PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight

By Suzanne Herel

VALLEY FORGE, Pa. — Members debated four potential changes to the $1,000/MWh energy offer cap last week at a specially called meeting of the Markets and Reliability Committee, failing to agree on any one — or even which should be the main and alternate proposals.

Further discussion was deferred until Sept. 24, giving stakeholders only a few weeks to reach consensus before the Board of Managers takes the matter into its own hands before winter.

The proposals were presented by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and — for the first time — Calpine and the PJM Power Providers Group (P3).

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 periods of extreme temperatures, such as the 2014 polar vortex.

Direct Energy had kicked off the latest effort to reach agreement in July with its plan to raise the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers. The number is 50% more than the highest offers reported by PJM last winter. PJM said that it would support the Direct Energy proposal. (See PJM Stakeholders Struggle for Consensus on Offer Cap.)

Joe Wadsworth of Vitol reiterated his concern about potential unintended consequences inherent in applying different rules to the day-ahead and real-time markets. “We could be artificially creating arbitrage opportunities,” he said, adding that such a scenario might invite increased scrutiny from FERC enforcement.

“We need to ensure the day-ahead and real-time market parameters are the same whenever we can,” he said.

Jim Jablonski, of the Public Power Association of New Jersey, said that whatever the proposed offer cap is, it’s critical it be able to be supported by data. “We can’t get to FERC and say, ‘Oh, we just doubled the old one.’”

Jablonski asked Direct Energy’s Jeff Whitehead if he could estimate exactly how much uplift a higher cap might eliminate. “I’d love for somebody to say, ‘This is how much,’” he said.

Whitehead responded, “The higher the offer cap, the less uplift we’ll have.”

Steve Lieberman of ODEC called his plan “the only proposal that was a joint effort of load and supply.”

It would allow cost-based offers of up to $1,800/MWh and allow them to set LMPs.

And, he said, “Old Dominion firmly believes in the need for a cap that is the same in both markets.”

The Monitor’s proposal would allow cost-based offers to exceed $1,000/MWh when a unit’s short-run marginal costs exceed that cap. Price-based offers would have to be less than or equal to such cost-based offers. Monitor Joe Bowring said the approach addresses the issue of market power when the overall market is tight.

The P3 proposal was the only one that had not previously been presented.

In making the presentation, David “Scarp” Scarpignato of Calpine said that because generators have a must-offer requirement to enter into the day-ahead market, it’s essential they be able to recover their costs.

“The uplift method is a bad idea,” he said. “It’s unhedgeable, and there’s extra risks added to load prices. If you don’t put them into LMP, you lose a very important market signal.”

In allowing offers to set LMPs, according to the proposal, higher prices incent generators to perform.

Like Lieberman, Scarp said the day-ahead cap must equal the real-time cap. Under his proposal, cost-based offers for both markets would be capped at cost plus 10%; market-based offers would be capped at the higher of $2,700/MW or the cost-based offer.

The proposal also sets penalty factors of $1,350/MW for synchronized or primary reserves, and $750/MW for excess synchronized or primary reserves.

September 15, 2015

PJM Transmission Expansion Advisory Committee Briefs

PJM has reduced the number of potential transmission fixes for the AP South/AEP-DOM constraints to six candidates.

Six other projects were eliminated following sensitivity analyses for changes in load forecasts and fuel prices.

The projects remaining cleared the 1.25 benefit-cost ratio under all sensitivities and also reduced both AP South and AEP-DOM congestion in combined 2019 and 2022 simulations.

The six proposals include three by Dominion Resources and one submitted by Dominion High Voltage Holdings and Transource Energy (itself a partnership of American Electric Power and Great Plains Energy). The finalists also include one project each from LS Power and Duke-American Transmission Co. Costs of the projects range from $25 million to $301 million.

The fuel price sensitivity looked at natural gas costs $1/MMBtu higher and lower than the prices assumed in the base case. The load forecast sensitivity included an increase and decrease of 2% in load.

LS Power’s Sharon Segner questioned the planners’ screening. “There’s nothing that puts any kind of weight on the cost side and cost containment,” she said. LS Power’s $48.6 million proposal includes a cost cap.

