CARMEL, Ind. — Six panelists shared tales of shattering the old boys’ mold and being a minority in a sea of white employees during a discussion convened by MISO last week on increasing diversity in the energy industry. The discussion was part of the RTO’s Informational Forum.
Paula Glover, CEO of the American Association of Blacks in Energy, said she has walked through workplaces where she has spotted just three African Americans among 500 employees.
“The people I engage with on a daily basis do not look like me,” Glover said, noting that while African Americans make up 12% of the workforce, their employment rate in the energy industry is 7%.
“You tell me of diversity all you want, but if I can’t pinpoint it, it’s not there,” she said. “The numbers do not pan out well for this industry.”
Counted Twice
Carolene Mays-Medley, executive director of Indiana’s White River State Park and a former Indiana Utility Regulatory commissioner and state representative, said that early in her career, she remembers being counted twice as a minority because she was both black and female.
“When I got started around 1982, it was an old boys’ club,” said Marlene Parsley, Big Rivers Electric’s director of resources and forecasting. She said starting out young and female, she learned that not “rocking the boat” earned her respect among her colleagues.
“It is important to be the person in the room sometimes, because it does give that diversity of thought,” said Korlon Kilpatrick, director of regulatory affairs for Citizens Energy Group.
MISO Executive Director of System Operations Renuka Chatterjee joined the RTO as a young engineer 17 years ago.
“To understand my personal journey, you have to understand my Ellis Island story,” said Chatterjee, who was born and raised in India and came to the U.S. in 1997. Chatterjee spoke of entering engineering school while her female cousins did not attend college. She said even while earning a doctorate in the U.S., she learned it was common to be one of a handful of female students in science and technology courses.
“I recall one interview [in India], I was viewed as not a good investment because I would get married and have babies,” she said.
Starting a Career at the Bottom
Donald Broadhurst, general manager of Midwest transmission construction and maintenance at Duke Energy, said he began his energy career as a low-level employee. “I started out at the bottom. I was a substation electrician, but I wasn’t satisfied with that,” Broadhurst said. “The most important part is you. You have to do what you want to and not let others set limits.”
Broadhurst said corporate support can improve diversity.
“It does start at the top, and you have to make sure that your organization understands that it is a priority. I think it should. It has to be weaved in the talent lifecycle from recruitment to training to succession,” he said.
Mays-Medley said she has always been frustrated when she hears a company recruiter complaining about a lack of qualified female and minority candidates. “I ask, ‘Where are you looking?’ Maybe you need to diversify your candidate pool. … You can’t say that you don’t know where to go. There are lots of places to look,” she said.
Parsley said Big Rivers will reach out to churches and community centers to cast a wider recruiting net. “A lot of times, hearing ‘not a good fit’ means, ‘They don’t think like me,’” Parsley said.
Creating Inclusion
Glover said work culture is key to creating an inclusive environment. “For companies, it is ‘Who are we?’ when people walk in the door,” she said. Glover expressed optimism for the future, saying that millennials are entering the workforce accustomed to working in diverse environments.
Broadhurst said some people think of diversity as a threat to the majority white male industry and view it as “taking someone’s seat.” He said he always viewed jobs as being earned. “When you’re an African-American leader and you bring on another African American, it’s viewed differently than if your white counterpart [hires a white employee]. But if it’s the right thing to do, you must do it. You don’t just reach back for people that look like you; you look for talent,” he said.
Glover said existing workforces feeling threatened by diversity programs is “a real thing.” She said successful diversity programs include a management discussion addressing the fear and resentment the programs may evoke.
Mays-Medley said minorities and women have to stop competing “so hard” against one another or “tearing one another down” in the workplace. “I’ve come to realize that we do it because the seats are so limited. And the vision from the top is we can only have one position. That vision from the top has to be broadened.”
MISO CEO John Bear said the RTO engages in “intentional” diversity and has a board that’s more diverse than the RTO average. MISO South Vice President Todd Hillman said the RTO is creating a diversity and inclusion resource group for its employees.
According to MISO, the RTO’s workforce is 70% male/30% female and 74% white/26% non-white. From 2013 to 2016, MISO’s new hires have been 65% male/35% female and 67% white/33% non-white. The U.S. electric power workforce as a whole is 78% male/22% female and 79% white/21% non-white, according to the RTO.
MISO will not ask FERC to rehear its previously rejected Competitive Retail Solution, which would have applied a sloped demand curve and three-year forward capacity auction to the RTO’s retail-choice areas.
MISO spokesperson Jay Hermacinski last week confirmed the decision.
The RTO also notified stakeholders by letter, explaining that its stance was influenced by improved planning efforts from Michigan and Illinois and FERC’s current limbo. (See Backlog, Delays Feared as FERC Loses Quorum.)
“Following our filing of the CRS proposal, near-term resource adequacy circumstances have improved with passage of legislation in Michigan and Illinois, as well as other factors such as increased ability to import capacity into those states,” the letter read.
Late last year, Illinois and Michigan — which maintains a 10% retail choice cap — passed legislation to subsidize nuclear plants and provide a blanket energy policy, respectively. (See Michigan Energy Bill Preserves RPS, 10% Retail Choice Cap.)
MISO reiterated its commitment to work with Illinois regulators, lawmakers and utilities to address potential future capacity shortages. The issue will also be taken up with stakeholders at the March 8 Resource Adequacy Subcommittee meeting.
The RTO said its “immediate next steps” will focus on coordinating its resource adequacy process with Illinois in particular.
“While Illinois has addressed some short-term concerns around potentially retiring capacity, critical additional tools are still needed to ensure improved long-term price signals for committed capacity to reliably serve consumers in the state,” MISO said. “Given this, we have concluded the most productive near-term effort is working closely with state officials and Illinois stakeholders who continue the work of developing a state-based approach to fully address long-term resource adequacy requirements.”
