SPP and MISO warned of a reliability crisis if the Environmental Protection Agency’s proposed Clean Power Plan isn’t eased to account for up to 134 GW of generation retirements by 2020, most of them coal-fired units.
“Unless the proposed CPP is modified significantly, SPP’s transmission system impact evaluation indicates serious, detrimental impacts on the reliable operation of the bulk electric system … introducing the very real possibility of rolling blackouts or cascading outages that will have significant impacts on human health, public safety and economic activity,” SPP CEO Nicholas Brown said in his comment to the EPA.
SPP said it conducted a study that assumed new generation was added without additional transmission infrastructure. The model showed that portions of the system in the Texas panhandle, western Kansas and northern Arkansas “were so severely overloaded that cascading outages and voltage collapse would occur and would result in violations of [North American Electric Reliability Corp.] reliability standards,” Brown said.
NERC has expressed similar concerns, commenting that “developing suitable replacement generation resources to maintain adequate reserve margin levels may represent a significant reliability challenge, given the constrained time period for implementation.”
NERC’s 2014 Long Term Reliability Assessment said that plant retirements and limited capacity additions are contributing to diminishing reserve margins in the Midwest, New York and Texas.
SPP said its reserve margins, now at 13.6% above peak demand, would fall to 4.7%, or a reserve margin deficiency of about 4,600 MW, by 2020.
MISO: ‘Untenable and Infeasible’
MISO proposed that the EPA eliminate the interim 2020 performance requirements because the organization’s initial analysis of the rule shows that nearly 80% of total emissions reductions must be met by then.
The EPA’s performance requirements create “an untenable and infeasible timeline for reliable compliance, and would cause states and MISO member companies to make decisions on a severely truncated timeline,” MISO CEO John Bear warned.
Bear said it will take more time to build new generation, natural gas pipelines and other necessary facilities than the interim period allows. Bear pointed to MISO’s Multi Value Projects, which were driven by state public policy requirements such as renewable energy.
The MVP portfolio took five years of planning and shareholder discussion, and even now many of the projects are in development, regulatory and construction phases, he said.
Bear said the soonest a state compliance plan could be approved is 2017, adding that it may not be until 2019 that some states iron out a compliance strategy.
“Since action will be needed by 2020 to achieve the interim emissions performance levels, there will not be nearly enough time to plan for the replacement capacity, transmission upgrades and natural gas delivery infrastructure that will be required to maintain reliability and resource adequacy,” he said.
MISO asked the EPA to push back its proposed carbon dioxide reduction requirements, estimating that 11 GW of plant retirements in its region would need to occur in 2020, “well before sufficient replacement capacity can be placed into service.”
Bear warned that MISO’s planning reserve margin is already under pressure because 10 to 12 GW of coal-fired generation capacity will retire by 2016 to meet the agency’s Mercury and Air Toxics Standards (MATS).
The erosion of the reserve margin increases the likelihood that MISO will need to manage periods of high demand with “emergency operation procedures,” Bear said. “The probability of a loss-of-load event becomes greater than the MISO region has ever experienced.”
Under the “best circumstances,” new generation capacity would not be available until 2024, Bear told the EPA.
Technical Conference Sought
SPP seeks a series of technical conferences jointly sponsored by the EPA and the Federal Energy Regulatory Commission that would focus on the plan’s effects on regional markets and power system reliability. It wants NERC to conduct a “detailed, comprehensive and independent” study of the North American bulk power system, prior to the agency adopting its final rule.
SPP also wants to see the CPP compliance schedule extended by at least five years.
Some commenters, including the Kansas Corporation Commission, told the EPA that the plan is “extremely flawed” and requested that it be withdrawn for a system of emissions reduction that is less complicated and ensures reliability at a reasonable cost.
The KCC said Kansas has approved more than $3 billion of environmental compliance projects for coal-fired generating plants. “To avoid stranded ratepayer investment, specific coal-fired units that were retrofit in compliance with EPA rules should be excluded from the EPA’s calculations in determining a CO2 emissions goal.”
PJM, MISO, SPP and NYISO joined a chorus of critics last week in warning that the Environmental Protection Agency’s proposed carbon emission rule threatens grid reliability, saying the agency should provide more time to build the generation, transmission and natural gas pipelines needed to comply.
