III. Project Benefits

In this section, we address the economic and other benefits that parties attribute to DPV2, and compare those benefits to project costs. We conclude that DPV2 will provide significant economic benefits for CAISO ratepayers, and that it would also provide operational and other benefits. We find that potential alternatives to DPV2 are insufficient and are unable to provide the economic and other benefits of DPV2.

A. Economic Evaluation of DPV2

SCE, the CAISO, and DRA submitted economic evaluations of the proposed DPV2 project. Other parties made recommendations regarding the cost-effectiveness of DPV2 based on review of the submitted economic evaluations or commented on specific aspects of the methodologies employed in the economic evaluations.

1. Benefit Perspectives

SCE, the CAISO, and DRA evaluated the benefits of the proposed DPV2 transmission project by comparing estimates of total costs that would be incurred without the proposed project and total costs if the proposed project is built.

As described in D.06-11-018, the benefit perspective of CAISO-area ratepayers is of primary importance in the Commission's evaluation of a proposed transmission project, since it reflects the effects on customers of the utilities within our jurisdiction.9 All three parties reported the net impact of the DPV2 project on CAISO ratepayers. The CAISO also presented benefit results for the entire Western Electricity Coordinating Council (WECC) region (the WECC or Societal perspective). SCE provided limited information regarding potential economic impacts in Arizona and the WECC region.

As noted in D.06-11-018, there are three general categories of costs or benefits arising from operation of a transmission project: (1) the change in total production costs, or energy benefits, (2) changes in other quantifiable economic benefits and costs not derived from production cost analyses, and (3) foreseeable project consequences whose expected economic effects cannot be monetized. We address these three types of costs and benefits with respect to DPV2 in Sections III.A.3, III.A.4, and III.B, respectively. We evaluate construction and operational costs of DPV2 in Section III.A.5.

The energy benefits due to a transmission project consist of the net changes in consumer costs (consumer surplus), producer net income (producer surplus), and congestion revenues flowing to transmission owners or holders of transmission rights (transmission surplus). Since the Societal WECC-wide perspective represents a largely closed system with few imports or exports, the Societal benefit computed as the DPV2-caused net WECC-wide change in consumer surplus, producer surplus, and congestion revenues closely approximates the overall change in energy production costs due to operation of DPV2.

Energy benefits from the CAISO Ratepayer perspective are the net result of the increase in consumer surplus and changes in the utility-retained generation producer surplus and the Participating Transmission Owner (PTO) congestion revenues in the CAISO area. The producer surplus and congestion revenues received by CAISO-area utilities ultimately benefit CAISO-area consumers, because the utilities' generation and congestion revenues reduce revenues that would otherwise be sought from consumers to cover costs.

In D.06-11-018, the Commission declined to adopt a threshold benefit-cost ratio or payback period that a transmission project proposed for its economic benefits would be required to achieve in order to be granted a CPCN. As we explained in that decision, transmission projects such as DPV2 may have other benefits and costs in addition to those that can be quantified in a benefit-cost ratio. In Sections III.D and VII, we consider and weigh all relevant factors, including environmental impacts, in reaching a decision on SCE's CPCN request.

2. Overview of Parties' Economic Evaluations of DPV2

a) SCE

The results of SCE's economic evaluation of DPV2, as contained in its PEA and Exhibit 6, are summarized in Table 1. To allow comparison of DPV2 costs and benefits, SCE calculated the 2005 present value of DPV2 revenue requirements using SCE's fixed charge rate model and discounting at an assumed 10.5% marginal cost of capital. SCE projects that DPV2 will provide benefits to CAISO ratepayers of almost $460 million in excess of its costs, with a resulting benefit-cost ratio of 1.71.

Table 1

SCE's Economic Evaluation of DPV2

Proponent's Environmental Assessment

(CAISO Ratepayer Perspective)

(Net Present Value, $2005 Million)

In addition to energy benefits, SCE reports that CAISO-area transmission owner revenues will increase due to the DPV2-caused increase in revenue requirements, which would increase rates for CAISO wheeling service and Existing Transmission Contracts, and thus would decrease the revenues required from CAISO ratepayers. SCE also includes the effect of DPV2-caused reductions in energy costs on revenues needed for franchise fees and uncollectibles.

An earlier economic evaluation of DPV2 that SCE submitted to the CAISO on March 17, 2005 contained more detail than the economic evaluation submitted in the PEA. As summarized in Table 2, the March 17, 2005 study provided disaggregated CAISO Ratepayer benefits, which indicate the extent to which SCE forecasts that utility-retained generation and PTO congestion revenues would decrease as a result of DPV2's operation.

Table 2

SCE's Evaluation of DPV2 Energy Benefits

March 17, 2005 Report to CAISO

(CAISO Ratepayer Perspective)

(Net Present Value, $2005 Million)

In its March 17, 2005 economic evaluation, SCE modeled DPV2 operation for the years 2009 through 2014, and reported energy results for those years from the WECC-wide or Societal perspective and the perspective of Arizona customers, in addition to the CAISO Ratepayer perspective. With the assumptions underlying SCE's evaluation, the results in Table 3 indicate that Arizona customers would not benefit from DPV2 during the modeled years. SCE did not report lifecycle benefit-cost ratios from these additional perspectives. We address these impacts further in Section III.D.

Table 3

SCE's Evaluation of DPV2 Yearly Energy Benefits

March 17, 2005 Report to CAISO

($2004 Million)

SCE forecasted DPV2's impact on energy costs using the Global Energy (formerly Henwood) production cost model using a "transportation" power flow simulation. In a transportation model, generator and load locations are aggregated into zones, and power is simulated to flow along contract paths between the zones, with each path potentially representing multiple transmission lines. Flows between zones are restricted by modeler-specified limits and do not reflect the effects of loop flow. A transportation model calculates prices on a zone-wide basis.

SCE used a stochastic approach to assess DPV2's energy benefits over a wide range of load forecasts, natural gas prices, and available hydroelectric generation. SCE assigned probability distributions to these key factors, based on documented historical variations, and simulated system operations under 100 different combinations of future conditions based on values chosen from the probability distributions using Monte Carlo (random sampling) techniques. SCE then calculated energy benefits as the probability-weighted expected value of benefits based on results of the 100 system simulations.

SCE calculated electricity prices and resulting consumer and producer surpluses based on projected spot market prices equal to marginal costs in each modeled zone. SCE did not reflect that, in some market conditions, generators may be able to sell power at prices in excess of marginal costs, i.e., that they may successfully mark up their bids above marginal costs and receive higher revenues in an exercise of market power.

b) CAISO

The results of the CAISO's economic evaluation of DPV2 are summarized in Table 4. The CAISO finds DPV2 to be cost-effective, with the CAISO Ratepayer benefit-cost ratio likely to be in the range between 1.25 and 3.34. This range arises because of uncertainty regarding congestion revenues between the CAISO control area, with its planned market redesign based on locational marginal prices (LMP), and Arizona.

