it has been thwarted by the courts. (See Marketers Seek Rehearing on NY Low-Income Moratorium.)
Two-Track Process
The notice sets out a two-track process, one an evidentiary process to determine “whether ESCOs should be completely prohibited from serving their current products to mass-market customers” or whether reforms could save it. Evidentiary hearings will follow written submissions from energy marketers, consumers and PSC staff on a list of 20 questions posed in the notice. Responses are due April 7, 2017.
The commission defines “mass-market” customers as residential and small commercial customers — those whose bills do not include a demand rate element.
Among the questions is whether the commission currently has authority to penalize ESCOs for abuses and whether it should revisit its decision to exempt them from Article 4 of the Public Service Law. Another asks whether ESCOs should be required to offer value-added energy efficiency and energy management services as a condition of selling gas and electricity.
The second track would include “collaborative” meetings of interested parties to develop proposals on what new practices or products “would provide sufficient real value to mass-market customers … [and] ensure just and reasonable rates.”
“For too long, [the PSC] has seen substantial overcharges and deceptive practices by the ESCO industry harming New York consumers,” the commission said in a press release. “As part of these hearings and by obtaining testimony under oath, we will give ESCOs the opportunity to explain their pricing practices and to hear from consumers who have been harmed by these practices. We will then push ahead with reforms to ensure that ESCOs provide useful, value-added, economical services to New York consumers, particularly as part of our efforts under Reforming the Energy Vision.”
ESCOs Cry Foul
ESCOs have said the state’s approach to reform has been heavy-handed and has not given them a proper chance to respond to the allegations. They have also challenged the state’s data.
“The Retail Energy Supply Association believes that a fair and impartial review of New York’s competitive energy markets will show clear and unambiguous benefits for consumers and the state’s economy,” spokesman Bryan Lee said Monday. “RESA seeks to keep the competitive markets for electricity and natural gas open to all consumers. RESA intends to actively participate in this Public Service Commission proceeding to achieve that goal. Consumers enjoy and demand choices in every aspect of their daily purchasing decisions, from car insurance and cell phone providers to doctors and vacation destinations. Any policy changes ultimately identified by the commission must preserve opportunities for choice by consumers in their energy supply decisions.”
Retail choice was phased in by utilities on different schedules, beginning with Consolidated Edison in 1998.
More than 20% of New York’s residential and small commercial customers currently receive energy from one of the approximately 200 ESCOs operating in the state. Regulators have previously cited several examples of unacceptable conduct, including companies that charged more than double or triple the rates of incumbent utilities. The commission has also cited examples of companies falsely representing themselves as local utilities.
BOSTON — The New England Power Pool’s collaborative process to address climate change while preserving wholesale electricity markets won an endorsement from FERC Commissioner Cheryl LaFleur at the ISO-NE Consumer Liaison Group meeting Thursday.
LaFleur, a New England native, was referring to the Integrating Markets and Public Policy collaborative, which seeks to reconcile markets with state mandates to decarbonize the grid. (See Markets vs. Climate Goals the Subject at NECA Conference.)
Stakeholders are meeting into next year with the goal of having ISO-NE present Tariff revisions to FERC.
“I think there’s a lot in it for customers because we will still harness the power of the competitive market while also having the states address climate change [to see if] those are two things that can be reconciled,” she said.
One contentious point is that states have mandated clean energy procurements leading to subsidized out-of-market contracts that skew prices.
“What I’m worried about as we go forward is if we go without a plan and try to have it both ways: try to have a market that’s working … but then we get to a place where it’s not working and it begins to be cannibalized by the subsidized resources,” LaFleur said.
Noting the unlikelihood that the Trump administration would endorse a federal carbon tax, LaFleur said that the commission would probably look favorably on a state-based consensus that meets the regional goals along with market-based solutions.
“In my mind, Plan A is the region creates some kind of comprehensive plan that recognizes the state environmental goals and the [role of] pricing in the wholesale market and files it at FERC,” she said.
She said the two alternatives would have unappealing outcomes: The current state of affairs, with FERC acting as arbiter in the disputes between state governments, RTOs and market participants; or a de facto reregulation, as states more actively promote resource adequacy with preferences for cleaner energy sources, with out-of-favor generators then looking for their own state support.
“Pretty soon you realize the market’s pretty small and you’ve reregulated in a messy, expensive way. I don’t think that’s a good idea, particularly for a region that invented competitive markets, ISO-NE,” she added.
