Competitive Power Ventures must provide additional information to prove it adequately mitigated market power to continue making market-based sales at its newly opened Towantic Energy Center, FERC ruled Thursday (ER13-343-008, et al.).
FERC’s ruling came in response to CPV’s triennial market power update, which it filed on June 30, 2017, for Towantic, a 785-MW generator in Oxford, Ct., and three other gas-fired plants in CPV’s Northeast region.
CPV Towantic Energy Center in early May, with construction nearly complete. | CPV
The commission’s market-based rate rules require applicants to provide information regarding affiliates and upstream ownership. It considers as affiliates any entity that owns at least 10% of the outstanding voting securities of the applicant.
Two pension funds indirectly own more than 10% of Towantic, but CPV argued that they are only allowed to vote 9% of their shares in an upstream entity. FERC said that doesn’t account for their entire ownership.
“Because the pension funds are included among the stockholders whose votes determine how the votes of the excess shares will be allocated, the sum of votes by the pension funds of their 9% of the shares plus the proportional vote of their excess shares gives the pension funds an effective vote greater than 10%,” the commission said.
It instructed the applicants to update their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production. FERC gave them 30 days to comply.
The other plants are the 725-MW CPV Woodbridge Energy Center in Keasbey, N.J., and the 725-MW CPV St. Charles Energy Center in Waldorf, Md., which were granted MBRA in February 2013 (ER13-342, ER13-343).
[Editor’s Note: An earlier version of this story incorrectly stated that FERC was questioning the ownership of all four CPV plants and that they did not already have MBRA.]
FERC on Thursday identified 13 additional transmission owners it said should change accounting practices that could inflate rates by underestimating tax credits.
The commission ordered a Section 206 proceeding investigating the companies’ use of a double averaging formula to calculate accumulated deferred income taxes (ADIT) (EL18-155, et al.). The utilities include two Ameren subsidiaries, American Transmission Co., GridLiance West Transco, ITC Midwest, Northern States Power, Public Service Company of Colorado, Southern California Edison, TransCanyon DCR, Southwestern Public Service and Virginia Electric and Power Co.
In April, FERC opened a similar investigation of five MISO TOs after rejecting proposed formula rate template revisions that would have applied the two-step averaging methodology in annual true-up calculations of ADIT balances.
The commission signaled it would probe whether the practice makes deferred income tax credits appear lower than they should be, possibly raising rates (ER18-224, EL18-138). The filers were ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas and Electric Co.
The commission said that the TOs’ practice of averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.”
“Because most companies tend to continuously make investments in plant[s], which in turn generates ADIT, plant and ADIT balances typically increase throughout the year,” the commission said.
MISO TOs Offer New Formula
On June 4, the five MISO TOs submitted revisions to remove the proposed double averaging and instead apply the IRS’ proration methodology in calculating the annual transmission formula rate true-up.
In last week’s order, FERC suggested that the 13 newly identified utilities would need to similarly revise their rates.
“Upon initial review, the concerns we identify might be addressed by revising respondents’ transmission formula rates to eliminate the use of the two-step averaging methodology to determine ADIT balances,” FERC said. “In particular, respondents could modify their transmission formula rates to apply the first step of the two-step averaging methodology to generate a prorated ADIT value for the year, without taking the second step of averaging the prorated value for the year with the beginning-of-year balance.”
Change of Heart
FERC noted that, in previous proceedings, it had allowed TOs to use the two-step methodology “based on the understanding that this methodology was necessary to comply” with the IRS’ normalization rules, an accounting system the Department of Treasury uses for regulated public utilities to reconcile accelerated depreciation of their public utility assets or investment tax credits with regulatory treatment.
However, FERC said in April that its opinion on the matter has since changed, guided by private letter rulings from the IRS. FERC said it now interprets updated IRS rules to “not require that any averaging convention applied to other elements of rate base also apply to taxpayer’s prorated [ADIT] balance.”
