CARMEL, Ind. — MISO planners approved an expedited project request in northeast Arkansas and are evaluating three others in Michigan, officials told the Planning Advisory Committee last week.
The $3 million Hickman Central project, submitted by Arkansas Electric Cooperative Corp. in October, will include a new substation, a quarter-mile line to connect it to the Dell-Blytheville North 161-kV line and two 161/345-kV transformers, said Edin Habibovic, manager of expansion planning in MISO South.
The Little Rock-based cooperative said the improvements are needed by October 2017 to accommodate about 35 MW of new industrial load. It said getting approval under the 2017 Transmission Expansion Plan in December 2017 would be too late.
MISO recommended that AECC begin work on the project “as needed” to meet the in-service date in less than 10 months and said the project would be formally included in MTEP 17.
The RTO also received three expedited review requests from ITC Holdings’ Michigan Electric Transmission Co. on Nov. 30:
A new 120-kV substation and 2 miles of double circuit 120-kV lines to handle an added 6 to 10 MVA in northern Michigan;
A new 120-kV substation and 0.1 miles of underground cable to serve 5 MW of new DTE Energy load in Detroit; and
A new 138-kV substation to serve 35 MW of new Consumers Energy load near Grand Rapids, Mich.
MISO said it is performing an independent reliability analysis “to determine that the projects [do] not cause any harm to the system.” The RTO plans to schedule a Technical Studies Task Force meeting in January to discuss results, said Senior Manager of Transmission Expansion Planning Thompson Adu.
After seven years in the PAC chair, American Transmission Co.’s Bob McKee has announced he will not seek re-election.
MISO PAC Liaison Jeff Webb called him the “PAC Man” and presented him with a Pac-Man themed blanket. “It is in fact, sadly, game over,” Webb joked.
During his tenure, McKee oversaw MTEPs from 2010 to 2016. In parting words, he encouraged stakeholders to “take stock” and be actively involved in MISO’s planning process.
ITC’s Cynthia Crane will take over next year as chair.
VALLEY FORGE, Pa. — PJM’s proposed timeline for reviewing tie-line requests will need another round of revisions before members are comfortable with endorsing it.
Two clarifications precluded members from bringing it to an endorsement vote at last week’s Planning Committee meeting. The first concern was an implication that the applicant must present their request at a meeting of the System Operations Subcommittee’s transmission owners group (SOS-T) following PJM’s legal and technical review. The second issue was the timeline’s awkward construction, in which it counts down to a FERC filing date and then counts down again to an in-service date.
“We thought it was valuable, but if it’s causing issues, we can remove it,” PJM’s Sue Glatz said. She went on to request an endorsement vote with the understanding that the clarifications will be made.
Stakeholders questioned PJM’s pressure to secure approval despite reservations.
“It’s essential that these documents be clear and concise. I’m not wishing this on anyone, but there is the possibility that some of us might not be around to interpret them,” American Municipal Power’s Ed Tatum said.
| PJM
PJM’s Paul McGlynn countered that the process has been going on for quite some time. “We’ve been at it for four months now,” he said.
Project-Selection Guidelines Criticized as Too Subjective
PJM unveiled guidelines for how it will select market efficiency projects, noting a “bright line” criterion that it must relieve at least one economic (capacity or energy) constraint. Projects also must clear a benefit/cost ratio of 1.25:1 and proposals with estimated costs of more than $50 million will be subject to an independent review.
John Farber of the Delaware Public Service Commission questioned what he called PJM’s “market efficiency at any cost” metrics and asked that it increase its focus on gathering “objective data to move this from a subjective to an objective process” going forward. He said PJM’s analysis is subjective and that cost containment caps are not a “panacea.”
PJM’s Asanga Perera said congestion created by any outages needed to complete a proposed project would be factored into decisions if it’s useful, but that it’s “tough” to include short-term factors and a “one-time thing” like an outage into a 15-year analysis.
“I think what we’re suggesting with some of these slides is that a project without outage congestion might be a better choice,” McGlynn said.
PJM will publish the guidelines, which will be effective for the 2016/17 transmission planning cycle, on the market efficiency web page.
New Forecast Sees Further Load-Growth Reductions
PJM is again reducing its load growth projections due to the economic outlook and increased efficiency.
In its preliminary 2017 forecast, expected summer load for 2020 dropped 2.1% compared to last year’s forecast, while that for 2022 was down 2.9%. The winter 2020/21 forecast dropped 2.6% and 2022/23 was down 3.5%. 2020 was chosen for comparison because it’s the next year for the Base Residual Auction; 2022 is the year used in the Regional Transmission Expansion Plan study.
Analysis Needed to Answer Winter Resource Adequacy PS
Work is being done to assess how well it processes all factors, including how to quantify the operational risks of activities such as transmission outages and generator maintenance.
“Our suggestion is going to be that PJM take the next two or three months to assess internally,” he said.
