Lower natural gas prices and increased renewable penetration pushed wholesale power prices down sharply in most of the country last year, FERC reported last week.
The commission’s 2019 State of the Markets report noted that prices dropped 20% to 30% in MISO, PJM, NYISO and ISO-NE compared with 2018. Prices in northern CAISO were down 10%, and those in southern CAISO down 20%.
SPP’s prices were the lowest of the organized markets, averaging $30.43/MWh, unchanged from a year before, according to the report by the Office of Energy Policy and Innovation’s Division of Energy Market Assessments (DEMA).
Only ERCOT saw an increase, as record-high demand in summer pushed prices for the year to $49.65/MWh, up 20%.
Natural Gas
Although natural gas demand hit new highs, record-high production and relatively mild weather resulted in price declines of 35% to 41% at hubs in the Mid-Atlantic, New England and New York City. The biggest drops were in the Southwest, where hubs traded at negative prices at times because of pipeline takeaway capacity constraints.
U.S. natural gas production rose to 92.2 billion cubic feet per day (Bcfd) in 2019, up 8.4 Bcfd, the second-largest increase since the advent of shale exploration. Net gas exports averaged 5.1 Bcfd through November 2019, up from 1.9 Bcfd in 2018.
U.S. natural gas pipeline in-service capacity additions by region (Bcfd) | FERC Office of Energy Projects
Natural gas shippers added nearly 5 Bcfd (17 miles) of commission-jurisdictional pipeline capacity in 2019, down from the 13 Bcfd added in 2018.
Overall natural gas demand increased 2.6 Bcfd to 84.9 Bcfd in 2019, a 3% jump. Demand for electric generation averaged 30.9 Bcfd, up 7%, with a 12% increase in the Midwest.
Fuel Mix
Natural gas was responsible for 42% of generation nationwide between January and November 2019, according to the Energy Information Administration (EIA), with 26% from coal, 22% from nuclear, 4% from wind and 1% from solar.
MISO and SPP were most dependent on coal, which accounted for 43% of the regions’ generation. Solar and wind were big contributors in CAISO and SPP, respectively.
As in recent years, most new generation was natural gas or renewables and most retirements were coal plants.
Generation by fuel type | ABB Velocity Suite
The biggest retirements were the 670-MW Pilgrim Nuclear Power plant in ISO-NE (May 2019) and the 980-MW Three Mile Island nuclear power plant in PJM (September 2019).
PJM added 356 MW of natural gas-fired capacity, mostly combined cycle units. MISO saw a net decrease of 852 MW as it lost 2.9 GW of coal-fired capacity and gained 969 MW of natural gas and 997 MW of wind capacity.
SPP added 1.8 GW of wind capacity and had no retirements in 2019.
CAISO’s capacity dropped by 21 MW, losing 600 MW of natural gas capacity and adding 561 MW of solar.
Storage, DERs
Battery storage capacity increased by 174 MW in 2019, down from a 202-MW boost in 2018. But EIA forecasts about 400 MW of new battery storage will be added in 2020 and 1,816 MW in 2021.
“While it is unlikely all planned facilities will be operational by the end of 2021, the large increase represents a sea change in the role that battery storage plays in the bulk power system,” FERC said.
Battery storage capacity additions in recent years | EIA Form 860M
Battery storage additions have been clustered in a few states, led by California with 38% percent of planned capacity through 2023.
Capacity from distributed energy resources using net metering rose 4 GW to a record 23 GW in 2019, most of it in California, New Jersey, Massachusetts, Arizona and New York. The five states represent 70% of the net-metered capacity in the country, including California’s 40% share.
All but 6% of net metered capacity is solar PV. Solar PV’s price dropped 37% between 2013 and 2017, FERC said.
Transmission
Order 1000 transmission planning regions had 309 transmission projects go into service during the year, led by MISO (104) and PJM (101). In 2019, PJM, ISO-NE and NYISO each announced, or awarded to developers, new transmission projects using the competitive bidding processes in Order 1000.
Transmission additions by transmission planning region | C Three Group
FERC on Friday rejected rehearing requests by American Municipal Power and Illinois Municipal Electric Agency over the commission’s November 2017 order approving PJM’s tougher requirements for pseudo-tied generators. The commission also approved PJM’s December 2017 compliance filing required by the order (ER17-1138).
“The commission found that PJM’s new pseudo-tie requirements would help ensure that external resources bidding into the PJM capacity auctions are comparable to internal resources in assuring that they will be deliverable to PJM’s system when needed,” FERC said last week. “With this principle in mind, we continue to find that PJM’s proposed treatment of pseudo-tied resources is just and reasonable.”
