See a pre-print of my Oct. 2009 Natural Gas & Electricity article on pricing schemes for gas pipelines. E-mail warner@bwmq.com to get a copy.
A family member called me recently about the tax consequences of her “short sale” real estate transaction. In a situation that is common in this economy, her family had moved due to a job transfer. The former house didn’t sell, so they tried renting. The rental situation worked for a while, then the tenants had to move back to their former house when a relative didn’t keep a commitment to a “rent to buy” transaction. The family needs to move on. They are hoping their short sale is approved by the bank. Another concern was about the potential tax consequence of forgiveness of part of the real estate debt.
In another recent experience, I became acquainted with several investors who have had problems/questions about Florida real estate purchases and with qualifying for real estate professional status. What is apparent from these and similar circumstances is that the tax law doesn’t work the same in real estate for everyone. Depending on the filing status of the taxpayer, adjusted gross income, extent of work in the real estate field and a host of other factors, tax results can be dramatically different for different investors. If you are thinking of investing in real estate now, due to the opportunity in the market, be careful, get informed, plan, but don’t be afraid. But,don’t assume that all of your losses will be immediately deductible. Like any other business, education, hard work and experience pay off.
In my consulting work in the energy sector, I have found that some operators are considerably more savy than others. Some companies understand creative financing, regulatory and investment strategies, others are less experienced. Regulatory factors are particularly important; real money must be spent to clear the necessary hurdles to navigate to the successful conclusion of projects and to profitable operations. But, if all this is done an energy franchise can be extremely valuable over time.
Early in my career a gas pipeline holding company I worked for was acquired by another big outfit that was seeking to diversify its portfolio. They wanted to find a good “cash cow” to invest in to get out of the ups and downs of their cyclical business. portfolio They did find that, but the analysis that was done by Wallstreet bankers at the time was poor. I have seen the analysis. The bankers didn’t understand the business, and didn’t spot the hidden assets that made the project ultimately a success. If the business had been what they thought, the transaction would have failed miserably. Hence, the need for careful due diligence and the involvement of people who really understand. Another factor in the success of the project was the value of the utility franchises that were owned by the acquiree. An analysis that looks primarily at existing assets can’t adequately capture the potential for growth project of such a franchise. Smart energy operators must understand the difference between regulated and unregulated profits, and how to generate high earnings.
Gas Pipeline Pricing Evolution – MeetingThe Challenges of Modern Markets
Gas pipeline prices (rates or tolls) in the United States have evolved over the time since passage of the Natural Gas Act (NGA) in 1938[i] from a strict cost-plus-profit model to a more indirectly regulated regime today. This article discusses past and present pricing alternatives and the ramifications of a number of current risks facing pipeline developers and their customers.
The first (and still used) cost-plus pricing models determined prices by employing “cost of service” principles. The resulting prices are either known as “Stated Rates” or “Cost of Service Rates.” Stated Rates remain fixed in a pipeline’s base tariff between rate change dates, such as the dates that general rate changes are implemented. Cost of Service rates vary periodically between the system-wide rate change dates as the inputs into the cost of service formula change.
Stated Rates please regulators because the pipeline owner experiences incentives to reduce costs as a way to improve profits, thereby also encouraging rate stability. The cost reductions may be passed on to shippers if rates are reduced. The gas pipeline industry today faces claims by gas producer interests, some shippers and some state regulators that the efficiency incentives under Stated Rates have been too strong. Some of those parties argue that the NGA should be changed in a way that successful rate challenges would occasion relief back to the date of a rate complaint, rather than being effective only prospectively as under current law.
Costs of Service rates usually fall flat with regulators today because they tend to guarantee profit results and do not provide substantial efficiency incentives. However, Cost of Service formula rates still exist under specific contract rates with shippers because of the shippers’ desire to not pay more than actual costs. Cost of Service rates, depending on how they are defined, may create extra administrative and audit burdens. However, in some situations Cost of Service rates can be useful as a means of resolving disputes between a pipeline and its customers.
