Page 1579 – RTO Insider

February 14, 2015

Exelon-Pepco Deal Moves Forward in NJ, Del.

By Ted Caddell and Michael Brooks

Exelon’s $6.8 billion bid to acquire Pepco Holdings Inc. took two steps forward last week when it gained approvals from both the New Jersey Board of Public Utilities and the staff of the Delaware Public Service Commission.

The New Jersey BPU gave final approval Wednesday to a settlement that will give Atlantic City Electric customers $62 million in rate credits.

The BPU’s approval means that the acquisition now needs only the regulatory approval of Delaware, Maryland and D.C. The Delaware PSC must vote on the staff settlement agreement, which was announced Friday.

Among other incentives in the agreement is a stipulation that guarantees New Jersey customers benefits equal to those eventually approved by Delaware, Maryland or D.C.

Pepco Holdings is headquartered in D.C., and includes Atlantic City Electric, Pepco, which serves D.C., and Delmarva Power & Light, with customers in Delaware and Maryland.

The $62 million in rate credits comes out to about $114 for each of Atlantic City Electric’s 544,000 customers.

Wednesday’s agreement contains other incentives, including:

An energy-efficiency program that would provide $15 million in energy savings over five years;
Reliability commitments exceeding BPU requirements;
Promises to hire 60 union workers, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s current $709,000 annual giving for 10 years.

“This merger represents a great compromise that will provide many benefits to New Jersey,” BPU President Richard S. Mroz said in a written statement. “Additionally, the settlement protects the jobs of nearly a thousand New Jersey residents and keeps the company’s local operational headquarters in Mays Landing.”

Exelon CEO Christopher Crane and Pepco CEO Joseph Rigby also issued statements praising the agreement.

One party that didn’t sign the agreement was New Jersey’s consumer advocate, Stefanie Brand, director of the Division of Rate Counsel. Brand said the agreement, which was approved by the BPU staff last month, fails to protect consumers.

“There is nothing in the agreement that keeps Exelon from coming in and asking for a rate increase later that wipes out” the customer credits, she said in an interview Wednesday. “We certainly made our concerns known” during hearings and negotiations, she said.

Brand said Exelon more than doubled its initial rate credits offer during the negotiations that led to the settlement. “We do think [the BPU] got some good concessions, and I’m hopeful that Exelon won’t do things to wipe them out,” she said. “We were looking to lock it down a little bit more.”

More Approvals Needed

While Exelon has the approvals needed from the Federal Energy Regulatory Commission, Virginia and now New Jersey, it still needs those of Maryland, D.C. and Delaware.

“We are working cooperatively and productively with the public service commissions and other stakeholders in Delaware, the District of Columbia and Maryland to demonstrate how the merger will benefit the PHI utilities’ customers and communities,” Exelon Spokesman Paul Elsberg said Wednesday night. “We continue to expect the merger to close in second or third quarter of this year.”

Maryland

Maryland finished evidentiary hearings yesterday. Those hearings were supposed to conclude last week, but it took so long to go through every witness that two more hearings were added. Because of that, the decision of the Public Service Commission has been pushed back a week, from April 1 to April 8.

The state’s consumer advocate, the Office of People’s Counsel, has urged the PSC to turn down the deal as it stands, calling the benefits Exelon is offering “either non-existent or woefully deficient.”

Exelon has offered $40 million in customer credits in Maryland. The PSC staff has recommended $167 million in credits.

District of Columbia

Exelon and Pepco are also facing headwinds in D.C., where People’s Counsel Sandra Mattavous-Frye has called on the Public Service Commission to reject the merger.

Exelon has promised $14 million in incentives for D.C. Evidentiary hearings were to begin this week, but Mattavous-Frye asked the commission for more time to review additional information filed by Exelon and Pepco. A revised schedule for the hearings was released Wednesday night, which has evidentiary hearings pushed back to the end of March.

