A power generator fined $5 million for allegedly cheating ISO-NE wants federal regulators to drop two other allegations or combine them with the original complaint (IN15-4).
FERC fined Maxim Power in May for overcharging ISO-NE by offering into the day-ahead market with a price for oil-fired generation when in fact it was burning cheaper natural gas. (See FERC Fines Maxim Power $5M in Switching Scheme.)
FERC filed suit July 1 in U.S. District Court in Massachusetts to enforce its penalty.
FERC’s suit followed a Notice of Alleged Violations in November that included two other alleged schemes: that the company gamed ISO-NE market mitigation rules in 2012 and 2013, and that it boosted its generators’ outputs during testing using “extraordinary measures” in order to collect inflated capacity payments from 2010 to 2013.
Those two allegations were not mentioned by the commission in its filings seeking to collect the fine.
On Wednesday, Maxim attorney William S. Scherman sent a letter asking four FERC commissioners to add the “unpursued claims” to their federal court suit or confirm that they are no longer pursuing them. Commission Chairman Norman Bay, who headed the Office of Enforcement during the cases’ investigations, has recused himself in the matter.
“Maxim Power should not be forced to litigate piecemeal in federal district court,” Scherman wrote. “This would not only be inefficient and burdensome but also significantly add to Maxim Power’s litigation costs. As the commission knows, all companies consider litigation costs as part of their case assessment. But intentionally seeking to drive up a private entity’s litigation costs is not a reasonable litigation strategy.”
Scherman asked the commission to take action by Sept. 3.
PJM generators will earn $10.9 billion from this year’s capacity auction — a 45% jump from last year — in the first test of the RTO’s new Capacity Performance requirements. But some merchant generators smarting from low gas prices and competition from wind say that’s not enough for what ails them.
Securities analysts said the results will boost earnings for Exelon, Dynegy, NRG Energy, Public Service Enterprise Group, Calpine and Talen Energy.
The results have particular implications for Exelon’s Illinois nuclear fleet and American Electric Power’s potential sale of its merchant fleet.
Exelon: Retirements Still on the Table
Exelon announced Monday that three of its nuclear plants in PJM failed to clear the 2018/19 auction, including the 1,819-MW Quad Cities plant in Illinois, the second year in a row that it failed to clear. Company officials say they may retire Quad Cities if the Illinois General Assembly does not pass legislation that would boost revenues for the company’s nuclear fleet.
Exelon must notify PJM by September of any plants it won’t offer into the May 2016 Base Residual Auction for delivery year 2019/20.
Quad Cities, which has lost about $300 million over the last six years, is expected to lose about $50 million annually, according to Joseph Dominguez, executive vice president for government and regulatory affairs at Exelon.
Analysts from UBS Global Securities called Exelon “the clearest ‘winner’” in the auction because of its assets in both the ComEd zone, where prices hit $215/MW-day, and EMAAC, which cleared at $225/MW-day.
But Dominguez said the increase in capacity prices was a “marginal improvement” for Exelon’s generation. “What we got today is important, but it’s one year’s worth of revenue,” he told the Chicago Tribune on Friday. “We have to see a sustainable path forward.”
FirstEnergy spokesman Mark Durbin echoed Exelon Monday, saying PJM’s rule changes “resulted in clearing prices that really come closer to the operating costs of plants. But it’s only representative of one year; we’re not sure how reflective it is of long-term trends. It is a snapshot in a one-year time frame.”
Capacity revenue represented less than one-fifth of energy market revenue in PJM in 2014.
The results also did not help Exelon’s money-losing Clinton, Ill., plant in MISO. Exelon faces a December deadline for informing MISO if the 1,065-MW plant will be shut down before the planning year beginning June 1, 2016.
Seeking Help from the States
Exelon wants Illinois legislators to approve legislation that would require utilities to purchase credits from low-carbon generators including nuclear and wind. Illinois lawmakers did not take action on the Low Carbon Portfolio Standard before the spring legislative session ended, but they may consider it in November.
AEP and FirstEnergy also are seeking aid from state officials. The companies have asked the Public Utilities Commission of Ohio to approve above-market purchase power agreements from their coal generators.
PUCO has scheduled evidentiary hearings beginning Sept. 28 to consider the request from AEP, which is hoping to boost the value of its merchant fleet for a possible sale. (See Cold Weather, Low Gas Prices Drive AEP Earnings.) The commission is expected to consider FirstEnergy’s “Electric Security Plan” proposal as part of a rate case later this month.
In FirstEnergy’s second-quarter earnings call, CEO Chuck Jones cited PJM’s capacity market changes and the Ohio ESP as “key initiatives [that] will drive the near-term financial strategy” of the company.
Meanwhile, Dominion Resources won approval from the Virginia legislature in February for a nine-year rate freeze, meaning it won’t have to share the rise in capital revenues with ratepayers. Dominion said it wanted to suspend its biennial rate reviews to provide it and customers with “rate stability” as it responds to the Environmental Protection Agency’s Clean Power Plan.
