PPL last week said it expects to need to raise only about $2 billion from equity sales through 2020, which would enable the company to come in near the top of its projected 5 to 6% compound annual earnings growth per share over that time.
During its first-quarter earnings call, the company also said it expect calls for nationalization of electric utilities in the U.K. to fade and that it isn’t interested in fully or partially divesting its business there.
PPL CEO Bill Spence says his company is looking for organic growth. PPL expects to need raise $2 billion in equity sales through 2020. | PP&L
PPL earned $452 million ($0.65/share) on revenue of $2.13 billion in the first quarter, as opposed to $403 million ($0.59/share) on revenue of $1.95 billion in the first quarter of last year. Its adjusted earnings were 74 cents/share, beating the Zacks consensus estimate of 66 cents. The difference stemmed from a one-time impact of 9 cents/share from foreign currency hedges.
PPL expects to use its “at the market” offering program for most of its equity sales. CFO Vincent Sorgi said the company has a shelf offering that would allow it to sell up to $3 billion in stock.
The company isn’t looking to perform acquisitions, but rather to pursue organic growth, with midsized transmission projects such as Project Compass being the kind of opportunities it envisions after 2020, according to CEO Bill Spence.
Exelon’s plans for its generation subsidiary rely heavily on a push for new legislation and market rule changes that ensure profitability for plants the company is threatening to close, officials said last week.
During a first-quarter earnings call last week, CEO Chris Crane said Exelon plans to push for subsidies for its nuclear plants in Pennsylvania similar to the zero-emission credit (ZEC) programs in Illinois and New York, and the one recently passed by the New Jersey Legislature but not yet signed by Gov. Phil Murphy.
Crane also said he expects Exelon’s generation business to benefit from PJM’s adoption of new price formation rules and FERC’s resilience initiatives.
Although Crane didn’t mention it, Exelon’s Pennsylvania nuclear plants could also earn subsidies from a New Jersey plan that takes into account how plants affect the state’s air quality, regardless of where they’re based. (See Izzo: Nukes Outside NJ Likely Eligible for State ZECs.) Efforts to enact nuclear subsidy programs in Pennsylvania have so far failed to gain much traction.
Crane also said Exelon will work with ISO-NE to develop market reforms allowing it to keep open the four units of its Mystic Generating Station in Charlestown, Mass., that it said it would close in June 2022.
Exelon CEO Chris Crane says his company will work with ISO-NE on market reforms. Exelon has said it will close the Mystic Generation Station without market reforms.
The company is “going to look to get to the right reforms to make these assets more economic in the future,” Crane said. He noted that ISO-NE “put out a study recently saying that there were five assets in New England needed to ensure reliability into the future, one being the Everett Marine Terminal and the others being the Mystic [units].”
On the same day it said would close Mystic, Exelon announced it was buying the Everett Marine Terminal, an LNG import facility in Everett, Mass., which provides Mystic and other power plants in the area with fuel.
ISO-NE last week asked FERC for permission to waive certain Tariff requirements to allow the RTO to retain Mystic Units 8 and 9 to maintain fuel security, following up on a plan the RTO outlined in an April memo. (See ISO-NE Moves to Keep Exelon’s Mystic Running.)
Crane, along with Joe Dominguez, the company’s vice president of governmental and regulatory affairs and public policy, also addressed a PJM plan announced April 30 to help ensure fuel security. (See PJM Seeks to Have Market Value Fuel Security.)
Dominguez said Exelon would like to see PJM incorporate environmental impacts associated with different fuel mixes, pointing out that during the cold snap last winter, New England had to rely heavily on oil to produce power.
“In 2018, emissions need to be going down,” he said. “And any resolution of this issue that results in emissions going up is going to continue to create incentives for state actions and, indeed, for other federal actions to correct the flaws in those market.”
Crane said that while consumers have benefited from low-cost gas, the industry needs to either build redundancy into the gas delivery system or limit its dependency on gas to make the power production and delivery system more secure.
Exelon had net income of $585 million ($0.60/share) on revenue of $9.69 billion in the first quarter, down from $990 million ($1.06/share) and $8.75 billion in revenues a year earlier. The company’s operating earnings were 96 cents/share, beating the Zacks consensus estimate of 93 cents.
Crane said the company plans to target a 7.4% rate base growth for its utilities and 6 to 8% earnings per share growth through 2021.
Exelon is still on the prowl for acquisitions, if it can find smart ones, according to CFO Joseph Nigro.
“To the extent we can add something that we think will be accretive to the bottom line and fits with the value proposition that we’re trying to bring both to our shareholders and our customers, we’re going to be aggressive with doing that,” Nigro said.
FERC last week denied Bayonne Energy Center in New Jersey a waiver of several NYISO Tariff provisions, which the plant said it needed to enter the ISO’s monthly installed capacity (ICAP) auction in June.
NYISO clusters project developers that have achieved similar milestones into a “class year,” and evaluates the cumulative impacts of all of the projects in a given class year through an interconnection facilities study. The ISO recently adopted process changes authorizing it to bifurcate a class year in order to minimize delays for project developers unaffected by additional upgrade studies, allowing those developers an earlier “exit ramp” from the interconnection process.
Bayonne Energy Center | Direct Energy
Bayonne last month asked FERC permission to waive 11 provisions and add two new natural gas-fired units with approximately 120 MW of summer capacity to its existing 512 MW of capacity in time for the June ICAP auction.
The plant said that its 2017 class year study, originally scheduled for completion in December, was now slated to be completed in April. Bayonne would then be potentially subject to an additional 30-day delay while the ISO determined whether it needed to bifurcate the class year, jeopardizing the ability of the new capacity to participate in the June auction. Bayonne contended that it was not seeking waiver of any substantive requirements, but of the timing of certain requirements to allow for timely participation.
The commission’s May 4 order (ER18-1301) found that, in seeking waiver of 11 Tariff provisions, “Bayonne’s waiver request is not limited in scope,” and that granting the request could possibly harm third parties by delaying the ISO’s completion of the class year 2017 process for other projects. The commission also pointed out that “it is unclear whether Bayonne will even need waiver of these provisions given that it is not clear yet that whether class year 2017 will bifurcate.”
“We also note that Bayonne assumes, without support, that both NYISO and its Market Monitoring Unit can expedite their processes if the commission grants the waiver request,” the commission said. “In this way, it is unclear whether granting the waiver request would even provide Bayonne the relief it seeks.”
While the wildfires that ravaged California last year have long burned out, the financial implications for Pacific Gas and Electric are just beginning to surge as the utility works to reduce the impact on shareholders.
PG&E last week reported first-quarter profits of $468 million ($0.91/share), compared with $544 million ($1.06/share) in 2017, falling short of expectations of Wall Street analysts. The utility reported $21 million in wildfire-related costs in the quarter under “items impacting comparability.”