At the same time, officials in New England and elsewhere complained that the EPA’s Clean Power Plan does not give enough credit for carbon emission reductions that have already been accomplished.
The critiques were among more than 1.6 million comments filed with the EPA before a Dec. 1 deadline.
SPP warned of rolling blackouts while NYISO said the plan ignored New York City’s reliance on oil-fired generation. PJM, MISO, NYISO and the ISO/RTO Council called on the agency to add a reliability “safety valve.”
Sen. Lisa Murkowski (R-Alaska), who will likely become chairman of the Senate Energy and Natural Resources Committee under a Republican majority next year, and House Energy and Commerce Committee Chairman Fred Upton (R-Mich.) last month called on the Federal Energy Regulatory Commission to convene a technical conference to address reliability concerns.
Some congressional Republicans have threatened to use oversight hearings and appropriations bills to blunt the rule. But lacking a veto-proof majority, the GOP is unlikely to block President Obama’s signature environmental initiative. (See GOP Election Victories Unlikely to Thwart EPA Carbon Plan.)
The proposed rule would require states to devise plans to cut existing power plant carbon emissions from 2005 levels by 30% by 2030, with intermediate goals along the way.
PJM’s Board of Managers today announced a final Capacity Performance plan that includes a more gradual transition into the new market design and increased benefits for high-performing generators than staff’s Oct. 7 proposal.
The board’s proposal will be submitted next week for Federal Energy Regulatory Commission approval. PJM hopes to receive FERC’s OK in time to begin implementing changes in May’s Base Residual Auction for delivery year 2018/19.
The board’s changes are intended to blunt criticism that PJM’s plan was overly expensive and being implemented too quickly. On Oct. 28, 14 coalitions representing more than 80 stakeholders submitted their critiques via briefing papers to the board. Eight of the groups generally opposed the proposal while six were generally supportive. (See Coalitions Make Their Cases to PJM Board.)
In a late afternoon press conference today, Executive Vice President for Markets Andy Ott said the changes would provide an “insurance policy” at a cost of about $2 to $3 per month per household when it is implemented in 2018.
“Many of the issues raised during this five-month discussion of Capacity Performance are not unique to the PJM region,” PJM CEO Terry Boston said in a letter to stakeholders outlining the board’s revisions. “PJM is modeling its approach after the ‘Pay for Performance’ capacity market design that FERC recently approved for ISO-NE, along with changes in the transition period that allow time for market participants to adapt and to lessen cost impacts. This design also allows for greater opportunities for all resources to participate in this enhanced capacity market.”
Changes Detailed
The board made the following eight changes to PJM staff’s Oct. 7 proposal, saying it would “improve the balance between the cost of infrastructure improvements and the benefits of reliability”:
Revises the performance requirement, incentive and payment structure to one similar to that approved by FERC for ISO-NE.
Penalties (or “performance payments”) from under-performing resources will be allocated to over-performing generators, including energy-only resources that provide energy during emergencies. The change will allow intermittent resources and non-capacity resources to earn additional revenue.
Adopts a “no excuses” approach to performance requirements except for retention of the exemption for resources following PJM scheduling and dispatch instructions.
PJM says this will ensure generators invest in maintenance and fuel security — such as obtaining dual-fuel capability — to avoid penalties. “This approach appropriately assigns performance risk to capacity suppliers who are in the best position to manage the risk,” PJM said.
Reduces the volumes and capabilities of capacity to be procured during the 2015-2018 transition period.
“This will reduce transition costs but still maintain reliability through the transition period,” PJM said.
Expands opportunities for intermittent resources by allowing them to submit “coupled” resource offers.
Eliminates the multi-year pricing mechanism.
The board said it made the change based on concerns that the mechanism — intended to reduce risk for multi-year investments in the single-year market structure — could result in “pricing anomalies and perverse incentives.” The board said the issue would be addressed separately.
Modifies cost allocation for Capacity Performance to include all “compliance hours,” defined as any period when PJM implements emergency procedures requiring implementation of demand response or the loading of emergency capacity.
PJM said the change, based on discussions with its Independent Market Monitor, would maximize market efficiency and encourage year-round DR.
Maintains DR as a supply-side resource, for now.
PJM said it will address uncertainties over DR’s role in wholesale markets — the result of an appellate court ruling voiding federal jurisdiction over DR compensation — in a separate proceeding.