Table 4

CAISO Economic Evaluation of DPV2

(Levelized Annual $2008 Million/Year)

 

Societal Perspective

Modified Societal

CAISO Ratepayer (LMP Only)

CAISO Ratepayer (LMP + Contract Path)

Levelized Benefits:

        

Energy

$ 56

$ 84

$ 57

$ 198

Operational

20

20

20

20

Capacity

12

12

6

6

System Loss

2

2

1

1

Emissions

1

1

1

1

Total Benefits

$ 91

$ 119

$ 84

$ 225

Levelized Costs

$ 67

$ 67

$ 67

$ 67

Benefit-Cost Ratio

1.35

1.77

1.25

3.34

As indicated in Table 4, the CAISO presents economic results for two versions of the Societal perspective and two versions of the CAISO Ratepayer perspective. Unlike SCE and DRA, the CAISO forecasts the extent to which producers may exercise market power to bid up prices above system marginal costs. The two versions of the Societal perspective differ in their treatment of the effects of DPV2 in mitigating the ability of generators to exert market power. In the CAISO's basic Societal perspective, the reduction in market power-derived producer profits that the CAISO forecasts due to DPV2 is viewed as a negative benefit and offsets much of the projected consumer benefits from reduced energy costs. What the CAISO calls the Modified Societal perspective does not consider that portion of producer surplus arising from the exercise of market power to be a valid benefit and, thus, reflects the related increase in consumer surplus as a benefit. Because of the societal value in reducing producer monopoly profits, we determined in D.06-11-018 that, for evaluations that include strategic bidding above system marginal costs, the Modified Societal perspective, rather than the CAISO's Societal perspective, is the appropriate perspective to use in evaluating the societal benefits of a proposed transmission project.

To evaluate potential energy benefits of DPV2, the CAISO used the PLEXOS Direct Current Optimal Power Flow network model. A network model simulates electrical flows on individual transmission lines based on electrical principles and line characteristics, and models loop flow. Such a model optimizes the dispatch of generators to provide least-cost supply and permits calculation of LMP, consistent with the CAISO market redesign planned for the end of 2007.

The CAISO based its calculations for what it calls the CAISO Ratepayer (LMP Only) test on the modeling assumption that an LMP-based market structure would be applicable throughout the WECC. However, most of WECC employs contract-path scheduling, with no plans to implement an LMP-based market structure. The CAISO acknowledges that, as a result, its CAISO Ratepayer (LMP Only) calculation overestimates CAISO-area utilities' loss of congestion revenue due to DPV2 and thus underestimates CAISO ratepayer benefits.

Because of the inaccuracy in its modeling of WECC-wide operations, the CAISO also reports an adjusted CAISO Ratepayer (LMP + Contract Path) benefit perspective. This adjusted calculation excludes much of the congestion revenues between southern California and the Southwest indicated by the CAISO's LMP-based modeling. This exclusion results in substantially lower pre-DPV2 congestion revenues for CAISO utilities, and consequently a much lower negative benefit in the form of reduced congestion revenues when DPV2 is added. Recognizing some shortcomings to this adjustment as well, the CAISO believes that "the true answer lies somewhere between the CAISO benefits computed with and without this adjustment."

The CAISO developed low, medium, and high forecasts for load growth, hydro conditions, gas prices, and the degree of market power exhibited in producers' bids. To analyze the effects of uncertainty on the energy benefits of DPV2, the CAISO performed system simulations for 17 representative (out of 81 possible) combinations of the identified variations in these market conditions. It assigned probabilities to each of the 17 scenarios and used the results to calculate probability-weighted benefit-cost ratios. The CAISO also analyzed energy benefits for eight contingency scenarios representing certain outages and other contingency events, for which it did not assign probabilities and whose results it did not include in the calculated benefit-cost ratios.

In addition to energy benefits, the CAISO quantifies and includes in the reported benefit-cost ratios several non-energy benefits of the DPV2 upgrade as indicated in Table 4, principally operational benefits and capacity value. The CAISO assumes that the annual benefits for each of these areas of non-energy savings would not change over time in real terms and would not depend on market conditions such as demand, gas prices, or hydro conditions.

c) DRA

DRA's economic evaluation of DPV2, prepared with the assistance of its consultants including Woodruff Expert Services (WES), is summarized in Table 5. DRA forecasts that, with two successive sets of adjustments to SCE's base case analysis, DPV2 will provide net energy benefits of $261 million in excess of DPV2's costs, with a CAISO Ratepayer benefit-cost ratio of 1.31.

Table 5

DRA Economic Evaluation of DPV2

(CAISO Ratepayer Perspective)

(Net Present Value, $2005 Million)

DRA used the same system model and database used by SCE. DRA reviewed SCE's economic evaluation of DPV2, but did not address the CAISO evaluation in its testimony.10 DRA critiques several methods and assumptions used by SCE, describing some that underestimated and others that overestimated the value of DPV2. To address some of these concerns, DRA prepared a two-step analysis. First, DRA prepared what it called a Deterministic Reference Case, which used SCE's base forecasts for loads, gas prices, and hydro conditions but changed certain modeling conventions. As the second step, DRA updated SCE's gas price forecast to the higher forecast current at the time of DRA's assessment. DRA calls this deterministic simulation the WES Reference Case.

DRA considered uncertainty by evaluating eight sensitivity and contingency cases involving extreme outage events or alternative assumptions regarding gas prices and supply conditions. To assess the impact of forecast risk on the estimated value of DPV2, DRA used what it called an Uncertainty Margin method to conclude that the level of forecast risk can be relatively high without jeopardizing the conclusion that DPV2 is likely to provide net benefits.

DRA also undertook what it calls a tipping point analysis to identify which parameters, assumptions, or relationships drive the conclusions of its economic evaluation of DPV2. It identified four variables as tipping points: modeling conventions, the natural gas price differential between Arizona and California, the on-line status of the Palo Verde nuclear units, and the wholesale cost of natural gas. DRA calculates that, in order for DPV2 to be cost-effective, the wholesale Topock (Arizona) gas price must exceed $5 per million British thermal units (mmBtu), the gas price differential between Arizona and California must exceed $0.50 per mmBtu, and Palo Verde must operate. Alternatively, DRA finds that DPV2 would be cost-effective if gas prices exceed $6.40 per mmBtu, even if there is no California-Arizona price differential.

DRA cautions that the WES Reference Case, while providing DRA's best estimate of DPV2's value, is limited by several identified uncertainties that could be better quantified, but only with significant additional effort. DRA is also concerned that some important uncertainties regarding modeling methods and assumptions may not have been identified, and cautions further that paradigm shifts in the energy market could render the DPV2 project uneconomic.

d) Other Parties

TURN presented testimony in Phase 1 that primarily addressed economic methodology issues that we have resolved in D.06-11-018. In its opening brief in Phase 1, TURN states that it agrees with SCE, the CAISO, and DRA that the proposed DPV2 project is likely to be a cost-effective investment for CAISO ratepayers. TURN finds comfort in the fact that DPV2 economics underwent substantial review by different parties using different methods and all concluded that DPV2 would be beneficial.

PG&E, SDG&E, Global Energy, and BAMx made recommendations in Phase 1 regarding the methodology to be used for economic evaluations of transmission projects. However, none of these parties took a position on the cost-effectiveness of DPV2.

3. DPV2 Energy Benefits

In this section, we address several areas of concern regarding the parties' economic evaluations of DPV2. We also describe the CAISO's and DRA's examination of several unlikely but potentially significant contingency scenarios.

a) System Modeling

As we discussed in D.06-11-018, while the CAISO's view is that only network models provide an acceptable level of accuracy, both the network and transportation approaches as employed in evaluating DPV2 have strengths and weaknesses.

A network model such as the CAISO used in its DPV2 evaluation may provide more accurate forecasts of physical flows and locational prices in an LMP market and may identify the resulting congestion and its economic implications with more accuracy compared to a transportation model. However, because most of WECC outside of California uses contract path scheduling, the CAISO makes an "LMP + Contract Path" adjustment to its modeling results to approximate the market paradigm between the Southwest and southern California. While this adjustment has some similarities to SCE's and DRA's contract path approach, the CAISO still forecasts generator dispatch and power flows based on its network simulation. The "LMP + Contract Path" adjustment is, as the CAISO acknowledges, a simple approximation.

The CAISO's "LMP + Contract Path" measure of DPV2 energy benefits to CAISO ratepayers is over three times as large as that derived in the "LMP Only" calculation, as indicated in Table 4 above. As the CAISO suggests, the actual benefits may fall somewhere in this range. Thus, the potentially greater accuracy of the CAISO's detailed modeling of power flows appears to be overshadowed in the benefit-cost assessment by the degree of imprecision in the CAISO's calculation and allocation of congestion costs between Arizona and southern California.

