4. Regulatory Matters
Regulatory Assets and Liabilities. Duke Energy's regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (See Note 1.)
Duke Energy's Regulatory Assets and Liabilities
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December 31, |
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Assets (Liabilities) |
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2003 |
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2002 |
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(in millions) |
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Net regulatory asset related to income taxes |
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$ |
1,152 |
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$ |
936 |
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Asset retirement obligation (ARO) costs(a) |
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547 |
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— |
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Deferred debt expense |
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169 |
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174 |
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Vacation accrual(a) |
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70 |
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|
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— |
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U.S. Department of Energy (DOE) assessment fee(a) |
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33 |
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44 |
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Demand-side management costs(a) |
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18 |
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38 |
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Project costs(a) |
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17 |
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20 |
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Environmental cleanup costs(a) |
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8 |
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10 |
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Emission allowance control(a) |
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2 |
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4 |
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Removal costs(b) |
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(948) |
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— |
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Nuclear decommissing costs(b) |
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(259) |
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— |
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Other deferred tax credits(b) |
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(160) |
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(156) |
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Nuclear property and liability reserves(b) |
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(157) |
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(152) |
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North Carolina clean air compliance(b) |
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(95) |
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— |
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South Carolina rate decrement |
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(23) |
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— |
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Purchased capacity costs (see Note 5)(c) |
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(43) |
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151 |
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Fuel cost liabilities(b) |
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(30) |
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(7) |
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Gas purchase costs(d) |
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(28) |
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44 |
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| (a)Included in Other Regulatory Assets
and Deferred Debits on the Consolidated Balance Sheets |
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| (b)Included in Other Deferred Credits, Other Liabilities and Current Liabilities on the Consolidated Balance Sheets | ||||||||
| (c)Included in Other Current Assets, Other Regulatory Assets and Deferred Debits, Other Current Liabilities, and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets | ||||||||
| (d)Included in Accounts Payable and Receivables on the Consolidated Balance Sheets | ||||||||
Duke Energy periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, companies may have to reduce their asset balances to reflect a market basis less than cost, and write-off their associated regulatory assets and liabilities.
Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy's contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE's failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy's costs incurred as a result of the DOE's partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power.
Removal Costs and Nuclear Decommissioning Costs. As a result of the adoption of SFAS No. 143 on January 1, 2003, approximately $1,207 million of removal costs and nuclear decommissioning costs at December 31, 2003 related to certain of Duke Energy's regulated operations have been classified as regulatory liabilities. See Note 7 for further discussion.
Franchised Electric. Rate Related Information. The NCUC and the PSCSC approve rates for retail electric sales within their states. The FERC approves Franchised Electric's rates for electric sales to wholesale customers, excluding the other joint owners of the Catawba Nuclear Station: those rates are set through contractual agreements.
At December 31, 2003, Franchised Electric had recorded approximately $500 million in regulatory liabilities (net of regulatory assets). Management estimates that current rates are sufficient to recover these costs, in addition to providing a reasonable return for shareholders. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. This assessment reflects the current political and regulatory climate in the states in which Franchised Electric operates, and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be required to be recognized in current period earnings. The majority of these regulatory assets, including deferred debt expense and the regulatory asset related to income taxes, are amortized and recovered over the lives of the related assets/debt instruments.
Fuel costs are reviewed semiannually by the FERC and annually by the PSCSC, with provisions for reviewing those costs in base rates. The NCUC reviews fuel costs in rates annually and during general rate case proceedings. All jurisdictions allow Franchised Electric to adjust electric rates for past over- or under-recovery of fuel costs. The difference between actual fuel costs incurred for electric operations and fuel costs recovered through rates is reflected in revenues.
In 2002, the state of North Carolina passed clean air legislation that includes provisions that freeze electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007 (rate freeze period), subject to certain conditions, in order for certain North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state's coal-fired power plants over the next ten years. Included in the legislation are provisions that allow electric utilities, including Duke Energy, to accelerate the recovery of these compliance costs by amortizing them over seven years (2003-2009). Franchised Electric's amortization expense for 2003 included $115 million related to this clean air legislation. The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized within certain limits although the legislation requires that a minimum of 70% of the total be amortized within the rate freeze period. In year 2003, amortization of compliance costs were approximately 54% of the annual levelized compliance costs.