Paul McGlynn, PJM general manager of system planning, said planners will consider cost certainty in further pruning the list of finalists.

Planners hope to select a winning project in time to include it in the 2015 Regional Transmission Expansion Plan.

Last month, they announced the selection of 11 other market efficiency projects with a combined cost of $59.2 million to address congestion in other areas of the footprint. (See “11 Market Efficiency Projects Selected; 12 still in running for AP South/AEP-DOM,” in PJM TEAC Briefs.) Those projects will be recommended to the PJM Board of Managers in October.

McGlynn noted that the RTO has done relatively few market efficiency projects in the past. “We’re very pleased to be having on the order of a dozen [market efficiency] projects to be taking to the board,” he said.

Planners also will reevaluate nine proposed projects to address constraints on the Loretto-Wilton Center 345-kV line, which caused the COMED locational deliverability area to bind in the 2018/19 Base Residual Auction in August. COMED cleared at $215/MW-day, $50 above the RTO price. (See PJM Capacity Prices Up 37% to $165/MW-day.)

The projects, with costs ranging from $11.5 million to $290 million, fell short of the 1.25 benefit-cost ratio in the original analysis. But one or more could clear the threshold if the analysis shows they can increase COMED’s capacity emergency transfer limit, McGlynn said.

Reliability Projects

The 2015 RTEP also will include reliability projects selected from among 91 proposals — 26 transmission owner upgrades and 64 greenfield projects — made in response to Window 1, which closed July 20. The window covered N-1 and N-1-1 thermal and voltage problems as well as generation deliverability and common mode outage and load deliverability issues.

The proposals range in cost from $13,000 to $167.1 million.

The RTEP recommendations also will include dozens of generation-related network upgrades (see pp. 34-68 of the PJM presentation).

Meanwhile, planners have begun reviewing proposals received in response to Window 2, which closed Sept. 4. The window sought solutions for transmission owner criteria and light load reliability criteria violations.

High Voltage Problem in AEP

Planners are considering more than $51 million in transmission upgrades to address a large increase in the number of high-voltage warnings in the AEP transmission zone and northeastern Mid-Atlantic regions. AEP also has seen a large increase in reactor switching for both low- and high-voltage conditions.

The problems, which generally occur during light load periods, are resulting from changes in dispatch due to new and deactivated generation, reactive support deficiencies and increased line charging from new transmission facilities.

Planners are considering spending $51 million to install a 450-MVAR static VAR compensator at the Jacksons Ferry 765-kV substation and a 300-MVAR shunt line reactor on the Broadford end of the Broadford–Jacksons Ferry 765-kV line in southern AEP.

They’re also planning six new shunt reactor installations in New Jersey, the cost of which is still being finalized.

Pratts Area Update

Planners said they will recommend selection of a Dominion project that requires no new right of way to address reliability problems near Pratts, Va.

pjm — PJM staff selected Dominion to build a 230-kV line from the Remington substation to the Gordonsville substation.

Dominion will build a new 230-kV line from the Remington substation to the Gordonsville substation and install a third 230/115-kV transformer at Gordonsville at an estimated cost of $103.7 million.

PJM announced last month it was reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require about 18 miles of new rights of way, far more than initially believed. The proposal from Dominion Resources and FirstEnergy was estimated at $129 million to $164 million.

The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.

In response to a question, McGlynn said planners had not independently verified Dominion’s assertion that the new line could be built in the existing 115-kV corridor. “We relied on the work of the entities that proposed the project,” he said.

A representative from Madison County, Va., which had urged PJM to reject the original plan, praised the new solution, saying it was “symmetrical with the identified need and an appropriate fix.” The county had complained that the original project was unnecessarily large for the rural county.

— Rich Heidorn Jr.

September 15, 2015

FERC Again Denies Polar Vortex Make-Whole Payments

By Michael Brooks

The cold weather temperatures produced by the polar vortex of January 2014 continue to haunt FERC.

The commission has denied another generator’s request for $1.3 million in make-whole payments for natural gas it purchased that was never used during the event, citing rules against retroactive ratemaking (ER15-952).

