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.
PJM energy market prices were down almost 40% in the first half of 2015 compared with 2014, while capacity and transmission service charges rose by double digits, the Independent Market Monitor reported last week.
The load-weighted average real-time LMP, which hit $69.92/MWh in the first six months of 2014 — largely due to the record-breaking polar vortex in January — dropped to $42.30/MWh in 2015, the Monitor reported in its second-quarter State of the Market report.
Uplift charges dropped by $590.1 million (71%) in the first six months of 2015, while congestion costs were down $523.6 million (36%).
Auction revenue rights and financial transmission rights revenues offset 88% of congestion costs in the day-ahead energy market and the balancing energy market for the 2014/15 planning period.
Including capacity, transmission and other charges, prices were down almost 31%, from $88.90/MWh in 2014 to $61.61/MWh this year.
Withholding Concerns
The Monitor said prices reflected short-run marginal costs except during high demand hours in February 2015, which “raises concerns about economic withholding,” it said. The Monitor reported similar concerns for January 2014.
“Overall the market structure of the PJM aggregate energy market remains reasonably competitive for most hours, although the market structure during high demand hours remains a concern,” the report said.
“The performance of the PJM markets under high load conditions raised a number of concerns related to capacity market incentives, participant offer behavior in the energy market under tight market conditions, natural gas availability and pricing, demand response and interchange transactions.
“In particular, there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage.”
Net revenues were lower for all new entrant generation in the first six months of 2015 than in 2014. But net revenues for new entrant gas and coal units were generally higher in 2015 than in the first six months of every other year since 2009.
Coal Loses Generation Share; Solar up 30%
The RTO saw gas displacing coal, with coal-fired generation down 16% (to 39% of the total) and gas-fired generation up 29% (21% of the total). Solar net metering generation rose 30% to 262 GWh but remained only a flicker of the total (0.07%).
Recommendations
The report includes four new recommendations:
Energy Market: PJM should remove non-specific fuel types such as “other” or “co-fire other” from the list of fuel types associated with their price and cost schedules. The Monitor recommends that PJM require market participants to make available at least one cost schedule with the same fuel type and parameters as that of their offered price schedule. (Priority: Medium)
Demand Response: DR resources should be required to notify PJM of material changes affecting the capability of the resource to perform as registered. (Priority: Medium)
Ancillary Services: PJM should report the reason for every hour in which PJM dispatch increases day-ahead synchronized reserve megawatts. (Priority: Medium)
Planning: PJM should enhance the transparency and queue management process for merchant transmission investment to remove barriers to competition. (Priority: Medium). (See related story, PJM Monitor Asks FERC to Resolve TransSource Dispute.)
John C. Citrolo, markets director for PSEG Energy Resources and Trade and a regular attendee at PJM stakeholder meetings, died Aug. 2. PJM’s Market Implementation Committee marked his passing with a moment of silence at its meeting last week.
Known to his friends as “Jay,” the 49-year-old Citrolo lived in Southampton, N.J., with his wife Sandi and his dogs, Jada and Mya.
He was a graduate of Upsala College, where he played football, and earned a master’s degree in economics at Temple University. Prior to joining PSEG, his career in the power industry included jobs with the State of Delaware, Conectiv Energy, Calpine and Net2000. He was also the co-founder and co-owner of the Medford Gym in Medford, N.J.
Surviving, in addition to his wife, Sandra Grungo Citrolo, are his father, John Citrolo Sr.; his stepmother Sally; his sister, Mary E. “Betsy” Citrolo; mother- and father-in-law, Sandra and Burt Roff; as well as six nieces and nephews. His mother, Beverly Young, died in 2013.
Memorial contributions in John’s name can be made to Joe Joes Place, an animal rescue organization, at 7 Tidswell Ave., Medford, NJ 08055.
PJM’s biggest news story of the year may well come Friday with the release of the results from last week’s capacity market auction.
The 2018/19 Base Residual Auction – the results of which are due Friday afternoon — will be the first under the new Capacity Performance rules approved by FERC in June. The rules increase incentives for high-performing resources and penalties for poor performers, largely eliminating force majeure provisions under a “no excuses” policy.
The auction, which ran from Aug. 10-14, was postponed from May due to delays in winning FERC approval.
The changes will be phased in beginning with the 2018/19 and 2019/20 delivery years, when PJM hopes to make at least 80% of its procurement CP resources, with the remainder “Base Capacity” subject to lower performance expectations. The transition will be complete for 2020/21, when PJM expects 100% of capacity to be CP.
