Late Changes to House Energy Bill Leave Democrats Miffed

By Rich Heidorn Jr.

WASHINGTON — A key House committee last week approved what would be the first comprehensive energy legislation in eight years, but hopes for passage dimmed after Republican amendments eroded bipartisan support.

H.R. 8, the North American Energy Security and Infrastructure Act of 2015, cleared the House Energy and Commerce Committee 32-20 on Wednesday with support from only three Democrats. The bill includes measures to improve energy infrastructure, resilience and reliability while increasing scrutiny of RTOs and FERC.

A preliminary draft of the bill had passed a subcommittee unanimously. But Wednesday’s markup devolved into partisan sniping after Chairman Fred Upton (R-Mich.) replaced the original bill with a 208-page amendment that stripped gas and electric infrastructure funding sought by Democrats. The amendment also includes provisions that would speed the approval of liquefied natural gas export terminals and repeal current law requiring that federal buildings phase out the use of fossil fuel-generated energy.

The changes left Rep. Frank Pallone (D-N.J.), the ranking Democrat on the committee, fuming. “This bill only aims to help polluters in my opinion,” he said. “It continues to ignore the impact of climate change, which remains the biggest threat to our energy security and way of life.”

Upton said the bill is intended to create jobs, improve infrastructure and ensure affordable energy. “While it has been difficult to find bipartisan consensus on as many fronts as I would have liked, I believe we have written a substantive, thoughtful bill,” he said in opening the committee markup.

Congress has not approved a comprehensive energy bill since the Energy Independence and Security Act of 2007. While the House bill is unlikely to pass as is, many of its provisions could find their way into final legislation if bipartisanship prevails.

The Senate Energy and Natural Resources Committee passed its own legislation, the Energy Policy Modernization Act, on July 30 by a bipartisan 18-4 vote.

The package, crafted by Chairwoman Lisa Murkowski (R-Alaska) and ranking member Maria Cantwell (D-Wash.), also would expedite LNG projects and streamline the federal permitting process. It includes measures to improve energy efficiency and cybersecurity and encourage hydropower and geothermal development.

Below is a summary of the House bill’s major provisions affecting the electric industry:

RELIABILITY

Fuel Security

The bill would require traditional vertically integrated utilities to incorporate “reliable generation” into their integrated resource plans, defining it as generation facilities with firm-fuel contracts, dual-fuel capability or sufficient on-site fuel to operate “for the duration of an emergency or severe weather conditions.” (Section 1107)

The requirements would not apply to companies engaged in competitive, unbundled retail electric sales.

FERC Reliability Review

FERC, in consultation with the North American Electric Reliability Corp., would be required to conduct reliability analyses of any federal rule affecting electric generators that is expected to result in an annual effect on the economy of at least $1 billion. The FERC review would evaluate the impact of the rule on electric reliability; resource adequacy; the nation’s electricity generation portfolio; the operation of wholesale markets; electric transmission lines; and natural gas pipelines. (Section 1108)

RESILIENCE

Hardening

The bill would require all utilities to develop plans for improving the resilience of their systems against physical sabotage, cyberattacks, electromagnetic pulses, geomagnetic disturbances, severe weather and earthquakes. Among the measures that utilities may consider are the hardening of distribution facilities; technologies that can isolate or repair problems remotely, such as advanced metering and monitoring and control systems; cybersecurity measures; distributed generation; microgrids and non-grid-scale energy storage. (Section 1107)

State regulators “shall consider” authorizing spending on such improvements, the bill says.

The legislation also establishes a competitive grant program for states and local governments for spending on resilience and reliability. (Section 1201)

Strategic Transformer Reserve

The bill would authorize the creation of a stockpile of large power transformers and trailer-mounted mobile substations to recover from the threats listed above. (See “Hardening.”)

The issue caught Congress’ attention as a result of the April 2013 rifle attack on Pacific Gas and Electric’s Metcalf substation and a campaign by former FERC Chairman Jon Wellinghoff to raise awareness of the grid’s vulnerabilities. Wellinghoff cited a 2013 FERC analysis that he said concluded that an attack that disabled nine critical substations could cause an extended blackout in the continental U.S. (See Report: Sabotage Threat Uncertainty Could Lead to Wasteful Spending.)

The Energy Department would be required to develop a plan for the reserve and identify preferred funding options, including fees on owners and operators of bulk-power systems and critical electric infrastructure, federal appropriations, and public-private cost sharing. (Section 1105)

Grid Security Emergencies

If the president declares a grid security emergency, the Secretary of Energy would have authority to order measures to protect or restore the reliability of critical electric infrastructure. (Section 215A)

FERC

Merger Authorization

It would limit FERC review of merger and consolidation acquisitions to those of $10 million or more. (Section 4222)

FERC Enforcement

FERC would be required to create an Office of Compliance Assistance and Public Participation to “promote improved compliance with commission rules and orders.” (Section 4211)

The proposal is an apparent response to complaints by some in the Washington energy bar that FERC’s Office of Enforcement, formerly headed by Chairman Norman Bay, is unfair and heavy handed. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)

The office would “promote improved compliance” with commission rules through outreach and publications and, “where appropriate, direct communication with entities regulated by the commission.’’

