Stakeholder Soapbox: Electric Market Offer Caps are a Vital Consumer Protection

By Christopher Hargett, Diana McNally-Barsotti and Joel Yu

The benefits of wholesale electric markets can only be achieved when competition is effective. FERC must not only provide for markets that benefit customers but must also not lose sight of the importance of protecting markets (and customers) against market power abuses. To this end, the focus on customer impacts must remain as FERC considers changes to existing electric market offer caps. Some organized markets have sought to increase offer caps to levels above $1,000/MWh because of the impact seen from high natural gas prices during the extreme weather events in the winter of 2013/14. Such efforts are overly reactionary to one winter season experience and do not indicate that a change in policy and consumer protection is warranted at this time. Moreover, they are predicated on the misguided belief that increasing the offer cap is the only means to properly compensate generators for their performance. Since the advent of organized electric market operation, there has been no evidence that a change to this important offer cap is needed.

Protecting Electric Customers

Bids into wholesale electric markets and associated federal regulations are based on the premise that, absent market power, competitive market pressure should discipline offers to levels at or near suppliers’ marginal costs required to cover short-run operations (including opportunity costs). However, because marginal suppliers may be limited during peak periods, and because the market demand-side load is generally not price responsive, a truly functional competitive market may not be present. As a result, offer caps are necessary to protect customers from excessive prices as generation resources become scarce during high demand periods. Moreover, they take into account the fact that “prices are generally more sensitive to withholding and other anticompetitive conduct under high load conditions,” when more costly supply is required.[1]

Due to the experience of the 2013/2014 winter, organized electric markets are seeking to promote resource availability and performance in ways that add competitive forces to the market’s supply side during peak demand hours. While the organized electric markets have well developed mitigation measures in place, there is no substitute for the $1,000/MWh offer cap as a fail-safe protection to customers. Furthermore, energy market offer caps serve as a valuable incentive for generators to minimize fuel costs, which in turn translates into customer benefits through fair electricity prices. Moreover, the existing cap encourages generators to limit their reliance on spot fuel purchases. This incentive is not only good for economics but also for the reliable operation of the electric system. And, under existing rules, individual generators are able to be compensated for documented increased fuel costs when incurred. Such provisions protect generators as well as consumers, and any change to the offer cap should consider the experience with such requests, as discussed below.

It is also inaccurate to claim that higher short-term price signals will result in better resource performance and help maintain reliability. This hypothesis was proven false in PJM’s experience over the past two winters. In response to high natural gas prices in winter 2013/14, PJM temporarily increased its offer cap to $1,800/MWh for the 2014/15 winter but ultimately had no resource clear above $1,000/MWh. In fact, while prices cleared below $1,000/MWh, generators boosted performance year-over-year. When PJM experienced its all-time winter peak in February 2015, the generator forced outage was 13%, compared to 22% in January 2014. In New York, historical data supports this conclusion as well, as no generator in NYISO has ever demonstrated that it incurred costs above the $1,000/MWh offer cap, including the 2013/14 winter when natural gas prices spiked to unprecedented levels.

Regional Coordination

FERC should not act on a generic basis to modify energy market offer caps across organized markets, nor should it allow differences in offer caps between regions. Contrary to FERC’s goal, any difference in offer caps in neighboring regions would create unnecessary seams issues and could result in inefficient bidding behavior between regions. That’s because suppliers could concentrate their offers into the market with the higher offer cap, forcing operators in the lower offer cap region to call on resources out-of-market to meet their system reliability needs. This would unnecessarily increase costs to consumers in both regions. Such bidding incentives are an unjust application of market power and should be avoided. True price flexibility and differentiation between markets are, and should continue to be, a reflection of infrastructure constraints.

The Right Approach

Price signals are not the only tool available to compensate suppliers according to their cost of operation.[2] Out-of-market payments are the appropriately tailored solution when considering the precarious alternative. Taking this approach ensures that generators are compensated for their performance and for meeting customer needs in extreme conditions, without creating potential market vulnerabilities at all other times to the detriment of electric customers. Out-of-market payments address these rare costs in a fair manner for generators and customers and should be transparent for all market participants. Trends should be monitored, and any changes, if considered in the future, should be based on information about such payments.

[1] 2014 State of the Market Report for the New York ISO Markets, Potomac Economics, May 2015, p 17.