New Jersey Energy Associates, which owns the 290-MW South River combined-cycle plant, said PJM asked that a planned outage for the plant be canceled so it could be available for dispatch on Jan. 27, 2014. The plant purchased $2.7 million worth of gas, having been assured by PJM that it would be compensated for its fuel costs, according to NJEA. The RTO, however, repeatedly canceled the plant’s scheduled start time, forcing it to sell the gas at a $1.3 million loss.

The claims are similar to those of Duke Energy and Old Dominion Electric Cooperative. During the same week as NJEA’s claim, Duke purchased gas for $12.5 million when PJM said that its Lee plant in Illinois would be needed. The plant was never called on, however, and Duke was forced to sell the gas at a loss of $9.8 million. ODEC complained that PJM canceled multiple dispatches that left gas it had purchased unused and that it was due $15 million. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

FERC, however, remained steadfast on its assertion that these kinds of complaints constitute retroactive ratemaking.

“Ratepayers had not received any prior notice of NJEA’s requested relief, which was sought roughly 12 months after the events in question,” the commission said. “We therefore conclude, as we did in the similar Duke and ODEC cases, that the relief sought by NJEA is prohibited by the filed rate doctrine and rule against retroactive ratemaking.”

FERC, however, did find that NJEA was entitled to recover its start-up costs under PJM’s Tariff. The Tariff allows market participants to recover costs related to the start-up of resources offered in the day-ahead energy market if PJM cancels its selection of those resources. While NJEA did not specify how much they would be allowed to recover under this provision in its complaint, it said “this would only be a fraction of its actual unrecovered costs.”

As he did in the Duke and ODEC cases, Commissioner Philip Moeller dissented. He once again noted that PJM is the only grid operator that does not allow its participants to vary their day-ahead energy market offers by hour or update their offers in real time.

As a result of the Duke and ODEC complaints, FERC found that PJM’s Tariff was potentially unjust and unreasonable in this regard and ordered the RTO to make Tariff changes by Nov. 1. While PJM agreed that changes were needed, and it began the stakeholder process to do so, the RTO told the commission in July that it would need until Nov. 1, 2016, to resolve the numerous questions raised by the changes (EL15-73).

“In light of this delay in reforming PJM’s markets,” Moeller argued, “the majority’s repeated failure to guarantee cost recovery for generators acting in good faith to ensure system reliability may regrettably impact reliability during the approaching winter of 2015-2016.”

September 15, 2015

Baker: New England Must Sacrifice to Lower Costs

By William Opalka

BOSTON — New England’s states may have to set aside their self-interests to overcome high energy prices that are slowing the region’s economy, Massachusetts Gov. Charlie Baker told the 2015 ISO-NE Regional Plan meeting on Thursday.

The first-term Republican said the region’s competitive advantages are at risk, citing a “sense of desperation” among his fellow governors over energy costs.

“One of the things that’s going to be most fundamental to our ability to succeed is to develop strategies and plans that can get a lot of people who don’t necessarily agree on things to come together and find a way to put the optimal success of the region above what might be the most optimal solution for any particular player,” he said.

“We don’t believe we can achieve the energy security, competitiveness, reliability and affordability … alone. It’s got to be a regional conversation,” he said.

Massachusetts, Rhode Island and Connecticut agreed earlier this year to seek multi-state, long-term contracts to procure large-scale renewable resources. More problematic is building large, multi-state electric transmission and natural gas pipeline projects.

“I think it’s pretty hard to look at the data and conclude that we won’t need to increase our capacity over time,” Baker said, referring to New England’s increasing reliance on natural gas generation and the fuel shortages that occur in the winter months. (See Dueling Studies Dispute Need for More Pipelines in New England.)

He also endorsed exploring the feasibility of importing more hydropower, which would require expensive power lines. “Canadian hydro has potential to be a significant player in the region,” he said, adding that the decision to proceed will depend on how the projects affect ratepayers. “If it doesn’t make sense, we won’t do it,” he said.

Policy Mandates Sometimes at Odds with Market Forces, Panelists Say

Following the governor’s address, a panel discussed whether the region’s pursuit of public policy initiatives is incompatible with low-cost energy.