Cost-Plus Pricing Fundamentals
For companies that calculate rates under cost-plus pricing, one of the most important and contentious cost elements is the cost of common equity. Cost of service, or the revenue requirement of the utility, includes operating expenses, taxes, return on rate base including the cost of debt and equity financing, depreciation, and a reduction for incidental revenues.
To calculate the return on rate base, it is necessary to first calculate rate base. This item represents the net current investment in utility facilities that has been financed by investors. Rate base includes the cost of property, reduced by accumulated depreciation and deferred income taxes. Rate base also includes operating capital, such as materials and supplies inventories and prepayments.
The weighted average cost of debt and equity, or return on rate base, includes: (1) the sum of the cost of debt multiplied by the percentage of the total capital structure that is financed by debt, and (2) the cost of each source of equity financing multiplied by the percentage of the total capital structure that is financed by each equity source. Once the weighted cost of each financing source is calculated, the costs of all the financing sources are summed to derive the total weighted average cost of capital. The cost of common equity is generally the subject of much dispute and litigation, the details of which are beyond the scope of this article except to say that some new pricing methods may in part have the advantage of bypassing such disputes.
The Importance of Perceived Gas Pipeline Market Power
The U. S. federal regulatory regime rests on the regulatory importance of perceived (or actual) gas pipeline market power[ii]. At the industry’s inception the concept of cost-plus pricing reflected the idea that gas pipelines are essential utilities to the public, costly to duplicate, and have the potential to exercise market power; i. e., gas pipelines if left unrestrained by regulation could presumably exercise market power by charging rates above the cost of service rate and/or competitive rate.
The Evolution of Market-Oriented Pricing Strategies
Market-oriented strategies may be employed to develop successful gas pipeline projects under regulatory policy changes that occurred in 1996 and 1999.[iii] During those years, the FERC issued policy statements that enhanced the competitive landscape for new natural gas pipelines and for expansions of existing pipelines.
1996 Developments –
At the urging of the pipeline industry, in early 1996 the FERC issued its Statement of Policy on Alternatives to Traditional Cost-of-Service Ratemaking and its companion Policy on Regulation of Negotiated Services of Natural Gas Pipelines (1996 Policy Statement)[iv]. These documents became important as permitting indirectly market responsive pricing for pipeline transportation through a price-capped rate regime.
The 1996 Policy Statement introduced two new concepts for both the pricing of new gas pipeline infrastructure and for fostering markets for ongoing gas storage and transportation transactions. Under the first concept, “negotiated rates,” the pipeline and its customers by agreement may deviate from normal cost-plus tariff pricing. As an example, variations from the usually required straight-fixed variable pricing method (“SFV”)[v] are permitted. In addition, the pipeline may propose innovative cost of service calculation methods, such as rate levelization plans.[vi]
Negotiated rates are attractive to shippers because they allow better matching of cost calculations by service period to ability to pay, and such plans can result in a fixed rate for a number of years that is not subject to rate case disputes. For example, a rate levelization regime may benefit shippers by providing significantly lower initial prices than the traditional cost of service and declining rate base methodology (Traditional Rate Method).[vii] (Indeed, some projects very likely won’t get built today at all unless a levelized price is used, particularly because the FERC no longer permits existing shippers to subsidize expansions, as further discussed below.)
The second important idea in the 1996 Policy Statement is the concept of a “recourse rate.” As a predicate to permitting flexible, negotiated rates, the FERC required a calculation of a ceiling price to serve as a constraint on potential monopoly pricing power. Recourse rates for pipeline infrastructure additions have devolved generally into a price that is established under the Traditional Rate Method.[viii] The FERC required that such recourse rates would always be offered as an alternative to negotiated prices. The Commission ruled that costs and revenues related to negotiated services must be separately identified in pipeline records to facilitate the review of the effects of such services during general rate case proceedings.
When a rate case arises, the pipeline must be prepared to assume the full risk of its negotiated services without seeking discount adjustments in establishing the billing determinant levels used to calculate prices. Cost allocations among the pipeline’s various services must be calculated as though the negotiated service shippers are paying maximum recourse rates. As a result of these rules, entering into negotiated transactions exposes the pipeline to the full risk of each transaction, but with pricing tools needed to meet a broader market demand and the potential for improved earnings due to lighter regulation over price.
