4. Regulatory Matters

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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.) The following table details Duke Energy’s regulatory assets and liabilities.

Regulatory Assets and Liabilities

		Assets (Liabilities)		December 31,
				2002					2001
				(in millions)
		Purchased capacity costs (see Note 5) (a)		$	151				$	349
		Deferred debt expense			263					203
		Net regulatory asset related to income taxes			936					510
		U.S. Department of Energy (DOE) assessment fee (b)			44					53
		Emission allowance control (b)			4					10
		Demand-side management costs (b)			38					57
		Gas purchase costs (c)			44					—
		Project costs (b)			20					—
		Environmental cleanup costs (b)			10					28
		Nuclear property and liability reserves (d)			(152	)				(100	)
		Fuel cost liabilities (d)			(7	)				(17	)

Franchised Electric. 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 sales are set through contractual agreements. (See Note 5 for ownership interests in Catawba Nuclear Station.)

Franchised Electric has currently recorded approximately $660 million in regulatory assets (net of regulatory liabilities). 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. In addition to cost recovery, Franchised Electric records a current return on the purchased capacity and demand-side management assets.

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 Duke Energy 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 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding Regional Transmission Organizations (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.

As a result of these rulemakings, Duke Power and the franchised electric units of two other investor-owned utilities, Progress Energy (formerly known as 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, 2002, Duke Energy had invested $37 million in GridSouth, including carrying costs. 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. In March 2001, GridSouth received provisional approval from the FERC. 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 and the outcome of initiatives such as the FERC’s Notice of Proposed Rulemaking (NOPR) on Standard Market Design (SMD) and the RTO cost/benefit study initiated by the Southeastern Association of Regulatory Utility Commissioners (SEARUC). The SEARUC cost/benefit study, issued in November 2002, states that under most scenarios neither RTOs nor SMDs provide net benefits to retail customers in the Southeast over the next few years. The final rule from the SMD NOPR is not expected to be issued until after July 2003. 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 believes its investment in GridSouth is probable of recovery.

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. The Carolina Utilities Customer Association, a group that represents industrial customers in regulatory proceedings before the NCUC, has appealed the decision related to the settlement agreement to the North Carolina Court of Appeals. 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’s regulatory reporting from 1998 to 2000. Duke Energy intends to fully cooperate with the government in connection with this investigation.

Natural Gas Transmission. The British Columbia Pipeline System (BC Pipeline) and the field services business in western Canada have recorded approximately $479 million of regulatory assets related to deferred income tax liabilities. Under the current NEB 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, 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 these 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.

Union Gas (which provides gas distribution, transportation and storage services in Ontario, Canada) has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly, if required, to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred pending approval by the OEB. Gas purchase costs deferred by Union Gas as of December 31, 2002 were $44 million, and are expected to be recovered from customers in 2003 and 2004. These amounts represent a direct flow-through of costs to customers and, therefore, no rate of return is earned on the deferred balances. The OEB’s approval for recovery of these gas purchase costs focuses on a review of the prudence of costs incurred. Management believes that recovery of these costs is probable.

Texas Eastern Transmission, LP, which is primarily engaged in the interstate transportation and storage of natural gas, has recorded approximately $65 million of regulatory assets related to income taxes, loss on redeemed debt and environmental clean-up costs. Management believes that recovery of these costs is probable.

In 2000, the FERC issued Order 637, which revised its regulations for the intended purpose of improving the competitiveness and efficiency of natural gas markets. Order 637 effects changes in capacity segmentation, rights of first refusal (ROFR), scheduling procedures, as well as various reporting requirements intended to provide more transparent pricing information and permit more effective monitoring of the market. The FERC also required each interstate pipeline to submit individual compliance filings to implement the requirements of Order 637. Several parties, including Duke Energy, filed appeals in the District of Columbia Court of Appeals seeking court review of various aspects of Order 637, including (1) the right of customers to segment their capacity rights in a manner that would allow both a forwardhaul and a backhaul transportation transaction to a single delivery point, and (ii) the ROFR granted to existing customers to extend contracts beyond the end of the contract’s primary term. In 2002, the District of Columbia Court of Appeals generally affirmed the Order but remanded certain issues to the FERC for further disposition, including the forwardhaul/backhaul and ROFR issues. These matters are still under review by the FERC. In addition to the Order 637 general rulemaking proceeding, Duke Energy’s interstate pipelines made individual tariff filings to comply with the requirements of Order 637, and these individual compliance proceedings are in different stages of the review, approval and implementation process before the FERC. Management believes that the implementation of Order 637 will have no material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

