Darryl Tietjen Public Utility Commission of Texas Southwest Electric Distribution Exchange Conference April 27, 2011

1. Darryl Tietjen Public Utility Commission of Texas Southwest Electric Distribution Exchange Conference April 27, 2011 Distribution Cost of Service (DCOS) Perspectives—The Future of Electric Distribution Ratemaking

2. Purpose of this presentation is to: • Provide a quick and general overview of traditional rate regulation and the ratemaking process • Discuss recent and emerging regulatory and legislative developments in the recovery of distribution-related costs and investments

3. Provide a quick and general overview of traditional rate regulation and the ratemaking process • Discuss recent and emerging regulatory and legislative developments in the recovery of distribution-related costs and investments

4. Traditional Cost Recovery for Regulated Investor-Owned Utilities • In Texas, Sec. 36.051 of the Public Utility Regulatory Act (PURA) states that: • “In establishing an electric utility’s rates, the regulatory authority shall establish the utility’s overall revenues at an amount that will permit the utility a reasonable opportunity to earn a reasonable return on the utility’s invested capital used and useful in providing service to the public in excess of the utility’s reasonable and necessary operating expenses.”  PURA provides a reasonable opportunity for a utility to earn its authorized return but does not provide a guaranteed level or rate of return.

5. What Triggers A Utility Rate Case? • Earned return is too low • The utility company initiates a rate case • Earned return is too high • PUCT Staff reviews annual PUC Earnings Monitoring Reports and makes recommendation to the Commission to require a company to file a rate case • Intervenor group files petition to initiate a rate case

6. In Cost-of-Service regulation, the regulator determines the Revenue Requirement—i.e., the “cost of service”—that reflects the total amount that must be collected by the utility so that it can recover its costs and earn a reasonable return. Basic ratemaking formula: Rate Base x Allowed Rate of Return = Required Return $$ + Operating Expenses = Cost of Service (Revenue Requirement) What is “Cost of Service” Regulation?

7. Basic Issues in Rate Proceedings • Regulated Rates are essentially made up of the following basic components: • Return on investment through rate of return on invested capital • Return of investment through recovery of depreciation expense • Recovery of reasonable and necessary expenses • Recovery of taxes • Recovery of reasonable fuel expenditures (for vertically integrated companies)

8. Overall Objectives of the Ratemaking Process • Develop the utility’s revenue requirement (i.e., the utility’s reasonable cost of service) • Design rates to recover cost of service • Cost of Service study is developed to allocate the utility’s revenue requirement to various customer classes (e.g., residential, commercial, industrial) • Rates are designed to recover the utility’s revenue requirement from the various customer classes  These steps constitute a conceptually simple process, but in practice, a comprehensive rate case is typically a massive undertaking with regard to the effort and volume of information necessary to complete the process.

9. The Rate Filing Package Prepared Testimony • A Rate Filing Package (RFP) must be accompanied by the applicant’s prepared testimony • Topical and relevant issues related to the electric and energy industry • Economic issues • Accounting and Finance • Legal and regulatory issues and analysis • Engineering issues

10. The Parties • Utility (applicant) • Intervenors • Involved parties may be friends or foes of the utility • Could include customer groups, rate/consumer advocates, other utilities, competitors • Commission Staff

11. Basic COS Component: Rate Base • The Rate Base is the net amount of investment, funded by investors, in utility plant and other assets devoted to the rendering of utility service upon which a reasonable rate of return may be earned. • Plant in Service is the largest component of a company’s rate base • Generally, it is one of the least controversial aspects of a rate proceeding unless the prudence of construction is an issue or excess capacity is at issue • Materials and supplies • Cash Working Capital • For vertically integrated utilities, Rate Base includes fuel inventories consisting of gas in storage, coal, and nuclear fuel inventories

12. Criteria for Inclusion of Costin Rate Base • “Used and useful” concept – only plant currently providing or capable of providing utility service to customers is included in rate base • “Prudent investment” concept – only plant prudently purchased or constructed is includable in rate base • Construction of nuclear generation plants in 1980s led to state commission prudence reviews of construction management and costs associated with construction of nuclear facilities. In some cases, these prudence reviews led to disallowance of plant costs for ratemaking purposes • Prudence disallowance of transmission and distribution investment rarely, if ever, occurs.

