MRC / MC Approvals

The following issues were approved by the Markets and Reliability and Members committees Thursday with little discussion. Each item is listed by agenda number, followed by a summary of the issue and links to prior coverage in RTO Insider.

Markets and Reliability Committee

2. PJM MANUALS

Members endorsed manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.

3. COORDINATED TRANSACTION SCHEDULING

Members approved a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.

The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.

The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.

See New NYISO Product OKd

4. SYNCHRONIZED RESERVE (SR) PERFORMANCE

MRC approved increased penalties for under-performing Tier 2 synchronized reserve providers.

The committee approved a proposal introduced by Dave Pratzon, of GT Power Group, (Package B) after the Operating Committee selected it over a proposal from PJM and the Market Monitor (Package A).

Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.

The proposal was approved 3.6 to 1.4.

See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote

5. CAPACITY CREDIT CALCULATION FOR WIND RESOURCES

Members approved new rules to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.

Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.

The MRC selected Alternative 2 under which state estimator data would be used to interpolate output for each five-minute period with curtailments.

See MRC Considers Changes to Wind Capacity Calculations

6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS

Members approved two proposals to streamline the demand response registration process.

Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.

The MRC approved the following changes:

Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.

The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.

See Simplified Demand Response Registration OKd

7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER

Members approved the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.

PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.

See PJM Proposes Operating Reserve Changes to Cut Uplift

Members Committee

3. CETL STABILITY– EASILY RESOLVED CONSTRAINTS

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal approved by the MC.

The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.

Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.

See Quick-Fix Transmission Upgrades OKd

4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS

PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes endorsed by the MC.

The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.

See: MRC Actions

October 1, 2013

Bid to Relax Switching Rules Falls Short

A proposal to allow intra-year switching to nodal pricing failed at the Members Committee Thursday, falling just short of the two-thirds vote needed for approval.

The proposal by retail marketer Direct Energy, which would have allowed a limited number of such switches monthly, was opposed by members who said it would create administrative problems for electric distribution companies (EDCs) and potential losses for Financial Transmission Rights holders. The sector-weighted vote was 3.3 in favor and 1.7 against, short of the 3.34 total needed for passage.

It was the second loss for Direct Energy, which failed to win more than 35% support for its bid at the Market Implementation Committee (MIC) in August. (See TOs Flex Muscles, Reject Retailer’s Nodal Pricing Bid)

David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load.

The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.

The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.

Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing.

The current rules mean it can take a customer up to 17 months to make the switch after deciding to do so — “major barrier” to adoption, Scarpignato said.

Scarpignato said the change would also help reduce congestion costs across PJM and assist PJM operations, which has said it would like more “granular” dispatch of demand response resources. Under the current zonal dispatch, Scarpignato said, “some of the DR in that zone is actually hurting” PJM’s attempts to relieve constraints.

Scarpignato’s argument won support from representatives for Old Dominion Electric Cooperative and Dominion, as well as from Howard Haas of Monitoring Analytics, PJM’s independent Market Monitor. “Nodal pricing is the way to go,” Haas said. “Unequivocally it is the way to go.”

Representatives from Exelon Corp. and Pepco Holdings spoke in opposition.

Jason Barker, of Exelon, said his company saw little “utility” to allowing intra-year switching and significant financial risk to the remaining zonal customers, who could see their costs increase.

“As the operator of three EDCs we do see substantial downside,” he said. “We’re disappointed that it’s come before the Members Committee after being roundly defeated at the MIC.”

Gloria Godson, of Pepco, said the change would be a “significant burden” on EDCs. “We will have to add additional staff to manage this.”

Scarpignato said the intra-year switches would have minimal financial impact on FTR holders and others in the zone. He said new customers connect to the grid year-round without major impacts.

In answer to a question from Godson, PJM’s Tom Zadlo said the change could impact FTRS. “It is potentially possible that there are some impacts on FTRs but it’s impossible to quantify.” The impact would depend on the size of the loads that switched, he said.

Marji Philips, representing Hess Corp., said economists’ preference for nodal pricing is similar to their support for energy–only markets in lieu of a capacity market. “It’s good in theory. As a practical reality it stinks.”

Philips said that PJM’s hedging tools are based on zones and hubs. If many customers switch to nodal pricing in mid-year, she said, it could create “ghettos” where customers will have to pay more of a risk premium because suppliers can’t hedge their loads.

Fourteen of 16 public power members voting supported the change along with three-quarters of 20 other suppliers and all eight end use customers. Transmission companies voted 7-2 against while generation owners split 5-5.