FERC’s current uncertainty also figured into the RTO’s reasoning. It is unclear when new commissioners will be appointed and a quorum restored to address a rehearing, MISO said.
The RTO will continue to work on “solutions focused on competitive retail areas that do not implicate the traditionally regulated areas of the MISO region” and maintain separation between rules for vertically integrated utilities and competitive retail suppliers.
“The FERC order does not change that commitment,” MISO said.
At a Feb. 21 Informational Forum, MISO CEO John Bear attempted to calm what he called “some trepidation among stakeholders, saying the RTO will not apply a forward market or sloped demand curve systemwide.
“We’re going to stand by that,” Bear said.
However, given the “brevity” of FERC’s order (ER17-284), MISO is interested in getting more detail from the commission, Bear said. It is still unclear whether or not MISO will receive detailed commission guidance. (See FERC Rejects MISO’s 3-Year Forward Auction Proposal.)
PORTLAND, Ore. — Stakeholders last week expressed concerns over how the Western Interconnection’s four transmission planning organizations can align their separate regional processes to identify projects that could provide interregional benefits.
“I think we need to have a bit of a rethink about the relationship between planning processes — either at the planning regions or at [the Western Electricity Coordinating Council] — [and] the interregional coordination process” among the four Western planning groups, Fred Huette, senior policy associate with the Northwest Energy Coalition (NWEC), said during the Western Planning Regions’ annual interregional coordination meeting.
The Feb. 23 meeting brought together stakeholders and representatives of CAISO, ColumbiaGrid, Northern Tier Transmission Group (NTTG) and WestConnect to discuss interregional coordination under FERC Order 1000. The order requires transmission providers to participate in a planning process that identifies the most cost-effective solutions to transmission needs and allocate costs based on estimated benefits.
No Interregional Projects Identified
In the 2016/17 planning cycle, the four groups have not identified any interregional projects driven by regional needs. Like most parts of the country, the West is experiencing stagnant or declining loads. None of the regions declared a reliability, economic or public policy requirement for any transmission projects, let alone one that crosses regional seams.
NTTG and WestConnect received submissions for three interregional projects — SWIP-North (Western Energy Connection), Cross-Tie (TransCanyon) and TransWest Express (TransWest Express) — intended to move renewable energy from the inland West toward California. The projects are based on the prospect that California will need more renewables, but no requirement has been identified yet.
All three are seeking cost allocation through WestConnect. NTTG said Western Energy Connection did not submit details on SWIP-North in time to be considered for cost allocation during the current cycle, while the other two projects have not sought allocation.
“The conclusion that came out of [the study process] is that our draft regional plan will support the addition of any one of those interregional projects, but those interregional projects are not necessary to satisfy NTTG’s needs,” said Craig Quist, PacifiCorp director of area transmission planning and vice chair of the NTTG Planning Committee.
Larry Furumasu, senior planning engineer with ColumbiaGrid, said his group’s study showed that 15 previous “areas of concern” within the Pacific Northwest were ameliorated by load reductions last year.
Neil Millar, CAISO executive director of infrastructure development, said the ISO’s transmission plan this year is a “bit unique in being so light.” He said loads are declining because of increased behind-the-meter generation — largely rooftop solar.
“We think we’ve at this point exhausted economically driven transmission opportunities,” Millar said. “So we’re really at a bit of a calm before the storm until we move forward with transmission planning to address broader renewable portfolio standards, with [California’s] 50% by 2030 goal in particular.”
‘Big Picture’ on Economic Upgrades
On the theme of economically driven projects, Ellen Wolfe of Resero Consulting asked WestConnect a “big picture” question: How is a project determined to be “economic?”
Wolfe posed the actual case of a CAISO transmission path in Valley Electric Association’s Nevada service area that rings up about $60 million worth of congestion annually in the export direction. The ISO has little motivation to relieve the constraint because the trapped generation means lower costs for California consumers, although in-state renewables are more likely to be curtailed.
“So Nevadans would actually win if this constraint was relieved, because they would see this renewable energy flow to Nevada,” Wolfe said, asking how such a project would get identified and paid for if the ISO was not motivated to do so. “I didn’t see in [WestConnect’s] study description how that kind of project would pop up. It’s really a project in the CAISO footprint that would benefit WestConnect.”
Kegan Moyer, a consultant representing WestConnect, said he wasn’t familiar with the constraint in question, but that “high levels of congestion on a regionally significant element” would prompt the group to explore potential upgrades. He noted, however, that there is “very, very little” congestion within WestConnect, a U-shaped region that includes all or most of Nevada, Arizona, New Mexico, Colorado and Wyoming.
Wolfe pressed her point.
“So that’s the question: If the constraint’s not in WestConnect, but it benefits WestConnect [to relieve it], how does anyone ever decide to relieve it?” she asked.
Moyer replied that WestConnect would not have the “purview” to plan within the Valley Electric system.
“It seems like a great project for interregional coordination, but I don’t really see how it gets actually coordinated,” Wolfe said.
Dave Smith, director of engineering and operations at TransWest Express, wondered what is preventing the current interregional planning process from performing more like a regionalized process that would come about with the expansion of CAISO into PacifiCorp’s territories and other parts of the West.
CAISO’s Millar pointed to the inherent challenges of having multiple organizations work together on a project-by-project basis as opposed to a more “coordinated, programmatic” approach under a single organization.
“I don’t believe the ISO message is that the interregional process flat out won’t work, but we do [have] a higher … expectation for success on an opportunity in a broader footprint as opposed as to having to move through all the different reviews [and] approvals,” Millar said.
