FERC last week rejected Big Rivers Electric’s request for a waiver to keep MISO interconnection rights for one of its coal plants through late 2017.
Big Rivers was seeking to keep its Coleman Station in Kentucky interconnected to MISO’s grid for an additional year after the RTO ended a three-year system support resource agreement for the 433-MW coal plant in September. After that, the company said it would file another interconnection termination waiver request in August 2017 while it decides whether to restart the plant with environmental upgrades or convert it to natural gas. Big Rivers also said it was waiting on a MISO compliance filing regarding the retention and transfer of interconnection rights of a retiring SSR. (See FERC OKs Change to MISO SSR Process.)
Coleman Station | Big Rivers
FERC denied the request on the grounds that projects in MISO’s interconnection queue could be impacted by the waiver and Big Rivers’ stated intent to file a waiver extension would mean the requested waiver would not be limited in scope.
“Because MISO indicates that at least one project in its interconnection queue could be affected by granting this waiver request, we cannot conclude that granting Big Rivers’ request would have no undesirable consequences,” FERC said in its Feb. 3 order (EL17-15).
The commission said Big Rivers’ indecision on whether to restart Coleman “directly contradicts” its claim that it has taken “significant steps” to restore the plant to commercial operation soon. FERC also pointed out that an interconnection rights transfer would not apply to Coleman because it exhausted the maximum 36 months of suspension/SSR designation that MISO allows in a five-year period and could no longer sit idle and stay connected.
Big Rivers had argued that terminating Coleman’s interconnection service would harm regional reliability and increase costs for its members. The cooperative said it spent $6.5 million in 2014 to idle Coleman and spends $2.8 million every year to preserve the plant. FERC said Big Rivers’ expenses are merely to maintain the coal station’s “existing state” and not enough to return it to commercial operation, as the plant would violate EPA’s Mercury Air Toxics Standards and need environmental improvements.
Finally, FERC brushed aside Big Rivers’ arguments that terminating interconnection service would run counter to language in MISO’s generation interconnection agreement. FERC pointed out that Big Rivers never had a generator interconnection agreement with MISO.
After SPP staff and stakeholders presented alternative proposals Wednesday to improve the process in which members are assigned financial credits and obligations for sponsored upgrades, the only consensus was that more time is needed. Eight years of applying the credits incorrectly has complicated the task of trying to properly compensate project sponsors and claw back money from members that owe debts for the upgrades.
“I don’t think there’s a single proposal that addresses everything in the way we want to,” said Kansas City Power and Light’s Denise Buffington, the task force’s chair. “I think we’re going to have to cherry-pick what’s important. Concepts are important, and knowing what concepts would be nonstarters for you would be helpful.
“We don’t have the option of doing nothing,” she said, reminding the task force of its charge from the Board of Directors.
Sunflower Electric Power’s Davis Rooney suggested developing a matrix of the proposals’ elements to gain a better understanding of which pieces will be kept and which will be discarded.
“Are we retaining or not retaining the safe-harbor limit? The wind rule … the highway/byway” transmission-cost allocation rule? he asked. “Some of those questions seem pretty common across the proposals.”
“This has to be a package for us,” countered The Wind Coalition’s Steve Gaw. “Seeping little elements out, agreeing to take this out and that out … that will create a challenge. The idea that you have a set funding stream on capacity upgrades and you will get reimbursed over time … that might have some attractiveness to it.”
Some stakeholders expressed a preference for using transmission congestion rights (TCRs) or incremental long-term TCRs, while others suggested following a staff proposal to create a new schedule under the SPP Tariff. Staff is already digging through FERC orders to see how the RTO might justify Tariff changes, and it is soliciting input from MISO and PJM on how they allocate the cost of upgrades.
Meena Thomas, a senior market economist with the Public Utility Commission of Texas, said the state regulators’ Cost Allocation Working Group would be unlikely to accept any increase in base-plan funding as part of any rule change.
“Based on discussions at the CAWG, they have a concern,” Thomas said.
Staff proposed replacing the Tariff’s Attachment Z2 with a separate Schedule 13. SPP’s Charles Locke said the new schedule’s charges would fund all upgrade sponsors’ credit payments and would apply to all network and point-to-point customers.
“A separate schedule might be cleaner and less complex in both administration and Tariff structure,” Locke said.
