Page 1424 – RTO Insider

July 18, 2016

SPP Strategic Planning Committee Briefs

RAPID CITY, S.D. — The Transmission Planning Improvement Task Force’s recommendations to streamline SPP’s transmission planning process won unanimous approval from the Strategic Planning Committee and the Markets and Operations Policy Committee last week.

If the recommendations win final approval from the Board of Directors next week, SPP will combine the Integrated Transmission Planning (ITP) near-term and 10-year assessments and NERC transmission planning (TPL) assessments into a single 10-year study that will produce an annual transmission expansion plan addressing reliability, economic and policy needs.

The new process will begin in September 2017, with its first results unveiled in October 2019. SPP will complete the 2017 ITP10, the 2017 and 2018 ITPNTs and conduct TPL assessments during the transition period.

NextEra Energy Transmission’s Brian Gedrich, the task force’s chair, said the new process will yield more accurate and forward-looking results.

“It’s a holistic approach, the opposite of the sequential way we do it now,” Gedrich told the SPC. “A lot of manpower resources are spent to provide [transmission-planning] information for you and the board. This will free up time so folks can do analysis … that will actually be actionable.

“No one was happy with the process. Today, all you do is take a 10-year look ahead. How can you possible see what is happening in real time, when all you look out is 10 years?”

Gedrich said building the initial future cases would require two to four additional full-time equivalents and $350,000 to $400,000 in consulting costs, depending on whether staff analyzes two or three futures. The task force recommended two futures.

“What are we getting out of this additional cost?” asked SPP Director Harry Skilton, who chairs the RTO’s Finance Committee. “I hear you say more efficiencies, but what tangible benefits do members get?”

ITC Holdings’ Marguerite Wagner agreed the benefits can be difficult to quantify.

“We spend hundreds of millions of dollars on transmission, and we see congestion in the same areas,” she said. “We expect this new process to be more granular, thus leading to potentially better solutions and outcomes.”

“As you do the same thing over and over, I think you will gain efficiencies. Right now, as we start and stop, you lose a lot of time,” Gedrich said.

Skilton seemed satisfied with the responses. “If in the judgment of the membership it will get better results, address congestion in the near term and improve the planning process … that’s a helluva accomplishment,” he said.

The task force’s other recommendations included:

Standardizing the ITP’s scope and developing a streamlined assumptions document;
Developing a single, base reliability powerflow model that will be used for all planning processes;
Adding accountability with mechanisms designed to promote timely data exchanges, reviews and approvals; and
Limiting the initial 2019 study scope to two study futures to help facilitate the move to the new planning process.

Export Pricing Task Force Given the Go-Ahead

The committee unanimously accepted staff’s recommendation to create an export-pricing task force to research SPP’s Tariff and FERC policy and evaluate how best to take advantage of the RTO’s abundant variable energy resources.

SPP Boardmember Phyllis Bernard, SPP VP Michael Desselle, Golden Spread Electric Co-Op's Mike Wise lead SPC meeting (RTO Insider)-web — Left to right: SPP board member Phyllis Bernard, SPP VP Michael Desselle, Golden Spread Electric Co-Op’s Mike Wise © *RTO Insider*

The task force would make recommendations on establishing “equitable and nondiscriminatory” rates to address recovering incremental transmission and facility costs needed to export and import electricity, and “how to avoid paying for it on the back of SPP ratepayers — which will be difficult to do,” said Sam Loudenslager of SPP’s regulatory staff.

Loudenslager said the SPP region currently has 22,000 MW of variable resources in its queue and not yet in service.

SPP’s Corporate Governance Committee, which doesn’t meet until late August, will have to approve the task force’s formation.

Dogwood Energy’s Rob Janssen suggested the task force’s representation include members experienced with life on the seams.

“We have to remember we have members with loads on both sides of the border, who move power any given day or time,” he said.

“If you can’t get the money right, you can’t get anything done,” SPP Director Phyllis Bernard said. “This is one of those task forces focusing in on how to get the money right. There are genuine legal problems here, and absent federal direction, export pricing has to be the solution.”

Asked by SPC Chairman Mike Wise of Golden Spread Electric Cooperative whether the task force would develop a marketing campaign to “advertise our energy,” Loudenslager responded, “I’m not a marketing guy.”

– Tom Kleckner

July 18, 2016

PJM, Retail Marketers Intervene in Dayton Power Subsidy Bid

By Rory D. Sweeney

PJM and the Retail Energy Supply Association want a say in Dayton Power and Light’s plan to keep its coal-fired plants running.

Both organizations have filed motions to intervene in DP&L’s “electric security plan” application before the Public Utilities Commission of Ohio. If their past actions are any indication, they will voice objection to the plan, much as they did in similar cases involving FirstEnergy and American Electric Power, which are Ohio’s two largest electric utilities. (See PJM Looking at AEP, FirstEnergy PPAs; Critics Join Forces.)

