PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — The Market Implementation Committee last week approved rule changes that will help the Illinois Municipal Electric Agency to meet its capacity requirements with historic resources.

IMEA is among the load-serving entities that procured capacity resources outside of their locational deliverability areas to serve a portion of their load.

PJM’s Reliability Pricing Model capacity construct, which launched after IMEA obtained its external capacity, does not provide a way to allocate and maintain the benefits of historical resource and transmission service agreements — an issue that can increase an LSE’s costs if its LDA becomes modeled separately and binds in an auction.

The Independent Market Monitor had expressed concern that PJM’s initial proposed solution was overly broad. But it agreed with the revised solution, which covered only LSEs subject to fixed resource requirements (FRR).

FRR entities such as IMEA are subject to a percentage internal resource requirement (PIRR) if their zone is modeled separately, voiding the use of their historic capacity resources.

The solution approved by members makes three rule changes:

The PIRR is enforced only if the LDA has been separately modeled due to certain triggers;
An FRR Entity would be 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 would be due four months prior to a Base Residual Auction instead of the current two-month deadline.

PJM Asked to Consider Masking FTR Ownership

PJM would consider masking ownership of financial transmission rights under a problem statement presented by DC Energy’s Bruce Bleiweis at the MIC last week.

Currently, all RTOs publish the identities of FTR holders when posting auction results. By contrast, in all other market transactions, such as capacity auctions and daily energy auctions, PJM does not disclose the ownership, Bleiweis said.

“I think the inequity is transparent to everyone here,” Bleiweis said. “We don’t see any reason FTRs should be treated differently” than any other power product.

FERC initially allowed the current transparency to spur a secondary FTR market. Now that this market is established, this disclosure is no longer necessary, Bleiweis argued. He said that knowing another company’s position could lead to unfair competitive advantages.

There was some confusion as to what exactly is disclosed in other products, however. Carl Johnson of the PJM Public Power Coalition said he thought PJM published capacity positions of companies once the delivery year began.

PJM’s Tom Zadlo answered that only a list of cleared units is posted. Bleiweis said that if the problem statement is approved at next month’s MIC meeting, he would work with PJM to generate a simple list showing exactly what is posted for each product.

Marji Philips of Direct Energy said she “remains very concerned” by the proposal. In the past, she said, market participants have identified “mischief” in the FTR markets that the Independent Market Monitor and PJM did not catch, based on the increased transparency.

Bleiweis said PJM’s effort would be consistent with ISO-NE, which approved a move to aggregate FTR ownership at its November 2014 Markets Committee meeting.

— Michael Brooks and Rich Heidorn Jr.

August 18, 2015June 15, 2023

Federal Briefs

The Nuclear Regulatory Commission has determined that NextEra Energy’s Seabrook Station could operate for another 20 years beyond 2030 without negative impact on the environment. NRC published its final report on the environmental impacts of renewing Seabrook’s operating license and gave the plant’s owners the green light to move to the next step in the re-licensing process.

“The NRC’s preliminary recommendation is that the adverse environmental impacts of license renewal for Seabrook are not great enough to deny the option of license renewal,” according to NRC, which based its findings on an environmental report submitted by NextEra Energy, consultation with federal, state and local agencies and NRC staff’s independent review and public comments.

A Safety Evaluation Report, the last step in the license renewal process, is scheduled for release in May. NextEra has been working through the renewal application since 2010.

More: New Hampshire Union Leader

Mass. Mayor to Ask FERC to Extend Meetings for Tennessee Gas Pipeline

The mayor of Peabody, Mass., wants FERC to add a special meeting near the city to allow the public to comment on Kinder Morgan’s plan to build a lateral from its Tennessee Gas Pipeline.

Mayor Ted Bettencourt said he would seek the additional meeting after he met with the Northeast Municipal Pipeline Coalition, a group opposing the pipeline. Kinder Morgan has said it wants to build the pipeline to provide fuel for power plants. The Northeast has experienced a shortage in natural gas during times of peak demand, such as frigid winter days and nights.

Several meetings have already been held concerning the pipeline, which is to run from Dracut, through Peabody and connect to an existing line in Danvers.

More: The Salem News

Ninth Circuit Throws out Suit Against FERC Curtailment Order

A panel of judges from the Ninth Circuit Court of Appeals has ruled that a group of wholesale electricity customers has no standing to sue FERC for requiring it to pay for curtailing wind generation in times of unusually high hydro generation.