In comparison to a network model, a simpler transportation model such as SCE and DRA used is computationally faster and allows a more complex analysis of uncertainty. A transportation model generally can permit more sophisticated modeling of generator operation. Despite CAISO concerns, SCE and other parties assert that, with care, a transportation model may be calibrated and validated regarding the effects of power flow complexities such as loop flow on system dispatch, prices, and congestion costs.

SCE describes that it established transfer limits on modeled interzonal transmission paths between Arizona and southern California to approximate how real world power flows on these paths would be limited. SCE used a Southern California Import Transmission nomogram, which quantifies the aggregate allowable electricity flows on the paths into southern California, depending on the amount of generating capacity operating in southern California and the status of the Palo Verde nuclear units. SCE described that, in addition to transportation modeling, it used separate power flow analyses to demonstrate the physical feasibility of DPV2 operation.

It is not possible to determine, based on the record before us, the extent to which modeling differences affected the parties' results. None of the parties benchmarked their modeling efforts to historical experience. Further, the CAISO and SCE/DRA evaluations used different input databases and simulated different market scenarios. The CAISO used a database developed by the Seams Steering Group-Western Interconnection (SSG-WI) with modifications to reflect SCE's system more accurately, whereas SCE and DRA used a database developed by SCE based on its recent procurement plans. While the CAISO and DRA reported inputs and results for each of the scenarios they simulated, SCE presented only expected value results obtained from its probability-weighted aggregation of the 100 simulations it undertook.

The most useful comparison available in the record that illuminates the effects of modeling differences is for the year 2013, which all parties modeled. SCE's stochastic results, DRA's Deterministic Reference Case, and the CAISO's "medium conditions and no bid markup" base case are roughly comparable. The resulting 2013 energy benefits from the CAISO Ratepayer perspective are summarized in Table 6. The fact that the energy benefits found by DRA fall almost exactly at the midpoint of the CAISO's "LMP Only" and "LMP + Contract Path" range of benefits supports the CAISO's view that market results will lie somewhere between its two estimates. Because SCE's stochastic process captures the higher value of DPV2 under extreme market conditions, we would expect the energy benefits reported by SCE to be significantly larger than the energy benefits that DRA found using base case conditions. The results summarized in Table 6 are consistent with this expectation.

Table 6

DPV2 Energy Benefits in 2013

(CAISO Ratepayer Perspective)

($2013 Million)

As TURN suggested, this limited illumination of differences in the parties' production cost modeling efforts confirms that there is value in having both network and transportation models employed in evaluating DPV2. The fact that the relationships among the energy benefits found by the parties are logical provides some assurance both that the CAISO's "LMP Only" and "LMP + Contract Path" estimates bracket actual energy benefits and that the more simplistic transmission modeling underlying the SCE and DRA analyses may be reasonably reliable. We have greater confidence in the results of the parties' evaluations because SCE, CAISO, and DRA modeling efforts produce consistent estimates of energy benefits.

b) Natural Gas Price Forecasts

Both the overall level of natural gas prices and the California-Arizona differential in delivered gas prices affect the level of DPV2 energy benefits. Additionally, the relative efficiencies of power plants in California and elsewhere will influence the extent to which out-of-state gas generation may displace California generation. The gas price level matters because, if gas-fired generators in Arizona have an efficiency (heat rate) advantage over those in California, the higher fuel efficiency will yield greater economic savings when fuel prices are high. Also, the greater the California-Arizona differential in delivered gas prices, the larger the energy savings will be.

Natural gas price forecasts for 2013 utilized or reported in this proceeding are summarized in Table 7.

Table 7

Natural Gas Price Forecasts

($/mmBtu in 2013)

Source

Vintage

Arizona (Topock)

Southern California

California-Arizona Differential

         

CAISO DPV2 evaluation

Aug. 2004

$ 5.71

$ 6.08

$ 0.37

SCE DPV2 evaluation (Global Insight)

Oct. 2004

$ 5.27

$ 5.66

$ 0.39

SCE Global Insight gas price update

Oct. 2005

$ 6.26

$ 6.72

$ 0.46

DRA DPV2 evaluation (WES Reference Case)

Nov. 2005

$ 7.23

$ 7.62

$ 0.39

DRA gas price update

Jan. 2006

$ 9.53

-

-

In the system simulations undertaken by the CAISO, variations in gas prices had a greater effect on DPV2 energy benefits than any other market condition considered. The CAISO used a base-case natural gas price forecast published by the California Energy Commission (CEC), and developed "very low" and "very high" forecasts representing the lower 5% and upper 95% confidence levels. The effect of these gas price variations on DPV2 energy benefits is shown in Table 8, for base-case load forecasts and hydro conditions. As expected, the effect of gas prices on DPV2 benefits is not symmetrical, with high gas prices having a greater effect on DPV2 benefits than would low gas prices.

Table 8

CAISO Evaluations of DPV2 Energy Benefits

with Varying Levels of Natural Gas Prices

(Base-case Load Forecasts and Hydro Conditions, No Market Power)

($ Million Nominal)

 

Societal

CAISO Ratepayer (LMP Only)

CAISO Ratepayer (LMP + Contract Path)

2008 benefits:

      

Low gas prices

$ 6.76

($ 2.41)

$ 17.07

Base gas prices

42.83

19.81

70.83

High gas prices

85.81

48.79

141.49

 

2013 benefits:

 

Low gas prices

$ 20.68

($ 2.89)

$ 50.81

Base gas prices

55.50

40.05

137.07

High gas prices

102.45

91.68

240.63

SCE used natural gas price forecasts developed by Global Insight. Compared to the CEC forecasts used by the CAISO, the Global Insight forecasts contain slightly lower gas prices and a higher California-Arizona price difference. Because lower gas prices would tend to make DPV2 look less economic while a larger California-Arizona price difference would tend to make DPV2 look more economic, the extent to which gas price assumptions contribute to the differences in SCE and CAISO results is unclear.

SCE developed a gas price probability distribution function based on historical gas price fluctuations to model uncertainty in future gas prices. DRA takes issue with the variations in gas prices that SCE modeled, because SCE included the California energy crisis period in the historical gas price data used to estimate future volatility. DRA submits that the events during that period, including market manipulation, suggest that the period's data are not representative of reasonable future market outcomes. DRA undertook a statistical analysis in which it excluded gas price data from the energy crisis period, and found almost 40% lower volatilities in Topock winter gas prices and about 50% higher correlations in winter prices among the gas pricing basins, compared to the relationships SCE assumed in its modeling. DRA did not quantify the impact on DPV2 economic results.

In its WES Reference Case, DRA used a November 2005 forecast of gas prices at Topock for 2009 and 2010. As can be seen from Table 7, DRA's gas price forecasts are higher than those used by the CAISO and SCE, and the Arizona-California price differential used by DRA is higher than that used by the CAISO and the same as the one used by SCE. Because of these differences, DRA's gas price forecasts would tend to make DPV2 look more economic than would the forecasts used by the CAISO and SCE.

SCE provided an October 2005 update to the Global Insight natural gas price forecast, which is included in Table 7. The natural gas prices in this update are higher than those used by the CAISO and SCE, but less than the prices used by DRA in their economic evaluations. The Arizona-California price differential in this forecast is $0.46 per mmBtu, higher than the differentials used in any of the economic evaluations. DRA provided a late-filed update to its assumed gas price for 2013, using January 16, 2006 Topock futures prices for 2009 and 2010. While no party updated its economic evaluation of DPV2 using these updated gas price forecasts, it is clear that these higher gas prices would increase the value of DPV2 substantially as long as the Southwest has surplus generation with attractive fuel efficiencies.

c) Mitigation of Market Power

All parties agree that the increased transfer capability added by DPV2 would reduce generators' ability to wield market power through strategic bids above system marginal costs, with resulting ratepayer benefits. Parties disagree regarding the extent to which forecasts of these market power mitigation benefits should be relied upon in determining the likely economic benefits of DPV2.