Ultimately, DR would be adapted to become a peak shaving commitment, modeled on the load side.
Limited DR would be eliminated; annual DR would be converted to a Capacity Performance product, and summer DR would be treated as Base Capacity during the transition period.
Promises to adjust the forward load forecast to address concerns that overly bullish demand predictions had caused the RTO to procure more capacity than needed, at additional cost to consumers.
The promise is part of the proposal to eliminate the short-term resource procurement target, a 2.5% “holdback,” which the Market Monitor says can result in price distortions.
By recognizing the “recent trends and impacts of energy efficiency,” the 2.5% holdback will no longer be necessary, PJM said.
Transitional Period
The board acknowledged stakeholder concerns that it might not be possible to begin requiring enhanced performance for winter 2015/2016 due to the short time available for investment in winterization, dual-fuel capability and firm-fuel contracts.
Instead, it said it would seek to procure up to 2,500 MW of additional “base” capacity — the current product definition — for December 2015 through March 2016.
For the 2016/17 delivery year, PJM proposes an auction to procure a “transitional version” of the Capacity Performance product with lower prices and nonperformance penalties than when the transition is complete. “If a resource that already has [a capacity] commitment for the delivery year clears as Capacity Performance, the Capacity Performance commitment replaces its previous commitment,” PJM said.
This transitional version of the product would make up 60% of total capacity. For the 2017/18 delivery year, Capacity Performance would increase to 70%, while in 2018/19 and 2019/20, PJM proposes 80% of total capacity be fulfilled by the new product.
Beginning in 2020/2021, all capacity would be obtained under the Capacity Performance rules.
“During the transition, Base Capacity would retain the same rules as the current annual capacity product except that the peak performance penalty structure would replace the peak forced outage metric that is currently used,” PJM said.
The Federal Energy Regulatory Commission gave final approval to a North American Electric Reliability Corp. standard on physical security without a provision that would have given FERC and other government agencies the ability to overrule transmission owners’ definition of “critical” facilities.
In its final order (RM14-15), FERC said it dropped the veto proposal in response to criticism that the term “applicable governmental authorities” was too vague, making the standard impractical to enforce. Many also called it redundant, as FERC’s power to enforce NERC reliability standards would already ensure coverage of the most critical facilities.
“We are persuaded by commenters that the [Notice of Proposed Rulemaking] directive would present NERC, as the entity that would have to develop the proposed modification, and the commission, which would have to approve any NERC proposal, with a number of substantial policy issues,” FERC said.
The NOPR said the commission and “other appropriate federal or provincial authorities” should have the ability to add or remove critical facilities. The NOPR was issued under pressure from members of Congress alarmed by the 2013 sabotage of a Pacific Gas and Electric substation. (See FERC: We’ll Have Last Say on Sabotage Rules.)
The reliability standard (CIP-014-1) requires that transmission owners and operators perform risk assessments to identify transmission stations and substations “that, if rendered inoperable or damaged, could result in widespread instability, uncontrolled separation, or cascading within an Interconnection.” Operators of such facilities will be required to conduct an evaluation of the physical threats posed and report on how they are addressing them.
“While the rule does not go as far as some would like, it is still a step in the right direction,” Commissioner Norman Bay said last week. “It’s my hope that registered entities have already begun the process of doing risk assessments and engaging in planning.”
FERC OKs NERC 5-Year Performance Assessment
FERC last week also accepted NERC’s second performance assessment, which the organization is required to file every five years. The commissioners praised NERC for its work in ensuring reliability, but they also said there was room for improvement.
In its order, FERC directed NERC to submit a report on its work to improve the coordination among the regional entities, as well as an analysis of repeat reliability violations by companies.
Chairman Cheryl LaFleur said FERC’s approval of the assessment “reflects the commission’s continued confidence in the work of NERC and the regional entities in strengthening the reliability of the bulk power system. At the same time, it appropriately challenges NERC and the regional entities to further strengthen their efforts.”
The commission also gave preliminary approval to NERC’s revised Real Power Balancing Control Performance Reliability Standard (RM14-10). The standard (BAL-001-2), which applies to balancing authorities and regulation reserve sharing groups, is designed to maintain Interconnection frequency within predefined limits.
Up-to-congestion trading volumes in PJM have dropped by about 85% since September, after the Federal Energy Regulatory Commission said it might make the transactions liable for uplift assessments.
