CARMEL, Ind. — MISO easily managed what turned out to be a “near-normal” March, the RTO said Tuesday.
The RTO’s load averaged 71.1 GW for the month, in line with the 70.8 GW average a year earlier. But the 85.3 GW monthly peak set on March 14 came up 2.5 GW short of last March’s peak.
During an April 24 Informational Forum, MISO reported relatively mild weather in most of the footprint during March, although cold conditions persisted in parts of MISO Midwest.
“I would say winter just won’t go away this year,” observed MISO Senior Director of Systemwide Operations Rob Benbow, who added that lower temperatures kept demand relatively low during the month.
“We did see a lot of diversity in our weather footprint,” Benbow said, noting that one day in March saw snowstorms up north while parts of MISO South were under tornado warnings.
“When you span that far across the United States, you expect that,” he added.
Real-time prices in March were about 14% lower than they were last year, averaging $25.40/MWh, while day-ahead averaged $25.55/MWh.
Benbow said the price drop was due to lower congestion and natural gas prices compared with last year. Gas prices in March averaged $2.48/MMBtu at Chicago Citygate and $2.66/MMBtu at Henry Hub, down from $2.84/MMBtu and $2.83/MMBtu, respectively.
Benbow said the month brought the usual onset of generation maintenance outages, with planned outages doubling to about 25 GW as February transitioned into March.
MISO also set a new, 15.6-GW record peak for wind generation on March 31, toppling its previous 15-GW wind record set in January.
Queue Progress
MISO also provided an update on its interconnection queue, with Benbow saying completion of affected systems studies continue to slow queue progress, a topic debated in early April at a FERC technical conference. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)
MISO’s generator interconnection queue currently includes 561 projects, totaling 93.1 GW, and the April 2018 definitive planning phase queue cycle added 244 projects, representing 41.2 GW.
MISO said it is managing 14 ongoing queue cycles with five more queue cycles set to begin in the coming months. The lion’s share of the queue is renewable generation, with 42.7 GW of wind, 37.4 GW of solar and 12.3 GW of natural gas generation.
Avangrid on Monday said its first quarter earnings rose slightly on new rate plans and increasing output from its wind fleet, and the company highlighted its growing opportunities in renewable energy — particularly offshore wind.
The company posted net income of $244 million for the quarter ($0.79/share), up 2% from the same period a year ago.
CEO James P. Torgerson said in an analyst call that “earnings improved primarily due to the implementation of our multiyear rate plans [and] increased wind production, mainly from the 534 MW of capacity that came on line in 2017.”
| Vinyard Wind
Torgerson noted Avangrid subsidiary Central Maine Power (CMP) is set to sign a contract with Massachusetts by the end of this month for the state’s 9.45-TWh clean energy solicitation, which was awarded to CMP’s New England Clean Energy Connect (NECEC) transmission project after the original winner was rejected by siting officials in New Hampshire. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
CMP partnered on the project with Hydro-Québec, which will deliver up to 1,200 MW of Canadian hydropower to the New England grid via a 145-mile transmission line. The partners estimate the project will cost $950 million and will soon file with the Massachusetts Department of Public Utilities, said Torgerson.
Avangrid also completed the sale of its gas trading business last quarter and expects to sell off its gas storage business in May.
The company said it has 497 MW of onshore wind and solar under construction, to be operational by the end of 2019. Avangrid’s Vineyard Wind partnership with Copenhagen Infrastructure Partners bid 400-MW and 800-MW projects into Massachusetts’ offshore wind solicitation, the winners of which will be announced in May. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Vineyard Wind in the first quarter also submitted a bid for 190 MW of offshore wind in Connecticut, with selection scheduled for June.
Regulatory Update
Torgerson expressed muted optimism about a FERC administrative law judge’s March ruling that municipal utilities and commission staff failed to prove the New England Transmission Owners’ base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable, rebuffing requests to reduce it. (See ALJ Rules New England Tx Owners’ ROEs not Unjust.)
“We feel that’s positive, but the commission will still ultimately need to decide, and there’s really no time frame at this point to make that decision,” said Torgerson.
The corporate tax cuts passed by the Trump administration in December created benefits for the company, and Avangrid is working with state regulators in New York and New England to offset major storm recovery and advanced metering infrastructure (AMI) costs through the windfall before passing benefits to customers.
The AMI discussions are ongoing in New York and the company anticipates approval later in 2018. “The earnings adjustment mechanism discussions have been impacted by the ongoing storm activity and the AMI discussions and other things, so that’s been delayed somewhat,” said Torgerson.
