Southern Co. and three Missouri utilities say that MISO has billed them more than $21 million in excessive transmission rates since Entergy joined the RTO in December 2013.
In a complaint filed Wednesday with the Federal Energy Regulatory Commission, the companies accuse MISO of imposing a “massive and unlawful increase” for power moved over the Entergy system (EL15-66).
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
It alleges MISO shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South. The companies allege the allocations violate MISO’s Tariff and FERC findings that — with the exception of certain multi-value projects — point-to-point export services are provided under a no-cost-sharing rule.
Bringing the complaint are Kansas City Power & Light’s Greater Missouri Operations Co., The Empire District Electric Co., Associated Electric Cooperative Inc. (AECI) and five Southern Co. affiliates: Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power.
MISO spokesman Andy Schonert said that FERC is already litigating these issues in docket EL14-19, a section 206 proceeding it initiated in February 2014. “These claims are not new,” he said. “We are reviewing the legal arguments and plan on responding.”
FERC began that case to investigate MISO’s proposed regional “through and out” rate. AECI complained that most legacy customers would be charged a zonal rate based on the facilities in their zone. Thus, the co-op argued, it and other customers would be forced to pay rates based on both the MISO and Entergy footprints after the Entergy integration into MISO.
The case was consolidated with others involving challenges by stakeholders in the South over what Entergy should be able to collect in rates as part of MISO. Many of those disputes have been under settlement talks over the last two years. Last week, FERC terminated settlement procedures and set the matter for hearing.
‘First of its Kind’
At the heart of the new complaint is the no-cost-sharing provision in MISO’s Tariff that, according to plaintiffs, acknowledges the historical lack of coordinated planning between MISO’s legacy region and the newly added Entergy region.
With no basis to conclude that customers of one region benefit from projects planned and constructed to benefit customers of the other region, the Tariff provides that any system-wide rate or cost allocation under the Tariff “shall be limited to the planning area where the project terminates,” the complaint states.
Because FERC noted that Entergy’s integration into MISO as the “first of its kind,” the commission justified the separation of the MISO footprint into two distinct regions for cost allocation and rate design purposes, the utilities say.
They asked FERC to force MISO to modify rate schedules in the Tariff related to export service and to ensure that the no-cost-sharing rule be applied to exports from the Entergy region.
The complainants said they were customers of Entergy prior to its MISO integration and hold long-term, point-to-point transmission service contracts with the company.
Charges for long-term, point-to-point transmission service under Entergy’s Open Access Tariff have jumped from $1.78/kW-month to $3.33/kW-month — an 87% increase — since Entergy joined MISO, they said.
“This massive rate increase should never have happened. It was and remains unauthorized,” the utilities said.
Increases Detailed
The utilities say much of the transmission is used to move wind generation from the Southwest to the Southeast.
When Entergy joined MISO, “it essentially became a continental divide stretching from the nation’s northern border to [the] southern border — with MISO as the gatekeeper for the delivery of Western wind to Southeastern loads and delivery of low-cost Southeastern base-load generation to Western loads,” the complaint states.
Southern said it has paid $8 million more in transmission fees between December 2013 and April 2015.
KCP&L said it paid Entergy $6 million a year for point-to-point transmission service prior to MISO but that the amount has nearly doubled since then.
AECI said it is paying $8.3 million a year, up 94% since Entergy joined MISO.
Empire District, based in Joplin, Mo., said only that its total costs for point-to-point transmission service on Entergy’s system have doubled.
Efforts to keep the Ginna nuclear plant operating has spurred a turf war between federal and state regulators who are conducting independent reviews.
The New York Public Service Commission asked the Federal Energy Regulatory Commission on Thursday for a rehearing of FERC’s April ruling that rejected the rate schedule in the reliability support services agreement between Ginna’s owner and the local distribution utility (ER15-1047). FERC ordered settlement and hearing procedures. (See FERC Rejects Ginna Rates, Orders Settlement Proceeding.)
The PSC said FERC interfered by “illegally” claiming jurisdiction over retail rates when it rejected some contract terms. It said FERC also violated the Federal Power Act when it declared the RSSA a reliability-must-run agreement and interfered with state jurisdiction to determine a mix of adequate resources.
“FERC ignores the fact that the NYPSC has an obligation under state law to ensure the availability of adequate generation facilities needed for reliability and is currently exercising its authority in reviewing the Ginna RSSA,” the New York regulators wrote. “The commission’s assertion of jurisdiction over the underlying terms of the RSSA would interfere with the NYPSC’s authority and represents an impermissible overreach of the commission’s jurisdiction.”
