New Jersey regulators approved a $25.5 million annual increase in Atlantic City Electric Co.’s base distribution rates and recovery of $70 million costs for recovery following the June 2012 Derecho and Hurricane Sandy in October 2012.
Capital costs of $44.2 million were included in the rate base while deferred operation and maintenance expenses of $25.8 million will be amortized over three years.
The New Jersey Board of Public Utilities announced its approval of a settlement signed by the utility, the Division of Rate Counsel and intervenors including Wal-Mart Stores, Inc. on June 21.
The company’s $25.5 million base rate increase, which excludes sales and use tax, is based on a return on equity of 9.75%. The new rates will cost residential customers using 1,000 KWh per month $4.44, a 2.8% increase. The changes took effect July 1.
The company, a subsidiary of Pepco Holdings, Inc. (PHI), had sought a base rate hike of almost $70 million. Because of the lower increase, the company said it will reduce its capital expenditures by about $150 million through 2015, a cut of 30%.
The New Jersey legislature voted last week to urge state utility regulators to support development of an offshore transmission “backbone” to deliver wind power and relieve transmission congestion.
The Senate approved a resolution supporting the New Jersey Energy Link (SCR 159) 24-12 on Thursday, after an identical measure (ACR 197) passed the Assembly 58-18 on June 24.
The resolution asks the state Board of Public Utilities (BPU) to request that PJM include the project in its Regional Transmission Expansion Plan (RTEP) with an assumed capacity of 1,000 to 3,000 MW.
Map of Proposed New Jersey Energy Link (Source: Atlantic Wind Connection)
The measure outlines a four-stage process leading to commencement of construction in 2016 and urges BPU to sign a contract allowing the project developer, Atlantic Grid Development, LLC, to recover future development costs from ratepayers. The Federal Energy Regulatory Commission would be asked to modify a 2011 order so that ratepayers are not liable for any costs incurred before June 28 if the project is abandoned for reasons beyond the developers’ control.
The resolution also calls for a study by the New Jersey Economic Development Authority of the “economic activity, tax revenue growth, job creation [and] pollution reduction.”
The New Jersey Energy Link is the northernmost section of the Atlantic Wind Connection, which could transport wind from offshore turbines as far south as Virginia.
The developers say the project will create about 2,000 jobs, including 500 or more in the Delaware River port of Paulsboro, where they plan to build offshore converter platforms.
Atlantic Grid said four wind developers — Apex Wind Energy, EDF Renewable Energy, Fishermen’s Energy and OffshoreMW, LLC – have endorsed the project as the most efficient means to deliver the state’s offshore wind.
The developers say the undersea transmission also will help relieve transmission congestion when the wind isn’t blowing, allowing North Jersey to access cheaper power.
Atlantic Grid CEO Bob Mitchell has said approval of the legislation is “crucial” to getting the project built.
Stefanie Brand, director of the New Jersey Division of Rate Counsel, could not be reached for comment yesterday. She said previously that the line should not be considered until there is offshore generation for it to service, saying there are likely cheaper solutions to North Jersey’s transmission congestion. A BPU spokesman did not immediately reply to requests for comment yesterday.
New Jersey lawmakers approved legislation in 2010 committing the state to purchase 1,100 MW of offshore wind by 2020. But the only project proposed to date, a 25-MW pilot off Atlantic City, has been unable to win approval from state ratemakers to date.
Ron Binz – Consultant & FERC Nominee (Source – Public Policy Consulting)
President Obama last week tapped former Colorado utility regulator Ron Binz to replace outgoing FERC Chairman Jon Wellinghoff.
Who is he? A Democrat, Binz served as chairman of the Colorado Public Utilities Commission from 2007 through 2011, during which he drew praise from renewable energy advocates, opposition from the coal industry and criticism for his travel practices. He joined the PUC after serving as head of the state Office of Consumer Counsel from 1984 to 1995.
What is he likely to do at FERC?
Here are some clues: In a 2012 article he co-wrote for an electricity policy journal, Binz called for a new regulatory compact, saying that current utility regulation is “cumbersome … overly judicial and confrontational.” As a result, he wrote, it “provides limited motivation for utilities to innovate, diversify to manage risks, or undertake new efficiencies.”
The electric utility industry, he said, is in the midst of “what may be the most uncertain, complex and risky period in its history” due to large investment needs, stricter environmental controls, decarbonization, changing energy economics, new technologies and reduced load growth.
