Eleven respondents have submitted proposals for MISO’s Duff-Coleman transmission project, the RTO’s first competitive project under FERC Order 1000.
MISO said Friday that all 11 proposals were judged complete.
“Now that we have finalized our review of the proposals for purposes of completeness, we will begin evaluating the proposals based on the criteria set forth in the MISO Tariff and our Business Practices Manual,” said Priti Patel, MISO North regional executive and executive director of the RTO’s competitive transmission administration.
Ameren Transmission Company of Illinois and PPL TransLink;
Duke-American Transmission Co.;
Edison Transmission;
GridAmerica Holdings;
ITC Midcontinent Development;
Midcontinent MCN, with the Missouri Joint Municipal Electric Utility Commission;
NextEra Energy Transmission Midwest;
Republic Transmission, a subsidiary of LS Power Transmission, with Big Rivers Electric;
Vectren Energy Delivery of Indiana, a unit of Southern Indiana Gas and Electric, and Public Service Enterprise Group;
Transource Energy, a partnership between American Electric Power and Great Plains Energy, with subsidiaries Transource Indiana and Transource Kentucky; and
Xcel Energy Transmission Development.
The request for proposals window on the project opened in January and closed early last month. (See MISO Duff-Coleman RFP Deadline Passes; RTO Reviewing Bids.) The $67.4 million project was approved by the MISO Board of Directors as part of the 2015 MISO Transmission Expansion Plan.
MISO expects to announce its selection no later than Dec. 30. Construction on the pair of substations and the 28.5-mile 345-kV connecting line in Southern Indiana and Western Kentucky is expected to last through 2020, with the line in service by the beginning of 2021.
VALLEY FORGE, Pa. — After PJM’s Craig Glazer started with the food analogies, speakers at Thursday’s Grid 20/20 symposium couldn’t resist serving up a smorgasbord of edible metaphors.
Glazer, vice president of federal government policy, kicked off the conference, “Focus on Public Policy Goals and Market Efficiency,” talking about apples as a stand-in for power. To the laughter of the overflow audience, a slide depicted a grocery store display pricing the fruit to reflect subsidies (49 cents), subject to partial FRR adjustments (58 cents), MOPR’D per PJM rules (60 cents) and cleansed of all subsidies (65 cents).
PJM’s Craig Glazer likened the pricing of apples to MW at Grid 20/20. Image source: PJM
Currently, the recipe for competitive markets doesn’t call for carbon reduction, the preservation of jobs and tax bases, or the retention of uneconomic plants, he said. But these are among the public policy goals that some states are looking to achieve.
“A state could say, ‘Just add my one little ingredient,’” Glazer said. “The result isn’t just the most efficient solution for state A. Everybody gets it. How do we not force it on states B and C, who haven’t authorized us to put that ingredient into the blender?”
Penned amid efforts by money-losing coal-fired generators in Ohio and nuclear generators in Illinois to win state-backed subsidies, the report concluded that PJM’s markets efficiently manage the entry and exit of capacity resources, but they could be hamstrung by policies to protect social, economic or political interests.
The study drew a volley of critical correspondence to the Board of Managers from generators who said it presented a skewed view of the risks and benefits associated with competitive markets as compared with the traditional regulated model. (See Generators Rebut PJM Study on Investment in Competitive Markets.)
The subject incited just as lively of a debate at last week’s forum, which consisted of three panels: defining the problem, discussing traditional responses and studying alternative solutions.
FERC Commissioner Tony Clark, who will be leaving his post next month, delivered the opening remarks. Clark said that integrating public policies into competitive markets has become an increasing challenge for regulators.
“It’s going to be at the core and heart of what FERC is doing over the next several years and what states are going to be doing,” he said. “It’s going to last long past the next six weeks of my tenure, I can guarantee that.”
Although FERC’s job is not “passing philosophical judgement” on state policies, he said, those policies impact the commission’s jurisdiction over wholesale markets.
“We have the responsibility for just and reasonable rates,” he said. “There may be an iterative process where we try to set the boundaries and bumpers around what is permissible and what is not. But it’s not going to be an easy process.”
Even states that share a goal — such as the nine in the Regional Greenhouse Gas Initiative — can have differing ideas of how to reach the objective, said Marc Montalvo, president of Daymark Energy Advisors, who spoke with Glazer on the first panel.
State policies also can have unintended consequences, he said, citing the challenges faced by California and Hawaii, which are chasing ambitious renewable power goals.
“Every last region inside of the country is wrestling with the same issues. We want to make sure we’re doing smart investments, protecting consumers, respecting competitiveness,” he said. “All of us who are working in the markets are trying to figure a way to mix that batter up to make a delicious pancake.”
How Can PJM Markets Change?
The second panel was led by Hung-po Chao, senior director of economics for PJM. Panelists were Independent Market Monitor Joe Bowring; Steve Schleimer, senior vice president of government and regulatory affairs for Calpine; Susan Bruce, an attorney representing the PJM Industrial Customer Coalition; Jim Wilson of Wilson Energy Economics; and Lisa McAlister, deputy general counsel for American Municipal Power.
“The competitive wholesale market was designed to address and ensure reliable supply and an efficient market that includes resource adequacy issues,” Chao started off. “It was not designed to accommodate many other social objectives, like a clean environment. Here the question is: As these policy challenges are upon us, are there things that the PJM electricity markets can change to accommodate positive externalities?”
Playing off of one of Glazer’s analogies, McAlister said that just one kitchen tool — a blender — can’t make every dish.
