State and RTO officials have had two weeks to digest the Environmental Protection Agency’s final power plant carbon emission rule and the battle lines — and paths to compliance — are developing.
While states in the Northeast say they are well on the way to compliance, many in the South and Midwest have already joined in the first set of legal challenges — even as other officials in the Midwest consider carbon trading plans.
Change in state carbon emission targets from draft rule to final
The 15 states who joined in the request for a stay included half of those in SPP, six of those in MISO and five of those in PJM. No Northeastern states were among them. More states may join once the clock on legal challenges begins with publication of the rule in the Federal Register.
PJM, meanwhile, remains concerned about the time required to build transmission to deliver wind power to eastern load centers.
RTO Insider’s follow-up coverage of EPA’s Clean Power Plan includes reports from throughout the Eastern Interconnection:
PJM is concerned that the Environmental Protection Agency was too optimistic about how quickly it can add transmission and how much help its states will receive from wind resources in meeting the Clean Power Plan.
The RTO released a report on the impact of the proposed carbon rule on July 31 — days before EPA issued its final rule — that challenged the agency’s assumptions on the pace of both generation additions and transmission expansion.
“Under some CPP scenarios — particularly in the early years of compliance — generators could retire at a faster rate than replacement generation, or the new transmission needed to solve reliability problems, could be built. These scenarios potentially could put a much greater strain on the existing transmission system,” the report said.
The report, the second of two produced in response to a request from the Organization of PJM States Inc. (OPSI), builds on the economic analysis from PJM’s first report for the group to determine the range of transmission that would be required under three scenarios for coal plant retirements: 6 GW, 16 GW and 32 GW.
“Generation needs could exceed available resources by 2024 in a 32-GW at-risk future scenario, in which units retire evenly across each year from 2020 to 2029. If retirements occurred earlier in the 2020-2029 compliance period, resource adequacy needs could exceed resources for a 32-GW scenario by 2022 and by 2028 under a 16-GW at-risk scenario,” the report said.
Final Rule Lessens Reliability Concerns
PJM COO Mike Kormos said Monday that several changes in the final rule — relaxing the initial deadlines by two years, creating an easier path to interstate trading and the inclusion of a reliability safety valve — made the regulations less of a threat to reliability. He said the RTO will likely run additional sensitivity analyses based on its observations and requests from states.
But Kormos said it was too soon to tell how the changes in the final rule would affect the conclusions PJM made in the July 31 report.
“We’ll look to do some refinements and some additional scenarios,” he said in an interview. “I can’t tell you definitively whether anything is going to dramatically change.”
Kormos said that while some states face tighter or looser emission caps under the final rule than under the draft, “they were not drastically different in aggregate.”
‘Informal’ Discussions on Trading
Kormos said PJM has thus far had only “informal” discussions with stakeholders about the prospect of interstate emissions trading as a compliance measure. “I’m unware of any specific initiatives,” he said. (See related story, Final Clean Power Plan More Suited to Carbon Trading, Experts Say.)
PJM already collects data on emissions and renewable energy credits for states and others under its Generation Attributes Tracking System and stands ready to perform a similar role under an interstate CO2 trading program. “If there’s a desire, I’m sure we would be open to having those discussions,” Kormos said.
Timelines
Between the submission of state implementation plans and EPA’s interim deadline, PJM said, generation owners would need to announce retirement decisions, replacement generation would have to be identified, reliability violations must be identified and transmission solutions developed, designed, sited and constructed.
“Once the PJM board approves transmission upgrades, historical experience shows that the pace at which transmission can be completed can range from five years (the Carson-Suffolk 500-kV line) to more than 16 years (the Wyoming-Jackson’s Ferry 765-kV line),” the study said. “Moreover, if a number of large-scope transmission projects are required across the United States, the lack of equipment availability could increase lead time substantially.”
Moving Target
The location and size of both retiring generators and replacement resources will be uncertain for some time and will “remain a moving target” for transmission planners, the report said.
It notes that generation interconnection projects typically enter the queue three to five years before their desired in-service dates and that more than 80% of projects that enter the queue withdraw before reaching commercial operation.
“A successful replacement resource would have to anticipate the retirement of at-risk generators,” the report said. “Otherwise, the grid will face the likelihood of significant delays between the retirement of at-risk generators and the completion of replacement resources. Reliability studies that look more than three years out must hypothesize build rates, locations and fuel sourcing.”
The study identified reliability violations requiring new transmission in areas where deactivating coal-fired generators are less likely to be repowered with natural gas, such as those far from pipelines.
More Challenging than MATS?
PJM said its experience with EPA’s Mercury and Air Toxics Standards (MATS) “suggests that build rates may not ensure that the necessary transmission will be in service before retirements occur.”
Most transmission improvements resulting from MATS were upgrades to existing facilities. In contrast, the carbon plan will likely require more greenfield transmission to connect wind resources in western PJM to load centers in the eastern portion of the RTO.
Because they require new rights of way, greenfield projects require more time to reach commercial operation.
How much states will count on renewable resources to meet their compliance goals is a big source of uncertainty, PJM said.
“The EPA renewable portfolio standard reliance assumptions differ from PJM’s historical queue experience,” the report says. “It is likely that all the wind-powered facilities that the EPA anticipates to be available will not make it online as shown in the economic analysis. Moreover, historical transmission build-out rates are not likely aggressive enough to meet the EPA’s wind penetration rate assumptions.”
“Scenario studies suggest that overloads clustered along specific corridors would require additional review to assess the feasibility of certain types of upgrades. That, in turn, would impact both the cost of solving identified reliability criteria violations and the ability to complete construction of facilities in time to simultaneously comply with the CPP while avoiding those reliability violations.”
A Maryland circuit court judge Wednesday declined to stay Exelon’s acquisition of Pepco Holdings Inc. while it considers an appeal from the state’s Office of People’s Counsel.
In June, OPC appealed the Maryland Public Service Commission’s 3-2 decision to approve the $6.8 billion deal in Queen Anne’s County Circuit Court. It was joined by Public Citizen, the Sierra Club and the Chesapeake Climate Action Network. In late July the parties jointly filed a motion to stay the deal while the appeal process continued.
