PJM’s Board of Managers will ask the Federal Energy Regulatory Commission to approve a proposal opposed by generators to reduce payments to frequently mitigated units (FMUs).
General Counsel Vince Duane told the Markets and Reliability Committee last week the RTO will make the request under Section 206 of the Federal Power Act because the proposal by PJM and the Independent Market Monitor failed to win two-thirds of the Members Committee in June.
The plan garnered a 65.6% sector-weighted vote of the committee, with support from only 23% of Generation Owners and about half of Transmission Owners and Other Suppliers. End Use Customers and Electric Distributors voted unanimously in favor of the proposal, which would limit FMU adder payments to units whose net revenues are not covering their avoidable cost rate (ACR). (See FMU Proposal Falls Short.)
President Obama last week named Cheryl LaFleur as chairwoman of the Federal Energy Regulatory Commission effective July 30 and said new Commissioner Norman Bay will succeed her in the top spot on April 15, 2015.
LaFleur has been serving as acting chair since Nov. 25, when former Chair Jon Wellinghoff resigned.
Bay, who has served as director of FERC’s Office of Enforcement since 2009, won confirmation to the commission under an unusual agreement that Obama wouldn’t promote him to the chairmanship for nine months.
The compromise was crucial to winning the votes of some who criticized Obama’s plan to make Bay — who has never been a regulatory commissioner — chair immediately upon his appointment.
The last five FERC chairmen served a median of 30 months before becoming chair. Only one served less than a year on the panel before his promotion.
The four-unit, 2,422-MW coal-fired Roxboro Steam Plant in in Semora, N.C., is one of the largest power plants in the United States. (Source: Duke)
The North Carolina Eastern Municipal Power Agency is selling its stake in four Duke Energy Progress power plants to Duke in a deal valued at $1.2 billion, the organizations announced last week.
The agreement involves about 700 MW at two coal-fired plants and three nuclear units. When the deal closes, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.
Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.
The deal will allow the agency to unburden itself of a large chunk of the approximately $1.9 billion in debt under which it has been struggling.
The single-unit, 900-MW Harris Nuclear Plant is located near New Hill, N.C. (Source: Nuclear Regulatory Commission)
“NCEMPA’s decision to sell its power generating assets was driven by a desire to lower its power costs and reduce its risk of generation ownership,” said NCEMPA spokesperson Rebecca Agner on Friday. “This agreement will reduce NCEMPA’s outstanding debt by more than 70% and make our costs more competitive. After the sale, NCEMPA will not own any generation assets.”
The agreement needs approval from the Federal Energy Regulatory Commission and several state agencies.
Duke spokesman Jeff Brooks said the agreement was attractive for the company for a number of reasons. He acknowledged that the $1.2 billion sales price was somewhat higher than “book value” of the plants, but he said having sole ownership “will provide long-term fuel savings,” benefiting both Duke and its customers.
“These units were among the least costly [in the Duke fleet] to operate from a fuel standpoint,” he said. In buying back the 700 MW of capacity, Duke will be able to increase wholesale energy revenue while lowering its average fuel costs.
Municipalities will benefit from lower debt service costs.
Although Duke has retired a number of coal units in the region in recent years, the Roxboro and Mayo plants are among its youngest and have already seen substantial emissions control retrofits.
“We have made substantial investments in emissions control and dry ash” collection, Brooks said. “The coal units are among the cleanest in the nation.”
The two nuclear stations could run for at least two decades. The licenses for Brunswick Units 1 and 2 are good until 2034 and 2036, respectively. The Harris license expires in 2046.
The Markets and Reliability Committee last week endorsed two manual changes and approved changes to rules on black start compensation and auction-specific transactions.
Manual Changes
Members endorsed changes to Manual 37: Reliability Coordination to update the System Operating Limits (SOL) definition and violation language (sections 3.1, 3.2) to conform to the North American Electric Reliability Corp. standard.
Revisions to the cost allocation section of Manual 14B: PJM Region Transmission Planning Process also won endorsement. The changes describe the current solution-based methodology as detailed in the PJM Tariff.
