November 1, 2024

Q1 Earnings Briefs

aepSummoning his inner rocker, American Electric Power CEO Nick Akins said last week he is looking forward to the company’s fully regulated future, one without merchant plants, capacity markets and auctions.

A drummer in his spare time, Akins told financial analysts at an earnings call Thursday that AEP’s outlook reminds him of how he felt at this year’s Rock and Roll Hall of Fame Induction Ceremony in New York.

“The ceremony was outstanding, as usual — much like AEP’s performance in recent years — but there was still an overhang for me, because as a Journey fan [lead singer] Steve Perry spoke but didn’t sing with the band at the ceremony,” said Akins, who sits on the Rock and Roll Hall of Fame and Museum’s board of trustees.

AEP CEO Nick Akins on drums rocking out for the Hall of Fame’s 20th anniversary AEP/Twitter

“I can tell you today that we feel at AEP very good about where we stand as a company today, with no real overhanging issues to cloud our view of where this company is going,” he said. “It’s as if Steve Perry, in fact, did sing once again with Journey. Don’t stop believing in AEP.” (See AEP’s Akins Optimistic over Regulated Future.)

Investors haven’t, pushing AEP’s stock price from its $67.44/share open Thursday to close at $67.83/share Friday, despite missing analysts’ expectations for the first quarter.

AEP reported first-quarter earnings of $592 million ($1.20/share), up from $501 million ($1.02/share) in Q1 2016. Operating earnings came in at 96 cents/share, missing Wall Street’s expectations of 97 to 98 cents.

The Columbus, Ohio-based company attributed its drop in sales — to $3.9 billion from $4 billion — to its service territory’s third-warmest temperatures in 40 years.

AEP did realize a $127 million profit through the earlier-than-expected sale of four merchant plants to Lightstone, a joint venture between The Blackstone Group and ArcLight Capital Partners. The plants include three fired by natural gas, with 2,533 MW of capacity, and the giant 2,665-MW Gen. James M. Gavin coal plant.

The company is plowing the transaction’s proceeds back into its regulated business, transmission and AEP Renewables. Akins said AEP’s affiliates are on pace to invest $300 million to $350 million in contracted renewables; the company has an investment goal of $1 billion over the next three years.

“Our progress has been consistent with our message of using a disciplined approach to methodically [reduce the] risk of merchant generation and augmenting … earnings from contracted renewables,” he said.

AEP hopes to complete its strategic review of its merchant fleet this year, Akins said. He said the company has given its consent to Dayton Power and Light to retire its 603-MW share of a 2,317-MW coal plant due to close in 2018 and sell its 330-MW share of the 1,300-MW coal-fired William H. Zimmer Power Station to Dynegy in exchange for the latter’s 312-MW share of Conesville Unit 4.

That will reduce the company’s competitive generation business to its ownership stake in Conesville Power Station’s four units (1,695 MW) and one of the Cardinal Power Station’s three units (595 MW). The plants burn coal and oil.

AEP reaffirmed its earnings guidance range of $3.55 to $3.75/share.

Entergy Reports Another Bad Quarter

Entergy Beats Expectations Despite 80% Drop in Earnings.)

The results included a $230.9 million charge for the costs of winding down Entergy Wholesale Commodities and its five nuclear units.

CFO Drew Marsh told analysts the company expects “pretty strong cash flow” for the next few periods because it won’t be paying for refueling outages at two of the nuclear plants.

“Are we making any progress? I would say, absolutely,” Marsh said. “Internally, we’ve been scrubbing the numbers down hard, so we would hope to show you some specific progress over the balance of the year.”

CEO Leo Denault announced Entergy Louisiana recently signed a contract with a Calpine subsidiary to build a 360-MW gas peaking plant in Bogalusa, La. Entergy will operate the plant, which is expected to be completed in 2021.

Xcel Energy Says 1st Q Earnings ‘In Line’

Despite matching 2016 first-quarter performance, Xcel Energy CEO Ben Fowke said Thursday his company survived warmer temperatures with “first-quarter earnings … generally in line with our internal plan.”

Xcel reported first-quarter earnings of $239 million ($0.47/share), virtually unchanged from the year prior of $241 million ($0.47/share). That fell short of the Zacks consensus estimate of 50 cents/share.

Fowke was unperturbed, saying that by keeping its operating costs flat for the year, the company will be on track to meet its earnings guidance of $2.25 to $2.35/share.

He also noted Xcel was named by the American Wind Energy Association as the No. 1 utility wind provider for the 12th straight year. The company has proposed adding almost 3,400 MW of new wind to its system as part of its “steel-for-fuel” strategy.

NextEra Sees More Fossil, Nuke Retirements

NextEra Energy officials said they continue to see a bright future for renewable energy and darker days for traditional power sources.

Speaking during the company’s April 21 conference call with financial analysts, NextEra CFO John Ketchum said “improved wind and solar economics” and low natural gas prices will “continue to lead to additional retirements of coal, nuclear and less fuel-efficient oil- and gas-fired generation units, creating significant opportunities for renewables growth going forward.”

NextEra Energy Resources, the company’s wholesale electricity supplier, owns and operates about 16,500 MW of wind and solar capacity. Ketchum said the company had signed contracts for 413 MW of new wind generation and 208 MW of solar energy during the first quarter.

