FERC last week ordered RTOs and ISOs to file reports detailing their current practices and planned changes on five price formation issues, saying it needed more information before taking substantive action.
In September, the commission issued a Notice of Proposed Rulemaking that would require RTOs and ISOs to align their settlement and dispatch intervals, saying it was the first of a number of proposals on which the commission plans to act. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
FERC said last week that the RTO/ISO reports, due in 75 days, will help it identify best practices and inform its future actions. It asked for information on:
pricing of fast-start resources;
commitments to manage multiple contingencies;
look-ahead modeling;
uplift allocation; and
transparency.
“Identifying best practices for these five areas should provide incentives to maintain reliability, to facilitate accurate and transparent pricing, to reduce uplift, and for market participants to operate consistent with dispatch signals,” the commission wrote. “We have selected these areas because the discussion at the price formation workshops and the comments received after the workshops suggest that a number of RTOs and ISOs have sufficient experience with these areas such that we may be able to discern best practices and understand unintended consequences.
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“The commission seeks this information not only to answer technical questions regarding how each RTO/ISO addresses these topics, but also to understand the reasons why each RTO/ISO has made its set of policy choices,” it added.
Commissioner Cheryl LaFleur said the issue is one of the commission’s most important initiatives, particularly because of the shift from coal to lower carbon resources. “I know there’s been a lot of anticipation and even impatience for action in this area,” she said. “This is the second in a series of orders; I don’t believe it will be the last.”
Commissioner Tony Clark said the energy markets “are our best performing and most mature markets.”
“So it seems to me that this is an appropriate manner in which to deal with this … so that we take it one bite at a time and we don’t have secondary unintended effects [that might occur] if we were to act all at once.”
Commissioner Colette Honorable noted that some have complained that work on price formation issues has “stalled” in RTO stakeholder processes.
“While we are working, I want to gently ask that [stakeholders] continue working, too, and that if you identify market flaws and other issues that need to be addressed, please continue to demonstrate your leadership.”
FERC last week accepted a compliance filing by NYISO regarding its revised compensation methodology governing the provision of frequency regulation service under Order 755. “We believe that NYISO has demonstrated that its interim market power mitigation measures have successfully limited opportunities for firms to benefit from bidding regulation movement above marginal costs, and therefore meet the requirements of Order No. 755,” FERC wrote (ER12-1653).
Tennessee Gas Pipeline on Friday filed an application with FERC for a certificate of public convenience and necessity for the Northeast Energy Direct pipeline (CP16-21).
Tennessee Gas, a unit of Kinder Morgan, is seeking FERC approval in the fourth quarter of 2016, with construction starting in January 2017 and an in-service date of Nov. 1, 2018. The company estimates the project will cost $5.2 billion.
“Adding the NED project capacity to transport incremental natural gas supplies will ease natural gas capacity constraints and is expected to provide significant benefits to energy consumers in the region in the form of lower natural gas and electricity prices,” the application says.
The project consists of two components that will transport natural gas from the Marcellus shale gas region of Pennsylvania to New England.
The supply path component is a 174-mile segment from Bradford County in northern Pennsylvania to an existing compressor in Wright, N.Y. The segment can transport 1.23 million dekatherms per day, of which Tennessee Gas says it has long-term contracts for 552,262 dekatherms per day.
The market path component continues from Wright for 188 miles through New York and Massachusetts, turning slightly north into New Hampshire and then moving south to its end in Dracut, Mass. This route has a capacity of 1.3 million dekatherms per day, with contracts for 751,650 dekatherms per day.
The staff of the New Hampshire Public Utilities Commission has released a report that said Northeast Energy Direct is its preferred project of several proposed natural gas pipelines to ease supply constraints. (See NH PUC Staff: Northeast Energy Direct Pipeline Would Lower Power Prices.)
SPP has responded to stakeholder feedback by making several tweaks to its redesigned website.
Many of the improvements were to the site’s search function, which now returns results sorted with the most recently posted documents first and includes the ability to filter results by file type.
After logging in to their profiles on the site, users are now returned to the page they were previously viewing, rather than being taken to their profile page. Changes have also been made to simplify registration for meetings and other events.
Calendar (ICS) files sent to users after meeting registrations now include hotel information and have been reformatted to display all information in a more readable manner.
The RTO said its website project team is already at work on another set of improvements, to come in the next several weeks.
