FERC-516 & FERC-730 Final Rule (Docket No.RM06-4-000) July 20, 2006
Supporting Statement for
FERC-516, Electric Rate Schedule Filings
Promoting Transmission Investment through Pricing Reform
As Proposed in Docket No. RM06-04-000
(Final Rule issued July 20, 2006)
The Federal Energy Regulatory Commission (Commission/FERC) requests Office of Management and Budget (OMB) review and approval of FERC-516, Electric Rate Schedule Filings, an existing data requirement, regarding Promoting Transmission Investment through Pricing Reform as proposed in the Commission's Final Rule issued July 20, 2006, in Docket No. RM 06-4-000. FERC-516 (OMB Control No. 1902-0096) is currently approved by OMB through July 31, 2008.
In addition, the Commission is initiating a new information collection, FERC-730 “Report of Transmission Investment Activity”. Section 35.35(h) of the Final rule will require jurisdictional public utilities to report annually to the Commission no later than April 18, 2007, and, in succeeding years, on the date on which FERC Form No. 1 information is due. FERC-730 will require the following data and projections: (subsection i) in dollar terms, actual investment for the most recent calendar year, and planned investments for the next five years; and (subsection ii) for all current and planned investments over the next five years, a project by project listing that specifies for each project the expected completion date, percentage completion as of the date of filing and reasons for delay. In the NOPR, FERC-730 was known as “Form X” and a draft was provided in the Appendix. As the Commission stated in the NOPR (at P 49), the purpose of the reporting requirement is to determine the effectiveness of the proposed rules and to provide the Commission with an accurate assessment of the state of the industry with respect to transmission investment. (For discussion on the comments in response to proposed FERC-730, see item #8 of this submission.)
The subject data collections will be affected by the proposed regulations because they revise the filing requirements under 18 CFR Part 35. Specifically, the proposed revisions will remove 18 CFR § 35.34(e) (Innovative transmission rate treatments for Regional Transmission Organizations). It will be replaced with a section 35.35 under Subpart G, entitled Transmission Infrastructure Investment Provisions. These revisions are to implement Section 1241of the Energy Policy Act of 2005 which mandates that the Commission establish, by rule, incentive- based (including performance-based) rate treatments for the transmission of electric energy in interstate commerce by public utilities for the purpose of benefiting customers by ensuring reliability and reducing cost of delivered power by reducing transmission congestion.
All of the proposed changes in the subject Final Rule are provided for under proposed section 219 of the FPA as added by section 1241 of the Energy Policy Act 2005.1 We estimate that the annual reporting burden under FERC-516 will be increased by 45,080 hours for the implementation of the proposed revisions identified in the subject Final Rule and an additional 6,000 hours for the proposed information collection FERC-730.
Background
Transmission investment has declined in real dollar terms for 23 years, from 1975 to 1998, before increasing again, although investment for the most recent year available, 2003, is still below 1975 levels.2 Over the same time period, electric load more than doubled, resulting in a significant decrease in transmission capacity relative to load in every North American Reliability Council region. Edison Electric Institute (EEI) estimates that capital spending must increase by 25 percent, from $4 billion annually to $5 million annually, to assure system reliability and to accommodate wholesale electric markets, and that the 2.5 percent growth rate in transmission mileage since 1999 is insufficient to meet the expected 50 percent growth in consumer demand for electricity over the next two decades.3 The Secretary of Energy’s Advisory Board at the Department of Energy determined that investment in the transmission grid will only occur when regulatory policy: (a) provides reasonably certain cost recovery; (b) provides regulatory certainty, in terms of who can operate the system and under what rules; and (c) provides a return that makes investment in transmission a reasonable option, considering other available investment options.4
NOPR (Docket No. RM06-4-000)
On November 18, 2005, the Commission issued a NOPR in Docket No. RM06-4-000, regarding Promoting Transmission Investment through Pricing Reform. The purpose of the proposed rulemaking was to promote greater investment in new transmission capacity. The need for capital investment in energy infrastructure is a national problem that requires a national solution. Inadequate transmission infrastructure results in transmission congestion that impedes competitive wholesale markets and impairs the reliability of the electric grid. To address the need for transmission capacity, the proposed rulemaking provided price reforms applicable to the entire electric grid, in both organized and in other markets and to both vertically-integrated utilities and transcos.5
To address the need for new transmission infrastructure and to encourage necessary investment, new section 219 of the Federal Power Act (FPA) specifically charges the Commission with the responsibility to establish, by rule, incentive-based (including performance-based) rate treatments for the transmission of electric energy in interstate commerce that:
• promotes reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce, regardless of the ownership of the facilities;
• provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies);
• encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities; and
• allow the recovery of all prudently incurred costs necessary to comply with mandatory reliability standards in accordance with section 215 of the FPA, and all prudently-incurred costs related to transmission infrastructure development, in accordance with section 216 of the FPA (transmission national interest corridors).
Section 219 of the FPA also requires the Commission to issue a rule to provide for
incentives to each transmitting utility or electric utility that joins a Transmission Organization6 and to ensure that any recoverable costs associated with joining may be recovered through transmission rates charged by the Transmission Organization that provides transmission service to the utility. Lastly, section 219 provides that all rates approved under these rules are subject to the requirements of sections 205 and 206 of the FPA, which provides as described more fully below, that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential.
The Commission proposed to amend part 35 of its regulations. The Commission seeks to provide incentives and regulatory certainly sufficient to support expanded and improved transmission infrastructure (including advanced technologies) while at the same time ensuring that transmission rates remain just, reasonable, and not unduly discriminatory or preferential.
For all jurisdictional public utilities, including transcos, the Commission is encouraging incentive-based rate proposals, including proposals to:
(1) provide a rate of return on equity (ROE), within the zone of reasonableness, that is sufficient to attract new investment in transmission facilities;
(2) recover 100 percent of prudently incurred transmission-related Construction Work in Progress (CWIP) in rate base;
(3) recover prudently incurred pre-commercial operations costs by expensing these costs instead of capitalizing them;
(4) adopt a hypothetical capital structure;
(5) accelerate the recovery of depreciation expense;
(6) recover all prudently-incurred development costs in cases where construction of facilities may substantially be abandoned as a result of factors beyond the public utility’s control;
(7) provide deferred cost recovery; and
(8) provide any other incentives approved by the Commission that are determined to be just and reasonable and not unduly discriminatory or preferential.
For transcos only, the Commission proposed to authorize the following incentives subject
to the requirements of sections 205 and 206 of the FPA that all rates, charges, terms and conditions are just and reasonable and not unduly discriminatory or preferential:
(1) a higher ROE which is both sufficient to encourage Transco formation as well as to attract new investment in transmission facilities; and
(2) an adjustment to the book value of transmission assets being sold to a Transco to remove the disincentive associated with the impact of accelerated depreciation on federal capital gains tax liabilities.
The Commission would also consider authorizing an ROE for a public utility that joins a
Transmission Organization that is higher than the return on equity that the Commission might otherwise allow if the public utility did not join a Transmission Organization (but still within the zone of reasonableness). The Commission will also allow public utilities that join a Transmission Organization to recover prudently incurred costs associated with joining the Transmission Organization, either through transmission rates charged by public utilities or through transmission rates charged by the Transmission Organization that provides services to the public utilities.
The Commission would approve prudently-incurred costs necessary to comply with the mandatory reliability standards of section 215 of the FPA and also approve prudently-incurred costs related to transmission infrastructure development pursuant to section 216 of the FPA.
Finally, the Commission proposed to require that jurisdictional public utilities file an annual report (Form X) on their current and projected transmission investment activity. The annual report will be used as a basis for determining the effectiveness of the proposed rules and to provide the Commission with an accurate assessment of the state of the industry with respect to transmission investment. This information would be reported to the Commission on a proposed new form which would consist of a basic spreadsheet.
