Stakeholders approved a rule change to ensure zones don’t lose Auction Revenue Rights due to anomalies caused by storms or other extraordinary events.
The vote to revise the definition of Zonal Base Load was prompted by Superstorm Sandy in 2012. Storm-related outages produced ZBLs in the AE, JCPL, PSEG and RECO zones that were far lower than would have been expected under normal conditions, PJM’s Brian Chmielewski told the Market Implementation Committee.
PJM obtained a waiver from the Federal Energy Regulatory Commission in February to prevent the zones from losing a portion of their Stage 1A ARR allocations as a result of the muted ZBLs.
ARR allocations are based on zones’ base loads, defined as the lowest daily zonal peak load for the year ending Oct. 21 preceding the annual ARR allocation.
The revised definition allows PJM to ignore load figures resulting from “extraordinary circumstances,” resulting in “an abnormal reduction” in energy consumption. The new definition will require changes to the Tariff, Operating Agreement and Manual 6.
Stakeholders approved two initiatives to improve demand response measurement and verification (M&V) last week.
The Market Implementation Committee approved a problem statement to improve the M&V accuracy for emergency DR. PJM’s Pete Langbein told members the existing procedures, which use the hour before an event as the customer baseline (CBL), may be inaccurate for dispatches in the early morning and on days with multiple dispatches.
Langbein said members have also raised concerns about the:
Cumbersome administrative process to use an economic CBL, which requires an Electric Distribution Company review;
After-the-fact selection of CBLs for use in settlements; and
Use of economic CBLs for customers that primarily participate in the ancillary services market.
Residential DR M&V
Separately, the MIC also approved an issue charge that tasks the Demand Response Subcommittee with developing more accurate M&V methodology for residential demand response. The MIC approved a problem statement on this issue last month. (See PJM Seeks Better Data on Residential DR.)
PJM currently measures load reductions for much of its residential DR based on data that was compiled more than a decade ago in Maryland and New Jersey. PJM’s Shira Horowitz has said the data is no longer representative because of the growth of PJM’s footprint, changes in DR programs and increases in the energy efficiency of air conditioners and other appliances.
The old data were collected based on legacy “direct load control” (DLC) programs. Residential DR now includes use of smart meters and programmable thermostats.
The timetable for developing new M&V rules for residential DR is six months if only manual changes are required, and nine months if they entail Tariff changes requiring a filing with the Federal Energy Regulatory Commission.
Members last week approved rule changes to reduce “adder” payments to frequently mitigated generation units (FMUs), after rejecting a joint proposal from the RTO and the Independent Market Monitor.
The PJM-IMM proposal won only 43% support in a vote of the Market Implementation Committee. It would have limited adders to units whose net revenues are not covering their avoidable cost rate (ACR).
Three generator-backed proposals won at least 60% support from the MIC and are eligible to be considered by the Markets and Reliability Committee on May 29.
Topping the voting with 65% support was a proposal (Package G) to cap adders at 12% of the gross Cost of New Entry (CONE). It will be the primary proposal considered by the MRC — where, unlike the MIC, the voting will be sector-weighted.
Another proposal (Package H) would change adders only for Tier 2 FMUs — units that are offer-capped between 70% and 80% of their run hours over the prior 12 months. The units currently receive $30/MWh, or 15% of the cost offer, not to exceed $40. The revision would eliminate the 15% option, leaving only the $30 adder.
The final proposal (Package F prime) would restrict the adder to a percentage of the cost offer for units with more than 500 run hours in a rolling 12-month calculation period. The cap would be 15% for Tier 1 units (60% – 70% mitigated hours), 20% for Tier 2 units (70% – 80% mitigated hours) and 25% for Tier 3 units (over 80% mitigated hours). Adders would be unchanged for units with less than 500 run hours.
Packages H and F prime will be considered only if the primary proposal fails to win a two-thirds sector-weighted vote at the MRC.
Market Monitor Joe Bowring says the adders are no longer needed because of PJM’s capacity market. Had the PJM-IMM proposal been in effect in 2013, PJM said it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire. (See Increased FMU Costs Lend Urgency to Fix.)
