Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. NOTE: After the meetings, Independent Market Monitor Joe Bowring will provide a briefing on the 2017 State of the Market Report.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
(There appears to be an error in PJM’s post-ed agenda for the MRC. The times for Items 3 and 4 overlap.)
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. The revisions were developed as part of a periodic review and encompass real-time system monitoring and communication requirements, including external resources.
C. Manual 14A: New Services Request Process and Manual 14E: Additional Information for Upgrade and Transmission Interconnection Projects. Revisions developed to implement previously approved revisions to PJM’s transmission service and upgrade requests. (See “Transmission Issues,” PJM PC/TEAC Briefs: Feb. 8, 2018.)
E. Manual 37: Reliability Coordination. Revisions developed to clarify language and simplify references to NERC standards.
3. Energy Price Formation Senior Task Force (EPFSTF) (9:40-10:15)
Members will be asked to endorse a proposed charter for the EPFSTF and proposed revisions to the energy price-formation issue charge related to development of a real-time, 30-minute reserve product. (See “30-Minute Reserves,” PJM Operating Committee Briefs: March 6, 2018.)
4. Tariff Revisions to Address Overlapping Congestion (9:30-9:45)
Members will be asked to endorse Tariff and Operating Agreement revisions to address overlapping congestion. A vote on the proposal was held over from February’s MRC meeting to address concerns about cancellation of certain market-to-market payments. (See “Overlapping Congestion,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)
Members Committee
1. Tariff and Operating Agreement Revisions to Address Overlapping Congestion (1:10-1:30)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions to address overlapping congestion. (See MRC Item 4 above.)
RENSSELAER, N.Y. — NYISO energy prices averaged $33.83/MWh in February, down sharply from their cold snap average of $99.55 in January but up 9.3% from the same month a year ago, Rob Pike, director of market design, told the ISO’s Business Issues Committee on Thursday.
The ISO’s year-to-date monthly energy prices averaged $72.85/MWh in February, up 92% from a year earlier. Average sendout was 426 GWh/day, compared with 463 GWh/day in January and 418 GWh/day a year ago.
New York natural gas prices for the month averaged $3.14/MMBtu at the Transco Z6 hub, down from $17.94 in January. Prices were up 11.1% from a year ago.
Distillate prices gained 19.3% year over year, with Jet Kerosene Gulf Coast averaging $13.72/MMBtu. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.86/MMBtu, compared with $14.83 in January.
The ISO’s local reliability share was 14 cents/MWh, lower than 59 cents the previous month, while the statewide share of -64 cents/MWh was higher than -$1.52 in January. Total uplift costs also rose from January.
Broader Regional Markets
Reviewing the Broader Regional Markets report, Pike highlighted NYISO’s ongoing work to clarify the minimum requirements for delivering external capacity into the Installed Capacity (ICAP) market. The BIC in January approved ICAP Manual revisions covering deliverability requirements for capacity imports from NYISO Business Issues Committee Briefs: Jan. 17, 2018.)
Pike also noted that NYISO last month urged FERC to deny a complaint by the New Jersey Board of Public Utilities against the ISO, PJM, Consolidated Edison, Linden VFT, Hudson Transmission Partners and the New York Power Authority. The complaint challenges the implementation of the mutual benefits provisions in the NYISO-PJM Joint Operating Agreement and requests amendments to it.
“First, the complaint was an impermissible collateral attack on prior FERC orders, attempting to reopen matters that have been addressed or are being addressed in other proceedings,” the ISO said in its FERC filing. “Additionally, the complaint is inconsistent with an Order No. 1000 cost allocation principle requiring voluntary agreement for the NYISO to be allocated costs.”
The ISO further argued that the complaint is inconsistent with the provisions of the JOA and tariffs that address cross-border cost allocation. The BPU also misinterpreted provisions of the JOA spelling out that NYISO and PJM not charge each other for mutual benefits, the ISO said.
External Deliverability Rights
The BIC recommended that the Management Committee approve Tariff revisions that would create external-to-Rest of State (ROS) deliverability rights, which would improve the ability for transfer capability into ROS to participate in the capacity market.
Ethan D. Avallone, senior market design specialist, said Hydro-Quebec US (HQUS) proposed that the ISO develop a method for awarding capacity resource interconnection service (CRIS) to entities that create increased transfer capability through transmission upgrades over external interfaces.
FERC in January 2017 granted HQUS a waiver (ER17-505) making it eligible to receive CRIS corresponding to the incremental transfer capability created by its Cedars Rapids Transmission intertie project. The commission noted that the issue was not addressed earlier because of other priorities and not because of objections from the ISO or other stakeholders.