It accepted PJM’s prediction that resource performance will continue to worsen without changes, as the RTO sees much of its coal fleet retire, replaced largely by natural gas-fired generation. The majority rejected the arguments of opponents who said the changes were not necessary because generator performance improved last winter following more modest changes, including testing of seldom-used units.
Chairman Norman Bay dissented, saying the proposal will continue to allow generators to profit from poor performance while potentially saddling ratepayers with billions in excessive capacity costs annually.
Friction with Stakeholders
The ruling was followed by a testy, six-hour stakeholder meeting over CP manual changes June 18 that left some stakeholders complaining that the RTO had not thought through all the details. Criticism continued in July, as some members warned PJM officials that the way the RTO plans to calculate CP could lead generators to ignore dispatch instructions to avoid penalties. (See PJM Members: Capacity Performance Penalties May Hurt Dispatch Discipline.)
FERC issued a procedural order July 28 saying it needed more time to consider rehearing requests of its June 9 order from state regulators, consumer advocates, generators and the Independent Market Monitor.
Higher Costs
According to a cost-benefit analysis released in October by PJM and the Monitor, CP could cost ratepayers as much as $6 billion over the next four years, with long-term costs of as much as $700 million annually.
PJM says the increased performance will result in increased monthly capacity costs of about $2 to $3 per household beginning in 2018, assuming average winter and summer weather. In a year of extreme weather, officials say, it would result in net savings because the increased capacity costs will be more than offset by reduced energy costs.
For More Information
PJM’s Board of Managers filed the Capacity Performance proposal in December to increase the reliability expectations of capacity resources with a “no excuses” policy that would result in larger capacity payments and higher penalties for non-performance. (See What You Need to Know about PJM’s Capacity Performance Proposal.)
FERC’s June 9 order required several significant changes from PJM’s Capacity Performance proposal. (See What is Changing in PJM’s Proposal?)
PJM’s Independent Market Monitor has called on FERC to settle a dispute between PJM and a transmission developer, saying the RTO’s unwillingness to release relevant files is unfair to the developer and impeding the Monitor’s own attempts at resolution (EL15-79).
TransSource — not to be confused with Transource Energy, a partnership of American Electric Power and Great Plains Energy — asked FERC in June to order PJM to provide the company with data showing how the RTO calculated network upgrade costs in its system impact studies for several of its auction revenue rights requests. (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)
PJM responded by asking FERC to dismiss the complaint. The RTO insisted it had provided TransSource with all the relevant data, and that the specific files that the company is requesting were not used in the cost calculations. These files, called PLS.CADD, are held by transmission owners and are “highly confidential” according to PJM.
The Market Monitor told FERC in an Aug. 6 filing that it “is concerned that the primary defense raised by PJM is that the complainant does not have the facts sufficient to support its case, and that the claims amount to overly broad generalizations, when the complainant’s case is primarily based on TransSource’s claims that they have not been provided adequate facts to assess the determination to increase assigned costs to TransSource.”
TransSource maintains that under the PJM Tariff and the Federal Power Act, it has a right to the PLS.CADD files. While the Monitor did not comment on specific Tariff or legal provisions, it agreed that TransSource should have access to the files.
“The complaint does not request substantive relief, but only that what appear to be reasonable requests for additional information be answered before TransSource is required to make financial commitments that TransSource is not be able to make unless and until those question are answered,” the Monitor said. It also said the fact that the files are held by the TOs, and not PJM, “is a major obstacle to a resolution.”
The Monitor said it would prefer an administrative law judge to handle hearing or settlement proceedings. In a filing last week, TransSource said it supported this idea.
TransSource “persists in making overly broad and vague accusations such as PJM ‘refused’ to provide any data,” PJM said. “Such accusations deny the commission a true and accurate picture as to exactly what data and assumptions TransSource was denied.” PJM also said that it had informed the company that if PLS.CADD files had been used in the studies, then the RTO would have ordered their release.
PJM also argued that the company lacked evidence for its other accusations, including that transmission owners Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light intentionally inflated the costs of the network upgrades to make it impossible for TransSource to secure funding for them.
SunEdison has sold Dominion Resources a 50% interest in its 420-MW Four Brothers solar project in Utah.
Under the terms of the joint venture, Dominion will invest about $500 million to get 50% of the project equity and 99% of the federal and state tax benefits. SunEdison has secured necessary funding to complete the rest of the estimated $650 million facility. It is scheduled to be operating by mid-2016.