Revisions to Manual 14A: Generation and Transmission Interconnection Process were deferred to await coordination with MISO. The revisions are intended to reflect changes in how interim deliverability studies are conducted.
Black Start Compensation, ‘Back Stop’
Members approved a “back stop” mechanism for acquiring black start services through transmission providers when PJM solicitations fail to obtain service for a zone. Members also approved minor Tariff and manual changes relating to the compensation of black start units. (See PJM to Seek Smaller Black Start Changes.)
The new rules:
Allow energy-only black start units to be compensated. There was previously no mechanism to compensate energy-only generators through the base formula rate.
Allow automatic load rejection (ALR) units to recover NERC Compliance costs as documented to the Market Monitor.
Allow fuel-storage compensation for liquefied natural gas, propane and oil. Previously, only oil storage was compensated.
Limit black start units sharing a common fuel tank to claim the fuel-storage compensation for only one unit, closing a loophole.
Schedule a review of compensation formulas every five years (down from the current two years) to align it with the RTO-wide black start solicitation.
The System Restoration Strategy Senior Task Force had considered several proposed changes but none of the others received the minimum 50% support to forward it to the MRC for consideration. With its work complete, the task force will be sunset, said MRC Chairman Mike Kormos, PJM’s executive vice president for operations.
Auction-Specific Transactions
Members gave final approval to a manual change that will make it easier for banks to purchase capacity providers’ revenue streams. The change, proposed by Citigroup Energy, will allow auction-specific transactions to be entered into PJM’s eRPM system after the auction that initiated them. Previously, such transactions could not be submitted to PJM until after the third incremental auction for a delivery year. (See Stakeholders Look to Expedite Auction-Specific Transactions.)
PJM will increase performance penalties and incentives and seek ways to incorporate firm gas transportation in energy prices under an initiative announced last week to reduce generator outage rates.
PJM CEO Terry Boston announced the initiative, which he said resulted from a three-day meeting of the Board of Managers and discussions with present and former leaders of the Members Committee and stakeholder sectors.
The action was prompted by January’s extreme cold, when as much as 22% of PJM’s generation suffered forced outages, three times the normal winter rate.
“We would have to interrupt load if this happened in [future] winters,” Boston told the Markets and Reliability Committee Thursday, noting that the RTO will lose about 8,500 MW of generation to retirements by the winter of 2015/16. “We feel [changing capacity rules] has to be one of our highest priorities.”
Officials said the changes may increase capacity costs but should also reduce volatility during tight supply/demand conditions.
Redefinition of Capacity
“You should think of this as a holistic redefinition of what capacity is,” said Andy Ott, executive vice president for markets.
Members’ initial response to the initiative — which PJM said would be conducted under expedited procedures outside the normal stakeholder process — was muted.
David “Scarp” Scarpignato of Direct Energy questioned whether PJM would bring proposed changes to “advisory” votes before the MRC or Members Committee.
Gregory Carmean, executive director of the Organization of PJM States (OPSI), expressed concern that additional costs would be largely for winter performance while capacity cost allocation is based on summer loads.
Carl Johnson, representing the PJM Public Power Coalition, expressed misgivings over the initiative during a later MRC discussion regarding the Triennial Review of capacity auction parameters.
Johnson said stakeholders haven’t received enough information on the cost impact of the parameter changes, which include a potential increase in the Installed Reserve Margin. Referring to PJM’s plans to “redefine” capacity Johnson said, “When we don’t understand what we’re buying when we buy capacity, to say we’re going to be buying more of it, we cannot support.”
The Consumer Advocates of PJM States discussed the initiative yesterday and was expected to issue a statement later this week.
Fuel Security
A key part of the new definition will be fuel security, meaning incentives are likely to encourage nuclear generators, dual-fuel units and firm gas contracts.
“At 20 mph [the speed at which gas flows], there’s not a lot of difference between just-in-time delivery and too dang late,” Boston said.
He also referred to two coal plants that were unable to operate in January because they lacked natural gas needed to start up. “Twenty thousand dollars’ worth of fuel oil could have brought those units up,” Boston said. “I would pay that now.”