1999 Developments –
Pricing principles continued to evolve with the issuance of an order that departed dramatically from past pricing principles. Prior to 1999, a debate raged in the industry regarding which expansion project costs would be rolled-in, or averaged into, existing rates and which projects involve costs so significant that they should be priced on a stand-alone basis, which is referred to as incremental pricing.[ix]
Under the new pricing policy[x], the Commission stated:
“The threshold requirement in establishing the public convenience and necessity for existing pipelines proposing an expansion project is that the pipeline must be prepared to financially support the project without relying on subsidization from its existing customers.”
The Commission explained that the requirement for projects to be able to stand on their own without subsidies “…recognizes that a policy of incrementally pricing facilities sends the proper price signals to the market …the market will then decide whether a project is financially viable.” The FERC set in stone the principle that existing customers should not have to subsidize a project that does not serve them. This no-subsidy principle therefore made it more difficult to build new projects in competition with other more depreciated pipeline systems without the tools available from the newer, more creative pricing methods. However, rolled-in pricing was still permitted in certain circumstances, such as when a project would reduce existing rates or if the project is constructed solely to enhance system flexibility or reliability.
Economic and Regulatory Approaches in a New Environment
The Environment Today –
Significant economic, environmental and political pressures surround new infrastructure projects. These issues confront all stakeholders: governmental agencies, project sponsors, debt holders and gas consumers. With the disappearance of formal public convenience and necessity hearings in most regulatory jurisdictions, regulators increasingly rely on the confluence of market forces to decide which projects should be built. Today market forces are used to: (1) select among potential project sponsors, (2) allocate capacity among shippers and (3) create contractual means to mitigate project risks (such as the risk of a cost overrun or the risk of shipper default). Whether project sponsors build a project generally no longer is dependent on regulatory approval, rather sponsors are at risk for their investment decisions.
Since the market decides those matters, then logically market forces in many instances should also be permitted to select the means of pricing the projects, both over the short-term and long-term. However, to this point public policy has not been resolved in favor of unbridled market-based pricing of all gas transmission projects due to a strong lingering concern that gas pipelines are uniquely invested in the public welfare, are costly to duplicate and good alternatives to pipeline transportation do not exist in all geographic and product markets. Nevertheless, the FERC’s current incremental pricing and negotiated rates policies permit more market-responsive prices than were possible in prior years.
Blending Regulatory and Negotiated Rate Options –
Negotiated rates can be viewed as economically efficient because they bring a willing buyer and willing seller together in an environment where potential market power is constrained. In practice, negotiated prices are not a “one size fits all” proposition. A key dynamic of such prices is how the parties choose to deal with the length of the pricing arrangement, considering particularly that (for projects to secure debt financing) a degree of certainty usually must be achieved over contract terms of 10 or 15 years, or more. One issue that hasn’t, in my opinion, been dealt with completely yet by regulators or project participants is what will happen to the rates, depreciation recovery and ultimate project success once existing negotiated rate projects ramp off of their existing contracts. Today’s typical negotiated contracts with their 10 or 15 year contract terms are significantly shorter than the probable life of the facilities and related gas supplies. Project sponsors can’t be assured that they will be able to negotiate acceptable prices again with a new group of shippers. If such newly negotiated arrangements fail, then a host of regulatory issues could arise since it is not at all clear what rate base will then be available to the project sponsor under then existing regulatory principles.
We might ask, given the negotiated rate option’s availability, is there still a role for cost-plus pricing? Yes, there is for several reasons. First, the pipeline must establish initial rates for at least its interruptible services and re-justify or change those rates within three years of the inception of services under traditional rate principles. Second, a pipeline may have a mix of traditional services and other negotiated services. Third, the recourse price must be calculated under traditional pricing to establish a cost ceiling for comparison to negotiated prices, since the pipeline may not charge base tariff rates above the cost ceiling.