Central to PG&E’s woes is the legal concept of “inverse condemnation,” which makes a utility potentially liable for wildfire-related property damage caused by utility equipment even in cases when that equipment has passed inspections and utility negligence isn’t proven.
During an earnings call and presentation Thursday, PG&E CEO Geisha Williams said the current treatment of the company’s wildfire responsibility is “a strict liability approach that presumes a commensurate cost recovery path for investor-owned utilities that just isn’t true.” She said that utilities cannot raise rates without regulatory approval, so applying inverse condemnation to utilities “undermines the premise” of the concept.
California’s courts have set a precedent of applying the state’s inverse condemnation provisions to IOUs, and a state trial court last week denied PG&E’s challenge of inverse condemnation related to the 2015 Butte Fire.
Aerial view of fires in Napa and Sonoma Counties, October 2015
The state’s IOUs have banded together on the wildfire issue, pressing on legislative, regulatory and legal fronts to change the approach to inverse condemnation. Newly introduced legislation would revise wildfire liability provisions by allowing utilities to recover wildfire costs through rates if they conform to state-regulated safety plans. (See Calif. Legislation Shields Utilities from Wildfire Costs.)
Fitch Ratings downgraded PG&E’s stock in February because of wildfire risk. Utility liability for wildfires over the last 10 years has created worries among state lawmakers and the California Public Utilities Commission over the potential for IOU bankruptcies. (See Picker Seeks Guidance on IOUs, Aliso Canyon.) PG&E awaits other legal rulings regarding inverse condemnation associated with the 2017 fires, and the utility says climate change is playing a larger role in the conditions that led to the massive blazes.
The utility said that is has been working to harden its systems against wildfires, increasing its spending on vegetation management to $440 million in 2017 from $190 million in 2013, increasing inspections in high fire risk areas and acquiring two helicopters to assist in wildfire response, with plans to acquire two more. It plans to add 200 new weather-monitoring stations this year.
Williams also discussed the growth of community choice aggregators (CCAs), which has left remaining bundled customers to foot the costs for legacy contracts. The issue is becoming more prevalent as CCAs grow. She said the California energy landscape is in a period of “dynamic change,” mentioning climate change, CCA growth, increasing use of electric vehicles, and growth in carbon-free and renewable energy resources.
NiSource is seeking rate hikes across multiple states to cover hefty infrastructure investments after the company delivered a 13% increase in earnings during the first quarter.
The Merrillville, Ind.-based utility last week reported first-quarter earnings of $259.7 million ($0.77/share), compared to $230.6 million ($0.71/share) over the same period in 2017.
“Our systems performed well throughout the prolonged winter heating season, and we’re on pace to deliver on our earnings, capital investment and customer commitments in 2018,” CEO Joseph Hamrock said during a May 2 call with investors and analysts.
NiSource filed several rate hike applications with different regulators during and after the quarter, hoping to recoup the approximately $1.8 billion it plans to spend on infrastructure this year.
“The biggest driver of our strong financial performance continues to be the impact of our long-term infrastructure modernization investments, supported by solid regulatory outcomes and established infrastructure trackers,” CFO Donald Brown said.
Hamrock said NiSource expects to continue to invest $1.6 billion to $1.8 billion in its utility infrastructure every year until 2020. The investments should boost operating earnings 5 to 7% per year, he said.
Subsidiary Northern Indiana Public Service Co. filed a settlement last month in its pending base rate case with the Indiana Utility Regulatory Commission. Brown said the request is NIPSCO’s first natural gas base rate increase in more than 25 years and will improve pipeline safety and reliability (44988). If approved, the settlement would result in an annual revenue increase of $107.3 million through fixed charges on customer bills. NiSource expects a commission decision in the second half of this year.
NIPSCO employees finish a substation project in March in Northern Indiana | NiSource
NIPSCO also filed a seven-year gas infrastructure modernization plan with the IURC in early April that proposes $1.25 billion of investments through 2025. The program would recover the costs of modernizing underground natural gas infrastructure through a customer bill charge (44403). NiSource similarly expects a ruling in the second half of 2018.
NiSource subsidiary Columbia Gas of Pennsylvania also has a $47 million per year rate increase request on file with the Pennsylvania Public Utility Commission as of mid-March.
Brown said the case would “provide the company with an opportunity to earn a fair return on its infrastructure capital investments and enhance pipeline safety.”
In late April, the Public Utilities Commission of Ohio approved a rate increase allowing NiSource-owned Columbia Gas of Ohio to begin recovery on about $207 million of infrastructure investments made in 2017. Columbia Gas of Massachusetts also filed a request with the Massachusetts Department of Public Utilities to increase revenues by about $24 million annually in an effort to recover costs incurred from regulatory mandates and gas distribution infrastructure upgrades. The DPU on April 30 also allowed the Massachusetts subsidiary to recover $84 million of capital investments in its rates. Finally, Columbia Gas of Maryland is seeking a $6 million per year rate hike with that state’s regulators as of April 13 for make pipeline upgrades.
Hamrock said corporate tax cuts at the beginning of the year helped to lower its rate hike requests in Indiana, Pennsylvania, Maryland and Massachusetts, as well as the rate request for its gas infrastructure replacement program in Ohio.
Eversource Energy said Wednesday that it will seek to support earnings growth through offshore wind contracts from its Bay State Wind partnership and a new rate plan in Connecticut that increases the average customer’s electricity bill by 3.8%.
The company reported first-quarter earnings of $269.5 million, compared with $259.5 million in the same period a year ago.
Eversource’s transmission unit earned $107.4 million in the quarter, up 11.4% from a year earlier because of additional investment in its electric transmission system.
The company’s electric distribution and generation business earned $104.2 million in the first quarter, down 6.5% from last year primarily because of the sale of generation assets, as well as higher depreciation, property tax, and operations and maintenance expenses, which were partially offset by higher electric distribution margins. Exceptional storm-related costs drove O&M expenses higher.
CFO Phil Lembo said in an analyst call May 3 that “we had significant storm activity in March this year, very significant, particularly in eastern Massachusetts, as a result of a series of nor’easters that hit us over an 11-day span.”
“The vast majority of the restoration costs, about $150 million, was deferred under regulatory mechanisms for future recovery,” Lembo said.
Regulatory Updates
Lembo noted the “good news” of a FERC administrative law judge’s March 27 ruling that municipal utilities and commission staff failed to prove that the New England Transmission Owners’ (NETOs) base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable. (See ALJ Rules New England Tx Owners’ ROEs not Unjust.)
FERC last October rejected a bid by NETOs, including Eversource, to increase their ROE to the levels in place before being reduced by a 2014 commission order that was vacated by an appellate court early last year. The commission said it would address the actual rate in a later remand order but has yet to do so (ER15-414, EL11-66).