“Unlike a real competitive market, the current PJM capacity construct is not sufficiently robust to accommodate unforeseen events,” McAlister said. “Adding another tweak to the 24 major adjustments since 2010 will only add another layer of complexity and uncertainty. It is time to look at simpler constructs that would be more resilient in the face of constant change.”
At Thursday’s Markets and Reliability Committee meeting, AMP’s Ed Tatum will be seeking support for an initiative to consider an overhaul of the capacity market. (See related story, Co-ops, Munis Call for Reset of PJM Capacity Model.)
Wilson agreed that changes to the capacity market are needed.
PJM’s changing resource mix is creating a need for flexible capacity, he said. “All of that is valued properly in the energy and ancillary services markets” he said, but not in the capacity market.
Schleimer took a different view, saying that without the capacity market, there would be no independent power producers, and consumers would be shouldering the risk of building generation under state integrated resource plans.
“When you have more apples on hand than you will ever need, costs are always going to be low. You can either have an energy market with scarcity pricing, or you can have a capacity market to allow investors a reasonable opportunity to recover their capital,” he said. “Where do we want to end up 10, 20 years from now? In a world where new investment is only made from rate base?”
“I don’t know if we have a strong view decided on this because it’s such a difficult question and the history of this issue is so important to it,” responded Bruce.
She recalled 1997, when Pennsylvania’s Electricity Generation Choice and Competition Act went into effect. “The ideas of markets and shifting the risk away from customers was something attractive to industrial customers,” she said. “The driver was to reduce cost, reduce risk for customers.”
The Origin of the Markets
Bowring agreed. “The markets have worked very well. You have to remember where restructured markets came from — they’re an alternative to a regime in which public utilities commissions made decisions, many opaque, various policies of many kinds,” he said. “It was a conscious decision to move to markets.”
He said there exist ways aside from subsidies to achieve public policy goals. For example, he said, “If you want to deal with carbon, have a carbon price; don’t subsidize nuclear, have a carbon price.”
“Markets can’t handle the recent attempts to intervene in the market in Ohio on behalf of companies that wanted subsidies in their favor,” Bowring said. “That’s fallen by the wayside for various reasons, but we do need tools to address that type of intervention. We need to continue to react to change. The market has to be flexible, and the market designers have to be flexible.
“The reason we have markets is to provide power to customers at the lowest possible [cost]. We have to be careful not to let other aspects of the debate interfere with that or undermine them. Markets are more fragile than we all think, and they could go away fairly easily.”
Capacity Market at Risk?
The third panel, moderated by Vince Duane, PJM’s senior vice president for law, compliance and external relations, hosted William Berg, vice president of wholesale market development for Exelon; Peter Fuller, vice president of market and regulatory affairs for NRG Energy; Stu Bresler, PJM’s senior vice president of operations and markets; Raymond DePillo, senior director of market development for PSEG Energy Resources and Trade; and John Moore, senior attorney for the Sustainable FERC Project.
Asked if the capacity market is at risk, Bresler said, “I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk. The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”
“Yes, I do think we are putting the capacity market at risk,” DePillo said. “We’re going through what is effectively a fleet transformation. How do we do that in the most effective way possible? We are going to need uneconomic retention,” he said, referring to state initiatives such as New York’s nuclear subsidies.
“The more we attempt to use the capacity market, particularly in isolation, to solve all the blender issues we are facing today, the more distorted it gets,” Berg said.
He advocated a holistic approach. “That starts with an honest conversation about what constitutes a subsidy so onerous it needs to be subject to mitigation,” he said.
For his part, Moore said the Sustainable FERC Project supports a goal of 80% carbon reduction by 2050.
“There are a lot of good state policies that get us a long way that we should protect,” he said. “I wonder if we’re going down the wrong fork in the road adding complexities to the capacity market.”
Bresler introduced an idea for a two-stage capacity auction that would integrate subsidized resources but prevent them from impacting the prices of other generators. Fuller welcomed PJM’s effort to respond to out-of-market state policies but expressed concern that the model would place all of the risk of state policy implementation on resources at the margin, which could defeat the goal of protecting price formation.
The concern, which PJM’s proposal acknowledges, is that resources will bid zero to ensure they clear in stage 1; those that don’t won’t receive any capacity revenue through the second, higher-priced stage, clearing after subsidized units are removed. “It is unclear whether this potential would have any significant impacts on resource offer behavior in the capacity auctions,” PJM said.
Berg wasn’t so sure. “My first thought is if there was ever any doubt that … resources will bid zero, this is it amped up on steroids,” he said.
PJM CEO Andy Ott closed out the session, saying, “I see this issue as fairly large for us.” He added, “It’s no secret that PJM feels strongly about its competitive markets.”
Stakeholders can expect the dialogue to continue, he said.
“Don’t worry,” he reassured the audience. “We’re not going to make a filing tomorrow.”
MISO said it will work to improve the role of the Planning Advisory Committee in interregional matters following complaints that the committee was hearing after the fact about Interregional Planning Stakeholder Advisory Committees (IPSAC) decisions.
Eric Thoms, MISO manager of planning coordination and strategy, said the PAC’s seven voting sectors should decide the RTO’s IPSAC vote on study approvals or whether potential interregional projects should proceed to regional review. However, Thoms said those votes should continue to be conducted at IPSAC meetings.
The MISO-SPP IPSAC’s nonbinding votes — one vote from each RTO — are taken under advisement by the MISO-SPP Joint RTO Planning Committee, a group of RTO staffers that has ultimate say over what interregional issues the RTOs pursue.
For interregional matters involving PJM, the PAC will continue to provide advice and recommendations to MISO planning staff participating in the MISO-PJM Joint Planning Committee. No votes are conducted in the MISO-PJM IPSAC.