While Dominion is assuming the risk of increased compliance and operating costs, analysts said the freeze allows the company to retain an additional 5 to 8 cents per share of earnings from PJM capacity revenues.
Transition Auctions
With the first auction under PJM’s new rules behind them, generators are now turning their attention to this month’s CP transition auctions for the 2015/16 and 2016/17 periods.
PJM will hold a transition auction on Wednesday and Thursday to obtain CP resources for 60% of the updated reliability requirement for delivery year 2016/17. Results are expected Monday, Aug. 31. The transition auction for 2017/18 (70% CP) will be Sept. 3-4, with results posted Sept. 9.
Participation is voluntary and open to any resource able to meet CP requirements, regardless of whether the resource cleared in the BRA for the delivery year.
FirstEnergy’s Jones said the transition auction results will have a big impact on how much the company is willing to spend to boost its plants’ reliability.
“We need to see where both the Base Residual Auction and then where in particular the transition auctions clear, because those are the more imminent,” he said. “For the Base Residual, you got three years to figure how to get your units reliable for that one. The transition auctions are a little more pressing in terms of time.”
UBS is predicting CP resources will clear the two auctions at about $120/MW-day, a “modest risk premium” to the base capacity resources, which cleared at $59/MW-day for 2016/17 and $120/MW-day for 2017/18 RTO-wide.
Other Generators
PSEG announced that its planned Sewaren Unit 7 had cleared the auction — the only new generation in EMAAC. The company said it plans to begin construction on the $600 million combined-cycle plant in early 2016. The company said it will replace the nearly 70-year-old Units 1, 2, 3 and 4.
PSEG said it cleared about as much capacity as in the 2014 auction, with all but one unit clearing as CP.
Talen declined to share the details of its offerings, but spokesman George Lewis said, “In general, we see the CP product as a positive, and the results from Friday are generally good and certainly within what was expected. It met most people’s expectations.
“Our view is it’s a partial picture at this point,” Lewis said. “We’ll find out more next week and the week after what the outcome of the [transition] auctions will be, and whether the results of the [BRA] will change the way generators or capacity resources will view bidding into these capacity auctions.”
Dynegy and Calpine had no comment on the results. AEP, NRG and AES did not respond to requests for comment.
A Calpine spokesman noted, however, that 4,600 of its 5,700 MW of PJM generation is in either ComEd or EMAAC.
Stocks Tumble
PJM generators saw their shares drop slightly on Monday, but it was a day when the market was down across the board on fears of economic weakness in China. The Dow Jones industrial average finished the day down 588 points, or 3.6%.
Exelon closed the day down 1.1% at $32.64 after an intraday high of $33.54. Dynegy was down 2.4% at $24.71, with an intraday high of $26.51. NRG shares dropped 1.8% to close at $19.22 after seeing an intraday high of $20.36. PSEG closed down 3.31% at $40.65, with an intraday high of $41.83. Calpine dropped 3.82% to close at $15.87, with a high of $16.76.
Talen saw the biggest slump, 4.7%, which brought its shares down to $15.17.
Below is a summary of the issues scheduled to be voted on at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:20)
Members will be asked to endorse the following manual change:
Manual 37: Reliability Coordination — Modifies section 2.4.2. (Change management process), replacing reference to the Change Control Review Board with the Enterprise Change Management Standard. The standard ensures that changes to PJM business application systems, programs, data, systems software and hardware are authorized and applied so as not to compromise the stability and security of any information technology component. Also updates the definition of system operating limits (SOL) to make clear that PJM controls to the most conservative limits and that interconnection reliability operating limits (IROL) are an elevated level of SOL, not distinct from it. Clarifies the SOLs and IROLs monitored by the RTO as well as SOL violations reporting.
3. EXTERNAL CAPACITY TRANSFER RIGHTS (9:20-9:40)
The committee will be asked to endorse a rule change allowing load-serving entities to meet their capacity requirements with historic resources. Current capacity rules procedures lack a method to recognize historical resource and transmission commitments that were used to serve the capacity needs of LSEs’ internal network load, a situation that impacted the Illinois Municipal Electric Agency when PJM modeled its ComEd locational deliverability area (LDA) with a separate variable resource requirement curve. The proposed solution is three-pronged: The percentage internal resource requirement is enforced only if the LDA has been separately modeled due to certain triggers; a fixed resource requirement (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. (See “Members OK Rule Change on External Capacity Transfer Rights” in PJM Market Implementation Committee Briefs.)
4. TRANSPARENCY OF OPERATIONAL CHANGES (9:40-9:55)
Proposed manual revisions would require PJM to announce the creation of new “closed-loop” pricing interfaces five days before the close of the next financial transmission rights auction. The rules would except outages of short duration (less than 10 days) and those setting price for demand response according to current manual and tariff instructions. PJM uses such interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems. (See “Package Calls for Notice on Pricing Interfaces” in PJM MIC Briefs.)