He said the charge could either be a regionwide charge or a combination of regionwide and zonal charges. The rate would be revised periodically, he said, possibly through an annual formula update.
Under the Schedule 13 proposal, Locke said, the entire facility cost would not be “simply” rolled into rates, instead being limited by the extent to which the facility is used for transmission service. He said the proposal would address legacy Z2 balances and eliminate directly assigned upgrade costs in the future.
Barraged by questions about his proposal, Locke injected some levity into the discussion. “Just to clear things up, I’m going to throw some calculations on the board,” he said to laughter.
The staff proposal had its supporters. “I’d like to see where Schedule 13 goes,” said the Kansas Power Pool’s Larry Holloway. “[I’d like to know] how material are the dollars that fly around and some idea of how big it is.”
American Electric Power’s Richard Ross proposed an approach he said was “fair, reasonable and efficient.” He focused on sponsored network upgrades, saying the current approach has been to view the projects as “new construction,” but that they should be viewed as economic projects.
Ross suggested continuing to calculate revenue credits for long-term service and regionally funding the costs while eliminating the short-term revenue credit calculations and grossing up other credits by 2%. He said existing sponsorships should be handled the same way.
“The process would eliminate the invoicing and stop the proliferation of new project sponsors and their associated accounting,” Ross said.
Dennis Reed, a recent Westar Energy retiree and now a consultant with his Midwest Regulatory Consulting firm, had his own ideas. He proposed eliminating short-term TSR credits to reduce the number of new upgrade sponsors but leaving the rest of the TSR-upgrade process the same.
Reed suggested creating a 20-year payback schedule for only those generation interconnection (GI) upgrades that create available transfer capability (ATC) and giving ILTCRs for sponsored upgrades, which must still meet the current need test.
“The basic goal is to minimize the work staff has to do,” said Reed, alluding to the processing of short-term service requests, which account for about 2% of all Z2 work.
Reed said his proposal would reduce the number of future upgrade sponsors and give GI customers a guaranteed payment schedule for all upgrades that provide added ATC. It would also lower costs to transmission customers because most upgrades that do not increase ATC — generally for switches and enhanced control systems — are not eligible for payments, he said.
“A builder of a sponsored upgrade will know the possible value of any upgrade it builds,” Reed said.
Xcel Energy released fourth-quarter and year-end earnings results Thursday, beating investors’ expectations for earnings per share by a penny but missing their fourth-quarter revenue forecasts by hundreds of millions of dollars.
Minneapolis-based Xcel said it earned $227.5 million ($0.45/share) during the fourth quarter, up from $209 million ($0.41/share) for the same period last year. Zacks Investment Research’s consensus estimate was 44 cents/share.
At the same time, the company reported fourth-quarter revenue of $2.8 billion, up from $2.65 billion a year ago, but short of the expected $3.5 billion. Xcel laid the blame on warmer-than-expected weather.
Xcel Energy wind farm | Xcel Energy
CEO Ben Fowke called 2016 an “excellent year” in a press release Thursday. During a later conference call with analysts, he said, “I don’t think the quarter is indicative of where we think trends will go. We are seeing good customer growth in Colorado and Minnesota and other jurisdictions.”
Fowke said the company plans to invest $3.5 billion in its “steel-for-fuel” strategy, taking advantage of ample wind resources in Colorado and the Dakotas. Xcel completed its first project, the 200-MW Courtney Wind Farm, as a general contractor in North Dakota last year. Regulatory approval in hand, its 600-MW Rush Creek project in Colorado is expected to go into service in 2018.
Xcel is also adding 1,500 MW of wind in Minnesota through power purchase agreements and another 750 MW through “self-build” proposals, in which as owners, the company will benefit from 100% of the production tax credit and “maximize the fuel savings” for customers. Fowke said the company has received 95 proposals from 17 bidders for almost 10,000 MW wind generation and will soon file for regulatory approval.
The company is embroiled in a regulatory and legislative tug-of-war in Minnesota over plans to retire two 680-MW coal units by 2026 at its Sherco plant northwest of Minneapolis. The Minnesota Public Utilities Commission in January opened a docket over Xcel’s plans to build a 780-MW combined cycle natural gas unit as a replacement, but a state legislator has since filed a bill that would give the company authority to construct, own and operate the unit without obtaining PUC approval.