Delaware

Delaware has three days of hearings scheduled to start Feb. 18, but they may not be needed.

Late Friday afternoon, Exelon issued a statement that said it reached a settlement with the PSC staff, the Delaware Public Advocate, the Department of Natural Resources and Environmental Control and several trade groups.

The agreement calls for:

$49 million in rate credits for Delmarva electric and gas customers over 10 years;
$2 million in energy-efficiency program funding;
Reliability improvement commitments;
Hiring of at least 83 union employees;
Maintaining a headquarters in Newark and company facilities in Wilmington and Millsboro; and
Charitable contributions exceeding Delmarva’s 2013 level of $699,000 for 10 years after the merger.

Earlier in the week, Public Advocate David Bonar said Exelon initially offered $17 million in customer credits for Delmarva Power’s Delaware customers. “Obviously, we felt that was substantially low,” he said.

So did a consultant hired by the Public Service Commission, who said $62.9 million, or about $100 per customer, would be a more appropriate figure.

February 13, 2015June 15, 2023

ISO-NE Chooses $740M Land-Based Tx Project for Boston Area

By William Opalka

ISO-NE announced Thursday it had chosen a land-based, alternating current transmission project to address reliability concerns in the Boston area that came in about $260 million less than a competing undersea cable proposal.

The Greater Boston and Southern New Hampshire Reliability Project, proposed by Eversource (formerly Northeast Utilities) and National Grid, has a price tag of $739.7 million and is expected to be completed in 2018.

The all-AC project was chosen over a proposal from New Hampshire Transmission, which included both AC and underwater high voltage, direct current transmission.

ISO-NE said the AC plan was selected because it is significantly less expensive and it promised superior operating performance.

“Greater Boston is the largest area of consumer demand on New England’s power system, and its transmission system is in critical need of an upgrade,” said Stephen Rourke, vice president of system planning.

The project is past due, ISO-NE said in a statement. “The year of need for certain components of the Greater Boston Reliability Project was pre-2013. The ISO is analyzing whether additional special operating plans need to be developed to be able to manage the system in Greater Boston during peak load conditions” before the project is complete, it said.

The land-based AC plan is a 25-mile series of overhead lines in existing rights-of-way, connecting a substation in New Hampshire with one in Massachusetts, along with two eight-mile underground sections.

SeaLink Falls Short

The competing project outside Boston, dubbed SeaLink, was proposed by NHT, a subsidiary of NextEra Energy, owner of the Seabrook nuclear station in southern New Hampshire. It would have run 50 miles of undersea HVDC cable from the Seabrook substation to a substation in Massachusetts, with another 18-mile section buried on land.

The two project sponsors engaged in a vigorous debate about their opponents’ estimates and the costs to be incurred by ratepayers. The AC partners pointed to the initial high cost of SeaLink, its expensive technologies and the risks associated with undersea cables.

NHT contended SeaLink would be cheaper, saying the AC project would affect service, forcing utilities to buy more expensive replacement power during its construction. NHT upped the ante by offering to swallow any overruns above a cost cap of $679 million.

Both plans include the reconductoring of several 115-kV lines and other substation and transmission equipment upgrades, estimated to cost $221 million.

Concerns Identified in 2009

ISO-NE said the Boston area’s reliability concerns were identified in 2009. Several upgrades, including line reconductorings, were advanced to ensure reliability could be maintained after the retirement of all four Salem Harbor generating units — two in 2011 and two in 2014, according to the RTO.

In 2013, ISO-NE updated its original needs assessment to reflect several major system changes, including resource additions and retirements, changes in underground cable ratings in Boston, and updated load forecasts.

ISO-NE planning engineers worked with NHT to help develop its plan from a conceptual proposal into a workable solution. The RTO also worked with Eversource and National Grid to update components of the AC project based on the findings of the 2013 needs assessment. Updated versions of both plans were presented to the ISO-NE Planning Advisory Committee in June 2014.