The provision is intended to provide entities subject to FERC regulation “the opportunity to obtain timely guidance for compliance with commission rules and orders” — an opportunity FERC says it already offers through “no-action” letters.

RTOs/ISOs

GAO Study

The Government Accountability Office would be required to conduct reports on each RTO’s and ISO’s “market rules, practices and structures.” (Section 4221)

The grid operators would be judged on a number of issues, including whether they produce just and reasonable rates; facilitate fuel diversity, reliability and advanced grid technologies; and promote “equitable treatment of business models, including different utility types.”

GAO also would evaluate the transparency of grid operators’ governance structures and stakeholder processes as well as the transparency of dispatch decisions, including the need for out-of-market actions and the accuracy of day-ahead unit commitments.

The report also would review how well grid operators facilitate “the ability of load-serving entities to self-supply their service territory load.”

The American Public Power Association, which opposes mandatory capacity markets, said the bill doesn’t go far enough. The group said the bill doesn’t address problems faced by public power utilities “forced to participate in the FERC-blessed mandatory capacity markets and is silent on the issue of self-supply for such LSEs.”

APPA, which represents more than 2,000 community-owned, not-for-profit utilities, said it wants the legislation changed to allow wholesale markets to “become more affordable and workable for public power utilities that are willing and able to build a variety of power generation facilities if not blocked from doing so by rules skewed toward certain market participants.”

Financial traders could benefit from a requirement that RTOs ensure “the proper alignment of the energy and transmission markets by including both energy and financial transmission rights in the day-ahead markets.”

Industry sources said the provision would encourage more widespread use of products similar to PJM’s up-to-congestion trades and ERCOT’s point-to-point congestion hedges.

Capacity Markets

RTOs and ISOs operating capacity markets would be required to provide to FERC an analysis of how the markets use competitive forces and include “resource-neutral” performance criteria. FERC would be required to report to Congress on whether each market meets the criteria and make recommendations for those that don’t. (Section 215B)

INFRASTRUCTURE

Deadlines

A final decision on a federal authorization for gas pipelines would be due no later than 90 days after FERC issues its final environmental document, unless a schedule is otherwise established by federal law. (Section 1101)

It would require the Energy Department to act on applications for LNG export facilities within 30 days of the conclusion of reviews under the National Environmental Policy Act. (Section 3006)

Frank Macchiarola, executive vice president for government affairs at America’s Natural Gas Alliance, praised the bill, saying that it “recognizes and seeks to maximize the opportunities presented by our nation’s domestic energy abundance.” ANGA represents independent natural gas exploration and production companies in North America.

Carbon Capture

The Energy Department would be required to evaluate all carbon capture and sequestration projects funded by the agency every two years. (Section 1109)

Hydropower

The bill would reauthorize hydroelectric production incentives through fiscal year 2025 and require FERC to minimize infringement on private property rights in issuing hydropower licenses. (Sections 1301-1304)

FERC would be authorized to issue exemptions from licensing requirements for development of new hydropower projects at existing non-powered dams.

It would build on changes in two bills enacted in 2013 that streamline regulations on small hydropower sites. A 2012 Energy Department report said the powering of non-powered dams could unlock 12 GW of generating capacity. (See Tiny Hydro Projects Joining Generation Mix in PJM.)

APPA said it was disappointed that the bill does not include “substantive” licensing reform.

“The current hydropower licensing process must be reformed so that public power and other utilities can increase reliable emissions-free hydropower generation without unnecessarily prolonged resource agency review,” it said.

The bill would provide special relief for one hydro project, however.

The developers of the proposed hydro project on the U.S. Army Corps of Engineers’ W. Kerr Scott Dam on the Yadkin River in North Carolina would have an additional six years to start construction under the bill. Wilkesboro Hydropower has proposed adding a turbine that would generate 2 MW at the unpowered dam.

FERC granted the developers a license in July 2012 giving them two years to begin construction and five years to complete it. In May 2014, FERC granted Wilkesboro Hydropower a two-year extension (P-12642-007).

Under the Federal Power Act, FERC told the developers, the deadline for starting construction may only be extended once.

October 2, 2015

PJM Members OK $2,000/MWh Energy Market Offer Cap

By Suzanne Herel

VALLEY FORGE, Pa. — The Markets and Reliability Committee voted overwhelmingly Thursday to raise the energy market offer cap to $2,000/MWh in a move that outgoing CEO Terry Boston called “the stakeholder process at its best.”

The MRC approved the new cap by an unweighted 84-17 margin, after which the Members Committee gave final approval by voice vote.

Boston said the Board of Managers would approve the new framework and PJM would be filing a Tariff change with FERC within a couple of weeks.

He apologized for not having the Tariff language ready before the vote, saying, “We were not as optimistic as we should have been about this getting approved this morning and afternoon.” He said the language would be made available to members a few days before the FERC filing.

Boston appeared touched by the vote, which comes as his seven-year tenure nears its end. “In the first meeting of the year, after this was voted down last year, I begged for consensus,” he recalled.

There was a smattering of applause when the vote was revealed at the MRC, and many who had sparred this year over the issue offered praise to PJM staff, each other and the four entities who agreed to withdraw their own proposals in favor of the simplified plan: Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3) and the Independent Market Monitor.

