A Risky Business Utilities wrestle with how much to charge for their product.
The trading model has many good points, including the imposition of market discipline upon both transfer prices and prices to external third parties. Trading also encourages the use of resources and capital at their market value and the cultivation of specialized skills within different business units. But applying the model, particularly to the risks of power pricing, continues to be a challenge.
In fact, the challenge of how pricing is applied may be the difference between success and a long-term strategic decline. Competing against a firm using a return-to-asset model (e.g., one which transfers or internally prices to downstream activities to meet the financial objectives of upstream assets), may place an entity using a trading model at a decided disadvantage if risk valuation is implemented incorrectly. While the return-to-asset player, through internal transfer prices, may engage in predatory pricing in the most competitive portion of the market, the entity using the trading model but implementing risk valuation incorrectly will be at a strong disadvantage. What's wrong? If the trading entity, instead of using pricing based upon the marginal cost of risk to the enterprise, uses a purely theoretical price, it will be unlikely to be competitive with the return-to-asset player.1 The marginal costs of taking risks should be quantified dynamically using appropriate enterprise-wide methods. Critically, risk taking has a cost, but unless a firm can bear such costs at the margin for less than a purely abstract theoretical cost, it will not create value for shareholders.2 Accepting greater risk for greater reward is at best value-neutral, and may even be value-destroying as it distracts from other more beneficial efforts. Conversely, ignoring the marginal cost of risk taking can be perilous.
At one time, risks inherent to the production and marketing of gas and power were subsumed in larger cost structures or paid for through surplus capacity and sub-optimal operation. No longer. In the last 10 years many unregulated and regulated utilities have adopted the so-called trading model to better deal with shortages and surpluses in their supply mix. The trading model places trading at the center of a vertically integrated firm comprising generation and asset management all the way through to distribution and sales.
Although it is accepted that arm's-length transfer pricing (that is, internally pricing at market valuations) in energy trading helps ensure that resources are optimally used and that returns to various activities are not artificially subsidized, critical issues remain regarding how such market transfer pricing is obtained.
In this regard, the ascendancy of certain disciplines has led to the oversight of larger and more basic issues on how businesses should set prices in often imperfectly competitive markets. Knowing the purely theoretical price of a complex, non-linear energy market exposure is critical. But it defies business logic to use such prices unadjusted for what the actual and empirical cost of risk taking is at the margin for a given energy utility. Only through empirical analysis, using a risk-metric simulation, can energy utilities discover what the additional costs of risk-taking are for an enterprise.
Moreover, the emergence of traded gas and power markets with sophisticated practitioners using advanced financial and statistical techniques for valuing, parcelling, and transferring risk appears to have ignored the basic requirements for profit maximization in competitive markets-pricing at marginal cost. Advanced techniques to recognize and quantify optionality in the modern and flexible operation of power generation are critical to success in deregulated and competitively traded markets, but their use unadjusted for what is the actual marginal cost of exposure is incorrect.
A Fine Line Between Pricing and Risk
Reviewing the literature, one searches in vain to find out how pricing in a purely theoretical framework, both internally and to third parties, should be related to the cost structure and comparative advantages of an individual firm.3 Yet how one implements a transfer-pricing scheme might have a big impact upon the success of a particular business model.4 It may be as important as how derivatives are valued and the statistical methods utilized.
Perhaps the absence of attention to how one implements a transfer-pricing scheme involving derivatives, and how it should relate to company-specific factors (e.g., cost structures) arose because advances in financial-risk management have narrowed into a specialized field, emphasizing advanced mathematics and statistics. The relevance of company-specific factors has been ignored in favor of the weighty challenge of spanning state-spaces (that is, pricing non-traded or illiquid contingent assets or liabilities).5 In creating such state-spanning prices (e.g., half-hourly options on power, or daily options on gas), differences over results, typically are attributed to market inefficiency or doctrinal views on methods.6 Company-specific differences, such as customer-base diversification, technology, and cost structures usually are not considered as sources of risk-pricing differences. How surprising, since company-specific differences do not imply inefficient financial-commodity markets.7 Moreover, informational efficiency does not imply long-run perfectly competitive markets for goods and services, which by implication would mean that all participants produce at the same marginal cost, albeit with different levels of risk-taking services.