The project will be discussed at Wednesday’s PAC meeting.

Eversource ups Tx Spending

In an earnings call with analysts last Thursday, Eversource identified the Boston area as one of its key areas for investment. It announced that it will spend $3.9 billion on transmission upgrades and expansions from 2015 to 2018, a $900 million increase over the $3 billion proposed a year ago.

It identified several big-ticket items in the area, including its share of the AC plan, totaling at least $707 million. There are also “hundreds” of reliability projects throughout New England coming in at $968 million.

February 12, 2015

N.J. BPU Approves Exelon’s Acquisition of Pepco

By Ted Caddell and Michael Brooks

Exelon’s $6.8 billion bid to acquire Pepco Holdings Inc. took another step forward Wednesday when the New Jersey Board of Public Utilities approved a settlement that will give Atlantic City Electric customers $62 million in rate credits.

The board’s approval means that the acquisition now needs only the regulatory approval of Delaware, Maryland and D.C.

Among other incentives in the agreement is a stipulation that guarantees New Jersey customers benefits equal to those eventually approved by Delaware, Maryland or D.C.

Pepco Holdings is headquartered in D.C., and includes Atlantic City Electric, Pepco, which serves D.C., and Delmarva Power & Light, with customers in Delaware and Maryland.

The $62 million in rate credits comes out to about $114 for each of Atlantic City Electric’s 544,000 customers.

Wednesday’s agreement contains other incentives, including:

An energy-efficiency program that would provide $15 million in energy savings over five years;
Reliability commitments exceeding BPU requirements;
Promises to hire 60 union workers, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s current $709,000 annual giving for 10 years.

Exelon CEO Christopher Crane and Pepco CEO Joseph Rigby also issued statements praising the agreement.

More Approvals Needed

While Exelon has the approvals needed from the Federal Energy Regulatory Commission, Virginia and now New Jersey, it still needs those of Maryland, D.C. and Delaware.

Maryland

Exelon has offered $40 million in customer credits in Maryland. The PSC staff has recommended $167 million in credits.

District of Columbia

Exelon and Pepco are also facing headwinds in D.C., where People’s Counsel Sandra Mattavous-Frye has called on the Public Service Commission to reject the merger. Exelon has promised $14 million in incentives for D.C.

Evidentiary hearings were scheduled to begin this week, but Mattavous-Frye asked the commission for more time to review additional information filed last week by Exelon and Pepco. According to a revised procedural schedule released Wednesday night, evidentiary hearings have been pushed back to the end of March. D.C.

Public Service Commission spokeswoman Kellie Didigu said that commission policy is to issue a decision within 90 days from the date the record closes. Under the revised schedule, the record will close May 13, pushing a decision to as late as August.

Delaware

Delaware has three days of hearings scheduled to start Feb. 18, but Public Advocate David Bonar thinks they may not all be needed. “We’re still working very hard to try to reach a settlement agreement,” he said in an interview Wednesday, “and we’re fairly confident that we can achieve that goal.”

He said Exelon initially offered $17 million in customer credits for Delmarva Power’s Delaware customers. “Obviously, we felt that was substantially low,” he said.

So did a consultant hired by the Public Service Commission, who said $62.9 million, or about $100 per customer, would be a more appropriate figure.

Since then, Exelon has sweetened the pot, according to Bonar. While he wouldn’t give hard figures, he said “it has grown substantially.”

He said he feels the sides are close to a settlement. “We are pretty well done meeting face to face,” he said.

The original version of this story incorrectly stated that two more “public sessions” were added to Maryland PSC evidentiary hearings due to the amount of people who wanted to testify. The sentence has been corrected to reflect that two more hearing dates were added due to the length of time it took to hear every witness.

February 9, 2015June 15, 2023

ISO-NE Capacity Prices Likely to Fall in Future

By Rich Heidorn Jr.