13. Basic COS Component: Rate of Return • The Rate of Return is the percentage rate that the PUC finds should be earned on the rate base in order to cover the costs related to the financing provided by the company’s capital investors. • What is meant by the phrase “allowed rate of return”? • In the utility industry, the phrase “allowed rate of return” is generally synonymous with “the cost of capital.” It refers to the rate of return on rate base required to recover the utility’s: • Costs of common stock, long-term debt, and preferred stock • The total dollar amount of return, which includes earnings, is calculated by multiplying the allowed rate of return by the utility’s total dollar amount of rate base. • The Commission-authorized Rate of Return can be considered as the rate of return that is permitted, but not guaranteed.

14. Basic COS Component: Operating Expenses • Allowable Operating Expenses include operation and maintenance costs (O&M), depreciation, and all taxes, including income taxes. • O&M expense includes: • Power production expenses • Transmission expenses • Distribution expenses • Customer accounts expenses • Customer service and informational expenses • Sales expenses • Administrative and general expenses

15. Operating Revenues and Expenses • Requirements for inclusion of costs in revenue requirement • Costs must be just and reasonable • Costs must be prudently incurred • Cost adjustments must be known and measurable

16. Test-Year Concepts • Identification of test year • Historical test year – generally based on financial data for the most current 12 months for which information is available during the preparation of the rate application • In some circumstances, forecasted test years may be used—for example, the new CREZ utilities in Texas will likely use forecasted test years • The use of historical test years is far more common than the use of forecasted or prospective test years.

17. In Cost-of-Service regulation, the regulator determines the Revenue Requirement—i.e., the “cost of service”—that reflects the total amount that must be collected by the utility so that it can recover its costs and earn a reasonable return. Basic ratemaking formula: Rate Base x Allowed Rate of Return = Required Return + Operating Expenses = Cost of Service (Revenue Requirement) To summarize the “cost of service” one more time…

18. Quick Overview of Allocation of Costs After the utility’s revenue requirement is established, the next steps are to: • Allocate revenue requirements to customer classes • Structure and design rates to recover revenue requirements • Rate = Cost/Billing Determinants • Develop supporting schedules and file final tariffs.

19. Rulemaking Activities at the PUC • PUC Subst. R. 25.192—(the “Interim TCOS” rule) • This rule allows transmission service providers to update their transmission rates twice per year to reflect the return on and of new transmission investment (along with related taxes); it does not include any adjustments to expenses. • PURA 35.004(d) provides specific statutory authorization for recovery mechanisms for transmission investment: “…the commission may approve wholesale rates that may be periodically adjusted to ensure timely recovery of transmission investment.”

20. Streamlined Recovery of Distribution Investment? • Utility companies have for many years been seeking a similar type of streamlined recovery mechanism for distribution investment. • For transmission and distribution utilities, about 2/3 of their rate base, on average, is related to distribution. • For the state’s two largest utilities—Oncor and CenterPoint—that translates to over $5 billion and about $2.5 billion, respectively.

21. Streamlined Recovery of Distribution Investment? The critical question is: Does PURA authorize the type of recovery for distribution investment that it does for transmission investment? Therein lies the proverbial rub….

22. PUC Rulemaking on Distribution Cost Recovery Factor (DCRF) In May 2010, Commission Staff opened a rulemaking project to develop a DCRF mechanism that would be similar to the existing interim TCOS recovery mechanism. While parties in the rulemaking contested many issues relating to such a mechanism, the central point of controversy was: Is a mechanism for streamlined recovery of distribution costs legal?

23. PUC Rulemaking on Distribution Cost Recovery Factor (DCRF) • In December 2010, based on comments from parties in the rulemaking, Staff submitted to the Commissioners a Proposal for Adoption. • Under Staff’s proposal, the basic operation of the DCRF would have been similar to that of the interim TCOS rule—it would have allowed utilities to make streamlined filings requesting updated rates reflecting a return on and of distribution investment. • After considering Staff’s Proposal for Adoption, the Commission…

24. PUC Rulemaking on Distribution Cost Recovery Factor (DCRF) ….declined to adopt the rule. One commissioner (Chairman Smitherman) stated that he did not believe that the mechanism contemplated in the proposed rule was legal under existing statute. Two commissioners (Commissioners Nelson and Anderson) stated that they believe the PUC already has the statutory authority to adopt such a rule, but opted to give the Legislature an opportunity to address the issue and pass a bill if deemed necessary or for statutory clarification purposes.