But Dave Pratzon of GT Power Group, which represents generators, said the PJM-IMM proposal was “too extreme a screen.”
“It’s like a homeowner saying to their mortgage company, ‘You should be happy because I’m covering the insurance and taxes. Don’t worry about the principal and interest,’” he said. “You can’t stay in your house that way. A unit owner can’t run their unit that way.”
Bowring said the adders were intended to ensure generators earn enough to cover their going-forward costs. “It’s not intended to provide a return on fixed costs,” he said.
The failure of the PJM-IMM proposal was not a surprise. It won support from little more than one-quarter of those polled in a generation-heavy MIC subgroup that has been considering alternatives.
Acknowledging they were taking what several called “a leap of faith,” stakeholders last week endorsed PJM’s plan for cutting uplift and capturing reserve costs in energy prices.
The Market Implementation Committee voted 118-48 in favor of the PJM proposal, with 37 members abstaining.
While all who spoke said they endorsed the goal of reducing uplift, some stakeholders said they were concerned that the plan would unfairly penalize load and potentially increase overall costs.
It would increase day-ahead and real-time reserve requirements when hot- or cold-weather alerts or max emergency generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion (MAD) synchronized reserve requirement of 1,300 MW.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into Locational Marginal Prices and not uplift.
The adders would be reduced or cancelled if scheduling the additional resources causes difficulty managing the area control error (ACE).
Simulation Not Possible
PJM had hoped to provide members a simulation to illustrate the impact of the changes but was unable to do so. “We don’t have a system that can create real-time [simulations] in the granularity that real time occurs,” said Adam Keech, director of wholesale market operations. Although PJM calculates LMPs every five minutes, the “perfect dispatch” tool that would be used for the simulation can only calculate by the half-hour.
Instead, officials showed the MIC a range of impacts the new practices might have had on eight days in January that resulted in almost $343 million in uplift.
The projection assumed that lost opportunity costs, a component of uplift, would increase by the same percentage that total uplift decreases. Keech said that assumption was an “intuitive” guess, acknowledging, “It’s probably not a one-to-one relationship.”
On Jan. 27, the worst day of the month, uplift totaled $76 million while LOC was $2.1 million. If the change offset 5% of uplift, it would have resulted in net savings of $3.7 million. If the change reduced uplift by 50%, the savings would have been $37 million.
Keech said the impact of the changes will vary daily depending on “how much uneconomic generation … we have on the system that we can soak up.”
MRC Vote
The Markets and Reliability Committee will vote on the changes May 29. But because the new procedures involve only changes to Manual 11, PJM could implement them unilaterally even without stakeholder support.
PJM officials said they plan to implement this “short-term” fix in time for summer and consider other long-term changes that would entail Tariff changes later.
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), said he wanted to see more examples to be convinced of PJM’s assurances that the changes will only capture actions PJM operators are already taking when weather emergencies mandate “conservative operations.” He said he was concerned the new rules could result in PJM invoking shortage pricing more often.
“It’s a leap of faith we’re being asked to take,” said Dave Mabry, of the PJM Industrial Customers Coalition. “We’re just not sure that we’re [not] going too far.”
Worst Uplift Ever
Keech said PJM was responding to concerns voiced by many stakeholders. “We’re coming off a winter with the worst uplift we’ve ever seen,” he said.
Jung Suh of Noble Americas said PJM’s proposal was a reasonable solution to a major problem. “We’ve seen the uplift charges this winter. It was real. It was painfully real.”
Suh said uplift over the summer will be lower than the past winter, allowing an opportunity to test the effectiveness of the new procedures under less stress. “This makes sense,” Suh said. “I don’t think we should go into the winter with an untested proposal.”
Louis Slade of Dominion said his company could not support the changes because it shifts cost allocation in a way “that’s not in line with cost causation.”
David “Scarp” Scarpignato of Direct Energy agreed, saying it was unfair to charge load for costs it didn’t cause. He noted that synchronized and primary reserves are intended to replace units that trip off line. “That’s why [reserve targets] are based on the largest single contingency,” he said.