More Flexible Operations
Officials also will be seeking to reverse a trend toward less flexible unit operating parameters. In a 23-page white paper issued Friday, PJM said unit flexibility has dropped as a result of staffing reductions and other cost cuts. (See Problem Statement on PJM Capacity Performance Definition.)
Ott said limits on unit flexibility must be a function of operational limits, not financial concerns. “We’ve seen units with three starts per day reduced to one; units with very short minimum run times became very long minimum run times,” he said.
The effort will also seek to boost operations and maintenance spending to improve generator availability on “low probability peak events” such as January’s polar vortex or last September’s unexpected heat wave.
“Generation owners may choose to cut O&M costs or choose not to make investments that enhance availability as a means to manage costs,” the report noted. “In making such a decision, the generation owner has implicitly or explicitly made a calculation that the benefits of such measures [increased net revenues] do not cover these ‘additional’ costs.”
Generator owners also have complained that there is no way to reflect such costs in supply offers.
“Competitive pressure to clear in the RPM capacity market may push generation owners to not make these investments if they feel other competitors are taking a similar strategy due to the risk of pricing themselves out of the market,” the report said.
Insufficient Penalties
PJM said current penalties for capacity resources that are unavailable during the 500 “peak” hours per year are insufficient.
The Tariff defines summer peak hours as Hour Ending 1500 to HE 1900 on non-holiday weekdays from June through August. Winter peak hours are HE 800 to HE 900 and HE 1900 to HE 2000 on non-holiday weekdays in January and February.
Penalties are assessed only if the forced outage rate during peak hours (EFORp) is more than the five-year average forced outage rate (EFORd5) of the resource.
Generators are often able to avoid even these penalties because the Tariff forgives outages related to a lack of gas as “Out of Management Control (OMC).”
“The penalties for being unavailable during the pre-defined peak hours … provides no incentive to make investments in O&M or infrastructure to enhance availability since there is little risk of incurring a capacity market penalty for being unavailable during reliability critical events,” the report said.
The current structure “provides an incentive for generation owners to hide the real cause behind an outage, or to shift the cause of an outage to a third party such as a gas pipeline” and claim it as OMC, the report said. However fuel delivery contracts and installation of dual-fuel capacity “are business decisions well within the control of the generation owner.”
‘Enhanced’ Liaison Committee Process
PJM officials said they will invoke a never-used “Enhanced Liaison Committee” process so that the new rules can be filed with the Federal Energy Regulatory Commission in time for the winter of 2015/16.
“If Polar Vortex conditions occurred in 2015/16 and outage rates were as high as PJM experienced in January 2014 … PJM would almost certainly experience a loss-of-load event,” the report said. PJM hopes to reduce outages this winter by resuming winter generation testing.
The process — developed by the Governance Assessment Special Team (GAST) in 2011 and documented in Manual 34 — was created to allow members to provide input on issues for which consensus is unlikely and the board acts independently.
“There will be a lot of opportunity in the next two months for dialogue,” promised Dave Anders, director of stakeholder affairs.
PJM has scheduled two meetings — 1-4 p.m. Aug. 12 and 18 — to discuss the initiative and the problem statement white paper.
On Aug. 20, PJM plans to release a draft white paper detailing proposed solutions; it will be the subject of a third meeting from 9 a.m. to noon Aug. 22. Stakeholders’ written comments on the second paper will be due Sept. 12, followed by a fourth meeting to receive additional comments Sept. 24.
The enhanced liaison process will begin Oct. 7 when PJM issues the final version of its solutions whitepaper. Additional input from stakeholders will come through coalitions, which will be required to submit briefing papers by Oct. 28.
The board will meet with the Enhanced Liaison Committee Nov. 4.
The proposed solutions may incorporate cold-weather initiatives being conducted by other committees, including energy storage participation in RPM (Planning Committee); qualifying transmission upgrade (QTU) credits and unit market offers (Market Implementation Committee); and cold weather resource performance improvements and gas unit commitment coordination (Operating Committee).
