FERC Filings
REQUEST FOR CLARIFICATION OR IN THE ALTERNATIVE REHEARING OF THE ELECTRIC POWER SUPPLY ASSOCIATION AND THE WESTERN POWER TRADING FORUM
ARGUMENTS
1.
Mitigation Measures that Cap Prices Below the True Market Price Will Only Discourage Investment and Delay Development of Competitive Markets
As the Commission has been repeatedly warned, a reliance on mitigation measures that cap prices below the true market price will provide only short-term political relief, rather than meaningful reform, for California’s dysfunctional energy markets. The Commission has previously recognized that the primary problem facing California’s bulk wholesale power market is a fundamental mismatch of supply and demand. Thus, solutions to the problems adopted by the Commission must ensure that additional generation infrastructure development is encouraged by any mitigation plan adopted. A move towards below-market price caps wholly fails to meet that requirement and is in fact at cross-purposes with it.
In addition, the Commission has, perhaps unwittingly, created significant problems and concerns in its drive to find a politically acceptable solution to California’s energy crisis. First, the Commission’s rules have become a moving target. Each mitigation Order includes a different methodology and different
inputs for determination of the proxy price. Each has spawned a series of clarifications and explanations sought by the CAISO and market participants. Second, the clearly complex proxy price approach set out in the April 26th and June 19th Orders have engendered uncertainty and confusion, undermining market confidence that will, in turn, discourage much-needed investment in California.
For competitive markets to flourish, supply and demand must interact freely to determine the price, thereby allowing market participants to make intelligent resource allocation decisions. This result cannot be replicated by the regulatory efforts to “mimic” the outcomes of a robust market, particularly during periods of scarcity. The best defense against price spikes is to encourage greater numbers of suppliers to enter the market, not to restrict existing suppliers to artificially determined rates.
Further, price caps will lead to a sub-optimal mix of generating units, favoring base-load plants when peaking units may be needed. Peaking plants must recover their entire operating cost in a limited number of days, or even hours. Competitive power suppliers bear all the risks associated with these plants and must have confidence that market-clearing prices will reach the levels necessary to ensure a return on their investment.
Finally, below-market price caps will discourage demand-side management by dampening price signals and discouraging the development of
much-needed risk management tools.
The financial community is beginning to recognize the problem as well. A June 27th Merrill Lynch Energy Merchants briefing paper included the following:
It is vitally important for policymakers to sit up and take sobering notice of the California Crisis, and the resultant impacts that have occurred, not only on California’ own pocketbook, but on the $52+ billion in REAL equity value (just for these four companies [Dynegy, El Paso, Enron and Williams] alone) which has evaporated since the beginning of the year. Many politicians and policymakers appear to be overwhelmingly ignoring shareholders in the quest to protect/insulate consumers from market realities; the result of dis-incentivizing investment is already taking solid shape as uneasy energy shareholders speak with their feet.
Similarly, the Williams Capital Group, LP has issued a recent report stating that:
I/n our view, investors have lost faith in the U.S. power supply/demand outlook for the next several years – viewing the potential to over build capacity as a major risk to power profitability earnings and fearing re-regulation or electricity and/or natural gas price controls will cap profits and restrict earnings growth rates.
Discussing California, the Group’s Report goes on:
The market [in California] has sent the private sector the signal that new capacity is needed. While generators have responded to the signal, regulatory meddling may disincentivize the private sector and obstruct the addition of new generating capacity. . . . The politics of fear have entered the market and generators have responded by withdrawing new supply plans. If regulators hope to encourage new supply, we believe they will respond by solidifying the generators’ expectations of regulation and free market prices. New generating capacity will be installed by private enterprise if and only if the risk of investing hundreds or millions of dollars per project is secured by expectations of financing (reasonable stock market valuations), reasonable returns, and regulatory stability.
A June 25th Credit Suisse First Boston Report raised similar concerns, recognizing the “angst of investors in terms of dealing with the potential of a new era of regulation in the natural gas and power industry. With trust, credibility and visibility critical investment factors, it is our opinion that the new administration, the new FERC and California politicians have fomented an environment of mistrust.” The Report goes on: “Lesser ability to raise the necessary capital
to build new energy assets in the Western U.S. and elsewhere is an obvious consequence of the politically motivated FERC actions.” (emphasis added.)