“I do fear that the short-term solution becomes the long-term solution when there’s no consensus on a long-term solution,” he added. “… We’ve seen that a bit.”
Keech said changing the cost allocation would require a Tariff change and could not be completed before the summer.
An unplanned shutdown of the Salem 1 nuclear generating facility Wednesday was the third for the PSEG-operated plant in Lower Alloway Township, N.J., in less than a month.
Salem 1 Nuclear Plant (Source: PSEG)
Nuclear Regulatory Commission regulations call for stepped-up oversight for reactors that have three unplanned shutdowns within a nine-month period. The latest incident occurred when the protection system for the main generator activated after detecting an unexpected voltage change. NRC spokesman Neil Sheehan said the cause of the shutdown is still under investigation but added shortly after that the plant was a “in a safe condition.”
Salem 1 tripped offline April 8 after the breakdown of a condensate pump. It also tripped April 13 due to a faulty generator protection relay, a switch that protects the generator from changes in voltage. Salem 1 was licensed in 1976. Salem Unit 2 is offline for refueling.
Exelon’s Limerick Generating Station got a thumbs-up from the Nuclear Regulatory Commission in its 2013 annual review. The results mean the station will receive a “normal” level of oversight by NRC inspectors – which still means 5,440 hours of inspection per year.
“We take very seriously the task of stepping back on a regular basis to size up plant performance,” said Bill Dean, NRC’s Region 1 administrator. “Limerick, by virtue of its performance in 2013, will receive our routine — though still substantial — battery of inspections,” Dean said.
Energy Future Holdings Corp., the company that emerged from a leveraged buyout of Texas giant TXU, has filed for bankruptcy after failing to find funding for $40 billion in debt.
The company filed for Chapter 11 protection, saying it has reached deals with some of its largest creditors and that it aims to emerge from protection with 11 months. Investors took TXU private in 2007 with $32 billion in cash and $13 billion in assumed debt. But a series of bad positions, including being on the wrong side of plunging natural gas prices, doomed the company.
Rates for Commonwealth Edison residential customers will go up 20% starting in June, as bills start to reflect a new charge for supply during peak-demand hours. The new energy charge of 7.596 cents per KWh compares to the 5.52 cents residential customers now pay.
The charge reflects prices secured during a power-generator auction held last month by the Illinois Power Agency. Those prices, in turn, reflected higher-than-usual future winter costs, based in part on this past winter’s experience. Different classes of residential customers, such as apartment or condo residents, or single-family homes, may pay slightly different rates. ComEd executives have said the energy-price increase will boost the average monthly bill to about $82.
A flaw around a tube in the reactor’s vessel head at FirstEnergy’s Beaver Valley Unit 2 is being fixed with a welded patch, according to the company and the Nuclear Regulatory Commission. The microscopic flaw was found during the unit’s refueling procedure. An NRC spokesman said the flaw was not a safety threat, but could have grown into one if not addressed.
The reactor pressure head is the original, dating back to 1977. It is scheduled to be replaced in 2017, according to company officials.
Dominion Resources has added to its growing solar portfolio by buying two solar projects in Tennessee’s McNairy County, near the town of Selmer. The two fixed-tilt photovoltaic (PV) plants, named Mulberry Farm and Selmer Farm, will generate 16 MW when completed. The projects, which are being developed by Chapel Hill, N.C.-based Strata Solar LLC, will sell its output to the Tennessee Valley Authority.
Dominion has 41 MW of solar operating in Connecticut, Georgia and Indiana and 139 MW under construction in California.
Dominion Considering License Extensions for Nuke Plants
Dominion Resources is considering seeking a second 20-year license extension for each of its six nuclear units in Virginia and Connecticut. The six already received 20-year extensions atop their original 40-year operating licenses. This would extend their service lives to 80 years. Without the extensions, the plants’ licenses would expire between 2032 and 2045.