DP&L’s application proposes a 10-year reliable electricity rider (RER), which would help parent company AES continue operating its fleet of coal-fired plants. Under the rider, DP&L would agree to acquire generation from the shares another AES subsidiary owns in the Ohio Valley Electric Corp. and the Conesville, Killen, Miami Fort, Stuart and Zimmer plants — all baseload coal-fired facilities DP&L used to own but was required to sell under its current ESP.

The rider would further stipulate that the difference between the revenue requirements of each plant and its expected revenue would be calculated annually. Depending on the outcome of the calculation, customers would receive a credit or a charge.

PJM, RESA, Dayton Power and Light — Kyger Creek Power Plant

In announcing the application, DP&L estimated that, if approved, the first year of the rider in 2017 would result in an additional $1.21 charged to each monthly bill but “contribute an estimated $26.5 billion in positive economic benefits for Ohio.”

In their filings, PJM and RESA said approval of the plan would have market-wide impacts.

“The commission’s decision in this matter will affect the viability of the competitive retail electric market in DP&L’s service territory,” RESA said in its filing.

“The nature and extent of PJM’s interest is to ensure DP&L’s RER proposal will not negatively impact PJM’s ability to administer efficient and competitive wholesale energy, ancillary service and capacity markets, and maintain the reliability of the transmission system in the PJM region,” PJM’s filing stated.

DP&L’s plan has drawn criticism from environmental groups, including the Ohio Environmental Council and the Environmental Defense Fund. Both groups are also contesting similar proposals from FirstEnergy and AEP.

The companies are “cherry-picking some of their worst plants, and they’ll put those in a package and they’ll say that the state of Ohio needs these for jobs and economic development,” said John Finnigan, a lead attorney with EDF.

“It’s a subsidy for these plants. These plants are out of the money.”

Under its current ESP, DP&L was required to divest its generating assets. AES decided in 2014 to retain the Dayton-area power plants, which were nearly 3,500 MW at the time. The generation was sold to another AES subsidiary, AES Ohio Generation.

Both AES Ohio and DP&L are overseen by DPL, another AES subsidiary. Today, DPL serves (through DP&L) approximately 515,000 customers in 24 counties throughout West Central Ohio and operates (through AES Ohio) 3,066 MW of generation, 2,078 MW of which is coal-fired.

DP&L said it was reviewing the petitions to intervene. “Once a thorough review is complete, we will explore all options for our next steps,” said spokeswoman Mary Ann Kabel.

July 18, 2016

FERC OKs 9.8% ROE in Transource Settlement

FERC last week approved Transource Kansas’ settlement with the Kansas Corporation Commission, under which the company will receive a 9.8% base return on equity for any transmission facilities in SPP (ER15-958).

The company will earn a total of 10.3%, including a 50-basis-point adder previously approved by the commission for participation in an RTO.

FERC trial staff supported the settlement in an April 27 filing but noted that the agreement was silent on the top end of the discounted cash flow (DCF) zone of reasonableness. “Therefore, if Transource Kansas (or its affiliates) makes a future request seeking additional ROE incentive rate adders for a specific transmission project, the commission’s approval of this settlement will not eliminate the need for the applicant to make a Section 205 filing that includes a two-step DCF analysis establishing a zone of reasonableness, the top of which will cap any total ROE,” staff said.

Transource Kansas is a subsidiary of Transource Energy, a joint venture between American Electric Power and Great Plains Energy.

– Rich Heidorn Jr.

July 18, 2016

FERC Rejects PJM Cost Allocation on Dominion Project

By Rory D. Sweeney

FERC accepted PJM’s cost responsibility assignments for 33 of 34 baseline upgrades, ordering the RTO to change the billing for one Dominion Resources project and revise its Operating Agreement to address inconsistencies (ER16-736, EL16-96). PJM’s Board of Managers approved the projects in December as additions to its Regional Transmission Expansion Plan.

The commission rejected the cost assignment on Dominion’s 500-kV Cunningham-Elmont rebuild project (b2665), saying it should be funded solely by Dominion ratepayers rather than spread across the region.

FERC said PJM’s proposal was inconsistent with its February order that transmission owners should pay all of the cost of projects that solely address a TO’s local planning criteria. (See FERC Does 180 on Local Tx Cost Allocation in PJM.)

The commission gave PJM 30 days to submit a compliance filing “to reflect the appropriate cost responsibility assignment” — allocated to the transmission owners’ zones via the solution-based distribution factor (DFAX) method.

PJM had proposed the DFAX method for 30 other low-voltage projects addressing local planning criteria. Costs of the three other projects — involving 500-kV or double-circuit 345-kV lines — will be allocated 50% on a regionwide, postage-stamp basis and 50% via DFAX.

Commissioner Cheryl LaFleur dissented on the b2665 decision, noting it involved a 500-kV line. “High-voltage lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation,” she said.

She also reiterated concerns she’s noted previously that incumbent TOs may be delaying action on transmission upgrades until the projects become immediately necessary and therefore no longer subject to competitive bidding under Order 1000.

