Warren Buffett is stepping in where two other suitors have failed and will soon make a deal for Oncor, Texas’ largest transmission and distribution utility, according to The Wall Street Journal.
Citing sources “familiar with the matter,” the Journalreported that an announcement by Berkshire Hathaway Energy proposing to acquire Oncor was imminent. The acquisition’s terms have not been disclosed but are thought to be more than $17.5 billion and less than the $18.7 billion NextEra Energy put up last year, according to reports.
Buffett
NextEra’s bid was spiked by the Public Utility Commission of Texas, which ruled in April that the proposed merger was not in the public interest. The commission subsequently rejected two requests for rehearing by NextEra and Oncor. (See NextEra-Oncor Deal Meets Third Denial.)
NextEra’s failure was preceded by that of Dallas-based Hunt Consolidated, which saw its bid fall apart last year when the PUC placed conditions on the transaction that the Hunt family was unable to meet. Hunt’s motion for rehearing also was turned down by the commission. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
Oncor’s sale is instrumental to resolving the $42 billion bankruptcy of Energy Future Holdings, Oncor’s parent company. EFH declared Chapter 11 bankruptcy in April 2014, and creditors last year reached a settlement contingent on Oncor’s sale.
A regulated utility, Oncor has maintained its profitability despite EFH’s woes. The Berkshire Hathaway acquisition, like the previous two failed bids, would require PUC approval.
Berkshire Hathaway, headed by billionaire Buffett, was among those thought to be interested in the company after the Hunt deal fell apart.
Oncor would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, the company held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
Buffett has made several large purchases lately, including spending $32 billion for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, he told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
Warren Buffett’s bid for Oncor won an immediate endorsement from the head of the Texas Public Utility Commission’s staff Friday, suggesting the Oracle of Omaha may succeed where two other suitors for the state’s largest transmission and distribution utility failed. But first, Buffett may have to overcome a challenge from hedge fund Elliott Management, which is reportedly unhappy with the offering price.
Des Moines, Iowa-based Berkshire Hathaway Energy (BHE) announced Friday it had reached an agreement on an all-cash deal that will pay $9 billion for bankrupt Energy Future Holdings (EFH), Oncor’s parent. BHE said that is based on an equity value of $11.25 billion for 100% of Oncor. The Wall Street Journal, which reported Thursday that the deal was imminent, said the purchase has an enterprise value of about $18 billion including debt.
BHE said it expects the purchase to close in the fourth quarter, following approvals by federal and state regulators and the judge overseeing EFH’s bankruptcy.
The PUC rejected prior bids for Oncor by Florida-based NextEra Energy and Dallas-based Hunt Consolidated. But PUC Executive Director Brian Lloyd issued a statement praising the BHE offer, saying he looks “forward to an expeditious filing of this agreement for the commissioners to consider.”
“I applaud both Berkshire Hathaway Energy and Oncor for their productive efforts with PUC staff, the Office of Public Utility Counsel, the Steering Committee of Oncor Cities and Texas Industrial Energy Consumers,” he said. “These parties have developed a transaction that fortifies the successful ring-fence protections the commission ordered in 2007. Both BHE and Oncor are proposing additional assurances regarding Oncor’s independence, financial integrity and commitments to invest in infrastructure, cybersecurity and system reliability for the more than 10 million Texans served by Oncor.”
PUC spokesman Terry Hadley said Lloyd’s statement was based on meetings that preceded the merger announcement. “As is typical with this process, the PUC staff and other parties mentioned in the statement met informally to see what can be resolved prior to an official filing,” Hadley said. He said the first filings on the deal will likely be with the bankruptcy court.
Winning the Debtors
Winning regulators’ approval is only part of the challenge facing Berkshire, however.
Elliott Management, a $33 billion hedge fund that is the biggest holder of EFH bonds, is signaling it may make a competing bid for Oncor, the Journal and Reuters reported late Friday. Elliott added to its stake in the last several months, acquiring them from other funds tired of waiting for an Oncor sale.
Although the fund has no experience in an acquisition of this size, the Journalreported, it could threaten a higher bid to force Berkshire to improve its offer, which is insufficient to pay creditors 100 cents on the dollar. With a “blocking” position in two classes of EFH debt, Elliot has a pivotal role in whether creditors accept the Berkshire offer and complete EFH’s bankruptcy reorganization. Elliott had previously opposed NextEra’s higher bid for Oncor.
Reuters noted that Elliott filed a lawsuit in May asking EFH to consider a debt reorganization that could convert the hedge fund’s debt to equity, which could give it control of Oncor. EFH owns 80% of Oncor.
Prior Deals Rejected
The PUC rejected NextEra’s $18.7 billion bid for Oncor in April, ruling that the proposed merger was not in the public interest. (See NextEra-Oncor Deal Meets Third Denial.)
The commission said it believed the risks posed by NextEra’s acquisition outweighed the benefits, fearing that it would dilute Oncor’s credit profile and eliminate local control. The PUC insisted on strong ring-fencing provisions, including “a truly independent” Oncor board with control over decisions on capital expenditures and operating expenses — a requirement NextEra rejected as a “deal-killer.”
The DallasMorning News reported that BHE has agreed to 44 commitments to the PUC, including an independent board that would have complete control over how to use Oncor’s dividends. Only two of the 12 board members would be appointed by BHE, the paper said.