[2] PJM recently received FERC approval for its Capacity Performance program, whereby units that perform under high demand conditions are rewarded. In New York, NYISO is undertaking several initiatives to bolster performance while ensuring compensation including clarifying market mitigation measures and fuel availability reporting.

Christopher Hargett, Diana McNally-Barsotti and Joel Yu are senior policy advisors at Con Edison. Subsidiaries Con Edison Company of New York and Orange and Rockland Utilities are transmission owners within NYISO. A subsidiary of Orange and Rockland Utilities, Rockland Electric, is a transmission owner within PJM.

(Editor’s Note: This column marks the beginning of an occasional RTO Insider feature, Stakeholder Soapbox. If you’d like to contribute your own op-ed article, contact Rich.Heidorn@RTOInsider.com.)

September 29, 2015

Clean Power Plan, REV Highlight IPPNY Conference

IPPNY President Gavin Donohue said generators are willing to work with New York regulators regarding the state’s capacity market but said it’s unclear what changes are being sought. “What problem are we trying to solve?” he asked. “We’ve had stresses on the system during the winter [and] during the summer the last few years and quite frankly the system has worked very well.”

IPPNY Chairman John Reese, senior vice president of US Power Generation, called on state regulators to demonstrate “courage” by pushing for an increase in the cost of new entry. “Nobody believes you can actually build or enter the New York market for the current cost of new entry price,” he said. “Upstate New York capacity prices are lower than PJM, are lower than New England. Those are not survivable.”

Kenneth Daly, CEO of National Grid New York, speaks as James Gallagher, executive director of the New York State Smart Grid Consortium (left), and UBS Securities analyst Michael Weinstein (right) listen. Daly said the next five years of the state’s Reforming the Energy Vision initiative will be transitional, as state regulators evaluate demonstration projects and determine which worked and which did not. “Ten years from now is when we’ll start to see game changers. Battery storage is clearly the one biggest change that our industry will face. And if we go through another investment cycle these next five years of modernizing our grids we’ll then have far greater capability in that second five-year period to integrate renewables, to give customers choice, to use more local demand response.”

Richard Dewey, executive vice president of NYISO (left), and John Shelk, president of the Electric Power Supply Association (right), said EPA’s final Clean Power Plan addressed problems with the draft rule. Dewey said the preliminary rule “would have left us with about one to three days of oil burn in New York state – which is about 100 less than we typically need [for] reliability.” Shelk said the final rule fixed an “artificial” advantage for new gas plants. But he said it remains unclear how regions outside the Regional Greenhouse Gas Initiative will incorporate carbon costs in economic dispatch. “Clearly we’re not going to have — certainly not on day one — a price on carbon in the rest of the states,” he said.

September 29, 2015

Integrated System to Join SPP Market Oct. 1

By Tom Kleckner

SPP will welcome the Integrated System and its three primary entities as full members Thursday, extending its footprint into Big Sky Country.

The IS — comprised of Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — expands SPP’s footprint to 14 states, adding the Dakotas and parts of Iowa, Minnesota, Montana and Wyoming.

It will add more than 5,000 MW of peak demand and 9,500 miles of transmission infrastructure to SPP’s responsibilities, while increasing its territory by 55% to 575,000 square miles.

“It’s a significant change for SPP, considering the amount of area we’re responsible for and the parties we’re responsible for as members,” Executive Vice President Carl Monroe, SPP’s chief operating officer, told RTO Insider. “We’re extending our footprint and ensuring SPP’s members will get the benefits of our services.”

While SPP expands with the IS, indications are it will not gain another potential member with Lubbock Power & Light’s announcement last week that it will join ERCOT in 2019.

Reliability Coordination Began June 1

SPP has been providing reliability coordination for the IS since June 1, monitoring power flow and managing congestion while WAPA, Basin Electric and Heartland dispatched their generating resources. The three entities will transfer functional control of their facilities to SPP at midnight Wednesday night and become active participants in the Integrated Marketplace, forming the new Upper Missouri transmission zone.

Other entities will become full SPP members Thursday, including the East River Electric Power Cooperative, Northwest Iowa Power Cooperative and Corn Belt Power Cooperative. It will be SPP’s first major membership additions since 2009, when Nebraska’s major utilities joined the RTO, and boosts its membership to 92.

“We’re really looking forward to Oct. 1,” Monroe said. “We have very good relationships with those parties, and some are already participating in SPP’s working groups.”