“We believe it is possible to relicense these units for another 20 years of safe operations,” said Rick Zuercher, a Dominion spokesperson. The average age of the 100 operating U.S. nuclear plants is 34.7 years, according to Nuclear Regulatory Commission spokesman Scott Burnell.
Dominion’s four reactors in Virginia produce 42% of the electricity used by Dominion Virginia Power’s nearly 2.4 million customers. The company will need approval from both the NRC and the state Corporation Commission for the extensions in Virginia.
With PJM planners nearing a proposed fix for the Artificial Island stability problem, the issue of who will pay for the project took center stage last week. Delaware regulators were not happy with what they heard.
Paul McGlynn, general manager of system planning, presented the Transmission Expansion Advisory Committee with preliminary cost allocation examples on the two least expensive projects among 10 finalists.
The cost of a $240 million proposal by Exelon and Pepco Holdings Inc. to add a 17-mile 500-kV line paralleling an existing 500-kV line from Red Lion to Hope Creek would be spread among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.
In contrast, LS Power’s $234 million proposal to run a 230-kV line across the Delaware River to a new or expanded substation on Delmarva Peninsula would be assigned entirely to the Delmarva Power and Light (“Delmarva”) zone, McGlynn said.
John Farber, of the Delaware Public Service Commission, said he couldn’t understand how Delmarva would be wholly responsible for a project meant to address stability problems in New Jersey. He said the assessment would boost total network transmission costs for Delmarva by 20%.
Farber requested that PJM provide cost allocations for all the projects still under consideration so those who would have to pay could use it to “assess PJM’s decision.”
McGlynn defended the allocation. “The flow on that line [would be] from Salem to Silver Run [Delaware] all year long,” he said.
McGlynn said the cost allocation, which will follow methodology approved by the Federal Energy Regulatory Commission, will not be a factor in determining which project is selected.
Just and Reasonable?
Sharon Segner, of LS Power, said PJM should consider Delmarva’s concerns and whether the RTO’s choice produces just and reasonable rates. “There may be some wiggle room in terms of working with Delaware on the cost allocation,” she said. “It would be worthwhile to be creative.”
The LS Power proposal is the lowest cost option, according to an analysis presented to the TEAC in April. The Exelon-PHI proposal was the second cheapest. (See Planners Near Artificial Island Pick.)
McGlynn also presented the TEAC last week with the results of market efficiency studies that showed neither the southern Delaware crossing nor the line to Red Lion would produce sufficient savings to be a consideration in the selection. The two projects showed benefit-to-cost ratios of 0.25 and 0.15, respectively, well below the 1.25 threshold for market efficiency projects.
PJM has scheduled a special TEAC meeting for May 19 to share information on how the 10 finalists fared in several key areas, including cost, project complexity, siting and permitting.
After receiving feedback from stakeholders, another special meeting will be held June 16 during which PJM will discuss its final recommendation. “I wouldn’t expect, necessarily, a recommendation on the 19th,” McGlynn said. “I expect a recommendation on the 16th.”
The PJM Board of Managers is expected to consider the recommendation at its July 22 meeting.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge, N.J. Five utilities and three independent developers made more than two dozen proposals in PJM’s first competitive transmission project under FERC Order 1000.
FERC Rejects Arbitrage Fix; OKs Most of DR Changes
By Rich Heidorn Jr. and Ted Caddell
PJM yesterday opened the 2017/2018 Base Residual Auction amid modest hopes among generators that the RTO’s rule changes will cause a rebound in prices.
Last year’s capacity auction saw big price drops in most of PJM, compounding the woes of generators, whose energy revenues have been suppressed by cheap shale gas.
PJM stakeholders approved several major changes in an attempt to bolster the capacity market, including a cap on imports and limits on demand response. But lackluster load growth and auction parameters that suggest there may be less price separation this year than last have tempered expectations.
