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
(Click to zoom.)
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.
Creditors of the 55-MW Fibrominn power plant — the first in the U.S. designed to burn poultry litter as its primary fuel — have won federal approval to gobble up the Minnesota facility from receivership.
The Federal Energy Regulatory Commission ruled Thursday that the transfer of the plant to Benson Power from owner PowerMinn is in the public interest (EC15-76).
Benson Power was formed to acquire and operate the plant and has no other FERC-jurisdictional or power-related assets. Benson is owned by CPV Biomass and several insurance companies that provided $202 million toward its construction. They include Prudential, The Hartford, John Hancock Life Insurance, Nationwide and Metropolitan Life.
The output of the Fibrominn plant will continue to be sold to Northern States Power under an existing 21-year long-term power supply contract.
The plant, located in Benson, Minn., was lauded after its 2007 opening for its practical use of waste from the region’s abundant turkey and chicken farms.
But it has struggled in recent years. Bird flu has reduced supplies of the odiferous biomass it turns into megawatts. The plant has had to turn to other bio material, such as wood chips.
Also making the plant less competitive are the drop in natural gas prices and improving economics for wind and solar energy. Two years ago, Fibrominn began defaulting on debt.
FERC found that the transfer of the plant will not result in adverse effects on competition or rates, nor inappropriate cross-subsidization of a non-utility asset. The commission said Class B and Class C members — largely consisting of the insurance companies — hold only a passive interest.
The insurance companies have indirect interests in other power ventures. Prudential, for example, has non-controlling interests in the 150-MW Elk River Wind Farm in Kansas. And Metlife has a stake in operations including the 32-MW Long Island Solar Farm.
The Class A holder, which will serve as sole management member of the plant, is CPV Biomass, which is owned by Silver Spring, Md.-based Competitive Power Ventures.
FERC said CPV does not own or control other generation in the MISO territory.
However, the former owners of PowerMinn’s parent company, the Herrick family, cried foul. They filed a motion to intervene in the transfer application, contending that they are owed payments related to production tax credits involving the plant. They expressed concern that their rights could be extinguished by the transaction.
But FERC ruled that the Herrick protest was outside of the scope of the proposal before the commission.
Future Viability?
As of January, the plant owed creditors nearly $240 million, while its fair market value was under $79 million. The application filed with FERC does not elaborate on the strategy Benson will take to improve the plant’s viability.
While designed to burn poultry litter for up to 90% of its fuel needs, the plant has relied mostly on more expensive wood chips. The Minnesota bird flu crisis has reportedly resulted in the deaths of nearly 4.2 million turkeys and nearly 1.6 million chickens since March.
Major poultry producers are making deliveries “when they can” from uninfected farms, the plant’s manager told the Associated Press.
Donald Atwood, a CPV vice president, told the AP his company has a multi-year contract to manage the facility for the note-holders.
“I don’t know what the lenders have in mind for the future,” Atwood said, adding that he expects to continue to burn poultry litter.
“We’ll adjust our fuel percentages based on market conditions,” he said. “I’m highly confident that the project will be successful.”
GROTON, Conn. — States and federal regulators need to keep consumers in mind when picking jurisdictional fights over control of the electric industry, Federal Energy Regulatory Commissioner Tony Clark said last week.
Clark
“We can’t have a war between FERC and the states on some of these issues and get consumers stuck in the middle,” he said in a keynote speech to the New England Energy Conference and Exposition on Wednesday.
“There has been an almost soft form of reregulation in parts of the market. We should acknowledge that that’s happening. We should also acknowledge that that may have an impact on other goals,” he said.
“We don’t want to be caught in the worst of all worlds, which in my mind is having just high enough capacity prices where we get everybody pretty darn well mad at us — we’ve got the congressional delegations mad at us; we’ve got governors mad at us; we’ve got consumer advocates made at us — and yet at the same time [the prices are] set at such a point that they may be being undermined by other things that are going on, so you’re not getting the investment that those prices would otherwise encourage because you have other state or local public policies that are undercutting that or maybe suppressing prices in some way.”
