8. Resolving Ratemaking Issues in A.03-02-027
In this section the Commission addresses major components of revenue requirements for the 2003 test year rate case. Under general ratemaking principles, the Commission allows a utility such as SFPP to file a general rate case application to recover in base rates a forecast of its operating costs to provide customers safe and reliable service.22 The Commission adopts a test year forecast based on the best information about expected future events and historical trends. By using a prospective forecast methodology SFPP has an opportunity to recover its costs and earn a return (profit) on its investment in plant in service. SFPP is expected to exercise discretion to expertly manage its operations during the test year and adapt as necessary to differences between the forecast and actual events. Included in the test year forecast are allowances for damages to plant, accidents, and general maintenance and repairs. Every subsequent general rate case allows SFPP to reflect its prior actual investment in plant as a part of the forecast for the next test year. Thus when SFPP spends more money than forecast for capital projects during the prior test-period, it adjusts the new test year forecast to include the actual investment in utility plant.
8.1. Cost of Capital and Rate of Return
In this section, we adopt a test year 2003 capital structure of 60% equity and 40% debt, accept the company forecast of embedded debt cost at 7.08% and adopt a return on equity of 12.61%. We reject SFPP's argument that the risk of the oil pipeline operations subject to our regulation warrants a return on equity of 15.86%.
SFPP requests a 2003 capital structure of 60% "equity" and 40% debt, based on the capital structure of KMEP the affiliated entity that manages SFPP's finances. (See § 3.3 Control of SFPP.) SFPP is a partnership, and thus this "equity" capital represents the partners' investment or ownership interest retained in SFPP to finance its long-term assets included in rate base. For ease of
reference we will identify this ownership interest as equity. Additionally, SFPP's expert witness proposed a weighted cost of debt of 7.08% and a return on equity of 15.86%. (See SFPP April 27, 2007 Opening Brief at 34 - 43.) SFPP argues that because of infrequent rate reviews this structure and these costs are reasonable.
SFPP admits that the debt instruments and costs of debt available to KMEP may not be available to SFPP directly, but it based the proposal on the costs available to KMEP. SFPP argues that capital investments in long-term plant are large and not uniform over time - but "lumpy" - and that over time depreciation leads to a reduced actual return (because the rate base declines as depreciation accumulates). Thus, combining the operating risks of an oil pipeline with the lumpy nature of additions, leads to the need for a high return in order to attract capital.
A group of the intervenors, CCUV,23 propose a 44.8% equity and 55.2% debt ratio and they rely on a proxy of four other pipeline companies' data which shows a range of 44% - 61.4% debt ratio, with a median ratio of 53.5%. (See CCUV April 26, 2007 Opening Brief at 38 - 51.) For ease of discussion we will round this to 45%/55% capital structure. Thus the CCUV recommended equity component is a quarter smaller, 45% compared to 60%. Before considering any return on equity differential due solely to capital structure, this difference alone would have a significant impact on cost of capital. CCUV also proposes a return on equity of 12.28% and a debt cost of 6.41%. CCUV further argues that SFPP's cost is too high because it includes certain short-term debt, that was in fact an affiliate loan, and which is more correctly identified as long-term debt. (Id. at 48 - 50.) Finally, CCUV proposes that the appropriate return on equity should be 12.28%.
These differences in capital structure and cost components lead to a huge 330 basis point difference in the cost of capital: SFPP requests approximately 12.35% and CCUV recommends 9.05%, as shown in the table below:
SFPP |
CCUV | |||
Percentage |
Cost |
Percentage |
Cost | |
Equity |
60% |
15.86% |
45% |
12.28% |
Debt |
40% |
7.08% |
55% |
6.41% |
Weighted Cost |
12.35% |
9.05% | ||
In D.89-11-068, the Commission reasoned that the utilities should be given some discretion to manage their capitalization with a view towards a balance among investors' interests, regulatory requirements, and ratepayers' interests.24 The Commission also concluded that the energy utilities' capital structures should continue to be evaluated on a case-by-case basis. In 2003, the Commission adopted returns on equity ranging from 10.90% for SDG&E and Sierra Pacific Power Company (Sierra), to 11.605% for Edison.25 PG&E was authorized a return on equity of 11.22%, but it and Edison were involved in bankruptcy or severe financial crises caused by the collapse of the state's restructuring of the electric wholesale markets pursuant to Assembly Bill 1890. Moreover, these four large utilities are corporations, whereas SFPP is a limited partnership. These differences and others only underscore the need to evaluate rate of return on a case-by-case basis.
SFPP seeks an equity return of 15.86% while the intervenors propose 12.28%. We reject SFPP's evaluation of its risk and we further reject the declining rate base argument. SFPP's rates could be in place for a significant period of time so despite the accrual of depreciation and reduction to plant in service (a proxy for rate base) there would be no reduction in rates. We are adopting rates much in arrears - a timely decision would have been in late 2003 or early 2004 and no one would have known then when SFPP would file its next proceeding or when it would be resolved. We knew, however, in 2003 that the last full rate case for SFPP was decided in May 1992 (D.92-05-018) and so 2003 base rates could also have been expected to be in effect for a long time: unchanged for the effects of depreciation or capital additions.