“We conclude that if the IRS’ proration methodology is applied to calculate ADIT balances in forward-looking formula rates — such as the Attachment O formula rate templates of certain MISO TOs — then the additional averaging step need not also be applied in order to comply,” FERC said.
RENSSELAER, N.Y. — NYISO stakeholders last week backed joint proposals by North America Transmission (NAT) and the New York Power Authority to build two 345-kV transmission projects while several losing bidders cried foul.
In an advisory vote, the Business Issues Committee urged the Management Committee on Wednesday to recommend the Board of Directors approve the ISO’s draft AC Transmission Public Policy Transmission Planning Report. Dawei Fan, manager for public policy and interregional planning, said the report contains analysis of seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface.
NYISO staff analyzed seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface, and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. | NY PSC
Advised by consultant Substation Engineering Co. (SECO), ISO staff recommended two 345-kV transmission projects proposed jointly by NAT and NYPA. The BIC voted 76.33% in favor of the report and its recommendations.
Project T027 is a double-circuit 345-kV line from Edic to New Scotland for Segment A. Project T029 for Segment B is a standard 345-kV line from Knickerbocker to Pleasant Valley.
NYISO’s analysis was driven by a December 2015 order by the New York Public Service Commission on “Finding Transmission Needs Driven by Public Policy Requirements.”
T027 had higher costs than other Segment A proposals, but staff determined them warranted by benefits provided by the double-circuit design, including “significant increase in Central East voltage transfer capability, increased production cost savings, and excellent operability and expandability.”
T029 provides similar transfer incremental and production cost savings with the second-lowest cost, and demonstrates excellent operability, staff said. More important, the report said, “T029 poses the lowest siting risk due to the low structure height increase and more than 50% of its new structures with reduced height.”
Staff also said that T027 and T029 would result in cost savings when being built by the same developer simultaneously.
The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency. T029 is estimated at $324 million to $422 million. Staff projected the in-service date for the selected projects in April 2023, “assuming the developer will start the Article VII preparation immediately following the approval of this report by the NYISO board.”
Challenges to Planning Process
Stakeholders abstaining or opposing the motion June 20 included utilities, transmission owners and other developers whose proposals were not selected for recommendation. Several of them submitted comments to the BIC or read statements.
John Borchert, senior director of energy policy and transmission development for Central Hudson Gas & Electric, which abstained, said his company wanted the benefits of improved transmission capability for its service area but was “dissatisfied with the NYISO’s work and its project evaluation.”
He said “the lack of transparency, the way that the aspects of the projects were treated during the evaluation, effectively disqualified projects, and the way that the local TO upgrades were handled during the process have led to frustration and confusion for both those developing projects and for those interconnecting transmission owners.”
Consolidated Edison and its subsidiary Orange and Rockland Utilities voted against the motion, and O&R submitted written comments.
“We don’t feel confident that the recommended selection for Segment B is in the customer’s best interest due to a lack of transparency in the selection process, and deficiencies in evaluation,” said Jane Quin, director of Con Ed’s energy markets policy group. “We are concerned that … NYISO has not considered the full costs associated with the proposed Middletown upgrades, which are local upgrades on the Orange and Rockland system … and could cost as much as 20% of the Segment B project cost.”
The ISO “failed to make clear the technologies and project attributes it would or would not consider, and the reasons for such decisions, and it did not consider stakeholder input on the matter,” Quin said.
Fan responded that the Middletown transformer “is just one of the distinguishing factors for Segment B projects … [for which] the major drivers are the magnitude of the power delivery and the structure design.” He said SECO had included $16 million for the Middletown transformer costs, which it deemed adequate.
Fan said the ISO had already had two meetings with developers and six meetings with the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee to consider comments from stakeholders.
Looking for Fatal Flaws
Zach Smith, NYISO vice president for system and resource planning, noted that “any project recommended for selection does go through our interconnection process … there has been a system impact study that’s been done that’s up at [the Operations Committee] tomorrow for consideration.”