AMP’s Challenge
AMP’s rehearing request alleged five errors by the commission, including a challenge to PJM’s decision to set the electrical distance requirement at 0.065 per-unit impedance. AMP said the commission “failed to weigh and substantiate the impact of the proposed electrical distance requirement with the level of reliability assurance” and “failed to address the relationship between the value selected as the electrical distance requirement and the impact on PJM’s state estimator.”
| PJM
PJM said the 0.065 threshold was based on a distribution factor analysis (DFAX) to identify the external facilities that would be impacted by PJM’s dispatch of external resources. PJM said the distance requirement made at least 130 GW of existing external resources in the Eastern and Midwestern U.S. eligible for pseudo-ties. The commission accepted PJM’s threshold, saying it was the “result of significant analysis and requiring PJM to rely on an external resource with a higher impedance value would increase the risk to PJM’s state estimator.”
The commission reiterated its previous finding that the electrical distance requirement was just and reasonable “because establishing a bright-line test for external participation strikes an appropriate balance between allowing external resources to participate in PJM’s capacity auctions, while providing PJM with a level of reliability assurances.”
IMEA’s Arguments
IMEA questioned FERC’s interpretation of Section 217(b) of the Federal Power Act and whether the commission’s decision “violated the sanctity of contracts.”
The agency argued that the commission’s determination that Section 217(b) of the FPA only applies to the energy markets and not capacity markets “effectively destroys the self-supply rights of load serving entities (LSEs).”
It said that if Section 217(b) does not apply to capacity markets, then PJM and other RTOs could make filings through Section 205 of the FPA to eliminate all “self-supply options” based on a finding that having control of all resources and planning would ensure better reliability.
FERC was unmoved. “Unlike energy markets, RTOs implement capacity markets to ensure long-term reliability and resource adequacy and, therefore, different requirements for using generation may be applied to capacity and energy markets,” the commission said.
FERC last week accepted Tri-State Generation and Transmission Association’s petition for a declaratory order that recognizes the cooperative as jurisdictional to the commission when it added its first non-utility member last year (EL20-16).
The commission agreed with Tri-State’s contention that the admission last September of Mieco, a wholesale energy services company that provides natural gas to Tri-State and other purchasers, made the cooperative a non-exempt jurisdictional public utility for purposes under the Federal Power Act (FPA).
FERC found that since Sept. 3, Mieco has “continuously been earning patronage capital through its sales of natural gas below index prices” and that Mieco and Tri-State have engaged in transactions that generated patronage capital — or the difference between a cooperative’s yearly operating income and expenses. It said Mieco has a vote in Tri-State’s operations “tailored to its status as a non-utility member,” noting that although the natural gas marketer holds voting rights different from those held by utility members, the commission has not found that the FPA “requires that owners have equal levels of control to demonstrate ownership.”
It said because no party provided evidence countering Tri-State’s claim that Mieco is not an exempt entity under the FPA, Tri-State “has demonstrated that Mieco’s rights are sufficient … to establish that Tri-State has not been wholly owned by entities exempt under [the FPA] since Sept. 3.
“Tri-State is grateful to FERC for its actions today and looks forward to working with FERC in a constructive manner for the benefit of Tri-State’s members,” Tri-State CEO Duane Highley said in a statement.
Tri-State G&T’s service territory spans much of the Rockies. | Tri-State
The company noted that it advances member flexibility for more self-supply and local renewable energy development. As part of Tri-State’s Responsible Energy Plan, members have additional flexibility for the self-supply of power and more local renewable energy development.
Partial requirements contracts address the concerns of some members that desire self-supply above the 5% provisions in their current contracts.
Tri-State also requested relief to terminate controversy and remove uncertainty due to pending complaints filed in November before the Colorado Public Utilities Commission by members La Plata Electric Association and United Power. The cooperative said the utilities asked the PUC to “establish an exit charge [for the Member to be relieved of its obligations under its Wholesale Service Contract and exit Tri-State] that is just, reasonable, and nondiscriminatory.”
FERC said that while it had jurisdiction over Tri-State’s exit charges, it declined to rule that the jurisdiction is exclusive, recognizing that no federal court has found the commission has exclusive jurisdiction over “rules or practices that directly affect a jurisdictional rate.
“We find that the Colorado PUC’s jurisdiction over complaints before it regarding Tri-State’s exit charges is not currently preempted,” FERC wrote. “A ruling by the Colorado PUC on those complaints would not be preempted unless and until such ruling conflicts with a commission-approved Tariff or agreement that establishes how Tri-State’s exit charges will be calculated.”
Tri-State is a generation and transmission cooperative that provides wholesale electricity to 43 member electric distribution cooperatives and public power districts in Colorado, Nebraska, New Mexico and Wyoming.
Other Tri-State Requests Accepted
The commission also issued four other orders related to Tri-State’s request for FERC jurisdiction that the cooperative said ensure “consistent wholesale rate regulation” for its member distribution utilities. Those orders:
Granted Tri-State’s and Thermo Cogeneration Partnership’s request for market-based rate authorization. FERC denied Tri-State’s request for certain waivers and blanket authorization and granted Thermo Cogen’s request for waivers commonly granted to market-based rate sellers (ER20-681).
Found that Tri-State and Thermo Cogen had rebutted the presumption of market power in the Western Area Power Administration’s Colorado-Missouri balancing authority area and that they met the criteria for Category 2 sellers in the Northwest, Southwest and SPP regions and Category 1 sellers in the Southeast, Northeast and Central regions.