The 36% increase in prices in last week’s ISO-NE capacity auction likely represents the peak for the foreseeable future, analysts say.

The ninth Forward Capacity Auction cleared at $9.55/kW-month — up $2.52 over FCA 8 — outside of the Southeastern Massachusetts-Rhode Island (SEMA) zone, where prices were administratively set at $17.73/kW-month for 353 MW of new resources and $11.08/kW-month for 6,888 MW of existing resources.

The auction cleared about 1 GW of new generators, which can lock in their initial prices for seven years. During the lock-in period, they take a place at the bottom of the supply stack as zero-bid price takers.

“All else being equal, we believe that in the upcoming auction … the clearing price will decrease and will be set by the de-list bids of existing generators,” analysts for ICF International said, estimating that about 300 MW of excess supply cleared the auction. “Assuming no change in any parameters from FCA 9 … the maximum impact of the excess capacity in FCA 10 prices will be around $2/kW-month. Depending on the de-list bids, the impact may be less.”

Analysts for UBS Securities agreed that last week’s results “[signify] the near-term ‘top’ of this market.”

“We estimate next year’s auction could tentatively be in the ~$6-7/kW-month range … seeing this as the level at which transmission backs out of the auction (1.028 GW of [New York] imports cleared at $7.97/kW-month) as well as expecting a continued decline in demand response,” UBS said.

iso-ne fca 9 at a glance — (Click to Zoom.)

They also predict that prices in the SEMA region will converge to the pool-wide average as the zone around Boston did this year.

Transmission Didn’t Clear Auction

Analysts said it appeared no transmission cleared last week. “It may be that the combination of transmission and generation costs are too high, the volumes required might be high or additional incentives associated with potential new CO₂ regulations may be required to improve the economics of transmission projects,” ICF said. “Alternatively, some transmission projects may not have qualified.”

UBS said merchant transmission is a potential “wildcard” for future auctions, saying a project such as Eversource Energy’s (formerly Northeast Utilities) Northern Pass could offset as much as 400 MW of supply.

Demand Response Continues Contraction

Demand response, which cleared 3,041 MW in FCA 8, fell to 2,803 in last week’s auction, a drop of about 238 MW, or 8%, analysts said. ICF said about 600 MW of existing DR was de-listed while 367 MW of new DR resources — believed to be energy efficiency — cleared.

DR has been on a steady decline in New England’s capacity market since peaking at 3,645 MW in FCA 6.

In contrast, ICF said there appeared to be no significant de-listing of existing generators, indicating that their de-list bids were below clearing prices.

“This implies that existing generators believe that capacity prices are high enough to offset potential penalties from underperformance under the [Pay-for-Performance program] or that penalties will be adequately compensated by credits for performance under scarcity conditions,” ICF said.

February 9, 2015June 15, 2023

Exelon, LS Power Join CPV in Adding New England Capacity

By William Opalka

New generators from Exelon, LS Power and Competitive Power Ventures were the apparent winners in New England’s capacity auction last week, while NRG Energy and Public Service Enterprise Group walked away empty handed.

ISO-NE’s ninth Forward Capacity Auction added more than 1,000 MW of gas generation to the region’s mix. Two of the sites are expansions of existing power generation facilities and the third, and largest, is a greenfield site that has been slated for development for at least 16 years. (See Prices up One-Third in ISO-NE Capacity Auction.)

The new resources are a 725-MW combined-cycle resource in Oxford, Conn., under development by Competitive Power Ventures, and Exelon Generation’s two-unit 195-MW CT in Medway, Mass., according to the companies.

Analysts agree that LS Power, with two 45-MW combustion turbines in Wallingford, Conn., was the other successful bidder. LS Power did not return telephone calls seeking comment.