Arbitrage Technical Conference
General Counsel Vince Duane said PJM will ask FERC to delay scheduling of a technical conference the commission ordered in May, when it rejected the RTO’s plan to curb speculation in capacity market auctions. The conference is to develop solutions to eliminate arbitrage opportunities between the base residual auction (BRA) and incremental auctions (IAs).
“Any conversations with FERC thus far I would characterize as very preliminary,” Ott said in response to a stakeholder question.
Exelon, a company primarily known for its generation fleet, continued its customer-buying spree last week when it announced an agreement to buy Integrys Energy Services for $60 million.
Integrys is a competitive retail electricity and natural gas company with nearly 1.2 million customers across 22 states and D.C.
Exelon will fold those customers in with its existing 2.5 million retail electricity and gas customers served by its Constellation subsidiary. Integrys has commercial and industrial customers across more than 100 utility service territories, primarily in the Northeast. Its residential customers are mostly in Illinois, Michigan and Ohio.
Why is Exelon getting into retail when other utilities such as Dominion are getting out?
“We continue to see growth opportunities in our competitive businesses and the value of matching load to generation, which was one of the primary reasons for our acquisition of Constellation in 2012,” Exelon spokesman Paul Adams said last week. “Integrys Energy Services is a well-run company with an attractive customer base in key markets.”
Chris Crane, Exelon’s president and CEO, also emphasized matching load to generation. “Integrys Energy Services’ geographic footprint is a perfect strategic fit for Constellation and will create opportunities to reach more customers and grow the business, particularly in regions where Exelon also owns significant generation assets,” he said.
The agreement is the latest divestment move by Chicago-based Integrys Energy Group. In June, it announced it would sell its regulated utility operations — Michigan Gas Utilities, Minnesota Energy Resources, North Shore Gas, Peoples Gas, Upper Peninsula Power Company and Wisconsin Public Service — to Milwaukee-based Wisconsin Energy for $9.1 billion.
Others have also decided to get out of the retail business. Dominion Resources announced in March it would sell its retail electric business to NRG Energy.
NRG is paying $165 million for Dominion’s 600,000 retail customers in Illinois, Maryland, New Jersey, Ohio, Connecticut, New York, Massachusetts and Texas. Exelon is paying $60 million for 1.2 million customers.
In April, the company announced plans to buy Pepco Holdings Inc., which will add nearly 2 million distribution customers to its regulated customer count while increasing its rate base to almost $26 billion from $19 billion.
In March, Exelon announced that it was buying Indianapolis-based ETC ProLiance Energy. ProLiance is a retail supplier of natural gas with about 2,500 commercial and industrial customers in eight states. The terms of that acquisition were not released at the time.
One of the prizes of buying a retail business like Integrys is that it will allow Exelon to compete for some of the valued municipal contracts its regulated utilities, such as Commonwealth Edison, have been losing to retail companies. This includes the contract for a large chunk of Chicago’s customers. In 2012, Exelon lost 700,000 residential customers in Chicago to a retail energy business — Integrys.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee meeting 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 Valley Forge covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM Manuals (9:10-9:20)
Members will be asked to endorse the following:
Revisions to Manual 37: Reliability Coordination to update the System Operating Limits (SOL) definition and violation language (sections 3.1, 3.2) to conform to the North American Electric Reliability Corp. standard. Includes updates to various references and the Interconnected Reliability Operating Limit (IROL) table (Section 3.1).
Revisions to Manual 14A: Generation and Transmission Interconnection Process to reflect changes in how the interim deliverability studies are conducted. Language was added regarding projects proposed for interconnection to PJM and those seeking connections with MISO. Stakeholders in MISO are reviewing similar language; the manual may require additional changes depending on their feedback.
Updates to the cost allocation section of Manual 14B: PJM Region Transmission Planning Process to describe the current solution-based methodology as detailed in the PJM Tariff. There are no changes to the actual method or calculation.
3. System Restoration Strategy Task Force (SRSTF) Recommendations (9:30-10:00)
Members will consider minor Tariff and manual changes to the compensation of black start units. The System Restoration Strategy Senior Task Force considered several proposals but only one received the minimum 50% support to forward it to the MRC for consideration. (See PJM to Seek Smaller Black Start Changes.) The proposal would:
Allow energy-only black start units to be compensated. There is no mechanism to compensate energy-only generators through the base formula rate.
