Fortnightly
Trading on the Index: Spot Markets and Price Spreads in the Western Interconnection
October 01, 1996By Robert McCullough
Using cash and futures markets, traders can tie contracts to a price index.
But which one?
And how to adjust for different delivery points?
FOR THE PAST 20 YEARS, THE WESTERN
Systems Coordinating Council (WSCC) has built a reputation for innovation in electric markets. Today, with members in the United States, Canada, and Mexico that serve customers from the Pacific Ocean to the Plains states, and with over 140,000 megawatts (Mw) of generation and transmission stretched across three countries, the WSCC continues to lead change in power markets.
Transparent pricing has become a reality throughout the region.
Last year the Pacific Northwest subregion of the WSSC counted eight large (50 megawatts or more) industrial contracts with spot pricing. Puget Sound Power and Light recently proposed to shift all of its major customers to spot pricing when its current merger proceeding closes. The New York Mercantile Exchange (NYMEX) offers futures trading at Palo Verde and the California/Oregon border (COB). Alberta's new power pool adds a third market-price indicator. Soon we may see spot pricing for bulk power throughout the Western Power Exchange (WEPEX). This growing emphasis on spot pricing turns attention to pricing mechanics.
In one sense, spot pricing is nothing new. Commodity contracts have often included a spot-pricing component. For example, many utility contracts employed stack-pricing components during the 1980s. "Stack pricing" (also known as system lambda or real-time pricing) became more common during the 1980s. But many stack-pricing contracts proved difficult to administer. Sharp turns in the market often required an audit of the mathematics of the stack-pricing calculations \(em an unpleasant task for both seller and buyer.
What's new, however, is the reliance on external indices. In markets such as primary metals, chemicals, and fuels, commodities are often priced with reference to an external market or market survey. (Metals Week, for example, is often cited in metals contracts and energy contracts that serve the metals industry.) Electricity will now join the list of markets with contracts pegged to external price indices.
So the real question is not spot pricing, but which index to use.
In electricity, the arrival of NYMEX has encouraged the use of indices based at COB. Nevertheless, for a number of reasons, COB does not make for a very good market for industrial contracts north of California. Other providers have introduced pricing indices \(em some good and some poor. Each offers its own advantages and applications, but questions remain.
How can traders index their purchases to an impartial source of market data? How can they choose among the available indices? What adjustments should they make if a price index is geographically distant or applies to slightly different products than the contract commodity?
Markets, Surveys, and Geography
Indices fall into two major groups: market-based and survey-based. At the moment, power traders in the WSSC can turn to only three market-based indices: the Alberta Power Pool, and NYMEX's COB and Palo Verde indices. Prices at the Alberta Power Pool accurately reflect the entire market in the province; unfortunately, however, Alberta lies at the extreme edge of the WSCC. The NYMEX indices, while good, reflect a very small volume compared to the market as a whole. A single large transaction could dominate the NYMEX futures market for either Palo Verde or COB.
A survey index prepared for the WSSC region could provide an alternative to the three active indices. Many such survey indices appear in industry journals, including Clearing Up/California Energy (News Data Corp.), Megawatt Markets (Pasha Publications), and Power Markets Week (McGraw-Hill). Dow Telerate also offers interesting indices. The most complete set of indices may be obtained from Economic Insight, a firm in Portland, OR. The firm conducts a survey daily and reports on one-day prescheduled power, both on and off peak.
Economic Insight's collection of Internet-based price indices cover five markets (COB, Palo Verde, the Canadian border, Midpoint, and Meade) plus six regions (northern California, southern California, the Pacific Northwest, Mid-Columbia, the central Rocky Mountain states, and the inland Southwest) (see Map opposite).
The region boasts three open markets for electricity \(em Alberta's power pool, NYMEX COB, and NYMEX Palo Verde. The division of the WSCC into markets and regions reflects the gradual evolution of traditional bilateral transactions into organized markets. Although regulators in California may doubt whether such an evolution can occur without their inspired leadership, the natural evolution of open competition tends to create central markets.
The "Mid-Columbia" market offers an interesting example of how markets take shape. Almost all network transactions north of the California border involve network transmission provided by the Bonneville Power Administration (BPA). Although BPA's transmission tariffs vary, most transactions enjoy the benefit of a postage-stamp transmission charge for power movements from Canada in the North to California in the South (access to COB requires an additional postage-stamp rate). Logically, then, the market in the Pacific Northwest should remain the same for any location, as long as each generator has access to BPA's network.