Executives also discussed the New Hampshire Site Evaluation Committee’s (SEC) March 30 decision to formalize its rejection of Northern Pass, a joint venture between Eversource and Hydro-Quebec for a 1,090-MW transmission line to bring up to 9.4 TWh of Canadian hydropower to New England each year. Massachusetts had chosen Northern Pass, but in light of the rejection selected as an alternative a transmission project proposed by Avangrid subsidiary Central Maine Power. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Lee Olivier, Eversource executive vice president for business development, said the SEC has scheduled a May 24 meeting to hear Eversource’s request to reconsider the rejection. If rejected again, “the next step would be to appeal to the New Hampshire Supreme Court,” Olivier said.
Offshore Wind Hopes
Eversource partnered with Orsted to form Bay State Wind for a offshore wind solicitation in Massachusetts, and in December the company proposed a 400- or 800-MW wind farm 25 miles off New Bedford to be paired with a 55-MW battery storage facility.
Olivier said Massachusetts officials delayed by a month the date to select projects for negotiation, to May 23, 2018, now to be followed by submission of contracts to the Department of Public Utilities by July 31.
Connecticut is also conducting a request for proposals for offshore wind, and the company bid approximately 200 MW last month, Olivier said. A winning bidder is expected by midyear, he said.
Olivier said Bay State Wind can produce up to 2,500 MW of wind energy from its 300-square-mile lease area south of Martha’s Vineyard and interconnect it to surrounding states and Long Island, even extending over land to New York City with relatively minor upgrades to existing infrastructure.
“We’ll also have returns on these assets, transmission-like returns,” Olivier said. “Clearly once you get in, if you’re one of the first selected, you’ll have a first-mover advantage in every other solicitation.”
CARMEL, Ind. — The Reliability Subcommittee’s effort to explore how MISO should address increasingly uneven availability of resources could revive a discussion on developing a capacity market divided by season, stakeholders learned last week.
MISO kicked off its “resource availability and need” effort last month with a white paper on changing availability and an announcement that it would devise specific rules to counter the effects of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and the rising use of intermittent resources. (See MISO Looks to Address Changing Resource Availability.)
During a May 3 RSC meeting, MISO Executive Director of Market Operations Jeff Bladen said the new effort has prompted some stakeholders to ask the RTO to revisit its 2015 proposal to create seasonal capacity auctions, a move that was put on indefinite hold last year after stakeholder pushback.
At the time, seasonal capacity auctions seemed like “a single point solution to a broader set of issues that called for a more holistic approach,” Bladen said, noting that the new effort wasn’t intended to preclude a re-examination of the possible need for the auctions.
Near-term Solutions
Bladen also said several stakeholders urged MISO to focus on near-term solutions to ensure that an adequate amount of resources is at the ready, including improving outage coordination, modifying the rules of emergency-only resource types and creating forecasts that provide a better picture of resource availability in the footprint.
A utility’s cash flow influences the lumping of outages, Bladen said, with fleet operators grouping outages when they expect low energy prices, especially in spring and fall.
“When prices are low, operators tend to take outages. It’s expected,” he said. “This is not as simple as, ‘well, everybody takes outages throughout the year.’ It’s much more complicated than that.” MISO said that most of its planned outages are scheduled less than a week before they are taken.
MISO might turn to a solution that requires more accountability from operators, Bladen said.
“Maybe there’s some expectation for generators to replace themselves [during an outage]? That’s pretty extreme,” Bladen said, stressing that MISO has not seriously discussed that measure.
Bladen said MISO could examine its existing load-modifying resource contracts to include staggering availability times and provide incentives to resources that offer during emergencies outside of summertime.
“Does it make sense to expect non-summer participation when it’s not compensated like in summer?” Bladen asked.
He pointed out that this summer, MISO faces an 80% chance of entering emergency conditions. (See MISO: Summer Reserves Adequate, but Emergency Likely.) He also said that a reduction in zonal resource credit offers has reduced the number of uncleared zonal resource credits in capacity auctions since the 2014/15 planning year.
“While we don’t think the platform is burning, the temperature is certainly rising,” Bladen said. “I want to be clear. The system is not unreliable. There’s just a better chance of emergencies.”
Storage Mentions
The Advanced Energy Management Alliance and other stakeholders called out MISO’s white paper for not explicitly mentioning the help energy storage could provide during tight operating.
Bladen said the omission was deliberate in order to remain technology- and resource-neutral.
“I would say that was intentional. We didn’t intend to reference technologies, but rather we were recognizing the resource availability profiles without going to where solutions could be found,” Bladen said.
Nevertheless, Bladen said MISO must consider the impacts that FERC’s Order 841 may have on its resource availability.
DTE Energy and the Organization of MISO States also asked the RTO to consider revising its loss-of-load expectation (LOLE) study process to include more availability risks associated with its resource mix.
Bladen said MISO envisions more stakeholder discussion before proposing changes to the LOLE study. He said altering study methods could produce a larger planning reserve margin requirement.
“It raises the prospect of socializing the risk by requiring everyone to procure more capacity,” Bladen said. “That’s a choice we can make as a community, but we have to be completely transparent about that choice.”
Consumers Energy’s Jeff Beattie cautioned MISO against risking some of its value proposition to its members by creating an insurance-sharing pool.
Bladen agreed that MISO needs to carefully consider balancing the sharing of resources in the footprint. “I’m glad you raised it because that’s something that needs to be front and center in the conversation,” he said.
He also said the RTO must also investigate shifting loss-of-load risk as part of resource availability. A recent renewable integration study by MISO found that as more intermittent renewable resources join the fleet, the loss-of-load risk becomes shorter but steeper, occurring later in the day after sundown. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
Developing solutions to MISO’s resource availability issues could stretch well into 2019, Bladen said, and he expected that parts of the solution will be handled by the Market Subcommittee and Resource Adequacy Subcommittee as well as the RSC. He asked for more stakeholder opinion on what approaches the RTO should take.
When FERC set out the requirements for RTOs in Order 2000 in 1999, it put stakeholders at the center of the rulemaking process, guaranteeing that generators, transmission operators, electricity buyers and public interest groups would have a voice in any rule change filed for commission approval.
The stakeholder process works well for many routine issues, but it has shown an inability to reach consensus on major contentious issues, says Christina Simeone, who authored a May 2017 study on PJM’s governance. Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania, says some of the shortfalls in PJM’s stakeholder process resulted from compromises made under the Governance Assessment Special Team (GAST) process created in 2009.
Last week, the issues Simeone’s paper raised were back in the news, following complaints by FERC Commissioner Robert Powelson and regulators from Pennsylvania and Illinois over PJM’s decision in February to file two competing proposals for insulating its markets from state-subsidized generation. (See Powelson: ‘Erosion of Confidence’ in Stakeholder Process.)