Over the past 16 years, panelists said, New England’s energy strategy has often been at cross-purposes. The development of competitive markets, the transition from coal to natural gas generation, the integration of renewables and the need for expensive infrastructure all have made it difficult to keep rates affordable.

“In New England, our representatives have decided that renewable energy is really important, notwithstanding whatever preferences the market may have in its short-term, day-to-day interest,” said Edward Krapels, founder of Anbaric Transmission.

“I see us going down two paths,” he said. “The planning by the ISO to maintain reliability leads you down one path. Actions by the governors to create a clean energy economy take you down a parallel path and the two don’t converge.”

He said the three-state model for procuring renewables is the beginning of that convergence.

Public policy has had to contend with “the historical forces of technology and geology” — cheap natural gas — said Katie Dykes, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection.

“This low gas price environment that we’ve had has done more for the fuel mix of this industry than the [Environmental Protection Agency] and the environmental advocates have been able to do over the last several years,” said Bob Hayes, vice president of natural gas trading for Calpine.

But he cautioned that the region’s dependence on liquefied natural gas “for the foreseeable future is a precarious one at best and one that I’d definitely be concerned about.”

Tanya Bodell, executive director of research firm Energyzt, said EPA’s initial draft of the Clean Power Plan was an example of policy ignoring reliability. EPA backed off from its proposed early deadline of 2020, delaying it by two years, after widespread criticism.

“That change was needed to show that your state plan is going to result in a reliable outcome,” she said.

September 15, 2015

MISO Beats Challenge on Wind Exports

By Rich Heidorn Jr.

MISO and its wind generators are having trouble getting along.

Just two days after FERC rejected allegations that MISO was blocking a wind farm from exporting power to PJM, the RTO was hit with a new complaint accusing it of giving special treatment to external generators seeking to deliver power into the Midwest.

The disputes have arisen as the RTO is attempting to close a capacity shortage that could arise as soon as 2020.

Acciona Wind Energy USA accused MISO in May of blocking it from selling power into PJM by improperly interpreting a process designed to streamline energy exports.

The company complained that MISO had excluded a portion of its 180-MW Tatanka wind farm’s capacity from participating in its pre-certified path study process, which allows interconnection customers to avoid lengthier studies when MISO evaluates their transmission service requests (TSRs). (See Acciona: MISO Blocking Access to PJM.)

MISO Acted ‘Reasonably’

But FERC ruled Sept. 2 that the claim was without merit, saying that MISO conducted Acciona’s system impact study in accordance with its Tariff and business practice manuals. “We find that MISO reasonably concluded that it was appropriate to deny the TSRs given the lack of available transmission capacity absent upgrades,” the commission ruled (EL15-69).

FERC also rejected the company’s claim that MISO was requiring it to make “several hundred million dollars” of upgrades, saying the estimate appears to include all of the costs of the N. LaCrosse-N. Madison 345-kV multi-value project rather than the “but for” upgrades required for Acciona’s service request.

Two days after FERC’s ruling, three wind generators filed a complaint asking the commission to block MISO from enacting rules that would exempt external generation from having to provide “cash at risk” deposits to enter the definitive planning phase, the final stage of the RTO’s study queue (EL15-99).

EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy said MISO’s external network resource interconnection service (E-NRIS) protocol is unfair to internal generation, which is required to make the M2 milestone payments. MISO won FERC approval for the milestone payments in 2012, arguing that they were necessary to weed out speculative projects, whose withdrawal from the queue results in time-consuming restudies.

‘No Safeguard’

The three companies sought fast-track status for their complaint, saying that MISO plans to add 7 GW of external generation into the queue, which it said could have an “enormous impact.”

“There is no safeguard to protect MISO’s queue management from further delay and restudies (and cascading restudies) if any of the 7 GW of [external projects] withdraws; nor is there any safeguard to protect interconnection customers from shifts in network upgrade costs if any [external] customer withdraws,” the complaint said.

The companies called the M2 milestone payment, which is based on generating capacity and transmission voltage, an “extreme burden,” saying a 150-MW project could be required to put up as much as $1 million.

They filed the complaint after MISO’s Planning Advisory Committee delayed a vote Aug. 19 on a proposal by Wind on the Wires that would have imposed the M2 costs on external generators. (See Interconnection Deposit Proposal Tabled.)