He expected to have more information for March’s Planning Committee meeting.
‘Immediate Need’ Designations Questioned
At the meeting of the Transmission Expansion Advisory Committee, stakeholders questioned PJM’s determination of “immediate need” for several transmission reliability projects and criticized the decision not to open them to competitive bidding.
In particular, an American Electric Power project in northeastern Indiana raised eyebrows. The company says an outage of its South Butler-Collingwood 345-kV line would result in the loss of more 300 MW of load.
One fix, estimated at $76.5 million, would involve a new 345-kV switching station and a new double-circuit 345-KV line of 17 miles. PJM said it favors an alternative proposal from AEP estimated at $107.7 million because it would also address aging-infrastructure concerns.
PJM’s recommendation rankled some members, who felt the project could have been identified earlier to allow for competitive bidding. Some also questioned including costs for local infrastructure that they said shouldn’t be allocated throughout the RTO.
Five transmission towers along the route are in immediate need of replacement, 79 will need to be addressed within three years and another 22 will need to be fixed soon thereafter, according to AEP’s assessment.
Sharon Segner of LS Power questioned PJM’s findings on two projects it plans to award to Dominion, the incumbent transmission owner, based on immediate need. According to Dominion’s proposal, the projects aren’t slated to be completed until 2021, which is beyond PJM’s definition for an “immediate need” project, Segner said. She suggested opening a 30-day window for competitive transmission developers like her company to propose alternatives.
“Right now, the incumbent transmission owner cannot meet it in three years. Therefore, it would seem to me the right thing to do would be to see if anyone can meet it in the proposal window,” she said.
PJM’s Steve Herling said that would create months of analysis and third-party verification for PJM that would only delay AEP from completing the project.
“We’ve already considered all of these factors, and what we have here is our decision. If you take exception to our decision, you can communicate it to the board,” he said.
PJM staff also pointed out that a recent FERC docket offered stakeholders the opportunity to raise these concerns. The commission’s July order in that case made clear that the definition is based on the date of need, not the in-service date (ER16-736, EL16-96). (See FERC Rejects PJM Cost Allocation on Dominion Project.)
PJM Review of Artificial Island Bid Elements Completed
“There may be benefits to installing the optical ground wire and new relay, but that scope of work would not directly address the operational performance issue,” McGlynn explained.
An OPGW serves as both a ground and a telecommunications link. PJM determined that although high-speed relaying using such wires would improve the clearing times for line faults, some bus-fault clearing times were more limiting. “Since the timing is not improved by the OPGW and line relay changes, they will not improve the stability margin,” PJM said.
One of the preliminary recommendations from PJM’s analysis is to remove the ground wire and relay upgrades from the project scope, McGlynn said.
Stakeholders asked whether, based on the scope changes, PJM plans to re-evaluate submitted proposals, but Herling said that was not possible.
“Realistically, we’re only looking at the finalists … in the context that things have changed. … We’re not going to go back to the most expensive projects that were eliminated,” he said. “We’re still working our way through the cost issues and the constructability issues. … Obviously, we still have a lot of work to do.”
RTOs and ISOs would be required to incorporate fast-start resources into energy and ancillary services pricing under a Notice of Proposed Rulemaking approved by FERC on Thursday (RM17-3).
Kheloussi | FERC
The commission said new rules are required to allow fast-start resources to set LMPs — changes regulators said should reduce uplift and provide more accurate price signals to encourage investments.
“Without some form of fast-start pricing, most fast-start resources are not eligible to set prices even when they are the marginal resource,” Daniel Kheloussi, a staffer in FERC’s Office of Energy Policy and Innovation, said during a presentation at the commission’s monthly meeting. “Further, even when fast-start resources can set prices, they may not be able to recover their commitment costs, such as start-up and no-load costs, through prices. As a result, prices may not reflect the marginal cost of serving load.”
The commission said fast-start resources are unique because they are often dispatched to inflexible minimum or maximum operating limits, making them ineligible to set LMPs. They also are usually committed in real-time.
“As a result, the cost to commit these resources is incurred at roughly the same time the incremental energy costs are incurred, which raises the question of whether the commitment costs should be included in the LMP,” the commission said. “Finally, fast-start resources can arguably respond quickly enough to be considered part of an RTO’s/ISO’s operating reserves even when they have not yet been committed.”
Seeking to build on the RTOs’ best practices, the NOPR would:
Standardize the definition of fast-start resources to include any resource committed by the RTO/ISO that is able to start up within 10 minutes or less, has a minimum run time of one hour or less and that submits economic energy offers to the market. The definition would be technology-agnostic.
Require that an RTO must incorporate the start-up and no-load costs (commitment costs) of a committed resource in energy and operating reserve prices for the resource’s minimum run time.
Require RTOs to relax the resource’s economic minimum operating limit (eco min) when calculating prices — treating it as if it is dispatchable from zero to the economic maximum operating limit (eco max).