5. MARKETS GATEWAY (9:55-10:05)
The committee will be asked to endorse revisions to the Operating Agreement and Tariff to reflect the transition from the eMarket tool to Markets Gateway. Training on the new tool is expected to be held in the second half of this year.
Members Committee
CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to endorse a Tariff revision instituting previously endorsed fees for proposed transmission projects. Beginning next year, PJM will charge $5,000 to study greenfield or upgrade proposals of between $20 million and $100 million and $30,000 for projects costing more than $100 million. The fees will be implemented on a two-year trial basis. (See “PJM Lowers Proposed Tx Project Study Fee” in PJM Planning Committee Briefs.)
C. New Tariff language aims to more accurately reflect how PJM processes requests for merchant network upgrades. The changes address definitions, queue entry, agreements and the capacity market.
After failing to win approval from the MRC for a proposal to redesign the FTR and auction revenue rights process, Steve Lieberman of Old Dominion Electric Cooperative is seeking its endorsement from the Members Committee. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The proposal garnered just 59% of a sector-weighted vote at the MRC’s July 23 meeting. Since then, the proposal has been presented to the Liaison Committee and has been the subject of conversation among numerous stakeholders and members, according to ODEC.
The proposal incorporates three elements. The first, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, would escalate current ARR results using a zonal load forecast growth rate of +1.5%. The other two elements would change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio. It also would treat each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.
The D.C. Public Service Commission will announce its decision on Exelon’s acquisition of Pepco Holdings Inc. at its open meeting 11 a.m. Tuesday (Case No. 1119). The commission will stream the meeting on its website and on the PSC mobile app.
FERC and state regulators in Maryland, Delaware, New Jersey and Virginia have already approved the $6.8 billion deal.
In D.C., more than half of the district’s Advisory Neighborhood Commissions and almost half of the 12 members of the city council have publicly stated their opposition to the deal. The Office of People’s Counsel and the attorney general’s office also advised against approval without significant concessions. (See Deadline Looms for Decisions in Exelon-Pepco Deal.)
Exelon says the merger would improve Pepco’s reliability. Opponents have said the deal will benefit Exelon shareholders more than ratepayers. If approved, the deal would create the Mid-Atlantic’s largest electric and gas utility.
RTO Insider will be at the PSC meeting to tell you of the decision as soon as it happens. Check our website Tuesday afternoon for full coverage.
PJM’s first auction under its new Capacity Performance rules saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.
The Base Residual Auction procured 166,837 MW of capacity for delivery year 2018/19, giving the RTO a 19.8% reserve margin, well above the target of 15.7%.
Price Premiums
Capacity Performance resources, which represented more than 80% of capacity acquired, were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL locational deliverability area (LDA), the premium was $90.
In the BGE and PEPCO LDAs, base demand response and energy efficiency priced at a discount of more than $100 compared with CP resources.
While CP resources are subject to stiff penalties for failure to perform during emergencies year-round, base capacity is only liable if it fails to perform during the summer peak period.
3 Exelon Nukes Fail to Clear
Clearing prices were generally in line with analysts’ expectations. But that was not enough for Exelon, which announced Monday that three of its nuclear plants — Quad Cities in Illinois, Oyster Creek in New Jersey and Three Mile Island in Pennsylvania — did not clear.
Oyster Creek is scheduled to be retired by 2019. Exelon said it expects to make a decision on retiring Quad Cities, which has lost about $300 million over the last six years, by September.
Spokesman Paul Elsberg declined to specify the price at which Exelon offered the three plants into the auction, citing “competitive reasons.” He said all of Exelon’s other nuclear plants in PJM cleared. That includes the Byron plant in Illinois, which the company says also has been losing money.
In last year’s auction, Oyster Creek, Byron and Quad Cities all failed to clear. But analysts said the company would earn almost $150 million more in capacity revenue from planning year 2017/18 than it would have if all of the company’s capacity had cleared because the additional supply would have reduced clearing prices. (See How Exelon Won by Losing.)
New Capacity
The auction, which ran from Aug. 10-14, also resulted in 3,500 MW of new capacity, most of it gas-fired, a decline from the 5,900 of new entry from last year’s auction.
Analysts cited higher interest rates, lower spark spreads and the short runway to the auction following FERC’s June order approving CP as reasons for the decline.
More than 4,100 MW of new capacity offered into the auction, all but 600 MW clearing. The new cleared capacity includes 2,919.3 MW from new gas-fired combined-cycle generators and combustion turbines, and 587.6 MW from uprates to existing units. EMAAC and MAAC each cleared 526.7 MW of new units, while the rest of the RTO cleared 1,865.9 MW of new generation.
Public Service Enterprise Group announced Monday that its planned 540-MW combined-cycle plant in Woodbridge, N.J., was the winner in EMAAC.