Subject Final Rule (Docket No. RM06-4-000)
On July 20, 2006, the Commission issued a Final Rule in Docket No. RM06-4-000, Promoting Transmission Investment through Pricing Reform. In the Final Rule, the Commission provides incentives for transmission infrastructure investment that will help ensure the reliability of the bulk power transmission system in the United States and reduce the cost of delivered power to customers by reducing transmission congestion. The Rule does not grant outright any incentives to any public utility, but rather identifies specific incentives that the Commission will allow when justified in the context of individual declaratory orders or section 205 filings by public utilities under the FPA. A number of these incentives reflect departures from what the Commission has permitted in the past and a willingness to consider much greater flexibility with respect to the nature and timing of rate recovery for needed transmission infrastructure. While the Commission in recent years has permitted higher rates of return and deviations from past ratemaking practices in a few individual transmission infrastructure cases, 7 the Commission in the Final Rule has determined generically that these types of ratemaking options and others should be considered on a broader basis for those applicants that can demonstrate that their infrastructure proposals meet section 219 requirements.
In reaching its determinations in this Final Rule, the Commission has considered comments that reflect widely divergent views with respect to whether and when utilities should receive incentives and what they must demonstrate in order to receive particular incentives. As noted, the Rule does not grant incentives to any public utility but instead permits an applicant to tailor its proposed incentives to the type of transmission investments being made and to demonstrate that its proposal meets the requirements of section 219. Further, under the Rule, the Commission will permit incentives only if the incentive package as a whole results in a just and reasonable rate. For example, an incentive rate of return sought by an applicant must be within a range of reasonable returns and the rate proposal as a whole must be within the zone of reasonableness before it will be approved.
An important component of this Rule is the willingness to provide procedural flexibility, including the use of expedited declaratory orders on permitted ratemaking treatments, to help with financing and up-front regulatory certainty for project investments. The Commission is particularly attuned to the need for flexibility to support long-distance interstate projects that significantly reduce the cost of delivered power by reducing transmission congestion on the interstate grid.
The Final Rule provides incentive-based rate treatments to any public utility transmitting electric energy in interstate commerce that meets the requirements of section 219 and this Final Rule. The Commission will not limit an applicant’s ability to seek incentive-based rate treatments based on corporate structure or ownership. In addition, the Final Rule provides additional incentives, to the extent within the Commission’s jurisdiction,8 to any transmitting utility or electric utility transmitting electric energy in interstate commerce that joins a Transmission Organization.9 Finally, to the extent the Commission’s jurisdiction allows, the Commission encourages public power entities to take advantage of the incentive-based rate treatments outlined in the Final Rule.
A. Justification
1. Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to FERC and the public of any changes to its jurisdictional rates and tariffs, file such changes with FERC, and make them available for public inspection, in such manner as directed by the Commission. In addition, FPA section 206 requires FERC, upon complaint or its own motion, to modify existing rates or services that are found to be unjust, unreasonable, unduly discriminatory pr preferential. FPA section 207 further requires the Commission upon complaint by a state commission and a finding of insufficient interstate service, to order the rendering of adequate interstate service by public utilities, the rates for which would be filed in accordance with FPA sections 205 and 206.
In developing these proposed requirements, the Commission is implementing the Congressional mandate of the Energy Policy Act of 2005 to establish incentive-based an where applicable performance-based rate treatments for the transmission of electric energy in interstate commerce. This mandate as expressed by new section 219 of the Federal Power Act addresses an identified need to encourage construction of transmission infrastructure and encourage investment. Sufficient supplies of energy and a reliable way to transport those supplies are necessary to assure reliable energy availability and to enable competitive markets. Without sufficient delivery infrastructure, some suppliers will not be able to enter the market, customer choices will be limited, and price may be needlessly higher or volatile. The implementation of the incentive and performance-based rate treatments support the Commission’s mandate to support investments in transmission capacity to reduce the cost of delivered power by reducing congestion.
2. The data filed in FERC-516 enables the Commission to exercise its wholesale electric rate and electric power transmission oversight and enforcement responsibilities in accordance with the Federal Power Act, the Department of Energy Organization Act (DOE Act)10and EPAct 2005.
Detailed submissions are necessary for the Commission's determination of reasonable and equitable rates and more abbreviated submissions are sufficient for decisions involving formula, settlement, and qualifying small power producer rates, and in non-rate increase filings. The proposed regulations are part of a statutory mandate of promoting greater capital investment in new transmission capacity. The proposed amendments to the existing regulations are intended to promote reliable and economically efficient transmission and generation of electricity by providing incentives for increased capital investment by providing a rate of return that attracts new investment in transmission facilities, and by providing incentives to utilities that join Transmission Organizations.
The information enables FERC staff and other parties to examine and evaluate the cost elements that comprise rates and in particular to examine and evaluate financial elements comprising a utility’s rates (including as appropriate, plant investment, expenses, tax computations and development of the rate of return on investment) to determine whether and how much of these elements should be included in the utility’s rates. With regard to rate of return, staff analyzes the financial data to determine the appropriate rate of return that a utility will be permitted to earn on the facilities used to provide the service at issue. Examples of the financial data include book and market values of common stock, earning per share, dividends per share and historical growth rates in dividends.
Through this data collection process, FERC is able to regulate public utilities and licensees by exercising oversight and review of the reported rate schedules. Without this information, FERC would be unable to discharge its responsibility to approve or modify utility electric rate schedule filings. Further, without incorporating the procedures as the subject Final Rule is requiring, the Commission would not be meeting its statutory obligations under the Federal Power Act in particular to advance the Congressional initiative of increasing capital investment in transmission facilities. In addition, the Commission would fail to further its own initiatives to advance additional transmission capacity as evidenced by the issuance of a proposed policy statement to promote the efficient operation and expansion of the transmission grid11 and a policy statement on Transco independence.12
3. There is an ongoing effort to determine the potential and value of improved information technology to reduce the burden. Specifically, in order to increase the efficiency with which it carries out its program responsibilities, the Commission has been implementing measures to use information technology to reduce the amount of paperwork required in its proceedings.
In Order No. 614 (RM99-12-000), the Commission stated that it was initiating a process "necessary to accommodate the movement toward an integrated energy industry and to facilitate the development of common standards for the electronic filing of all electric, gas, and oil rate schedule sheets. Order No. 614 required public utilities to take responsibility for the designation of their tariffs, rate schedules and service agreements, and pagination of their tariff sheets along the lines of the natural gas pipeline program. Order No. 614 also stated that the Commission intended to move to a common standard for the filing of all electric, gas and oil rate schedule sheets.
In addition, in RM 01-5-000 FERC proposed that future tariff filings be made over the Internet with software developed (and distributed to public utilities for their use at no cost) software to be downloaded at the users' sites) to enter data manually (for small data sets and to edit corrections) and/or to download spreadsheet data, or other properly formatted system output, directly into the application. In addition, the software will perform edit checks at the utility site to ensure a complete filing and a successful upload at the Commission. The proposed tariffs will change from a tariff-sheet format to a section-based forma that is better suited for electronic filing. The software has undergone testing and refinements to reflect industry comments that were given in several technical conferences held in the summer of 2005 and during testing periods. Integration of eTariff with FERC’s internal business process software is proceeding with a target date of the third calendar quarter 2006.
In the proposed regulations, the Commission is establishing that respondents file electronically FERC-730 (spreadsheet) that identifies their planned capital investment for the next five years.
4. Filing requirements are periodically reviewed as OMB review dates arise or as the Commission may deem necessary in carrying out its regulatory responsibilities under the Act in an effort to alleviate duplication. All Commission information collections are subject to analysis by Commission staff and are examined for redundancy. There is no other source of this information.