The customers had argued that the dispatch-curtailment mandate — originally put into place as a result of high expected hydro generation on the Columbia River — meant that increased generation prices would be passed on to them. FERC issued the curtailment policy to cover incidents of “last resort” when high water levels forced Bonneville Power Administration to generate electricity that exceeded demand. In order to preserve system integrity, FERC decided it could mandate curtailment by other generators.

The plaintiffs argued that the mandate exceeded FERC’s area of responsibility, as it dealt with generation rather than transmission. The judges noted that the plaintiffs may suffer harm from the rule but that they had no statutory standing under FERC rules.

More: Courthouse News Service

Report: Wind Could Replace Coal, Gas as Dominant Resources

The National Renewable Energy Laboratory released a report that shows that wind power’s capacity factor could reach 65%, exceeding both coal and natural gas.

The Department of Energy’s lab data indicates that increasing to a 65% capacity factor could reduce wind’s cost, improve transmission line efficiency and provide necessary power at times of peak demand. The report shows that if “near-term” technology and enough appropriate sites are used, the capacity factor of wind turbines could exceed both coal and natural gas. The report also indicated that new wind power technology on the horizon would mean that wind alone would be able to power the U.S. demand.

More: Greentech Media

NRC: Beaver Valley Nuclear Station Has Enough Staff for Emergencies

The Nuclear Regulatory Commission has determined that the emergency plan of the Beaver Valley Nuclear Power Station in Pennsylvania is adequate to meet the needs for any large-scale emergencies. The commission reviewed the new safety guidelines put into place following the 2011 Fukushima nuclear disaster in Japan.

All of the nation’s nuclear stations are undergoing a commission review of plans updated after the disaster.

More: Times Online

NRC Report Says Yucca Mountain Environmental Risk Low

A report issued by the Nuclear Regulatory Commission found that a nuclear waste repository at Yucca Mountain would pose “only a negligible increase” in health risk from radioactivity leaking into groundwater. The study is one of the final products of the funding for the Yucca Mountain project, which President Obama mothballed in 2010.

The report will be presented next month in Washington and Nevada.

More: Las Vegas Review-Journal

New Mexico Site Eyed for Storing Spent Nuclear Fuel

Holtec International has submitted documents showing its intent to file for a license to store spent nuclear fuel at a site in southeast New Mexico. The company said the facility would retain spent fuel from stations that are shutdown or in the process of decommissioning — Connecticut Yankee, Humboldt Bay, Kewaunee, La Crosse, Maine Yankee, Millstone Unit 1, Oyster Creek, Rancho Seco, Trojan, Yankee Rowe and Zion stations.

The letter of intent says that the site is 35 miles from any large population center. Holtec is asking the Nuclear Regulatory Commission for permission to store the fuel underground with the same system being used at Callaway and San Onofre stations.

Holtec said it is planning on filing its complete license application by June 2016.

More: FierceEnergy

NRC Dismisses Complaint Against San Onofre Station as Moot

The Nuclear Regulatory Commission has dismissed a complaint filed by an anti-nuclear organization against San Onofre nuclear generating station as moot because the station is being decommissioned. The Friends of the Earth filed the complaint against San Onofre owner Southern California Edison, alleging it failed to get approval for new steam generators before installing them.

The commission noted that fuel has been removed from the station and it is permanently closed, and so the complaint is unnecessary.

More: The Energy Collective

August 18, 2015June 15, 2023

PJM Stakeholders Seek ‘Miracle’ to Break Offer Cap Standoff

By Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM stakeholders last week launched another bid to change the $1,000/MWh energy offer cap, but consumer advocates said they were not optimistic about reaching consensus in time for next winter.

Marji Philips of Direct Energy proposed raising the cap to $2,700/MWh for cost-based day-ahead offers and price-based real-time offers — 50% more than the highest offers reported by PJM last winter.

“Everybody likes a piece of it and nobody likes the whole thing,” she said of those with whom she shared the proposal before the meeting. “So that means it must be pretty good.”

PJM’s Board of Managers asked stakeholders to make another attempt to reach consensus after efforts last year fell short. (See Members Deadlock on Change to $1,000 Offer Cap.) Philips and other PJM veterans said the $1,000 cap, which has been in effect for about 18 years, was set as a multiple of the highest prices seen at that time.

In January, PJM won FERC approval for a temporary waiver that allowed prices to rise as high as $1,800/MWh, but the RTO made it through last winter without having to invoke it. In the 75 days that the waiver was in effect, there were 54 cost-based offers between $1,000/MWh and $1,800/MWh, but none cleared.

PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked as high as $140/mmBtu.

Higher Cap Better for LSEs

Philips said raising the cap is better for load-serving entities such as her company, because higher LMPs can be hedged while uplift cannot. She said it would also reduce capacity prices because increased energy market revenue would cause a drop in the net cost of new entry (CONE). “Here’s an opportunity to control our destiny,” she said. “We’d rather see [stakeholders] filing [a change] than PJM.”

Philips said she had been reluctant to back a change to the cap on day-ahead offers but was convinced by PJM that it was needed to enable price convergence with the real-time market.

The proposal also would require changes to scarcity pricing rules to ensure that generation dispatched for reserves receives lost opportunity costs — which could be higher than the existing $1,000 cap — she said.

Philips said her goal was “incenting the market to do the right thing. We’re trying to keep PJM as a market and not as a cost-based system.”

PJM Endorses Proposal

PJM officials — who proposed a $2,700 cap on price-based offers and removing the cap on cost-based offers in a FERC docket on price formation in March (AD14-14) — said they would accept the proposal. “It is something we would consider to be acceptable,” said Stu Bresler, senior vice president of market services.

Jim Benchek of FirstEnergy thanked Philips for the proposal, calling it “a good starting point.”

Consumer Reps Wary

But consumer representatives were not quick to embrace it.

Carl Johnson, representing the PJM Public Power Coalition, said he did not think consensus could be reached in time for an Oct. 1 FERC filing — the deadline PJM officials have said is necessary to ensure new rules are in place for winter 2015/16.

Johnson noted that stakeholders were unable to reach agreement last year despite months of debate. “Even though the pope will be in [Philadelphia], I don’t think that’s going to be enough time to give us the miracle we need to come up with consensus,” he said.

“There’s a lot here that we will need to digest,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.

Griffiths said while consumer advocates are willing to consider lifting the offer cap for generators that can demonstrate costs above $1,000/MWh, they continue to have concerns about letting those offers set LMPs for the entire market.

Philips responded that while stakeholders can debate whether the cap should be lower than $2,700, not allowing high marginal prices to set LMPs is “antithetical to the entire market structure.”

Griffiths said later that his members are willing to consider market clearing prices above $1,000/MWh but that PJM had not demonstrated a spirit of compromise in last year’s efforts, saying the RTO’s unwillingness to consider a cap below $1,800 was “insulting.”

David Mabry, representing the PJM Industrial Customer Coalition, said any change in the cap should be accompanied by broader market power protections than current rules, which test only local market power. He cited the Independent Market Monitor’s charge in the 2014 State of the Market report that some generators appeared to engage in economic withholding during high demand hours in January 2014. (See Monitor: Winter Prices Boosted PJM Prices, Raise Withholding Concerns.) Mabry said cost-based offers should be limited to short-run marginal costs.

Consultant Roy Shanker called market power concerns a “red herring,” saying existing rules are sufficient. “If you misrepresent your costs, you’re in big trouble,” he said.

August 18, 2015June 15, 2023

Entergy Offers to Close Ark. Coal Plant to Meet EPA Haze Rule

By Tom Kleckner

Entergy has proposed closing one of its two largest Arkansas coal plants by 2028 and making modifications to the other to comply with the Environmental Protection Agency’s Regional Haze rule.

Entergy filed the proposal with EPA on Aug. 7, describing it as a “more reasonable, long-term, multi-unit approach” than the agency’s recently published federal implementation plan (FIP) for controlling the utility’s emissions. Entergy said its plan would achieve “virtually identical visibility benefits” as the EPA proposal but cost more than $2 billion less.

The company told EPA it would end coal-fired operations at its White Bluff plant by 2028, accept lower sulfur dioxide (SO₂) emission rates at its White Bluff and Independence plants and install nitrogen oxide (NO_x) control technology on its coal units within three years of the final FIP’s effective date — likely in 2016.

The EPA’s proposed FIP required installation of scrubbers and low-NO_x burners on the four units at White Bluff and Independence, and NO_x controls at Entergy’s gas/oil-fired Lake Catherine plant. The Regional Haze rule seeks to improve visibility in parks and wildlife areas by reducing particulate matter emissions.

The New Orleans-based company said its modeling — which it said “EPA should have conducted but failed to undertake” — indicates it does not need to invest more than $2 billion in scrubber technology at the plants and asked the EPA to amend the FIP accordingly.