SPP prides itself on being a stakeholder-driven organization and its governance model was a major reason the IS joined. Heartland CEO Russell Olson cited the RTO’s “collaborative process” in a statement announcing the move last year.

“They felt they would have a voice,” Monroe said, “and that made a difference in their decisions.”

Joining SPP gives IS members access to the RTO’s markets. Several current members have already credited market savings with allowing them to reduce the size of rate increases or providing additional pricing efficiencies through a broader pool of resources.

“I would guess that would be able to happen again from expanded footprint,” Monroe said. “Savings in the energy market will reduce the cost of wholesale energy. Depending on how each entity handles its customers, it could be a reduction in costs.”

Monroe said SPP’s increased membership also will reduce RTO service fees for existing members. “Everyone will be paying less as a ratio than they would have paid before,” he said.

WAPA, Basin Electric and Heartland began discussing joining an RTO four years ago to increase their options for buying and selling power. All three conducted public hearings and assessments before determining last year that SPP was the best fit. FERC approved the move in November.

“We felt that SPP was a solid philosophical match for our cooperative,” said Paul Sukut, Basin Electric’s CEO and general manager.

WAPA will become the first federal power marketing administration to join an RTO. WAPA spokesperson Lisa Meiman said joining SPP “alleviates the marketing restraints” the agency was facing in delivering firm power to its customers.

Because the Energy Policy Act of 2005 placed conditions on power marketing administrations joining RTOs, SPP did have to “accommodate” WAPA’s “unique needs,” Meiman said. SPP modified its Tariff to exempt WAPA from regional cost-sharing charges. WAPA also is exempt from congestion and marginal loss charges when it is marketing and delivering federal hydropower to its federal load, she said. FERC issued an order Monday approving SPP Tariff changes accommodating WAPA (ER15-2350).

WAPA will merge its Eastern Interconnection balancing authority into SPP’s balancing authority, and its Eastern and Western Interconnection transmission facilities will be incorporated into the new Upper Missouri Zone. Meiman said WAPA will remain a transmission operator and develop transmission rates, revenue requirements and other necessary rates for use in SPP’s Tariff.

WAPA’s Western Interconnection BA will not become a part of SPP’s BA, nor will UGP’s Western Interconnection generation and load become part of the Integrated Marketplace.

Lubbock Sees Savings in ERCOT

Excitement over the addition of the IS was tempered last week when Lubbock Power & Light, which receives its energy through SPP member Xcel Energy, said it will join ERCOT to reduce its energy and capacity costs. (EDITOR’S NOTE: An earlier version of this story incorrectly stated that Lubbock Power & Light was an SPP member.)

The LP&L Electric Utility Board met with the Lubbock City Council on Sept. 24 to outline its transition to ERCOT, which manages 85% of the Texas grid. LP&L is the third-largest municipally owned electric company in the state, after San Antonio and Austin.

“That’s their decision,” Monroe said. “We’re a voluntary organization. If that’s what they intend to do, they make those choices that are best for their organization.”

LP&L says significant transmission infrastructure will be needed to interconnect with ERCOT, and that approval, certification and construction will likely take four years. The process began with a feasibility study, which was approved by the Public Utility Commission of Texas last week.

The utility says taking advantage of smaller, cheaper contracts in the ERCOT market will save it $20 million annually over what it currently spends in a long-term wholesale contract with Xcel Energy. LP&L’s three old, small power plants are seldom committed.

Lubbock also will be freed of about $40 million in annual capacity fees in ERCOT’s energy-only market.

LP&L also said it will benefit from Texas’ diversified energy portfolio and a simplified regulatory environment.

Monroe said SPP hasn’t had any conversations with LP&L or Xcel or looked at the implementation plans. “I’m not sure what [the announcement] means,” he said.

In a press release, Xcel expressed disappointment and said the city’s proposal will increase costs for customers in both ERCOT and the areas it serves in SPP. Noting the “significant investments” it has made in the area’s high-voltage network, Xcel said “Lubbock’s portion of the annual cost of these investments will be added to the costs Xcel Energy customers in Texas and New Mexico already pay.”

Xcel also said its long-term power supply agreement for a portion of Lubbock’s power needs through 2044 could be “impacted” by the utility’s move to ERCOT. According to LP&L, it will honor the contract by purchasing 170 MW from Xcel after June 1, 2019, which means it will remain interconnected with SPP.