Offshore Potential
After establishing its offshore wind business last year, Avangrid quickly won a Bureau of Ocean Energy Management (BOEM) lease auction off Kitty Hawk, N.C., an area that could produce up to 2.5 GW of energy. The company also last year acquired its 50% partnership in Vineyard Wind.
| Vinyard Wind
Torgerson also highlighted upcoming opportunities in offshore wind.
“In New York, they are looking for 800 MW in the fall and 2,400 MW by 2030,” he said. “Rhode Island is evaluating or looking to evaluate the implications from the Massachusetts RFP and want information on that, how it could impact Rhode Island. So, there is an expectation that Rhode Island may be looking for some offshore wind as well.”
Offshore wind got a boost on two fronts earlier this month when U.S. Interior Secretary Ryan Zinke announced two new proposed offshore wind leases for Massachusetts, while the Interior Department’s BOEM issued a call for commercial interest in four wind energy areas in the New York Bight. (See Interior Plans Would Boost Mass., NY Offshore Wind.)
“We will be looking at those very closely,” said Torgerson. “And Governor Phil Murphy in New Jersey is said to be looking for about 3,500 MW offshore of New Jersey.”
To model the impacts of carbon pricing on dispatch, resource costs and emissions in its wholesale electricity market, New York would do well to start by estimating a social cost of carbon (SCC), experts told a state task force Monday.
The Integrating Public Policy Task Force (IPPTF) heard three presentations on SCC and related topics as the group drilled further into technical details in its mission to reconcile the wholesale electricity market with state environmental goals.
The IPPTF is jointly run by NYISO and the state’s Department of Public Service (DPS). The April 23 discussions were part of issue “Track 3” and “Track 5” in the group’s five-track effort to price carbon emissions.
“Each and every ton [of CO2] that’s emitted contributes to harms that you and I face from climate change,” Bethany Davis Noll, litigation director at the Institute for Policy Integrity at the NYU School of Law, said in explaining how the SCC attempts to put a monetary value on the damages associated with the incremental rise in carbon emissions each year. “What economists tell us is that if we can figure out a way to put a dollar value on those harms, it’s easier for us to face or figure out what to do in response in order to stop them.”
Davis Noll presented a report on the SCC determined by the Obama administration’s Interagency Working Group (IWG) on Social Cost of Greenhouse Gases, which in 2016 estimated the SCC at $50 per ton of CO2.
Numbers Game
President Trump in March 2017 signed an executive order disbanding the IWG and withdrawing its technical support documents, but federal agencies are still required to monetize climate harms, said Davis Noll.
Some agencies are still using the IWG’s number, while EPA and the Bureau of Land Management have proposed to use an “interim” social cost of carbon.
“Basically, the interim estimate brings the $40 to $50 number down to $1,” Davis Noll said.
The methodology used to get the $1 value obscures the global harm of emissions “and was rejected by the IWG as inappropriate for this type of analysis,” Davis Noll said. “Agencies are not allowed to do lopsided analysis, putting a dollar value on the one side and not using a well-recognized tool on the other side.”
David Clarke, director of wholesale market policy for Power Supply Long Island, contended the state has two approaches to consider: either a federally approved tariff or state regulation.
“What’s your view on FERC and what kind of things they would consider when deciding whether a social cost of carbon is just and reasonable?” Clarke asked.
Davis Noll’s position is as follows: Based on the “extensive research” already done on the SCC, the widespread support for the IWG number suggests it clearly is “just and reasonable” according to FERC standards.
“I think FERC is actually receptive to using it themselves in their decisions … here all we have to do is figure out whether the ISO’s proposal’s going to be judged just and reasonable,” Davis Noll said.
She added, “The executive order doesn’t do anything, it really just disbands the working group … and so far, there are so many states relying on this number — that’s also supportive.” States incorporating the IWG value into their environmental policies include California, Colorado, Illinois, Maine, Minnesota, New Jersey, New York and Washington.
New York Way
Warren Myers, DPS director of market and regulatory economics, presented a report recommending the task force use in its analysis the CO2 value already adopted by the New York Public Service Commission (PSC).
The commission in its January 2016 Benefit Cost Analysis Framework Order (14-M-0101) relied on the IWG’s “central value” SCC minus the Regional Greenhouse Gas Initiative (RGGI) allowance price, until Tier 1 renewable energy credit (REC) procurements were established later that year under the state’s Clean Energy Standard (CES).