SCE and DRA did not model strategic bidding or estimate the ability of DPV2 to mitigate generators' market power. These parties express skepticism about the ability to quantify market power mitigation benefits with any degree of reliability. Global Energy states that it would be desirable to analyze the benefits of reducing market power if cost-based studies without strategic bid markups show insufficient project benefits, but submits that the CAISO's approach must be refined and undergo further testing before it can be accepted.

The CAISO simulated generators' exercise of market power via strategic bid markups, using an empirical approach in which it correlated historical market prices above marginal costs with two measures of market concentration. In Table 9, selected results illustrate DPV2 benefits that the CAISO forecasts due to mitigation of market power. To facilitate comparison, this table presents only CAISO scenarios that include base-case forecasts of load, gas prices, and hydro conditions, so that the differences reflect solely the CAISO's modeling of market power. A comparison of the No Market Pricing, i.e., marginal cost-based pricing, and Medium Market Pricing results indicates annual societal and CAISO ratepayer benefits ranging between $15 million and $56 million due to the modeled reduction in producers' market power.

Table 9

CAISO Evaluations of DPV2 Annual Energy Benefits

with Varying Levels of Market Pricing

(Base-case Load, Gas Price, and Hydro Conditions)

($ Million Nominal)

 

Modified Societal

CAISO Ratepayer (LMP Only)

CAISO Ratepayer

(LMP + Contract Path)

2008 benefits:

      

No market pricing

$ 42.89

$ 19.81

$ 70.83

Medium market pricing

58.85

37.87

98.74

High market pricing

71.12

54.82

124.50

  

 

2013 benefits:

  

 

No market pricing

$ 55.54

$ 40.05

$ 137.07

Medium market pricing

77.43

54.88

193.50

High market pricing

93.86

65.22

237.23

As we would expect, the CAISO reports that the highest DPV2 benefits due to market power mitigation would occur if there are high loads, high gas prices, and dry hydro conditions. The CAISO forecasts that DPV2 would provide large market power mitigation benefits under this combination of extreme conditions, with annual energy benefits generally ranging between $54 million and $321 million more with medium market pricing than if no market power is assumed.

We agree that a transmission project such as DPV2 can provide important benefits due to the resulting reductions in market concentration and generator market power. As we recognized in D.06-11-018, the CAISO has made substantial advances in its efforts to forecast strategic bidding and the ability of a transmission upgrade to reduce generators' market power. However, we questioned the manner in which the CAISO used historical data to predict future generator bidding behavior. Among our concerns, the anticipated CAISO LMP-based market, along with strengthened market power mitigation and monitoring, and resource adequacy and capacity requirements, will differ substantially from the historical circumstances that underlie the CAISO's bidding algorithms. We also questioned the reasonableness of the CAISO's use of statistically derived market-wide price-cost markups to approximate individual generators' bid-cost markups. Another concern we expressed in D.06-11-018 is that the CAISO did not verify adequately the predictive ability of its market power model.

Our concerns regarding reliance on the CAISO's estimations of benefits due to DPV2's mitigation of market power are compounded by the difficulties in modeling congestion revenues between the CAISO control area and Arizona. As can be seen in Table 9, the CAISO forecasts much higher market power mitigation benefits in the CAISO Ratepayer (LMP + Contract Path) calculation than in the CAISO Ratepayer (LMP Only) calculation. The compounding effects of the uncertainties regarding the CAISO's estimates of both congestion revenues and market power mitigation increase our reluctance to rely on the estimates of market power mitigation benefits submitted by the CAISO for DPV2. Nevertheless, the CAISO results illustrate the value of DPV2 in reducing producers' ability to elevate prices due to market power.

d) Treatment of Generation Units Owned or Controlled by CAISO-Area Utilities

As modeling simplifications, SCE and the CAISO assume in their economic evaluations of DPV2 that all energy will be bought and sold at spot market prices, and that no new generation will be owned or controlled by CAISO utilities. DRA bases its economic evaluation of DPV2 on modifications to SCE's base case and, thus, also incorporates these assumptions. However, DRA is concerned that both of these simplifications tend to overestimate DPV2 benefits.

The assumption that all energy is bought and sold at spot market prices credits DPV2 with price reductions for all energy sold, to the extent that DPV2 reduces spot market prices. DRA points out that, in reality, much of the utilities' energy needs are met by cost-of-service generation and by power contracts whose costs to ratepayers may be either partially or entirely insensitive to spot market prices.

We agree with SCE that calculating DPV2 benefits as if existing utility-owned generation is sold at spot market prices does not bias the calculated CAISO Ratepayer energy benefits. While the assumption of spot market prices for all utility-owned generation is incorrect, in the calculation of CAISO Ratepayer benefits the resulting (and also erroneous) increase in the utilities' producer surplus is passed on to ratepayers. Thus, the erroneous increases in consumer and producer surpluses due to utility-owned generation offset each other, with no net effect on the calculated CAISO Ratepayer benefit.

DRA is correct that, to the extent that CAISO-area load is served by new utility-owned generation, or through existing or new spot price-hedging contracts with merchant generators or non-CAISO area utilities, the assumption that DPV2 will decrease spot market prices for such power would overestimate energy benefits to CAISO ratepayers. This is because, unlike existing utility-retained generation, the resulting erroneously assumed increase in producer surplus is not included in the calculation of CAISO Ratepayer benefits and thus does not offset the erroneous increase in consumer surplus. The CAISO's inclusion of market power mitigation benefits for DPV2 amplifies these overestimations of DPV2 benefits in the CAISO's evaluation.

We recognize the inherent difficulties and imprecision in forecasting the nature of future energy sources and the pricing terms by which energy will be sold to CAISO-area utilities. Without knowing the extent to which these modeling simplifications overestimate DPV2 benefits, we consider this uncertainty along with other factors in assessing the likely economic benefits of DPV2.

e) Extrapolation of Energy Benefits After the Study Period

In calculating the value of DPV2 energy benefits, SCE, the CAISO, and DRA extrapolated benefits for the last year simulated and then discounted the future benefits to produce either a present value (SCE and DRA) or a levelized annual value (the CAISO). SCE and DRA modeled WECC system operation and DPV2 energy benefits from June 1, 2009, the anticipated in-service date, through December 2015, and then calculated energy benefits beyond 2015 assuming that annual benefits remain constant in real inflation-adjusted dollars.

Although DPV2 is projected to commence operations in mid-2009, the CAISO conducted its analysis of DPV2 for 2008 and 2013 because the SSG-WI database used in the CAISO's assessment had been developed for the years 2008 and 2013. The CAISO assumes a 1% real (adjusted for inflation) escalation rate for energy benefits after 2013, for the remainder of the assumed economic life.

We are not convinced that DPV2 energy benefits are likely to escalate at 1% in real terms each year after 2013, as assumed by the CAISO. The CAISO justifies this assumption based on expected above-inflation escalation of commodity prices and an anticipated replacement of coal by gas as the marginal electricity source that determines market prices. However, DRA and SCE forecast that, with operation of DPV2, the surplus energy from the Southwest that will displace higher-cost California generation will already be almost exclusively gas-fired, not coal-fired, during the studied 2009 - 2015 period. Additionally, continuation of DPV2 energy benefits beyond the study period is based in significant part on expectations that current locational differences in gas prices and gas-fired generator efficiencies are likely to continue, and that there will continue to be generation surplus in the Southwest and particularly in Arizona. On balance, we find that SCE's and DRA's view that annual DPV2 energy benefits are likely to remain constant in real terms is the more realistic assumption.