Allow automatic load rejection (ALR) units to recover NERC Compliance costs as documented to the Market Monitor.
Allow fuel-storage compensation for liquefied natural gas, propane and oil. Currently, only oil storage is compensated.
Limit black start units sharing a common fuel tank to claim the fuel-storage compensation for only one unit, closing a loophole.
Schedule a review of compensation formulas every five years (down from the current two years) to align it with the RTO-wide black start solicitation.
Facing a barrage of criticism from environmentalists, New Jersey officials and spurned bidders, PJM’s Board of Managers has delayed action on planners’ recommendation that it select Public Service Electric & Gas to fix the Artificial Island stability problem.
Instead, the board will allow PSE&G and finalists Transource Energy and Dominion Resources to “supplement” their proposals in response to finalist LS Power’s offer to cap its project cost at $171 million — $40 million to $90 million less than the PSE&G project.
“The project costs included in any such supplemental proposals to PJM will be factors considered in the final selection for an Artificial Island solution. However, the Board has reiterated that cost is only one of several considerations that will drive a final decision,” Vice President for Planning Steve Herling said in a letter to the Transmission Expansion Advisory Committee yesterday.
Herling said PJM will respond to the criticism of its recommendation and its handling of the solicitation — the first under the Federal Energy Regulatory Commission’s Order 1000 — at the Aug. 7 TEAC meeting. Planners also will discuss “any issues that require further analysis,” Herling added.
PJM also will contact the Nuclear Regulatory Commission to discuss how some of the proposals might impact the switchyards for Artificial Island’s occupants, the Salem and Hope Creek nuclear plants.
The board made its decision in a closed meeting Tuesday and announced it yesterday in a liaison meeting with PJM members.
Comments Mostly Critical
The board received 10 comments from bidders and other stakeholders after PJM planners announced their decision to recommend PSE&G last month. Only PSE&G and the Delaware Public Advocate supported the recommendation. Delaware said it preferred the planners’ recommendation — a 500-kV line between the Hope Creek nuclear plant and Red Lion, Del. — because a 230-kV southern path to Delaware would allocate the entire project cost to Delaware ratepayers.
Wetlands are among the sensitive ecosystems that would be impacted by the northern 500-kV path chosen by PJM planners. (Source: PSEG)
LS Power, Atlantic Grid Development, Dominion and Transource contended the proposal selected was technically inferior and/or more expensive than their own proposals. Exelon and Pepco, which made a joint proposal, said they would not challenge the recommendation but joined the others in criticizing the process as unfair and lacking transparency.
New Jersey’s Board of Public Utilities and Division of Rate Counsel criticized PJM’s recommendation as more expensive and presenting more of a permitting risk than the southern alternative because of its impact on sensitive environmental areas. The Sierra Club and the Delaware Riverkeeper Network said they shared the state’s concerns over the environmental impact of the northern path.
PJM’s choice “is very damaging environmentally, and not just to one important ecological resource, but to hundreds,” Delaware Riverkeeper Maya K. van Rossum said. The Riverkeeper Network is a non-profit organization formed to “advocate, educate and litigate” on behalf of the river. It promised it would “be active and committed” in its opposition to the 500-kV proposal.
Process Not Followed
Several of the bidders criticized PJM for failing to follow the procedures spelled out in PJM’s Order 1000 compliance filings, which revised Schedule 6 of the Operating Agreement.
PJM had said it would invite transmission developers to develop solutions to individual transmission needs and choose the best proposal from among the submissions. If none of the proposals were satisfactory, PJM could either revise its problem statement in a new solicitation window or develop its own solution and designate the incumbent transmission owner(s) to build it.
The bidders say that PJM changed the requirements by adding a unity-power-factor requirement — typically required for new generation interconnections — which none of the 26 proposals could meet.
Instead, the planners proposed adding a static var compensator (SVC) to all of the finalists’ proposals at an additional cost of $80 million.
