STATE OF NORTH CAROLINA UTILITIES COMMISSION RALEIGH DOCKET NO. E-100, SUB 84

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1 STATE OF NORTH CAROLINA UTILITIES COMMISSION RALEIGH DOCKET NO. E-100, SUB 84 BEFORE THE NORTH CAROLINA UTILITIES COMMISSION In the Matter of Investigation of Integrated Resource Planning in North Carolina ) ORDER ADOPTING INTEGRATED RESOURCE ) PLANS ) BY THE COMMISSION: North Carolina General Statute (c) requires the North Carolina Utilities Commission (Commission) to "develop, publicize, and keep current an analysis of the long-range needs" for electricity in this State. This includes (1) the Commission's estimate of the probable future growth of the use of electricity; (2) the probable needed generating reserves; (3) the extent, size, mix and general location of the generating plants; (4) arrangements for pooling power to the extent not regulated by the Federal Power Commission (now the Federal Energy Regulatory Commission, or the FERC); and (5) other arrangements with other utilities and energy suppliers. The purpose of this requirement is "to achieve maximum efficiencies for the benefit of the people of North Carolina." The statute requires the Commission to develop a plan for the future requirements for electricity for North Carolina or the area served by a utility and to consider its analysis in acting upon any petition for construction. In addition, it requires the Commission to submit annually to the Governor and to the appropriate committees of the General Assembly the following: (1) a report of its analysis and plan; (2) the progress to date in carrying out such plan; and (3) the program of the Commission for the ensuing year in connection with such plan. Commission Rule R8-60 requires that each of the investor-owned utilities and the North Carolina Electric Membership Corporation, (collectively, "the utilities") furnish the Commission with an annual report that contains specific information that is set out in subsection (c) of the rule and provides that the Public Staff and any other intervenor may file its own report, evaluation, or comments regarding the utilities' reports. In addition, Rule R8-62(p) requires certain additional information be included in the reports about the construction of transmission lines. In its July 13, 1999 Order Adopting Least Cost Integrated Resource Plans And Clarifying Future Filing Requirements in Docket No. E-100, Sub 82, the Commission imposed additional requirements for the Annual Reports. Specifically, the utilities were directed to include a full response to each item of information required by the Rules; appropriate explanations for each item where the information requested is not available; and appropriate explanations referencing the location of information in the filings where such information does not follow the same general order of presentation as contained in the Commission Rules. The Commission further ordered the utilities to adhere to the requirement that each ten-year forecast and plan consist of the ten years next succeeding the annual September 1 filing date. Finally, the Commission required the utilities to file 1999 Annual Reports which included a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of projected reserve margins and a discussion of the adequacy of the respective utility's transmission system. On or about September 2, 1999, the second Integrated Resource Plan (IRP) filings were made under the current rules by Carolina Power & Light Company (CP&L), Duke Power (Duke), North Carolina Power (NC Power), and North Carolina Electric Membership Corporation (NCEMC). On December 7, 1999, the Public Staff filed its comments on the IRPs filed by the utilities. On December 21, 1999, Duke and NC Power filed responses to the Public Staff comments. CP&L and NCEMC did not file reply comments. By Order issued October 29, 1999, public hearings were scheduled for the purpose of taking non-expert public witness testimony during the month of January. By Order issued February 10, 2000, the public hearings previously scheduled in Edenton and Raleigh were rescheduled for March 28, 2000, in Raleigh. Carolina Industrial Group for Fair Utility Rates I and II (CIGFUR) intervened in the proceeding but did not file comments.