The PSC’s March 2017 Value of Distributed Energy Resources (VDER) Order (15-E-0751) set compensation value at the higher of Tier 1 REC or SCC minus RGGI. Converted by DPS to dollar per ton, the latter figure would gradually increase over the coming decade from $40.74/ton in 2020 to $56.77/ton in 2030. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
| NY Dept. of Public Service
Myers said the precise dollars and cents values for each year could be a little misleading, since it is the order of magnitude that really matters. So, while those precise calculations do reflect the IWG numbers adopted by the PSC, we should not conclude they are necessarily any more accurate than Davis Noll’s $50/ton estimate, he said.
A portion of the SCC has already been internalized in the ISO’s locational-based marginal pricing, Myers said, “and so what we would like is the externality, which we say is the SCC minus the relevant RGGI number.”
One reason developers and environmentalists in the VDER proceeding “opposed using the Tier 1 RECs price only was that it just really doesn’t triangulate at all; it isn’t tied at all specifically to carbon; it’s just a compliance cost of a program with certain program parameters,” Myers said.
Howard Fromer, director of market policy for PSEG Power New York, said he appreciated the DPS’s effort to send a consistent price signal to the market that clarifies “here is the value of avoiding carbon.”
However, he said state subsidies for large amounts of preferred technologies, such as the $180/MWh cost for the first 90 MW of offshore wind on Long Island, has the potential to undermine the price signal consistency.
“I would hope that we would not blindly lock ourselves into the [IWG] number, given that I have very little confidence in what today’s interagency task force, if reconstituted, might produce, and I would much prefer to speak to the New York [Public Service] commission, frankly, with consistency with their policy,” he said.
Modeling Resource Shift
Tim Duffy, NYISO manager of economic planning, presented a report addressing customer impacts via a proposed methodology for modeling and analysis. The ISO proposed starting from a base case using its Congestion Assessment and Resource Integration Study (CARIS) data, updated and extended, and carrying through to both a simple change case and a dynamic change case, which would add assumed changes to fleet and load.
“For the purpose of developing the system resource shift scenario or case, we assume achievement of CES in 2026,” said Duffy. The CES mandates that New York get 50% of its electricity from renewable resources by 2030.
The ISO study aimed to define enough market scenarios to span the range of plausible impacts of a carbon charge throughout the state, as well as the key factors affecting marginal emission rates in various parts of the state, such as whether a new renewable resource is located upstate or closer to the load centers around New York City, he said.
Estimates for 2020 | IWG/U.S. Gov.
“We’re proposing to run multiple years here, 2020, 2025 and 2030, and all the data associated with each of those three years would be provided,” said Duffy.
IPPTF co-chair Nicole Bouchez, NYISO principal economist, referred to the Brattle Group carbon pricing report from last August.
“We’re looking at something in the same conceptual way that Brattle looked at this, which is first you look at what are going to be the direct price impacts, and then you look at these dynamic changes, how does investment change, how do the numbers change,” said Bouchez.
Marc Montalvo of Daymark Energy Advisors, representing the state’s Utility Intervention Unit, said, “The state is going to seek to meet its CES policy objectives with or without this carbon charge policy. So, if we add the carbon charge, will that be a successful thing to do? Analytically, how do we measure success?”
The task force will next meet May 7 at NYISO headquarters to further cover issue “Track 5,” which it will discuss again June 4 to complete the assumptions and scenarios. The study results are scheduled to be presented in September.
In a related move, the ISO has scheduled a public forum May 1 on analysis of transmission congestion on the New York state bulk power system and the potential costs and benefits of relieving transmission congestion through its CARIS process.
The New York State Energy Research and Development Authority (NYSERDA) published a white paper Thursday outlining plans to accelerate the state’s energy efficiency (EE) goal by 40%.
The paper calls for 185 trillion British thermal units (TBtu) of cumulative annual site energy savings relative to forecasted 2025 consumption. The agency said that would deliver almost one-third of the emissions reductions needed to meet the state’s goal of reducing greenhouse gas emissions 40% from 1990 levels by 2030.
NYSERDA said this would include a 30,000-GWh reduction from forecasted 2025 electricity sales — a 3% reduction in investor-owned utility sales in 2025 and average savings exceeding 2% of IOU sales between 2019 and 2025.
The new target is based on savings in buildings and the industrial sector across all fuel sources (electricity, natural gas, heating oil and propane).
“This paper proposes a portfolio of accelerated actions to drive an additional 41 TBtu of aggregate efficiency savings statewide by 2025 or a 40% increase above the state’s current commitments for the 2019–2025 period,” NYSERDA said.
NYSERDA said it will spend an additional $36.5 million to train more than 19,500 people for energy efficiency and other “clean energy” jobs.