Analysts for UBS Global Research said the other new combined-cycle plants were likely in Ohio or West Virginia, where they can obtain gas from the Utica shale play. They cited four proposed plants that had been seeking financing: Moundsville, 550 MW in West Virginia; Advanced Power’s 700-MW unit in Carroll County, Ohio; Clean Energy Future’s 800-MW facility in Lordstown, Ohio; and the 550-MW NTE Energy unit in Middletown, Ohio.
Imports
Generation imports clearing rose to almost 4,700 MW, a slight increase over last year, when PJM imposed capacity import limits because of concerns that transmission constraints might prevent some external resources from being able to deliver power into the RTO.
Most of the imports clearing came from west of PJM and all met the requirements for exceptions to the import limits, meaning they will be paid the RTO clearing price. To qualify for the exception, they were required to have pseudo-ties allowing them to be treated as internal generation, subject to redispatch and locational pricing, have long-term firm transmission service and agree to abide by must-offer requirements.
Demand Response
Demand-side resources rebounded slightly following two straight years of decline from their peak for delivery year 2015/16.
More than 11,000 MW of demand response cleared, 1,484 of it CP — more annual DR than had ever cleared before, PJM said. Of 1,247 MW of energy efficiency cleared, 887 was CP. DR offers increased 3.4% from last year, with 95% clearing.
“That’s in the face of the uncertainty caused by the ongoing Supreme Court review of the EPSA case,” Stu Bresler, senior vice president for markets, said in a press conference late Friday. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)
“I think we’ll see quite a bit of innovation at the DR level in order to figure out ways to aggregate resources and continue to participate and be Capacity Performance going forward,” Bresler added.
Demand response aggregator EnerNOC saw its stock rise 3.34% Monday to close at $8.35, after an intraday high of $8.71.
Renewables
Renewables with a nameplate capacity of more than 14,000 MW also cleared, including 6,600 MW of wind, 1,450 MW of it as CP.
About 857 MW of wind capacity offered into the auction — all of it clearing — an increase of almost 7% over last year. Based on wind’s 13% capacity factor, that translates to nameplate capacity of 6,594 MW.
Almost 184 MW of solar resources offered and cleared (484 MW of nameplate capacity at a 38% capacity factor), a jump of 58% from last year.
“An extremely small portion of that cleared as capacity performance, due, I would imagine to the risk of nonperformance in the winter months,” Bresler said.
Prices ‘as Expected’
Bresler said he was pleased that the RTO clearing price was in line with analysts’ expectations, saying it was an indicator of the “transparency” of the PJM market.
The $10.9 billion total cost of the capacity procured was a $3.4 billion increase over 2014 “right in the middle” of the $2 billion to $5 billion range PJM and the Market Monitor had predicted in a joint analysis, Bresler said.
Bresler acknowledged that the discount between CP and base capacity was generally smaller than the RTO and outside analysts had expected.
“But given the fact that we’re heading to 100% Capacity Performance two auctions from now … I don’t think that that result is bad at all. In fact I think that it’s a good result because the vast majority of resources offered at CP and wanted to take on that performance requirement.”
ComEd Break Out
ComEd prices broke out from the rest of the RTO as a result of reduced transmission capacity into the zone from MISO to the west, Bresler said.
Bresler said the capacity emergency transfer limit (CETL) into the ComEd LDA was reduced by 25% from 2014 due to several factors, including changes in MISO’s transmission system west of the LDA and “many changes” in firm transmission service reservations into and out of PJM from MISO and other areas.
“The net results of those combinations of factors was that when we did the transfer analysis into the ComEd zone we hit constraints to the western side of the ComEd zone much sooner than we have in the past, which required us to funnel the imports in the analysis from just the eastern direction. …That meant we hit a binding transmission limit for the transfers at a lower level.”
Consumer Reaction
The ComEd increase did not go over well with the Citizens Utility Board, a Chicago-based consumer group.
“For the second time in less than a year, consumers in the state — first in central and southern Illinois and now in northern Illinois — face significantly higher electric bills because of a flawed power-pricing system,” said CUB Executive Director David Kolata, in a reference to MISO’s capacity auction results in April, which saw a nine-fold increase in Illinois. (See Ill. AG Joins Call for Changes to MISO Auction Rules.)
“Illinois’ electricity market is not working well for consumers. This price spike is one more red flag that the rules governing the capacity auction open the door for power generators like Exelon, NRG and Dynegy to make windfall profits.”
CUB estimates that a typical family in ComEd will pay $3 to $7 per month more as a result of the PJM capacity results.
Comparison to 2014 Results
In addition to the impact of the new CP requirements, PJM said the auction results reflected changes approved by FERC in November to the RTO’s variable resource requirement (VRR) curve shape and gross cost of new entry (CONE) values (ER14-2940).
