Texas regulators on Wednesday agreed to reconsider its recent rejection of a proposed acquisition of Oncor by Florida-based NextEra Energy, which sought a review of the decision.
The state’s Public Utility Commission will rehear the case (Docket 46238) during its May 18 open meeting, the first without longtime Chairman Donna Nelson, who is retiring May 15. No replacement has yet been named to the three-person panel. (See Texas PUC Chair Nelson Stepping Down.)
The PUC last month unanimously rejected NextEra’s $18.7 billion bid for the Texas utility, saying the risks outweighed the promised benefits. (See Texas Commission Denies NextEra’s Bid for Oncor.)
In a filing made earlier this week, NextEra said the commission went beyond the scope of its powers when it found the acquisition not to be in the public interest, calling the PUC’s order “unprecedented.”
“The order represents an expansion of power that exceeds the limits set by the Legislature and the bounds of the commission’s own precedent,” NextEra said, listing 14 points of error ranging from “the exercise of authority not granted by the Legislature to reliance on facts not in evidence.”
The company said the order also ignores “Moody’s determination that NextEra Energy’s acquisition … will unequivocally benefit Oncor,” and that it fails “to give any consideration to the benefits and protections” of the 73 regulatory commitments the company made to the PUC.
NextEra requested the commission give it as much time as allowed by law to “encourage possible settlement discussions.”
At stake is a $275 million termination fee that NextEra would be liable for should the deal fail for certain reasons.
The PUC has until June 7 to act on NextEra’s request.
Oncor’s future is central to parent company Energy Future Holdings’ bid to exit Chapter 11 bankruptcy proceedings, which have now dragged on for three years. The PUC rejected Hunt Consolidated’s bid for Oncor last year.
Duke Energy is asking North Carolina officials to revisit state rules around renewables and provide the utility with greater control over what generation resources it must use, company executives said during a first-quarter earnings call Tuesday.
The largest utility in the U.S. posted a first-quarter profit of $716 million ($1.02/share) compared with $694 million ($1.01/share) a year ago. The increase was helped in part by last year’s acquisition of Piedmont Natural Gas.
Adjusted earnings per share were $1.04, down from $1.13 in the first quarter of 2016 and just missing analyst expectations. Executives attributed the decline to mild weather — along with the sale of Duke’s international energy business in December — and announced plans to cut about $100 million in expenses.
Turbine blades prepared for installation at Duke’s Frontier Windpower Project in Oklahoma | Duke Energy
Duke’s electric business reported income of $635 million, down $9 million year over year, while earnings at its commercial renewable energy arm, which sells solar and wind power to other utilities and corporate customers, fell by $1 million to $25 million.
The company is pursuing two separate actions through North Carolina’s government to exert increased control over the generation it must use to serve customers.
First, Duke has asked the North Carolina Utilities Commission to reduce what the utility must pay qualified facilities under the Public Utility Regulatory Policies Act, which requires electric utilities to pay such facilities the avoided costs of not building traditional power plants. In its filing, Duke said that rate has dropped to $35/MWh from currently recognized rates of $55 to $85.
Company CEO Lynn Good said that action went to hearing in mid-April.
Duke is also lobbying members of the state legislature to develop an annual competitive process that sets out a determined volume of renewable resources.
“What’s being proposed is an opportunity to move this development of renewables and solar in the state into a more sustainable model,” Good said. “A competitive process would impact [the] price to customers and [we] believe that better planning and better pricing would create a more sustainable market. … We believe it’s costing customers about $1 billion more than a market price would cost them over a 12-year period.”
The explanation came as Good and other company executives described plans to shift renewable investment toward regulated jurisdictions rather than commercial. Duke has $2.5 billion slated in its five-year plan for such investments, about $1.5 billion for regulated regions and $1 billion in commercial.
