Dominion Seeks To Add Carbon Tax In Fuel Factor

Dominion Energy Virginia is taking advantage of its annual, and usually boring, fuel cost review to move the cost of any future carbon tax or emissions allowances out of its fixed base rates and into its variable fuel charge. If the State Corporation Commission agrees it could either lower or raise your bill someday but place your bets on the latter.

The case (here) has also drawn testimony that Dominion has so much natural gas capacity under contract in existing pipelines that it is selling the excess capacity to others – about 25 percent of it, in the case of the Transco pipeline. It needs no more capacity, according to a witness hired by environmental groups.

UPDATE:  Through a Twitter response I’m told that Dominion has notified other parties it will withdraw the request to place any future CO2 costs into the fuel charge,  and the document I missed has been flagged.  So the “is” in the lede paragraph is now a “was.”  I’ll leave the story up because it remains something to watch.   

The utility is allowed a dollar-for-dollar recovery of its fuel costs, with no added profit. Every year it makes a forward estimate of what it will spend on coal, natural gas, uranium fuel, purchased power and related inputs (including contracts for transportation). That amount is then adjusted up and down based on the results from the prior year. The result is costing you 2.7 cents per kWh this year and a projected 2.42 cents per kWh next year.

The early retirement of several fossil fuel plants and the addition of more solar generation (free fuel) are in part behind those lowering costs.

Questions of profit do enter the issue in one way: If Dominion sells electricity off-system and earns a margin, 75% of that profit is credited to customers in the fuel charge. Dominion is projecting $1.3 million in such profits next year, with $1 million credited to customers.

The company’s big profits, of course, are in its base rates, already deemed excessive in prior SCC reports on its operation. Those base rates have stayed the same for a long time, while more and more of the capital costs have moved to separate rate adjustment clauses. As those costs move from one pot to another, the profit margin in the first pot grows. Base rates never seem to go down.

There are no carbon tax costs yet, either under the Regional Greenhouse Gas Initiative or some proposed federal scheme, but the utility also participates in standing cap and trade programs for nitric oxide (NOx) and sulfur dioxide (SO2). Those costs and some revenues are currently accounted for in base rates as plant operation costs.

Dominion wants to move them all, with related incremental costs, to the fuel factor. Here’s the rationale from Glenn Kelly, director of generation services:

“The Company currently collects emission allowance costs through base rates. However, these costs are clearly variable in nature and are closely associated with generation from fossil fuels. Because these costs are determinate in the dispatch of the Company’s generation fleet, it would be logical to collect these costs through fuel rates in the future. In addition, during a given year, emissions allowances could result in net revenues or net costs. Recovery of emissions allowances through the fuel factor would allow for the review and reimbursement of these variable expenses, or the flow through of benefits to customers, on a more current basis.”

Under the stalled RGGI proposal, blocked until at least the 2020 General Assembly, money paid by generators to purchase allowances to emit CO2 was to be returned to those utilities and then back to the ratepayers. There was no clear way to do that, and this change to the rules could create that path.

But many supporters of RGGI or other carbon tax schemes have other plans for that money. Absent a return to ratepayers in some fashion, the payments for emissions credits would be taxes collected through the fuel factor. If there is no repayment to ratepayers, there is reason to ask whether the charge belongs in base rates. Anytime the pea is moving under the walnut shells, it pays to watch closely. When a cost moves out of base rates, they should go down in proportion.

Gregory M. Lander, the environmental witness who works out of Massachusetts for Skipping Stone, Inc., was highly complimentary of how Dominion is now managing the pipeline contracts, better than it was a year ago. Ultimately that is also good for ratepayers, he said. His testimony is here.

This fuel case is not about the Atlantic Coast Pipeline, but if that pipeline is ever completed and used to feed gas to Dominion generators, the fuel factor is where the new pipeline’s costs would appear. There are no routine cases anymore, not with this crowd and in this environment. Testimony in one case often bears on another.

Lander was so impressed by how well Dominion is now doing managing its excess pipeline capacity that he wants the SCC to require more information on the transactions and suggests Dominion improve its revenue with a reserve price. This overlaps some of the issues raised in a Bacon’s Rebellion report in March about Virginia Natural Gas and its pipeline contracts.

But it is clear that Lander is looking beyond that and is really focused on the need for the ACP.

“…the Company’s existing contracts made significant deliveries to non-power plant locations during the review period. For example, 25% of its total used capacity on the Transco system—fully 51 billion cubic feet (Bcf) annually—went to uses other than Company power plants. Therefore, I conclude that the Company has sufficient pipeline capacity to serve its existing generation fleet. Further, because of the frequency, magnitude, and duration of the non-power plant deliveries under its existing pipeline contracts, I conclude that the Company has ample pipeline capacity to serve additional power generation load should that be necessary.”

Dominion also has contracts to move gas through Columbia Gas Transmission and its own affiliate, Dominion Energy Transmission. Lander testifies that excess capacity on those is more valuable than with Transco, because Transco has substantially increased its overall capacity recently.

“Recent expansions, like the Atlantic Sunrise project, that Transco has brought into service in the regions where the Company was predominantly making segmented releases have suppressed the value of capacity in the secondary market. It is basic supply and demand. When the supply of pipeline capacity increases greater than the demand for that capacity increases, the value of that capacity declines….

“In the future, I expect the Company will be less and less able to “make its ratepayers whole” by selling excess capacity on the secondary market. That, in turn, makes it important that the utility not over-procure firm capacity in the future because it virtually guarantees a greater net cost to ratepayers.”

That “firm capacity” he is advising against, of course, is the embattled Atlantic Coast Pipeline.

(Hat Tip:  Albert Pollard)