ECC, Gas-Day Testing to Begin with ‘Big Bang’
SPP staff told stakeholders last week to expect a “big bang” testing approach — an apparent reference to the complexity and breadth of the systems involved — next summer and fall as it continues to develop the markets system’s enhanced combined-cycle (ECC) software. (See “Enhanced Combined-Cycle Project Moves Forward” in SPP Board of Directors/Members Committee Briefs.)
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The ECC project, intended to provide more sophisticated modeling that captures combined-cycle plants’ flexibility, is being conducted in conjunction with improving gas market-clearing logic. SPP anticipates market participants will be able to begin gas-day testing in August and ECC testing in December.
The testing will involve more than a dozen systems or interfaces, four different vendors and seven SPP departments. At least two other system revisions will be released in addition to the ECC/gas-day releases.
Staff told SPP’s Change Working Group — which is responsible for implementing changes affecting markets and members — said it would deliver quarterly releases of the markets systems through 2016, making incremental improvements to the ECC functionality. One project manager said the team will have to see how downstream systems are affected as it gathers upstream system requirements.
Adding to the project’s complexity is the market-clearing engine, or, as SPP’s Jim Gonzalez said, “The actual calculator.” The ECC logic is so complex, Gonzalez said, the clearing engine has to run 20 times to produce a good solution.
MISO’s Steering Committee put its own operations under inspection during a Nov. 19 meeting, when it addressed stakeholder concerns that meeting materials are being posted too late.
Michelle Bloodworth, MISO’s executive director of external and stakeholder affairs, said meeting and agenda materials should be posted at least a week before the meeting under governance guidelines.
“We have not forgotten this and we’re taking a lot of strides internally,” Bloodworth said, adding that MISO is looking at different options on how to notify stakeholders when materials are posted.
MISO management will address the committee’s concerns on posting and discuss verbal updates versus updates accompanied by posted materials at an informational forum Dec. 15.
The Steering Committee went over a tentative schedule of monthly 2016 meetings. In light of the impending stakeholder redesign, the committee is embracing a “business as usual” policy through March until a more defined plan emerges from the stakeholder redesign committee. (See MISO Board Reduces Meeting Schedule; AC Likely to Follow.)
Also during the meeting, the closed Operations Working Group and the closed Operations Planning Working Group were merged by vote into the temporarily named Confidential Reliability Working Group. The Steering Committee also gave the go-ahead on a draft charter and management plan for the newly merged entity. The group’s purpose is to “provide a forum to promote the reliability of the Bulk Electric System and to develop, review and recommend operational planning practices,” according to the draft management plan.
Kent Feliks, chair of the Market Subcommittee, asked the Steering Committee for ideas on how the subcommittee should address projects that are withdrawn from MISO’s market roadmaps. Currently, there’s no procedure in place for projects that drop out of the 2017-2019 Market Roadmap. Feliks said a possible procedure and improvements to MISO Market Roadmap process will be discussed at the Dec. 1 Market Subcommittee meeting.
MISO Tops Wind Record, Reports Low October Energy Prices
Todd Ramey, vice president of system operations and market services, told an informational forum last week that the RTO set a new wind generation record Oct. 28, with instantaneous output of 12.4 GW, breaking the previous record of 11.9 GW, set Jan. 8. Wind produced 4.1 TWh for the month, up from 2.9 TWh in September and 3.6 TWh in October 2014.
Meanwhile, at a MISO informational forum held Nov. 18, the RTO reported relatively low wholesale energy prices for the month of October, owing to inexpensive fuel prices, strong wind farm output and slightly higher temperatures above historic October averages.
According to a MISO presentation, load peaked at 84.6 GW on Oct. 8, significantly less than September’s peak of 113.9 GW. Average load for the month was 68.6 GW, down 2.4% from October 2014.
LMPs averaged $25.34/MWh in October, down from $26.80/MWh in September and $32.44/MWh in October 2014.
MISO Launches ‘Jargon-Free’ Blog
MISO last week introduced a blog, MISO Matters, an effort to increase understanding of RTO operations by simplifying technical topics. The first entry features breakdowns of peak load, automatic reserve sharing and the MISO Transmission Expansion Plan.
“We will feature what MISO is doing around big topics, like [the Clean Power Plan] and transmission planning, but also try and explain some of the day-to-day business operations,” MISO spokesman Andy Schonert said. “Most of all, the goal of the blog is to tell MISO’s story free of jargon and acronyms, and explain what MISO does on a daily basis.”