Analysts at ICF International called the new generation a validation of ISO-NE’s Pay-for-Performance program, which increased both performance expectations and penalties for plants that fail to deliver power when called. “The restructured capacity market is working,” ICF said. “Since 2002, most of the capacity additions in ISO-NE have either been sponsored by a state or driven by administratively set prices. FCA 9 is the first auction with major economic capacity additions.”

All of the new generators are believed to have dual-fuel capabilities, meaning they should be able to operate even if they cannot obtain natural gas.

PSEG, NRG Units Did not Clear

PSEG confirmed that its proposed 475-MW combined-cycle plant at its existing Bridgeport Harbor Station site had not cleared and analysts for UBS Securities said it appeared NRG’s proposed 340-MW combined-cycle repowering of its Canal Generating Station also failed to clear.

UBS said NRG still may develop the Canal plant, possibly aided by bilateral contracts with local municipal utilities. The site is in the Southeast Massachusetts-Rhode Island (SEMA) zone, which failed to procure enough capacity resources for the 2018/19 commitment period.

PSEG said that although its Bridgeport plant did not clear in FCA 9, it will continue development work and seeking community approvals to “allow us to be ready when and if the markets indicate support for this investment in the future.”

CPV Site’s Long History

The site of CPV’s Towantic Energy Center in Oxford has a rather storied history. First proposed in the 1990s, the site appeared ready to be developed more than a decade ago until the bankruptcy of Calpine scuttled the plan. Rights to the plant were acquired by General Electric in 2007, which designed the current configuration. It is a partner in the plant with CPV.

The site was fully permitted in 1999 for a 512-MW plant. Plans that call for a larger footprint have sent the project back before the Connecticut Siting Council.

CPV spokesman Braith Kelly said the company fully expects the project to be completed on time when the capacity commitment period starts on June 1, 2018.

“The technology is greatly improved from the time of the previous permits, so the environmental impact will be even less than before,” he said.

However, an active citizen group has been opposed to the plant, citing environmental and health concerns.

Delays, if they occur, would not necessarily impair the company’s standing in the ISO-NE market.

“A resource delayed for reasons beyond its control (one example could be lawsuits that delay the issuance of needed permits) can go to [the Federal Energy Regulatory Commission] and request a one-year deferral of its capacity supply obligation,” said Marcia Blomberg, a spokeswoman for ISO-NE.

She also said a resource that cannot meet its schedule can trade out of its obligation through annual and monthly reconfiguration auctions leading up to each capacity commitment period.

“Or it can make a bilateral trade with another resource. This is the most likely path to be taken by resources that are delayed for some reason,” she added.

Peakers

The successful peaking units likely wouldn’t face the challenges CPV has, as they are expansions of existing sites.

However, last year it reached an agreement with Wallingford, Conn., to add two peaking units to its existing array of five 50-MW units. The town owns and operates its own municipal electric system and leases the power plant site to LS Power. The company bought the generating plant from Pennsylvania-based PPL in 2011.

Exelon said both of its Medway units will run mainly on natural gas but will have the ability to run on ultra-low-sulfur distillate fuel oil as a back-up. ISO-NE has been encouraging the development of dual-fuel-capable generation to ease natural gas pipeline constraints during the winter.

Exelon said it is currently in the permitting phase for the Medway expansion. Construction is expected to begin in 2017 and be completed by mid-year 2018.

The company currently owns and operates approximately 2,200 MW of both combined-cycle and peaking generation in the Boston area, including the existing three-unit, oil-fired 117-MW peaking facility in Medway.

The Medway facility also is in the generation-short SEMA zone.

UBS estimates the plant, expected to cost about $150 million, will generate $35 million to $40 million in incremental cash flow, based on the $17.73/kW-month clearing price, adding 2 cents per share to Exelon’s earnings.

February 6, 2015June 15, 2023

Entergy Retail Sales Up 2.3% in 2014; Higher Growth Forecast Through 2017

By Chris O’Malley

Entergy yesterday reported a drop in fourth-quarter earnings, but executives gave an upbeat outlook, citing stronger-than-expected growth in retail sales and forecasts of increasing demand as a result of the “industrial renaissance” in the Gulf.