“It is important that incumbent transmission owners report their transmission needs to PJM in a timeframe that allows PJM to meet them in a timely manner, and open them to competitive bidding requirements if they are not in fact immediate,” she wrote. “If it appears over time that incumbent transmission owners may be postponing identification of transmission needs to avoid competitive bidding, further action may be needed to ensure that customers receive the intended benefits of Order No. 1000 planning processes.”

OA Inconsistencies

The commission also ordered PJM to correct inconsistencies in its Operating Agreement.

The agreement requires that the transmission owner be the designated entity when 100% of the project costs are allocated to the transmission owner’s zone, as in Form 715 projects. However, another section of the Operating Agreement appears not to exempt Form 715 projects from the competitive proposal process. FERC required PJM to clarify that exemption and the process the RTO will follow in these situations.

The second inconsistency involved determinations for how proposals qualify as “immediate-need” reliability projects. The commission found it “proper” for PJM to use the date a reliability need must be addressed rather than the expected in-service date and said the agreement needs to reflect that.

FERC gave PJM 30 days to submit revisions or explain why such changes are unnecessary. Parties interested in intervening must file notices within 21 days.

The commission expects to file a final order on this proceeding with 180 days from publication in the Federal Register.

July 18, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — Two 345-kV lines that were knocked out when a tornado leveled four transmission towers in Commonwealth Edison territory on June 22 were back online as of July 12, PJM’s Chris Pilong told the Operating Committee last week.

The twister hit near LaSalle, in North-Central Illinois, around 10 p.m., he said, tripping the Plano 0101 and Plano 0102 lines.

In response, a number of generators in the ComEd zone and other PJM areas manually reduced their output.

The effect of the eight-day outage was localized, with only minimal congestion of $136,000, Pilong said.

“There were no emergency procedures, nothing too crazy,” he said.

On June 30, the Plano 0101 was restored using a temporary structure while the other line remained out of service. On July 10, Plano 0101 was moved onto a permanent structure, Pilong said. By the end of July 12, both lines had been restored.

EKPC Forecast Errors Puzzle Operators

In other reports on operations, Pilong noted that the Eastern Kentucky Power Cooperative zone has been showing an unusually high percentage of peak load forecast errors.

“There is something going on there. We’re trying to dig into it and nail down who’s high — is it just one entity?” he said. EKPC has 16 member cooperatives.

“It is a cause for concern, but it doesn’t violate NERC criteria,” Committee Chairman Mike Bryson said. “When we see a significant change like that, we want to understand what’s causing it and see if we have to make any adjustments.”

The average RTO-wide load forecast error performance for June was 2.57%, within the goal of 3%. EKPC’s was highest, at 3.6%, down from 4.7% for the first quarter of the year.

CP Units to be Ineligible for Winter Testing; May Choose to Self-Schedule

Generators that have cleared as Capacity Performance will be ineligible to participate in the PJM-scheduled cold weather tests beginning this winter under changes to Manual 14D that the OC will be asked to endorse next month.

Non-CP resources will be eligible for testing and will be compensated as a pool-scheduled resource on their cost-based schedule.

CP resources may elect to self-schedule tests, enabling them to be compensated as a self-scheduling resource according to the Tariff.

Regardless of how the tests are performed, PJM wants to keep track of the results and is asking that they be submitted within five days of testing.

“When it included all units, there were a number of unit owners that told us they were testing outside of the program,” Bryson said. “That’s one of the things we’re trying to capture.”

The changes came after generators last month opposed a proposal to keep CP units in the testing but end their compensation. All capacity resources will be required to be CP beginning in the 2020/21 delivery year. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)

— Suzanne Herel

July 18, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The Market Implementation Committee last week endorsed changes to Manual 18 clarifying rights and responsibilities under auction-specific bilateral transactions.

The trades — which are intended to be physical, not merely financial — are expected to become more popular under the tougher Capacity Performance rules, PJM said.

Members had asked for clarification on issues such as which party is entitled to bonus payments, which is responsible for performance and whether members would be indemnified if a party to a bilateral deal defaults. (See “PJM Proposes Clarifications to Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

To ensure the physicality of such deals, PJM offered the following clarifications: The rights and title to cleared capacity go to the buyer; the seller remains obligated to perform and to pay for any deficiencies; and the buyer will indemnify PJM Settlement if the seller defaults on its performance obligations. There were four abstentions.

Members to Study Ways to Prevent Black Start Billing Delays

The committee also approved a problem statement and issue charge to study annual revenue requirements for black start units.

The issue arose after a large number of such units entered service before their billing requirements were approved, leading to billing delays and large retroactive charges. Many were replacing retiring units. (See “Retroactive Black Start Billing Charges Focus of Proposed Study,” PJM Market Implementation Committee Briefs.)

Current Tariff language does not clearly define the review process for the costs of new units entering black start service outside of the annual revenue recalculation period.

“Basically, what we’re looking for is to put language in the Tariff and minimize the potential of billing delays,” PJM’s Tom Hauske said. “We’ve also added transparency for billing to the issue charge.”

The issue will be worked by the full MIC and is expected to take six months.