“Customer origination activity continues to be largely driven by economics,” he said. “Based upon continued equipment efficiency improvements and cost declines, Energy Resources can offer wind [power purchase agreements] at very competitive prices.”

The company reported first-quarter earnings of $1.58 billion ($3.37/share), compared to $653 million ($1.41/share) a year earlier. Adjusted to exclude the effects of non-qualifying hedges, the net effect of “other than temporary” impairments, operating results from its Spain solar project and merger-related expenses, Q1 earnings were $820 million ($1.75/share) versus $732 million ($1.59/share) in Q1 2016.

– Tom Kleckner

SPP Board Cancels Panhandle Line, Seeks New Congestion Study

By Tom Kleckner

TULSA, Okla. — SPP’s Board of Directors on Tuesday sided with stakeholders’ recommendation to cancel a major 345-kV line but promised a new study to address congestion in the footprint.

The board directed staff to pull Southwestern Public Service’s Potter-Tolk line in the Texas Panhandle from the 2017 Integrated Transmission Planning 10-year assessment’s portfolio. The project was originally identified as reducing congestion and adjusted production costs (APC), avoiding future reliability projects, and improving thermal and voltage stability margins.

However, the board in January asked SPP staff to further evaluate the project after SPS argued against the need for the line, saying it was “the wrong time” for it. The additional analysis and modeling changes revealed a 6.5% decrease in the region’s APC savings, and a third-party review added $29 million to the project’s $144 million projected cost after more detailed routing assumptions lengthened the line from 90 miles to 109. (See “Members OK Removing SPS Line from 2017 ITP10,” SPP Markets and Operations Policy Committee Briefs.)

The board’s move came following a lengthy discussion that raised questions about SPP’s planning processes, the reliability of stakeholder data being provided for studies and the amount of additional wind energy that will eventually be built in the area.

Getting the Red and Yellow Out

“This hurts me to take this out of the portfolio, but that damn yellow and red has been in that area of Texas ever since we can remember,” said Board Chair Jim Eckelberger, alluding to the shades used to denote high prices — often driven by congestion —on SPP’s price contour map. “We’ve got to get rid of it. There’s nothing blue [low-cost] down there. It’s just congested all the time.”

Eckelberger was able to mollify members by also asking SPP to conduct a high-priority study in a “thoughtful way” to “do away with the yellow.” Staff will report back to the board and Members Committee in July with its study assumptions and scope for an analysis to be completed no later than April 2018. That would also allow additional time to see how much additional generation is developed in the Panhandle.

“By the time we see the end result, we’ll see an awful lot of what is actually being built in that area,” Eckelberger said. “I’ll be damned if we’re going to have that yellow in there for the long term.”

The motion passed easily, drawing only opposition from independent transmission provider ITC-Great Plains and an abstention from West Texas’ Golden Spread Electric Cooperative.

Stuart Solomon, president of American Electric Power subsidiary Public Service Company of Oklahoma, asked the board to broaden its view and study congestion in other areas of the SPP footprint. “The Texas Panhandle is not the only place we’re seeing extreme congestion,” he said.

“As long as we’re going through this process, why not?” Eckelberger responded.

The Potter-Tolk line would have run southwest of Amarillo to connect with an SPS power plant being re-evaluated for continued operation. Initial studies showed the line would reduce congestion in a frequently constrained area (FCA), but new load projections showed a reduction of almost 800 MW in the area.

In March, SPS parent Xcel Energy announced wind projects totaling 1,230 MW in New Mexico and Texas north of the FCA. Another 8.8 GW of wind projects, based on SPP’s generation interconnection queue, have been proposed in the northern Panhandle.

“Based on these recent revelations and some of the uncertainty about these revelations, there’s too much uncertainty to proceed with Potter-to-Tolk,” SPP Engineering Vice President Lanny Nickell said. “The projects that have already been approved and come into service will dramatically reduce the congestion in the area. It doesn’t eliminate it but reduces it.”

PTC Impact

Steve Gaw, who represents the Wind Coalition, noted some of the study scenarios did not assume additional wind generation would be built. He said the phase-out of the production tax credit will lead to additional wind energy coming online after the first results of SPP’s new transmission planning process are released and before it can be considered. Projects that begin construction this year will receive 80% of the PTC value, a percentage that will fall to 60% in 2018 and 40% in 2019.

Gaw said it is unrealistic to assume there will be no additional wind growth, considering 4 to 5 GW of wind generation sites have approved interconnection agreements, the queue contains a potential 27 GW of wind energy and the PTC deadlines.

“If the assumption here is to stay exactly as we are today … to me, that’s an unreasonable assumption,” he said. “That does not adequately encompass what wind development is going to do. I’m concerned that if we don’t do something more … we’re going to run into a significant issue without having properly prepared for it.

“Yes, there’s a risk of building a project that’s not needed. There’s also a risk of not building a project that is needed.”

“If you look back at … various studies over the years, you’ll find we’ve been very conservative, probably too conservative, in forecasting the expansion of renewable generation in the footprint,” ITC-Great Plains’ Brett Leopold said. “It results in inefficiencies in planning.”