Duke’s solar facility at Camp Lejeune in North Carolina
“Returns are tight, [and] the tax position is uncertain for us at least over the next couple of years,” Good said. “We feel like we have a really strong portfolio of 3,000 MW [of] wind and solar, backed by a long-term contract.”
Good noted that the “majority” of Duke’s revenue in renewables comes from wind production tax credits as investment tax credits from solar construction dropped by a penny year over year.
Duke Energy line worker | Duke Energy
She highlighted a $25 billion, 10-year plan for grid modernization, which includes investments to automatically reroute power and accelerate grid restoration when necessary. She also described plans to spend $4.9 billion to bury underground “select sections of poorly performing overhead lines, many located in hard-to-access areas” in the Carolinas.
“We found that our heaviest concentration of densely vegetated lands that cause outages are really preponderantly in the Carolinas,” said Lee Mazzocchi, of the company’s Grid Solutions group.
While Good touted a 2016 safety achievement award for Duke’s Midwestern local distribution companies, she omitted any discussion of environmental safety issues at coal ash piles that the company estimates will cost $5 billion to address. Only one question from analysts touched on the subject, and that was simply to ask if the company’s plans were changing in light of potential changes on the federal level.
American Electric Power and Dynegy on Tuesday completed the transfer of their stakes in a pair of Ohio coal-fired plants that the two companies own in common.
The transfer is part of AEP’s strategic review of its merchant assets.
AEP sold its 330-MW (25.4%) share of the Zimmer plant and will assume Dynegy’s 312-MW (40%) interest in the Conesville plant. As part of the deal, AEP returned a $58 million letter of credit to Dynegy.
AEP’s Conesville Plant | Ohio Citizen Action
Columbus, Ohio-based AEP now owns 92% of Conesville’s four units, with Dayton Power & Light holding the remaining 129 MW of Unit 4.
AEP’s other competitive assets in Ohio include a 595-MW unit of the Cardinal plant near Brilliant, Ohio; 603 MW of the Stuart plant near Aberdeen, Ohio; and a 48-MW hydro plant near Racine, Ohio.
The Stuart plant, of which AEP owns a 26% share, is expected to be retired by June 2018.
AEP CEO Nick Akins made reference to the swap during the company’s April 27 earnings call with financial analysts when he said, “We continue to explore our strategic alternatives with [Conesville and Cardinal] and, in the case of Cardinal, seeking ways to enable a more modern and efficient relationship … as we explore our strategic alternatives in parallel.”
AEP created its competitive generation company, AEP Generation Resources, in early 2014 after separating its distribution and transmission operations in Ohio from its AEP Ohio-owned generation assets.
MISO’s summer planning reserve margins will remain firmly above requirements even after it shaved nearly half a percentage point from an initial assessment for the season.
Reserve margins could range anywhere from 14.1 to 19.7% throughout the summer, and MISO sees a high probability (79.3%) for calling up load-modifying resources and a much lower one (12%) for exhausting its 10.2 GW of LMRs and dipping into operating reserves. The chance of load shedding stands at 5%.
| MISO
Based on forecasts for above-normal temperatures in its footprint this summer, the RTO expects peak demand to hit 125.1 GW, with 148.5 GW of available capacity on hand to meet it. Summer demand peaked at 120.7 GW last year.
“We are expecting to have sufficient resources in the footprint,” Todd Ramey, MISO vice president of system operations, said during an annual summer readiness workshop on May 8.
While forecasts for declining demand are driving up the base reserve margin, the increased Midwest-South regional transfer limit is providing extra wiggle room, the RTO said.
“We appreciate the ongoing efforts of load-serving entities and states to ensure adequate resources are in place,” Ramey said in a press release.
The forecasted above-normal summer temperatures “can pose some operational challenges,” said Darius Monson, MISO resource adequacy adviser. “It’s worth noting, in a high-load scenario, we are planning to rely heavily on demand response resources.”
The summer reserve estimates include total firm imports, DR and energy efficiency resources based on cleared megawatts in the 2017/18 capacity auction. Non-firm deliveries were excluded from the summer assessment.