2017 Congestion Assessment and Resource Integration Study
The BIC also voted to recommend that the Management Committee ask the Board of Directors to approve the ISO’s 2017 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 report.
The 2017 CARIS includes six studies on three areas, Edic-Marcy, Central East, and New Scotland-Pleasant Valley. | NYISO
Tim Duffy, economic planning manager, presented the draft report, which he said provides analysis of the potential costs and benefits of relieving congestion on the New York grid by using generic transmission, generation, demand response and energy-efficiency solutions.
One stakeholder expressed skepticism about the rationality of the projected resource mix used to theoretically meet the state’s goals to get 50% of its energy from renewables by 2030.
Real-time fuel mix, March 12, 2018. NYISO is updating its manual for combined cycle generating units equipped to switch from gas to oil. | NYISO
“We certainly recognize that any of these numbers could be argued with, but the objective was to get to the 2030 goals,” Duffy said.
The study presents a series of metrics for a wide range of potential futures and scenarios. One set of results can be viewed as a “business as usual” case, incorporating incremental resource changes based on the ISO’s study inclusion rules, Duffy said.
Some results identify limited opportunities for transmission build-out based solely on production cost reductions. A second set of results is more forward-looking and captures impacts of changes on the grid through large-scale growth in renewable resources and implementation of energy-efficiency programs.
The ISO identified the three transmission elements — or groups of elements — where congestion was most prevalent in the New York Control Area based on an analysis of historic and projected congestion, and potential production cost savings.
Manual Update on Fuel Swap Testing
The BIC approved sending the Operations Committee a proposed update to the Ancillary Services Manual covering automatic fuel swap capability testing.
Harris Miller, associate operations engineer, said automatic fuel swap tests are required each capability period by combined cycle generating units that participate in Con Ed’s minimum oil burn program and are equipped to automatically switch from gas to oil.
Each applicable generating unit must demonstrate a swap from natural gas to oil after an actual loss of gas pressure, a simulated loss of pressure, or an operator-initiated swap.
The swap must occur within a time frame consistent with the design parameters of the unit, must not exceed 60 seconds and should occur during stable operation while the unit remains synchronized to the transmission system. Each unit must coordinate real-time automatic swap tests with both the ISO and Con Ed.
In the event of a failed test, the operator must identify the cause of failure, undertake remedial action, and keep Con Ed and the ISO informed about its progress fixing the problem.
CARMEL, Ind. — Stakeholders are questioning a MISO proposal that would draw a sharp distinction between the cost allocation eligibility for interregional and internal projects.
The preliminary proposal would make cost sharing available to 100-kV projects along the PJM and SPP seams but limit it to internal market efficiency projects of 230 kV and above.
MISO staff have expressed confidence about the proposal — unveiled last month — and say the change will capture a reality in the footprint, where 230-kV lines are prevalent. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.) The plan also respects FERC’s 2016 order requiring MISO to lower its voltage threshold to 100 kV on interregional projects with PJM.
“Views can change in the next few months, but right now, we’re on a good path,” MISO Director of Strategy Jesse Moser said of the allocation proposal during a March 15 Regional Expansion Criteria and Benefits Working Group meeting.
Several stakeholders at the meeting asked MISO to consider lowering the internal market efficiency project voltage threshold to 100 kV, while others favored the 230-kV limit — and a few preferred keeping the 345-kV limit.
Ottertail Power’s Stacie Hebert said her company favors maintaining the 345-kV market efficiency project threshold, but it thought 230 kV was a “reasonable compromise.”
Moser said the divergent stakeholder views he’s heard on the proposal suggest the RTO may have struck a compromise.
But WEC Energy Group’s Chris Plante said he couldn’t understand the reason for the differing thresholds.
“We have difficulties reconciling a 100-kV interregional voltage threshold with a 230-kV voltage threshold for MISO market efficiency projects,” Plante said.
While Plante said his company could become comfortable with MISO’s proposed removal of the postage stamp rate, he asked the RTO to also examine the possibility of implementing separate postage stamp rates for the Midwest and South regions. Since Entergy joined the RTO in 2013, MISO South has been subject to an integration transition period, which limits cost sharing in the region.
Madison Gas and Electric’s Megan Wisersky also said her company supported “consistency between internal and interregional projects” and a regional postage stamp rate.