The next step after that is a facilities study, and “what’s key here to our evaluation is to understand whether there are any fatal flaws in our assessment,” Smith said.
Borchert said, “There was no reason why an interconnecting transmission owner should not be consulted if these solutions are talking about equipment that’s going to be installed in their service territory. And the process needs to be done if it’s part of the overall selection and it has an impact on the selection, and it needs to be done prior to the selection being made.”
Carl Patka, the ISO’s assistant general counsel, said, “When we designed the overall planning process, we did not require, and FERC did not approve requiring, a complete interconnection-level analysis for proposed projects. That was proposed during the Order 1000 process, it was proposed during the stakeholder process, and it was rejected. And the reason for that is people did not want to create a barrier to entry and proposal of new projects based upon information that competing developers could not have from the incumbent utility.”
Brian Duncan of NextEra Energy Transmission NY (NEETNY) made a presentation arguing that NYISO was picking winners for a $1 billion project “despite a virtual tie on project benefits” among competing projects, which included NEETNY’s T022 in Segment B.
The ISO “did not provide analysis on cost-contained pricing … and three other project combinations that are virtually identical, provide all the quantifiable and quantitative benefits [and] are within 1 to 5% of the cost estimate using SECO’s numbers,” Duncan said. He also questioned why NYISO made tower height a big issue in its selection when its solicitation made no mention of the factor.
Patka said the PSC order did not mandate the ISO to use cost-contained pricing but required developers to provide two sets of costs, “one based on raw construction costs and one on 80%/20% cost overrun/cost underrun language. … They said they hoped that FERC will adopt cost containment when they address the rate issue, but their words were exactly, ‘The NYISO should evaluate the costs based on raw construction costs.’”
Patka also said that tower heights were considered by NYISO as a risk of project delay and to project completion, as visual impact is a key environmental impact of transmission, and that the ISO had reviewed its analysis with New York Department of Public Service staff.
Duncan also took issue with the concrete pole installation cost estimates, saying that SECO used a metric of dollars per pound on the weight of the pole rather than a more logical figure of total costs, including labor. He also said the ISO’s estimate of 5% in synergy savings on the combined projects by one developer was “overstated.”
“If those issues are addressed, project T022 would be the lowest-cost project by millions of dollars, probably tens of millions of dollars,” Duncan said.
SECO Vice President Joe Allen said he agreed “there would be no synergy” between the two upgrades.
Smith said NYISO could “take that back, but it won’t affect the ranking at all.”
Kathleen Carrigan, New York Transco general counsel, read comments the company jointly submitted with National Grid.
Losing bidders cried foul last week over NYISO’s selection of North America Transmission and the New York Power Authority to build two 345-kV transmission projects to address public policy needs identified by the New York Public Service Commission. | NYISO
The two companies submitted proposal T019 for Segment B, including “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings.”
Carrigan said series compensation technology is widely used across the U.S., and she submitted a study showing no detrimental system impacts from it. NYISO and SECO “considered proposal T019 as too risky due to the inclusion of the series compensation, despite no technical analysis in support of their conclusion,” she said.
Smith said that while the ISO does not oppose the use of series compensation as a technology, it did see potential problems with its application in the National Grid/NY Transco project. In a FAQ document posted with the BIC meeting materials, the ISO cited potential subsynchronous resonance and damage to generators as the major risk of series compensation technology.
Carrigan said NYISO’s own metrics show the National Grid/NY Transco proposal paired with T029 produces consistently better performance results than the ISO’s favored project.
For example, when combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW. “This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325,” she told RTO Insider after the meeting.
“Projects T027 + T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029 (40,089 GWh vs. 27,524 GWh); and finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.
HOUSTON — While sharing her organization’s report on the state of the ERCOT market in 2017 last week, Potomac Economics’ Beth Garza was naturally asked her forecast of this summer’s energy prices.
