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

Transmission Developers Launch Competitive Affiliates

By Tom Kleckner and Rich Heidorn Jr.

Three new transmission developers affiliated with established utilities have entered the race for competitive transmission projects in the Midwest.

FERC this month conditionally accepted formula rate templates and related protocols for two new developers in SPP and one in MISO.

The commission acted on filings by ATX Southwest (ER15-1809), an affiliate of Ameren; Kanstar Transmission (ER15-2237), an affiliate of Westar Energy; and Midwest Power Transmission Arkansas (ER15-2236), whose parent is a joint venture of Westar and Berkshire Hathaway Energy.

Midwest Power set its sights on MISO, which expects to issue its first competitive solicitation under FERC Order 1000 as part of its 2015 Transmission Expansion Plan.

ATX and Kanstar intend to compete in SPP, which issued a request for proposals May 5 for its first competitive upgrade, the 21-mile North Liberal-Walkemeyer 115-kV project in Kansas. (See Walkemeyer Transmission Project Wins SPP OK.)

The commission approved the companies’ proposed base returns on equity (ROE) for filing, setting them for hearings and settlement procedures.

Midwest Power was granted use of MISO’s base ROE, currently 12.38%, subject to the outcome of complaints challenging the rate (EL14-12 and EL15-45).

ATX’s request for a base ROE of 10.9% and Kanstar’s requested 10.5% base were accepted for filing and set for hearing and settlement judge procedures.

All three companies also were awarded 50-basis-point adders for participation in an RTO, subject to the total ROE being within the “zone of reasonableness” established in the hearing and settlement procedures.

Also approved were the companies’ hypothetical capital structures, 60% equity and 40% debt for Kanstar and Midwest, and 56-44 for ATX.

FERC denied ATX’s request to recover costs related to transmission facilities abandoned for reasons beyond the entity’s control and its request to include 100% of construction work in progress (CWIP) in its rate base during development and construction. It also denied ATX’s request to include 50% of CWIP in its rate base for all transmission projects it is awarded through SPP’s Order 1000 solicitation process.

FERC also denied Kanstar’s request to recover 100% of costs associated with its proposed Walkemeyer project, should the company be selected to develop the project and it is later discontinued.

The commission announced its orders on Kanstar and Midwest Power at Thursday’s open meeting.

Unfinished Business

In a related order, the commission on Wednesday dismissed as moot a 2013 petition by the trade group WIRES seeking a generic “statement of policy” on regulated rates of return for transmission investments (RM13-18).

WIRES, which represents transmission owners, made the petition in an attempt to counter a dozen complaints challenging as unjust and unreasonable the FERC-approved ROEs for transmission owners around the country.

The commission said it had addressed the issue in Opinion 531, its June 2014 ruling adopting a two-step discounted cash flow method for setting ROEs (EL11-66-001). (See FERC Splits over ROE.)

The group issued a press release expressing disappointment in the commission’s rejection of the petition.

“The downward pressure on ROEs has increased since Opinion No. 531, as have the uncertainties of ongoing litigation,” said WIRES Counsel Jim Hoecker, a former FERC chair. “If other investments become more attractive to investors than transmission, the long-term impacts on the [Environmental Protection Agency’s Clean Power Plan], renewable energy development and the commission’s pro-market objectives could be significant.”

With the number of would-be transmission developers continuing to grow, however, there’s little evidence that the sector is having trouble attracting investment.

Among WIRES members: Berkshire Hathaway Energy.

September 22, 2015

FERC Charges Third Firm with UTC Scam in PJM

By Ted Caddell

FERC has charged a Pennsylvania-based power trading company with manipulating the PJM wholesale market by making risk-free up-to-congestion trades in the summer of 2010.

The Notice of Alleged Violation said Coaltrain Energy of Landenberg, Pa., executed up-to-congestion transactions “that were designed to falsely appear to be spread trades but that were in fact a vehicle to collect” line-loss payments from PJM. It said the company “sought not to profit from changes in price spreads but rather to profit by clearing large volumes of up-to-congestion transactions.”

Coaltrain is the third company FERC has charged recently with such trading violations, following actions against Powhatan Energy Fund of Pennsylvania and Florida-based City Power Marketing last year.