In last year’s auction for delivery year 2017/18, annual resources cleared at $120/MW-day in most of PJM following rule changes that limited DR and generation imports. That represented a doubling of prices in Virginia, West Virginia, North Carolina and much of Ohio (from $59/MW-day in the 2013 BRA) and little change in MAAC and ATSI. The PSEG zone ($215/MW-day) was also flat.
Last year’s rebound in prices were still below the $136/MW-day for 2015/16 and the all-time high of $174 set for delivery year 2010/11.
PJM will conduct transitional auctions to integrate CP resources into years for which the BRAs have already have been held, with the 2016/17 auction on Aug. 26-27 and the 2017/18 on Sept. 3-4.
In developing the CP proposal, Bresler said PJM officials surveyed natural gas generators to determine the cost of adding dual fuel capability. Lack of gas was one of the problems that contributed to the extraordinarily high forced outage rates during the polar vortex of January 2014.
“And the answers that we received back centered right around $40 or so per megawatt-day,” Bresler said. “So the increase we saw from last year to this year of about $45/MW-day really [was] very consistent with what we expected.”
Eversource Energy last week proposed burying 60 miles of its proposed Northern Pass power line from Canada, but some critics insist the entire route be underground. Others, including New Hampshire’s governor, say that while the revised route is an improvement, they are hopeful for a plan with even fewer visual impacts.
Eversource subsidiary Northern Pass Transmission had previously proposed burying 8 miles of the now 192-mile route, but the company bowed to pressure and removed above-ground lines through the White Mountain National Forest and other sensitive areas.
On Thursday, the Appalachian Mountain Club naturalists group, which has been a vocal critic, said it and its allies should take some credit for the “dramatic shift” but that Eversource could do more. “For years the company has claimed that burial of the line was technically impossible and prohibitively costly … So while we are glad to see this additional 52 miles of the project buried, the question remains: Why not all of it?”
Jack Savage, speaking for the Society for the Protection of New Hampshire Forests, said “Northern Pass deserves credit,” but more must be done.
“Given that the new technology is apparently allowing Northern Pass to propose burying another 52 miles without increasing the overall project cost of $1.4 billion, there would seem to be opportunity for more burial along roadways,” he added.
Eversource said it doesn’t need to make any more concessions.
“There are going to be folks who’ve ardently opposed this from the outset and perhaps are going to look at it as an opportunity,” Bill Quinlan, president of the utility’s New Hampshire operations, told the New Hampshire Union Leader on Wednesday. “They’re going to say, ‘We got them to move this far; we can get them to move further,’ and I think that’s unlikely.”
Political Leaders Split
Political leaders in the state are divided.
“I have made clear that if Northern Pass is to move forward, it must propose a project that protects our scenic views and treasured natural resources while also reducing energy costs for our families and businesses,” Democratic Gov. Maggie Hassan said in a statement. “This route is an improvement over the previous proposal.”
She said dialogue from the company must continue and include “further improvements.”
However, the change was enough to win the support of Charles Morse (R-Salem), president of the New Hampshire Senate. “The changes announced by Eversource represent a major improvement to the project and a great opportunity for our state, and I am pleased to be able to support the Northern Pass project as now revised,” Morse said.
Eversource says it will file plans in October with the New Hampshire Site Evaluation Committee, a panel including members of the Public Utilities Commission, other state officials and members of the public. The company hopes to start construction in 2017 and have the line in service in 2019.
Capacity Reduced
The decision to bury more of the line forced a reduction in its capacity from 1,200 MW to 1,000 MW.
Revised path for Northern Pass shows buried sections in yellow.
Rerouting of the line makes it 5 miles longer, up from the original 187 miles that included underground lines only near the Canadian border. The additional underground miles would be buried along existing roads through the White Mountain National Forest, Franconia Notch and the Appalachian Trail.
A draft environmental impact statement released by the U.S. Department of Energy last month said the cheapest alternative would also have the most visual impact on natural areas. (See Price Tag Likely to Rise for Northern Pass Transmission Line.)
The company said the price tag of the project will remain at about $1.4 billion. Spokesman Martin Murray said the Northern Pass will use HVDC Light technology from ABB that is cheaper and more efficient than conventional HVDC cable. Reducing the project’s capacity also keeps its cost stable, Murray added.
Eversource has said burying the entire route would double its cost and make it economically unfeasible. About 400 above-ground structures will be eliminated by the new plan, with 80% of the route along existing roads and company rights of way.
The company said the additional underground construction will result in the longest HVDC underground land cable installation in North America.
But that comes at a cost. According to the draft EIS, the “DOE has determined that extended burial of a transmission line with a capacity of 1,000 MW would be practical and technically feasible. The burial of a transmission line with a capacity of 1,200 MW for extended distances would not be feasible.”
The new underground route includes most of alternative 5c and elements of alternative 4c from the draft EIS.
