5. As-Available Capacity Pricing
5.1. Scope of this Decision
A Commission determination on the price for as-available capacity will only affect about 20% of QFs currently delivering power to the utilities, because many QFs have contractually specified (fixed) capacity payments. These fixed capacity payments were provisions in two of the original standard offer contracts (SO): SO2 and Interim SO4 (ISO4) contracts.
5.2. Background
While QFs with SO2 or ISO4 long-term firm capacity contracts are paid a capacity price that is fixed by the terms of their contracts, SO1 QFs and Revised SO1 (RSO1)89 QFs are paid the "as-available" prices that were set almost ten years ago for all three utilities. These payments are based on the annualized cost of a peaker plant (typically a combustion turbine, or "CT"), adjusted in some cases by an Energy Reliability Index (ERI) that reflects the lower value of capacity in periods when the individual IOUs were long on capacity. The ERI varies between a minimum of 0.1 and a maximum of 1.0. The annualized costs of a CT (in $ per kW-year) are allocated to time-of-use periods using capacity allocation factors, then converted to as-available capacity prices (in $ per kWh) by dividing by the hours in each TOU period.
The bulk of the capacity value is allocated to the summer on-peak period. If an as-available QF delivers a steady flow of power throughout this time period, the QF is given credit for displacing the purchase of a full CT (assuming the ERI is equal to 1.0).
The 2007 as-available capacity prices for the utilities are as follows: PG&E90 at $69.93 kW-year; SCE91 at $4.93 kW-year; and SDG&E92 at $70.34 kW-year. Although the SCE value of $4.93/kW-year was much lower than that for the other utilities, it was uncontested and memorialized in a Joint Recommendation signed by CCC, CAC, DRA, IEP, Watson Cogeneration Company (WCC), and SCE, and the value of $4.93/kW-year had been adopted in each of SCE's last five ECAC proceedings, 1992-1996 (D.96-12-051, pp. 4-5).
Under Electric Restructuring, the plan was to pay QFs the PX price for as-available power, an all-in payment for energy and capacity. This all-in payment to QFs would have commenced only after a Commission determination that the PX was, indeed, fully operational under the terms and conditions of Pub. Util. Code § 390(c). Of course, such a determination was never made because the PX never achieved this level of operation and ceased market operations in January 2001 during the 2000-2001 energy crisis.
Since the energy crisis and its aftermath, the utilities resumed procurement on January 1, 2003 and have received increasing levels of authority to transact for various power products on a forward basis:
In R.01-10-024, the Commission worked to give the IOUs procurement authority, often referred to as `AB57 authority,' including the authority to sign contracts for up to five years' duration. Utilities resumed procurement on January 1, 2003, and undertook power procurement in 2003 in accordance with Commission approved 2003 short-term plans. In D.03-12-062, the Commission approved the utilities' 2004 short-term procurement plans. In D.04-01-050, the Commission established that each load serving entity has an obligation to acquire sufficient reserves for its customer loads, endorsed a hybrid market structure, and extended utilities' procurement authority into 2005. In R.04-04-003 (especially D.04-12-048), the Commission approved the IOUs' long-term procurement plans and gave the IOUs procurement authority for short, medium, and long term contracts for the planning period 2005 through 2014. (R.06-02-013, pp. 7-8.)
In D.02-10-062, Section VI, the Commission adopted a list of authorized products, specified authorized procurement transaction processes, and established upfront reasonableness guidelines for transactions. (D.03-12-062, mimeo., p. 20.)
The vast majority of the time, capacity payments made for general procurement purposes are for power products that have dispatchability (optionality) and/or firmness (delivered at specific times and recourse for non-delivery). With the exception of QF contracts, resource adequacy (RA) resources must generally be firm power products in order to be counted to meet RA requirements. Table 6 (below) shows some key power contract components and component types.