Members Debate Ways to Release Excess Capacity into Incremental Auction

The MIC heard three proposals for how to release excess capacity into the third incremental auction for the 2017/18 delivery year, to be held in February.

PJM must file its plans with FERC by November. The RTO’s proposal mirrors its approach for the 2016/17 third incremental auction. In that auction, PJM released 4,556 MW of capacity at an average price of $4.79/MW-day, netting $21,827/day. That reduced the RTO’s total reliability charge by 0.103%.

At the time that PJM received permission from its members and FERC for a Tariff change to release the capacity for the 2016/17 incremental auction, it did not address the subsequent auction because the Supreme Court had not yet ruled on whether demand response resources would remain in the wholesale energy markets. (See Supreme Court Upholds FERC Jurisdiction over DR.)

Last week, stakeholders who said they felt the released capacity was worth much more presented alternate proposals.

One came from Direct Energy, which proposed a sloped offer curve for the sale of an estimated 10,000 MW. This price floor would help prevent supply resources from being able to cheaply buy out of their obligation at load’s expense. (See “Price Floor for Incremental Auctions?”, PJM Market Implementation Committee Briefs.)

“We’re reducing reliability for everyone with little financial benefit in exchange,” Direct Energy’s Jeff Whitehead said. “In the 2016/17 third incremental auction, PJM sold excess capacity for nearly $5 [per MW-day] when the price in the rest of the RTO was $60.”

With a similar premise, Michael Borgatti of Gabel Associates presented a proposal on behalf of NextEra Energy that would make PJM’s sell offer into the existing third incremental auction equal to the transitional incremental auction adder that the RTO currently charges to load.

He provided an example showing that selling all 10,017 MW of excess capacity would produce $284,698/day in incremental revenue using the current charge of $28.42/MW-day. Selling the same capacity at $5.02/MW-day would bring in $50,285/day.

Even selling just half of that capacity at the higher price would bring in more money — $142,349 — than PJM could reap selling 10,017 MW at the $5.02/MW-day price.

Dave Mabry, of the PJM Industrial Customer Coalition, likened the release of excess capacity at $4.79/MW-day to a “fire sale,” suggesting that PJM consider keeping the capacity.

Added Steve Lieberman of Old Dominion Electric Cooperative: “I do believe there is a break-even point where we’d rather have the megawatts than the money.”

Independent Market Monitor Joe Bowring, who had to leave the meeting before the presentations, weighed in on the issue, saying simply, “You should not buy more capacity than you need. You should not sell it back for less than the price paid for it. It’s bad for customers.”

While the proposals addressed only the upcoming auction, Whitehead said he would be drafting a problem statement to study the issue on a long-term basis.

Special Session Planned on Fuel-cost Policy Development

The MIC will hold a special session July 27 to further detail PJM’s requirements for developing fuel-cost policies.

In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.”

It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submission of cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).

PJM is required to make a compliance filing in the docket by Aug. 16. (See “Members Delay Endorsement of Manual 15 Changes Regarding Definitions, Fuel Cost Policy,” PJM Market Implementation Committee Briefs.)

“We want to improve the process so that from a compliance perspective, PJM does not feel as exposed as we do today, given the way the process currently operates,” said Stu Bresler, senior vice president of market operations.

Participants prodded PJM to move more quickly and be more definitive with its rulemaking process.

Lieberman expressed concern over being forced to draft policies in compliance with manual changes that are only in draft form and not yet approved.

He explained after the meeting that, with approval targeted for mid-October and implementation likely in December, the timeline creates a “narrow” window to make and get approval for any necessary policy-submission changes prior to the compliance deadline. FERC’s order for a PJM compliance filing on the issue further complicates the situation, he said, because the commission’s ruling on that could come as late as mid-October and may require further filings from PJM.

“A member faces a lot of uncertainty prior to the start of winter and not a lot of time for resolution,” he said.

Bresler acknowledged that the timeframe is “compressed.”

Carl Johnson, who represents the PJM Public Power Coalition, pressed for adding clarity on the process to the Tariff, including expected review periods and potential remedies for unapproved submissions. He said his members want to know “what it is they need to supply to PJM and be sure that once they’ve done that, they’re going to get an approved policy.”

Bresler acknowledged the comments and reminded participants that they need to retain enough documentation to validate the input to the cost-based offer they submit. He confirmed that once a policy is approved and a cost-based offer submitted, if additional market-power issues arise, they will go before FERC.

Bowring said his staff has developed a policy template for every fuel type. He said his interest is market-power mitigation. PJM ultimately approves or rejects the policies, and the Monitor reviews them beforehand to determine if they are consistent with not exercising market power, he noted.

— Suzanne Herel and Rory D. Sweeney

July 18, 2016

PJM Planning Committee and TEAC Briefs

PJM planners have begun studying a redesign of the Transmission Expansion Advisory Committee process with the aim of providing more discussion, documentation and transparency through the Regional Transmission Expansion Plan cycle.

“We’re looking at additional ways of doing that [rather] than the monthly meeting,” Steve Herling, vice president of planning, told the Planning Committee.