A number of variations in the methods that blend the best features of regulation and negotiation are possible and available to meet the concerns of all stakeholders over the entire life of the project. Such blending is probably under-used today and would often be desirable. For example, customers may have concerns about certain elements of the cost of service, such as concerns regarding potential unjust earnings that could occur with economic changes over a long time period, resulting in stale cost inputs such as an outdated return on equity. On the other hand, a project sponsor may need to be protected against a change to the basic project pricing formula that may harm the recovery of the expected returns over the life of the facilities, such as could occur with an interim switch from the levelized method to the traditional rate method[xi], or due to an unexpected, hypothetical regulatory rate base that may evolve if the project sponsor is forced to revert to traditional regulatory pricing. If more use were made of blended regulatory and negotiated pricing arrangements, conceivably very long-term arrangements could be set that would both assure all parties of reasonable outcomes and avoid unnecessary regulatory disputes.
Other Considerations in Managing Project Risks –
Project sponsors and project participants would be well advised to consider in their long-term strategic and financial plans strategies and changes that will be necessary after the initial contracts to adapt to changing market, supply and regulatory conditions. For example, an under-appreciated need relates to setting a long-run strategy to depreciate and recover project costs. Long-term depreciation policies can dramatically affect a variety of important financial results, such as financial statement profitability, the amount of property taxes that may be paid by the project, the timing of cash flows, and in sum project returns.
NOTES
[ii] The potential market power of owners of gas pipeline and storage projects has historically been restrained through cost-based pricing requirements implemented through the regulations pertinent to rate cases and other NGA Section 4 rate filings. Other constraints have occurred at the certification stage, such as through regulation of initial rates, implementing procedures for processing complaints, evaluating the impacts of projects on competitors and other stakeholders and through optional certificate rules. In recent years the methods used by FERC to review potential market power and to prevent its perceived ill effects have been refined through new policy statements, orders and regulations, such as Orders 436 and 500, et. al. Additional legislation, such as the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005, resulted in further extensions and elaboration of such energy policies.
[iii] Direct development of market-based rates for certain projects in competitive markets, such as for storage projects or in specific competitive gas transmission markets, is beyond the scope of this discussion. This article also does not discuss regulatory techniques used in other industries, such as price indexing employed for oil pipelines, because such approaches have not yet been applied by FERC to gas pipelines.
[iv] See 74 FERC ¶ 61,076 (1996).
[v] SFV prices mean charging fixed daily or monthly prices that include all pipeline costs, except costs that vary with throughput. Variable costs under this method are billed as gas volumes move through the pipeline system.
[vi] Rate levelization plans are intended to produce rates that remain stable throughout the terms of shipper contracts through some form of cost averaging. For example, a level rate may be calculated by changing the
timing of recovery of returns on investment or by modifying the timing of recovery of depreciation. Rate levelization plans are generally developed with the intent that the net present value of each particular project is the same as under the Traditional Rate Method, discussed below. The FERC has not defined a required levelization program in those instances where level rates are developed. Rate levelization plans that include straight-line depreciation may produce poor earnings in some years as a function of the way levelized prices are computed.
[vii] Under the Traditional Rate Method, prices, or rates, are calculated based on a declining rate base over the pipeline’s life and assuming the straight-line depreciation method. Assuming the absence of significant ongoing capital expenditures, rates under this method will tend to be the highest at the inception of service and will decline steadily thereafter.
[viii] To ensure that the recourse rate is not unduly restrictive, pipelines in certificate proceedings typically seek to calculate recourse rates under return and depreciation assumptions that make the negotiated price more attractive than the recourse rate.
[ix] Under the former pricing policy, the Commission applied a presumption in favor of rolled-in rates (rolling-in the expansion costs with pre-existing facilities’ costs) when the cost impact of the new facilities would result in a rate impact on existing customers of not more than five percent, and some system benefits would occur. In those instances, existing customers generally would bear these rate increases without being allowed to adjust their contract volumes.
[x] Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement) at 88 FERC ¶ 61,277.
