During American Electric Power’s second-quarter earnings call with financial analysts last week, CEO Nick Akins was pressed about the uncertainty the company’s proposed Wind Catcher Energy Connection was placing on its share price. In the company’s earnings release, Akins had promised the company’s investments in its regulated businesses “will continue to support our 5 to 7% earnings growth rate.”
Akins | Business Roundtable
During the July 25 call, Akins was asked at what point do you decide that you are better off walking away from the table and the uncertainty?
“A very fair question,” he responded. “We cannot afford to continue to allow this thing to languish given construction has started and the company is incurring expenses associated with it.”
Two days later, AEP removed the uncertainty, canceling Wind Catcher, a $4.5 billion, 2-GW wind farm in the Oklahoma Panhandle. The move came one day after the Texas Public Utility Commission rejected the proposal. (See related story, AEP Cancels Wind Catcher Following Texas Rejection.)
Wall Street appeared to like the company’s reaction. After closing the day of the earnings call at $69.38, AEP stock ended the week at $71.14/share, up $1.76. That’s still well below the company’s 12-month high of $77.63, which it hit in November.
AEP’s Wind Catcher site | Invenergy
Ohio-based AEP reported a “very healthy quarter” thanks to a late winter and early summer, with second-quarter earnings of $528 million ($1.07/share). That was up from the prior year second quarter of $375 million ($0.76/share).
NextEra Energy Earnings Up
NextEra Energy announced a small increase in second-quarter earnings last week, reporting net income of $795 million ($1.64/share). That was a $2 million improvement from the prior year’s quarter of $793 million ($1.68/share).
The Florida company’s adjusted earnings of $1 billion ($2.11/share), compared to $881 million ($1.86/share) in last year’s second quarter. That beat Zacks Investment Research’s consensus estimate of $2.07/share.
NextEra announced in May it will pay Southern Co. almost $6.5 billion for Gulf Power, Florida City Gas and shares in the Oleander and Stanton natural gas power plants. CEO Jim Robo said the company “remains on track to meet its objectives for the year.”
Despite the good news, NextEra’s stock lost $2.03/share following the July 25 earnings announcement, finishing the week at $166.99.
Xcel Energy Beats Analysts’ Expectations
Xcel Energy reported a 16% increase in second-quarter earnings boosted by favorable weather and sales growth, exceeding analysts’ expectations.
The Minneapolis company on Thursday announced earnings of $265 million ($0.52/share), up from $227 million ($0.45/share) a year ago. Zacks’ analyst survey had forecasted profits of 47 cents/share.
The results exclude the effects from 2017’s federal tax legislation.
The company’s stock finished the week at $46.59/share, up 68 cents.
RENSSELAER, N.Y. — NYISO experienced a peak load of 31,293 MW on July 2, the highest demand so far this summer but falling far short of the all-time peak of 33,956 MW, the ISO’s Management Committee heard last week.
Operations Vice President Wes Yeomans on Wednesday informed the committee about grid operations during a six-day heat wave in early July, which will be reported formally in August.
High temperatures and humidity on July 1 caused the grid to have “experienced a very high peak for a Sunday,” Yeomans said.
The ISO activated demand response on July 2 in New York City’s Zone J in response to the weather and the forced outage of a 345-kV line in the city, he said. Last summer, demand never exceeded 30,000 MW, with the peak of 29,699 MW occurring July 19, coming in 7% below the 10-year average of 31,968 MW.
The 33,956-MW record came at the end of a weeklong heat wave on July 19, 2013.
| NYISO
The ISO in May reported a total of 42,169 MW of resources available to meet this summer’s expected peak demand of 32,904 MW, 2.9% above the 10-year average. (See NYISO Ready to Meet Summer Demand.)
COO Rick Gonzales delivered the operations report for June, noting that high levels of wind curtailment upstate were coincident with scheduled outages of the Browns Falls-Taylorville 115-kV line and the forced outage of the Marcy-Coopers Corners 345-kV line.
MC Approves Change on Congestion Data Reporting
The committee voted in favor of changing how NYISO reports historic congestion, supporting the Business Issues Committee vote earlier in July that the current process is resource-intensive and the resulting data under-utilized.
NYISO Transmission Congestion Map | NYISO
The vote recommends that the Board of Directors endorse the new process, which will require Tariff changes. (See “BIC OKs Change on Congestion Data Reporting,” NYISO Business Issues Committee Briefs: July 11, 2018.)
No Cost of Service Study
The committee voted that a new cost of service study (CSS) should not be conducted during late 2018 and 2019 to inform a decision on whether a modification of the 72%/28% cost allocation between withdrawal billing units and injection billing units is warranted, pursuant to Tariff Section 6.1.2.3.
Chris Russell, manager of customer settlements, said that language included in Rate Schedule 1 requires a vote by the committee in Q3 2018 to determine whether a new CSS should be conducted to evaluate the allocation between withdrawals and injections.
The ISO’s current RS1 allocation provides rebates for recoveries from non-physical transactions.
MC to Help Fill Board Vacancies
Committee Chair Erin Hogan said she had been asked to form a subcommittee to help fill two upcoming vacancies on the board after Directors Thomas F. Ryan Jr. and Jane Sadowsky complete their terms.
Hogan asked that each sector representative by Aug. 1 provide two candidates to serve on the subcommittee in order to complete preliminary work next month and get a search firm to select board candidates by Thanksgiving.
CAISO’s push to become a reliability coordinator (RC) passed its first milestone last week after its Board of Governors approved the proposed rate design for its newest line of business.
The board also passed an “interim” rule change for the ISO’s reliability-must-run program, as well as approving RMR designations for two NRG Energy gas-fired generators in the Southern California Edison service territory.
Approval of the RC rate scheme came just a week after Peak Reliability, the current RC for the Western Interconnection, announced that it would cease operations at the end of 2019. (See Peak Reliability to Wind Down Operations.) Peak made the decision to fold after most of its customer base defected to CAISO, which promised to offer similar reliability services at significantly lower cost.