The discussions — internal for now — stem from an April 29 “Order 1000 Lessons Learned” meeting, in which PJM proposed three tracks: a reliability project process document, an energy efficiency project process document and a TEAC redesign. A fourth track to address upgrade projects also was suggested.

“We will shortly be starting discussions around the market efficiency process and decision-making,” Herling said. “We have been working internally with market folks to put together a draft set of documentation that will serve as a starting point. … Hopefully in another month, we should be getting to a point where we can air some of that with the membership.”

For starters, Herling said, planners are looking at alternatives to the 12-month planning cycle.

New 345-kV Line Proposed for Newark Airport

The most efficient solution to Newark Liberty International Airport’s need for additional energy resources is to introduce a third 345-kV line, PJM told the TEAC last week.

Because it is an immediate need, an RTEP window is not feasible, and all of the projected $43 million cost would be assigned to the local transmission owner, Public Service Electric and Gas, said TEAC Chair Paul McGlynn.

The upgrade is expected to be ready by June 2018, when the airport’s expansion is set to be completed.

The airport’s current load is about 40 MVA, but a planned new terminal will add about 33 MVA. Another 8 MVA is expected to be added by plans to extend the Port Authority Trans-Hudson (PATH) railroad.

Planned upgrades to Terminals B and C will increase the load even more.

Two new 345-kV underground cable circuits, part of the Bergen-Linden Corridor project, will serve the airport’s load. But PSE&G would be unable to restore power within 24 hours if those lines were lost, McGlynn said, necessitating an additional line.

PJM Concerned PSE&G Equipment at the End of its Life

An assessment of the 138-kV circuits on PSE&G’s Metuchen-Edison-Trenton-Burlington Corridor shows that they are at the end of their life and must be addressed, McGlynn told the TEAC.

“It would require expensive foundation work to get them back to where they need to be,” he said, noting that a survey of the transmission lines indicated that 25% of the towers are exceeding their load-carrying design capability; 35% are at between 99% and 100%; and 81% are between 95% and 100%.

“It’s at the end of life, and we need to do something about it,” he said.

The 30 miles of line from Metuchen to Trenton is about 86 years old. The 22 miles from Trenton to Burlington is 75 years old.

Also of concern is PSE&G’s Newark Switch, a 63-year-old substation with a transformer from 1927 and two others dating to 1958.

“If they were to fail, it could potentially take out the entire station,” he said.

Two DOM Projects Change Scope, Boost Cost

Two projects in the Dominion transmission zone have undergone a change in scope, increasing their cost significantly.

The cost of upgrading the overloaded Idylwood 230-kV bus has jumped from $55 million to $80 million following a detailed look at the cost of GIS breakers (gas-insulated high-voltage switchgear), permitting, labor, a security wall and transmission structures.

The project, addressing N-1 and N-1-1 thermal violations, is expected to be in service by Feb. 1, 2020.

Meanwhile, a proposal to expand the Halifax station to address thermal violations on the Halifax-Chase City 115-kV line has been scrapped because the station is located in a flood plain.

The need to build a new switching station outside of the flood plains boosted the price of the project from $26 million to $43.6 million, including the purchase of real estate.

The work is expected to be complete by the end of the year.

Members Endorse Using Same Load Model for IRM study

The Planning Committee unanimously endorsed the same load model PJM used last year for the 2016 reserve requirement study, the 10-year period from 2003 to 2012.

It will reset the installed reserve margin (IRM) for the next three delivery years and create an initial IRM for the first all-Capacity Performance delivery year in 2020/21.

The results of the study are expected to be presented in September, with a vote on the IRM the following month.

Members had endorsed the assumptions for the IRM study, proposed by the Resource Adequacy Analysis Subcommittee, at their last meeting. (See “Installed Reserve Margin Study Assumptions Endorsed,” PJM Planning Committee & TEAC Briefs.)

A total of 55 candidates were studied. Two other models came close: the 12-year period from 2002 to 2013 and the 10-year span from 2004 to 2013.

The tie-breaker was determining which period achieved world load diversity, PJM’s Tom Falin said.

New Shickshinny 500-kV Switchyard Proposed in Northeast Pa.

PPL is revising its transmission line designations as a result of the new Shickshinny switchyard for Moxie Energy’s 850-MW gas-fired Freedom station outside of Wilkes-Barre, Pa. The existing Susquehanna-Lackawanna 500-kV line will be split into the Susquehanna-Shickshinny line (5067) and the Shickshinny-Lackawanna line (5062).

— Suzanne Herel and Rory D. Sweeney

July 15, 2016

MISO Backs Forward Auction Plan, Rejects Prompt Proposal

By Amanda Durish Cook

Citing an analysis by The Brattle Group, MISO has decided to stick with its original forward design in its capacity auction overhaul, rejecting the hybrid prompt auction proposal it had negotiated with the Independent Market Monitor.

Jeff Bladen, executive director of MISO market services, said the forward proposal was the “best fit” to address price formation and encourage entry by new resources.

“This is the best chance of seeing real improvement,” Bladen said during a special conference call of the Resource Adequacy Subcommittee Thursday .