The Final Rule proposes as noted above to implement a Congressional mandate to encourage construction of transmission infrastructure and encourage investment. Sufficient supplies of energy and reliable way of transport those supplies are necessary to assure reliable energy availability and to enable competitive markets. The Final Rule serves a dual purpose in that FERC is proposing incentives to encourage additional construction of transmission infrastructure and as the same time tracking through reporting requirements whether industry has implemented the incentives introduced by FERC. The information will be unique to each respondent as they identify what initiatives they have undertaken to implement these incentives. FERC believes these reporting requirements will provide better and more accessible information to the public and the Commission.
5. The Final Rule applies only to entities that own, control, or operate facilities for transmitting electric energy in interstate commerce and not electric utilities per se. These entities would not be considered small entities within the meaning of the Regulatory Flexibility Act. However, the Commission will consider granting waivers in appropriate circumstances.
6. If the collection were conducted less frequently, the Commission would be unable to perform its mandated oversight and review responsibilities with respect to electric rates. Furthermore, Section 205 of the FPA mandates that the information be filed every time a licensee or public utility proposes to change its rates. In the Final Rule, FERC proposes that jurisdictional public utilities be required to report annually to the Commission no later than April 18, 2007 and in succeeding years, the actual transmission investment for the most recent calendar year and planned investments for the next five years. In addition, applicants seeking to have the Commission approve incentive-base rate treatment for transmission infrastructure investment will make a tariff filing with FERC in accordance with section 205 of the FPA that details how the proposed rate treatment justifies incentive-based (or performance-based) treatment.
7. This proposed program meets all of OMB's section 1320.5 requirements with the exception of part "d" thereof. Section 1320.5(d) limits the collection of data to an original and two copies of any document. The data provided under FERC-516 includes service agreements and transaction reports and would be filed by the respondents to comply with the provisions as indicated in Item A (1.). Currently an original and five copies are required to be submitted to the Commission. This is the minimum necessary to permit processing within the statutory time frame for Commission action. The original is routed to eLibrary for public viewing over the Commission's web site. One copy is distributed to the Public Reference and Files Maintenance Branch for public inspection in the Commission's Public Reference Room. An additional copy is distributed to the Office of General Counsel for legal review. Three copies are distributed to the Office of Energy Markets and Reliability for technical review by analysts in rate filings, rate investigations and financial analysis.
However, if the eTariff NOPR is adopted and electronic filing is put into place, this will eliminate the need for paper copies entirely for service agreements and transactional reports. During this transitional period, however, the traditional number of hard copies will still be needed for efficient processing of the data.
8. The Commission's procedures require that the rulemaking notice be published in the Federal Register, thereby allowing all public utilities, natural gas and oil pipeline companies, state commissions, federal agencies, and other interested parties an opportunity to submit comments, or suggestions concerning the proposal. The rulemaking procedures also allow for public conferences to be held as required.
The NOPR was issued on November 18, 2005 along with a request for comments and is scheduled to be published in the Federal Register on November 29, 2005. Comments were due on before January 11, 2006.
The Commission did not receive specific comments concerning its burden estimates and uses the same estimates in the Final Rule. Comments on the reporting requirement proposed in the NOPR as Form X are addressed below. Form X is adopted in the Final Rule as noted above as FERC-730.
It should be noted that the comments received concerning Form X and the Commission’s subsequent adoption of FERC-730 did not lead the Commission to revise the NOPR’s estimates of the public reporting burden.
As noted above, Section 35.35(h) of the Final Rule would require jurisdictional public utilities to report annually to the Commission no later than April 18, 2007, and, in succeeding years, on the date on which FERC Form No. 1 information is due, the following data and projections: (subsection i) in dollar terms, actual investment for the most recent calendar year, and planned investments for the next five years; and (subsection ii) for all current and planned investments over the next five years, a project by project listing that specifies for each project the expected completion date, percentage completion as of the date of filing and reasons for delay.
A number of commenters13 supported the proposed Form X reporting requirement. For example, International Transmission stated that such reports are important to determine if the investment incentives adopted by the Commission are actually working to elicit investment in transmission that benefits consumers. Some of these commenters made a number of recommendations, including the following: define transmission investment for reporting; include separate categories for new generation interconnection versus other types of system upgrades; classify investments by voltage level to distinguish facilities that have little or nothing to do with the interstate transmission grid; exclude small, miscellaneous upgrades; provide instructions that Transmission Facilities in the table “Capital Spending On Electric Transmission Facilities” are defined as transmission assets under the Uniform System of Accounts in accounts 350 through 359; like the report with FERC Form No. 1; provide a list of categories for the “Reasons for Delay” column, such as siting, delayed completion of a new generator; report the consumer benefits of the project (e.g., congestion relief, enhanced reliability); require the posting of the information on RTO, ISO, Transco or public utility websites or OASIS; require that all the reports be aggregated in one report that is made public, thereby providing manufacturers with a better basis to plan for industry needs.
Commenters also contend that the report did not go far enough.14 Some15 stated that such reports should extend to all transmission providers, including those subject to new section 211A of the FPA and government-owned entities. Semantic asserted that the reporting requirements proposal is incomplete and does not adequately secure the comprehensive state of the grid information required by the regulators and market participants. Semantics would require that power systems state data must be made available in real-time to identify parallel flows and to avoid under-investment, over-investment or bad investments; that the report should provide for the filing of data that enables the Commission to fulfill its oversight responsibility for RTOs under § 35.34(k)(4) and to promote compliance with § 35.34(k)(1). Semantics further recommends that time of day rate schedules should be reported into a web-accessible national repository. Semantic explained that capital investment in advanced technologies will relieve congestion if this information is made known to technology vendors and entrepreneurial entities.
Certain commenters16 that support the reporting also expressed concerns. For example, National Grid stated that the Commission should clarify that the forward-looking projections in Form X, rendered in good faith and upon a reasonable basis, would not subject the reporting transmission owners to claims of fraud, detrimental reliance or other liabilities arising from the fact that actual capital spending may vary from reported projections.17 Ameren requested that the Commission clarify that the reported information be provided for informational purposes only and should not be allowed to form the basis of a review by the Commission or other entities regarding the reasonableness or prudence of the amounts reported. PG&E and the Nevada Companies asserted that a disclaimer should be added to footnote 1 explaining that much of the information reported here may change over time and may be subject to correction. Trans-Elect asserted that the reporting requirement, alone, should not be allowed to form a basis for a section 206 investigation.
Some commenters raise confidentiality concerns.18 EEI and KCP&L urged that the Commission afford Critical Energy Infrastructure Information (CEII)19 status to this information since it clearly relates to the production, generation, transmission or distribution of energy, could be useful to a person planning an attack and gives strategic information beyond the location of critical infrastructure. EEI encouraged the Commission to perform an evaluation as to the need for confidentiality of selected company information due to the commercially sensitive nature of the information. Similarly, Ameren and TransElect requested that the Commission clarify that the required information may be submitted pursuant to the Commission’s confidential filing procedures.20
A number of commenters opposed the reporting requirement for a variety of reasons. Several21 claim that the Commission has not provided adequate justification for the Form X data collection, as required by the Paperwork Reduction Act, given that the Commission already collects information on utility transmission investment and planning in existing FERC Form Nos. 1, 714 and 715 and that the Commission has not demonstrated the need to make the information collection mandatory. Ameren, AEP and PJM TOs stated that the requested information duplicates information already being compiled by RTOs in their planning process; and MISO States suggested that the Commission obtain an aggregate report from the RTO. PJM recommended that Form No. 1 requirements be modified prospectively, instead of requiring a new form. EEI is concerned that the Commission, state commissions and the public may inappropriately rely on the information, expecting the plans to be implemented without regard to the regulatory approvals and applicant and market decisions involved. EEI further states that reporting information on planned future facilities can lead to unnecessary opposition that might not occur with a proper public siting process, lead to speculation in land use fees that can harm the applicant’s customers.