MISO and PAC members agreed to postpone the discussion to the Sept. 16 meeting, the companies said, but MISO later informed members that the E-NRIS protocol is final.

Capacity Worries

MISO is seeking to attract and retain capacity resources to offset retirements of coal-fired generation as a result of federal environmental rules and competition from low-cost natural gas.

In 2014, MISO projected it would face a 2.3-GW capacity shortfall beginning next year. In June, however, the RTO said its newest survey with the Organization of MISO States indicated it will have enough capacity to offset any zonal shortages until 2020. (See MISO Survey: No Shortfall Until 2020.)

September 10, 2015

PJM Transition Auction Means Reprieve for Exelon Nukes

By Suzanne Herel and Rich Heidorn Jr.

VALLEY FORGE, Pa. — Capacity Performance resources cleared at $151.50/MW-day in the transition auction for the 2017/18 delivery year, PJM said Wednesday, calling the results “demonstrably competitive” at nearly $60/MW-day below the RTO’s price cap.

The results meant at least a temporary reprieve for Exelon’s Quad Cities and Byron nuclear plants, which cleared the transition auction after failing to clear in the Base Residual Auction for 2017/18. Exelon said Thursday morning that all of its nuclear plants in PJM cleared in the transition auction and that the company will defer any decisions about the future of Quad Cities and Byron for one year.

PJM held the auction Sept. 3-4 to obtain CP resources for 70% of the updated reliability requirement for 2017/18, procuring its target of about 112,195 MW, said Stu Bresler, senior vice president for markets. The clearing price cap was $210.83/MW-day, or 60% of the net cost of new entry.

Bresler said the results showed “a very steady, very rational progression of clearing prices given the steadily increasing proportion of our reliability requirement that we procured as Capacity Performance for these three delivery years.”

The RTO-wide clearing price was $134/MW-day for the 2016/17 transition auction, which obtained 60% of total requirements as CP. (See PJM 2016/17 Transition Auction Clears at $134/MW-day.)

The transition auction for 2017/18, which cleared $17.50/MW-day higher, procured 70% of total requirements. Neither transition auction had locational restraints.

In the Base Residual Auction for 2018/19, where 80% of resources were CP, most of the RTO cleared at $164.77.

New Generation in COMED, ATSI Zones

Total capacity offered into the 2017/18 transition auction was 133,769 MW. Of the capacity that cleared, 102,178 MW represented resources committed in previous auctions that now will be converted to the new product at a higher price.

About 10,000 MW of the CP that cleared were from resources that did not clear in the Base Residual Auction in 2014, less than 9% of the total.

Bresler said most of the newly cleared generation was in the COMED (almost 4,000 MW) and ATSI (more than 2,300 MW) zones.

“I think it was fairly well publicized after the Base Residual Auction for ’17/18 the resources that did not clear,” he said. “It just speaks to those that were available to do so in this particular auction from those zones. And I think that’s what we saw.”

PJM reported that 4,339 MW of nuclear cleared for the first time in the transition auction.

Exelon confirmed that Byron Units 1 and 2 (2,336 MW) and Quad Cities Units 1 and 2 (1,737 MW) in Illinois, which did not clear the BRA for 2017/18, were among the winners this time around. (See How Exelon Won by Losing.)

The company said Thursday that it will continue operating Quad Cities through at least May 2018. Byron is already obligated to operate through May 2019. It said it will bid all its eligible nuclear plants, including Quad Cities, Byron and Three Mile Island into the 2019/20 BRA next year.

“While Quad Cities and Byron remain economically challenged, we are encouraged by the results of the recent capacity auctions. The new market reforms help to recognize the unique value of always-on nuclear power, while preserving the reliability of our electric system,” Exelon CEO Chris Crane said in a statement. “However, these plants are long-lived assets with decades of useful life left, and today’s decision is only a short-term reprieve. Policy reforms are still needed to level the playing field for all forms of clean energy and best position the state of Illinois to meet [the Environmental Protection Agency’s] new carbon reduction rules.”

The company said it will “continue its dialogue” with Illinois policymakers for state support for the nuclear units.