RTO Insider’s Rich Heidorn Jr. talked last week with Simeone about her study on PJM’s governance, which asked “Can Reforms Improve Outcomes?”
Simeone points to PJM’s lower committees, where generation and transmission owners with multiple affiliates can dominate the voting on proposed solutions. The power dynamic is largely reversed at the RTO’s senior Markets and Reliability and Members committees, she says, because sector-weighted voting often results in buyer-side stakeholders (the Electric Distributor sector and End User sectors) exercising veto power over proposals resulting from the lower committees. PJM’s rules require a two-thirds vote from the members of the five sectors to recommend a rule change to the Board of Managers.
In 2015, more than 77% of the generation needed to meet PJM’s summer peak was controlled, in full or in part, by only 10 companies. Although each company had only one vote at PJM’s senior committees, their multiple affiliates gave them more power at the lower committees. Note: Capacity totals and affiliate counts for companies may have changed since 2015. | Simeone
Simeone recommends that states have a vote through their governors and that PJM review the makeup of its five sectors, noting the dispersion of stakeholders representing the fastest-growing industry segments: renewable energy (Generation Owners), energy efficiency (Electric Distributors, Transmission Owners and Other Suppliers) and demand response (Other Suppliers). She says FERC should require RTOs to re-evaluate their governance processes regularly to comply with the “ongoing responsiveness” principle of FERC Order 719. The researcher is now working on a second phase of the study, expected to be published in the fourth quarter, that will explore the issues further.
This interview has been edited for clarity and length.
RTO Insider: So, it’s been about a year since you issued this report, and you made some recommendations that you acknowledged probably would require a FERC order, because the existing sectors are unlikely to give up whatever advantages they have. I’m curious, have you gotten any feedback from PJM to your findings?
Simeone: I have not received formal feedback … I have briefed the Members Committee on the report, and I’ve briefed various different groups, [including the National Association of State Utility Consumer Advocates and the Organization of PJM States Inc. (OPSI).] (See Policy Churn, Voting Rules Raise Questions on RTO Governance.)
The shortcomings of the stakeholder process I think are starting to gain more attention. I would say there [has] been some general acknowledgement that the stakeholder process could use improvements; I think there’s disagreements on what those improvements could be.
RTO Insider: In your study, you have a continuum that shows, pure market efficiency at the left side, and at the right axis, pure politics. What do you mean by politics in that context?
PJM Decision Making Continuum | Simeone
Simeone: On one side it’s pure market efficiency: What would an academic economist say [about] how the market should be designed? On the complete opposite end of the spectrum, design choices could be made [based on] pure politics. You know, this stakeholder wants this, or this state wants this. The decision that ends up happening on market design falls somewhere on that continuum. And there was always a role for politics to interject in that process, because FERC had always envisioned the role of stakeholders.
Generally, these really controversial issues are about who pays and who is getting paid — and then fairness and power balance issues. And it just sets up this legitimacy compromise. If PJM chooses market design that goes too far toward an efficient market, it is going to be seen as illegitimate to some of the people who have politically motivated priorities. If it goes too far on politics, it’s going to be seen as illegitimate to the people who are prioritizing a competitive market outcome.
So, finding the right place on this continuum is critical to the organization that’s being seen as legitimate. This is very difficult … and the hypothesis is: Could a reform improve the effectiveness of the stakeholder process in finding that sweet spot on the decision continuum that preserves legitimacy?
RTO Insider: Your report mentioned sector self-selection. You said voting in the wrong sector can complicate caucusing and reduce trust among members. Did you hear examples of that in your research, or is this more a theoretical concern?
Simeone: Yeah, I think that this is not … a top concern. I think the bigger issue is making sure the sectors reflect the actual stakeholders in the market. Those five sectors have been in place since the RTO was formed. So, you’re talking about 20 years. In 2009, you had the Other Supplier, and the Generation Owner sector at about 300 members, and 117 members, whereas the other three sectors were between 30 and 60 participants. Fast-forward [to] 2016, and the growth in the Other Supplier [and] Generation Owner sectors has been huge. … This is where all the new market entrants are coming in — renewable energy, demand response, energy efficiency, marketer traders — and they’re all kind of being lumped in to these two supply-side sectors. … As they become more diverse, it’s not clear that any kind of sub-sector has its own voice.
Generation Owners’ share of votes at lower level committees increased from 22% to 28% of the total between 2009 and 2016, while Other Suppliers’ share increased from 55% to 57% — mostly due to an explosion in the number of affiliates. The three other sectors saw their shares decline. | Simeone
To me that’s one of the most important things — making sure the sectors reflect the participants. That will have some impact on sector-weighted voting; you may have to adjust weighting. But getting the sectors right, and then the weights right, is important.
The other thing is looking at some of these legacy deals [from GAST]. At the higher-level committees, only the voting members can vote. At the lower level, it’s the voting member, and all of the affiliates. … There’s going to be a huge supply-side bias through the effect of affiliates at the lower level. … The lower level voting data is completely opaque. You have no idea what’s going on there.
At the lower level, you only need 50% majority to get something passed. Ten companies, through their use of affiliates — [based on] one of the Seasonal Capacity Resource Task Force votes, where I know there was 190 votes cast — in theory, could have prevented anything from passing, because they had 108 votes out of 190 cast. Now, I have no idea if any of these companies voted, let alone all of these companies, but it’s just an illustration.
Of 185 votes by the Markets and Reliability Committee in 2015-16, 158 (85%) were by acclamation and all but one passed (99.4%). But only 12 of 26 sector-weighted votes passed (46%). | Simeone
RTO Insider: Right. And then at the upper level, you’ve got the buy side — End Use Customers and Electric Distributors — which can effectively block a two-thirds vote.
Simeone: Right. … Because the higher-level committee data is transparent, researchers from Penn State have been able to empirically measure the strong voting coalition on the load side. They can’t get anything passed [themselves], but they can block. And so, to me, this is a clear area of reform, where there should not be this splitting of power between the different committees.
Now, I’ve heard some people say, hey, well, this is kind of Congress, where you have an upper chamber and a lower chamber. But in the House and Senate, a proposal can originate from either chamber. Here … all the creativity in the proposal development happens at the lower level. Yes, you need a problem statement approved at the higher level, but all of the creativity — all of the details of the proposal — happen at the lower level.
So, if there were sector-weighted voting at the lower and the higher level, that might be a better alternative — more neutrality, and less bias, in the process. The next area of reform is transparency. And I think that’s critically important.
RTO Insider: Transparency of votes at the lower level?
Simeone: Transparency in votes at the lower and the higher level. Especially when you think about these larger companies, who own generation and distribution, what type of behavior are these firms exhibiting? Could they be using their votes on the regulated distribution side to advance proposals that would [benefit] their generation? You know, that’s an interesting question to look at. But because the data is protected, you can’t determine if that’s going on or not.
