The ERCOT Technical Advisory Committee on Friday unanimously endorsed a revision to the Commercial Operations Market Guide (COPMGRR044) that aligns with a previously approved protocol change.
Solar Roof | Meridian Solar
Nodal Protocol Revision Request 794 was approved by the Board of Directors on Feb. 14 and by the TAC in January. It moves reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols.
The vote was conducted by email after the February TAC meeting was canceled.
Public Service Enterprise Group has received approval to operate as a third-party supplier of retail electric energy in New Jersey and eastern Pennsylvania, company officials said during its report on earnings for the fourth quarter and full year of 2016.
“The forecast for 2017 doesn’t assume meaningful contribution from retail sales, but Power’s team will begin its marketing efforts,” CFO Dan Cregg said.
“This is primarily a defensive move on our part,” said CEO Ralph Izzo. “We’ve opted to pursue this organically, building the capability in-house. We still are targeting between 5 and 10 TWh at its maturity. … We have a head of the operation onboard that we’ve hired and a couple support folks and are talking to people about some of the back-office fundamentals that we don’t want to build on our own.”
The business would be in addition to its requirement to provide power to default customers within its footprint that don’t shop around — about 11 of the company’s 50 annual terawatt-hours of production, Izzo said.
“What we’re looking to do here is to basically claw back some of the [customers who purchased elsewhere] that over years had gone away either by some combination of migration or changing of thresholds for the [basic-service] customer. We think that it will help us capture some lost margin and improve our management of basis differentials,” Izzo said.
PSEG reported income of $887 million ($1.75/share) for 2016 compared to $1.68 billion ($3.30/share) for 2015. For the fourth quarter, the company reported a loss of $98 million (-$0.19/share) compared to income of $309 million ($0.60/share). Expenses associated with the early retirement of coal-gas units at the Hudson and Mercer generating stations and reserves for a leveraged lease impairment accounted for the difference in year-end results, company officials said. The fourth-quarter loss reflects the impact of depreciation and other expenses associated with the plant retirements.
NJ Gov. Chris Christie and PSE&G President and COO Ralph LaRossa in Hackensack on October 28, 2016 discussing improvements made to PSE&G equipment since Superstorm Sandy. | PSEG
Operating earnings for the year were $1.48 billion ($2.90/share), virtually unchanged from the $2.91/share earned in 2015. Operating earnings were $279 million ($0.54/share) for the quarter compared to $255 million ($0.50/share) for the same period last year.
Company officials and analysts largely shrugged off the quarterly losses, noting annual operating results came solidly within its guidance of $2.80 to $2.95/share.
“The board’s recent decision to increase the common dividend by 4.9% to the indicative annual level of $1.72/share represents confidence in our firm’s investment strategy and an acknowledgment of our strong financial condition,” Izzo said.
FERC has accepted MISO’s plan to pare down pre- and post-service restrictions on its directors as part of a package of transmission owner agreement bylaw changes.
The short Feb. 23 order (ER17-686) approved all MISO’s requested bylaw changes effective Feb. 27. RTO staff said the bylaw change was needed to attract more board member recruits.
Most prominently, FERC’s delegated order cuts the pre-service restriction to one year and eliminates a post-service restriction. MISO’s directors had been subject to a two-year pre- and post-service prohibition on affiliations with RTO members, affiliates and market participants. (See Board OKs Pay Hike, Change to Independence Rules.)
The edits also added the gender-neutral “board chair” in lieu of “chairman” and specified that adjustments to board compensation must be made by an independent compensation consulting firm. The RTO last year used firm Willis Towers Watson to up board compensation by $4,000 annually.
Other bylaw edits the commission approved allow board elections to take place earlier in the year, remove the requirement that the annual MISO members meeting be held on the second Thursday of December — allowing for more flexible scheduling — and eliminate the specific Jan. 1 due date for the annual $1,000 MISO membership fee. MISO staff said membership fee billing and payment usually takes place sometime after Jan. 1.
Finally, the edits clarify that member voting — even voting to remove a board member — can take place outside of meetings.