BHE says that it does not pay dividends “and can invest our profits back into our businesses to provide additional value for our customers. This relationship to our parent uniquely positions us to take a long-term view and to take on ambitious energy projects that other companies may not be able to afford.”
The company also reportedly committed to returning 90% of interest rate savings to customers in rate cuts until the next rate case after one currently pending is final. There would also be no involuntary layoffs or wage and benefit cuts for at least two years for Oncor’s 3,700 workers, the Morning News said.
“The bankruptcy court has to bless it, and it ultimately has to come to commission,” Geoffrey Gay, who represents the Oncor cities steering committee, told the paper. “If they follow the path of failures by Hunt and NextEra, they ought to be able to safely navigate through these obstacles.”
BHE contributed almost 10% of the earnings last year to Buffett’s Berkshire Hathaway conglomerate, whose holdings include GEICO, Kraft Heinz, Fruit of the Loom, Benjamin Moore and BNSF Railway. The company earned $24.07 billion last year, and its $223.6 billion in revenue last year ranked it No. 2 on the Fortune 500 list, behind only Walmart.
Texas Connections
In an apparent bid to curry favor with state regulators, the second paragraph of the press release announcing the deal noted the conglomerate’s other holdings with headquarters in Texas, listing 10 of them.
“Oncor is an excellent fit for Berkshire Hathaway, and we are pleased to make another long-term investment in Texas — when we invest in Texas, we invest big!” Buffett said in a statement. “Oncor is a great company with similar values and outstanding assets.”
| Buffett
Oncor CEO Bob Shapard said the merger would give his company “access to additional operational and financial resources as we continue to position Oncor to support the evolving energy needs of our state.”
“Being part of Berkshire Hathaway Energy is a great outcome for Oncor,” he added in a statement. “Oncor will remain a locally managed Texas company headquartered in Dallas, committed to the communities we serve, and our customers will continue to receive the safe and reliable service they have come to expect from our dedicated team of employees.”
Shapard, who announced plans to retire last October, will become executive chairman of the Oncor board. Senior Vice President and General Counsel Allen Nye will replace him as CEO, as previously announced, Oncor said.
Nye said he was “excited to begin the regulatory approval process,” adding “this transaction has significant support across our key stakeholders.”
Resolving Bankruptcy
Oncor has been ring-fenced since 2007, when EFH, a collaboration of several private-equity firms, acquired TXU Corp. in a leveraged buyout. EFH, saddled by nearly $50 billion in debt when it bet wrong on high gas prices, declared Chapter 11 bankruptcy in 2014.
Creditors last year reached a settlement of the bankruptcy contingent on Oncor’s sale. EFH has already spun off generator Luminant and retailer TXU Energy into a new publicly traded company, Vistra Energy. (See TXU Energy, Luminant Rebrand as Vistra Energy.)
With about 121,000 miles of transmission and distribution, Oncor owns and operates the grid for most of North Texas.
It would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, BHE held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
| Berkshire Hathaway Energy
BHE earned $2.29 billion last year, 9.5% of the conglomerate’s total. Had Oncor’s $431 million in profits been part of BHE in 2016, the energy unit would have generated 11.1% of the conglomerate’s earnings.
BHE is headed by CEO Greg Abel, who has been mentioned as a possible successor to the 86-year-old Buffett as chairman of Berkshire.
The Oncor purchase would be Berkshire’s largest acquisition since its $32 billion deal for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, Buffett told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
“Even at $9 billion, the takeover of Oncor … is tens of billions of dollars shy of the mega-deal Berkshire Hathaway Inc. shareholders have anticipated for more than a year,” Tara Lachapelle and Liam Denning wrote in a Bloomberg Gadfly column Friday. “Costco Wholesale Corp., 3M Co. and Hershey Co. are closer to the kinds of names investors had in mind for Berkshire’s next big transaction, as its cash pile grows uncomfortably high.”
MISO’s Independent Market Monitor still sees room for significant improvement after giving the RTO’s markets a passing grade for last year.
“Although the energy markets generally set efficient prices in 2016, we recommend improvements to MISO’s price formation through improved shortage pricing and price-setting by peaking resources,” Monitor David Patton said in his annual State of the Market report released last week, which included nine new recommendations.
The Monitor concluded that — based on the “output gap” measure of economic withholding (the difference between potential and actual energy output) — “potential” withholding of generation represented just 0.11% of load and scarcity mitigation was “infrequently implied.”
The report also showed that modest declines in fuel prices contributed to slightly lower energy prices, make-whole payments and congestion costs than in 2015. MISO’s peak load of 121 GW was slightly higher than the previous year but well below the forecasted peak of 125.9 GW because of mild weather and lower loads. Real-time congestion, however, rose 4.3% from 2015, totaling about $1.4 billion, “amongst the highest in the U.S.,” according to Patton, which he in part attributed to high outage rates in MISO South.
| Potomac Economics
The Monitor’s new market recommendations — many of them already familiar to MISO staff and stakeholders — join a rolling list of unimplemented recommendations dating back to 2010:
Improve shortage pricing by adopting an improved contingency reserve demand curve that reflects the expected value of lost load (VoLL). Patton recommended earlier this year that the RTO immediately up its $3,500/MWh VoLL limit to $9,000/MWh and change its operating reserve demand curve calculation to a sloped curve that he contends would better price shortages. (See MISO, IMM Differ over Scarcity Pricing Changes.)