The average volume of cleared up-to-congestion trades had increased 22.5% in the first three quarters of 2014, compared to the first nine months of 2013, according to the Independent Market Monitor’s third-quarter State of the Market report.
But the growth came to a halt Sept. 8, the effective date set by FERC for any uplift assessments.
Market Monitor Joe Bowring told the Members Committee webinar last week that traders appear to have begun limiting their UTC trades to the most profitable paths, as average profits have increased from $0.02 per MW in the two months before Sept. 8 to $0.94 per MW in the two months after.
Before the FERC ruling “you could make money and have a very small margin with large volumes,” Bowring said. Now, he said, traders are shunning less profitable trades that they fear will be net losers if uplift assessments are applied.
FERC ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than INCs and DECs in the interpretation of a forfeiture rule and in the application of uplift charges. (See UTC Trading Falls Following FERC Order.) FERC has scheduled a technical conference on the issue for Jan. 7.
The Monitor’s quarterly report said the reduction in UTC trading has not resulted in “negative impacts … and there have been some positive impacts.” Day-ahead and real-time binding constraint hours have fallen sharply since Sept. 8.
PJM is planning an effort to identify discrepancies among its governing documents, an initiative prompted by a lawsuit that officials say could have harmed the RTO’s credit rating and increased its insurance costs.
At last week’s Markets and Reliability Committee meeting, General Counsel Vince Duane presented the first read on a problem statement to create a Tariff Harmonization Senior Task Force to review what he called “legal boilerplate” provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35.
“Sometimes they should be the same; sometimes they should be different,” he said.
Duane said the inconsistencies came to light when counsel examined the documents in connection with a lawsuit brought in 2008 by PPL electrician Marlin Yorty, who was severely burned while working at a substation on the Juniata-Conemaugh 500-kV transmission line.
In October 2013, the Pennsylvania Superior Court ruled that PJM was not responsible for Yorty’s injuries because it was protected by a Federal Energy Regulatory Commission tariff that superseded state law.
“We began looking at the provisions more carefully in the legal department and found inconsistencies and vulnerabilities,” Duane said.
Separately, the MRC approved non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35. The changes are intended to align the documents.
Transmission upgrades of $20 million or more and all “greenfield” transmission proposals will be charged a $30,000 fee under an Operating Agreement revision approved by the Members Committee Thursday.
The proposal by LS Power was approved by an 84% sector-weighted vote after an earlier proposal by the Regional Planning Process Task Force, which would have charged only greenfield projects, fell short of a two-thirds majority. The task force’s proposal was approved by the Markets and Reliability Committee in October. (See PJM Members Approve $30K Fee on ‘Greenfield’ Tx Proposals.)
The result is a victory for LS Power and other nonincumbent transmission developers, who contended it was unfair to charge greenfield projects only.
PJM officials said that upgrades by transmission owners typically did not require the intensive engineering analysis that the fee is intended to pay for. “There is virtually no cost in evaluating these proposals,” said Steve Herling, vice president of planning.
The fee will be re-evaluated after a two-year trial.
ICC to Vote on Rock Island Clean Line at Next Meeting
The Commerce Commission could vote today on the future of a $2 billion direct-current transmission project designed to bring wind energy from the Midwest, including Iowa, into the PJM system.
The 500-mile Rock Island Clean Line would transmit wind energy to a $300 million converter station in Grundy County, where the direct current would be transformed into an alternating current and introduced to the grid. The ICC vote on the project was scheduled for a meeting earlier in the month but was delayed to give commissioners more time to review it. The operators are seeking a certificate of public convenience and necessity.
The project has attracted opposition from landowners along its proposed right-of-way.
Customer Advocate Calls for Rejection of Duke Energy’s $1.9B Grid Upgrade
The Office of Utility Consumer Counselor said Duke Energy hasn’t provided enough details on its proposal to spend $1.9 billion on transmission and distribution upgrades and that the proposal includes items that shouldn’t be billed to ratepayers.
“The information we found in Duke Energy’s filings does not meet the statute’s requirements, while also falling short of the standards established in previous cases involving the approval of other utilities’ plans,” Consumer Counselor David Stippler said. He said items such as vegetation management, a $3 million energy learning center and radio system improvements that are included in Duke’s seven-year plan should not be included in the rate base.