Changing Nature
MISO has recommended that it scrap its current footprint-wide postage stamp rate for market efficiency projects. The RTO currently allocates 80% of project costs to local resource zones based on expected benefits and recovers the other 20% via postage stamp allocation to all regional load.
The RTO wants to assign all costs to benefiting transmission pricing zones and work with stakeholders to create more specific benefit metrics and cost allocation zones. It currently relies on the postage stamp rate as a means of recognizing both benefits not currently quantified within its cost allocation and the changing nature of beneficiaries as the resource fleet evolves.
MISO planning coordinator Davey Lopez said the RTO’s current interregional cost-sharing rules are inconsistent and complicate interregional planning. To remedy this, Lopez said MISO must lower its SPP interregional cost-sharing threshold to 100 kV, matching its threshold with PJM.
“Most of the existing tie lines between MISO and SPP are less than 230 kV,” Lopez added.
MISO’s Tariff does not currently define regional cost allocation for sub-345-kV economic projects with PJM (although a plan is due in October in response to a FERC directive) and still requires economic projects with SPP to be at least 345 kV to be eligible for regional cost-sharing. The Tariff also doesn’t address sub-345-kV interregional projects located wholly outside of the RTO.
More Cost Allocation Zones
Other stakeholders at the meeting called on MISO to provide more detailed benefit metrics regarding a plan to further refine and shrink its existing cost allocation zones, which are currently based on the historic grouping of transmission pricing zones by state jurisdiction. They are nearly identical to the 10 local resource zones used in the annual capacity auction, although MISO this year won FERC approval to carve out an 11th zone in Texas for more specific cost allocation for the impending 500-kV Hartburg-Sabine project, the RTO’s only competitively bid transmission project this year. (See MISO Board Approves Texas Competitive Tx Project.)
Cost Allocation Zones in MISO today | MISO
MISO staff stressed they haven’t established a position on rearranging existing transmission pricing zones or valuing new benefit criteria. Discussions on the new cost allocation plan will continue through fall.
A coalition of the country’s largest utilities last week urged Congress to maintain an electric vehicle tax credit and remove the cap that limits the benefit to the first 200,000 manufactured vehicles.
In a March 13 letter to congressional leaders, the 36 energy companies asked Congress to maintain the EV tax credit in its fiscal year 2018 omnibus spending legislation and eliminate the existing cap in order to accelerate the adoption of EVs and “boost our economic and national security.”
“First-mover companies — all American manufacturers — are all likely to hit the existing 200,000 vehicle-per-manufacturer cap this year, just as a new generation of affordable, state-of-the art EVs hits the market,” the letter says. “These automakers created thousands of American EV jobs by making early investments in EV research and development, manufacturing capacity and charging infrastructure.”
Utilities want a 200,000-vehicle cap removed from an EV tax credit | emotorwerks
Signatories to the letter include American Electric Power, Consolidated Edison, Duke Energy, Edison International, Florida Power & Light, Long Island Power Authority, National Grid, NV Energy, Pacific Gas and Electric, Public Service Enterprise Group, Seattle City Light and National Grid.
The utilities said they “look forward” to a time when EVs can support grid resources, help integrate intermittent renewable generation and provide demand response. Eliminating the cap would provide certainty to automakers and consumers, and support jobs, the utilities said.
Section 30D of the Internal Revenue Service code provides a credit of up to $7,500 for EVs. It was originally included in the Energy Improvement and Extension Act of 2008 and was amended in the American Recovery and Reinvestment Act of 2009. The credit begins to phase out when at least 200,000 EVs have been sold for use in the U.S.
Two years ago, SPP said a staff wind-integration study had found the RTO could “reliably handle” wind penetration levels of up to 60% of load with a few operational modifications. (See Study: 60% Wind Penetration Possible in SPP.)
On Friday morning, it happened. At 3:45 a.m. March 16, wind accounted for 13,928.94 MW of the system’s total load of 22,998.71 MW, a penetration level of 60.56%.
SPP said the record was among nearly a dozen it has set in the previous 90 days. Last year, it became the first North American RTO to exceed wind penetration levels of greater than 50%. Wind penetration reached as high as 56.25% in December, when SPP set its record for wind demand at 15.7 GW.
| SPP
The RTO has added almost 12.5 GW of wind capacity since 2010, giving it 17.75 GW of installed wind. With the addition of another 5.3 GW that have interconnection agreements but are not yet in service, SPP’s wind capacity will exceed its minimum load of 20.42 GW. Another 35 GW of wind capacity is under various stages of review in the generator interconnection queue.