“It’s a denial of the motion to stay, but our appeal obviously goes forward,” People’s Counsel Paula Carmody told the Baltimore Business Journal.
“We are pleased the judge agreed with our view that the requests for a stay had no merit,” Exelon spokesman Paul Adams said in a statement.
Along with the Maryland PSC, regulators in Delaware, New Jersey and Virginia have approved the acquisition, as has FERC. Only the D.C. Public Service Commission has yet to rule on the deal. Exelon has said it expects the deal to close by the end of the third quarter this year.
Carmody told the Journal that oral arguments in the appeal are scheduled in December and acknowledged this would mean that arguments could take place after the deal is closed.
Iberdrola USA has refiled its acquisition plan for UIL Holdings with Connecticut regulators, attempting to address objections that scuttled the previous plan.
The plan, filed Friday with the state Public Utilities Regulatory Authority, promises more ratepayer benefits, increased employment in Connecticut and protections for the state subsidiaries from any financial difficulties encountered by Iberdrola’s other U.S. or international operations (15-07-38).
The lack of “ring-fencing” protection for the electric distribution company, United Illuminating, in the original February filing was one of the deal-killers that PURA staff cited in its draft decision that recommended rejection of the deal. (See Iberdrola Withdraws UIL Acquisition; Plans to Refile.) “Ring-fencing measures will protect the UIL utilities from unforeseen potential future events affecting the IUSA affiliates or their other affiliates, including utilization of a special purpose entity and a ‘Golden Share,’” the filing states. The Golden Share would be held by an independent director from outside the company who would essentially hold veto power over any voluntary bankruptcy petitions filed by UIL.
The proposal also says the utility units will be rated by the credit rating agencies and will issue their own debt. “As a result, UIL and the UIL utilities will be maintained as separate entities and be afforded with important financial and bankruptcy protections.”
“With this new application, we believe that we’ve effectively addressed all of the points of concern that were outlined in PURA’s draft decision relating to the original application,” James P. Torgerson, UIL’s president and CEO, said in a statement. “We are fully prepared to move forward in this process.”
Other proposals to smooth the approval include:
Customer rate credits of $20 million in the first year following the closing, or greater amounts spread over longer time periods;
A new management position drawn from the ranks of existing local management and based in the state, titled president of Connecticut operations;
Connecticut operations would be headquartered in the state for at least seven years;
No involuntary terminations, except for cause or performance, in Connecticut for at least three years following closing of the deal, along with a commitment for 150 new employees;
A freeze of electric distribution rates until Jan. 1, 2017; and
$6 million over three years for the state’s clean energy initiatives.
Under Connecticut law, regulators have 120 days to act on the filing.
The Environmental Protection Agency’s final Clean Power Plan provoked howls of outrage from coal interests, praise from environmentalists and cautious optimism from regulators and grid operators.
The rule was a mixed bag for the nuclear industry but a win for wind and solar power advocates. Natural gas proponents were miffed by an unexpected change that means they may benefit less than expected from coal’s decline.
On Wall Street, traders punished coal companies while many utility stocks were up modestly.
Below is a summary of the initial reactions to the final rule.
Coal: Rule is Illegal
“Even in the face of damning analyses and scathing opposition from across the country, EPA’s final carbon rule reveals what we’ve said for months: This agency is pursuing an illegal plan that will drive up electricity costs and put people out of work,” said Mike Duncan, president and CEO of the American Coalition of Clean Coal Electricity.
Arch Coal, whose shares plunged 90% on bankruptcy fears, echoed the sentiment.
“The administration seems increasingly desperate to salvage an ill-advised and poorly designed rule which won’t work, won’t pass muster with states and won’t stand up to legal scrutiny,” said Deck Slone, Arch’s senior vice president of strategy and public policy.
Regulators, RTOs: Cautiously Optimistic on Reliability Safety Valve
Federal Energy Regulatory Commission Chairman Norman Bay, a Democrat, praised EPA’s “willingness to consider potential reliability concerns and its efforts to address those concerns by adding time and flexibility for compliance, adopting a reliability safety valve and requiring state plans to be reviewed for reliability.”
Republican Commissioner Tony Clark also praised EPA’s engagement but struck a less optimistic view, warning of “the difficult path that now lies ahead.”
“The regulation makes it likely consumers will be required to bear the burden of stranded costs of investments forced to retire years before the useful life of the asset has expired,” he said. “Whatever EPA believes are the environmental benefits of this regulation, it cannot be said that it will be easy or inexpensive. Such is the stuff of unicorns and leprechauns.”
The National Association of Regulatory Utility Commissioners said it would conduct a detailed review to determine how the rules will affect states. “Although NARUC has taken no position on whether the EPA should establish these rules, we have stated that if the agency does issue rules, it should provide states with maximum flexibility to respond,” President Lisa Edgar said.
MISO said it is conducting a regional and state-by-state analysis of the rule. “We will work now on modeling the final rule and run the analysis to help stakeholders better understand compliance options,” the RTO said in a statement.
PJM said it will analyze the reliability safety valve EPA offered in response to grid operators’ concerns.
Environmental Groups Generally Pleased
Environmental groups were generally pleased, though some expressed disappointment with the delay in the initial deadlines, which were pushed from 2020 to 2022.
“For too long the United States has failed to take action on climate change, held hostage by climate deniers in Congress and by industry laggards unwilling to limit pollution that threatens the U.S. and global environment,” Conservation Law Foundation President Bradley Campbell said. “Now we finally have a plan that’s right for our environment and our economy, encouraging states to work together to reduce carbon emissions on a national scale.”
Jordan Stutt, a policy analyst at the Boston-based Acadia Center, said the experience of states participating in the Regional Greenhouse Gas Initiative has shown that a market-based program can reduce CO2 emissions while driving economic growth and innovation. “EPA has recognized this potential for low-cost emissions reductions and has designed the Clean Power Plan in a way that supports widespread implementation of RGGI-like trading programs.”
Allison Clements, director of The Sustainable FERC Project, said the plan “provides states with achievable goals to cut carbon pollution and builds upon the ample flexibilities provided in the original proposal. The final rule’s extra time for initial compliance, requirement that states consider reliability implications and limited ‘reliability safety valve’ put to bed any concerns that the rule will cause grid reliability problems.”