Transfer control of market-to-market flowgates to improve procedures for M2M activation and coordination. The Monitor would like to see MISO, PJM and SPP become more active in transferring monitoring of constraints when the non-monitoring RTO has all of the transmission loading relief on a flowgate. Last month, MISO and SPP announced plans to begin swapping flowgate control. (See MISO Interregional Plans with SPP Echo PJM Efforts.)
File changes with FERC to give MISO increased authority to approve generation and transmission planned outages and the ability to coordinate outage schedules in order to lower costs. The Monitor said the move would reduce both outage-related congestion during peak outage season and capacity-related emergency events during the shoulder months. Currently, the RTO can only recommend outage schedules and work with operators to reschedule planned outages when reliability is at risk. Last month, both MISO and the Monitor expressed concern over higher-than-usual planned outages in MISO South during the spring. (See MISO South Outages Worry RTO, Monitor.) The Monitor reported that from January 2016 to May 2017, 25% of all real-time congestion ($457 million) could be traced to concurrent generation outages.
Establish regional reserve requirements, creating a local, 30-minute reserve product and developing procurement requirements in areas with voltage and local reliability needs. The Monitor said the reserve product will align the market with reliability needs, allow MISO to accurately price subregional shortages and “lower costs by allowing the markets to satisfy MISO’s reliability needs and reducing out-of-market actions by MISO operators.” Like several other 2016 State of the Market recommendations, this recommendation appeared earlier this year when the Monitor submitted it for consideration in the RTO’s Market Roadmap list of market changes. (See MISO Steering Committee OKs IMM Proposals for Market Roadmap.)
Change MISO’s Day-Ahead Margin Assistance Payment (DAMAP) and Real-Time Offer Revenue Sufficiency Guarantee Payment (RTORSGP) rules to compensate wind operators whose output more closely matches their day-ahead forecasts and reduce gaming opportunities and unjustified costs. Patton warned the RTO late last year that wind generators appeared to be deliberately over-forecasting their output to inflate payments made through revenue sufficiency guarantees. (See MISO IMM Sees Deliberate Over-Forecasting by Wind Operators.)
Increase the accuracy of MISO’s Look-Ahead Commitment recommendation, which was developed in 2012, and seek to improve resource commitment by modeling system conditions for a three-hour future time frame.
Improve forecasting incentives for wind resources by creating a method to validate wind supplier forecasts and use the results to alter dispatch instructions if needed, while improving forecasting incentives by modifying deviation thresholds and settlement rules.
Disqualify from the Planning Resource Auction any resources expected to be unavailable during peak conditions. MISO is currently shopping its own proposal to prohibit resources on extended outages from participating in future auctions or making changes to capture the risk of such outages in loss-of-load-expectation analyses. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
The Monitor also warned that the $1.50/MW-day footprint-wide clearing price in MISO’s spring capacity auction was too low to be sustainable.
“This is essentially zero. This is not an efficient price under current capacity levels and will motivate poor retirement and export decisions by MISO’s competitive suppliers,” Patton said.
Despite FERC’s rejection of a three-year forward market design for MISO’s retail-choice areas, the RTO should pursue “more reasonable and efficient alternatives,” he added.
In a decision that could boost prospects for controversial state policies favoring select types of electricity generation, the Second Circuit Court of Appeals last week rejected a suit claiming that a Connecticut renewable energy procurement law intruded on FERC’s authority.
A wind turbine installation on I-95 in Fair Haven, CT.
The June 28 ruling affirmed a lower court decision in favor of a Connecticut law that requires the state to solicit proposals for renewable energy projects and utilities to enter into bilateral contracts with the winners. Renewable energy developer Allco Finance challenged the law’s implementation as discriminatory (16-2946, 16-2949).
The court also lifted an injunction it issued last November that blocked the awarding of clean energy contracts by Connecticut, Massachusetts and Rhode Island. (See Court Halts New England Clean Energy Contracts.)
The court’s opinion — which reviewed the Connecticut program based on the Supreme Court’s 2016 decision in Hughes vs. Talen — could influence district courts that are considering motions related to New York and Illinois policies providing zero-emission credits (ZECs) to nuclear plants. (See Federal Suit Challenges NY Nuclear Subsidies.)
FERC Authority
Hughes vs. Talen found that a Maryland plan to spur construction of new natural gas-fired generation encroached on FERC’s authority over wholesale prices under the Federal Power Act. But the Second Circuit ruling identified a key distinction between the Maryland and Connecticut programs.
“While Maryland sought essentially to override the terms set by the FERC-approved PJM auction, and required transfer of ownership through the FERC-approved auction, Connecticut’s program does not condition capacity transfers on any such auction,” the appeals court said. “Connecticut, instead, transfers ownership of electricity from one party to another by contract, independent of the auction.”
Furthermore, the contracts stemming from the requests for proposals are just the kind of bilateral agreements already subject to FERC oversight, the court said.