The notice named principal owners Peter Jones and Shawn Sheehan, along with traders Jeff Miller, Robert Jones, Jack Wells and Adam Hughes.

According to their LinkedIn profiles, and PJM and FERC records, Sheehan and Hughes are currently affiliated with XO Energy, a PJM member, and formerly worked at Energy Endeavors, another company that PJM has accused of manipulative UTC trades. XO and Energy Endeavors have listed the same Landenberg address as Coaltrain.

Jones also was affiliated with Energy Endeavors.

PJM sued Energy Endeavors in Delaware Superior Court seeking the return of more than $6 million in line-loss profits. The same complaint sought $17 million from City Power Marketing. The docket lists no filings since 2013, when the court denied the defendants’ request to stay the proceedings. PJM’s most recent financial statement indicates it is still attempting to collect the money — among a total of $28 million in defaults resulting from line-loss payments later questioned by FERC.

Energy Endeavors asked FERC in 2011 to cancel its market-based rate authority, saying it had ceased trading activities.

Sheehan did not immediately return a call for comment.

September 22, 2015

MISO Planning Advisory Committee Briefs

MISO officials are considering changes to how they conduct the annual Transmission Expansion Plan in order to focus future plans on long-term needs.

Officials told the Planning Advisory Committee meeting last week that they are considering changes to the first two steps of the seven-step futures development process.

“Year after year, the annual MTEP future definitions have modeled similar themes,” MISO said. From MTEP 12 through MTEP 16, the RTO has modeled low-growth, high-growth and business-as-usual cases.

Under the proposed change, planners would refresh the uncertainty variables annually based on whether there are new drivers for revising futures definitions.

Beginning with MTEP17, planners would use futures for as many as three years. MISO said sensitivities to existing futures can capture specific system needs without having to design new futures. For example, rate-based and mass-based compliance approaches can be studied as sensitivities to the Clean Power Plan future.

“After evaluating near-term needs for the last several MTEP cycles, it’s time to focus on long-term overlay design and development,” MISO said.

Stakeholders will discuss the proposed changes at the October and November PAC meetings. MISO hopes to finalize a revised process by end of the year.

MISO Proposing Changes to Review of Out-of-Cycle Projects

MISO has proposed changes to the way it handles the review of expedited projects to quell complaints over Entergy’s Lake Charles out-of-cycle transmission upgrades.

“We do think a few minor adjustments are necessary,” said MISO’s Matt Tackett, who presented the proposed changes.

Entergy’s $187 million out-of-cycle transmission project to serve additional load in the Lake Charles, La., industrial zone created a row that lasted for months. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

MISO is proposing that projects meeting the voltage and cost thresholds for classification as market efficiency projects be tested to see if they would have satisfied the 1.25 benefit-cost ratio. MISO’s presentation says this requirement would be for “transparency and informational purposes.”

The project would be reviewed by Sub-regional Planning Meetings (SPM) and/or the Technical Study Task Force (TSTF), where the submitting transmission owner would explain the need for the expedited review.

MISO planners will propose the project, or any alternative, for the MTEP, based on the project review and input from the SPM/TSTF.

The PAC would weigh in only at the end of the MTEP cycle.

Projects not eligible for expedited review would be any that are qualified as MEPs and are not required to meet transmission owner obligations. “It is expected that under normal circumstances, the transmission owners will identify the needs for projects early enough to be vetted in the normal MTEP process without the need for expedited review,” MISO said.

MISO will be accepting comments on the proposal until Oct. 16. After reviewing the comments, MISO will bring any revisions to the November PAC for the final proposal.

One of the most vocal critics of MISO’s handling of Entergy’s Lake Charles project, George Dawe of Duke-American Transmission Co., said the proposed changes are not an improvement.

“I’m more concerned now than I was with the original [Business Practices Manual] language,” said Dawe, who represents the Transmission Developer Sector at the PAC. “It seems to me you’ve gutted the BPM.”

Dawe said the current BPM allows the PAC sectors to register their displeasure with a proposed out-of-cycle project to the MISO board.

“It seems to us that a controversial expedited project should be required to pass more stringent review, not less review and no PAC vote,” he continued after the meeting. “Under the new process, the board would not be aware of [PAC stakeholder] displeasure until the end of the year when comments on the MTEP are solicited. By that time, the project would already have been de facto approved and potentially under development by the transmission owner.”