CARMEL, Ind. — Mild temperatures and inexpensive natural gas resulted in a slight load decrease and lower energy prices in MISO in January.
Average load was 76.2 GW, a 0.7-GW decrease over December. LMPs averaged under $30/MWh systemwide, a 7.6% decrease from December, with real-time prices of $28.04/MWh and day-ahead prices of $28.69/MWh. The average January gas price was $3.28/MMBtu, a decrease of 8.6% from the prior month.
Operating conditions in the RTO during January were “generally favorable,” punctuated by a few short-lived severe weather conditions, Executive Director of Market Design Jeff Bladen said at a Feb. 21 Informational Forum. MISO reported zero minimum or maximum alerts or warnings.
The RTO also recorded 4,245 GWh of systemwide wind production in the month, a drop from December’s 5,687 GWh, but 3% higher than January 2016’s 4,110 GWh.
WILMINGTON, Del. — After months of rule changes, PJM stakeholders decided to largely take a break at last week’s Markets and Reliability Committee meeting. Aside from endorsing some administrative revisions and an uncontroversial exception to competitive bidding for substation equipment, members rejected or deferred votes on all other voting items, often citing FERC’s lack of a quorum for why there is no pressing need to decide.
Decision on Order 825 Implementation Postponed Until March
Stakeholders agreed to delay voting for a month on additional rule changes associated with Order 825, which requires that shortage pricing be triggered for any period of energy or operating reserve. The order required PJM to eliminate its practice of waiting until a shortage is forecast for a sustained period before shortage pricing. (See FERC Issues 1st RTO Price Formation Reforms.)
To continue to avoid “transient shortages,” PJM has proposed a two-part response to the order. The first part, which was filed last month, satisfies FERC’s requirements for initiating shortage pricing. The second part — which PJM plans to submit to FERC as a Federal Power Act Section 205 filing contingent upon approval at the Members Committee meeting in March — would adjust its operating reserve demand curves. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
“Is this a decision the commission could make absent a quorum?” American Municipal Power’s Ed Tatum asked. PJM staff confirmed that there has been a challenge in the docket, so FERC wouldn’t be able to accept it via delegated approval.
Susan Bruce of the PJM Industrial Customer Coalition asked if a vote could be delayed another month to work out issues. It’s possible, PJM’s Adam Keech responded, but the delay might create exposure for PJM’s markets if FERC requires implementation of five-minute settlements, also mandated by Order 825, by May.
Keech also explained that an increase in the market clearing price will have as much as triple the impact on reserve clearing price credits. PJM’s analysis found that a 5% increase in the clearing price would add about $6.4 million, or 15%, to the credits, while a 10% increase in the price would add about $8.7 million, or 20%.
For the purposes of simplicity, the sensitivity study assumed that lost opportunity cost credits remained static. Generally, however, “as the clearing price credits go up, the opportunity cost credits go down,” Keech said.
Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes
A problem statement and issue charge to address replacement capacity failed to garner 50% approval after presenter Bob O’Connell of Panda Power Funds navigated around objections to secure a vote. He’ll get another chance on a separate problem statement involving incremental offers next month, when members also will consider the proposed charter language for the Incremental Auction Senior Task Force.
Several members had attempted to postpone voting on the problem statement for a month, but a vote to postpone fell short, receiving 3.33 in a sector-weighted vote that required 3.34 to pass. That allowed O’Connell to call for a vote.
Tom Rutigliano of consulting firm Achieving Equilibrium said a delay would help alleviate problems with the problem statement, such as what he called a mischaracterization of some FERC orders that put stakeholders “on a path to repeat the same conclusions that FERC has already rejected.” But O’Connell was intent on bringing the motion to a vote. Rutigliano then proposed some hastily devised amendments, some of which O’Connell accepted.
Citigroup Energy’s Barry Trayers also proposed amending the language to focus on streamlining the replacement-capacity process and reducing PJM staff discretion. O’Connell considered this a friendly amendment and included the revisions.