By joining ERCOT, the city says it would also escape FERC regulation. As a Texas-only grid operator, ERCOT is regulated by the PUCT and the state legislature; FERC governs SPP and other interstate providers.

The PUCT and ERCOT would both have to approve LP&L’s move.

September 29, 2015

PJM MRC and Members Committee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be at the PJM Conference and Training Center in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report. (Note: The meetings were delayed by a week because of the pope’s visit to Philadelphia and relocated to the CTC because facilities were not available in Wilmington on the new date.)

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

Manual 40: Certification and Training Requirements. Makes miscellaneous edits; clarifies concepts, roles and responsibilities related to PJM’s systematic approach to training; updates the process for member training and PJM certification and reflects changes in terminology of operator titles.
Manual M10: Pre-Scheduling Operations. Adds procedures for maintenance outages under Capacity Performance rules: the requirement for PJM members to provide estimated “early return time” for planned outages; ensures that PJM will coordinate rescheduling if it withdraws or withholds approval of a planned outage; references PJM’s authority to withhold or withdraw approval of maintenance outages with at least 72 hours’ notice; adds requirement that maintenance outages be submitted at least three days prior to the operating day of their commencement.
Manual 14D: Generator Operational Requirements. Incorporates minor changes to the cold weather testing program for seldom-used generators. (See “Members Choose Status Quo on Winter Testing” in PJM Operating Committee Briefs.)
Manual 14B and 14A: Generation and Transmission Interconnection Process. Changes document how PJM will oversee transmission projects that have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy. (See PJM Wins OK on Multi-Driver Tx Projects.)

3. PRICE FORMATION (9:30-10:30)

Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. The proposal, hammered out by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and the PJM Power Providers Group (P3), would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments. (See related story, Consensus Near on Energy Market Offer Cap?)

Members Committee

CONSENT AGENDA (1:20-1:25)

B. The committee will be asked to endorse Reliability Assurance Agreement revisions regarding external capacity rights. The rule change allows load-serving entities to meet their internal capacity requirements using historic resources under certain conditions: The percentage internal resource requirement is enforced only if the locational deliverability area has been separately modeled due to certain triggers; a fixed resource requirement entity is permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative are due four months prior to a Base Residual Auction instead of the current two-month deadline. (See IMEA Reaps Limited Relief from Capacity Rule Change.)

C. New Tariff language reflects the switch from eMkt to Markets Gateway.

ENDORSEMENT (1:25-2:25)

Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. (See MRC agenda item 3, above.)

September 29, 2015

NYPA Head Pledges ‘Most Advanced’ Utility

By William Opalka

SARATOGA SPRINGS, N.Y. — New York Power Authority CEO Gil Quiniones says the state-run company will be the “most innovative and advanced utility in the U.S. in a very short period” due to massive investments and its commitment to facilitate the remaking of the industry in the state.

Addressing the fall conference of the Independent Power Producers of New York, Quiniones said NYPA expects to spend $3 billion to $4 billion on infrastructure over the next decade, with nearly half of that total — $1.5 billion — in smart grid generation and transmission assets.

New York has embarked on the Reforming the Energy Vision initiative to transition to cleaner and more distributed generation. NYPA’s five-year strategic plan was written in the context of REV, he said.

That means a revamping of operating procedures and technologies that can accommodate distributed resources. “As we move into this REV world, we have to be sure that all this generation and transmission infrastructure works in synchronicity with the advent of distributed resources,” Quiniones said. “… Our grid has to be connected and smart and optimized and the only way to do that is to digitize it and use big-data analytics.”

NYPA has 16 power plants and 1,400 circuit miles of transmission, including one-third of the state’s high voltage system. It serves 51 small municipal and rural cooperatives.

One project now underway is the retrofit of the Massena substation, which Quiniones said will result in “the most advanced substation of its size in this country. It will be microprocessor-based, fiber optic-based; it will provide unparalleled situational awareness and operational flexibility.”

Last year, NYPA built a 15-MW microgrid on Rikers Island in New York City, which captures waste heat from the facility and runs parallel and synchronous to the utility system. It can island in the event of another city-wide power interruption, such as during Superstorm Sandy. This is intended to be the first of several microgrids NYPA will build.

NYPA is acting as a facilitator with vendors SolarCity and SunEdison to install solar panels at the 698 school districts in the state. “I predict there will be a very fast ramp up of solar in our public schools,” Quiniones said.