Table 6 Power Contract Components | |
Components |
Types |
Time-of-Delivery |
7x24 Baseload; 6x16 peak; 6x8 super-peak; 5x8 critical peak. |
Price Structure |
Fixed; Indexed; Tolling. |
Firmness |
Unit-Contingent; Firm |
Availability |
All hours and months, or as specified. |
Dispatchability |
Dispatchable, non-dispatchable, or intermittent. |
Efficiency |
Heat rate, sometimes including periodic heat rate tests for unit contingent contracts. |
Delivery Point |
NP15, SP15, or as agreed. |
Recourse for Non-Delivery |
Payment for replacement energy at a specified price, or as agreed. |
5.3. Proposals on As-Available
Capacity Pricing
Four parties (DRA, TURN, SCE, and SDG&E) recommend that no additional capacity payments be made to QFs for as-available power because Day-Ahead energy sold at the NP15 and SP15 trading points already implicitly has capacity value embedded in the energy price. PG&E proposed an as-available capacity payment that would recover only the current cost of an existing generator, resulting in a significantly lower capacity payment of $10.42/kW-year, relative to its existing payment.
In contrast, the QF parties recommend significantly increased capacity payments for as-available power. The QF parties generally recommend that the SRAC capacity value should be the fully annualized fixed cost of a simple cycle combustion turbine (CT) for each utility. CCC recommends $100.50/kW-year in 2006 (Exhibit 102, p. 51). CAC/EPUC recommends $83.50/kW-year for PG&E, and $86.59/kW-year for SCE in 2008 dollars (Exhibit 134, pp. 5, 75-76), or about $80.20/kW-year for PG&E, and $83.20/kW-year for SCE in 2006 dollars. IEP recommends $78.68/kW-yr for 2006 (Exhibit 95, p. 71).
DRA, SCE, SDG&E, and TURN contend that there is some capacity value in the Day-Ahead power indices at NP15 and SP15 because Day-Ahead power is a firm delivery product for which there are contractual consequences for non-delivery. This is in contrast to the relative lack of performance obligations in the existing standard offer QF contracts.
QFs must be paid a price not to exceed the utilities' avoided cost. [DRA] recommends replacing the SRAC transition formula price with a market-based SRAC price that does not exceed the utilities' avoided cost. If QFs are to be paid a market-based SRAC price, the capacity value in the market price must not be paid in the market-based SRAC price (Exhibit 154, p. 48).
.... One can also consider separating energy and capacity by determining the maximum capacity value portion in the market-based price. But data for determining a "capacity value subtractor" for as-available capacity may not be readily available. [DRA] understands that utilities recently conducted capacity RFOs in connection with their respective procurement activities. For future reference, the Commission should also look into the possibility of using some of the data from such capacity RFOs to develop a capacity value subtractor for purposes of backing out capacity value from market-based prices. Depending on the utilities bid offer specifications, bids for as-available capacity might indicate separate prices for capacity and energy. (DRA, supra, p. 51.)
While [DRA] recognizes that it can be difficult to isolate capacity from energy in market prices, the above recommended methodology to determine the energy portion of the market price, may yet be the only viable solution to keep the SRAC reflective of the utilities' avoided cost. (DRA, id., p. 51.)
SCE has developed a heat rate pricing methodology for existing QFs that: (1) compares SP15 DA prices to natural gas prices to compute an implied market heat rate; and (2) multiplies the implied market heat rate by a monthly bidweek natural gas price to produce an `all-in' SRAC price. This approach requires no separate calculation of or payment for as-available capacity because any capacity value is more than adequately reflected in the `all in' SP15 DA prices used to compute the implied market heat rate. (Exhibit 1, p. 4.)
The ... energy price ... based on the electric market for firm deliveries, contains both an energy component and a capacity component. If the Commission determines that the payment derived from the transition formula should constitute the entire payment to a QF, no added adjustments to the TOD factors are required. However, if the Commission continues to provide a separate as-available capacity payment, there would be double counting since the market price for firm energy contains both energy and capacity components. In that event, SDG&E proposes to remove the capacity value contained in market prices through the simple decomposition described in the E3 report. (Exhibit 85, p. 12.)