“It’s really cool that we were able to pull this off given the short time frame,” said Marji Phillips of Direct Energy, which had initiated the first of the four proposals. “I want to compliment everyone who supported this — especially when I was yelling at you at the last meeting.”

Pepco Holdings Inc.’s Gloria Godson called the vote “a beautiful thing to behold.”

The Details

The proposal caps cost-based offers at $2,000/MWh and allows them to set LMPs, with market-based offers allowed to equal cost-based ones. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through after-the-fact review and subsequent make-whole payments.

Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.

Jeff Whitehead of Direct Energy, whose proposal would have raised the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers, said the company was willing to back the compromise because it ensures “that as much generator compensation cost is recovered as possible in energy prices, which are hedgeable, and something load servers can compete on.”

“Uplift is not [hedgeable] and is a cost that gets rolled into risk adders that get passed on to consumers,” he added.

Likewise, David “Scarp” Scarpignato of Calpine said P3 didn’t believe the consensus proposal offered the “proper price formation,” but the group was willing to support it because it does allow generators to recover costs and raises the level that can set LMPs.

Temporary Change; FERC Action Expected

Some of those who opposed raising the cap previously — or thought the compromise was insufficient — were willing to support what is now assumed to be a temporary solution. FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

Exelon’s Jason Barker, who at the last meeting on the issue had criticized the framework, supported it Thursday as “an improvement over the status quo” and said he hoped FERC would improve on the filing. “We will look forward to FERC … recognizing flaws inherent in this proposal,” he said. (See Consensus Near on PJM Energy Market Offer Cap?)

Similarly, Dynegy’s Jason Cox said, “Dynegy reluctantly supports this compromise as a way to ensure that our costs are covered until FERC acts. We believe that we should not allow market distortions and continue to support potential massive uplift during critical periods.”

Susan Bruce of the PJM Industrial Customer Coalition said her group continued to have concerns over the proposal but offered support in return for a promise from the Market Monitor and PJM that there would be “robust reporting” on offers between $1,000, the current cap, and $2,000.

Delaware, Maryland Unconvinced

Representatives of state commissions generally opposed the proposal.

John Farber, public utility analyst for the Delaware Public Service Commission, asked that PJM consider releasing information about the heat rates of the generators setting the clearing price.

Walter Hall of the Maryland Public Service Commission said his agency remained unconvinced of a need to raise the cost cap.

Jim Jablonski of the Public Power Association of New Jersey pointed out that PJM fared better this past winter, which saw colder temperatures, than it had during the previous season’s polar vortex.

And, he said, “Capacity Performance is designed to provide a financial incentive to perform whenever needed and designed to eliminate future emergencies. Reliability, therefore, in our view is protected. We do not think a change is warranted. Two thousand dollars is not supportable except as a compromise, has no factual basis and definitely is going to be open to challenge.”

September 29, 2015

MISO: Complaint Mischaracterizes M2 Payment

By Michael Brooks

MISO told FERC last week that a group of wind generators alleging special treatment for external generators misunderstands the purpose of the M2 milestone payment in the RTO’s interconnection process (EL15-99).

The generators — EDF Renewable Energy, E.ON Climate & Renewables N.A. and Invenergy — complained to FERC earlier this month that revisions to MISO’s rules would exempt generation outside the RTO’s footprint from providing a cash-at-risk deposit in order to enter the definitive planning phase of the study queue. They argued this was unfair to internal generators, which are required to make the deposit, known as the M2 milestone. (See MISO Beats Challenge on Wind Exports.)

MISO said the complainants are asking that existing external generators seeking network resource interconnection service (NRIS) pay the M2 milestone, which is only required for new generation, regardless of its location. The RTO said the milestone isn’t charged to existing internal generation that only seeks NRIS.

The payment, approved by the commission in 2012, is to discourage speculative projects from entering the queue; withdrawals from the queue result in time-consuming and costly restudies.

“The M2 milestone is a ‘readiness’ milestone, designed to demonstrate that projects are ready to proceed to commercial operation,” MISO said. “External NRIS projects need not demonstrate ‘readiness’ because they must be ‘existing’ generators by definition under the MISO Tariff.”

MISO also disputed the complaint’s claim that not having to paying the M2 milestone gave external generators an unfair competitive advantage. Because it treats existing generation the same regardless of location, MISO said, “under complainants’ theory, internal NRIS-only projects within MISO also would have an unfair advantage, and by extension, also should pay the M2 milestone. Such a position is a collateral attack on the commission-approved Tariff that provides for different payments for NRIS-only projects as just and reasonable.”

‘Unripe Complaint’

MISO also criticized the generators’ decision to file an ‘unripe complaint,’ saying that the language of the revisions was not final. The RTO said such filings circumvent the stakeholder process and that FERC should continue to discourage them.

The generators said that their decision to file was based in part on an e-mail from MISO to Wind on the Wires that said the Business Practice Manual revisions concerning M2 milestone payments was final.

The Planning Advisory Committee in August tabled WoW’s proposal that all external generators seeking NRIS pay a portion of the M2 milestone.