Late Friday, the Federal Energy Regulatory Commission approved most of PJM’s proposal for making demand response an “operational resource.” However, the commission rejected a proposal requiring DR providers to respond to sub-zonal dispatch. The commission also rejected PJM’s proposals for eliminating financial speculation in the auction, instead scheduling a technical conference to develop a solution. (See related story, PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
2013 Results
In last year’s auction, RTO prices dropped 56% to $59.37/MW-day, while prices in ATSI dropped more than two-thirds (to $114/MW-day) and MAAC fell 29% ($119). Prices in the Public Service zone rose 31% to $219.
Over the objections of consumer advocates and others, FERC approved PJM’s plan to create five import zones with a combined limit of 6,499 MW for this year’s base auction (ER14-503). (See FERC Clears Capacity Import Limits.)
The cap represents a 17% reduction from the imports that cleared in 2013. However, external resources can win an exception to the limits if they are pseudo-tied; have confirmed, firm long-term transmission service; and accept the same must-offer requirement as internal resources. PJM’s planning parameters show that only 1,524 MW of the 6,499 MW are available after 4,777 MW in exceptions.
FERC also approved rules requiring DR providers to give more assurances in their offers (ER13-2108), as well as limits on the clearing of limited demand response (ER14-504) that a PJM simulation suggested could increase capacity revenues by $1 billion annually. (See FERC OKs Limits on DR in Capacity Auction.)
Utility Execs Not Excited
In earnings calls over the last two weeks, executives of PJM companies praised the RTO’s rule changes but said they didn’t expect a dramatic rise in prices.
AEP CEO Nick Akins predicted RTO prices of $80 to $100 but added, “But who knows? I mean … the way this capacity construct works … things happen all the time.” Akins’ prediction is in line with that from UBS Securities, which predicted in February that RTO prices will rebound to $80 with MAAC flat at $120.
FirstEnergy CEO Tony Alexander told analysts he was encouraged by these “modest reforms” but more excited that “momentum is growing for changes that can truly help” such as a premium for having fuel on-site, which could boost nuclear and coal plants.
“I don’t think any of the rules currently approved are going to move the auction substantially,” added Leila L. Vespoli, FirstEnergy’s executive vice president of markets.
FirstEnergy President Donald R. Schneider said the “wildcard” will be the volume of offers from new generation in the interconnection queue.
PSEG CEO Ralph Izzo, however, said it is the actions of DR providers that may have more impact. “Really, a large part of the auction turns on what you expect for DR,” he said. The volume of cleared DR dropped 16% last year over 2012.
PPL CEO William Spence said there are too many variables to make a prediction on prices.
“There are a lot of moving parts, a lot of modifications have been made. There is a lot of kind of noise out there around the residual auctions and so forth,” he said. “So I think for this year at least, we are not going to put out an expectation around where we expect RPM prices to settle out, because there is a lot more uncertainty, in our view, coming into this auction than we have seen in past auctions.”
Spence said neither the auction results nor the spike in energy prices over the winter would influence the company’s long-term strategy. The company is reportedly considering selling its generation assets.
“We continue to have, as our No. 1 priority, the aggressive cost control and optimizing the dispatch of our plants,” he said. “At the same time, we do continue to consider other options that could enhance value. There is no particular data point or viewpoint of forward prices that we are waiting for or that would substantially impact our thought process around strategic options for that business.”
IPP Views
Among independent power producers, Calpine was downbeat while NRG was more positive.
Calpine President and Chief Operating Officer John B. Hill said the company has a “flattish to the modestly down view” of this year’s auction prices. “PJM has pushed forward some very strong rules … but we don’t have super high expectations for the auction this year,” he said.
NRG Energy’s Chief Operating Officer Mauricio Gutierrez was a bit more optimistic. “The combined effect of higher requirements and limits on demand response, the limits on capacity imports and the significant levels of un-cleared coal megawatts are positive signs in PJM,” he said.
Load Forecasts
PJM’s load forecast, released in February, predicts the RTO’s summer peak growing almost 7,000 MW to 164,195 in 2017, a 4.4% increase.
