PJM should change its rules on pricing and scheduling of interface transactions to reflect changes in system conditions and eliminate the need to schedule physical transactions across seams, the RTO’s Independent Market Monitor says.
The two proposals were among four new recommendations that Monitoring Analytics made in its third-quarter State of the Market report.
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The Monitor said PJM and neighboring balancing authorities should develop an optimized joint dispatch that treats their seams like any other constraint under LMP rules.
It also recommended that PJM adjust its weighting procedure to “ensure that the interface prices reflect ongoing changes in system conditions and that loop flows are accounted for on a dynamic basis.” It said PJM should conduct an annual review of the mappings of external balancing authorities to individual interface pricing points to reflect changes to the impact of the external power source on PJM tie lines as a result of system topology changes.
The Monitor also recommended changing the submission deadline for real-time dispatchable transactions from 1200 the day before to three hours before the requested start and that the minimum duration be reduced to 15 minutes from one hour. “These changes would give PJM a more flexible product that could be utilized to meet load in the most economic manner,” the Monitor said.
Offering a different solution on an issue it has discussed before, the Monitor said the amount of tier 1 megawatts paid when the non-synchronized reserve market clearing price goes above zero should be equal to the tier 1 megawatts estimated by the real-time security constrained economic dispatch market solution.
The Monitor has said that its preferred solution is to stop paying tier 1 synchronized reserves the synchronized-reserve market-clearing prices when the non-synchronized price is above zero. Last month, the Market Implementation Committee approved a problem statement proposed by Monitor Joe Bowring to consider changes to the payments.
Map of SPP’s new territory, highlighted in blue (Source: Basin Electric Cooperative)
SPP won federal approval Nov. 10 to add three new members in the Upper Great Plains, a seven-state expansion that restores the RTO’s scope after its loss of Entergy to MISO.
SPP’s footprint shrunk in Arkansas, Louisiana, Mississippi and Texas after Entergy’s defection to MISO. Its territory now shifts north with the Federal Energy Regulatory Commission’s approval (ER14-2850) to add Heartland Consumers Power District, Basin Electric Power Cooperative and the Western Area Power Administration’s Upper Great Plains Region (Western-UGP).
The three new SPP members represent the backbone of the bulk electric system in seven states and consist of about 9,500 miles of transmission lines with more than 3 million customers, increasing SPP by about one-fifth.
Basin Electric has 2.8 million customers and 2,100 miles of transmission lines. Heartland serves 28 municipalities, including Sioux Falls, S.D. Western-UGP covers 378,000 square miles of prairie and farmland.
“FERC’s substantive approval clears the way for us to continue to work toward [integration]. We expect to take on reliability coordination of the … transmission system in June 2015, with full membership in October 2015,” SPP Chief Operating Officer Carl Monroe said in a statement after FERC’s approval.
Little Rock-based SPP said the expansion will bring stakeholders more than $334 million in net benefits. SPP cites increased ability to commit and dispatch generation that affects flows through and out of Nebraska. It also pointed to the availability of lower-priced generation, including Western-UGP’s excess hydro power.
Concerns Raised
FERC and stakeholders took issue with parts of SPP’s integration plan, however.
The commission rejected SPP’s proposal to revise Schedule 12 of its Tariff, which covers the collection of FERC assessments. FERC noted that the cost of regulating Western-UGP and other federal power marketing agencies is administered in a different manner and that it was concerned about the possibility of a double assessment of FERC charges.
Kansas utility regulators told FERC that the three new members of SPP should be responsible for a “proportionate share” of costs for certain base plan upgrades in service before and after Oct. 1, 2015, because they would benefit from SPP membership and services. Otherwise, Kansas ratepayers would face an unreasonable financial burden when utilities in the state recover those costs from their customers, the Kansas commission argued.
FERC said the Kansas commission “neglects to consider the benefits the rest of the SPP membership will receive” from the three new members’ legacy systems, such as increased grid reliability and congestion management.