Kicking the Can?

Golden Spread’s Mike Wise filed a letter with SPP raising concerns about the project’s withdrawal, noting it was the only FERC Order 1000-eligible project in ITP10. The letter was cosigned by Hunt Transmission Services’ Bill Bojorquez and distributed to members an hour after the board meeting began.

Wise and Bojorquez said that the conclusion that the only Order 1000 project was no longer needed “should raise several red flags to the board.” They criticized the increased cost estimate (“We … were not shown sufficient evidence … the original cost estimate was unreasonable.”); the “highly suspect” change in load projections; and a new generation plan for “new wind generation that lacks regulatory approval.”

Wise’s main point of contention was SPP’s inability to relieve a north-south constraint that staff admitted costs the area about $38 million a year in congestion.

“For many years, a lack of transmission in this area has caused the establishment of the FCA and this constrained flowgate,” Wise and Bojorquez wrote. “The result is significantly higher LMPs for all network consumer loads in the south part of the system, and the ITP process of SPP has not identified or offered a solution.”

“We’re really anxious to get not just the flowgate alleviated, but this FCA … eliminated,” Wise told the board and members. “If not today, then when? If this isn’t the line, then what is going to resolve the FCA and this flowgate? We can’t just kick the can down the road another year and look at it again. That’s what we’ve said for 10 years now.”

Bill Grant, director of strategic planning for SPS, defended his company. “We didn’t ask SPP to go out and use new assumptions,” he said, referring to load projections that may not have been in the 2017 models.

“We need to continue to look at this area,” he said. “If the wind does develop, some of that wind will be identified in the GI study. We’re building generation too, so we might be paying for some of these projects as well. If we’re the ones adding wind, that’s the proper thing to do.”

MISO Stakeholders Give Go-Ahead on SD Interregional Project

By Amanda Durish Cook

The first MISO-SPP interregional project inched closer to reality Thursday with a vote of confidence from the MISO Planning Advisory Committee.

Four stakeholder sectors in attendance at a special April 27 PAC meeting ― Environmental, Transmission Owners, Coordinating and Power Marketers ― voted unanimously to approve the South Dakota project’s regional review. The $5.2 million project will relieve congestion on the tie line shared between the Western Area Power Administration and MISO’s Xcel Energy territory. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)

MISO-SPP Interregional Project
| MISO & SPP

The PAC charter does not require a voting sector quorum for project recommendation votes. MISO moved its stakeholder vote from the Interregional Planning Stakeholder Advisory Committee to the PAC late last year amid concerns that a vote in the IPSAC wouldn’t give stakeholders time to process voting issues and would be poorly attended. (See “PAC Could Hold IPSAC Vote Outside of Interregional Meetings,” MISO Planning Advisory Committee Briefs.)

SPP, meanwhile, will hold its stakeholder vote at a Seams Steering Committee teleconference May 3. SPP officials have also recommended its stakeholders approve the project, the only joint recommendation to come out of the RTOs’ coordinated system plan study conducted last year.

Both stakeholder votes are nonbinding. The MISO-SPP Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — can override the votes.

Before the vote was conducted, MISO officials hinted that they would press for regional review regardless of their stakeholders’ views.

“We’re just trying to memorialize stakeholder opinion,” MISO’s Eric Thoms explained of the vote.

MISO PAC liaison Jeff Webb said the small project has already come a long way because it comes recommended by both MISO and SPP leadership, a first for the RTOs. “This is a procedural motion more than anything,” he said. “We’re merely seeking input … and we anticipate that no stakeholders would oppose the project. We have the right to take your vote under advisement, and we’re very much inclined to check this project out.”

MISO will proceed with a regional review process only if the JRPC also votes in favor of the project. If it is approved, the RTO would most likely process the project as part of its 2017 Transmission Expansion Plan, said Davey Lopez, MISO adviser for planning coordination and strategy.

At an April 25 Informational Forum, MISO CEO John Bear said the possible approval of the first MISO-SPP interregional project would be a “rare” occurrence, given the complex approval process the project must clear.

MISO would designate its portion of the project as miscellaneous, unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects. The RTOs have no voltage threshold on interregional projects, but they do have a $5 million cost criteria, a requirement that either RTO must see a 5% or greater share of the project’s benefits and a condition that the estimated in-service date be within 10 years of project approval.

Acting on a complaint by Northern Indiana Public Service Co., FERC last year ordered MISO to eliminate its 345-kV threshold on interregional projects with PJM. (See FERC Signals Bulk of NIPSCO Order Work Complete.)

Salt River Project Signs on to Become 9th EIM Participant

By Robert Mullin

Phoenix-based Salt River Project (SRP) on Thursday signed an agreement with CAISO that puts the utility on track to join with the Western Energy Imbalance Market (EIM) in April 2020.

| Salt River Project

By linking up with the EIM, SRP will follow a course already charted by Arizona’s biggest utility, Arizona Public Service, which began trading in the West’s only real-time electricity market last October. (See Arizona Public Service, Puget Sound Energy Begin Trading in EIM.)

Publicly owned SRP is Arizona’s second largest electricity provider and the biggest supplier of water in the greater Phoenix area. It serves more than 1 million customers within a territory that covers more ground than the state of Delaware.