“In reality, there might be additional non-firm support,” Monson said.
The RTO also assumed that planned and forced outages would be consistent with the previous five years, and that no MISO South capacity would be stranded in a post-outage situation.
MISO will also hold realistic hurricane simulations with MISO South operators May 23-24 and June 20-21, a first for the RTO, which ordinarily holds less-detailed hurricane drills, according to Marty Sas, senior manager of South reliability coordination. The exercise will start with an intact system and simulate a 31-hour storm that takes nearly 200 transmission lines and 25 generators out of service.
ALBANY, N.Y. — Gov. Andrew Cuomo has nominated John Rhodes, CEO of the New York State Energy Research and Development Authority, to chair the Public Service Commission, NYSERDA Chairman Richard Kauffman said Wednesday.
Rhodes | NYSERDA
“John represents continuity,” Kauffman told several hundred attendees at the Independent Power Producers of New York annual meeting. “If you know his background, he’s someone committed to markets.”
The PSC has been operating with only interim Chair Gregg Sayre and Commissioner Diane Burman since March, when Chair Audrey Zibelman resigned and Commissioner Patricia Acampora retired. The commission also has had a two-year-long vacancy. (See NY REV Won’t Lose Momentum, Departing Zibelman Says.)
The Cuomo administration has taken a position that the two existing commissioners are sufficient for a quorum, but that interpretation “hasn’t been tested,” said state Sen. Joseph Griffo (R), chairman of the Senate Committee on Energy and Telecommunications, who spoke to the IPPNY conference before Kauffman.
Kauffman said Cuomo, a Democrat, intends to name nominees for the other two vacant seats soon enough to ensure their confirmation before the end of the current legislative session in June.
But Griffo said that the Senate will “carefully vet” Cuomo’s nominees. “It’s not going to be a pro forma type of submission,” he said.
Rhodes has run NYSERDA since September 2013, following stints as director for the Center for Market Innovation at the Natural Resources Defense Council and chief operating officer at Good Energies, an investment firm focused on renewable energy and energy efficiency.
He is a former partner at Booz Allen Hamilton and has also worked as a trader and general manager at Metallgesellschaft, a German mining, metals and engineering firm. He has a bachelor’s degree in history from Princeton University and a master’s degree in management from Yale.
CAISO’s wholesale costs to serve load last year fell by 9% to $7.4 billion, the lowest nominal expense since 2008, according to an annual market performance report from the ISO’s internal Monitor.
The Department of Market Monitoring also used the report to signal its growing support for lifting FERC-imposed bidding restrictions on some participants in the Western Energy Imbalance Market (EIM).
The Monitor attributed much of the drop in wholesale costs to a 9% decline in prices for natural gas, with increased output form solar and hydroelectric resources and decreased transmission congestion also contributing. Electricity prices averaged $34/MWh over the year, down $3 from 2015.
The report noted the impact of CAISO’s growing number of low-cost solar resources, which accounted for about 83% of the 2,300 MW of new summer peak generating capacity installed in the ISO during 2016, along with 300 MW of newly built gas-fired peaking generation and 50 MW of additional energy storage.
“Solar energy is expected to continue to increase at a high rate during the next few years as a result of projects under construction to meet California’s renewable portfolio standards,” the Monitor said in its report. “This continues to increase the need for flexible and fast ramping capacity that can be dispatched by the ISO to integrate increased amounts of variable energy efficiently and reliably.”
Renewable integration efforts during the first half of 2016 drove sharp increases in ancillary services costs, which nearly doubled to $119 million, accounting for 1.6% of total wholesale energy costs, compared with 0.7% in 2015.
During the second quarter, ancillary services costs averaged 81 cents/MWh, more than 50% above the yearly average. The increase in large part stemmed from the ISO’s expanded seasonal procurement to manage a growing surplus of solar and hydro during California’s spring run-off. (See CAISO: Forecasting Challenges Drove Increased Regulation Requirements.)