2 UTILITY RESPONSES TO RULES R8-60(c) AND R8-62(p) The Public Staff comments contained a summary of the information filed by the utilities in response to requirements contained in Rules R8-60 and 62. All of the information filed by the utilities was satisfactory to the Public Staff, except for two instances: (1) NC Power responded to the requirement for listing wholesale purchase power commitments by stating that "there are no wholesale purchase power commitments included in the ten-year forecast" and that "for purposes of this filing, purchase contracts with non-utility generators are considered 'firm purchases' rather than 'wholesale purchase commitments.'" The Public Staff considered the response "unclear." (2) NCEMC did not respond to the requirement for the information on transmission lines contained on FERC Form 1. The Public Staff commented that NCEMC is not subject to FERC jurisdiction and thus does not generate the FERC Form 1 information. Nevertheless, as the Public Staff pointed out, the previous Order Adopting Least Cost Integrated Resource Plans And Clarifying Future Filing Requirements, issued July 13, 1999, in Docket No. E-100, Sub 82, required "that future filings by all utilities pursuant to NCUC Rules R8-60 and R8-61 shall include a full response to each item of information required by the Rules." RESERVE MARGINS The Commission Order Adopting Least Cost Integrated Resource Plans And Clarifying Future Filing Requirements, issued July 13, 1999, in Docket No. E-100, Sub 82, required "that the filings due September 1, 1999, shall include a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of projected reserve margins and a discussion of the adequacy of the respective utility's transmission system." The Public Staff's comments contained the following discussion of the utilities' filings in response to the reserve margin portion of the requirement: (1) CP&L provided an assessment of the adequacy and appropriateness of its level of projected reserves. This assessment indicated that a reserve margin of 15% was adequate. CP&L found that the industry's widely used "one day in ten years" Loss-of-Load Exception (LOLE) criteria would be satisfied by a reserve level of 1,500 MWs, or a reserve margin of approximately 11.7%. CP&L used computer modeling, its own studies, and assessment of capacity assistance from neighboring electric systems to evaluate the reliability criteria. CP&L's survey of other utilities found a range of reserve margins, from 9.8% to 20.5%, with a majority of the utilities' reserves in the range of approximately 15% to 18%. CP&L also believes that the high reliability and small size of planned additions allow lower reserve levels. CP&L expects to attain a 15% reserve margin in all but the first two years of the current ten-year period. (2) Duke responded that its lowered reserve margin target of 17% was supported by the increased availability of existing generation, shorter lead times for new generation, and the emergence of new purchased power options. Duke's operating experience was also factored into the selection of a 17% reserve margin. Duke reported that between June 1997 and July 1999, there were 15 days when generating reserves dropped below 3%, without factoring in purchases and Demand Side Management (DSM). When purchases and DSM were factored in, the lowest reserve margin reached was 12%. Duke's reserve margin is slightly above the 17% target for the entire ten year planning period. (3) VEPCO reported that its target reserve margin is 12.5%. VEPCO's planning reserves in the past were established using a 12-hour loss of load criterion. VEPCO, this year, has initiated a review of this reserve planning criterion to evaluate its appropriateness. VEPCO's preliminary results determined that a reserve margin between 12% and 13% should be used as a target. An internal task force determined that a reserve margin of 12.5% would be adequate to cover various contingencies. This 12.5% reserve margin target is the lowest of the three major investor-owned utilities in North Carolina. Furthermore, while it is in the overall range that CP&L found for the utilities surveyed, it is well below the range of 15% to 18% maintained by the majority of the utilities in its survey. As noted earlier, VEPCO's reserves range from approximately 9.4% to 11.1 % for the 2000 to 2009 period, with the lowest levels occurring at the end of this period. VEPCO never reaches its target level of 12.5%, which is the level it plans to use to determine the amount of capacity to acquire in the wholesale market. For example, if VEPCO's reserve margin in the