“My title is not market predictor. It’s market monitor,” Garza, director of ERCOT’s Independent Market Monitor, reminded her luncheon audience June 21. “I get to watch and opine. I’m sorry to disappoint you.”
Speaking to those gathered at the Gulf Coast Power Association’s lunch in Houston, Garza shared highlights from the State of the Market report. Energy insiders listened attentively as she reviewed 2017 data — and even more so on the rare occasions Garza looked ahead to 2018.
Garza said reserve margins will be tighter this summer than last year, primarily because of the retirement of 4.2 GW of coal generation over the last 12 months. That dropped ERCOT’s planning reserve margin from 18.9% to 9.3% — since increased to 11% — and raised fears of potential shortages during a long, hot summer. (See ERCOT Gains Additional Capacity to Meet Summer Demand.) On Friday, as the system flirted with June’s demand record of 67.8 GW, the ISO still had more than 3.5 GW of operating reserves.
“We had an interesting test of the system in May,” Garza said, referring to the multiple demand records ERCOT set for the month in the face of above-normal temperatures. “But as others have said, a hot May does not necessarily portend a hot summer.”
Statewide temperatures have dropped since then, thanks to recent torrential rains. That has also dampened forward prices, which have settled at about $150/MWh after soaring above $250/MWh in May.
| Potomac Economics
“Is that a reaction to the rain and the temperatures?” Garza asked. “We got through May, but the rest of June has not been severe.”
Garza allowed herself some prognostication in addressing the forward prices.
“I can look at future prices and infer an estimate of how many hours of real-time prices at the 9,000/MWh cap we’ll see,” she said, noting ERCOT saw only 3.5 hours of prices above $1,000/MWh last year. Garza recalled a straw poll of attendees at the recent GCPA spring conference, with expectations of five to 10 hours at the $9,000/MWh cap this year.
“That’s what the future pricing seems to indicate, but that’s based on a $200 price. I haven’t done the math on $150 prices,” Garza said. “If we have 2 GW of wind generation on peak, it’ll be a high-priced day. If we have 10 GW of wind generation on peak, it’ll be a moderately priced day.”
Garza also put in a plug for the addition of real-time co-optimization in the market, one of six recommendations the Monitor has made in each of its last few reports and one of several market improvements being considered by the Public Utility Commission of Texas. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)
“It’s the key missing link in our market,” she said. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to where we see tight reserve margins, the likelihood of scarcity events and high prices increase, because of the ineffective allocation of reserves. If they were allocated differently [through real-time co-optimization], we wouldn’t see those high prices.”
NERC: Grid Resilience, Reliability Improved in 2017
By Rich Heidorn Jr.
The bulk power system showed improved ability to rebound from severe storms last year while continuing to improve on most other reliability metrics, NERC said last week.
NERC cited two Category 5 events — the most severe — last year in hurricanes Harvey and Irma. “While wind and water damage were record setting, the restoration efforts and subsequent recovery times were improved from historical benchmarks,” NERC reported in its State of Reliability 2018 report.
Harvey damaged 85 substations and more than 850 transmission line structures in South Texas, resulting in 225 transmission line outages. But utilities’ use of amphibious vehicles, airboats and aerial drones allowed them to perform damage assessments even before roads were clear of flooding and storm debris, NERC noted.
Irma caused a record number of electric outages in Florida, with 4.45 million customers losing power in Florida Power & Light’s territory, up from 3.24 million from Hurricane Wilma in 2005. But system hardening between the two storms reduced restoration time to 10 days from 18, NERC said.
The report recommended NERC encourage increased use of mutual assistance programs and drones and increase information sharing by publishing event reports and conducting other outreach on the lessons learned from the storms.
The storm observations were among six findings in the NERC report. The organization also found that:
The report said the only metric “indicating cause for concern” is planning reserve margins, with all regions except for the Texas Regional Entity projecting sufficient reserves for the next five years.
It cited ERCOT’s preliminary summer seasonal assessment of resource adequacy (SARA), which reported that operational tools such as load management and distribution voltage reductions could be needed to maintain sufficient operating reserves.