PSE&G Proposal
PSE&G’s winning proposal was estimated at $1.066 billion before PJM planners eliminated two 500-kV lines from it. That reduced the project’s cost by more than three-quarters to a range of $211-$257 million, making it equal to an LS Power 230-kV proposal that was the cheapest among the finalists, PJM said.
“Although credited to [PSE&G], the selected Hope Creek to Red Lion 500-kV solution is nowhere close to the originally submitted proposal,” American Electric Power, co-owner of Transource, said in its July 18 letter to the board. “A modification that results in a more than 75% reduction in scope from what was originally proposed is a new project and should be treated as such.”
LS Power insisted its proposal would cost only $149 million and offered to cap its recovery at $171 million, a savings of at least $40 million to $90 million over the PSE&G project. (See Losing Bidders Blast Artificial Island Choice.)
Exelon and Pepco said that PJM had failed to provide the transparent selection process it promised FERC. “Following the filed process would likely have resulted in a significant reduction of more than a year’s worth of hard work performed by, and expenses incurred by, all participants,” they wrote.
In his letter to the TEAC yesterday, Herling said PJM was committed to improving its process to ensure fairness and transparency. “Order 1000 … has created entirely new processes, which are especially challenging when evaluating transmission solutions as complex as those required for the Artificial Island stability issues,” he said.
State officials know when large shipments of potentially explosive Bakken crude are shipped by rail to a refinery in the state but won’t release that information to the public because of security concerns, The News Journal reported.
CSX Corp. and Norfolk Southern Corp. have begun reporting oil train shipments in compliance with an emergency order issued in May by the U.S. Department of Transportation. Delaware safety officials, however, signed confidentiality agreements to share the information only with state and local emergency management agencies. Other states, including Oklahoma and Pennsylvania, also keep quiet about crude oil shipping details.
At an investor meeting in the spring, a PBF Energy official said its Delaware City refinery receives about 102,400 barrels of crude via rail shipments daily. A Sierra Club of Delaware member has resorted to compiling a map of oil shipments in Delaware based on reports she receives from volunteer observers in order to inform the public. Last July, 47 people were killed and much of a small town in Quebec was destroyed when a train carrying crude derailed.
A Newark city councilman said the University of Delaware could have saved everybody a lot of time and trouble had it vetted a data center and power plant plan better earlier in the process. Noting that the 279-MW power plant that was part of the data center plan was what ultimately doomed the project, Councilman Stu Markham said the university could have reached the “no” point long before the city and other groups invested so much time in investigating the plan.
A university official said the plan looked like a good fit at first, but it later became apparent that the data center, with the large power plant, didn’t fit in with the university’s plans. The site is still open for development, but any power plant built there will be smaller, university officials have said.
The city council last week confirmed new Public Service Commission member Willie L. Phillips and reconfirmed Betty Ann Kane as chairman. The confirmations mean that for the first time since December, all three commission seats are filled.
Kane was first named to the commission in 2007 and became chairman in 2009.
Phillips, an attorney, comes to the commission with a background in utility regulation and compliance enforcement. He was previously assistant general counsel for the North American Electric Reliability Corp.
Alternative Suppliers Provide Savings 3 Years Running
The state Commerce Commission’s Office of Retail Market Development issued its annual report, saying that retail electric competition continues to provide savings for residential customers. The report said ComEd residential customers saved an estimated $39 million between June 2013 and May 2014. Residential switching continued in the last year, but at a slower rate than the previous two years, according to the report.
IURC Nominating Committee Gets 8 Names to Consider
The nominating committee of the state Utility Regulatory Commission has identified eight candidates to replace Commissioner James Atterholt and will interview them July 30. Nominated were: James L. Adams, Marline R. Breece, Karen E. Caswelch, Carole Sparks Drake, Eric M. Hand, Robert L. Hartley, James F. Huston and David R. Johnston. Atterholt’s seat opened up when Gov. Mike Pence tapped him as his chief of staff. Pence will be presented with three finalists following the interview.