New Coal Also Clears

Some 4,165 MW of coal-fired generation also cleared for the first time in the transition auction.

In total, coal cleared 37,455 MW; gas 35,298 MW; and nuclear 29,970 MW.

Higher percentages of energy efficiency (almost 28%) and demand response (65%) came from new rather than previously cleared resources. Of 700 MW of DR acquired, 455 MW represented new commitments.

“I can’t really speculate on the drivers there,” Bresler said. “My hypothesis, I guess, would be that these demand response providers have since the Base Residual Auction for ’17-18 found additional resources that could provide the Capacity Performance level of reliability and therefore offered those resources into the auction.”

$1.7 Billion Increase

The Base Residual Auction for 2017/18 — held in 2014, before the introduction of the tougher CP requirements — cleared at $120/MW-day in most of PJM, with the PSEG locational deliverability area at $215. (See Capacity Prices Jump Following Rule Changes.)

The incremental cost of the transition auction was $1.7 billion, below the estimate of $3.1 billion to $4.2 billion PJM and the Market Monitor had predicted, Bresler said.

Independent Market Monitor Joe Bowring declined to comment on the results aside from saying that they were consistent with the rules. He said his office is working on a comprehensive report on all three CP auctions.

Walter Hall, of the Maryland Public Service Commission, said his agency is keeping an eye on how the prices will affect consumers. “Obviously, it’s going to increase prices somewhat,” he said. “That is a negative. It is a problem, but it’s a problem we knew was coming.”

Dan Griffiths, executive director for the Consumer Advocates of PJM States, said he still had to review the numbers.

But, he said, “I don’t think our position has changed, that this was an extremely excessive solution to the problems we faced.”

PJM, he said, “never considered the impact on consumers.”

Higher Risks, Rewards

The Capacity Performance construct allows capacity resources to receive higher prices in exchange for taking on stiffer penalties for non-performance.

The transition auctions, part of a five-year shift leading to 100% CP for the 2020/21 delivery year, had been delayed in order to allow DR and energy efficiency resources to participate, per a FERC order.

Under the rules of the transition auctions, participation is optional, and market participants may offer all or part of resources that were committed under the Base Residual Auctions for those years as Capacity Performance resources.

The RTO’s 2018/19 Base Residual Auction, the first BRA under the CP rules, saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.

CP resources were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL LDA, the premium was $90. (See PJM Capacity Prices Up 37% to $165 /MW-day.)

September 1, 2015

Timing of PJM Auction Announcement Sparks Real-Time Debate

By Rich Heidorn Jr.

CAMBRIDIGE, Mass. — PJM’s 2016/17 transition auction results were released shortly after the stock market closed at 4 p.m. Monday — coincidentally during an EUCI conference in Cambridge, Mass., that attracted PJM Market Monitor Joe Bowring, PJM Senior Economic Policy Advisor Paul Sotkiewicz and Jim Wilson, a consultant to consumer advocates in the RTO.

Wilson, a featured speaker, reported — critically — on the results shortly after they were released, sparking a lively debate with Sotkiewicz. Bowring, uncharacteristically, declined to offer an opinion.

“Unfortunately, the way [PJM] ran the auction, instead of paying people $10, $20, maybe $30 [per MW-day] to upgrade their capacity commitment to Capacity Performance, they created a new clearing price of $134/MW-day, paid to everybody,” Wilson said.

“Of the 95,000 MW that cleared, almost all of it was in the RTO region and not in [MAAC], and they were able to go from $60 their previous clearing to $134. They basically get a $60 windfall — or about $1.7 billion,” Wilson said, concluding: “Very inefficient.”

That sparked a response from Sotkiewicz, who had appeared on an earlier panel with Bowring — both of them already aware of the results but sworn to secrecy until their release.

Sotkiewicz said that during the January 2014 polar vortex, “a lot of [the high generator outages were] coal resources in the west, gas generators in the west who were behind the [local distribution company] city gate who had no firm transportation to the city gate. Even if they did, they could be curtailed by the LDC. [They] also didn’t have dual-fuel capability.

“So, quite to the contrary, a lot of the problems that we did see were in the west during January. So to say that [the CP acquired was] in the west and it’s useless I think is disingenuous and incorrect.”