Scarpignato said after the meeting that his company was not giving up. “It was an extremely close vote,” he said. “We’re considering our options.”

October 1, 2013

Company Briefs

The volume of data generated by the smart grid threatens to drown utilities, who have yet to figure out what to do with the information or how to store it, according to industry experts. “It’s generating terabytes of data,” said a representative of the Electric Power Research Institute at a panel discussion at the Illinois Institute of Technology.

More: Forbes

PPL to Sell Montana Hydro Plants

NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.

More: Missoulian

FirstEnergy Slates Major Work at PA, OH Nuclear Plants

FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.

More: Pittsburgh Post-Gazette

Barbas Joins Pepco Board

Pepco Holdings Inc. named former Dayton Power and Light Co. CEO Paul M. Barbas to its board of directors. Barbas is also a former chief operating officer of Chesapeake Utilities Corp. and executive vice president of Allegheny Power.

More: Pepco Holdings Inc.

October 1, 2013

PJM to Consider Storage as Capacity

Members agreed Thursday to consider new rules to allow batteries, flywheels and other advanced storage technologies to bid in the capacity market.

The Market and Reliability Committee approved a problem statement and issue charge with only two no votes despite some wariness from some members.

The proposal was sponsored by Demansys Energy LLC, which aggregates commercial and industrial customers for participation in the regulation market.

Janette Kessler Dudley, vice president of business development and regulatory affairs, noted that PJM currently has no rules allowing batteries or other advanced storage resources to participate in the Reliability Pricing Model. “What my company is interested in is parity,” she said.

Steve Lieberman, of Old Dominion Electric Cooperative, said he was not convinced storage is compatible with other capacity resources.

He said the issue should receive a lower priority than those currently before the Capacity Senior Task Force. “We should proceed carefully as far as expectations go,” he said.

Members ultimately decided the move the issue from the CSTF to the Planning Committee.

Gloria Godson, of Pepco, said she supported the inquiry but that PJM shouldn’t approve new rules until it fully understands the technologies. She noted the amount of “retooling” the RTO has done to address problems with the integration of demand response.

Raghu Sudhakara, of Rockland Electric Co., noted that NYISO already allows four hour resources to participate in its capacity market. “There’s no reason PJM, being as sophisticated as it is, can’t accommodate new technologies,” he said.

PJM currently has about 56 MW of non-pump storage.

See Energy Storage: Ready for its Close-Up?

October 1, 2013

Current Capacity Imports OK: Study

PJM should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17, officials told a special meeting of the Planning Committee Friday.

Officials said that their initial review found PJM can import 11,000 to 12,000 MW. “We may have gotten close to what our limit would be, but we haven’t gotten to it yet,” said Stu Bresler, PJM vice president of market operations.

Officials cautioned that their results were preliminary and subject to change with further analysis.

Friday’s meeting was prompted by a problem statement approved by the Planning Committee Sept. 12.

The committee will seek to adopt a methodology for determining an RTO import limit that can be applied in the PJM planning process as well as included in next year’s Base Residual Auction. “It would function much like a CETL (Capacity Emergency Transfer Limit) for the entire RTO,” Bresler told the Markets and Reliability Committee in a brief discussion Thursday.

In addition to ensuring space for capacity, PJM must account for long term transmission contracts and 3,500 MW for the RTO’s Capacity Benefit Margin, which is reserved for importing capacity from external areas in emergencies.

Officials said their initial review identified a 500/230 kV transformer in the Duke Energy Carolinas zone as the limiting facility.

Bresler said PJM likely will propose a combination of path-specific limits with an overall RTO import cap. “The sum of the path-by-path limits could exceed what an overall limit would be,” he said.

Officials were unable to say Friday how much of the RTO’s total import capacity is to PJM’s west, the source of most of the imports that cleared in the May auction.

October 1, 2013

Bowring: UTCs Boost FTR Shortfalls

Market Monitor Joseph Bowring last week released an analysis that he said proves his contention that up-to congestion (UTC) transactions are increasing shortfalls in Financial Transmission Rights funding.

Day-Ahead Congestion & Binding Constraints (Source: Monitoring Analytics LLC)

“There’s no reason to believe up-to congestion transactions help price convergence,” Bowring said in presenting his monthly report to the Members Committee webinar. “But they do increase day-ahead congestion.”

The monitor’s analysis was based on a simulation of market results with and without UTC bids for a five-day sample in May.

The analysis found that UTCs affect unit commitment and dispatch in the day-ahead market, increasing the number of binding constraints and negative balancing congestion.