“We are continuously evaluating the development of generation resources in our footprint to ensure a safe and reliable operation,” said Bruce Rew, SPP’s vice president of operations. “As additional generation is constructed, we will compare those impacts to our forward-looking studies to ensure a reliable grid.”
At the time of the 2015 wind integration study, SPP’s wind penetration levels were approaching 39% and its record wind peak was 9,948 MW. The report recommended installing voltage reactive support capabilities for existing wind farms; enhanced operations tools to monitor real-time voltage stability limits; allowing the reliability coordinator additional flexibility in redispatching; and new planning criteria for and evaluation of phasor measurement units to provide real-time situational awareness.
Rew said the RTO has improved its wind forecasting capabilities and made “numerous” changes since 2015 through its market and reliability coordination processes.
FERC last week affirmed an initial decision approving how Entergy has equalized production costs among its operating companies, batting away several grievances raised by Louisiana regulators.
The commission affirmed three findings from an administrative law judge’s 2016 ruling on the company’s bandwidth payments (EL10-65-005), determining that Entergy:
Properly accounted for the 9.3% interest sale and leaseback of the Waterford 3 nuclear plant near New Orleans in its accumulated deferred income taxes when it characterized the sale as financing and excluded it from bandwidth formula payments;
Can keep interruptible load in its system monthly coincident peaks used to develop the 2010 and 2011 bandwidth calculations, although all other years of Entergy’s bandwidth payments exclude interruptible load; and
Appropriately accounted for the costs of the allowance for funds used during construction (AFUDC) for the River Bend nuclear plant north of Baton Rouge in bandwidth payment calculations.
The allocation of 2007-2015 production costs among Entergy’s half dozen operating companies under its multistate system agreement has been a source of disagreement for a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.
River Bend plant | Entergy
In a 2010 filing with FERC, the Louisiana Public Service Commission contended that Entergy’s bandwidth payment calculation suffered from several inconsistencies. Among its complaints: 1) The formula needed to include the company’s Waterford 3 sale and leaseback account as production costs, and 2) the demand responsibility factor for allocating fixed costs and the reserve equalization cost credit for interruptible load used to calculate 2010-2011 bandwidth payments was incorrect and warranted refunds. The PSC also said the bandwidth formula should include certain River Bend plant-related costs excluded from Entergy’s total production costs, arguing that the company should not have treated the plant’s AFUDC as a regulatory asset and liability, even though it was apparently ordered to do so in a 1991 order (U-17282).
However, FERC said accumulated deferred income taxes associated with Waterford 3 are not “properly includable for commission cost-of-service purposes.” The commission also determined that Entergy in 1991 did not have the requisite data to make accounting changes for the River Bend AFUDC, and that the company had correctly accounted for AFUDC in regulatory asset and liability accounts by recording it in plant-in-service accounts.
“We are in no position to speculate on the Louisiana commission’s intentions,” FERC said of whether the Louisiana PSC actually meant for Entergy to create the regulatory asset and liability nearly 30 years ago.
FERC also said it already resolved the interruptible load issue in a 2012 order that required Entergy to remove all of it from its cost allocation in response to the Louisiana commission’s 2007 complaint (EL07-52-001). “No further relief is available in this separate proceeding,” FERC said.
The commission also agreed with the judge’s position that it had “already ruled on the interruptible load issue and provided relief to the maximum extent possible when it prescribed refunds for the refund effective period from April 3, 2007, through July 3, 2008, and prospectively from May 7, 2012.” The administrative law judge in 2016 said the appropriate time for the Louisiana PSC to “have asked for extraordinary relief beyond the 15-month refund period” would have been in 2012.
ALBANY, N.Y. — With the cost of energy storage declining worldwide, New York plans to ride the wave of the technology to a cleaner energy future, targeting deployment of 1,500 MW by 2025.
Participants heard that and more at the Capture the Energy 2018 conference on Wednesday, hosted by the New York Battery and Energy Storage Technology (NY-BEST) Consortium.
William Acker, executive director of NY-BEST, said three key factors are driving the use of energy storage.
“We talk about increasing the efficiency of the grid, about reducing peak load and serving as a peaking facility for the grid,” Acker said. “We talk about increasing renewables.”
And the “linchpin,” according to Acker: resilience.
“We were over at National Grid yesterday and we were talking about resilience, that resilience means something different from reliability,” Acker said. “Reliability is how well you do on typical operating days; resilience is how well you do in the face of adversity. Winston Churchill had resilience. It’s how well you do when you’re facing the storms.”