Sherco Generating Station | Xcel Energy
“The bill was driven by legislators who are concerned about the loss of jobs and tax revenue and wanted to expedite the decision process,” Fowke said. “It’s important to note we have provided extensive justification for the plant, and the commission will still need to approve cost recovery.”
Fowke said any capital investment for the project, expected to cost more than $1 billion, “will likely” happen after 2021.
The company raised its dividend by 6.3% to $1.36/share, the 13th straight year it has increased it. Fowke also noted Xcel met or exceeded its earnings guidance for the 12th straight year. Its stock price closed up 83 cents at the end of the week, to $41.45.
Xcel reaffirmed its 2017 earnings guidance of $2.25 to $2.35/share.
DALLAS — SPP’s Regional State Committee last week accepted a working group’s proposal to leave unchanged the criteria used to exempt load-serving entities from transmission project costs in service requests.
The Cost Allocation Working Group recommended that no modifications be made to the thresholds used to determine what project costs should be borne by LSEs making long-term transmission service requests (TSRs). The RSC, composed of 10 regulators from across SPP’s 14-state footprint, accepted the proposal but then directed the CAWG to conduct annual reviews of the aggregate study safe-harbor criteria.
SPP’s aggregate transmission service study process combines all long-term point-to-point and designated network resource requests received during a specified time period into a single study.
The RTO splits the costs of transmission projects between the entire SPP footprint and LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.
The safe harbor exempts LSEs from upgrade costs for a TSR when the aggregate studies’ waiver criteria are met:
Wind generation may not exceed 20% of designated resources.
TSRs must have a minimum five-year term.
Designated resources may not exceed 125% of forecasted load.
Utilities can also apply for an increase in the safe-harbor limit of $180,000/MW.
The CAWG approved the five-year and 125% thresholds unanimously, but it cleared the 20% wind limit by a 6-3 vote. Representatives from the Arkansas, Missouri and New Mexico commissions opposed the motion, while Iowa’s representative abstained.
Adam McKinnie, chief utility economist for the Missouri Public Service Commission and the CAWG’s chair, said he wanted to address wind energy’s operational issues in other ways than by determining who pays for which transmission projects.
“We felt something should be done, but I didn’t see this particular criteria as being the right tool for the job,” McKinnie said.
“Our state utilities had a lot of input to me on this,” said the Nebraska Power Review Board’s John Krajewski. “While I’m sympathetic and I understand the desire to eliminate this threshold, there are a lot of concerns with regard to the operations of thermal units and [SPP’s ability] to send proper signals to thermal units.”
Krajewski said the safe-harbor limits don’t prevent LSEs from adding wind above the 20% threshold. “If you exceed the threshold, then you would simply have to pay for any necessary transmission improvements,” he said.
McKinnie said the CAWG would next review and discuss the safe-harbor limit.
12% Planning Reserve Margin OK’d
The RSC also unanimously endorsed the Supply Adequacy Working Group’s recommendation to replace SPP’s capacity margin terminology with a 12% planning reserve margin requirement.
The revision request (RTWG-RR 187) was approved by the Markets and Operations Policy Committee in January. It incorporates previously approved policies that identify who is responsible for resource adequacy, the resource adequacy requirement and how and when the requirement should be met. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
The committee also made several personnel moves. RSC Chair Steve Stoll, a commissioner with the Missouri PSC, announced Commissioner Kim O’Guinn (Arkansas Public Service Commission) and Board Member Dennis Grennan (Nebraska PRB) have been added to the Regional Allocation Review Task Force to fill their states’ seats.
Committee members unanimously agreed to establish a nominating committee for future RSC elections and to work out the details during their annual retreat in July.
CMS Energy reported that 2016 was its best year for generation reliability ever, as it retired more than half of its coal-fired facilities and announced plans to terminate a nuclear plant power purchase agreement.
The Michigan-based company last year retired seven of its 12 coal-fired generation units, representing about 1,000 MW.
Palisades Nuclear Plant | Palisades Power
“Delivering operational success like this while at the same time transitioning our fleet so significantly requires a disciplined team,” CEO Patti Poppe said during a Feb. 2 earnings call.