To become more proactive, MISO plans to make presentations to the PAC on issues scheduled at subsequent IPSAC meetings. “We need to do our due diligence to get out in front of PAC with a list of issues that we’re going to present,” Thoms told the committee during an Aug. 17 meeting. “We will give you forewarning in person. We need to come in front of you with these topics beforehand.”
Transmission Owners sector representative Cynthia Crane expressed reservations with the PAC’s vote being conducted in the IPSAC where she said a different set of stakeholders are in attendance. She said fewer sector representatives typically attend IPSAC meetings versus the PAC.
“I think you may end up with a different vote. I have some concerns,” Crane said.
PAC Chair Bob McKee agreed with the voting concern. “It’s tough to have this sort of conversation in front of a different body,” he said.
Sean Brady of Wind on the Wires asked for a timeline on what interregional efforts MISO is undertaking, such as scopes, study and approval processes. Thoms said he would take the comments under advisement.
MISO-SPP Coordinated Study Focusing on 5 Interregional Areas in Dakotas
Thoms also said MISO is proposing to look at five needs in its coordinated study with SPP, focusing on potential project spots along its seam with SPP’s Integrated System in North Dakota, South Dakota and Iowa. The study is currently expected to last through April. The final scope discussion is expected at the Sept. 7 joint meeting with SPP.
“Once we identify the needs, we can hit the ground running,” Thoms said.
Adam McKinney of the Missouri Public Service Commission questioned why MISO would embark on this study when it couldn’t approve a single interregional project after the 2015 study. (See “MISO Rethinks Coordinated Study with SPP,” MISO Planning Advisory Committee Briefs.) He likened it to an ill-matched girlfriend and boyfriend getting married. “It’s like if I go on a trip with my girlfriend for three days, and we can’t stand each other, then we decide to get married for five years,” he said.
McKinney also said he didn’t want smaller projects set aside in a quest to identify larger projects only. “I want my smaller problems fixed, and I don’t want them ignored in some big overlay bonanza.”
Thoms said that threshold for conducting regional reviews of projects with SPP is low: a requirement to reduce congestion by 5% or more on either side of the seam.
This newest study will take place as MISO considers making changes to align its study timeline with SPP and scrapping the “triple hurdle” of interregional and separate regional reviews of joint projects. (See MISO, SPP Disagree on 2016 Joint Study.)
Thoms asked for stakeholder feedback on the coordinated study by Aug. 24.
He also told stakeholders that MISO and PJM are working on a cost allocation method for a new project type: targeted market efficiency projects, short-term projects of $20 million or less to relieve congestion. (See MISO, PJM Unveil JOA Process for ‘Targeted’ Market Efficiency Projects.)
Thoms said MISO will report to the PAC once it determines how to split costs within the RTO. “We haven’t quite figured out the cost allocation yet,” Thoms said.
Longer, More Detailed Tx Overlay Study in Works
Citing a changing resource mix, MISO this year has set out a more detailed regional transmission overlay study, which identifies transmission needs and the most efficient solutions.
MISO said the draft scope for the multi-year study will use the three futures developed for MISO’s 2017 Transmission Expansion Plan (MTEP) to “identify regional needs and develop long-term overlay roadmaps.” (See MISO Proposes 3 New MTEP 17 Futures.)
MISO plans to finalize the overlay scope at the Sept. 21 PAC meeting.
The study will result in a list of regional transmission needs by the end of 2017 and identify transmission project candidates in 2018. In 2019, MISO envisions setting up business cases and cost allocations on selected projects.
McKee said the overlay scope resembled the vetting process for the market efficiency project (MEP) and multi-value project (MVP) portfolios.
PAC liaison Jeff Webb said the overlay may fit some of the MEP and MVP criteria as MISO’s changing fleet is driving a more detailed study.
“It’s not something we ought to do every year, but our fleet is changing,” Webb said. “If it looks similar, that’s because it is, but I don’t want to judge it just yet. Let’s see what the analysis shows. … We haven’t done the analysis yet so let’s not get ahead of ourselves.”
$104 Million in MISO South Projects Recommended to Board
MISO’s Market Congestion Planning Study has identified five projects totaling about $185 million to recommend to its Board of Directors.
Arash Ghodsian, of MISO’s economic studies department, said four of the five projects being submitted for recommendation are in MISO South. The four are spread across Arkansas, Mississippi, North Louisiana and Southeast Louisiana, and Ghodsian said none of them meet the 345-kV voltage threshold to become an MEP:
The $7.6 million, 6.5-mile long rebuild of the Trumann–Trumann West 161-kV line in Arkansas comes with a benefit-to-cost ratio of 13.36 and an estimated 2018 in-service date.
The $6.7 million relocation of the existing 500/230-kV Lakeover transformer near Jackson, Miss., has a 1.43 B/C ratio and is estimated to be in service by 2020.
Upgrading the Minden–Sarepta 115-kV terminal equipment in northern Louisiana will cost about $1.9 million with a 1.83 B/C ratio and is estimated by 2020.
The construction of a new 230-kV transmission line and substation south of the existing Ninemile substation in Southeast Louisiana will cost about $88 million and have a B/C ratio ranging from 1.96 to 42 with an in-service date by 2022.
Ghodsian said the projects will be reviewed to see if any should be expedited.
Zheng Zhou, with MISO’s economic studies department, said the RTO also intends to recommend the $81 million Huntley–Wilmarth 345-kV line project from Minnesota to Iowa as an MEP in MISO North. The line, expected to be in service in early 2022, comes with a 2.02 B/C ratio.
Zhou said stakeholders generally supported the Minnesota project.
PAC liaison Jeff Webb said if the projects are approved by the board, they will move into MTEP 16.