A number of consumer groups, transmission operators and state regulators also raised concerns about seams issues, including the potential that some utilities that serve Montana retail customers could be required to pay for transmission service from both SPP and MISO.
FERC said concerns about such pancaked rates were beyond the scope of the proceeding and should be taken up in hearings and settlement judge procedures later.
MISO-SPP Dispute
(Source: SPP)
MISO raised a handful of concerns, including whether FERC’s rulings on the expansion could put it at a disadvantage in its dispute with SPP over their joint operating agreement.
SPP alleges that the JOA was breached after Entergy joined MISO late last year and began transferring electricity over SPP’s lines. MISO said that SPP has billed it for more than $35 million for flows exceeding the limited 1,000-MW physical contract path between MISO Midwest and MISO South. The latter consists mainly of Entergy’s footprint.
MISO sought a confirmation that FERC’s approval of SPP’s proposed cost allocations for Basin Electric’s projects would not prejudice the issue of whether MISO should be held responsible for any charges that could stem from the JOA dispute.
FERC sought to alleviate MISO’s concerns, saying “we confirm that our acceptance of [SPP’s expansion] does not prejudge the outcome of the ongoing hearing and settlement judge procedures.”
Since last April, FERC has convened five settlement conferences between SPP and MISO.
Talks Sour
The tone of the talks soured recently. On Nov. 17, SPP filed a scathing rebuttal opposing a request by MISO for expedited consideration of the JOA dispute, calling it “procedurally improper, unsupported and an impediment to further progress in ongoing settlement negotiations.”
To date, MISO “has not paid a dime for any of the flows it has imposed on SPP’s system,” SPP said.
SPP argues that some of the charges are the result of MISO failing to reserve service under an accepted agreement. “If MISO simply reserved service on an hourly basis it would not be subject to these daily charges,” SPP said.
Hands Full
SPP plans to take on reliability coordination of its three new members starting in June.
SPP said in its most recent annual report that the most significant transmission challenges facing much of its footprint stem from an increase in oil and gas drilling.
“New oil and gas drilling facilities are built faster than they can be captured in SPP’s planning processes and models,” the RTO said. “Additionally, pipeline expansions are proposed for the region that will increase the need for electric transmission facilities to serve the pumping stations.”
The PJM Board of Managers won’t make its Dec. 1 target for filing the RTO’s Capacity Performance proposal with the Federal Energy Regulatory Commission, CEO Terry Boston told members last week.
As a result, PJM will likely post two sets of parameters for the May 2015 capacity auction — one assuming the status quo and one assuming FERC approval of what the board ultimately files.
Boston also said he will recommend that the board’s Section 206 filing not incorporate PJM’s proposal to eliminate demand response as a supply resource. The proposal, outlined in an Oct. 7 white paper, would make load-serving entities responsible for incorporating DR in reduced demand estimates. (See PJM DR Cos. Confident; Reject PJM EPSA Response.)
Boston said PJM should delay changes in its DR rules pending the resolution of a potential Supreme Court review of the D.C. Circuit Court of Appeals’ Electric Power Supply Association ruling voiding federal jurisdiction over DR compensation. “We think the courts and FERC have to do their job,” Boston said. “CP will work either way.”
Boston said the board, which heard from 50 speakers during a four-hour meeting with stakeholder coalitions on Nov. 11, met the day afterward and also conducted a two-hour teleconference with PJM staff last week. The board plans to meet again after Thanksgiving. “The board knows where each coalition stands,” Boston said. “They are weighing all sides of the issue.”
NJ Regulators OK Pass-Through
Meanwhile, the New Jersey Board of Public Utilities decided last week to allow bidders in its February Basic Generation Service auction to pass through “unanticipated” capacity costs approved by FERC.
Retail customers that do not choose alternative suppliers obtain their power through the BGS auctions. In New Jersey, 85% of residential ratepayers and 70% of small commercial customers rely on BGS.
The BPU said it acted because it was unlikely FERC would rule before the next BGS auction in February and it feared potential bidders would decline to participate or include large risk premiums to cover the uncertainty.