“I think one of the biggest challenges with regards to interregional transmission projects is that they’re all tied to the regional process,” Moyer said. “And for an official [interregional transmission project] evaluation to really have full meaning behind it, there has to be a regional need identifying each of the applicable regions.”
Solution?
NWEC’s Huette offered a possible solution: that the four organizations consider more closely coordinating their regional planning processes, rather than just collaborating on the interregional process. The theory: Interregional projects could be the most cost-effective way to collectively serve regional needs, which are currently identified through discrete, if not isolated, regional processes.
“If we get too process-bound here, I think we may lose some opportunities or delay some opportunities that might be worth looking at,” Huette said.
Smith said it would be helpful to have some kind of scorecard showing where each group is in its evaluation of an interregional project. “You all say it’s in different places, but where is it?” Smith said.
Allocating Costs, Calculating Benefits
Smith also contended that the planning groups should start thinking about cost allocation, perhaps drawing up a sample project to demonstrate how costs would be shared according to benefits.
“I would encourage that this group move forward with those discussions. …Waiting for the next annual meeting is a long time away for that discussion,” he said.
“All four regions … we have a common tariff,” ColumbiaGrid President Patrick Damiano responded. “There is a common tariff language framework that’s been approved through FERC that talks about how cost allocations take place for interregional transmission projects.”
“Everybody won’t be adopting California’s [cost allocation], if that’s what you’re asking,” PacifiCorp’s Quist told TransWest Express’ Smith.
Gary DeShazo, CAISO director of regional coordination, said he didn’t think the issue was so much cost allocation but rather how to calculate the benefits of a project.
“You can’t do cost allocation unless everybody can agree to the benefits,” DeShazo said. “So if you’ve got four different ways to calculate the benefits across the four different planning regions, then there will be questions asked. Am I paying more from this project than I should be?”
Julia Prochnik, director of western regional grid planning with the Natural Resources Defense Council, said she saw no mention of non-transmission alternatives in the groups’ presentations. “I know that right now that there wasn’t any identification of need in regional plans, but it would be something nice for the future to see how some of these other components could address different scenarios,” she said.
Damiano explained that ColumbiaGrid has a complex mix of FERC-jurisdictional, federal and municipal members — with only its FERC-jurisdictional members subject to Order 1000.
“We didn’t identify any Order 1000 need, so there was no reason to look at non-wires alternatives under Order 1000, at least for ColumbiaGrid,” Damiano said.
CAISO’s Millar joked that he was “crushed” that Prochnik didn’t see his reference to non-transmission alternatives buried in his slides.
“But we do look for those solutions and we do have a separate section in the transmission plan now where we identify all the places [where] we are already relying on the emergence of preferred resources,” he said, referring to non-emitting generation.
As the meeting wrapped up, Huette raised the need for stakeholders to be kept regularly informed about the interregional planning process, even if not required to be part of every step of the process.
“I’m not asking for a lot here,” he said. “I’m not asking for every single detail, but I think it would be helpful for those of us not involved in those discussions to hear a bit more about what is happening on the interregional level among the four planning regions during the year.”
OGE Energy CEO Sean Trauschke isn’t the kind of guy to let a 2-cent shortfall ruin his good nature.
OGE Energy CEO Sean Trauschke | OGE
“Hi, how are you?” he said, enthusiastically greeting one financial analyst after another during Thursday’s fourth-quarter earnings call, often engaging them in friendly chit-chat. Employees say that’s Trauschke’s ebullient style, calling him a “genuine guy.”
OGE reported net income of $57.9 million ($0.29/share) in the fourth quarter of 2016, compared to $29.4 million ($0.15/share) the year prior. Although that missed the Zacks consensus estimate of 31 cents/share, investors pushed the company’s stock price up $1.15 to $36.10/share by Friday’s close.
For the year, the company reported net income of $338 million ($1.69/share), compared to $271 million ($1.36/share) in 2015.
“It was a good year, both operationally and financially,” Trauschke said. “We do have a lot of good things happening at our company and in our communities.”
Trauschke said OGE’s utility, Oklahoma Gas and Electric, added 9,000 customers during the year, just above its historical growth rate of 1%, while adding 100 MW of load. He said a rebound in oil and gas prices is increasing the state’s economic activity, pointing out that Oklahoma City’s unemployment rate stands at 4%.
The CEO attributed the increase in yearly earnings to a $114 million impairment taken in 2015 against Enable Midstream Partners, a gas gathering and processing joint venture with Texas’ CenterPoint Energy. OGE’s 26.3% ownership in Enable resulted in a $141 million cash contribution, up slightly from $139 million the year before.
“This is free, unencumbered cash flow for OGE to use for our capex programs and support dividend growth,” CFO Steve Merrill said.
OGE, which has the right of first offer and the right of first refusal on CenterPoint’s stake, made another bid for it Feb. 15 with an unnamed partner. CenterPoint rejected an earlier OGE offer in September.
“Enable [has] great assets and prime locations,” Trauschke said. “We are excited about what the future holds.”
OG&E asked the Oklahoma Corporation Commission for a $69 million rate increase last summer. An administrative law judge in December recommended a $41 million increase, and a hearing was held before the OCC on Feb. 2.
“We are confident in our case and optimistic regarding the ultimate outcome,” Trauschke said.
OGE issued guidance of $1.93 to $2.09/share for consolidated earnings in 2017, assuming normal weather.
Despite one of the warmest-ever first quarters in New England, Eversource Energy reported 2016 earnings of $942.3 million ($2.96/share), up 7% over 2015 earnings of $878.5 million ($2.76/share). Revenues fell 4% to $7.64 billion.