The RSSA was ordered by state officials and is scheduled to be retroactive to April 1, once approved by regulators. The agreement would cost about $175 million a year and be effective through late 2018. Ginna says it lost more than $150 million between 2011 and 2013.
Several other parties also asked FERC for clarifications or rehearings of the April order last week:
Industrial and commercial customers questioned the September 2018 end date for the RSSA, noting that a proposed transmission project that is supposed to make Ginna’s continued operation unnecessary may go online in early 2017. The intervenors suggest the RSSA should be terminated at that time and not after its entire term.
Entergy Nuclear Power Marketing asked that the issue of the initial term also be considered in the settlement process.
TC Ravenswood wants FERC’s review to expand into a consideration of the “price-suppressive” effects Ginna’s contract would have on the capacity market.
The Alliance for a Green Economy asked for another reliability study, saying information from discovery in the NYPSC proceeding undermines the rationale for the RSSA.
Exelon’s Constellation Energy Nuclear Group, Ginna’s owner, proposed a cost-of-service cap to address FERC’s rejection of the negotiated rates with Rochester Gas & Electric.
Entergy’s Arkansas and Mississippi operating companies will pay $32.6 million to their sister companies under a bandwidth recalculation report approved by the Federal Energy Regulatory Commission on Thursday (ER07-956).
The commission found in a 2005 order that the Entergy system was no longer in rough production cost equalization. It ordered an annual “bandwidth” true-up ensuring that no operating company would book production costs that are more than 11% above or below the system average production costs. (See FERC Bundles Entergy ‘Bandwidth’ Disputes for Hearing.)
Regulators in each state where the company operates have regularly challenged the annual bandwidth filings.
The updated report approved last week was based on 2006 test data and reflected adjustments on issues such as accounting for interim storm damage costs stemming from Hurricanes Katrina and Rita.
It will result in additional payments of $26.5 million by Entergy Arkansas and $6.1 million by Entergy Mississippi. The recipients are Entergy’s Gulf States Louisiana ($19 million), Louisiana ($2.7 million) and Texas ($10.9 million) operating companies.
The company said it will provide updated bandwidth payment/receipt amounts to wholesale customers on their next monthly bill.
Commissioner Colette Honorable, former chairman of the Arkansas Public Service Commission, did not participate in the ruling.
Gulf States Split
The case was complicated by Entergy Gulf States’ 2007 split into Entergy Texas and Entergy Gulf States Louisiana.
Texas industrial energy consumers filed a protest contending that because Entergy Gulf States was in operation in 2006, the allocation of payments due to the company should be addressed by state regulators in Texas and Louisiana.
The company balked, noting that because the Texas and Louisiana commissions adopted different allocation methods, Texas retail customers were credited $19 million more in 2007 bandwidth payments than were received.
FERC sided with the company, noting that Entergy Gulf States “no longer exists.”
FERC said that while Entergy Gulf States Louisiana and Entergy Texas did not exist in 2007, “it is only logical to place them into Entergy Gulf States’ position in order to ensure rough production equalization.”
OATT Revisions ‘Moot’
FERC also ruled last week in the matter of Entergy’s 2011 proposed revisions to its Open Access Transmission Tariff to comply with Orders 729 and 676-E. Because Entergy’s OATT was cancelled with its 2013 integration into MISO, Entergy’s compliance filing “is now moot,” FERC said (ER10-3357).
WASHINGTON — Federal regulators said Thursday they expect sufficient resources to meet peak electric demand this summer despite coal-fired retirements, a continued drought in the West and modest load growth driven by a rebound in industrial activity. Prices are expected to be moderate, based on forwards.
Staff of the Federal Energy Regulatory Commission gave a presentation at its Thursday meeting, shortly before the board of the North American Electric Reliability Corp. approved its summer reliability assessment.
NERC noted that the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) took effect in April 2015. “While this rule has contributed to retirement of fossil-fired generating units, the retirements have not caused the Planning Reserve Margin to fall below the NERC reference margin level,” the report said. “However, there is less resource capacity overall compared to previous summers to manage unforeseen challenges and severe conditions.”
Nationwide generating capacity has declined by about 3% since last summer, as retirements of coal-fired generation outweighed an increase of 2 GW of utility-scale solar and about 3.5 GW in wind generation, a 6% increase.
Fuel supplies should be plentiful as a result of recoveries in coal stockpiles and gas storage levels. FERC said coal stockpiles have been recovering since last summer but that a rise in natural gas prices could increase coal-fired generators’ output, creating the potential for supply problems in the Midwest.