The issue was to be taken up again at the PAC’s Sept. 16 meeting but was struck from the agenda at the request of WoW’s Sean Brady.

Brady said he asked to remove the item from the agenda because of MISO’s email. “Making the BPM language effective immediately indicated that this matter was resolved and a vote on the M2 milestone payment was moot,” he said.

September 29, 2015

Talen Seeks Change in Divestiture Options

By Rich Heidorn Jr.

Talen Energy asked FERC on Friday to allow it to sell four generators totaling 1,351 MW in eastern PJM to satisfy divesture conditions the commission set in a December order approving the company’s formation (EC14-112).

In their application to spin off their generation into the new company, PPL and Riverstone Holdings proposed two mitigation packages.

One involved divestiture of six Riverstone plants, and one PPL plant, in New Jersey and Pennsylvania totaling 1,315 MW. The second involved the same six Riverstone plants, plus the 399-MW Crane coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania, for a total of 1,346 MW. (See PPL, Riverstone Accept FERC Mitigation Plan on Talen Spinoff.)

Talen now says it wants to replace the two divestiture packages with a third involving the Crane plant and three former PPL generators in Pennsylvania: the 660-MW Ironwood combined-cycle plant, the 248-MW Holtwood hydro plant and the 44-MW Wallenpaupack hydro generator.

Talen said its request was the result of its inability to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of both previous divestiture options.

The Bayonne plant provides steam to a tank terminal storage facility, which owns the land beneath the generator. The storage facility is owned by a subsidiary of Macquarie Infrastructure Co., the Australian conglomerate.

Macquarie informed Riverstone last October of its intention not to extend the lease on the generator. (In February, Macquarie agreed to purchase the nearby Bayonne Energy Center, a 512-MW gas-fired generator, from ArcLight Capital Partners.)

Talen said efforts to negotiate an extension of the lease beyond its current expiration in October 2018 “proved futile,” forcing it to retire the plant effective Nov. 1, 2018.

“Accordingly, divesting the Bayonne facility could prove challenging,” Talen said. The proposed “Option 3” divestiture package will provide “the market more flexibility to identify the assets more highly valued by potential purchasers,” it said.

Talen said the revised divestiture plan would have essentially the same reduction in the company’s market power.

The company — which is required to complete its divestiture by June 1, 2016 — asked FERC to rule on its request by Nov. 30.

September 29, 2015

Federal Briefs

FERC has agreed to a pre-filing review of Columbia Gas Transmission’s proposed 165-mile natural gas pipeline in West Virginia. Columbia said the formal application of the $2 billion Mountaineer Express Project will be filed in April. If approved, construction will begin in the second half of 2017.

The proposed pipeline is designed to give producers in the Marcellus and Utica shale regions a new gateway to markets in the east. The pre-filing process, which involves a series of public scoping sessions, allows the pipeline operator to modify its design before submitting a formal application.

More: Associated Press

Senate Democrats Ask Obama to Block Arctic Drilling

A dozen Democratic U.S. Senators last week sent a letter to President Obama asking him to block any more drilling in the Arctic Ocean. The senators had previously opposed Royal Dutch Shell’s drilling program in the Chukchi Sea, which Obama allowed.

“You have stated many times that America must reduce our greenhouse gas emissions and build our capacity for clean, renewable energy,” the letter reads. “Allowing Shell to expand fossil fuel drilling in the Arctic is incompatible with this imperative and with your commitment that the United States will lead the global effort to address climate change.”

The letter was signed by Sens. Sheldon Whitehouse (R.I.), Jeff Merkley (Ore.), Patrick Leahy (Vt.), Ben Cardin (Md.), Bernie Sanders (Vt.), Al Franken (Minn.), Richard Blumenthal (Conn.), Brian Schatz (Hawaii), Martin Heinrich (N.M.), Ed Markey (Mass.), Cory Booker (N.J.) and Gary Peters (Mich.).

More: The Hill

NRC Inspecting Failure of Control Valves at Callaway

The Nuclear Regulatory Commission is conducting a special investigation into the failure of three of four steam generator water-flow control valves at Ameren’s Callaway nuclear plant in Fulton, Mo.

The failures were noted in three separate instances: one in August 2014, one in December 2014 and a third at an unspecified date. The 2014 incidents were related to a system modification. The third instance was also related to the same system and has since been corrected.

“The purpose of this special inspection is to better understand the circumstances surrounding the valve failures, determine if the licensee’s extent of condition review was sufficiently comprehensive and review the licensee’s corrective actions to ensure that the causes of the failures have been effectively addressed,” NRC Region IV Administrator Marc Dapas said. Callaway is a 1,190-MW single-unit station that went commercial in 1984.

More: POWER Magazine

EPA Hears Criticism of Proposed Methane Emission Rule

Representatives of the oil and gas industry told the Environmental Protection Agency that its proposed rules controlling methane emissions could kill the incentive to produce natural gas.

Industry representatives shared their views at a meeting in Colorado hosted by EPA to hear feedback on the proposed rule, which would cut emissions by 40 to 45% by 2025 compared with 2012 levels. The agency said the rule could add $420 million annually to the cost of energy extraction but would reduce health care costs by up to $550 million a year.