RTO Insider: Among your recommendations, you cited fairness issues, and you said to ensure RTO/ISO neutrality, there should be procedures in place to monitor, and correct for behaviors that create preferences, or prejudices. What kind of procedures might be effective at that?
Simeone: I think that’s an area to look into further. There have been some researchers at Penn, led by Cary Coglianese, a professor in Penn’s law school. And he found a variety of projects that talked about regulatory excellence. One of the sub-initiatives in some of these regulatory excellence projects talk about how you monitor organizational culture and how you put management processes and metrics in place to achieve the kind of culture that you want.
FERC has said that the RTO needs to be independent from any market participant. But the RTO also has to be responsive to participants at the same time.
So, what kind of processes can you put in place to acknowledge that, yes, an organization could potentially be biased? I think there’s a lot of work to do to dig further into that topic.
RTO Insider: So, you would put this more in the category of areas needing more research, as opposed to having real recommendations for such procedures at this point?
Simeone: Yeah. And I wouldn’t put that as the top-tier reform at this point. I think it’s important, but not quite as important as things like getting the sectors right, looking at some of these legacy deals, like the split of power, transparency and then the role of the states. I think that’s another really big one.
RTO Insider: Let’s talk about getting greater state participation. That was one of your strong recommendations. Is that related to your observation that it can be difficult to determine what the public interest is because it’s diverse and often conflicted?
Simeone: Exactly. … There are some stakeholders who have strong accountability over the RTO. FERC has this kind of legal accountability, but not the political accountability of the RTO. FERC can’t appoint a CEO to an RTO. Nor can they appoint board members to the RTO.
Transmission owners tend to be the stakeholders that are thought to have the most accountability over the RTO, because their participation is voluntary but needed to run the system — and also because PJM is operating their assets. And then the state has the ability and the right to put policies in place that affect the market. So, these are the stronger accountabilities. And everybody else has maybe comparatively weaker accountabilities.
This raises the question of, does this reduced political accountability benefit certain private interests to the detriment of public interest? And it’s a really complicated question, because what is the public interest? Some people identify [it] as competition, lowest cost, new technologies. Others may say it’s economic development or preserving industry that’s important to my state. Or pursuing this particular environmental goal. And the public interest can change over time.
… So, I think as market design becomes more political, the importance of states participating in the process increases. Not to make things more complex, but actually to kind of integrate those opinions in earlier on in the process. And it is not clear — it’s just a hypothesis — that this would improve outcomes.
I think OPSI should always be a part of the process. …The only problem is that OPSI can only speak [when all members are in] consensus. And clearly the issues in PJM are numerous, and there’s not always consensus on the part of the states.
So, is there an opportunity to have a complement to OPSI, where states can present their opinions on an individual basis, early on in the process? I don’t have all the answers to what that looks like, but I think it’s an important thing to look into. Part of the phase two research will be presenting to the stakeholders a little survey about how these other RTO/ISOs integrate state opinions into the process … and then trying to get stakeholders to think about what they feel would be options for a revised approach.
RTO Insider: You reference the D.C. [Circuit Court of] Appeals’ decision on [the minimum offer price rule]. [See On Remand, FERC Rejects PJM MOPR Compromise.] What’s your perspective on that?
Simeone: NRG [Energy] brought [the appeal challenging FERC’s order] where there was a supermajority stakeholder agreement on design changes to the minimum offer price rule, and FERC —
RTO Insider: — kind of undid the compromise.
Simeone: Not only did they undo the compromise, but they kind of went the other way. … And [the court] basically said, no, FERC, you can’t do that — you can disagree with the stakeholders and kick it back to them. But you can’t renegotiate the compromise.
So, for me, I think it has some interesting implications, because it raises the value of supermajority agreement. Could it spark some behavior that might yield some interesting outcomes? Sure. You know, if there’s certain stakeholders who are really motivated to achieve certain outcomes. Could they strike quid pro quo deals with stakeholders that don’t typically vote in the system? So, for example, the financial traders participate in the process, but not very frequently — only on issues that are important to them. So, if you’re trying to give the stakeholders supermajority, does it then become more valuable to court voters like that to [say] ‘Hey, if you vote for me on this issue, I’ll help you out on your issue.’ That was not explored in the report, because the decision came after.
RTO Insider: So, it raises additional questions. You don’t necessarily see it impacting stakeholder reforms at this point.
Simeone: Right. I think it raises the importance of getting the stakeholder process right. To be clear, there are some people who think the PJM stakeholder process is a complete mess that can never be right. And I disagree with that wholeheartedly. I think it’s really important that the stakeholders are involved. And I think there are many, many things about the stakeholder process that are very strong and critically important to informing these decisions.
But, like anything, the markets have evolved, the stakeholders have evolved, circumstances have evolved. The stakeholder process needs to evolve, and it hasn’t for almost 10 years now. So, it’s time. I think this should be seen as reform consistent with improving the process — which is a normal part of evolution rather than an attack on the stakeholder process, or kind of a judgment that the stakeholder process is somehow bad. I’ve just heard some people just be hyperbolic in their criticisms, and I don’t think it’s warranted.
[Editor’s Note: This story has been updated to include additional filings posted at FERC after RTO Insider went to press Tuesday morning.]
By Rory D. Sweeney and Rich Heidorn Jr.
If it were a Broadway show, PJM’s “jump ball” proposals for protecting the capacity market from subsidized resources would have closed after one night.
Monday was the deadline for the critics to file their comments on PJM’s proposal and the reviews were largely negative. RTO Insider’s initial review of four dozen filings found almost no commenters wholeheartedly endorsing either PJM staff’s capacity repricing proposal or the Independent Market Monitor’s MOPR-Ex plan to extend the minimum offer price rule to existing resources in addition to new entries (ER18-1314). (See PJM Board Punts Capacity Market Proposals to FERC.)
PJM’s plan would allow state-subsidized generators to bid into capacity auctions but ensure they don’t suppress prices by removing those offers in a second “repricing” stage of the auction.
Numerous commenters said PJM had failed to prove the need for the proposed changes, arguing there was little evidence state subsidies, such as nuclear plants receiving zero-emission credits, were suppressing prices. Several commenters said the proposals would increase prices while failing to address the capacity and energy markets’ fundamental flaw: the failure to capture attributes valued by states, such as carbon-free generation. PJM’s state regulators, led by the Organization of PJM States Inc. (OPSI), were unanimously opposed.
Exelon’s Clinton Power Station is one of the nuclear plants eligible for zero-emission credits in Illinois. New Jersey is considering similar subsidies for its nuclear plants.
Hedging Their Bets
While few commenters enthusiastically endorsed either proposal, many offered qualified support for MOPR-Ex. Others hedged their positions.