EEI argued that the only accurate measure of the effectiveness of the incentives is the number of applications filed for incentives, encourages the Commission to simply monitor the number of applications for new transmission facilities, the magnitude of the facilities involved and the incentives sought and thereby obtain the most accurate measure of the effectiveness of the proposed incentives. EEI also encouraged the Commission to rely on annual aggregate transmission investment information that EEI has provided to the Commission and can continue collecting for the Commission’s benefit. Nevada Companies asserted this information should not be required since it is inaccurate and incomplete.
Southern, SCE and Ameren proposed limitations on the information to be provided as follows: only aggregate information should be required, and project-specific information should not be required since it is extremely burdensome, entails security and confidentiality issues, and is subject to change; if project-level information is required, that it be limited to major transmission projects, i.e., 345 kv and above; and limit project-specific reporting requirements to only projects costing $20 million or more and that are subject to a Transmission Organization’s or a regional planning organization’s planning and approval process.
To ensure that these rules are successfully meeting the objectives of section 219, the Commission needs industry data, projections and related information that detail the level of investment. The rule’s purpose is to both provide new investment as well as ensure that customers benefit. Thus, information regarding projected investments as well as information about completed projects will help the Commission to monitor the success of the ratemaking reforms announced in this rule. The Commission is therefore adopting the proposed reporting requirement Form X and designating it as the FERC-730. Further, the Commission will make certain modifications to clarify when reports must be filed and what data must be submitted in FERC-730 reports.22 The information required in FERC-730 is not available from Form Nos. 1, 714 or 715, nor is it available from other federal agencies. For instance, FERC Form No. 1 requires the reporting of historical financial data but does not contain forward looking projections of expected transmission investments.23 Thus, the information sought is not already readily available and will be required only from public utilities that have been granted incentive rate treatment for specific transmission projects under the provisions of § 35.35.
The Commission agrees with commenters that, for some utilities, the information requested is similar to information submitted to RTOs. However, the Commission does not receive that information, and the information provided to RTOs may not be identical to the information requested here. Therefore, to ease the administrative burden, those utilities providing information to RTOs can submit the same information to the Commission. We strongly encourage utilities that submit FERC-730 reports to do so in an electronic format via eFiling.24 To rely on information collected by EEI, as recommended, would not provide the Commission with the accurate information it needs to assess the effectiveness of its regulations under section 219. The Commission would not have available to it the survey instruments or the analysis behind the reported information. Thus, reliance on second-hand gathered survey information for the purposes of rate setting would not provide the independent, factual basis to allow the Commission to make a determination that continuing incentives is appropriate. Likewise, the summary investment information available in existing reports does not provide information on projected investment or reasons for delays in projects, thereby limiting its value for determining the effectiveness of the rules.
The Commission does not believe a CEII designation is required for this information since it is expected to only include information on capital spending and a general designation of the project name, without requiring data on facility location. With respect to confidential treatment of FERC-730, as a general matter the Commission does not believe that this type of general planning information involves commercially sensitive information. However, while the Commission will require applicants to provide capital spending projections and other information in their applications, it also recognizes that applicants may have legitimate reasons to maintain confidentiality of certain information. For this reason, applicants can request protection of information under § 388.112.
With respect to project-level information, this information is needed to determine the status of critical projects and reasons for delay, and will play a role in the Commission’s evaluation of continuing incentives. To facilitate this review, the Commission will require that filers specify which projects are currently receiving incentives in the project detail table and that they group together those facilities receiving the same incentive. The Commission will not limit the information to projects above a certain voltage, since lower-voltage projects can have significant impacts on reliability and congestion relief, nor will the Commission limit the information to projects subject to a Transmission Organization’s or a regional planning organization’s planning and approval process since the Commission is addressing a national problem and complete coverage is therefore necessary. As discussed earlier in the Final Rule, projects eligible for incentives – and hence required to submit data – are not restricted to projects or investments that result from regional planning processes. The Commission agrees with SCE that a minimum dollar threshold of $20 million is a reasonable level for reporting of significant projects.
The Commission agrees with many of the recommendations for modifications to the tables in the revised FERC-730 (see Appendix). The Commission will not require the reporting of consumer benefits of projects. In order for these projects to have received an incentive, the project must have met the requirements of the Final Rule, which includes that it benefits consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion. The Commission will not require the addition of operating data to the table since the sole purposes of the information collection is to determine the level of capital spending, the status of significant and critical projects and reasons for delay. The Commission will not require a Proposed Operating Date, as recommended by Ameren, since the Commission’s sole concern with this information is that the planned projects are completed on time; operational start-up issues such as synchronization with the grid and testing introduce additional issues not directly relevant to tracking the progress of investments in new infrastructure.
Further, the Commission will not require year-by-year capital spending estimates for the project detail table as recommended by TAPS since the goal of the rule is not to ensure the achievement of annual capital spending targets but rather to ensure the overall project is completed, and if not, the reasons for the delay. The Commission will not require the inclusion of cost allocation or pricing information as recommended by TAPS since that information is beyond the scope of the Commission’s requirements. The Commission does not see the need for a disclaimer that information is subject to change, since the required information is clearly labeled “projected” and “expected” and therefore assumed to be subject to change. Since the Final Rule applies to public utilities and incentives are being permitted pursuant to sections 219 and 205, which pertain to public utilities, the Commission will not require information from entities that are not jurisdictional under section 205, although such entities are encouraged to voluntarily provide this information. The Commission clarifies that the meaning of “On Schedule” in the Project Detail table is the most up-to-date, expected project completion date.
The Commission also clarifies that the reported information is to be provided for informational purposes only, and its purpose is not to establish the prudence of the amounts spent. As the Commission specified in the Final Rule, it expects applicants will propose metrics and provide a nexus between the incentive and the investment, and therefore the information in this report will not be the sole basis for a section 206 investigation. The Commission further clarifies that the projections in FERC-730, rendered in good faith and upon a reasonable basis, would not subject the reporting transmission owners to claims of fraud, detrimental reliance or other liabilities arising from the fact that actual capital spending may vary from reported projections.
Rather than requiring all public utilities to submit FERC-730, the Commission clarifies that only those public utilities that have been granted incentive-based rate treatment for specific transmission projects under the provisions of § 35.35 must file FERC-730 in the manner prescribed in Appendix A. A public utility is subject to the FERC-730 reporting requirement beginning with the year the Commission issues an order in response to a filing made pursuant to section 205 of the Federal Power Act, or in a petition for a declaratory order that precedes a filing pursuant to section 205. The initial FERC-730 filing is due by April 18 of the following calendar year and subsequent filings are due each April 18 thereafter.
In addition, the Commission is adding a new provision to § 35.35(h) and delegates to the Chief Accountant or the Chief Accountant’s designee authority to act on requests for extension
of time to file FERC-730 or to waive the requirements applicable to any FERC-730 filing.
Finally, the Commission finds the data issues raised by Semantic to be beyond the scope of the Final Rule. While the data requested by Semantic could provide a useful purpose for the operations and management of electric facilities and may have applicability to the Commission’s regulations for RTOs, this rulemaking is limited to an evaluation of incentives for investment in electric transmission facilities. Therefore, the reporting requirements of the rulemaking are appropriately limited to data on industry investment.