“That’s compatible with our plan to stand up our own RC and offer those services to others in the West anyway,” CAISO CEO Steve Berberich told board members during their July 26 meeting. “We intend to work very closely with Peak to make sure we have a reliable transition of these services.”
Phil Pettingill, CAISO director of regional integration, told the board the ISO is “uniquely positioned” to provide RC services in the West because of its “very detailed” network model, which can be leveraged “to potentially increase reliability in at least that portion of the interconnection that we’re operating.”
“Because we already have these tools and that infrastructure in place, our projections are showing that we’ve got an opportunity to provide that RC service at roughly 40% of what the current costs are, and provide that higher quality service at the same time,” Pettingill said. The ISO estimates it will be able to provide RC services to the entire interconnection for about $18.5 million, compared with Peak’s current budget of $45 million. (See CAISO Puts $18.5 Million Price Tag on RC Services.)
CFO Ryan Seghesio told the board that CAISO based its RC rate design on the existing rate design, rather than calling out RC services as a distinct function from other ISO operations. He noted that RC services would initially represent about 2% of CAISO’s annual costs upon roll-out to the ISO’s balancing authority area on July 1, 2019, followed by an increase to 9% as others in the West join by the end of next year. The ISO plans to hold its overall revenue requirement to about $205 million, even after introducing RC services.
| CAISO
With the revenue requirement largely stable, Seghesio said RC revenue streams will decrease CAISO’s grid management charge rate — the ISO’s primary revenue source — by $11 million, as well as reduce rates for Western Energy Imbalance Market participants. Supplemental RC services will be billed separately, potentially further reducing other ISO charges.
Seghesio noted that some RC customers have asked the ISO to implement stronger cost containment measures in its proposal, “essentially assuring or guaranteeing some maximum level of cost increase year over year.” But CAISO management “currently believes our existing cost containment measures are adequate,” he said, pointing out that the ISO’s revenue requirement is capped by FERC.
Seghesio said the RC allocation will remain fixed at 9% at least until the ISO performs its next cost-of-service study.
“We’re very confident at this point that the 9% represents a good look at how the 2020 cost-of-service study will look, because that’s the data we’ve used” to arrive at the estimate, Seghesio said.
Speaking during public comment on the proposal, Jeff Rehfeld, senior counsel with NaturEner, expressed “disappointment” that the ISO plans to charge generation-only balancing authorities the same rates as BAs that serve load. The company is a renewable energy developer that operates two generation-only BAs in Montana.
“Our balancing authorities, due to their generation-only characteristics, do not require some of the reliability coordinator services that are required to be provided to other balancing authorities which have load and transmission. And, similarly, the amount of attention and resources that a reliability coordinator must devote to a generation-only BA” is less than required for BAs with load, Rehfeld said.
The proposed rate structure “is not defensible under a cost-causation analysis, [nor] is it fair or equitable,” he said, because it requires generation-only BAs to subsidize other RC customers. He held up Peak’s funding model as more equitable.
“In the case of gen-only and, particularly, your company, the variability of the resources and also the prospect these resources will be operating in two separate RC areas, adds a complexity that justifies our volumetric [megawatt] calculation” for determining rate, Pettingill responded. “I think it’s really the operational engineering analysis that supports our logic.”
Jim Shetler, general manager of the Balancing Authority of Northern California, said his group is “comfortable” with the Tariff changes as proposed. He also pointed to another milestone for CAISO’s RC effort: its first customer commitment.
“In keeping with the concept of early notice on what entities intend to do, I would like to report that at its meeting yesterday, the BANC commission authorized me to go forward with transitioning our services from Peak RC to the ISO, and we’ll be looking forward to making that happen,” Shetler said.
CAISO plans to file the RC rate proposal with FERC at the end of August.
RMR Actions
The Board of Governors on Thursday also approved a modification to the ISO’s RMR program that would replace the existing pro forma RMR agreement with an “interim” version of the agreement. CAISO management sought the change “pending the development of a more comprehensive proposed amended RMR agreement” targeted for board approval in March 2019.
The interim agreement contains a provision allowing for its termination and the immediate re-designation of an affected RMR unit under a “new comprehensive agreement” upon FERC approval, said Keith Johnson, CAISO infrastructure and policy manager.
Pacific Gas and Electric and the Six Cities group of publicly owned utilities in Southern California supported the proposal, while Calpine called it “piecemeal and unnecessary.”
Johnson was careful to note that the interim agreement would not apply to the two gas-fired plants the board on Thursday agreed to designate as RMR — the 54-MW Ellwood Generating Station and one unit at the 1,516-MW Ormond Beach plant. NRG announced in March that it planned to retire the plants, along with its Etiwanda Units 3 and 4. (See NRG Set to Retire California Gas Plants.)
CAISO determined that Ellwood’s retirement would leave a 45-MW deficiency in the local capacity requirement for the Santa Clara subarea next year, while the loss of Ormond Beach would result in a 170-MW shortage for the Moorpark subarea. The ISO expects the units will also be needed in 2020 while the region awaits completion of a 230-kV transmission line and SCE completes the procurement of new resources expected to be online in 2021.
Eric Eisenman, director of ISO and FERC relations for PG&E, said his company was “neutral” on the specific RMR designations but urged CAISO to more quickly address the company’s concerns about the RMR mechanism, such as the lack of a must-offer obligation for RMR units and their existing rate of return.
Eisenman acknowledged that the RMR revision process is moving along, “but not at the pace that matches the urgency PG&E has expressed and continues to express.”
“In all likelihood, if there are any new RMR designations in the PG&E footprint for 2019, PG&E will oppose the terms and conditions before this board and before FERC,” Eisenman said.
CAISO Governor Ashutosh Bhagwat noted the ISO’s expressed concerns about the difficulty of rushing through an initiative as complex as that related to RMRs.
“But I do share PG&E’s sense of urgency. I feel like the faster we can get this done, the better, because we’re essentially [placed] in the position of ad hoc negotiations every single time” the ISO negotiates an RMR, Bhagwat said. “That’s clearly not ideal.”