In addition, federal courts have been refereeing jurisdictional fights. Courts have struck down on constitutional grounds efforts by Maryland and New Jersey to sign contracts with new generators. (See Rebuffed by Courts, CPV Seeks FERC End-Around.) Meanwhile, FERC is hoping the Supreme Court will overturn a ruling voiding its pricing rules for demand response as an intrusion on state authority. (See Supreme Court Agrees to Hear Demand Response Appeal.)
And FERC Chairman Norman Bay has warned states seeking to implement rights of first refusal on transmission development that they may be interfering with interstate commerce. (See FERC Rejects Rehearing Request on SPP Order 1000 Filing.)
Clark pleaded for a cease fire. “There’s plenty of tools that FERC has and there’s plenty of tools that states have to go to war with each other,” he said. “In my mind it’s … a game you can’t win. So you can’t play it.”
Clark also talked about the commission’s unenviable role regarding the Environmental Protection Agency’s proposed Clean Power Plan.
“It’s not our rule,” he said. “And yet just about every potential negative impact that folks have brought up are things that are squarely within FERC’s wheelhouse. Whether it’s related to the need for infrastructure siting because of the push towards natural gas; whether it’s potential market issues that come up at the seams in markets …; whether it’s reliability issues, which in certain regions of the country we’re very concerned about — all of those are squarely within FERC’s wheelhouse.
“So whether we want the issue in front of us or not, the issue wants us.”
Eversource Energy customers will see a 35% drop in electric generation charges, to 8.228 cents/kWh from 12.629 cents/kWh beginning in July.
United Illuminating residential generation charges will decrease about 31% to 9.18 cents/kWh from 13.3108 cents/kWh.
For a typical customer who uses 750 kWh, the drop in generation prices will save more than $30 a month. The rates go into effect July 1 and last until Dec. 31.
New Haven officials and the current owners of the defunct English Station power plant want UIL Holdings to pay for a large share of the plant’s cleanup. Uri Kaufman, a representative for Asnat Realty of New York and Wilmington, Md.-based Evergreen Power, appeared before state utility regulators to comment during a hearing on the proposed $3 billion acquisition of UIL Holdings by Spanish energy giant Iberdrola.
Kaufman urged the Public Utilities Regulatory Authority to require the two merger partners to create a $60 million fund to pay for the cleanup of English Station, which sits on a 9-acre island in the Mill River. The site is riddled with carcinogens, heavy metals and other contaminants. United Illuminating, a UIL Holdings subsidiary, closed the plant in 1992 and paid Quinnipiac Energy of Killingworth $4.25 million in 2000 to assume ownership of the power plant and put $1.9 million in escrow to pay for cleanup.
Release of Trove of Emails Results in Another Public Hearing for Refinery
The Department of Natural Resources and Environmental Control extended a comment period until June 9 on proposed water use and wastewater permits for the Delaware City Refinery after previously undisclosed emails and records were released. The refinery still uses a 1950s-era system of withdrawing cooling water from the Delaware River and discharging wastewater that environmentalists say causes huge losses of aquatic life. PBF Energy, the refinery’s owner, says that upgrading the cooling system would cost $300 million, more than the purchase price of the facility.
In addition to the records that were released, the state denied a request from The News Journal for several hundred more documents, citing confidentiality rules. They include communications sent from Gov. Jack Markell’s office and his private email accounts.
“It appears if you want to secretly work out a deal on environmental issues in Delaware without any public input, the best approach may be to first break the law, and then negotiate secretly for what you want with the assurance that the public cannot be informed or involved,” said Dave Carter, conservation chair for Delaware Audubon.
Pence Signs New Energy Bill Releasing Utilities from Mandates
Pence
Gov. Mike Pence signed a new energy efficiency law that allows utilities to set their own conservation goals, rather than making them meet state mandates. The law also allows utilities to charge ratepayers to fund the programs. Environmentalists say the law, with its less-stringent oversight, will make it harder to attain Environmental Protection Agency-mandated emissions reductions.
The Utility Regulatory Commission rejected Duke Energy’s plan to upgrade its grid at a cost to ratepayers of $1.9 billion over the next seven years. Duke’s customers would have experienced a 1% rate increase each year, from 2016 through 2022. Ratepayer advocates said Duke’s plan contained provisions not covered by the 2013 grid modernization investment recovery law, such as $48 million for vegetation management, a $1.5 million customer contact computer program and a $177 million smart meter program.