BPU President Richard S. Mroz said the action would ensure “the integrity and competiveness” of the auction. “Faced with the uncertainty of federal action on a draft PJM proposal, there was good reason to believe that electric suppliers would either not participate in the upcoming auction or would bid much higher prices to mitigate unknown risks,” he said.
Md. Auction Sees Reduced Participation
The Maryland Public Service Commission blamed uncertainty over the CP proposal for a nearly 50% drop in bidder participation in its Oct. 20 auction for Standard Offer Service, Maryland’s method of supplying customers that do not shop.
The state’s four investor-owned utilities sought 2,184 MW for residential and small and medium commercial customers. The PSC said only five suppliers submitted bids on one or more of the 10 products available in the auction, down from nine in the previous auction.
Only two bidders offered to supply residential and small commercial customers, and only one bidder made offers for several other products.
Pepco (330 MW of combined residential and small commercial customers), Potomac Edison (46 MW of 12-month and 24-month residential supply) and Delmarva Power & Light (122 MW of residential and small commercial) each received only one bid.
Overall, the PSC received bids totaling 1.8 MW for every megawatt it sought, compared with a 3-1 ratio in the previous auction.
“Although the Maryland PSC accepted the bid results and determined that the SOS auction was in line with market conditions, the material reduction in generator interest in bidding in the auction is a cause of great concern,” PSC Chairman W. Kevin Hughes said in a letter to the PJM board.
In testimony to the PSC, Maryland’s bid monitor, Boston Pacific, concluded that “the current level of uncertainty was great enough to keep many bidders from offering for the longer-term residential and [small commercial] products.”
Consolidated Edison of New York has opened a new front in its attempt to persuade federal regulators that it’s been saddled with an unfair share of two transmission upgrades in northern New Jersey.
The company filed a complaint on Nov. 10 with the Federal Energy Regulatory Commission stating its opposition to a cost allocation formula that PJM has devised for the upgrades (EL15-18). Con Ed said it is being overcharged by about $650 million for the projects.
PJM assigned Con Ed $629 million of the costs of a $1.2 billion transmission upgrade to address a short-circuit problem in the Public Service Electric and Gas transmission zone outside New York City. PJM said Con Ed’s responsibility resulted from its use of the “Con Ed-PSEG wheel,” in which Public Service Enterprise Group, PSE&G’s parent company, takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City. PSE&G was allocated $52 million of the cost.
Con Ed was also assigned $51 million of PSEG’s $100 million Sewaren storm-hardening project.
In April, FERC rejected Con Ed’s attempt to avoid paying for the short-circuit project but said it wanted more information on how PJM performed the distribution factor (DFAX) analysis that determined Con Ed’s share of the cost. (See FERC Rejects Con Ed Challenge on Tx Upgrade.)
Con Ed also said PJM’s Tariff requires a review of instances where PJM’s cost allocations will produce “objectively unreasonable” results.
The company said the new complaint will provide a more holistic consideration of the cost allocation than the rate filing that prompted FERC’s earlier order.
“FERC has recognized that parties have a right to challenge previously approved cost allocation methodologies,” Con Ed spokesman Bob McGee said. “As such, Con Edison exercised its rights under the Federal Power Act and challenged the cost allocations themselves, the decisions and actions taken by PJM in producing the cost allocations and the discrete elements of PJM’s Tariff that caused these unjust, unreasonable, unduly discriminatory and preferential results.”
The Federal Energy Regulatory Commission has ordered hearing and settlement procedures on MISO’s proposed cost allocation for the Presque Isle Power Plant, which would cause steep rate increases for residents in Michigan’s Upper Peninsula.
The Nov. 10 ruling (ER14-2860, ER14-2862) comes after a flood of ratepayer and political pushback to MISO’s system support resource agreement (SSR) that blocks Wisconsin Electric Power Co. (WEPCO) from closing the aging and costly generator near Marquette, Mich.