Dominion Energy, Public Service Electric and Gas, American Electric Power and the Nuclear Energy Institute said FERC should reject both options but that if forced to choose, they preferred PJM’s proposal. While “imperfect,” repricing “is a far more balanced a solution” that respects state initiatives and avoids the possibility of load paying twice for capacity, NEI said.
Exelon opposed both options but called the Monitor’s proposal “particularly indefensible.”
Old Dominion Electric Cooperative — seeking to protect its self-supply resources procured outside of the capacity market — said both proposals should be rejected but that it would accept MOPR-Ex if it were amended to include the municipal/cooperative entity exemption from the capacity repricing proposal. “ODEC’s primary position remains that the commission should avoid layering yet another significant design change onto the already complex [Reliability Pricing Model] construct,” it said.
Consumer advocates from D.C., Maryland and New Jersey also said they would accept MOPR-Ex over repricing, subject to a settlement proceeding or stakeholder process “to further refine” it. The Ohio Consumers’ Counsel took a similar position, saying MOPR-Ex proposal is “less detrimental to markets and to consumers because it is more likely to encourage uneconomic generating resources to retire.”
IMM Joe Bowring acknowledged his proposal “is not perfect” but “is the only choice consistent with markets in this proceeding.”
The PJM Industrial Customer Coalition gave the proposal lukewarm support, saying its members “do not object” to it as “a reasonable extension of the existing construct” but are in full opposition to the repricing proposal.
Several commenters questioned why PJM was pushing for swift action on the proposals while it is conducting its quadrennial review of the variable resource requirement curve and launching a fuel security initiative. (See PJM Seeks to Have Market Value Fuel Security.)
“In light of other, overlapping initiatives currently underway, it is unwise and unnecessary for PJM to push forward with either of the proposed capacity market modifications — particularly when both modifications failed to obtain stakeholder consensus,” AEP said.
American Municipal Power said FERC should order PJM to reconvene the Capacity Construct/Public Policy Senior Task Force “without arbitrary deadlines to complete the evaluation of whether and what types of changes are needed to accommodate state actions.”
“The commission should reject the proposal and direct PJM to reconvene the stakeholder process in its administrative resource adequacy construct, as well as the current quadrennial review process and the novel fuel security proposal,” AMP said.
“Rather than seeking multiple arbitrary commission deadlines and guided processes for the additional work needed to resolve issues with PJM’s proposal, the commission should direct PJM to address the issues with the two proposals and create a supportable proposal that achieves the first principles identified by the commission in the [ISO-NE Competitive Auctions with Sponsored Policy Resources] proceeding.” (See Split FERC Approves ISO-NE CASPR Plan.)
Blow It Up and Start Over
Several companies suggested FERC use its Section 206 powers to craft a solution, though they disagreed on how urgent the problem is.
NRG Energy asked FERC to create “its own just and reasonable capacity market design.”
“While NRG agrees that the existing PJM rules are being overwhelmed by subsidized generation, neither of the two PJM proposals will result in a long-term sustainable market structure,” NRG said. “Inaction is not a viable option.”
The PJM Power Providers Group agreed “the threat … is real” and backed developing a different MOPR “that removes many of the exemptions contained in the MOPR-Ex proposal.”
The New Jersey Board of Public Utilities asked FERC to reject the filing and order PJM to “ensure that any future capacity market revisions are complementary to” attributes sought by the states.
“PJM’s proposals do not aid the commission in its longstanding efforts to harmonize state policies with capacity market planning,” the BPU said. “Status quo is the appropriate action for now.”
The American Public Power Association said the proposals are “further evidence of the ongoing unsuitability of mandatory capacity markets to ensure resource adequacy.” It said, “bilateral contracting or ownership should be supported instead of merchant development of generation resources.”
“APPA agrees that such state policy goals should be accommodated, but raising capacity prices for customers without any assured benefit is not the way to do it,” the association said.
Full Rejection
Consumer advocates from Illinois, Delaware, West Virginia, Kentucky and Indiana said FERC doesn’t have the authority to choose one of the two proposals. “Effectively, PJM is asking the commission to conditionally approve a proposal and then oversee a rewrite of that proposal,” they said.
The Illinois Commerce Commission also questioned FERC’s authority to act on either proposal, adding that, despite “PJM’s lip service to states’ rights … PJM reserves to itself the discretion to cherry-pick which resources are worthy of state policy revenue.”
“State laws that do not seek to impermissibly intrude upon the wholesale electricity market or abrogate a commission mandated rate, properly fall within the jurisdiction reserved to the states and do not violate the [Constitution’s] Supremacy Clause,” the ICC wrote.
Rare Endorsements
One full-throated endorsement came from comments filed jointly by Starwood Energy Group and Direct Energy, who argued MOPR-Ex “is narrowly tailored to mitigate artificial price suppression in PJM’s capacity market while retaining core market fundamentals” and “preserves the ability of both customers and investors to bring new capacity resources, and offer existing economic capacity, into the market on a competitive basis.”
The companies opposed PJM’s repricing proposal and repeatedly juxtaposed the two to argue for MOPR-Ex, which it said “does not thrust the capacity repricing costs onto the market generally.”
The American Petroleum Institute also expressed support, arguing that repricing “effectively provid[es] preferential treatment to high-cost, subsidized resources for capacity commitments that continue to inefficiently displace lower-cost resources.”
“Contrasted with capacity repricing, implementation of MOPR-Ex is straightforward and narrow with all subsidized resources subject to mitigation without exception, and nonsubsidized resources would not be subject to mitigation,” API said in a joint filing with private equity Panda Power Funds and J-POWER USA Development, an independent power producer and developer with 2,700 MW of generation operational or under development in PJM.
LS Power Associates also backed MOPR-Ex saying it is “based on the well-established minimum offer price rule that has long been part of PJM’s capacity market,” while the repricing proposal is “fundamentally unfair” and “irredeemably flawed.”
Rockland Capital argued for the MOPR-Ex with settlement discussions to “ensure that the exceptions from mitigation are tailored to preserve wholesale market prices first and accommodate state interests second.”
The Natural Gas Supply Association was less outspoken in its support but nonetheless urged approving and suspending implementation of MOPR-Ex, then directing those involved to engage in settlement discussions to consider “how exemptions are provided and the appropriateness of unit-specific exemptions, including exemptions provided for units subject to a renewable portfolio standard.”
The group pointed to the nuclear subsidies recently passed in New Jersey as evidence “that the time is now to address state subsidies given that the number of subsidies in the market continue to grow.” (See Exelon to Push for Laws, Rules to Boost Profitability.)
Vistra Energy and its Dynegy Marketing and Trade subsidiary took a similar position, saying “an appropriately designed” MOPR is the best way to support competition.