The utility estimates that it will save up to $4.5 million yearly by participating in the EIM.

“The EIM can help save money for SRP and its customers by providing real-time access to the lowest-cost resources across a significant portion of the Western grid,” John Coggins, SRP’s senior director of power delivery, said in a statement. “It will complement SRP-owned generating resources and energy purchases from the wholesale market.”

Salt River Project Arizona Public Service EIM
Theodore Roosevelt Dam

SRP controls about 9.5 GW of generating capacity, which includes the utility’s ownership of 3,461 MW of natural gas, a 688-MW share in the output from the Palo Verde nuclear plant and 745 MW of renewable generation, more than half of which is hydroelectric. The portfolio also includes 2,225 MW of coal-fired generation.

Perhaps most important for the EIM, which relies on having ample transmission capacity to prevent market separation, SRP offers key transmission assets that will improve transfer capability in the desert Southwest. Among them are 500-kV lines extending from Phoenix to points north and west, including to the Mead and Marketplace wheeling points near the California-Nevada border, the Navajo generating station in northern Arizona and the Palo Verde plant west of the city. Palo Verde, Mead and Marketplace all function as key pricing points for power wheeled into the Southern California market.

Under its agreement with CAISO, SRP will pay the ISO a $910,000 fixed implementation fee to cover preparations for EIM membership. Those include integrating SRP’s full network model into the market’s software, facilitating data exchange and performing market simulations leading up to the go-live date.

SRP will be the ninth balancing authority to join the EIM. Besides APS, current members include PacifiCorp, NV Energy and Puget Sound Energy. Portland General Electric is scheduled to begin trading in the market this October, followed next spring by Idaho Power. Sacramento Municipal Utility District and Seattle City Light are slated to join in April 2019, making them the first publicly owned participants.

CAISO estimates that the EIM has produced $142 million in gross benefits for its members since the market commenced operation in November 2014. The benefits represent either cost savings — for example, the reduced need for reserves and greenhouse gas credits — or increased profits from merchant operations. The market’s ability to reduce renewable curtailments also enables participants to collect renewable energy credits that would not otherwise be issued. (See EIM Benefit up 8% in Q4 with APS, Puget Sound Additions.)

MISO’s Next Step on Storage: ‘Common Issues’; Task Team?

By Amanda Durish Cook

CARMEL, Ind. — MISO will schedule a “common issues” meeting in response to a request from a group of stakeholders to better define energy storage, a prelude to the possible formation of a task team dedicated to the issue.

Consumers Energy, DTE Energy, Ameren, Xcel Energy and Indianapolis Power and Light, which all own storage resources, submitted a joint request that MISO create a model for storage’s participation in the market and track its growth using the RTO’s Market Roadmap project list. The companies asked that MISO revise its Tariff, dispatch methodology, capacity constructs and models used to determine interconnection rights to “recognize the physical and operational characteristics of energy storage resources.”

At an April 26 Steering Committee meeting, Chair Tia Elliott said the common issues meeting will be used to gather information before creating an energy storage task team or work group. The meeting date has not been scheduled by MISO’s stakeholder relations team.

The RTO is already under pressure to revise its rules for storage under FERC’s Feb. 1 order in response to a complaint by IPL over compensation for the 20-MW battery at its Harding Street Station. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)

Justin Stewart of MISO’s stakeholder relations unit said the stakeholders’ request was too broad to be covered by a single Market Roadmap assignment, saying it “touches too many market functions.”

Under the stakeholder redesign completed last year, Steering Committee members can assign completed issues submissions forms to other committees, reject considering the issue altogether, assign it as a common issue or send it back for more detailed information.

Aligned with NOPR

DTE’s Nick Griffin, who authored the request, said his proposal aligns with the aims of FERC’s Notice of Proposed Rulemaking on energy storage, issued in November. (See FERC Rule Would Boost Energy Storage, DER.)

“Whether or not FERC mandates this, we feel this will be useful to leverage storage in the MISO market,” Griffin said.

Steering Committee members said the topic could warrant a common issues meeting and then a possible task team. But they said creating storage market definitions was too tall an order for a typical Market Roadmap assignment.

“The topic of energy storage does touch many of the areas under [the main MISO committees]. It may be appropriate for us to consider a task force or a work group … where these issues related to energy storage can be discussed,” Elliott said.

MISO Executive Director of External Affairs Kari Bennett said the RTO was open to creating a stakeholder group to handle energy storage topics as part of a “big picture evaluation.”

MISO energy storage
MISO’s Kim Sperry (L) and Kari Bennett | © RTO Insider

“I think there’s a lot of embedded issues in here, and the Market Roadmap typically only handles one issue. … I think that a common issues meeting could be used to tease out all of those individual issues,” Alliant Energy’s Mitchell Myhre said.

MISO Executive Director of Market Design Jeff Bladen said a task team could use its six-month lifespan to come up with a “package of recommendations,” then have the RTO’s committees review their possible responsibilities in creating market definitions for storage. “Because it’s so important, it would be important for stakeholders to get a chance to think through all of those issues in a multifaceted fashion,” Bladen said.