The company boosted earnings for the year to $551 million ($1.98/share) from $523 million ($1.89/share) in 2015, although fourth-quarter earnings dropped to $77 million ($0.28/share) from $106 million ($0.38/share) a year earlier.
CMS plans to spend $18 billion over the next 10 years in capital expenses: $8 billion on gas infrastructure and maintenance; $4 billion on maintaining and building generation, including renewables; and $6 billion to upgrade its electric distribution. The company said it could spend an additional $3 billion on improving gas infrastructure, grid modernization, additional renewables and replacement of PPAs. Rate increases to pay for the capital improvements will be limited to 2%, CFO Tom Webb said.
Poppe said CMS will improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. (See Entergy, Consumers Announce Closure of Palisades Nuke.) According to CMS, the plan will save customers $172 million over four years.
Poppe said the substitute capacity plan for the Palisades PPA is “solid” and replaces a “single, big-bet capital project for many smaller options” with less risk. She said CMS could make more PPA replacements in the future by building new plants.
“We’ve long said that an inflexible, above-market PPA is not a cost-effective option for our customers and provides no long-term value for our investors. At the same time, we want to assure that we have sufficient resources to serve the load in Michigan,” Poppe said.
While year-over-year net income climbed about $300 million thanks to its Integrys acquisition, WEC Energy Group’s fourth-quarter earnings call focused largely on the company’s natural gas initiatives.
WEC reported net income of $194.4 million ($0.61/share) for the fourth quarter of 2016 compared to $179.3 million ($0.57/share) in fourth quarter 2015. Net income for the year was $939 million ($2.96/share) compared with $638.5 million ($2.34/share) for 2015, CEO Allen Leverett said during a Feb. 1 conference call. (See WEC Energy Shows $183M Profit After Integrys Deal.)
Leverett would not say whether the company plans to file a rate case with the Wisconsin Public Service Commission this year, saying only that its 2017 strategy is to keep rates flat while managing costs.
WEC projects 2017 earnings per share of $3.06 to $3.12, assuming normal weather. The company plans to continue its focus on natural gas distribution systems and infrastructure improvements.
The company signed an agreement Jan. 30 to acquire Michigan-based Blue Water Gas Holdings for $230 million. Blue Water, which owns an underground natural gas storage facility in Michigan, could provide up to one-third of the storage needs of WEC’s three gas distribution companies in Wisconsin through long-term service agreements as a subsidiary.
Leverett said WEC would file with the Wisconsin PSC for approval of service agreements for the storage. Leverett said the company chose the service agreements structure so the commission would not have to approve an out-of-state acquisition and WEC’s state-regulated companies would not be directly involved in an interstate natural gas business.
“I believe this investment will bring very meaningful customer benefits,” Leverett said, adding that there “certainly is room” for WEC’s own storage projects in the future.
UMERC Seeks OK for 2 Generators
New subsidiary Upper Michigan Energy Resources Corp. (UMERC) filed with the Michigan Public Service Commission on Jan. 30 to build two natural gas generating stations in Michigan’s Upper Peninsula. (See Michigan Upper Peninsula Getting its Own Utility.)
UMERC plans to pay about $275 million to build 180 MW of natural gas generation in two Upper Peninsula counties. If approved by the Michigan commission and MISO, construction will begin late this year or early in 2018.
“We are targeting commercial operation in 2019. At that time or soon after, we expect to be in a position to retire our coal-fired Presque Isle power plant. This should give significant savings in operations and maintenance expenses as well as reduce carbon emissions,” Leverett said.
Presque Isle Power Plant | WEPCo
WEC’s five-year capital spending plan has increased from $9.2 billion to $9.7 billion with the spending on natural gas storage and Upper Michigan’s new gas generation. Leverett said the revised plan does not include $1.7 billion of capital investments in subsidiary American Transmission Co.
On Jan. 30, ATC’s development company and Arizona Electric Power Cooperative entered a joint operating agreement to create ATC Southwest. The new transmission company will develop transmission projects in Arizona, California and other parts of the Southwest. “The largest opportunities outside of the footprint are in the West,” Leverett said.