Monitor David Patton continued his criticism of the forward proposal, which he has called “fundamentally unsound.” (See MISO, Monitor Release Negotiated Auction Redesign.)

According to Brattle’s analysis, a forward model would reduce price volatility by 35 to 37% compared to the current Planning Resource Auction. The hybrid prompt proposal, Brattle analysts said, would reduce volatility by 25 to 28%. Brattle said a forward proposal paired with a broader and more gently sloping demand curve could reduce price volatility by 44 to 48%.

Bladen said MISO is still “fine-tuning” the curve shape and could incorporate Brattle’s recommendation.

Brattle analysts said that while the forward model attracts an additional 1,800 MW of merchant supply when compared to the status quo and “substantially” improves reliability, it still falls “somewhat” short of redesign objectives.

A wider demand curve could bring 2,200 MW in merchant supply, meeting the one-day-in-10-years loss-of-load expectation. Brattle said the prompt hybrid proposal supports an additional 1,200 MW of merchant supply and that, although reliability improves under the model, it is “still substantially short of reliability objectives.”

Not Surprised

Patton criticized Brattle’s analysis, saying it measured volatility and reliability but ignored efficient pricing that allows generators to recover costs. Patton insisted that some volatility was natural.

“Volatility is a secondary metric at best,” he said.

Patton said he wasn’t surprised by MISO’s decision to move ahead with its own proposal.

“Fundamentally, I never felt like we reached a compromise because MISO never agreed to do the prompt proposal. They always had a strong preference for a forward proposal. I think it’s a mistake,” he said.

Despite that, Patton said he did not feel that working with MISO on the prompt proposal was a “charade.”

Bladen said the forward proposal minimized Tariff changes and is the best choice when considering reliability and FERC precedent. Patton countered that the legal hurdles to implementing a prompt proposal “weren’t nearly as daunting as MISO makes it seem.” He also said instituting the two-stage prompt auction would not undermine the current PRA, although it may lower prices.

Several stakeholders questioned Brattle’s Monte Carlo analysis, a probability simulation using repeated sampling. Brattle analysts noted that “findings may change with future refinements, particularly to assumptions in how utilities participate in forward auctions.”

“That’s a pretty big caveat,” Dynegy’s Mark Volpe said.

Brattle analyst Kathleen Spees said the forward analysis carries substantial uncertainty “simply because there’s not as much evidence on how utilities will behave. In the prompt proposal, we have much more empirical evidence.”

Bladen said the Monte Carlo analysis took “thousands” of scenarios into account.

Volpe asked if Brattle supported MISO’s decision to move ahead with the forward proposal.

“Look, nothing is going to be perfect or perfectly predictable in this environment,” Brattle analyst Sam Newell said. “That said, the elements of this proposal are clearly better that the status quo and better than other alternatives, including the prompt proposal.”

Newell said the forward proposal “achieves an economic efficiency that the alternative does not” and is the best proposal to provide reliability at least cost. Newell also said the forward proposal is “unambiguously” better than the current construct.

In response to stakeholder questions, Newell and Spees said their study did not consider scenarios assuming supply from MISO South, reduced demand or a case focusing on renewable growth.

“If this is a billion-dollar business, why so many simplifications?” asked Indianapolis Power and Light’s Ted Leffler.

Newell responded that the lack of historical evidence prevented a more definitive study.

“MISO has looked exhaustively at the prompt hybrid proposal. We simply didn’t believe we could move forward with the hybrid prompt proposal,” Bladen said.

FERC Filing Next Month

MISO expects to file its proposal with FERC sometime next month. Bladen said MISO would “act without undue delay,” as directed by its board.

Draft Tariff language and revised Business Practices Manuals are expected to be posted by July 20; stakeholder discussions regarding the language is planned at the Aug. 3-4 RASC meeting. MISO will make another presentation regarding Tariff language on Aug. 8 before the Markets Committee of the Board of Directors.

Volpe said that MISO excluded stakeholders by not presenting the Advisory Committee with both proposals for review before announcing a decision.

Bladen said it wasn’t MISO’s intention to subvert the stakeholder process and pointed to the year and a half of discussion on auction redesign. He agreed the Advisory Committee could hold a special meeting on the auction design proposals or even recommend a delay in filing.

“We don’t want to stand in the way of the Advisory Committee coming together to debate,” Bladen said.

Marcus Hawkins, an engineer with the Public Service Commission of Wisconsin, responded that for the first seven months of the discussion, stakeholders had only an issues statement from MISO.

IMM Critical of Analysis

In his own presentation, Patton said prices in the forward proposal are “heavily dependent on decisions that regulated and external entities make to offer” and would result in annual price fluctuations exceeding $500 million, resulting in poor price signals to competitive suppliers.

“There is no way to predict where this market will clear year-to-year,” Patton said. He said MISO’s forward proposal fails to ensure auction clearing prices are consistent with the marginal value of reliability.

Patton said MISO’s forward proposal is not comparable to forward markets in other RTOs. “This is the first time that I’ve seen a model where the demand does not reflect the requirement,” he said.