MISO sought the SSR last year after determining that the 400-MW coal-fired plant was needed for reliability of the region’s grid.
Upper Peninsula ratepayers would shoulder the bulk of the estimated $100 million annual cost to keep Presque Isle in operation. Michigan and Wisconsin utility regulators say the cost of keeping the plant in operation is unreasonable. (See Michigan: FERC Favors Transmission in Presque Isle Dispute.)
The Michigan House of Representatives on Nov. 6 passed a resolution calling on FERC to reverse its acceptance of MISO’s cost allocation, which it said would saddle Upper Peninsula residents with 99.5% of the Presque Isle costs. The resolution asks FERC to divide the cost in “a more equitable manner.”
Dozens of cities and towns drafted similar resolutions and filed them with FERC. A number of businesses in the Upper Peninsula complained that their monthly costs would rise by several hundred dollars a month and that they would be forced to cut jobs.
FERC’s files were filled with complaints from residential ratepayers, as well.
“I am a semi-retired elder on a very limited income. Having to pay $30 to $50 more on my electric bill would be an extreme hardship for me and many others like me,” wrote Ruth Pickem, of St. Ignace, Mich.
“If Wisconsin does not have to pay because they do not benefit from the plant, then we should not have to either. We do not benefit from this plant! Close it!” Pickem added.
The uproar over Presque Isle even triggered bipartisan legislation from Michigan lawmakers in Congress, Democratic Sen. Debbie Stabenow and Reps. Dan Benishek (R) and Gary Peters (D).
“The Power Act,” introduced earlier this month, would essentially require FERC to overrule decisions by the North American Electric Reliability Corp. if a review found it resulted in “unjust and unreasonable” rate increases.
The bill’s sponsors said NERC’s intervention “upended” an earlier FERC finding that Upper Peninsula ratepayers should bear only 14% of Presque Isle’s operating costs.
WEPCO has expressed interest in adding new generation in the Upper Peninsula.
Other studies have been conducted into the possibility of building new transmission to the Upper Peninsula, although that would likely cost hundreds of millions of dollars. A combination of both new transmission and generation remains under debate.
A hearing date in the Presque Isle SSR matter has yet to be scheduled.
From left to right: Board of Managers Chairman Howard Schneider; board member “Neel” Foster; and board member Sarah Rogers. (Source: PJM Interconnection LLC)
The PJM Nominating Committee voted last week to renominate Board of Managers Chairman Howard Schneider and board members John McNeely “Neel” Foster and Sarah Rogers to new three-year terms.
The three nominations will be brought to a vote by members at the PJM Annual Meeting in May. The Nominating Committee also is seeking a candidate to fill the unexpired term of Bill Mayben, who plans to retire in 2015. Under the Operating Agreement, Mayben’s replacement must be someone with expertise in the operation or concerns of transmission-dependent utilities.
Meanwhile, the Members Committee elected new members to the Nominating and Finance committees, as well as sector whips (see table).
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Katie Guerry of EnerNOC was elected to a one-year term as MC vice chairman. She will assume the position in January, when Jim Jablonski of the Public Power Association of New Jersey becomes chairman, succeeding Dana Horton of American Electric Power.
MISO plans to unveil a plan next spring for monitoring and managing low-voltage facilities that can cause overloads on its transmission system.
The plan, which will focus on sub-100-kV lines, is in response to the Sept. 8, 2011, Southwest blackout that cut power to 5 million people in Arizona, Southern California and Baja California in Mexico.
Investigators found that the loss of a 500-kV transmission line owned by Arizona Public Service Co. increased power flows through lower voltage systems in parallel to significant transmission corridors, according to a 2012 report by the Federal Energy Regulatory Commission and North American Electric Reliability Corp.
“The flow redistributions, voltage deviations and resulting overloads had a ripple effect, as transformers, transmission lines and generating units tripped offline, initiating automatic load shedding throughout the region in a relatively short period of time,” the report said.