Entergy said it would not be able to install dry scrubbers at White Bluff — which it shares with several other entities — until at least 2021, leaving only a few years to recover the approximately $1 billion investment. It said the EPA’s analysis incorrectly classified Independence as a best-available retrofit technology (BART)-eligible resource under the Clean Air Act and said the plant is well below EPA’s haze standards.

“Scrubbers at Independence are simply not necessary to ensure that visibility … nor are they justifiable based on EPA’s own analysis of the visibility benefits resulting from such a huge investment,” Entergy said, citing costs of as much as $1.53 billion to install scrubbers.

The utility also disagreed with the EPA’s analysis that proposed NO_x BART controls at Lake Catherine. Referring to its own study, Entergy said the NO_x controls would result in “inconsequential” visibility improvements.

Entergy said its approach “would ensure superior, long-term visibility benefits than would the proposed FIP” and a “dramatic decrease in [greenhouse gas] emissions, large reductions in SO₂ emissions … and large reductions in … NO_x emissions.”

White Bluff and Independence are both two-unit baseload coal plants capable of generating more than 1,600 MW each. The two plants date back to 1980 and 1983, respectively, and are ranked among the top 45 dirtiest coal plants by Environment America.

Lake Catherine is a 45-year-old, single-unit, gas/oil-fired plant capable of 750 MW. It is used primarily for peaking purposes.

Glen Hooks, director of the Sierra Club’s Arkansas chapter, praised Entergy for the decision to close White Bluffs but said the company should go further. “Although we’re excited about the announcement, we hope that it also spurs the company to take a hard look at its dirty and outdated Independence coal plant,” he said in a statement.

August 18, 2015June 15, 2023

PJM Planning Committee Briefs

Competitive developers expressed reservations last week about a PJM proposal to exclude transmission projects below 200 kV from competition.

PJM said projects below 200 kV are almost always allocated to one zone and thus automatically assigned to the incumbent transmission owner.

PJM’s Suzanne Glatz said the “voltage floor” would allow the RTO to eliminate the cost of evaluating competitive proposals in cases where the likely solution is a transmission owner upgrade. The voltage threshold would not apply to market efficiency projects.

Of 1,523 projects approved by the PJM Board of Managers under the Regional Transmission Expansion Plan, 104 (7%) were greenfield projects, of which only 13 (less than 1%) were allocated to more than one zone and thus open to competition, Glatz said.

In 2014, only two of 55 projects selected to correct violations below 200 kV resulted in solutions above 200 kV. Both projects were transmission owner upgrades.

“There’s very few that are coming out as potential greenfield [competitive] projects,” Glatz said.

“Is 15 years really a sufficient baseline for what the future may hold?” asked Sharon Segner of LS Power, citing technology changes affecting demand response and energy efficiency. Segner also questioned why PJM’s analysis failed to include 2015 submissions, which included dozens of lower voltage submissions from the marketplace.

Brenda Prokop of ITC Holdings said her company doesn’t favor a voltage floor but that PJM’s criteria for excluding projects (see table) “gives us a little more comfort.”

“We appreciate PJM’s effort to balance interests” of developers and efficiency, she said.

Vice President of Planning Steve Herling said PJM would like to implement the changes in 2016.

Climate Change Impact? Higher Highs has PJM Adjusting Weather Forecasts

PJM is planning to change the way it forecasts weather in its planning studies due to a trend of higher peak temperatures.

The RTO has based its forecasts on temperature and humidity data from 26 weather stations dating back to 1973. But a new analysis revealed that peak readings for 1993-2013 were higher than those for 1973-1993.

Twenty of 26 weather stations had higher maximum temperature humidity index readings in the last 20 years than the earlier period, PJM’s Andrew Gledhill said.

As a result, Gledhill said, the RTO plans to exclude the earlier data and rely on that from 1994/95. It will reevaluate the historical base on a regular schedule — perhaps every five years — going forward.

Gledhill said a survey of North American forecasters indicated that most use samples of 20 years or less. “The fact that PJM uses 40 years — we’re kind of an outlier,” he said.

The change would suggest higher load forecasts, countering factors such as lackluster economic growth and energy efficiency that are likely to mute projected load growth. Herling said PJM will offer stakeholders a look at the combined impact of all of the load forecast changes at the Planning Committee’s September meeting.

Exelon’s Rebecca Stadelmeyer and FirstEnergy’s Jim Benchek asked for more discussion of the weather forecasting at the Load Analysis Subcommittee.

“This is a drastic change to what we’re used to,” Stadelmeyer said. “We want to be comfortable [with the change]. We’re not now.”