Stippler has recommended that the Utility Regulatory Commission deny the plan, which would result in rate increases of about 1% per year from 2016 through 2022 for Duke’s 800,000 customers in the state.
A Duke spokeswoman said the company has provided hundreds of pages of documentation and that all its proposed expenses are necessary and responsible. “Our electric grid is aging and many components need to be updated and replaced,” she said. “This plan is about modernizing our electric grid and bringing our system into the 21st century.”
State Signals Intent to Deny Exelon’s Conowingo Permit
The state Department of the Environment said it needs more information on Conowingo Dam’s impact on the health of the Chesapeake Bay and said it intends to deny a key approval for the Exelon Generation facility. The DEP has scheduled a Jan. 7 public hearing in advance of a Jan. 31 deadline the state must meet to sign off on the water quality portion of the Federal Energy Regulatory Commission’s overall operating permit.
The Susquehanna River hydro facility has already obtained a one-year extension of its current license, so DEP’s decision does not have an immediate impact on plant operations. If the state continues to withhold the water quality permit, Exelon may have to change how it operates the facility. The company has faced persistent criticism about how much nutrient-rich sediment the dam allows downstream.
Michigan PSC to be First Agency to Use PACE for New Headquarters
The Public Service Commission’s landlord is using Property Assessed Clean Energy (PACE) financing to pay for efficiency improvements at its new headquarters, the first energy agency in the U.S. to use the emerging funding mechanism.
The building’s private owner is using $500,000 in PACE financing for LED lighting, a solar array and HVAC equipment. PACE financing is typically done through a local government agency and the costs are repaid through a property tax assessment, making it easy for building owners to transfer repayment obligations to a new owner. With its headquarters, the commission will repay the costs of the 20-year fixed-rate loan through the project’s energy savings.
“PACE is an innovative way that landlords, tenants and local officials can work together to pursue energy-efficiency projects that would not otherwise take place,” PSC Chairman John Quackenbush said.
BPU Again Denies Fisherman’s Energy Wind Project Due to High Prices
The third time was not the charm for the proposed Fisherman’s Energy wind project off the coast of Atlantic City.
The Board of Public Utilities again denied approval for the 25-MW project, saying that the projected energy price of $199.17 per MW/h was too high and that ratepayers could end up responsible for $19 million if the project fails. The project has been in the works for three years and has gained federal funding, but it hasn’t been able to get BPU approval to go forward.
State Senate President Stephen Sweeney, a Democrat, decried the state’s failure to build a single offshore turbine since New Jersey passed the Offshore Wind Economic Development Act.
“Over three years ago we passed legislation that was meant to make New Jersey the national leader in wind and renewable energy,” Sweeney said in a statement. “It means hundreds, if not thousands, of new jobs for our state in a time of economic uncertainty. But three years later, even though the bill was signed into law, nothing has happened to make this a reality. New Jerseyans have suffered because of this inaction.”
Gov. McCrory Sues Legislature over Coal Ash Commission Makeup
Gov. Pat McCrory, along with two former governors, is suing Senate Leader Phil Berger and House Speaker Thom Tillis over the makeup of the state’s new Coal Ash Management Commission.
The legislature formed the commission after Duke Energy’s massive coal ash spill into the Dan River in February. McCrory, who was a Duke executive before becoming governor, contends that the commission’s makeup — the legislature names six of nine members — violates the separation of powers by giving the legislature control over environmental regulation, a function he says belongs with the executive branch.
“The disagreement among the two branches is not acrimonious, but it is of fundamental importance,” McCrory said. “I have too much respect for North Carolina’s constitution to allow the growing encroachment of the legislative branch into the responsibilities the people of North Carolina have vested in the executive branch.”
Berger and Tillis have said that McCrory could have vetoed the legislation and didn’t.
AEP Ohio’s Energy-Only Auction Results Accepted by PUCO
The Public Utilities Commission has approved the results of AEP Ohio’s energy-only auction, which set the average clearing price of $51.37 per MW/h for 40% of the company’s load from January through May of next year. Five suppliers submitted winning bids during the 14-round auction.
This was the fourth auction, and its results will ultimately determine retail generation service rates through May. The independent auction manager was National Economic Research Associates. Boston Pacific Company monitored the auction. Winning bidder names will be disclosed in 21 days.