New York Public Service Commission Chair John Rhodes, whom the governor tapped to lead his energy storage initiative, said the state’s Reforming the Energy Vision “can be an awesomely complex interweaving of multiple proceedings, but it’s kind of a complicated machine that’s trying to do something simple.”
“It’s good to keep in mind what that simple thing is: arrive at an energy system that is cleaner, that’s more affordable, that’s more resilient, that’s always reliable,” Rhodes said. “Basically, the energy system that’s right and necessary for New Yorkers.”
He said the grid contains latent value that is not currently being captured or monetized. A natural approach to remedying that shortcoming would be to reveal and reward that value, whether it relates to carbon reduction, location, firming and time-based capabilities, or the provision of system-level services.
Rhodes also emphasized the benefits of markets at scale.
“We know that when markets get big, costs come down, innovative companies find different ways to persuade different kinds of customers with a different kind of proposition appealing to their different motivations,” Rhodes said. “We want that. We don’t want one-offs. If we’re doing things, we’d rather see first-of-a-kind innovations than one-of-a-kind innovations.
“As a regulator, and as a contributor to this agenda, we’re obviously trying to encourage more innovation and more investment — other people’s money,” he said. “And we’re obviously going to try to do that as smartly as possible. We are going to as much as possible stay in the mode of being solution-agnostic. We want to specify the problem and have the world come up with solutions, harvest the benefits of competition, pick the best and set the others aside.”
Rhodes said the preliminary results of a storage study New York is developing already indicate that the lifetime benefits of the state’s 1,500 MW by 2025 storage goal “completely and clearly” exceed costs.
“And they also reveal that God wants storage to be in Zones J and K [New York City and Long Island]. Amazingly, it’s confirming what everybody expected,” Rhodes said.
Yayoi Sekine, a Bloomberg energy analyst, spoke about the decreasing cost of lithium-ion batteries and the increasing penetration of electric vehicles in the automobile market. She predicted the cost of the batteries will drop from the current $209/kWh to $70/kWh by 2030, and that EVs will make up one-third of all motor vehicles by 2040.
The world has moved from a scenario in which the people talking about EVs “seemed kind of crazy” to one in which more than 1 million EVs were sold last year, with major automakers moving into the market, Sekine said.
Joe Martens, director of the New York Offshore Wind Alliance, detailed some of the “stunning” developments in offshore wind mentioned by Rhodes.
Wind farms are growing in scale along with the size of wind turbines, Martens said, noting that General Electric this month announced the development of the largest-ever offshore wind turbine, a 12-MW giant standing 853 feet tall.
“New York is off to a very good start,” Martens said, noting that the state has set a goal of 2.5 GW of offshore wind by 2030 and issued a master plan for the industry, while the Long Island Power Authority last year signed a contract with Deepwater Wind for 90 MW of wind power from what will be the largest offshore wind farm in the U.S. when it becomes operational in 2022.
Also last year, the New York State Energy Research and Development Authority recommended that the U.S. Bureau of Ocean Energy Management establish at least four new wind energy areas off the state’s coast, each capable of siting a minimum of 800 MW of generation, Martens said.
LM Wind Power transports a 241-foot turbine blade it made for GE in Spain. | GE
“There is cause for optimism” regarding the prospects of combining storage with offshore wind projects in New York, Martens said. The Massachusetts offshore wind solicitation in December provided one hopeful sign, with two out of three bidders pairing storage with their generation plans. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Martens also mentioned Statoil’s recent bid to combine offshore wind with storage off the coast of Scotland. “The purpose of that was to teach the battery when to hold back and store electricity and when to send power to the grid, which is obviously the Holy Grail of trying to figure out how to maximize profits,” he said.
SACRAMENTO, Calif. — CAISO officials on Wednesday urged California lawmakers to pass legislation that would convert the grid operator into an RTO, saying a regionalized grid would benefit the state.
CAISO executives told Assembly Utilities and Energy Committee Chairman Chris Holden (D) that they support his regionalization bill (AB 813), which represents a third attempt to regionalize the ISO. The bill is getting opposition from some quarters.
“A regional grid will be good for California,” CAISO Director of Regional Integration Phil Pettingill told the committee. He said a “major evolution” is occurring in the West, with utilities looking for ways to procure more renewables, in alignment with California’s goals.
Mark Rothleder, CAISO vice president of market quality and renewable integration, pointed out that the West is an interconnected system with 38 balancing authority areas. He said the state’s goal of generating 50% of its electricity with renewables by 2030 is achievable but faces challenges dealing with the “duck curve” load shape of California energy demand.