CAISO’s ancillary services costs rose last year after the ISO expanded its regulation procurement to accommodate the increased volume of variable solar resources on its system.
The Monitor estimates about 1.6% of solar generation was dispatched down in the real-time market last year, with the largest reductions — about 3.4% — occurring during March as a result of low seasonal loads coinciding with relatively high solar output.
“More solar generation was economically dispatched down in 2016 compared to 2015 primarily because there was more inexpensive hydroelectric generation available throughout the year,” the Monitor said.
Just 0.3% of forecasted wind output was dispatched lower in real time throughout the year, which the Monitor attributed to the tendency of wind resources to bid into the market at relatively lower prices than solar.
Non-economic curtailments of renewable resources declined last year, the Monitor noted, likely because of the expansion of the EIM, the West’s only real-time energy market. The EIM’s inclusion of NV Energy in late 2015 and Arizona Public Service last fall significantly increased imbalance transfer capacity out of California, increasingly turning the state into an exporter of renewable generation to other areas of the West. (See EIM Report Show Continued Growth in CAISO Exports.)
The Monitor said improved transfer capability helped ensure competitiveness in the EIM, with mitigation of bids triggered by congestion occurring in the market’s participating balancing areas during only 1 to 4% of intervals.
“This increased structural competitiveness provides a basis for DMM to support removing special bidding restrictions currently placed by FERC on some Energy Imbalance Market participants,” the Monitor said, referring to Berkshire Hathaway Energy affiliates PacifiCorp and NV Energy.
FERC last year rejected a request by the two companies to rehear a 2015 decision prohibiting them from bidding generation into the EIM at market-based rates. The commission determined that both companies must provide market power analysis for EIM sub-markets as well as the market as a whole, a condition that would apply to any EIM member (See Berkshire Denied Rehearing on Market Power.)
The Monitor said that analysis it performed last year indicates that the inclusion of NV Energy’s transfer capacity “dramatically” reduced PacifiCorp’s potential to exercise market power in the EIM by significantly improving the links between the ISO and PacifiCorp’s balancing area.
“This structural competitiveness mitigates the potential for the exercise of market power through both economic and physical withholding during most intervals,” the Monitor said.
CAISO has “partially” addressed some of the Monitor’s own recommendations for improving competitiveness in the EIM, the Monitor noted, including increased enforcement of measures meant to account for internal transmission constraints and improved modeling of PacifiCorp transmission limits to better reflect the congestion impact of contracted line capacity.
The Monitor said it would support eliminating the bidding restrictions once all the concerns in FERC’s orders have been addressed.
Three public interest groups say they were shut out of last week’s FERC technical conference on tensions between state energy policies and wholesale markets (AD17-11) and called on the commission to improve the transparency of RTOs.
In a letter to the commission, Public Citizen, the Public Utility Law Project of New York and the Pennsylvania Utility Law Project complained that the technical conference did not include any public interest consumer advocates, although Public Citizen had submitted an application to speak.
Although the Consumer Advocates of PJM States testified on one PJM panel, “neither government nor public interest consumer advocates” were included on any of the ISO-NE or NYISO panels, the letter said. “FERC’s failure to include any public interest consumer advocates decidedly leaves one of the most important stakeholders in the outcome with no voice,” they wrote.
The groups also said they were concerned that the Trump administration will appoint new FERC commissioners who subscribe to a “new, radical administration baseload electricity policy” as articulated by Energy Secretary Rick Perry’s memorandum announcing a study of policies affecting baseload power. (See related story, Exelon Encouraged by Perry’s Memo, Thinks ZECs Will Hold Up.)
“While the Department of Energy actually lacks clear authority to implement the sweeping proposals suggested in the memo, FERC likely does have the power to do so,” the groups said.
FERC has lacked a quorum since February. The five-member commission has three open seats, and Commissioner Colette Honorable announced last month she will not seek reappointment when her term expires in June.