In 2003, Duke Power reported to the PSCSC a 14.25% return on common equity, for the twelve month period ending March 31, 2003, for Duke Power's retail operations in South Carolina. In Duke Power's most recent base rate case proceeding, the PSCSC approved a rate of return on common equity range of 12.00% to 12.50% for Duke Power's South Carolina retail operations, with South Carolina retail rates based on 12.25%. In connection with the PSCSC's monitoring of the financial and operational condition of jurisdictional electric utilities, the PSCSC requested, and Duke Power provided, certain information relating to its reported returns on common equity. As a result, in September 2003, the PSCSC ordered Duke Power to implement a rate decrement of $30 million for South Carolina rates over the next twelve months (which took effect October 1, 2003 and expires September 30, 2004). The rate decrement was recorded in 2003 as an other liability (as it resulted from past bills paid by customers) and as a charge to revenues. Under this ruling, Duke Power was ordered in 2003 to write off to interest expense $16 million in deferred debt issuance costs that were previously capitalized as a regulatory asset.
Regional Transmission Organizations (RTOs). In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding RTOs. These orders set minimum characteristics and functions RTOs must meet, including independent authority to establish the terms and conditions of transmission service over the facilities they control. The orders provide for an open and flexible RTO structure to meet the needs of the market and for the possibility of incentive ratemaking and other benefits for transmission owners that participate. The FERC proposes to have RTOs or other independent transmission providers operate transmission systems in all regions of the country.
As a result of these rulemakings, Duke Power and the franchised electric units of two other investor-owned utilities, Carolina Power & Light Company and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies' combined transmission systems. As of December 31, 2003, Duke Energy had invested $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. The sponsors expected that GridSouth would be substantially operational by the FERC's Order 2000 "deadline" date of December 15, 2001. However, in July 2001 the FERC ordered GridSouth and other utilities in the Southeast to join in a mediation to negotiate terms of a southeastern RTO. It does not appear that the FERC will issue an order specifically based on that proceeding. In 2002, the GridSouth sponsors withdrew their applications to the NCUC and the PSCSC for approval of the transfer of functional control of their electric transmission assets to GridSouth, and announced that development of the GridSouth implementation project had been suspended until the sponsors have an opportunity to further consider regulatory circumstances. Duke Energy believes that more open wholesale electric markets will at some point provide benefits to consumers and other market participants. Duke Energy continues to examine options relative to RTOs in light of the existing complex regulatory environment. Management expects it will recover its investment in GridSouth.
Other Matters. As part of a fee in lieu of taxes agreement with Cherokee County, South Carolina, Duke Energy has agreed to transfer legal title of its Mill Creek combustion turbine facility located in Cherokee County, SC, to Cherokee County and then lease Mill Creek back from Cherokee County for approximately 20 years. Under the lease agreement, Duke Energy will continue to operate Mill Creek as if it were the owner and will bear all costs of maintaining, operating and repairing Mill Creek. Duke Energy will retain the exclusive right to use Mill Creek. At the end of the twenty-year lease period, Cherokee County will transfer legal title of Mill Creek back to Duke Energy. The assets of Mill Creek will continue to be carried upon the books of Duke Energy as this transaction does not meet the qualifications for sale-leaseback accounting treatment.
On January 14, 2003, the PSCSC decided to conduct an independent management audit of Duke Power's preventive maintenance programs and service restoration procedures for its South Carolina retail electric service area in connection with a winter storm in December 2002. The PSCSC has contracted an independent firm to perform the management audit on its behalf. In late November 2003, the independent firm submitted its report to the PSCSC and in early December 2003, Duke Power submitted its response to issues raised by the report. Management believes that the final disposition of this matter will have no material adverse effect on consolidated results of operations, cash flows or financial position.