Environmentalists and state officials called on FERC this week to broaden its review of natural gas pipeline applications while gas producers and electric generators said only minor changes are needed to the commission’s 1999 policy statement.
FERC received about 2,000 comments in response to its Notice of Inquiry asking whether it should reconsider how it balances project benefits against adverse consequences in light of the shale gas revolution, global warming and other changes since it last considered the issue almost 20 years ago (PL18-1). (See FERC Outlines Gas Pipeline Rule Review.)
Most of the comments before Wednesday’s filing deadline came from individuals opposed to fracking and pipeline expansions.
| National Fuel Gas
The commission asked for comments on four topics: the reliance on precedent agreements to demonstrate project need; landowner interests and the use of eminent domain; the evaluation of alternatives and environmental effects under the Natural Gas Act and National Environmental Policy Act; and the efficiency and effectiveness of the commission’s certificate process.
Status Quo
The Edison Electric Institute, Electric Power Supply Association, American Petroleum Institute, American Gas Association and Interstate Natural Gas Association of America (INGAA) generally supported continued use of precedent agreements, while calling for a streamlining of the permitting process and opposing regional reviews of pipelines or consideration of greenhouse gas emissions.
“EPSA believes the assessment of project need should continue to be based on precedent agreements (i.e., contracts with pipeline project customers), which remain the most objective evidence of market demand for pipeline capacity,” said the group, which represents independent power producers. “EPSA urges the commission not to make the certificate review process more unwieldy or challenging at this time in which significant investment in infrastructure will be needed to meet expected demand and ensure reliability.”
The industry groups proposed only modest changes, for example, improvements to FERC’s website and communications to make it easier for landowners to participate in the process.
Other gas backers cited the economic boost the shale revolution has provided. “The energy renaissance that has occurred in this country, spearheaded by the increased development of natural gas production in Pennsylvania, has increased domestic economic activity, has dramatically improved air quality, and has significantly increased the nation’s energy security and global competitiveness,” said the Pennsylvania Chamber of Business and Industry.
Pa vs. NYMEX gas prices | Marcellus Shale Coalition
The Marcellus Shale Coalition, which represents about 200 producing, midstream, transmission and supply chain members in the shale play, said producers have been hurt by limited pipeline capacity. “Natural gas produced in some regions of Pennsylvania has sold for over 65% less than natural gas produced and sold in other basins across the nation,” it said. “While efforts continue in Pennsylvania and throughout the Appalachian Basin to grow natural gas demand and usage, it is clear that the natural gas produced in Pennsylvania must also be transported to larger, more established markets where demand is greater,” the group said.
Calls for Change
The attorneys general of Massachusetts, Illinois, Maryland, New Jersey, Rhode Island, Washington and D.C. countered that the commission’s reviews are too narrow. “In assessing project need, the commission generally fails to account for the extent of regional need for new gas capacity or the evolving market for gas demand and relies too heavily on precedent agreements as proof of need for isolated projects,” they said.
“The commission’s single-minded reliance on precedent agreements is also contrary to the existing policy statement, which directs the commission to ‘consider all relevant factors reflecting on the need for the project,’ including studies of projected demand, the market to be served and potential cost savings to consumers.”
The American Antitrust Institute said FERC should evaluate precedent contracts between a pipeline and an affiliated customer differently than one with an unaffiliated customer to support the commission’s policy of promoting competition.
“Importantly, the repeal of the Public Utility Holding Company Act in 2005 removed restrictions on integration between energy companies. Vertical integration, particularly between pipelines and electric or gas distribution companies, can create anticompetitive incentives to engage in conduct that restrains competition and harms consumers. These possibilities can strongly influence the incentives motivating pipeline construction and the effects of affiliate precedent contracts on competition and ratepayers.”
INGAA said the commission shouldn’t differentiate between affiliates and non-affiliate customers agreements “because both appropriately represent market need. While FERC has the authority to investigate allegations of undue discrimination in favor of an affiliated entity if it has any concerns, it is unnecessary for the commission to distinguish between precedent agreements with affiliated and unaffiliated entities.”
The Industrial Energy Consumers of America said the current process “does a good job in identifying the need for new pipeline capacity within the context of serving domestic demand.”
But it said the commission should set a higher bar for pipelines intended to deliver gas for LNG exports. “The LNG export ‘cost versus benefit’ equation is significantly different because the supply is not serving the domestic market, which is the ‘public interest.’ LNG exports serve the public of other countries,” the group said.
Regional vs. Individual Review
Others, including the Nature Conservancy and Virginia’s U.S. senators, Mark Warner and Tim Kaine, said FERC should look at the combined impact of multiple projects in a region and seek to collocate them where possible.
“When multiple projects are being proposed [in the same region], we recommend that FERC consider cumulative impacts through issuance of a programmatic environmental impact statement (PEIS) that would simultaneously consider the purpose and need of each project, the aggregate impacts of all proposed or foreseeable projects on the affected area and the optimal combination of pipelines to deliver gas from the production areas to markets,” the environmental organization said. “This request is consistent with the Council on Environmental Quality guidance on ‘Effective Use of Programmatic NEPA Reviews’ issued on Dec. 18, 2014.”
The senators also agreed with the Conservancy and New Jersey Department of Environmental Protection that FERC should do more to limit pipelines crossing land set aside for conservation.
Some commenters said the commission should not issue final certifications for projects that haven’t obtained all required state and federal environmental permits.
Tolling orders
The senators and others also said FERC should end its use of tolling orders, which keep rehearing requests in legal limbo.
“As a result of this strategy, FERC prevents court challenges to its decision in a meaningful time frame,” said the VOICES coalition, which represents more than 200 organizations opposed to fracking. “Meanwhile, it grants the pipeline company the power of eminent domain and the right to begin and continue construction, all the while knowing that challengers are awaiting their ability to challenge the project in court. The result is that even in those cases where legal challenges to FERC approvals have succeeded, the victories have come too late to genuinely impact the FERC decision already rendered.”