Markets may be efficient and prices may convey all relevant information regarding such risk-taking services, but participants may be very different, reflecting company-specific abilities to carry such risks. Turning this point on its head, the absence of perfect competition in product/service markets implies that significant differences in the costs of risk-bearing may exist.8 Often, it seems, such differences in cost structure are perceived erroneously as a form of market inefficiency. It may simply imply that markets for non-traded energy risk are not in long-run equilibrium, not perfectly competitive, or that firms in such markets produce at different cost structures. Thus, in the presumption that the price for accepting risk should be the same for all market participants, allowing for conceptual differences has no merit.9 Introducing non-risk neutrality into pricing does not address underlying assets, technology, or cost structure, and their effect on pricing risk in gas or power markets.10
Evaluating the costs of risk on a purely theoretic stand-alone basis, and ignoring potential savings that may arise from one's assets and other activities, resembles a full absorption-cost approach to pricing. This is because rather than purely variable and additional cost of risk taking being utilized, a full theoretic cost is used, as though the entire enterprise were created for this one exposure/deal. Unlike an asset-based business model that may price in a predatory manner, even below marginal cost in the most competitive portion of the market, when the trading model is wrongly applied it results in full-cost pricing of price and market risk on a theoretic stand-alone basis for a specific deal. In contrast to the marginal-cost method of pricing, widely accepted as economically optimal and the preferred transfer-pricing scheme, a full-cost approach to pricing burdens an enterprise with historic assets and cost structures.11 Full theoretic cost pricing of price and market risk might have some merit if a power company's entire portfolio represented a handful of very large customers, or there were little or no flexible generation to back the marketing or trading activities. However, pricing risk on a full-cost basis defies economic rationality once a risk-spreading base of customers has been created, destroying the many benefits of the commodity-trading model.
To realize the potential of the commodity-trading model, price and market risk must be priced at the marginal cost to a specific enterprise. The absence of long-run competitive equilibrium implies that the costs of bearing such risks are unlikely to be equal for all enterprises. We examine two common examples of pricing risk-load-shaping premium, as well as volume balancing and flexibility-to take advantage of company-specific marginal cost differences.12
Looking at load shaping, typically half-hourly prices are priced using option theory. (As high-frequency volatility may be very high relative to day-ahead volatility, such exercises often lead to debates over accuracy and the extent to which non-replicable full-value should be attributed.) Although the use of option theory is correct in the abstract, different customer load profiles, when aggregated, may resemble a baseload or standard-load profile. Although it is critical to price in theory the risk-neutral cost of taking risk on a certain profile, for a large energy utility with a diversified customer base, this does not represent the marginal and forward-looking cost of supplying the additional megawatt-hours. Unless a potential customer is so large that it will systemically alter a utility's embedded cost structure, a marginal cost of serving a particular shape should be used to attract new customers and keep existing ones. Charging for shape may be a valuable source of additional income for utilities with flexible generating capacity, but new business only can be gained and existing ones retained by recognizing the marginal cost of serving the marginal customer.
Balancing and flexibility, important components in the sale of energy, occur because of changes in ambient temperature, cloud-cover, capacity utilization, or other factors. Such volumetric risk also may be highly correlated with prices, thus creating further exposures. As such, balancing and flexibility represent a form of optionality that energy purchasers possess, allowing them to call more than expected or put back less than expected gas and power, depending on the factors mentioned. Useful debate may arise concerning the extent to which such optionality is utilized economically, which again will affect the marginal cost of taking risk. In this light, understanding the costs involved in providing flexibility and balancing is very important, but the lessons learned regarding the marginal costs of serving customers remain.
Pricing the optionality in balancing and flexibility-that is, the right to vary around forecasted quantity, as though every deal were on a standalone basis and as though every customer were going to use their options economically-defies business rationality. Although it is an empirical matter for investigation, customers who are balancing-down (taking less) offset customers balancing up (taking more). Moreover, with sufficient customers across different end-user-categories and different geographic locations, a quantifiable portfolio diversification effect may arise, further reducing the actual cost of bearing such risk. It is difficult to justify attempting to charge a 10 percent balancing cost using option theory and losing the deal, when the actual marginal cost of risk taking, given off-setting take and load factors, may be 2 percent.