And while the appeals court affirmed that “states may not regulate interstate wholesale sales of electricity unless Congress creates an exception to the FPA,” it also determined that the Public Utility Regulatory Policies Act “contains such an exception, permitting states to foster electric generation by certain power production facilities … that have no more than 80 MW of capacity and use renewable generation technology.”
“The decision comes out on the right side legally, clearly on the better side for the states who want to set up programs to encourage renewable energy,” said Seth Jaffe of the law firm Foley Hoag, who wrote a blog post on the case. “The court properly noted that the state really wasn’t getting in the way of FERC setting wholesale prices.”
In a June 30 blog post, John Moore of the Natural Resources Defense Council wrote that “contrary to the claims of some generators who would like to see state energy laws invalidated per Hughes, the 2nd Circuit made clear that Hughes applies only to a narrow class of state schemes that, like Maryland’s, seek to ‘override’ the rate set by the FERC-approved auction and instead guarantee a generator a wholly different rate — not policies like the Connecticut clean energy programs.”
Dormant Commerce Clause Claims Rejected
The Second Circuit also rejected Allco’s claims that Connecticut violated the dormant Commerce Clause of the U.S. Constitution: the idea that states may not pass laws discriminating against interstate commerce to protect intrastate commerce. Allco argued Connecticut’s law violated the clause by making the state’s acceptance of renewable energy credits (RECs) contingent on the ability of a generator to deliver its electricity to the New England grid.
SunPower “Intelegant” award-winning installation in Westport, CT.
Allco claimed that Connecticut’s rules discriminated against the company’s solar facility in Georgia by not letting its RECs count toward Connecticut utilities’ renewable portfolio standard requirements. The company also argued that Connecticut discriminated against Allco’s New York facility in requiring producers of RECs in adjacent control areas to pay transmission fees in order to sell their credits to Connecticut utilities.
The Second Circuit first considered “whether the allegedly competing entities — Allco’s Georgia generator, on the one hand, and generators located in ISO-NE and adjacent control areas, on the other — provide different products, i.e., different RECs. We find that they do.” (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)
The opinion gave “greater weight” to the market for RECs produced by generators able to connect to Connecticut’s grid and noted that “Connecticut’s RPS program makes geographic distinctions between RECs only insofar as it piggybacks on top of geographic lines drawn by ISO-NE and the [New England Power Pool], both of which are supervised by FERC — not the state of Connecticut.”
Regarding the court’s dormant Commerce Clause finding, Jaffe said, “I think they got it right; the reasoning is pretty sound, but I can certainly imagine people continuing to litigate this.”
The decision said it recognized “the importance of Connecticut’s interest in protecting the market for RECs produced within the ISO-NE or in adjacent areas. Connecticut’s RPS program serves its legitimate interest in promoting increased production of renewable power generation in the region.”
The court’s arguments in favor of the Connecticut program “are not that different from arguments that we’ve sometimes seen rejected by the courts, in saying, ‘Well, we understand the policy preference, but you’re not allowed to essentially discriminate,’” Jaffe said.
[Editor’s Note: An earlier version of this story said the ruling was by the D.C. Circuit Court of Appeals.]
DENVER — SPP and Peak Reliability extolled their virtues as reliability coordinators (RCs) before the Colorado Public Utilities Commission last week in a bid to provide the reliability function for the Mountain West Transmission Group.
Peak Reliability is Mountain West’s current RC. SPP would include the RC function among the bundled services it would provide Mountain West, should the informal collaboration of Western utilities eventually become members of the RTO. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)
The courtship is leaving the Colorado PUC a little queasy.
“This is like if your child potentially dates, if not marries, the wrong person,” Chairman Jeff Ackermann said in wrapping up the information session. “Take that wherever you want to go, but ultimately, consenting adults do what consenting adults want to do.”
“We may not want to pay for the wedding,” Commissioner Frances Koncilja pointed out.
Mountain West — comprising eight investor-owned utilities, municipalities, generation and transmission cooperatives, federal power marketing administration projects, and their subsidiaries — announced in January that it was beginning discussions with SPP about potentially joining the RTO. The group expects to arrive at a decision by October.
| WAPA
However, Koncilja prodded a panel of Mountain West representatives as to when the commission would see financial numbers coming out of the negotiations with SPP.
“I share your sense of urgency,” said Steve Beuning, director of market operations for Mountain West member Xcel Energy, offering no further response.
Peak Reliability currently provides only RC services to Mountain West for about 5 cents an hour, CEO Marie Jordan said.
If SPP is to assume RC responsibilities for Mountain West, its members “would continue to pay what they pay Peak now,” according to SPP COO Carl Monroe.
“What they save is anything they would have to do if we were not the RC,” Monroe said, reminding the commission that SPP would also likely be running the balancing authority and the markets, besides other functions. “I know when we have to provide the functions we provide, we can do it more cost-effectively and more reliably than if we [were just the RC].”
Monroe said SPP’s “first line of defense” against reliability concerns is to let the market take action by resolving binding constraints through economic dispatch, which uses the lowest-cost generation facilities to meet consumer demand while recognizing any operational limits.
“The market itself provides you that mechanism. The market, for us, is a tool to maintain enhanced reliability,” he said.
Beuning pointed out that economic dispatch is “the missing piece in our tool kit.” The Western Electricity Coordinating Council, which has served as the Western Interconnection’s Regional Entity since 2007, has yet to implement economic dispatch. Peak was spun off as an independent RC from the WECC in 2014.