As indicated in a sensitivity calculation performed by the CAISO, use of an assumption that annual DPV2 benefits will remain constant in real terms after 2013, rather than escalate faster than inflation, would decrease the levelized energy benefits and benefit-cost ratios that the CAISO calculated for DPV2 by about 9%.

f) Contingency Analyses

The CAISO and DRA evaluated the economic impacts of several potential market conditions whose likelihood of occurrence may be too low and uncertain to warrant inclusion in benefit-cost ratios. Although individually unlikely, these contingency events could have a significant effect on the cost-effectiveness of DPV2 if they do occur. Such contingency analyses are useful in that they shed light on the extent to which DPV2 may provide insurance value for high-impact, low-probability events. They also examine downside risks that unexpected market developments may render DPV2 uneconomic.

For DPV2, the CAISO analyzed eight contingency scenarios representing major transmission or generation outages or additions. In these contingency cases, the CAISO used base-case (medium) demand, gas price, hydro, and market (bid markup) conditions. The impacts of these contingencies on calculated 2013 energy benefits are summarized in Table 10.

Table 10

CAISO Evaluation of DPV2 Energy Benefits in 2013

Under Specified Contingency Conditions

(Base-case Load, Gas Price, and Hydro Conditions)

($2013 Million)

 

Societal

Perspective

Modified Societal

CAISO Ratepayer (LMP Only)

CAISO Ratepayer (LMP + Contract Path)

Base-case conditions

$ 58.83

$ 77.43

$ 54.88

$ 193.50

Add 1,200 MW of gas-fired combined cycle at Palo Verde

85.01

114.52

127.58

291.87

Add 2,400 MW of gas-fired combined cycle at Palo Verde

91.39

122.45

184.03

338.52

Mountainview plant out of service

58.85

92.95

77.95

267.30

Mohave coal plant in service

73.68

96.21

104.22

242.96

San Onofre nuclear plant out of service

85.82

134.10

145.74

380.68

Pacific DC intertie out of service

63.80

84.73

51.92

214.81

10% lower transfer capability for Paths 49 and 66

61.53

80.65

99.59

123.99

Retirement of 3 units in SCE control area

56.51

74.11

43.75

191.39

Because the two versions of CAISO Ratepayer benefits reported by the CAISO only bracket expected benefits with some inaccuracy, the reported Societal and Modified Societal benefits are more instructive in our consideration of the CAISO's contingency scenarios. The Societal benefit provides an indication of WECC-wide energy savings with no market power mitigation attributed to DPV2, whereas the difference between the CAISO's Societal and Modified Societal results indicates market power reduction benefits that the CAISO attributes to DPV2.

The first two of CAISO's contingency scenarios consider the construction of new combined cycle plants in Arizona whose power could be transported over DPV2. It is expected that new gas-fired plants could be constructed with significant cost savings in Arizona. With assumed California-Arizona gas cost differences, these contingency scenarios indicate that access to this relatively inexpensive generation would provide significant energy benefits, with the first 1,200 MW plant increasing DPV2's Societal benefits by about 45%. It is informative, however, that DPV2 would provide only marginal additional energy benefits if 2,400 MW rather than 1,200 MW of new gas capacity is constructed in Arizona.

In three contingency scenarios, the CAISO considers generation reductions in SCE's service area, with the identified plants being out of service for the entire year. The additional benefits of DPV2 if the Mountainview plant is out of service appear to lie in its ability to thwart generators' exertion of additional market power, since the Societal benefits that exclude market power remain almost unchanged from the CAISO's base-case results. DPV2 would be more valuable during a complete outage of the San Onofre units.

In two scenarios, the CAISO considers transmission limitations. The value of DPV2 as insurance against an outage of the Pacific DC intertie or a reduction in the transfer capability of Path 49 (east of the Colorado River) and Path 66 (the California-Oregon intertie) appears limited.

DRA evaluates eight sensitivity and contingency cases, based on the Deterministic Reference Case that is a modification of SCE's base case. DRA reports the impacts of these contingencies on energy benefits for CAISO ratepayers for each year between 2009 and 2015. The average annual impacts of each of these contingencies are summarized in Table 11.

Table 11

DRA Evaluation of DPV2 Energy Benefits

Under Specified Contingency Conditions

(CAISO Ratepayer Perspective)

(2009 - 2015 Average, $2004 Million)

DRA's Palo Verde outage scenario assumes that all three Palo Verde nuclear units are out of service for the entire study period. DRA reports that this would reduce DPV2 energy benefits to CAISO ratepayers by about one-third, compared to the otherwise identical Deterministic Reference Case, as power flows out of California to the overall benefit of Arizona ratepayers. DRA's "no gas price differential" scenario assumes that there is no gas price differential between Arizona and southern California. This would reduce CAISO ratepayer benefits by about 14%.

In the Stirling Solar scenario, DRA assumes that a 1,000 MW Stirling solar dish installation interconnects at the potential Midpoint substation near Blythe. DRA reports that this would increase DPV2 energy benefits by about 66%, largely because the solar installation would provide most of its output during daytime peak hours when the value of power will be high and surplus generation in Arizona is likely to be low.

DRA's California Retirement Postponement case assumes that 3,108 MW of California generation that is slated for retirement between 2006 and 2015 is not retired during the study period but instead remains in service. DRA finds that this would produce a very slight increase in DPV2 energy benefits.

In the Alternative Arizona Expansion case, DRA replaces 800 MW of generic coal plant addition that SCE assumes will be added in Arizona in 2013 and 2014 to maintain needed reserve margins. DRA replaces this capacity with 850 MW of gas-fired peaking and cycling capacity, to assess whether new peaking and intermediate capacity in Arizona would be more beneficial than addition of baseload generation. This produces a very slight increase in projected DPV2 benefits. Finally, like the CAISO, DRA evaluates a scenario in which both San Onofre units would be out of service for the study period. DRA's analysis indicates that DPV2 energy benefits to CAISO ratepayers would increase by 61% with the San Onofre outage.

The CAISO and DRA contingency analyses complement the evaluations of more likely market conditions, and enhance our ability to assess the value of DPV2. More exploration of conditions that could adversely affect DPV2's cost effectiveness would have been helpful. However, the studied contingency events confirm that the energy benefits of DPV2 may be enhanced considerably if the availability of surplus energy in the Southwest is increased or, to a lesser extent, if supply is removed from California.

4. DPV2 Non-energy Benefits

SCE and the CAISO attribute certain non-energy benefits to DPV2 that they include in the reported benefit-cost ratios. SCE reports (see Table 1 in Section III.A.2.a) that inclusion of DPV2 in transmission revenue requirements will increase SCE's transmission revenues from wheeling and Existing Transmission Contracts by $28.1 million on a net present value basis. SCE also reflects that the energy savings realized due to DPV2 will reduce ratepayer charges for franchise fees and uncollectibles, a forecasted net present value savings of $13.0 million.

The CAISO's economic evaluation includes significant non-energy benefits, which are shown in Table 4 in Section III.A.2.b. The largest non-energy benefit reported by the CAISO arises due to system operational savings. The CAISO projects that DPV2 will avoid the need to start and run at minimum load substantial amounts of high-cost generating capacity in southern California that would be needed otherwise to protect against outage contingencies for major transmission lines or nuclear units. The CAISO explains that the resulting $20 million levelized annual benefit arises largely from avoidance of Minimum Load Compensation Payments to the uneconomic generators.