“The path to delivering on New York’s 2025 energy efficiency target recognizes that a mix of strategies will be necessary, focusing on the approaches best suited for specific markets and their needs and on the mix best suited for long-term cost-effectiveness,” the report said. “The portfolio will include a good measure of innovation, testing those approaches with the best promise, then scaling those that take hold.”
NYSERDA said it will seek to meet the 2025 target by:
“Accelerating and shifting” utility energy efficiency programs by increasing market-based EE, more leverage of public funds and more effective programs. “This includes the proposed development of a shared savings approach that provides greater opportunity and reward for utilities to advance energy efficiency as a business and as a resource.” (See NY Fine-tuning CES; Phasing out EE Program.)
Dedicating at least 20% of any additional public investment in EE to low- to moderate-income consumers.
Strengthening laws on building codes and appliance standards by increasing EE requirements.
“Driving deep energy savings” through building retrofits and construction and cost-effective heat pump adoption. “If New York is to achieve the 40 by 30 … climate goals, it will be essential to retrofit the state’s existing building stock to dramatically reduce energy consumption, so that most buildings are able to reach passive house or net zero energy performance levels. This presents an imperative to develop deep (i.e., 30-40-50% energy savings) and replicable retrofit strategies … In the absence of government mandates, [efficient construction practices] will only reach true scale when market players view them as sound financial investments.” (See Lovins: We’re Only Scratching the Surface on Energy Efficiency.)
Leading by example with EE in state facilities.
The agency noted the state’s 2015 energy plan identified lighting as one of the biggest EE opportunities.
“Since then, utilities’ efficiency programs have focused heavily on lighting. At the same time, costs of high-efficiency lighting products have come down and natural adoption [has] increased, resulting in a greater portion of the lighting savings potential being achieved in the years since this study was published as compared to other end uses.
“However, this data shows several other high-potential, end-use opportunities in addition to lighting — specifically, cooling and water heating. This highlights a need to broaden the scope of utility programs to address other cost-effective efficiency measures and to encourage approaches that pair lower-cost opportunities like lighting with other efficiency improvements to achieve deeper savings.”
Utility EE programs have had success in reducing energy use in lighting but major savings remain in cooling, and water heating, NYSERDA says.| NYSERDA
The state Public Service Commission will take steps to implement the white paper, beginning with a technical conference.
“Following the initial technical conference, DPS Staff will initiate and define a process and schedule supporting further development of the jurisdictional aspects of the white paper,” NYSERDA said. “This is expected to include additional technical conferences, as well as topical working groups and a formal written stakeholder comment process with the goal of developing an adequate record for commission action, including benefit, cost, and practical implementation information.”
The NYISO Board of Directors has rejected two appeals of Management Committee votes on capacity zones and locational capacity requirements.
The board declined to override the committee’s Feb. 28 vote that fell short of the threshold for authorizing a Tariff change to create rules for establishing and eliminating capacity zones. The committee had voted 54.1% in favor, short of the 58% required. (See “MC Rejects On Ramp/Off Ramp Changes” in NYISO Management Committee Briefs: Feb. 28, 2018.)
The issue arose from Tariff revisions approved by FERC in 2012, setting rules for creating new capacity zones in the New York Control Area. The changes led the ISO to create a new capacity zone for the G, H, I and J load zones in the Lower Hudson Valley and New York City.
In denying an appeal by Central Hudson Gas & Electric and the New York Power Authority, the board said although some stakeholders called for developing rules for eliminating zones, FERC has not required them. The Independent Power Producers of New York (IPPNY), Cricket Valley Energy Center, Castleton Commodities Merchant Trading, Roseton Generating and the Long Island Power Authority (LIPA) opposed the appeal.
In 2017, ISO staff launched the “On Ramps and Off Ramps” project to consider rules for eliminating zones and concluded the deliverability-based approach used for creating zones was inappropriate for cancelling them. Staff said a reliability-based transmission security approach would be better for both creating and eliminating zones.
IPPNY said the change would distort market price signals and create uncertainty. Although it opposed the appeal, LIPA said it favors changes to the capacity zone rules.
“While we acknowledge the considerable time and effort NYISO staff and stakeholders spent developing the proposal, we deny appellants’ request that the NYISO take the extraordinary measure of filing the proposal pursuant to [Federal Power Act] Section 206,” the board said, calling “unpersuasive” the appellants’ contention that current rules are unjust and unreasonable.
“The NYISO has filed Tariff amendments pursuant to Section 206 only a few times in its history. The facts and circumstances presented here do not warrant that approach. Even if the board were so inclined, we do not believe the NYISO could satisfy the significant burden of proof required to implement the proposal pursuant to a Section 206 filing.”
The appellants’ arguments regarding price impacts on customers were not persuasive, the board said.