Compliance Filing in IPL Complaint

In March, MISO requested a rehearing of FERC’s order in the IPL complaint, arguing that the storage NOPR is a “near-complete” overlap of the ordered storage revisions (EL17-8). MISO said IPL’s insistence that it participate fully in the market is hollow, as the Harding Street storage only provides primary frequency response.

However, with FERC at a near-standstill from the lack of a quorum, MISO made a compliance filing April 3 in response to the order, proposing the creation of a new resource category, Stored Energy Resource – Type II, that would not be limited to regulating services (ER17-1376). The proposal would require that storage function largely as a demand response resource, except that it would be treated as a regular generation resource for settlements and would not be eligible for revenue sufficiency guarantee payments or day-ahead margin assurance payments.

“We made a compliance filing in the docket, but it doesn’t do justice to the issue,” Bladen said, indicating that a more detailed market model for storage is inevitable.

Avangrid Q1 Net Income up 13% on NY, Conn. Rate Hikes

By Michael Kuser

Rate increases in New York and Connecticut helped Avangrid boost first quarter earnings by 13%.

The company, which benefited from increases for New York State Electric and Gas and Rochester Gas & Electric in New York, and United Illuminating in Connecticut, on Tuesday reported consolidated net income of $239 million ($0.77/share), compared with $212 million ($0.69/share) for the same period in 2016. Operating revenues were up 5.2% to $1.76 billion from $1.67 billion.

Rochester Gas & Electric Substation | Avangrid

CEO James P. Torgerson told analysts on a conference call that the company is “on track” to meet its target of 8 to 10% compound annual earnings growth through 2020. Company officials also talked about prospects for the company’s renewable generation business and gave a status report on other federal and state regulatory issues.

The company has “no expectations” of seeking a rate increase in 2017 for Central Maine Power, Torgerson said. Gov. Paul LePage has said high electric rates are hindering business, even though the state has the lowest industrial and residential energy prices in New England as of February, according to the Energy Information Administration. LePage claims, however, that Maine competes not with other states in New England, but with states like Michigan and Alabama, which have lower rates.

New York

On the slow progress in securing approval of NYSEG and RG&E’s combined proposal for advanced metering infrastructure, Torgerson noted that the New York Public Service Commission has only two out of five commission seats filled. As part of the state’s Reforming the Energy Vision initiative, the utilities are starting their AMI work by installing 20,000 smart meters in Ithaca.

avangrid renewables offshore wind farm
Avangrid’s Barton Wind Farm

Settlement talks on a request by multiple intervenors seeking to compel the utilities to institute a “collaborative process” on AMI issues have been slowed by the investigation into RG&E’s response to a freak wind storm on March 8, which left more than 30,000 households without power for days.

RG&E’s $145 million R.E. Ginna retirement transmission alternative project went in operation in the first quarter. The project upgraded transformers and other equipment at two substations, increasing the capacity for one 115-kV and three 345-kV underground lines.

Connecticut

Torgerson also said “timing is getting critical right now” on a decision by Connecticut lawmakers on whether or not to pay subsidies to Dominion Energy’s Millstone nuclear plant in Waterford. S.B. 106, which is pending in the legislature now, “would put more cost back on to the customer,” Torgerson said. “I think Dominion would say [it will] lower the cost, but I think it actually raises a little.”

“There’s been really no detailed information provided to be able to make a determination as to whether that plant truly needs to get a subsidy or not to continue to run and what kind of profitability it has,” added CFO Rich Nicholas. “I think that’s the biggest rub right now that’s going on with Millstone and Connecticut.” (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)

ROE Move Now Up to FERC

Torgerson and Nicholas both commented on the D.C. Circuit Court of Appeals’ April 18 ruling overturning FERC’s 2014 order setting the base return on equity for Central Maine and other New England transmission owners at 10.57%. The court said the commission failed to meet its burden of proof in declaring the previous 11.14% rate unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)

“We all know that the 11.14% was in the range of reasonableness that FERC had set out, so we’re waiting to see what FERC will decide to do,” Torgerson said. “Then if they get over that, then we’ll have to determine if setting the base ROE at the midpoint of the upper half of the range of reasonableness is just and reasonable in and of itself.”

Nicholas looked for a more long-term resolution: “I think that the hope would be that maybe as we get new commissioners [at FERC] … that maybe they revisit the whole process and see if they can find a process whereby you avoid this pancaking where we now have four different complaints on the same issue.”

Renewables Unit Continues Growth

Avangrid Renewables’ contribution to earnings per share increased by 41% in the first quarter from Q1 2016, rising to 26% of adjusted EPS. The company is looking to keep the growth momentum going with future projects, including by bidding on offshore wind projects in Massachusetts.

On April 25, Avangrid participated in the bidders conference for clean energy proposals in Massachusetts. Torgerson said that he hoped to leverage parent company Iberdrola’s experience — the company has about 1.3 GW of offshore wind in operation or under construction — to win a contract to supply some of the 1,600 MW of offshore wind being solicited by Massachusetts.

The notice of intent to bid is due in early May, with proposals due at the end of July. The selection will probably come by the end of January 2018, Torgerson said.