[xi] Such a switch has been advocated by FERC Staff in a number of gas pipeline rate proceedings, creating very difficult issues for some of the parties.
Do You Understand the Concepts Behind Depreciation?
Accountants and those who have taken accounting courses ususally understand the basics of depreciation. The basic concept is one of allocating the cost of long-lived depreciable assets (original cost, less net salvage value) through recording depreciation expenses in the periods of time that are benefitted by the costs of property, plant and equipment. Many people have heard of depreciation methods like the straight-line method, sum-of-years digits method, and the declining balance methods. Still a large group, but probably fewer people, know about tax depreciation methods that are specified in our tax laws, such as the Section 179 deduction, 50% bonus depreciation, and a variety of other accelerated and straight-line methods.
Depreciation – An Art (or Science) More Refined for Capital Intensive Industries
The Society of Depreciation Professionals is a major professional organization that fosters the teaching of the concepts of depreciation for capital intensive industries and the licensing of experts in the field of depreciation. People people who pass its rigorous professional licensing test are known as Certified Depreciation Professionals.
The reason that special expertise is required for depreciation professionals reflects the nature of the forces that cause retirements of long-lived depreciable assets as described by studies performed beginning in the 1920s and 1930s at Iowa State College. The result of these studies was a system of 22 “Iowa Curves” (statistical models) that describe the percent of depreciable assets surviviving at any point in time during the assets’ service lives and the probable average service lives of depreciable property. The Curves are classified into four groups (L, S, R and O curves) by three variables: the average life of the property, the location of the mode of the retirements, and the variation in the life of the retirements. (See the book, Depreciation Systems, by Wolf and Fitch published by Iowa State University Press, 1994.) These generalized curves, with the use of appropriate software and judgment, are used today by depreciation professionals serving the utility and other capital intensive industries as an aid to developing appropriate depreciation rates. Many factors enter into establishing appropriate depreciation rates such as the forces behind retirements (wear and tear, economic obsolescense, technological obsolescense, actions of governments, management actions, acts of God, etc.), the net cost of interim retirements of property (cost of removal and salvage value), and depreciation expenses already recorded. Basically, the curves are used to estimate the depreciable costs as they change over time that the depreciation rates will be applied against.
Why Are Depreciation Studies Important?
Depreciation studies are required to establish appropriate depreciation rates under public utility regulation, such as by the Federal Energy Regulatory Commission (“FERC”)and state regulatory commissions. In addition, depreciation rates affect income taxes, property taxes and the recorded net book value, or shareholders’ equity, of each capital intensive company. Certainly, prudent managements are interested in the probable lives of their productive assets. The answer to the probable life question is critical to capital budgeting decisions. The rapidity of change in our economy today makes periodic depreciation studies especially critical, since poor depreciation forecasts cost real money through the potential for overpayment of taxes and the possibility of underrecovery of the cost of service of regulated enterprises. The public at large also has a vested interested in these depreciation studies because they are a key element underlying the prices everyone pays for public utiltiy services.
Forecasting the Cost of Terminal Retirement
You may have heard the terminology “net negative salvage” or “asset retirement obligation”. Depreciation studies are not complete unless they provide for the allocation of costs related to the final retirement of long-lived facilities to the periods of time benefitted by the facilities. A major difficulty with this topic is the complexity of forecasting a future retirement cost and allocating that cost to current accounting periods. The Financial Accounting Standards Board and the FERC have both recognized the importance of dealing with these costs. A partial discussion of this topic is available at the www.bwmq.com web site in an asset retirement obligation article.
The energy industry includes companies that invest in extremely capital intensive and technologically sophisticated energy projects. These projects develop, transport, process, market, refine and/or deliver natural gas, electricity and petroleum products to the consumer.