The drought in California and the West, now in its fourth year, will reduce hydroelectric production, likely resulting in higher prices but no threat to reliability.
New York’s reserve margin has improved thanks to repowered generation capacity and lower forecast demand.
MISO’s projected reserve margin increased to 18% from 15% in 2014. NERC said MISO’s capacity resources are up by 4.5 GW “due to improved accounting for the reduction of contract path-limited resources in MISO South.”
Demand Response
Less demand response will be available in PJM, NYISO and ISO-NE. PJM expects 6,900 MW of DR, down by nearly 2,500 MW from a year ago, and less than half of the 14,800 MW that cleared in the Base Residual Auction in 2012, for the 2015/16 delivery year. “A substantial number of market participants traded away these positions in the RTO’s [incremental] auctions and through other transactions,” FERC said.
New York’s DR fell by 65 MW (5%) over last year while it dropped by 62 MW (9%) in New England. None of the three regions called on DR last summer.
The staff of the New York Public Service Commission issued a report Thursday predicting adequate supplies and moderate prices. Current wholesale prices are about 4.4 cents/kWh, compared to 6.6 cents/kWh a year ago, the PSC said.
Demand, Weather Forecasts
The Energy Information Administration has forecast a 2.9% increase in electric demand from last summer, which saw unusually mild weather.
The National Oceanic and Atmospheric Administration is forecasting warmer-than-normal temperatures in the West and Southeast and below-normal temperatures for parts of Texas and eastern New Mexico.
Only three hurricanes are forecasted, compared with the average of seven. “Generally speaking, hurricanes do not have the same level of impact on the U.S. energy markets as they did several years ago, due to the substantial shift in natural gas production from the Gulf of Mexico to onshore shale production,” FERC said.
Forward Prices
A 5.7% increase in natural gas production and a 71% increase in storage inventories versus last year caused a big drop in gas futures. The injection season began April 3 with 1.5 Tcf of natural gas in storage, up 79% from 2014 and only 4% below the five-year average.
NYMEX gas futures for June through August are averaging $2.89/MMBtu, a 40% drop from 2014. Peak power forward prices are down by an average of 24%, with a 34% drop for the ISO-NE internal hub.
The Algonquin Citygate near Boston showed the biggest drop among gas futures, recording a 46% reduction to $2.96/MMBtu. However, FERC said gas generators in ISO-NE could face challenges when Spectra Energy Partners begins maintenance and expansion of the Algonquin pipeline in late August.
In contrast, the commission said the rebuilt Susquehanna-Roseland 500-kV transmission line between Pennsylvania and New Jersey, which went into service May 11, should lower congestion in that region of PJM.
Market Changes for ISO-NE, CAISO
The commission also noted market developments since last summer.
ISO-NE is now allowing generators to submit up to 24 separate hourly offers in the next-day market and to update their offers during the operating day. Until the change in December, resources were limited to a single day-ahead offer and could not change their offers during the operating day. The RTO also will allow resources to submit negative offers as low as -$150/MWh to provide price signals to curtail generation when consumer demand is low.
The CAISO Energy Imbalance Market, which began in November, also will be entering its first summer test. The EIM enables balancing authorities in five Western states served by PacifiCorp to voluntarily take part in the imbalance energy portion of the ISO’s real-time market.
Meanwhile, SPP and MISO South will enter their second summer with full LMP markets.
New Focus for NERC
NERC said that although its assessment shows enough resources to meet summer demand, the transformation of the nation’s resource mix continues to present challenges. Natural gas now represents 40% the nation’s generation capacity.
“NERC continues to monitor key measures of essential reliability services to provide greater insight on how this trend is impacting reliability,” said John Moura, NERC director of reliability assessments.
In addition to continuing its efforts to ensure that the new generation mix provides adequate levels of frequency response, voltage control and inertia, NERC for the first time is considering operational risks from ongoing resource outages.
“The operational risk approach provides a much clearer picture of the actual capability of a given system within the bulk power system and its resilience against extreme weather and system conditions,” Moura said.
GLASTONBURY, Conn. — A hearing in a Connecticut suburb last week offered a microcosm of the energy debate swirling across New England as the region grapples with expanding its infrastructure to support its increasing reliance on natural gas-fired generation.
About 50 people attended a Federal Energy Regulatory Commission scoping meeting last week on the Atlantic Bridge Project, which would replace or expand 18 miles of the Algonquin pipeline in Connecticut, New York and Massachusetts. The project, which includes a section under the Connecticut River, would expand or replace three compressor stations and several metering and regulating stations, all in existing rights-of-way (PF15-12).
