December 12, 2007
Mr. Michael Moran
Branch Chief
United States Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 3561
450 Fifth Street, N.W.
Washington, D.C. 20549
FILED VIA EDGAR
Dear Mr. Moran:
The Empire District Electric Company (the “Company”) has received your letter dated November 30, 2007 (the “Comment Letter”) setting forth the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) relating to the Company’s Form 10-K for the year ended December 31, 2006 (the “Form 10-K”).
The Company acknowledges that it is responsible for the adequacy and accuracy of the disclosure in the Form 10-K and in its other filings under the Securities Exchange Act of 1934, as amended. The Company acknowledges that comments of the Staff regarding the Form 10-K or changes to disclosure in response to the Staff’s comments do not foreclose the Commission from taking any action with respect to such filings. The Company also acknowledges that the Staff’s comments may not be asserted by the Company as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
For your convenience, we have reproduced the comment from the Comment Letter (in bold) immediately before the Company’s response.
Dividends, page 55
1. Please revise future disclosure within the notes to the financial statements to explain the circumstances when your Junior Subordinated Debentures 8-1/2% Series can restrict your ability to pay dividends. See 4-08(e) of Regulation S-X.
We will revise our future disclosures to explain the circumstances when our Junior Subordinated Debentures 8-1/2% Series can restrict our ability to pay dividends. As supplemental information for the Staff, we intend to revise our disclosure as follows: “In addition, under certain circumstances, our Junior Subordinated Debentures, 8-1/2% Series due 2031, reflected as a note payable to securitization trust on our balance sheet, held by Empire District Electric Trust, an unconsolidated securitization trust subsidiary, may
also restrict our ability to pay dividends on our common stock. These restrictions apply if: (1) we have knowledge that an event has occurred that would constitute an event of default under the indenture governing these junior subordinated debentures and we have not taken reasonable steps to cure the event, (2) we are in default with respect to payment of any obligations under our guarantee relating to the underlying preferred securities, or (3) we have deferred interest payments on the Junior Subordinated Debentures, 8-1/2% Series due 2031 or given notice of a deferral of interest payments.”
Critical Accounting Policies, page 56
2. We note that unrecognized investment gains and losses related to your pension benefits (and OPEB benefits as discussed in Note 1 on page 77) are recognized in expense over a 10-year period. Please clarify if this is how you determine market-related value of assets and explain how this complies with the 5 year requirement in paragraph 30 of Statement no. 87.
The 10-year amortization period refers to the period over which gains or losses are amortized into FAS 87 expense. It does not refer to how the market-related value of our pension and OPEB assets is determined. The market-related value (“MRV”) of assets is determined by smoothing gains / (losses) over 5 years. Gains / (losses) are defined as the difference between the actual return on the fair value of assets and the expected return on the MRV. The MRV is equal to the fair value of assets as of the measurement date minus the sum of the following amounts:
80% of the gain / (loss) during the prior year
60% of the gain / (loss) during the second prior year
40% of the gain / (loss) during the third prior year
20% of the gain / (loss) during the fourth prior year
This complies with paragraph 30 of SFAS 87 and paragraph 57 of SFAS 106.
Regulatory Assets and Liabilities, page 58
3. You indicate that you normally recognize expenses and credits when incurred. Please explain any circumstances in which you had deferrals which were not incurred. We may have further comment.
In accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation (“SFAS 71”), we record a regulatory asset for all or part of an incurred cost that would otherwise be charged to expense if the conditions of paragraph 9a and b of SFAS 71 have been met. Additionally, we follow SFAS 71 paragraph 11 which says that a liability should be recorded when a regulator has provided current recovery for a cost that is expected to be incurred in the future. We follow this guidance for incurred costs or credits that are subject to future recovery from or refund to our customers in accordance with the orders of our regulators. The disclosure you reference on page 58 is intended to describe our accounting policy related to regulation and our compliance with the guidance of SFAS 71. All of our recorded regulatory assets and liabilities comply with the guidance of SFAS 71 and none of them have been deferred before the cost was incurred.
Consolidated Statements of Income, page 66
4. Explain to us the charge that was taken related to the plant disallowance and how you calculated the amount recorded.
We routinely capitalize costs of additions to utility plant and property and assess the recoverability of these costs from rate payers. Historically, such costs have been allowed rate recovery by our customers. As a
result, we have historically concluded that costs incurred between rate cases will be allowed recovery in future rates, including costs associated with our Energy Center Units 3 and 4. In our Missouri rate case (ER-2006-0315) Stipulation and Agreement as to Certain Issues, approved December 21, 2006, the Company agreed to a disallowance for regulatory purposes of the Missouri jurisdictional portion of $1 million of our Energy Center Units 3 and 4 costs recorded in Plant in Service, which would not be afforded rate recovery in Missouri rates. In accordance with SFAS 71, paragraph 10, we reduced the capitalized value of our Energy Center Units 3 and 4 by recording a charge to expense for $828,000, which represents the Missouri jurisdictional portion of these capitalized costs. Until this stipulation was finalized on December 21, 2006, we considered these capitalized costs to be probable of recovery in rates. The remaining portion of the costs, $172,000, relates to non-Missouri jurisdictions for which we are recovering or it is probable that we will recover such costs in our rates.