For the five days examined, the FTR funding deficit was $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.

In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.

The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.

The average cleared volume of UTC trades increased 73% between 2011 and 2012.

September 24, 2013

Frequency Regulation: The `Wedge’ for Energy Storage

A 2010 white paper by the Electric Power Research Institute (EPRI) identified 10 applications for energy storage across the entire electricity supply chain, including end-users. Below are some of the most promising:

Frequency Response: While large scale use is a long term ambition for storage, “frequency response is the wedge into actual utility application in the field,” says Imre Gyuk, manager of the Department of Energy’s energy storage research program. Storage can provide much quicker performance than fossil fuel plants, which can take five minutes to respond. “In these five minutes the need may already be in the opposite direction,” Gyuk noted. Beacon Power, for example, says its flywheels can respond nearly instantaneously to operator control signals — up to 100 times faster than traditional generators. Beacon cited a recent study for the California Energy Commission which found that a 30-50 MW fast-response storage device could provide as much or more regulation capability as a 100 MW combustion turbine.
Back-up Power: Researchers see large end users purchasing storage for backup power during grid interruptions. EPRI reports that diesel generators have a failure rate of more than 20%. A White House report released in August recommended that energy storage systems be a top priority for new investments to modernize the grid and improve reliability.
Support for Intermittent Resources: Wind power produces only 10% of nameplate capacity in peak hours. “That alone is practically a mandate for storage,” said Gyuk. A 2010 study estimated a need of 0.8 to 1.5 MW of intra-hour balancing for every 10 MW of wind.
Delaying Transmission and Distribution Upgrades: Storage can provide alternatives to grid upgrades in locations with slow load growth and infrequent maximum load days. These benefits could range from $150,000 – $1,000,000/MW-year, according to EPRI.

September 24, 2013January 15, 2025

Energy Storage: Ready for its Close-Up?

AES Laurel Mountain (Source: DOE)

On Laurel Mountain, W.V., AES Corp. installed 32 MW of battery storage to support its 98 MW wind farm. The project provides PJM with regulation service and allows AES to smooth minute-to-minute fluctuations in output from its turbines.

In Hazle Township, Pa., Beacon Power is installing 200 flywheels that will provide PJM 20 MW of frequency response. The company put 4 MW into commercial operation on September 11 and expects the full 20 MW plant operational next year.

In Lyon Station, Pa., batteries housed in what look like large storage sheds are providing 3 MW of frequency regulation to PJM and peak demand management services to Met-Ed.

These are the vanguard of energy storage applications that will change both the economics and operations of the grid — providing quicker, more accurate frequency regulation, aiding in the integration of variable resources, eliminating the need for some grid upgrades, and providing alternatives to natural gas-fired peakers.

PJM members will be asked Thursday to approve an initiative to draft market rules to allow batteries, flywheels and other advanced energy storage devices to participate in the RTO’s capacity market.

This raises the question: Is advanced storage ready to move beyond pilot projects and into day-today operations?

Pumped hydro, a decades-old technology, currently provides virtually all of the grid’s storage capability, with more than 127,000 MW installed worldwide. Compressed air energy storage installations are second, followed by sodium-sulfur batteries. Other technologies total less than 85 MW combined.

Beacon Power Flywheels in Hazleton, PA as of 9/2013 (Source: Beacon Power)

Beacon Power flywheels in Hazleton, Pa. (Source: Beacon Power)

Experts say some of the most promising storage applications, such as hydrogen-powered fuel cells that could provide bulk storage, are a decade or more from commercial deployment. But some more mature technologies could take significant roles in the next several years.

“The future is already here — at least the beginning of the future,” said Imre Gyuk, manager of the Department of Energy’s energy storage research program, at a briefing earlier this month in Washington.

Costs

For storage to reach its potential, its costs must come down at the same time that its capability improves.

Storage can provide benefits in regulation, voltage support and power quality and reliability as well as deferring transmission and distribution upgrades and reducing the need for peaking generators. But “even with all those benefits, it’s difficult to make it add up” to exceed costs, Haresh Kamath, energy storage program manager for the Electric Power Research Institute (EPRI), told the briefing.

Most energy storage technologies have higher capital costs than natural gas-fired peakers. Flywheel capital costs are similar to a combined-cycle plants. Sodium sulfur (NaS) batteries, the most economical battery for utility-scale applications, have been estimated at 1.8 to 3.5 times the cost of a combined cycle plant.

The two crucial of measures of storage capability are cycle life (the number of complete charge-discharge cycles before becoming unusable) and round-trip efficiency (the system’s energy output relative to input). Improving these measures will boost storage in comparisons against generation.