In October, six drones from different vendors will be tested to monitor the condition of power lines. The authority also is beginning to monitor power line conditions and operations with a robotic device from Hydro-Quebec.

Much of the innovation is taking place in the North Country, home to most of the state’s wind farms, whose variability stresses the system.

Other initiatives include:

Installing dynamic line rating technology sensors and intelligence so the system can know exactly how much power is being carried through its lines. This aids efficiency by acting as a “fast switch” as it can transfer as much as 300 MW from one line to another in milliseconds to prevent system overload;
Condition-based monitoring that would base equipment replacement on the condition of the asset rather than on manufacturers’ recommendations;
Transformer-testing software to prevent catastrophic events.

September 29, 2015

Consensus Near on PJM Energy Market Offer Cap?

By Suzanne Herel

The authors of four competing proposals to change the $1,000/MWh energy market offer cap have agreed to put forward one plan for consideration by the PJM Markets and Reliability Committee on Thursday — the last chance stakeholders will have to come to consensus before the Board of Managers takes the issue into its own hands.

The proposal outlined during a special MRC meeting last week would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments.

There would be no change to the treatment of the 10% adder, shortage penalty factors and start-up or no-load compensation. Cost-based offers would be considered to include the 10% adder.

The framework was hammered out during a conference call last week attended by Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3), the Independent Market Monitor — jokingly dubbed “the four horsemen”— and PJM staff.

“I think it’s fair to say that none of the four proposers who participated in the call felt it was their home run,” said committee secretary Dave Anders. “But it was something they looked at as a bridge that, should the stakeholders come to consensus on it or something close to it, it could work for this winter and until FERC” takes action.

Stakeholders already had been rushing to reach consensus after being told in July at the Liaison Committee meeting that the Board of Managers planned to take up the issue in time for winter.

Then, on Sept. 17, FERC announced its intention to take action on offer caps and other price formation issues. The commission made the statement as it issued a proposed rule requiring RTOs and ISOs to align their settlement and dispatch intervals (RM15-24). It gave no timeline for future action. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

PJM Approves

PJM’s Adrien Ford said the new framework “is something PJM staff can fully support” to the board.

Absent consensus, she said, staff is prepared to recommend a Tariff change similar to the waiver it filed last year, which allowed prices to rise as high as $1,800/MWh. PJM made it through the winter without having to invoke it.

Staff would recommend, however, that the increased cap remain beyond the winter and would clarify in its transmittal note that any FERC action would supersede the new language, Ford said. “We view it as an interim solution for a winter or two,” she said.

PJM staff hasn’t finalized exactly what it would recommend if consensus can’t be reached, she said. One outstanding issue is whether to eliminate the cap altogether. Any solution supported by PJM would allow generators full cost recovery, she said.

Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.

On Thursday, ODEC, Direct Energy and the Market Monitor said they would withdraw their proposals to support the new framework. David “Scarp” Scarpignato of Calpine, which is a member of P3, said he hadn’t had time to canvass the group to guarantee they would do the same, but he said initial feedback from the P3 members he reached during a break in the meeting pointed in that direction. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)

“We see there are some areas we’re not going to come to agreement in the time we have to do so,” said Steve Lieberman of ODEC. “But we’re probably not as far apart as we may have thought. Is it perfect? Absolutely not. We shouldn’t let that get in the way of an incremental improvement.

“It’s hard to argue that this is not an improvement. It does allow generators to recover their costs. It does offer load the security blanket of a cap, albeit higher than we otherwise would wish to support.”

Susan Bruce, representing the PJM Industrial Customer Coalition, agreed.

While noting that she had not reviewed the proposal with her clients, Bruce called it “a good-faith effort at compromise.”

She said she was pleased that market-based bids above $1,000/MWh must be below the cost-capped bids and that a hard cap will remain at $2,000/MWh.

“It addresses — maybe not ideally, but practically — many of the concerns that have been raised. While there are areas of this that would give customers pause, I think it’s hard to view this as anything but a good workable framework around consensus,” she said.

“It addresses my clients’ particular concerns about our aggregate market power. … The 10% adder is problematic, but if we’re looking for consensus, it will necessarily involve compromise.”

Exelon, Maryland Balk

Not everyone was on board, however.