Asked for his opinion on the “efficiency” of the auction after the conference ended, Bowring seemed uncharacteristically tongue-tied, pausing and exchanging glances with Sotkiewicz.

“We’ll be doing a report on it fairly soon and have a detailed analysis,” he said finally. “It’s hard to tell just looking at the prices. We reviewed the outcome. The outcome was consistent with the rules.”

September 1, 2015

MISO Proposes $2.4 Billion in Transmission Projects

By Chris O’Malley

ST. PAUL, Minn. — MISO staff will seek board approval in December for about 352 transmission projects totaling $2.4 billion in its 2015 Transmission Expansion Plan.

That’s virtually the same dollar amount as MTEP 14, but this year’s plan includes more baseline reliability projects and what could be the first competitively bid market efficiency project.

The largest of the projects in MTEP 15 is Entergy’s controversial $187 million Lake Charles, La., baseline reliability project to accommodate an industrial upswing in the gulf region. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

The market efficiency project ranks fifth in cost at an estimated $67 million to $72 million. MISO is considering three alternatives to relieve congestion in southern Indiana, with PJM as a potential partner. MISO Vice President for Transmission Jennifer Curran told the Board of Directors’ System Planning Committee last week that a request for proposals could be posted in January, with developer proposals due in July. (See Southern Indiana Transmission Project Keeps Morphing.)

Another significant portion of MTEP 15 is a bundle of 13 transmission upgrades identified in the voltage and local reliability study to reduce costs in MISO South. Estimated at $300 million, the projects should produce $498 million in 20-year net present value benefits by decreasing the need for uneconomic generation in load pockets such as Amite South and WOTAB, MISO executives told the board.

More Baseline Projects

While the total price tag for MTEP 15 is nearly identical to MTEP 14 — a coincidence, RTO officials said — the complexion of projects differs significantly. Proposed in MTEP 15 are 91 baseline reliability projects totaling $1.2 billion, compared to 50 projects totaling $177 million in 2014.

Projects driven by local needs are fewer in MTEP 15: 251 for a total of $1 billion versus 312 projects for $1.6 billion in MTEP 14.

The big difference was the inclusion in MTEP 14 of the $676 million 500-kV Great Northern transmission line, built in response to a long-term transmission service request from the Manitoba border to the Iron Range in Minnesota.

Interregional Planning

Curran also updated the board on the status of interregional planning efforts, which have shown mixed results.

She acknowledged that at least two of three potential MISO-SPP interregional projects earlier touted to offer $235 million in benefits are now “uncertain to unlikely.”

Curran said the two projects now look less attractive in part because of differences in how the two RTOs modeled the impact of the Environmental Protection Agency’s Mercury and Air Toxics Standards. MISO applied MATS retirement assumptions about SPP generation in the MISO model, but SPP did not have the same retirements show up in its model. (See 2 of 3 MISO-SPP Seams Projects Likely Doomed.)

“There are also differences in the amount and type of generation added, leading to a larger net addition of future generation in the interregional models when compared to the MISO regional models,” MISO spokesman Andy Schonert said. “The magnitude, type and location of these future units can lead to increased transfers and resulting differences in congestion levels at seams, which impacts the projected value associated with certain transmission projects.”

Potential interregional projects with PJM also were pared down.

In June, the RTOs narrowed the list of “quick hit” flowgate projects to two, from 39 in March. Among the survivors is the proposed resagging of the Northern Indiana Public Service Co. section of the Michigan City-La Porte 138-kV line.

The nearly $10 million in congestion relief for the finalists is a big reduction from the $408 million in potential congestion relief that the 39 projects initially identified could have brought. However, Curran told the board that MISO officials found that 22 of the flowgates had already been included in other planned or currently in-service projects.

September 1, 2015

PJM Markets and Reliability Committee Briefs

WILMINGTON, Del. — PJM expects to spend $280 million in 2016, a $3 million increase over 2015, including $36 million on capital projects, according to a preliminary budget presented last week.

The spending plan will result in a composite expense charge of 32.9 cents/MWh, a rate that has remained consistent for the past five years.

