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Clean energy advocates accuse Dominion Virginia Power’s recently submitted resource plan of inflating future power needs and the costs of integrating solar systems, but the utility defends its calculations.
The advocates claim the strategy – part of Dominion’s efforts to comply with the Clean Power Plan – is to build new power plants, including a fifth nuclear reactor, as a means of boosting the assets that can earn a regulated, and thus secure, profit.
Dominion’s 2016 Integrated Resource Plan, submitted in April, is the first time since the U.S. EPA finalized the Clean Power Plan (CPP) that Virginians have a real opportunity to assess “least-cost” options in a carbon-constrained world.
“The Commission ordered (Dominion) to perform rigorous modeling of how the company might best comply with the CPP. The company’s filing, however, contains several fundamental flaws,” said Will Cleveland, an attorney with the Southern Environmental Law Center in remarks at the State Corporation Commission in Richmond earlier this month. Cleveland is the lead counsel for Appalachian Voices, the Chesapeake Climate Action Center and Natural Resources Defense Council (NRDC).
Dominion “has layered error upon error that leads to only one result: unnecessary and costly investment in company-owned generation to meet an inflated and unlikely future load growth,” Cleveland said.
Dominion spokesman David Botkins responded, saying “the company’s load forecasting methodology has been consistently used for over 30 years and was found generally sound and appropriate by Commission staff.”
Starla Yeh, a senior policy analyst with the NRDC, says part of the problem is the inputs the utility used when performing the modeling. She testified that despite Dominion’s historic practice of purchasing about one-quarter of its total power from other suppliers, it neglected to include purchased power in its modeling “even if it is economical to do so.” That “produces only one result: over-investment in company-owned generation,” she said.
Bob Thomas, who is managing Dominion’s IRP and is its Director of Energy Markets Analysis, said “if it’s cheaper for customers that we purchase power, that’s what the model simulates. In this case, it was our own units that was the cheaper option for our customers.”
But Cleveland said Thomas is only telling part of the story. After reviewing Dominion’s filings and challenging Thomas during the IRP hearings, he said Dominion capped the amount of purchased power the model could buy at a very low, arbitrary amount, leaving Dominion’s own units as the only other option.
Thomas acknowledged Dominion has purchased power it has needed every year since 2000.
“The artificial restriction on power purchases cut off potentially cheaper compliance options, so as of right now we simply have no idea what the cheapest CPP compliance options are,” Cleveland said.
After weeks of hundreds of discovery requests by the advocates, Commission staff and the state Attorney General’s office, Cleveland said he is “hopeful the order will require Dominion, at a minimum, to model compliance with the same levels of imports they historically have had.”
Karl Rábago, executive director of the Pace Energy and Climate Center in New York and a respected solar analyst, said Dominion “inflated the cost of solar using a ‘proxy’ cost for grid upgrades that radically alters how the model selects solar resources.”
Rábago testified that the only scenario that Dominion asserted could meet its emissions cap under the CPP was $1.5 billion more expensive than a model it ran but did not disclose — which did not involve any nuclear but instead on a mix of natural gas and solar — until compelled to do so under discovery proceedings. He said Dominion rejected his scenario “as too ‘risky’ without actually running the comprehensive risk analysis they ran on all other (scenarios).”
Botkins rebutted Rábago’s testimony, saying he did not include the cost of upgrading its transmission network and backup generating sources to accommodate its modest, but now growing, portfolio of solar energy systems.
Rábago asserted that the charge Dominion used – of $390 per kilowatt – “was way out of the range of reasonableness” and “means that the IRP (scenario) selected even less solar than it would have had fair costs been included.”
Bob Thomas, who is managing Dominion’s IRP and is its Director of Energy Markets Analysis, defended the $390-per-kilowatt figure. He claimed for every 1,000 megawatts of solar added and its intermittent availability, Dominion needs to back it up with 450 megawatts of natural gas-fueled combustion turbines.
Rábago was quick to add that he’s been challenging Dominion’s solar integration costs in at least three IRPs. “My point is that the company is supposed to take a hard look at resources and their costs and benefits. They have not,” Rábago said.
Botkins said Dominion will “develop new planning processes and tools to better quantify renewable energy integration costs … in future IRPs.”
Energy efficiency consultant Jeffry Loiter said Dominion neglected to “properly study alternative rate designs” that would integrate efficiency options into meeting future power demand. But Dominion replied that characterization “was not shared by Commission staff” and that it offered alternative rate designs in the current and previous IRPs.
Dominion claims demand throughout its service territory in Virginia will grow by about 1.5% per year. But independent economist James Wilson challenged that in testimony, saying demand has been relatively flat for the past decade. Much of that is widely attributable to the 2008-2010 recession but more recently to companies boosting investments in energy efficiency.
Power demand from the increasing number of data centers in Northern Virginia is growing, Wilson acknowledged. But some data center operators – companies such as Amazon, Facebook and Google – are choosing to power their operations with renewable sources either in Virginia or elsewhere in the PJM power grid that Dominion operates in.
Dominion’s application for a combined construction and operating license at the Nuclear Regulatory Commission for a third reactor at its North Anna complex in central Virginia – its fifth system-wide – could be issued as early as next March, according to Thomas.
With that in hand, Virginia regulators are expected to decide whether the utility can proceed and if, as a least-cost option, adding a fifth reactor will, or won’t, adversely impact ratepayers and whether it is needed to maintain system reliability.
The Commission is expected to weigh in on the integrated resource plan by Dec. 1.
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