(Source: California PUC)

Market Rules

In addition to the cost and technology challenges, market rules are also an obstacle to widespread deployment.

Storage can provide several benefits simultaneously to the wholesale system, electric distribution companies, and end-use customers. “These characteristics, plus the difficulty in monetizing multiple stakeholder benefits, often act as barriers to the widespread deployment of energy storage systems, whose multi-functional characteristics also complicate rules for ownership and operation among various stakeholders,” EPRI said in a 2010 white paper. It concluded policy changes would be needed “to realize the true potential of storage assets.”

Rule Changes Could Quadruple Revenues

Researchers at Energy and Environmental Economics reported in a 2009 paper that storage revenues could be increased by as much as four-fold by reducing minimum size requirements for market participation and permitting bi-directional bidding for regulation.

The study looked at potential revenues for a theoretical storage resource located in Allentown, Pa., based on 2007 market clearing prices ($41/MW-day for capacity, $14/MWh for regulation and $34/MWh for energy). It found a system with 1 MW of charge and 2 MWh of energy storage would generate revenues of more than $250,000, most of it from regulation, with additional revenue from capacity and energy arbitrage — storing energy overnight when prices are low and selling during peak hours.

As of the time of the study, PJM capacity rules required a minimum of 12 hours of capacity and a minimum resource size of 0.1 MW.

One key to increasing revenues, the analysis found, was permitting asymmetric bidding in the regulation market — allowing the battery to earn regulation revenue when charging and discharging — in recognition that regulation dispatches over an hour can be energy neutral.

Changing market rules to permit asymmetric bidding and to allow energy storage to offer one hour of regulation with less than one hour of energy storage would increase the net present value of energy storage in PJM from about $1,000 per kWh of energy storage to nearly $3,500.

FERC Order, Stimulus Funding

Storage received a boost from the Federal Energy Regulatory Commission in July with Order 755, which requires PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. (See FERC Rule Boosts Storage, Renewables.)

Storage also was a prime beneficiary of federal stimulus money under the 2009 American Recovery and Reinvestment Act (ARRA). About $185 million in ARRA funds leveraged $585 million from industry for 16 energy storage projects, not including eight smart grid projects with storage. The goal of the federal spending is to demonstrate the technologies’ technical feasibility, document costs, stimulate regulatory changes and generate follow-on projects. Four of the 16 projects have been completed to date.

Proposed Legislation

To provide additional incentives, Sen. Ron Wyden (D-OR), chairman of Senate Energy and Natural Resources Committee, and Sen. Susan Collins (R-ME) reintroduced legislation in May to create an investment tax credit for energy storage.

California Storage Mandate

With or without federal incentives, a lot more storage will be added over the next few years. On Sept. 3, the California Public Utilities Commission issued a proposed order requiring the California grid to obtain 1.3 GW of storage by 2020, a target that will require utilities to increase their storage by 30% annually.

The order was prompted by Assembly Bill 2514, which barred pump storage projects larger than 50 MW from eligibility in order to enable a “market transformation” for new technologies.

The order would prohibit utilities from owning more than 50% of the storage resources to be procured across the three “grid domains” of transmission, distribution, and customer-located storage.

To address utilities’ concerns that the 2020 goal is too ambitious, it would allow utilities to defer up to 80% of their targets if they can show they can’t procure enough “viable projects to meet the targets.”

EPRI’s Kamath said California’s mandate could do for storage what Germany’s world-leading commitment to solar power did to reduce solar’s “soft” costs, including permitting, inspection, interconnection, financing and customer acquisition.

“It’s going to have effects all across the industry,” said Klamath.

_______________________________

Resources for Additional Research:

DOE/EPRI 2013 Electricity Storage Handbook
DOE International Energy Storage Database
Electricity Storage Technology Options (EPRI, December 2010)
Impact of Market Rules on Energy Storage Economics (United States Association for Energy Economics)
Market and Policy Barriers to Deployment of Energy Storage (Ohio State University)

September 24, 2013

Binz Nomination in Doubt with Manchin Defection

Ron Binz’ nomination to the FERC chairmanship was hanging by a thread late last week after coal-state lawmakers took the former Colorado regulator to task at his confirmation hearing and Sen. Joe Manchin (D., W.V.) announced he would oppose the nominee.

Binz will need the backing of one Republican and all of the remaining 11 Democrats to win the recommendation of the 22-member Senate Energy and Natural Resources Committee. That will be tough for Democrats to pull off.