ATC’s return on equity is still in flux, Leverett reminded shareholders. In September, FERC approved a 10.32% base ROE for MISO transmission owners. (See FERC Cuts MISO Transmission Owners’ ROE to 10.32%.) ATC qualifies for a 50-basis-point adder and is currently recognizing a 10.82% ROE. However, in another pending docket, the same FERC administrative law judge who first lowered the return said MISO TOs’ ROE should be lowered further to 9.7% (EL15-45). With adder points, the decision could bring ATC’s ROE to 10.2%. Leverett said he expects an order by the end of June even with former FERC Chairman Norman Bay’s resignation and the current lack of a commission quorum.
In a victory for wind energy advocates, FERC last week rejected SPP’s proposed method for measuring generators’ reactive power, saying it said would result in excessive and unnecessary costs (ER17-107).
The commission rejected the RTO’s October compliance filing in response to Order 827, which revised the pro forma large and small generator interconnection agreements to add reactive power requirements for all newly interconnecting nonsynchronous generators.
Smoky Hills Wind Farm in Kansas
Although the order required grid operators to ensure compliance by measuring reactive power at the “high-side” of the generator substation, SPP sought an “independent entity variation” allowing it to conduct measurements at the point of interconnection.
SPP said the variation was justified because its transmission system is dispersed over a wide geographic area and that many interconnection customers use longer generator lead lines to the point of interconnection to reach optimal parts of the transmission system.
The RTO said that measurements at the generator substation will not reflect “the charging or impedance” on the generator lead lines between that substation and the interconnection, creating a risk of excessive high and low voltages on the transmission system. SPP said that reliability standards would require the installation of reactive power compensation devices, at additional cost to transmission customers.
The proposal brought protests from several renewable generators and the American Wind Energy Association, which said the commission had considered the potential for long generator lead lines in their deliberations on Order 827. They also said SPP was not unique in having high-voltage nonsynchronous generator lead lines of 20 miles or longer.
The commission agreed, noting that Order 827 found that “requiring fully dynamic reactive power capability at the point of interconnection may result in significantly increased costs for nonsynchronous generators.”
Although setting reactive power requirements at the point of interconnection “would provide the greatest amount of reactive power to the transmission system,” the commission said, “the costs associated with providing that level of reactive power do not justify the added benefit to the transmission system.”
“In Order No. 827, the commission carefully considered the appropriate point at which to measure reactive power and ultimately found that ‘measuring the reactive power requirements at the high-side of the generator substation reasonably balances the need for reactive power for the transmission system with the costs to nonsynchronous generators of providing reactive power.’”
FERC also said SPP was not unique in its geography and had failed to provide information to support its reliability concerns. “Like SPP, other ISOs/RTOs have nonsynchronous generation interconnecting with the generator terminals located a significant distance from their point of interconnection. Similarly, SPP faces the same growing penetration of nonsynchronous generators as other ISOs/RTOs that in part resulted in the commission issuing Order No. 827,” the commission said.
It ordered the RTO to submit an additional compliance filing within 30 days.
Preparing for the loss of its quorum, FERC last week issued an order delegating additional authority to staff and approved two massive natural gas pipelines that could have languished for months after former Chairman Norman Bay’s resignation.
The commission granted a certificate of public convenience and necessity (CPCN) on Thursday for the 510-mile Rover Pipeline, which would transport 3.25 million dekatherms/day from eastern Ohio to southern Michigan (CP15-93). On Friday, the commission approved a CPCN for Transcontinental Gas Pipe Line Co.’s Atlantic Sunrise pipeline, which would transport 1.7 million dekatherms/day from Pennsylvania to South Carolina (CP15-138).
The approval of Rover prevented a yearlong delay in construction. Tree-clearing on the project is prohibited between March 31 and Oct. 1 in Michigan, Ohio and Pennsylvania, and between Nov. 15 and March 31 in West Virginia, to protect the endangered Northern Long-eared bat, according to its environmental impact statement.
The commission also approved two smaller pipeline projects late last week:
A 99-mile pipeline proposed by National Fuel Gas Supply and Empire Pipeline to connect McKean County in north-central Pennsylvania to an existing main line in Erie County, N.Y. The project includes an interconnection to the TransCanada system at the Canadian border west of Buffalo. Empire will be able to transport 350,000 dekatherms/day into Ontario (CP15-115).