Wind, Solar Celebrate
Renewable energy advocates were quick to praise the plan, with the wind industry saying it could provide a majority of the clean power states will need.
“Low-cost wind energy reduced carbon emissions by 5% in 2014, and we’re capable of doing a lot more. We can build a more diverse, reliable, cleaner energy mix for America, while creating jobs and keeping money in consumers’ pockets,” said Tom Kiernan, CEO of the American Wind Energy Association.
Not to be outdone, the solar industry said that it can provide a 50-state solution.
“Solar energy is the most sensible compliance option for states under the Clean Power Plan. Solar works in all 50 states, has zero carbon emissions, creates more jobs per megawatt than any other technology and can be deployed cost-effectively and quickly — all while improving grid reliability,” said Rhone Resch, CEO of the Solar Energy Industries Association.
Mixed Emotions for Nuclear
The Nuclear Energy Institute said it was pleased that the final rule will count nuclear plants under construction and plant uprates toward compliance rather than the starting point for goal-setting calculations.
“Based on our preliminary review, the final rule appears to require larger carbon reductions than the proposed rule and places a greater emphasis on mass-based compliance approaches. Those two factors alone should drive increased recognition of the value of existing nuclear power plants,” it said.
The group said it was disappointed, however, that EPA did not incorporate the “carbon-abatement value” of existing nuclear power plants.
Exelon says its Clinton nuclear plant has been losing money due to low natural gas prices and competition from wind. The Nuclear Energy Institute expressed mixed feelings about the final EPA rule. (Pictured above: Clinton nuclear plant. Source: Exelon)
“EPA notes correctly that ‘existing nuclear generation helps make existing CO2 emissions lower than they would otherwise be but will not further lower CO2 emissions below current levels.’ What the final rule fails to recognize is that CO2 emissions will be significantly higher if existing nuclear power plants shut down prematurely.”
Natural Gas: Half a Loaf
Calpine, the country’s largest generator using natural gas, called the plan “a workable and achievable approach to control CO2 emissions that will benefit generations to come.”
“This flexible, market-based solution will reward the companies that invest and have invested smartly in cleaner generation,” CEO Thad Hill said.
America’s Natural Gas Alliance took issue with changes from the proposed rule that mean natural gas will fill less of the void left by retiring coal generators.
“The White House is ignoring market realities and discounting the ability of natural gas to achieve the objective of emissions reductions more quickly and reliably while powering growth and helping consumers,” said the group, which represents independent gas exploration and production companies. “We believe the White House is perpetuating the false choice between renewables and natural gas. We don’t have to slow the trend toward gas in order to effectively and economically use renewables.”
The Edison Electric Institute said its primary concern “remains the overall timing and stringency of the near-term reduction targets.”
“Until we review the final guidelines in their entirety, it is difficult to assess whether they address the range of concerns we have raised over the past year. Ultimately, it is imperative that the final guidelines respect how the electric system works and provide enough time and flexibility to make the necessary changes to achieve carbon emission reductions.”
Business and Industry Split
Businesses outside the electric industry were split.
Last week, 365 companies and investors sent letters to more than two dozen governors voicing their support for the plan and encouraging the states’ “timely finalization” of implementation plans to meet the new standards.
“Our support is firmly grounded in economic reality,” wrote the businesses, including industry giants such as General Mills, Mars, Nestle, Staples, Unilever and VF Corp. “Clean energy solutions are cost-effective and innovative ways to drive investment and reduce greenhouse gas emissions. Increasingly, businesses rely on renewable energy and energy efficiency solutions to cut costs and improve corporation performance.”
“Having access to clean energy choices, whether efficiency or renewable energy, helps us manage our energy-related costs while also reducing our environmental impact,” said Letitia Webster, senior director of global sustainability at VF Corp., a North Carolina-based apparel company whose brands include The North Face and Timberland.
The American Iron and Steel Institute said, however, that the rule will raise electricity costs for domestic steel companies and threaten the industry’s ability to remain competitive with foreign suppliers.
“The leading steel-producing states in the U.S. are heavily dependent on coal for electricity production. This rule will have a disproportionate impact on coal-fired utilities and, in turn, impede economic growth for steelmakers,” CEO Thomas J. Gibson said.
Gibson added that the domestic steel industry competes with steel producers in countries where energy costs are often subsidized. “Limitations on CO2 emissions instituted in the U.S. must also apply at the same level of stringency to other major steel-producing nations, such as China. Otherwise, steel production and manufacturing jobs will shift to other nations with higher rates of greenhouse gas emissions.”
Stock Market
While the Dow Jones Industrial Average closed down 91.66 points (a 0.52% drop), electric utility stocks generally fared well. Nuclear-heavy Exelon was up 1.1%, while coal-dependent companies fared slightly worse, with Duke Energy gaining 1%, American Electric Power up 0.85%, Southern Co. up 0.51% and Entergy up 0.4%.
Not unexpectedly, major coal companies suffered through a tough Monday. Arch Coal saw its shares drop from $1.80 to 18 cents, while Peabody Energy was down 9.2%. Consol Energy, a coal, oil and natural gas company with a mining business focused in the Appalachian Basin, dropped 7.6%.
After sifting through 4.3 million comments and attending months of meetings with state regulators, utilities and RTO officials, the Environmental Protection Agency yesterday released a final Clean Power Plan that relaxes some controversial proposals while increasing its target for emission reductions.
As expected, EPA bowed to nearly universal opposition to a requirement that states meet interim goals as soon as 2020, replacing that with a 2022 target while leaving 2030 as the deadline for full compliance. As also expected, the rule incorporates a reliability “safety valve.”
At the same time, the Obama administration upped its ultimate target, saying it will require a 32% reduction in power plant CO2 emissions from 2005 levels, up from 30% in the draft rule.
EPA said it will permit all low-carbon resources, including renewables, energy efficiency, natural gas, nuclear and carbon capture and storage to have roles in compliance.