The company posted fourth-quarter net income of $120.1 million, or 66 cents a share, down from $146.9 million, or 82 cents a share, for the same quarter in 2013. Entergy cited higher taxes and increased operating costs as a cause for the drop. But revenue grew by 5% to $2.83 billion, beating estimates of $2.7 billion.

For the year, retail sales grew by 2.3% versus a forecasted 1.9%. “Industrial sales led the way with 5% growth, beating our estimates of 2.8% by a wide margin,” Entergy CEO Leo Denault told analysts during a Feb. 5 conference call. Chemicals, petroleum refining and pulp and paper were responsible for nearly 60% of the industrial growth.

While most of the increases came from existing customers, Entergy said it is also seeing increasing numbers of new customers, forecasting that retail sales will grow by 3.25 to 3.75% annually through 2017. “We continue to believe that Entergy has some of the best growth fundamentals in the business,” Denault said.

Lake Charles Tx Project

Entergy cited that growth in a filing with MISO in December for out-of-cycle approval of a $187 million transmission project near Lake Charles, La., which the company says will be “one of the largest transmission projects in Entergy history.”

News of the project, which will include new substations and 25 miles of 500-kV and 230-kV lines, sparked controversy among MISO transmission developers. Entergy requested expedited approval of the project, saying it needed to be started in the first half of 2015 for completion by summer of 2018, meaning that it would be built by Entergy and not considered for a competitive solicitation under the Federal Energy Regulatory Commission’s Order 1000.

At MISO’s Planning Advisory Committee meeting last month, several transmission developers questioned why Entergy had not announced the need sooner. (See Entergy Out-of-Cycle Transmission Request Draws Competitors’ Ire.)

Entergy’s footprint in the Gulf Coast includes fast growing petroleum refining, industrial gases and wood products.

Declining petroleum prices and cutbacks in drilling portend some reduction in growth among certain petrochemical customers, but the outlook for Entergy’s core industrials remain robust, Entergy executives said.

Entergy Wholesale

Company executives said reduced drilling could increase natural gas prices, improving the margins for the company’s nuclear power plants, which operate in competitive markets in New York and New England.

Executives said the Entergy Wholesale Commodities group also will benefit from ISO-NE’s Forward Capacity Auction this week, which saw prices increase by about one-third. “We are seeing some positive changes in capacity markets,” Denault added. (See Prices up One-Third in ISO-NE Capacity Auction.)

MISO Integration

Reviewing 2014 trends, he also pointed to Entergy’s first year as part of MISO’s new southern region. “Although the numbers are still estimates, it now appears that customers across the utility will in fact realize more MISO-driven savings than we had originally expected.”

Arkansas Rate Structure

Entergy recently said it intends to file a new rate case in Arkansas, likely in March or April. It has been seeking regulatory changes from the state legislature that could boost earnings. “I would expect that we would [back] some legislation around this” soon, said Theo Bunting, group president of utility operations.

February 4, 2015June 15, 2023

Prices up One-Third in ISO-NE Capacity Auction

By William Opalka

ISO-NE’s ninth Forward Capacity Auction saw prices increase by about one-third as 1,400 MW of new resources cleared to replace retiring coal plants.

While the RTO exceeded its six-state requirement of 34,189 MW by more than 500 MW, the Southeastern Massachusetts-Rhode Island zone failed to meet its obligation.

Monday’s auction was held to meet demand for the capacity commitment period from June 1, 2018, to May 31, 2019.

A preliminary estimate of the total cost is about $4 billion, compared to the 2014 auction that resulted in a total cost of about $3 billion.

The 24,447 MW of new and existing capacity resources that cleared the auction outside of SEMA/RI will be paid $9.55/kW-month. In FCA 8, most resources cleared at $7.025/kW-month.