The groups also called on FERC to improve RTO governance and transparency, criticizing FERC’s December order dismissing Public Citizen’s complaint that it was denied a right to fully participate in PJM. The order said that government consumer advocate offices, which have the right to vote, can represent Public Citizen’s interests (ER17-249). “That is akin to the U.S. Environmental Protection Agency representing the views of the Sierra Club,” they wrote.
“Although some describe the RTOs as ‘quasi-public’ institutions, given the power FERC has bestowed upon them, there is nothing public about them. All of the FERC-jurisdictional RTOs … are private, membership corporations. None are subject to federal or state transparency or other governance requirements imposed on government institutions, such as open meeting laws or federal/state freedom of information act statutes.”
The groups said individuals that are not members of the New England Power Pool can only attend stakeholder meetings through a “sponsorship” from an existing member. “But even after being ‘sponsored,’ the decision to approve participation is made by the chair of the Participants Committee — a position currently held by a for-profit power company executive. Such a privatized model of controlling civil engagement is inappropriate.”
The letter also renewed the March 2016 request by Public Citizen and more than two dozen environmental and public interest groups that FERC provide public funding for interventions before the agency, as it says is required by the 1978 Public Utility Regulatory Policies Act (RM16-9). (See Citizens Groups Seek Public Funding for FERC Interventions.)
CAISO last week experienced its first “Stage 1” grid emergency in nearly a decade, days after Southern California Gas warned that continued restrictions on its Aliso Canyon storage facility could deprive the region’s natural gas-fired generators of enough fuel to avoid blackouts this summer and winter.
The ISO on May 3 issued an emergency notice from 7 to 9 p.m. after grid operators determined that they could not meet load and operating reserve requirements. At the time, load was 2,000 MW above forecast and nearly 800 MW of imports never materialized, compounded by the outage of a 330-MW gas-fired plant.
About 800 MW of demand response was “critical” in meeting grid needs, according to CAISO.
“It was unusual that the issues began developing around the peak, and demand wasn’t ramping down much, but solar was ramping off faster than what the thermal units online at the time could keep up with in serving load,” CAISO spokesperson Steven Greenlee told RTO Insider.
That forced the ISO to dip into reserves and slip below required reserve margins, prompting it to declare a Stage 1 emergency.
“This stage allows us to trigger the demand response interruptible programs, which are managed by the investor-owned utilities,” Greenlee said.
It was the first such emergency notice issued since an extremely hot day in August 2007. In a Stage 3 emergency — the most serious — utilities are warned of load curtailments.
Relief Well 2 at Aliso Canyon | SoCalGas
While the ISO has drawn no link between the emergency and ongoing constraints within the pipeline system that feeds Southern California’s gas fired generation, the timing was uncanny. The event came less than a week after SoCalGas cautioned state and ISO officials that it might be unable to meet system needs during peak seasons for electricity demand. The gas utility contended that a recent state-directed reliability assessment of its network relied on overly rosy assumptions.
SoCalGas said a prohibition on gas withdrawals from its Aliso Canyon facility and limited injections there might prevent it from responding to gas supply and demand imbalances. The leak at the gas storage facility, discovered in October 2015 and plugged in February 2016, led to increased use of the La Goleta, Honor Rancho and Playa del Rey storage facilities, where reserves are now 40% lower than a year ago.
“The state was lucky this past year to have experienced a mild summer and winter,” SoCalGas said in an April 28 letter to CAISO, the California Public Utilities Commission and the California Energy Commission. “For the upcoming summer and winter seasons, Californians cannot rely on luck, and energy reliability should not depend upon mild weather conditions.”
In response, the agencies have requested that SoCalGas present its findings at a May 22 workshop on summer reliability to be held in conjunction with the Los Angeles Department of Water and Power.
“The issues raised by SoCalGas are part of ongoing data requests the joint agencies have made of the utility,” the agencies said in a joint statement. State officials “are working in close coordination to address the importance of natural gas and electricity reliability for Southern California as we look forward to the summer and next winter.”