Natural gas generators will play a smaller role in replacing retiring coal plants under the final rule than EPA projected in its draft plan. Source: Duke Energy
But the final plan anticipates less switching from coal to natural gas and more reliance on — and incentives for — renewables. EPA projects renewables will account for 28% of generating capacity by 2030, up from 22% in the proposed rule, an increase of nearly one-third.
EPA said it increased renewables’ role in part because of the falling cost of solar and wind power and expectations of additional reductions in the future. The agency will seek to take advantage of those economics while offering pollution credits for states that add renewables before 2022, with similar incentives for those that make early energy efficiency investments in low-income communities.
Trading-Ready State Plans
In addition to delaying initial compliance by two years, EPA said the final rule also grants states more flexibility in meeting their targets, allowing them to develop trading-ready compliance plans for participating in emission credit markets with other states without the need for complicated interstate agreements.
State plans are due in September 2016, but states that need more time can make a preliminary filing and request extensions of up to two years for submitting a final plan.
Litigation Expected
EPA also released a federal implementation plan that it said can provide a model for states while also serving as a “backstop” for states that balk at compliance.
The solar industry says it offers a “50-state” solution to replacing coal-fired generation.
EPA will have to use that backstop if some states stand firm in their pledges to refuse to comply, as Senate Majority Leader Mitch McConnell, a Republican from coal-producing Kentucky, has urged. About two dozen states have indicated they may challenge the plan in court.
EPA, however, says that many states are already on the path to compliance, noting that all states have demand-side energy efficiency programs and all but 13 have renewable portfolio standards or goals. Half of the states have energy efficiency standards or goals.
“The idea of setting standards and cutting carbon pollution is not new. It’s not radical,” President Obama said at a White House ceremony announcing the plan. “What is new is that, starting today, Washington is starting to catch up with the vison of the rest of the country.”
Reliability ‘Safety Valve’
The rule seeks to ensure sufficient generation resources by requiring states to address grid reliability in their plans and includes a “safety valve” that could buy some retiring generators additional time to address any reliability concerns.
EPA noted that — unlike the Mercury and Air Toxics (MATS) rule — the Clean Power Plan does not impose plant-specific requirements, allowing states flexibility to “smooth out” their emission reductions over time and across sources.
International Audience
The Clean Power Plan is the latest of the Obama administration’s initiatives — which includes the controversial loan guarantees for clean energy technologies, a doubling of fuel economy standards for cars and light trucks, and a separate rule limiting emissions from new power plants — directed at climate change.
By now addressing power plant emissions — the largest source of greenhouse gases (32% of the U.S. total) — the Clean Power Plan will give the Obama administration a platform for urging other nations to cut their emissions at a United Nations climate change conference in Paris in December.
“I am convinced that no challenge poses a greater threat to our future and future generations than a changing climate,” Obama said in a 25-minute speech that was frequently interrupted by applause from supporters.
Obama also quoted the observation of Washington Gov. Jay Inslee: “We’re the first generation to feel the impact of climate change and the last generation that can do something about it.”
“We only get one planet,” Obama continued. “There’s no plan B.”
What Changed in the Final Rule?
The Environmental Protection Agency made a number of significant changes to the final Clean Power Plan based on feedback to the preliminary plan released last year. Here is a summary of the most important changes:
Source‐specific CO2 emission performance rates: The plan uses two different CO2 emission rates to define the “best system of emission reduction” (BSER), one for coal-steam and oil-steam plants and a second for natural gas plants.
Rate‐ and mass‐based state goals: The plan uses the CO2 performance rates to set both rate‐based (CO2 lbs/MWh) and mass‐based goals (total CO2 metric tons) for states. The draft rule used only rate-based targets; the mass-based targets were added to accommodate states that want to take part in emissions trading.
Energy efficiency building block eliminated: The final plan eliminates building block 4, relying on demand‐side energy efficiency, reportedly due to concerns it might be unenforceable: utilities can’t control their customers’ efficiency. “EPA nonetheless anticipates that, due to its low costs and potential in every state, demand‐side EE will be a significant component of state plans,” the agency said.
Refinements to the three remaining building blocks:
Building block 1: Improved efficiency at power plants. EPA originally proposed heat rate improvements of 6% for coal and oil generators, which industry officials said was unachievable. The final rule anticipates improvements of 2.1 to 4.3%, depending upon the region.
Building block 2: Shifting generation from higher emitting coal to lower emitting natural gas power plants. The final rule assumes natural gas plants will run at 75% of net summer capacity. The draft expected natural gas units to run at 70% of their nameplate capacity, a metric that many commenters said was incorrect because it doesn’t reflect real operating conditions.
Building block 3: Shifting generation to zero‐emitting renewables. The final BSER analysis does not include existing or under‐construction nuclear power or existing utility‐scale renewable energy generation as part of building block 3. EPA expects a bigger role for renewables than originally proposed “based on up‐to-date information clearly demonstrating the lower cost and greater availability of clean generation than was evident at proposal. It takes into account recent reductions in the cost of clean energy technology, as well as projections of continuing cost reductions.” Generation from under‐construction nuclear facilities and nuclear plant uprates can still be incorporated into state plans and count towards compliance. “Nuclear power competes well under a mass‐based plan, as increased nuclear generation can mean that fossil fuel units are operating less and emitting fewer tons of CO2,” EPA said.
Grid reliability measures: States must show they have considered reliability in developing their compliance plans, “such as consultation with appropriate state reliability or planning agencies.” To address unexpected reliability concerns, states can amend their approved plans or seek temporary relief under a reliability safety valve.
Trading‐ready mechanisms: In response to concerns that requiring formal, up‐front agreements between states would deter use of trading as a compliance mechanism, the final rule allows states to design rate‐based or mass‐based trading-ready plans permitting individual power plants to use out‐of‐state reductions to achieve required CO2
Clean Energy Incentive Program: EPA will reward states making investments in renewable energy and demand‐side energy efficiency projects implemented in low‐income communities during 2020 and 2021 by awarding them emission rate credits (ERCs) or allowances.
Relaxed initial deadlines: The plan allows states a two‐year extension to submit compliance plans. By September 2016, states must submit either a final plan or an initial plan with a request for an extension to September 2018. Initial compliance goals will go into effect in 2022, not 2020.