FERC last week denied a rehearing request of its November 2017 order on remand regarding transmission cost allocation in the WestConnect planning region. WestConnect’s transmission providers requested the rehearing in December after FERC affirmed its original order in the proceeding (ER13-75-012).
In 2016, the 5th U.S. Circuit Court of Appeals remanded a commission order rejecting the utilities’ Order 1000 compliance filing.
Western U.S. transmission lines | Southwire
The utilities’ initial compliance filing included a provision stipulating that costs for projects selected in a regional plan would be allocated only to beneficiaries who agreed to participate in those projects. Other WestConnect members participating in the planning process would not be obligated to pay for those projects’ costs, a measure designed to avoid discouraging nonpublic utility transmission providers from participating in planning.
FERC found that WestConnect’s “non-binding” process did not comply with Order 1000, which prohibits planning participants from claiming an exemption from cost allocation merely by asserting they receive no benefits from the resulting infrastructure. The commission noted that the “fundamental driver” of Order 1000 was to minimize “free ridership” within the system.
WestConnect Planning Region | WestConnect
The court asked FERC for “additional factual findings” on WestConnect’s planning process, saying the commission’s mandates regarding the role of nonpublic utility transmission providers were arbitrary and capricious and that it had not shown its orders would not produce unjust rates.
The WestConnect transmission providers argued the order on remand did not address deficiencies identified by the court and therefore violated “both the express purpose of Order No. 1000 and the principle of cost causation under the Federal Power Act.”
FERC countered that the rehearing request relied primarily on WestConnect’s free-rider argument, and it said that its order on remand explained “at length” why the commission often “expects nonpublic utility transmission providers will accept allocation of the costs of transmission projects that benefit them (i.e., they will pay their share of the costs of those projects), and why any potential free ridership would occur for only a limited subset of transmission projects.”
“We continue to expect that free ridership in the WestConnect region will be limited, and we note that the complete elimination of free ridership is not required by the just and reasonable standard of the FPA or Order No. 1000,” FERC said.
The commission said attempts to eliminate free ridership “may not be feasible” given the region’s “uniquely integrated nature” and the fact that Order 1000’s requirements do not apply to nonpublic utility transmission providers. The group’s planning region covers Arizona, California, Colorado, Nevada, New Mexico, South Dakota, Texas and Wyoming.
“We continue to believe that the approach to regional transmission planning and cost allocation accepted in the compliance orders and order on remand is consistent with Order No. 1000 and will result in just and reasonable rates while taking into account the unique characteristics of the WestConnect region,” FERC said.
Federal courts last week rejected two challenges from MISO stakeholders involving FERC Order 1000.
Court Upholds Minn. ROFR
The U.S. District Court for Minnesota on June 21 dismissed competitive developer LS Power’s challenge to the state’s right of first refusal law (17-4490).
The ruling allows Minnesota to continue to grant in-state transmission owners a ROFR to build new high-voltage transmission lines that connect to their facilities. LS Power had claimed that state ROFRs essentially invalidate Order 1000’s elimination of the federal ROFR and undermine FERC’s goal of competition. The U.S. Justice Department had joined the company’s challenge, claiming Minnesota’s law unconstitutionally regulates interstate commerce, in violation of the Constitution’s dormant Commerce Clause. (See Justice Department Joins Challenge to Minn. ROFR Law.)
But the court said the law neither overtly discriminates nor imposes a burden on interstate commerce.
The ROFR “is part of Minnesota’s broader regulation of the provision of electricity to the consumer market,” the court said.
It cited 1997’s General Motors Corp. v. Tracy, in which the U.S. Supreme Court allowed Ohio to continue to tax natural gas sales differently depending on whether they were made to in-state regulated public utilities or out-of-state marketers. The Supreme Court determined that when evaluating a challenged state statute, controlling weight must be given to the possibility of negative consequences on the ability of regulated utilities to serve their captive consumers in a monopoly market.