Economic dispatch “is the one thing that comes along with being a market operator,” Beuning said. “It’s my belief and opinion that at this point, we could obtain an integrated service at a lower cost for our customers, instead of paying for RC services or paying the Peak.”
“It would be a lost opportunity cost for us to not bundle those services together,” said Denton McGregor, reliability center manager for Mountain West member Black Hills Power.
Status Quo — or No
Jordan touted Peak’s experience as Mountain West’s incumbent RC and the knowledge it has gained providing the same service for the Western Interconnection. She said Peak continuing as the region’s single RC would address reliability concerns caused by the continued addition of renewable and intermittent resources, and it would provide a “single, unbiased” entity focused exclusively on reliability coordination.
“A single RC has been a very important piece of the vision for reliability in the West,” Jordan said. “The biggest concern is how the interconnection continues to bring on [renewables]. I also don’t want to underestimate how knowledge grows … we’re mature in our tools, we’re mature in our sophistication and we have learned. Based on feedback I get from our funding members, our model is becoming so much more reliable for them, from the time we started … to where we are today. It’s been tremendous growth.”
A nonprofit organization like SPP, Peak is responsible for an area of 1.6 million square miles that includes all or parts of 14 western states, Canada’s British Columbia and the northern portion of Baja California, Mexico. It oversees more than 110,000 miles of transmission lines, with centers in Vancouver, Wash., and Loveland, Colo.
For his part, Monroe played up SPP’s experience as both an RC and a market operator, underscoring the understanding the RTO gained integrating RC services in the Western Interconnection with the 2015 addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)
“Reliability for us is job [No.] 1,” he said. “When we’ve added things, we’ve done so in a manner that protects reliability or enhances reliability. Part of the benefits Mountain West is looking to get are those benefits at a cheaper cost to the consumers themselves. Everything we do is designed to enhance reliability at a cheaper cost.”
WECC CEO Jim Robb said costs would likely increase for Mountain West members should SPP become their RC.
“The cost of providing RC services isn’t particularly scalable,” he said. “I can’t see Peak’s cost structure changed, but it seems to me the pressures in aggregate go up. How they are allocated among customers remains to be seen.”
And that’s an issue for the Colorado PUC.
“We’re concerned about how these costs roll out and which ones end up back here in this room at some point in the future,” Ackermann said.
Monroe said SPP would incur additional costs should it separate the RC function from the market and balancing authority functions. He said there is a benefit to having multiple RCs in an interconnection, as evidenced by the 13 RCs in the Eastern Interconnection.
“We think [multiple RCs] reduces risk because now you have two different organizations and two different systems looking over that whole area,” he said. “In the East, we reduce the risk because we have people helping us do that. We’ve never been in an environment where we weren’t coordinating with other parties.”
Negative Consequences
Losing Mountain West would cost Peak — which has operated with a $44.6 million budget for each of the last two years — about 10% of its load.
“It’s negative to the interconnection, [and] it’s negative to area reliability — and not just for the Mountain West,” Jordan told RTO Insider. “We’ve taken full responsibility to keep this grid functioning reliably, and that’s a consensus shared by our members.”
The PUC has tentatively scheduled a third information session on Mountain West’s proposal to join SPP. The Aug. 24 session will focus on governance issues.
SPP will be holding its leadership meetings at the Colorado Convention Center and a nearby hotel in Denver next month. As he did during the PUC’s first information session in March, Monroe invited those in the room to attend the meetings and see how the RTO governs itself. He said SPP set aside 190 seats for the July 11-12 Markets and Operations Policy Committee meeting, with 170 attendees having already registered.
SPP stakeholders last week spent two hours discussing the need for a high-priority congestion study in the Texas Panhandle, only to determine that more discussion is needed.
The Strategic Planning Committee scheduled the two-hour conference call June 26 to review the study’s scope and its scenarios. Despite stakeholder suggestions to relitigate the requirement for the study and consider alternative study methods, SPC Chair Mike Wise successfully kept the group on task.
“These other issues are part [of the discussion] but very tangential,” said Wise, senior vice president of regulatory and market strategy for Golden Spread Electric Cooperative. “We can have a fuller discussion at the next SPC meeting.”
The committee added time to its July 13 face-to-face meeting in Denver, following a two-day Markets and Operations Policy Committee meeting. Members plan to discuss a suggestion by American Electric Power’s Richard Ross that the congestion study evaluate confirmed service and unfilled hedges.
SPP’s Board of Directors directed staff in April to conduct the high-priority study after it canceled a 345-kV transmission project in the area. Chairman Jim Eckelberger agreed the study should take a systemwide look at congestion caused by the proliferation of wind farms. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)
“I’d rather take a little more extra time and do it right, rather than punch on,” SPP Director Larry Altenbaumer said. “I appreciate the complexity of issues out there, but we have to decide how best to deal with the continued growth of wind in our footprint.”
Staff is currently analyzing the saturation point for renewables sinking within SPP to determine at what point the additional generation would “no longer be economic,” SPP Director of Engineering Antoine Lucas said.
“Until then, continue to expect additional requests and more renewables added to the system,” he said. “Renewables are now replacing other renewables at similar price points.”