“It falls woefully short of correct market principles that PJM should be endorsing and has endorsed in the past,” said Exelon’s Jason Barker. Payments to individual units, recovered in uplift, fail to send clear market signals, he said.

Walter Hall of the Maryland Public Service Commission said that the state would be unlikely to support an offer cap as high as $2,000.

“We have not been persuaded that there is a need at this time [for] a raising of the offer cap; however, we do agree that generator cost recoveries are important and would be willing to see some mechanism added to the PJM Tariff that would provide that, but without setting [LMPs],” he said. “We’re willing to discuss some alternative to that, some higher level of offer cap, but unlikely to be willing to go as far as $2,000.”

Hall also asked for more information regarding the generators most likely to be on the margin and setting the highest costs.

“We would have some concern that perhaps there are very inefficient units being maintained here that would be providing the last megawatt of electricity,” he said.

September 22, 2015

SPP to Push Regional Approach in First CPP Webinar

By Tom Kleckner

SPP’s Clean Power Plan (CPP) Task Force was given an advance look last week at a webinar that will open the dialogue with state and utility officials charged with implementing the Environmental Protection Agency’s CO₂ emission rule.

SPP is hosting the webinar Tuesday for air quality regulators, utility commissions and government contacts at its member utilities in each of the RTO’s 14 states. More than 70 had registered to attend as of last week.

SPP met its goal of having each state represented by at least one registrant, said SPP Vice President for Engineering Lanny Nickell, the RTO’s point person on the CPP.

“We want to introduce ourselves as an RTO, particularly to the air quality and environmental regulators,” Nickell said. “We haven’t done that before in a programmatic approach. They don’t all know who SPP is and how it works.”

Southern States Slower to Embrace Regional Compliance

The webinar attendees will hear from SPP that state-by-state compliance with EPA’s final CPP rule will be more costly than regional compliance, and that more new generation and transmission infrastructure will likely be needed. In addition to being more expensive, SPP says state-by-state compliance would be more difficult for the RTO to manage.

Asked about the SPP states’ early plans, Nickell said, “The states in our north have expressed the most interest in working with each other.” Pausing, he said, “I don’t get that same sense from the states in the South.”

Several of SPP’s states — Arkansas, Kansas, Louisiana, Nebraska, Oklahoma and Texas — are led by Republican governors and legislatures that have pledged to battle EPA’s final rules rather than comply.

SPP’s Sam Ellis, who led a staff team that “pored over” the final rules, said states have flexibility under the regulations, but “they would lose it if they don’t implement their own plan.” EPA says it will implement a federal plan in the states that do not submit an “approvable” plan of their own.

Trading Framework

The final rule provides a framework for trading of CO₂ allowances. Nickell is expected to tell the webinar attendees that there are merits to developing regional carbon trading markets and will encourage states to develop their own plans.

Ellis told the task force EPA will consult with “planning authorities” in developing the federal plan and accept comments on whether to include allowances for reliability emergencies. He said the agency believes its rate-based and mass-based approaches contain sufficient flexibility to mitigate reliability issues without having to seek extensions under the reliability safety valve.

“The EPA may not have considered interactions between the federal plan and potential state plans for a given region,” Ellis said.

The Clean Power Plan Task Force was formed under the Strategic Planning Committee’s direction to review EPA’s federal implementation plan and recommend the role SPP should play in assisting states’ compliance. The group will also work to ensure regulators have a clear communications path to SPP.

“Our hope is SPP develops concepts and policies the states can embrace,” said Michael Desselle, SPP’s chief compliance and chief administrative officer and the task force’s staff secretary.

The webinar is the beginning of SPP’s communication effort. Besides the broad overview of SPP and its responsibilities, registrants will receive SPP’s take on the CPP and a high-level overview of the three analyses it has already performed on the CPP — though, as Nickell noted, those assessments were done on the EPA’s earlier draft rules. (See SPP: State-by-State Compliance Would Hike Costs.)

“We want to talk about what we believe our role to be, and that’s reliability,” he said. “We want to encourage the regulators in our states to talk with us, and to do so early in the process.”

September 22, 2015February 5, 2025

DER, Capacity Performance Issues at PJM Market Summit

By Suzanne Herel

PLYMOUTH MEETING, Pa. — PJM staff, stakeholders, financiers, regulators and industry leaders debated the effects of environmental rules and RTO policies on the capacity market, reliability and investments at Infocast’s PJM Market Summit 2015 last week.

Following are some highlights. (Presentations for the executive forum, “Disruptive Factors in the PJM Market,” can be found here.)

Mike Kormos, PJM executive vice president and chief operations officer, gave the keynote address, “Priorities and Future Directions for the PJM Interconnection.”

Kormos borrowed a phrase from outgoing CEO Terry Boston for his presentation: “The future ain’t what it used to be,” highlighting the differences between projections from two decades ago and the reality of today.

One of the biggest game changers is gas.

“Even as late as 2007, gas wasn’t being talked about. Gas was too volatile. People didn’t want to get into that part of the business,” he said. “Now, gas is king. It’s all we’re seeing.

“Everyone is thinking gas will remain cheap and plentiful.” But, he said, “We were wrong in 2000. Are you sure we’re right in 2015?”

Prospects for Adoption of Distributed Energy Resources

“The future is quite uncertain,” said Steve Fine, vice president at ICF International. “A lot is going to depend on how DER interacts with the wholesale market.” There, aggregators would play an important role.

He added: “We’re moving away from a net metering system and more toward a distribution resource planning process.”

There are barriers to adoption, he said, including customer pushback, the impact on rates and utility financials, policy uncertainty, metering and data transmission issues, and interconnection standards.

Implications of EPA 111(d) on the PJM Market

pjm — From left to right: Reid Harvey, EPA; Asim Haque, PUCO; Harry Singh, Goldman Sachs; Kathleen Barron, Exelon; and Joe Kerecman, Calpine. © RTO Insider

Reid Harvey, director of the Environmental Protection Agency’s Clean Air Markets Division, said that the agency is holding calls with states and groups of states to determine how they plan to implement the final Clean Power Plan released in August.

Joe Kerecman, director of government and regulatory affairs for Calpine, said he favors a regional approach. “Just like in PJM, scale matters to market efficiency, and we think that would be the best outcome,” he said.

Kathleen Barron, senior vice president of federal regulatory affairs and wholesale market policy for Exelon, said the Illinois energy giant will be keeping an eye on how the plan’s implementation will affect its nuclear plants, some of which are struggling.

“The CPP is really the last big unknown,” she said. “We’ll be looking very closely at how states are trending for CPP implementation and what that means for our nuclear stations. It’s too soon to know whether the CPP will be the missing link for this particular sector, but we’re keeping an eye on it.”

For his part, Asim Haque, vice chairman of the Public Utilities Commission of Ohio, said his state would be litigating the rule.

A New Day for Demand Response

Greg Poulos, manager of regulatory affairs for EnerNOC, said demand response provides an “incredible value” to consumers. “If you take demand response out of the capacity market, it would cost consumers about $10 billion annually,” he said.

Allen Jones, a consultant for the OPENADR Alliance, said the use of DR is changing, regardless of what the Supreme Court decides on the D.C. Circuit Court of Appeals ruling threatening FERC’s authority over DR.

“It’s being used for more than just, ‘Oh we have a terrible problem, we need to curtail some load,’” he said, noting that retail giant Walmart, among others, has piloted a program integrating it into its energy use plan. “Demand response is going to be something you’re going to see more and more of.”

The Results of the Capacity Auction

pjm — From left to right: Jason Barker, Exelon; Jason Cox, Dynegy; Mike Bryson, PJM; and John Rohrbach, ACES. © RTO Insider

The winners of the new capacity market construct are the consumers, said Jason Barker, director of wholesale market development for Exelon. “We’ve estimated the net benefits to consumers somewhere in the neighborhood of $1 billion to $7 billion per year,” he said.

Among the surprises for George Katsigiannakis, principal of ICF International, was the amount of new generation. “I expected a larger amount,” he said.

“The price of the base product was the biggest surprise from that auction. The amount of DR was a surprise for me, also — I was expecting less DR,” he said.

Pricing, however, was not a shock, he said. “We were expecting those levels.”

Steve Lieberman, director of RTO and regulatory affairs for Old Dominion Electric Cooperative, said he expected a much greater spread between the Capacity Performance and base products.

Now, he said, “I’m hoping we can sit on our hands and stop fussing with it. … Let the auctions run, take a step back, digest the results and take it from there.”

September 22, 2015

Iberdrola, UIL Would Clean Up Site if Connecticut Acquisition Approved

By William Opalka

Iberdrola USA and UIL Holdings have agreed to clean up an abandoned power plant site in New Haven if Connecticut regulators approve their proposed $3 billion merger.

The companies on Thursday agreed to a consent order with the state’s Department of Energy and Environmental Protection that would allow the contaminated English Station site to be cleaned up for reuse.

The Connecticut Public Utilities Regulatory Authority rejected the proposed acquisition in June on other grounds, saying that the plan was not in the public interest. The companies refiled a new plan in July that they said addressed regulators’ objections. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)

The state estimates site remediation would cost under $30 million. The companies have committed to spend any amount in excess of that if necessary.

The agreement was announced in a statement by Gov. Dannel P. Malloy, Attorney General George Jepsen and DEEP Commissioner Robert Klee. “The state will strongly oppose any attempt to recover remediation costs from ratepayers. The companies will propose the scope of work to fully examine the pollution and clean it, and DEEP will review and approve the scope of work,” they said.

“This is an important settlement — to New Haven and to Connecticut. The English Station has long been a site that absolutely needed to be cleaned up and given a second life, and now it will be,” Malloy said in the statement.

The plant is situated on Ball Island in the middle of the Mill River in New Haven. It was operated by UIL unit United Illuminating for 63 years and closed in 1992. It is contaminated with polychlorinated biphenyls, heavy metals and other contaminants.

Administrative proceedings will continue against UIL to determine responsibility for cleanup of contamination in the river, according to state officials.

The acquisition, which includes natural gas distribution companies in Massachusetts, must also be approved by that state’s regulators.

Connecticut regulators will conduct hearings on the acquisition in October. A decision is expected by Dec. 4.

September 22, 2015

FERC to Look over NERC’s Shoulders on Reliability

By Rich Heidorn Jr.

FERC said last week it will require the North American Electric Reliability Corp. to provide the commission access to NERC databases in what Chairman Norman Bay said is an effort to apply “Moneyball” techniques to reliability.

The commission issued a Notice of Proposed Rulemaking that would give FERC access to NERC’s transmission availability data system (TADS), generating availability data system (GADS) and protection system misoperations databases (RM15-25).

“It takes the concept of ‘Moneyball’ to our analytics on reliability,” said Bay, referring to the best-selling book on Oakland Athletics General Manager Billy Beane’s use of statistical analysis in evaluating baseball players.

The commission said access to the data “would inform the commission more quickly, directly and comprehensively about reliability trends or reliability gaps that might require the commission to direct [NERC] to develop new or modified reliability standards.”

TADS and GADS contain data on transmission and generation outages, respectively, including cause codes.

The protection system database collected information on about 2,000 misoperations in 2014, including causes. “Protection system misoperations have exacerbated the severity of most cascading power outages, having played a significant role in the Aug. 14, 2003, Northeast blackout,” FERC said.

“While the aggregated TADS, GADS and protection system misoperations data provided in NERC’s periodic reports afford the commission some insight into the reliability and adequacy trends identified by NERC, we believe that having direct access to the underlying data will assist the commission in its understanding of the periodic reports, thereby helping the commission to monitor causes of outages and detect emerging reliability issues,” FERC said.

FERC Micromanaging NERC?

Commissioner Cheryl LaFleur issued a concurring statement expressing concern that the proposal could be seen as micromanaging NERC. Although FERC has ordered NERC to initiate standards on geomagnetic disturbances and physical security, LaFleur said that authority should be used sparingly.

“It is important that we recognize the distinction between [FERC’s] oversight role and NERC’s primary responsibility to monitor reliability issues and propose standards to address them. Ultimately, I believe our efforts to sustain and improve the reliability of the bulk electric system are furthered by mutual trust and shared priorities between the commission and NERC,” she said.

“I understand that today’s proposal might be controversial within the NERC community. I therefore welcome comment on the proposal, including any potential issues or concerns not identified in the NOPR.”

Comments on the proposal are due 60 days after publication in the Federal Register.

The commission also gave final approval to two sets of reliability standards and preliminary approval to a third.

FERC approved reliability standards PRC-002-2, which specifies requirements for time-synchronized data for post-disturbance analysis (RM15-4), and PRC-005-4, adding sudden pressure relaying systems to the protection system maintenance rules (RM15-9).

It also approved a NOPR proposing to approve standard PRC-026-1, which would require that protective relay systems differentiate between faults and stable power swings (RM15-8).