Denied Tri-State’s request for regulatory waivers and blanket authorizations, saying it does not typically grant waivers where the seller makes sales at cost-based rates.
Accepted Tri-State’s stated rate Tariff and wholesale electric service contracts and instituted a Section 206 proceeding under the FPA to determine whether the cooperative’s Tariff and electric service contracts are just and reasonable. The order establishes a refund effective date, as well as hearing and settlement judge procedures (20–676).
Found that Tri-State’s filings raised issues of material fact that could not be resolved based on the record before it, saying they would be more appropriately addressed through hearings. It accepted the cooperative’s state rate Tariff and wholesale contracts to be effective Feb. 22 and Feb. 25.
Accepted Tri-State’s Tariff and instituted a Section 206 proceeding and hearing and settlement judge proceedings (ER20-686).
FERC’s 206 investigation will determine whether Tri-State’s proposed formula rate, base return on equity (ROE), formula rate implementation protocols, reactive supply and voltage control service rates and real power loss factor are just and reasonable.
The commission also accepted Tri-State’s proposed service agreements and a notice of cancellation for filing. It held two contested cancellation notices in abeyance. It rejected without prejudice a board policy that describes members’ option to use self-owned or -controlled distributed or renewable generation resources to serve up to 5% of that members’ requirement (ER20–689).
FERC also found the cooperative’s board policy and generation contracts are deficient without another board policy on file that comprises specific rate mechanisms, terms and conditions that significantly affect the rates utility members must pay if they produce energy in excess of the 5% allowance. It directed Tri-State to refile the rate schedules. The commission did accept the cooperative’s bylaws and other rate schedules for filing.
Commission Partially Accepts GridLiance Filing
The commission found that GridLiance High Plains’ amendments to FERC’s pro forma large generator interconnection agreement (LGIA) and pro forma large generator interconnection procedures partially comply with requirements of orders 845 and 845-A, requiring a further compliance filing within 120 days (ER19–1961).
The commissioners said GridLiance’s proposed revisions regarding the option to build transmission partially comply with the orders’ requirements because they incorporate most of their language without modification. However, FERC found that GridLiance had not justified its proposal to retain language of its pro forma LGIA that the commission removed from FERC’s pro forma LGIA in the revisions set forth in the orders.
The language at issue provides that the “interconnection customer shall so notify transmission provider within 30 calendar days” as required by orders 845 and 845-A.
FERC on Thursday approved a new MISO Tariff provision that allows transmission owners to recover interconnection facility operations and maintenance costs from interconnection customers.
The decision allows MISO to include a new rate schedule — Schedule 50 — to allow TOs to recoup costs from interconnection customers for “reasonable expenses, including overheads, associated with operation and maintenance, and repair” of TO-owned interconnection facilities (ER20-170).
MISO TOs filed in October for the new rate schedule.
“While relevant provisions of a MISO generator interconnection agreement … already explicitly provide that interconnection customers ‘shall be responsible’ for all reasonable [operations and maintenance] expenses, there is presently no mechanism in the Tariff to enable the calculation and recovery of such expenses from interconnection customers,” the TOs explained to FERC.
MISO joined the filing as administrator of its Tariff but took no stance on the proposed revisions.
The TOs plan to allocate O&M annual charges based on a calculation involving the interconnection facilities’ installed costs as a share of a total annual transmission gross plant. When installed costs aren’t available for calculation, TOs will have to submit filings so FERC can review the alternate calculations.
In accepting the new schedule, FERC disagreed with renewable energy proponents that the Schedule 50 approach would “unduly” shift costs to interconnection customers. Some had argued that a process including transmission facilities didn’t translate well for interconnection facilities because they’re newer and less prone to maintenance charges. But the commission said the average useful life or O&M costs of an interconnection facility aren’t much different than the average useful life or O&M costs “of other similar transmission facilities.”
Other clean energy advocates said O&M costs should be assigned directly to interconnection customers instead of using a calculation. FERC again disagreed.
” … [E]ven in the instances where transmission owners utilize direct billing, not all costs are able to be directly assigned, some are assigned based on various allocators, and some costs are not even recovered,” the commission explained.
FERC on Thursday accepted changes to the New England Transmission Owners’ (NETOs) interconnection study deadlines and the scope of their feasibility studies (ER19-1952).
However, the commission only partially accepted a separate Order 845/845-A compliance filing by ISO-NE and NETOs to reflect the orders’ changes to the commission’s pro forma large generator interconnection agreement (LGIA) and large generator interconnection procedures (LGIP), ordering a further compliance filing within 120 days (ER19-1951).
Renewable developers EDF Renewables, E.ON Climate & Renewables N.A. and Enel Green Power N.A. had argued that the revised deadlines — extending the feasibility study from 45 to 90 days and the system impact study (SIS) from 90 to 270 days — are unreasonably ambitious. They noted ISO-NE’s severe backlog, with feasibility studies averaging 229 days and SIS averaging 443 days.
