Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - TUCSON ELECTRIC POWER CO | d471081d8k.htm |
Exhibit 99.1
Tucson Electric Power Company Rate Case
Preliminary Settlement Term Sheet
January 22, 2013
The following is a summary of certain material terms to which some parties to the Tucson Electric Power (“TEP” or “Company”) rate case, Docket No. E-01933A-12-0291, have preliminarily agreed as a general settlement framework. This Term Sheet does not create a binding agreement of any kind.
A. Base Rate Increase
TEP will receive a non-fuel revenue increase of $76,194,000. This does not include the change in fuel revenue.
B. Residential Bill Impact
Upon the effective date of the new rates, the average monthly bill for the average residential customer will increase by less than $3.00. This overall impact reflects a base rate increase, as well as reductions in the Purchased Power and Fuel Adjustment Clause (“PPFAC”) rate and Demand Side Management (“DSM) surcharge resulting from the adoption of the proposed Energy Efficiency Resource Plan.
C. Cost of Capital
Return on Equity: 10.0%
Embedded Cost of Debt: 5.18% long term/1.42% short term
Return on Fair Value Increment of rate base: 0.68%
Capital Structure: 56.5% debt (55.97% long term/0.53% short term) and 43.5% common equity (actual test-year capital structure)
D. Purchased Power Fuel Adjustment Clause
TEP’s existing PPFAC will continue except that broker fees, lime costs and sulfur credits will now be recovered through the PPFAC. TEP will also credit 100% of proceeds from the sale of SO2 allowances to the PPFAC. TEP will continue to recover its base purchased power and fuel costs through base energy rates as determined by the Commission in this case.
TEP will seek Commission authorization to defer TEP’s April 1, 2013 PPFAC rate adjustment until the effective date of new rates in this docket.
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TEP agrees to make a one-time credit of $3 million to the PPFAC related to prior sulfur credits.
E. Energy Efficiency
TEP will implement an Energy Efficiency Resource Plan (“Plan”), as proposed by Staff, which is intended to treat energy efficiency and demand-side management similar to a generation resource. Under this Plan, TEP will invest (just as TEP does with other conventional energy resources) in cost-effective energy efficiency programs that have been approved by the Commission and earn the rate of return established in this case on that investment, after providing documentation that the expected energy savings have been achieved. The investment costs and the return on the investments will be recovered through an after-the-fact DSM surcharge. Other provisions in the Plan include:
| • | 5-year amortization of energy efficiency investments. |
| • | Adoption of pending EE implementation plan programs and pro-rata budget as recommended by Staff in Docket No. E-01933A-11-0055 and approve the corresponding DSM surcharge. |
| • | Closure of Docket No. E-01933A-11-0055. |
| • | TEP will voluntarily resume program levels at budgets previously approved by the Commission beginning March 1, 2013, and shall recover such costs through the Plan. |
| • | Any customer who can demonstrate an active DSM program and whose single site usage is 25 MW or greater may file a petition with the Commission for an exemption from the DSM adjustor and if approved, will be removed from the EES denominator. The parties are not required to support any such petition and some parties may plan to oppose any such petition. |
F. Lost Fixed Cost Recovery/Opt-Out Residential Rate/Large Customer Exclusion
The parties support energy efficiency (“EE”) as a low cost energy resource and recognize that TEP’s effective pursuit of EE and distributed generation (“DG”) will result in fixed cost revenue erosion for the Company. The parties also recognize the Commission’s interest in directing EE and DG policy. The parties thus agree to adopt a Lost Fixed Cost Recovery (“LFCR”) mechanism, designed to recover only those lost fixed costs associated with the amount of EE savings and DG that is authorized by the Commission and determined to have occurred in a particular year.
The parties propose approval of an LFCR mechanism that is similar to the LFCR approved for Arizona Public Service Company. The LFCR will have a 1% year-over-year cap. Any amount in excess of the 1% cap will be deferred for collection until the first future year in which including such costs would not cause the annual increase to exceed the 1% cap.
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Residential customers will have an option to opt out of the LFCR (for example, by opting for a higher basic service charge). TEP will develop a customer outreach program to inform/educate customers about both the LFCR and the optional opt-out rates.
Large power service customers will be excluded from the mechanism, with corresponding changes to their rate schedules.
The LFCR will recover lost fixed cost from January 1, 2013 forward and the first LFCR surcharge will not go into effect until July 1, 2014.
The LFCR will be subject to periodic Commission review.
G. Environmental Compliance Adjustor
TEP will implement Staff’s proposal for an environmental cost tracker (the Environmental Compliance Adjustor (“ECA”)) that mirrors the existing Environmental Improvement Surcharge (“EIS”) approved for APS. The ECA will recover environmental compliance costs, subject to a cap equal to 0.25 percent of total retail revenue.
H. Rate Design
TBD. The rate design portion should remain open for a period of time, not to exceed one year, if concerns develop over the rate design subsequent to the implementation of new rates.
I. Springerville Unit 1
TEP agrees with Staff’s recommendation to file a report with the Commission no later than July 31, 2014, addressing the status of the Springerville Generating Station (“SGS”) lease agreements and the estimated change in TEP’s non-fuel revenue requirement at the conclusion of each primary lease term. Specifically, TEP commits to reporting on the following matters:
| A. | The details concerning any commitments made by TEP to purchase SGS Unit 1, or any agreements entered into by TEP to otherwise retain capacity rights to SGS Unit 1, after the end of the primary lease term in January 2015; |
| B. | The details concerning any commitments made by TEP to purchase replacement generating resources, or any purchased power agreements entered into by TEP for replacement power, if TEP elects not to purchase or otherwise retain capacity rights to SGS Unit 1 after the end of the primary lease term in January 2015; |
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| C. | The details concerning any commitments made by TEP to purchase the SGS Coal Handling Facilities, or any agreements entered into by TEP to extend the Coal Handling Facilities lease term, after the end of the primary lease term in April 2015; and |
| D. | The estimated non-fuel revenue requirement associated with each of the commitments described above, including the proposed rate treatment of any remaining balance of SGS leasehold improvements. |
Based on the information in the above reporting, the Commission on its own motion or on a recommendation of a party in this case, may require TEP to explain why its rates should not be reduced through the normal Commission process.
J. Procurement
TEP accepts Staff’s proposed modifications to the Company’s energy procurement program except the Risk Manager recommendation. The Settlement addresses the recommendation related to the sulfur credit refund as explained in the discussion under Section D. PPFAC regarding the sulfur credit.
K. San Juan Thermal Event (Fire)
TEP agrees to maintain a separate accounting of all direct costs related to the thermal event at the San Juan mine and that such cost recovery, with the exception of TEP’s share of the insurance deductible, be deferred until the insurance settlement has been completed. TEP shall then be eligible to put through all costs in excess of the insurance recovery subject to the standard prudence determination of all fuel costs flowed through the PPFAC. This accounting and regulatory treatment is not intended to set a precedent for future events.
L. Nogales Transmission Line Costs
TEP will seek appropriate rate treatment from FERC for recovery of those costs.
M. Timing of Effective Rates
The parties shall use best efforts to ensure that the Commission shall have the opportunity to discuss this matter at its June, 2013 Open Meeting and thereby issue a decision to implement new rates by July 1, 2013.
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