But Kathleen Sgamma of the Western Energy Alliance said the rule would push up the price of natural gas and maybe convince industrial consumers to switch back to dirtier fuels, such as diesel. She and other industry officials noted that while the rules only target the oil and natural gas industries, other industries, such as agriculture, produce significant amounts of methane emissions but would remain unregulated.

More: Associated Press

PennEast Files FERC Application for Marcellus Shale Gas Pipeline

A group of New Jersey and Pennsylvania utilities filed a formal application with FERC to move forward with the controversial $1 billion PennEast Pipeline project to tap into Marcellus Shale natural gas production, saying the new pipeline would deliver low gas prices, stable electricity rates and a manufacturing renaissance to the region.

The 118-mile pipeline, which is fiercely opposed by environmentalists and adjoining landowners, will deliver 1 billion cubic feet of gas a day from the Marcellus gas region to markets in Pennsylvania and New Jersey. About 72% of the capacity is committed to local distribution companies, including UGI Utilities in Pennsylvania and Public Service Electric & Gas, South Jersey Gas, Elizabethtown Gas and New Jersey Gas in New Jersey. Power plant operators and gas producers have locked up the rest of the capacity.

More: The Philadelphia Inquirer

Northern Pass Tx Line Review Period Extended

The Energy Department has agreed to reopen the environmental study of the Northern Pass transmission line, which would import hydroelectric power from Canada.

Developer Eversource Energy made enough changes to the transmission line’s route to warrant preparation of a supplement to the draft Environmental Impact Statement, the department said. Political leaders and environmental groups asked the department to reopen the environmental review of the project in light of the new tower heights, configuration and locations.

The department is also extending the public comment period on the draft EIS to Dec. 31, 2015, and postponing the public hearings to a date to be determined before the end of the new public comment period. Eversource said it does not expect the changes to the schedule will delay the project.

More: New Hampshire Union Leader

Feds Plan Auction of Offshore Leases for Windmills

Federal officials will seek bids to lease nearly 344,000 acres of ocean floor off of New Jersey on Nov. 9. If fully developed, the area could provide enough power for 1.2 million homes, according to the Interior Department and the Bureau of Ocean Energy Management.

Thirteen companies have qualified to bid on the leases in an area which runs roughly from Long Beach Island to Cape May. Gov. Chris Christie’s administration would have to approve the projects.

More: Associated Press

FERC Announces 2016 Meeting Dates

FERC on Monday announced its 11 open meeting dates for 2016. As in past years, the commission will not meet in August.

More: FERC

September 29, 2015

Stakeholder Soapbox: Electric Market Offer Caps are a Vital Consumer Protection

By Christopher Hargett, Diana McNally-Barsotti and Joel Yu

The benefits of wholesale electric markets can only be achieved when competition is effective. FERC must not only provide for markets that benefit customers but must also not lose sight of the importance of protecting markets (and customers) against market power abuses. To this end, the focus on customer impacts must remain as FERC considers changes to existing electric market offer caps. Some organized markets have sought to increase offer caps to levels above $1,000/MWh because of the impact seen from high natural gas prices during the extreme weather events in the winter of 2013/14. Such efforts are overly reactionary to one winter season experience and do not indicate that a change in policy and consumer protection is warranted at this time. Moreover, they are predicated on the misguided belief that increasing the offer cap is the only means to properly compensate generators for their performance. Since the advent of organized electric market operation, there has been no evidence that a change to this important offer cap is needed.

Protecting Electric Customers

Bids into wholesale electric markets and associated federal regulations are based on the premise that, absent market power, competitive market pressure should discipline offers to levels at or near suppliers’ marginal costs required to cover short-run operations (including opportunity costs). However, because marginal suppliers may be limited during peak periods, and because the market demand-side load is generally not price responsive, a truly functional competitive market may not be present. As a result, offer caps are necessary to protect customers from excessive prices as generation resources become scarce during high demand periods. Moreover, they take into account the fact that “prices are generally more sensitive to withholding and other anticompetitive conduct under high load conditions,” when more costly supply is required.[1]

Due to the experience of the 2013/2014 winter, organized electric markets are seeking to promote resource availability and performance in ways that add competitive forces to the market’s supply side during peak demand hours. While the organized electric markets have well developed mitigation measures in place, there is no substitute for the $1,000/MWh offer cap as a fail-safe protection to customers. Furthermore, energy market offer caps serve as a valuable incentive for generators to minimize fuel costs, which in turn translates into customer benefits through fair electricity prices. Moreover, the existing cap encourages generators to limit their reliance on spot fuel purchases. This incentive is not only good for economics but also for the reliable operation of the electric system. And, under existing rules, individual generators are able to be compensated for documented increased fuel costs when incurred. Such provisions protect generators as well as consumers, and any change to the offer cap should consider the experience with such requests, as discussed below.

It is also inaccurate to claim that higher short-term price signals will result in better resource performance and help maintain reliability. This hypothesis was proven false in PJM’s experience over the past two winters. In response to high natural gas prices in winter 2013/14, PJM temporarily increased its offer cap to $1,800/MWh for the 2014/15 winter but ultimately had no resource clear above $1,000/MWh. In fact, while prices cleared below $1,000/MWh, generators boosted performance year-over-year. When PJM experienced its all-time winter peak in February 2015, the generator forced outage was 13%, compared to 22% in January 2014. In New York, historical data supports this conclusion as well, as no generator in NYISO has ever demonstrated that it incurred costs above the $1,000/MWh offer cap, including the 2013/14 winter when natural gas prices spiked to unprecedented levels.