The group cited the nearly yearlong tolling order that preceded a successful court challenge to the TGP NorthEast Upgrade Project. “The court determination that FERC had violated the National Environmental Policy Act by engaging in illegal segmentation and failing to consider cumulative impacts came only after the pipeline was fully constructed and in operation.”
Opponents of the Northeast Energy Direct pipeline marching in protest. | PopularResistance.org
A coalition of environmental groups, including the Natural Resources Defense Council, Sierra Club and Earthjustice, said FERC should use an “all relevant factors” approach in determining project need. Relying almost exclusively on precedent agreements, they said, ignores that “there may be alternatives to the proposed capacity to meet the purported demand, such as using underutilized existing pipeline capacity or alternative, cleaner energy resources.”
The groups also said pipelines may not remain economic for their entire 40- to 50-year lifespan because flat load growth and competition from renewables and distributed energy resources may undermine gas demand.
“An integrated, more comprehensive review would assess the need for new pipelines based on the energy needs of the region(s) directly affected by the project. Such an assessment would examine factors such as existing and proposed pipeline capacity, long-term energy needs and state policies.”
GHG Emissions
Perhaps the most contentious issue FERC will have to navigate is pipelines’ contributions to GHG emissions.
Most of the individual comments filed were form letters from fracking opponents and climate activists in which only the first sentence varied. (“Dear Secretary: Your greed in placing profit ahead of respect for the Earth and its inhabitants is appalling.” “Dear Secretary: We need to keep as many fossil fuels in the ground as possible, and we need to protect our families and our homes from pipeline leaks and environmental damage.” “Fracking is an irresponsible action, which puts our health in danger. It devastates water and land.”)
All five commissioners voted in favor of initiating the pipeline review. But Democrats Cheryl LaFleur and Richard Glick have repeatedly dissented or issued concurrences in protest of the Republican majority’s refusal to consider GHGs on individual projects.
Last August, the D.C. Circuit Court of Appeals ruled that FERC’s environmental impact statement for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions. In May, however, the Republican majority said FERC will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” Republicans Kevin McIntyre, Neil Chatterjee and Robert Powelson said they were taking the action to “avoid confusion as to the scope of our obligations under NEPA and the factors that we find should be considered” when determining whether a project is in the public convenience and necessity under the NGA. (See FERC Narrows GHG Review for Gas Pipelines.)
Numerous commenters disagreed in their filings this week.
The Harvard Electricity Law Initiative argued that “accounting for the economic risks and environmental harms of downstream and upstream greenhouse gas emissions in a certificate proceeding is consistent with judicial precedent and commission practice.”
The NRDC coalition quoted from a March dissent by Glick, who called climate change “the single most significant threat to humanity.”
“It is difficult to understand how NEPA’s demand that an agency take a ‘hard look’ at the environmental impacts of its actions can be satisfied if the impacts of GHG emissions are ignored,” he wrote.
EEI and individual utilities said, however, that pipelines have helped reduce CO2 emissions by allowing gas generators to replace coal.
The Competitive Enterprise Institute, a conservative think tank, opposed considering GHGs, saying “Saving the planet one gas pipeline at a time is a fool’s errand.
“Worse, importing climate concerns and [social cost of carbon] analysis into public convenience and necessity determinations will fuel spurious ideological controversies, discourage economically beneficial investment in U.S. energy infrastructure and make natural gas prices more volatile.”
FERC on Wednesday granted NYISO a temporary Tariff waiver to allow it to reserve 256 MW of transmission congestion contracts (TCCs) for load-serving entities in two upcoming auctions while it seeks commission approval of a permanent fix (ER18-1889).
The waiver will allow 14 LSEs to renew grandfathered agreements for TCCs that would otherwise be sold in the Autumn Centralized Transmission Congestion Contract Auction in August and the November 2018 Reconfiguration Auction.
Location of congested transmission | NYISO
Last month, stakeholders approved Tariff changes to allow extensions of historic fixed-price TCCs, which originated from grandfathered agreements before NYISO’s formation. (See “Proposal to Extend TCCs Advances,” NYISO Business Issues Committee Briefs: June 20, 2018.)
The proposal, if approved by the ISO’s Board of Directors, will be filed for FERC approval later this summer.
The commission approved the waiver based on NYISO’s statement “that despite expeditiously pursuing the extension proposal with stakeholders, it is impossible to complete the required process of review and approvals, including commission review, prior to the Autumn Centralized TCC Auction.”
Without a Tariff waiver, the ISO said it would risk overselling the amount of available transmission capacity.
The commission’s July 25 order noted that the waiver is limited to the two auctions and that the 256 MW represent only 1% of average total transmission capacity supporting new TCCs.
The commission said it also relied on the assertion of the New York Municipal Power Agency, a joint action agency of 36 member municipalities, that it needed the waiver to support the long-term supply contracts between its member municipalities and the New York Power Authority.
After years of inactivity on the topic, MISO’s Steering Committee is directing the Market Subcommittee to re-examine whether the RTO should create a process to compensate resources for energy delivered during a system restoration event where the real-time market has ceased to function.
Steering Committee members made the decision during a July 25 conference call. The Market Subcommittee will host discussion on the topic at future meetings.
Reliability Subcommittee Chair Bill SeDoris brought the issue forward for assignment by the Steering Committee, saying the time is ripe to create a pricing structure for energy used to restore the system from blackout conditions. The RSC pointed to MISO’s declining reserve margin, its tendency to enter more emergency conditions and FERC’s possible future rulemaking to promote resilience.
“This issue is key to compensation for the ultimate act of resilience: the restoration of the bulk electric grid,” the RSC said in its submittal.
SeDoris said the need for a restoration power price was raised in stakeholder meetings as far back as 2012. In 2015, the project was added to the Market Roadmap with low-priority status and has since been in “parking lot” status, the term MISO gives to low-priority market improvements that are on hold. During this year’s June meeting to kick off the Market Roadmap ranking process, SeDoris urged the RTO to resume work on the project. (See MISO Stakeholders to Rank Market Improvement Ideas.)