Duke said it would file a revised plan. “We’re still reviewing the order and considering our options, but we remain committed to making critically needed investments to modernize our system for the benefit of our customers,” the company said in a statement. “This is one of the first times this new law has been interpreted, and it’s being clarified for all Indiana utilities at the commission and in the Indiana Court of Appeals.”
Chinese Company Building 28-MW of Wind Energy Plants
HZ Windpower, a wind energy subsidiary of China Shipbuilding Industry Corp., is planning to build 28 MW of wind facilities in the state. Lt. Gov. Kim Reynolds met with HZ Windpower executives last week and said the 14 2-MW turbines could be the first of many more for the state.
The turbines will be part of the “Community Wind” projects and will be in Creston, Dyersville, Mason City and Perry.
Canada Pledges to Cut Emissions by 30% by 2030, Still Behind US Goal
Aglukkaq
Canada announced it has set a goal to cut greenhouse gas emissions by 30% by 2030 and said it will set new regulations for various industries, including electric generation. A 30% reduction compares to the stated U.S. goal of 26% to 28% by 2025. Both countries are submitting their emission-reduction goals to the U.N. for a climate change agreement due to be signed in December in Paris.
“Canada’s ambitious new target and planned regulatory actions underscore our continued commitment to cut emissions at home and work with our international partners to establish an international agreement in Paris,” said Leona Aglukkaq, Canadian Environment Minister.
A bill that encourages the development of community solar projects was signed by Gov. Larry Hogan last week. The bill creates a three-year pilot program allowing community solar projects and will collect information on the projects and determine their impact on the state.
Community solar projects allow multiple owners to invest in a large-scale solar project and offset a portion of their electric bill with a share of the renewable power. Until now, such large projects were mostly the domain of utilities and investment companies.
Enbridge Agrees to $75 Million Settlement on Kalamazoo Spill
Enbridge has agreed to pay $75 million to settle legal claims related to a 2010 pipeline spill of more than a million gallons of crude oil into the Kalamazoo River. About $30 million will be spent on wetland and river restoration. The agreement, between the company and the state Department of Environmental Quality, also includes removing a dam on the river and improving recreational access on the river.
The company spent more than $1 billion in cleanup costs, but state officials acknowledged that not all of the oil residue was collected. The spill of heavy crude oil extracted from Canadian oil sands affected nearly 40 miles of the river and more than 4,000 acres along the river banks.
The company has yet to settle penalties with the Environmental Protection Agency. It paid a $3.7 million fine imposed by the National Transportation Safety Board for lax safety management.
State Gives Thumbs-up to Loop Line’s Early Completion
ITC Holdings has completed the third and final phase of its 138-mile “Thumb Loop” 345-kV line in the state about six months ahead of schedule. The line, capable of supporting capacity of up to 5,000 MW, wasn’t expected to be completed until late this year.
ITC said the loop line will meet the maximum identified wind energy potential in the state’s Thumb region as well as boosting regional system reliability and wholesale market competition. Gov. Rick Snyder has pointed to the line’s benefits in helping agricultural processing operations and for bringing more renewable energy to the grid.
Phase 3 comprises 56 miles of line in Huron and Sanilac counties and the Banner substation, near Sandusky. The original phase, begun in 2011, was 62 miles of lines and two substations in Tuscola and Huron counties. Phase 2 involved 20 miles of lines and substations in St. Clair and Sanilac Counties.
Lawmakers Ponder Cutting Solar Subsidies; Company May Fail
A solar cell manufacturer that failed to meet a hiring goal that was a condition of getting state loans could go out of business if state support is cut. Silicon Energy of Mountain Iron failed to hire the 25 solar panel production jobs it promised when it began getting the first of two loans totaling about $7 million. It has 11 workers now. A bill that passed the House would strip the subsidies.
“The Made in Minnesota solar program is a very expensive way to reduce pollution and create jobs,” Republican state Rep. Pat Garofalo said. Silicon Energy President Gary Shaver said low-cost solar panels from China “destroyed the market for us.”