The National Oceanic and Atmospheric Administration says there is a 60 to 70% chance that temperatures will be above normal this summer.
SoCalGas also warned state agencies of safety concerns stemming from operating its pipeline system at maximum pressure. The availability of storage injection capacity reduces the risk of over-pressurization on natural gas lines.
“Operating close to a pipeline’s maximum pressure is a pipeline safety and compliance concern,” the company said.
The natural gas utility said that the state had assumed “perfect operating conditions and optimal market conditions” when asking it to do a recent reliability assessment. This could lead the agencies to be overly optimistic and put gas and electricity supply at risk.
The analysis assumed full utilization of gas receipt points, a theoretical maximum that is not reasonable for operational planning and is dependent on the behavior of suppliers, shippers and customers. An assumed 1.5 Bcfd withdrawal rate would require significantly higher inventory at Playa del Rey and is not possible if storage inventories are not replenished.
The assessment also assumed that Aliso Canyon would not be used this summer, but held in reserve, which the utility said is “not prudent.” The facility’s low inventory, new well configuration and prohibition on injection will likely reduce withdrawal capacity. The assessment also used daily average capacity that does not address hourly customer demand fluctuation, SoCalGas said.
The company also pointed out recent events that increased natural gas demand without warning. In July, high temperatures and humidity pushed up electricity demand and cloud cover limited solar generation, leading to natural gas demand 11 to 25% above plan. Storage withdrawals were needed to handle the variability. In August, a fire in the Cajon Pass affected transmission lines and caused a 25% spike in natural gas demand from generators over a five-day period.
Still, state officials still considered that Southern California’s grid weathered last summer without any major incidents, attributing the success to measures taken after the 2013 shutdown of the San Onofre nuclear plant, deployment of new energy storage and increased use of automated DR. (See Sandoval: Nuke Shutdown, Auto-DR Aided Aliso Canyon Response.) CAISO also relied on temporary tariff provisions meant to improve schedule coordinating, which FERC last November extended by another year. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)
The fact that one broken pipe at Aliso Canyon led to widespread reliability concerns over an extended time demonstrates the precarious balance between fuel supply and electricity scheduling, weather and unforeseen events with which grid operators must continually grapple.
WASHINGTON — D.C. Circuit Court of Appeals appeared sympathetic to FERC’s request to dismiss a challenge to its ruling on SPP’s Order 1000 rules, questioning the standing of the plaintiffs.
The court heard oral arguments Friday in a dispute over provisions in SPP’s Tariff that recognize state and local right-of-first-refusal laws (15-1157).
LSP Transmission, a subsidiary of independent transmission developer LS Power, sued FERC in June 2015 over three Order 1000 compliance filings submitted by SPP (ER13-366). LSP argued that the commission’s acceptance of the state ROFR provisions illegally excludes certain projects from the competitive process that SPP established in response to Order 1000.
Lack of Standing?
While LSP attorney Michael Engleman of Squire Patton Boggs and FERC attorney Holly Cafer were given the chance to argue the merits of LSP’s complaints, much of the hour-plus hearing was taken up by Judges David Tatel and Nina Pillard’s questions over FERC’s argument that the company lacked standing in the case. (Judge Robert Wilkins, who was not present in the courtroom because of a death in his family, listened in by phone.)
Tatel and Pillard seemed sympathetic to FERC’s argument that, because LSP had not suffered direct harm as a result of the commission’s orders on the compliance filings, it lacked standing to challenge them. Before Engleman could get into the details of his argument during his opening remarks, Tatel interrupted him, asking him to address the standing argument.
Tatel said FERC’s orders may be illegal, but they have to cause injury in order for LSP to have standing. He repeatedly asked what sort of relief the court could provide to LSP. Pillard said that LSP might not like the regulatory regime set up under Order 1000, but that that was a separate argument.