Will he face trouble winning Senate confirmation? He shouldn’t count on the votes of coal-state senators. But his support from industry and even some Colorado Republicans suggest he’ll survive, barring some unforeseen revelations. One potential snag: Obama has appointed him to not only join the commission but to immediately become chairman, a departure from past practice.
Dual Role
As is the case at FERC, the Colorado PUC served both a judicial and policy-making role. Binz saw the PUC’s role as “not simply as an umpire calling balls and strikes, but also as a leader on policy implementation” he said in an interview with a demand response group.
In that role, Binz participated in the drafting of Colorado’s Clean Air-Clean Jobs Act which offered utilities incentives for replacing coal-fired power plants with natural gas. Binz later rejected requests that he recuse himself from PUC cases implementing the law.
The bill, which was opposed by both the coal industry and independent power producers, led to the retirement of six coal-fired generators, the addition of pollution controls at two others and the construction of new gas generation at a cost of about $1 billion, according to the Denver Post.
Frequent Flyer
Binz also generated controversy for his frequent travel, spending 200 days at conferences during his tenure. In an apparent reference to Binz, a report by the state auditor said one unnamed commissioner was traveling so often that it was “difficult for division staff to meet with him and ensure his preparedness for meetings and hearings.”
In 2011, the Colorado Independent Ethics Commission found he had violated state travel policy by accepting free travel to speak at an industry conference in Houston. The panel declined to fine him, however, saying he did not personally benefit.
Binz was unapologetic about his travel, telling an interviewer that utility regulators and staffs “need much greater access to educational resources: publications, conferences [and] seminars” to prepare for emerging issues and not be “only reactive.”
Since leaving the PUC, Binz has worked with a Colorado renewable energy institute and run a consulting firm with clients including homebuilders, trade associations and environmental and consumer groups.
Industry Reaction
Binz’ nomination won praise from executives at Public Service Enterprise Group Inc., NextEra Energy Inc., Xcel Energy Inc. and the American Wind Energy Association.
NextEra CEO Jim Robo called Binz “a superb choice,” saying he “recognizes the need for diversity in the U.S. electricity supply and understands our country needs smart policies to modernize the grid to match up with today’s changing energy mix.”
Public Service Enterprise Group Chairman Ralph Izzo called Binz “a strong and timely choice.
“In Colorado, he showed a willingness to work with diverse groups and elected officials of both parties to develop and implement commonsense legislation,” Izzo said.
(Source FERC)
He also received an endorsement from former Colorado House Speaker Lola Spradley, a Republican, who said his “expertise and leadership proved critical to advance a balanced approach in Colorado.”
Alaska Sen. Lisa Murkowski, ranking Republican on the Energy and Natural Resources Committee, issued a statement that was noncommittal on Binz’ qualifications but skeptical of Obama’s plan to elevate him immediately to chairman.
Murkowski said she “strongly believes that each of the commissioners, and especially the chair, must have and maintain a judicial temperament and must demonstrate a record for balance and a scrupulous regard for the law and the rules. It is noteworthy that in recent decades it has been rare to elevate the newest member of the commission directly to chairman. Under the law, FERC’s chair is responsible for setting the agenda and managing the agency.”
The last five chairmen served a median of 30 months before becoming chair. Only one, Patrick H. Wood III, served less than a year on the panel before his promotion.
The Markets and Reliability Committee Thursday approved changes to the way PJM determines beneficiaries of market efficiency transmission projects.
MRC also changed the way PJM planners add generation in market efficiency simulations and revised the definition of production costs to include cross border purchases and sales.
The changes, which were approved without opposition, were developed by the Regional Planning Process Task Force to align modeling and beneficiary determinations with the revised cost allocation formula approved by the Federal Energy Regulatory Commission in PJM’s Order 1000 compliance filing.
PJM uses an hourly unit commitment dispatch simulation to measure savings in production costs and load payments over 15 years.
Under the change approved by MRC (Package 10), benefits of regional projects will be calculated on a 50/50 ratio based on its impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). (See chart)
Benefits of local, low-voltage projects will be determined entirely on the change in net load or capacity payments for zones that experience decreases.
Under the previous method for both regional and local projects, 70% of benefits were calculated based on production or capacity cost savings, with the remainder based on change in net load or capacity payments.
Generation Expansion
MRC also changed the way PJM adds generation in market efficiency simulations. Comparing forecasted load against forecasted generation typically results in a shortfall in the Installed Reserve Margin (IRM) in the later years of the 15-year horizon.