Patton also said Brattle did not properly model the prompt proposal, including a much steeper demand curve than recommended. He said Brattle’s Monte Carlo analysis carried too much uncertainty because of assumptions regarding the demand curve and participant behavior. “I don’t envy The Brattle Group,” Patton said.

Stakeholders Split

Before Thursday’s meeting, stakeholders provided feedback on the two proposals.

Two members of the Michigan Legislature wrote a letter in support of a forward auction. “The three-year forward proposal provides long-term pricing signals that we feel are critical to attract new generation capacity to Michigan,” Sen. Mike Shirkey (R-Jackson) and Rep. Gary Glenn (R-Larkin Township) wrote.

Northern Indiana Public Service Co. and Alliant Energy asked that MISO and the Monitor take more time to explain and vet their proposals with stakeholders. Likewise, Duke Energy, Big Rivers Electric, Hoosier Energy and Southern Illinois Power Cooperative said they required more information before backing a proposal.

Illinois Industrial Energy Consumers and DTE Energy said neither proposal was acceptable.

Wolverine Power Cooperative called for a footprint-wide three-year forward auction instead of a proposal that blends a regulated prompt auction and a retail-choice forward auction.

American Electric Power also said it preferred at least a three-year advance auction for the entire footprint.

“This provides a price signal to the resource owner in time to budget and plan for maintenance, upgrades, fuel supplies, development of new resources, etc. It also would allow loads, both retail switching and wholesale, sufficient time to develop, evaluate and budget for supply offerings, with known auction result prices,” AEP said.

The Organization of MISO States said it needed more information before it selected a proposal to support, but it also added that it had “mixed opinions as to whether each proposal will promote generation investment.”

Dynegy also said it supported the prompt proposal. “At this point, it is abundantly clear that the hybrid prompt proposal may result in a clearer price signal for supporting restructured competitive retail markets,” Dynegy wrote.

Consumers Energy said the forward proposal is the better option but wanted revisions to Safe Harbor provisions for not entering generation into the auction and wanted the cost of new entry raised “to better incent new generation in shortage situations.”

Main Line Generation asked for the addition of a minimum price offer rule in both proposals.

July 14, 2016

Puget Sound Energy, Talen Agree to Close Colstrip Units

By Robert Mullin

Puget Sound Energy (PSE) and Talen Energy reached an agreement with environmentalists to shut down Units 1 and 2 at the coal-fired Colstrip power plant in Montana by July 2022.

Under the July 12 settlement filed in the U.S. District Court in Missoula, the Sierra Club and the Montana Environmental Information Center (MEIC) agree to dismiss their lawsuit against the plant’s owners for alleged violations of the federal Clean Air Act. PSE and Talen will also be required to reduce sulfur dioxide and nitrous oxide emissions from the units ahead of retirement (Case 1:13-cv-00032-DLC-JCL).

The agreement also stipulates that the environmental groups will drop legal action against Colstrip Units 3 and 4, which are jointly owned by PSE, Talen, Portland General Electric, Avista, PacifiCorp and NorthWestern Energy. Those coal-fired units were built in the mid-1980s and have a combined net generating capacity of 1,480 MW.

“PSE believes this settlement is in the best interest of our customers by avoiding the potential need for the installation of additional pollution control equipment for Units 1 and 2 due to future regulatory requirements,” the company said in a statement.

Environmental Rules, Competitive Pressures

Competitive pressures stemming from low natural gas prices factored into PSE’s decision to close the units. The company also cited “shifting policies and regulations on the federal and state levels,” EPA’s regional haze rule and the Clean Power Plan as additional reasons.

“Our customers expect PSE to be good stewards of the environment and to keep energy costs reasonable,” CEO Kimberly Harris said. “The eventual closure of Units 1 and 2 at Colstrip without the risk of further legal proceedings or additional significant investments in the units to meet regulatory requirements enables us to accomplish both of these goals.”

puget sound energy, talen, colstrip — Colstrip Power Plant *Source: Talen Energy*

Built in the mid-1970s, the two units can produce 614 MW of electricity, most of which is supplied to consumers in Washington and Oregon. Earlier this year, Washington lawmakers passed a bill that would enable PSE to recover its share of the costs for shutting down the units from ratepayers, while Oregon established a mandate requiring PacifiCorp and PGE to become coal-free by 2030 and 2035, respectively.

In May, Pennsylvania-based Talen notified Colstrip’s other five owners that it planned to cease functioning as the plant’s operator in May 2018. As the plant’s only merchant owner, the company is unable to recover its costs from a rate base and is especially exposed to low power prices on the open market.

The move was part of a broader strategy to withdraw from Montana by the company, which last month agreed to be acquired by Riverstone Holdings. (See Riverstone to Acquire Talen in $1.8 Billion Deal.)

Opportunity for Wind?

Colstrip’s owners collectively own the two 250-mile, 500-kV transmission lines that connect the plant with the Bonneville Power Administration’s transmission network and load centers in the Pacific Northwest. Renewable energy advocates have eyed Colstrip’s transmission as a possible boon for wind development in Montana, a state that the American Wind Energy Association ranks as third in the U.S. for wind potential.