The project’s output is under contract with a 20-year power purchase agreement with Berkshire Hathaway Energy’s subsidiary PacifiCorp.
Overbuilt, We Energies Seeks to Sell Excess Capacity Elsewhere in Wisconsin
We Energies wants Wisconsin regulators to force two other utilities in the state to buy its excess power rather than building new gas-fired generating plants for $1.2 billion.
One of the utilities in need of new generation, Alliant Energy’s Wisconsin Power & Light, has applied for state approval to build a $750 million natural gas-fired plant in Beloit. Alliant said We Energies and its parent, WEC Energy Group, should have submitted its plan earlier and WEC now seeks to force a process in which it would be sole bidder to supply Alliant. The other utility seeking to build new generation is Wisconsin Public Service, which is owned by WEC.
We Energies said selling power to Alliant and WPS would allow the neighboring utilities to avoid the cost of construction and could provide We Energies customers some rate relief by selling excess power. The state Citizens Utility Board and the Wisconsin Industrial Energy Group issued a joint statement saying the proposal was worth considering.
Ameren Withdraws Application for 2nd Callaway Nuclear Reactor
Ameren has withdrawn its application from the Nuclear Regulatory Commission for a second reactor at its Callaway Energy Center plant in Callaway County, Mo., after years of delay.
Ameren said its decision to abandon the project was based on its assessment of long-term capacity needs, declining costs of alternative generating technologies and the regulatory framework in Missouri. CEO Warner Baxter told analysts during the company’s second-quarter earnings call that it continues “to believe nuclear power must be an important clean energy source for our company and country.” Callaway was recently granted a 20-year license extension.
Ameren first filed its application for a second unit in 2008. The company teamed with Westinghouse in 2012 for a small modular nuclear reactor that would be about a fourth of the size of a conventional plant. After being passed over twice for federal grants, Ameren said it was “stepping back” from the project at the end of 2013.
Minnesota Co-ops Combine to Acquire Alliant Territory
Nobles Cooperative Electric, Federated Rural Electric and 10 other electric distribution cooperatives completed their acquisition of Alliant Energy’s electric service territory in southern Minnesota.
The acquisition transfers about 43,000 Minnesota Alliant Energy accounts to local electric cooperatives. According to Rick Burud, general manager of both Nobles Cooperative and Federated Rural, the transfer is a first of its kind. “It is a very unique situation for electric cooperatives to have the opportunity to purchase service territory from investor-owned utilities,” he said.
In 2013, the 12 cooperatives formed Southern Minnesota Energy Cooperative as the single point of contact for the purchase of electric service territory from Alliant. The acquisition process was approved by the Minnesota Public Utilities Commission, Iowa Utilities Board and FERC.
ERCOT’s Board of Directors selected general counsel Bill Magness to become the RTO’s next president and CEO. Magness, who is also currently senior vice president for governance, risk and compliance, will succeed Trip Doggett, who announced in June he plans to retire next year as president and chief executive. Doggett has been CEO since 2010.
“Bill’s leadership skills, as well as his significant executive experience at ERCOT, have positioned him to successfully lead ERCOT through an era of evolving changes in the energy industry,” ERCOT Board Chair Craven Crowell said. “He also understands the importance of — and is committed to — strong working relationships with stakeholders, the Public Utility Commission of Texas and the Texas Legislature.”
World-Renowned Auction Expert Joins ERCOT’s Board of Directors
Cramton
ERCOT approved Peter Cramton as the new independent member of its Board of Directors. An economics professor at the University of Maryland at College Park and a widely recognized expert in energy auctions, Cramton succeeds Michehl Gent, whose third and final term concluded in May.
The ISO said Cramton has played a lead role in the design and implementation of electricity and gas auctions in North America, South America and Europe since 2001. Cramton also chairs Market Design Inc., an economics consultancy that focuses on the design of auction and matching markets. “Peter is a pioneer in his field, and we are delighted to welcome him to ERCOT’s Board of Directors,” ERCOT Board Chair Craven Crowell said in a press release.
The Public Utility Commission of Texas, which oversees ERCOT, approved Cramton’s appointment to the board. State law mandates the board include five unaffiliated members, from which the chair and vice-chair are chosen.
Four Corners Resumes Operation Following Bomb Scare
Operations returned to normal at New Mexico’s Four Corners Power Plant last week following the discovery of three suspicious devices in one of the plant’s three active units.
