Page 1295 – RTO Insider

May 12, 2017

CAISO Initiative Could Toss Lifeline to Struggling Generators

By Robert Mullin

A new CAISO initiative could allow power producers a way to temporarily suspend the operation of an unprofitable generating plant — and possibly provide compensation to plants denied permission to do so.

That would crack the door for the ISO to issue a type of capacity payment to some financially struggling generators not needed to maintain system reliability, even if it falls far short of establishing a capacity market.

The Temporary Suspension of Resource Operations initiative will explore under what circumstances the ISO might permit a resource owner to temporarily pull a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manual.

“The initiative will assess how potentially allowing this type of resource status change would interact with other requirements of the CAISO Tariff, contracts, and with grid and market operations,” the ISO said in an issue paper describing the scope of the effort.

CAISO said it was seeking to address the issue in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).

Completed in 2003, La Paloma — like other gas-fired plants in California — has in recent years struggled to compete in the wholesale market because of depressed prices, largely driven by lower-priced renewable resources. The owners estimated that the plant would lose $39 million annually under continuous operation and asked that CAISO allow them to shut down the three units from July to November 2016.

The ISO rejected the plant owners’ requests because they were made for economic — and not physical — reasons. It also rebuffed an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At that time, 42 MW of the plant’s Unit 2 were under an RMR agreement.

Last December, two months after FERC refused to overturn the ISO’s decision, La Paloma filed for bankruptcy, citing $524 million in debt and an “inhospitable regulatory environment.”

caiso initiative generators — CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | *Kern County, California Public Health Services Department*

While market participants generally agreed with CAISO’s decision, some suggested that FERC direct the ISO to amend its Tariff to address revenue shortfalls for conventional generators. FERC rejected the request.

The new initiative seeks to address at least some of those stakeholder concerns. In its filings with FERC, CAISO acknowledged the importance of keeping conventional generation available to help integrate the growing volume of renewables on its system and noted that it was actively pursuing market changes to compensate generators for their needed characteristics.

The ISO seeks to keep the scope narrow, avoiding a discussion of using the current outage management system — which is intended for maintenance outages — for economic requests.

“The distinction here is that this initiative will look at the conditions under which the CAISO may allow a participating generator to temporarily suspend the operation of its generating unit,” the ISO said in its paper. “The solution will likely involve a process and a new method for requesting and then reporting a temporary suspension of operations.”

Perhaps most significantly, the ISO wants stakeholders to consider the need for a mechanism to compensate generators not needed for resource adequacy but denied permission to suspend operations, including a potential cost allocation scheme.

The initiative will also explore maximum and minimum time limits for temporary suspensions, timelines for requesting suspension and whether suspended resources should maintain a level of readiness to return to the ISO market if it’s needed.

The ISO additionally expects to consider whether a generator can switch operation from one balancing authority area to a neighboring one for an extended period of time and how that would affect resource adequacy accounting.

Under current rules, owners that plan to mothball a generator must provide CAISO 60 days’ notice before shutting down and submit a “long-range” outage request. To maintain its repowering rights and deliverability status, the plant must provide a repowering plan within one year of closing.

CAISO will kick off the initiative with a May 19 stakeholder call.

May 12, 2017

Md. PSC OKs 368 MW in Offshore Wind Projects

By Rich Heidorn Jr.

Maryland regulators on Thursday approved two offshore wind projects totaling 368 MW, setting in motion what the state called the nation’s “first large-scale” offshore wind deployment.

The Public Service Commission awarded offshore renewable energy credits (ORECs) to US Wind and Deepwater Wind’s Skipjack Offshore Energy.

PSC Chairman W. Kevin Hughes said the approval “brings to fruition the General Assembly’s efforts to establish Maryland as a regional hub for this burgeoning industry.”

renewable energy credits offshore wind — Maryland Offshore Wind Lease Area | *BOEM*

The PSC awarded the credits at a levelized price of $131.93/MWh for 20 years, beginning when the plants start generating.

US Wind’s 62-turbine, 248-MW project, 12 to 15 nautical miles offshore, has an estimated cost of $1.375 billion and is expected to begin operations in January 2020. It will connect to the grid at the Indian River Substation in Delaware.

Skipjack’s 15-turbine, 120-MW project, 17 to 21 miles off the coast, is estimated at $720 million and has a target in-service date of November 2022. It will connect to the grid at a substation in Ocean City, Md.

Conditions

The PSC’s order included more than two dozen conditions, including requirements that the developers create almost 5,000 direct jobs during the development, construction and operating phases of the projects.

The companies will be required to use port facilities in the Baltimore region and Ocean City for construction, operations and maintenance, fund almost $40 million in upgrades at the Tradepoint Atlantic (formerly Sparrows Point) shipyard in Baltimore County and invest at least $76 million in a steel fabrication plant in the state (Case No. 9431).

To address concerns about the ability to see the turbines from the shore, the order also requires US Wind to locate its project as far to the east of the designated wind energy area as practical. “Each developer also must take advantage of the best commercially available technology to lessen views of the wind turbines by beach-goers and residents, both during the day and at night,” Commissioner Anthony O’Donnell said.

The two companies must notify the PSC by May 25 whether they accept the conditions. The projects also are subject to the federal government’s approval of site assessment, construction and operations plans.

“As we review the details of the commission’s order, we thank the Public Service Commission for the trust that they have placed in Deepwater Wind,” CEO Jeff Grybowski said in a statement. “We look forward to continuing our dialogue with the Ocean City community about the Skipjack Wind Farm. Our goal is to build a project that the entire community is proud of.”

Deepwater Wind operates the first offshore wind project in the U.S., the 30-MW Block Island project off Rhode Island that began operations in December. (See Offshore Wind Industry Looks for Next Gust of Support.)

US Wind, a subsidiary of Italy’s Toto Holdings, thanked the PSC for the decision in a statement, saying “Maryland is now the undisputed national leader for offshore wind.”

“This marks the real start toward an extensive offshore wind industry that will one day soon stretch from Cape Cod, Mass., to Cape Hatteras, N.C., and provide as much as a third of the East Coast’s electricity,” the Chesapeake Climate Action Network said in a statement.

Cost to Ratepayers

An analysis conducted for the PSC estimated the ORECs will cost residential customers less than $1.40/month and boost rates for commercial and industrial customers by less than 1.4% — below the limit set by the legislature in the Maryland Offshore Wind Energy Act of 2013. The law allows offshore wind to comprise up to 2.5% of total retail electricity sales.

The projects are part of the state’s plan to reduce carbon emissions 40% by 2030 and will allow electric suppliers to replace some renewable energy credits produced in other states. Maryland’s renewable portfolio standard requires production of 25% of electricity from renewables by 2020.

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.)