Ranking member Lisa Murkowski (R-Alaska) has already stated her opposition and no Republicans spoke in favor of Binz at his confirmation hearing Tuesday. Also in doubt is Sen. Mary Landrieu (D., La.), who has not indicated she will support the nominee.

`War on Coal’ Target

If Binz’ nomination fails, it will be because he became the target for those angry over the Obama administration’s so-called “war on coal.”

Binz would have limited influence over coal’s life or death as FERC chairman: Although FERC policies ensuring transmission access for renewables impacts coal indirectly, the agency has no role in the setting of climate or pollution policy.

But the timing of his confirmation hearing was inauspicious. The War-on-Coal blowback reached a crescendo last week as the EPA issued its long-awaited greenhouse gas limits on new power plants.

Manchin complained at Tuesday’s hearing that Obama’s environmental policies were beating the “living crap” out of his state. On Wednesday, he announced his opposition to Binz, criticizing him for prioritizing “renewables over reliability.

“His approach of demonizing coal and gas has increased electricity costs for consumers,” Manchin said.

Colorado PUC

Binz served as chairman of the Colorado Public Utilities Commission from 2007 through 2011, during which he drew praise from renewable energy advocates and opposition from the coal industry.

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. The bill, which was opposed by the coal industry, 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. See: Who is Ron Binz, And What Will He Do at FERC?

Binz told last week’s hearing he would be “source neutral” and emphasize reliability as FERC chair. He noted that coal provides 40% of Colorado’s electricity, more than any other source. He also acknowledged he had spoken “inartfully” at a forum when he called natural gas a “dead end” fuel.

Norris Allegation

Adding to Binz’ woes last week were comments from FERC Commissioner John Norris, who reported that Senate Majority Leader Harry Reid persuaded President Obama to reject him as FERC chairman because he was too “pro-coal.”

Norris, a Democrat, told TransmissionHub that Reid’s chief of staff cited a vote he made as a member of the Iowa Utilities Board. Reid’s office denied Norris’ account.

Senate Minority Leader Mitch McConnell (R-Ky.) said Thursday that he would actively work against the nomination of what he called the Senate Majority Leader’s “foot soldier in his and this Administration’s War on Coal.”

September 24, 2013

Company Briefs

Duke Energy Corp. is the latest company to end a long-standing practice of insuring its retirees, a cost-saving approach already embraced by IBM, Time Warner, Caterpillar, General Electric and DuPont.

About 14,500 retirees of were informed that the company will no longer provide insurance to supplement Medicare coverage. Instead, Duke will pay retirees an annual stipend toward the cost of insurance.

More: The News-Observer

Most U.S. Firms Ignore Climate Risk Disclosures

Almost 75% of the nation’s publicly traded companies are ignoring a three-year-old Securities and Exchange Commission requirement that they inform investors of the risks that climate change may pose to their bottom lines.

The data, culled from the annual reports of 3,895 U.S. public companies listed on major stock exchanges, found that only 27% mentioned “climate change” or “global warming” in their most recent filing. Nearly all of the 179 energy companies reviewed mentioned climate change.

More: Inside Climate News

Solar panels line the roof top of Walmart 3784 in Franklin, Ohio. (Source: Wal-Mart)

Companies Unplug from Grid, Jolting Utilities

The number of electric generation units at commercial and industrial sites has more than quadrupled since 2006, leading utilities such as AEP to consider getting into the on-site power business.

On-site generation still accounts for less than 5% of U.S. electricity production. But it is gaining momentum because of falling prices for solar panels and natural gas, as well as a fear that power outages caused by major storms will become more common. Wal-Mart, which produces about 4% of the electricity it uses, plans to boost that to 20% by 2020 and expects to be paying as little for solar power as utility power in less than three years.

More: The Wall Street Journal

Lobbying Wins Boosts Exelon CEO’s Pay

Exelon Corp. boosted the stock awards for CEO Christopher Crane to $4.2 million in 2012, 25% above his target, thanks to his work lobbying state and federal officials. The company’s board of directors credited Crane for winning approval of the Constellation merger and for influencing new Environmental Protection Agency regulations and deregulation measures in Ohio.

More: Crain’s Chicago Business

FirstEnergy Elects Ex-NRC Official to Board

FirstEnergy Corp. announced the election Luis A. Reyes, former administrator of the Nuclear Regulatory Commission’s Atlanta-based Region II, to its board of directors. His term will run until the company’s 2014 annual meeting. Reyes will serve on the board’s Corporate Governance and Nuclear Committees.

More: FirstEnergy Corp.