“We’re very uncomfortable at this time,” Benchek said.

— Rich Heidorn Jr.

August 18, 2015June 15, 2023

Company Q2 2015 Earnings Roundup

Consolidated Edison reported second-quarter net income of $219 million ($0.75/share), compared with $212 million ($0.73/share) a year ago.

The company said results reflected changes in the rate plans of its utility subsidiaries, including growth in its gas delivery service related to oil-to-gas conversions, and lower operations and maintenance expenses, offset in part by higher interest expenses.

Adjusted earnings, excluding a gain on the sale of solar electric production projects, leasing transactions and the mark-to-market effects of the competitive energy businesses, were $228 million ($0.78/share) in 2015 compared with $189 million ($0.65/share) in 2014.

“Con Edison’s operating and financial performance continues to be strong,” CEO John McAvoy said. “We are embarking on a new era of energy delivery and customer choice. We are proposing new demonstration projects that will showcase energy efficiency tools, demand response and the usage information customers need to make choices, promoting solar power, energy storage and other distributed energy resources.”

Operations and maintenance expenses for Con Ed of New York were lower, reflecting lower electric operating costs and lower costs for support and protection of underground facilities to accommodate municipal projects. (See related story, NYPSC Accepts 7 REV Demos, Rejects 5.)

— William Opalka

Duke Q2 Earnings Drop; 2015 Still on Track

Duke Energy reported lower-than-expected second-quarter earnings Aug. 6, but the company said it remains on track to meet its 2015 goals.

Although adjusted earnings dropped to 95 cents/share from $1.11 for last year’s second quarter, Duke reaffirmed its 2015 adjusted diluted earnings guidance range of $4.55 to $4.75 per share.

The company reported $5.59 billion in revenue for the quarter, significantly below Wall Street estimates of $5.85 billion and the $5.71 billion it generated last year.

The Charlotte, N.C.-based company said results were affected by continued weakness in its international business — particularly Brazil — and the timing of operations and maintenance expenses at its regulated utilities.

Duke’s international business income was $52 million for the quarter, down 64% from the second quarter of 2014. A $1.5 billion stock buyback in connection with its $2.8 billion sale of 11 power plants in April to Dynegy helped offset international results.

“We met our customers’ energy needs … during extended periods of warmer-than-normal temperatures, particularly in the Southeast,” Duke CEO Lynn Good said in a press release. “Equally important, we continued to follow through on the growth initiatives that will provide long-term benefits for our customers.”

In a call with investors, Good said Duke has made “significant progress” in its coal ash removal efforts. The company announced in June it would shut down 12 coal ash basins in North Carolina in addition to 12 basins it already announced plans to close.

— Tom Kleckner

Dominion Meets Expectations

Dominion Resources met expectations with second-quarter earnings of 73 cents/share, near the top of its guidance of 65 to 75 cents.

Dominion posted earnings of $413 million, compared with earnings of $159 million for the same period in 2014. Revenue of $2.75 billion missed Zacks Investment Research’s estimate of $2.93 billion, however.

The Richmond, Va.-based company said earnings were up because a planned refueling outage at Millstone Power Station did not occur and because of higher revenues from growth projects. “All of the major projects in our infrastructure growth plan continue to move forward on time and on budget,” CEO Thomas Farrell said.

Dominion affirmed its 2015 operating earnings guidance of $3.50 to 3.85 a share.

— Tom Kleckner

Wholesale Business Drags Down Entergy Earnings

Entergy’s second-quarter profit tumbled 21% on declines in its wholesale commodities unit.

Net income of $148.8 million ($0.83/share) fell below analyst expectations of $1.14/share and the $189.4 million ($1.15/share) in the second quarter of last year.

Revenue for the New Orleans-based power provider fell 9%, to $2.71 billion.

Most pronounced was a $121 million drop in revenue for the wholesale commodities business. Power sales declined due to lower wholesale energy and capacity prices.

Revenue from Entergy’s utility segment of $1.5 billion was flat: it compares to $1.4 billion in the same quarter last year.

CEO Leo Denault told analysts that Entergy is ramping up for additional transmission projects that will meet rising industrial demand, including the $187 million Lake Charles project in Louisiana expected to be in service in 2018. (See MISO Board to Review Entergy Lake Charles Project Following Stakeholder Pushback.)

Despite the sour quarter, Denault said the company is on track to meet its earnings guidance for the year of $5.10 to $5.90 per share.