The meeting, one of a series being held in the three states, is part the initial phase of an environmental assessment.
Critics say the “segmenting” of the expansion review is a way to sidestep a review of the overall impact of the expansion. Developer Spectra Energy Partners says the project matches contractual supply commitments in place and does not need to address the region’s overall energy future.
Utilities, ISO-NE and most of the region’s governors strongly support proposals to build more pipeline capacity throughout New England to bring more natural gas from the Marcellus region.
Local landowners have complained of encroachments on their properties while environmentalists have invoked the national debates over climate change and natural gas extraction through fracking. (See related story, Another Meeting Day, Another Drama at FERC.)
Organized labor and business interests have aligned in support, citing jobs and economic development spurred by construction and lower electricity prices.
Nicholas Monacchio, representing the Laborers International Union of North America, highlighted the economy. “We are facing a real energy crisis due to the pipeline constraints … and the economic benefits will be a number of good-paying construction jobs,” he said.
“When businesses look around [and] they say ‘I can go to any state in the country and pay less for electricity than I do in Connecticut,’ we need to change that,” said Eric Brown, counsel for the Connecticut Business and Industry Association.
The counterargument came from the environmental community. “For every $1 million invested in gas, you get about five jobs. For $1 million in energy efficiency, you get 10 or 11,” said Martha Klein, communications chair for the Connecticut Sierra Club.
“These pipelines are meant for exports, which will lead to high profits for the pipeline, for which we are being forced to pay,” local environmentalist Dave Schneider said, referring to a proposed tariff by the states that would fund pipeline expansion through an assessment on electricity rates.
Spectra said the project will allow delivery of an additional 222,000 dekatherms of natural gas per day to Northeast markets by creating additional capacity between a receipt point on Algonquin’s system in Bergen County, N.J., and delivery points on the Algonquin and Maritimes systems.
In its latest monthly status report to FERC, Spectra reported that it has completed about 95% of the civil surveys required for the above-ground facilities and is conducting a geotechnical survey to document subsurface conditions and bedrock properties along the route. The geotechnical survey work will continue through the spring and summer of 2015.
The Department of Energy is expanding a biomass generation plant at its Savannah River Site. The project is part of the department’s Energy Savings Performance Contract program, in which a private company finances and maintains energy equipment in federal facilities. Framingham, Mass.-based Ameresco plans to boost output of the six-year-old 20-MW plant by 3 to 4 MW. Ameresco received $795 million to build the original plant, which uses forest residue and wood chips as fuel, and the expansion.
Oklahoma Sen. James Inhofe, chairman of the Environmental and Public Works Committee, thinks it’s time to scale back the Nuclear Regulatory Commission’s budget. He said despite a lower-than-expected workload associated with new nuclear licensing and review processes, the commission’s budget has grown by 34% and its workforce by 25% in recent years.
“The Nuclear Regulatory Commission’s workload is decreasing, but regulations are increasing,” he said. “I am going to work with Senate appropriators to adjust the NRC’s budget.”
Inhofe said breadth of the NRC’s oversight is also increasing in an effort to drive up the cost of compliance. “Every increase in regulation makes it more difficult for nuclear energy to remain cost competitive, and I believe there’s an intention to make that happen,” Inhofe said.
NRC Revising Rules on Foreign Ownership of Nukes in US
The Nuclear Regulatory Commission is changing how it assesses foreign ownership of U.S. nuclear reactors. Current regulations prohibit foreign ownership of commercial reactors, which is creating problems for some planned new commercial nuclear generating stations. Two years ago, NRC ruled that Unistar Nuclear Energy, a subsidiary of French company EDF, could not build a proposed plant on the site of the Calvert Cliffs nuclear station in Maryland.
The commission has told its staff to come up with a plan to set guidelines for partial foreign ownership. NRC said the decision to revise rules takes into account “the realities of today’s interconnected and global nuclear energy markets.”
The Department of Energy has given final approval for the Cheniere liquefied natural gas export terminal near Corpus Christi, Texas. Houston-based Cheniere plans to have the terminal in operation by 2018. The approval grants the facility a license to export up to 2.1 billion cubic feet of LNG per day for up to 20 years to countries with which the U.S. does not have a free trade agreement. Dominion Resources’ Cove Point LNG terminal in Lusby, Md., received the same authorization last week.
DOE Warns Against Chinese Investment in LNG Projects
The Department of Energy is advising American firms against allowing Chinese investment in U.S liquefied natural gas projects, an industry executive said. Freeport LNG chief executive Michael Smith said the warning has led to a dearth of gas export deals with China. “We were advised by the DOE to be careful who our customers were, because this is very political,” Smith said.