The CAISO also reports capacity benefits totaling $6 million per year for CAISO ratepayers and $12 million per year from the Societal perspective. These benefits reflect the CAISO's assessment of the value of the 1,200 MW of firm import capability added by DPV2. The CAISO assumes that capacity prices are capped at the cost of new peaking units. Based on its assessment that capital and fixed operating costs for a peaking unit are significantly less in Arizona than in California,11 the CAISO assumes that the cost benefit of constructing peaking capacity in Arizona would be split equally between the buyers and sellers of capacity. The CAISO decreases the maximum savings benefit by an additional one-third to provide "a more conservative estimate" of the capacity cost savings attributable to DPV2, and obtains a total $12 million annual benefit.

The CAISO finds that operation of DPV2 will yield a net reduction in transmission losses, producing $1 million of levelized annual benefits to California ratepayers ($2 million on a Societal basis). The CAISO also reports a reduction in nitrogen oxide (NOx) emissions costs, based on lower emissions by new combined cycle plants in Arizona compared to emissions of older plants in California. The CAISO calculates $1 million of levelized benefits, based on the emissions reductions and the assumption that the value of NOx credits will be higher in California than in Arizona.

We have concerns regarding the capacity value that the CAISO attributes to DPV2. While there currently is excess summer peak capacity in the Southwest, forecasted growth in that region is such that most, if not all, of the excess capacity would be needed to meet summertime needs in the Southwest by the time DPV2 is operational. In its updated evaluation of DPV2, SCE forecasts that no existing Arizona capacity would be available to provide firm capacity to California when DPV2 comes online. The WECC forecasts a regional reserve margin for the Southwest of 21% in 2008, declining to 19% in 2013. Thus, it appears likely that DPV2 would be able to deliver 1,200 MW of firm summer peak capacity to California only if additional capacity is built in Arizona for that purpose.

If additional capacity were to be built in Arizona to provide firm capacity to California, it is unclear whether peakers or combined cycle plants would be more economical. The DRA and SCE evaluations indicate that, while Arizona's existing capacity may be needed to meet local summer peaks by the time DPV2 comes online, Arizona is projected to maintain significant excess gas-fired capacity in winter that can be used to provide economical energy to California. The Southwest is expected to continue to have surplus low-cost generation in winter because winter peaks there are low compared to summer peaks. Because of this, both SCE's and DRA's analyses indicate that the bulk of DPV2's energy benefits would accrue in winter months, particularly in on-peak hours of winter months. Thus, a potential builder of new generation in Arizona would need to consider this competition for seasonal energy production in deciding whether to build new generation for export to California.

We recognize that difficulties in siting new generation in California, combined with cost differentials that may exist, may motivate generators to construct outside of California to meet California capacity needs. However, for the above reasons, we believe that it is speculative to assume that new power plants will be constructed in Arizona such that the full 1,200 MW transfer capability of DPV2 will be used to deliver firm summer peak capacity to southern California.

In summary, the CAISO's forecasts of the value of the non-energy benefits of DPV2 may be reasonable. However, we are not convinced that the full capacity benefit the CAISO attributes to DPV2 will be realized.

5. DPV2 Costs

a) Costs of Proposed Route and Authorized Route Alternatives

SCE provided cost estimates for its proposed route for the DPV2 project and for several alternative routes considered during the proceeding. No other party contested or presented evidence regarding SCE's cost estimates. As a result, we accept SCE's cost estimates for the DPV2 route alternatives authorized in this decision.

SCE's cost estimate for its proposed route for DPV2 is $577,663,000 in 2005 dollars, including pension and benefits, and administrative and general overheads. This cost estimate must be adjusted to reflect the authorized project route and route segments.

We find in Section IV that the West of Devers 230 kV upgrades included in SCE's proposed project are not feasible, and we authorize SCE to construct the Devers-Valley No. 2 500 kV line instead. Use of Devers-Valley No. 2 instead of the 230 kV upgrades reduces SCE's DPV2 cost estimate to $545,285,000. We authorize SCE to terminate the Devers-Harquahala 500 kV line at either the Harquahala power plant, as reflected in SCE's proposed project, or at a new Harquahala Junction that would shorten the route by five miles. SCE estimates that construction of Harquahala Junction would reduce costs by $24,080,000. In the vicinity of the Alligator Rock ACEC, we authorize SCE to construct DPV2 either adjacent to DPV1, as in SCE's proposed route, or using the Alligator Rock-North of Desert Center alternative. SCE estimates that the Alligator Rock-North of Desert Center route segment would add $8,952,000 to the cost of DPV2, including Allowance for Funds Used During Construction (AFUDC). While not provided by SCE, we estimate based on the amount of AFUDC in other SCE cost estimates that a comparable cost estimate for the Alligator Rock-North of Desert Center segment excluding AFUDC would be approximately $8,284,000.

b) Specification of Maximum Reasonable Cost

While the Federal Energy Regulatory Commission (FERC) ultimately will decide how much of the costs for this project SCE may recoup in transmission rates, we have jurisdiction pursuant to § 1005.5(a) and the responsibility to specify in the CPCN a "maximum cost determined to be reasonable and prudent" for the DPV2 project.

We adopt a maximum cost for DPV2 pursuant to § 1005.5(a) of $545,285,000 in 2005 dollars, including pension and benefits, and administrative and general overheads. This maximum authorized cost is decreased by $24,080,000 if the Devers-Harquahala line is terminated at Harquahala Junction. The maximum authorized cost is increased by $8,284,000 if the Alligator Rock-North of Desert Center route segment is used. These costs are in 2005 dollars. As SCE requests, in assessing compliance with these cost caps, SCE may deflate actual expenditures to their equivalent value in 2005 dollars using the Handy-Whitman Index of Public Utility Construction Costs.

SCE's cost estimates are based on preliminary design work. SCE requests that the Commission authorize it to seek additional cost recovery based on changes in cost estimates due to the adopted mitigation measures and mitigation monitoring program, final design criteria, and other factors.

We believe that SCE included sufficient allowance for contingency costs-almost 15%-to accommodate final design changes, as well as the adopted EMF mitigation, environmental mitigation, and mitigation monitoring program. The contingency budget may also be sufficient to accommodate possible routing changes in the Kofa and Alligator Rock areas, as discussed in Section IV.A. If, upon completion of the final, detailed engineering design-based construction estimates for the authorized project, SCE concludes that the costs will be materially (i.e., 1% or more) lower than the maximum cost we adopt, SCE should submit its updated cost estimate with an explanation of why we should not revise the maximum cost downward to reflect the new estimate. If SCE's final estimate exceeds the maximum cost we have adopted, SCE should seek an increase in the approved maximum cost pursuant to § 1005.5(b), at which time we will assess whether the cost increases affect the cost-effectiveness and need for the DPV2 project.

c) Effect of Route Alternatives on Cost-effectiveness of DPV2

SCE, the CAISO, and DRA based their economic evaluations of DPV2 on the project route proposed by SCE in its application. At the ALJ's request, SCE submitted late-filed exhibits indicating how construction cost changes associated with route alternatives would affect the parties' economic evaluations of DPV2.12 Because construction of the Devers-Valley No. 2 500 kV alternative would be less expensive than SCE's proposed 230 kV upgrades west of the Devers substation, this route alternative would increase the benefit-cost ratios for DPV2 by about 3.3%. Similarly, termination of DPV2 at Harquahala Junction in Arizona would be less expensive than the SCE-proposed termination at the Harquahala power plant, and would increase benefit-cost ratios by about 5.0%. SCE did not provide benefit-cost results for the Alligator Rock-North of Desert Center route alternative, but we estimate that this more-expensive alternative would reduce benefit-cost ratios by about 1.5%.

6. Discount Rates

Consistent with our determination in D.06-11-018, it would be appropriate to use SCE's most recently adopted weighted cost of capital as the discount rate in evaluating the benefits of DPV2. In D.05-12-043, the Commission adopted an 8.77% rate of return for SCE for 2006. In D.06-08-026, we granted SCE's request to waive a test year 2007 cost of capital application, so that the authorized 8.77% rate of return is also applicable during 2007.