— Chris O’Malley

August 18, 2015June 15, 2023

Wind Power Continues Growth Despite Policy Uncertainty

By William Opalka

Clean energy technologies like wind turbines are seen as beneficiaries of the Clean Power Plan, and two reports released by the U.S. Department of Energy show its growth continued last year despite uncertainty over federal policies.

The 2014 Wind Technologies Market Report from the Lawrence Berkeley National Laboratory shows total installed wind power capacity in the United States grew 8% in 2014 to reach a nameplate capacity of nearly 66 GW, enough for almost 5% of electricity demand. Wind now generates more than 20% of electricity used in Iowa, South Dakota and Kansas. Meanwhile, prices for wind power purchase agreements have reached all-time lows. The national average levelized price of wind PPAs signed in 2014 was $23.50/MWh, down from $70/MWh in 2009.

The report cautions that most of these PPAs are from lower-cost regions of the country. The prices also benefit from the production tax credit, a federal subsidy that has helped the industry boom but will expire unless Congress extends it. Projects under construction at the end of 2014 will qualify, but that pipeline is expected to end sometime in 2016.

Electric utilities continued to be the dominant off-takers of wind power in 2014, either owning (26%) or buying (40%) power from two-thirds of the new capacity installed last year, according to the report. Merchant projects accounted for the remaining one-third.

Distributed wind — 7,400 turbines serving on-site or local loads — reached an installed capacity of 906 MW according to the 2014 Distributed Wind Market Report, by the Pacific Northwest National Laboratory.

About 58% of the distributed capacity is connected to distribution lines, with the remaining 42% serving on-site loads, either as behind-the-meter, off-grid, microgrid or remote net meter resources.

August 18, 2015June 15, 2023

SPP-MISO M2M Working Well, but Room for Improvement

By Tom Kleckner

SPP and MISO met last week with their stakeholders to review the first five months of market-to-market (M2M) operations between the two RTOs, saying that while the process is off to a good start, there’s much room for improvement.

“On the whole, market-to-market is working well. It’s a more efficient solution when both markets have control of the congested flowgate,” said David Kelley, SPP’s director of interregional relations. “We’re just talking about design flaws in the overall process … specific instances where we don’t believe it’s working as it should.”

“The price convergence is not happening on some flowgates,” said MISO’s Ron Arness, senior manager of seams administration. “We need to improve that.”

M2M is intended to improve price convergence on flowgates along the RTOs’ seams: The RTOs compensate each other for redispatching generation to reduce congestion in a way that reduces overall costs.

‘Philosophical Discussion’ Needed

The two RTOS have identified nine issues that need a “philosophical discussion,” Kelley said. They include developing criteria for M2M’s usage when one or both RTOs do not have effective control of a flowgate, leading to oscillation — when one market has significantly more control over a flowgate than the other market, resulting in the constraint’s unbinding and reloading too quickly during the exchange of shadow prices — and price separation. They also have called for criteria to recalculate firm-flow entitlements (FFE) due to modeling issues or outages.

SPP has a separate concern over the differences in the RTOs’ settlement billing cycles, which ends up with SPP floating dollars for several days while trying to remain revenue neutral. Arness said those discussions will involve SPP’s and MISO’s upper management.

SPP maintains the oscillations have overloaded flowgates and led to higher shadow prices for transmission constraints — the marginal costs of reducing a constraint per megawatt of flow.

“SPP was able to manage constraints just fine before market-to-market, and we didn’t have oscillation,” Kelley said. “We believe changes can be made, but the [joint operating agreement] is flexible enough to where we can do that.”

Through July 27, MISO has sent $10.4 million to SPP to compensate for congestion costs, with SPP sending MISO $2.2 million. The two RTOs have experienced 243 M2M events — when the RTOs exchange messages concerning a flowgate needing relief — totaling 1,024 hours.

SPP and MISO have 135 permanent flowgates and 45 temporary flowgates between the two. MISO’s footprint accounts for the bulk of those flowgates, with 89 permanent and 13 temporary.

The two RTOs hold weekly review calls to approve M2M events. SPP and MISO review real-time operations of the events and the data-sharing processes to ensure they are able to correctly perform M2M settlements. The two parties must reach agreement before performing any settlements or adjustments.

Monitors’ Perspective

SPP’s and MISO’s market monitors took turns presenting their views of M2M’s performance so far.

SPP’s Market Monitoring Unit noted effective M2M should lower shadow prices and the length of congestion events but that it has not yet looked at enough data for most constraints. It said data for the first months showed no major unexpected M2M effect on prices, but those impacts vary by constraint.