A group of landowners and a coal industry group sued in federal court to block plans by the Tennessee Valley Authority to shutter a coal-fired generating plant. The TVA announced last year that it was going to close the two-unit Paradise Fossil Plant in Muhlenberg County and replace it with a new gas-fired generator.
This month, the Kentucky Coal Association filed suit in U.S. District Court in Owensboro arguing that the TVA didn’t follow federal rules in closing the plants. A group of landowners joined the suit, protesting the planned installation of a 24-inch natural gas pipeline to the proposed new generator. The TVA has said that it followed proper procedures, and the decision to convert to natural gas was designed to meet emissions guidelines.
The Somerset County Commission asked county planners to review a draft ordinance aimed at regulating commercial wind farm development in anticipation of a vote by the commissioners this fall.
The draft was developed in 2012 but never voted on. Now, some landowners and others are taking a second look at it and suggesting revisions, including larger setbacks between proposed facilities and homes, schools and roads. Pioneer Green, a company with a proposal in the pipeline to develop a 50-turbine plant in the county, is urging the county to finalize the ordinance.
A state judge ruled last week that the bid-rigging case against Chesapeake Energy will go to trial. Judge Maria Barton of Cheboygan County District Court ruled that there was enough evidence of alleged bid rigging between Chesapeake Energy and Encana Corp. at a 2010 land-lease auction. Barton cited emails between an Encana executive and a man bidding on the company’s behalf that said, in part, “This is a Chesapeake area and we will not be bidding.” Encana settled anti-trust charges against it with a $5 million civil payment to the state in May.
Planned Nuclear Co. Gets $260 Million in Tax Breaks
Camden Waterfront skyline
A company with plans to build nuclear reactors and related equipment at a future plant on the Camden Waterfront was given $260 million in tax credits and other economic subsidies in what is being described as the third-largest subsidy in state history. The state Economic Development Authority awarded the incentives to Holtec International based on its promises to create 235 new jobs and relocate 160 other jobs from other parts of the state.
Once the operation is set up it will get $26 million a year for 10 years. Holtec was also eyeing Charleston, S.C., as a location. It plans a 600,000-square-foot plant to build the reactors.
The award to Holtec, whose board includes Democratic powerbroker George Norcross, was decried by numerous lawmakers, with one calling it “crony capitalism.”
Chilicothe Prison Cells to be Warmed with Solar Heating
A $1.7 million solar-power system will heat cells and hot water in a state prison in southern Ohio, saving taxpayers about $245,000 a year. The system uses 400 panels installed on the roof of Ross Correctional Institution. Solar energy is used to heat an antifreeze-like liquid, which is then used to heat eight cell blocks at the prison, according to the Department of Rehabilitation and Correction. The system also produces hot water for prisoners. Ross was opened in 1987 and holds about 2,100 inmates.
A state appellate court last week upheld a ruling that gave towns the right to regulate some oil and gas development. The court threw out an argument that the state Public Utility Commission has the authority to overrule local governmental action in regulating where well sites and other facilities can be located.
With its ruling, the court upheld an earlier decision by the state Supreme Court. That decision was challenged by state regulators who saw it as a challenge to their authority. “Local zoning matters will now be determined by the procedures set forth under the [Municipalities Planning Code] and challenges to local ordinances that carry out a municipality’s constitutional environmental obligations,” President Judge Dan Pellegrini wrote in the opinion.
Delegate Appeals for Fed Help Against AEP Rate-Hike Plan
State Delegate Clif Moore thinks Appalachian Power’s recent request to raise rates 17% is too much, and he is reaching out to federal officials for relief. “Please be advised this correspondence respectfully transmits my utter disdain, shock and amazement with American Electric Power in their quest to seek a 17% increase in already unaffordable electric costs,” Moore wrote. “It is, in my humble opinion, imperative for state and federal regulators to verify that current rates are within legal limits.” He has called on the Federal Trade Commission to intervene. Appalachian, an AEP subsidiary, filed the base rate request with the Public Service Commission, seeking a $226 million increase to go into effect in April 2015.
Overhead shot of Pacific Gas and Electric’s Metcalf substation, which came under attack last year.