Allow offline fast-start resources to set prices under certain system conditions when they are economic and feasible.
Require RTOs to incorporate fast-start pricing in both the day-ahead and real-time markets to support price convergence between the two.
The NOPR is the third issued by the commission since it initiated a proceeding on price formation in RTO/ISO markets in June 2014 (AD14-14). It follows a June order requiring RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period (RM15-24). (See New FERC Rule Will Double RTO Offer Caps.)
Inflexible
Fast-start resources are often required to be dispatched at their eco min or are block-loaded — in which the eco min equals its eco max.
Because the system may not need all of the resource’s eco min to meet load, other resources must be dispatched down, making them the most economic option to serve the next increment of load. “Therefore, despite the fact that a fast-start resource is essentially marginal, this restriction prevents a fast-start resource dispatched at its economic minimum operating limit from setting the LMP,” the commission said.
Thus, some RTOs have relaxed the resources’ eco min limits, treating them as dispatchable in a pricing algorithm separate from the dispatch algorithm. But while these changes can improve price signals — especially during stressed conditions when the need for fast-start resources is the greatest — the disconnect between prices and dispatch instructions can cause over-generation. Only some RTOs conduct reconciliations between the pricing and dispatch runs to prevent excess generation, FERC said.
RTOs Have Differing Approaches
In comments filed following the commission’s technical workshops on price formation, many stakeholders said they would support changes allowing resources dispatched at their operating limits to set LMP and allowing start-up and no-load costs to affect prices. The Electric Power Supply Association and Western Power Trading Forum said such changes could help address CAISO’s “duck curve” by redistributing excess costs incurred during the middle of the day to the ramping periods.
Region
Fast-Start Resource Definition
No-load costs incorporated in LMPs?
Startup costs incorporated in LMPs?
Set DA prices?
Set RT prices?
Offline prices set LMP?
FERC NOPR
Start-up: within 10 minutes or less. Minimum run time: one hour or less. Other: Submits economic energy offers.
Yes
Yes
Yes
Yes
Yes
CAISO
Start-up: online within two hours or less. Other: can be committed in CAISO’s 15-minute market or short-term unit commitment process.
Yes
No
Yes
Yes
No
ISO-NE
Start-up: 30 minutes or less. Minimum run time: one hour or less. Minimum down time: one hour or less.
Yes (1)
Yes (1)
No
Yes
No
NYISO
Does not apply fast-start pricing to all fast-start resources.(2)(3)
N/A
Yes
Yes
Yes
Yes
PJM
Start-up: two hours or less (fast start CT). Block-loaded resource: eco min = eco max.
No
No
Yes (4)
Yes
No
MISO
Start-up: 10 minutes or less. Minimum run time: one hour or less.(6)
Yes
Yes
Yes
Yes
Yes (5)
SPP
Start-up: 10 minutes or less. Minimum run time: one hour or less. Other: total minimum down time one hour or less. (10)
No (7)
No (8)
Yes (9)
Yes
No
(1) New rules effective March 1, 2017 (ER15-2716).
(2) Uses “hybrid gas turbine pricing logic” and “offline gas turbine pricing logic” for all fast-start block loaded resources in its real-time energy market. Allows all fast-start block loaded resources to set price in its day ahead energy market.
(3) Worked with Market Monitoring Unit and stakeholders on revising its “hybrid gas turbine pricing logic.” In a Dec. 14 FERC filing (ER17-549), the ISO proposed broadening its eligibility criteria to allow all fast-start resources to be eligible to set prices in its real-time energy market.
(4) Yes. But generally limited to certain operational conditions like constraint control.
(5) Yes. Only under reserve or transmission scarcity conditions.
(6) Extended LMP took effect in 2015 (150 FERC ¶ 61,143). Planning to implement ELMP Phase II to apply fast-start pricing to more peaking resources.
(7) No. But does allow inclusion of no-load costs in mitigated energy offer curves for unit commitment.
(8) No. But does allow inclusion of start-up costs in mitigated energy offer curves for the unit commitment.
(9) Yes, if offered into day-ahead market.
(10) Implementing fast-start pricing to commit quick-start resources more efficiently in real-time in Q2 2017.
ERCOT (Not subject to FERC NOPR)
Start-up: 10 minutes or less. No minimum run time requirement (11) (17)
Yes (12)(13)
Yes (13)(14)
Yes (15)
Yes (13)(16)
Yes
(11) Resource is exempted from following instructions for the first five-minute dispatch. Regulation reserves are used to cover missing energy.
(12) Yes. Market participants may include no-load costs in energy offer curves.
(13) Uplift may occur in cases in which the assumptions built into the energy offer curves are not correct and costs are not fully recovered.
(14) Yes. Market participants may include startup costs in energy offer curves.
(15) Yes. Day-ahead market is voluntary. Market participants may include no-load and start-up costs in energy offer curves.