In 2001, the NCUC and the PSCSC began a joint investigation, along with the Public Staff of the NCUC, regarding certain Duke Power regulatory accounting entries for 1998, including the classification of nuclear insurance distributions. As part of their investigation, the NCUC and the PSCSC jointly engaged an independent firm to conduct an accounting investigation of Duke Power's accounting records for reporting periods from 1998 through June 30, 2001. In 2002 Duke Power entered into a settlement agreement with the NCUC and the PSCSC in which the parties agreed to changes in the accounting primarily related to nuclear insurance distributions, a one-time $25 million credit to Duke Power's deferred fuels account for the benefit of North Carolina and South Carolina customers, the reclassification of $50 million of a $58 million suspense account to a nuclear insurance operation reserve account and an additional $2 million adjustment to the nuclear insurance operation reserve account. The remaining $8 million in the suspense account was credited to income, resulting in a net $19 million pre-tax charge in 2002. A residential retail customer and the Carolina Utility Customers Association, Inc., (CUCA) a group that represents industrial customers in regulatory proceedings before the NCUC, appealed the decision related to the settlement agreement to the North Carolina Court of Appeals. On February 17, 2004, a panel of the North Carolina Court of Appeals unanimously affirmed the NCUC's decision. In addition, in February 2003, Duke Energy received a Western District of North Carolina Grand Jury subpoena for documents related to the audit by the NCUC and the PSCSC of Duke Power regarding certain Duke Power regulatory accounting entries from 1998 to 2000. On March 10, 2004, Duke Energy received notice from the U.S. Attorney for the Western District of North Carolina that its investigation had been closed and that no action against Duke Energy or any individuals was warranted.
In 2002, the NCUC issued an order denying a petition by CUCA to initiate a general rate proceeding and dismissing its complaint alleging unjust and unreasonable rates charged by Duke Power. CUCA appealed this order to the North Carolina Court of Appeals and on February 17, 2004, a panel of the Court unanimously ruled that the NCUC's denial of CUCA's petition and complaint was proper and therefore affirmed the NCUC's order.
Natural Gas Transmission. Rate Related Information. The British Columbia Pipeline System (BC Pipeline) and the field services business in western Canada have recorded approximately $543 million of regulatory assets related to deferred income tax liabilities. Under the current NEB-authorized rate structure, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services' rates will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.
When evaluating the recoverability of the BC Pipeline and the field services' regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and the field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.
On December 1, 2003, BC Pipeline filed an application with the NEB for an order approving cost of service based tolls for 2004. It is not possible to predict at this time what the final result of those applications, including the impact on tolls and rates, will be.
Union Gas Limited (Union Gas) has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recovery from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB's review and approval of these gas purchase costs primarily considers the prudence of the costs incurred.
The process for OEB approval of Union Gas' rates for 2004 is currently underway, with an OEB decision expected during the first quarter of 2004.
During 2002, Union Gas applied to the OEB for a change to the formula used to set the return on equity (ROE). In September 2003, the OEB consolidated this application with a similar application brought by Enbridge Gas Distribution. The proposed methodology had the effect of increasing the ROE awarded to Union Gas. In January 2004, the OEB issued its decision which reaffirmed the existing formula.
The OEB has proposed changes to the implementation dates for the Gas Distribution Access Rule (GDAR). GDAR provides the means by which gas vendors access gas distribution systems in Ontario. A March 2004 compliance deadline established by the OEB is expected to be extended to February 1, 2005. Union Gas has been granted leave to appeal the vendor consolidated billing provisions of GDAR by the Court of Appeal for Ontario.
In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.
Management believes that the effects of these matters will have no material adverse effect on Duke Energy's future consolidated results of operations, cash flows or financial position.
Notices of Proposed Rulemaking (NOPR). NOPR on Standards of Conduct. In November 2003, the FERC issued Order 2004, which harmonizes the standards of conduct applicable to natural gas pipelines and electric transmitting public utilities previously subject to differing standards. There remain two key issues regarding which Duke Energy has filed a formal request for clarification and rehearing with the FERC. The issues concern the Order's (i) restriction on how companies and their affiliates interact and share information, including corporate governance information, and (ii) expansion of coverage to affiliated gatherers, processors, and intrastate pipelines. A response to the request is anticipated in the second quarter of 2004. Full compliance with Order 2004 is required by June 1, 2004.
NOPR on Amendments to Blanket Sales Certificates and Order Proposing to Amend Market-Based Tariffs and Authorizations. In November 2003, the FERC issued two separate orders which condition market-based rate and blanket certificate authority on compliance with market behavior rules and codes of conduct addressing market manipulation, price reporting and record retention. Violation of the new conditions could result in disgorgement of unjust profits or suspension or revocation of a company's tariff or certificate. Duke Energy does not anticipate any significant financial impacts resulting from compliance with these new rules.
Final Rule on Cash Management Practices. In October 2003, the FERC issued a Final Rule implementing documentation and reporting requirements for FERC-regulated entities that participate in cash management programs. Management expects the Final Rule to have no material adverse effect on the consolidated results of operations, cash flows or financial position.