The 2015 earnings included 5 cents/share in integration costs. The company, which had previously operated under its six electric and gas distribution companies in Massachusetts, Connecticut and New Hampshire, rebranded under the Eversource name in February 2015. (See Northeast Utilities Rebranding as Eversource Energy.)
In the fourth quarter, the company reported earnings of $229.2 million ($0.72/share), up from $181.8 million ($0.57/share) in 2015 but below the Zacks consensus estimate of 75 cents. Fourth-quarter revenues of $1.78 billion also fell short of analysts’ expectations of $1.97 billion.
The company largely offset the negative impact of the warm weather in the first quarter by managing operating costs, Eversource CEO Jim Judge said.
Eversource projected 2017 earnings per share of between $3.05 and $3.20 and long-term EPS growth through 2020 of between 5 and 7%.
“2016 was a year of continued strong earnings and dividend growth and the emergence of new opportunities for us to be the catalyst for clean energy development in New England,” Judge said. “We envision 2017 to be a year during which many opportunities to enhance service and clean energy options for our customers advance, from bringing clean hydroelectric power into the region, to enabling solar, energy storage, natural gas expansion and offshore wind development.”
In December, the company announced it had become 50-50 partners with Denmark-based DONG Energy in Bay State Wind, which plans to develop an offshore wind site south of Martha’s Vineyard. The 300-square-mile site has the potential to develop at least 2,000 MW. Bay State Wind expects to bid the project into the initial Massachusetts solicitation for offshore wind this summer.
The company is also an investor in Spectra Energy’s proposed Access Northeast natural gas pipeline, which has stalled following legal setbacks in Massachusetts and New Hampshire. Connecticut, Rhode Island and Maine passed legislation allowing their electric distribution companies to sign long-term contracts for natural gas pipeline capacity, but in August, the Supreme Judicial Court in Massachusetts ruled that the Department of Public Utilities does not have the authority to review and approve such contracts. In October, the New Hampshire Public Utilities Commission said it could not approve such contracts under current law.
Northern Pass Route Map | Eversource
“One option involves pursuing a change in the laws in Massachusetts and New Hampshire so that they align with statutes in Connecticut, Rhode Island and Maine,” said Lee Olivier, executive vice president for enterprise strategy and business development. “We also appealed the New Hampshire PUC order to the state Supreme Court, which agreed last week to consider the case. Another avenue is to secure contracts with natural gas distribution companies in Massachusetts and other New England states.”
Eversource is also an investor in the Northern Pass transmission project to bring Canadian hydropower into New England. Last month, the New Hampshire Supreme Court upheld a lower court ruling that the project had the right to bury a power line under a state highway. Hearings on the project are expected before the New Hampshire Site Evaluation Committee between April and July. The company hopes to have a permit from the Department of Energy late this year, with construction beginning early in 2018 and operations commencing in late 2019.
AUSTIN, Texas — The Public Utility Commission of Texas concluded four days of hearings on NextEra Energy’s proposed $18.7 billion acquisition of Oncor on Friday with both regulators and the Florida company warning of potential “deal-killers.”
The hearing concluded after NextEra’s legal staff submitted into the record a revised list of regulatory commitments, which now number 72. The applicants, intervenors and commissioners briefly discussed minor revisions to the document before adjourning the hearing.
PUC staff and intervenors have sought to revise some of the company’s earlier commitments, with staff expressing concerns over Oncor’s existing debt, credit ratings, board makeup, budgets, dividend policies and ring-fencing measures.
CEO’s Last-Minute Pitch
In a last-minute appearance before the PUC on Thursday, NextEra CEO Jim Robo said several of staff’s revisions to the commitments would qualify as “burdensome conditions” or “deal-killers.”
He said a number of the changes would affect how credit rating agencies viewed the deal, a point Mark Hickson, the company’s executive vice president of corporate development, strategy and integration, made frequently to the commission earlier in the week. (See NextEra CEO Crashes PUC Hearings on Oncor Acquisition.)
Robo told the commissioners he wanted to address “head-on” issues raised during the first two days of hearings on the acquisition (Docket 46238), which he said he had watched online.
Texas vs. Florida
Having heard concerns from the commissioners over Oncor’s potential out-of-state ownership, Robo played up his Texas ties. Robo noted his wife grew up in Dallas, their marriage took place in Dallas and his many in-laws in the state include the mayor of Waco (Kyle Deaver). He also noted that NextEra has invested $8 billion in Texas through various subsidiaries.
“There’s been a lot of talk and discussion about how Oncor is a gem, and I couldn’t agree more,” Robo said. “I’ve been very clear … I love the Oncor management team. I’ve asked every one of them to stay. I do know this: As good as Oncor is, as terrific a company as NextEra is, we will be a better utility together. That’s my vision.”
Robo said Oncor and NextEra’s utility, Florida Power & Light, will be able to share best practices, benefiting both of them. Oncor CEO Bob Shapard’s “team will teach us things; we’ll teach Bob’s team things. We’ll be a better company going forward,” he said.
PUC commissioners began the hearing Tuesday by peppering Shapard with questions about whether Oncor would approve of being managed by a Florida company with a reputation as an aggressive competitor.
“A broad concern in the pink building,” Commissioner Ken Anderson said, referring to the nearby state Capitol, “as well as with the stakeholders, is that [NextEra is] not known as being wallflowers. Even early on in this process, they have gently reminded us that [our approach] wasn’t the right approach.”
Shapard worked hard to allay the PUC’s concerns.
NextEra is “trying to show they’re listening,” he said. “They’re trying to convince you they’re listening to other parties.” As the owner of FP&L, NextEra is the largest investor, employer and taxpayer in Florida, a position it has vigorously protected, Shapard acknowledged.