MISO says it received $10.5 billion to $35.8 billion in net benefits from in-service MVPs since authorizing them in 2011.
The results are part of MISO’s second annual limited review of MVPs. The RTO said congestion and fuel savings account for 75% of overall MVP benefits.
Davey Lopez, MISO advisor of planning coordination and strategy, said the MVP B/C range is about 2 to 2.7, in line with expectations when the RTO approved the 17 MVP projects in 2011.
Northern Indiana Public Service Co. announced that it will demolish its Dean H. Mitchell power plant on Lake Michigan and conduct an environmental cleanup.
NIPSCO will spend $18 million and two years demolishing the Gary, Ind., coal plant, built in 1955 and taken offline in late 2001. The company said it plans to work with city officials to develop the site.
“This is a positive step forward for the community, our customers and the environment as we clear the path for new investments and opportunities for the future,” NIPSCO Executive Vice President Violet Sistovaris said in a statement.
Consumers Energy’s new 8.5-acre solar array located in Western Michigan University’s Business Technology and Research Park has begun generating power.
The 1-MW solar plant is Consumers’ second large-scale project in Michigan. The first was a 3-MW solar plant opened in April at Grand Valley State University.
Both projects are part of the company’s Solar Gardens program. Ratepayers who subscribe to the program receive a varying credit on their monthly bills depending on how much power is produced at the plants.
Consumer Group Calls for Deeper Ameren Rate Decrease
Consumer advocate group Citizens Utility Board is arguing that Ameren’s proposed 2017 cut in electric rates for its Illinois customers is not enough.
CUB, along with an industrial customer group, says ratepayers are owed $30 million, more than double the $14.4 million cut that Ameren set forth in its filing. The group is urging the Illinois Commerce Commission to approve a more substantial decrease.
“We are glad that Ameren Illinois has proposed a rate cut for its customers, but our expert testimony shows that customers deserve double the decrease,” Citizens Utility Board Executive Director David Kolata said. “We’re going to do everything we can to make sure customers get a fair rate cut.”
JCP&L to Invest $387M in Infrastructure by Year-end
Jersey Central Power & Light plans to complete $387 million in infrastructure projects in its northern and central service areas by the end of the year.
The FirstEnergy subsidiary already has spent $233 million to pay for the final phase of a 115-kV transmission line through Mercer, Middlesex and Monmouth counties, a substation expansion in Morris County and 2,000 miles of tree trimming.
“Last year, JCP&L experienced its best service reliability in over a decade, and our goal is to make our system even better,” said Jim Fakult, the company’s president.
LP&L Management Considers Building Compatibility Study
Lubbock Power & Light is hiring a contractor to take a closer look at concerns that many downtown buildings may not be able to connect to new power lines that are being buried underground.
The municipal utility told the Lubbock Electric Utility Board that the contractor would identify the number of structures that are and are not compatible with the new system. The utility is moving downtown aerial wires to underground conduits in a series of phases.
American Electric Power’s Southwestern Electric Power Co. subsidiary has issued a request for proposals for up to 100 MW of wind power capacity.
SWEPCO wants to buy wind assets that can be put into commercial operation by 2019. The assets must be interconnected to SPP and located in the states of Arkansas, Louisiana, Texas, Oklahoma, Kansas or Missouri.
Bids will be accepted through Sept. 15. The application forms and additional information can be found here.
The Public Utility Commission of Texas last week granted ERCOT and SPP staff’s request for a five-week extension before reporting back on how they will together study Lubbock Power & Light’s planned move to ERCOT.
Commission Chair Donna Nelson acknowledged the complexity of analyzing LP&L’s integration into ERCOT and its impact on SPP’s neighboring grid. “We have to assume [ERCOT and SPP] are moving as quickly as they can,” Nelson said during the PUC’s Aug. 18 meeting. “We’ll give you this extension, but don’t ask for another.”
The commission last month detailed specific issues the RTOs should analyze and asked them to produce a study scope before its August open meeting. The PUC has regulatory oversight of ERCOT and would have to approve LP&L’s migration to the Texas grid (Docket No. 45633). (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)
ERCOT’s director of system planning, Warren Lasher, and SPP’s vice president of engineering, Lanny Nickell, responded with a joint letter Aug. 11 saying they were “not yet able” to provide a firm schedule for completing the analyses. They promised a “more definitive response” for the commission’s Sept. 22 open meeting.
“At that time, ERCOT and SPP expect to be able to provide more information regarding the coordinated studies, including technical details and a more informed estimate of the study schedule,” they said.
“I look forward to hearing from them. Go forth and do good,” Nelson said.
According to the letter, staff have met four times since the July 20 PUC meeting, comparing their transmission-planning study processes and discussing study approaches and project schedules. Lasher and Nickell noted the two RTOs have not worked together on transmission-planning studies in the past and said differences in their study processes meant they would not be able to supply the requested details before last week’s PUC meeting.
The two officials said the study could be completed as early as the second quarter of 2017.
Last September, LP&L announced its intention to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT study completed in June indicated it will cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L.
El Paso Electric, SWEPCO Settlements
In other actions, the PUC approved a settlement with El Paso Electric allowing the utility to build a voluntary community solar pilot program (Docket No. 44800) and a settlement in which Southwestern Electric Power Co. will pay $23,000 for violating reliability and service standards when it fell behind in tree trimming (Docket No. 46117).
The SWEPCO order gave Commissioner Ken Anderson a chance to speak out on one of his pet peeves. “Tree trimming needs to be done on an annual basis,” he told SWEPCO representatives. “You’re in East Texas, where things actually grow.”
PUC staff are working on a study evaluating Texas utility tree-trimming practices.