The first and most basic appropriate payment to QFs consistent with PURPA `avoided costs' would be an unhedged market price contract, which could be based on ISO imbalance prices,93 on-peak and off-peak prices reported by a publicly available service such as the Intercontinental Exchange (ICE) or Dow Jones, or hourly prices from a future day-ahead market when and if developed.94 These market prices are for firm energy, which includes both energy and capacity, and represent utilities' `avoided costs' as specified by PURPA. (Exhibit 149, p. 2.)
TURN also notes that
with the issuance of D.05-10-042 Firm Liquidated Damages (LD) contracts will no longer `count' for RA purposes after a transitional `phase-out' period that runs through 2008. After that, all Load Serving Entities, including the utilities will be required to purchase a `resource adequacy capacity product' to meet their load plus reserves, in addition to firm energy. This RA capacity product could be purchased as a bundled product that includes energy or separately as an unbundled `RA capacity product.' An unbundled capacity product would meet the RA requirement, even if it doesn't include a fixed `strike price,' or fixed heat rate for the associated energy production. (D.05-10-042, mimeo., pp. 25-28.)
TURN further notes that any such capacity product will be less valuable than a capacity contract that includes a fixed price or heat rate for the associated energy.
According to TURN, "full, annualized fixed cost of a peaker plant no longer represents the avoided cost of as-available capacity because if the utility built or purchased a peaker plant, such as a modern CT, it would obtain not only the pure capacity for RA purposes, but also the ability to receive energy at a price equal to the peaker's heat rate times the cost of gas. As a result, an as-available capacity price set equal to the annualized cost of a new CT would, when combined with a market-based SRAC energy price, provide QFs with a total payment that exceeds the utility's actual avoided cost." (Exhibit 149, p. 3.)
TURN argues that the RA program does not require the utilities to purchase "capacity" in the traditional sense of a peaking plant. Rather, utilities are only required to obtain a resource adequacy capacity product that obligates a generator to make its energy available to the CAISO at any price it chooses, constrained only by the applicable energy price cap. In contrast, a new CT provides a known price for energy based on the plant's heat rate, typically, 10,000 Btu per kWh or less. Thus, at a $7 gas price, the energy from the new peaking plant would cost 7 cents per kWh or less, plus variable O&M. Using a taxi cab example raised in hearings, contracting for a new peaking plant would be the equivalent of paying a cab driver a set fee for standing by and waiting for the passenger, and then an additional seven cents per mile. In contrast, the RA capacity product provides a fixed charge for standing by, but would allow the driver to quote a rate of up to 40 cents per mile once the passenger gets in the cab. Clearly, the product (standing by) is much more valuable when the per mile or per kWh charge is fixed in advance.
TURN notes in its testimony that the sum of unhedged market energy prices and CT capacity costs is greater than the total avoided costs. TURN also notes that
the theory that the capacity value is based on the cost of a combustion turbine was established in the late 1970s when CTs were far less efficient than they are today. Heat rates of 15,000 Btu/kWh were common... A CT therefore had little or no energy value and would be the cheapest cost of pure capacity at that time. Technology has rendered this old theory obsolete. Modern CTs are very different. They have a heat rate in the range of 10,000 Btu/kWh, which is considerably less than many older steam plants, while offering more flexible operations than steam plants that must run overnight to meet peak on two consecutive days. Therefore, we can no longer just claim that marginal energy costs - or market prices - plus a CT equals marginal generation costs, because the CT produces significant fuel savings relative to older steam plants and even more savings when compared to market prices. (Exhibit 149, pp. 4-5, footnote 8.)
SCE compares as available power in relation to modern options theory as follows: "an SO1 [as-available power] contract essentially gives the QF a special seller's `put' option with the following basic features:
o It allows the seller to deliver (i.e., "put") a flow of power (up to a contractually specified maximum rate of flow) to the utility for up to 30 years and receive the as-available energy and as-available capacity prices as periodically approved by the Commission.
o The seller also has a one-way option to terminate the contract on 30-days' notice.
o Under the SO1 contract, the utility has no option that it can exercise but instead must simply accept the power as delivered." (Exhibit 1, p. 88.)