The Federal Energy Regulatory Commission tentatively approved a rule to protect the grid against physical threats last week after ordering changes to allow the commission to overrule transmission operators’ definition of “critical” facilities.
The Notice of Proposed Rulemaking (RM14-15) said the North American Electric Reliability Corp.’s draft “largely satisfies” the commission’s March 7 order, which called for developing the standard in an unusually short three months. The order, which was issued under pressure from members of Congress alarmed by the 2013 sabotage of a Pacific Gas and Electric substation.
It will require transmission owners and operators to provide protection for “critical” substations, but it allows each utility to determine what substations are critical.
Veto Rights
The commission ordered NERC to change the rules to allow “applicable governmental authorities” — including FERC, other federal agencies and Canadian provinces — to add or subtract facilities from an entity’s list of critical facilities. “It’s not something we expect to happen frequently but it’s authority that we thought we should have,” acting FERC Chair Cheryl LaFleur said Thursday.
Transmission operators will be required to have their critical facility lists reviewed by third parties; TOs that reject third-party recommendations would be noncompliant unless they provide a “written, technically justifiable” reason for doing so.
The commission also ordered NERC to eliminate references to “widespread” instability, saying the phrase “could, depending on the meaning of `widespread,’ narrow the scope [and number] of identified critical facilities under the proposed Reliability Standard beyond what was contemplated in the March 7 Order.”
It ordered NERC to submit an informational filing after one year evaluating resiliency measures for recovering from a loss of critical facilities.
The commission accepted NERC’s justification for excluding generator owners and operators from the rule, agreeing that a generation facility “does not have the same critical functionality as certain transmission stations and transmission substations due to the limited size of generating plants, the availability of other generation capacity connected to the grid and planned resilience of the transmission system to react to the loss of a generation facility.”
However, it required NERC to do a second informational filing to address whether “high impact” control centers for generators and other non-transmission entities should be covered by the rule.
Reliability Standard CIP-006-5 (Cyber Security—Physical Security of BES Cyber Systems) already requires primary and backup control centers of reliability coordinators, balancing authorities and generator operators to implement some physical security protections, including restrictions on physical access. But the commission said the existing rule “may not be sufficient to `deter, detect, delay, assess, communicate and respond to potential threats and vulnerabilities’” and does not require an unaffiliated third-party review as in the proposed standard.
Commissioner Tony Clark acknowledged the criticism Thursday but said the standard was “a very solid first step” and that rejecting it was not an option.
“Some have noted that the proposed standard would not provide enough visibility across the interconnection given that the identification of facilities would be done as a `bottom-up’ exercise. I believe there is a grain of truth in those concerns,” he said in a statement issued after the commission meeting.
“I encourage all stakeholders to view this as an iterative process that will continue to be improved. I view our proposed modifications and informational filings as avenues for further discussion and development to ensure that total grid awareness is considered when selecting assets to be further protected by enhanced physical security.”
Comments on the standard will be due 45 days after publication in the Federal Register, with reply comments due 15 days after that.
“I just would plead with folks to be rational,” said Commissioner John Norris, who had expressed concern that the expedited deadline and the commission’s ex-parte rules would inhibit the development of intelligent rules. (See FERC Orders Rules on Grid’s Physical Security.) “We can’t barricade our way out of this.”
Other Standards OK’d
The commission also gave preliminary approval to the Protection System Maintenance Reliability Standard (RM14-8), which requires applicable entities to include certain autoreclosing relays as part of their protection system maintenance programs.
The NOPR requires NERC to submit a report in two years based on actual performance data and simulated system conditions from planning assessments to recommend whether the standard is covering all relays necessary to ensure reliability. It also requires NERC to amend the standard to include maintenance and testing of supervisory devices associated with applicable relays.
FERC also gave final approval to the Generator Relay Loadability reliability standard and revisions to the Transmission Relay Loadability standards (RM13-19-000 and RM14-3-000). The commission said the generator relay standard will reduce the likelihood of premature or unnecessary tripping of generators during system disturbances. The commission ordered revisions to the current standard governing transmission relay loadability to prevent “compliance overlap” by eliminating potential inconsistencies between the two standards.