PJM predicted growth of 80 to 120 MW in APS from hydraulic fracturing and a 288- to 896-MW boost in the Dominion zone from new data centers. An undisclosed project under construction is forecast to add 50 to 195 MW to BGE’s summer peak beginning in 2017. Peak demand in the AEP zone was reduced by 370 MW, reflecting the loss of an aluminum smelter.
CETO/CETL ratios
PJM’s planning parameters report noted that planners had added three Locational Deliverability Areas (LDAs) — ComEd, BGE and PPL — to the nine modeled in last year’s auction.
Prior to each BRA, the Capacity Emergency Transfer Objective (CETO) and Capacity Emergency Transfer Limit (CETL) are calculated for each of 27 potential LDAs to determine whether separate demand curves should be modeled for them to ensure reliability.
The MAAC, EMAAC and SWMAAC LDAs are always modeled separately.
LDAs are also modeled separately if the CETL is less than 1.15 times its CETO or the LDA had a locational price adder in any of the three prior base auctions.
PJM can also model LDAs separately if it believes it necessary for reliability.
PJM said it would model the ComEd, BGE and PPL LDAs separately for the first time because of concern over generation retirements. The RTO said it wanted to “proactively identify locational supply concerns before they actually occur.”
PJM said most CETL values are about equal to or slightly higher than last year’s auction. The exception is the Pepco LDA which dropped to 5,208 MW, a reduction of 22% from last year, due to generator retirements.
The PS, DPL and SWMAAC zones showed the lowest CETO/CETL ratios, all below 1.4.
Below is a summary of the issues scheduled to be brought to a vote at the Members Committee meeting Thursday. Each item is listed by agenda number, followed by a summary of the issue.
RTO Insider will be in Cambridge, Md., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
5. Consent Agenda
The committee will be asked to approve the following:
B. Revisions to Manual 34: Stakeholder Process
Changes to voting methods at the Standing Committees, and posting and notice requirements.
Section 8.4: Voting Method
The voting procedures would be changed to allow members to indicate their preference for the status quo over proposed rule changes.
As under current rules, each member may vote yes, no or abstain on each proposed alternative. If one or more alternatives receives more than 50% support, a second vote will be taken asking participants to choose between the most popular change and the status quo.
If a simple majority does not prefer the proposed alternative over the status quo, the chair will lead a discussion to determine whether to continue working toward a proposal with wider support or to terminate work on the issue.
If the status quo receives less than a simple majority, the most popular proposal will be the main motion at the Markets and Reliability Committee. Other proposed alternatives that received greater than 50% support may be considered by the MRC as alternative motions.
Section 10.4: Posting Process Timelines
Members would have five business days to comment on proposed revisions to governing documents before votes of the Markets and Reliability or Members committees (down from the current 10-day requirement).
Section 11.13: Consultation with Transmission Owners and Members
Except in emergencies requiring immediate action, PJM would be required to provide Transmission Owners and PJM members 30 days’ notice before making a Section 205 filing to change the creditworthiness provisions of the Tariff. The notice time for making Section 205 filings on other matters would remain at the current seven days.
C. Settlement Formulation Review – Phase II initiative: Clarifications to the Tariff and Operating Agreement (OA) on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.
D. Credit Available for Virtual Transactions: Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).
E. Synchronized Reserve penalty charges for Tier 2 resources: Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failure to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.
F. PJM’s change of mailing address: Changes to the Tariff and Operating Agreement to reflect PJM’s new mailing address to: 2750 Monroe Blvd., Audubon, PA 19403.
6. PJM Board of Managers Nominating Committee (NC)
The committee will be asked to re-elect to the Board of Managers Ake Almgren, who joined the board in 2003, Susan Riley (2005) and Charles Robinson (2011).
Gov. Jack Markell is ready to fill a seat on the Public Service Commission that has been empty for two years, according to reports. Chairwoman Arnetta McRae left the commission in 2011 to take another job, leaving the part-time five-member panel one commissioner short. Commissioner J. Dallas Winslow Jr. was named chairman a few months later, but the fifth commission seat has been empty since.