Many commenters agreed that there is a significant need for new investment in transmission facilities. EEI stated that, although increases in transmission investment are predicted over the 2004 to 2008 period, the industry still has not reached the optimal level of investment.25 International Transmission noted that growth in transmission capacity has lagged behind the growth in peak demand over the last three decades and this trend is projected to continue through at least 2012.26 International Transmission cited to studies estimating the cost of power interruptions and fluctuations to range from between $29 billion and $135 billion annually,27 the cost of the August 2003 Northeast-Midwest blackout to be between $4 billion and $10 billion,28 congestion costs of $4.8 billion in the ISO/RTO markets of California, New York, New England, the Midwest and PJM for 1999 to 2002,29 and increases in PJM congestion costs, from $499 million in 2003 to $808 million in 2004.30
Many transmission users and state commissions also agreed that there is a need for additional investment in transmission infrastructure.31
However, some commenters disputed the need for new transmission investment. They asserted that the Commission has overlooked that investment in transmission has increased in recent years.32 They also contend that investment in transmission by utilities in RTOs and ISOs has been significant, citing to the approximately $2 billion of approved spending in PJM since 2000. E.ON US asserted that wide-spread system shortages have rarely occurred during the past 40 or more years, and that there does not appear to be any trend line that would suggest that it is becoming a serious problem now.
The issue of whether there is a need for new transmission investment that is sufficient to justify transmission incentives was put to rest by section 219. Section 219 mandates that the Commission "establish, by rule, incentive-based (including performance-based) rate treatments" and, in doing so, "promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce" (emphasis added). If this were not enough, the legislative mandate of section 219 is supported by abundant evidence, as discussed above, including the fact that transmission investment in real dollars terms is lower today than it was in 1975 when the load was significantly smaller and that, even with the transmission additions of recent years, the industry still incurs significant congestion costs due to inadequate transmission.
In section 219(a) of the FPA, Congress directed the Commission to establish incentive-based rate treatments to foster investment in transmission facilities.
Several commenters argued that incentive-based rates are not necessary to encourage transmission construction or that incentives will not accomplish the intended goal.33 Others asserted that reliance on incentives may increase the price of electricity without any real benefit.34
Commenters urged the Commission to limit the scope of any incentive-based treatments or to adopt mechanisms to ensure that they have their intended effect. For example, the New Mexico AG and TAPS asserted that the Commission may implement an incentive-based mechanism by penalizing utilities or RTOs that fail to make investments necessary to ensure the reliability of the transmission grid. The Delaware Commission contends that providing incentives without assessing penalties for failure to meet obligations violates the just and reasonable standard. NASUCA stated that it is unfair to provide incentives that increase utility profits but do not hold applicants accountable for performance. The Missouri Commission proposed that the Commission implement a process that determines performance-based return on equity. Other commenters recommended that the Commission make approval of any incentives conditional on the applicant showing a need for the incentive or that the facility would not have been built absent the incentive.
In contrast, a number of commenters, including EEI and a large number of utility and Transco commenters argued that incentives are needed to foster investment in transmission facilities. EEI asserted that incentives are needed to stimulate planning and investment in national interest electric transmission corridors. NU states that the many risk factors associated with transmission investments, such as considerable time delays, negative public opinion of transmission construction, state siting uncertainties and recovery of project costs, justify incentives.
The fundamental issue raised by certain commenters – whether transmission incentives are necessary to encourage new infrastructure – was put to rest by the plain language of section 219(a), which requires the Commission issue a rule that adopts "incentive-based . . . rate treatments." Certain commenters urge the Commission to adopt "penalties" in the Final Rule for entities that do not build sufficient transmission. The Commission declines to do so in the Final Rule.
Other commenters do not oppose incentives outright, but rather are concerned with the extent to which incentives may increase rates to consumers. Those concerns are premature. The Final Rule does not grant incentive-based rate treatments or authorize any entity to recover incentives in its rates. Rather, it informs potential applicants of incentives that the Commission is willing to allow when justified. Before adopting any incentive-based rate treatments for a particular company, the Commission will need to determine that the applicant has justified its specific incentive request. In addition, although the Commission intends to provide flexible procedural mechanisms by which an applicant may obtain an early determination of which incentives it may receive (e.g., through an expedited declaratory order proceeding), before recovering any incentives in its rates, specific rates must be approved under section 205 of the FPA.
The incentives adopted in the Final Rule are properly understood only in the context of the traditional regulatory principles they seek to further. The longstanding rule is that utility rate regulation must adequately balance both consumer and investor interests. It is not enough to ensure that investors are properly compensated, and it is not enough to ensure that consumers are protected against excessive rates. The Commission’s policies must ensure both outcomes and, in doing so, strike the appropriate balance between these twin objectives. In striking that balance, the courts have recognized that there is no single formula for establishing a just and reasonable rate. Rather, the test is whether the "end result" is just and reasonable.35
The traditional policies the Commission re-examined in the Final Rule reflect both fundamental precepts: the need to balance investor and consumer interests and the recognition that there is no single formula for doing so. For example, in ensuring that rates produce adequate returns for investors, the Commission does not set a single return on equity for all public utilities, nor does it presume that there is only one return on equity that is appropriate for any individual utility. Rather, the Commission’s precedents require the establishment of a range of returns and the Commission selected an ROE within that range that reflects the facts and circumstances of a particular case. Similarly, the Commission’s policies regarding the recovery of Construction Work in Progress (CWIP) seek to balance investor and consumer interests by allowing, in the typical case, 50 percent of CWIP in rate base. This policy balances investor and consumer interests in the ordinary case by permitting investors recovery of some construction costs on a current basis while also protecting consumers against full rate recovery before a particular facility is placed into service.
The Commission’s procedural regulations respecting rate recovery also seek to balance investor and consumer interests. For example, the Commission allows public utilities to determine, as a general matter, the timing and frequency of when to seek a rate increase, which ensures that investors can file a rate increase when current rates are no longer adequate (e.g., when the utility is undergoing a large construction program). However, the Commission also typically requires a utility seeking a rate increase to expose all of its costs to review and therefore do not generally permit "single issue" rate filings (selective rate adjustment).
Section 219 requires the Commission to re-examine these and other policies to determine whether they continue to strike the appropriate balance in encouraging new transmission investment given the significant need for new transmission infrastructure in the Nation. The Commission does so in recognition of the unique and substantial challenges faced by large new transmission projects. Siting major new transmission lines is extraordinarily difficult, given the environmental and land use concerns associated with obtaining and permitting new rights-of-way. The experience of American Electric Power Corp. in taking 16 years to complete construction of a new high-voltage transmission line from Wyoming County, West Virginia to Jackson Ferry, Virginia represents an extreme example, but it is illustrative of the significant risks and challenges associated with siting large new transmission projects.36
These challenges and risks are underscored by the fact that, in many instances, new transmission projects will not be financed and constructed in the traditional manner. New transmission is needed to connect new generation sources and to reduce congestion. However, because there is a competitive market for new generation facilities, these new generation resources may be constructed anywhere in a region that is economic with respect to fuel sources or other siting considerations (e.g., proximity to wind currents), not simply on a "local" basis within each utility's service territory. To integrate this new generation into the regional power grid, new regional high voltage transmission facilities will often be necessary and, importantly, no single utility will be "obligated" to build such facilities. Indeed, many of these projects may be too large for a single load serving entity to finance. Thus, for the Nation to be able to integrate the next generation of resources, the Commission must encourage investors to take the risks associated with constructing large new transmission projects that can integrate new generation and otherwise reduce congestion and increase reliability. The Commission’s policies also must encourage all other needed transmission investments, whether they are regional or local, designed to improve reliability or to lower the delivered cost of power.