Adjustments Ahead
Besides an expected lessening of government activism in climate policy, LaFleur will have to adjust to being a minority member of FERC when three Republicans are expected to be nominated to FERC next year.
“[FERC commissioner] is my first government job and it’s only been for President Obama, so I’ll see what it’s like,” she said. LaFleur said the Democrats on the commission had a good working relationship with the former Republican members. “The only thing we’ve had that had a partisan feel was anything that relates to environmental rules.”
That could continue.
“One of the things everyone will be watching is where the new administration takes us in the intersection of energy and the environment,” she said.
Regardless of what the Trump administration does, LaFleur said, she’s on FERC for the duration.
“I plan to serve out my term until 2019. I don’t know what anybody else is going to do, but I know what I’m going to do,” she said.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee assigned two subcommittees to consider responses to discrepancies in day-ahead market make-whole payments.
ERCOT staff said it noticed a material increase in make-whole payments in November, which it said resulted from the implementation in June of NPRR617, which eliminated the caps on the first two parts of three-part day-ahead offers. It said a review determined the increase resulted from a mismatch between start-up and minimum energy costs used by the day-ahead market’s clearing engine and those used for payments.
None of the operating days met the 2% threshold to prompt resettlements. A software code fix corrected the problem effective Nov. 16.
The ISO is evaluating additional means of monitoring settlement outcomes “to more rapidly identify implementation issues or other anomalies in the future.”
TAC Chair Adrianne Brandt assigned the issue to the Commercial Operations and Wholesale Market subcommittees for further discussion and potential policy recommendations.
Committee Vice Chairs Approved
The TAC unanimously confirmed Oncor’s Martha Henson as vice chair of the Protocol Revision Subcommittee. The committee also unanimously confirmed the re-election of TXU Energy’s John Schatz as vice chair of the Commercial Operations Subcommittee.
The TAC approved three nodal protocol revision requests (NPRRs), one nodal operating guide revision (NOGRRs) and two revisions to the Settlement Metering Operating Guide (SMOGRRs).
The committee tabled a Commercial Operations Market Guide revision request (COPMGRR044), pending the COPS’ resolution of the related NPRR794. The changes relocate reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols.
NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. Also approved was the related PGRR051.
NPRR803: Removes un-codified language from NPRR439, which was approved four years ago and updated a counter-party’s available credit limit for the day-ahead market’s current day.
NOGRR162: Establishes a process for resolving real-time data discrepancies that affect ERCOT’s network security analysis. NERC Standard IRO-010-2 (Reliability Coordinator Data Specification and Collection) requires ERCOT and applicable entities to have a mutually agreeable process for resolving real-time data conflicts.
SMOGRR018: A change sponsored by the Texas Industrial Energy Consumers will allow efficient private use network configurations without jeopardizing ERCOT-polled settlement metering requirements.
SMOGRR019: Makes several changes to the Settlement Metering Operating Guide, including a requirement that nameplate photos be submitted as part of site certification package for new or replacement instrument transformers.
Stakeholders also left NOGRR164 on the table until its accompanying protocol change (NPRR792) can be taken up by the board next week. The TAC will then conduct an email vote on the NOGRR.
CARMEL, Ind. — MISO has come up with two possible responses to its Independent Market Monitor’s suggestion to apply its 50-MW physical withholding threshold to affiliated market participants collectively, rather than individually.
MISO told the Resource Adequacy Subcommittee on Nov. 30 that the withholding threshold should either use allocations based on load ratio share, or the fixed 50-MW limit should be scrapped in favor of a new threshold based on percentage of generation assets.
MISO’s Cliff Risley said the downside to the load ratio share option is that market-sensitive information could be released inadvertently through how many megawatts each affiliate is awarded. Risley also said the percentage option could result in more allowed withholding overall and weaken capacity market efficiency.
MISO and the Monitor are proposing to set withholding limits on a company basis rather than the current market participant basis, which allows affiliates to hold back 50 MW apiece without overstepping the Planning Resource Auction withholding threshold. (See “MISO Takes 1st Steps in Monitor Recommendations,” MISO Resource Adequacy Subcommittee Briefs.)
Monitor David Patton said the two alternatives remove the “common incentive” for affiliates to withhold to boost prices for a sister company, but putting the 50 MW on a pro rata basis is “more draconian” than the current market rules.
“There are cases where withholding less than 50 MW is mitigated. You’ve now made the affiliation more stringent,” Patton said. He also said he didn’t know how the percentage method could be distributed fairly.