“The governor is in the process of setting up interviews and plans to nominate a replacement for consideration by the Senate in June,” Markell spokeswoman Kelly Bachman told The News Journal. “There were discussions regarding the possibility of shifting the PSC to a full-time commission; however, at this time we are moving forward on filling the vacancy while maintaining the part-time make-up of the PSC.”
Campaign Flyer for Montgomery County Councilman Roger Berliner (D-1)
A Montgomery County councilman introduced a resolution asking state regulators to require Exelon to improve reliability as a requirement for its takeover of Pepco. Councilman Roger Berliner’s resolution urges the state Public Service Commission to require Exelon to make a “firm commitment” to deliver top quartile performance as a part of its approval of the proposed takeover. Pepco has ranked poorly in performance metrics.
Exelon last month offered to purchase Pepco’s parent company, PHI Holdings, for $6.8 billion. Exelon has promised $100 million in rate credits and other assistance to customers as part of the terms of the purchase.
The commission is currently reviewing a Pepco request for a $43 million rate increase, money the utility has said it needs for infrastructure improvements.
PSEG Reaches $1.2 Billion Settlement on Energy Strong
Public Service Electric & Gas and the state Board of Public Utilities reached a settlement last week on the utility company’s plan to harden its infrastructure to better withstand storm damage. The settlement sets the cost for the system-wide project at $1.2 billion over three years, far less than the original price tag of $3.9 billion. The settlement allows PSEG to recover $1 billion of the costs from customers.
The plan, dubbed “Energy Strong,” was proposed in the wake of the damage done by Superstorm Sandy, which left millions of customers without power. The settlement means cutting the amount of improvements. PSEG Chief Executive Officer Ralph Izzo said he was disappointed that the program was scaled back but glad work will commence. “Clearly, we are not able to make every improvement we planned, but this settlement will allow us to begin to make meaningful upgrades, including upgrading substations that were flooded in Superstorm Sandy and Hurricane Irene,” he said.
Consumer advocates were more optimistic about the settlement. “This has gone from a massive, undefined and frankly unfair program in terms of method of cost recovery, to a now well-defined, targeted work that benefits customers,” said Rate Counsel Director Stefanie Brand.
The state Senate last week passed a two-year freeze in the state’s “green” energy standards and called for studies on their effectiveness. The green standards, mandating renewable energy and energy-efficiency programs, will go back into effect in 2017 without further legislative action.
The original version of SB 310 called for a permanent freeze in the standards, but Gov. John Kasich’s office pushed for the two-year “pause” and further study. Environmentalists, consumer advocates and some business groups have criticized the state’s green standards as too pro-utility. Supporters of the standards freeze, including FirstEnergy, argue that mandating further standards would lead to higher energy bills.
A House-sponsored measure that would cap variable electric rate hikes at 30% – introduced in the wake of the skyrocketing rates during this past winter – made it out of committee but didn’t make it to the floor for a vote before the House recessed.
Rep. Bob Godshall (R-Montgomery) introduced HB 2104 and gathered bipartisan support for the bill. But Godshall said a “full-scale attack” on the bill was launched by electricity suppliers. Some consumers who had signed up for variable rate plans saw bills double or triple this winter.
Electricity suppliers oppose the 30% cap. “HB 2104 in its current form would impose rate caps and price controls contrary to the original intent of electricity deregulation,” said Richard Hudson of the Retail Energy Supply Association. The House may reconsider the bill when it reconvenes in June.
Dominion Virginia Power is seeking a 6% rate increase to cover the unexpected spikes in winter fuel costs and to fund transmission line improvements. The request, filed with the State Corporation Commission last week, would raise a typical residential monthly bill from $107.99 to $114.36 if approved. About $4.46 of that is for fuel costs; the rest is for transmission work.
FirstEnergy subsidiaries Mon Power and Potomac Edison filed a joint rate increase request for $96 million with the state Public Service Commission. Mon Power and Potomac Edison serve about 385,000 and 135,000 customers, respectively. If approved, it would mean an increase of about $14 a month to a typical customer’s bill. The last base rate increase approved by the commission was five years ago.