MISO said a transmission owner’s request that the ISO manage some of its low-voltage facilities also was a driver in the initiative.
MISO will identify low-voltage systems that impact the bulk-electric system and establish criteria to determine what it should monitor or manage. MISO would monitor the low-voltage elements by including them in models and tracking power flows against operating limits. It would include the most important low-voltage lines in its congestion management and transmission planning.
Under its current proposal, MISO would include in its N-1-1 contingency analyses an assessment “of BES elements that would potentially overload and trip facilities on the low-voltage system that would propagate back to BES” or that would cause the models to fail to solve, indicating possible system instability.
A low-voltage facility would be deemed to have an impact on the BES if the trip of low-voltage facilities causes an overload greater than 100% of the emergency rating on a BES element or results in an unsolved power flow, and the initial BES contingency has a 3% line outage distribution factor (LODF) on the low-voltage candidate facility.
The effort is not intended to broaden the definition of the BES, MISO spokeswoman Jennifer June Lay said. “This is considered a BES reliability issue that is part of the ongoing reliability services provided by MISO and would result in no additional services to be marketed.”
MISO said it is working with stakeholders to develop a final methodology. It said it will update assessments of the low-voltage systems every two or three years.
Asset owners would be able to examine results, validate findings and comment on solutions, such as whether existing mitigation is available to avoid overloads of a low-voltage facility.
The 2011 Southwest blackout proved pricey for utilities.
FERC has meted out at least three penalties so far, including a $12 million penalty announced last summer against the Imperial Irrigation District. The non-profit California utility violated four reliability standards for transmission operations and planning said to have undermined BES reliability, regulators charged. FERC also said IID fell short in coordinating operations planning with neighboring systems. FERC only collected $3 million from IID, as it ordered the utility to spend $9 million on reliability enhancements.
Yesterday, FERC announced a settlement with the Western Area Power Administration’s Desert Southwest Region, which it said had violated three reliability standards in the blackout. WAPA agreed to improvements, including the modeling of “critical external facilities and facilities operated below 100 kV that can impact system operating limits on its transmission system,” FERC said.
In response to requests from several senators from both parties, the Department of Energy’s Inspector General has begun an investigation into the Federal Energy Regulatory Commission’s Office of Enforcement.
“After reviewing this situation, we have determined that we will be undertaking a review of aspects of FERC’s enforcement program,” Inspector General Gregory Friedman said in a letter to Republican Sen. John Barrasso of Wyoming.
The letter is dated Oct. 23 but was only recently made public.
Barrasso and Sen. Susan Collins (R-Maine) had written Friedman in September, asking him to investigate allegations in an Energy Law Journal article by former FERC counsel William Scherman that “the FERC enforcement has become lopsided and unfair.”
The senators requested that Friedman look into allegations that enforcement targets “are not being given actionable notice by FERC of conduct” that “constitutes market manipulation.” The senators were also concerned that companies “who do not otherwise appear frequently before FERC are held to different standards.”
Quid Pro Quo?
The senators also pointed to Commissioner Norman Bay’s written answers to questions posed by the Senate Energy and Natural Resources Committee after his confirmation hearing in May, shortly after Scherman’s article was published. Sen. Lisa Murkowski (R-Alaska) asked about the appearance of quid pro quo regarding FERC’s approval of Exelon’s 2012 merger with Constellation Energy Group, which occurred the day after Constellation agreed to a settlement with the Office of Enforcement. Murkowski noted that the settlement agreement made reference to the merger.
Bay answered, “To the best of my recollection, I did not indicate to the parties involved in the Exelon-Constellation merger that it would be prudent to settle the pending enforcement matter to get the merger approved. I do not know whether anyone else at FERC did so.”
“Given these circumstances, did the former FERC chairman [Jon Wellinghoff] or any member of FERC’s staff suggest or actively or effectively require that a regulatory approval would be contingent upon the ‘voluntary’ settlement of an enforcement dispute?” the senators asked Friedman.