Some stakeholders argued that FERC Order 697 already prohibits coordination among affiliates that are franchised public utilities and the withholding proposal should only apply to affiliates not covered by the rule.
Risley asked for more stakeholder feedback before Dec. 14.
Projects Without GIA Counted in OMS-MISO Survey?
MISO’s Darrin Landstrom asked stakeholders if the RTO should include resources that have yet to secure a generator interconnection agreement in the annual OMS-MISO Survey.
| MISO
Currently, MISO only includes Tier 1 resources — those that have a signed generator interconnection agreement — into the survey’s regional and zonal weighted averages. The RTO is asking if it should include Tier 2 resources — projects still in the interconnection queue — into the survey totals, or create a separate survey category for them. RASC Chair Gary Mathis asked if MISO could use historical data to calculate the likelihood of projects being completed after they enter the final stage of the queue. Landstrom said the option could be explored.
Laura Rauch, MISO’s manager of resource adequacy coordination, reminded stakeholders that MISO’s ongoing effort to revise its queue rules could complicate the suggestions, as the queue’s stages and restudy periods could be changed.
Landstrom asked for input on the issue by Dec. 15.
IMM Clears Up Market Mitigation Application
The Monitor is proposing a Tariff change to make clear which resources are subject to PRA market mitigation measures.
IMM staffer Michael Chiasson said market mitigation will apply to “generation resources, including behind-the-meter generation, that are internal to or are pseudo-tied into MISO.”
Chiasson said MISO’s Tariff is currently unclear as to what resources are answerable to the Monitor; the edits would be made to Module D.
Demand resources, energy efficiency resources and external resources will be exempted from market mitigation measures, Chiasson said. He asked for stakeholder feedback by Dec. 14.
UPDATE: Quoting unnamed transition team officials, The New York Times, The Washington Post and others reported Dec. 7 that President-elect Trump plans to nominate Oklahoma Attorney General Scott Pruitt as EPA Administrator. Trump confirmed the reports Dec. 8.
By Rich Heidorn Jr.
President-elect Donald Trump is sending EPA watchers conflicting signals, interviewing potential agency heads who are vocal critics of climate science while also claiming an “open mind” on the issue.
In an interview with editors and reporters of The New York Times on Nov. 22, Trump said he has an “open mind” on humans’ role in global warming, appearing to soften his campaign pledge to withdraw the U.S. from the Paris Agreement.
Former vice president and climate activist Al Gore speaks with reporters after meeting with President-elect Donald Trump at Trump Tower in New York on Nov. 5.
On Monday, Trump met with former vice president and climate activist Al Gore at the invitation of Trump’s daughter Ivanka. Gore told reporters afterward the “lengthy and very productive session” was a “sincere search for areas of common ground.”
Politico reported Dec. 1 that Ivanka intends to make climate change “one of her signature issues.” Quoting a source close to her, Politicosaid Ivanka, who has endorsed liberal positions on pay equity and parental leave, “is in the early stages of exploring how to use her spotlight to speak out on the issue,” seeing herself as a “bridge” to moderate and liberal women.
That would put her in conflict both with her father’s prior statements on the issue and those of EPA transition leader Myron Ebell and the candidates rumored to be in the running to head the agency.
The Associated Press reported Nov. 29 that it had seen internal documents from the president-elect’s transition team that indicate the new administration plans to stop defending the Clean Power Plan in court. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
‘Bunch of Bunk’
Trump’s Chief of Staff Reince Priebus told Fox News on Nov. 27 that the president-elect’s “default position” on climate change is that “most of it is a bunch of bunk.”
“The only thing he was saying after being asked a few questions about it [by the Times] is, look, he’ll have an open mind about it, but he has his default position, which most of it is a bunch of bunk, but he’ll have an open mind and listen to people,” Priebus said.
Pruitt | ScottPruitt.com
On Nov. 28, Trump met in New York with two rumored EPA candidates, Oklahoma Attorney General Scott Pruitt, one of the state officials leading the legal challenge to the CPP, and Kathleen Hartnett White, former head of the Texas Commission on Environmental Quality, who has criticized “the imperial EPA.”
Other EPA candidates, according to Reuters, include two former EPA executives during the George W. Bush administration, energy attorney Jeff Holmstead and Mike Catanzaro, a lobbyist for CGCN Group. Venture capitalist Robert Grady of Gryphon Investors, who served in President George H.W. Bush’s administration, also is in the running, Reuters reported.