The Bureau of Ocean Energy Management approved Royal Dutch Shell’s oil-exploration plan in the Chukchi Sea after the company submitted a renewed and reinforced plan for its Arctic drilling operations.
“We have taken a thoughtful approach to carefully considering potential exploration in the Chukchi Sea, recognizing the significant environmental, social and ecological resources in the region and establishing high standards for the protection of this critical ecosystem, our Arctic communities and the subsistence needs and cultural traditions of Alaska Natives,” BOEM Director Abigail Ross Hopper said. “As we move forward, any offshore exploratory activities will continue to be subject to rigorous safety standards.”
Shell still needs to obtain other permits, including one to moor its equipment in Seattle’s harbor. A city-hosted hearing on that is scheduled for this week, but protests were already forming by Saturday.
The owners of a hydroelectric station said to have lured Henry Ford to open a vehicle assembly plant in St. Paul 90 years ago have won a regulatory victory forcing Northern States Power to keep buying its electricity.
The Federal Energy Regulatory Commission on Thursday denied an application by Northern States Power to terminate its mandatory purchase obligation from Twin Cities Hydro (QM15-2).
Twin Cities’ parent, Brookfield Renewable Power, has operated the 18-MW qualifying facility on the Mississippi River since taking it over from Ford Motor Co. in 2008. Three years later, Ford closed its St. Paul plant.
Northern States Power has been obligated to buy the power under the Public Utility Regulatory Policies Act. It provides for the termination of purchasing electricity from a facility if that facility has “nondiscriminatory” access to certain types of markets.
Northern States argued that it should no longer be required to buy Twin Cities’ power because the hydro facility has been selling energy into MISO’s wholesale energy markets since 2008.
But FERC adopted “rebuttable presumptions” that a facility with a capacity at or below 20 MW does not have nondiscriminatory access to markets. The commission has maintained that such smaller facilities are often interconnected at the distribution level and thus may “lack the same level of access to markets as those connected to transmission lines.”
These smaller facilities may face obstacles such as pancaked delivery rates and administration burdens to access distant buyers, FERC said.
FERC ruled that Northern States failed to demonstrate that the Minnesota hydro facility has non-discriminatory access to both energy and capacity markets.
Northern States “thus acknowledges that the Twin Cities [facility] cannot, at present, access the MISO capacity market. In contrast to the MISO energy market, [Twin Cities] has no history of sales into the MISO capacity market,” FERC said in its decision.
Twin Cities said because it is interconnected through Northern States’ distribution system, it would have go through the MISO interconnection process to obtain network resource interconnection service, at considerable cost and time.
“Here, both NSPM and Twin Cities note that transmission constraints exist which will directly impact the Twin Cities [facility’s] access to the MISO capacity market.”
The facility’s dam was completed in 1917 by the U.S. Army Corps of Engineers. Ford added the hydroelectric generating station in 1924.
Brookfield Renewable Power operates 7,000 MW of hydro capacity on 74 river systems in 14 power markets in North America, Latin America and Europe.
The Federal Energy Regulatory Commission proposed Thursday to change when it assesses annual charges to hydropower operators that are not state and municipal entities.
Under FERC’s Notice of Proposed Rulemaking, the charges would start two years from the effective date of a project license, exemption or amendment authorizing new capacity — not when construction on a project commences (RM15-18).
The revisions would eliminate the need for licensees and exemptees to notify FERC of construction starts in order to invoke the fees. FERC also no longer would have to contact the entities to elicit the information. FERC said the change would provide certainty as to when the charges would go into effect and improve administrative efficiency.
The fees apply to projects exceeding 1.5 MW of installed capacity. Original licenses, relicenses, exemptions and amendments adding new capacity generally require that construction start within two years of the date of issuance. The changes would mean that charges will be assessed regardless of when the projects commence or whether or not FERC has granted an extension.
FERC predicts that an average of 5.2 licensees and/or exemptees annually will end up paying annual charges before the start of construction. On average, 10.6 entities are expected to be affected by the rule change.
When Exelon announced its acquisition of Pepco Holdings Inc. last year, it appeared its biggest regulatory obstacles would be in Maryland and D.C., where most of Pepco’s customers reside. With last week’s narrow win in Maryland, and Delaware regulators unofficially on board, only the District’s approval is needed to complete the deal.
Opponents of the deal attacked Exelon on a number of grounds, including its record on renewable and distributed energy and the fact that it would give the company an 80% market share of the state’s distribution customers.