But the commission said it expects “that the average study lengths will drop due to the reduced scope of the feasibility study and due to the other interconnection process improvements,” citing expanded use of consultants and a streamlined approach for managing SIS models and data.
EDF Renewables’ Williston solar project in Vermont became operational in 2016. | EDF Renewables
Under the previous rules, many interconnection customers that chose the separate feasibility study later modified their projects before the SIS, reducing the time savings from conducting the feasibility study first. The new rules eliminate the option to integrate the feasibility study within the SIS and allow customers to forgo the feasibility study. Feasibility studies will be reduced to a limited power flow analysis, instead of the full power flow analysis allowed previously.
Regarding the LGIP filing, the commission found that it proposed, “without justification, language that differs in one respect from the commission’s requirements related to the process for analyzing surplus interconnection service requests.”
The filing parties explained in their transmittal letter (but did not specify in proposed Tariff revisions) that ISO-NE would limit the analysis it performs to its existing 10-business-day material modification framework for accommodating technological changes. The commission said it “may be inadequate to complete the evaluation required under Order No. 845.”
The commission required a further compliance filing to address the stand-alone network upgrades definition; interconnection customers’ ability to exercise the option to build; NETOs’ proposal to recover actual costs rather than a negotiated amount for oversight costs related to the option to build; the method for determining contingent facilities; requests for interconnection service below generating facility capacity; provisional interconnection service; and both the process and definition for surplus interconnection service.
FERC Partially Accepts Emera Maine Filing
FERC on Thursday also accepted amendments to Emera Maine’s LGIA and LGIP but ordered a further compliance filing within 120 days (ER19-1887).
The commission found that the revised dispute resolution procedures in the company’s LGIP comply with Orders 845/845-A and that the variations are “consistent with or superior” to them. “However, the deadlines in Emera Maine’s proposed dispute resolution timeline contain an apparent incongruity,” the commission said, ordering a further compliance filing to address a five-day discrepancy in stated terms.
The commission found that the LGIP’s method for determining contingent facilities is in partial compliance but that proposed criteria for identifying contingent facilities “lack the requisite transparency.” It ordered the company to describe the specific technical screens, analyses, triggering thresholds or criteria it will use to identify such facilities.
The commission also ordered further compliance filings to incorporate pro forma revisions to section 3.1 of its LGIP; to revise section 4.4.6 to clarify how it will assess changes to a generating facility’s technical specifications; to clarify the deposit amount the interconnection customer is required to tender; and to specify that Emera Maine will complete its assessment and determination of whether a proposed technological change is a material modification within 30 days of an interconnection customer submitting a technological change request.
Wednesday’s Planning Advisory Committee meeting opened with stakeholders asking for information on proposals generated by ISO-NE’s first competitive transmission solicitation in December.
The RFP seeks to address reliability concerns over the planned retirement of the Mystic Generating Station near Boston. (See ISO-NE Issues First Competitive Tx RFP.)
The RTO “received 36 Phase One proposals prior to the submission deadline of March 4, with costs ranging from about $49 million to $745 million,” said ISO-NE Director of Transmission Planning Brent Oberlin. In-service dates ranged “roughly” from mid-2023 to 2026, he said.
“Right now, the ISO is weeding its way through all the proposals … and we have received a number of requests to publish them,” Oberlin said. “Our current policy is that we want to release that information together with the ISO’s draft determination.”
Oberlin noted that eight qualified transmission project sponsors submitted bids. Among them was Anbaric, which on Thursday announced details of its proposed 900-1,200 MW Mystic Reliability Wind Link project, including an option for an additional 1,200 MW.
In response to a question from Sebastian Libonatti, of Avangrid Networks, Oberlin said ISO-NE would not immediately release executive summaries of the various proposals. In a Thursday memo, the RTO explained it would wait 175 calendar days to divulge proposal details because of concerns over inadequate or inaccurate information in some of the proposals.
ISO-NE’s memo said that some proposals do not meet the identified needs, or violate the Tariff, and that due to the two-phase solicitation process, some of the initial proposals’ life-cycle costs are misleading.
“Posting a list of the Phase One Proposals with these potential serious flaws without noting them will not facilitate meaningful stakeholder discussion or review and will result in wasted effort as non-compliant proposals are evaluated,” the memo said.
During Wednesday’s meeting, Phelps Turner, a senior attorney for the Conservation Law Foundation in Maine, said, “We also want to flag that we have due process concerns with the proposed schedule, which should be expedited to ensure openness and transparency, planning principles that were clearly outlined in [FERC] Order 1000, and we also want to make sure we set a good precedent with this first competitive procurement [in New England].”
Turner told RTO Insider that the CLF was concerned about the evaluation process for all proposals, not just for any single bid.
“Order 1000 says that stakeholders must be provided an opportunity to participate in the process in a timely and meaningful manner,” Turner said, comparing the 175 days the RTO is taking to the week or so its solicitation schedule provides for stakeholders to see the proposals and submit comments.