Cost Allocation for Seams Projects
Nelson and Anderson also briefly discussed holding a special meeting involving MISO and SPP staff to gather their input on allocating costs for seams projects. Anderson, a member of the Organization of MISO States, said Missouri representatives have questioned whether the interregional planning changes FERC ordered for MISO and PJM should also apply to MISO’s seams with SPP and ERCOT.
Acting on a complaint by Northern Indiana Public Service Co., the commission in April ordered MISO to reduce its minimum voltage threshold for interregional economic transmission projects from 345 kV to 100 kV and to eliminate the $5 million cost threshold for such projects. It also ordered the removal of the requirement for a third, separate benefit-cost analysis for the combined regions (EL13-88). (See FERC Orders Changes to MISO-PJM Interregional Planning.)
Deepwater Wind announced it has completed the 30-MW, five-turbine Block Island Wind Farm, an announcement that drew the praise of the National Ocean Industries Association and others, including the Sierra Club.
“The completion of any offshore energy project is no small feat; the road from concept to completion can be very lengthy and rife with challenging regulatory hurdles, unanticipated permitting delays, and vocal environmental opposition alongside enthusiastic public support,” NOIA President Randall Luthi said.
“Our untapped offshore wind energy potential is enormous and it holds the key to creating thousands of good paying clean energy careers, cleaning up the dangerous fossil fuel pollution endemic in many our coastal cities, and provides another effective solution to addressing the climate crisis,” said Mary Anne Hitt, director of Sierra Club’s Beyond Coal Campaign.
For the first time in more than 40 years, carbon emissions from natural gas this year are expected to exceed those from coal, according to data released last week by the Energy Information Administration.
Though natural gas is less carbon-intensive, Americans are using more of it, as the country eases its reliance on coal-fired generation.
At the same time, annual carbon intensity rates have been decreasing, in part because of the growing consumption of carbon-free generation such as nuclear and renewable power.
The U.S. remains No. 1 in the world for electricity generated by wind power and No. 2, behind China, for wind power capacity, according to an annual report released last week by the Energy Department and its Lawrence Berkeley National Laboratory.
Nearly 8,600 MW of wind capacity were installed in the U.S. in 2015, a 77% increase over the previous year’s installations.
By comparison, China installed 30,293 MW of wind capacity last year.
River Group Sues Portland General over Dam Operation
An Oregon environmental group has sued Portland General Electric in federal court, alleging that the utility’s dam operations along the Deschutes River are violating the Clean Water Act.
The focus of the lawsuit is a $100 million, 273-foot underwater tower and fish-collection facility that PGE built in 2009 in partnership with the Confederated Tribes of Warm Springs, co-owner of the Round Butte Dam.
The Deschutes River Alliance alleges the tower’s operation violates standards for water temperature and dissolved oxygen, while also contending that the Oregon Department of Environmental Quality is not enforcing water quality standards. The utility countered that the facility is intended to restore salmon and steelhead runs and that restoration will entail a long-term effort.
NASA Study Shows Methane Hot Spot Comes from Natural Gas Leaks
Researchers say an unusual concentration of the atmospheric methane over the Southwest appears to come mostly from leaks in natural gas production.
NASA’s Jet Propulsion Laboratory and the California Institute of Technology released a report Aug. 15 that listed more than 250 sources of a methane hot spot over the Four Corners region, including gas wells, storage tanks, pipelines and processing plants. Only a handful were natural seeps from underground formations, according to researchers. The study said about 25 locations are responsible for most of the methane leaks.
Evidence of the hot spot dates back to 2003, and a satellite image released in 2014 showed it in vivid color, but the origin wasn’t clear until recently. The new study identified the sources with spectrometers aboard aircraft that flew 3,000 to 10,000 feet above the ground over about 1,200 square miles in the Four Corners in April 2015.
Developers of the Dakota Access Pipeline said last week they will halt construction on the $3.8 billion oil pipeline that is to run from North Dakota to Illinois pending a hearing in federal court in D.C. this week. The Standing Rock Sioux Tribe is suing regulators for issuing permits for the pipeline that the tribe says goes through sacred land and poses a threat to its drinking water.
Members of the tribe and its supporters blocked construction equipment last week while it waited for its request for a temporary injunction, which was approved this week.
Judge Erred in Blocking BLM Fracking Rules, Law Profs Charge
Law professors arguing for the Obama administration said that a judge was mistaken when he ruled against the Bureau of Land Management’s rules concerning fracking on federal land.
The bureau in 2015 issued rules that would have required energy companies to disclose what materials they used in the fracking process. District Judge Scott Skavdahl of Casper, Wyo., vacated the rules, saying the bureau didn’t have the authority to regulate fracking.
In his ruling, Skavdahl pointed to an article written by Florida State University professor Hannah Wiseman to support his conclusion. Wiseman, however, joined 35 other law professors in a brief filed with the 10th U.S. Circuit Court of Appeals, saying the judge misinterpreted her piece.
NRC Reports Violations at Entergy’s FitzPatrick Plant
The Nuclear Regulatory Commission released a report citing Entergy’s James A. FitzPatrick nuclear plant for two violations of “very low safety significance,” including sending workers into high radiation areas without first meeting with the plant’s radiation protection department and for failing to address a long-term radioactive leak.
The report, which covered the second quarter of 2016, said an atmospheric control system failed and was not addressed within the required 30 days. It also cited the plant for allowing radioactive material to escape from a filter sludge tank in the radioactive waste building, though no radiation was leaked into the atmosphere.
Entergy says it has developed a corrective action that will be implemented within the next month.
Vice President of Finance Jo Biggers has left MISO after 16 years, the RTO announced last week.