“It’s always been low priority … but given all the talk around resilience and reliability, the time is right to get this in front of stakeholders again,” SeDoris said, adding that it would be unfortunate if MISO and its members were to face a blackout without a restoration pricing mechanism in place.
Consumers Energy’s Jeff Beattie asked if LMP would provide a pricing framework for restoration energy.
The RSC said day-ahead and real-time markets will not be running during a restoration event because the MISO system will be broken into multiple islands with “widespread blackouts and loss of contiguousness.”
“There are no markets if the system is black, and the markets don’t start back up until the system is stable,” SeDoris explained.
SeDoris also said restoration compensation would differ from MISO’s existing black start services definition because black start resources derive their revenues from the capacity they provide, not MISO’s energy market. Black start generators are those able to restore electricity without using an outside electrical supply.
While SeDoris agreed with other Steering Committee members that utilities will be naturally incentivized to restore service and that the probability of reaching a system restoration event is extremely low, he contended that having no compensation rules could make a bad situation worse. Other Steering Committee members had said MISO could sort through the details of compensation once it recovered from total blackout.
“There’s nothing out there to say, ‘We pay $1,000/MWh or cost of new entry,’” SeDoris said, throwing out examples. “How would we end this? Are we looking at litigation?”
American Electric Power on Friday announced it is canceling its proposed $4.5 billion Wind Catcher Energy Connection project, one day after receiving a negative ruling from the Public Utility Commission of Texas.
The PUC on Thursday denied AEP subsidiary Southwestern Electric Power Co.’s request to acquire a 70% interest in the project, which was scheduled to be completed in 2020 to take full advantage of the federal production tax credit.
AEP had said Wind Catcher would save customers of SWEPCO and sister company Public Service Company of Oklahoma (PSO) more than $7 billion over 25 years. PSO would have owned the remaining 30% share.
“We are disappointed that we will not be able to move forward with Wind Catcher, which was a great opportunity to provide more clean energy, lower electricity costs and a more diverse energy resource mix for our customers in Arkansas, Louisiana, Oklahoma and Texas,” AEP CEO Nick Akins said in a statement.
Wind Catcher included a 2-GW wind farm,to be built by Invenergy on 300,000 acres in the Oklahoma Panhandle, and a 360-mile, 765-kV transmission line from the facility to Tulsa, where it would have been connected to the PSO and SWEPCO grids.
| AEP
FERC and Arkansas and Louisiana regulators had already approved the project. The Oklahoma Corporation Commission had yet to issue a ruling, but had also expressed concerns.
Saying the project’s costs placed an undue burden on SWEPCO’s Texas ratepayers, the PUC rejected an administrative law judge’s proposal for decision (PFD) on the utility’s request for a certificate of convenience and necessity to participate in the project (Docket No. 47461).
“I don’t believe I could approve the PFD, because I don’t believe it provides sufficient safeguards for the ratepayers,” said PUC Chair DeAnn Walker. “The costs are known. The benefits are based on a lot of assumptions that are questionable.”
PUC Chair LeAnn Walker (center) discusses the Wind Catcher decision with Commissioners Shelly Botkin, Arthur D’Andrea. | PUCT
“They’re asking us for $4.5 billion in taxing authority against the people of Texarkana and Longview,” Commissioner Arthur D’Andrea said during the PUC’s open discussion, referencing the major cities in SWEPCO’s East Texas footprint.
“It’s one thing when the story is, ‘We need this generation to go forward,’” D’Andrea said. “But when the question is, ‘We don’t need it, and we think it will lower the rates, and we think it’s a good deal and it’s a financial play.’ … You have a burden to show the taxpayers and businesses of Texarkana and Longview really have something to gain from that. I don’t think [SWEPCO has] met that burden.”
Settlement Unlikely
The PUC in May approved a 478-MW wind farm for Southwestern Public Service, following a settlement agreement between SPS and various parties. (See Texas PUC Issues Final Order for SPS Wind Farm.)
SWEPCO was never able to reach a settlement with its intervenors.
“The only reason it worked in the SPS case was because everyone agreed to [customer protections],” Walker said. “We don’t have that situation here, where everyone could agree to what I believe are reasonable conditions.”
Thompson & Knight attorney Rex VanMiddlesworth, who represented the Texas Industrial Energy Consumers trade group, said SWEPCO’s “unnecessary $4.5 billion investment of ratepayer money” was built on a series of improbable assumptions that included $4.75/MMBtu gas prices in 2021, a federal carbon tax by 2026 and the cancellation of most other wind projects in SPP’s interconnection queue. The Energy Information Administration predicts Henry Hub gas prices will be $3.66/MMBtu in 2021, not reaching $4.75/MMBtu until 2046.
Rex VanMiddlesworth presents the TIEC arguments | PUCT
VanMiddlesworth also said Wind Catcher was “burdened” by the $1.6 billion generation tie across Oklahoma.
“That made the project 40% more expensive to construct than other wind projects, while delivering 8% less energy,” he told RTO Insider. “The commission properly found that this was not a risk that should be imposed on Texas ratepayers.”
During AEP’s quarterly earnings conference call Wednesday, Akins seemed prepared for what might come, telling analysts that the company’s “first signal of 2021 capital budgets” assumed no Wind Catcher expenditures.
Akins said Wind Catcher was incremental to AEP’s base plan, which supports 5 to 7% growth in transmission and other investment among its regulated companies.
“If Wind Catcher were not to happen, there would still be opportunities for those kinds of resources to be applied to our resource plans in [the Wind Catcher] states,” Akins said. “Obviously, we don’t want to miss the opportunity for Wind Catcher because it’s a great way to deal with the resource plans in all of those states at one time, rather than independently with perhaps less efficient projects.”
Akins likened AEP’s situation to being in a football field’s red zone, “with time running out, 3rd down with two plays to go, needing a touchdown, with both plays already called. They’re called Texas and Oklahoma.”