The new owner of Peoples Gas, WEC Energy Group, told the Illinois Commerce Commission that it has fired the contractor in charge of the natural gas main replacement project in Chicago — this after the project’s price has quadrupled to $8 billion.
WEC Energy Group, formed after Wisconsin Energy purchased People’s Gas parent Integrys Energy Group, said that Jacobs Engineering Group was no longer in charge of the accelerated gas main replacement project. It shouldn’t come as a surprise, though. One of the conditions the ICC placed on its approval of the acquisition was a promise that WEC take firm control of the problem-plagued project.
When the project was first unveiled in 2009, Peoples said the cost of replacing about 2,000 miles of pipe over 20 years would be about $2.2 billion. The ICC approved a customer surcharge to finance the replacements. The cost estimate then went up to $2.6 billion, and then $4.6 billion. When the ICC sought more information in June from Peoples’ management, top managers called before the commission were unable to provide any firm guidance. That management team has since largely been replaced.
Wildfires, Market Shifts Cutting Rail Traffic to Delaware Refinery
The number of tank cars delivering crude to the Delaware City Refinery has been cut in half because of wildfires in the west and shifting markets, according to the refinery’s owner. The refinery received an average of about 125,000 barrels per day during the first quarter of the year, according to Tom Nimbley, CEO of PBF Energy, which owns the facility on the banks of the Delaware River near Delaware City. In the second quarter, that number dropped to about 60,000 barrels per day.
Nimbley said North American crude oil — the type it receives by rail from the Midwest and Canada — has become too expensive compared with crude it can receive by water from other sources. “Factoring in transportation costs, it is plainly evident that these barrels cannot find an economic home on the East Coast, or a lot of other places” at current price levels, Nimbley said during a conference call with analysts.
Nimbley said rail deliveries could continue to fade, to 45,000 to 50,000 barrels per day, if the same market conditions persist. “We buy our crude basically two to three months early, so the crude we’re running in the third quarter is based on prices that exist in the second quarter, and those prices did not support rail economics,” Nimbley said.
SolarCity, the solar development and financing company run by Tesla CEO Elon Musk, reported strong results in its second-quarter earnings, saying it booked 395 MW of solar projects and installed 189 MW. That’s a healthy rise from the previous quarter, when the company booked 237 MW and installed 153 MW.
SolarCity also said it produced 1.25 TWh of energy in the quarter. Through the end of the quarter, the company had installed 1,418 MW, an increase of 86% over the same period in the previous year, and said it had a total of 262,495 customers. The company said favorable regulatory rulings in California and Arizona contributed to its success.
Duke Energy Progress Completes NCEMPA Asset Purchase
Duke Energy Progress has completed the purchase of North Carolina Eastern Municipal Power Agency’s generating assets for $1.25 billion. The purchase includes ownership of about 700 MW of generation at Brunswick Nuclear Plant Units 1 and 2 in Brunswick County, Mayo Plant in Person County, Roxboro Plant Unit 4 in Person County and the Harris Nuclear Plant in Wake County.
The sale gets NCEMPA out of the generation business. It has entered into a 30-year power purchase agreement with Duke.
SunEdison has been named the “Official Solar Energy Partner of NASCAR Green.” The partnership intends to build on the expanded use of solar technology at race-team shops and race tracks across the country.
“Our strategic partnership with SunEdison will help NASCAR further reduce the sport’s environmental impact and help continue to educate our fans on renewable energy,” said Steve Phelps, NASCAR’s chief marketing officer.
NASCAR says a study it commissioned in 2014 found that four out of five NASCAR fans believe the earth is going through a period of climate change, and that two out of three of those fans feel a personal responsibility to do something about it.
Xcel Energy CEO Ben Fowke said last week that the Minneapolis-based utility supports development of large, attractively priced solar power projects, but it will keep pushing to limit more costly rooftop and subscriber-based community solar gardens. Xcel recently won approval from Minnesota regulators to develop its first three utility-scale projects in the state, the largest of which will generate 100 MW.
Fowke said recent studies have confirmed that large solar development “is far more cost-effective for consumers than smaller applications” and solar policy needs to be based on “sound economics.”
“While solar gardens and rooftop solar have a place in our portfolio as an option for consumers, because they require heavy, heavy subsidization of non-participants, you’ll continue to see us advocate that the primary focus be utility-scale solar so that we can keep energy costs affordable for consumers,” Fowke said.
American Electric Power has named Bruce Evans as the new president and chief operating officer of AEP Texas. He is replacing Wade Smith, who is now senior vice president of grid development for AEP Transmission. Evans was vice president of distribution operations for AEP Texas.
Evans has a bachelor’s degree in finance from Hardin Simmons University in Abilene and a master’s degree in finance from Dallas Baptist University. He also attended the Advanced Management Program at Harvard University. He has built his career in utilities, spending the first 21 years at West Texas Utilities, Central Power & Light, Central & South West and AEP. He was president and CEO of the former CPL from 1996 to 1998.
After a failed attempt at Arctic exploration last year, Royal Dutch Shell plunged a drill bit into the mud at the floor of the Chukchi Sea. The exploratory well will be Shell’s first action in the search for oil reserves that may measure in the billions of barrels. And even as the first well was being drilled, protests against Shell’s Arctic explorations continued. The icebreaker Fennica — in Portland, Ore., for repairs after gashing open its hull — steamed past protesters on its way to join the rest of the marine drilling fleet.
Shell is betting big on this Chukchi Sea attempt, but it is racing the clock as winter is already starting to bear down on the drill site. A previous attempt had to be halted when an iceberg drifted toward a drill ship in 2012.
But Shell said it is committed to this year’s attempt, and for good reason. The Arctic prospect “has the potential to be multiple times larger than the largest prospects in the U.S. Gulf of Mexico, so it is huge,” CEO Ben van Beurden said. But its potential is also far off. “If, indeed, we do find oil, and if we find an acceptable path to develop it, it will start to produce in 2030,” he said.
EDP Renewables Planning to Build 250-MW Wind Farm in Maine
EDP Renewables has applied to build a 119-turbine, 250-MW wind farm near Bridgewater, Maine. If the Spanish company’s first project in the state gains approval and is built, it will eclipse what is now the largest wind facility there, the 185-MW SunEdison wind farm now under construction near Bingham.