To promote national energy independence, environmental responsibility and market forces (or proxies for market forces) within in the industry, Federal and state governments regulate portions of the industry. They provide economic incentives, such as accelerated income tax depreciation methods and various tax credits to businesses and consumers. The Federal government, through the Federal Energy Regulatory Commission (“FERC”), regulates oil pipelines, natural gas pipelines and the interstate transmission of electricity. In many instances Federal authority must be sought prior to building energy infrastructure or abandoning service, or to receive approval for operating terms and conditions. The FERC regulates accounting and the prices (i.e., rates) for the services falling within its jurisdiction. In some contexts prices are established through cost-based rate principles determined in rate cases while in other instances regulated ceiling prices are adjusted through price indices, price discounts or negotiated prices.
Some of the businesses within the energy industry are not price regulated. Examples include petroleum production, natural gas production and energy commodity marketing. Prior commodity price regulation (such as for natural gas commodities) was removed in the 1970s through 1990s through initiatives referred to in the industry as deregulation or “unbundling”. In truth, these changes established new forms of regulation in an attempt to better simulate the benefits of an effective market while constraining perceived monopoly power of transporters. In this process, transportation services were unbundled from sales services. Now large end-use energy customers may purchase energy commodities directly from producers, rather than buying the commodities from the company that transported the commodity to the market.
Natural gas and electricity distribution services are generally regulated at the state level. Such services are provided by a utility that has a monopoly in its state-approved franchise service territory. State regulation often parallels Federal rules, though the mechanics of regulation varies. State-regulated energy utilities are heavily regulated regarding service expansion and termination, rate regulation, energy development plans, conservation programs and other matters.
To prepare financial models of development or expansion projects within the energy industry, care must be taken to include, where applicable, the potential impact of price-regulation on projected revenues, as well as the projected impacts of competitive forces. Energy commodity prices are extremely volatile. Such commodities are traded through well developed markets, such as the NYMEX futures market and at natural gas trading hubs. Therefore, where applicable, the industry employs financial hedges as a means of controlling risk. Asset values for existing and planned projects are affected by energy commodity price changes and economic conditions generally. Scarce and depleting energy resource values reflect petroleum engineers’ reserve estimates and the changing costs of development, transportation and production. Electricity prices reflect a host of complex factors such as consumer demand changes, the ability or inability to wheel (transport) electricity between regional markets, the reliability of facilities and natural forces, such as storm activity.
The cost of operating an energy project reflects the cost of the installed facilities, their (typically long-term) depreciation schedules (both tax and book), costs of operation and the weighted average cost of capital employed. The industry employs a variety of financing techniques, and a sound financial structure is extremely important to project success due to the capital intensive nature of the industry. Controlling risk is extremely important to the industry due to the many years that elapse between the installation of facilities and the recovery of all costs related to those facilities.
The energy industry includes companies that are price regulated using cost of service principles. One of the most important cost elements is the cost of common equity. In a landmark Supreme Court case decided many years ago, referred to commonly as the Hope case, the Supreme Court decided that regulated utilities must be compensated for the cost of capital used to finance operations, including the costs of capital associated with equity-financed investments.
Regulatory agencies over time have used four principal techniques to estimate the cost of common equity, including 1) the capital asset pricing model (CAPM) method, 2) a risk premium method wherein an equity risk premium is added to the current market cost of utility debt, 3) a comparable earnings approach that estimates the equity return of the utility on returns associated with alternative investments, and 4) the DCF method. Estimating the cost of common equity is almost always contentious in rate case litigation and an army of experts specializes in testifying on this issue.
The most commonly accepted method today is the DCF method. The form of this model most commonly employed in regulatory proceedings is as follow:
K=D/P + G, where
K = the cost of equity capital
D = the expected current future annual amount of dividends per share (look at the recent quarterly dividend history and increase the last annual dividend total if the company has a trend of increasing its dividends)
G = the expected dividend per share growth rate (%), commonly estimated using expected earnings per share growth rates based on analyst consensus estimates (see www.finance.yahoo.com for such estimates)
P = the current stock price (usually averaged over a recent historical period, such as the last quarter or six months)
Typically, the cost of common equity for a particular utility is not based on its own cost factors, but is based on the mean or median of a group of at least 4 proxy companies that are similar to the utility. Determining the appropriate proxy group for the utility is often a contentious issue, particularly since there are not many “pure” utility holding companies whose stock trades on the public securities markets. So instead, analysts choose companies whose portfolio includes a substantial portion of investments that are similar to the utility 1/.