Regional Coordination

FERC should not act on a generic basis to modify energy market offer caps across organized markets, nor should it allow differences in offer caps between regions. Contrary to FERC’s goal, any difference in offer caps in neighboring regions would create unnecessary seams issues and could result in inefficient bidding behavior between regions. That’s because suppliers could concentrate their offers into the market with the higher offer cap, forcing operators in the lower offer cap region to call on resources out-of-market to meet their system reliability needs. This would unnecessarily increase costs to consumers in both regions. Such bidding incentives are an unjust application of market power and should be avoided. True price flexibility and differentiation between markets are, and should continue to be, a reflection of infrastructure constraints.

The Right Approach

Price signals are not the only tool available to compensate suppliers according to their cost of operation.[2] Out-of-market payments are the appropriately tailored solution when considering the precarious alternative. Taking this approach ensures that generators are compensated for their performance and for meeting customer needs in extreme conditions, without creating potential market vulnerabilities at all other times to the detriment of electric customers. Out-of-market payments address these rare costs in a fair manner for generators and customers and should be transparent for all market participants. Trends should be monitored, and any changes, if considered in the future, should be based on information about such payments.

[1] 2014 State of the Market Report for the New York ISO Markets, Potomac Economics, May 2015, p 17.

[2] PJM recently received FERC approval for its Capacity Performance program, whereby units that perform under high demand conditions are rewarded. In New York, NYISO is undertaking several initiatives to bolster performance while ensuring compensation including clarifying market mitigation measures and fuel availability reporting.

Christopher Hargett, Diana McNally-Barsotti and Joel Yu are senior policy advisors at Con Edison. Subsidiaries Con Edison Company of New York and Orange and Rockland Utilities are transmission owners within NYISO. A subsidiary of Orange and Rockland Utilities, Rockland Electric, is a transmission owner within PJM.

(Editor’s Note: This column marks the beginning of an occasional RTO Insider feature, Stakeholder Soapbox. If you’d like to contribute your own op-ed article, contact Rich.Heidorn@RTOInsider.com.)

September 29, 2015

Clean Power Plan, REV Highlight IPPNY Conference

IPPNY President Gavin Donohue said generators are willing to work with New York regulators regarding the state’s capacity market but said it’s unclear what changes are being sought. “What problem are we trying to solve?” he asked. “We’ve had stresses on the system during the winter [and] during the summer the last few years and quite frankly the system has worked very well.”

IPPNY Chairman John Reese, senior vice president of US Power Generation, called on state regulators to demonstrate “courage” by pushing for an increase in the cost of new entry. “Nobody believes you can actually build or enter the New York market for the current cost of new entry price,” he said. “Upstate New York capacity prices are lower than PJM, are lower than New England. Those are not survivable.”

Kenneth Daly, CEO of National Grid New York, speaks as James Gallagher, executive director of the New York State Smart Grid Consortium (left), and UBS Securities analyst Michael Weinstein (right) listen. Daly said the next five years of the state’s Reforming the Energy Vision initiative will be transitional, as state regulators evaluate demonstration projects and determine which worked and which did not. “Ten years from now is when we’ll start to see game changers. Battery storage is clearly the one biggest change that our industry will face. And if we go through another investment cycle these next five years of modernizing our grids we’ll then have far greater capability in that second five-year period to integrate renewables, to give customers choice, to use more local demand response.”

Richard Dewey, executive vice president of NYISO (left), and John Shelk, president of the Electric Power Supply Association (right), said EPA’s final Clean Power Plan addressed problems with the draft rule. Dewey said the preliminary rule “would have left us with about one to three days of oil burn in New York state – which is about 100 less than we typically need [for] reliability.” Shelk said the final rule fixed an “artificial” advantage for new gas plants. But he said it remains unclear how regions outside the Regional Greenhouse Gas Initiative will incorporate carbon costs in economic dispatch. “Clearly we’re not going to have — certainly not on day one — a price on carbon in the rest of the states,” he said.

September 29, 2015

Integrated System to Join SPP Market Oct. 1

By Tom Kleckner

SPP will welcome the Integrated System and its three primary entities as full members Thursday, extending its footprint into Big Sky Country.

The IS — comprised of Western Area Power Administration-Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — expands SPP’s footprint to 14 states, adding the Dakotas and parts of Iowa, Minnesota, Montana and Wyoming.

It will add more than 5,000 MW of peak demand and 9,500 miles of transmission infrastructure to SPP’s responsibilities, while increasing its territory by 55% to 575,000 square miles.

“It’s a significant change for SPP, considering the amount of area we’re responsible for and the parties we’re responsible for as members,” Executive Vice President Carl Monroe, SPP’s chief operating officer, told RTO Insider. “We’re extending our footprint and ensuring SPP’s members will get the benefits of our services.”