Companies that have invested in California and the west will have to pay attention to the message their equity investors are sending regarding the political and regulatory risk of continued investment in the western market. Investors may no longer be willing to risk investing in companies that are making infrastructure investment in California and the west.
2.
The June 19th Proxy Price Methodology Will Understate the Market Clearing Price for Power
The Commission needs to recognize that the process set out in the June 19th Order for determining a proxy marginal cost will significantly understate the true market-clearing price for power. First of all, the proxy price understates gas costs by directing the CAISO to average the mid-point of the monthly bid-week prices reported for three spot market prices for California. While the Order asserts that generators can pre-buy their monthly gas requirements for this price, that assertion belies the fact that generators rely on spot gas purchases to generate power for spot electricity sales. The Commission’s mitigation measures, by their very definition, apply only to spot market electricity sales. While generators prudently buy forward gas to support their forward power sales, it would be fiscally irresponsible to purchase forward gas contracts for power sales that may or may not materialize. Daily prices can be above or below the monthly price, but it is likely that at time of reserve deficiencies the daily price will reflect a higher demand for natural gas. In addition, the stated proxy price methodology fails to account for the in-state costs of natural gas transportation. Therefore, the Commission should allow each generator to identify its point(s) of receipt and to specify local transport costs. As noted below, the Commission should ensure that the market clearing price reflects accurate gas costs.
Second, by requiring that fuel costs be averaged, rather than differentiated based on geographic region, the Order ignores the significant fact that gas is purchased at different locations in California depending on the location of the generation unit. For units located in southern California, the methodology should use a gas price for gas delivered in the southern portion of the state, which reflects the cost of gas for generating units in southern California. For generating
units located in northern California, the methodology should use a PG&E Citygate price, which is where gas is actually purchased for units in the northern part of the state – not at Malin. Rather than averaging costs over the entire state, the Commission should employ a methodology that reflects the true cost of gas for generating units, including, where applicable, imbalance charges. The Order also suggests that a party can, in the alternative, use the average cost in its entire portfolio and apply it to its marginal unit. This approach is impractical, since the generator cannot hedge gas costs for a marginal unit without knowing whether or not it will run!
Third, the Commission’s methodology will often exclude the highest
costs actually paid for power. By establishing the proxy price as the “market-clearing price,” but allowing bids that exceed that cost to be accepted and then
justified, the market-clearing price fails to accurately reflect the cost of power. This, in turn, dampens price signals and results in higher demand and less supply.
In the April 26th and June 19th Orders, the Commission posits that generators and marketers will earn capital recovery on bilateral contracts entered into in advance of spot markets or with energy that can be generated or procured for less than the administratively determined market clearing price. This fails to account for the basic economic fact that incremental supply will not earn a return on the margin and will thus have no incentive to remain in the WSCC market. Even in the textbook world of perfect competition, market prices must rise to a level sufficient to cover total costs, including a return on capital. The Commission’s proxy marginal cost method is unlikely to allow market-clearing prices to rise to this level. As noted above, the proxy market-clearing price is not a true market-clearing price because it artificially excludes the highest cost bids.
Further, it fails to include any marginal capacity costs in its measure of short-run marginal costs. The practical implication of this is that bidders will have to actively bid in a way to assure full cost recovery, which means bidding higher in high demand periods. For inframarginal units (those with short-run marginal costs below the Commission’s proxy price) some of these costs may be recovered even with the Commission’s proxy price methodology. But, because a true market-clearing price will not be used, full cost recovery will not be permitted for other units.
3.
The Order Disregards the Benefits Power Marketers Provide
By requiring power marketers to be price takers, the June 19th Order wholly disregards the benefits power marketers bring to the market as a whole. FERC should reconsider the price mitigation plan’s exclusion of marketers from selling above the mitigated price. Making marketers price-takers limits their valuable contribution as buyers and sellers in a competitive market. This aspect of the plan takes a key market participant out of the market at critical times and has the underlying affect of encouraging marketers to seek volume and liquidity, in both spot and longer-term markets outside of the west to manage their portfolio risk.