The curve shows that the state’s load dips in the middle of the day as solar resources increase output, then ramps up steeply in the evening as the sun sets. The steep ramps require CAISO to lean on fast-ramping generation to meet evening demand, which regionalization supporters say could be tapped more easily from inland renewables under a regional grid. The arrangement would also allow California to export more of its surplus solar during the day.
State Assemblyman Bill Quirk (D) acknowledged there are reservations across the region about “getting in bed with the 800-pound gorilla we call California.” But despite the misgivings and the complications, “I am convinced we can come up with a fair way of doing this.”
Quirk recently proposed separate legislation on the committee’s April 4 agenda that would require California utilities to procure power from gas-fired plants that cannot make sufficient profit in CAISO markets.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said regionalization would help lower California’s costs for reaching its carbon reduction goals.
“The rest of the West isn’t going to decarbonize because California tells them to, but they will buy cheap electrons,” he said. He said California will continue to have control over its resource decisions, CO2 policy, generation siting, and retail rates and programs.
“All of those things you do today, you can continue to do in the future, and that is important to recognize,” he said.
But Matt Freedman, attorney for The Utility Reform Network, warned that regionalization could force California to conform to policies of the Trump administration, which he said is hostile to the state and its clean energy goals. He also suggested that FERC would exert more control over the new RTO, and that “this is not your father’s FERC.”
Holden is taking a cautious tack on the regionalization effort, saying the hearing was “an opportunity to look at the contours of AB 813.” He added that he is trying to make the process as transparent as possible after the regionalization skeptics raised many issues during last year’s effort, including concerns by labor groups about the exporting of energy-related jobs.
“We recognized that an issue of this magnitude required a little more conversation on a broader scale,” Holden said.
As of Thursday, AB 813 was not listed on the agenda for the committee’s April 4 hearing.
WASHINGTON — FERC on Thursday ordered 48 electric utilities to revise their transmission rates to reflect the recently enacted Tax Cuts and Jobs Act, which reduced the corporate income tax rate from 35% to 21%.
The utilities required to file changes — which include Portland General Electric, West Penn Power, New York State Electric and Gas, NorthWestern Corp. and Pacific Gas and Electric — all include a fixed line item of 35% in their transmission tariffs. Most utilities use formula rates that include an annually adjusted input for their tax payments, so they do not need to file any changes, FERC staff said at the commission’s monthly open meeting.
FERC issued its directive in two separate, nearly identical orders: one in which the full commission participated, and the other in which Chairman Kevin McIntyre recused himself. The latter order is addressed to 15 utilities, including several American Electric Power subsidiaries, Baltimore Gas and Electric, Black Hills Power, San Diego Gas & Electric and UNS Electric.
Most of the utilities in the orders have their own docket; the commission grouped three FirstEnergy subsidiaries into one docket and two NV Energy subsidiaries into another.
The utilities are required to file their changes, or show why they should not be required to, within 60 days of the dates of the orders.
FERC also granted two requests to lower transmission rates to reflect the new law: one from Public Service Company of Colorado (ER18-840) and another from multiple MISO transmission owners, including Ameren Illinois, ITC Midwest, Montana-Dakota Utilities and Northern Indiana Public Service Co. (ER18-783).
MLPs, Gas Pipeline NOPR
The commission also issued a revised policy to no longer permit master limited partnerships (MLPs) to recover an income tax allowance in their costs of service (PL17-1).
In its 2016 ruling in United Airlines v. FERC, the D.C, Circuit Court of Appeals found the commission had failed to demonstrate that MLPs were not double recovering when they receive both an income tax allowance and a return on equity based on the discounted cash flow methodology, remanding the case back to FERC.
Reflecting its new policy, FERC issued an order on the remanded case, denying SFPP, a Kinder Morgan subsidiary, an income tax allowance for its West Line, a 515-mile oil pipeline that runs from the Los Angeles Basin to Phoenix, Ariz. (IS08-390).
Shortly after the commission issued its orders, shares for multiple MLPs took a sharp downturn, news outlets reported.
FERC’s revised policy statement also directed oil pipeline MLPs to reflect the elimination of income tax allowance in their Form No. 6 filings, which the commission will use in its 2020 review of the oil index pipeline level.
For natural gas pipelines, FERC issued a Notice of Proposed Rulemaking that would require them to make a one-time informational filing to allow the commission to evaluate whether their rates are just and reasonable under the new tax law and its new policy statement (RM18-11). However, gas pipelines would also be able to simply file reduced rates.
