Page 1312 – RTO Insider

May 12, 2017

Federal Hydro Customers Seek Change in MISO Capacity Rules

By Amanda Durish Cook

CARMEL, Ind. — Customers of the Southwestern Power Administration (SWPA) asked MISO on Wednesday to change how it accredits their hydropower allocations from the federal power marketing administration, saying current rules are shortchanging them and denying the RTO full use of the resources’ seasonal peaking capacity.

resource adequacy rules MISO hydropower — Henley | © *RTO Insider*

“We didn’t come today with a fix. … We’re going to hope that the people in the room come up with a solution and a fix in future meetings,” Rick Henley, of Jonesboro City Water and Light in northeast Arkansas, told stakeholders at a May 10 Resource Adequacy Subcommittee meeting. Appearing on behalf of SWPA customers with Aiden Smith, the agency’s vice president of transmission strategy, Henley offered a problem statement outlining their concerns.

Move from SPP to MISO

SWPA markets about 2,000 MW of power produced by 24 U.S. Army Corps of Engineers hydropower projects, most of them located in the SPP footprint.

When Entergy joined MISO in 2013, it added 27 SWPA customers to the RTO’s footprint in addition to one existing customer. “As a result, the vast majority of SWPA’s federal hydropower customers were not present in MISO’s stakeholder processes when the rules concerning resource adequacy were crafted,” the problem statement said.

The problem, Henley said, is that MISO’s resource adequacy rules treat the hydro assets as baseload power when they were designed to provide peaking power. He said MISO could reap reliability benefits in the summer and winter if it modified its requirements for hydro assets.

MISO’s Business Practice Manuals require the Use-Limited Resource type to be available for the four peak hours of the day (1,460 hours/year). But because SWPA’s contracts with Jonesboro and other “preference customers” typically only guarantee power for 1,200 hours/year, MISO revised its rules to give the SWPA customers a reduced capacity credit of 82% of their federal allocations to spread the guaranteed amount of firm energy across 1,460 hours.

Intended as Peaking Power

“While the federal preference customers are very grateful for this compromise, MISO, its footprint and the customers could be better served by federal hydropower if it was used as intended as peaking power,” the problem statement says.

It noted that SWPA hydropower has 236 MW of import capability into MISO. It said one unnamed preference customer with a 100-MW allotment is not importing into the RTO because of the current rules but would do so if the problem were resolved.

“We have a 1,200-hour product that does not conform with MISO’s 1,460-hour resource adequacy rules,” Henley said. “We’re scheduling now as a baseload resource, and we think it reduces the ability of the federal hydropower when it’s most needed and valuable in the MISO footprint. If we can bring more resources to the table, you [would] think that would bring down prices for everyone.”

Jonesboro City Water and Light, which has a 303-MW peak demand for 36,000 customers, has an 80-MW hydropower allocation from SWPA. “It’s a pretty big deal for us,” Henley said of the hydropower share. “We think there’s a better way to utilize this resource within MISO constraints.”

David Sapper of Customized Energy Solutions said stakeholders have long considered asking MISO to revise its resource adequacy rules, saying it’s difficult for any fuel type to meet the availability requirements.

RASC liaison Shawn McFarlane said MISO can examine the issue with stakeholders, but he said the RTO would not commit to a timeline. He said it could work to compile statistics on hydropower use for stakeholders.

“Obviously, anything we apply has to work generally; we cannot create one-offs,” McFarlane said.

RASC Chair Chris Plante said stakeholder process dictates that the issue is first sent to the Steering Committee, which would decide which committee works on it. Steering Committee Chair Tia Elliott said her committee would most likely move the issue to the RASC at the May 24 meeting.

May 11, 2017

NextEra’s Rejected Oncor Bid Gets Second Look

By Tom Kleckner

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.

May 11, 2017

Duke Angles for More Resource Control amid Declining Profits

By Rory D. Sweeney

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 energy tax credits first quarter earnings — 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.

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.

Good said they were not.

May 10, 2017

AEP, Dynegy Swap Merchant Assets

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 Conesville Plant 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.

— Tom Kleckner

May 10, 2017

MISO Slims Summer Reserve Prediction

By Amanda Durish Cook

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.

The grid operator now predicts an 18.8% reserve margin, down 0.4% from a March estimate — made before the Planning Reserve Auction — and 0.6% above last summer’s reserve. (See Anemic Loads, Plentiful DR Boost MISO Summer Outlook.)

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 Slims Summer Planning Reserve Margin Prediction — | *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.

May 10, 2017

Cuomo Names NYSERDA CEO as PSC Chair

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.

John Rhodes NYSERDA — 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.

— Rich Heidorn Jr.

May 10, 2017

Monitor Report Shows Sharp Decline in CAISO Costs

By Robert Mullin

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.)

ancillary services costs CAISO — 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.

May 9, 2017

Public Interest Groups Cry Foul over Technical Conference, RTO Transparency

By Rich Heidorn Jr.

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.)

public interest consumer advocates This article is cornerstone content — Tyson Slocum, Director of Public Citizen’s Energy Program, at an earlier FERC Hearing | © *RTO Insider*

“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.)

May 9, 2017

California Grid Emergency Comes Days After Reliability Warning

By Jason Fordney

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.

natural gas demand CAISO grid emergency — 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 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.

May 9, 2017

DC Circuit Questions LS Power Standing in SPP ROFR Case

By Michael Brooks

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.)

FERC order 1000 rofr spp — 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.