The MMU also said SPP and MISO calculate their shadow prices differently and that M2M on some flowgates can have a significant impact on prices for a large portion of the SPP market, especially in Nebraska and western Kansas.

MISO’s Independent Market Monitor (IMM) said M2M coordination has been a “net benefit” in MISO by reducing congestion costs. The IMM did note, however, a number of startup issues that were “isolated and … not ongoing.”

The IMM said the two RTOs have used work-arounds when normal coordination did not lead to efficient results. It said while some work-arounds have been expedient, they “have not been ideal” and called for improved coordination procedures and possible JOA revisions.

“In particular,” the IMM said, “the current JOA may assign the monitoring responsibility for a flowgate to the RTO that has less or ineffective relief capability. In theory, this would not preclude efficient coordination. In practice, timing and coordination issues cause this to result in constraint oscillation, inefficiencies that are difficult to resolve and higher costs.”

August 18, 2015June 15, 2023

Final Clean Power Plan More Suited to Carbon Trading, Experts Say

By Chris O’Malley

Cap-and-trade, appealing to economists but anathema to most in Congress, is likely to be a core compliance plan for many states under the Environmental Protection Agency’s final version of the Clean Power Plan.

“Trading itself got a lot more prominent than” in the draft plan, said Doug Scott, vice president of strategic initiatives at the Great Plains Institute and a former Illinois Commerce Commissioner.

Trading would set a price on carbon much like the cap-and-trade program that helped reduce compliance costs with acid rain regulations in the 1990s and the Waxman-Markey CO₂plan that died in Congress in 2010.

While at least 40 states have been talking about some sort of trading collaboration toward meeting their carbon-reduction mandates, EPA’s initial proposal in mid-2014 set rate-based goals measured in pounds of CO₂ per megawatt-hour.

Last fall, EPA provided technical advice explaining how to translate rate-based goals to mass-based equivalents that measure total carbon emissions in metric tons — a measurement more conducive to multistate trading.

The final rule goes a step further and “reduces confusion and ambiguity” for states contemplating trading, said Minnesota Public Utilities Commissioner Nancy Lange.

Essentially, the final rule “sets out elements you need to have for a trading-ready plan,” Lange added.

“I think you’ll find EPA is not only recognizing but embracing trading [plans],” Scott said.

Uncertainty Remains for Clean Power Plan

But Scott and Lange said that how many and which states will make carbon allowance trading a big part of compliance is impossible to say this early into the game.

For one thing, the final rule turned many states’ preliminary compliance planning upside down. EPA in its final rule loosened — or in many cases tightened — carbon-reduction targets in each state.

Kentucky is reeling from the final rule, which is 27% more stringent than the draft rule. Indiana and West Virginia, which also generate a big portion of power from coal, are facing carbon reductions that are 19% more stringent than before.

In addition to having to make big changes to their compliance modeling, some states face uncertain outcomes as their elected leaders vow to fight EPA in court.

The Indiana Department of Environmental Management, for instance, said it is still studying the final rule and doesn’t want to discuss potential options. The agency deferred to Gov. Mike Pence’s office as to how the state is likely to proceed.

Pence has already signaled his intentions. In June, he wrote a letter to President Obama stating that Indiana would not comply unless the rule was significantly changed.

(See related story, SPP, MISO, PJM States Join Opposition to EPA Plan)

‘Trading-ready’ vs. Formal Trading Pacts

Even with such fighting words in many states, Scott predicts state regulators will continue to discuss carbon-allowance trading scenarios in the months ahead.

“There will be a lot of discussions between states individually,” he said, though predicting it might be a year before anything coalesces.

Scott’s Minneapolis-based Great Plains Institute and the Washington-based Bipartisan Policy Center have been providing staffing support on carbon compliance to the Midcontinent States Environmental and Energy Regulators (MSEER), which includes MISO and SPP states, and to the Midwestern Power Sector Collaborative.

A number of meetings have already been held, including a workshop in Detroit in June.

Trading credits or allowances has lots of potential, says Todd Ramey, MISO’s vice president of system operations. “Trading has the benefits of allowing for a level of price transparency folks need to know. In order to monetize your carbon emissions, there needs to be a general understanding of what that value is in real time,” Ramey told the Detroit workshop.

A number of panelists agreed that multistate trading plans that were “trading-ready” were likely more plausible than formal multistate trading agreements. “Nobody has committed to anything in terms of a multistate effort” so far, Lange said.