While SPP expands with the IS, indications are it will not gain another potential member with Lubbock Power & Light’s announcement last week that it will join ERCOT in 2019.

Reliability Coordination Began June 1

SPP has been providing reliability coordination for the IS since June 1, monitoring power flow and managing congestion while WAPA, Basin Electric and Heartland dispatched their generating resources. The three entities will transfer functional control of their facilities to SPP at midnight Wednesday night and become active participants in the Integrated Marketplace, forming the new Upper Missouri transmission zone.

Other entities will become full SPP members Thursday, including the East River Electric Power Cooperative, Northwest Iowa Power Cooperative and Corn Belt Power Cooperative. It will be SPP’s first major membership additions since 2009, when Nebraska’s major utilities joined the RTO, and boosts its membership to 92.

“We’re really looking forward to Oct. 1,” Monroe said. “We have very good relationships with those parties, and some are already participating in SPP’s working groups.”

SPP prides itself on being a stakeholder-driven organization and its governance model was a major reason the IS joined. Heartland CEO Russell Olson cited the RTO’s “collaborative process” in a statement announcing the move last year.

“They felt they would have a voice,” Monroe said, “and that made a difference in their decisions.”

Joining SPP gives IS members access to the RTO’s markets. Several current members have already credited market savings with allowing them to reduce the size of rate increases or providing additional pricing efficiencies through a broader pool of resources.

“I would guess that would be able to happen again from expanded footprint,” Monroe said. “Savings in the energy market will reduce the cost of wholesale energy. Depending on how each entity handles its customers, it could be a reduction in costs.”

Monroe said SPP’s increased membership also will reduce RTO service fees for existing members. “Everyone will be paying less as a ratio than they would have paid before,” he said.

WAPA, Basin Electric and Heartland began discussing joining an RTO four years ago to increase their options for buying and selling power. All three conducted public hearings and assessments before determining last year that SPP was the best fit. FERC approved the move in November.

“We felt that SPP was a solid philosophical match for our cooperative,” said Paul Sukut, Basin Electric’s CEO and general manager.

WAPA will become the first federal power marketing administration to join an RTO. WAPA spokesperson Lisa Meiman said joining SPP “alleviates the marketing restraints” the agency was facing in delivering firm power to its customers.

Because the Energy Policy Act of 2005 placed conditions on power marketing administrations joining RTOs, SPP did have to “accommodate” WAPA’s “unique needs,” Meiman said. SPP modified its Tariff to exempt WAPA from regional cost-sharing charges. WAPA also is exempt from congestion and marginal loss charges when it is marketing and delivering federal hydropower to its federal load, she said. FERC issued an order Monday approving SPP Tariff changes accommodating WAPA (ER15-2350).

WAPA will merge its Eastern Interconnection balancing authority into SPP’s balancing authority, and its Eastern and Western Interconnection transmission facilities will be incorporated into the new Upper Missouri Zone. Meiman said WAPA will remain a transmission operator and develop transmission rates, revenue requirements and other necessary rates for use in SPP’s Tariff.

WAPA’s Western Interconnection BA will not become a part of SPP’s BA, nor will UGP’s Western Interconnection generation and load become part of the Integrated Marketplace.

Lubbock Sees Savings in ERCOT

Excitement over the addition of the IS was tempered last week when Lubbock Power & Light, which receives its energy through SPP member Xcel Energy, said it will join ERCOT to reduce its energy and capacity costs. (EDITOR’S NOTE: An earlier version of this story incorrectly stated that Lubbock Power & Light was an SPP member.)

The LP&L Electric Utility Board met with the Lubbock City Council on Sept. 24 to outline its transition to ERCOT, which manages 85% of the Texas grid. LP&L is the third-largest municipally owned electric company in the state, after San Antonio and Austin.

“That’s their decision,” Monroe said. “We’re a voluntary organization. If that’s what they intend to do, they make those choices that are best for their organization.”

LP&L says significant transmission infrastructure will be needed to interconnect with ERCOT, and that approval, certification and construction will likely take four years. The process began with a feasibility study, which was approved by the Public Utility Commission of Texas last week.

The utility says taking advantage of smaller, cheaper contracts in the ERCOT market will save it $20 million annually over what it currently spends in a long-term wholesale contract with Xcel Energy. LP&L’s three old, small power plants are seldom committed.

Lubbock also will be freed of about $40 million in annual capacity fees in ERCOT’s energy-only market.

LP&L also said it will benefit from Texas’ diversified energy portfolio and a simplified regulatory environment.

Monroe said SPP hasn’t had any conversations with LP&L or Xcel or looked at the implementation plans. “I’m not sure what [the announcement] means,” he said.

In a press release, Xcel expressed disappointment and said the city’s proposal will increase costs for customers in both ERCOT and the areas it serves in SPP. Noting the “significant investments” it has made in the area’s high-voltage network, Xcel said “Lubbock’s portion of the annual cost of these investments will be added to the costs Xcel Energy customers in Texas and New Mexico already pay.”

Xcel also said its long-term power supply agreement for a portion of Lubbock’s power needs through 2044 could be “impacted” by the utility’s move to ERCOT. According to LP&L, it will honor the contract by purchasing 170 MW from Xcel after June 1, 2019, which means it will remain interconnected with SPP.