An FBI spokesman said the three devices, each a steel pipe with its ends capped, were hollow and did not contain explosive material. The devices’ discovery Aug. 3 led to an evacuation of all plant personnel. Operations did not resume until the following day.
The FBI said there was no indication the devices were related to explosions at two Las Cruces churches Aug. 2.
CFO Russ Stidolph told Curry County, N.M., commissioners Aug. 4 that Tres Amigas has posted $8.2 million in collateral to begin making necessary upgrades for the Public Service Company of New Mexico grid.
Stidolph said Tres Amigas is working with land owners to acquire rights of way. He said he expects “significant progress” to be made with land owners in the next months.
Arkansas Electric Cooperatives Inc. announced Aug. 12 that its Today’s Power subsidiary has reached an agreement to provide a 1-MW solar array for Tri-County Electric Cooperative of Hooker, Okla. The facility is projected to generate more than 50 million kWh over its 25-year useful life.
AECI, a utility service cooperative owned by 17 Arkansas electric cooperatives, launched Today’s Power in February to provide renewable energy solutions, energy efficiency programs and emergency backup generators for large commercial, industrial or utility customers. Today’s Power has an exclusive distribution agreement to promote and sell tenKsolar products in Arkansas, Tennessee, Mississippi, Louisiana, Oklahoma and Missouri.
South Plains II is expected to generate 1,200 GWh of energy each year, enough to power more than 90,000 homes and avoid the emission of 2 billion pounds of carbon dioxide. Hewlett-Packard plans to purchase 112 MW of the project’s capacity to power its Texas-based data centers. The remaining 188 MW of capacity will be sold to an affiliate of Citigroup, which is financing the project.
Hunt Consolidated Energy agreed to pay $19 billion for the transmission business Oncor, the jewel of Energy Future Holdings. Energy Future is selling Oncor as part of its bankruptcy proceeding.
Energy Future, formerly TXU, selected Hunt Consolidated among many other offers. Hunt Consolidated has been in the energy business in Texas for more than 80 years.
As part of the bankruptcy restructuring, Energy Future will spin out its competitive businesses — TXU Energy and Luminant — and turn over Oncor to Hunt Consolidated, which will manage the company out of the current Dallas headquarters. The deal still needs several legal and regulatory approvals. Oncor has more than 3 million customers in North and West Texas.
FirstEnergy has expanded the roles of several corporate executives in an effort to “support the company’s focus on customer service and cost management.”
Among those promoted are James Lash, president of FirstEnergy Generation, who will also serve as executive vice president of FirstEnergy. CFO James F. Pearson will see a bump up from senior vice president to executive vice president. Charles Lasky, vice president of fossil fleet operations, will shift to the human resources department as a senior vice president.
FirstEnergy also filled several vacant positions. Trent Smith, vice president of sales and marketing for FirstEnergy Solutions, will serve as supply chain vice president for the parent company, filling a void left by Gary Benz, who was named senior vice president of strategy in June. Gary Grant will take over as vice president of customer service at FirstEnergy Utilities, replacing Ronald Green, who is retiring after 38 years with the company.
The coal-fired Brunner Island power plant in York County, Pa., will soon be burning natural gas to help power its three generators.
New owner Talen Energy says it will spend $100 million to convert the plant to dual fuel, which includes building a 3-mile pipeline to tap into an interstate line. A Talen spokesman said the plant would still burn coal, but he could not say how much power would be generated by either fuel.
While Brunner Island is often listed among the dirtiest plants in the U.S., Talen said the plan isn’t being driven by the Environmental Protection Agency’s Clean Power Plan or any other environmental regulations. “The real driver behind this project is the long-term sustainability of that plant and 200 jobs,” spokesman Todd Martin said. The project is expected to be completed by spring 2017.
Bechtel Breaks Ground on Natural Gas Plant in Virginia
Construction company Bechtel is building a natural gas-fired plant in Leesburg, Va., which will generate enough power for 800,000 homes in Virginia and D.C.
The Stonewall Energy Center is expected to cost about $800 million and be completed by mid-2017. Bechtel has sold its interest in the project to Panda Power Funds, now the plant’s sole owner. A Panda Power spokesman said no new pipelines or transmission lines will be needed and that the plant will use the latest emissions-controlling technology.
AEP Promotes Haynes to SVP of Strategic Initiatives
Haynes
American Electric Power has promoted Stephan Haynes, vice president of strategic initiatives, to senior vice president of strategic initiatives. Haynes will continue his role as chief risk officer.