The Texas play resulted in a sack, though, and time ran out.
MILWAUKEE — Middle America could significantly decarbonize over the next three decades, but today’s actions and investment decisions and future public policy will be critical to meeting that goal, says a new report by a diverse group of regional energy experts.
The report by the Midcontinent Power Sector Collaborative (MPSC) says the midcontinent electricity sector could “substantially decarbonize by midcentury,” possibly reducing CO2 emissions by 80 to 95% from 2005 levels using existing technology. Entitled “A Road Map to Better Energy,” the analysis was released at a July 24 conference hosted by the Great Plains Institute and the MPSC, a group of regulated utilities, generation and transmission cooperatives, merchant power providers, environmental organizations, and regulatory agencies.
“That’s a really, really critical finding,” Jeff Deyette of the Union of Concerned Scientists said of the carbon reduction potential. “We should be saying that loud and a lot, especially to those that are” doubters.
Great Plains Institute CEO Rolf Nordstrom praised the group for tackling such a contentious subject. He said the roadmap is especially important considering the diverse interests of the group’s members.
“The truth is the world is lousy with roadmaps. Who put this one together is important,” he said. “In today’s environment, where the public discourse can be so fractured and groups can talk past one another … it seems all the more important to note that — it’s in the name — this group is so collaborative,” Nordstrom said.
In the study scenarios in which carbon emissions fall to either 80% or 95% below 2005 levels, the midcontinent region would shift further from coal-fired generation, with no new coal capacity built even when considering carbon capture technology.
In a 95% reduction scenario with low natural gas prices and moderate renewable prices, the 2050 resource mix becomes nearly all wind generation and natural gas with carbon capture technology. With low renewable costs and moderate gas prices, wind dominates with slightly more solar participation. Nuclear generation remains largely static in both cases.
“The key finding is the region can do this,” said Franz Litz of the Great Plains Institute, adding that in California, solar and wind don’t complement each other well, whereas in the midcontinent, the two renewable resources have a more symbiotic relationship.
In a business-as-usual study model that included combinations of either moderate gas prices/low renewable costs or low gas prices/moderate renewable costs, the MPSC found that carbon emissions drop from about 500 million metric tons of carbon dioxide equivalents (MMT CO2) in 2016 to slightly less than 300 MMT CO2 by 2050.
MISO’s current generation mix consists of 77% natural gas and coal, with 18% non-emitting resources.
Policies?
The group said that despite regulatory uncertainty and the demise of the Clean Power Plan, it expects “substantial decarbonization will ultimately be required of the sector.”
Deyette said polices are needed to accelerate the transition: “We’re just not going to get there on the current voluntary choices of the utilities,” he said.
Consultant Judi Greenwald, who once served as an adviser on climate change to Energy Secretary Ernest Moniz, pointed out that even today’s natural gas boom was nudged along beginning in the 1970s with generous government subsidies that encouraged research and development into extraction.
“It may look like market forces, but it has its roots in a mix of technology exploration and public policy,” Greenwald said.
The Lost Study
Greenwald pointed out that the U.S. itself released a study on decarbonizing by 2050 in November 2016 as a component of the Paris Agreement on climate change.
“Maybe you missed it — there was a lot going on that month,” Greenwald joked.
The paper, “United States Mid-Century Strategy for Deep Decarbonization,” is no longer available on the White House website, but a version can be found on the U.N. website. It charts a threefold strategy for decarbonization: transforming the energy system, sequestering carbon and reducing non-CO2 emissions to bring net emissions from under 7 gigatons of carbon dioxide equivalent (CO2E) in 2005 to about 1 gigaton CO2E by 2050.
“Its status is somewhat indeterminate,” Greenwald said of the strategy paper.
Nordstrom encouraged attendees to think about what other countries are doing, especially China, which produced 60% of the world’s solar panels in 2017 and is currently leading the world in electric bus adoption.
“This is our time to determine where the puck is going to be, to use a tired, tired sports metaphor,” Nordstrom said.
‘Long-Lived Choices’
MPSC members say time is of the essence to get to a mostly decarbonized electricity sector in three decades.
“2050 is 32 years away. Some think that’s a long time, others not so much,” Greenwald said. She pointed out that even building appliances last about 10-20 years, while cars stay on the road 15-20 years. Investments being made now will determine the pace of decarbonization, she said. “You want to affect these investments now if you want to get going.
“Deep decarbonization of the U.S. economy is a challenge, but it’s doable,” Greenwald said. “It’s up to us. The emissions that we will have in the next several decades are up to us.”
“The choices that we make today are long-lived choices,” agreed Litz.
Miles Keogh, executive director of the National Association of Clean Air Agencies, said the plan to 2050 should be viewed through a backwards timeline. “Alright, it’s as if we’re getting married by 2050, and we have to have all this new generation built by then; we have to count backwards to see when we have to start constructing,” he said.
Keogh warned that 2050 is fast approaching and steps must be taken now if deep decarbonization is the goal.
“I think we have the money; I don’t think we have time,” he said, warning that as more time goes by without meaningful work, “the more unlikeable, strident and vigorous the driver has to be.” Keogh said the most universally disliked drivers tend to be policies. He pointed out that of the state regulators in MISO, only three — Iowa, Minnesota and Illinois — did not sue the federal government over the Clean Power Plan.
Keogh also said the immediate future holds little to no chance of any sweeping federal policies.
“The movement toward decarbonization is now not a federal matter; it’s a state and local matter,” he said. “We’re going to have this president until 2020, 2024 maybe. So legislation on the federal level is not going to be an immediate, immediate driver,” Keogh said.
Greenwald said she’s often asked if she’s an optimist or a pessimist regarding the goal of deep decarbonization. On that, she quoted physicist and clean energy pioneer Amory Lovins: “I am neither — because they are just two different forms of fatalism. I believe in applied hope. Things can get better, but you have to make them so.”
Greenwald added there’s no one silver bullet for decarbonization, “just a lot of buckshot,” meaning a variety of strategies.