Former Wisconsin Public Service Commissioner Eric Callisto, now a partner with law firm Michael Best & Friedrich, also criticized the proposal, saying “I think the whole tone has changed in many ways.”

“As proposed [the changes] don’t strike the right balance between truly urgent needs that justify MISO’s expedited review versus the vast majority of projects that should make their way through the standard MTEP process,” he said afterward. “The proposal leans too much in favor of expedited review, to the detriment of an open and competitive process.”

MISO Seeks Feedback on Proposed Analysis of Final Carbon Rule

MISO is soliciting stakeholder feedback until Oct. 7 on a proposed framework for its study of the Environmental Protection Agency’s final Clean Power Plan.

The emissions targets will be examined under regional, sub-regional and state-level compliance, based on both rate- and mass-based caps. Planners also will consider a possible “equivalency exchange” rate between rate- and mass-based plans, given the possibility for disparity in state approaches.

Transmission needs will be identified and solutions developed for three futures. One assumes the CO₂ limits are met. The “accelerated” CPP future assumes the targets are surpassed as technological advancements and public policy makes renewables and demand-side resources more competitive than expected. The “partial” CPP future assumes legal challenges slow or end compliance, and only the early, 2022 emission targets are met.

In November, MISO will finalize the scope of the study, including futures definitions and modeling assumptions.

Through mid-2016, planners will model futures and sensitivities, considering state implementation plans as they become available.

Planners will develop transmission overlays beginning in 2016. MTEP 2016, however, will be based on the preliminary EPA draft rule.

No Go for MISO-SPP Interregional Projects

MISO will not recommend approval of three potential interregional projects with SPP following an additional analysis that incorporated stakeholder feedback, Arash Ghodsian, MISO’s technical adviser for economic studies, told PAC members. MISO said it worked with stakeholders and SPP to “sharpen [its] analysis” and concluded that none of the three projects were justified by the projected benefits. Last month, MISO told the PAC two of the three projects looked less attractive following additional modeling, indicating a “disconnect in coordination” between the two RTOs. (See 2 of 3 MISO-SPP Seams Projects Likely Doomed.)

Ghodsian said MISO updated its regional congestion analysis after making some modeling changes and incorporating four futures. Staff identified future load changes between interregional and regional models and replicated SPP’s assumptions on retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics Standards.

“Given where we are with the projects, we don’t see why we need to go forward with any of them,” Ghodsian said. He said the projects are not more cost-effective at addressing the identified transmission issues than what MISO’s regional transmission plans build. Staff said its goal is not to find interregional projects for the sake of doing one, but to identify more cost-effective projects that would not be found in traditional regional planning. Ghodsian said MISO and SPP “effectively collaborated” during the study, gaining insight into their respective planning processes.

MISO’s revised analysis concluded:

The $141 million Elm Creek-NSUB 345-kV project showed present value benefits over 20 years of $25.6 million and a benefit-cost ratio of 0.49.
The $18.5 million rebuild of the S. Shreveport-Wallace Lake 138-kV line showed a benefit-cost ratio of 0.86.
The $5.3 million series reactor on the Alto-Swartz 115-kV line shows $20.5 million in benefits and a B/C ratio of 4.34, including the adjusted production cost benefit for MISO South.

MISO is evaluating alternatives to the Alto series reactor project in the market congestion planning study.

AEP Agrees to Pay Share of Market Efficiency Project

MISO’s Digaunto Chatterjee shared a letter from American Electric Power affirming its commitment to “pick up incremental cost/payment” if MISO approves either the Rockport-Coleman 345-kV double circuit or the Duff-Rockport-Coleman 345-kV single circuit market efficiency projects.

MISO is choosing from among three MEP projects in Southern Indiana, the third a Duff-Coleman 345-kV single circuit line. (See MISO Plan to Revisit Runner-Up Tx Project Rekindles Stakeholder Angst.)

Staff have completed their economic and reliability evaluations. The reliability no-harm study identified constraints on two circuits for all three project alternatives, with an estimated mitigation cost of $200,000.

Staff said it will make its final recommendation during a special PAC meeting Sept. 25 but is still awaiting PJM’s final position and funding commitment.