This assumption proves largely correct. A review of specific utility transactions shows a high correlation for the values reported for Mid-Columbia. The importance of the Mid-Columbia index comes from the fact that its market participants in the area \(em largely the owners of the huge Mid-Columbia dams \(em are more accessible than the largest player in the region, BPA.
BPA's slow acceptance of competitive forces has simply moved the market 100 miles to the east. As BPA comes to realize the importance of the marketmaker role, the Dittmer office (BPA's dispatch center in the Portland area) should gradually usurp the relevance of the Mid-Columbia index.
Economic Insight's Canadian index shows up as the weakest among its set of indices, an unfortunate side effect of B.C. Hydro's market actions. Since B.C. Hydro dominates the electric business in British Columbia, pricing tends to be less market-oriented than elsewhere within the WSCC. Published prices from the utility (available through its marketing subsidiary, Powerex) bear little relevance to wider WSCC markets or even, in many cases, to conditions in the Pacific Northwest or Alberta. The logical hypothesis is that B.C. Hydro is attempting to monopolize the power system in its area, obscuring the price signals as part of its strategy. This hypothesis draws reinforcement from the lack of correlation between daily prices at the Alberta Power Pool daily prices and electric prices elsewhere in the WSCC.
Transmission Constraints
and Basis Risk
NYMEX defines "basis risk" as the uncertainty as to whether the differential between the cash and the futures markets will widen or narrow between the time a hedge position is implemented and the time it is liquidated. The predictability and size of the basis depends on three different relationships:
1) The price of the futures contract versus the spot price of the underlying commodity (the "cash/futures basis")
2) The spot price at the futures contract delivery point versus the spot price at a different location (the "locational basis")
3) The spot price at the futures contract delivery point versus the spot price of a similar, but not identical, commodity at the same location (the "product basis").
Recent power negotiations have produced a variety of basis schemes. Some industrial contracts have proposed using natural gas indices at local hubs. A number of these contracts have specified the natural gas price at Sumas, WA. As a general rule, natural gas indices serve as a poor choice for electric contracts. In the WSCC, the correlation between natural gas and electric prices is surprisingly poor. A more natural approach would be to use the market prices at COB, Palo Verde, and Alberta as a benchmark for pricing in bulk-power contracts. But how accurately do these indices predict local prices? What differential should apply when the local power market is distant from the index?
Power transfer capability can illustrate relationships between different market regions. In this case, data from the WSSC (bidirectional, nonsimultaneous, 1995 summer) reveals just how weak the interconnections are between regions (see Chart opposite). This revelation appears at odds with the reputation of the WSCC as one of the world's most tightly integrated power markets. In fact, WSSC's internal interconnections are small when compared with the area's 140,000+ Mw of generation. Transmission capability is routinely saturated on an annual basis \(em so much so that constraints often arise for transmission over the Canadian border, access to the Pacific Northwest intertie, and transmission though Utah.
The most significant transmission constraint that affects the use of a price index in bulk-power contracts may be the seasonal hydro "fish flush" in the Pacific Northwest. Recent environmental rulings have moved more and more generation into spring months. On a planning basis, the oversupply in these months is now sufficient to displace all thermal generation in the Pacific Northwest and to fill transmission lines to California. This effect creates a disparity between prices north of the California border and those in the rest of the WSCC. During some hours in recent years, prices in the Pacific Northwest have fallen to 1.5 mills. Since 1.5 mills just covers transmission costs, the seller in effect pays a commodity price of zero. Prices throughout the remainder of the WSCC tend to reflect natural gas generation costs during the same period.
Using the COB index tends to have two effects: First, COB indexing tends to overstate prices for contracts to the north of the California border. Second, COB indexing gives the wrong price signal for contracts where energy use is highly dependent on price.
Plotting the Differential
Many market participants have a good anecdotal feel for price differentials between WSCC sub-regions, but lack of data up to now has made accurate calculations impossible.
To move from anecdote to evidence, a logical approach would rely on the Alberta, COB, and Palo Verde markets for pricing information, with adjustments to reflect geographic differentials. Economic Insight's data suit this purpose perfectly since they carefully map the whole of the WSCC. This approach also minimizes concerns about the use of survey data versus actual market data, since the fluctuations are taken directly from markets at COB, Palo Verde, or Alberta.