The Electric Power Supply Association said it opposed capacity repricing but agreed “100%” with PJM that changes are needed.
“The commission should summarily reject the ‘capacity repricing’ proposal … which would enable and encourage state interference with the commission-jurisdictional RPM market, and should instead focus on a MOPR approach, consistent with its recent commitment to ‘use the MOPR as [its] standard solution’ where state policies threaten the organized capacity markets.”
EPSA noted that the Monitor’s MOPR-Ex plan received more support among stakeholders than PJM’s alternative. If the commission does not find MOPR-Ex just and reasonable, EPSA said, it should find PJM’s current MOPR rules are not just and reasonable because they don’t cover existing resources.
Exelon, however, said MOPR-Ex “would prevent state-supported clean generators from clearing at all, replacing them with polluting units. Perversely, that will not just force customers to pay higher electricity prices but also will inflict on customers the additional costs of grappling with the pollution [MOPR-Ex] has created.”
‘Externalities’
Exelon said PJM’s premise — that states making payments to recognize the environmental benefits of renewable and nuclear generators states are “distorting” price signals — is incorrect.
“Sound economics understands that when states tax polluting generators, or pay clean generators for their environmental value, they do not ‘distort’ price signals. They reduce distortions and account for true economic costs and benefits. The only distortion comes from treating clean and polluting generators as the same when they are not.”
The Institute for Policy Integrity at New York University School of Law, a nonpartisan think tank that says it is dedicated to improving the quality of government decision-making, also cited the markets’ failure to value environmental externalities.
FirstEnergy, in a joint filing with East Kentucky Power Cooperative, also agreed that the capacity market is failing to account for externalities — but defined those uncompensated attributes as “resilience, fuel diversity and fuel security.”
“The simple facts are, notwithstanding numerous amendments and market design enhancements through the years, PJM’s wholesale capacity market has never worked as intended. States are compelled to address the needs of their constituents. It therefore should be no surprise that states within the PJM footprint are responding to this long-term market failure by implementing policies that are designed to preserve important generation units and their associated attributes, including generation and zero-emissions attributes.”
They said FERC should reject PJM’s proposals and require the RTO to “develop a holistic solution to the fundamental issues facing its markets.”
Resume Negotiations
Several commenters called on PJM to return to stakeholder negotiations.
Dominion said it opposes both proposals because they extend mitigation to existing capacity resources. “Dominion Energy does not agree that existing capacity resources have the same pricing effects as new capacity resources and warrant identical treatment,” it said. FERC should insist the RTO resume stakeholder discussions to develop rule changes “that focus on actual distortive pricing effects stemming from state public policies,” Dominion said.
Talen Energy Marketing and its fleet of generation subsidiaries argued both proposals are “inadequate” and asked FERC to “direct PJM to engage with its stakeholders in a broader price reform effort, including necessary revisions to the energy market, that would seek to appropriately compensate generators for other, non-price attributes that provide measurable value to the grid.”
States Unanimous
In a rare unanimous vote, OPSI urged FERC to reject both proposals and argued that PJM should “respect the resource choices of state policymakers unless there is a legal determination that a state policy impermissibly intrudes” on federal jurisdiction. State subsidies aren’t impacting the market’s ability to attract resources and provide adequate returns, and PJM’s evidence to the contrary is purely “speculative” and anecdotal, OPSI said.
“Data shows that adequate numbers of generation resources are consistently able to recover their costs, while receiving rational price signals, from PJM markets,” OPSI said. “PJM abandons the cost-minimizing principle and instead proposes an exceedingly complex design change that will place more weight on administratively determined artificially inflated prices rather than actual market participant offers.”
It noted that the Monitor’s State of the Market report found the average age of at-risk units is 42 years while a Department of Energy-funded report found that the average lifespan for coal units in the Eastern Interconnection is 40 years.
“Such findings seem less indicative of market failure, than of rational market signals of entry and exit. … Rather than rising, there is significant data that shows capacity prices should be falling,” OPSI said, noting the results of PJM’s recent quadrennial analysis of its demand curve and recommendations to reduce the expected cost for a new unit to enter the market.
OPSI said the CCPPSTF was flawed because its charter limited it to only consider the capacity market.
The Maryland Public Service Commission said PJM’s proposed changes would “obscure resource clearing, increase uncertainty and raise customer prices.”
The Pennsylvania Public Utility Commission noted that neither proposal received a two-thirds majority at the Markets and Reliability Committee and that both “could result in subsidized resources in one state, significantly increasing market prices in another state.” (See “No Consensus on Capacity Revisions,” PJM MRC/MC Briefs: Jan. 25, 2018.)
It said capacity repricing would incent market sellers to underbid in the first stage of the auction “causing further price volatility” while MOPR-Ex could cause states to pay twice for capacity even as it suppresses energy prices.
The Public Utilities Commission of Ohio said FERC should preserve the current rules “until a direct path to addressing state subsidies, if at all, can be determined.”
“The commission, state commissions and other parties have taken significant steps to resolve perceived capacity market design deficiencies that have not been fully implemented. Yet, in less than three years, PJM is again before the commission proposing another significant overhaul of the capacity market under far less certain circumstances,” PUCO said. “While PJM has provided information on the price suppression effect of subsidies, it has not similarly substantiated the level of penetration of state-subsidized resources that would trigger the need to depart from the status quo with another major overhaul of RPM. Furthermore, the PUCO notes that there is no analysis as to the cost impacts of either proposed option on load.”
The New York Public Service Commission, which is working with the NYISO to incorporate a carbon adder into its wholesale market to accommodate state-subsidized nuclear plants, sought assurances that the commission’s ruling on the PJM proposal “will not serve as binding precedent for other control areas.”
Quad Cities nuclear plant
“This is critical for other control areas to have the autonomy needed to develop market mechanisms that address their regions’ unique circumstances,” the PSC said in a joint filing with the New York State Energy Research and Development Authority.
Environmental Groups Oppose
A joint filing from the Sustainable FERC Project, Sierra Club, Natural Resources Defense Council and Environmental Defense Fund asserted that “PJM wrongly puts the commission in the position of policing the efficiency of state policies.” The proposals put “wholesale market rules on a collision course with states’ core duty to protect the public.”
The filing included a report from “subsidy expert” Doug Koplow that argued energy subsidies “have long been pervasive at both the federal and state level without attendant impacts on PJM’s wholesale markets that have prevented that market from attracting record levels of investment.”
“Even if one state’s policies were to somehow to harm customers in other states, that would not justify commission intervention to countermand those laws where they are lawfully within the state’s authority,” the filing argued.
The Solar RTO Coalition, a newly formed group of solar developers and capital providers, said it is “challenging” to address supply-side subsidies.
