BPA says a Financial Reserves Policy surcharge for power customers is likely mainly due to high power purchase expenses earlier in the year, which were $206 million more than BP-18 rate-case expectations.

“Power reserve levels show that a surcharge is nearly certain to trigger for the full $30 million,” Chris Dunning, deputy CFO, said during the Q3 Quarterly Business Review on July 30, which BPA also provided as an audio file.

The low reserves level was despite a $182 million offset of reserves that Bonneville proposes to transfer from Transmission Services to Power Services to address allocation errors between the two units stretching back to 2003, as well as other offsets from agency-level factors.

Power’s reserves for risk are forecast to end the fiscal year at nearly $186 million, representing 38 days cash on hand, significantly below the floor of 60-days level for triggering the surcharge, and more than $107 million shy of the mark.

The surcharge was established in October to help strengthen BPA’s financial health, as required under the agency’s strategic and financial plans (CU No. 1871 [17]), and further developed in the BP-20 initial rate case released in December (CU No. 1880 [13]).

Policy dictates that if triggered, it could result in up to $30 million per year being recovered for Power’s reserves through a rate adjustment over the 10-month period of December through September.

The 10-month surcharge period results from the new procedure of considering actual financial results in November after closing the book on the fiscal year, which ends in September, rather than the prior practice of keying off the Q3 forecast, Dunning said.

This development was not unexpected; BPA warned in April at its Q2 QBR there was a 61 percent chance of the surcharge triggering, which included a 33 percent chance it would be $30 million (CU No. 1901 [13]).

If this continues to hold through the end of the fiscal year, and the full $30 million surcharge is triggered, it would increase the effective BP-20 power rate—which was held to no increase—by 1.5 percent over the rate period, according to the final BP-20 record of decision released July 25 (CU No. 1912 [17]).

The high purchased-power expenses stemmed from a cold winter that led to high energy demand at a time of lower-than-expected hydro generation and natural gas constraints due to a British Columbia pipeline explosion in October.

This is also the reason Power is projecting to end the fiscal year with $243 million in net revenues, $47 million below the rate case forecast, Dunning said, despite offsets from agency-level factors including $76 million in cost-management actions, $61 million in interest expense reductions and $25 million from additional revenues.

Transmission expects to end the year with net revenues $3 million above the rate case forecast because of lower expenses.

At $358 million, its reserves for risk represent 214 days of cash-on-hand, well above the 60-days threshold, and potentially in Reserves Distribution Clause territory, where the administrator has discretion over whether the additional funds should be disbursed and how they should be used, such as for rate relief or early debt repayment.

However, the RDC has a two-part test that requires agency reserves for risk also exceed its threshold; at $544 million, it falls around $25 million short of that, so there will be no RDC triggered.

In other developments, Administrator Elliot Mainzer noted that the year-end net revenue forecast for the agency was $238 million, $36 million below rate-case expectations.

In addition, capital expenditures for both business lines were below expectations, but while Transmission was on track to finish all its projects, there have been some delays within the federal hydropower program, Mainzer said.

“It’s an area of concern for me, and on the minds of customers,” he said, adding that “BPA would continue to work with it partners to see what’s going on.”

Mainzer also mentioned that all the terms of the Coordinated Transmission Agreement with the California ISO have been finished.

The CTA—aimed at ensuring the reliability of BPA’s transmission system while enabling Western EIM flows—was finalized in 2017 (CU No. 1790 [12]). Bonneville first worked it out to facilitate PacifiCorp’s entry into the market, and has been doing EIM settlements since 2014.

Regarding the financial reserves error, in a workshop the same day as the QBR, BPA said its initial proposal for resolving the misallocation of financial reserves between Power and Transmission is to reallocate about $182.4 million from Transmission’s financial reserves to Power’s financial reserves.

This amount includes $158.7 million in principal and $23.7 million in interest, which would correct all of the validated errors from FY 2003 to FY 2018.

While BPA extended its investigation of potential errors as far back as FY 2002, when business unit allocations was first adopted, Acting Treasurer Nadine Coseo said numbers from that period were neither auditable nor traceable, key considerations for making a defensible proposal.

Coseo noted that FY 2002 financial statements had no beginning balance, nor is it known what process was used to split the balances between Power and Transmission. She added that the cash split recorded for that year was probably “backcast” from FY 2003.

Another criterion for the correction is that it would make the business units whole, “while also not unduly disadvantaging” one line over the other, Coseo said. This meant the application of interest to the principal.

Further, Bonneville has opted to apply simple interest, rather than compound, because in its normal business practices any accumulated interest on amounts in the BPA Fund maintained by Treasury is paid out through interest credits, and does not build up over time, Coseo said.

Finally, the agency decided to use the effective interest rate, which accounts for the actual interest earned in the BPA Fund and assigned to the cash split balances. The other choice—the rate-case interest rate—is based on forecasts and has no bearing on the Fund’s interest rate, Coseo said.

The next steps are to collect comments on the proposal through Aug. 21, and then issue a final record of decision in October.

News Editor - Clearing Up

Rick Adair has been with NewsData since 2003, and is news editor for Clearing Up and editor for Water Power West. Previously, he covered environmental and energy issues in the Lake Tahoe area. He has a doctorate in earth sciences.