In last week’s decision, the district court said many of the entities that own existing transmission facilities in Minnesota are regulated public utilities that serve captive markets and operate as monopolies.
“The reasons cited in support of giving greater weight to the monopoly market in Tracy apply here; namely, to avoid any jeopardy or disruption to the service of electricity to the state electricity consumers and to allow for the provision of a reliable supply of electricity,” the court concluded.
As in Tracy, the court said it could not predict the economic consequences of upending the ROFR.
“Minnesota not only gives existing owners a right of first refusal to build new transmission lines that will connect to their existing facilities, but in return Minnesota also places extensive regulatory burdens on those owners. Any intervention by the court could upset the balance between those burdens and regulation.”
The court’s ruling recognized that both Congress and FERC have said Minnesota has a right to adopt a ROFR for new transmission lines. It also said the state’s statute does not discriminate against out-of-state entities because it “draws a neutral distinction” between existing TOs whose facilities will connect to a new line and all other entities, “regardless of whether they are in-state or out-of-state.”
Were it not for the state’s ROFR, the Huntley-Wilmarth line — ITC Midwest and Xcel Energy’s planned 50-mile, 345-kV transmission line in southern Minnesota — would have been opened for MISO’s competitive bidding process in 2016 under Order 1000.
Review of MISO-SERTP Allocation Denied
In a separate case, the D.C. Circuit Court of Appeals on June 22 denied Ameren’s petition for review of a cost allocation proposal under Order 1000 because the appeal introduced an argument that was not first raised in a FERC proceeding (16-1150).
Ameren Transmission | Ameren Corp
The case dates to 2013, when MISO filed a cost allocation methodology under Order 1000 for interregional projects developed with seams neighbor Southeastern Regional Transmission Planning (SERTP). The RTO had proposed to allocate its costs for those projects based on a cost-avoidance method that would include the estimated costs of displaced regional transmission projects rendered unnecessary by the interregional project.
However, MISO proposed that its calculation would include only those costs for avoided projects that had been identified in its annual Transmission Expansion Plan but not yet approved, while excluding costs for approved projects.
FERC rejected the proposal, saying that excluding approved regional projects from the analysis would undervalue potential benefits of an interregional project, especially because approved projects tend to be the most cost-effective. Order 1000 requires the costs of an interregional project to “be allocated in a manner roughly commensurate with the project’s benefits.”
In appealing FERC’s decision, Ameren argued that the commission’s mandated change in cost allocation could harm developers — and by extension, their customers — that had already invested in MTEP-approved projects that were later displaced.
The company also raised a new concern in the appeals case: that FERC’s decision did not comport with its obligation to ensure just and reasonable rates.
The D.C. Circuit seized on the new argument and said that petitioners must first raise arguments in front of FERC before approaching an appeals court.
Ameren contended that the argument of just and reasonable rates lies at the heart of every FERC rate order and should not be considered a new argument in a petition for review, but the court countered that the company misunderstood the Federal Power Act’s requirement that arguments be exhausted at FERC before an appeal.
“If we were to accept petitioners’ rationale, parties would never need to raise specific legal arguments before the commission as long as they broadly challenge the justness and reasonableness of rates,” the court said.
At any rate, the court said, FERC had already adequately explained its decision requiring MISO to account for approved MTEP projects in its SERTP cost allocation methodology.
“In the end, we conclude that the commission adequately responded to petitioners’ concerns about the possible effects of including approved regional projects in the cost allocation calculation. Petitioners ultimately disagree with the commission’s policy judgment about whether the importance of properly calculating an interregional project’s benefits outweighs the effects of potentially displacing approved regional projects. Petitioners’ disagreement with the commission’s resolution of that issue does not render the commission’s explanation any less thorough or reasoned,” the court concluded.