The commodity-trading model has many good points, but the challenge lies in how it is applied. Even without movements in forward curves and volatility, changes in the marginal cost of risk-taking will arise. Deals may offset existing positions and therefore reduce risk. When available, savings in the opportunity cost of risk capital should be included, to the extent required, in the marginal cost of pricing gas and power risk to third parties. Such exercises, however, require real-time, dynamic simulation. Such efforts could lead to certain segmentation criteria, wherein deals and exposures below a certain size are inconsequential.
- Thomas, S., "The Seven Brothers," Energy Policy, 31 (2003) p. 397.
- Stulz, R.M., "Rethinking Risk Management", The Revolution in Corporate Finance, edited by Stern, J.M. and D.H. Chew, Jr., Oxford: Blackwell Publishing, 2003, pp. 367-384.
- Some recent interest in this topic includes: Essaye, T. & B. Humphreys, "Portfolio Optimisation," , Vol. 8/No.1, April 2003; and Fronmuller, M. and D. Cobb, "Playing the Asset Optimisation Game," Platts Energy Business and Technology, October 2002, pp. 32-33.
- Eeckhoudt, L. and C. Gollier, , London, Harvester Wheatsheaf, 1995. pp. 153-182.
- Copeland, T.E. and J. Fred Weston, , Third Edition, New York: Adison-Wesley Publishing, p. 125.
- Capital market efficiency should not be confused with the concept of perfect capital markets, as described in the text. Capital market efficiency describes a situation when prices fully and instantaneously reflect all available relevant information. (See, Fama, E.F. "Efficient Capital Markets: A Review of Theory and Empirical Work," , May, 1970, pp. 383-417.)
- , p. 331.
- Brealey, R.A. and S.C. Meyers, , London, McGraw Hill, 2000, pp. 353-354.
- A weak defense for ignoring company-specific differences might be motivated using portfolio theory: Company-specific differences, idiosyncratic risk, may be diversified away, and hence only systematic or market risk is reflected in the prices of securities and commodities. The number of gas and power players may be insufficient to construct a diversified portfolio. Second, creating a diversified portfolio against company-specific differences, such as the cost-of-risk bearing, does not imply immunization from differences in pricing of risk. Company-specific differences with respect to efficiency in risk bearing of non-traded risk are difficult to diversify away.
- Haar, L. "Fallacies in the Stakeholding Debate," , Vol. 19, No.4, December 1999, pp. 44-48. Reference to an explanation of Fisher's Separation Theorem, which is how profit maximization at the firm level may be separated from the individual preferences of shareholders with regard to risk aversion. See Fisher, I. (1930), , New York, MacMillan, chapters 10 and 11.
- Drury, C. Costing: An Introduction, Third Edition, London: Chapman & Hall, 1995. pp. 195 - 212.
- Other examples include the company specific commodity price, given the load-shape/volume versus that of published indices, and the internal pricing for the use of risk capital.
Marginal-Cost Pricing Around the Globe
It is quite surprising that the case for marginal-cost pricing needs to be revisited. Notions such as embedded cost, a full- or absorption-cost/full-cost approach to pricing, practiced in the United States under rate of return regulation, were largely abandoned during the 1970s in favour of marginal-cost pricing.1 The application of marginal cost methods to rate making gained ground because these were viewed as encouraging more efficient use of resources, especially given historical returns on fixed asset regulation.2 In England and France, under state ownership, experiments with marginal-cost pricing were made as early as the 1950s. The UK pool system, adopted in the late 1980s revolved around the use of short-run marginal cost for dispatching the plants in their merit order, combined with a problematic use of capacity payments.3 -L.H.
- Viscusi, W.K., J.M. Vernon, and J.E. Harrington, Jr. , London, MIT Press, 2000, pp. 361-388.
- Pacific Gas and Electric Co., , 2nd Edition, San Francisco: PG&E, 1992, pp. 275-276.
- Helm, D. , Oxford, Oxford University Press, 2003, pp.125-151.
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