3 last years of its forecast were at the 12.5% level, its reserves would have to be approximately 500 MWs higher. If VEPCO maintained a 15% reserve margin instead, the reserves would have to be over 900 MWs higher than reported. VEPCO has firm purchases of over 3,000 MWs for each year of the planning period. (4) NCEMC did not provide an assessment of the adequacy of its reserve margin. The Public Staff believes that the Commission should continue to require the filing of this reserve adequacy report, including the criteria used to determine reserve margin targets, within the annual IRP reports. The information supplied is important and is not found elsewhere. CP&L and Duke appear to meet their projected reserve margin targets for the planning period. VEPCO misses its target in all years, and its projected reserve margin declines beginning in 2004 and lasting through the end of the planning period. The Public Staff recommends that CP&L and Duke maintain reserve margins of approximately 15% and 17%, respectively. VEPCO should address whether its 12.5% target is adequate, when it is so much lower than CP&L's, Duke's, and the majority of the surveyed utilities and why its reserve margins do not meet even this target. Duke's response to the Public Staff's comments was as follows: The VACAR Reserve Sharing Agreement currently provides that the members collectively maintain 1,694 MW of Contingency Reserves. Duke's share is currently 525 MW. Each VACAR member maintains its share of Contingency Reserves, enabling the members to respond to such factors as generation and transmission equipment unavailability. Duke believes that it is inappropriate to create additional reserve measures and requirements. Duke's 1999 Annual Plan filing stated that continued use of the 17% planning reserve margin target is appropriate at this time. Duke continually reviews the generating system capability, level of potential DSM activities, scheduled maintenance, purchased power availability and transmission capability to assess Duke's capability to reliability meet the customer load. Duke notes that significant changes are taking place in the electric industry. As a result, it may be advisable to deviate from the 17% planning reserve margin target. Future Annual Plan filings will address reserve margins and it is inappropriate to attempt to establish future reserve margins in this manner. NC Power's response to the Public Staff's comments was as follows: In the Comments, Public Staff expresses concerns about the adequacy of NC Power's reserve margin target of 12.5%. The reserve margins shown on the Company's response to Item (1) are based on the results of the expansion planning process completed as part of the development of the Company's resource plan. These reserve margins represent the results of the model evaluation, indicating what the system reserves must be to maintain our commitment to providing reliable service to our customers (i.e., twelve loss-of-load hours exclusive of incremental capacity purchases from outside of our system). The Company's model assumptions take into account the very low forced outage rate of its nuclear units, as well as the relatively low forced outage rates of its fossil units. The assumptions also account for the large number of small capacity units on the Company's system which serve to minimize the effect of forced outages and increase overall system reliability. As noted by the Public Staff in the Comments, an internal task force, determined that a target reserve margin of 12.5% would be adequate to cover various contingencies. Comments at 6. See Report at 46. That task force, comprised of various executive level personnel, studied the appropriate target reserve margin needed to balance the concerns related to lower reserve margins resulting from the model evaluation and the uncertainty relating to the level of native load to be served in the near future resulting from total retail choice beginning in 2002 in Virginia. The task force determined that a 12.5 % reserve margin target would be the adequate level to carry on the system at this time. Since the filing of the Company's resource plan, the Company has issued a Request for Proposals (RFP) with an all-source bid, with preference toward peaking capacity. Bids in response to the RFP are due by January 17, 2000 at which time the Company will evaluate the best option for obtaining the capacity

4 needed to meet the 12.5 % target reserve margin level. CP&L did not respond to the Public Staff comments. TRANSMISSION ADEQUACY The Public Staff's comments contained the following discussion of transmission adequacy: All of the utilities included a statement regarding their transmission line adequacy as required in the July 19, 1999, Order in Docket No. E-100, Sub 82. However, these statements describe the process for ensuring adequacy rather than providing technical details that would be sufficient for assessing the impact of various planning elements. The Public Staff recommends that the Commission require the utilities to file the following information: 1. A statement on direct utility interconnections/transfer points. For each transfer point provide the voltage level, the transfer capabilities in and out of the system for both the summer and winter seasons, any limitation on generation and purchase power planning, and plans to improve or limit these transfer capabilities over the planning period. Indicate the amount of power passing through these points for wheeling to other utilities and the amounts imported for native loads. 2. A descriptive and quantitative discussion on the impact of the open access policy and power wheeling (wholesale and retail) on the transmission line capabilities and planning. 3. The utilities' needs for building or upgrading transmission lines to meet native load growth during the planning period. 4. The utilities' plans to meet expected power wheeling demand during the planning period. 