FERC on Friday accepted SPP’s request to waive Tariff provisions governing the selection of an industry expert panel, allowing it to use one of its 2016 panelists to complete the 2015 panel evaluating proposals for the RTO’s first competitive solicitation under Order 1000 (ER16-126).
SPP filed the waiver request with FERC on Oct. 20, saying that the only candidate in its 2015 pool with expertise in one of five subject areas required wouldn’t be able to serve. (See SPP Seeks Waiver on Panel; Sets New Wind Records.)
FERC found “good cause” to grant SPP’s requested waiver, saying it “will remedy a concrete problem and allow for regulatory certainty regarding review of the proposals submitted for the project.”
FERC noted the waiver requested was of limited scope, covering just two subsections of SPP’s Tariff and it addressed a one-time event. The commission said the request “will create no undesirable consequences since the candidate’s qualifications will be reviewed and approved by both the Oversight Committee and the SPP Board of Directors prior to serving on the IEP.”
Duke Energy was able to offset a slump in its international business thanks to increased revenue from its U.S. regulated operations and the early closing of certain strategic initiatives, the company said in announcing its third quarter results.
The Charlotte, N.C., company reported earnings per share of $1.35, compared with $1.80 a year ago. Adjusted earnings — excluding special items and discontinued operations — were $1.47/share compared with $1.40/share over the same period last year.
The company also narrowed and reduced its full-year guidance to $4.55 to $4.65/share from $4.55 to $4.75.
“This range reflects mild October weather as well as storm expenses, unfavorable foreign currency trends and the potential for extending bonus depreciation,” CEO and President Lynn Good said on an earnings call with analysts.
Duke’s international business has experienced a decline, contributing in 2015 about half of the $0.60/share it did in 2013 and 2014, CFO Steve Young said. “About half of this decline is due to the three-year drought in Brazil, while unfavorable exchange rates and lower crude oil prices comprise the remaining half,” he said.
Income from the international business was down to $69 million in the third quarter compared with $80 million in 2014.
Young said the division’s earnings are expected to stabilize by the end of the year and show a modest growth in 2016, when hydro dispatch is predicted to improve.
“Over the past several months, we have begun to see higher water inflows and lower market power prices,” he said. “Further, meteorologists are forecasting a strong El Nino weather pattern through early 2016, which could lead to increased rainfall in Southeastern Brazil.”
Earnings from Duke’s commercial portfolio dropped $0.08/share, primarily as a result of the sale of the Midwest Generation business to Dynegy, which closed in April. Weak wind resources this year have led the company to lower its full-year expectations from $100 million to $75 million, Young said.
However, the commercial business — unregulated renewables and commercial electric and gas transmission — is expected to get a boost next quarter from tax credits related to more than 300 MW of wind and solar generation that is set to come online.
The regulated business benefited from the recently completed acquisition of 700 MW of generation from the North Carolina Eastern Municipal Power Agency. The business also was boosted by the first warmer-than-normal summer since 2012 in the Carolinas.
“On the regulated side, we’re on track to complete construction of 128 MW of utility-scale solar in North Carolina by the end of this year, and are moving forward with investments in both South Carolina and Florida,” Good said.
Young said Duke Energy also has been successful in attracting new business that is expected to add nearly 7,200 jobs in its six-state service area.
Duke Energy, which earlier this year was hit with $102 million in federal penalties related to the massive Dan River coal ash spill, made its final payments last week with two $5 million contributions to environmental remediation programs.
The money went to a Texas-based firm, Resource Environmental Solutions, to fund remediation in Virginia and the Carolinas.
The payments settle Duke’s guilty pleas to nine misdemeanor violations of the federal Clean Water Act. The pleas came as a grand jury was considering criminal charges against the company relating to its handling of coal ash at 14 North Carolina plants. Duke agreed to pay $68 million in fines and $34 million in restitution.
Xcel Energy is proposing the option of 100% renewable electricity for its Minnesota customers. The “Renewable Connect” program would be offered to all customers, but it is primarily aimed at business and corporate customers seeking to achieve sustainability goals.
The plan, submitted to the state Public Utilities Commission, would offer a package of wind and solar energy at a premium price, but Xcel said it would not take a profit from it. The company said the plan would provide long-term pricing certainty and allow customers to claim environmental awareness, something many companies value.
“Businesses are more careful about how they source everything, including energy,” said Bill Blazar, a vice president of the Minnesota Chamber of Commerce. “It is almost like a kosher seal on a chicken — they are looking for that something to offer to their customers who want it. They are responding to the market.”