FERC ruled last week that inconsistencies between the termination provisions in MISO’s generator interconnection procedures (GIP) and pro forma generator interconnection agreement were unreasonable, but it simultaneously accepted the RTO’s proposed Tariff changes to remedy the discrepancy (EL18-17).
In an October 2017 order, FERC found that an interconnection customer’s ability to extend the commercial operation date (COD) of a project by up to three years without MISO seeking termination under its pro forma GIA conflicted with a provision in the RTO’s GIP stating that any extension required a material modification of the interconnection request, or the project risked removal from the queue.
FERC originally took issue with the differences in 2012, and MISO at the time contended that the two provisions did not conflict because its GIP applied before the execution of a GIA, with the GIA provisions taking precedence after an agreement is executed.
But the discrepancy arose again after MISO successfully sought to terminate a GIA with EDF Renewable Energy’s 150-MW Merricourt wind project in North Dakota. (See FERC Upholds MISO Cancellation of GIA.) While FERC sided with the RTO in the termination, it instituted an investigation over the inconsistency in late 2017.
As part of a paper hearing in the proceeding, MISO late last year submitted a proposal to clarify within the GIP section of its Tariff that the COD for a project that completes the definitive planning phase of the interconnection queue will be spelled out in a GIA.
“MISO states these proposed revisions also remove any ambiguity as to which Tariff provision determines the COD and any permissible extension beyond the COD, thereby providing greater certainty,” the commission noted.
FERC said that MISO’s approach addressed its concerns.
“We also agree with MISO that the GIP and pro forma GIA are intended to work together, and although the pro forma GIA ‘memorializes the arrangements reached in the GIP,’ the GIP does continue to apply even after execution of a GIA; therefore, specifically referring to the correct section of the GIP in the pro forma GIA is preferable to separating the two documents entirely in these circumstances,” the commission wrote.
FERC also directed MISO to make a further Tariff filing to make it more clear that an interconnection customer can extend its COD by up to three consecutive years before risking withdrawal from the queue.
FERC last week accepted Great River Energy’s slimmed-down annual revenue requirement for reactive supply and voltage control at eight of its generating stations.
The cooperative’s revenue requirement is reduced by a little more than $1 million per year with the June 21 order (EL18-45).
Stanton Station | Great River Energy
Great River settled for the lower amount after FERC opened an investigation in early January into whether the rates were just and reasonable. The company had originally proposed an approximately $5.2 million requirement for the eight plants but lowered it to $3.9 million after settlement proceedings. The individual requirements for the plants now range from $8,371 to $1.7 million per year, lowered from the original range of $24,908 to $2.3 million.
The co-op had claimed the $5.2 million figure was based on previous requirements accepted by FERC in 2010, with adjustments made to reflect the 2017 retirement of the 189-MW coal-fired Stanton Station in Stanton, N.D., and the addition of three generating facilities since 2010: the 170-MW natural gas-fired Cambridge Station and the 19-MW Maple Lake and 23-MW Rock Lake oil-burning stations, all in Minnesota.
But FERC questioned the figure, saying Great River did not adequately support its revised reactive power revenue requirements, including “development of multiple fixed charge rates, its accessory electrical equipment allocator and its generator/exciter investment portion of the turbogenerator.” The commission also said it did not provide complete information on the reactive service capability of its units, including MISO test reports.
FERC on Thursday granted San Diego Gas & Electric a waiver allowing it to continue the CAISO interconnection study process for its proposed Top Gun Energy Storage project without having to post financial security to itself.
In its June 21 order (ER18-1360), the commission said it found that SDG&E acted in good faith, that the waiver request was of limited scope and addressed a concrete problem, and that granting it would have no undesirable consequences.
Energy storage | SDG&E
Because the utility is both the primary transmission owner (PTO) and the interconnection customer, the commission found it unnecessary for it to post financial security to protect itself from the risk of the project being abandoned after associated network upgrades have been undertaken.
For SDG&E to perform accounting entries to move money from one intracompany account to another intracompany account “in this case serves no useful purpose,” the commission said.