‘Looking Very Closely’
White | Texas Public Policy Foundation
Although Trump did not specifically mention the CPP during the Times interview, his moderate tone was a marked contrast to his previous bombast on global warming.
Trump was asked by Times columnist Thomas Friedman if he would “take America out of the world’s lead of confronting climate change.” Trump responded that he is “looking at it very closely.”
“I absolutely have an open mind. I will tell you this: Clean air is vitally important. Clean water, crystal clean water is vitally important. Safety is vitally important,” Trump said.
Editorial page editor James Bennet asked, “When you say an open mind, you mean you’re just not sure whether human activity causes climate change? Do you think human activity is or isn’t connected?”
Trump responded: “I think right now … well, I think there is some connectivity. There is some, something. It depends on how much. It also depends on how much it’s going to cost our companies. You have to understand, our companies are noncompetitive right now.”
White House correspondent Michael Shear followed up with a question about the potential of foreign leaders to impose tariffs on American goods to offset the carbon that the U.S. had pledged to reduce.
“I think that countries will not do that to us,” Trump responded. “I don’t think if they’re run by a person that understands leadership and negotiation, they’re in no position to do that to us, no matter what I do. They’re in no position to do that to us, and that won’t happen, but I’m going to take a look at it. A very serious look. I want to also see how much this is costing, you know, what’s the cost to it, and I’ll be talking to you folks in the not too distant future about it, having to do with what just took place.”
‘Hoax’
In a 2012 tweet, he called climate change a hoax created “by the Chinese in order to make U.S. manufacturing noncompetitive.” During the campaign, he said he would “cancel” the U.S.’s involvement in the Paris Agreement, which aims to limit global warming to 1.5 degrees Celsius above preindustrial levels. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
But in a video released Nov. 21, Trump also made clear that he will steer a different course than President Obama on energy policy, renewing his promise to “cancel job-killing restrictions on the production of American energy, including shale energy and clean coal.”
Trump and the Republican Congress could use the Congressional Review Act to cancel some of the Obama administration’s most recent regulations, including a Nov. 15 Interior Department rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.
The act allows an incoming Congress to reject regulations finalized within 60 days of the end of either the House’s or Senate’s sessions.
The Congressional Research Service has concluded the act would apply to regulations finalized after May 30, if Congress holds no more sessions this year, The Washington Post reported Nov. 22.
In contrast, an EPA regulation intended to reduce methane gas leaks was finalized on May 12, making it likely exempt from being reversed under the act, the Post reported. EPA said the rule, designed to reduce methane emissions from new or modified oil and gas wells, will prevent 11 million metric tons of carbon dioxide equivalent emissions by 2025.
DALLAS — Stakeholders working to improve SPP’s cumbersome Z2 crediting process for network upgrades met here last week to learn about how potential solutions might affect the RTO’s other functions — leaving one stakeholder pining for the good old days when he worked in an operations center.
Another stakeholder, the Kansas Power Pool’s Larry Holloway, expressed mild frustration as the Nov. 29 conversation turned to long-term and incremental long-term congestion rights (LTCRs and ILTCRs, respectively) and their potential addition to the Z2 process.
“There seems to be a bit of mission creep. I thought we were looking at a better way to do business with Z2,” said Holloway, KPP’s assistant general manager of operations. “I thought we were looking at a less complex way of handling [Z2] going forward and handling the burden of these historic costs. Now it sounds like we’re keeping Z2 and having another process moving forward.”
“Our goal is to come up with a better process,” Bruce Rew, SPP’s vice president of operations, reminded the task force. “We’re working through the process of how we would transition to a different process.”
SPP staff suggested LTCRs and ILTCRs could serve as potential alternatives to Z2 credits. LTCRs cover the entire June-May year and can be renewed annually or converted into TCRs. ILTCRs, already used by most RTOs, would provide the option of long-term rights for participant-funded transmission upgrades.
“The TCR process tries to forecast what the [congestion] pool will be,” said Charles Cates, SPP’s manager of transmission services, explaining that solving congestion at one point on the system can create congestion elsewhere. “A TCR is your share of the congestion pool. The value of the TCR may increase as more transmission requests come onto the system. Some bidders may try and predict where that congestion will be and seek TCRs.”
“I’d like to ditch this Z2 nightmare, but the problem is, [when] you give away the TCR to a project sponsor whose project resolves the issue and there’s no congestion, he’s getting nothing [of value],” American Electric Power’s Richard Ross said. “I’m afraid this will give incentives for some sort of twisted sponsorship where sponsors will want to solve some, but not all, of the congestion. If there’s still congestion and you’ve given that TCR away to that sponsor, it’s not available for that transmission customer that wants, needs and expects it.”