25. PUC Rulemaking on Distribution Cost Recovery Factor (DCRF) So…….. At the present time, the Commission still does not have a rule or mechanism that provides for streamlined recovery of distribution-related costs.

26. Is there really a need for a streamlined mechanism for distribution costs? Not surprisingly, the answer to this question is in the eye of the beholder…..

27. Is there really a need for a streamlined mechanism for distribution costs? • Utility companies say: • the current regulatory ratemaking paradigm is outdated and stale, and does not reflect current market and industry conditions. • Providing for streamlined recovery of investment in distribution infrastructure reduces uncertainty about cost recovery and enhances economic incentives for additional distribution investment • The existing ratesetting process is bloated, inefficient, and costly. • For example, in CenterPoint’s recent base-rate proceeding, parties submitted over 2,000 requests for information (in addition to the info in the nearly 7,000 pages included in CNP’s initial filing).

28. Is there really a need for a streamlined mechanism for distribution costs? • Intervenor/ratepayer groups say: • Utility companies are attempting to circumvent appropriate regulatory scrutiny and push through rate increases quickly without allowing affected parties a reasonable opportunity for review. • Limited-issue rate adjustments constitute “piecemeal” ratemaking. • Even though some regulatory lag may exist with regard to recovery of distribution investment, that is not necessarily a bad thing, as regulatory lag is a natural (and in fact desirable) part of regulation. • The utilities’ goal is to create a regulatory system in which comprehensive rate cases became a thing of the past and the traditional checks and balances (such as regulatory lag) in the ratesetting process are no longer meaningful.

29. Adventures in Legislation—Current Legislative Bills • Senate Bill (SB) 1693 and House Bill (HB) 3610: • these bills are referred to as the “PRA” bills (Periodic Rate Adjustments); they were originally filed as identical companion bills, and they provide explicit statutory authority for the implementation of a streamlined distribution-related cost-recovery mechanism. • Passage of either of these bills would definitively eliminate the intervenors’ principal argument against implementation of such a mechanism—that it is illegal.

30. SB 1693 and HB 3610 These legislative bills: Provide for streamlined PUC proceedings that would authorize recovery of and on new distribution investment, along with related taxes. Do not provide for recovery of expenses (same as interim TCOS rule), but latest version of SB 1693 does provide that rates may be adjusted based on changes in distribution-related “intangible plant” (e.g., software for outage management systems) and “communication equipment and networks” (e.g., smart grid infrastructure). SB 1693 provides that the PUC may determine in either the PRA filing or the utility’s next full rate proceeding that the investments were prudent, reasonable, and necessary.

31. SB 1693 and HB 3610 These bills also: Would apply to both ERCOT and non-ERCOT (still vertically integrated) utilities. Provide for municipalities’ continued original jurisdiction over a utility’s rates (with PUC having appellate jurisdiction, as it has currently). Provide for rate updates on an annual basis (SB 1693 limits utilities to four PRA increases between full rate cases).

32. SB 1693 and HB 3610 These bills also: Provide that new rates resulting from the PRA should reflect the effects of any increases in base-rate revenue resulting from load growth. SB 1693 provides that PUC rules shall require utilities to file earnings reports that allow the PUC or regulatory authorities to determine whether the utility is over-earning. SB 1693 has a six-year sunset provision (the law would expire August 31, 2017).

33. PUC Rulemaking—Subsequent to Passage of Legislative Bill • Many legislative bills (such as the PRA bills) specifically require the PUC to adopt rules that establish the specific procedures and details pursuant to implementing the provisions of the new law.  Once a law is passed, the arguments about some issues may still not be over, as stakeholders can be expected in the ensuing rulemaking process to continue to advocate their interests and argue about the appropriate interpretation of the new law.

34. Expectations for the PRA bill(s)…. • After all is said and done, the most likely outcome with regard to the possibility of a PRA type of mechanism is that a bill will be passed and a rule will then be adopted, after which the utilities will have available for their distribution investment a recovery mechanism that is essentially the same as that for transmission investment.  Specifically, utilities in Texas will be able to more efficiently and timely recover and earn a return on distribution-related investment.

35. Questions? Darryl Tietjen Director, Rate Regulation Division Public Utility Commission of Texas 512-936-7436 darryl.tietjen@puc.state.tx.us