“When they first came in [to Texas], they thought this market was like Florida, but it’s not,” Shapard said. “I think Jim will trust us to handle business in Texas.”
Ring Fencing
Robo also addressed the commissioners’ concerns over NextEra’s unregulated businesses, citing his “very clear business strategy of de-risking” them. He also said NextEra would not try to pass on affiliate costs from its subsidiaries in Oncor’s upcoming rate case. “Our intention is not to layer costs on Texas customers,” he said.
NextEra and Oncor say the ring fence proposed in the acquisition is sufficient. PUC staff and intervenors Texas Industrial Energy Consumers (TIEC), the Texas Office of Public Utility Counsel and the Steering Committee of Cities Served by Oncor are pushing for stronger protection.
Staff said the acquisition would be “funded with high levels of debt that would significantly increase NextEra Energy’s debt as a percentage of total capitalization, while removing the protective ring fencing currently protecting Oncor.”
The changes “would expose Oncor to the substantial risks of NextEra Energy’s nonregulated businesses, which carry much more risk than that of a [transmission and distribution] utility,” staff said.
A strong ring fence has been credited with insulating Oncor from its unregulated generation and retail energy affiliates when a Chapter 11 bankruptcy took down Energy Future Holdings, the company formed by private equity investors following a leveraged buyout of TXU Corp. in 2007.
PUC staffer Stephen Mack said there was no disputing that the ring fence around Oncor has served its purpose and the risks to the company are lower than if it had been exposed to the “EFH family.” Oncor has “maintained a strong credit rating, and it cares deeply about maintaining that credit rating,” Mack said.
Attorney Geoffrey Gay, representing cities served by Oncor, noted that when Hunt Consolidated withdrew its offer for Oncor last year, the utility was still able to reach out to 18 other entities to gauge their interest. “That tells me the industry in general recognizes Oncor is a gem,” Gay said. “It’s worth a lot, and its ownership will be beneficial to whoever acquires it.”
The makeup of Oncor’s board of directors is one of the central points of contention. NextEra has committed to an Oncor board composed of 11 people, with three designated as “disinterested directors” and four independent from NextEra and its subsidiaries.
The company has promised to maintain Oncor’s independence by placing Texas residents and independent directors on the utility’s board. Shapard would chair, with General Counsel E. Allen Nye Jr. succeeding him as CEO. Nye is the son of former TXU CEO Erle Nye, who retired from the company before the 2007 buyout. (See NextEra Energy Talks Up its Oncor Acquisition.)
Robo told the PUC that changes to the board composition, or any of about a dozen other commitments, would be deal-killers.
“I appreciate you coming in and being so frank,” Commissioner Brandy Marty Marquez said.
“I feel very strongly that when we make commitments, we’ll do what we say,” Robo responded.
NextEra says it needs to maintain control over Oncor’s board to ensure its ability to appoint or remove the utility’s directors. The company said that is a fair trade-off for lending its A- credit rating and $59.2 billion market capitalization to help Oncor eliminate the more than $11 billion in debt left by EFH.
The Texas entities don’t see it the same way. TIEC submitted testimony from Charles Griffey, a former executive with Houston-based Reliant Energy, who offered a number of recommendations, including a requirement that all the board members be Texas residents.
“The TIEC members represent billions of dollars captive to Oncor that could be harmed if this doesn’t turn out well,” said the TIEC’s legal counsel, Phillip Oldham. “Our group requires us to kick the tires, look under the hood and see how much stress this situation can endure.
“We ask you to take a hard look at that issue in particular,” he said. “Our desire is to ensure Oncor is protected and continues to do the job it’s been doing, even if there are problems with the parent.”
Debt Overhang
Oldham also said NextEra is not really “extinguishing” Oncor’s debt, a position with which Anderson agreed.
“That’s not really correct,” Anderson told an Oncor panel of witnesses. “It’s being refinanced. Whatever the amount and however you describe it, what they’re really doing is spreading the peanut butter over a bigger piece of bread.”
Hickson said that NextEra has $12.2 billion in funding for the transaction — $9.8 billion for an 80% interest in Oncor and $2.4 billion for a 20% interest in various holding companies.
He agreed that the full debt would not transfer to NextEra, saying the company would assume only $6.5 billion, in line with its 60/40 debt-to-equity ratio.
“We have said we are going to finance this transaction in a way that allows us to maintain our strong credit rating,” Hickson said. “We are laser focused, as we always have been as a company, in maintaining our credit metrics, which means maintaining our target metrics.”
Hickson pointed Anderson to commitment No. 71, which requires NextEra and its subsidiaries to “provide advance notice of their corporate separateness to lenders on all new debt.”
Anderson expressed concern during the week about the ability of NextEra’s affiliates to collect expenses from Oncor.
“I haven’t decided what I think about it completely yet,” Anderson said. “Where we’ve talked about federal tariffs, it’s not going to be sufficient for me. I’ll come up with the language, but this falls pretty close to being a deal-killer for me.”
“We know what your deal-killers are; we just haven’t determined what ours are,” Chairman Donna Nelson said to Hickson.
Not on the Record
Robo did not testify on the record Thursday and was not made available for comment afterward. He answered the commissioners’ questions in what was an “emergency” open meeting of the PUC — framed as an opportunity to visit with the commissioners and get to know them better.
“We envision [Robo’s] discussion as a statement of opportunity and to discuss the company’s position,” said NextEra’s lead legal counsel, Anne Coffin. “It’s no different than calling people up before regular open meetings. It’s not evidence; it’s simply dialogue.”