Utilities Preparing
Xcel Energy’s Nicholas Martin said his company has moved beyond meeting renewable portfolio standards. He also said natural gas generation plays only a “supporting role” in its fleet.
“For many utilities, it’s been a transition from coal to gas. For us, it’s been a transition from coal to largely renewables,” he said. Xcel has pledged an 80% carbon-free energy fleet by 2030 in the upper Midwest and 60% in the rest of its service territory by the early 2030s.
“I can see us going beyond that,” Martin added.
DTE Energy’s Greg Ryan said his company plans for at least an 80% reduction in emissions levels from 2005 by 2050.
“The Clean Power Plan was going to be not too heavy of a lift,” Ryan admitted. “Especially after the 2016 election, we believed this is something we can lead the way on.”
Minnesota Public Utilities Commission Chair Nancy Lange said utilities should keep customers content so they stay on the grid and don’t exit for community aggregation programs that could disrupt the utility structure.
“To me, there’s a continuum of cost on one side and carbon on the other side, and reasonable people should care about both,” said Arkansas Public Service Commission Chair Ted Thomas, who also chairs the Organization of MISO States. “Look at my state; we’re on the cost side of the continuum, no doubt.”
Lange said regulators must reflect often on whether their decisions stifle innovation.
“I know … we’ll probably have gas plant proposals in front of us. That risk about climate is going to ripen, especially in Minnesota’s case,” she said, referring to Minnesota Power’s contested plan to partner with Dairyland Power Cooperative on a new 550-MW natural gas plant on the Wisconsin-Minnesota border. Opponents of the proposed plant say it could compromise the state’s ability to meet its own emission-reduction targets.
If you peruse my columns (and thank you if you do), you may have noticed chronic heartburn over all manner of subsidies.
Huntoon
To be sure, I think everyone should have the right to buy a Tesla. But I don’t think anyone should have to contribute toward someone else’s Tesla.
Ditto someone’s microgrid, rooftop solar, home battery, grid battery, new nuclear plant, old coal plant, etc.
Which brings me to today’s topic: Offshore wind. Coming soon to a beach near you if the ambitions of just about every state north of Virginia pan out.
Now, please don’t get me wrong, I think wind energy is wonderful. If you’ve been to Atlantic City in the last 12 years, you may have noticed five wind turbines in the back bay. Yours truly did the resource analysis, the financials, the permitting and the contracting for that project. I drove the stakes in the ground to mark where the turbines were placed. Back then, wind project development was a jack-of-all-trades business. I was the jack.
Offshore Wind in Reality Is Anti-wind
My objection to offshore wind is that in reality it’s anti-wind. Here’s why: Whatever value you want to assign to wind (and other renewables), it is critical that we make the most of our collective money.
Offshore wind squanders that money.
How do we know that? Because onshore wind is a fraction of the cost.
For a given amount of subsidy dollars, to get 1 million MWhs of offshore wind, we could get 11 million MWhs of onshore wind.
| Lazard Levelized Cost of Energy Analysis
Here are the numbers, using a recent study by analysts who support offshore wind (seeking to show that offshore wind is more valuable than onshore wind). They define value as the market revenues in $/MWh. So in PJM, for example, onshore wind has a value of $39/MWh, and offshore wind has a value of $45/MWh.[1]
But here’s the thing. Onshore wind costs in the range of $30 to $60/MWh per Lazard’s most recent Levelized Cost of Energy analysis.[2] Offshore wind is estimated by Lazard to have a mid-point cost of $113/MWh – which I would suggest is way too low,[3] but let’s go with it.
Using the midpoint of the Lazard cost range for onshore wind of $45/MWh, and subtracting the onshore value of $39/MWh, means onshore wind on average needs a subsidy of $6/MWh.
Using the Lazard cost midpoint for offshore wind of $113/MWh, and subtracting the offshore value of $45/MWh, means offshore wind on average needs a subsidy of $68/MWh.
See the difference? Offshore wind sucks up $68/MWh, when onshore wind needs only $6/MWh. We can get on average 11 times more onshore wind from a given dollar of subsidy. Wow.
Lots of Onshore Wind Out There
It’s important to point out the enormous subsidy of offshore wind cannot be based on a claim that we’re running out of onshore wind. In PJM, for example, only some 8,200 MW of onshore wind have been installed, while the potential onshore wind resource is a staggering 365,000 MW.[4]
Yes, you read that right. Installed wind in PJM is only 2% of the potential wind resource. And the PJM onshore potential is 43 times the total offshore wind currently planned for the entire East Coast (8,500 MW).
The undeveloped onshore resource is out there, waiting. Why sacrifice so much to subsidize offshore wind when that same subsidy dollar could create 11 times more onshore wind? With 11 times more environmental benefits?
Offshore Apologia Doesn’t Hold Up
I raised these concerns at the summer meeting of Mid-Atlantic regulators, to a panel of offshore wind proponents (no skeptics allowed on the panel). I received answers something like these (answers in quotes with my comments following):
“There’s not enough onshore wind in places like New Jersey.” If you care about global warming, why should you care if the wind is built in your state? And even if that mattered, offshore wind isn’t going to be located in New Jersey – or any other East Coast state for that matter. By federal law, each state’s offshore boundary extends only 3.5 miles from the coastline (with the notable exception of, where else, Texas). So this must be about political bragging rights instead of responsible use of taxpayer and consumer dollars.
“Offshore wind is a better resource than onshore wind.” This misses the point that offshore wind, being a better resource, is already reflected in the value-cost comparison above.
“Offshore wind costs are declining, as shown in Europe.” True enough, but as the current numbers reflecting the most recent decline show, offshore wind is nowhere close to making sense. When and if it ever is, that would be the time to spend scarce taxpayer and consumer dollars on it, instead of on onshore wind.
“It’s a long-term investment.” A bad idea is a bad idea. It doesn’t become a good idea by calling it an investment and thereby taking money from people who could productively use it. Whenever offshore wind comes to make sense, then, and only then, would it be a good idea.