Notice of Inquiry
FERC also opened a broad inquiry into the effects of the tax law on all the industries it regulates (RM18-12).
Commissioners and staff said they were particularly interested in accumulated deferred income taxes — money that companies collect from ratepayers in anticipation of paying income tax — and bonus depreciation, a tax incentive that allows companies to immediately deduct the purchase of certain business properties.
Comments on the Notice of Inquiry are due 60 days after its publication in the Federal Register.
Democratic FERC Commissioners Cheryl LaFleur and Richard Glick have split with the Republican majority over its refusal to consider greenhouse gas emissions in two pipeline orders, the first skirmishes in what may be an escalating debate before the commission and in the courts.
The split came first in Wednesday’s order on remand confirming as in the public interest the 685-mile Southeast Market Pipelines Project, which will supply four gas-fired generators in Florida (CP14-554, et al.).
In August, a split D.C. Circuit Court of Appeals panel remanded FERC’s February 2016 approval of the pipeline, ruling 2-1 that FERC must consider the impact of greenhouse gas emissions when licensing gas pipelines (16-1329). (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
The court ruled in favor of a petition by the Sierra Club, ordering FERC to quantify and consider the project’s downstream GHG emissions or explain why it could not do so. The court also directed the commission to explain whether it still adheres to its prior position that the social cost of carbon tool is not useful in performing its review under the National Energy Policy Act.
Glick opposed the pipeline in Wednesday’s vote. LaFleur — the only current commissioner who took part in the 2016 order — supported the approval along with the three Republican commissioners but issued a partial dissent.
FERC’s ruling affects the Southeast Market Pipelines Project, including the nearly 500-mile Sabal Trail pipeline between Alabama and Florida | Sabal Trail Transmission
The project involves three pipelines, including the nearly 500-mile Sabal Trail, which will connect the other two pipelines between Tallapoosa County, Ala., and Osceola County, Fla., south of Orlando. Scheduled for completion in 2021, the project has a capacity of more than 1 Bcfd. It will supply two new plants — Florida Power & Light’s Okeechobee Clean Energy Center and Duke Energy’s Citrus County Combined Cycle Plant — and FPL’s existing Martin County Power Plant and Riviera Beach Clean Energy Center.
LaFleur: ‘Causal Relationship’
LaFleur said she agreed with the court that the downstream GHG emissions that result from burning gas transported by the pipelines are an indirect impact of the project and that those emissions are “reasonably foreseeable.”
The final Supplemental Environmental Impact Statement (SEIS) estimates that the project will indirectly result in annual gross downstream GHG emissions of 14.5 million metric tons of carbon dioxide-equivalent units (CO2e). Reflecting the reductions in GHG emissions that will occur as the gas-fired generators replace coal-fired units and displace oil as an alternate fuel, the SEIS calculated annual net downstream GHG emissions of 8.36 million metric tons CO2e. (See table.)
| FERC
The majority contended that the emissions data cannot “meaningfully inform” the commission’s public interest determination.
“We are required by NEPA to reach a determination regarding the significance of all environmental impacts, including downstream GHG emissions. It is our responsibility to use the best information we have to make that determination,” LaFleur said. “In this case, we can gauge significance by comparing the gross and net GHG emissions of the SMP Project to the total state and national emission inventories to calculate how the SMP Project increases those GHG inventories,” she continued. “Here, I believe that a net increase of 3.6% of the Florida inventory for a single pipeline project is significant. Due to the need of the project, I believe that increase is acceptable but should be disclosed and assessed.”
LaFleur also parted with the majority view that the social cost of carbon is not an appropriate tool for evaluating the impact of GHG emissions. “That is precisely the use for which the social cost of carbon was developed — it is a scientifically derived tool to translate tonnage of carbon dioxide or other GHGs to the cost of long-term climate harm.”
She said concerns over the lack of consensus on the appropriate discount rate could be addressed by calculating it using a range of rates.
LaFleur said the commission should conduct a detailed cost-benefit analysis of the project, “including more information on the need for a project, the likely end-uses of the transported gas and the alternatives.” She said she would press the issue in the “generic” pipeline review proceeding announced by Chairman Kevin McIntyre in December. (See FERC to Review Gas Pipeline Approval Process.)
Glick: ‘Willful Ignorance’
Glick said the order failed to properly address either of the two issues raised by the court “and, as such, does not adequately respond to the court’s mandate.”