Regulatory Assets and Liabilities and Deferred Items, page 88
5. Please explain the nature of the regulatory liability for pension and other postretirement benefits and any interrelatedness of this item to the pension related regulatory assets. In this regard, we note the disclosure on page 98 that approximately $6 million was recorded as a regulatory pension liability in connection with the adoption of SFAS no. 158. Furthermore, we assume you made fair value pension adjustments related to the acquisition of Missouri Gas, if not, please explain.
We account for our pension and OPEB plans following the guidance of SFAS 87 and SFAS 106. The costs associated with our pension and OPEB plans are recovered in our rates charged to customers in all of our jurisdictions. To facilitate this recovery, our Missouri regulators have permitted us to use a tracking mechanism to capture the difference between pension and OPEB costs determined in accordance with SFAS 87 and SFAS 106 and the amount of pension and OPEB costs which are currently part of our rates. Our Kansas regulators also allow similar treatment for pension costs. This difference is recorded as a regulatory asset or liability in accordance with SFAS 71 as it is or will be recovered or refunded through our future rates granted by our regulators.
Additionally, when we adopted the provisions of SFAS No. 158, we concluded that the additional unfunded pension and OPEB obligations required to be recorded on our balance sheet by SFAS No. 158 were also probable of future rate recovery based on, among other factors, the SFAS 87 and SFAS 106 rate recovery mechanisms present in our jurisdictions. Thus a regulatory asset was recorded to offset any charges that would otherwise have been recorded to accumulated other comprehensive income under SFAS 158.
Lastly, we recorded fair value adjustments to the pension and OPEB liabilities as part of our purchase accounting related to the acquisition of Missouri Gas, and recorded the offset to those adjustments as regulatory assets. Pursuant to an order reached with the Missouri Public Service Commission (MPSC), (Case No. GO-2006-0205) it was agreed that the effects of purchase accounting entries related to pension and OPEB would be recoverable in future rate proceedings. These costs are probable of recovery in future rates, therefore regulatory assets have been recorded in accordance with SFAS 71.
As supplemental information to the Staff, the following table presents all the recorded amounts of regulatory assets and liabilities as of September 30, 2007 associated with our pension and OPEB plans:
Description |
| Amount (in millions) |
| Explanations |
|
|
|
|
|
Pension Tracker |
| $(1.3) |
| Rate recovery higher than expense to date for gas segment and Kansas jurisdiction electric segment |
|
|
|
|
|
Pension Tracker |
| 2.4 |
| Expense higher than rate recovery for electric segment in Missouri |
|
|
|
|
|
Pension — FAS 158 |
| 25.3 |
| Offset to unfunded liability recorded upon adoption of FAS 158; see discussion above |
|
|
|
|
|
OPEB - FAS 158 |
| 4.4 |
| Offset to unfunded liability recorded upon adoption of FAS 158; see discussion above |
|
|
|
|
|
Tax Benefit - OPEB Medicare D Subsidy |
| (6.4) |
| Additional tax benefits resulting from Medicare D subsidy that will be passed through to ratepayers |
|
|
|
|
|
Pension and OPEB — Missouri Gas Acquisition |
| 5.7 |
| Offset to fair value entries; see discussion above |
|
|
|
|
|
OPEB - Other |
| 2.3 |
| Other OPEB deferred costs currently being recovered in rates in MO, KS and AR |
12. Commitments and Contingencies, page110
Gas Segment, page 115
6. Please revise your future disclosure to provide an estimate of future remediation costs related to your MGP Sites, or state that such an estimate cannot be made. See paragraph 10 of SFAS no. 5. Furthermore, please explain how the current rate structure addresses this issue. Also, please explain what consideration you gave to SAB Topic 2.A.7 regarding this issue as it relates to the purchase price allocation of Missouri Gas.
We will revise our future disclosures to include an estimate of future remediation costs related to our MGP sites. As supplemental information for the Staff, we intend to revise our disclosure as follows: “We estimate our remediation costs to be approximately $319,000, based on our best estimate at this time.”
Relative to the purchase price allocation for Missouri Gas, we recorded an estimated liability for future costs of $319,000. This amount was based on a range of independently determined fair values for the estimated costs to remediate the property at two sites. This fair value estimate included a likelihood assessment per the guidance in SFAS 5. We believe that this methodology is consistent with the guidance of SAB Topic 2.A.7.
Our agreement with the MPSC (Case No. GO-2006-0205), approving the acquisition of Missouri Gas, states that we can reflect a liability and offsetting regulatory asset not to exceed $260,000 for the acquired manufactured gas plant (MGP) sites. The Commission agreed that up to $260,000 of costs related to the clean-up of these MGP sites would be allowed for future rate recovery. Accordingly, we concluded that rate recovery was probable. At the acquisition date, a regulatory asset of $260,000 was recorded as part of the purchase price allocation based on our agreement with the MPSC, and in accordance with SFAS 71.
We believe that we have fully responded to your comments. However, if you have any questions about any of our responses to your comments or require further explanation, please do not hesitate to call me at (417) 625-6595.
| Sincerely, | ||
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| THE EMPIRE DISTRICT ELECTRIC COMPANY. | ||
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| By: | /s/ Gregory A. Knapp |
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| Gregory A. Knapp | |
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| Chief Financial Officer | |
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