SCE states that
by way of comparison, the `gold standard' of commercial value in the electricity market is the buyer's `call' option.... A unit-contingent call option allows the buyer to make a periodic payment to the seller in order to secure the right to call on a specific facility to deliver electricity at a stated per-kWh price. Frequently, these call options are structured as tolling agreements allowing for the buyer to purchase the fuel, thereby placing the risk of variability in the fuel price directly on the buyer. Ultimately, all power in the system comes from power plants and ownership of a physical power plant can itself be considered to approximate the value of a unit-contingent call option structured as a tolling agreement. (Id.)
Further, SCE states that,
in contrast to this classic buyer's `call' option, the as-available SO1 contract is a kind of special seller's `put' option. The first problem encountered in trying to evaluate the utility's avoided cost of undertaking the purchase obligation associated with this special seller's `put option' under an SO1 contract is that the utility would not normally seek to purchase such a one-sided product in the market. In short, the as-available contract is simply not a `natural' [or transactable] commercial product. Otherwise, one would actually observe this product being voluntarily transacted in the market at least occasionally. Thus, there are no readily available commercial reference points that are exactly appropriate; instead, there are only synthetic and conceptual constructs to guide our thinking about the issues. (Id.)
SCE recommends that if the Commission disagrees with its position on as-available capacity, the maximum payment authorized for-as available capacity should be considerably less than the full CT value. SCE admits that the state is currently short on capacity and the ERI values are likely to be above the minimum level of 10%. However, as the ERI values become larger, as-available prices under the current methodology get larger and may exceed the actual avoided costs for as-available capacity. As SCE notes, firm performance obligations are preferable to as-available contracts because the utility cannot avoid resource commitments based on the historical delivery performance of a QF and the avoided cost should accurately reflect this.
Therefore, SCE recommends that if the Commission is inclined to require as-available capacity payments, the traditional calculation of capacity value (CT * ERI) should be modified. In this case, SCE recommends that an additional element be added to the formula to reflect the fact that as-available capacity is not a perfect substitute for a physical CT. The new formula would be CT*AA* ERI, where AA is a fraction less than 1.0 but no greater than 0.2. SCE maintains that this modified calculation would ensure that the as-available capacity payment option reflects the fact that as-available is less valuable to the utilities than firm performance. SCE's description of the proposal is incomplete and does not present a clear method of implementation. SCE also suggests another approach which would cap a QF's actual as-available capacity payments to no more than the class average performance of all as-available QFs.
The utilities also contend that, unlike as-available standard offer contracts which have voluntary performance requirements (i.e., the financial incentive to receive the full capacity payment during certain delivery times), and are terminable by the QF on 30 days' notice, recent as-available contracts, such as Renewable Portfolio Standard (RPS) contracts, do include more stringent performance requirements and are generally not terminable by the seller. In addition, SCE points out that the capacity price for as-available wind generators in the RPS is discounted by 76% in the least-cost, best fit evaluation process, in a manner similar to SCE's proposal to discount as-available capacity prices to reflect their relative value to the utility.
In response to these arguments, the QF parties urge the Commission to maintain the current capacity pricing mechanism and simply modify the ERI values to reflect that each utility is currently seeking additional capacity to meet its RA requirements. They contend that the levelized cost of a CT best represents the cost the utilities would incur to procure a new capacity resource and thus represents the cost that the utilities avoid through the purchase of QF capacity. They note that the Commission has recently adopted the levelized capacity cost of a new CT as the MPR for as-available capacity and that all three utilities and TURN supported the use of the SCE cash flow model and levelization over a period of 20 years to determine the MPR for as-available capacity. While the QF parties have each proposed different input assumptions, they have each utilized the MPR model to calculate as-available capacity prices. The QF parties also argue that the lower short-term capacity values resulting from the real economic carrying charge method will not reflect the cost that the utility would pay when procuring a capacity product.
The QF parties further argue that because QFs providing as-available capacity do not receive the full capacity price unless they deliver during all of the hours in which capacity has value (i.e., in all but the off-peak hours), it is appropriate to set the price for both firm and as-available capacity payments using the same CT proxy method. The QF parties also note that, under the standard offers, QFs are obligated to deliver any energy they produce in excess of their on-site needs to the utilities. Therefore, while as-available contracts lack firm performance requirements, they are obligated to provide power to the utilities in the event that they are operating, unlike other generators in the market that may withhold or remove their power from the market to sell elsewhere.