EDP is proposing to build a 50-mile transmission line to connect the project to the regional power grid. In order to quiet opposition, EDP has already promised up to $2 million in energy efficiency projects for area residents and businesses.
Clean Line Energy Asks Missouri PSC to Reconsider Nixed Project
Clean Line Energy Partners is asking the Missouri Public Service Commission to give it another chance to get a permit to build a $2.2 billion transmission line that would run from Kansas wind farms to markets in the east. The PSC denied a permit to the Grain Belt Express project in July.
“The project is too important to Missouri’s energy future not to pursue,” a company official said. The transmission line would run from Dodge City, Kan., across Missouri, through Illinois, to a substation in Indiana. Three of the commission’s five members voted against the project, questioning whether the line was needed to help Missouri meet its renewable energy mandate by the 2021 deadline.
UIL Holdings will invest $80 million in the Northeast Energy Direct natural gas transmission line project being proposed for New York, Massachusetts and New Hampshire. The investment will give UIL a 2.5% ownership stake in the pipeline project proposed by Kinder Morgan. Plans call for the natural gas transmission line to extend 188 miles from upstate New York, through western Massachusetts and southern New Hampshire, before terminating in Dracut, Mass.
Construction of the $3 billion project is expected to start in 2017, with the pipeline becoming operational in November 2018. Northeast Energy Direct is part of a larger, 412-mile project that would bring natural gas from the Marcellus Shale deposits of north-central Pennsylvania to the population centers in southern New England.
Michael West, a UIL spokesman, said the company’s deal with Kinder Morgan gives it the opportunity to purchase an even larger ownership stake in the transmission line project.
KANSAS CITY — SPP’s Board of Directors/Members Committee last week voted to approve moving the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT following continued debate over costs and tradeoffs.
The Members Committee approved the motion 8-5, with six abstentions. The board vote is not public, but Chairman Jim Eckelberger took the somewhat unusual step of ensuring that the board and Members Committee quickly knew the motion had passed.
The measure passed the Markets and Operations Policy Committee and other stakeholder groups with similar splits. Some members questioned the expense and effort to implement a small change. Members from SPP’s northern footprint have complained that the adjustments do little to increase the knowledge of day-ahead prices. (See SPP Members Reluctantly OK Day-Ahead Change.)
The change is intended to comply with the Federal Energy Regulatory Commission’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle.
Assuming FERC approval, SPP will post day-ahead results at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.
SPP faces an Aug. 4 compliance filing deadline with FERC. “If we don’t pass this, we will have to say why we can’t comply,” Carl Monroe, SPP’s chief operating officer, said before the votes. “And I’m not sure I can defend that.”
SPP staff has estimated it will take $1.5 million and 14 months to implement the changes, which will require new software. Staff suggested including that work with the Enhanced Combined Cycle (ECC) project.
Bruce Rew, SPP’s vice president of operations, noted that both projects improve the market-clearing engine’s functionality. “We would be working both together in the same project, because both are focused on improving solution time,” Rew said.
Board Backs Change to ARR Allocations
The board also approved the MOPC’s recommendation to change the annual auction revenue rights allocation system capacity to better match the annual transmission congestion rights (TCR) auction and reduce underfunding.
The board agreed with the MOPC’s recommendation to change the percentage for ARR allocation from the original 60% of system capacity to 80% for the seasonal or shoulder months. The percentages are unchanged for June (100%) and July to September (90%).
Those pushing the 60% allocation for seasonal months said it was an aggressive number and would solve the TCR markets’ underfunding problem, but they recognized it would cause problems for some market participants.
“I think the members said at MOPC that by going down to 60%, you are masking all the other issues,” Xcel Energy’s Bill Grant said.
The revision will settle or convert all annual ARRs during the annual process. No ARRs would be carried forward, and infeasible TCRs would be reduced. All residual capacity would still be allocated and auctioned in monthly processes.
Out-of-Bandwidth Projects Ordered Re-Evaluated
Continuing a discussion that began at the MOPC meeting two weeks earlier, the board put seven over-budget transmission projects on hold, ordering them to be brought back to the board in January following “proper evaluations.”
The seven projects were initially estimated by a third-party consultant to cost $62.8 million as part of the 2015 Integrated Transmission Planning 10-Year Assessment (ITP10). After the projects’ notices to construct (NTCs) were issued, additional study by the members revealed the projects’ cost would come to $147.7 million. (See SPP Frustrated over Transmission Project Overruns.)
The projects were among those filtered out of the 30 committed projects resulting from the ITP10 and near-term planning processes. Only four projects came within a 30% variance “bandwidth,” with 23 exceeding that threshold and three projects coming in below.
SPP staff brought seven of the largest above-estimate projects to MOPC, which recommended suspending NTCs for three of the projects and moving forward with the other four.
But the board overruled MOPC in ordering all seven restudied. NTCs are decisions for the board, Director Julian Brix said.
“The board giveth, the board taketh away,” he said. “There’s too much differentiation in these projects. This is about the board’s fiduciary responsibility.”
SPP Vice President of Engineering Lanny Nickell said his staff conducted interviews with the transmission owners granted NTCs. The feedback indicated material and labor costs were similar, but the third-party consultant had not taken into account individual design standards, rebuilding aging facilities, unforeseen substation work or building through wetlands or other sensitive areas.
“We didn’t ask the right questions,” Nickell said. “We didn’t have adequate information during the planning process.”
Nickell said transferring study responsibility to the third party, a compressed timeline and dealing with competitive information also contributed to the variances.
“The third party did a horrible job,” said Kelly Harrison, president of Westar Energy’s Prairie Wind Transmission. “All they had to do was ask. There wasn’t anything about the project that … we wouldn’t have shared with them.”
SPP was able to allay the concerns of American Electric Power and others that the re-evaluations would change the projects’ reliability or economic needs, and with it, cost allocations. Stuart Solomon, president of AEP’s Public Service Co. of Oklahoma, noted AEP is responsible for four of the seven projects, “all reliability rebuilds based on need.”