5. A list of all transmission lines (161 KV and above) that were operated above 80% of design limits. Report at least the following information: maximum line loading, maximum design capability, projected loading growth in MWs during the planning period, schedule for improvements, if any, and anticipated capability improvement resulting from scheduled improvement(s). 6. Impact of loss of one major interconnection or one major line on other lines. 7. The Public Staff recommends that the Commission require the utilities to file this information with the transmission adequacy statement in their next IRP annual reports. Duke responded as follows: The overall Public Staff concern is that utilities responded with statements describing the process for ensuring transmission system adequacy rather than providing technical details that would be sufficient for assessing the impact of various planning elements. The Public Staff is recommending the filing of enormous amounts of data and information. Much of this data is publicly available in the form of reports and models as a result of ongoing joint studies with our interconnected neighbors. Duke opposes this burdensome recommendation and further expresses concern that should the Commission adopt the Public Staff's recommendations to institute a new filing requirement of this magnitude circumvents the appropriate rulemaking process and procedure. However, Duke believes this issue requires more clarity and suggests that a meeting attended by the Public Staff, Duke, CP&L, VEPCO and NCEMC be held to better understand the Commission's needs and suggest an efficient and responsive reporting mechanism. NC Power responded that it would not object to filing the information recommended by the Public Staff if the Commission should request it. FILING REQUIREMENTS FOR ECONOMIC DEVELOPMENT AND SELF-GENERATION DEFERRAL RATES

5 The Public Staff comments contained the following discussion of filing requirements for economic development and self-generation deferral rates: By Order issued November 28, 1994 in Docket No. E-100, Sub 73, the Commission adopted Interim Guidelines and Filing Requirements for Economic Development Rates, which also included selfgeneration deferral rates. CP&L and Duke have approved tariffs for economic development rates, and VEPCO has filed for such approval. The filing requirements state: The utility shall review the combined effects of existing economic development rates annually within the approved LCIRP process and file the results in its short-term action plan... Similar language appears in the guidelines for self-generation deferral rates contained in the same Docket. None of the utilities subject to these interim guidelines have complied with these requirements. The Public Staff recommends that the utilities with economic development and/or self- generation deferral rates comply with the filing requirements in their future annual reports pursuant to Rule R8-60. Duke responded as follows: Duke has an economic development rider. There are several customers currently receiving electric service under tariffs subject to the rider. The effects of the addition of and continued service to such customers on Duke's resource planning is reflected within the load forecast data. In future annual report filings, Duke would agree to include the overall peak demand in MW for this class of customers and total annual energy amount. However, to require filing of additional data regarding such rates in connection with the Annual Plan would involve the inclusion of information not relevant to integrated resource planning and would circumvent the appropriate rulemaking process. NC Power responded that it would comply with the requirement in all future IRP filings. Utility Responses to Rules R8-60(c) and R8-62(p) CONCLUSIONS NC Power did not list the firm purchases from each individual source in its original filing, but its response to the Public Staff comments included a list of individual sources for each firm purchase. The Commission considers the latter NC Power response to be satisfactory. NCEMC did not respond to the requirement for the information on transmission lines contained on FERC Form 1. The Commission notes that FERC Form 1, pages 422 and 423, requires statistics on existing transmission lines, which are to be filed once every five years. NCEMC has few or no existing transmission lines. FERC Form 1, pages 424 and 425, requires statistics on transmission lines added during the year. NCEMC did not add any transmission lines during the year and reported that it has none under construction. The Commission considers NCEMC's failure to state specifically that it had no information to report under Rule R8-62(p)(1) to be a minor omission, and that NCEMC's overall response to Rules R8-60 through R8-62 is reasonable. Reserve Margins The Commission recognizes that the electric power industry is in the midst of a time of economic and regulatory transition and that the resulting changes have led to the rethinking of certain long-accepted industry standards. As a result of these changes and the amount of information contained in the present record, the Commission does not believe that it is appropriate to mandate the use of any particular reserve margin for any jurisdictional electric utility at this time. For this reason, the Commission concludes that it would be more prudent to monitor the situation closely, to allow all parties the opportunity to address this issue in future filings with the Commission, and to consider this matter further in subsequent integrated resource planning proceedings. At this point, the Commission has no reason to believe that existing generation resources are inadequate in light of current conditions. The Commission does, however, want the record to clearly indicate its belief that providing adequate service is a fundamental obligation imposed upon all jurisdictional electric utilities, that it will be actively monitoring the adequacy of existing electric utility reserve