Exelon worked on several tracks, negotiating settlements with some of those who initially opposed the deal while working to undermine the arguments of those who remained in its way.
The three members of the Maryland Public Service Commission who voted to approve the deal said they were satisfied that ratepayers would receive benefits and that its 46 conditions protected against any harm. They acknowledged, however, “No merger is without risks.”
Here’s a closer look at how Exelon overcame the opposition.
Winning over Opponents
Exelon made concessions to win over several opponents, including commitments to fund energy efficiency programs, renewable generation, microgrid projects and public recreational projects.
Perhaps the most important wins were getting the support of Maryland’s Montgomery and Prince George’s counties, home to 536,000 ratepayers, nearly three-quarters of Pepco customers in the state.
The commission said the settlements with the counties indicated “strong public support for the merger.” It did not mention that the Montgomery County Council split from County Executive Ike Leggett, unanimously approving a resolution opposing the deal.
It wasn’t enough to eliminate all critics. The Sierra Club, the Clean Chesapeake Coalition, the Mid-Atlantic Renewable Energy Coalition, the Maryland, District of Columbia and Virginia Solar Energy Industries Association and Public Citizen all continued their opposition. The commission rejected their criticism, along with objections from state Attorney General Brian Frosh, the Maryland Energy Administration and the Office of Peoples Counsel.
Dominance
As the parent of Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power & Light, Exelon would provide electricity to more than 80% of Maryland’s electric distribution customers. While this was a source of worry to merger opponents, the commission majority said it viewed it as a positive.
“Having the three contiguous Maryland electric distribution utilities share common support functions among themselves and with Exelon’s other distribution utilities (PECO Energy in Pennsylvania and Commonwealth Edison in Illinois) presents a rare opportunity for Delmarva and PEPCO to leverage greater economies of scale, increase the potential for improved reliability performance with better cost control and benefit customers with synergy savings,” the commission said. “It also enables easier pooling of resources to restore service to customers more quickly following major storms, leading to greater resilience for our Maryland utilities. The sharing of ‘best practices’ among all six Exelon distribution companies will lead to day-to-day operational efficiencies and increased effectiveness, reducing operating expenses and ultimately rates for customers lower than they otherwise would have been.”
The commission noted that in D.C. and nine states, one investor-owned utility serves 100% of the customer base. Ten other states have utilities serving more than 80% of the customer base. “Yet there is no evidence in the record that either the D.C. Public Service Commission or the commissions of those other states have been less able to effectively regulate the reliable provision of electricity within their jurisdictions,” the majority said.
The commission concluded that the concern was “greatly overstated.”
“While we are cognizant of the impassioned concerns of the opposing parties and our dissenting colleagues, we find that these concerns are either not supported in the record or have been adequately mitigated by the conditions we set forth,” the majority said.
It noted that Nancy Brockway, a former New Hampshire regulator who testified against the merger on behalf of the Office of People’s Counsel, “conceded that she could not provide a specific example over the past two years since the Exelon–Constellation merger where the commission has experienced a loss of regulatory control over BGE.”
Opponents said that unlike Exelon, Pepco had no generation fleet to protect from policy and technological changes. But the commission noted that distribution companies also face risks from disruptive technologies such as net metering and distributed generation. “Already we have seen both Delmarva and PEPCO seek increases to their fixed customer charges in recent rate cases, in part to account for concerns regarding customers paying their ‘fair share’ of grid maintenance in the face of declining monthly usage,” the commission wrote.
The commission also dismissed concerns over the loss of Pepco’s voice within the PJM stakeholder process.
“All else equal, the merger will result in one less voting member in PJM senior committees, which given current PJM membership, would mean that there would be 527 voting members, rather than 528 voting members,” the commission said. It also noted that Exelon agreed to give $350,000 to fund the Consumer Advocates of PJM States, which represents state consumer advocates.
Exelon agreed to identify at least three independent third-party engineering firms qualified to conduct facility studies for interconnections to the transmission grid. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.) It also agreed to remain in PJM through at least Jan. 1, 2025, and allow access for the Independent Marker Monitor to review its demand response bids in the PJM energy, reserves and capacity markets.
Reliability Issue
Perhaps Exelon’s most powerful argument was Pepco’s lackluster reliability performance.
Pepco came under blistering criticism after widespread outages in the Washington region in 2010. A Washington Post analysis found that the company’s customers suffered longer and more frequent outages than their counterparts in other major cities. One 2009 survey found the company’s customers experienced 70% more outages than customers of large urban utilities and the lights stayed out more than twice as long. It was called the “most hated company in America” in 2011, based on the American Consumer Satisfaction Index.