“Steve and his team have done an incredible job identifying, analyzing and developing mitigation strategies for risk events that could impact AEP,” CFO Brian Tierney said “He also has helped the company evaluate strategic opportunities to grow our business and to move our transmission joint ventures forward.”
Haynes has a bachelor’s in business systems analysis from Harding University and an MBA from Ohio State.
Dispute’s Resolution Sets Up Closure of New Mexico Plant’s Units
Public Service Company of New Mexico and four other parties signed an agreement to end their dispute over the future of the coal-fired San Juan Generating Station in northwestern New Mexico. The settlement potentially paves the way for the state Public Regulation Commission to approve PNM’s plan to shut down two of the power plant’s four generating units to meet federal haze regulations.
Environmental, clean energy and consumer organizations had opposed PNM’s proposals for San Juan, largely because the utility and its parent firm, PNM Resources, wanted to acquire 197 MW of excess coal generation that will be left behind in one of the two remaining generators. The new accord ends that opposition, allowing PNM to take ownership of the additional 197 MW to keep San Juan’s two remaining units fully operational.
The agreement must still be reviewed in a public hearing, now scheduled for Sept. 30, before the PRC makes a final decision.
El Paso Electric has filed a rate increase request with the Public Utility Commission of Texas on Aug. 10 that would add $8.41 to an average residential customer’s monthly bill. The new rates would go into effect Sept. 14, although EPE said a months-long rate case might delay imposition of the increase until the second quarter of 2016.
EPE filed a separate rate case with the New Mexico Public Regulation Commission in May, asking for about $8.6 million that would result in a 9% increase to the average monthly residential bill for its customers in that state. Any approved increase in New Mexico would go into effect in 2016, officials said.
Utility officials said they are seeking to recover some of their infrastructure costs for the El Paso Montana Power Station and its transmission lines and a new operations center. The first two generating units at the Montana station cost about $206 million, with another $20 million for the transmission lines and $40 million for the operations center.
When the Clean Power Plan was released last year, New York’s grid operator was concerned with its impact despite the state’s membership in a regional carbon trading regime.
Changes made in the final plan based on input from grid operators — combined with a more pronounced shift toward gas generation and renewables in New York as new power plants move closer to completion and the state has committed another $1.5 billion for clean energy over the next decade — seem to have allayed those fears.
“Based on our initial review, it appears EPA responded positively to major concerns regarding reliability in the draft rule, and that the final rule is generally favorable to New York,” NYISO spokesman David Flanagan said.
EPA also added a reliability safety valve and a requirement that states seek grid operators’ reliability assessments on their implementation plans.
“A reliability safety valve will allow a state to propose a modified emission standard for an affected generator for a temporary period of time to address an unforeseen emergency situation that threatens reliability,” Flanagan said.
In June, the state committed to reducing all greenhouse gas emissions by 40% from 1990 levels, cutting energy consumption in buildings by 23% from 2012 levels and getting half of the state’s energy from renewable sources.
While New York is ahead of most other states, it will have to make decisions on retirements of aging, fossil fuel plants and the future of the Indian Point nuclear facility.
New England
The New England states — members of the Regional Greenhouse Gas Initiative, along with New York — are generally well ahead of the targets set in the Clean Power Plan, in some cases by several years. EPA has recognized RGGI as a model compliance tool.
Connecticut, Massachusetts and New Hampshire have less stringent goals for the 2022 interim period, reflecting what EPA calls a “smoother glide path.” However, those states have more stringent goals by 2030 compared to other states.
Connecticut’s interim goal is 899 lbs/MWh and its 2030 goal is 786 lbs/MWh; Massachusetts is at 956 and 824, respectively; Rhode Island, 877 and 771; and New Hampshire comes in at 1,006 and 858.
Maine no longer has any of the coal-burning power plants considered the primary target of the emissions reductions. Under the goals, Maine would have to reduce its carbon dioxide emissions per megawatt-hour of electricity by 10.8% by the year 2030.
Vermont is one of three states, along with Alaska and Hawaii, exempted from the rules. Vermont’s largest source of electricity is hydropower imported from Canada. The Green Mountain State has some in-state dams and two wood-burning power generators.
The Union of Concerned Scientists issued a report last week that said the Northeast states are among 20 states that have made commitments (including carbon caps, coal plant closures and mandatory renewable electricity and energy efficiency standards) that put them more than halfway toward meeting their 2030 targets. Sixteen states are likely to surpass the targets, the group said.