“Appellants assert that retaining a locality longer than needed causes undue price separation and would result in ‘excess costs’ for Zone J and Zones G-I customers. However, they calculate potential excess costs to consumers based on current system conditions in which there exists a continued reliability need for the G-J Locality to remain in place. Under system conditions that might support elimination of the zone, the cost impact of retaining the zone — if any — would be much lower,” the board continued. “We note that NYISO staff performed an analysis that illustrated, among other scenarios, the potential for adverse consumer impacts of prematurely eliminating a capacity zone. Appellants’ papers are silent on the NYISO’s consumer impact analysis, offering instead a conclusory economic assessment that is based upon incorrect assumptions.”
The board declined to remand the issue for further work but said stakeholders could consider it during the annual issue prioritization process.
Locational Capacity Requirements
In a related matter, the board also rejected an appeal from LIPA, NRG Energy and Helix Ravenswood, which asked the board to override the Management Committee’s Feb. 28 vote approving a change in how the ISO calculates locational capacity requirements (LCRs). The measure passed with a 77.55% vote. (See “Alternative Methods for Determining LCRs” in NYISO Management Committee Briefs: Feb. 28, 2018.)
NYISO calculates the LCRs to maintain the statewide installed reserve margin (IRM) set by the New York State Reliability Council (NYSRC) based on the one-day-in-10 years loss-of-load expectation (LOLE).
The LCR rule change replaces the “TAN 45” methodology adopted for the 2006/07 capacity year, before the creation of zones G-J. Loads in the Lower Hudson Valley complained that TAN 45 increases their local requirement while reducing requirements for New York City and Long Island.
The new rules, originating from an economic approach recommended by Independent Market Monitor David Patton, are based on the lowest cost-to-supply capacity.
Opponents of the change called for more study of the issue. LIPA contends that the new method underestimates the capacity costs for a new unit in its zone and that it is being forced it to subsidize New York City, noting that its LCR is expected to increase to more than 100% of peak load, while the city is expected at less than 80%.
New York City and 60 large industrial, commercial and institutional energy consumers opposed the appeal of the rule change.
In rejecting the appeal, the board said the rule change was a “significant improvement” that had been “carefully developed, thoroughly vetted and received widespread support from market participants.”
“Contrary to appellants’ assertions that the new approach would introduce volatility, analysis indicates that the alternative LCR methodology will provide results that are more stable than the current approach,” the board said.
The board also turned aside arguments that the new methodology is flawed because it does not optimize the IRM calculation along with the LCR calculations, saying it “ignores the fact that the IRM is set by the NYSRC — not the NYISO.” The board said the ISO will work with the Reliability Council to explore a co-optimized approach but the new rules should not be delayed by that effort.
The board said, “Concerns over ‘rate shock’ are unpersuasive.”
“The NYISO is open to further discussion on [subsidization concerns and] … alternative approaches to cost allocation,” it said. “Such discussion is outside the scope of the instant proposal, however, and should not delay [its] implementation.”
Buoyed by recent positive developments, American Electric Power (AEP) CEO Nick Akins had several reasons Thursday to proclaim the company “in better shape than in the first quarter of last year.”
Not even falling pennies short of the Zacks Consensus Estimate for first-quarter earnings could dampen his mood. AEP posted earnings of $473.2 million and $0.96/share, similar to 2017’s first quarter ($474.3 million, $0.96/share) but missing the Zacks estimate of $1.00/share.
Paraphrasing Jon Bon Jovi, one of the Rock and Roll Hall of Fame’s newest inductees, Akins, who sits on the Hall’s board of directors, told analysts during a conference call, “This phrase will stick with you the rest of the day: We’re halfway there, living on a prayer, take our hand and we’ll make it, we swear.
“So, enjoy the ride with American Electric Power.”
Just this week alone, AEP saw FERC approve a settlement reducing the base return on equity for its PJM transmission companies to 9.85% (See “AEP ROE Reduced to 9.85% in Settlement” in Company Briefs.) and its Public Service Company of Oklahoma (PSO) subsidiary reach a settlement with several consumer groups over its Wind Catcher project.
AEP’s Wind Catcher site | Invenergy
“Wind Catcher is finally feeling some tail winds,” Akins said, referring to the massive 2-GW, $4.5 billion wind farm in the Oklahoma Panhandle. “We have accomplished settlements in Arkansas, Louisiana and now Oklahoma … that provides the framework for the various commissions to bless this significant project and its benefits for our customers.”
Akins said AEP is working to add other parties in Oklahoma to the settlement, including Oklahoma Corporation Commission staff. The state’s attorney general, Michael Hunter, opposes the project, saying PSO did not follow a competitive bidding process and doesn’t need the generation.