“It’s standard practice in the legal community to share redacted versions, and while we would prefer the unredacted proposals be published, redacted ones are better than nothing,” he said.
Modeling More Offshore Wind, Slowly
ISO-NE presented the PAC preliminary results of the Anbaric 2019 Economic Study for scenarios adding from 8,000 to 12,000 MW of offshore wind in southern New England, which it found causes export interface congestion in the Southeastern Massachusetts/Rhode Island (SEMA/RI) interface.
The assumptions include retirements of nearly 4,500 MW.
The RTO’s lead engineer for system planning, Haizhen Wang, led discussion of the study, which compared the Anbaric results to those presented at last month’s PAC from a similar study requested by the New England States Committee on Electricity (NESCOE). (See ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
NESCOE, Anbaric and RENEW Northeast had requested separate analyses at the April 2019 PAC meeting.
The new analysis found that interconnecting more OSW close to load centers outside of the SEMA/RI areas (such as the Mystic and Millstone substations) would reduce the congestion hours of the SEMA/RI export interface.
Total renewable spillage in the Anbaric_8000 scenario, primarily OSW and hydro, decreases approximately 50% compared to the NESCOE scenario. This is because the assumed nuclear retirements decrease the energy oversupply in the Anbaric scenario. | ISO-NE
Retirement of large baseload must-run nuclear generation would lower spillage associated with over generation, the report said.
Theodore Paradise, Anbaric senior vice president for transmission strategy and counsel, asked about a rise in natural gas energy production under both constrained and unconstrained scenarios for 8,000 MW OSW, which assumes new OSW insufficient to cover the retired nuclear generation.
Peter Wong, ISO-NE manager for resource adequacy, said that more assumed nuclear retirements means fewer hours of oversupply, during which the RTO would otherwise spill the offshore wind.
“As [OSW] increases to 10,000 MW and 12,000 MW, does the natural gas run in terms of amount decrease?” Paradise asked.
“As we add more offshore wind to the system, the need for other generating resources would decrease when the offshore wind is not constrained by export limits,” Wong said. “That’s why the natural gas generation keeps decreasing as we add additional offshore wind to the system.”
The RTO plans to present additional spillage and marginal emissions results from the NESCOE study in April, complete ancillary service analysis by May and publish the final report by June 1, Wang said.
The Anbaric study will see additional GridView results presented with 2015 load/PV/wind profiles in April, with the final report to be published in June or July. The RTO also will present NESCOE and Anbaric transmission cost estimates in March and April.
If time does not permit a presentation at the PAC, the RTO will still make the relevant information available to stakeholders, Wang said.
The RENEW GridView results with 2015 load/PV/wind profiles will be presented in April, and the final report in July.
Draft 2020 CELT Load Forecast
Jon Black, manager of load forecasting, presented an update on the annual 10-year forecasts of energy and demand that the RTO publishes as part of the capacity, energy, loads and transmission (CELT) report.
He focused on the heating and transportation electrification forecasts newly included in CELT 2020, saying that the usual topics of gross energy, summer demand and winter demand forecasts, as well as energy efficiency and solar forecasts will be discussed in more detail at the April PAC.
The 2020 heating electrification forecast focuses on the adoption of air-source heat pumps (ASHPs), currently the most prevalent heat pump technology, he said.
“Heating electrification is a nascent trend,” Black said, noting that the emergence of other technologies, such as ground-source heat pumps, may warrant consideration in future forecasts.
Final draft 2020 heating electrification forecast in terms of monthly energy (GWh) | ISO-NE
One stakeholder wondered how the RTO could estimate the effect of ASHPs on load while only using three winter months of data.
“We’re mapping it to heating degree days, which is a variable that we use in our forecast models,” Black said. “In general, when it gets cold, you use your heat pumps more, and we are mainly focusing on getting the winter demand impact as good as we can, which is why we focused on more of the colder months.
“Essentially, those colder months yield a relationship between how cold it is and how much electricity you use before and after installing a heat pump,” he said. “We apply those assumptions to all the months and days in our forecast where you have heating degree days.”
A related presentation at last month’s PAC showed that heat pumps and plug-in electric vehicles make up only 4% of projected 2030 annual net load, which spikes to about 10% during winter evening peaks. But the draft CELT shows EV load impact steadily rising from near zero today to 1.2% of load and nearly 180 GWh in terms of monthly energy in January 2030.
Final draft 2020 EV forecast in terms of monthly energy (GWh) | ISO-NE
The EV forecast in the draft CELT estimates the adoption of electrified light-duty vehicles for each state and the region over the next 10 years, both battery-electric vehicles (BEV) and plug-in hybrids (PHEV), Black said.
The RTO takes the adoption estimates and extrapolates monthly demand and energy impacts per EV based on recent historical EV charging data licensed from ChargePoint. It developed energy and demand assumptions based on an aggregate EV charging profile reflecting between 118 and 247 EV drivers across the region between June 2018 and May 2019.
The aggregate profile reflects 78% residential and 22% non-residential, he said.