A 12.9-mile pipeline loop in Wayne and Pike counties in eastern Pennsylvania to serve Tennessee Gas Pipeline’s mainline that runs into New England (CP16-4).
The orders issued by FERC last week, Bay noted, added “more than several billion cubic feet of new gas pipeline capacity.” In all, the commission issued more than 60 orders last week, including issuances on capacity market rules in MISO, NYISO and ISO-NE, financial transmission rights in PJM, the Energy Imbalance Market run by CAISO and SPP’s measurement of reactive power.
In at least two of the orders, Bay issued statements recommending changes in FERC policies, including one criticizing the minimum offer price rule in capacity markets. (See related stories, Bay Calls for Review of Marcellus, Utica Shale Development.)
Loss of Quorum Sparks Fears
Bay resigned effective Feb. 3 after President Trump named Commissioner Cheryl LaFleur as acting chairman.
There were already two vacancies on the commission, so Bay’s departure left FERC with only LaFleur and Commissioner Colette Honorable — one member short of the quorum needed to resolve contested cases, including challenges to infrastructure projects. (See LaFleur Reinstates Morenoff as FERC General Counsel.)
A coalition of 14 energy trade associations representing the oil and gas industry, utilities, hydropower and nuclear interests wrote to Trump on Thursday urging him to fill the vacancies. “The absence of a quorum will leave the agency unable to tackle much of its important work promoting energy infrastructure for the benefit of U.S. energy consumers,” the letter said.
| Matcor
On Wednesday, U.S. Sens. Ed Markey and Elizabeth Warren, both Democrats from Massachusetts, expressed concern that rehearing requests for the recently approved Atlantic Bridge project would go unheeded. (See Atlantic Bridge Project Approved by FERC.) “We request that FERC immediately rescind the order authorizing the Atlantic Bridge pipeline project until such time as the agency has a newly constituted quorum in place that will allow it to hear an appeal of this project,” they wrote.
New Delegation Order
The commission on Friday delegated additional authority to staff to keep some cases moving (AD17-10).
Under the order, effective Feb. 4, Office of Energy Market Regulation (OEMR) Director Jamie Simler or her designee can:
Accept and suspend rate filings, and make them effective subject to refund and further order of the commission, or set them for hearing and settlement judge procedures. For initial rates or rate decreases submitted under Section 205 of the Federal Power Act, for which suspension and refund protection are unavailable, FERC staff has authority under FPA Section 206 to institute proceedings to protect customers’ interests.
Take “appropriate action” on uncontested filings seeking waivers of the terms and conditions of tariffs, rate schedules and service agreements (including waivers related to capacity release and capacity market rules) under the FPA, the Natural Gas Act and the Interstate Commerce Act.
Accept settlements not contested by any party or participant, including commission trial staff.
FERC staff also can extend the time for action on matters when permitted by statute. “By issuing the order today, the commission intends that to ensure that FERC staff has authority to prevent such filings from taking effect by operation of law during the no-quorum period,” the commission said in a statement.
The commission also said it would be guided by the 2012 Anti-Deficiency Act, which allows work to continue during a lapse in appropriations on activities the suspension of which would “imminently threaten the safety of human life or the protection of property.”
That ensures commission staff will continue inspecting and responding to incidents at LNG facilities and jurisdictional hydropower projects, FERC said.
All pre-existing delegations of authority to staff will remain in effect, FERC said. The temporary order will remain in effect until after the confirmation of a third member restores the quorum.
Because FERC commissioners are subject to Senate confirmation, that may not happen for months. Trump, focused in his first few weeks on filling out his cabinet and his Supreme Court pick, has not named any FERC candidates.
WASHINGTON — Environmental activists opposing fracking and pipeline expansions regularly disrupted FERC meetings during Norman Bay’s two-and-a-half-year tenure as a FERC commissioner and chairman. On at least one occasion, activists took their protests to the street outside Bay’s D.C. house.
The activists contended FERC was shirking its responsibility by failing to consider whether the commission’s approvals of interstate natural gas pipelines were resulting in increased emissions. FERC has long insisted that such concerns are beyond its authority, as it doesn’t regulate the production of natural gas — a responsibility held by the states and the Interior Department.
Protestors at Norman Bay’s home | Beyond Extreme Energy
But as it turned out, Bay had some misgivings about the commission’s legalistic reading.