To address the substantial challenges and risks in constructing new transmission, the Final Rule identifies instances where the Commission’s regulatory policies may no longer strike the appropriate balance in encouraging new investment. The Final Rule identifies several policies that should be adjusted, where appropriate on the facts of a particular case, to encourage new transmission investment or otherwise remove impediments to such investment. Although each reform adopted by the Final Rule constitutes an "incentive" as that term is used by section 219, this label has caused some confusion in the comments. It is true that the Commission’s reforms adopted in the Final Rule provide "incentives" to construct new transmission, but they do not constitute an "incentive" in the sense of a "bonus" for good behavior. Rather, as explained below, each incentive will be applied in a manner that is rationally tailored to the risks and challenges faced in constructing new transmission. Not every incentive will be available for every new investment. Rather, each applicant must demonstrate that there is a nexus between the incentive sought and the investment being made. The Commission’s reforms therefore continue to meet the just and reasonable standard by achieving the proper balance between consumer and investor interests on the facts of a particular case and considering the fact that our traditional policies have not adequately encouraged the construction of new transmission.
A few examples will illustrate this point. The Final Rule permits higher returns on equity for certain transmission investments. This may be appropriate in several contexts, such as where the risks of a particular project exceed the normal risks undertaken by a utility (and hence are not reflected in a traditional discounted cash flow (DCF) analysis) and where necessary to encourage creation of a Transco or participation in a Transmission Organization. However, this does not mean that every new transmission investment should receive a higher return than otherwise would be the case. For example, routine investments to meet existing reliability standards may not always, for the reasons discussed below, qualify for an incentive-based ROE.
The Final Rule also adopts incentives that are designed to reduce the risks of new investments. For example, the Final Rule provides that the Commission will provide assurance of recovery of abandoned plant costs if the project is abandoned for reasons outside the control of the public utility. Although this qualifies as an "incentive" under section 219, it is perhaps more properly characterized as reducing a regulatory barrier – the potential lack of recovery of costs – to infrastructure development. Moreover, this reform adequately balances consumer and investor interests because it is available only when a project is abandoned for reasons beyond the control of the public utility.
The Final Rule also adopts certain reforms that affect the timing of recovery of new transmission investments. Given the long lead time required to construct new transmission, and the associated cash flow difficulties faced by many entities wishing to invest in new transmission, the Final Rule provides that, where appropriate, the Commission will allow for the recovery of 100 percent of CWIP in rate base. Here again, the Commission seeks to remove an impediment – inadequate cash flow – that its current regulations can present to those investing in new transmission. The Commission also will permit, where appropriate, the recovery of the costs of new transmission through a single issue rate filing without requiring the public utility to re-open all its transmission rates to review. The Commission does not, however, suggest that such selective rate adjustments will be appropriate in all cases. Rather, as with each incentive adopted by the Final Rule, an applicant must show that there is a nexus between its proposal to make a single issue rate adjustment and the facts of its particular case.
Congress directed the Commission to issue a rule establishing incentive-based rate treatments no later than one year after enactment of EPAct 2005, or by August 8, 2006.
Certain commenters urged the Commission to apply the rule to investments made before August 8, 2005 while others asked the Commission to apply the rule to investments made after August 8, 2005. 37 Certain commenters argued that the Commission should not approve incentives for facilities that are pending at the time the Final Rule becomes effective, while others request that the Commission not allow incentives for investment in facilities that an applicant already has committed to build or for Transcos that already exist.38
Several commenters argued that, once the incentives have been granted, the Commission should not eliminate them, or should do so only under very limited circumstances.39 In contrast, others argued that the Commission should grant incentives for a specific time period or retain the flexibility to change or review any incentives if it is found the incentives provide no customer benefit.40 The California Oversight Board requests that any authorized incentives be subject to refund.
KKR explained that, under certain circumstances, investors in transmission assets may need favorable rate treatment for a sufficient period of time to ensure an appropriate return on their capital, i.e., for a 15 to 30-year period.41 KKR recommended that public utilities requesting incentive treatment for an extended period into the future propose criteria that can be used to evaluate that entity’s performance during periodic evaluations. KKR notes that applicants may not always be able to meet certain proposed metrics due to circumstances beyond their control. For example, a transmission owner should not lose its incentive rate treatments if it does not succeed in meeting desired reductions in congestion because the applicant may not have complete control of the factors affecting congestion, such as generation additions, changes in load location and operation of neighboring systems, and RTO policies. KKR emphasized that the Commission should retain the flexibility to assess an applicant’s proposal as the facts and circumstances will vary case-by-case. Finally, KKR recommended that applicants be required to file a report on their performance every several years and that the Commission may initiate a proceeding to review incentives only if the criteria are not met. KKR explained that frequent reviews run the risk of distorting results due to the “lumpiness” of capital investment and the long time periods to make capital additions and for capital additions to have effects. Further, KKR stated that frequent reviews will make long-term investments more uncertain and, hence, less likely. In supplemental comments, KKR asserted that higher ROEs are of material value for Transcos only when long-term. KKR cited International Transmission as an example, noting that it is only able to invest in excess of every dollar it earns back into its system due to the certainty afforded it by its rate compact, which is long-term, formula-based, and includes a reasonable ROE. The certainty and long-term horizon of International Transmission’s rates give debt and equity investors in International Transmission comfort that they will ultimately receive an adequate return on their capital.
Section 219 of the FPA became effective on August 8, 2005. Codification of section 219 on that date and the requirement for a rule authorizing investment incentives provided notice to the industry that Congress intended that the Commission provide incentive-based rate treatments promptly. Thus, the Final Rule will become effective 60 days after publication in the Federal Register. However, the Commission clarifies that any investment made in, or costs incurred for, transmission infrastructure after August 8, 2005 that ensures reliability or lowers the cost of delivered power by reducing transmission congestion will be eligible for incentive-based rate treatments under the Final Rule. Applicants seeking incentive-based rate treatments for investments made or costs incurred after August 8, 2005 will need to satisfy the requirements of the Final Rule to obtain and recover any incentives and will need to make an appropriate filing under section 205.
The fact that a proposed expansion was in a utility’s expansion plan as of August 8, 2005 does not disqualify the project for incentive treatment. Inclusion of a facility in a plan does not mean that a project can or will get built. Even where a project already has been planned or announced, the granting of incentives may help in securing financing for the project or may bring the project to completion sooner than originally anticipated. Congress’s directive that the Commission issue a rule within one year of enactment of EPAct 2005 shows that Congress intended for the Commission to take steps to bring new transmission on line expeditiously.
With respect to the issue of how long an incentive-based proposal should remain in effect, the Commission recognizes that it may be necessary to authorize incentives that may extend over several years in order to support investment in long-term transmission. It can be important to investors making long-term investments in long-lived facilities to be assured that a ratemaking proposal adopted prior to construction of those facilities will not later be altered in a manner that undermines the basis for the financing of those facilities. The Commission will therefore allow applicants to propose specific time periods by which their incentive-based proposals will not be "re-opened" in a manner incompatible with the nature of the initial approvals. However, to ensure that ratepayers are also adequately protected, the Commission will require any applicants seeking such a fixed term for its plan to explain how ratepayers can be assured that such a plan is delivering the benefits that formed the basis for the Commission's initial approval of it. For example, an applicant may propose periodic progress assessments with appropriate metrics to measure how well the project is progressing and whether the proposed investment in new transmission is improving reliability or reducing congestion. Such metrics would provide the Commission a means to determine whether and how the applicant is providing the anticipated benefits and thus that the approved incentives need not be revisited. Because the scope and size of each project will differ, any applicant seeking incentive-based rate treatments may propose metrics for its project as well as the frequency for review of those metrics.42 An applicant may include its proposed metrics and any timetable for review in its section 205 rate filing seeking recovery of incentives.43 Where such metrics are found to be needed and are approved by the Commission, an applicant would be required to submit information filings to the Commission consistent with the approved metrics and timetable. The Commission clarifies, however, that the metrics reviews will not be opportunities to re-argue the issues addressed in proceedings granting the incentive-based rates; they are for the purpose of measuring whether the plan is being implemented as initially approved.