Norman Bay, President Obama’s nominee for chairman of the Federal Energy Regulatory Commission, is about to get his day in the Senate, along with acting FERC Chairwoman Cheryl LaFleur. Obama nominated Bay, the director of FERC’s Office of Enforcement, on Jan. 30. The president nominated LaFleur to a second five-year term May 1.
It is Obama’s second attempt at filling the chairmanship left vacant since former Chairman Jon Wellinghoff’s term expired. Former Colorado regulator Ron Binz withdrew his nomination in October after failing to win enough support from the Senate Energy and Natural Resources Committee, which will conduct the confirmation hearing for Bay and LaFleur May 20.
Wellinghoff, an ally of Senate Majority Leader Harry Reid (D-Nev.), reportedly lobbied for the nomination of Bay, a former U.S. attorney whom Wellinghoff brought to the commission in 2009.
Committee Chair Mary Landrieu (D-La.), said last week she was impressed with Bay, calling him “very, very knowledgeable about energy markets and structure.” Sen. Joe Manchin (D-W.Va.), however, expressed concern about Bay’s energy experience. Unlike most FERC commissioners in the last decade, Bay has never served as a state utility regulator. Bay had no energy experience before joining FERC. (See FERC Pick a Blank Slate.)
Bay also may face tough questioning over the commission’s enforcement policies, which some critics have labeled heavy-handed. (See FERC, CFTC Reject Due Process Complaints.)
The Tennessee Valley Authority is cutting more than 10% of its workforce through early retirements, attrition and layoffs, its largest staff reduction in more than 20 years.
The federal utility, which has accepted 750 early retirements and won’t fill 1,000 vacant positions, said layoffs will be announced later this year. The company will also lay off 390 Bechtel contract workers from the Wyatt Bar Nuclear Plant in Texas. Staffing levels are at 12,612, down from 51,709 in the 1980s.
TVA says the cuts are necessary to bring staffing levels and electric rates in line with other utilities as power consumption in its service territory drops. TVA President Bill Johnson says he wants a $500 million reduction in annual expenses by next year. TVA supplies power to about 9 million people in Tennessee, Alabama, Mississippi, Kentucky, Georgia, North Carolina and Virginia.
The proposed Fishermen’s Energy project off the coast of Atlantic City and Dominion Resources’ project off Virginia Beach each will receive up to $47 million in federal funding, the Department of Energy announced last week.
Fishermen’s Energy won the grant even though the $188 million project was rejected by New Jersey regulators, who said it would cost utility customers too much. The company wants to build five 5-MW turbines as a laboratory for researchers to learn about offshore wind and investigate interactions between turbines.
The company’s chairman Dan Cohen said the grant was a recognition that “No other project in America is more prepared to put steel in the waters.” A spokesman for the Board of Public Utilities said he could not comment on the grant, noting that Fishermen’s Energy is appealing the agency’s rejection in state court.
Dominion’s project is a 12-MW wind farm to be built 26 miles off the coast of Virginia Beach. It will demonstrate installation, operation and maintenance methods for wind turbines located far from shore, and test hurricane-resistant designs.
A third project to be built off the Oregon coast will also get federal money, the Department of Energy said.
The Nuclear Energy Regulatory Commission is backing off allegations that Exelon purposely violated reporting regulations regarding its nuclear decommissioning funds.
The NRC last year charged that Exelon purposely misled regulators about the funds, but in a ruling issued May 1, it said that it found “insufficient evidence to support a conclusion that Exelon officials acted willfully.” The NRC ruling went on to say, however, that the inaccurate reports in 2005, 2006, 2007 and 2009 about the amount of money in the decommissioning funds was “avoidable.”
The solar array project atop the White House, a project started in 2010, went live last week, White House officials said. It is expected that President Obama will use the installation in announcements this week about further government-backed solar projects. A White House spokesperson described the solar array as capable of generating 6.3 kW and is “part of an energy retrofit that will improve the overall energy efficiency of the building.”
Energy Secretary Ernest Moniz called the installation “a really important message that solar is here. We are doing it, we can do a lot more.”