Attorneys for the intervenors declined an opportunity to put Robo under oath, agreeing to expedite the hearings by having their witnesses respond to Robo’s comments following the open meeting.
April 29 Deadline
The PUC is scheduled to next take up the case at its March 30 open meeting. It has an April 29 deadline to issue an order.
“I have found this entire process, the intervenors, the staff … to be extremely informative to us,” Hickson said. “We have learned so much since July 29 [when the company’s deal with EFH was announced]. We have a lot of very thoughtful participants in this room. It has shown us time and time again we haven’t been able to think of everything on our own. We have been continuing to welcome that input. It’s been very helpful in getting us to where we are today.”
The PUC’s approval would end EFH’s nearly three years in bankruptcy. What’s left of TXU has already spun off its Texas competitive businesses — power generator Luminant and retailer TXU Energy — as standalone companies.
On Feb. 17, a U.S. bankruptcy judge in Delaware accepted EFH’s plan after the company said it had resolved a final dispute, with noteholders agreeing to modify what they were owed. The settlements were with two creditor groups, who were offered 95% or 87.5% of their make-whole claim premiums, in addition to full principal and interest. The groups had been seeking about $800 million.
AUSTIN, Texas — NextEra Energy CEO Jim Robo made a last-minute appearance before Texas regulators Thursday —leaving nothing to chance in the company’s pursuit of Oncor, the Lone Star State’s largest utility.
NextEra offered up Robo to the Public Utility Commission after the first two days of hearings on NextEra’s proposed $18.7 billion deal, which the CEO told the commissioners he had watched online (Docket 46238).
Texas Ties
Having heard concerns from the commissioners over Oncor’s out-of-state ownership, he was quick to play up his Texas ties, noting his wife is from Dallas, their marriage took place in Dallas and he has in-laws in Waco.
“There’s been a lot of talk and discussion about how Oncor is a gem, and I couldn’t agree more,” Robo said. “I’ve been very clear … I love the Oncor management team. I’ve asked every one of them to stay. I do know this: As good as Oncor is, as terrific a company as NextEra is, we will be a better utility together. That’s my vision.”
Robo said Oncor and NextEra’s utility, Florida Power & Light, will be able to share best practices, benefiting both utilities. Oncor CEO Bob Shapard’s “team will teach us things; we’ll teach Bob’s team things. We’ll be a better company going forward,” he said.
Robo addressed the commissioners’ concerns over NextEra’s unregulated businesses, citing his “very clear business strategy of de-risking” them, and whether NextEra would try to pass on affiliate costs from its subsidiaries in Oncor’s upcoming rate case. “Our intention is not to layer costs on Texas customers,” he said.
Robo then reviewed a list of 68 regulatory commitments NextEra had made to the PUC, some of which have been revised by PUC staff. Mark Hickson, the company’s executive vice president of corporate development, strategy and integration, had answered questions from the commissioners on the same commitments the day before. (See NextEra Still Faces Skepticism over Oncor Acquisition.)
Dealbreakers?
Staff expressed concerns over NextEra’s commitments dealing with existing legacy debt, credit ratings, the makeup of Oncor’s board of directors, budgets, dividend policies and ring-fencing measures to protect Oncor customers. “NextEra Energy proposes transactions funded with high levels of debt that would significantly increase NextEra Energy’s debt as a percentage of total capitalization, while removing the protective ring fencing currently protecting Oncor,” staff wrote.
Staff and intervenors have called for stronger ring-fence measures than those proposed by NextEra, with staff saying the deal “would expose Oncor to the substantial risks of NextEra Energy’s nonregulated businesses, which carry much more risk than that of a [transmission and distribution] utility.” A strong ring fence insulated Oncor from the Chapter 11 bankruptcy that took down Energy Future Holdings, the company formed by private equity investors following a leveraged buyout of TXU Corp. in 2007. (See NextEra Energy Talks Up its Oncor Acquisition.)
Robo said several of staff’s revisions to NextEra’s commitments would qualify as “burdensome conditions” or “deal-killers.” He said a number of staff’s proposed changes would affect how credit-rating agencies viewed the deal.
“I appreciate you coming in and being so frank,” Commissioner Brandy Marty Marquez said.
“I feel very strongly that when we make commitments, we’ll do what we say,” Robo responded.
NextEra’s legal staff will submit a new document in the record Friday morning, when the hearings will conclude, reflecting Robo and Hickson’s comments on the regulatory commitments.
Not on the Record
Robo did not testify on the record and was not made available for comment afterward. He answered the commissioners’ questions in what was an emergency open meeting of the PUC — framed as an opportunity to visit with the commissioners and get to know them better.
“We envision [Robo’s] discussion as a statement of opportunity and to discuss the company’s position,” said NextEra’s lead legal counsel, Anne Coffin. “This would be a duly noticed open meeting. It’s no different than calling people up before regular open meetings. It’s not evidence, it’s simply dialogue.”
Attorneys for the intervenors declined an opportunity to put Robo under oath, agreeing to expedite the hearings by having their witnesses respond to Robo’s comments following the open meeting.
The PUC has an April 29 deadline to issue a decision on NextEra’s bid.
Although MISO’s new queue design has just been implemented, RTO officials are continuing to look for improvement.
“We are not done. Queue reform is a journey, not a destination,” MISO Vice President of System Planning and Seams Coordination Jennifer Curran told the System Planning Committee of the Board of Directors on Feb. 21. FERC approved the changes in January. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
Curran said that while MISO has already addressed multiple requirements that could arise from FERC’s December Notice of Proposed Rulemaking (RM17-8) requiring changes to pro forma large generator interconnection rules, the NOPR could require additional work on cost caps and eliminating barriers to storage’s participation.