SCE and DRA discounted future DPV2 benefits and costs to 2005 using a 10.5% nominal discount rate, stated to be SCE's most recently established incremental cost of capital. The CAISO discounted future DPV2 benefits and costs at a real discount rate of 7.16%, stated to equal SCE's weighted cost of capital. Assuming the long-term annual inflation rate of 2.28% used in SCE's assessment, this would equate to a nominal discount rate of 9.44%.

Based on the yearly DPV2 energy benefit and cost results that SCE reported in Exhibit 6, use of an 8.77% discount rate rather than a 10.5% discount rate would increase the CAISO Ratepayer perspective benefit-cost ratio that SCE calculated from 1.71 to 1.88, an increase of about 10%. The record does not contain comparable yearly results for the DRA and CAISO evaluations of DPV2. However, with use of an 8.77% discount rate, we would expect a similar percentage difference in the benefit-cost ratios found by DRA. It appears that the impact of an 8.77% discount rate on the benefit-cost ratios found by the CAISO would be less than 5%, since the discount rate it used was closer to the currently authorized rate of return.

7. Load Forecasts and Baseline Resource Plans

As we noted in D.06-11-018, the applicant's resource plan and assumptions about transmission and generation resources in other portions of the study area are important components of the economic evaluation of a proposed transmission project.

In its economic evaluation of DPV2, SCE used the system database it maintains for the Commission's long term procurement proceeding, but updated its forecasts for loads, natural gas prices, and available hydro generation. SCE included increased energy efficiency, demand response, and renewable resources sufficient to meet the State's renewables goals. SCE determined that generation should be retired based on published retirement dates, if a plant reaches a life of 55 years, or if retirement is planned due to air quality restrictions. DRA used SCE's resource plan and load forecast assumptions in its own economic evaluation of DPV2.

The CAISO modeled the transmission and generation system using the SSG-WI database, which the CAISO modified in consultation with SCE to improve its representation of the SCE system. The CAISO describes that it added generation resources to the SSG-WI database to reflect renewables goals in each state, and added new gas-fired generation, primarily combined cycle plants, in each of the WECC areas as needed to maintain at least a 15% planning reserve margin. The CAISO also states that it added a few new thermal units that were economically attractive after renewable and capacity adequacy standards were met.

No party takes issue with the load forecasts and resource plans used in the economic evaluations of DPV2. DRA calls attention to one difference between the baseline resource plans developed by SCE and the CAISO: the CAISO included series capacitor upgrades sponsored by the Salt River Project, referred to as the East of River (EOR) 9,000+ project. SCE's (and therefore DRA's) assessment did not include these upgrades. The effect of this exclusion is that the SCE and DRA assessments reflect a lower baseline transfer capability, potentially translating into higher energy benefits attributed to the 1,200 MW increase in transfer capability due to DPV2. However, DRA did not make a recommendation regarding whether SCE should have included the EOR 9,000+ upgrade in its baseline resource plan. In their economic evaluations of DPV2, no party assumed that construction of DPV2 would affect the resource plans in other respects.

B. Nonquantified DPV2 Benefits

Some potential economic benefits of DPV2 are difficult to quantify. Each of the three economic evaluations of DPV2 discusses certain potential benefits in qualitative terms. Most of the potential benefits discussed qualitatively by one party were addressed quantitatively by another party in its evaluation of expected energy benefits (mitigation of market power), non-energy benefits (operational and capacity values, value of reduced emissions and transmission line losses), or contingency value (effects of new generation east of Devers, emergency generation or transmission outages, and gas price fluctuations).

In addition, parties credit DPV2 qualitatively with potential benefits to the extent it allows earlier retirements of aging power plants, encourages fuel diversity, allows reserve sharing, and/or increases voltage support for Southern California. The parties' discussion of these potential additional benefits of DPV2 is useful in extending our attention beyond the limits of the quantitative analysis. We consider these factors in our consideration of DPV2's economic value, even though their potential benefits have not been measured.

C. Alternatives to DPV2 and the No Project Alternative

Our evaluation of whether SCE should be granted a CPCN to construct the DPV2 project would not be complete without consideration of alternative resources that could be added or other actions that could be taken in lieu of the proposed project. Additionally, in accordance with CEQA requirements, the Final EIR/EIS evaluates the No Project alternative. In essence, the No Project alternative examines impacts if the proposed project, or a variation thereof, is not approved and built.

1. Alternatives to DPV2

In D.04-12-048, the Commission directed SCE and the other investor-owned utilities to follow the loading order in the Energy Action Plan (EAP). The updated EAP II13 requires that the investor-owned utilities integrate all cost-effective energy efficiency into their resource plans. EAP II also requires inclusion of reasonable amounts of demand response and the procurement of renewable generation to the fullest extent possible. The Renewable Portfolio Standard (RPS) program as originally established required 20% of electricity sales to come from renewable sources by 2017, but that 20% goal has been accelerated from 2017 to 2010.

In D.04-12-048, the Commission found SCE's long term procurement plan to be reasonable, subject to revision to include energy efficiency targets as adopted in D.04-09-060 and demand response programs proposed for implementation in Rulemaking 02-06-011. In its economic evaluation of DPV2, SCE includes the resources that are in its long term procurement plan, with increased energy efficiency, demand response, and renewable resources sufficient to meet the State's RPS goals. We agree with SCE and the CAISO that additional development of energy efficiency, demand response, and renewable generation beyond the targets already set is not a feasible or cost-effective alternative to DPV2, as discussed more fully below.

In this proceeding, DRA and the CAISO assess possible development of combined cycle generation in southern California as an alternative to DPV2. The Final EIR/EIS suggests that new combined cycle plants could be built near the Devers, Etiwanda, and/or Valley substations.

DRA compares the addition of five 250 MW gas-fired combined cycle generators in California to construction and use of DPV2 to tap surplus generation from existing gas power plants in Arizona. DRA reports that ratepayers could finance construction of the California plants under 10-year power purchase agreements for approximately the same present value cost as the cost of building DPV2. DRA calculates that, with the new California gas generation, CAISO ratepayer benefits would be only 61% of the ratepayer benefits produced by accessing surplus Arizona energy via DPV2. DRA concludes that the alternative of investing additional capital in new California generation appears to be less preferable than building DPV2.

The CAISO compares the cost of building a new combined cycle plant in California with the cost of building a comparable new plant in Arizona to provide power to California using DPV2. The CAISO estimates that construction and operating costs for a combined cycle plant built in Arizona would be about 10% less than costs for a California plant. It finds that baseload power from such a plant in Arizona, delivered to California via DPV2, would be about 4% more expensive than power from a new gas plant in California, due to allocation of a share of DPV2 costs. The CAISO cautions, however, that its California combined cycle cost estimate does not include transmission or gas interconnection costs, which it could be substantial.

The CAISO submits that California needs to add 5,000 MW or more in the next five years due to load growth and generation retirement. In its opinion, both additional generation in southern California and inter-regional transmission upgrades including DPV2 should be pursued. SCE concurs with the CAISO that both generation and transmission options are needed, and submits that non-transmission alternatives could not meet all of the project objectives and/or could not be counted on to develop fast enough or in enough magnitude to avoid need for the DPV2 project.