Avangrid offshore wind
North Carolina Offshore Wind Map | BOEM

“They are really encouraging proposals that would include generation able to commit to deliveries by the end of 2020,” he said. Torgerson said the Massachusetts clean energy projects “not only will benefit Massachusetts and help them reach some of their renewable targets but also … help consumers in Maine by lowering energy prices in Maine.”

In March, Avangrid Renewables won the Bureau of Ocean Energy Management’s auction for an offshore wind lease on 122,000 acres about 24 nautical miles off the coast of Kitty Hawk, N.C. It was one of the final accomplishments of Avangrid Renewables CEO Frank Burkhartsmeyer, who is resigning May 17 to become CFO of Oregon-based natural gas provider NW Natural. (See Avangrid Renewables CEO Steps Down to Take NW Natural Role.)

No 2nd Term for FERC’s Colette Honorable

By Michael Brooks

FERC Commissioner Colette Honorable announced Friday she will not seek a second term on the commission. Her current term expires June 30.

“After much prayer and consideration, I’ve decided not to pursue another term at the Federal Energy Regulatory Commission,” Honorable said in a statement. “I appreciate the strong bipartisan support I’ve enjoyed over the years and look forward to continuing this important work after leaving the commission.”

Honorable at an EBA event in 2016 | © RTO Insider

Honorable was nominated by President Barack Obama in August 2014 to fill the remainder of former Commissioner John Norris’ term. The Senate unanimously confirmed the former Arkansas Public Service Commission chairman  in December 2014. (See Senate Confirms Honorable to FERC.)

Neither Honorable nor FERC said when she would leave the commission. “We have nothing more than her statement,” a FERC spokeswoman said.

Honorable could serve until her successor is confirmed or the end of the current Congressional session, whichever comes first.

In the past, some commissioners have stayed on past their terms’ expiration dates, saying they would wait until a replacement is named.

But Commissioner Tony Clark left at the end of September last year after his term expired in June without any nomination being submitted. And the commission has been without a quorum since February, when Chairman Norman Bay resigned after President Trump named Cheryl LaFleur acting chair.

Honorable had been interviewed on E&ETV’s “OnPoint” web show April 24 and gave no hint of her impending decision. She also said the commission was “hopeful that any day, any week we will hear who the nominees will be” and that she had no insight into when they would be announced.

Stakeholders and members of Congress have grown increasingly agitated that the president has not submitted any nominations to the Senate.

Honorable’s chances of being reappointed diminished with Trump’s election. Although the commission has not traditionally been marked by partisan divisions, the president gets to appoint members of his party to three of the five seats and pick the chairmanship. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)

Since Republicans Philip Moeller and Clark left, the five-member panel had been all Democrats: Honorable, Bay (whose term ran through June 2018) and LaFleur (June 2019).

Although Bay’s departure left an opening for a second Democrat, FERC insiders had not expected Honorable to remain.

DC Circuit Puts Hold on CPP, MATS Challenges

By Michael Brooks and Rich Heidorn Jr.

The D.C. Circuit Court of Appeals granted the Trump administration’s requests to hold in abeyance lawsuits challenging EPA’s Clean Power Plan and Mercury and Air Toxics Standards, small but important victories for the president — just before his 100th day in office — as he tries to reverse the Obama administration’s regulations on fossil fuel-fired power plants.

The orders also come just before a march in D.C. protesting President Trump’s policies on climate change.

The administration filed its requests on the CPP and MATS cases — along with several others regarding numerous lawsuits concerning Obama-era environmental regulations — shortly after Trump signed an executive order at EPA headquarters last month directing agencies to review all existing regulations “that potentially burden the development or use of domestically produced energy resources.” (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

The court on Friday ordered the suit against the CPP, filed by 26 states , to be paused for 60 days, with EPA required to file a status report in 30 days.

Stay

Implementation of the CPP was stayed by the Supreme Court in February 2016, shortly after the states filed their challenge, and the D.C. Circuit heard more than seven hours of oral arguments in September. The stay was a surprise to many and came without explanation, but it’s likely the Supreme Court wanted to avoid what happened with MATS.

The court in June 2015 found that rule illegal because EPA had not considered its costs. But because the rule, first proposed in March 2011, had not been stayed during the years of litigation, companies had been making investments and closing power plants in order to comply by the April 2015 effective date.

Instead of voiding the rule, the Supreme Court remanded the case back to the D.C. Circuit, which ordered EPA to rewrite the rule with a proper cost-benefit analysis. The court’s Thursday order suspended the case until further notice. EPA is required to file a status report in 90 days.

The holds give the administration more time to figure out how to revise — or potentially rescind — the rules. It is unclear how it intends to do this. But in the case of the CPP, the order does stave off the court from potentially upholding the rule.

Chief Judge Merrick Garland did not participate in the order, as he had recused himself from cases while his nomination to the Supreme Court by President Obama was pending before the Senate.

EPA Request

EPA asked the court to delay action on the CPP challenge on March 28, the day Trump signed an executive order directing EPA Administrator Scott Pruitt to begin the lengthy process of undoing the rule.

“The Clean Power Plan is under close scrutiny by the EPA, and the prior positions taken by the agency with respect to the rule do not necessarily reflect its ultimate conclusions,” EPA said in its motion. “EPA should be afforded the opportunity to fully review the Clean Power Plan and respond to the president’s direction in a manner that is consistent with the terms of the executive order, the Clean Air Act and the agency’s inherent authority to reconsider past decisions. Deferral of further judicial proceedings is thus warranted.”