Barrasso had pointed criticism for Bay at the future FERC chairman’s confirmation hearing. “I find this very troubling,” Barrasso told Bay regarding Scherman’s allegations. “I believe this raises serious questions about your fitness to be on the commission. I also believe that these tactics have contributed to driving investors out of the electric market and that means a less reliable grid and higher costs to consumers.” (See Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing.)
Sen. Robert Casey (D-Pa.) also wrote to Friedman about FERC’s enforcement tactics in July. Casey did not bring up specific allegations, only asking whether or not the office was violating any due process or confidentiality laws.
“I appreciate that FERC investigates matters that may bring instability or fraud to the energy marketplace,” Casey wrote. “However, to do this fairly and effectively, it is important that FERC’s policies on investigations and enforcement actions be transparent.”
News of the IG’s investigation came as FERC last week released its annual Report on Enforcement.
The report highlights eight settlements in fiscal year 2014 that resulted in almost $25 million in civil penalties and disgorgement of $4 million in unjust profits. Some of these penalties were offset by reliability enhancements that FERC ordered. For example, FERC penalized the Imperial Irrigation District $12 million for its role in the 2011 Southwest blackout, but this was offset by the $9 million spent by the utility on reliability enhancements. (See related story, MISO to Look Closer at Low-Voltage Threats to System.)
Otherwise, the largest of these penalties was against Louis Dreyfus Energy Services ($4.3 million) “for virtual transactions made to increase the value of the company’s position in financial transmission rights” in MISO. The company also paid a $3.3 million disgorgement to MISO under the settlement.
FERC also collected $4 million from Erie Boulevard Hydropower for failing “to adequately maintain and operate dam safety mechanisms” and $2 million from Arizona Public Service Co. for, among other violations, failing “to perform necessary operational planning studies.”
Gas Index Manipulation
Among the settlements is one with Direct Energy Services, in which the company agreed to pay a $20,000 penalty and disgorge $31,935 for manipulating natural gas prices in May 2012. FERC said the company lowered prices at the Algonquin and Transco Zone 6 hubs by buying next-day physical index gas and selling comparable volumes of fixed-price gas. The company’s action lowered the Gas Daily Index, benefiting the company financially, according to the report.
The report notes that Direct Energy self-reported the violation, and its “quick action due to its strong compliance program and its cooperation with Enforcement’s investigation resulted in relatively small civil penalty and disgorgement payments.”
At FERC’s monthly meeting last week, Bay asked enforcement staff what led Direct Energy to self-report the violations. Staff member Michael Raibman said that after the company’s outside counsel gave a presentation regarding the Constellation settlement, a trader went to his supervisors, saying he suspected that some of his colleagues were engaged in the type of activity described in the presentation. Direct Energy’s compliance division then began an internal investigation the next day, Raibman said.
“So how helpful was the transparency provided in the commission’s order in the Constellation settlement?” Bay asked.
Raibman replied that Direct Energy said it had found it very helpful “because they knew exactly what it was that we had found troubling Constellation and were able to identify the same pattern in their trading very, very quickly.”
New England power generators are joining FirstEnergy’s effort to expand a court ruling that would prevent demand response providers from participating in capacity auctions.
The New England Power Generators Association asked the Federal Energy Regulatory Commission Nov. 14 to order ISO-NE to exclude such resources from the Forward Capacity Market (EL15-21).
In May, the D.C. Circuit Court of Appeals threw out the commission’s Order 745, which required RTOs and ISOs to pay demand response providers for energy at LMPs. The Electric Power Supply Association had sued FERC, claiming the commission exceeded its jurisdiction. FirstEnergy Solutions then filed a complaint with FERC, seeking to expand the challenge.