She said MSEER has a workshop planned for Sept. 16 in Minneapolis that should be a good forum to discuss trading and other compliance scenarios in light of the final rule.

In the meantime, it’s not just Midwest states thinking more intently about trading plans. Scott said the Great Plains Institute also has been helping advise a number of states in the PJM footprint. His group plans to hold a seminar in October in Little Rock.

August 18, 2015June 15, 2023

So Far, So Good: Entergy Reaping Expected MISO Benefits

By Chris O’Malley

Nearly two years after joining MISO — and despite a seams spat between the RTO and SPP — Entergy said it is realizing expected cost savings from the integration.

Entergy and MISO’s Independent Market Monitor told the Entergy Regional State Committee in Little Rock on Aug. 11 that the December 2013 integration has produced substantial benefits and that the transition was well-managed.

Entergy cautioned that its recent review amounts only to an initial snapshot. But, so far, at least, it has identified $236 million in annualized energy related savings since integration in 2013.

MISO had estimated at the time of integration that Entergy customers could see savings of $1.4 billion over a decade.

Six Entergy operating companies operate in four MISO states: Arkansas, Louisiana, Mississippi and Texas.

Entergy vice president Matt Brown said the company would have had to acquire 1,402 MW of additional capacity resources had Entergy not joined MISO.

That’s slightly lower than 1,413 MW of avoided capacity estimated during a May 2011 study Entergy commissioned to look at potential cost savings of joining the RTO.

“The benefits that our customers are realizing from actual participation in the MISO RTO are meaningful and that they are at a level that is on par or better than what we projected in the change of control filings,” Brown told stakeholders.

The study focused on non-baseload resources and did not take into account transmission related benefits.

Broadly, the study looked at changes in costs resulting from the move to Day 2 RTO commitment and dispatch. That includes benefits in generation costs, purchased power costs, net wheeling costs and additional Day 2 production cost savings such as deferred generation investment.

On the other side of the equation were additional costs such as RTO administration and cost allocations for its share of MISO’s regional transmission projects.

“The takeaway here is that the capacity-related savings, the planning reserves, additional production cost [savings], if you will, associated with being in MISO have been in line with what we projected,” Brown said.

Among them was a 9% reduction in the portion of energy provided by Entergy’s legacy generation. “The legacy generation that we are using is being used more efficiently,” Brown said.

He cautioned that the approximately one-year post-integration period studied wasn’t enough time to draw broader conclusions. “But the information that we’re seeing is encouraging. Our customers are realizing meaningful benefits from being in MISO.”

Constraints Mar Integration’s Potential

The results also received some affirmation from MISO’s Market Monitor, Potomac Economics.

“Overall, we found that the market performance in MISO South has been well-managed and has produced substantial benefits,” said Robert Sinclair, a principal at Potomac. “The integration has been efficient.”

But Sinclair said the Operations Reliability Coordination Agreement (ORCA) and the South Region Power Balance Constraint (SRPBC) remain obstacles to transfers between MISO Midwest and MISO South.

The latter was created in response to the need to make transmission payments to neighbors for transfers more than 1,000 MW. MISO began limiting flows last year after SPP complained that MISO breached their joint operating agreement by moving power over its transmission footprint in excess of a 1,000-MW contractual limit.

Currently there’s a hurdle rate of nearly $10/MWh for transfers more than 1,000 MW, causing price separations between the regions. That raises efficiency concerns by limiting transfers more than 1,000 MW and price effects in both regions that don’t reflect physical realities of the network, Sinclair noted.

The best mechanism would be one allowing MISO to eliminate the SRPBC, Sinclair said. Reducing the hurdle rate to zero would support efficient interregional transfers and improved pricing.

Sinclair also reiterated the Monitor’s call to develop a reserve product that will reflect operating reserve needs in MISO South, in particular.

“We believe that if that constraint was released, we would have more instances where the power flows were above 1,000 MW and that would be more efficient because we would be experiencing more production cost savings,” Sinclair added.

$844M in Tx Projects for MISO South

Meanwhile, stakeholders received an update from MISO about its 2015 Transmission Expansion Plan, which proposes 352 projects totaling $2.4 billion.

Of those, 79 projects totaling $844 million are proposed for MISO South:

Arkansas: 15 projects totaling $159 million;
Louisiana: 34 projects ($473 million);
Mississippi: Seven projects ($30 million); and
Texas: 23 projects ($182 million).

However, the list is expected to be whittled down prior to board consideration in December.