The developers say the project, which they have dubbed the Forward New Hampshire Plan, will bring economic benefits of more than $3 billion to the state. Lower wholesale energy prices in the ISO-NE market are expected to save New Hampshire customers $80 million annually. Additionally, a 100-MW power purchase agreement with Hydro Québec is expected to reduce consumers’ yearly bills by another $10 million.
The line is projected to create 2,400 construction jobs and generate $30 million in annual tax revenue. The developers also have promised a $200 million Forward NH Fund to support initiatives in tourism, economic development, community investment and clean energy innovation.
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 CO2 plan 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.
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.
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.
The nine states participating in the Regional Greenhouse Gas Initiative released the “CO2 Emissions from Electricity Generation and Imports in the Regional Greenhouse Gas Initiative: 2013 Monitoring Report.” This report is the fifth in a series of annual monitoring reports called for in the 2005 RGGI Memorandum of Understanding. The report summarizes data for electricity generation, electricity imports and related carbon dioxide emissions for the RGGI states.
New Englanders are using less on electricity because of the mild summer. An abundance of natural gas and more efficient power plants have also helped reduce the wholesale price of energy, a respite from soaring heating costs in the winter, ISO-NE said.
The average wholesale price in June was 1.96 cents/kWh, down nearly 50% since June 2014. The decline continued in July, dropping by more than 27% year over year, the RTO said. Costs are falling for some ratepayers, but it’s uneven among New England states. The U.S. Energy Department said retail prices in New England were higher in June and July than in the same months last year.
The price for customers of Central Maine Power dropped by more than 13% in March 1. In Massachusetts, a reduction of more than 20% kicked in May 1.
Consumption Breaks Record in MISO South but Lights Stay on
The four states in MISO’s southern region set an all-time record for power usage of 32,618 MW on July 29, but the RTO didn’t have to declare emergency operations. MISO issued several hot weather notifications, which apparently worked. “Not only was this a big success for MISO and our members, but it was the first time our South Region Operations Center was truly tested,” said Katherine Prewitt, senior director of MISO’s South Region Operations, in Little Rock. The region consists of all or parts of Arkansas, Louisiana, Mississippi and Texas.
The previous peak for the region was 31,789 MW on Aug. 3, 2011.
Three solar projects could soon be online in the state, and additional installations could follow, induced by environmental regulations reducing carbon emissions and a 30% federal tax credit that will be reduced by 2017.
Arkansas Electric Cooperative Corp. announced plans for a 12-MW solar generation facility in February. Entergy in April announced an 81-MW facility. More recently, Ozarks Electric Cooperative said it would build a small facility in the northwest part of the state.
Any utility seeking to recoup costs from a state solar project through rate increases must obtain regulatory approval from the Public Service Commission. A decision is expected in Entergy’s case by the end of September.
State Senate President Martin M. Looney and New Haven officials are urging prospective merger partners UIL Holdings and Spanish energy giant Iberdrola to commit to paying the cost of cleaning up the mothballed English Station power plant.
The two merger partners are in negotiations with Attorney General George Jepsen and the Department of Energy and Environmental Protection to play a significant role in the cleanup of the 9-acre power plant site. A regulatory filing by the two companies said both would be involved in the cleanup, the cost of which has been estimated at $30 million. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)
Two out-of-state entities, Asnat Realty and Evergreen Power, bought the plant from UIL, but they failed to follow through on promises to clean it up.
Judge Denies Watchdog’s Request for Legislative Correspondence
Osborn
Marion County Superior Court Judge James Osborn turned down a request by Indianapolis-based Citizens Action Coalition to force a legislator to reveal his correspondence with utility executives, ruling that the separation of powers doctrine forbids the courts from getting involved in legislative affairs.
CAC filed suit after state House leaders denied its public records request for emails between House Energy Chairman Eric Koch (R-Bedford) and Duke Energy and Indianapolis Power & Light. The group sought correspondence that concerned a net metering bill that would have changed the way customers with solar panels are billed. That bill eventually was killed.
A Senate committee last week questioned former Consumers Energy executive Norm Saari whom Gov. Rick Snyder nominated to serve a six-year term on the Public Service Commission.
Saari appeared Aug. 13 before the Senate Energy and Technology Committee, where some members said that while they respect him, they were wary of his appointment by Snyder. Saari tried to assure them that while he worked nearly 30 years for Consumers Energy, he had no financial interest in Consumers or any other utility in the state.
Most recently Saari, a Republican, was chief of staff for the state House of Representatives. If affirmed, Saari would replace Commissioner Greg White, who is retiring.
Couple’s Complaint of Connection Fee Spurs Commission-Ordered Review
A letter written by a Stewartville couple to the Public Utilities Commission complaining of a $5 monthly fee they had to pay for their small wind generator has spurred the commission to order a review of the state’s electric utilities to see if they charge similar fees.
Alan and Kris Miller installed a small wind generator to power their hobby farm and were surprised when People’s Energy Cooperative charged them the monthly fee. People’s has since offered to refund Miller and about 30 other customers who faced similar monthly charges for wind or solar facilities.