Nine of the eleven active parties contend that a CT proxy should be used to establish as-available capacity payments made to QFs. Three non-QF parties (SCE, SDG&E, and TURN) state that as-available capacity prices should be expressed in real dollars, whereas the six QF parties have proposed the use of nominal dollars. 95 TURN notes that the Commission has never used nominal pricing for this purpose but has, instead, established "marginal capacity costs and single-year avoided capacity costs" in real dollars from the inception of the QF Program in California in the early 1980s.
The Commission has calculated marginal capacity costs and single-year avoided capacity costs in real terms for over 20 years, since the OIR 2 decision (D.82-12-120) and 1983 Test Year Edison General Rate Case (D.82-12-055). Levelized nominal dollar capacity costs have never been used before for either marginal or avoided costs since then. (Exhibit 149, Appendix B, p. 1.)
TURN provided a detailed calculation of the real economic carrying charge in real dollars for a CT in Exhibit 149, Table B-2, p. B-4). According to TURN, the CT capacity cost in a given year is equal to the capital cost of the CT times the real economic carrying charge rate, which in TURN's analysis is 9.94%, plus fixed O&M and insurance. This equals the total marginal CT cost, which is shown in Exhibit 149, Table B-2, Column 18. TURN shows this value for 2004 as $60.95 per kW-year, and notes that the corresponding levelized nominal dollar cost would have been $76.75 per kW in 2004. For 2006, the total marginal CT cost shown in column 18 of the table is $64.13/kW-year.
SDG&E makes similar note of the Commission's use of real dollars for this purpose:
In the past, the QF as-available capacity payments were set based on an annual avoided capacity cost, calculated as the Real Economic Carrying Charge (RECC) factor multiplied by the capital cost of a combustion turbine (CT), and the energy reliability index (ERI). (Exhibit 85, p. 14.)
In addition, SDG&E recommends that the value for full as-available capacity should net out the expected ancillary services value of the CT so as not to exceed avoided cost.
For 2006, SDG&E recommends a "full avoided generation cost [of] $83.75 per kW-year less the ancillary value of $14.82 per kW-year, so the proposed value for full as-available capacity is $68.93/kW-year" (Exhibit 85, p. 15).
"DRA recommends that the Commission modify the method for calculating as-available capacity prices for existing contracts to reflect the actual value that those contracts provide." (Exhibit 154: pp. 52-54, DRA Opening Brief, March 3, 2006, p. 10.) Although DRA recommends that the Commission modify the method (presumably based on the carrying cost of CT), DRA provides no specific alternative.
PG&E proposes to base "QF capacity prices [on] the resource's going-forward fixed costs." (Exhibit 28, pp. 3-42 to 3-43.) PG&E would define going-forward fixed costs as "...costs that do not vary with the resource's output, but which are needed to maintain an existing resource in operation [including] insurance, property taxes, and fixed operations and maintenance costs [but that] do not include depreciation of sunk capital, such as the cost of construction for the resource." (Id.) PG&E claims that the going-forward fixed cost for resource alternatives in 2006 and 2007 is approximately $23/kW-year.
CCC, IEP and the Renewables Coalition recommend calculating as-available capacity prices using levelized-nominal values. CCC and IEP use the Market Price Referent (MPR) methodology to calculate 20-year levelized-nominal values, and CCC cites a 2003 CEC estimate also based on a 20-year nominal levelization.96 SCE contends that it is inappropriate to use a 20-year levelized-nominal value to assess SRAC. SCE's Figure 5-1 (shown below) illustrates this concept by showing the difference between a 20-year levelized pricing stream and a SRAC pricing stream, as described here:
In Figure 5-1, the levelized-nominal stream represents a fixed price over the 20-year term that is equal (on a present value basis) to the annual stream that escalates at the rate of forecast inflation. However, the levelized-nominal stream overstates the capacity price in the early years and understates the capacity price in the later years. This is appropriate for the limited purpose of evaluating a firm capacity product for a 20-year term. One should be indifferent to these pricing streams, and the levelization of payments merely establishes a convenient payment methodology. In the context of developing an avoided firm capacity cost estimate for an unspecified time period less than the full 20 years, however, only the escalating curve appropriately represents the short-run price of firm capacity. Otherwise, payments made in the early years are overburdened by expected inflation that occurs throughout the entire 20 years. (Exhibit 2, p. 69.)