About $28 million of the capital projects budget is dedicated to upkeep and enhancement of current applications, systems and infrastructure.

Another $5 million will be spent on new products and services, including the technology to support intraday bidding. The remaining $3 million will go toward interregional coordination, such as coordinated transaction scheduling with MISO.

The Finance Committee is set to consider the budget on Oct. 1 before it goes before the Board of Managers on Oct. 15.

Revisions Will Reveal Closed-Loop Interfaces Earlier

The committee endorsed manual revisions requiring PJM to announce the creation of closed-loop pricing interfaces five days before the close of the next financial transmission rights auction. The rules make an exception for outages of less than 10 days and those setting prices for demand response under current manual and Tariff rules.

PJM uses such interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems. (See “Package Calls for Notice on Pricing Interfaces” in PJM MIC Briefs.)

Changes Pave Way for Transition to Markets Gateway

Members endorsed revisions to the Operating Agreement and Tariff reflecting the transition from the eMarket tool to Markets Gateway. Training on the new tool is expected to be held in the second half of this year.

Change to Manual 37 OK’d

The MRC endorsed changes to Manual 37: Reliability Coordination that modify section 2.4.2 (Change management process), replacing references to the Change Control Review Board with the Enterprise Change Management Standard. The standard ensures that changes to PJM business application systems, programs, data, systems software and hardware are authorized and applied so as not to compromise the stability and security of any information technology component.

They also update the definition of system operating limits (SOL) to make clear that PJM controls to the most conservative limits and that interconnection reliability operating limits (IROL) are an elevated level of SOL, not distinct from them. The changes also clarify what SOLs and IROLs are monitored by the RTO, as well as SOL violations reporting.

— Suzanne Herel

September 1, 2015

Markets Committee Briefs

ST. PAUL, Minn. — MISO, SPP and intervenors in the dispute over MISO’s use of SPP transmission to deliver power between its northern and southern regions have begun circulating drafts of a settlement amid optimism that it will be filed with FERC in October (ER14-1174).

Discussions on how costs paid to SPP will be allocated within MISO will begin in September “on a separate track,” Eric Stephens, deputy general counsel, told members at the MISO Informational Forum last week. Stephens said confidentiality rules on the settlement talks prevented him from discussing specifics of the deal.

But Market Monitor David Patton told the Markets Committee of the Board of Directors later that the settlement will allow MISO to eliminate use of its $9.57/MWh “hurdle rate” in determining whether to allow more than 1,000 MW of power flows between its two regions.

“We need to make sure that’s the case, but I think the team at MISO did a good job of moving the settlement in a direction that allows us to do that,” Patton said.

MidAmerican Energy’s Dehn Stevens told the Board of Directors meeting later that the Transmission Owner sector is “very comfortable with where [the settlement is] at.”

Organization of MISO States President Libby Jacobs told the board that her group is “very optimistic that there’s resolution on the horizon.”

“OMS would encourage that to be rapidly finished so that everyone’s focus can be on other issues,” she said.

In spring 2014, MISO began limiting flows between its northern and southern regions after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contract path.

While seeking to resolve the dispute with SPP, MISO implemented a $9.57/MWh hurdle rate — an adder to the LMPs of the importing sub-region — to establish market signals indicating when the savings from avoided redispatch costs exceed SPP’s additional transmission charges.

Patton: Fear of FTR Gaming over WAPA Integration Hasn’t Materialized

Patton told the Markets Committee that his staff has seen little evidence to confirm fears that SPP’s integration of the Western Area Power Administration (WAPA) could give market participants an opportunity to game the market by buying financial transmission rights from SPP “whose value predictably would change significantly” following the integration.

“We didn’t see a lot of participants engage in strategic FTR purchases the way we had thought they would,” Patton said.

He said his staff is continuing to review how SPP’s dispatch including WAPA affects MISO’s constraints in the FTR market and market-to-market process.

“We don’t have significant concerns, but it is a significant change because WAPA stretches from the Dakotas down to the southern end of SPP. It’s a huge change in their configuration. You can think of it as similar to our integration of MISO South.”

“So, no red flags, just continued vigilance?” asked Director Michael Curran.

“Yes,” Patton replied.

— Rich Heidorn Jr.