(16) Market participants may include no-load and start-up costs in energy offer curves.
(17) Analyzing the feasibility and benefits of implementing a multi-interval real-time market.
The commenters noted that start-up time requirements for quick-start resources range from 10 minutes in NYISO, MISO and SPP, to 30 minutes in ISO-NE and two hours in PJM and CAISO.
Several stakeholders praised MISO’s extended LMP. The program, implemented in March 2015, is designed to reduce uplift by incorporating all offer costs into market clearing prices. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.) The RTO is planning to implement ELMP Phase II to apply fast-start pricing to more peaking resources.
NYISO and ISO-NE also received some praise, while Golden Spread Electric Cooperative criticized SPP, saying the RTO’s market design and operator practices fail to reflect fast-start resources’ costs and their value to the system.
NYISO worked with its Market Monitoring Unit and stakeholders on revising its “hybrid gas turbine pricing logic,” resulting in a Dec. 14 FERC filing in which the ISO proposed broadening its eligibility criteria to allow all fast-start resources to be eligible to set prices in its real-time energy market (ER17-549).
ISO-NE will be implementing new rules effective March 1, 2017, to incorporate no-load and start-up costs in LMPs (ER15-2716).
SPP said it will be implementing fast-start pricing to commit quick-start resources more efficiently in real time in the second quarter of 2017.
PJM was criticized by its Independent Market Monitor, which said that relaxing eco mins for price setting is subjective and overrides “fundamental pricing logic,” sometimes increasing total production costs.
The RTO also was criticized for limiting its fast-start definition to combustion turbines and excluding reciprocating engines.
| GE Power Generation
“A natural gas-fired reciprocating engine that has a cold start-up time of only five minutes and has an economic minimum of 50% of its economic maximum is much, much more flexible, and provides significantly more value to the bulk electric power grid, on a per-megawatt-hour basis, than an inflexible block-loaded resource that takes two hours to start,” IMG Midstream and Tangibl said in comments to the commission.
ERCOT, which is not subject to the FERC NOPR, is analyzing the feasibility and benefits of implementing a multi-interval real-time market.
Comments Sought
The commission asked stakeholders to comment on its proposals, including whether they could result in the exercise of market power. “The concentrated ownership of fast-start resources could raise market power concerns that are not addressed in existing RTO/ISO market power mitigation procedures,” FERC said.
The commission also acknowledged that the changes could require complex and expensive software changes. “We seek comment on the required software changes, updates to optimization modeling and parameter inputs, estimated costs and time necessary to implement” the changes, FERC said.
Comments are due 60 days after publication in the Federal Register.
ERCOT’s electricity demand continues to grow more rapidly than expected, and while reserve margins are projected to shrink slightly, the Texas ISO says it still has sufficient capacity to support system reliability.
“Based on the information we have today and current planning criteria, we continue to see sufficient planning reserve margins through most of the 10-year planning horizon,” ERCOT’s senior director of system planning, Warren Lasher, said Thursday.
The Texas grid operator’s latest Capacity, Demand and Reserves (CDR) report, released last week, indicates next summer’s peak demand will reach nearly 73,000 MW, growing to more than 77,000 MW by summer 2021. ERCOT set a new system peak this summer when it reached 71,110 MW on Aug. 11.
| ERCOT
The ISO expects to have more than 82,000 MW of capacity available for next summer and more than 88,000 MW by summer 2021.
The increased load growth will cut the ISO’s reserve margin to 16.9%, down from the May 2016 forecast of 18.2%. The CDR sees the reserve margin climbing to 10.2% in 2018 but dropping to 19% in 2021 — still well above ERCOT’s 13.75% target.
ERCOT attributes the load growth to the state’s strong economy, fueled by a rebounding petroleum market and high-tech jobs in Central Texas.
“We’re seeing stronger growth than Moody’s projected a year ago,” said ERCOT Manager of Load Forecasting and Analysis Calvin Opheim. “Texas growth used to be tied to oil and gas and drilling. Those [industries] appear to be coming back alive, but when you come into Central Texas and San Antonio, a lot of people are moving here for well-paying jobs” in other industries.
Opheim said Moody’s forecast for Central Texas, which ERCOT incorporates in its planning models, projects employment growth rates of more than 3% in 2021.
The Federal Reserve Bank of Texas is also optimistic, saying a stabilized energy sector, recent improvements in the manufacturing sector and increased optimism by Texas businesses will likely lead to a “moderately” improved economy in 2017.
ERCOT’s demand in November 2016 was already up 11.2% compared to November 2015.
The new CDR shows almost 2,700 MW of new capacity since the May report, including 1,188 MW of wind and 262 MW of solar. ERCOT surpassed 500 MW of installed solar resources when a 160-MW project in West Texas was synched to the grid in November.
By next summer, the ISO expects to add nearly 3,000 MW of wind, more than 450 MW of solar and 2,660 MW of gas resources — more than 2,150 MW coming from two units near Houston and Fort Worth.