Natural Gas Use Rises in NE
Tom Kiley, CEO of the Northeast Gas Association, gave a brief review of the natural gas industry in the region, as well as of what turned out to be a mild winter. He referred to a separate winter review posted that day by the RTO for stakeholders seeking greater detail on the season.
“We plan for a lot of eventualities and scenarios, but certainly this COVID-19 pandemic is quite extraordinary … and clearly emphasizes how industry coordination and communication during challenging times remain of critical importance,” Kiley said.
U.S. natural gas production in 2019 set new all-time records (92.2 Bcf/d), as did consumption (85 Bcf/d).
“The EIA reported U.S. natural gas consumption grew in the electric power sector by 2.0 Bcf/d, or 7%, but remained relatively flat in the commercial, residential and industrial sectors,” Kiley said.
New 2019 additions to gas generation capacity in New England | NGA
New gas generation capacity in New England last year included PSEG Power’s 485-MW Bridgeport Harbor Station 5 in Bridgeport, Conn.; NRG Energy’s 333-MW Canal 3 plant in Sandwich, Mass.; and Exelon’s 200-MW West Medway unit in Medway, Mass.
Two New England pipeline capacity expansion projects went into service in 2019, both part of the Portland Natural Gas Transmission System: the second phase of Portland Xpress and the first phase of Westbrook Xpress.
Projects expected to go into service this year are the second phase of Enbridge’s Atlantic Bridge Project in Weymouth, Mass., the third phase of Portland Xpress, and the Station 261 Upgrade on the Tennessee Pipeline in Agawam, Mass.
Since 2012, more than a million new households have been connected for natural gas use in the six New England states plus New Jersey, New York and Pennsylvania, he said.
“Today this represents over 12 million households in total,” Kiley said.
FERC last week affirmed its 2018 ruling approving MISO’s current resource adequacy construct, rejecting multiple rehearing requests from critics of the decision.
Among those requesting rehearing were a collection of Midwest transmission-dependent utilities, a group of major capacity suppliers, Main Line Generation and MISO’s Independent Market Monitor.
The commission said most of those arguing for rehearing sought to make MISO’s RA construct more like the centralized capacity markets of Eastern RTOs/ISOs. But FERC noted that those designs ignore the fact that the RTO must defer to multiple state jurisdictions in its 13-state reach and that its RA design is meant to be complementary to states’ authority (ER18-462).
MISO Little Rock headquarters | MISO
The commission also pointed out that 90% of MISO’s load is served by vertically integrated load-serving entities that for the most part don’t use the RTO’s capacity auction to meet capacity requirements.
” … [U]nlike the centralized capacity constructs used in the Eastern RTOs/ISOs, MISO’s auction is not — and has never been — the primary mechanism for its LSEs to procure capacity,” the commission stressed.
Two years ago, MISO pre-emptively refiled its entire RA construct in response to a D.C. Circuit Court of Appeals ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned the decision could impact some of the RA rules that had been guided by FERC’s recommendations.
In a pair of orders a few months later, FERC both vacated and reinstated MISO’s entire RA construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed. (See FERC Vacates, Upholds MISO Resource Adequacy Rules.)
Still No Sloped Demand Curve, MOPR, Forward Mechanism
MISO Independent Market Monitor David Patton used the RA refiling as an opportunity to ask FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)
On rehearing, Patton again argued that a good RA design “will produce price signals sufficient to attract and retain the necessary amount of capacity” and that FERC itself made that issue paramount when accepting the sloped demand curves used in NYISO, PJM and ISO-NE’s capacity auctions.
But in last week’s ruling, FERC said MISO’s high percentage of vertically integrated utilities sets it apart it from NYISO, PJM and ISO-NE because MISO’s RA is not determined by its capacity auction prices alone. It said the RTO’s vertical demand curve is fine for now.
” … [W]e continue to find that MISO’s resource adequacy construct enables the MISO region to maintain sufficient resources to meet system-wide and locational reserve requirements,” the commission said, noting that last year’s Organization of MISO States-MISO RA survey indicates sufficient capacity supply through 2022.
The commission also rejected the capacity suppliers’ request that the RTO conduct the auction on a three-year forward basis for retail-choice areas in Illinois and Michigan. FERC found that both a prompt auction and a multi-year forward capacity auction can be reasonable, and the suppliers’ support of one design over the other wasn’t a justification to order MISO to change its auction timing. The commission also told the suppliers that MISO’s auction didn’t require a minimum offer price rule, again noting that vertically integrated utilities own about 90% of capacity in MISO.
The commission also rejected the suppliers’ argument that it’s discriminatory for the MISO capacity auction to be voluntary for buyers and mandatory for sellers who have uncommitted capacity. FERC said while it does have an obligation to ensure that “similarly situated market participants are not unduly discriminated against … it does not follow that market participants who are not similarly situated are unduly discriminated against simply because they are subject to different sets of rules.”