“This wind is coming on,” the Wind Coalition’s Steve Gaw said. “It doesn’t make sense to not consider its impact on the system. The potential benefits shouldn’t be ignored.”
The SPC did not come to an agreement on the study scenarios. Staff is recommending developing three scenarios from the five thresholds for interconnection costs of renewable energy, ranging up to $100,000/MW. SPP says the previous 7.6 GW of wind placed in service had an average cost of $32,500/MW. Connecting the total studied capacity of 43.3 GW would cost more than $1 million/MW to in part account for needed investment in new transmission infrastructure.
| SPP
SPP Vice President of Engineering Lanny Nickell said staff is looking at known constraints, rather than future generation, to ease its workload. He said 5.5 GW of wind projects have interconnection agreements and are meeting their milestones.
During the weekend before the call, SPP members Empire District Electric, Kansas City Power & Light, Oklahoma Gas & Electric, Southwestern Public Service and Westar Energy submitted a letter to the SPC and the board’s Members Committee, questioning the value of the study. Signatories said previous staff analysis of congestion in the area showed a benefit only when the models included “extraordinarily high levels of wind.” They said SPP’s next 10-year assessment of transmission needs would “provide a comprehensive solution for the region.”
“We are concerned that a special high-priority study will circumvent the generator interconnection and aggregate study processes that are used to identify cost-causers and the assignment of costs,” the letter said.
Z2 Task Force Suggests its own Retirement
The Z2 Task Force will this month recommend to SPP leadership and stakeholders two alternatives for assigning financial credits and obligations for sponsored transmission upgrades under Attachment Z2 of the RTO’s Tariff.
The group also agreed during its June 27 meeting in Dallas to let its charter expire at the end of July, unless otherwise directed by the board or MOPC.
The group has spent its last few meetings discussing the pros and cons of the two staff-suggested alternatives: granting Z2 credits only to upgrades that increase transfer capability and creating credit payment obligations under a Tariff schedule. (See SPP Members Send Z2 Alternatives to MOPC.)
Task force Chair Denise Buffington, corporate counsel at KCP&L, said she was disappointed the group was “unable to accomplish more.”
“It seems impossible to get folks to pull away from current parochial impacts to focus on the underlying policy decision: Do we want to socialize or subsidize these types of projects, or provide a market mechanism?” Buffington said. “There is no sense beating a dead horse. There is no support for it at this time.”
MMU: Wind Generation up, Coal Production down
SPP wind generation continues to increase at the expense of coal, the RTO’s Market Monitoring Unit said.
Wind accounted for 28% of all energy produced in SPP’s market this spring, up from 22% in 2016 and 15% in 2015. Coal’s share of output has meanwhile dropped to 40%, down from 57% just two years ago.
SPP recorded a North American RTO-high for wind penetration on March 19, when wind accounted for 54.2% of the market’s energy production.
The MMU’s State of the Market report, covering the months of March, April and May, also revealed that rising gas prices have led to a corresponding increase in LMPs.
Gas prices at the Panhandle hub have averaged $2.70/MMBtu this spring, compared to $1.68/MMBtu last year. At the same time, average real-time LMPs increased from $17.07/MWh to $23.48/MWh, while day-ahead prices rose from $17.37/MWh to $23.47/MWh.
POUGHKEEPSIE, N.Y. — While renewable resources currently have only a limited impact on the New York grid, that’s set to change as the state advances on its clean energy goals, industry experts said at a conference last week.
The amount of solar in NYISO’s interconnection queue has nearly doubled within the past three months — from 850 MW to 1,600 MW, CEO Brad Jones said at the Renewable Energy Conference. The Business Council of New York State and the Hudson Renewable Energy Institute hosted the June 28 event at Marist College.
Solar and wind together now account for around 5% of the state’s generation, compared with a 20% share for hydropower. That “5% piece of the pie has to grow incredibly, by as much as five times what it is today,” to reach the state’s Clean Energy Standard goal of having 50% of generation derived from renewable resources by 2030, Jones said.
“On the wind side, we’ve got 3,300 MW of wind in our queue, and that’s not including whatever the state may do with offshore wind,” he added. Gov. Andrew Cuomo earlier this year set a target of building 2,400 MW of offshore wind capacity by 2030.
The Marist campus on the Hudson River sits in the middle of Central Hudson Gas & Electric’s service area. The utility serves only 3% of the state’s load but leads the state in terms of photovoltaic integration.
“We have over 6,000 [solar] installations interconnected to the grid today … about 66 MW,” Paul Haering, Central Hudson senior vice president of engineering, said during a presentation. “So while you think that would have a dramatic impact in terms of our peak load, the reality is, when the sun shines is not when everyone’s turning their air conditioners on and coming home from work.”
Maximum summer demand for the utility typically occurs at 7 or 8 p.m. The mismatch between PV output and peak usage represents a challenge for how to integrate distributed energy resources while minimizing the need for new transmission infrastructure, according to Haering.
“But if I’m going to replace assets, I replace it with current standards,” Haering said. “That means larger wire size and higher-voltage circuits that help us to integrate more PV, which gives me better thermal and voltage profiles in order to be able to support the integration of more PV on the system.”