Planned resources reflect more than 10,000 MW of additional capacity by 2021.
The ISO’s long-term forecast, which is updated annually, includes the addition of a new LNG facility being developed on the Gulf Coast, but it doesn’t take into account Lubbock Power and Light’s proposed migration of 430 MW of load from SPP to ERCOT.
MISO’s Reliability Subcommittee last week narrowly approved a more stringent process for deciding on pseudo-tie requests.
The package, approved 5-4 with 13 abstentions at a Dec. 16 special meeting, includes a pro forma pseudo-tie agreement and Business Practices Manual language for generators that intend to sell their capacity or electricity outside the RTO’s footprint.
| MISO
MISO plans to file the proposed rules with FERC in early January. But Senior Director of Regional Operations David Zwergel said the narrow vote and large number of abstentions could give the RTO pause and lead to more discussions to see if minor language changes could address opponents’ concerns.
The new rules say proposed pseudo-ties can be rejected and existing pseudo-ties can be revoked if a market-to-market flowgate is not within 2% of MISO and the neighboring market’s calculated generator-to-load distribution factor. (See MISO Readies Updated Pseudo-Tie Rules.)
Andy Witmeier, of MISO’s operations division, said attaining RTOs — those using generators outside their borders — need to accurately calculate the impact that their pseudo-tied generation has on M2M flowgates.
The 2% provision, however, was a source of stakeholder confusion. Brian Garnett of Duke Energy said MISO had contradicted itself in the BPM language because in one instance, the RTO said the rules would not be retroactively applied, yet existing pseudo-ties could be subjected to the 2% rule. Amanda Schiro, manager of model engineering, said an existing pseudo-tie would only be subject to the 2% rule if it is modified, which would trigger a restudy under the new criteria.
Zwergel said he did not expect MISO to rescind any existing pseudo-ties based on the 2% threshold, but he said it wants to reserve the right in case an attaining RTO drastically changes its model and large discrepancies between models occur. Currently, pseudo-tie modeling in MISO is conducted four times per year, and Witmeier said the RTO’s modeling occurs “within a few weeks of other RTOs.”
WPPI Energy’s Steve Leovy said he’d like to see a more stringent tolerance than MISO’s proposed 2%, but RTO staff said they were confident with that threshold.
Stakeholders asked if MISO would include some of the pseudo-tie language in the MISO-PJM joint operating agreement. Ron Arness, senior manager of seams administration, said MISO could consider memorializing the changes in the JOA, but he did not see a need yet.
“It’s something we could monitor if [MISO’s and PJM’s rules] don’t align,” Arness said. “Today we don’t see any incompatibilities.”
Entergy’s Jeff Knighten, who cast an opposing vote, said his company agreed with a lot of details but “wasn’t ready to sign off yet.” Entergy said the 2% shift factor might work well “under test conditions,” but RTOs might not be able to maintain the same accuracy “under transmission outage conditions which may result in a substantial change in system flows.”
The other companies to provide public comments, NRG Energy and Occidental Chemical, likewise said details around the threshold were lacking and asked for justification.
CAISO’s Board of Governors approved a 2017 budget that includes a $4.3 million increase in spending but no corresponding rise in the grid operator’s revenue requirement.
“I do think it’s worth pointing out that the board has been engaged in development and review” of the budget before the vote, CAISO CEO Steve Berberich said during the board’s Dec. 15 meeting. “So it’s really been an ongoing process. This is just the final step.”
Although the ISO’s total expenditures are set to increase by 2% to $214.5 million, the annual revenue requirement will remain unchanged at $195.3 million, 18% its 2003 peak and 3.5% under the current FERC-approved cap.
The reason: Next year’s $4.6 million rise in labor expenses will be offset by expected revenues from other sources, including money earned from administering the Western Energy Imbalance Market (EIM). The EIM is projected to bring in $4.8 million for the ISO in 2017, compared with $2.5 million this year.
The ISO’s revenue requirement consists of five components, including operations and maintenance, debt service, cash-funded capital, an operation cost adjustment from the previous year and other costs and revenues. Those additional revenues are collected through EIM administrative charges and fees assessed for intermittent resource forecasting and generator interconnections.
Increased cash flow from other sources will allow CAISO to leave its 2017 revenue requirement unchanged from this year’s level. | CAISO
CAISO recovers its revenue requirement through grid management charges assessed to market participants based on their use of the transmission system to serve load or deliver exports. The charges are slated to increase slightly next year, with ISO transmission volumes projected to fall 2 TWh, to 240.7 TWh. The drop continues a decline in recent years that’s due in part to a persistent drought, which has reduced the volume of water being moved across the state using a massive network of electrical pumps.
Fixed fees related to market operations — such as inter-scheduling coordinator trade and congestion revenue rights fees — will remain unchanged.