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.

The process for OEB approval of Union Gas’ rates for 2003 is currently underway. A settlement agreement was filed with the OEB on January 20, 2003. The agreement settled many financial and operating issues for 2003, including a rate decrease of 2.3% effective January 1, 2003 pursuant to the pricing formula set by the OEB in its performance based regulation decision. The settlement agreement was approved by the OEB in February 2003. A hearing was held before the NEB in February 2003 to resolve outstanding issues and a decision is pending.

During 2002, Union Gas applied to the OEB for a change to the OEB formula used to set the return on equity (ROE). The proposed methodology has the effect of increasing the ROE awarded to Union Gas effective January 1, 2002. The OEB has decided to review the applications in a combined hearing that is expected to take place in the third quarter of 2003. With the expiration of the Performance-Based Regulation (PBR) trial period at the end of 2003, Union Gas plans on filing a cost of service rate application in the second quarter of 2003 to establish 2004 rates and expects to file a proposal for second generation PBR for 2005 in the fourth quarter of 2004.

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 September 2001, the FERC issued a NOPR announcing they would substantially modify the current standards of conduct uniformly applicable to natural gas pipelines and electric transmitting public utilities currently subject to differing standards. The proposal impacts how companies and their affiliates interact and share information by broadening the definition of “affiliate” covered by the standards of conduct. The NOPR also sought comment on whether the standards of conduct should be broadened to include the separation of employees involved in the bundled retail electric sales function from those in the transmission function, as the current standards only require those involved in wholesale marketing activities to be separated from the transmission function. Duke Energy filed extensive comments on the NOPR with the FERC in December 2001. In April 2002, the FERC Staff issued an analysis of all comments received which reflected important progress in several areas. With regard to corporate governance, however, the FERC Staff’s analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with transmission functions (pipeline and storage functions) and transmission functions within a single company that conducts both electric transmission and marketing functions (such as Duke Power). A public conference was held in May 2002 to discuss the proposed revisions to the gas and electric standards of conduct. Duke Energy filed supplemental comments with respect to the FERC Staff’s analysis in June 2002. The FERC is expected to take further action on the NOPR in the first half of 2003.

NOPR on Standard Market Design. In July 2002, the FERC approved a NOPR entitled Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (Standard Market Design or SMD). The FERC has proposed to modify the open access transmission tariff and implement an SMD that would apply to RTOs and to individual utilities that have not yet joined an RTO. The FERC proposes to require each transmission owner to give an Independent Transmission Provider (ITP) operational control over the transmission owner’s facilities. These ITPs will file SMD tariffs for transmission and ancillary services, administer day-ahead and real-time markets, monitor and mitigate market power, perform long-term resource adequacy and participate in transmission planning and expansion on a regional basis.

Duke Energy filed comments on certain aspects of the NOPR in November 2002, and again in January 2003, for those aspects of the filing for which the FERC chose to extend the comment deadline (e.g., transmission planning and pricing, states role, resource adequacy and congestion revenue rights). The NOPR contemplates implementation of SMD by 2004, although there are indications that the FERC expects the implementation timetable to be delayed. The FERC has stated that they will issue a White Paper on the SMD in April 2003. The White Paper is expected to reflect the evolution in the SMD discussion brought about by the various filed comments and testimony presented at technical conferences. No date for the final rule has been set.

©Copyright 2003

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