Akins admitted AEP is not likely to get Hunter “on board” but said the outreach will continue. He said the company is also continuing efforts to reach a settlement in Texas and hopes to have regulatory approvals in May and June.
“I think [the project] is framed up pretty well because a lot of work’s been done in the background,” Akins said. “As far as I’m concerned, we’re in a very good place.”
During AEP’s annual stockholder meeting Tuesday, Akins said the Columbus, Ohio-based company plans to invest $17.7 billion in capital ($12.8 billion in wires infrastructure, $1.7 billion in renewable energy) over the next three years. That capex does not include Wind Catcher.
AEP’s share price closed at $69.77/share Thursday, up 1.1% from its open.
Xcel Expects Approval of Texas Wind Farm
Xcel Energy CEO Ben Fowke said Thursday he expects the Texas Public Utility Commission to approve its Southwestern Public Service (SPS) subsidiary’s request to build a 478-MW wind farm in West Texas.
The commissioners appeared to be grappling with approving the company’s request during their April 13 open meeting. They questioned SPS and parties to a unanimous settlement on the proposal about the legal justification for a project when there is no apparent need for the capacity and asked for more information. (See Texas Regulators Seek More Details on SPS Wind Project.)
The commissioners asked for more information before Friday’s open meeting.
| GE Renewables
Asked by an analyst during Xcel’s quarterly earnings call what he expects from the PUC, Fowke said, “We’re expecting approval.
“We think the project’s driving tremendous benefits for consumers,” he said. “There were some questions asked [by the PUC], and they’ve been answered. You can always have more discussion, but our thought is it will be approved.”
The company’s proposal has been endorsed by PUC staff, who are also part of the settlement between the utility and various consumer groups.
SPS announced last year it intends to build 1.23 GW of wind generation through a pair of wind farms in Texas and New Mexico and a long-term contract from another facility as part of parent Xcel’s multistate investment in wind. Xcel said the projects will save the region’s customers about $2.8 billion over a 30-year period.
New Mexico’s Public Regulation Commission has already approved the facility.
Minneapolis-based Xcel reported first-quarter earnings of $291 million, or $0.57/share, up from $239 million and $0.47/share a year ago. That beat analysts’ projections of $0.51/share.
Pacific Gas and Electric (PG&E) will pay $98 million in penalties for past improper communications with the California Public Utilities Commission (CPUC), but the years-old proceeding related to the controversy will continue to drag on because of new emails that came to light last fall.
The CPUC on Thursday approved the $98 million settlement with PG&E, but the ex parte proceeding remains open to consider emails divulged late last fall revealing additional improper communications between the utility and its regulators. (See CPUCto Vote on $98M PG&E Settlement; Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.) The penalties covered eight different CPUC proceedings, including one related to the 2010 San Bruno pipeline explosion that killed eight people.
The communications “have cast public suspicion on the integrity of the Commission’s regulatory process,” the CPUC decision said. PG&E released 67,000 emails as part of the proceeding, including a new batch supplied to the agency in September that revealed more back-channel discussions. The ex parte proceeding was spurred by a public records request by the City of San Bruno in the wake of the September 2010 explosion.
None of the five commissioners who voted on the settlement Thursday were involved with the improper communications. Parties to the settlement include PG&E, the City of San Bruno, The Utility Reform Network (TURN), the City of San Carlos and the CPUC’s Office of Ratepayer Advocates and Safety and Enforcement Division.
TURN Executive Director Mark Toney on Thursday issued a scathing rebuke of the utility, saying “customers are tired of all the corruption at criminal corporation PG&E. And they want assurances that they are not paying even a penny of the costs of that corruption in their monthly bills, which is what this settlement provides.” PG&E was convicted of a felony related to the 2010 San Bruno pipeline explosion and in April 2015 paid a separate $1.6 billion fine for safety violations.
The new fines approved Thursday will come from shareholders and not ratepayers and will pay $12 million into the state’s general fund, $6 million each to the cities of San Bruno and San Carlos, and reduce by $10 million the revenue requirement in PG&E’s next general rate case. The utility will also forgo collection of $64 million in revenue in 2018 and 2019.
“PG&E’s failure to report these communications is an unacceptable violation of the CPUC’s rules and justifies the remedy provided in this case,” the CPUC said in a blog post. “Although these violations occurred more than four years ago, today’s decision is an affirmation that all parties to the CPUC’s proceedings must comply with the ex parte rules.”