The value for G is often contentious since regulators may view analysts’ high projected growth rates with suspicion, tending to believe that a company’s earnings will not grow faster than the general economy over the long-run. So in some jurisdictions, such as the Federal Energy Regulatory Commission, a weighted average growth rate is used. This includes the consensus short-term growth rate and a long-term growth rate, such as growth in GDP (gross domestic product) as estimated by private sources and the Social Security Administration.
The assumptions underlying the DCF model include the following items:
• Investors evaluate common stocks in a valuation framework and trade rationally.
• Investors discount expected cash flows at the same discount rate in every future period.
• Dividends alone (rather than earnings) are the source of common stock value
• The stock for which the DCF model is employed must not be a “growth” stock because K must exceed G.
• The dividend growth rate is constant in every future year and investors require the same future return in each future year.
• All financing of the enterprise is expected to be from the retention of earnings.
_________
1/ For an example of the importance of determining an appropriate proxy group, see the discussion by the Federal Energy Regulatory Commission in Opinion 396-B (Kern River Gas Transmission Company).
Rate Base, Cost of Service and Revenue Determination
The energy industry includes companies that are price regulated using cost of service principles. For those companies one of the most important cost elements is the cost of common equity. Cost of service, or the revenue requirement of the utility, includes the following items:
• Operating Expenses
o Operations and Maintenance Expenses
o Administrative and General Expense
• Taxes, Other than Income (Property Tax, Franchise Taxes, Payroll Taxes)
• Income Taxes
• Return on Rate Base (Weighted Average Cost of Capital Times Rate Base)
• Other Operating Expenses (Such as Regulatory Debits and Credits)
• Depreciation and Amortization Expense
• Less- Incidental Revenues (i.e. rents of utility property)
To calculate the return on rate base, it is necessary to first calculate rate base. This item represents the net current investment in utility facilities that has been financed by investors. Rate base includes:
• Gross Utility Plant (excluding work in progress)
• Less – Accumulated Depreciation and Amortization
• Less – Accumulated Deferred Income Taxes
• Plus –
o Prepayments (such as prepaid insurance)
o Materials and Supplies Inventories
The weighted average cost of capital includes: (1) the sum of the cost of debt multiplied by the percentage of the total capital structure that is financed by debt, and (2) the cost of each source of equity financing multiplied by the percentage of the total capital structure that is financed by each equity source. Once the weighted cost of each financing source is calculated, the costs of all the financing sources are summed to derive the total weighted average cost of capital.
The calculation of the income tax allowance for cost of service deserves some further explanation. To calculate this amount, it is necessary to calculate the projected return on equity dollars by multiplying rate base times the weighted average return on equity as explained in the preceding paragraph. To derive the income tax allowance, first divide the amount of the return on equity dollars by 1 less the company’s composite federal and state income tax rate. This will result in the amount of state taxable income. Then multiply the state taxable income by the state income tax rate to derive the state income tax amount. Then subtract the state income tax from the state taxable income to derive the Federal taxable income. Then multiply Federal taxable income times the Federal income tax rate to derive the Federal income tax. Then you can sum the state and Federal amounts to derive the total Federal and state income tax allowance. Attached is an example of these calculations, assuming the state tax rate is 5% and the Federal rate is 35% for a composite or total income tax rate of 38.25%. Rate base is assumed to be $1,000.000, and the weighted return on equity rate is assumed to be 6%, assuming rate base is 50% financed by equity and the return on equity cost rate is 12%.
See “Income Tax Allowance Example Computation” for an example.
The American Institute of CPAs created the CFF credential in 2008 to recognize the professional skill, training and experience of individuals who specialize in financial forensics services. Bruce E. Warner, CPA, became certified in financial forensics in 2008 and provides several CFF services to the energy industry. Bruce practices in the areas of bankruptcy and insolvency, economic damages, litigation support and stakeholder disputes.