The Marysville Power Plant, a coal-fired generator that stood for 93 years in eastern Michigan on the banks of the St. Clair River, was demolished in a controlled implosion on Nov. 7.
In its heyday, the plant employed about 250 people and produced 1,386 MW. Operations ceased in 2001. Owner DTE Energy sold the 30-acre site to a developer, who plans to convert the waterfront property into a multi-use facility including retail shops, housing, a marina and bike trails.
DTE Energy announced plans Nov. 6 to partner with southeastern Michigan’s Port of Monroe to market and transport gypsum produced from the emissions-control system at its Monroe Power Plant.
Under the collaboration, gypsum will be shipped from the Lake Erie port to clients in Canada and the Midwest. The Port of Monroe says it will build a 24,000-square-foot storage building. DTE, which recycled more than 350,000 tons of gypsum last year, said the arrangement will enable the utility to recycle 100% of its gypsum going forward.
Synthetic gypsum is produced from flue gas desulfurization systems, or “scrubbers,” which use lime or limestone as reagents. The byproduct is nearly identical to mined gypsum and can be used in manufacturing cement and drywall.
TXU Solar Partnership Offers High-Efficiency Home Panels
Texas retailer TXU Energy last week introduced a program it calls “TXU Solar from SunPower,” providing high-efficiency solar panels that the manufacturer says produce 70% more energy than conventional panels.
The program comes with a simple online and mobile monitoring system so homeowners can track their electricity production. SunPower said its panels, which have an expected lifespan of 40 years, will enable residential consumers to produce more of their own electricity than competing rooftop systems.
The new offer is being launched in North Texas. To be eligible, consumers must own a single-family home with a south-to-southwestern exposure.
Basin Electric: SPP Membership Helps Prepare Co-op for Future
Basin Electric Power Cooperative CEO Paul Sukut says joining SPP last month has expanded the North Dakota co-op’s access to power.
Sukut, speaking during Basin’s annual meeting earlier this month in Bismarck, said the cooperative’s membership in the regional grid allows it to purchase more power to supply growing demand. He said Basin is trying to keep up with the market while still maintaining its cooperative values.
“I can’t recall a time in the last 30 years we have had this much at stake,” he said, alluding to the Environmental Protection Agency’s Clean Power Plan.
American Electric Power has closed the sale of its commercial barge operation to American Commercial Lines for $550 million. AEP bought the river operation in 2001, but the company decided earlier this year to divest the asset and redeploy the capital to its regulated operations. The sale netted about $400 million after taxes, debt retirement and fees.
AEP will retain ownership of a fleet of 12 tow boats and 429 barges to deliver coal to its coal-fired power plants, but ACL will dispatch and operate the fleet through 2016. AEP River Operations, now the property of ACL, has its own fleet of about 56 towboats and 2,300 barges that deliver 45 million tons of commodities on inland waterways, including 10 million tons of coal.
Unit 1 at Talen Energy’s Susquehanna nuclear power plant automatically shut down Thursday after a malfunction that is being investigated.
Talen Energy assumed control and partial ownership of the plant earlier this year when it was spun off from PPL. Allegheny Electric Cooperative also owns a share of the plant.
Talen said the unit’s safety features worked as designed and that there was no release of radiation. Unit 2 remained in operation, according to the company.
FERC last week denied requests by Texas and Louisiana regulators for rehearing of its December 2013 order approving the Entergy operating companies’ incorporation into MISO and Entergy Arkansas’ exit from the companies’ system agreement.
The Public Utilities Commission of Texas contended FERC was wrong because in filing “limited” amendments to the agreement, Entergy didn’t subject its entire system agreement to scrutiny.
The Louisiana Public Service Commission contended that FERC’s order failed to determine what entity is responsible for costs left when an operating company withdraws. It said ratepayers of the last remaining company in the operating company system could unjustly bear the brunt of the costs needed to plan and operate the resources of multiple companies. Louisiana regulators also questioned whether Entergy’s proposed congestion cost would correspond with MISO practices and suggested that Entergy Arkansas’ exit would leave a regulatory gap in state authority over Entergy.
FERC’s Nov. 9 order denied the commissions’ complaints on all fronts, saying that the system agreement doesn’t require withdrawing companies to pay an exit fee or otherwise compensate remaining companies (ER13-432-001).