“Really this is a vote about whether we want to try to solve the problem on our own or if we want to have the commission solve it for us,” O’Connell said.
The proposal to revise the replacement-capacity rules comes after recent stakeholder debates about the impact of “paper capacity” — when a market participant offers into Base Residual Auctions and buys out of the obligation during subsequent Incremental Auctions to take advantage of price differences. (See “PJM Has No Objection to IMM’s ‘Paper Capacity’ Report,” PJM Market Implementation Committee Briefs.)
Regarding his second problem statement proposal, O’Connell said PJM’s opportunity-cost calculator needs to be recalibrated to account for penalty rates implemented along with the Capacity Performance market construct.
Independent Market Monitor Joe Bowring challenged a work activity to find ways to incorporate nonperformance charge rates into the calculators. O’Connell agreed to add “where appropriate” or “if necessary” as a revision.
The task force charter language was developed in response to a problem statement presented by Direct Energy that was approved in November. It focuses on the Incremental Auction structure and how excess capacity is sold back by PJM.
PJM’s Brian Chmielewski, who is facilitating the task force, said detailed replacement capacity issues will be addressed in a separate problem statement and issue charge.
Transmission Replacement Activity Hiatus Extended
Stakeholders agreed to extend the Transmission Replacement Process Senior Task Force’s hiatus for another 90 days, citing FERC’s continued silence on the issue.
In August, the commission issued an Order to Show Cause questioning whether PJM transmission owners are complying with their local transmission planning obligations, specifically with respect to supplemental projects, as required by Order 890. (See “Transmission Task Force Halts Most Action in Response to FERC Order,” PJM Markets and Reliability and Members Committees Briefs.)
The TOs responded in October, but FERC has not acted on the filing and has no deadline for doing so.
PJM’s Fran Barrett, who is facilitating the task force, said the commission’s loss of its quorum was unexpected and recommended extending the deferral.
Some stakeholders called for using the downtime to resolve the problems. “We can work a thorny issue for FERC so FERC doesn’t have to work it for us,” Tatum said, who added that he has “great concern” with extending the hiatus.
“The time we have been waiting for FERC to act has not been wasted time. We have been working hard,” Exelon’s Gloria Godson said.
O’Connell said the decision should be based on whether there is anything to talk about. “Just go ahead and tell Fran: ‘Fran, we have enough meat for a meeting. Go ahead, and schedule it. If we don’t have enough meat, don’t schedule it,’” he said.
Barrett agreed to return to next month’s meeting with an update.
Stakeholders Endorse Revisions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Revisions to Manual 22 to update terms and definitions, developed as part of a periodic review of the manual. The term revisions largely replace “partial outage” so that the manual now refers to forced, maintenance and planned outages as “derated.” For example, “Equivalent Forced Partial Outage Hours” became “Equivalent Forced Derated Hours.”
Revisions to manuals 13 and 27 will add the Mid-Atlantic Interstate Transmission Co. as a transmission owner in PJM. MAIT is a new subsidiary of FirstEnergy that owns and operates the company’s transmission assets in the Met-Ed and Penelec utility territories. (See NJ Opposition Derails FirstEnergy’s Tx Reorganization — but not Projects.)
Revisions to the RTEP and the Operating Agreement to exempt certain transmission substation equipment from Order 1000 competitive bidding. (See “Endorsements Sail Through by acclamation,” PJM Planning Committee and TEAC Briefs.) John Farber of the Delaware Public Service Commission staff took the microphone to thank PJM for its attention to the topic. The measure was also later endorsed by the Members Committee.
Two stakeholders complained that the proposals didn’t align with FERC’s order on the issue. “I don’t agree that the package is counter to FERC’s order,” PJM Public Power Coalition’s Carl Johnson replied. “In fact, I think it’s the first step to something they might approve.”
Consent Agenda Endorsed
The committee also endorsed:
Tariff, Operating Agreement and Reliability Assurance Agreement revisions to update definitions.
Revisions to the PJM Tariff regarding operating parameters.
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.