9. There are no payments or gifts to respondents in the proposed rule.
10 and 11. The Commission generally does not consider the data filed in rate filings to be confidential. There are no confidentiality or questions of a sensitive nature associated with the data requirements proposed in the Final Rule. Specific requests for confidential treatment to the extent permitted by law will be entertained pursuant to 18 C.F.R. Section 388.110. Section 205(c) of the FPA requires that every public utility have all of its jurisdictional rates and tariffs on file with the Commission and make them available for public inspection, within such time and in such form as the Commission may designate. Section 205(d) of the FPA requires that every public utility must provide notice to the Commission and the public of any changes to its jurisdictional rates and tariffs, file such changes with the Commission, and make them available for public inspection, in such manner as directed by the Commission.044 Commenters did raise concerns about confidentiality and identifying information as being CEII. The Commission did address these concerns and can be reviewed item no. 8 above concerning comments to the NOPR.
Comments were received concerning confidential treatment on the information to be reported on FERC-730. The Commission has addressed these concerns above in item no. 8 of this submission.
12. The Commission estimates there will be an increase of 45,080 hours for information requirements/collections under FERC-516, as proposed in the subject Final Rule. This is based on the Commission's recent experience with tariff filings. In addition, the Commission will adopt a new information collection, FERC-730 that will result in an additional 6,000 hours for a total of 51,080 hours. The Final Rule will consist of two reporting requirements, the tariff filing as described in item no. 6 above and the annual report (FERC-730).
Data Collection |
Number of Respondents |
Number of Responses |
Hours Per Response |
Total Annual Hours |
FERC-516 |
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Transcos |
30 |
1 |
296 |
8,880 |
Traditional Public Utilities |
200 |
1 |
181 |
36,200 |
FERC-730 |
200 |
1 |
30 |
6,000 |
Total |
230 |
1 |
222 |
51,080 |
*Transco-means a stand-alone transmission company that has been approved by FERC and sells transmission services at wholesale and/or on an unbundled retail basis, regardless of whether it is affiliated with another public utility.
Traditional public utilities are those enterprises engaged in the production and/or distribution of electricity for use by the public including investor-owned electric utility companies.
The Commission’s experience has found that on average it takes 183 hours for public utilities to prepare and submit a tariff filing. Because companies would only be required to modify existing tariff filings, the Commission has estimated that it will only take 100 hours to prepare the tariff filing. To the 100 hours, the Commission has added 136 hours to gather the data and submission of the annual report. The actual report will be submitted on a spreadsheet and is relatively easy to complete and submit. The bulk of the burden will be in research and gathering the data. FERC’s estimate assumes that one employee would have to work 3 weeks to develop, coordinate and file the report. It will take an additional 2 employees to provide project information and review with 2 days of effort.
FERC-516 (1902-0096)
Current OMB Proposed Proposed New OMB
Inventory in the NOPR in Final Rule Inventory
Number of respondents: 1,238 230 1,238 1,238
Number of Responses: 3,343 230 3,573 3,573
Hours per Response: 118 222 222 129
Total Annual Hours: 393,841 45,080 45,080 438,921
Difference: +45,080 45,080
Program Change: +45,080 45,080
FERC-730 (1902-xxxx)
Current OMB Proposed Proposed New OMB
Inventory in the NOPR in Final Rule Inventory
Number of respondents: 0 200 200 200
Number of Responses: 0 200 200 200
Hours Per Response: 0 30 30 30
Total Annual Hours: 0 6,000# 6,000 6,000
Difference: +6,000 + 6,000
Program Change: +6,000 + 6,000
#At the NOPR stage, FERC-730 was proposed as “Form X” to be included as part of the filing under FERC-516. However, it was decided after reviewing the comments to make Form X a separate information collection. The hours for Form X were not treated separately in the NOPR but are designated as a separate category in the Final Rule.
13. The estimated annualized filing cost to respondents as related only to the data collection requirements as contain in the Final Rule is as follows:
The Commission sought comments about the time and corresponding costs needed to comply with these requirements. No comments were received. Costs for FERC-516 and FERC-730 = $6,129,600 (51,080 hours at $120 an hour). (The hourly rate was determined by taking the median annual salary from Bureau of Labor Statistics, Department of Labor Occupational Outlook Handbook. The figures reported by BLS are for 2002 and added to them was an inflation factor of 4.73 percent for the period January 2003 through December 2004.)
14. The estimated annualized cost to the Federal Government related only to the data collection requirements as proposed in Final Rule is as follows:
Data Analysis FERC Total Cost
Requirement of Data Estimated Per One Years
Number (FTEs) x Salary = Operation
FERC-516 9.0 $117,321 $1,055,889
(Estimated 2006 data)
15. There is a program increase to the reporting requirements contained in FERC-516-0096 and the adoption of a new information collection, FERC-730. As noted above, FERC proposes that jurisdictional public utilities be required to report annually to the Commission no later than April 18, 2007 and in succeeding years, the actual transmission investment for the most recent calendar year and planned investments for the next five years. In applicants seeking to have the Commission approve incentive-base rate treatment for transmission infrastructure investment will make a tariff filing with FERC in accordance with section 205 of the FPA that details how the proposed rate treatment justifies incentive-based (or performance-based) treatment.
16. The results of this information collection will be posted on the Commission’s Internet web site in eLibrary. These documents are normally posted two days after they are received.
Schedule for Data Collection and Analysis
Beginning in April 2007 and to be filed annually thereafter, public utilities and transcos must file with the Commission an annual report on the actual transmission investment for the most recent calendar year and planned investments for the next five years. Applicants seeking to have the Commission approve incentive-base rate treatments will file a revised tariff on as needed basis or on occasion.
Estimated Activity Completion Time
Tariff Filed On Occasion
Initial Commission Order 60 Days
17. It is not appropriate to display the expiration date for OMB approval of the information collected. Currently, the information on the tariff filings is not collected on a standard, preprinted form which would avail itself to this display. Rather, public utilities and licensees prepare and submit filings that reflect the unique or specific circumstances related to rates and services involved in the filing. In addition, the information contains a mixture of narrative descriptions and empirical support that varies depending on the nature of the services to be provided. However, under the proposed regulations, public utilities will use a standardized format to file their annual report (FERC-730). This report as adopted will contain an OMB control number and expiration date.
18. For exceptions to the Certification Statement, see item no. 17 above.
B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS
This is not a collection of information employing statistical methods.
APPENDIX
NOPR
Form X - Proposed form to be provided in compliance with proposed section 35.35 (h)
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1/ Respondents are to specify their definition of electric transmission facilities, e.g., transmission lines over __kv capacity, substations, and control and visualization equipment. |
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Project Detail 1/ |
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1/ Respondents Must List All Projects Included In Current and Projected Electric Transmission Capital Spending Table |
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Final Rule
FERC-730, Report of Transmission Investment Activity
Company Name: ________________________________________
Table 1: Actual and Projected Electric Transmission Capital Spending
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Capital Spending On Electric Transmission Facilities 1/ ($ Thousands) |
Actual at December 31, |
Projected Investment (Incremental Investment by Year for Each of the Succeeding Five Calendar Years) |
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1/ Transmission facilities are defined to be transmission assets as specified in the Uniform System of Accounts in account numbers 350 through 359 (see, 18 CFR Part 101).
Table 2: Project Detail 1/
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Project Description 2/ |
Project Type 3/ |
Expected Project Completion Date (month/year) |
Completion Status 4/ |
Is Project On Schedule? (Y/N) |
If Project Not On Schedule, Indicate Reasons For Delay 5/ |
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1/ Respondents must list all projects included in the actual and projected electric transmission capital spending table, excluding those projects with projected costs less than $20 million.