“[Entergy Arkansas’] integration into MISO does not require a broader review of the system agreement. Nothing about Entergy’s intent to operate as a power pool within MISO is inherently inconsistent with behavior in an organized market,” FERC wrote. “Furthermore, nothing in the system agreement or commission precedent would bar Entergy from integrating the operating companies into MISO as a power pool.”
FERC last week also accepted Entergy’s compliance filings required by the 2013 order (ER14-1263, et al). The commission had ordered the companies to amend their costs and credits allocator to use energy usage instead of peak demand as the basis for calculations.
The Louisiana commission protested that Entergy’s revised allocator “departs dramatically from the criteria articulated by the commission” by using monthly energy usage data instead of hourly energy usage data, as MISO’s Tariff states. They asked FERC to reject Entergy’s method on the basis that it violated cost-causation principles.
FERC instead accepted Entergy’s compliance filing, noting that using hourly energy usage data “would be problematic because it would be inconsistent with the monthly allocation of ancillary services and uplift charges and credits related to generating units.”
“We find that Entergy has provided sufficient detail in its compliance filing to explain how it will calculate the energy-based allocator and has justified why its proposal is just and reasonable,” the commission wrote.
FERC Commissioner Colette Honorable, a former Arkansas regulator, did not participate in either ruling.
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.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 01: Control Center and Data Exchange Requirements. Adds requirements and changes terminology to be consistent with North American Electric Reliability Corp. standards. Makes minor edits for clarity. Removes dated reference to “floppy disk.”
Manual 03: Transmission Operations. Changes resulting from bi-annual review include project updates, edits and reorganization of sections.
Manual 12: Balancing Operations. Updates due to new instantaneous reserve check implementation. Eliminates mention of MISO as the Interconnection Time Monitor.
Manual 13: Emergency Operations. Updates day-ahead scheduling reserve requirement for Reliability First Corp. effective Jan. 1. Other changes made for consistency. Removes requirement that generators connected below 230 kV participate in voltage reduction.
Revisions to Manual 19: Load Forecasting and Analysis reflect updates to the PJM load forecast model. Adds variables to account for trends in equipment and appliance saturation and energy efficiency; revises weather variables; updates weather station assignment to zones; and revises weather normalization procedure. PJM will be publishing a white paper in 2016 to provide more detail on the forecast model. (See “Manual Changes on Load Forecast Approved Except for Solar Revision” in PJM Planning Committee and TEAC Briefs.)
Revisions to Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification to accommodate energy efficiency resources in the capacity market when they are reflected in the peak load forecast.
The committee will be asked to endorse modifications, clarifications and revisions to 12 terms in PJM governing documents.
xx. UNDERPERFORMANCE RISK MANAGEMENT IN RPM/CP (10:25-10:40)
Bob O’Connell, on behalf of the Supplier Caucus, will present a proposed problem statement and issue charge related to underperformance risk management in the capacity market. It would expand ways for generators to minimize penalties by netting them against over-performing generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
Members Committee
ENDORSEMENTS (1:25-2:05)
1. 2015 IRM STUDY RESULTS (1:25-1:40)
Members will be asked to endorse the installed reserve margin study results, re-setting IRM and the forecast pool requirement for 2016/17, 2017/18 and 2018/19 and establishing initial IRM for 2019/20. The study increases the IRM to 16.4% from 15.5% in the 2014 study. The IRMs also rose for the following two delivery years. (See “Committee Endorses Increase in IRM” in PJM Markets and Reliability & Members Committees Briefs.)
2. 2016/17 THIRD INCREMENTAL AUCTION (1:40-1:55)
As part of the transition to Capacity Performance, the committee will be asked to approve Tariff revisions allowing PJM to sell excess base capacity acquired in the third Incremental Auction for 2016/17 in February. (See “Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17” in PJM Markets and Reliability & Members Committees Briefs.)
3. ELECTIONS (1:55-2:05)
Members will be asked endorse the following elections:
Finance Committee
End Use Customer, David Evrard, Pennsylvania Office of the Consumer Advocate
Generation Owner, Michelle Greening, Talen Energy
Other Supplier, Marguerite Miller, Credit Suisse
Transmission Owner, Jim Benchek, FirstEnergy
Sector Whips
Electric Distribution, Steve Lieberman, Old Dominion Electric Cooperative
End Use Customer, Susan Bruce, PJM Industrial Customer Coalition
Generation Owner, Joe Kerecman, Calpine
Other Supplier, Katie Guerry, EnerNOC
Transmission Owner, Jodi Moskowitz, Public Service Enterprise Group