Marketers play a valuable role in competitive wholesale power markets by providing both products and services that improve reliability and performance while reducing risk in competitive markets. Marketers’ products are transaction based and often guarantee product quality; their services establish performance standards and price stability. These products and services are essential in a fully competitive market, since they furnish customers with an intermediary that can supply the appropriate products and services that fit with that customer’s needs and risk tolerances. The contribution of these products and services to the market is the cornerstone of market liquidity, a necessity in a fully competitive market.
A key product a marketer can provide clients is price risk management that is based on the marketer having a portfolio with diverse regional transaction volumes. This product allows the marketer to leverage its portfolio against regional (basis) risk for its customers. Consequently, marketers -- unhampered by physical limitations -- can potentially move power, for example, from the northwest to the southwest. Region specific generators without the benefit of a marketer’s multi-region portfolio typically will see moving power that same distance within the west as financially prohibitive, while a marketer can see the transaction as one that is financially advantageous in the context of its portfolio.
The recent blackout situation in Nevada demonstrated why it is valuable that marketers have full market flexibility. On Monday, June 25th and Tuesday June 26th, the CAISO declared Stage 1 and 2 emergencies. The Commission’s June 19th Order mitigation plan limited prices as supplies became scarce. It became financially infeasible for marketers to commit to transactions with transmission costs that the marketer could not recover in its sales price. Marketers’ participation in the Nevada market lessened and liquidity dwindled, leaving local utilities with no other choice but rolling blackouts. Without the right price signals marketers have little incentive to leverage their portfolios under the market mitigation plan.
Limiting marketers’ flexibility in the competitive wholesale market can eventually limit competition in the retail market. As market intermediaries, marketers have an interest in being both a buyer and a seller since, strategically, marketers are typically interested in the full range of marketplace transactions to balance out their portfolios. Driving marketers from the western wholesale electricity market has the potential to eliminate them as counter parties to this range of transactions and therefore reduce reliability and limit liquidity in a market that desperately needs it.
For the Commission to achieve its goal of robust, workable and fully competitive markets, it must adopt rules that encourage market entry, improve liquidity and enhance risk management. Forcing power marketers to be price takers achieves none of those goals. It is simply bad policy for the Commission to adopt market rules that reduce the number of market participants, limit liquidity and minimize the availability of risk management options. The Commission should reconsider its position on this issue.
4.
The CAISO’s Ability to Manipulate the Price Cap Must Be Minimized
In order for markets to work, market participants must be confident that pricing mechanisms are calculated accurately and implemented fairly. The Commission’s rules and directives in this very sensitive area must be administered with impartiality and without political influence. Unfortunately, the CAISO has demonstrated the ability to manipulate the Commission’s price caps in an apparent effort to achieve the political goals of the State of California. EPSA and WPTF have repeatedly indicated that the governance of CAISO is flawed and that it is unduly subject to the influence of the State of California, particularly given the fact that the California Department of Water Resources has become the largest participant in the California marketplace. The record demonstrates that the Commission’s price cap rules also have been unduly manipulated.
For example, while the Commission had its proxy price in place during emergency-only hours, the CAISO issued Stage 1, 2 and 3 emergencies virtually 24 hours a day. Suspiciously, these daily emergencies ceased as soon as the Commission’s June 19th Order went into effect. It was no longer helpful to the CAISO’s political objectives to have daily emergencies because now price caps applied all the time. Moreover, it meant that the California news media suddenly did not have “emergencies” to report on, so that the impression could be spread that the Governor “had solved the problem.” With the June 19th Order price cap approach, however, the CAISO was now able to dictate the price for non-emergency hours by determining when a Stage 1 emergency “qualified” for purposes of changing the non-emergency price cap.