And Central Hudson is adapting the grid to DERs through enhanced intelligence of the distribution grid itself rather than smart meters.
“We have technology now that allows for bidirectional flow of power on the system,” Haering said. “We built the grid for one-way power flows, so now with power coming the other way, we use bidirectional regulators and switch capacitators and substation path changers that have the capability to sense bidirectional flow and respond accordingly.”
In the past two years, National Grid has interconnected more solar than gas-fired generation in New York, said Melanie Littlejohn, the utility’s vice president of community and customer management for the state. That trend motivated National Grid to invest $100 million in Sunrun, the nation’s largest residential solar company. Storage is a key part of Sunrun’s portfolio, Littlejohn noted. (See NY Bill Sets Stage for Storage Targets.)
Littlejohn also pointed out that the North Country region has the most electric vehicles in Upstate New York, prompting the utility to install 68 charging stations in downtown Syracuse, in partnership with the federally supported Clean Cities coalition, which runs the utility’s stations throughout the state.
Who Pays?
Asked how National Grid manages the effect of renewable energy programs on customer rates, Littlejohn said, “Very gently. … More than 30% of our Upstate New York customer base lives at or below the poverty level.”
Tina Palmero, deputy director of the state’s Office of Clean Energy, said the New York State Energy and Research Development Agency is working to meet the governor’s ambitious offshore wind target by 2030: “And of course we have to think of rate impacts as well.”
One option for controlling costs could entail increased financial support for existing nonemitting resources. Regulators are looking at the operations of so-called Tier II generators, which consist mostly of small hydropower facilities, many of them family-run. “If it’s cheaper to keep them open than seeing them cease operation and having to procure new renewables, the commission will look at that and consider whether or not they should get some additional subsidy,” Palermo said.
Diane Burman of the New York Public Service Commission said that providing the best possible electric service to customers “is what it’s all about.”
Burman, who was recently confirmed for a second six-year term as commission, said she hopes to re-examine what the PSC can do in “giving the flexibility to others, so that we are not dictating the technology, maybe even the brand that should be used. That’s not helpful.”
Sweltering temperatures led to three new ERCOT demand records in quick succession during June. The ISO has set eight highs for monthly demand during the last 12 months.
The Texas grid operator recorded consecutive peaks of 66.7 GW, 67.5 GW and 67.7 GW during the afternoon of June 23. The final number, and new record, came during the 4 p.m. hour, breaking the previous record of 66.5 GW set in June 2012.
ERCOT stakeholders unanimously approved a pair of revision requests in an email vote last week, following the earlier cancellation of the monthly scheduled Technical Advisory Committee meeting.
Both changes were approved by 22-0 margins. The TAC has 30 voting members.
NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. Adds solar resource registration inputs omitted from the greybox tab for RRGRR009.
The growth of distributed energy resources on the California grid will require new approaches and better coordination between system operators to avoid problems, state officials heard last week at a California Energy Commission workshop.
Representatives from utilities, DER companies and others advised members of the CEC and the California Public Utilities Commission on the various issues related to integration of new technology onto the electric grid.
The grid is becoming more decentralized, and the amount of DERs — including rooftop solar, energy storage and a host of other technologies — is expected to grow significantly in California in the next three to five years. Fleshing out communication methods between transmission operators, distribution utilities, DER providers and CAISO is one of the biggest tasks associated with incorporating the new systems.
The Amount of DER Including Rooftop Solar is Projected To Keep Growing
DER companies are trying to open new markets at various points in the electricity delivery system, including selling to utilities and retail customers, as well as through development of market mechanisms at CAISO. The ISO wants to enable that process to help balance output from renewables, and next month will present its Board of Governors with a suite of related new rules stemming from its Energy Storage and Distributed Energy Resources (ESDER) Phase 2 initiative. (See CAISO Finalizes Rules for DR, Distributed Generation.)
Distribution system operators (DSOs) should be able to advise DER providers and communicate with them on grid integration and operational issues, Pacific Gas and Electric Director of Integrated Grid Planning Mark Esguerra said. CAISO should also provide day-ahead DER schedules to DSOs, as well as develop a pro forma DER integration agreement.
The ISO often dispatches DERs without knowing if they are feasible on the distribution system and when there is little visibility on their effect on load and the transmission-distribution interface, Esguerra said. DERs are different from demand response and energy efficiency resources because distributed energy is not an absence of load, but rather additional energy being put into the system that must be managed.
Tesla Business Development Manager Damon Franz said DERs can mitigate the effects of energy infrastructure on water and the environment. He also argued they provide a wide range of services, including backup power, lowering energy costs and managing the intermittency of renewables.
Franz highlighted the importance of data on what needs DERs can satisfy. He requested that permitting be made easier and said interconnection for energy storage “should be no more complicated than simply deploying a device.”
But Jim Baak, program director at Vote Solar, noted that California utilities are being asked or required to forego capital investment in favor of DERs, which might not be in the interest of their shareholders. There should be a wider focus beyond policies and process changes, and state policy objectives should align with financial goals of stakeholders, he said. There are also concerns about overinvestment in DERs in the wrong locations.
“My concern is the vision is somewhat myopic,” he said. “What we really hope to achieve with distributed resources is to achieve policy goals.”