“I keep hearing the word ‘incentives,’ but we’re really looking at reimbursement mechanisms,” said Oklahoma Gas & Electric’s Greg McAuley, agreeing with Ross. “We’re looking to pay [upgrade sponsors] back and make them whole for what they’ve added to the system, but we’re not trying to provide incentives for new transmission construction.”
Cates noted SPP’s TCR market is still going through growing pains since it was implemented as part of the RTO’s Integrated Marketplace in 2014. In recent months, the TCR market’s funding has just reached a 90% funding level.
“To be fair, we don’t have much of an ILTCR market because no one takes them,” SPP’s Lanny Nickell said.
The TCR market’s inability to provide a one-for-one offset with hedges against congestion has become a growing concern for load-serving entities. They point to wind farms being granted non-firm service while being allowed to put physical energy on the system.
“How do they get away with not paying for non-capacity upgrades, and why are we being forced to pay for sponsored upgrades?” Ross asked rhetorically. “That doesn’t make a bit of sense. Why are we paying $10 for something that’s not worth a nickel?”
Kansas City Power and Light’s Denise Buffington, the task force’s chair, asked staff to provide more information on how the capacity versus non-capacity issue is handled in other markets. The task force will meet again before January’s Markets and Operations Policy Committee meeting in Dallas, where it will take an even deeper dive into SPP’s ILTCR proposal.
‘And’ vs. ‘Or’
The group also discussed SPP’s aggregate and planning studies, generation interconnection process and the auction revenue rights and TCR processes. Staff also explained the Z2 process was used as a mitigation for FERC’s concern about “And” pricing for service, embedded costs and any other upgrade costs.
In a 2001 order, the commission said the pricing of transmission service could reflect either the greater of the network’s average cost (with expansion costs rolled-in) or the incremental cost of the expansion, known as “Or” pricing. It prohibited pricing based on a combination of average and incremental costs, known as “And” pricing.
SPP’s Tessie Kentner said any changes to the Z2 crediting process must not violate those principles. She said the commission accepted the RTO’s compliance filing and its use of Z2 credits for sponsored upgrades for Order 681, which requires organized electricity markets to make available long-term firm transmission rights.
“I think we have a deeper understanding of the complexity of Z2 and may have highlighted that Z2, as implemented today, still has many unknown impacts to participants,” Buffington said.
Ross did provide a moment of levity when he presented “Richard Ross Gold Stars,” in the form of Christmas ornaments, to SPP’s Steve Purdy and Charles Locke. Ross said it was a sign of appreciation to the two for representing the RTO’s position on Z2 credits.
“Somebody has to take the shots for the organization,” Ross said.
KEPCo Files FERC Complaint
The Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC under Sections 206 and 306 of the Federal Power Act and Rule 206 of the commission’s Rules of Practice and Procedure (EL17-21).
KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to KEPCo violated the RTO’s Tariff and the filed rate doctrine, and is “otherwise unjust, unreasonable and proscribed” by the FPA. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.
KEPCo COO Les Evans had hinted at the filing when his request for a waiver from directly assigned Z2 network upgrades was rejected by the SPP board in October. (See SPP Board Lets Action on Z2 Stand; Litigation Likely.)
Seven parties have already intervened in the case, including SPP members KCPL, Sunflower Electric Power, Western Farmers Electric Cooperative and the Arkansas Electric Cooperative Corp.
Competitive Transmission, Strategic Planning, Other Groups Meet
The Z2 task force’s meeting was just one of several held in Dallas last week in and around AEP’s offices.
The Competitive Transmission Process Task Force met Wednesday to revise draft revision requests that reflect input from the October Board of Directors meeting and to incorporate changes in SPP’s annual transmission revenue requirement template. The group will conduct a conference call next week to prepare for the January board meeting.
The Strategic Planning Committee met Thursday to review and discuss the operational challenges facing SPP as a result of the 22,000 MW of wind power in the interconnection queue.
Stakeholders shared their concerns that the expected expiration of renewable tax credits is leading to a surge of additional generation being added to the system, citing congestion concerns. Wind and solar resources account for 98% of SPP’s current generation interconnection queue.
Six companies — Avangrid, Calpine, CenterPoint Energy, DTE Energy, Exelon and Great Plains Energy — reported at least a 10% increase in year-over-year revenue. 
Avangrid, formerly Iberdrola USA, 