“I don’t feel the existence of the variance is a reason to suspend and re-study,” Solomon said during the discussion. He eventually supported the board’s decision, with the hopes SPP could “strive” for the October MOPC and board meetings.
Nickell said staff would be able to meet the board’s timeline, using detailed project proposals already in hand. AEP’s Linwood-South Shreveport 138-kV line rebuild has a 2017 need date, but Nickell said a mitigation plan is in place, should there be further delays.
No Raise in Administrative Fee Expected
Finance Committee Chairman Harry Skilton said the RTO expects its administrative fee for 2016 to be between 37 cents/MWh and 38 cents/MWh, consistent with the 2015 budget’s forecast.
The fee is currently 38.1 cents/MWh, having jumped about 15 cents since 2011 to pay for the Integrated Marketplace.
Skilton noted several factors that could affect the fee: 2015’s monthly peak loads, which are running 5% below 2014’s; the costs of complying with version 5 of the Critical Infrastructure Protection reliability standard; and the costs of improving combined-cycle functionality.
Date Change for Walkemeyer Project RFP
The board approved a staff recommendation to change a key date in its first competitive solicitation under Order 1000, the Walkemeyer-North Liberal project in Kansas.
General Counsel Paul Suskie said the change “mitigates a flaw in the process” by moving the “regulatory approval need date” eight months from the NTC’s issuance.
The SPP Tariff requires the need date be included in a competitive upgrade’s request for proposals to identify when an entity must have gained utility status in the state where the facility will be built. The change would meet a Kansas Corporation Commission statutory obligation to rule on such requests within 180 days of the initial filing and give the winning entity “reasonable time” to gain utility status in the state.
The original regulatory approval date was June 1, 2016. The board approval moves that date to Jan. 1, 2017. Changing the date gives RFP respondents sufficient time to finalize their work, Suskie said.
Suskie said staff would work with the Competitive Transmission Process Task Force to develop new policy setting to ensure future RFPs include a date that is reasonable and allows for the SPP process to work as designed.
New Member Process, Document Approved
The board approved a Strategic Planning Committee task force’s recommendations on improving the process of wooing prospective members to join the RTO.
The board first added several modifications to those offered the previous day by the Regional State Committee to a document outlining triggering mechanisms for when communication and work-group processes to be followed during negotiations with prospective members would apply.
The task force report notes that SPP’s staff “remains solely responsible for the direct negotiations with the prospective member” while stakeholders provide input on policy and changes to the governing documents.
SPP Seeks Larger Board
CEO Nick Brown said SPP has filed with FERC modifications to the bylaws that would allow up to three additional directors. He said the Corporate Governance Committee will be evaluating the results of an RFP to conduct a search for board candidates, the first such search SPP has conducted in seven years. The committee will discuss the issue further during its Aug. 27 meeting.
Competitive Tx Task Force Extended
The board approved extending the Competitive Transmission Process Task Force’s charter through 2016 and endorsed the group’s Load Responsible Entity concept. Golden Spread Electric Cooperative’s Mike Wise, chair of the Strategic Planning Committee, said the task force intends to bring a “full package” of recommended improvements to the MOPC in January. (See “Load Responsibility White Paper” in SPP Strategic Planning Committee Briefs, July 20.)
Two New Members
SPP welcomed its two newest members during the meeting: the Tri-State Generation and Transmission Association and Harlan Municipal Utilities. The additions increase SPP’s membership ranks to 92.
Tri-State Generation is a wholesale electric power supplier owned by the 44 electric cooperatives that it serves. The association generates and transmits electricity to its member systems throughout a 200,000-square-mile service territory across Colorado, Nebraska, New Mexico and Wyoming.
Harlan provides electricity, gas, water and telecommunications to a city of more than 5,100 in southwestern Iowa.
Special Guest
FERC Commissioner Cheryl LaFleur was among those sitting in the board’s inner circle. “I’m here to listen,” said LaFleur, who was in the area for Clean Power Plan-related hearings.
Dynegy told federal regulators last week they should reject complaints over its bidding in MISO’s capacity auction last April, saying the challenges suffer from a “fatal” procedural flaw.
In May, the Illinois Attorney General and Public Citizen filed complaints asking the Federal Energy Regulatory Commission to investigate Dynegy’s behavior in the Planning Resource Auction, which resulted in a nine-fold price increase for Zone 4 (EL15-70). Several other market participants, including Southwestern Electric Cooperative, also have filed protests over the results.
Dynegy, which has the commanding share of capacity in Zone 4, has previously denied there was any manipulation or underlying flaws in the MISO auction. (See Dynegy: No Evidence of Misconduct in Auction.)
In a July 30 filing, Dynegy said efforts by Illinois Attorney General Lisa Madigan to retroactively change the results of the auction “run squarely afoul” of previous FERC decisions.
Precedent Cited
The company cited a 2008 challenge by the Maryland Public Service Commission over PJM capacity auction results. The commission ruled that it would not invalidate results of completed capacity auctions that were conducted in accordance with approved market mitigation measures and were deemed by an independent market monitor to be competitive.
“So too here: because the complainants in these cases have not alleged that MISO violated its Tariff, and because [MISO Market Monitor David Patton] has confirmed that the results of the [auction] were competitive, the complainants’ challenges to those rules fail as a matter of policy,” Dynegy told FERC.
Dynegy said that although the attorney general wants the auction retroactively invalidated, “it never alleges, much less substantiates, any violation of the MISO Tariff.”
The company also said that Southwestern, which filed a complaint alleging that the auction results were unreasonable, also fails to show that MISO violated its Tariff.
“The complainants’ failure to clear that hurdle was fatal from the outset. Their more recent continued silence on the point only serves to underscore that failure,” Dynegy told FERC.
New York regulators last week began to sketch out the details of their ambitious Reforming the Energy Vision (REV) initiative with a white paper on rate design that seeks to upend business models that have been in place for more than a century and establish the state as a leader in the shift to distributed energy resources (DER).
The New York Public Service Commission staff straw proposal is intended to address the “discontinuity” between traditional cost-of-service regulation and the “multi-sided” market envisioned in Reforming the Energy Vision, with customers that are also producers and utilities that also serve as “platforms” for vendors offering services that help consumers reduce or time-shift their energy use.