Environmental groups — including the Sierra Club, Environmental Defense Fund and Natural Resources Defense Council — filed a response April 5 contending that EPA’s request “would have the effect of improperly suspending the rule without review by any court, without any explanation and without mandatory administrative process.”

“The relief EPA seeks flouts the terms of the order by which the Supreme Court temporarily stayed enforcement of the rule. The Supreme Court did not invalidate the rule; consistent with the authority granted courts by the Administrative Procedure Act, it issued a stay pending a decision by this court and an opportunity for Supreme Court review. Now EPA wants the stay, but not the judicial review that formed the basis for it,” they wrote. “Granting EPA’s motion would effectively convert that temporary enforcement relief pending judicial review into a long-term suspension of the rule likely continuing for years, without any court having issued any decision on the rule’s merits.”

CPP’s Vulnerabilities

Based on the judges’ questions and comments during oral arguments in September, it appeared four of the five challenges — a Constitutional issue; a bill drafting error; EPA’s alleged failure to provide sufficient notice of changes between the original and final plan; and a claim that it relied on dubious assumptions on the growth of renewables — had little chance of prevailing. But the judges seemed to be seriously considering the argument that EPA overreached its authority by creating CO2 emission limits that coal-fired generators can’t meet, forcing a “generation switch” to natural gas and renewables. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

Some observers say the administration may not succeed in killing the CPP, and that if it does, it will have little impact because the power industry’s decarbonization will continue without the rule.

At a panel discussion at the Energy Bar Association annual conference in April, David Doniger, director of the NRDC’s Climate and Clean Air program, said that most of the players in the electric industry have adjusted to the CPP’s goals and are unlikely to reduce decarbonization efforts because of Trump’s action.

“Whatever its noble objectives, it’s relatively irrelevant whether or not [the CPP is] enforced,” added panelist Ian C. Connor, global co-head of J.P. Morgan’s Power & Utility Group. “I have little doubt … that the industry will materially decarbonize and outstrip what the CPP is trying to do.” (See EBA Panel: CPP’s Demise not Certain — and it Doesn’t Matter.)

CPP Supporters: EPA Must Act on Carbon

New York Attorney General Eric T. Schneiderman tweeted in response to the court’s action Friday: “Despite today’s temporary pause in litigation, the facts remain the same: @EPA is still legally obligated to limit carbon pollution.”

“We are in a race against time to address the climate crisis,” EDF General Counsel Vickie Patton said. “The Supreme Court is clear that EPA has a duty to protect Americans from dangerous climate pollution under our nation’s clean air laws, and Environmental Defense Fund will take swift action to ensure that EPA carries out its responsibilities under the law. Climate progress and clean energy cannot be stopped by the litigation tactics of polluters.”

CPP Opponents: Good Riddance

William Yeatman, senior fellow at the Competitive Enterprise Institute, which opposes the CPP, said the action means one of two potential outcomes: “1) Either the rule is nixed because the EPA determines that it is precluded from issuing a climate rule for existing power plants because they are already regulated under the Clean Air Act’s hazardous air pollution program, or 2) the EPA significantly revises the rule to bring it ‘inside the fence line’ of electricity generating units, such that the agency no longer claims the authority to dictate to the states what their energy choices must be.

“Either way, the outcome will pardon the American economy from the ill-effects of the Clean Power Plan, which would have empowered the EPA to remake the electric industry,” Yeatman said.

Jeff Holmstead, a partner with the Bracewell law firm who headed the EPA’s Office of Air and Radiation from 2001 to 2005, called the news “important but not terribly surprising.”

“I don’t think the D.C. Circuit has ever gone ahead and decided on the legality of a rule when a new administration says it plans to rescind or revise it. The only question now is whether the case will be held in abeyance or remanded back to EPA. If the court had upheld the rule, it wouldn’t have prevented the new administration from revoking it, but it might have made this effort harder.  At the very least, today’s ruling means that it will not take as long for the administration to undo the Clean Power Plan.”

PJM Asked to Explain Day-Ahead Commitment Assumptions

By Rory D. Sweeney

VALLEY FORGE, Pa. — Is PJM’s day-ahead auction more art or science?

That question was raised by several stakeholders at Tuesday’s special session of the Market Implementation Committee on price transparency, after the disclosure that PJM operators — rather than algorithms — make the final decision on which units clear the day-ahead auction.

PJM day-ahead auction
Scarpignato (right) and Adam Keech, PJM | © RTO Insider

PJM’s Mike Ward, who manages the day-ahead market operations, downplayed human involvement in the process, saying “most of the tweaking is on the edges.” But that didn’t satisfy Calpine’s David “Scarp” Scarpignato or Public Service Enterprise Group’s Gary Greiner, who questioned the subjectivity of the operators.

“I’m sure you’re doing things that ‘make sense,’ but when you get people making the decisions, I could adjust things differently around the edges than what you might,” Scarp said.