Results of a two-year experiment with 400 customers of the New Hampshire Electric Cooperative will be announced soon. The distribution company that serves 80,000 customers in the central part of the state tested three new models for pricing electricity using smart meters.
Customers were divided into three groups: one remained on the standard rate per kilowatt-hour paid by all members of the co-op but with an in-home display that showed how much power was being used at any time of day in the home. The second group was on a “time of use” rate, with lower rates for off-peak hours, higher rates for peak hours and variations for each season. The third group had lower on-peak and off-peak rates but was charged a “critical peak rate” on the hottest days of the year, when system demand in New England was at its highest.
The experiment ran from November 2012 to November 2014. Thus far the results confirmed that the more information consumers get about their electricity usage, the less they use. A report will be issued in the summer.
A renewable energy fund is facing a cut of $50 million by legislators. A House bill seeks to slash that funding as part of an effort to make up for shortfalls in other areas of the budget. Currently, the fund provides rebates for homeowners and business owners installing solar panels. The fund is financed by utility companies, which must pay into the fund if they fail to buy a mandated number of renewable energy credits.
The Renewable Energy Fund rebate program began about six years ago and pays out an average of $4,300 per installation. The $50 million cut would nearly wipe out the fund’s budget for the next two years. The threat of the cut comes at a time when federal solar tax credits are falling from 30% to 10%, further squeezing the state’s new solar industry.
“New Hampshire has huge untapped potential,” said Kate Epsen, executive director of the New Hampshire Sustainable Energy Association. “People are trying to position themselves strategically.”
A state Senate committee passed a resolution calling for Congress and President Obama to reinstate the production tax credit for wind energy. The resolution now goes to the Senate for a vote. The production tax credit provided incentives for wind energy production but expired at the end of 2013. Supporters of the resolution said its expiration “wreaked havoc” in the state’s wind energy industry.
The state has been wrestling with wind energy issues for years. Most recently, the Board of Public Utilities rejected a proposed offshore wind farm that had been awarded $47 million in federal funding as too costly. In response, the state Senate passed a bill forcing the BPU to approve the project. The project still has not gained final approval.
Gov. Andrew Cuomo’s administration released an environmental review that is the penultimate step for a ban on hydraulic fracturing for natural gas in New York. The state Department of Environmental Conservation released a final version of the roughly 2,000-page document, known as the Supplemental Generic Environmental Impact.
“The final SGEIS is the result of an extensive examination of high-volume hydraulic fracturing and its potential adverse impacts on critical resources such as drinking water, community character and wildlife habitat,” DEC Commissioner Joseph Martens said in a statement. “We considered materials from numerous sources, including scientific studies, academic research and public comments, and evaluated the effectiveness of potential mitigation measures to protect New York’s valuable natural resources and the health of residents.”
Last December, the Cuomo administration announced it would ban high-volume fracking, citing concerns about its impacts on human health.
Entergy, the owner of the Indian Point nuclear plant, is planning to clean up several thousand gallons of oil that may have spilled into the Hudson River after a transformer exploded May 9. A fire suppression system extinguished the fire, but the plant shut down, according to a spokesman for the U.S. Nuclear Regulatory Commission.
The fire didn’t cause the release of any radiation and didn’t pose a threat to workers or the public, according to a statement on Entergy’s website. The nuclear plant is just 50 miles from midtown Manhattan.
McAuliffe Announces New Energy Efficiency Goals for State
Gov. Terry McAuliffe announced ambitious energy efficiency goals for the state, vowing to reduce consumption by 10% by 2020, two years earlier than the previous goal. He also announced the formation of a new group, the Executive Committee on Energy Efficiency, to help the state attain the goal.
Some studies show Virginia lagging behind other states in energy efficiency programs. Dawone Robinson of the Chesapeake Climate Action Network applauded McAuliffe’s plan. “Increasing energy efficiency is our lowest-hanging fruit when it comes to reducing the carbon emissions fueling severe weather and sea level rise,” he said.