That means utilities will see less of their earnings from centralized generation and returns on capital investments and more on service revenue and incentives tied to energy reductions, reducing transaction costs and increasing the volumes of DER, such as rooftop solar, microgrids and storage.
“The ratemaking paradigm must create alternatives to the current financial and institutional incentives and provide opportunities for utilities to earn from activities that achieve their service obligations in a manner that supports reductions in the total customer bill,” the paper says.
“The intent of REV is to harness markets to achieve innovative and cost-effective solutions, with utilities facilitating those markets both in their system planning and in day-to-day operations. Financial incentives and economic signals must be in alignment with this goal.”
In February, the PSC issued its “Track 1” order that created a framework for the shift from centralized generation to a customer-centric market that encourages adoption of clean distributed energy resources. The commission said that business as usual is no longer a viable option for utilities in meeting their statutory responsibilities to New Yorkers. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
Last week’s white paper will be the foundation for an anticipated “Track 2” order on ratemaking changes. “Track 2 looks closely at how we’re going to align the utility investment earning capacity with customer value,” Anthony Belsito, a policy advisor for the PSC, told the Infocast New York Reforming the Energy Vision Summit last week. (See related story, Public Helping Drive New York REV Agenda.)
Gradualism
The paper said that changes to rate design formulas must not cause large, sudden increases in customer bills. And this “gradualism” should also apply to industries such as solar and energy efficiency providers, it said. “Any changes affecting these industries should provide ample time for businesses to adapt and plan for new forms of opportunity.
“For the same reason, rate design changes should be oriented toward investments going forward, versus investments already made. To the extent possible, customer investments already made under assumptions of a program such as [net energy metering (NEM)] should not be disrupted.”
The report says concerns about the impact of NEM on utility earnings are “inconsequential” at current penetration levels.
“Input from the DER industry makes clear that the simplicity and predictability of NEM is very important in engaging customers and providing certainty to investors. Staff does not believe that there is any value in changing NEM for mass-market customers with on-site [distributed generation] at this time.”
Granularity vs. Simplicity
One of the challenges observed by the PSC is the conflict between increasing granularity in cost allocation and maintaining simplicity in billing, particularly for residential customers. That, the staff said, is where aggregators can play an important role. “Customers themselves may not need to see complex rates if a service provider or aggregator sees and manages complexity for them,” it said.
LMP+D
The paper proposes a new method for calculating the value of DER: adding a distribution component (“D”) to the wholesale LMP pricing (location-based marginal price of energy, as New York refers to it).
“The current convention of crediting at the average retail rate may be either too little or too much based on the nature of the resource and its location,” the paper says.
Click to zoom.
The value of D can include load reduction, frequency regulation, reactive power, line-loss avoidance and resilience.
The PSC plans to develop ways to calculate LMP+D in proceedings involving utilities and DER providers. Staff called for the state’s utilities to adopt software to determine distribution-level marginal costs.
LMP+D can incent net-metered facilities to install smart inverters that can increase the amount of solar generation that can safely be interconnected to a circuit. Staff said the commission should consider requiring smart inverters on future net-metered projects.
While the valuation of DER should vary by location, the paper says, customer charges should remain indifferent to location.
Customers participating in a utility demand response program or exporting power to the grid should receive compensation based on LMP+D, staff said.
Customers who supply only a portion of their electricity and do not participate in a utility program would receive no significant credits from their utilities. “In this circumstance, even when the ‘value of D’ as a service to the grid can be calculated, the reduction of the customer’s bill should continue to be based on the average cost of service. That is, NEM as it is currently constructed should remain applicable.”
Reforming the Energy Vision Rate Design
The paper proposes several additional changes:
Demand Charges — The paper proposes “for comment and further development” the concept of replacing part of the kilowatt-hour and fixed customer charges with a peak-coincident demand charge. “Because long-run distribution marginal costs are driven by coincident peak on a circuit-by-circuit basis, customers’ usage at system peak provides the most accurate measure of system costs. And, unlike fixed customer charges, peak demand can be managed by customers via DR, energy efficiency and/or DG,” staff said. Fixed customer charges should reflect only the costs of distribution that do not vary with customer demand.
“This change is not proposed as a mere reallocation of costs among customers,” the paper said. “It is proposed as part of a broader strategy to reduce long-term system infrastructure needs, encourage the optimal development of DER, discourage uneconomic bypass of the distribution system and maintain affordable rates for all customers.”
Time-of-Use Rates — The paper says utilities should develop time-of-use rate demonstration projects and offer technologies that have been shown to increase peak reduction savings, such as in-home displays, “energy orbs” and programmable and communicating thermostats. The paper cites studies showing TOU rates resulting in peak reductions as high as 47%. “Peak load reduction impacts are seen to increase as the peak to off-peak price ratio in TOU rates increases,” it added.
Smart Home Rate — The PSC said early-adopter consumers should be able to opt in to new rate structures. “A gradual approach to changes in mass-market rates should not prevent customers who are willing and able to begin participating in energy markets as active consumers from doing so.”
C&I Rate Design — While rates for commercial and industrial customers are more advanced than for mass-market customers, the report calls for additional improvements, saying demand rates should be more precise and reflect the time of energy use. “Current non-coincident demand rates can have the effect of inhibiting a customer from shifting load to off-peak times,” it says. “For example, a customer investing in storage to purchase off-peak power and utilize it at peak times might face an increased demand charge due to the shift in usage to the off-peak time.”
It called for utilities to examine their C/I rates and propose improvements in their next rate filing.
Standby Service Tariffs — Standby rates, which apply to large customers that generate much of their power on-site and use the distribution grid as a backup, can be another barrier to DER. The PSC recently expanded an exemption from standby rates for four years while it studies rate design changes. Standby rates are related to net metering and to the general rate design issue of fixed versus variable rates, the report notes. “In each case, the responsibility of a customer for the cost of the customer’s reliance on the distribution grid is at issue,” the staff said. “The cost of remaining connected to the grid should generally be lower than the cost of building redundancy and independence into a self-generation system.”