The transmission-dependent utilities argued that the RA construct should allow new capacity resources to obtain long-term financial hedges to shield against inter-zonal price separation in the auctions. FERC said such a provision fails to consider the capacity auction’s main purpose of ensuring reliability during peak days.
The commission said MISO’s local clearing requirements and capacity import and export limits are essential to zonal reliability and declined to order alterations so more resources could compete inter-zonally. The commission also left in place MISO’s zonal delivery charge, which the RTO uses to cover congestion between zones when an LSE that submits its own fixed resource adequacy plan taps resources in a lower-priced local resource zone to serve demand in a higher-priced zone. The commission disagreed that the zonal delivery charge is a form of rate pancaking, pointing out that the charge is meant to cover auction price separation between the LSE’s location and its load, not transmission service. Capacity prices should reflect the “locational cost of capacity,” FERC said.
MISO’s RA construct “appropriately balances the competing goals of maximizing competition and ensuring reliability by allowing LSEs to serve their load with remote resources but having them bear the risk of auction price separation if there are impediments to the deliverability of such resources,” FERC said.
New England stakeholders on Tuesday pushed back on ISO-NE’s draft assumptions showing that several variable changes between Forward Capacity Auctions 14 and 15 will improve system fuel security.
ISO-NE Manager of Outage Coordination Norm Sproehnle presented the New England Power Pool Reliability Committee with assumptions based on the RTO’s capacity, energy, loads and transmission (CELT) forecast and consistent with Planning Procedure 10 (PP-10) Appendix I.
The assumptions show FCA 15 will see increases in gas pipeline capacity, total PV, onshore and offshore wind nameplate and demand response, coupled with lower peak load, lower winter LDC natural gas demand forecast and lower equivalent forced outage rate demand (EFORd).
Utilization of gas supply vs LDC demand in New England. | ISO-NE
Chris Hamlen, the RTO’s assistant general counsel for markets, clarified “that the fuel security retention rules are in place only through FCA 15, and so beyond FCA 15 there is no mechanism in place for performing this type of review.”
Further, the RTO indicated that, in response to stakeholder concerns raised during the meeting, it would consider whether it is possible to adjust some of the assumptions in the retention analysis performed for FCA 15 to better reflect the way in which the impact analysis was performed for ESI.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings; those quoted in this article approved their remarks afterward to clarify their presentations.]
The committee will review FCA 15 fuel security inputs and results in April and May and vote on the proposed PP10-I revisions in May, if applicable. If necessary, NEPOOL’s Participants Committee will vote on the revisions in June.
The RTO also is preparing for fuel security reliability reviews of FCM retirement de-list bids, substitution auction demand bids, bilateral transactions and reconfiguration auction demand bids submitted in connection with FCA 15.
FCA-14 Auction Results
Ryan Hoskin, ISO-NE senior analyst for transmission services and resource qualification, presented results of FCA-14, which was held in the first week of February.
The RTO’s 2020 capacity auction cleared at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019. (See ISO-NE Capacity Prices Hit Record Low.)
Results of New England’s FCA 14. | ISO-NE
ISO-NE filed the auction results with FERC on Feb. 18 (ER20-1025) and posted its capacity supply obligations (CSO) spreadsheet on its website. No capacity supply obligations were traded this year under the substitution auction.
FCA 15 Capacity Zones OK’d
The RC also voted to recommend that ISO-NE identify the zonal boundaries to be used in modeling criteria for FCA 15 — unchanged from FCA 14 — in accordance with Tariff rules.
Al McBride, the RTO’s director of transmission strategy and services, reviewed the proposed capacity zone construct for FCA 15, as well as the interface transfer capabilities and external interfaces.
For FCA 15, the RTO will evaluate potential export-constrained zones, including Northern New England (NNE), which includes Vermont, New Hampshire and Maine, and a portion of Maine nested within NNE.
Potential import-constrained zones to be evaluated include Southern New England (SENE), which includes Northeast Massachusetts/Boston (NEMA), and Southeast Massachusetts/Rhode Island (SEMA/RI), and Connecticut.
The RTO will test the potential capacity zone boundaries and present the results at the May 2020 Power Supply Planning Committee, McBride said.
Zones that trigger the objective criteria indicating constraints will be modeled in FCA 15 and associated reconfiguration auctions, which will determine whether any of the modeled zones bind in the auction and experience price separation, he said.
Regarding internal interface transfer capability, the study noted increases associated with various transmission system upgrades, including ones in Greater Boston, Greater Hartford/Central Connecticut, Southwest Connecticut, as well as with SEMA/RI reliability project upgrades.
The study found a decrease in internal interface transfer capability associated with the updated load assumptions, updated NNE-Scobie transfer capability and the retirement of Mystic units 7, 8 and 9.
One stakeholder assumed that a drop in load would increase import capability and that the Mystic retirements will increase import capability.
“No, all these factors have the effect of lowering the transfer capability,” McBride said. “The load change really becomes as much about relative load changing, [and] in particular, changes in where load is on the key transmission lines.