In 2008, the RTO found that if it didn’t change its queue process, it would take a “clearly unacceptable” hundreds of years to process all of the project requests then in the queue, Curran said. Since then, MISO has moved from a “first-come, first-served” approach to a “first-ready, first-served” approach. She said historically 15% of queue entrants’ requested megawatts make it to commercial operation.
MISO’s new rules are designed to reduce restudies, allowing it in some instances to keep milestone payments from withdrawn projects to fund transmission upgrades on which other queue projects relied.
“Queue reform is, and has been, an on-going process. We will continue working with stakeholders to ensure we have the most efficient and effective rules in place to interconnect resources of all types,” Curran said.
Curran said the MISO queue remains dominated by wind projects, although there is also a “non-negligible” number of solar requests. She said the number of projects in the queue will face uncertainty in 2020 as wind production tax credits expire and planned wind projects could drop.
Wind has long had the highest project drop-out rates because several developers often enter the queue to serve a single load area, Curran said.
She also said MISO’s future HVDC lines must enter the interconnection queue under its “other” category because merchant lines can behave like new generation with their ability to inject energy.
Aside from 72 MW of storage planned for MISO Central, there is not a lot of storage on the horizon, she said. Storage also is a part of the RTO’s “other” queue categorization.
Duff-Coleman in Monitoring Phase
MISO has moved into the monitoring phase of Republic Transmission’s Duff-Coleman project construction in southern Indiana and Kentucky, Priti Patel, regional executive for MISO North and executive director of the RTO’s Competitive Transmission Administration, told stakeholders.
The RTO will receive quarterly project reports from Republic Transmission that will detail any construction delays or cost overruns, Patel said. Before Order 1000, she said, MISO received “vary basic” project reporting on market efficiency and multi-value projects.
Project reporting “is a very critical tool for MISO, to hold developers responsible. … Mainly, we will monitor and make visible the developer’s activities on the project so the developer eventually delivers what they have promised,” Patel said.
MTEP 16’s Huntley-Wilmarth upgrade — though not competitively bid because of Minnesota’s right-of-first-refusal statute — will also be subject to the more intensive reporting as a market efficiency project, Patel said. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)
Although MISO has no jurisdiction over the two projects, she continued, stakeholders can use its progress reports to raise any concerns to state or federal regulators.
Director Phyllis Currie asked if MISO encountered anything unexpected in last year’s competitive bid process.
MISO was impressed that all 11 developers provided “much more” information than required of them in the request for proposals, Patel replied.
MISO General Counsel Andre Porter halted the board’s question on whether any developers left disgruntled with the process. “That’s best left for closed session,” he said.
In a related matter, Patel said that MISO will complete its qualification of transmission developers by March 7.
NiSource is holding firm to its plan to retire half of its coal generation by 2023 while increasing infrastructure spending from already record levels, the company told Wall Street analysts Wednesday.
The company’s Northern Indiana Public Service Co. will close its 480-MW Bailly coal-fired plant near Chesterton, Ind., by mid-2018 and plans to shutter Units 17 and 18 (a combined 722 MW) at the 1,780-MW R.M. Schahfer plant near Wheatfield, Ind., by the end of 2023. (See NIPSCO Considers Closing 4 Coal Units in 7 Years.)
Bailly Generating Station | NIPSCO
NiSource spokesman Nick Meyer confirmed that MISO in mid-December approved the Bailly coal plant retirement for May 31, 2018. Meyer said both retirements are primarily the result of “low market gas prices and an aging coal fleet.”
The retirements are part NIPSCO’s biannual integrated resource plan submitted to the Indiana Utility Regulatory Commission on Nov. 1. The plan is still awaiting commission approval.
During an earnings call, NiSource CEO Joseph Hamrock said the company’s IRP does not call for any new generation through 2019. A longer-term proposal to replace the capacity will come in the next IRP in 2018, the company said.
In 2015, about 70% of NIPSCO’s approximately 3,800-MW generation fleet was coal-fired. Natural gas generation comprises roughly 20% of NIPSCO capacity, the lion’s share at the 535-MW Sugar Creek Energy plant near Terre Haute, Ind.
While NiSource’s coal capacity will shrink, it expects its infrastructure spending to balloon. Hamrock said NiSource invested a record $1.5 billion in gas and electric utility infrastructure in 2016, including replacement of 406 miles of gas pipeline, 60 miles of underground cable and more than 1,200 electric poles.
Hamrock also reaffirmed the IRP’s proposal to upgrade its remaining coal fleet, with the utility asking regulators for approval to invest $400 million in environmental upgrades at the two remaining Schahfer units and its 580-MW Michigan City coal plant.
Graycor Industrial Constructors completed a Wet Flue Gas Desulfurization system at NIPSCO’s R.M. Schahfer Generating Station located in Wheatfield, Ind., in 2014. | Graycor
Hamrock highlighted the company’s gas base rate case settlement approvals in Kentucky, Maryland, Pennsylvania and Virginia, as well Indiana regulators’ approvals of a seven-year $824 million gas modernization plan and a settlement granting NIPSCO a $72.5 million annual electric rate increase.
Altogether, NiSource plans $20 billion in long-term gas infrastructure investments and $10 billion in long-term electric infrastructure spending. Hamrock said NiSource now expects to invest between $1.6 billion and $1.7 billion in infrastructure in 2017, up from a prior estimate of $1.5 billion.
“We’re committed to further reducing our greenhouse gas emissions through these continued gas modernization investments and planned coal-fired plant retirements as we diversify our electric generation portfolio,” Hamrock said. In early 2016, he noted, NiSource signed on for EPA’s Methane Challenge Program, committing to reduce methane emissions by 300 Mcf over five years.