Engleman argued that LSP is harmed because it is excluded from bidding on certain competitive projects that SPP determines are subject to an incumbent developer’s ROFR under state and local laws. He said the court could provide relief by remanding the orders on compliance back to FERC for review or vacating the commission’s acceptance of the provisions in the RTO’s Tariff.
Engleman admitted, however, that LSP had not been denied being selected for a project under SPP’s competitive process. Cafer agreed with the judges when they asked her if LSP would have standing had it been denied a project, as it then would have suffered direct injury. But she also said the company wouldn’t be harmed if SPP determined that a project would not be competitively bid because of a local ROFR law.
“This court has held, in circumstances also involving compliance with a commission rulemaking that reformed transmission planning processes, that the petitioner must ‘have an active application for a transmission project’ to demonstrate an injury-in-fact for the purpose of constitutional standing,” Cafer said in a brief to the court. “LS Power has not made this showing.”
Engleman also stopped short of arguing that state ROFR laws are unconstitutional under the dormant Commerce Clause, something that former Chairman Norman Bay alluded to in a concurrence with the commission’s acceptance of SPP’s second compliance filing.
“State laws that discriminate against interstate commerce — that protect or favor in-state enterprise at the expense of out-of-state competition — may run afoul of the dormant Commerce Clause,” Bay said. “The commission’s order today does not determine the constitutionality of any particular state right-of-first-refusal law. That determination, if it is made, lies with a different forum, whether state or federal court.”
State vs. Federal
The judges were skeptical that they could vacate FERC’s acceptance of SPP’s Tariff provisions. They seemed sympathetic to Cafer’s argument that “Order 1000 wasn’t as expansive as LS Power hoped it would be.”
Engleman, in fact, had argued on behalf of FERC before the court in March 2014, with LS Power supporting Order 1000’s elimination of federal ROFR policies. (See Appellate Court Skeptical of Order 1000 Challengers.)
A three-judge panel including Pillard upheld the order, including against challengers who said that it did not mandate that load-serving entities’ input on transmission projects be heeded — an argument to which Pillard had seemed sympathetic.
Cafer said Order 1000 only eliminated federal ROFRs and does not pre-empt state law. Here, however, there seemed to be some skepticism from the judges, especially Pillard, who said if the order did pre-empt state law, it would be redressable by the court.
While federal law pre-empts state law when the two conflict under the Constitution’s Supremacy Clause, there are limited circumstances when rulemaking by federal agencies can do so.
Pillard asked Cafer if Order 1000 “effectively” pre-empts state laws — even if FERC didn’t intend to — by making the competitive process, with its regional cost sharing, the only choice for utilities. She wondered under what circumstances an incumbent developer would choose recovery through ratepayers over cost allocation to the beneficiaries of the project.
Cafer responded that state laws vary. Some states simply allow a ROFR to projects within a utility’s service area; others confine it to existing rights of way.
Engleman, however, argued that FERC has been inconsistent over whether RTOs can exclude projects subject to state ROFRs from the competitive process. He pointed out that FERC had denied SPP’s first compliance filing in 2013 but later reversed its position — without Commissioner John Norris — in October 2014 with SPP’s second filing. Norris had dissented in a similar, earlier order regarding PJM, saying the commission’s recognition of state ROFRs undercut Order 1000’s purpose. (See Order 1000 Reversal: Reality Check or Surrender to Incumbents.)
E Barrett Prettyman D.C. Circuit Courthouse
If the D.C. Circuit rules in favor of FERC, it is unclear whether LSP would appeal to the Supreme Court: The company lost a similar case regarding state ROFR provisions in MISO’s Tariff before the 7th U.S. Circuit Court of Appeals — a case the Supreme Court declined to hear on appeal in March. (See Supreme Court Refuses to Hear ROFR Challenge.)
The Supreme Court, however, would be much more likely to hear an appeal if the D.C. Circuit ruled in LSP’s favor.