MISO CEO John Bear and Biggers in 2015 Source: MISO
MISO said Biggers exited her position “to pursue other opportunities” and that it is beginning a search for a replacement. Biggers was responsible for procurement, facilities, accounting and FERC financial reporting. She joined MISO in August 2000, remaining in the same position throughout her tenure.
Until a replacement is found, MISO has delegated corporate service tasks to Senior Vice President of Compliance Services Steve Kozey. Finance and corporate planning responsibilities will be handled by Vice President of Strategy and Business Development Wayne Schug.
MISO declined to comment further on the departure. Beyond its short announcement, spokesman Jay Hermacinski said the RTO did not “have anything else to add.” Biggers could not be reached for comment.
WESTBOROUGH, Mass. — ISO-NE last week presented the five scenarios it will evaluate in its 2016 Economic Study, which envisions continued reliance on natural gas, renewables, energy efficiency and demand response.
The RTO is in the early stages of Phase I of the two-phase study, which will look at projected needs for 2025 and 2030.
The draft study will analyze the following futures:
The generation fleet meets existing renewable portfolio standards, with natural gas combined cycle units replacing any retiring units and filling any installed capacity requirement shortfalls.
The same as Scenario 1 except that all additional capacity needs, including retirements, are met with new renewable/clean energy resources, including nuclear power.
The “RPS-plus scenario” assumes additional renewable/clean energy resources above existing RPS requirements.
The “no retirement scenario” is the same as Scenario 1, except that RPS requirements are met by renewable/clean energy resources that are interconnected to the system, under construction or approved as of April 1, 2016, with alternative compliance payments — which would support renewable energy projects — used to meet any remaining RPS requirements. Combined cycle plants meet any installed capacity shortfalls.
The same as Scenario 4, except that retired units are replaced with combined cycle plants to meet installed capacity requirements.
Most of the scenarios reflect the region’s commitment to renewable generation and its shift away from coal and oil. “We see little to no generation from oil-fired units,” Michael Henderson, ISO-NE director of regional planning and coordination, told the Planning Advisory Committee on Wednesday.
In Scenarios 1, 4 and 5, fossil-steam resources burn oil, coal and natural gas at existing locations. Scenarios 2 and 3 have very large amounts of zero-dispatch-cost resources such as wind, energy efficiency and solar photovoltaic. And while Scenario 3 adds new import capability, energy imports are about the same as the other scenarios for 2030 because of the large-scale addition of zero-cost resources.
That is especially pertinent following Massachusetts’ approval of legislation requiring the procurement of large amounts of Canadian hydropower and offshore wind. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Phase I will consist of traditional economic study analyses, with an emphasis on production costs.
Phase II will supplement Phase I by discussing several market and operational issues, including Forward Capacity Auction clearing prices, intra-hour ramping, regulation and reserve requirements and access to natural gas.
A draft report is expected to be completed in the fourth quarter.
California must significantly upgrade its transmission system in order to meet its 2030 target of generating 50% of its electricity from renewable resources, according to an interagency study.
“We have either the seventh or eighth largest economy in the world — we need a grid to match that,” state Secretary for Natural Resources John Laird said during an Aug. 15 workshop to discuss the second iteration of the state’s Renewable Energy Transmission Initiative (RETI 2.0). The first initiative focused on helping the state meet a 33% renewable portfolio standard.
But there is uncertainty about the amount of new renewables needed to fulfill the 50% RPS — as well as the most cost-effective transmission solutions required to reach whatever resources are selected.
“It’s very difficult to predict what load will be” in the future, said California Energy Commission Chair Robert Weisenmiller, pointing out that demand for renewables — like other types of generation — will ultimately be driven by economic growth, the penetration of vehicle electrification and the success of the state’s “very aggressive” energy efficiency goals.
State officials conceived RETI 2.0 to determine what combination of renewable resources could meet their environmental goals most cost-effectively and what transmission will be needed to deliver their output. The initiative also seeks to identify the land use and environmental issues that could constrain development and access to resources.
The intended result: an “accelerated, agency-driven, high-level assessment to inform future planning and regulatory proceedings,” according to project director Brian Turner, of the state’s Natural Resources Agency.
Two Policy Developments
Two major policy developments last year drove the development of the initiative.
The first was Gov. Jerry Brown’s executive order directing California agencies to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030. That goal has so far failed to win legislative backing to become codified into law.
The second development was passage of SB 350, which not only increased the state’s RPS to 50% by 2030, but also set higher standards for energy efficiency in buildings, ensured utility progress toward GHG reductions, expressed intent to expand CAISO into other areas of the West and encouraged electrification of the state’s transportation fleet.
Those overlapping objectives are creating challenges for resource planners.
“How do you translate the high-level goals for SB 350 and the executive order into quantifiable objectives?” Turner asked. “How much [renewable resources] might we need to meet the 50% [RPS] by 2030?”
The initiative’s findings indicate that an additional 25 to 108 TWh of renewables will be needed, depending on growth in vehicle electrification, adoption of behind-the-meter solar and the success of energy efficiency programs.
That translates into 7,000 to 31,000 MW of new capacity, assuming a 40% average capacity factor — or 9,000 to 41,000 MW assuming a 30% capacity factor.
Adding to the uncertainty is that a 40% economy-wide GHG reduction could require the equivalent of a 55 to 60% RPS for the state.
Planners working on the initiative found that “environmental and land use constraints tend to favor in-state solar and out-of-state wind” for meeting mandates, but “determining the environmental and transmission access feasibility for in-state wind may [also] be a priority,” according to Turner.