Under current procedures, PJM scales existing generation units to assume supply will grow to meet the forecasted IRM. Active generation queue projects that are not part of the unit specific plan — existing PJM units as well as units that have an executed Interconnection Service Agreement (ISA) — can impact the location and type of generation scaled.
Under the new procedure, PJM planners will include all generation projects with executed ISAs or Facility Study Agreements (FSA). Existing units will be scaled based on location and technology to meet the reserve requirement. Planners also will include transmission upgrades for congestion that arise from scaling assumptions.
Cost Allocation and Benefit Determination – Market Efficiency Projects in PJM
Production Cost Definition
The current definition of production costs limits market efficiency simulations to purchases and sales within PJM, ignoring cross-border transactions.
Under the new definition, PJM will include costs for purchases from selected regions and lines outside PJM as well as sales outside PJM. Purchases will be valued at the load weighted LMP and sales will be valued at the generation weighted LMP.
If given final approval by the Members Committee, the changes will be effective in the 24-month market efficiency cycle beginning in January 2014.
The Markets and Reliability Committee Thursday approved changes to Manuals 11 and 14D, while the Members Committee approved changes to Manual 15.
Manual 11: Energy & Ancillary Services
Reason for changes: Clarifications, error corrections and changes to conform to other manuals.
Impact:
The changes:
Clarify and add conforming language for regulation rules:
Resources cannot clear for both RegA and RegD within an operating hour (Section 3.2.9)
Changes language to conform to M12. Regulation resources must return to their regulation range within 10 minutes of the end of a synchronized reserve event (Section 4.2.12). The current language calls for a return within two minutes.
Clarify hydropower units’ opportunity cost when providing synchronized reserve:
Hydro units providing Tier 2 synchronized reserve receive lost opportunity cost payments only when they are held to condense mode rather than off-line. (Section 4.2.7)
Corrects and clarifies Attachment C regarding cost offers and station manning:
Removes language stating that a resource can submit only five cost offers for energy. The actual limit is “in the 60s,” said Rus Ogborn of PJM.
Clarifies the compensation rules that apply when PJM requests generators be manned in order to start units more quickly. Units required to provide staffing will be compensated even if the resource is not called on because system conditions change.
Clarifies and cleans up revisions for Shortage Pricing rules. Changes were made to clarify existing rules and remove errors in the current text.
PJM contact: Rus Ogborn
Manual 14D: Generation Operational Requirements
Reason for changes: Conforming to other manuals; revised NERC standard; updated information and addition of wind unit dispatchability checklist.
Impact:
Multiple sections revised to replace outdated references.
Section 7.1.1, Generator Real-Power Control: Revised for consistency with M-36.
Section 7.1.3, Notification to PJM for Reactive Power Resource Status during Unit Start-up: revised to reflect changes in NERC Standard VAR-002-2b, R1, effective July 1.
Section 7.3, Critical Information and Reporting Requirements: Added references to PJM peak period maintenance season and changed notification time from 30 minutes to 20 minutes for consistency with section 7.4.
Section 7.4 Synchronization and Disconnection Procedures: Revised to include notification times for synchronizing and disconnecting generators from the system.
Section 8, Wind Farms Requirements: Revised to include references to Attachments L & M.
Attachment H, PJM Generation and Transmission Interconnection Planning Process Flow Diagram, revised for consistency with Manual M-14A/C.
Attachment M, Wind Unit Dispatchability Check List: New attachment.
PJM contact: Dave Schweizer
Manual 15: Cost Development
Reason for changes: Manual 15 was not revised to include information regarding cost-based offers when PJM made changes to the regulation market.
Impact: Information on cost-based offers is being moved into Manual 15 from Manual 11.
Section 2.8: Insert regulation cost offer component bucketing from M11 sub-section 3.2.1 and update regulation cost offer calculation example.
Exelon Corp. spent more than $400,000 lobbying the Maryland legislature between November 2012 and April 2013, making it the top spender in the state, according to recently-released data.
In all, utilities and other electric industry companies spent $1.25 million in lobbying over the six-month period. The companies spent $1.8 million in the year ending Oct. 31, 2012.
The companies’ lobbying reports do not specify what matters they were attempting to influence, with many citing only “energy matters.”