A redacted version of the report can be found here.
PENNSYLVANIA
Still Time for Philly Council to Authorize Sale of PGW
It looked like a deal to sell Philadelphia Gas Works to UIL Holdings Corp. for $1.86 billion was dead after the Philadelphia City Council failed to hold hearings on the deal, but efforts to save it are going down to the wire.
A UIL executive breathed life into the proposed sale when he appeared before the council on Nov. 13 and said UIL would consider amended sales terms. Labor leaders are meeting with UIL to address concerns, and Mayor Michael Nutter’s office is continuing to push for the sale. The council could still introduce legislation authorizing the sale at either of its two remaining meetings of the year, Dec. 4 and Dec. 11. The sale agreement expires Dec. 31. Nutter’s office and UIL could also agree to extend the sale agreement if the council doesn’t act in time.
The mayor proposed to privatize the nation’s largest municipal gas utility to pay down its underfunded pension plan and to attract private capital to upgrade the city’s aging natural gas distribution system.
Dominion Customers Could See Bills Increase by 30% by 2025 with EPA Emissions Rules
State lawmakers heard from Dominion Virginia Power that efforts to meet the Environmental Protection Agency’s emissions mandates could increase bills by 30%, or about $400 more a year, for the utility’s customers by 2025.
“In our world, that does not give us a lot of time,” Robert M. Blue, Dominion Virginia Power’s president, told a joint hearing of the House and Senate Commerce and Labor committees last Wednesday. “We need to start acting now. We don’t have the luxury of waiting.” Interim reduction goals need to be met by 2020.
A more optimistic view was offered by Cale Jaffee, director of the state office of the Southern Environmental Law Center. He said Virginia has already met nearly 80% of the carbon reduction goals and that investment in renewable energy sources could take it the rest of the way.
PSC Commissioner Responds to Complaints of Too Much Power
In response to a report complaining that the Public Service Commission had too much power, Chairman Michael Albert said that decreasing the commission’s oversight would be a bad thing for customers.
“Public utilities, whether publicly owned or privately owned, are monopolies,” he said. “The commission fills a special role with respect to public utilities. We are a surrogate for competition that is otherwise lacking in their operations.”
A report commissioned by the West Virginia Rural Water Association and groups representing small public service districts was critical of the commission’s policy of prohibiting public service districts from keeping contingency funds. Albert said the rule is sound because it protects stressed customers from paying utilities to keep a reserve.
PJM should change its rules on pricing and scheduling of interface transactions to reflect changes in system conditions and eliminate the need to schedule physical transactions across seams, the RTO’s Independent Market Monitor says.
The two proposals were among four new recommendations that Monitoring Analytics made in its third-quarter State of the Market report.
(Click to zoom)
The Monitor said PJM and neighboring balancing authorities should develop an optimized joint dispatch that treats their seams like any other constraint under LMP rules.
It also recommended that PJM adjust its weighting procedure to “ensure that the interface prices reflect ongoing changes in system conditions and that loop flows are accounted for on a dynamic basis.” It said PJM should conduct an annual review of the mappings of external balancing authorities to individual interface pricing points to reflect changes to the impact of the external power source on PJM tie lines as a result of system topology changes.
The Monitor also recommended changing the submission deadline for real-time dispatchable transactions from 1200 the day before to three hours before the requested start and that the minimum duration be reduced to 15 minutes from one hour. “These changes would give PJM a more flexible product that could be utilized to meet load in the most economic manner,” the Monitor said.
Offering a different solution on an issue it has discussed before, the Monitor said the amount of tier 1 megawatts paid when the non-synchronized reserve market clearing price goes above zero should be equal to the tier 1 megawatts estimated by the real-time security constrained economic dispatch market solution.
The Monitor has said that its preferred solution is to stop paying tier 1 synchronized reserves the synchronized-reserve market-clearing prices when the non-synchronized price is above zero. Last month, the Market Implementation Committee approved a problem statement proposed by Monitor Joe Bowring to consider changes to the payments.
Map of SPP’s new territory, highlighted in blue (Source: Basin Electric Cooperative)
SPP won federal approval Nov. 10 to add three new members in the Upper Great Plains, a seven-state expansion that restores the RTO’s scope after its loss of Entergy to MISO.