The Economic Development and Jobs Scam
As a final note, let me address a couple other leading arguments for offshore wind subsidies: economic development and jobs. The economic development claim typically comes from the wind developer’s consultant and is not only fanciful but also still pales in comparison to the negative impact of the subsidy cost (which somehow doesn’t appear in the press release).
As for jobs, let me give as an example the U.S. Wind project of 248 MW in Maryland, which the Maryland Commission claimed would create 4,540 new jobs in the operating phase of the project,[5] a claim that was cranked into the press release.[6]
This is a ridiculous number of new jobs for a relatively small (yet expensive) wind project. The project sponsor, U.S. Wind, claimed only 250 new jobs during the operating phase.[7]
So how could the Maryland Commission come up with 4,540 new jobs? The Commission’s consultant took its estimate of 226 new jobs and multiplied it by 20 years of project operation.[8] So every year, the same 226 jobs got counted again and again and again, for a total of 20 times. Is “scam” too strong of a word?
Oh, and as the Maryland People’s Counsel pointed out, the economic development claims completely ignored the negative effects on Maryland businesses (and jobs) from having to pay the enormous subsidies.[9] This is the free-lunch fallacy.
Bottom Line: All Ashore Please!
Subsidies are costly, especially when they sacrifice many times better options and can’t possibly produce the claimed benefits.
Politicians and regulators should suppress their Edifice Complex and support the wind resources that makes sense.
http://eta-publications.lbl.gov/sites/default/files/offshore_erl_lbnl_format_final.pdf (subtracting the $6/MWh of additional energy and capacity revenue on pdf page 15 from the offshore value on pdf page 11 to get the net onshore value). 2016 data are used from the study, rather than 2007-2016 data, because the latter do not fully reflect the fundamental change in natural gas prices over time. ↑
Pegging the cost of offshore wind is difficult because numbers bandied about in the trade press and in press releases can be deceptive. Some reported numbers are north of $200/MWh, and then there is a surprise like Maryland’s claim of Offshore RECs at $131.93/MWh. Now, with RECs, the developer is assuming some level of energy revenue that needs to be added to get total cost. But more importantly about the Maryland report is that the actual REC cost is $163/MWh in year one, escalating at 1% per year. Now, you might wonder how a REC cost starting at $163/MWh can actually cost $131.93/MWh. It can’t. The Maryland Commission converts the actual cost into a present value in 2012 dollars by an assumed discount factor. https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\121.pdf, pdf page 78. Of course, there’s no end to such nonsense – the Maryland Commission could have converted to 1912 dollars and said the cost was $6.50/MWh. ↑
The D.C. Circuit Court of Appeals on Tuesday dismissed claims by a labor union that FERC had failed to consider the effects of the closure of the Brayton Point power plant on ISO-NE’s Forward Capacity Auctions 9 and 10 but did suggest the commission should act on a similar claim regarding FCA 8.
Circuit Judge Cornelia Pillard filed the opinion for the three-member panel July 24, dismissing claims by the Utility Workers Union of America Local 464 and its president, Robert Clark, who contended that high clearing prices in FCAs 9 and 10 — resulting from the “illegal” closure of Dynegy’s 1,488-MW Brayton Point station in Massachusetts — increased the cost of their retail electricity service. The union represented workers at the plant, which closed last year.
The petitioners challenged FERC’s orders approving the results of those wholesale auctions as just and reasonable under Section 205 of the Federal Power Act.
The Brayton Point Power Station in Somerset, MA went offline in June 2017.
“Because no record evidence establishes a causal link between the claimed manipulative closure of Brayton Point and the clearing prices of FCA 9 and FCA 10 that FERC approved, we hold that petitioners lack standing to challenge FERC’s acceptance of those results,” the court said.
The union and others also had challenged Brayton Point’s closure before the commission as an attempt to manipulate the results of FCA 8.
In September 2014, the commission split 2-2 over whether it should reject the results from FCA 8 because of unchecked market power, allowing the 2017/18 auction results to become “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary. (See Court Asked to Force FERC Action on Disputed ISO-NE Capacity Auction.)
In the absence of final FERC action, the court lacked jurisdiction to consider that FCA 8 petition.
Tuesday’s ruling said, “Petitioners’ long-pending request that the full commission revisit Brayton Point’s retirement in the FCA 8 proceedings has yet to be resolved. We trust the commission will give it appropriate consideration without further delay.”
Missing Link
The court suggested the petitioners erred in referring solely to events that occurred in FCA 8, which saw total capacity costs for 2017/18 rise to $3.05 billion (or $7.025/kW-month) — almost double the previous high — as the region’s capacity shifted from an expected surplus to a deficiency of more than 1,000 MW. Prices surged again the following year to $9.55/kW-month for FCA 9 covering 2018/19 but fell to $7.03/kW-month in FCA 10.
“It might seem intuitive, given the laws of supply and demand, that the non-participation of a large plant like Brayton Point would exert some upward pull on auction prices,” the court said. “Again, that logic might suffice in relation to FCA 8, given that Brayton Point retired after the deadline for other suppliers to participate in that auction. But in this context, where petitioners challenge successive Forward Capacity Auctions exclusively by reference to events during FCA 8, the link is missing.”
The court said New England has structured its forward capacity markets to safeguard against undesired effects in one auction rolling through succeeding ones.
The cycle of annual auctions, “conducted three years before generators assume the resulting obligations, are spaced so as to permit the market to account and correct for the events of the previous auction,” the court said.
During American Electric Power’s second-quarter earnings call with financial analysts last week, CEO Nick Akins was pressed about the uncertainty the company’s proposed Wind Catcher Energy Connection was placing on its share price. In the company’s earnings release, Akins had promised the company’s investments in its regulated businesses “will continue to support our 5 to 7% earnings growth rate.”
Xcel Energy reported a 16% increase in second-quarter earnings boosted by favorable weather and sales growth, exceeding analysts’ expectations.