Operations and maintenance constitutes about 80% of the ISO’s budget at $173.6 million, up 2.6% because of rising labor costs, including merit pay and benefit increases for existing staff and the addition of seven new employees.
CFO Ryan Seghesio earlier this year told stakeholders that CAISO has held a “tough line” on headcount but that “stress points” in several departments necessitated additional hiring. (See CAISO Sees Steady Revenue Requirement Despite Spending Rise.)
The increased labor expenses will be partially offset by decreased costs from vacating the ISO’s Alhambra leased site, as well as declining outlays for consulting and contract staff.
Debt service costs will hold steady at $16.9 million. Construction of the ISO’s headquarters accounts for most of the debt, according to April Gordon, the ISO’s manager for budgeting and planning. Debt costs remain well below the 2006 peak of more than $80 million.
CAISO estimates it will spend $20 million on capital projects next year, most of them related to technology upgrades to support existing and new market operations.
Any minor year-end adjustments to the O&M budget made after the board’s approval will not affect the final approved budget, the ISO said.
FERC on Thursday proposed changes to its pro forma large generator interconnection rules intended to increase certainty and transparency for new resources (RM17-8).
The commission issued the Notice of Proposed Rulemaking in response to feedback gathered at a May technical conference and in subsequent comments. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.) Generation developers have long complained about the long wait time for interconnection approvals. Transmission providers complained about the number of projects that drop out of the interconnection queue — increasing the number of restudies needed — and the high concentration of projects, such as wind farms, in small geographic areas.
“Cost and timing uncertainty presents a significant obstacle, as some interconnection customers are less able to absorb unexpected and potentially higher costs or extended timelines resulting from the withdrawal of requests higher in the queue,” the commission said in a news release. “A lengthy interconnection process can be a challenge to generation technologies that are evolving rapidly. The commission believes that interconnection processes should be capable of incorporating rapidly evolving generation technologies into an interconnection request while maintaining system reliability.”
FERC detailed 14 changes to the pro forma Large Interconnection Agreement and Interconnection Procedures that it said should address these and other concerns. Among the most notable are requirements that transmission providers post the methodologies used to form network models in their interconnection studies, as well as congestion and constraint information, on their Open Access Same-Time Information System (OASIS) sites.
They would also be required to allow interconnection customers to:
limit their requested level of service below their generating facility’s capacity;
operate on a limited basis before the full interconnection process is completed; and
use surplus interconnection service at existing points.
RTOs and ISOs would also be required to develop a resolution process for interconnection disputes between developers and transmission owners.
The reforms would apply to projects over 20 MW, but the commission is seeking comment on whether any of them should apply to rules for small generators as well.
Commissioner Colette Honorable cited the need to accommodate new technologies, such as energy storage, as one of the main reasons for the NOPR. Two of FERC’s changes dealt with energy storage resources specifically. One would change the definition of “generating facility” in the pro forma documents to explicitly include storage. The other would require transmission providers to evaluate their methodologies for modeling storage resources in their interconnection studies and report their findings to FERC.
“The commission believes the proposed reforms will benefit interconnection customers through more timely and cost-effective interconnection and will benefit transmission providers by mitigating the potential for serial restudies associated with late-stage interconnection request withdrawals,” it said.
“I think this is a good example of the kind of bread-and-butter work that FERC does that may not always receive much public attention: work that is technical and weedy, but work that nevertheless is very important,” Chairman Norman Bay said at the commission’s open meeting Thursday. “I think today’s NOPR strikes an important balance between the needs of interconnection customers and those of transmission owners.”
Stakeholders have long sought commission action on the interconnection process. The pro forma agreement and procedures were established in 2003 and most recently updated in 2008. May’s tech conference was prompted by a petition from the American Wind Energy Association last year. (See After Years of Questions, Interconnection Customers Await Answers.)
Comments are due no later than 60 days after the NOPR’s publication in the Federal Register.
Michigan’s Upper Peninsula will get its own utility, two new generating plants — and maybe additional transmission — following actions by regulators and MISO officials seeking to address the region’s reliability and cost concerns.
MISO said Wednesday it has committed to a study examining the benefits of transmission connection between Ontario and Michigan’s Upper and Lower Peninsulas. The announcement followed the Michigan Public Service Commission’s Dec. 9 order approving the creation of the Upper Michigan Energy Resources Corp. (UMERC) (Case No. U-18061).
The company will be formed from the electric and gas distribution assets of Wisconsin Electric Power Co. (WEPCo) and Wisconsin Public Service — both subsidiaries of Milwaukee-based WEC Energy Group — and will begin serving about 40,000 Upper Peninsula customers Jan. 1.
The terms of UMERC’s creation were negotiated under a settlement signed by the companies, PSC staff, Attorney General Bill Schuette, Tilden Mining, Cloverland Electric Cooperative and others.