The increase was expected. (See ISO-NE Opens FCA 9 amid Expectations of High Prices.)

New Capacity

The auction results included 1,400 MW of new capacity to help make up the shortage of generation created by the announced or pending retirements of more than 3,000 MW. New resources include three power plants — two in Connecticut and one in Southeastern Massachusetts — and 367 MW of new demand-side resources.

The resources include a 725-MW combined-cycle resource in Oxford, Conn., under development by Competitive Power Ventures. Two 45-MW combustion turbines in Wallingford, Conn., and a 195-MW CT in Medway, Mass., also cleared.

The auction started with 5,432 MW of new resources qualified to compete, according to the RTO.

“The capacity market is working as designed. The price signals from last year’s auction helped spur investment in new resources, including more than 1,000 MW of new generating capacity, which will help address the region’s resource shortage and meet peak demand in 2018-2019,” ISO-NE CEO Gordon van Welie said in a statement.

He credited the Pay-for-Performance incentive that rewards the best performing resources — an innovation being used for the first time in FCA 9 — a sloped demand curve, a seven-year price lock-in for new resources and the ability to defer a capacity obligation for one year under extraordinary circumstances.

The region was divided into four zones: Connecticut; Northeast Massachusetts/Greater Boston (NEMA/Boston); Rest of Pool (ROP); and a new zone, Southeast Massachusetts/Rhode Island (SEMA/RI).

Shortfall

In SEMA/RI — home of the 1,517-MW Brayton Point generating station, which is set to close in 2017 — 7,241 MW qualified, falling short of the 7,479 MW needed to meet the zone’s local sourcing requirement.

The shortfall meant the zone was not opened to bidding. Instead, administrative pricing rules were triggered: 353 MW of new resources will receive the auction starting price of $17.73/kW-month, while the 6,888 MW of existing resources will receive $11.08/kW-month, which is based on the net cost to build a new resource.

February 3, 2015June 15, 2023

Patton: M2M, Real-Time Gas Prices to Aid Operations in MISO

CARMEL, IND. — Independent Market Monitor David Patton told the MISO Board of Directors’ Markets Committee last week that the RTO should see significant benefits from its market-to-market coordination with SPP and the ability to adjust gas reference prices in real time.

Patton said the market-to-market coordination should reduce the impact of SPP’s transmission loading relief (TLR) actions on MISO.

About 20% of the congestion pricing at MISO generator locations in December resulted from SPP TLRs, Patton said.

“While congestion costs for SPP constraints remain low, dispatch and pricing effects of these constraints were significant in December,” Patton said in a presentation to the committee.

The Federal Energy Regulatory Commission approved the SPP-MISO M2M rules last month. (See SPP, MISO Move Ahead on Flowgate Rules.) They will take effect March 1.

“When SPP issues TLRs, we generally price these constraints at vastly higher levels than in SPP,” Patton said. “Market-to-market should help.”

Real-Time Feed on Gas Prices

Patton said his office has implemented new procedures for adjusting reference prices during volatile gas pricing periods. Patton said MISO’s access to real-time data on gas prices is “a huge step forward. We’ve already implemented it and it works well.”

The new tools have been used only once because the winter has thus far not been “stressful,” Patton said.

February 3, 2015June 15, 2023

Bill Would Revamp Massachusetts Energy Landscape

A Massachusetts state legislator whose district includes the soon-to-be shuttered Brayton Point generating plant has filed legislation that would revamp the state’s energy landscape.

The bill was proposed by Rep. Patricia Haddad, a Democrat and an ally of Massachusetts Speaker Robert DeLeo.

The sweeping bill would require the state’s utilities to enter into long-term contracts with offshore wind developers. It also seeks to clear obstacles to gas pipeline and electric transmission construction by, among other methods, creating a siting board to more easily locate energy infrastructure.