Maryland Lobbying by the Electric Industry – November 2012-April 2013 vs. November 2011-October 2012 (Source: Maryland State Ethics Commission)
But legislative sources told RTO Insider the utilities spent much of their efforts lobbying to modify a bill offering subsidies to offshore wind power and fighting several bills that would add new safety standards on gas pipelines. They also opposed legislation that would have made wood and plant biomass eligible for inclusion in Maryland’s Renewable Energy Portfolio Standard.
After failing in two prior years, a less ambitious version of the offshore wind bill was approved. One gas pipeline bill, concerning implementation of federal pipeline safety laws, also was enacted. The biomass initiative became a task force study — the Maryland legislature’s consolation prize for bills lacking enough support to become law.
The Federal Energy Regulatory Commission (FERC) approved the merger of Entergy Corp’s transmission system with ITC Holdings Corp. and its move into the Midcontinent Independent System Operator (MISO).
Entergy’s transmission assets in Louisiana, Mississippi, Arkansas and Texas will be transferred to ITC Holdings, which operates transmission in Michigan, Iowa, Illinois, Minnesota, Kansas and Oklahoma. FERC’s approval came in four orders issued June 20. In addition to ruling the merger is consistent with the public interest (EC12-145), the commission approved formula rates for the new ITC operating companies (ER12-2681) and agreements governing the move to MISO (ER-12-2682, ER12-2693).
Map of ITC-Entergy Transmission Territories (Source: ITC Holdings Corp.)
The deal will give Entergy’s shareholders ownership of about 50.1% of ITC’s common stock. Entergy will continue ownership of its generation and distribution assets.
Commissioners Cheryl LaFleur and John Norris dissented in part, saying they opposed allowing ITC to use a 60% equity/40% debt capital structure for five years, which they said will cause a rate increase for Entergy customers. The commission should have required ITC to use the Entergy Operating Companies’ capital structure, which has a lower level of equity, they said.
The merger awaits approvals by state regulators in the Entergy operating region.
MISO and its supporters say the decisions by FirstEnergy and Duke Energy Ohio to leave MISO for PJM are proof that deliverability issues across the RTOs’ borders are due to PJM’s modeling rather than any physical constraints. But others — including FirstEnergy and Duke — say they are incorrect.
When it was in MISO, Duke’s energy and capacity was not considered deliverable into the PJM markets, the Indiana Utility Regulatory Commission contends. After Duke joined PJM in January 2012, “and without the building of any additional transmission facilities, deliverability of electricity and capacity was no longer an issue,” the state said in a filing with FERC.
Load Also Moved
PJM says MISO and its supporters are ignoring the fact that PJM assumed dispatch of Duke and FirstEnergy’s generation, and that the companies’ loads also moved to PJM.
Map of Duke and FirstEnergy Move to PJM (Source: Midcontinent ISO)
Duke said its Ohio affiliate left MISO because it jointly owned transmission and generation with PJM utilities, and because PJM is designed to accommodate retail choice.
FirstEnergy’s Rationale
FirstEnergy said its 2011 move allowed the company to realign its operations into a single RTO. American Transmission Systems, Inc. (ATSI), FirstEnergy’s transmission affiliate, has 32 interconnections with PJM, but only three with MISO, the company said in a FERC filing in August.
“The ATSI integration into PJM resulted in an addition of load to the PJM footprint that exceeded the amount of FirstEnergy generation capacity that was integrated, and therefore, regardless of the move to PJM, there was no increase in capacity sales, net of FirstEnergy load,” FirstEnergy said.
“Moreover, following the move to PJM, PJM obtained scheduling, dispatch and operational control over FirstEnergy’s transmission facilities and included FirstEnergy’s generation and load in its planning models. PJM could not have had such scheduling, dispatch and operational control over FirstEnergy’s facilities when FirstEnergy was in MISO.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee and Members Committee meetings 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 PJM Insider.
PJM Insider will be in Wilmington covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:25)
A. MRC will be asked to endorse changes to Manual 11 affecting regulation rules, hydropower generators, station manning and shortage pricing. The changes provide clarifications, correct errors and conform to other manuals.
B. MRC will be asked to approve changes to Manual 14D: Generation Operational Requirements. The changes conform to other manuals and reflect a revised NERC standard, updated information and addition of the Wind Unit Dispatchability Check List.
Members will be asked to select between two proposed changes to the modeling of Financial Transmission Rights. The two proposals from the Financial Transmission Rights Task Force (FTRTF) received near-unanimous support from the Market Implementation Committee in May. A third option failed with less than 40% support and a vote on a fourth option was postponed.
Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”
The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
4. SUSPENSION OF Day-Ahead Market for Loss of Internet (9:45-9:55)
PJM seeks stakeholder approval for contingency plans to respond to an Internet outage that forces the RTO to suspend the day-ahead market. PJM has no procedures for dealing with an Internet outage that could prevent the RTO from receiving participant data needed to solve the day-ahead market.
Under the proposed tariff changes, all market settlements would be done in real time.
5. Regional Planning Process Task Force (RPPTF) (9:55-10:15)
MRC will vote on a recommended change to the cost allocation of Market Efficiency projects. The proposal, developed by the Regional Planning Process Task Force, would calculate benefits on a 50/50 ratio based on its impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). The proposal received overwhelming support from respondents surveyed by the task force. Only 29% of respondents favored continuing the current method, under which 70% of benefits are calculated based on production or capacity cost savings.
6. Demand Response Problem Statement (10:15-10:30)
PJM will ask approval of a problem statement to consider how to treat demand response as operational capacity resources. PJM expects to deploy DR in system operations with increasing frequency due to DR’s increasing share of capacity and generation plant retirements. Use of DR under current rules creates potential operational problems. Potential results from the inquiry include:
Changes to DR obligations to move from administrative procedures to economic dispatch.
Base notification time requirements on physical response capability, similar to current requirements for generators.
Allow DR to operate with a dispatchable range similar to generation resources.
Caps on the amount of Limited DR that can be cleared above the quantity specified in reliability analyses.
7. Gas Electric Senior Task Force (GESTF) (10:30-10:45)
MRC will be asked to approve the charter for a task force it created in March to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation.
The proposed charter calls on the Gas Electric Senior Task Force (GESTF) to provide education, prioritize issues and draft problem statements and solutions for each issue.
The task force is expected to work last through the 2016/2017 delivery year, during which PJM expects significant additions of new gas-fired generating capacity to replace coal retirements. All PJM stakeholders may appoint representatives to the task force.
Sean McNamara will be the chairperson and Rami Dirani the secretary.
The committee will be asked to approve corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the tariff in 2008 and 2009.
One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges. The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”
9. Transparency of TO Calculations (10:55-11:10)
Robert Weishaar, an attorney who represents industrial energy users, will ask MRC to approve a problem statement that could result in requirements that transmission owners make tariff filings disclosing their calculation of total hourly energy obligations, peak load contributions, and network service peak loads. The calculations are used to allocate energy, capacity, and transmission cost responsibility among load serving entities.
Weishaar said two-thirds of PJM’s transmission owners have failed to file tariffs disclosing the methodology they use to make their calculations, in violation of Federal Energy Regulatory Commission rules.
A representative of the Electricity Storage Association will ask MRC to approve a problem statement that would develop rules for including advanced energy storage technologies in its ancillary services and capacity markets.
Although pumped hydro participates in PJM markets, the RTO has no rules for advanced technologies such as batteries, flywheels, thermal storage and compressed air, a representative of the Electric Storage Association told MRC members.
PJM will ask MRC to approve a problem statement that would seek to draft tariff language explicitly listing rules for wind resources to receive Lost Opportunity Cost credits.
Although the requirements are described in PJM Manuals, the Federal Energy Regulatory Commission said in a May 29 order that the requirements should be approved by the commission and listed in the PJM Tariff. “PJM has not shown that it is just and reasonable for PJM to have the discretion to reset compensation levels retroactively when neither the particular circumstances that would trigger PJM’s actions nor the financial consequences are specified in the tariff,” the commission wrote.
Members Committee
2. CONSENT AGENDA (1:20-1:25)
The committee will be asked to approve revisions to Manual 15: Cost Development regarding cost-based offers in the regulation market. Information on cost-based offers is being moved into Manual 15 from Manual 11.
3. PMU DEPLOYMENT (1:25-1:40)
PJM will seek endorsement of Tariff revisions approved last month by MRC requiring new generators to pay for the installation and maintenance of phasor measurement units (PMUs). PJM will pay for the communication link with the PMUs, which provide data that helps PJM in real-time operations and system planning. The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger.
4. DEMAND RESPONSE (DR) PLAN ENHANCEMENTS (1:40-2:00)
The committee will be asked to endorse PJM’s proposed filing in response to FERC’s April order requiring the RTO to seek commission approval for new rules imposed last year on demand response providers. FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.
The new rules will require Curtailment Service Providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.