SCE Figure 5-1 (Exhibit 2)
5.4. Adopted Capacity Payment Calculation
Today, we adopt two contract options for expiring or expired QF contracts and new QFs - Our Prospective QF Program. The first option is a one- to five-year as-available power contract. The second is a one- to ten-year firm, unit-contingent power contract. Payments for as-available capacity will be based on the fixed cost of a Combustion Turbine (CT) as proposed by The Utility Reform Network (TURN), less the estimated value of Ancillary Services (A/S), as proposed by San Diego Gas & Electric Company (SDG&E) and capacity value that is recovered in market energy prices, as proposed by TURN and SDG&E. Payments for firm, unit-contingent capacity will be based on the market price referent (MPR) capacity cost adopted in Resolution E-404997 with modifications described below. This would result in a capacity price of $91.97/kW-year ($156.97/kW-year -$10/kW-year - $55.00/kW-year).98
Our reasons for these determinations are described as follows. First, firm, unit-contingent capacity is more valuable than as-available capacity because, it is much more predictable and, therefore, much more reliable. Thus, firm power and as-available power cannot be priced identically. Historically, as-available QF power has been priced based on the real economic carrying charge of a combustion-turbine (CT) power plant. We will continue that practice as described herein because as-available QF power, as a block, does allow an IOU to avoid the procurement of additional capacity albeit without the same precision as that associated with a block of firm power. Second, the firm, unit-contingent power product from our prospective QF Program will allow an IOU to more precisely avoid the procurement of additional capacity.
Of course, we must take into account the Resource Adequacy requirements developed in R.04-04-003. (See, i.e., D.04-10-035 and D.05-10-042 et seq.) In D.04-10-035, the Commission found that QF as-available capacity should be "counted" for RA purposes at the historical level of deliveries. Due to the magnitude of QFs in the IOU portfolios, this approach is prudent. However, QFs under existing contracts are not under the same "must-offer obligation" required of other RA resources. However, these previous RA orders were issued prior to the development of our Prospective QF Program. The firm, unit-contingent power product should count for purposes of resource adequacy because it will be very similar to other modern power products that contain similar performance requirements. With regard to the as-available power product in our prospective QF Program, it should also count as a block of QF power. The issue of whether any of this QF power counts for purposes of RA is now moot with respect to the capacity payments because the capacity payments will no longer be contingent on RA counting rules. This follows from the fact that we cannot reasonably institute a meaningful long-term policy for expiring QF contracts, nor a policy for the entry of new QFs unless there is a capacity payment commitment.
It is true that QFs under existing contracts are not available to the CAISO as an RA resource. However, it is also true that all QFs with a dependable capacity under one MW are not capable of participating in CAISO markets, in terms of bidding and scheduling. Further, many as-available QFs are under one MW. Any generator under one MW, whether as-available or firm, does not have access to CAISO markets, nor does the CAISO have control access over sub-MW generators, including QFs. Thus, for example, even if QFs under one MW were fully dispatchable, CAISO systems are not currently set up to accommodate these sub-MW resources, nor will they be under the MRTU.
At this point, further consideration of any `disparity' between the adopted RA counting rules and the reality of resource needs of the CAISO can be ended by acknowledging that capacity payments under the prospective QF Program will not be contingent upon future determinations on the RA counting rules. Instead, the RA counting rules can count or not count QF power, depending upon how the RA portfolios will be conceptualized in the future. Prospectively, we are committing ourselves to this next era of QF power through the provision of reasonable capacity payments for the power products provided. The CAISO and the RA counting rules will have to accept this power as must-take and focus on refining and shaping IOU power portfolios through the use of other resource options.