After a five-month investigation, the commission last week declared the fee illegal and ordered a state-wide review of so-called net metering charges. Renewable advocates say such fees, which so far are unregulated, sap the incentive of those considering installing solar or wind generation for their homes or small businesses.
“They have no idea what the fee is going to be,” said David Shaffer, general counsel for the Minnesota Solar Energy Industries Association. “Maybe it is going to be $5 and maybe it is going to be $85 — until they know, they can’t make an informed purchasing decision so they choose not to buy.”
Gov. Nixon Appoints Former Aide to Chair State’s PSC
Gov. Jay Nixon has appointed former aide Daniel Hall to chair the Public Service Commission. Hall has served on the five-member PSC since 2010; he replaces Robert Kenney, whose six-year term expired Aug. 7.
Hall served under Gov. Bob Holden and House Speaker Steve Gaw before becoming a legislative aide to Nixon when he was attorney general. Kenney will join San Francisco-based Pacific Gas and Electric as its vice president for regulatory relations.
Witnesses Testify Against Federal Coal Royalty Payments
An overflow crowd packed a U.S. Interior Department meeting in Billings to discuss its policy of allowing private coal mining on government land. It was one of five sessions scheduled by Interior Secretary Sally Jewell, who has pledged a review of the government’s coal leasing program.
Most of the comments concerned the 12.5% royalties that the government collects on coal. “It’s time that you crack down on coal companies that have been getting sweetheart deals for too long,” said Renette Kaline, a Northern Cheyenne tribe member.
But some who depend on the mining said they were afraid that additional regulatory burdens could put their livelihoods at risk. “I’m scared,” said Ryan White, a miner. “I’m fearful of my future. I go to work every day wondering when the federal government will put my employer out of business.”
The Greycliff Wind Energy project, a 12-turbine project in central Montana that was proposed five years ago, continues to battle regulatory headwinds.
The project’s developers, Minnesota-based National Renewable Solutions, must persuade the Public Service Commission that the company has enough Montana owners to qualify as a Community Renewable Energy Project. The PSC rejected Greycliff Wind in June because it wasn’t convinced that local owners had a 50% stake in the company’s income, equity and voting rights.
National Renewable Solutions representatives spent last week in Sweet Grass County assuring the county commissioners “the project isn’t going away,” said the company’s Pat Pelstring.
Senior executives for Eversource Energy say the power company is willing to bury more of the transmission lines for the Northern Pass hydroelectric project, but not the entire 187-mile route from the Canadian border through northern New Hampshire to Deerfield.
“Full undergrounding is unnecessary and prohibitively expensive,” Lee Olivier, Eversource executive vice president, said in a conference call with financial analysts on July 31. “But some project modifications could be done with some additional undergrounding.”
The company is reviewing the environmental impact statement with an eye toward burying more of the line, he said. The most likely area for additional burial would be through 10 miles in the White Mountain National Forest, where the environmental report suggests overhead lines would not be allowed.
The state has reopened the Renewable Energy Fund, although with new restrictions and less money than was initially anticipated.
The freeze on REF applications, imposed on July 20, continues on applications for solar projects in the 100- to 500-kW range. Those projects have mostly been popular with businesses, according to Kate Epsen, executive director of the New Hampshire Sustainable Energy Association, a trade organization representing the renewable energy industry.
“It’s a really good category and a real shame that it’s being cut out, hopefully not forever, but even temporarily is a problem,” she said. “This was hitting an important market gap for these mid-sized projects. A lot of companies have been putting together good proposals, and there has been some good groundwork and business interest. Now that’s been taken away, or at least temporarily halted.”
Gov. Christie Signs Bill Boosting Net Metering Cap for Solar
Christie
Gov. Chris Christie has signed a bill that increases the cap under which utilities can stop paying owners of distributed solar for electricity their systems generate. The previous cap allowed utilities to stop paying when net metering systems recorded 2.5% of the state’s peak demand.
That level has already been reached. The new bill, sponsored by Sen. Bob Smith (D-Middlesex), boosted the cap to 2.9%. It is estimated that it will take another three years for that level to be reached. The new limit is designed to ensure economic incentive for the home solar industry in the state. The new level leaves room for another 700 MW of solar to be installed in the state.
“This is an important bill that moves solar forward in New Jersey,” Jeff Tittel, director of the New Jersey Sierra Club, said. “This is a ray of sunshine for the solar industry and will create clean energy and more green jobs.”
Coalition Opposes Utility Ownership of Large Renewables
Power plant owners and energy groups have joined forces to oppose utilities directly owning large-scale renewable energy projects such as wind farms. The Independent Power Producers of New York, Alliance for a Clean Energy New York, the Electric Power Supply Association and the New York Affordable Reliable Electricity Alliance said the concept would raise wholesale electric rates.