He also said that while low-cost solar is “ubiquitous” in California, a focus on resource and technology diversity would be more cost-effective because of the “long-term integration challenges” posed by an overreliance on solar. Geothermal may offer “important benefits” by 2030, but more investigation is needed into the costs, benefits and transmission access to those resources.
‘Broad Support’
The planners also found “broad support” among industry participants for further assessing procurement of out-of-state resources, with a focus on high-quality, low-cost options that would be complementary to in-state resources. That task is made difficult by a lack of information about the potential for developing the resources themselves and the transmission options for reaching them absent a broader study in cooperation with other Western states, an issue the initiative is seeking to address.
The subject of transmission access fell to the RETI 2.0 Transmission Technical Input Group (TTIG), led by Neil Millar, CAISO’s executive director of infrastructure development.
Fully Deliverable
Millar said that California has sufficient transmission capacity to fulfill the state’s 33% by 2020 RPS, but more will be needed to meet the 50% RPS with “full deliverability” for additional renewable resources. While the TTIG estimates that there is “significant transmission available to accommodate resources beyond 33% on an ‘energy only’ basis” — which would allow for quicker and less costly interconnection — those resources would be subject to curtailment.
Planners evaluated 11 different “Transmission Assessement Focus Areas” to determine the level of upgrades needed to fullfill California’s renewable and GHG goals.
Under California regulations, a generating resource is considered “fully deliverable” if its output can reach its intended load sink without hitting constraints — which typically requires a contracted path from a generator to a utility service area. The state’s rules also allow a utility to count those resources toward its resource adequacy requirement. “Energy-only” resources have no such requirements for deliverability and cannot be counted as capacity.
“The sufficiency of [energy-only resources] from a policy perspective is yet to be determined,” the group found.
To explore potential transmission solutions, the group evaluated seven internal and four transmission assessment focus areas to determine what transmission upgrades would be necessary to make new renewables fully deliverable into each area’s load centers.
For example, the San Joaquin focus area can currently handle 1,823 MW of deliverable and 3,131 MW of energy-only capacity, but developing another 5,000 MW of deliverable capacity to accommodate new resources would require upgrades costing about $440 million. Some areas — like the Tehachapi — would require few upgrades, while other areas require much more to open up renewable development.
Sushant Barave, a lead transmission engineer with CAISO, pointed out that transmission capacity is dynamic.
“Resource additions in one area may impact availability in other areas,” Barave said, adding that mitigating a constraint that limits flows through multiple focus areas would be the most cost-effective approach to planning.
Barave noted that energy-only resources might require less extensive upgrades, prompting CAISO CEO Steve Berberich to ask that a comparison between energy-only and fully deliverable requirements be made explicit in the group’s final report, to be published later this year.
The group also concluded that any out-of-state resources being delivered into California will be injected into one of the focus areas, subjecting new imports to the same transmission constraints as those faced by internal resources.
The potential for renewable imports from other areas of the West is still something of a blind spot for California grid planners. To remedy that, RETI 2.0 created the Western Outreach Project to “gather stakeholder input from across the Western Interconnection regarding the availability of renewable energy and transmission that could contribute to meeting California’s renewable goals,” according to Keegan Moyer, an Energy Strategies consultant working on the project — a collaboration with the Western Interstate Energy Board.
Key Questions
The project is looking to answer a number of key questions, including:
How much additional renewable development is likely in the West?
Where — and in which technologies — is development of renewables likely to occur over the next 15 years?
How will the future mix of renewables affect daily and seasonal power flows in the Western Interconnection?
What load centers could potentially import surpluses from California?
The project also seeks to determine the existing load capacity to deliver power from high-quality renewable areas into California — and what constraints limit additional deliveries.
“How would different expansion options affect deliverability to and from California?” Moyer said.
Another project task is to gain insight into generation fleet trends, including coal plant closures that could free up transmission capacity in the interior West and possible changes to hydroelectric utilization in the Northwest.
The project will also seek to answer the question of how increased use of dynamic scheduling, conditional firm and energy-only resources, and other renewable procurement arrangements will impact transmission availability and needs.
“It’s pretty clear that we have a lot of options,” Weisenmiller said. “We have to do it in a way that minimizes environmental and economic impacts.”
“I think significant progress is being made,” said Michael Picker, president of the California Public Utilities Commission. “The goal here, I think, is to reuse as much as we can, so we don’t have to go new.”
“In the old paradigm we were looking at renewables. Now we’re looking at greenhouse gases,” Weisenmiller said. “We’re in a brave new world that will require a lot of new thinking about how the pieces fit together.”
Critics of a proposal to lower CAISO’s energy market bid floor last week questioned the need for the measure and its efficacy in solving the ISO’s increasing intervals of oversupply.
The ISO contends that reducing the bid floor from -$150/MWh to -$300/MWh will provide the market with more “downward flexibility” — or the ability to curtail renewable resources in the market rather than through out-of-market operations.
CAISO hopes that lowering the bid floor will persuade self-scheduled resources to submit bids that reflect the marginal cost of operations when oversupply turns prices negative.
“To ensure the ISO is able to provide accurate price signals to incent a more flexible fleet of resources during this transition, market changes must be implemented to encourage generators to economically participate in the markets rather than self-schedule,” CAISO wrote in its proposal.
Self-schedules often represent renewable resources operating under power purchase agreements with load-serving entities that include take-or-pay clauses. The LSE’s penalty for refusing the power adds to its opportunity cost of not generating a renewable energy certificate (REC).
The ISO has authority to curtail self-scheduled deliveries to protect reliability during periods of oversupply. The ISO said it was compelled to take that step during 2.5% of five-minute intervals between April 2015 and April 2016.