In a five-page statement accompanying the commission’s ruling approving a 99-mile pipeline through Pennsylvania and New York on his last day in office, Bay gave his perspective on the impact of the shale gas revolution, lauding it for helping reduce electricity prices and carbon emissions but expressing concern about methane emissions and the potential for pipeline overcapacity (CP15-115).
Although it is not required to do so by the National Environmental Policy Act, Bay called on the commission to “analyze the environmental effects of increased regional gas production from the Marcellus and Utica” shale regions.
“Despite the growing importance of Marcellus and Utica gas production — it was 22.5 Bcfd in 2016 and is projected to surpass 44 Bcfd by 2050 — the commission has never conducted a comprehensive study of the environmental consequences of increased production from that region,” Bay noted. He said FERC should consider “the downstream impacts of the use of natural gas and … a life-cycle greenhouse gas emissions study.”
“As important as infrastructure development is,” he said, “it must also occur through processes that continue to promote public participation, transparency and confidence.”
Bay also said the commission should consider its reliance on signed agreements with shippers to determine the need for pipelines.
While these “precedent agreements” are useful indicators of need, Bay said the commission should also consider whether capacity is needed to ensure deliverability to power generators, reliability benefits and concerns “that anticipated markets may fail to materialize.”
He noted that LNG import terminals built during the early 2000s became stranded as shale gas largely eliminated the need for imports. “Overbuilding may subject ratepayers to increased costs of shipping gas on legacy systems. If a new pipeline takes customers from a legacy system, the remaining captive customers on the system may pay higher rates,” he said.
Bay — who resigned effective Feb. 3 after President Trump replaced him with Commissioner Cheryl LaFleur as acting chair — also had a parting shot at the minimum offer price rule in capacity markets. (See Bay Blasts MOPR on Way Out the Door.)
New York envisions a future when distribute energy resources can participate in wholesale energy and capacity markets as seamlessly as any conventional generator.
To help get there, NYISO on Thursday released the final version of its DER Roadmap, which seeks to create flexible pathways for distributed energy to participate in markets as the industry moves away from a model based on central power stations. A fall workshop laid out a broad outline of how these resources could optimize the grid. (See NYISO DER Workshop Ponders the Grid of the Future.)
| NYISO Distributed Energy Resources Roadmap
The document released last week provides more specific guidance and includes timelines and interim steps that could lead to implementing dispatchable DER rules in 2021.
“The NYISO’s market enhancements will permit dispatchable DER with various capabilities to participate in the wholesale markets. Integrating DER in this manner will require enhancements to wholesale market design, system planning and grid operations to better align resource investments and performance with system needs and conditions,” the report states.
DER can consist of demand management, power generation, energy storage or different combinations of all three aggregated into a single entity.
“The NYISO’s vison for dispatchable DER also aligns well with Reforming the Energy Vision in that it offers the potential to engage or animate certain consumers in ways that optimize grid utilization while helping these consumers better manage their own energy needs and costs,” Mike DeSocio, senior manager of market design, said at a media briefing Thursday.
| NYISO Distributed Energy Resources Roadmap
Other goals of the roadmap include the integration of DER into the energy, ancillary and capacity markets. “More fully integrating dispatchable DER will provide a means for DER to take advantage of real-time scheduling,” the report said. “It is important for the NYISO’s real-time systems to access and dispatch these resources in response to price signals reflective of grid conditions and needs.”
Improved load forecasts are seen as essential, as supply of distributed resources must be balanced with demand.
The roadmap also seeks ways to align compensation with system performance. The ISO said it intends to develop compensation aligning the flexibility and measured performance of DER with system needs, treating DER comparably with other resources.
Many of the DERs will be connected to the distribution network, unlike traditional generators, which are connected to the bulk transmission grid. The report said to ensure bulk power system reliability, an accurate representation of DER impacts at their interface to the grid is essential.
NYISO said the Roadmap is a starting point for discussions with stakeholders to develop market rules and operational protocols. It is also working with utilities to develop a series of demonstration projects that will require coordination or integration of DERs into the bulk power system.
Xcel Energy released fourth-quarter and year-end earnings results Thursday, beating investors’ expectations for earnings per share by a penny but missing their fourth-quarter revenue forecasts by hundreds of millions of dollars.