6 margins, and that it will take appropriate action in the event that any reliability problems develop. The Commission concludes that future filings by all utilities pursuant to Rules R8-60 and R8-61 should continue to include a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of the respective utility's projected reserve margins. Transmission Adequacy The Commission notes that much of the transmission data recommended by the Public Staff is provided in some form or other by each utility for use in the joint engineering studies of system reliability conducted by VACAR and SERC on an ongoing basis. Nevertheless, it is not clear how difficult it would be to compile the data in the form needed for an IRP filing. SERC's report to NERC addresses the same concerns about transmission adequacy, but it does not contain a compilation of the detailed data recommended by the Public Staff. The Commission is of the opinion that the suggestion by Duke for the interested parties to meet and discuss an efficient and responsive reporting mechanism for transmission adequacy is a good one. The results of such a meeting would be a suitable item for discussion in the next round of IRP filings due September 1, The Commission further concludes that future filings by all utilities pursuant to Rules R8-60 and R8-61 should continue to include a discussion of the adequacy of the respective utility's transmission system (161 KV and above). Load Served Under Economic Development Rates and Self-Generation Deferral Rates The Commission agrees that a utility review of the impact of its respective economic development rates (and selfgeneration deferral rates) is required by the Order of November 28, 1994, and notes that such review is specified to be in the context of the IRP process. The Commission concludes that future filings by all utilities pursuant to Rules R8-60 and R8-61 should identify, as applicable, the separate block of MW load representing those customers served under economic development rates and/or self- generation deferral rates. Approval of IRPs As indicated in earlier IRP dockets, the Commission is of the opinion that the IRP review is intended to ensure that each utility is generally including all of the considerations in its planning as required by the Commission's Rules; that each utility is generally utilizing state-of-the-art techniques for its forecasting and planning activities; and that each utility has developed a reasonable analysis of its long-range needs for expansion of generation capacity. Also, the Commission is of the opinion that evaluations of individual DSM programs, certificates to construct new generating plants or transmission lines, and individual purchased power contracts should be handled in separate dockets from the IRP proceeding. Consistent with this view, it should be emphasized that inclusion of a DSM program, proposed new generating station, proposed new transmission line or purchased power contract in the IRP does not constitute approval of such individual elements even if the IRP itself is approved. The Commission concludes that the current IRPs should be approved. No party has argued that the IRP filed by any utility should be rejected. The Public Staff's objections as to completeness of the current IRP filings have been adequately addressed. IT IS, THEREFORE, ORDERED as follows: 1. That this Order shall be adopted as a part of the Commission's current analysis and plan for the expansion of facilities to meet the future requirements for electricity for North Carolina pursuant to G.S (c); 2. That the Integrated Resource Plans filed by CP&L, Duke, NC Power, and NCEMC in this proceeding are hereby approved as hereinabove discussed; 3. That future filings by all utilities pursuant to Rules R8-60 and R8-61 shall continue to include a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of the respective utility's projected reserve margins.

7 4. That future filings by all utilities pursuant to Rules R8-60 and R8-61 shall continue to include a discussion of the adequacy of the respective utility's transmission system (161 KV and above); 5. That future filings by all utilities pursuant to Rules R8-60 and R8-61 shall identify, as applicable, the separate block of MW load representing those customers served under economic development rates and/or selfgeneration deferral rates; and 6. That the IRP filings due September 1, 2000, shall include a discussion of efforts by the interested parties to meet and develop an efficient and responsive reporting mechanism for transmission adequacy. ISSUED BY ORDER OF THE COMMISSION. This the 21st day of June, je NORTH CAROLINA UTILITIES COMMISSION Geneva S. Thigpen, Chief Clerk

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