Enbridge Plans to Bolster Oil Sands Pipeline Slowed By Zoning Board
A local zoning board in Dane County has held up plans by energy giant Enbridge to triple the capacity of a crude oil pipeline from northern Wisconsin to markets east in Chicago. The six-year-old pipeline, known as Line 61, delivers oil extracted from Canadian oil sands and would carry more crude oil each day than the proposed Keystone XL pipeline.
The Dane County Zoning and Land Regulation Committee told Enbridge it would need more pipeline insurance before it would consider granting the request to increase capacity. Enbridge says it has enough insurance already and argued that the zoning board is overstepping its authority by taking on responsibilities of federal regulators.
The Federal Energy Regulatory Commission said last week that the single-step discounted cash flow (DCF) analyses that it formerly used are adequate to support rate complaints made before it changed the rules.
FERC made the assertion in denying requests by Xcel Energy and the New England Transmission Owners that it reconsider its orders establishing hearing and settlement judge proceedings in return on equity (ROE) disputes.
The rulings involved complaints that sought to reduce the New England TOs’ ROE (EL13-33 & EL14-86-001) and two ROE disputes between Xcel’s Southwestern Public Service Co. (SPS) and Golden Spread Electric Cooperative (EL13-78 & EL12-59).
Opinion 531
Golden Spread has two agreements with SPS: a power purchase agreement with a 10.25% return on equity (ROE) and a transmission agreement with an 11.27% ROE. In April 2012, Golden Spread filed a complaint with FERC, using a single-step DCF analysis to show that SPS’s ROE in both agreements should be reduced to 9.15%. The co-op filed another complaint in July 2013 using more recent data but again asserting the 9.15% ROE.
Xcel and the New England TOs contended that the old, one-step DCF methodology is not valid because of the commission’s June 2014 ruling Opinion 531, which changed its DCF methodology to a two-step process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. The commission issued Opinion 531 on the same day it ordered the hearing proceedings in the Golden Spread complaints. (See FERC Splits over ROE.)
FERC disagreed, saying that both Xcel and the New England TOs misinterpreted the commission’s findings regarding the one-step DCF methodology in Opinion 531. The commission did not find that the one-step DCF methodology was inadequate, FERC said Thursday. “Rather, the commission found that, given the evolution of the electric industry, it had become more appropriate to use the two-step DCF methodology to determine what ROE to set as a public utility’s ROE.”
“That the two-step DCF methodology ‘is preferable to the one-step DCF methodology’ for ultimately setting a public utility’s ROE does not preclude the commission from relying on DCF studies using the one-step DCF methodology” in complaints made prior to Opinion 531, FERC said.
Golden Spread vs. SPS
FERC also disagreed with Xcel’s assertion that Golden Spread’s July 2013 complaint only served to extend the maximum 15-month refund-effective period for its April 2012 complaint. Golden Spread filed the later complaint the day before the first complaint’s refund period expired.
“Golden Spread filed two separate complaints, based on different facts, thereby commencing two separate proceedings,” FERC said. It noted that though both of Golden Spread’s analyses determined a 9.15% figure, this was a median ROE produced from different ranges: 7.51 to 10.59% in 2012 and 6.37 to 11.51% in 2013. Therefore, “we expect the parties in this case to litigate a separate ROE for each refund period,” the commission said.
New England TOs
The New England TOs had cited the use of the single-step DCF as one of their grounds for seeking rehearing of FERC’s orders on two ROE challenges: the commission’s June 2014 order on a December 2012 complaint (EL13-33) and its November 2014 order on a July 2014 complaint filed by a different group of complainants (EL14-86).
Both complaints alleged that the New England TOs’ 11.14% base ROE was unjust and unreasonable.
In addition to dismissing objections to the single-step DCF analysis, the commission also rejected the New England TOs’ argument that the commission erred in EL13-33 because the ROE that the complainants sought to change was already within the commission’s “zone of reasonableness.”
The commission disagreed. “The zone of reasonableness produced by a DCF analysis does not create a zone of immunity for a utility’s ROE. Showing that a utility’s existing ROE is unjust and unreasonable ‘merely requires showing that the commission’s ROE methodology now produces a numerical value below the existing numerical value.’ Therefore, the commission appropriately concluded that [the complainants] made a prima facie showing that New England TOs’ 11.14% base ROE might be unjust and unreasonable.”
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).