No Cost Sharing
PSC spokeswoman Judy Palnau said the new utility will avoid cost-sharing with Wisconsin, as it will be regulated by Michigan alone.
The utility will be the owner and operator of two new proposed generating facilities expected in operation by 2019, one year before the Presque Isle plant in Marquette shutters. UMERC will depend on power purchase agreements with WEPCo and WPS until the new generation is operating.
Presque Isle Power Plant | WEPCo
The commission said rates and service for Upper Peninsula customers should not be adversely affected by the changes.
“The transition to UMERC for ratepayers will be as seamless as possible. The commission observes that the personnel currently responsible for management, communications, regulatory compliance and customer relations will not change. Moreover, the PPAs will offer reasonable and affordable rates that may indeed, as the record indicates, be slightly lower than recent rates,” the order said. “The commission is also persuaded that the settlement protects ratepayers from any rate impact associated with the termination of Tilden as a customer, whether voluntary or involuntary. The settlement represents the beginning of the process of ensuring that reliable and affordable power is available over the long term in the UP.”
WEC spokeswoman Amy Jahns said the new utility would not have employees “specifically” assigned to it; instead, WEC’s office in Iron Mountain, Mich., and its WPS office in Menomonee, Mich., “will provide services to support the new utility.”
Jahns said the company is awaiting approvals regarding UMERC from the Wisconsin Public Service Commission and FERC.
Conditions Attached
The PSC’s approval came with several conditions, including that Michigan PSC staff receive UMERC’s yearly capital reports and operations plans and have access to all of WEPCo’s books and records concerning the 431-MW Presque Isle plant when the commission reviews the plant for decommissioning and final cost recovery from ratepayers.
WEPCo and WPS are also barred from changing any of the terms of their PPAs until Jan. 1, 2020. The companies also cannot request FERC to shift “any costs to UMERC customers that are currently shared between Wisconsin and Michigan.”
UMERC plans to build two natural gas-fired plants totaling 170 MW in the Upper Peninsula to provide power in the absence of the Presque Isle plant. WEC will seek permission from the PSC to build the plants next year. (See Upper Peninsula Ratepayers to Seek FERC Probe of Billing Fraud.)
PSC staff and Schuette supported the utility’s creation after the PSC obtained additional information in November on whether the proposal would have an adverse impact on customer rates.
Reliability and costs have long been concerns in the sparsely populated Upper Peninsula. Until recently, the area was home to a trio of system support resource agreements with MISO that kept retiring coal units online. Last month, FERC ruled that MISO and American Transmission Co. could reconfigure the western Upper Peninsula transmission system into two load pockets to end the last of the three SSRs. (See MISO Allowed to End White Pine SSR.)
MISO Agrees to Michigan Reliability Studies
At today’s Planning Advisory Committee meeting, MISO committed to a pair of reliability study requests submitted earlier this year by Michigan officials.
One will examine the benefits of transmission between Ontario and Michigan. The second will evaluate resource adequacy in MISO’s Local Resource Zone 7 in Lower Michigan under a scenario without either the Palisades or Fermi nuclear plants. Earlier this month, Entergy and Consumers Energy announced they intend to mothball the Palisades nuclear plan in southwestern Michigan on Oct. 1, 2018. (See Entergy, Consumers Announce Closure of Palisades Nuke.)
The studies were requested this summer by Michigan Gov. Rick Snyder, who asked the RTO to determine whether transmission linking northern Michigan to Ontario could improve reliability and reduce costs. (See Michigan Asks MISO to Study Tx Links to Ontario.)
“Generally when we get a request from a state, we try to be responsive as we can because we do believe that’s part of our role,” MISO Director of Planning Jeff Webb said.
MISO engineer Adam Solomon said the first phase of the studies are already underway and expected to be completed as part of the 2017 Transmission Expansion Plan’s batch of studies using Electric Generation Expansion Analysis System (EGEAS) modeling. Solomon said while the studies will “kind of overlap MTEP 17, [they are] not necessarily contained within.”
MISO Director of Regional and Economic Studies John Lawhorn said that although the studies will be treated separately, they are related to Michigan’s reliability concerns. “The results of one study will influence the other,” he said.
Lawhorn said the second phase of the studies, a transmission analysis, would begin early next year.
In a widely anticipated report, EPA said yesterday that fracking has harmed drinking water resources under some circumstances but that data gaps have made it impossible to quantify the scope of the problem.
The agency said it identified cases of impacts on drinking water at each stage in the fracking water cycle: acquiring water for use in fracking; mixing the water with chemical additives; injecting the water and chemicals into the production well to create and increase fractures; collecting wastewater after injection; and disposing or reusing wastewater.
General timeline and summary of activities at a hydraulically fractured oil or gas production well | EPA
“Impacts cited in the report generally occurred near hydraulically fractured oil and gas production wells and ranged in severity, from temporary changes in water quality to contamination that made private drinking water wells unusable,” EPA said.