BGE, PECO, and ComEd are all first quartile in their reliability metrics, the Maryland PSC noted.
“We find that this merger will enable Delmarva and PEPCO in Maryland to improve their reliability performance more quickly than they would without the merger. We find that their day-to-day normal weather outages will be reduced, their distribution infrastructure will be improved more quickly and at lower cost, and their ability to recover from outages following major storms will be improved, all because of the merger. These are the results that Delmarva and PEPCO customers have demanded and we find that approval of the merger will get them these results.”
OPC and the Maryland Energy Administration asserted that the commitments of improved reliability add little to the targets that Delmarva and PEPCO have already proposed with the commission.
In addition, an American Customer Satisfaction Index report released earlier this month ranked Exelon third from the bottom among at least two dozen investor-owned utilities. Exelon scored 69 on a 100-point scale, a drop from 75 last year.
Exelon dismissed the results. “This survey relies on perceptions of service but contradicts every objective measurement of how our utilities are actually performing,” Exelon said in a statement to the Chicago Tribune. The company said all three of its utilities “achieved outstanding performance last year in safety, reliability and customer satisfaction, ranking in the top quartile of peer companies for frequency of power outages and the top 10% of peer companies for safety.”
Ring Fencing
Another concern for opponents was the risk that Pepco’s customers could end up paying for any financial problems Exelon might experience as a result of its riskier merchant generation business.
The commission said it addressed those concerns by requiring even tougher “ring fencing” provisions than it had ordered in the Exelon-Constellation merger. Delmarva and PEPCO will maintain separate books, franchises debt and credit ratings for five years while maintaining an average equity ratio of 48%. Exelon agreed to put Pepco into a special purpose entity to provide additional insulation.
OPC contended the measures failed to fully protect Pepco customers, saying that an Exelon bankruptcy could harm Pepco’s credit rating, access to equity, and cost of equity and debt. It also contended Exelon’s reduced unregulated business will create pressure for Pepco to file more frequent rate cases and that ratepayers will suffer from the loss of “across-the-fence” competition between BGE and PEPCO on benchmark comparisons — a tool ratepayers can use to pressure underperforming utilities to improve.
The commission acknowledged “the evidence does demonstrate that one of Exelon’s motives for the merger is to diversify its financial reliance on volatile power market revenues from its generation business with the steady income stream from increased ownership of regulated distribution companies.”
But it said there was no evidence “supporting the assertion that Exelon will seek to loot the earnings from Delmarva and PEPCO to the financial detriment of those utilities.”
It also said merger opponents had failed to identify any instances in which the ring fencing provisions adopted in the Exelon–Constellation merger failed to protect BGE ratepayers.
How Much Money?
For some critics, the bottom line is how much of the merger’s benefits will go to ratepayers as opposed to shareholders.
The PSC said that as a result of the Exelon–Constellation merger, BGE achieved synergy savings of $15 million in 2012 and $23 million in 2013, above projections. Exelon estimates $37 million in synergy savings for Pepco’s Maryland utilities over five years.
“Given that we have conditioned approval of this transaction on an increased package of residential rate credits and customer investment funds (CIF) amounting to $109.2 million, this increases the ratio of direct rate credits/CIF funding versus allocated synergies to 2.95 — 13% higher than the ratio on which the Exelon–Constellation merger was conditioned,” the commission said.
The Maryland Energy Administration and OPC said Exelon’s concessions were only a fraction of the “windfall” its shareholders will receive. OPC estimated the “windfall” at $1.842 billion.
The commission said its rate credits and the CIF will equal 7% of the shareholder premium, “which is in the range of ratios on which we have conditioned other mergers in this state.”
WASHINGTON — The Federal Energy Regulatory Commission on Thursday gave preliminary approval to the second stage of its reliability standard to protect the grid from geomagnetic disturbances.
The commission’s Notice of Proposed Rulemaking (NOPR) would require grid operators to assess the vulnerability of their systems to a “benchmark” GMD event, which the North American Electric Reliability Corp. defined as a one-in-100-year occurrence. The standard (TPL-007-1, Transmission System Planned Performance for Geomagnetic Disturbance Events) would require planning coordinators and transmission planners to conduct the vulnerability assessments every five years. Entities that don’t meet performance requirements based on the assessments would be required to develop corrective plans to bring them into compliance (RM15-11).
NERC said mitigating strategies could include installation of hardware such as geomagnetically induced current (GIC) blocking or monitoring devices, equipment upgrades, training and operating procedures.