SPP’s footprint shrunk in Arkansas, Louisiana, Mississippi and Texas after Entergy’s defection to MISO. Its territory now shifts north with the Federal Energy Regulatory Commission’s approval (ER14-2850) to add Heartland Consumers Power District, Basin Electric Power Cooperative and the Western Area Power Administration’s Upper Great Plains Region (Western-UGP).
The three new SPP members represent the backbone of the bulk electric system in seven states and consist of about 9,500 miles of transmission lines with more than 3 million customers, increasing SPP by about one-fifth.
Basin Electric has 2.8 million customers and 2,100 miles of transmission lines. Heartland serves 28 municipalities, including Sioux Falls, S.D. Western-UGP covers 378,000 square miles of prairie and farmland.
“FERC’s substantive approval clears the way for us to continue to work toward [integration]. We expect to take on reliability coordination of the … transmission system in June 2015, with full membership in October 2015,” SPP Chief Operating Officer Carl Monroe said in a statement after FERC’s approval.
Little Rock-based SPP said the expansion will bring stakeholders more than $334 million in net benefits. SPP cites increased ability to commit and dispatch generation that affects flows through and out of Nebraska. It also pointed to the availability of lower-priced generation, including Western-UGP’s excess hydro power.
Concerns Raised
FERC and stakeholders took issue with parts of SPP’s integration plan, however.
The commission rejected SPP’s proposal to revise Schedule 12 of its Tariff, which covers the collection of FERC assessments. FERC noted that the cost of regulating Western-UGP and other federal power marketing agencies is administered in a different manner and that it was concerned about the possibility of a double assessment of FERC charges.
Kansas utility regulators told FERC that the three new members of SPP should be responsible for a “proportionate share” of costs for certain base plan upgrades in service before and after Oct. 1, 2015, because they would benefit from SPP membership and services. Otherwise, Kansas ratepayers would face an unreasonable financial burden when utilities in the state recover those costs from their customers, the Kansas commission argued.
FERC said the Kansas commission “neglects to consider the benefits the rest of the SPP membership will receive” from the three new members’ legacy systems, such as increased grid reliability and congestion management.
A number of consumer groups, transmission operators and state regulators also raised concerns about seams issues, including the potential that some utilities that serve Montana retail customers could be required to pay for transmission service from both SPP and MISO.
FERC said concerns about such pancaked rates were beyond the scope of the proceeding and should be taken up in hearings and settlement judge procedures later.
MISO-SPP Dispute
(Source: SPP)
MISO raised a handful of concerns, including whether FERC’s rulings on the expansion could put it at a disadvantage in its dispute with SPP over their joint operating agreement.
SPP alleges that the JOA was breached after Entergy joined MISO late last year and began transferring electricity over SPP’s lines. MISO said that SPP has billed it for more than $35 million for flows exceeding the limited 1,000-MW physical contract path between MISO Midwest and MISO South. The latter consists mainly of Entergy’s footprint.
MISO sought a confirmation that FERC’s approval of SPP’s proposed cost allocations for Basin Electric’s projects would not prejudice the issue of whether MISO should be held responsible for any charges that could stem from the JOA dispute.
FERC sought to alleviate MISO’s concerns, saying “we confirm that our acceptance of [SPP’s expansion] does not prejudge the outcome of the ongoing hearing and settlement judge procedures.”
Since last April, FERC has convened five settlement conferences between SPP and MISO.
Talks Sour
The tone of the talks soured recently. On Nov. 17, SPP filed a scathing rebuttal opposing a request by MISO for expedited consideration of the JOA dispute, calling it “procedurally improper, unsupported and an impediment to further progress in ongoing settlement negotiations.”
To date, MISO “has not paid a dime for any of the flows it has imposed on SPP’s system,” SPP said.
SPP argues that some of the charges are the result of MISO failing to reserve service under an accepted agreement. “If MISO simply reserved service on an hourly basis it would not be subject to these daily charges,” SPP said.
Hands Full
SPP plans to take on reliability coordination of its three new members starting in June.
SPP said in its most recent annual report that the most significant transmission challenges facing much of its footprint stem from an increase in oil and gas drilling.
“New oil and gas drilling facilities are built faster than they can be captured in SPP’s planning processes and models,” the RTO said. “Additionally, pipeline expansions are proposed for the region that will increase the need for electric transmission facilities to serve the pumping stations.”