OGE Energy hopes that a proposed legislative review of the Oklahoma Corporation Commission will relieve some of the company’s frustration regarding the regulator.
The state Senate in April unanimously approved a bill to create an executive-level task force to examine the OCC’s structure, mission, budget and staffing. OGE has complained recently about commission delays in approving rate cases, forcing the state’s utilities to implement interim rates that often have to be refunded following final regulatory approval.
The legislation still faces a final vote in the House of Representatives before it can be sent to Gov. Mary Fallin for her signature.
OGE is “fully supportive” of the bill, CEO Sean Trauschke told financial analysts during a May 4 first-quarter earnings call.
“It is not intended to undermine the OCC, but it’s a legislative effort to make it work better,” he said. “I am confident Oklahoma’s regulations will improve, but it won’t happen overnight.”
Trauschke said this would be the first full review of the OCC since its creation in 1970. The task force would consider whether commissioners should be appointed rather than elected, and whether to increase the commission’s seats from the current three.
“Are they funded properly? Are they regulating the right industries?” he said, noting the OCC currently oversees oil and the electric, gas and telecommunications utilities. “I do think the legislation will really address the efficiency and speed in which things are completed.”
Oklahoma State Legislature
As currently written into the bill, the seven-member review group would be led by Oklahoma’s secretary of energy and environment and include two legislative members, the state treasurer, attorney general and an appointee from the OCC. The task force would file a final report by September 2018.
Trauschke deferred several questions on Enable Midstream, its gas gathering and processing joint venture with Texas’ CenterPoint Energy, to its majority partner. CenterPoint has been looking to sell or spin off its 55.4% share of the venture, in which OGE holds a 25.7% limited-partnership interest in addition to its 50% management interest in Enable’s general partnership.
OG&E linemen | OG&E
Enable on May 3 reported a first-quarter profit of $120 million, up from $86 million in the first quarter of 2016. Revenue increased to $666 million from $509 million a year ago.
Better margins at Enable and lower depreciation expenses at Oklahoma Gas & Electric boosted OGE’s profits for the first quarter. The company had net income of $36 million ($0.18/share), compared to $25.2 million ($0.13/share) in the first quarter of 2016.
OG&E contributed earnings of 8 cents/share, up from 3 cents/share the year previous, and Enable pitched in with 10 cents/share, compared to 9 cents/share a year ago.
Wall Street reacted by driving OGE’s shares down 66 cents from Wednesday’s close of $34.62 to $33.96 in after-hours trading Friday.
CenterPoint Says Wait on Enable Update
CenterPoint is still on track to provide an update on its Enable ownership stake in August, when it will report second-quarter earnings, CEO Scott Prochazka told analysts during a May 5 call.
“We have talked about the list of options being a sale, a spin or keep,” Prochazka said. “And even under the keep situation, we continue to work on things that would reduce the variability associated with our ownership of Enable.”
The Houston-based company said Enable contributed 10 cents/share in the first quarter, compared to 9 cents/share the year prior. Prochazka said daily volumes of gas gathered, processed and transported were all up from the previous year, and noted the business recently announced a new project in the Texas-Oklahoma Panhandle’s Anadarko basin that adds 400 Mcfd of processing capacity.
“We continue to believe Enable is well positioned for success in [its] industry,” Prochazka said. “I think it’s fair to say … that improvements in the industry and changes that are occurring at Enable are both favorable for us, from an ongoing ownership perspective.”
CenterPoint reported earnings of $192 million ($0.44/share) for the first quarter of 2017, as compared to a profit of $154 million ($0.36/share) over the same period last year.
The company has asked for electricity and gas rate hikes to help recoup $480 million spent on transmission infrastructure in 2016 and $16.5 million spent on its natural gas distribution business.
CenterPoint’s share price closed at $27.98 on May 4 and dropped to $27.72 shortly after the earnings call the next day, before finishing at $28.05 in after-hours trading.