Once a full CT capacity value is determined, adjustments to that value should be considered. For example, we agree that the value of additional (ancillary services) revenue streams associated with the physical ownership of an actual CT should be accounted for in our estimate of capacity value. In its rebuttal testimony, CCC recommended the use of the full cost of a CT as the avoided value of as-delivered capacity, but also acknowledged that an adjustment to as-delivered capacity prices would be warranted given certain substantial evidence. (Exhibit 103, pp. 59-60.) CCC explored TURN's evaluation of the potential for such an adjustment based on an assessment of energy profits where an adjustment hinged on an accurate estimate of the number of hours of annual CT operation.
SDG&E recommends that:
the value of the CT in the ancillary service market would be deducted from proposed annual avoided capacity cost. As the name "as-available" implies, the as-available capacity of a QF does not have the same characteristics as a CT that can be dispatched as needed. If the utility owned a CT, it could capture added value by offering the unit in the CAISO ancillary services market as non-spinning reserve, while the utility cannot obtain that value from an as-available QF. It is estimated that this ancillary services value over June, 2003 - May, 2005 was $14.78/kW-year. The full avoided generation cost is projected to be $83.75 per kW-year less the ancillary value of $14.82 per kW-year, so the proposed value for full as-available capacity is $68.93/kW-year in 2006. (Exhibit 85, p. 15.)
SDG&E proposes a methodology for estimating its recommended ancillary services value adjustment of $14.82 per kW-year, to account for revenue received from the CAISO for the provision of non-spinning reserves. The CAISO defines this product as follows:
Non-Spinning Reserve is off-line generation capacity that can be ramped to capacity and synchronized to the grid within 10 minutes of a dispatch instruction by the ISO, and that is capable of maintaining that output for at least two hours. Non-Spinning Reserve is needed to maintain system frequency stability during emergency conditions.99
SDG&E assumed a 5% maintenance outage rate (438 hours/year), and that the CT would actually be operating (e.g., to serve native load) for 634 hours/year or about 7.2% of the year. During the remainder of the year (8,760 - 438 - 634 = 7,688 hours), the CT would be available to the CAISO to provide non-spin ancillary services. SDG&E obtained monthly non-spin prices from the CAISO for the period of June 2003 through May 2005 with a simple average of $1.93 per MW. Thus, the capacity value for non-spin reserves is estimated to equal 7,688 hours times $1.93 per MW = $14,815/MW or $14.82/kW-year.
In addition to an adjustment for ancillary services, TURN and SDG&E proposed a reduction in capacity payments to reflect the benefits received from the energy market. TURN maintains that an adjustment is warranted to "reflect that a dispatchable CT, when not operating, can be bid into the ISO's ancillary services markets and create some revenue that would not be created by the QF (and is thus not part of the CT-based avoided cost for the QF)" (Exhibit 149, p. 4.) TURN proposes two methodologies for calculating this amount. SDG&E proposes that this amount be calculated based on the energy reliability index (ERI) and adjusted annually. The minimum ERI proposed is 0.243, which results in $16.78/kW-year. (Exhibit 85, p. 16.)
We agree with TURN, SCE, and SDG&E on this issue. The avoided CT cost should be based on an economic carrying charge rate, escalated for inflation over the life of the contract. Using a levelized nominal dollar value to compute the CT cost would overstate the avoided capacity cost as well as present additional cost and risk for utilities and ratepayers. A primary concern is that the use of a levelized nominal value would require higher capacity payments in early years, exposing the utilities and their ratepayers to the risk of non-performance if the QF went off-line or simply failed to perform. While termination penalties or the posting of security could mitigate some of the concern, calculating a CT cost based on an economic carrying charge rate and escalating for inflation would eliminate this concern. In addition, as pointed out by SCE and TURN, it would be inappropriate to use a 20-year levelized value for a contract of less than 20 years in length. Using an economic carrying charge rate, escalated for inflation over the life of the contract, allows us to provide more flexibility in contract terms, from one year up to five years with the same CT cost estimate. As-available capacity prices should be expressed in real dollars.