The D.C. Circuit granted a stay until Dec. 16 on its ruling in order to give U.S. Solicitor General Donald B. Verrilli Jr. time to file a petition on FERC’s behalf to send the case to the U.S. Supreme Court. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)
NEPGA, which represents 26,000 MW of generating capacity in New England, asked FERC to issue an order by Jan. 15, two weeks before ISO-NE is set to begin its next Forward Capacity Auction on Feb. 2. An order at that time would “ensure that clearing prices are not distorted by the participation of resources that cannot lawfully participate in that auction and that will be unable to fulfill their obligations if selected,” the NEPGA complaint states.
NEPGA also argues that the reasoning of the D.C. Circuit’s jurisdictional holding in the EPSA case — that FERC was erroneously attempting to regulate a retail product — was not limited to the energy markets. Demand response capacity resources must be excluded from participating as supply in capacity auctions because they can’t fulfill their energy must-offer obligations as required by ISO-NE’s Tariff, the complaint states.
After investing in natural gas-fired generation and committing to a $2 billion pipeline investment, Duke Energy now says it might get into gas production.
Duke Chief Financial Officer Steve Young told the annual Edison Electric Institute Financial Conference Nov. 11 that the company’s increasing dependence on natural gas means wellhead investments could make sense for the company.
“Gas prices have some volatility and investments in gas reserves might make sense,” Young said, according to a Bloomberg News account of the conference.
Young didn’t make any specific references to natural gas production investments, but it was the first time a Duke executive raised such a possibility. Since then, the company has declined to make public any plans for natural gas production investments.
“Duke Energy is in the early stages of evaluating investments in shale gas production,” company spokeswoman Jennifer Zajac said. “There are no immediate plans and the company will not make any decisions on the matter any time soon.”
Zajac said Duke is carefully watching another company’s move in that direction, however.
”Duke Energy will continue to monitor Florida Power & Light’s request for a rate-base shale gas production framework from the Florida Public Service Commission,” she said.
The idea is that instead of passing on gas costs to customers as it does now, Duke could control the price at the wellhead, lock in prices for customers and earn a profit on the investment. It would need regulatory approval for such a plan.
NextEra Energy, FPL’s parent company, generates 52% of its electricity using natural gas and has invested in natural gas pipelines. It is pushing for approval of a 600-mile, $3.7 billion natural gas pipeline into Florida from a hub in Alabama. It would partner for the project with Spectra Energy Partners.
Earlier this year, FPL said it was partnering with PetroQuest Energy to develop more than three dozen natural gas wells in the Woodford Shale region in southeastern Oklahoma. It is waiting for the Florida PSC to approve the company’s plan to invest in natural gas production as a long-term program and add it into its rate-base case. Currently, the Florida PSC allows the company to engage in short-term fuel hedging agreements to smooth fuel price volatility. FPL said it expects a decision from the PSC by late this year or early next year.
Like NextEra, Duke is investing in gas-fired generation and pipeline construction. Earlier this year, Duke said it would partner with four other companies to build a 550-mile, $5 billion pipeline to bring Marcellus and Utica shale gas to Virginia and eastern North Carolina. Called the “Atlantic Coast Pipeline,” it would have a capacity of 1.5 billion cubic feet of gas per day. Duke would own 40% of the pipeline. (See Duke, Dominion Propose 550-Mile, $5 Billion Pipeline for Shale Gas.)
At the North Carolina CEO Forum in Raleigh on Oct. 23, Duke CEO Lynn Good noted that its generation portfolio is increasingly dependent on natural gas. “By 2013, it was 20%, and we think it is going to be more and more and more as we go forward,” Good said, according to the Charlotte Business Journal. As recently as 2008, she said, “it would have been close to 0%.”
As part of its $9 billion generation fleet modernization program, the company retired about 3,830 MW of older coal-fired units in recent years, and it says that number will grow to nearly 6,300 MW, about a quarter of its earlier coal fleet. It is building a $600 million gas-fired plant in South Carolina and a $1.5 billion plant in Citrus County, Fla.
The company generated 55% of its power with coal in 2005, a share projected to drop to 38% by 2015. Gas, which was responsible for only 5% of its 2005 output, is expected to generate 24% of its power next year. Duke owns about 50 GW of generation in the U.S.