We will adopt SFPP's proposed capital structure, 60% equity, 40% debt because it best reflects the structure of the actual financing source, KMEP, and the forecast for KMEP's cost of debt at 7.08%. Adopting the very high equity component of 60% is a significant mitigation of risk. With the lower debt service that results from more equity and less debt, it is less likely the company will have a liquidity issue, and indeed, more likely its actual cost of borrowing will be low, due to a high equity factor in the given marketplace and time-frame.
Thus, it is within our discretion, and within the recommended range, to adopt a return of 12.61% on equity, which yields a weighted cost of capital for test year 2003 of 10.40%. The equity return is significantly higher than the rate adopted for the major energy distribution utilities, and is slightly higher than the recommendation of intervenors. When viewed with the 60% equity ratio, this return should be a sufficient to compensate investors for the operating and financial risks associated with SFPP's operations. The adopted costs of capital are set forth in the following table:
8.2. Rate Base for 2003 and Beyond
Some portion of the $88 million in costs associated with SFPP's North Line Expansion was not expected to be incurred in calendar year 2003, but the company anticipated that all of such costs would be incurred by the end of 2004. The question is whether to include the project in test year 2003 rate base. As discussed below, we find that the project cannot be included in test year 2003 given the ratemaking mechanisms that apply to SFPP. We adopt a ratemaking adjustment for rates beginning on January 1, 2004 that includes the plant in rate base.
SFPP argues that the test year 2003 "reflect[s] costs and conditions expected to occur during the 12 months of the test year (2003) as well as reasonably anticipated changes in gross revenues, expenses or other conditions, which do not necessarily obtain throughout the twelve months of the test period but which are reasonably expected to prevail during the future period." (Concurrent Reply Brief at 11, emphasis deleted.) Indicated Shippers argue the plant would not be in service in 2003 and thus should be excluded from the test year rate base and therefore excluded from test year 2003 revenue requirements.
SFPP cites to Pacific Telephone and Telegraph Company v. Public Utilities Commission (1965) 62 Cal.2d 634, without specific reference. That venerable decision describes the test year ratemaking process where the Commission uses historical data, known or forecast events, etc., with adjustment, "to present as nearly as possible the operating conditions of the utility which are known or expected to obtain during the future months or years for which the commission proposes to fix rates." (62 Cal.2d 634 at 644.) In this case, the Commission is determining rate base for 2003 and it is uncontested that the North Line Expansion was not expected to be fully complete and in service for 2003. Therefore we will not include this investment in rate base for 2003 and thus we also exclude it from 2003 revenue requirements.26
SFPP errs in including post-2003 events in the test period as it proposes in its brief. The ratesetting test year is a fixed forecast period regardless of when the rate decision is actually resolved.
As noted elsewhere, SFPP's last general rate case decision was adopted in May 1993. We also could have expected test year 2003 to be in effect for some period before SFPP might have filed another general rate case. The North Line Expansion is a major facility forecast to add some $88 million to plant in service. This decision is not timely and yet it must be decided based on the record before us as expected for 2003. Unlike the major gas and electric utilities, or the Class-A water utilities, the Commission has no cyclical rate case plan with an attrition rate adjustment mechanism in place applicable to jurisdictional oil pipeline companies. Thus, we must consider these cases in such a way that we derive just and reasonable rates, avoid unnecessary additional proceedings, or otherwise burden either applicant or ratepayers. Absent a ratemaking allowance in 2003 for the North Line Expansion, SFPP could have filed a new proceeding for 2004, and possibly an entire rate case, to reflect this plant addition in 2004 and perhaps included other changes too.
A reasonable outcome, foreseeable in 2003, was the North Line Expansion would enter service in 2004, but after the test year, which would then entitle SFPP to file again for an opportunity to recover its reasonable costs in rates. The Commission is within its discretion to exclude the North Line Expansion from rates for test year 2003, but it is also reasonable to order an attrition rate adjustment for the North Line Expansion effective in 2004. This avoids improperly including the North Line Expansion in rate base for 2003 and avoids an unnecessary filing for 2004 or later to reflect a material change.
22 "[T]he cost principle is taken to mean that rates as a whole should cover costs as a whole." Bonbright et al., Principles of Public Utility Rates at 116 (2d ed., Public Utilities Reports, Inc., 1988).
23 The Indicated Shippers group mutated by the time of the April 26, 2007 briefs: ConocoPhillips joined with Chevron, Ultramar, and Valero, three original Indicated Shippers, to file briefs jointly as "CCUV." Meanwhile, BP West, another original Indicated Shipper, filed jointly with ExxonMobil. Additionally, Chevron, Ultramar and Valero filed separately but join with BP West and ExxonMobil on "market based" issues.
24 33 CPUC2d 495 at 541- 545 (1989).
25 See 2002 Cal. PUC LEXIS 718 where the Commission adopted 2003 capital structures and cost of capital for PG&E, SDG&E, Edison, and Sierra.
26 "The test period is chosen with the objective that it present as nearly as possible the operating conditions of the utility which are known or expected to obtain during the future months or years for which the commission proposes to fix rates [i.e, the test year]. The test-period results are "adjusted" to allow for the effect of various known or reasonably anticipated changes in gross revenues, expenses or other conditions, which were not obtained throughout the test period but which are reasonably expected to prevail during the future period for which rates are to be fixed, so that the test-period results of operations as determined by the commission will be as nearly representative of future conditions as possible." (62 Cal.2d 634 at 644.)