“We’ll run two, three, four more cases to keep adjusting it. We don’t just take it [once], that’s it and we approve it,” Ward said. “It’s hard to describe how we do it. … I judge [the benefit or harm] by the number of people calling and complaining.”

To avoid cutting into units’ profit, the operators compare LMPs to costs, Ward said, and consider many other factors, such as minimum or maximum runtimes.

Greiner | © RTO Insider

“Are there rules for that or is it more art than science?” Greiner asked.

“We don’t want people to lose money,” Ward responded. He noted that the percentage of load bidding into the day-ahead auction has risen from 75% when he started to “close to 100%” today.

PJM’s Chris Callaghan explained the RTO’s commitment review process, which ensures system reliability by allowing reliability engineers to provide input for commitment decisions and review the final plan. Any additional units identified as necessary from that final reliability check are committed in the Reliability Assessment and Commitment run. Engineers look first at non-cost options, followed by gas-fired combustion turbines, then by steam-generation units to satisfy reliability at the least cost, he said.

Continuing the discussion on price formation, PJM’s Scott Benner explained the RTO’s current thinking on complying with FERC Order 831, issued in November. The order caps at $2,000/MWh all incremental offers allowed to set LMPs and requires validation of offers exceeding $1,000/MWh to “ensure that a resource’s cost-based incremental energy offer reasonably reflects that resource’s actual or expected costs.”

PJM plans to implement a process to address those requirements in November but must submit its compliance filing by May 8, Benner said. A third-party vendor will provide “near real-time” commodity prices to enable PJM to calculate theoretical cost-based offers and compare them with actual offers received.

“We should be able to understand their costs or at least their general spot market activity,” Benner said.

“We’d be checking to make sure if your offer was in accordance with your fuel-cost policy,” PJM’s Jeff Schmitt said.

Throughout the presentations, stakeholders and PJM staff recommended objectives for the group’s final product, many of which focused on providing deeper insight into how the RTO makes price-formation decisions.

DC Circuit Upholds FERC Ruling in PURPA Dispute

By Wayne Barber

The D.C. Circuit Court of Appeals on Tuesday declined to overturn a FERC decision requiring Portland General Electric to purchase the full output of an Oregon wind power project under the Public Utilities Regulatory Policies Act.

The three-judge panel also rejected a claim by PáTu Wind Farm that PGE was required to accept the wind producer’s power through dynamic scheduling.

The court dismissed the utility’s petition for lack of jurisdiction and denied PáTu’s argument on its merits.

PURPA ferc power purchase agreement
Pa’Tu Wind Farm Construction | PaTu / White Construction Company

The case centered on a 2015 FERC ruling in which the commission determined that PGE must purchase all of the six-turbine, 9-MW wind farm’s power under a power purchase agreement between the two parties set out under PURPA.

Because PáTu, located in rural Oregon, is not directly linked to PGE’s grid, it sells power to the utility under the state Public Utility Commission’s approved PPA for “off-system” generators.

In order to transmit power to PGE’s grid, PáTu obtains transmission services from the Wasco Electric Cooperative and the Bonneville Power Administration. Wasco wheels PáTu’s power to BPA, which in turn transmits the energy to PGE’s Troutdale substation, the PPA’s designated point of delivery.

“Before the ink had dried on the power purchase agreement, the parties locked in a dispute over the nature of Portland’s purchase obligation,” the court said.

Believing it had purchased a firm product, PGE required PáTu to set day-ahead schedules under which the wind farm committed to delivering whole blocks of energy for each hour of the day. If PáTu overscheduled its deliveries, PGE paid the favorable avoided cost rates for the power delivered and required the wind farm to make up the difference by buying firm power from BPA, which was compensated at the lower market rate because it was not generated by PáTu.

On the other hand, if PáTu underscheduled, PGE only accepted and paid for only scheduled deliveries, forcing the wind farm to dispose of the excess at less-favorable rates, the D.C. Circuit noted.

PáTu contended that PGE could only buy all of its variable output through “dynamic transfer” — or scheduling in real time. PGE countered that, under its PURPA agreement, the wind farm was a customer of the utility’s merchant arm, not a transmission customer, and was therefore ineligible for dynamic scheduling.

In December 2011, PáTu filed a complaint with the PUC. The regulator saw nothing in the PPA requiring PGE to utilize dynamic scheduling, concluding that the utility must purchase all power PáTu generates and delivers.

But drawing a distinction between power “produced” and power “delivered,” the PUC appeared to leave PGE free to refuse to purchase any power produced in excess of what PáTu scheduled.

PáTu appealed to the Oregon Court of Appeals, which affirmed the PUC’s decision without opinion. The wind farm owner then filed a complaint with FERC, arguing that PGE must buy all of its output, scheduled or not, and that dynamic scheduling was the only way to accomplish that result.

FERC concluded that the PPA and PURPA regulations required PGE “to accept PáTu’s entire net output … delivered to Portland,” the D.C. Circuit noted.

FERC rejected PáTu’s specific request for dynamic scheduling, explaining that it has never required a utility to use any particular method to carry out its purchase obligation. It nonetheless clarified that, contrary to what the PUC had suggested, PGE could not escape its PURPA obligation by imposing overly rigid scheduling requirements or by refusing to purchase all power that PáTu produces.