The report identifies conditions under which impacts can be more frequent or severe, including:
Water withdrawals in times or areas of low water availability, particularly areas with limited or declining groundwater;
Spills of fracking fluids or wastewater involving large volumes or high concentrations of chemicals reaching groundwater;
Injections into wells whose steel casing or cement lacked “mechanical integrity,” allowing gases or liquids to escape;
Injections directly into groundwater resources;
Discharge of inadequately treated wastewater to surface water resources; and
Disposal or storage of wastewater in unlined pits.
“This assessment is the most complete compilation to date of national scientific data on the relationship of drinking water resources and hydraulic fracturing,” Dr. Thomas A. Burke, deputy assistant administrator of EPA’s Office of Research and Development, said in a statement.
Generalized depiction of factors that influence whether spilled hydraulic fracturing fluids or additives reach drinking water resources, including spill characteristics, environmental fate and transport, and spill response activities | EPA
EPA said, however, the report “was not designed to be a list of documented impacts.”
“Data gaps and uncertainties limited EPA’s ability to fully assess the potential impacts on drinking water resources both locally and nationally. Generally, comprehensive information on the location of activities in the hydraulic fracturing water cycle is lacking, either because it is not collected, not publicly available, or prohibitively difficult to aggregate,” the agency said. “In places where we know activities in the hydraulic fracturing water cycle have occurred, data that could be used to characterize hydraulic fracturing-related chemicals in the environment before, during and after hydraulic fracturing were scarce. Because of these data gaps and uncertainties, as well as others described in the assessment, it was not possible to fully characterize the severity of impacts, nor was it possible to calculate or estimate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle.”
Done at the request of Congress, the report was based on a review of more than 1,200 cited scientific sources, new research conducted as part of the study and an independent peer review by EPA’s Science Advisory Board. The board had been sharply critical of a 2015 draft that said the agency “did not find evidence that [fracking activities] have led to widespread, systemic impacts on drinking water resources” in the U.S.
The California Public Utilities Commission on Tuesday ordered Southern California Edison and San Diego Gas & Electric to meet with groups opposed to the commission’s 2014 settlement that saddled ratepayers with 70% of the costs related to the premature closure of the San Onofre Nuclear Generating Station.
Edison retired San Onofre nuclear generating station in 2013 after defective steam generators caused a radiation leak the previous year. | Pharoah Construction
Commissioner Catherine Sandoval reopened the record on the proceeding in light of revelations that former CPUC President Michael Peevey engaged in persistent unreported ex parte communications with SCE during negotiations leading up to the $4.7 billion deal.
“The CPUC’s rules require a level playing field by mandating ex parte disclosures for rate-setting proceedings, such as this one,” Sandoval said in a statement. “The CPUC must ensure the integrity of its processes and that its decisions serve the public interest.”
The CPUC urged the utilities to “carefully consider” changes to the agreement proposed by California’s Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) — both of which withdrew their support for the original deal when Peevey’s activities became public after state investigators seized notes from his home showing that he discussed terms of the settlement with an SCE executive at a Warsaw, Poland, hotel. Peevey had previously served as president of the utility.
SCE expressed disappointment with the Dec. 13 ruling but said it will comply with the directive to meet with the other settling parties by Jan. 31. The utility said it continues to believe that the original settlement represents an “appropriate allocation” of costs.
“SCE has provided or will provide refunds and rate reductions of almost $1.6 billion under the settlement, and this amount may be increased by recoveries from Mitsubishi Heavy Industries, the supplier of the defective steam generators,” the company said in a statement.
Among the modifications sought by TURN are the removal of some or all of the $2.17 billion in plant investment currently included in the rate base and a refund to ratepayers of costs related to the failed replacement steam generators that forced San Onofre’s permanent closure.
TURN has also proposed that SCE eliminate $25 million in utility funding for greenhouse gas research at the University California-Los Angeles, a key outcome of the secret talks with Peevey.
Contending that “information has value, as does unequal access to decision-makers,” ORA has proposed that SCE refund ratepayers $383 million for the “quantifiable loss” of ORA’s litigation position — the difference between the settlement amount and what ORA says ratepayers would have negotiated if the agency had equal access to information. The agency is also recommending the utilities issue an additional $408 million in refunds.
The CPUC has set an April 28, 2017, deadline for the settling parties to reach an agreement to modify the original settlement. If no agreement is reached, individual parties will be asked to file a summary of their positions in order to inform further action by the commission.
San Onofre was shut down in January 2012 after detection of a radiation leak from one of the plant’s generating units. Operators soon discovered that the steam generators in both units on the site suffered from excess tube wear, despite having been replaced in 2009 and 2011 at a cost of $671 million. SCE decided to retire the plant in 2013.
The Little Rock-based cooperative said the improvements are needed by October 2017 to accommodate about 35 MW of new industrial load. It said getting approval under the 2017 Transmission Expansion Plan in December 2017 would be too late.