Table 1 estimates the average differentials between different indices throughout the WSCC, based on survey data from a variety of sources.
To read this table, take the index used in the power contract. For example, if the contract used the NYMEX COB index, look down the left column until you find the actual physical location of the transaction. If an industry bought indexed power at Four Corners, the adjustment to the COB index would be -.45 mills, which reflects the generally higher power costs at COB.
Highlighted rows and columns reflect a relatively poor market relationship between that index and the rest of the WSCC. Three locations tend to report a poor correlation with other WSCC prices. The first two \(em the indices for "Canada" (primarily information from B.C. Hydro) and the Alberta power pool \(em reflect the lack of market access in British Columbia. The generally poor results tend to substantiate the impression many market participants have of B.C. Hydro's efforts to monopolize transactions in their province. The other index showing a relatively poor correlation with WSCC markets is NYMEX Palo Verde. Perhaps that fact stems from the recent introduction of the Palo Verde index.
Table 2 shows the correlations
(R squared, or "coefficient of determination") for each of the WSCC indices. The statistical quantity, R², shows the percentage of the total variance explained by a relationship between price indices at the two locations. A perfect explanation posts an R² of 100 percent; a poor explanation shows a low R².
With the exception of the three indices mentioned above, correlations throughout the WSCC remain quite high, reflecting the excellent access to transmission throughout the region and the availability of a number of sophisticated marketmakers. Economic theory predicts a high correlation as brokers purchase from low-cost areas and wheel the power to meet high-cost opportunities. The exception of British Columbia is also consistent with economic theory: B.C. Hydro's market power logically appears as a lower correlation between market forces on the opposite sides of the province.
A More Exacting Approach
The high correlations in the preceding tables allow an exploration of a more sophisticated version of basis adjustment. Over the past several years, for example, prices in the Pacific Northwest have enjoyed a relatively stable relationship to those at COB.
Basis is a relatively simple adjustment, such as: Pacific Northwest = NYMEX COB -.79.
While this adjustment gives a reasonable approximation of prices in the Pacific Northwest, a better model would use linear regression to estimate the relationship. Linear regression has offered a standard tool in utility forecasting and financial managements for many years. Though new to power contracting, linear regression represents a logical step in making price signals to the customer as precise as possible.
The linear regression relationship between NYMEX COB and the Pacific Northwest is: Pacific Northwest=.857 ' NYMEX COB +.837.
This equation provides a more nearly exact approximation of spot prices in the Pacific Northwest, given NYMEX COB prices. The slope (.857) reflects the greater volatility of COB prices as compared to comparable prices in the Pacific Northwest. Simply adjusting the prices on a one-to-one basis tends to overstate the highs and lows in the local geographic market.
The regression approach also accounts for real operating concerns. As mentioned above, the hydroelectric surplus in the Pacific Northwest tends to depress market prices below COB in the spring. A regression arrangement can adjust for this effect by adding an additional term for the months of May and June: Pacific Northwest = 1.237 +.832 ' NYMEX COB -.724 (if May or June).
Is this precision necessary in all cases? The answer depends upon the contract and the objectives of the parties. Most Pacific Northwest parties would like to sell more power during May and June. The approach used in the second regression equation would tend to lower prices in those months and increase sales. This method would prove appropriate in some cases, but not where customers are unlikely to respond to the price signal.
* * *
All in all, the shift to spot pricing appears to be a fait accompli. Adjusting to this shift, however, requires work and some inspiration. It also requires use of the increasing amounts of valuable data being generated on power markets from Canada to Mexico. Luckily, the data and the tools are in hand \(em only the work remains. t
Robert McCullough is the managing partner of McCullough Research, an energy policy and economics consulting firm in Portland, OR. McCullough Research specializes in public policy issues throughout the United States and Canada, primarily regarding the electric power industry. Recently, Mr. McCullough has been representing the Grand Council of the Cree in their negotiations with Hydro-Québec concerning the massive proposed developments on the rivers emptying into James Bay. His firm has also released several RFPs for energy resources and services delivered in the Northwest \(em seeking over 600 Mw in the 1997-2001 timeframe. Mr. McCullough was previously an officer at Portland General Corp., with responsibilities in finance, power marketing, and rate setting.
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