NiSource reported 2016 income of $328.1 million ($1.02/share) from continuing operations, compared to 2015’s $198.6 million ($0.63/share). Fourth-quarter earnings from continuing operations were $88.8 million ($0.28/share) versus $64.4 million ($0.20/share).
2016 was the first fiscal year for NiSource as an exclusively regulated utility, following its separation from Columbia Pipeline Group in mid-2015.
Hamrock said NiSource added 33,000 new customers in 2016, the best growth in a decade. NiSource serves roughly 500,000 electric customers in northern Indiana and 3.5 million natural gas customers in seven states.
CAISO market participants continue to seek more details about an “expedited” ISO proposal to procure black start resources.
During a Feb. 21 call to discuss the plan, stakeholders pressed ISO staff to provide more specific information on the expected technical requirements for black start units, how the procurement process would play out and the contract terms for selected resources.
The ISO developed the proposal after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area, which falls within Pacific Gas and Electric’s service territory. (See CAISO Kicks off Initiative to Procure Black Start Resources.)
CAISO’s black start procurement initiative was prompted by the need to acquire more system restoration resources to serve the constrained San Francisco area. | SF Travel
CAISO’s draft plan envisions significant collaboration between the ISO and an affected transmission owner to develop the specifications describing the requirements and selection criteria for the black start resource in the procurement process. The ISO would approve or reject the TO’s recommended resources. (See CAISO Proposes TO-focused Black Start Procurement.)
Ellen Wolfe, president of Resero Consulting, sought to know more about the history of black start procurement in California, questioning why CAISO was developing a new process.
“Historically, [TOs] have developed the restoration plans — is that correct?” Wolfe asked.
Neil Millar, CAISO executive director of infrastructure development, confirmed that utilities previously were solely responsible for devising black start plans. With the creation of CAISO, system restoration took on a collaborative approach in which the ISO “accumulates, reviews and can modify” plans if it identifies shortcomings.
“So it’s a layered approach, with the [TOs] taking a first cut and then the ISO looking at the aggregate of the various restoration plans and reviewing to make sure that there are adequate black start resources available,” Millar said, noting that the requirement for developing plans is now a “shared responsibility.”
Millar added that the ISO’s tariff allows for the acquisition of additional black start resources if needed.
“That’s the direction we see needing to move, but the question is how do we go about doing that and where should those costs actually fall?” he said.
Wolfe turned her focus to the proposed collaborative procurement process itself, asking whether the affected TO would get just the technical information from a resource bidding as black start capable, or cost information as well.
“We’re expecting that [the TO] would get all that information” from the bids, said Scott Vaughan, CAISO lead grid assets engineer. “Then they would provide a recommendation to the ISO and we would look at the analysis and either agree or not.”
Wolfe asked if the TO would effectively be acting as the “agent” for all the load-serving entities within its territory “in terms of making prudent financial choices as well.”
“The one point that we want to be clear on is that the ISO is ultimately procuring the additional service under our Tariff, so while we’re looking for the heavy participation of the [participating] TO to sort out which is the best resource, we ultimately have to wear our procurement decision,” Millar said.
Paul Nelson, electricity market design manager at Southern California Edison, sought more specifics on the potential length of the contracts and wondered whether entering multiyear arrangements with generators marked a “new area” for the ISO.
“Is this something you’ve done in the past?” Nelson asked.
CAISO currently has multiyear contracts for black start capability with TOs and generators, but they offer no compensation, explained Andrew Ulmer, the director of federal regulatory affairs at the ISO.
“So it’s a little different, because we’re talking about contracts with non-zero price terms now and figuring out a way to address that fact and allocate costs,” Ulmer said. “But [there is] no real difference in the structure of the contracts we have today.”
Ulmer added that the ISO is specifically seeking stakeholder feedback on the terms of the contracts.
Brian Theaker, director of market affairs at NRG Energy, asked if CAISO expected to publish a list of resources capable of meeting the black start requirements in the San Francisco area before conducting the solicitation.
“I think our expectation was that we would be able to define geographically the area that would help us meet the requirement, and that the generators themselves would be able to decide whether or not they were in or out,” Millar said.
Theaker raised the potential for a conflict of interest in the procurement.
“Is it possible that PG&E — in addition to being an entity that would review the offers into the solicitation process — would also be a party that would be participating in the solicitation process?” he asked.
Millar said it could happen, but it was unlikely because any black start-capable resource already owned by the utility is probably already included in the system restoration plan. “I think we’ll take your point that there needs to be some check and balance on a potential conflict there,” Millar added.
Alan Wecker, market design analyst at PG&E, said his company is “thinking through” the conflict-of-interest issue to ensure that it develops “walled-off procedures similar to how we run our [requests for offers] — such as the storage RFO — where we have our utility side participating as a bidder.”
CAISO is leaning toward a cost-of-service approach for compensating generators rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable resource. Under the current proposal, contracts — in which the ISO would be the counterparty — would run either five or 10 years with a clause requiring one year’s notice for termination.
On the issue of cost allocation, Wolfe asked if ISO staff had considered collecting the costs through CAISO’s transmission access charge. The ISO has proposed having individual TOs recover the expense from its customers through its reliability services rate schedule.
Ulmer said staff had considered the TAC alternative, and that the Tariff would allow the ISO to “peanut butter” the cost across all scheduling coordinators.
“But if we wanted to step back and make a more geographic, precise allocation of these costs, would that mechanism meet that requirement? We don’t think it would,” Ulmer said.
The ISO is seeking comments on the black start procurement proposal by Feb. 28 and plans to issue a draft final proposal by March 14. ISO management expects to submit a final plan to the Board of Governors approval in May.