For the as-available contract option, we adopt the CT cost and real economic carrying charge rate calculations proposed by TURN as presented in Exhibit 149, Appendix B, with an ancillary services adjustment and an energy benefits adjustment subtracted from the adopted value. TURN calculates a total marginal CT cost of $64.13/kW-year in 2006. Using the adopted TURN value for $64.13, the resulting capacity value would be $32.53/kW-year ($64.13/kW-year - $14.82/kW-year - $16.78/kW-year).
89 RSO1 contracts entered into pursuant to D.02-08-071, D.03-12-062, D.04-01-050, and D.05-12-009, are priced as directed in D.01-03-067.
90 PG&E's avoided cost posting states: "This Capacity Value is the combustion turbine proxy capacity value effective beginning April 1, 1997, as approved in CPUC D.97-03-017 on March 7, 1997. This value has been adjusted for use in 2006 to reflect inflation. A weighted average of the capacity value is used for meters without time-of-delivery metering." The value adopted in D.97-03-017 was $64.77/kW-year. http://www.pge.com/docs/pdfs/suppliers_purchasing/qualifying_facilities/prices/2006_asdelcap.pdf.
91 SCE's avoided cost posting states: "Pursuant to D.96-12-051, the Capacity Schedule for As-Available Capacity for Standard Offer Nos. 1 and 3 reflects SCE's shortage cost of $4.93/kW-year, which is based on an Energy Reliability Index of 0.1. Shortage costs are determined by adjusting the costs avoided by deferral of combustion turbines using an Energy Reliability Index and will remain in effect until revised pursuant to the Commission's directions. The schedule includes future escalations of capital costs and operation and maintenance costs. Per D.82-01-103, capacity payments are reduced 50% for projects under Standard Offer No. 3 with no time of delivery meters." http://www.sce.com/NR/rdonlyres/83102058-F6B9-4A6B-8255-1358C66F1A89/0/QF_SRAC.pdf.
92 SDG&E as-available capacity price of $70.34/kW-year was adopted in D.96-06-033.
93 TURN footnote: The use of Independent System Operator (ISO) imbalance prices is not our preferred option, because ISO imbalance prices truly represent the last few megawatts and can swing dramatically based on minute-to-minute imbalances between load and generation rather than day-to-day loads and resources.
94 TURN's preferred option.
95 SDG&E qualifies its recommendation on this point: "The levelized cost of a combustion turbine has been used in numerous recent proceedings by the Commission and various parties as the marginal generation capacity cost including demand response programs in R.02-06-001. From a theoretical perspective, however, for a short-term program like QF as-available capacity, a real economic carrying charge may be the more appropriate measure of marginal generation capacity cost. Real economic carrying charge reflects the short term cost savings from delaying investment in new generation plant; the effect of the QF if it can be counted under the resource adequacy counting rules has the same effect. Real economic carrying charge escalates annually with inflation over the life of the marginal resource unlike the levelized annual cost that is constant. Over a long period of time, the present value of the real economic carrying charge is the same as the present value of the levelized cost over the life of the marginal resource, but in the first year has a lower value. If the Commission shifts to using a real economic carrying charge approach in other ratemaking such as rate design and demand response avoided costs, SDG&E would recommend using the real economic carrying charge approach for QF as-available capacity in this proceeding." (Exhibit 85, p. 15, fn. 15.)
96 Exhibit 102, pp. 51-52; Exhibit 95, p. 70.
97 MPR Resolution, E-4049, December 2006, http://www.cpuc.ca.gov/Published/Final_resolution/63132.htm.
98 This figure was derived from the MPR Model, filename: 2006 MPR Model_Resolution E 4049_Final_12_13_06 (2).xls, "Cap_Fac" tab, Cell E4, where the model is solved for a 10-year contract beginning in 2007 on the "Control" tab.
99 CAISO Settlements Guide, Ancillary Services, Spinning Reserve and Non Spinning Reserve, Draft Revised, 01/31/2006) http://www.caiso.com/clientserv/settlements/SettlementsGuide/index.html.