“[The] decision [by PSE and Talen] marks an opportunity to use Colstrip’s existing transmission system to build out more clean energy and export it to Washington and other states,” the Sierra Club said in a statement.

“We want to work with the power plant owners, the community of Colstrip and Montana to plan for a transition that maximizes employment in clean-up, remediation and new renewable energy development in the Colstrip area,” said Mike Scott, a Sierra Club senior organizer.

Montana Gov. Steve Bullock (D), who faces a re-election campaign this fall, was less enthusiastic about the immediate prospects for the region.

“I stand with the workers and the community of Colstrip in being angry about this settlement outcome,” Bullock said. “The parties of this lawsuit took care of themselves. I am going to work to take care of the employees and their families.”

July 13, 2016January 23, 2024

Study Touts Benefits of CAISO Expansion

By Robert Mullin

CAISO’s expansion into a multistate, regional electricity market could save California ratepayers as much as $1.5 billion annually while helping the state to meet or exceed its 2030 emission-reduction goals, according to a study commissioned by the ISO.

California’s Clean Energy and Pollution Reduction Act — the 2015 law that established the state’s 50% by 2030 renewable portfolio standard — required CAISO to perform an analysis of the economic, environmental and reliability impact of regionalizing the Western grid.

The study modeled three 2030 scenarios: one in which California meets its RPS without expansion and ones with a regionalized market with state- and regionally focused procurements. The last scenario offered the most significant benefits, according to the analysis, which was conducted by The Brattle Group, Energy and Environmental Economics, Berkeley Economic Advising and Research and the Aspen Environmental Group.

‘Compelling Message’

The benefits estimated in the study are in addition to those expected from CAISO’s expanded Energy Imbalance Market.

Development of a regional market could generate up to 19,300 new jobs for the state by 2030, more than half of which would be related to construction of renewables, the study found. Other jobs would be the indirect result of realigned consumer spending based on reduced energy costs.

Real income in California is expected to increase by $4.1 billion to $7.9 billion annually, while state tax revenues would rise by $600 million to $1.6 billion.

The study’s findings provide a “pretty compelling and simple message,” CAISO CEO Steve Berberich said.

“The electric industry in California is at an inflection point,” Berberich told reporters during a call Tuesday to discuss the report. “I think the state has the ability to enable a new paradigm where clean energy and economic growth become one.”

The study analyzed two regional market footprints: one including only CAISO and PacifiCorp and a second including all of the U.S. portion of the Western Electricity Coordinating Council except the two federal power marketing agencies there, the Bonneville Power Administration and the Western Area Power Administration. “These footprints are hypothetical and are designed to capture a plausible range of impacts,” the study notes. “We understand that the individual utilities and states will have to conduct their own evaluations of the benefits and trade-offs of joining a regional entity and to decide whether or not to join one.”

Regionalization would provide the ISO the ability to optimize generation over a larger footprint, allowing California “to go beyond” its 50% RPS, Berberich said. The study included the costs of storage and transmission needed to integrate renewables.

Fear of Curtailments

Without expansion, the ISO predicts periodic renewable curtailments of up to 13,000 MW — even with the expected closure of Pacific Gas and Electric’s Diablo Canyon nuclear power plant in 2025.

“Absent a regional market, we’re very concerned that we could see a lot of renewable energy curtailed because there isn’t an adequate market to sink the power,” said Keith Casey, ISO vice president for market and infrastructure development.

Casey noted that other RTOs in the U.S. are facilitating the development of “non-RPS” renewables — renewable projects built based on cost-competitiveness rather than in response to mandates. “For example, since 2000, wind generation accounted for 80% of 44,000 MW of non-RPS-related renewable generation additions nationwide, and 80% of these non-RPS-related wind generation investments (over 28,000 MW) took place in six states (Texas, Iowa, Oklahoma, Kansas, Illinois and Indiana), all of which are in ISO-operated market areas,” the report said.

CAISO’s study found that a regional market could eventually save California ratepayers as much as $1.5 billion a year.

“We think this [expanded CAISO] market will provide a platform for renewable development to flourish,” Casey said.

Other highlights of the study:

- - By 2030, the market would help California reduce electric sector CO₂ emissions by 4 million to 5 million metric tons per year — 8 to 10% below a scenario with no regional market. That would represent a 58% decline from 1990 levels.
  - Land use for building new wind and solar developments to meet California’s RPS would be reduced by up to 71,300 acres inside the state and 31,900 acres elsewhere in the West because of more efficient resource expansion. The study projects increased transmission construction outside California to support out-of-state projects.
  - A regional market would reduce water use by combined-cycle gas units in California and gas and coal plants in other areas of the West as a result of the more efficient dispatch of renewable resources.
  - The market’s larger operational footprint would allow for improved renewable integration through centralized control and increased awareness of neighboring areas. Lower requirements for load-following resources, operating reserves and planning reserves would lower costs for maintaining reliability.