“New York cannot afford to overlook the benefits and tremendous successes of competitive wholesale energy markets by allowing utilities to once again put ratepayers directly on the hook for costly electricity investments — especially when the private sector has been successfully developing and operating large-scale renewable electric generation facilities for more than a decade,” Gavin Donohue, CEO of IPPNY, said in a statement.
The New York State Energy Research Development Authority countered that its ideas for utility ownership are just one of many options it listed in a June study to give the state new ideas on how to promote large-scale renewable energy projects.
Power Siting Board Moves Ahead on Clean Energy Future Plant
An administrative judge has ruled that a plan to build an 800-MW gas-fired power plant can go ahead to the Power Siting Board for the next step in the approval process. The judge noted that board staff have already determined the plant, proposed by Clean Energy Future, complies with applicable state law. CEF plans to spend $800 million on the plant, which would be built in an industrial park near Lordstown.
The next hearing of the board, which is overseen by the Public Utilities Commission, will be in September. If approved, the plant would begin operations in 2018.
Oklahoma Gas and Electric is pressing ahead with upgrades to its generating plants and preparing for a general rate case as it awaits a decision from state regulators in a $1.1 billion environmental compliance and replacement generation case. If approved, the OG&E request would increase customer bills by 15 to 19% by 2019, with the increases phased in each year as a separate line item on customer bills.
The Corporation Commission has not come to an agreement for a final order in the case. However, two commissioners indicated they would prefer to issue a final order within the next 30 days.
OG&E said it expects to spend about $700 million on an environmental plan to meet federal emissions regulations for regional haze and mercury and air toxics standards. It also estimates it will need about $410 million to modernize its aging Mustang natural gas plant in western Oklahoma City.
Corporation Commissioner Dana Murphy has been appointed to the Electric Power Research Institute’s Advisory Council to the Board of Directors. Murphy chairs SPP’s Regional State Committee.
The Advisory Council advises EPRI management and its board and assists in prioritizing relevant and balanced research to serve the public interest. The appointment was made by Lisa Edgar, president of the National Association of Regulatory Utility Commissioners, who said Murphy’s active service on the EPRI Advisory Council is “important to the cause of strengthening effective public regulation.”
PennFuture Names New Operating, Communications Officers
The environmental advocacy organization PennFuture has named a new chief operating officer and a new director of communications. The statewide organization said Jacquelyn Bonomo, who has experience with other environmental organizations, will become chief operating officer and vice president. She comes to PennFuture from Chesapeake Bay Funders Network, where she was executive director. She also has held upper positions in the National Audubon Society, the Western Pennsylvania Conservancy and the national Wildlife Federation.
Lauren Fraley, a legislative communications professional and former president of the Greater Pittsburgh Chamber of Commerce, will become PennFuture’s director of communications. She is taking the place of Elaine Lablame, who has moved to become the organization’s strategic campaigns director.
Invenergy says its proposed $700 million natural gas-fired Clear River Energy Center in Burrillville would be the most efficient fossil fuel power plant in New England. The plan was announced by Gov. Gina Raimondo and Invenergy CEO Michael Polsky.
If the project is approved by the Energy Facility Siting Board, construction of the 900-MW combined-cycle generator in the northwest corner of the state would start next year and the facility would begin selling power to the New England electric grid in 2019.
Invenergy expects the low-cost plant to displace older, less-efficient power plants that burn oil, coal or gas.
According to a report by the Texas Coalition for Affordable Power, 85% of the state’s customers served by the competitive electricity market pay more for power than those served by municipal utilities in Austin and San Antonio.
The report analyzed U.S. Energy Information Administration data on residential prices since 2002, the first year most residents were allowed to choose their electricity provider under deregulation. According to the study, residents in deregulated areas paid lower electric bills than most Americans for the first time in 2012 and 2013. However, the analysis found the average Texas household in deregulated areas paid about $4,800 more than residents of Austin, San Antonio and other cities served by just one municipal utility or by electric cooperatives from 2002 to 2013.
The state was the 18th cheapest state for homeowners over that 12-year period. Residents in nine states saw cheaper prices than Texans in regulated areas, while 26 states averaged cheaper prices in the competitive market.
State and RTO officials have had two weeks to digest the Environmental Protection Agency’s final power plant carbon emission rule and the battle lines — and paths to compliance — are developing.
While states in the Northeast say they are well on the way to compliance, many in the South and Midwest have already joined in the first set of legal challenges — even as other officials in the Midwest consider carbon trading plans.
Change in state carbon emission targets from draft rule to final
The 15 states who joined in the request for a stay included half of those in SPP, six of those in MISO and five of those in PJM. No Northeastern states were among them. More states may join once the clock on legal challenges begins with publication of the rule in the Federal Register.
PJM, meanwhile, remains concerned about the time required to build transmission to deliver wind power to eastern load centers.
RTO Insider’s follow-up coverage of EPA’s Clean Power Plan includes reports from throughout the Eastern Interconnection:
