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

New NYISO Head Brings Broad Experience

By Tom Kleckner and William Opalka

Bradley C. Jones joined ERCOT little more than two years ago from Energy Future Holdings as the grid operator’s vice president of commercial operations. The job gave him responsibility for market operations, design and development, settlements, retail operations and client relations.

He wouldn’t stay long.

In January, ERCOT appointed him senior vice president and chief operating officer, putting him in line to potentially succeed CEO H.B. “Trip” Doggett, who announced in June that he will retire in 2016.

In August, however, ERCOT named General Counsel Bill Magness as Doggett’s successor. So last week, after less than nine months in his new job, Jones announced he would succeed Stephen C. Whitley as CEO of NYISO.

Jones (left), Whitley (right) (Source: NYISO)

Jones will take over Oct. 12, as the New York power market faces a proposed overhaul led by the state’s governor and utility regulators.

In January, Gov. Andrew Cuomo called for the Public Service Commission to review the ISO, saying its market design is at odds with his administration’s Reforming the Energy Vision initiative, which seeks increased deployment of distributed resources and clean energy. Cuomo also called for more public and consumer representation on the ISO’s Board of Directors. (See NYISO: We’ll Cooperate with PSC Review.)

The ISO’s other challenges include the continuing shift to natural gas generation; reliability concerns caused by coal retirements and above-market contracts needed to keep some generators operating; transmission constraints into New York City; and discussions to change the capacity market that have not reached consensus.

Three Decades

Those who know him at ERCOT say Jones’ nearly three decades of experience in the industry have prepared him for the challenges.

“Brad was integral in the creation of the successful ERCOT market,” said Theresa Gage, ERCOT’s vice president of external affairs and corporate communications. “We are sad to see him go, but we are proud that NYISO recognizes the excellence in Brad that benefited the ERCOT market for so long.”

His new bosses in New York say Jones’ experience in the private sector and with the Texas grid is what made him the best candidate.

“The board gave serious consideration to a number of highly qualified and impressive candidates — both internal and external — and ultimately selected Mr. Jones because of his long and distinguished career in the electric sector,” NYISO spokesman David C. Flanagan. “His diverse background — with experience in grid operations, power plant operations, generation development, project finance, market design, and regulatory and legislative affairs — was the best fit for the NYISO at this point in its history.”

Whitley announced in January he would step down after more than seven years as the ISO’s head. He will remain with NYISO during a transition period and will become an adviser to the Board of Directors.

Jones last week declined an interview request, saying he is not yet ready to talk publicly. In a statement, he said he was “excited about the opportunity to work with the NYISO’s employees and stakeholders, as well as with government officials.”

Florida Native, Texas Career

Though born in Florida, Jones has spent most of his time in Texas, where he and his wife raised their six children.

He earned a bachelor’s degree in mechanical engineering from Texas Tech University and a master’s degree in finance from The University of Texas at Arlington. He is a registered professional engineer in Texas.

Last Coal Plant

He joined TXU Corp. as a plant engineer, rising through the ranks and various executive positions in retail, generation, investor relations, government relations and regulatory affairs. He led the development of TXU’s Oak Grove Project, a 1,634-MW coal-fired generating station located near College Station, Texas, and the last coal plant to be built in the state.

He remained with TXU after Energy Future Holdings (EFH) acquired the utility and its subsidiaries in a 2008 leveraged buyout. When he was tapped by ERCOT, Jones was serving as vice president of government relations for EFH’s competitive businesses.

While with TXU and EFH, Jones chaired ERCOT’s Technical Advisory Committee, which is comprised of stakeholders that make recommendations on operating guides and market protocols to the ISO’s Board of Directors.

Texas Market

“With his deep knowledge of the industry, Brad was always such a great resource for me,” said Pat Nichols, a senior communication strategist with TXU and EFH. “I was sorry to see Brad leave EFH but glad for his success.”

During the 1999 legislative session, Jones worked with the Texas Legislature to restructure the electric industry and allow customers to choose their electric suppliers. Then, as the Texas electric market prepared for retail competition, he led several ERCOT workgroups and committees that created the state’s competitive electricity market.

In 2001, Jones became one of only four recipients of the Public Utility Commission of Texas Commissioner’s Award for his leadership in preparing the state’s electric market for competition. He is well connected within the industry, having served on the boards of the Gulf Coast Power Association and FutureGen Industrial Alliance, chaired an Edison Electric Institute advisory committee and participated on a Texas Reliability Entity committee.

[Editor’s Note: An earlier version of this article mistakenly suggested that ERCOT had not yet chosen a successor for retiring CEO H.B. “Trip” Doggett.]

September 22, 2015

PJM to FERC: We’re Prepared for Winter

By Suzanne Herel

PJM is prepared to meet this winter’s load — even if it’s a bit higher than the record peak seen last season, COO Mike Kormos told FERC last week.

PJM’s winter preparedness study considered a peak load of 135,350 MW (not including demand response), below the record winter peak of 143,086 set Feb. 20.

“We did not identify any reliability problems,” he said. “Our margins are fairly sufficient as well. We do not see anything at this point that is problematic to us.”

pjm — PJM is responding to generation retirements (blue circles) with new generation (orange circles) and transmission (yellow lines).

PJM officials are feeling more comfortable, in part, because of the improved generator performance last winter.

Generator outage rates, which exceeded 20% during the 2014 polar vortex, were generally less than 15% last winter. Officials plan to repeat the winter preparation checklist and a testing program for seldom-run units that were credited with improving performance. (See Why Did PJM Grid Fare Better This Winter?)

Kormos noted that about 10,000 MW of generation has retired since last winter, only about 3,000 MW of which has been replaced. Although the RTO feels confident it can make up the losses, in part due to new transmission, “it is a 7,000-MW difference,” Kormos said.

In addition to making enhancements to the grid, PJM has been working on its relations with the gas industry. “We have spent a lot of effort since last winter continuing coordination,” Kormos said.

PJM this summer signed an information-sharing agreement with nine interstate pipelines. (See PJM, Pipelines Pledge Increased Cooperation to Boost Reliability.)

Beginning Nov. 1 until March, PJM will be holding weekly calls with the pipelines to talk about upcoming maintenance on either side, projected peak loads and forecasting conditions, he said.

Kormos said he was encouraged by one pipeline’s recent announcement that it is considering offering firm service customized for generators’ needs.

“Generators are not [local distribution companies]. They don’t draw gas every hour, seven days a week, 365 days [a year] like an LDC does. They don’t have storage contracts in place like LDCs do,” Kormos said. “They need a different service.

“We feel we are in a much better situation after the past two winters,” he continued. “We believe we’re doing a better job coordinating.”

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).