By joining ERCOT, the city says it would also escape FERC regulation. As a Texas-only grid operator, ERCOT is regulated by the PUCT and the state legislature; FERC governs SPP and other interstate providers.

The PUCT and ERCOT would both have to approve LP&L’s move.

September 29, 2015

PJM MRC and Members Committee Preview

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 at the PJM Conference and Training Center in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report. (Note: The meetings were delayed by a week because of the pope’s visit to Philadelphia and relocated to the CTC because facilities were not available in Wilmington on the new date.)

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

Manual 40: Certification and Training Requirements. Makes miscellaneous edits; clarifies concepts, roles and responsibilities related to PJM’s systematic approach to training; updates the process for member training and PJM certification and reflects changes in terminology of operator titles.
Manual M10: Pre-Scheduling Operations. Adds procedures for maintenance outages under Capacity Performance rules: the requirement for PJM members to provide estimated “early return time” for planned outages; ensures that PJM will coordinate rescheduling if it withdraws or withholds approval of a planned outage; references PJM’s authority to withhold or withdraw approval of maintenance outages with at least 72 hours’ notice; adds requirement that maintenance outages be submitted at least three days prior to the operating day of their commencement.
Manual 14D: Generator Operational Requirements. Incorporates minor changes to the cold weather testing program for seldom-used generators. (See “Members Choose Status Quo on Winter Testing” in PJM Operating Committee Briefs.)
Manual 14B and 14A: Generation and Transmission Interconnection Process. Changes document how PJM will oversee transmission projects that have benefits in at least two categories, including baseline reliability upgrades, market efficiency and public policy. (See PJM Wins OK on Multi-Driver Tx Projects.)

3. PRICE FORMATION (9:30-10:30)

Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. The proposal, hammered out by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and the PJM Power Providers Group (P3), would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments. (See related story, Consensus Near on Energy Market Offer Cap?)

Members Committee

CONSENT AGENDA (1:20-1:25)

B. The committee will be asked to endorse Reliability Assurance Agreement revisions regarding external capacity rights. The rule change allows load-serving entities to meet their internal capacity requirements using historic resources under certain conditions: The percentage internal resource requirement is enforced only if the locational deliverability area has been separately modeled due to certain triggers; a fixed resource requirement entity is permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative are due four months prior to a Base Residual Auction instead of the current two-month deadline. (See IMEA Reaps Limited Relief from Capacity Rule Change.)

C. New Tariff language reflects the switch from eMkt to Markets Gateway.

ENDORSEMENT (1:25-2:25)

Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. (See MRC agenda item 3, above.)

September 29, 2015

NYPA Head Pledges ‘Most Advanced’ Utility

By William Opalka

SARATOGA SPRINGS, N.Y. — New York Power Authority CEO Gil Quiniones says the state-run company will be the “most innovative and advanced utility in the U.S. in a very short period” due to massive investments and its commitment to facilitate the remaking of the industry in the state.

Addressing the fall conference of the Independent Power Producers of New York, Quiniones said NYPA expects to spend $3 billion to $4 billion on infrastructure over the next decade, with nearly half of that total — $1.5 billion — in smart grid generation and transmission assets.

New York has embarked on the Reforming the Energy Vision initiative to transition to cleaner and more distributed generation. NYPA’s five-year strategic plan was written in the context of REV, he said.

That means a revamping of operating procedures and technologies that can accommodate distributed resources. “As we move into this REV world, we have to be sure that all this generation and transmission infrastructure works in synchronicity with the advent of distributed resources,” Quiniones said. “… Our grid has to be connected and smart and optimized and the only way to do that is to digitize it and use big-data analytics.”

NYPA has 16 power plants and 1,400 circuit miles of transmission, including one-third of the state’s high voltage system. It serves 51 small municipal and rural cooperatives.

One project now underway is the retrofit of the Massena substation, which Quiniones said will result in “the most advanced substation of its size in this country. It will be microprocessor-based, fiber optic-based; it will provide unparalleled situational awareness and operational flexibility.”

Last year, NYPA built a 15-MW microgrid on Rikers Island in New York City, which captures waste heat from the facility and runs parallel and synchronous to the utility system. It can island in the event of another city-wide power interruption, such as during Superstorm Sandy. This is intended to be the first of several microgrids NYPA will build.

NYPA is acting as a facilitator with vendors SolarCity and SunEdison to install solar panels at the 698 school districts in the state. “I predict there will be a very fast ramp up of solar in our public schools,” Quiniones said.

In October, six drones from different vendors will be tested to monitor the condition of power lines. The authority also is beginning to monitor power line conditions and operations with a robotic device from Hydro-Quebec.

Much of the innovation is taking place in the North Country, home to most of the state’s wind farms, whose variability stresses the system.

Other initiatives include:

Installing dynamic line rating technology sensors and intelligence so the system can know exactly how much power is being carried through its lines. This aids efficiency by acting as a “fast switch” as it can transfer as much as 300 MW from one line to another in milliseconds to prevent system overload;
Condition-based monitoring that would base equipment replacement on the condition of the asset rather than on manufacturers’ recommendations;
Transformer-testing software to prevent catastrophic events.