GMDs caused by solar storms are “high impact, low frequency” events. While the probability of a severe disturbance is low, it could have a severe impact on the grid, resulting in widespread blackouts and damage to equipment that could result in sustained system outages, FERC said.
Developing a GMD standard is “difficult work because we are working on a reliability threat that is not fully understood and as to which actual data are not readily and consistently available,” Commissioner Cheryl LaFleur said.
FERC ordered NERC to make changes to the proposed standard, including refining its definition of the benchmark event; requiring installation of monitoring equipment where there are gaps; and setting deadlines for completion of corrective actions. It also said it was considering shortening NERC’s proposed five-year period for full compliance.
Benchmark Event
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The commission said it was concerned with NERC’s “heavy reliance” on spatial averaging — averaging impacts based on a square area 500 km in width — for the definition of the benchmark event.
“The geoelectric field values used to conduct GMD vulnerability assessments and thermal impact assessments should reflect the real-world impact of a GMD event on the bulk power system and its components,” FERC wrote. “A GMD event will have a peak value in one or more location(s), and the amplitude will decline over distance from the peak. Only applying a spatially averaged geoelectric field value across an entire planning area would distort this complexity and could underestimate the contributions caused by damage to or misoperation of bulk-power-system components to the system-wide impact of a GMD event within a planning area.
“However, imputing the highest peak geoelectric field value in a planning area to the entire planning area may incorrectly overestimate GMD impacts. Neither approach, in our view, produces an optimal solution that captures physical reality.”
As an alternative, FERC said NERC could require entities to conduct GMD vulnerability assessments and transformer thermal impact assessment using both the spatially averaged reference peak geoelectric field value (8 volts per kilometer) and the peak geoelectric field value of 20 V/km as identified in NERC’s 2012 GMD report (“Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System”). Entities would be required to take corrective actions, using engineering judgment, based on the results of both assessments.
“That is, the applicable entity would not always be required to mitigate to the level of risk identified by the non-spatially averaged analysis,” FERC said. “Instead, the selection of mitigation would reflect the range of risks bounded by the two analyses and be based on engineering judgment within this range, considering all relevant information.”
Defining the benchmark event is essential to the standard, LaFleur said, “because if you don’t get the benchmark right, you’re not protecting against the right thing.”
Transformers
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The commission also ordered NERC to answer why it would not require qualifying transformers to be assessed for thermal impacts using the “maximum GIC-producing orientation,” saying it was concerned this could underestimate the impact of a benchmark GMD event.
“These concerns reflect in part the difficulty of replacing large transformers quickly, as reflected in studies, such as an April 2014 report by the Department of Energy that highlighted the reliance in the United States on foreign suppliers for large transformers,” FERC wrote.
LaFleur called for a strategy to allow quicker replacement of damaged transformers. “Those types of efforts will not just help the grid in its resilience to solar storms but against other risks such as physical security, cyber threats and major storms of all types,” she said.
Monitoring Devices
The commission said it also intends to change the standard to require installation of GIC monitors and magnetometers to fill any gaps in existing monitoring networks to ensure more complete data for planning and operational needs.
“To be clear, we are not proposing that every transformer would need its own GIC monitor or that every entity would need its own magnetometer,” FERC said. “Instead, we are proposing the installation and collection of data from GIC monitors and magnetometers in enough locations to provide adequate analytical validation and situational awareness.”
LaFleur noted that monitoring equipment is more widely available in other parts of the world than in the U.S. (NERC’s standard drafting team used field measurements from the magnetometer chain in Northern Europe in defining the benchmark event.) “That should not be the case,” she said.
The commission invited comment on whether it should adopt a policy governing recovery of the costs of the monitoring equipment.
‘Scaling’ Factor
The commission asked for comment on whether the impact of the “scaling” factor used in the benchmark GMD event definition to account for differences in geomagnetic latitude should be reduced. It noted studies indicating that GMD events “could have pronounced effect on lower geomagnetic latitudes.” For example, 12 transformers were reportedly damaged and taken out of service as a result of a 2003 GMD event in South Africa at -40 degrees magnetic latitude.
Deadlines
FERC also was dissatisfied that the proposed standard did not establish deadlines for developing or implementing corrective action plans. It said it plans to require corrective action plans to be developed within one year of the completion of the vulnerability assessment.
The commission also asked for comment on whether NERC’s proposed five-year implementation period could be shortened. NERC proposes a phased, five-year implementation period to allow time for entities to develop the required models, conduct vulnerability assessments and develop corrective action plans.
Comments on the NOPR are due 60 days after publication in the Federal Register.