A plain reading of the Commission’s Order would indicate that the price for the non-emergency cap is equal to 85 percent of the highest price during the last Stage 1 emergency. The CAISO has embarked on creative interpretations of this simple concept. First, the CAISO declared that a Stage 1 emergency isn’t really a Stage 1 emergency that can reset the price cap unless the period of the Stage 1 lasts at least 60 minutes. Immediately upon the effectiveness of the June 19th Order, CAISO declared a series of Stage 1 emergencies lasting only 10 or 20 minutes in length, followed by Stage 2 and 3 emergencies. For example, on July 3rd a Stage 1 was called at 11:20 a.m. and a Stage 2 at 11:40 a.m. Market participants had not seen this pattern previously. Rather, Stage 1 emergencies tended to last for some time in most days, only moving to Stage 2 and 3 emergencies in the most critical situations.
Next, the CAISO declared that a Stage 1 emergency isn’t really a Stage 1 emergency that can reset the price cap unless the period of the Stage 1 lasts at least 60 minutes AND includes an entire bidding period. As evidence, we have the events of July 2nd explained through CAISO’s own e-mail to market participants received the morning of July 3rd:
At 13:32, the ISO declared a Stage 1 emergency. At that point, the Supplemental Energy Market for HE1400 had already closed with a maximum MCP of $91.87 (85% or the previous Stage 1 MCP). The next available opportunity to reflect the Stage 1 Emergency by using proxy bids established by filed heat rate curves was HE1500.
At 14:35, the ISO declared a Stage 2 Emergency. Therefore, neither HE1400 nor HE1500 was an hour when a Stage 1, but not a Stage 2 or Stage 3 or non-emergency, was in effect and there was no opportunity to establish a new maximum MCP for real-time energy transactions.
Such creative and convenient interpretations are cause for concern. Even if the CAISO’s actions were taken to artificially inflate the price cap, the fact that it
can so easily manipulate the price cap in the first place is of real concern. The plain language of Commission Orders should be implemented as they read and not be manipulated into completely new interpretations that lead to market
uncertainty and an understandable reluctance to participate in those markets.
In addition to the CAISO’s creative timing and length of Stage 1 emergencies, market participants have also noted that the CAISO has both called emergencies when reserves would not indicate an emergency situation and failed to call emergencies when reserves dip below the seven percent threshold. The only rationale for this pattern of behavior is the CAISO’s continued interest in manipulating prices for the State’s own political ends. CAISO has admitted that it does not follow the seven percent reserve rule for declaring a Stage 1 emergency and that it uses its discretion as to when it calls such emergencies.
There may be reasons for a truly independent system operator to be granted such discretion, but given the clear bias of CAISO to manipulate prices for its own political ends, the market can place no confidence in CAISO’s ability to make such decisions in an unbiased and fair manner. By failing to call an emergency, it leaves in place the existing price cap when, by the Commission’s proposal, the cap should be changed. When it calls an emergency that doesn’t exist, it makes a mockery of reliability concerns and unfairly changes the cap. Neither of these outcomes is acceptable to the marketplace. The Commission should clarify that the emergency that sets a new cap occurs when the reserve drops below seven percent for any length of time, not just when the CAISO calls it.
EPSA and WPTF offer several options to minimize CAISO’s ability to manipulate prices. First and most importantly, the Commission should audit CAISO’s price-setting function to ensure compliance. The Commission should require CAISO to submit data weekly to substantiate its price cap. The data should include for every hour: the system load, operating reserves, emergency status and highest price unit operating at the time. In addition, whenever CAISO resets the price cap, it should be required to submit the basis for its calculation, the system conditions at the time and the two hours before and after the reset period. The Commission’s review would provide some sense of stability to the market. The CAISO should be required to post the aggregate data that led to its decision to declare an emergency, thus making it transparent to all market participants, both inside and outside California.
In addition, if the Commission chooses to retain its current price cap approach, it should require CAISO to follow the plain language of its Order. In order to further minimize potential manipulation, the Commission could require CAISO to reset the price (whether up or down) whenever any emergency (Stage 1, 2 or 3) is called for any period of time. This broadening of the trigger to reset the price cap would greatly minimize CAISO’s ability to decide when a Stage 1 emergency is really a Stage 1 emergency. Although CAISO could still manipulate its own reserve numbers, either to hold off calling an emergency when reserves are low or to call an emergency when reserves are still above the trigger, the compliance review and this new reset mechanism should greatly curtail the potential for mischief.