“If you’re lowering load at a point on the transmission system that causes less local drawdown and more flow to remain on the system, but it seeks to try to get into, in this case, southeast New England, lowering load at particular points can actually cause more flow to be on those lines as it tries to serve the load beyond that point, lowering the transfer capability,” McBride said.
“We did some sensitivity analysis in an attempt to identify what the factors were,” he said. “The predominant thing we were looking at was the change from Mystic 8 and 9 at retirement, and we wanted to make sure we understood what the other factors were.”
For external interface import capability, limits are usually for the summer period, may not include possible simultaneous impacts and should not be considered as firm, McBride said.
For example, the electrical limit of the New Brunswick (NB)-New England (NE) Tie is 1,000 MW, but downstream constraints, particularly in Orrington South, led planners to adjust that tie’s transfer capability to 700 MW for ability to deliver capacity to the greater New England Control Area.
Similar to what it did with NB-NE, the RTO has assumed transfer capability for capacity and reliability calculation purposes to be 1,400 MW for the 2,000 MW Hydro-Quebec Phase II interconnection, lowering the figure due to the need to protect for the loss of the line at full import level in the PJM and New York Control Areas’ systems, he said.
An executive committee charged with overseeing administration of SPP‘s Western Energy Imbalance Service (WEIS) last week launched the working group responsible for developing and maintaining the market’s protocols.
The Western Markets Working Group (WMWG) will report to the Western Markets Executive Committee (WMEC), which approved both the group’s scope and its leadership during a March 19 conference call.
The WMWG will work with other stakeholder groups in recommending the protocols and associated Tariff changes to the WMEC and prioritizing approved system and process changes. It will also coordinate with regulators and task forces in implementing the WEIS market.
SPP’s WEIS and legacy footprints. | SPP
The committee unanimously approved Basin Electric Power Cooperative’s Valerie Weigel as the WMWG’s chair and Municipal Energy Agency of Nebraska’s Jeff Lindsay as vice-chair. They will serve two-year terms.
The working group will replace the WEIS Protocol Review Task Force, which has been developing the market’s protocols. The WMWG will consist of up to 12 members, with one representative from each non-affiliated signatory to the Western Joint Dispatch Agreement, the contractual arrangement between SPP and WEIS participants that governs SPP’s obligations to administer the market and its compensation.
SPP filed its WEIS Tariff in February, asking for an effective date of Feb. 1, 2021.
The WEIS market is modeled on the Energy Imbalance Service market SPP operated from 2007 to 2014. The RTO will centrally dispatch energy from the participants every five minutes using the most cost-effective generation to reduce wholesale electricity costs for participants. SPP says the market will provide price transparency and bilateral trades.
The WEIS market has attracted eight participants with the early March addition of Utah’s Deseret Power Electric Cooperative, a regional generation and transmission cooperative with six member retail systems. It is scheduled to launch next February. (See SPP Board OKs $9.5M to Build Western EIS Market.)
FERC on Friday approved PJM’s proposed rules on how the RTO will evaluate voluntary cost commitment proposals on competitive transmission projects (ER19-2915).
The Operating Agreement changes, which resulted from stakeholder-drafted motions at the Markets and Reliability Committee, require PJM to evaluate projects submitted in competitive proposal windows on multiple criteria, including “cost effectiveness.” (See PJM TOs Wary of Cost Containment Rules.)
The revisions clarify that PJM may not require developers to submit cost containments and that those that are voluntarily proposed are binding.
PJM would evaluate “the quality and effectiveness” of provisions that limit project construction costs, total return on equity (ROE) including incentive adders or capital structure.
Annual revenue requirement under partial and full cost caps | PJM
The RTO will submit to the Transmission Expansion Advisory Committee (TEAC) an analysis comparing the risks to be borne by ratepayers as a result of developers’ binding cost commitments or non-binding cost estimates.
In approving the rules, the commission rejected the objections of transmission owners, which argued the revisions did not provide enough details on how PJM will conduct its comparative analysis.
“We find that PJM’s filing is just and reasonable because it may assist PJM in its selection of the more efficient or cost-effective transmission solution and provides additional transparency of PJM’s evaluation of competing proposals,” the commission said. It noted that PJM is developing implementation details for the comparative analysis in Manual 14F.
“The proposed revisions provide reasonable flexibility both for developers to decide how to craft their voluntary cost commitment proposals and for PJM to evaluate and select the more efficient or cost-effective transmission solution. Moreover, the proposal provides for transparency, allowing stakeholders the opportunity to review any particular analysis conducted by PJM and raise any concerns via the TEAC process.”
FERC disagreed with arguments that the filing infringed on the rights of PJM transmission owners and nonincumbent transmission developers to exclusively make Federal Power Act Section 205 filings concerning transmission rates, revenue requirements and cost recovery.
It also rejected contentions that PJM will be determining whether the rate design elements under a proposal will result in just and reasonable rates. “PJM is proposing for the commission to determine, in reviewing the nonconforming DEA [designated entity agreement between PJM and a selected developer] with the cost commitment provision, whether any rate design component included in that provision is just and reasonable.”