“Climate change is the single most significant threat to humanity, fundamentally threatening our environment, economy, national security and human health. It is difficult to understand how NEPA’s demand that an agency take a ‘hard look’ at the environmental impacts of its actions can be satisfied if the impacts of GHG emissions are ignored,” he wrote.
Glick said the commission “is engaging in a collateral attack on the court’s decision by suggesting that it is not the commission’s ‘job’ to consider whether emissions from ‘the end use of the gas would be too harmful to the environment.’
“It is absurd to even contemplate NEPA not applying to the most significant environmental issue of our time,” Glick continued.
He said the commission’s “willful ignorance of readily available analytical tools” undermines public confidence in its consideration of pipeline applications. “I fear that today’s order, by limiting analysis of the environmental impacts of a proposed pipeline, will both increase the commission’s litigation risk and contribute further to the cynicism of the pipeline siting process.”
Previous D.C. Circuit rulings had found that FERC did not have to consider the climate-change effects of exporting natural gas in its licensing of LNG terminals. If the circuit court again rejects FERC’s Southeast Markets order, it could be up to the Supreme Court to settle the inconsistency.
Majority’s Comments
The majority said its staff “had no basis for determining the significance of impacts from these emissions” because “there is no widely accepted standard to ascribe significance to a given rate or volume of GHG emissions.”
“There are no conditions the commission can impose on the construction of jurisdictional facilities that will affect the end-use-related GHG emissions,” the majority continued. “The only way for the commission to reflect consideration of the downstream emissions in its decision-making would be, as the court observed, to deny the certificate. However, were we to deny a pipeline certificate on the basis of impacts stemming from the end use of the gas transported, that decision would rest on a finding not ‘that the pipeline would be too harmful to the environment,’ but rather that the end use of the gas would be too harmful to the environment. The commission believes that it is for Congress or the executive branch to decide national policy on the use of natural gas and that the commission’s job is to review applications before it on a case-by-case basis.”
The commission said the social cost of carbon tool is more appropriate for regulators whose responsibilities are tied more directly to fossil fuel production or consumption, such as the Bureau of Land Management and the Bureau of Ocean Energy Management.
It noted that the Council on Environmental Quality does not require agencies to conduct a monetary cost-benefit analysis for NEPA review.
The majority also rejected as outside the scope of the SEIS and the court’s mandate issues regarding GHG emissions from upstream production of natural gas, environmental justice and the project’s effect on the supply and demand for natural gas and substitute energy sources.
Second Pipeline Dissent
Glick and LaFleur also dissented in part Thursday on an order granting a certificate of public convenience and necessity to DTE Midstream’s proposed 14-mile Birdsboro Pipeline, which will supply up to 79,000 dekatherms per day of firm transportation service to the 450-MW Birdsboro Power Facility in Berks County, Pa. (CP17-409).
As in the Southeast Market order, LaFleur and Glick dissented over the commission’s refusal to use the social cost of carbon to consider the significance of the project’s environmental impacts.
They also cited concerns over the commission’s “‘new policy’ approach towards motions to intervene out of time,” articulated in a Feb. 27 order involving Tennessee Gas Pipeline (CP16-4-001).
“Today’s order suggests that good cause for late intervention does not exist where an entity seeking to participate as a party in the proceeding submits a motion on the same day it learned that the application had been submitted,” they wrote in their DTE Midstream dissent. “While we agree that late interventions should be limited to parties that demonstrate good cause, we are concerned by the potential consequences of the commission’s pronouncement, particularly as it would apply to landowners and community organizations that lack sufficient resources to keep up with every docket.”
Dissent in Hydro Case
LaFleur and Glick also joined in a partial dissent in a case involving two small U.S. Army Corps of Engineers hydropower projects in West Virginia: the 5-MW Morgantown Lock and Dam and 6-MW Opekiska Lock and Dam (P-13753-003, P-13762-003).
The majority denied rehearing requests of staff’s Sept. 29, 2017, orders authorizing the dams on the Monongahela River, upholding staff’s determination that the West Virginia Department of Environmental Protection waived its Clean Water Action Section 401 water quality certification authority by failing to act on the licensee’s applications within one year of receipt.
LaFleur and Glick said that although the state missed its deadline, they would have included the state’s “modest requests to enhance recreational use of the project lands” — including a permanent public restroom instead of a portable restroom, trash receptacles and fishing piers — which were not opposed by the Army Corps.
“It is commission practice to consider incorporating the late-filed conditions into the license as recommendations … as long as they do not interfere with the licensee’s safe and effective operation of the hydroelectric facility for electric generation,” they wrote.