It proposes a tax that would fund natural gas infrastructure, attempting to revive a proposal last year by the six New England governors that failed to gain traction. Environmental groups told The Boston Globe last week they object to the use of public subsidies for pipeline expansions and would like to see incentives for energy efficiency and storage.

It also encourages utilities to submit proposals for competitively bid transmission lines to deliver Canadian hydropower. Another proposal for that purpose bogged down in the legislature last year.

It would make conversion from coal-fired power plants to natural gas easier as well, which could aid efforts to repower the 1,517-MW Brayton Point plant. Brayton Point, the largest taxpayer in Haddad’s hometown of Somerset, is scheduled to close in mid-2017.

Massachusetts has the eighth-highest residential electric rates of any state, according to the U.S. Department of Energy. Each of the other New England states also ranks in the top 10.

Former Gov. Deval Patrick released a study last month that said the state needed significant investment in natural gas pipeline capacity to preserve electric system reliability. (See Gas Price Spikes Likely Through 2019, Study Says.)

ISO-NE also chimed in recently saying that grid reliability is threatened by the region’s inadequate pipeline capacity, which is unable to fully supply heating and power generation during the winter. (See ISO-NE CEO: Despite Mild Winter, Region Still Needs Infrastructure.)

February 3, 2015June 15, 2023

MISO Seeks to Ease Coal Retirement Conundrum

By Chris O’Malley

MISO is proposing to modify its Tariff so that generation owners retiring coal plants to meet looming environmental rules can avoid capacity deficiency penalties.

The Tariff revision (ER15-918) filed with the Federal Energy Regulatory Commission on Jan. 28 would apply to generation operating during the Planning Resources Auction offer window that will retire or suspend operations between the March 31 end of the window and the end of the 2015-2016 planning year on May 31, 2016.

Last year, several generators asked the Federal Energy Regulatory Commission for a waiver from MISO’s Tariff. They complained there was no clear mechanism within the MISO Tariff that would permit them to buy replacement capacity through the auction to cover the six-and-a-half-week period between the planned retirement of the coal units and the end of MISO’s planning year.

Only Where SSR is not Necessary

The proposed Tariff revisions would allow generators the option of not making offers into the PRA without facing liability for physical withholding.

It would apply only to the 2015-2016 planning year and only to generators for which MISO has determined a system support reliability agreement (SSR) is not necessary.

In testimony included with its filing, MISO said the proposal will not cause reliability concerns, explaining that a “critical condition” of the proposed change includes a determination by MISO that the retiring or suspending unit is not needed for reliability.

Also, the Tariff change will not relieve load-serving entities from obligations to meet the planning reserve margin requirements for a full year.

The proposed change “will allow market participants greater certainty and flexibility by providing a clear option to avoid risk by not being forced to make the difficult choice between making [zonal resource credit] offers for generation resources that MISO has determined may retire or suspend during the 2015-2016 planning year or being faced with the potential of physical withholding mitigation,” MISO said.

MISO’s Independent Market Monitor had expressed concerns that the change would “limit retrospective physical withholding mitigation” for generation resources.

MISO said the change is appropriate to provide certainty to market participants regarding generating units for which the RTO has determined that retirement or suspension does not present reliability issues.

Different Fates

One utility that was successful in obtaining a waiver was Indianapolis Power & Light. FERC approved its request last October after MISO said its analysis showed that Zone 6, in which IPL is located, has sufficient planning reserve margins even after accounting for the planned retirement of the company’s Eagle Valley coal-fired units.

FERC denied a similar request from Consumers Energy, however. The company plans to retire its “Classic Seven” coal units on April 15, 2016, due to the Environmental Protection Agency’s Mercury and Air Toxics Standards.

Consumers told FERC that purchasing replacement capacity for the entire year could cost up to $84.8 million. MISO opposed Consumers’ waiver request, saying it could cause MISO’s north and central regions to fall below the planning reserve margin. FERC denied Consumers’ request in November.