The settlement was originally crafted in March 2017, but a CPUC administrative law judge ruled that a proposed $1 million payment to the state’s general fund was too low, and PG&E agreed to pay another $11 million to the state. The settlement agreement approved Thursday is the largest financial remedy ever imposed by the commission over violations of its ex parte rules.
I’d like to apologize — on behalf of FirstEnergy — for dragging countless congressmen into the arcane world of the electric utility industry. You’ve had to listen to millionaire lobbyists — the quintessential swamp — talking about stuff so dry that we who toil in this world aren’t allowed to talk to our spouses about it.
Huntoon
And biggest apology to Sen. Manchin because you’re the biggest victim. Bailout for FirstEnergy via the Defense Production Act of 1950? OMG.
Do you think if there were a scintilla of national security threat we might have heard something from, hmm, let’s see, maybe the Defense Department?
But here we are.
If you’re just listening to FirstEnergy’s lobbyists, you’ve missed a few key facts. FirstEnergy’s plants are:[1]
Not baseload.
Old — not retiring prematurely.
Inefficient.
Unreliable.
Not needed for a reliable and resilient grid.
In the tough competition for weakest bailout argument, the winner is the argument that if we didn’t have all the coal plants we had last winter, there would have been an electricity problem, which is like saying if we didn’t have all the Fords we had last winter, there would be a car problem. Duh.
All the Fords aren’t disappearing overnight. And the Fords that do disappear are being replaced by better Fords.
A weaker argument for subsidizing old, inefficient and unreliable plants is hard to imagine. If it had prevailed 100 years ago, we’d still be driving Model T’s.
Quick Quiz
Let’s see if you’ve been conned with a quick quiz question: The Department of Energy projects in the year 2050, 32 years from now, there will be this much coal and nuclear generation in the United States:
0 gigawatts
10 gigawatts
100 gigawatts
274 gigawatts
The answer is (d) 274 gigawatts.[2] Yes, Rick Perry’s own Department of Energy projects a huge amount of coal and nuclear generation to be around for the next 32 years.
It’s a con to pretend coal and nuclear plants will disappear quickly (or at all), causing any sort of reliability problem — and to premise a bailout on such fantasy.
The Absurd
The absurd is that all the responsible entities in the electric industry know there is no emergency. All the independent grid operators, the unanimous Federal Energy Regulatory Commission (where four of the five Commissioners are Trump appointees), former federal regulators, and all the independent analysts have repeatedly said that. These would be the first to warn of an emergency if one actually existed.
Compounding the absurdity, earlier this month FirstEnergy told the bankruptcy court that all its coal and nuclear plants would be operating throughout its bankruptcy proceeding.[3] That proceeding will take at least five to six years.[4]
That means all the FirstEnergy plants will be operating for at least the next five or six years.
On top of that, Robert Murray, coal CEO and FirstEnergy’s fellow traveler, told The Wall Street Journal earlier this month there was no longer any need for a bailout to save his company from bankruptcy because of increased exports to Asia.[5] He now “expects his company to thrive whether or not the Trump administration intervenes,” the Journal reported.
There is no fire. Or even a puff of smoke.
The Tragic
FirstEnergy’s Akron, Ohio headquarters
FirstEnergy’s customers paid it $6.9 billion in return for the company’s transition from a regulated environment to a competitive environment. If that “bet” had turned out well, FirstEnergy would, of course, have kept the money. It hasn’t gone as well as FirstEnergy anticipated, and now FirstEnergy wants customers to bail them out all over again.
I didn’t realize just how outrageous that was until poring through the record of FirstEnergy’s stranded cost proceeding in Ohio from almost 20 years ago. FirstEnergy’s stranded costs were based on the difference between their regulated “net book value” and their net revenues in the future under market conditions.
Please bear with me. “Net book value” is the original cost of the plants reduced by the amount of capital that customers already have reimbursed the utility (a.k.a., depreciation). So, when FirstEnergy was paid net book value (less the future market revenues it would get to keep), it was paid the rest of the plant costs that customers hadn’t already paid for.
In other words, customers have already paid for 100% of FirstEnergy’s plants. FirstEnergy may retain legal title, but in equity the customers own the plants.
Can you imagine the tragedy of customers having to pay for those old, inefficient and unreliable plants all over again?
Let’s hope a surreal and absurd bailout and a tragic rate increase don’t come to pass. And if they do, let’s hope voters figure out who’s responsible.
KANSAS CITY, Mo. — SPP CEO Nick Brown said Tuesday the grid operator remains committed to making Mountain West Transmission Group’s membership proposal work, despite Xcel Energy’s surprise decision to pull out of the group and its pending integration into the RTO.