The alternatives range in cost from $67.2 million to $152.5 million. PJM’s share of the alternatives could run as high as $85.2 million for Duff–Rockport–Coleman and $54.6 million for Rockport-Coleman, according to MISO staff.

MISO cited “Tariff challenges” to the Rockport-Coleman project, saying it is unclear how to bid out a double circuit line when a portion of the line is built for another RTO and not cost shared through the MISO Tariff. Tariff changes may be necessary to allow PJM to compensate MISO.

MISO is also studying two efficiency projects in the South with a total estimated cost of about $124 million that cleared the 1.25 B/C ratio: reconductoring the 115-kV Mabelvale-Bryant-Bryan South line near Little Rock, Ark., and building a 230-kV line from a substation to Lewis Creek in southeast Texas. Staff is continuing to gather information and stakeholder feedback on its analyses.

Second Round of Feedback on MTEP 15

MISO’s Omar Hellalat said a second draft of MTEP 15 has been posted and the RTO is currently accepting a second round of stakeholder feedback. These “substantive” comments are due Sept. 28; the feedback and MISO responses will be relayed to the MISO Board of Directors.

The PAC will hold a second discussion on the plan Oct. 14 before sending it on to the System Planning Committee for its October and November meetings. The MISO board will then take up the projects in December.

The first round of stakeholder feedback included grammatical and content comments and clarifying questions.

— Tom Kleckner and Rich Heidorn Jr.

September 22, 2015

MISO Focused on Gas-Electric Coordination for Winter

By Michael Brooks

MISO is forecasting a 35% planning reserve margin for the winter and has implemented several changes to improve coordination with pipeline operators and ensure fuel deliveries to its fleet, Todd Ramey, vice president of system operations and market services, told FERC last week.

“We feel very comfortable that we have the resources and processes needed to ensure efficient operations for the coming winter,” Ramey said.

The RTO, which is forecasting a winter peak of 104 GW, is counting on installed capacity of 145 GW. MISO’s resource adequacy has come under scrutiny over the past two years, but concerns have been about meeting its summer peak. (See MISO Survey: No Shortfall Until 2020.)

Ramey said MISO has “new and improved” tools in its control room that increase situational awareness of pipeline conditions. In the past year, the RTO has also been conducting monthly calls with pipeline operators to share outage information, he said.

MISO has also implemented fuel surveys to gain greater awareness of the firmness of fuel deliveries to its gas-fired fleet, Ramey said.

In its first survey, conducted last year, only 15% of plants that responded had “primary firm” gas delivery, while 40% reported having “interruptible & other” arrangements; 24% of those surveyed did not respond. The RTO’s next survey will be in October, Ramey said.

MISO has also conducted informal fuel storage surveys. During the polar vortex, MISO found that generators’ coal inventories were lower than planned “due to some transportation disruptions,” Ramey said. He said that both inventories and rail supply are back to normal, but that the RTO would continue to keep an eye on them.

In response to a question from Commissioner Colette Honorable about the grid operators’ long-term objectives, Ramey said MISO was focused on working with state commissions as the region transitions from coal to natural gas.

Offer Cap

Ramey also said that MISO would make a filing concerning the $1,000/MWh energy market offer cap in the “next couple months.” He said stakeholders are still unsure about a final solution, but that the filing would at least address the cap for this winter. During the 2014 polar vortex, soaring natural gas prices pushed some generators’ costs over the cap.

September 22, 2015

NH PUC Staff: Northeast Energy Direct Pipeline Would Lower Power Prices

By William Opalka

The Northeast Energy Direct pipeline project through southern New Hampshire is the best way to lower electricity prices and increase reliability in New England, the staff of the state Public Utilities Commission concluded in a report released Wednesday.

The 48-page report examined three proposed pipeline expansions and an alternative for increased liquefied natural gas deliveries during the winter. The PUC ordered the study in the spring in response to high natural gas prices and concerns about reliability over the past two winters (IR15-124).

Kinder Morgan’s Northeast Energy Direct project would run on mostly new rights of way from Pennsylvania’s Marcellus Shale region through New York, Massachusetts and New Hampshire, terminating in Dracut, Mass. (See Kinder Morgan Trims Northeast Energy Direct.)

The Access Northeast project led by Eversource Energy and the Portland Natural Gas Transmission System, which would mostly expand pipelines on existing routes, provide lesser benefits, according to the report.