2/ Project description should include voltage level.
3/ Project types are New Build, Upgrade of Existing, Refurbishment/Replacement, or Generator Direct Connection.
4/ Completion status designations are Complete, Under Construction, Pre-Engineering, Planned, Proposed, and Conceptual.
5/ Reasons for delay designations are Siting, Permitting, Construction, Delayed Completion of New Generator, or Other (specify).
1?/Pub. L. No. 109-58, 119 Stat.594(2005).
2 ? EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures (1999-2008) at page 3 (2205). A copy of the report accompanies this submission.
3 ? Energy Policy Act of 2005: Hearings before the House Subcommittee on Energy and Commerce, 109th Congress, First session (2005) (prepared statement of Thomas R. Kuhn, President of EEI).
4 ? Comprehensive National Energy Policy: Hearings before the House Subcommittee on Energy and Commerce, 108th Congress, First session. (prepared statement of Glenn English, Chief Executive Officer of National Rural Electric Cooperatives Association).
? Transcos are stand-alone transmission companies that have been approved by the Commission.
6 Section 3(29) of the FPA (as added by section 1291(b) (29) of EPAct 2005) defines a Transmission Organization as a regional transmission organization, independent system operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.
7 See Western Area Power, 99 FERC ¶ 61,306, reh’g denied, 100 FERC ¶ 61,331 (2002) (Western), aff’d sub nom. Public Utilities Commission of the State of California v. FERC, 367 F.3d 925 (D.C. Cir. 2004); Michigan Electric Transmission Co., LLC, 105 FERC ¶ 61,214 (2003) (METC); American Transmission Company, L.L.C., 105 FERC ¶ 61,388 (2003) (American Transmission); ITC Holdings Corp., 102 FERC ¶ 61,182, reh’g denied, 104 FERC ¶ 61,033 (2003) (ITC Holdings).
8 With regard to non-public utilities, although the Commission’s regulatory authority is bound by statute; such entities could be covered by a public utility’s incentive rate proposal by a separate agreement between the public utility and a non-public utility. See Bonneville Power Administration, et. al. v. FERC, 422 F.3d 408 (9th Cir. 2005).
9 Transmission Organization is defined in 18 CFR 35.35(a)(2) of this Final Rule as “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.” Electric Utility is defined in section 3(22) of the FPA as “any person or State agency (including any municipality) which sells electric energy; such term includes the Tennessee Valley Authority, but does not include any Federal power marketing agency.” 16 U.S.C. 796(22). Transmitting Utility is defined in section 3(23) of the FPA as “any electric utility, qualifying cogeneration facility, qualifying small power production facility, or Federal power marketing agency which owns or operates electric power transmission facilities which are used for the sale of electric energy at wholesale.” 16 U.S.C. 796(23).
10?/ 42 U.S.C. 7172.
11 Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid, Docket No. PL03-1-000, 10 FERC ¶61,032 (2003).
12 Policy Statement Regarding Evaluation of Independent Ownership and Operation of Transmission, 111 FERC ¶61,473 (2005) (Transco Independence Policy Statement).
13 E.g., International Transmission, NRECA, APPA, National Grid, AEP and TAPS, Siemans, and NEMA.
14 E.g., International Transmission, Northwestern, Siemans, NEMA, and Semantic.
15 E.g., International Transmission, EEI, Northwestern, and KCP&L.
16 E.g., National Grid, Ameren, PG&E, and Nevada Companies.
17 See Section 27A of the Securities Act of 1933, as amended; Section 21E of the Securities Exchange Act of 1934, as amended; 15 U.S.C. §§ 77z-2 and 78u-5; 17 CFR § 240.3b-6.
18 E.g., TransElect, EEI, KCP&L, and Ameren.
19 They cite Critical Infrastructure Information, Order No. 630, 68 FR 9857 (March 3, 2003), FERC Stats. & Regs. ¶ 31,140 (2003), order on reh’g, Order No. 630-A, 68 FR 46,456 (Aug. 6, 2003), FERC Stats. & Regs. ¶ 31,147 (2003).
20 See 18 CFR 388.112.
21 E.g., EEI, Southern, SCE, KCP&L, Nevada Companies, Progress Energy, Mid-American and PG&E.
22 FERC-730 filers were reminded that each FERC-730 filing must be accompanied by a Subscription consistent with the requirements of 18 CFR 385.2005(a).
23 See e.g., FERC Form No. 1 schedule pp. 204-7, “Electric Plant in Service (Accounts 101, 102, 103 and 106)” which requires the reporting of the original cost of electric plant in service and p. 216, “Construction Work in Progress—Electric (Account 107)” which requires the reporting of expenditures for certain construction projects at December 31 of the reporting year.
24 The Commission will issue a separate notice on how to submit this data electronically via eFiling.
25 2004 State of the Markets Report, Federal Energy Regulatory Commission, Staff Report by the Office of Market Oversight and Investigations, June 2005, at p 27.
26 See Eric Hirst, U.S. Transmission Capacity: Present Status and Future Prospects, a study prepared for EEI and the U.S. Department of Energy Office of Electric Transmission and Distribution, June 2004 (Hirst) and Keeping Energy Flowing: Ensuring a Strong Transmission System to Support Consumer Needs for Cost-Effectiveness, Security and Reliability, a report of the Consumer Energy Council of America, Transmission Infrastructure Forum, January 2005. See also Affidavit of Jon E. Jipping, Exhibit A to the Reply Comments of International Transmission (the transmission system purchased in Michigan was 2.5 to 7 years behind schedule in maintenance on key transmission facilities).
27 Kristina LaCommare and Joseph Eto, Understanding the Cost of Power Interruptions to U.S. Electricity Consumers, Lawrence Berkeley National Laboratory (September 2004) at xiv.
28 See Final Report on the August 14, 2003 Blackout in the United States and Canada by the U.S. – Canada Power System Outage Task Force (April 2004) at 1.
29 See Hirst at 8.
30 See 2004 PJM State of the Market Report at 37 (March 8, 2005).
31 E.g., TDU Systems, APPA, and Maryland Commission.
32 E.g., NASUCA and Connecticut DPUC.
33 E.g., APPA, TAPS, NECOE, E.ON U.S., NARUC, and New Jersey Board.
34 E.g., Connecticut DPUC, NASUCA, NECPUC, Delaware Commission, Missouri Commission, and New Mexico AG.
35 See FPC v. Hope Natural Gas Co., 320 U.S. 591, 602-03 (1944).
36 Although new section 216 of the FPA improves the siting process for certain new projects, it does not eliminate all risks faced by such projects nor does it address the risks faced by other projects that do not reside in a national interest transmission corridor.
37 E.g., Progress, NEMA, and PG&E.
38 E.g., PG&E, Connecticut DPUC, NASUCA, TDU Systems and TANC.
39 E.g., Progress, NEMA, EEI, Trans-Elect, and National Grid.
40 E.g., TANC, Snohomish, Municipal Commenters, and TDU Systems.
41 See also National Grid and EEI.
42 The information may include, as well as supplement, information provided in FERC-730.
43 An applicant has the option to include metrics proposals in a declaratory order proceeding, but would also need to include them in the subsequent section 205 rate filing.
44?/See The Power Company of America, L.P. v. FERC, 245 F.3d 839 (D.C. Cir. 2001) (PCA). In PCA, the court found, 245 F.3d at 846, that the Commission may alter its view of what information is required to be on file under section 205(c) of the FPA and 35.15 of the Commission's regulations.
| File Type | application/msword |
| Author | Michael Miller |
| Last Modified By | Michael Miller |
| File Modified | 2006-07-27 |
| File Created | 2006-07-26 |