But integration work has been put on hold until the remaining Mountain West members decide what to do next.
“Obviously, the ball is in the court of the Mountain West participants,” Brown told SPP’s Board of Directors and Members Committee. “I’ve told them we remain committed to doing whatever it takes to come to a reasonable path forward, to create, again, the value that was expected from the previous agreement.”
Representing about 40% of Mountain West’s load and considered the group’s most influential member, Xcel announced Friday it was pulling its 1.4 million customers out of the agreement. That has left the Mountain West’s smaller entities reviewing their options. (See Xcel Pulls out of Mountain West, Endangering SPP Integration.)
“It would be a shame for an individual participant of the Mountain West to unilaterally destroy the value I think would be afforded to the new SPP members of Mountain West and also destroy the value on the table for our current members,” Brown said.
Board Chair Jim Eckelberger told directors and members the Mountain West entities had yet to sign a transition service agreement funding the integration work and approving a set of policy recommendations governing the terms of their RTO membership. In the absence of a signed agreement, Eckelberger said, the board’s March 13 approval of the integration’s funding and policy recommendations has been suspended.
SPP also announced on Tuesday that all Regional Tariff Working Group meetings previously scheduled to address the integration have been canceled through the end of May. The stakeholder group had scheduled 17 meetings before the July 31 board meeting to work on at least a dozen Mountain West-related revision requests.
On Monday, the Regional State Committee (RSC) approved the Cost Allocation Working Group’s request to suspend its work on the new member cost allocation review process. The RSC in January directed the group to draft a report on how new members affect existing cost allocations. (See Mountain West, Cost Allocation Top SPP RSC Concerns.)
The board and single representatives from each SPP member met in an executive session Tuesday afternoon to discuss next steps in the Mountain West integration. The group also discussed recent letters sent to SPP asking for more stakeholder involvement in new member negotiations. (See SPP Group Balks at Mountain West Concessions.)
SPP pointed to Brown’s earlier comments to the board when asked if any decision had been made on next steps.
Several members said their concerns were heard in the follow-up discussion, and the RTO said it would respond to each of the members’ letters.
NYISO must set a deadline for completing final market power reviews on retiring generators, FERC ruled.
The commission’s April 23 ruling came on a rehearing request by Entergy Nuclear Power Marketing but denied the company’s request that it set a 120-day deadline for the ISO’s review of its Indian Point nuclear plant (ER16-120-004, EL15-37-003).
Indian Point Nuclear Plant
The issue stems from the commission’s 2015 order that found the ISO’s Market Administration and Control Area Services Tariff wanting because it did not include rules on the retention and compensation of generators needed for reliability. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)
Entergy sought rehearing or clarification of the commission’s November 2017 ruling approving the ISO’s second compliance filing in the docket, in which the ISO added a 90-day deadline for completing reliability studies related to plant shutdowns. Entergy said the ISO’s lack of a deadline for the market power review left it without certainty about its authorization to exit the market.
The Services Tariff says the ISO can perform a market power review for capacity suppliers seeking to retire to determine whether the “decision has a legitimate economic justification” or is intended to withhold capacity to increase prices.
Entergy asked the commission to require NYISO to complete its final market power review of Indian Point by March 13, 2018, 120 days after receiving Entergy’s complete generator deactivation notice. The company contended FERC had previously approved the 120-day deadline, which it said reflected the ISO’s statements concerning when it plans to conduct the analysis and how long it takes to complete. (See Entergy Asks FERC to Clarify Indian Point Retirement Process.)
The commission said it had not approved the 120-day deadline but agreed with Entergy that the lack of a deadline “could impede the generator’s ability to make informed decisions about deactivating.” It gave the ISO 30 days to make a compliance filing proposing a “reasonable timeline” for completing the market power reviews.
“Although NYISO’s [Open Access Transmission Tariff] states that it will determine whether a generator is needed for reliability within the first 90 days after the generator gives notice of its intent to deactivate, neither NYISO’s OATT nor Services Tariff provide a timeline for NYISO to complete a final market power review (if needed), which impacts the ability of that generator to ‘be deactivated as planned,’” the commission said.
“NYISO should set a deadline for completing final market power reviews (if needed) working back from the proposed deactivation date rather than starting from the submission of a complete generator deactivation notice,” it continued. “This is because the final market power review may be less effective with data and assumptions too far removed from a generator’s actual deactivation date.”
Entergy plans to shutter Indian Point Unit 2 by April 30, 2020, and Unit 3 within a year after that. In December, the ISO reported that new gas-fired and dual-fuel generation coming online in the next few years will provide sufficient capacity to maintain reliability after Indian Point’s closure.