“The sheer scope of some of the issues that are associated with how to best incentivize the ‘proper’ development of generation resources … are part of the reason why PJM’s stakeholders were unable to come to a consensus.”
Both OPSI and the Solar Coalition sought to distinguish PJM’s filing from ISO-NE’s CASPR proposal, which the coalition said “was much narrower in scope.”
Ari Peskoe, of the Harvard Electricity Law Initiative, said, “PJM fails to explain why it equates state support for legacy assets with competitive state programs for environmental attributes, even though it concedes that the latter affect wholesale rates ‘to a lesser degree.’”
“Commission approval would substantially expand RTO authority in a field of shared authority. … States did not sign up to have a regional system operator pick and choose among their generation procurement programs, and any assertion to the contrary is unsupportable,” he said. “If the commission approves one of PJM’s proposals, it should expect a steady stream of [Federal Power Act Section] 206 complaints about laws and regulations ensnared or uncaptured by PJM’s arbitrary rules.”
Self-supply Concerns
Dayton Power and Light said either of the two proposals are improvements over the status quo but that FERC should correct “deficiencies” in the proposals by adopting changes to the fixed resource requirement (FRR) option that allows state regulators and regulated utilities to supply their own load with their own capacity resources outside the RPM.
“With the minor tweak to the FRR rules, Dayton believes that market price outcomes will be preserved and states wishing to subsidize varying attributes of generation can be accommodated,” it said. “The only changes needed is to allow for a partial or overlay FRR within a state as opposed to a full zone as the rule exists today. If a state subsidizes 1000 MW of generation for any reason it deems appropriate, it would remove a corresponding amount of load including reserve requirements from the PJM RPM auction.”
In its own filing, EKPC asked FERC to force PJM to change MOPR-Ex’s “public entity” exemption to recognize that the co-op is the only winter-peaking load-serving entity within PJM’s footprint. The proposal uses LSE’s zonal summer-peak demand forecasts to calculate the LSE’s eligibility for the exemption. The LSE cannot own more than 600 MW of generation above the peak summer load it serves. However, EKPC procures generation to cover its higher winter peak, which would put it beyond the 600-MW cap.
The Illinois Municipal Electric Agency avoided comment on MOPR-Ex and focused on criticizing the repricing proposal, which it said would hurt load in the ComEd zone by reducing capacity transfer rights allocated to load “due to the predictable decreased clearing of lower-priced imported generation under stage one.”
The National Rural Electric Cooperative Association reiterated its opposition to PJM’s mandatory capacity market. “However, recognizing that the commission may not at this time unravel PJM’s mandatory capacity construct, NRECA urges that the commission … mandate that any outcome of this proceeding must contain specific exemptions for self-supply by cooperative utilities and other load-serving entities.”
CenterPoint Energy executives said Friday they were “excited” about the company’s proposed acquisition of Indiana utility Vectren, saying it presents them with future growth opportunities.
“This transaction will continue to advance us towards our vision of being the nation’s leader in delivering energy, service and value,” CenterPoint CEO Scott Prochazka said during the company’s first-quarter earnings call with analysts and investors. “We’re excited about CenterPoint’s post-merger future.”
CenterPoint announced the $6 billion deal last month. The combined company would serve more than 7 million customers, operate electric and natural gas delivery systems in eight states and hold about $29 billion in assets. (See CenterPoint Energy to Acquire Vectren in $6B Deal.)
The Houston-based company hopes to close the acquisition in the first quarter of 2019. The deal still requires approvals from Vectren shareholders, FERC, the Federal Communications Commission, and regulators in Indiana and Ohio.
“We are combining two companies with strong capital investment opportunities and rate base growth,” said CFO Bill Rogers. “We believe we also have the right mix of unregulated products and services to meet the customer needs of today and tomorrow. This merger provides us the opportunity to deliver even stronger earnings results than we would as separate entities.”
CenterPoint reported first-quarter earnings of $241 million ($0.55/share), compared with $160 million ($0.37/share) for the same period in 2017, beating the Zacks Consensus Estimate of 44 cents.
Investors reacted to the news by driving CenterPoint’s share price up 6.1% to $26.88 at the market’s open. The stock closed at $26.41.
The combined CenterPoint-Vectren service area | CenterPoint Energy
Prochazka said the Vectren acquisition will lessen the company’s exposure to the midstream space through Enable Midstream Partners, a gas-gathering and processing joint venture with Oklahoma’s OGE Energy. CenterPoint owns a 54.1% share of Enable, while OGE holds a 25.7% limited-partnership interest and a 50% management interest.
“We continue to believe Enable is well-positioned for success,” Prochazka said, pointing to Enable’s earnings announcement earlier in the week in which it reported all-time highs for quarterly natural gas gathered volumes and processed volumes.
That’s not to say CenterPoint isn’t continuing to look for opportunities to reduce its ownership in Enable.
“We need to be very thoughtful and do so in a coordinated fashion with Enable, so we don’t have a negative impact on Enable,” Prochaska said.
Rogers made it clear that CenterPoint will not sell off portions of Enable to fund the Vectren acquisition, saying three times, “We do not intend to sell Enable common units to finance the acquisition of Vectren shares.”
OGE Gets Huge Boost from Favorable Weather
OGE on Thursday credited favorable weather for first-quarter earnings that almost doubled analysts’ projections.
The Oklahoma City-based company reported earnings of $55 million ($0.27/share), compared with 2017’s first-quarter profits of $36 million ($0.18/share). A Thomson Reuters survey of analysts had expected earnings of 15 cents/share.
CEO Sean Trauschke told analysts and investors during a conference call that it was the first time in five years OGE has begun a calendar year with weather that has driven up electricity sales.
“It feels good to have the first quarter behind us with positive weather,” Trauschke said. “Weather changes. It’s not something you can control. What does not change is our execution and focus on getting better.”
Ironically, Trauschke’s comments came in the aftermath of severe weather that hit OGE utility Oklahoma Gas & Electric’s service territory on May 2.
OG&E’s service territory | OG&E
“Tornadoes, high winds, rain, hail, the full complement,” Trauschke said, promising that service would be restored by noon May 3.
OG&E contributed earnings of 16 cents/share, double its performance in 2017’s first quarter. Trauschke said its Mustang Energy Center’s seven new units have already seen “close to 500 starts” and produced more power this year than its legacy units did all last year.
OGE’s revenue for the quarter was $492.7 million, up 8% from last year. Noting the company realizes most of its earnings in the second and third quarters, Trauschke reaffirmed year-end earnings guidance of $1.90 to 2.05/share.
The company’s stock price gained $1.41/share with Thursday’s earnings release, finishing the day up 4.3% at $34.23/share.
PPL last week said it expects to need to raise only about $2 billion from equity sales through 2020, which would enable the company to come in near the top of its projected 5 to 6% compound annual earnings growth per share over that time.