James Barner, resource planning engineer with the Los Angeles Department of Water and Power (LADWP), said that without an engaged interconnection process, DERs will affect reliability, including the problem of overgeneration at certain times. The utility plans to have 1,500 MW of distributed solar in the next 15 years, but DERs do create new problems on the system, he said, and rooftop and carport solar cannot be curtailed.
LADWP recognizes that DERs “add a lot of diversity to our renewables portfolio,” he said. Renewables represented 21% of the utility’s portfolio in 2016, but that is expected to grow to 65% by 2036. The utility plans to soon issue a Distributed Energy Resources Integration Study.
POUGHKEEPSIE, N.Y. — New York’s push to derive half its electricity from clean energy by 2030 must be accompanied by regulatory consistency to develop the necessary resources, panelists said at an energy forum last week.
State regulatory policy contains inherent conflicts that hinder renewable development, Paul DeCotis, senior director of energy and utilities at West Monroe Partners, said during the June 28 Renewable Energy Conference, hosted by the Business Council of New York State and the Hudson Renewable Energy Institute at Marist College.
DeCotis, who formerly served as energy secretary and chair of the state energy planning board for two New York governors, led a panel on regulatory structure.
Speaking about Long Island solar projects unlikely to be built because they’re proposed for green space, DeCotis said, “It goes against the policy of the state of New York on the one hand, in terms of renewable energy development, but it supports other green space initiatives. There’s always going to be an inherent policy conflict, which makes these goals even more difficult to attain. So it does take some certainty of regulatory environment, and it takes time.”
DeCotis noted that he and fellow panelist Paul Curran — managing partner of BQ Energy, a Poughkeepsie-based developer of wind and solar projects on brownfield sites — started talking about the state’s need for additional transmission infrastructure investments in 2007. Those projects are likely to come online in 2020.
“That’s 13 years for transmission to be built,” DeCotis said.
Consistency is Key
“I can play by any rules … but to the extent that the rules keep changing, it gets very difficult,” Curran said. “From a regulatory point of view, we love consistency.”
Regarding the troubled solar projects on Long Island, Curran said green space is the wrong location for renewable energy.
“There’s landfills all over the place; there’s brownfields all over the place — that’s the right place,” he said.
BQ didn’t build any transmission lines at the 35-MW wind farm it constructed in Buffalo. The developer spent just $1 to buy disused substations from a shuttered steel plant that used to draw 300 MW.
“We do the same thing with landfills,” Curran said. “There’s five or six landfills in the middle of New York City, nothing else can be done with them … but the closer we get to load centers, New York City, Boston, etc., the more people like Central Hudson [Gas & Electric] value the electricity,” adding that NYISO also recognizes the value of siting generation closer to where it’s consumed.
David Pacyna, CEO of North American T&D Group, said that when he talks to utilities about buying technology, “the concept of interconnecting renewables to make the utility assets perform properly under those scenarios of intermittency and so forth are, if not at the top of the list, very close to it.”
NATDG is a private equity fund that buys into technology service providers that sell to utilities in the U.S. and around the world. Prior to working for the company, Pacyna spent 30 years with Westinghouse Electric and Siemens and supervised construction of the Neptune project connecting Long Island with PJM, the Hudson transmission project and the Trans Bay Cable under San Francisco Bay.
“What does take it in hardware and software to make those rules that frustrate all but actually result in electricity coming out of the light socket?” asked Pacyna. “There’s a growing recognition [by regulators] of the need to invest in the grid.”
On rate designs, Pacyna said regulators in states such as Missouri and Illinois are starting to ask how they can best structure rates to incentivize investment in both grid modernization versus the grid of the future.
“Regulators also are asking how they can use performance-based rates to support investment in distributed energy and renewable resources,” he said.
Ray Wuslich, partner at Winston & Strawn, thought it would be easy to make a presentation in Poughkeepsie about the impact of the Trump administration on the power industry. But when he looked at President Trump’s energy policies, he found “there wasn’t much to go on.”
“We haven’t had any big ideas in the energy space, in energy policy, in over 25 years … really going back to the 1980s when FERC and Congress started looking at competition on the natural gas side and unbundling supplies from the pipeline transportation business,” Wuslich said. “It was crystalized in the Energy Policy Act of 1992 … and everything we’ve been doing since then has been evolutions of that.”
Former President Barack Obama pushed EPA’s Clean Power Plan, which Trump made a campaign issue for its impact on the coal industry, Wuslich noted. Now that Trump has called for repeal of the CPP, which may take up to five years to achieve, “the question is, can the repeal of that rule really save the coal industry and resurrect coal-fired generation?”
Wuslich cited the obstacles facing coal: economics (that is, cheaper, more efficient natural gas); an aging coal fleet; unfavorable state policies; renewable portfolio standards in 29 states and D.C.; major corporations that are focusing on sustainability and clean energy; and the apathy of utility executives, who are not rushing out to build new coal plants.
He noted that a recent Energy Information Administration report said repeal of the CPP could boost the prospects for coal.
“But does this make sense? Does this reflect reality, given where we are in the marketplace?” Wuslich asked. “There’s hardly a week goes by where you don’t see another blurb in the trade press that so and so is going to shut down 500 MW of coal, or 300 or 1,500 or whatever. It’s just a constant drip of these plants retiring, and that’s because of the market.”