CAISO is seeing an increase in curtailed self-schedules as more renewables come online in California.
The practice is only growing with the increased penetration of renewables in response to the state’s 50% by 2030 renewable portfolio standard.
“In April [2016] alone we had 11% of intervals where self-schedules were being cut,” Kallie Wells, senior market monitoring analyst in CAISO’s market infrastructure and development department, said during an Aug. 18 stakeholder call. “The shoulder months will likely see increased amounts of that.”
In addition to incentivizing LSEs to bid contracted renewable resources into the CAISO market rather than self-schedule, ISO staff say they also hope the change will encourage LSEs to negotiate renewable PPAs that give them the option to curtail renewables to accommodate the ISO’s operational needs.
Market Monitor not Convinced
CAISO’s internal Market Monitor says the ISO hasn’t made a compelling case.
The Department of Market Monitoring “is right now opposed to lowering the bid floor,” said Ryan Kurlinski, manager of the department’s analysis and mitigation group. “We’re not seeing the evidence that this policy will create additional decremental bids.”
Kurlinski contended that lowering the bid floor will create a greater likelihood for the exercise of market power in decremental bids and expand the opportunity for increasing bid-cost recovery — or uplift — payments, which are shared by load across the ISO.
While a number of stakeholders have commented in favor of the measure, others are skeptical.
“Can you tell me what type of resource would be bidding in at less than -$150/MWh?” asked Eric Little, manager of wholesale market and greenhouse gas market design at Southern California Edison.
“We did look into actual costs, and -$150/MWh did cover a portion of intermittent resources’ costs but didn’t cover another portion,” said Brad Cooper, CAISO’s manager of market design and regulatory policy.
“Whenever we talk about this it comes down to RECs, but there are no RECs worth more than” $150/MWh, Little said.
Greg Cook, CAISO director of market and infrastructure policy, said that “it comes down to the power purchase agreements.”
“We do know that there are those that have contracts that are take or pay, but those contracts are changing,” Little said. “Are you trying to get companies to renegotiate contracts?”
Seeking Evidence
Little also asked the ISO to provide more evidence supporting the change.
“I would like to see something that would show what elements will require a floor below -$150,” he said. “That would help us out.”
Nivad Navid, a principal with Pacific Gas and Electric, also sought more supporting data, asking CAISO to provide statistics showing how often the market clears at -$150/MWh. He also expressed concern about the ISO deterring LSEs from submitting self-schedules.
“We’re not saying you can’t self-schedule,” Wells said. “By lowering the bid floor, economic bids will more likely set the price” rather than out-of-market mechanisms. Wells also said a deeper pool of economic bids would prevent the ISO from cutting self-schedules.
“So when you change the bid floor, are you expecting that you will not need any more curtailment?” Navid asked.
“It sounds like the assumption you’re making is that there are resources that can’t bid into the market because of the bid floor of -$150,” said Josh Arnold, a settlement analyst at PG&E.
“That seems to be a sticky assumption to be making without providing supporting data,” he continued, adding that the ISO’s Board of Governors had previously said the -$150/MWh floor was appropriate.
Arnold questioned whether the renewables-heavy fleet serving California would change its market behavior as a result of the change, pointing out the difficulty in renegotiating contracts within the timeline of the proposal’s implementation. The ISO plans to seek approval from the board this fall, meaning the change could be implemented early next year, pending FERC approval.
“I’m very confused by the way you’re going about this,” Arnold said. “It seems like you’re anticipating an upcoming problem and trying to smash it with a hammer.”
CAISO is pairing the bid floor proposal with a plan to no longer exempt load corresponding with self-scheduled supply from being allocated costs associated with uplift payments. The ISO says the latter proposal will further incentivize economic bids over self-schedules and align allocation with cost-causation principles, as self-scheduled generation is also contributing to the oversupply issue.
The ISO is seeking comments on both proposals by Aug. 25 and plans to present a final plan to the board in October.
Northern Indiana Public Service Co. announced that it will demolish its Dean H. Mitchell power plant on Lake Michigan and conduct an environmental cleanup.
Consumers Energy’s new 8.5-acre solar array located in Western Michigan University’s Business Technology and Research Park has begun generating power.
Consumer advocate group Citizens Utility Board is arguing that Ameren’s proposed 2017 cut in electric rates for its Illinois customers is not enough.
Jersey Central Power & Light plans to complete $387 million in infrastructure projects in its northern and central service areas by the end of the year.
Lubbock Power & Light is hiring a contractor to take a closer look at concerns that many downtown buildings may not be able to connect to new power lines that are being buried underground.
“The completion of any offshore energy project is no small feat; the road from concept to completion can be very lengthy and rife with challenging regulatory hurdles, unanticipated permitting delays, and vocal environmental opposition alongside enthusiastic public support,” NOIA President Randall Luthi said.
For the first time in more than 40 years, carbon emissions from natural gas this year are expected to exceed those from coal, according to data released last week by the Energy Information Administration.
The U.S. remains No. 1 in the world for electricity generated by wind power and No. 2, behind China, for wind power capacity, according to an annual 
An Oregon environmental group has sued Portland General Electric in federal court, alleging that the utility’s dam operations along the Deschutes River are violating the Clean Water Act.
Researchers say an unusual concentration of the atmospheric methane over the Southwest appears to come mostly from leaks in natural gas production.
Developers of the Dakota Access Pipeline said last week they will halt construction on the $3.8 billion oil pipeline that is to run from North Dakota to Illinois pending a hearing in federal court in D.C. this week. The Standing Rock Sioux Tribe is suing regulators for issuing permits for the pipeline that the tribe says goes through sacred land and poses a threat to its drinking water.