“We view Access Northeast and Northeast Energy Direct as two very cost-effective projects that will moderate future winter electricity prices, though the numbers clearly indicate that NED will provide the greatest benefits to regional electricity customers,” the report said.

Portland Natural Gas did not provide enough information for the PUC to conduct a thorough analysis, according to the report. The report added that Access Northeast would enhance reliability but would have less impact on gas prices.

“As a result of the NED project, [Kinder Morgan subsidiary] Tennessee Gas Pipeline will have the ability to physically deliver into every pipeline system serving New England, as well as to incrementally serve markets along its own pipeline system,” the report adds.

The report is less confident in the ability of LNG to fill in gas supply gaps, as it did during last winter.

“There is no guarantee that the market conditions that enticed LNG tankers to New England in winter 2014/15 will recur in future winters. This means the very high prices of 2013/14 could reappear just as quickly as they disappeared in 2014/15, assuming, of course, similar extreme weather conditions. Finally, it is important to note that the increased availability of LNG in winter 2014/15 did not eliminate price spikes or energy cost premiums,” the report said.

New Hampshire’s report is the latest in a number of analyses weighing the merits of proposed infrastructure improvements for the region. (See Dueling Studies Dispute Need for More Pipelines in New England.)

September 22, 2015

Are You Two Related? FERC Wants to Know

By Rich Heidorn Jr.

Seeking to improve its ability to unravel complicated market manipulation schemes, FERC last week proposed a new way for identifying connections between companies and individuals.

The commission issued a Notice of Proposed Rulemaking requiring RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers, with lists of their “connected entities” and a description of their relationships (RM15-23).

The proposal would use a new system called Legal Entity Identifiers (LEIs), which are already used by the Commodity Futures Trading Commission and Securities and Exchange Commission to track swaps trades. FERC previously dropped use of the Data Universal Numbering System (DUNS), saying it was not effective for its purposes.

FERC said the new requirements will help the Office of Enforcement police market manipulation by providing a “more complete view of the relationships between market participants and the incentives underlying their trading activities.” The initiative would also help RTO market monitors in probes of cross-market manipulation, FERC said.

The office’s Division of Analytics and Surveillance runs automated screens to detect potential market manipulation. The office also has access to e-Tags, RTO trading data and information from the CFTC, including its Large Trader Report.

“Nonetheless, despite increased access to trading data, the commission cannot fully utilize this information in order to detect and deter market manipulation because of uncertainty regarding the identity of a given market participant, which may trade under different identifiers in different markets and venues,” FERC said. “The commission also lacks a clear window into the relationships between market participants and other entities, which can be complex. Without an understanding of which companies share ownership or debt interests, or who may function in key employment or other contractual roles (such as asset management), it can be difficult to ascertain which individuals or companies may benefit from a given transaction or, indeed, who may be jointly participating in a common course of conduct.”

‘Connected Entities’

The rule would require companies to identify all “connected entities,” a new term defined as those that have certain ownership, employment, debt or contractual relationships. It would replace current affiliate disclosure requirements contained in RTO and ISO tariffs unless the markets request their continuation.

FERC said it wanted a new definition “free of any associations that have developed around the term ‘affiliate,’ and one that is uniform across all of the RTOs and ISOs.”

Connected entities would include companies controlling more than 10% of another, as well as top executives and traders. The scope would extend beyond corporate affiliations, including contractual relationships such as tolling and asset management agreements and debt structures that are convertible to ownership interests.

FERC estimated that about 90% of reported wholesale electricity sales under commission jurisdiction are captured in Electric Quarterly Report data and affiliation information obtained from market-based rate filings and other sources. It sought comment on whether non-RTO market participants should also be required to make filings.

Companies would be required to file their connected entity data before being permitted to participate in RTO markets, and to verify their accuracy annually. FERC and the RTOs would be able to audit the filings to ensure compliance.

FERC said the change may ease compliance for market participants in multiple markets.

But in a concurring statement, Commissioner Cheryl LaFleur expressed concern that the rule “would create a significant new reporting regime for all market participants, as well as the RTOs and ISOs.” LaFleur said she might oppose the final rule if she concludes that “the benefits offered by new compliance obligations outweigh the burdens that will be faced by market participants.”

Comments on the rule will be due 60 days following publication in the Federal Register.