We agree with SCE and the CAISO that there is need to pursue a range of resources, including inter-regional transmission, in-state generation, and other alternatives. In D.06-07-029, the Commission found that, in order to maintain adequate capacity and reserves throughout the state, 3,700 MW of new generation must come on line beginning in 2009. The required new resources are in addition to the expected investment in energy efficiency and renewable generation, and are in addition to planned transmission upgrades. As the CAISO points out, new or refurbished generating units are likely to be needed in southern California for reliability and operational purposes, but siting opportunities may be limited. At the same time, an expanded transmission system would increase access to competitively priced energy, provide more flexibility in operating the grid, and increase grid reliability. We conclude that, even with the emphasis on energy efficiency, demand response, renewable resources, and distributed generation, investments in both transmission and conventional power plants also will be needed.

As SCE and the CAISO describe, several potential transmission projects that could increase transmission transfer capability between California and the Southwest were evaluated. The STEP process screened alternative transmission upgrades and undertook technical and economic studies to develop a consensus expansion plan, which includes both DPV2 and upgrades to series capacitors for DPV1 and the Southwest Power Link. Based on SCE's and the CAISO's showings, we find that the range of potential transmission alternatives has been considered carefully and that DPV2 is the preferred new transmission alternative to provide access to lower-cost energy in the Southwest.

2. The No Project Alternative

Under the No Project alternative considered in the Final EIR/EIS, DPV2's 1,200 MW of transfer capability would not be added, and the existing transmission grid and power generating facilities would continue to operate. To serve the expected continued growth in electricity consumption and peak demand within California, additional electricity would need to be generated within California or imported into California by existing transmission facilities. In the No Project alternative, there could be supply-side actions, including accelerated development of conventional, renewable, and distributed generation, or other major transmission projects. Additional energy conservation or load management could also be pursued.

The Final EIR/EIS states that the continued operation of existing gas-fired turbine generators and construction of new generation and transmission lines would have long-term environmental impacts including substantial air emissions and ongoing noise near the generators, and visual impacts depending on the locations of new transmission lines and generators. The Final EIR/EIS does not find that the No Project alternative would be environmentally preferable to the Environmentally Superior configuration of the DPV2 project.

As we discuss above, because of both the magnitude of resource additions that are needed and the operational, system reliability, and other benefits that transmission upgrades such as DPV2 would provide, the No Project scenario is not a desirable alternative to the DPV2 project.

D. Discussion

The Commission must take into account a wide range of factors consistent with §§ 1001, 1002, 1005.5, GO 131-D, and other statutory and regulatory requirements in evaluating whether to authorize DPV2. As we explain in this section, there is adequate record support that SCE should be granted a CPCN for the DPV2 project.

As we describe above, SCE, the CAISO, and DRA performed separate economic evaluations of the DPV2 project, using different methodologies, assumptions, and scenarios. All three parties reach similar conclusions that DPV2 would be cost-effective for CAISO ratepayers, with DPV2 likely to provide significant economic benefits in excess of its costs over a wide range of market conditions. SCE reports a likely benefit-cost ratio of 1.71 from the CAISO Ratepayer perspective (Table 1). The CAISO finds that the benefit-cost ratio from the CAISO Ratepayer perspective will be between 1.25 and 3.34, and that the benefit-cost ratio from a Societal perspective is either 1.35 or 1.77, depending on whether forecasted market power mitigation benefits are included (Table 4). DRA's evaluation in its WES Reference Case finds a CAISO Ratepayer benefit-cost ratio of 1.31 (Table 5).

In addition to quantified economic benefits, the parties cite several other benefits as further support for their recommendations that the Commission authorize SCE to construct DPV2. In assessing need for the project, we must weigh the significant economic and other benefits that are expected to accrue against the undesirable environmental effects that DPV2 may cause.

In concluding that DPV2 should be authorized, the parties focus on the economic benefits that would accrue because of the 1,200 MW increase in the transfer capability between California and Arizona. Access to Southwest generation is limited currently by congestion over the transmission interfaces between southern California and the Southwest. The increased access that DPV2 would provide to less expensive generation in Arizona and elsewhere in the Southwest would allow higher-cost generation in California to be replaced and would reduce the cost of energy to CAISO ratepayers.

In Section III.A.3.a, we describe differences among the parties' production cost modeling of the energy benefits of DPV2. As we found in D.06-11-018, both the network model used by the CAISO and the transportation model used by SCE and DRA in this proceeding have strengths and weaknesses. While a network model such as used by the CAISO has the potential for greater accuracy in LMP-based markets, such a model has difficulties in modeling dispatch and congestion costs on inter-regional transmission projects like DPV2. This limitation reduces the precision of the CAISO's estimates of DPV2 energy benefits. As reflected in Table 4 above, the CAISO was only able to bracket expected CAISO ratepayer benefits with a wide range of uncertainty. At the same time, concerns have been raised regarding SCE's validation of the more simplified transportation modeling used in SCE's and DRA's evaluations of DPV2. In light of these concerns, we conclude that there is value in the use of both network and transportation models in evaluating DPV2. As TURN suggests, we have greater confidence in the results of the parties' evaluations since SCE, the CAISO, and DRA modeling efforts produce comparable and consistent results.

In Section III.A, we have identified several aspects of the economic evaluations that, individually, may tend to bias DPV2 benefit estimates either positively or negatively. There are several ways in which parties may have underestimated the likely value of DPV2.

First, natural gas prices have increased, particularly from the levels used in the SCE and CAISO economic evaluations. DRA found that DPV2 would be cost-effective if Arizona gas prices reach $5.00 per mmBtu in 2010 with a California-Arizona gas price differential in excess of $0.50 per mmBtu, or if gas prices reach at least $6.40 even with no California-Arizona price differential.

Second, SCE and DRA did not reflect that some producers may be able to markup bids above marginal costs in an exercise of market power. We agree that, by increasing the amount and diversity of suppliers with access to the California market, DPV2 will enhance competition and reduce the potential for generators to exert market power. While we are not convinced that the CAISO's market power estimations are reliable, it is clear that DPV2 would provide some amount of market power mitigation, with benefits to CAISO ratepayers.

In its WES Reference Case, DRA evaluated DPV2 benefits using only base-case market conditions. Due to asymmetry in how energy costs are influenced by variations in system conditions, consideration of the effects of volatility in factors such as loads, gas prices, and hydro conditions likely would yield a higher expected value of DPV2 energy benefits, compared to an evaluation of benefits looking only at expected market conditions. As an example, high gas prices have a greater effect on DPV2 benefits than would low gas prices, as illustrated in Table 8.

Additionally, the CAISO and DRA benefit calculations do not recognize that wheeling customers and entities with Existing Transmission Contracts would contribute to DPV2 cost recovery, or that revenue requirements for franchise fees and uncollectibles would decline due to energy cost reductions attributed to DPV2. Similarly, SCE and DRA evaluations do not include economic benefits arising due to operational benefits, emissions savings, or reduced transmission losses, as found by the CAISO.

Another source of potential underestimation of DPV2 benefits is that the discount rates that SCE, the CAISO, and DRA used are all higher than SCE's cost of capital. Consistent with D.06-11-018, use of a discount rate equal to 8.77%, the cost of capital authorized most recently for SCE in D.05-12-043, would increase benefit-cost ratios as reported by SCE and DRA by about 10%. An 8.77% discount rate likely would increase DPV2 benefit-cost ratios reported by the CAISO somewhat less than 5%.

Other choices in the parties' economic evaluations may tend to overestimate the value of DPV2. As discussed in Section III.A.3.d, the SCE, CAISO, and DRA evaluations assume that all energy is bought and sold at spot market prices, and that no new generation will be owned or controlled by CAISO utilities. These simplifying assumptions overestimate the value of DPV2 in decreasing spot market prices, to the extent that CAISO-area load will be served by new utility-owned generation, or by new or existing spot price-hedging contracts with merchant generators or non-CAISO area utilities.

As another concern, we are not convinced by the CAISO's assumption that annual DPV2 benefits will increase by 1% in real terms (adjusted for inflation) each year after 2013. As we describe in Section III.A.6, the more realistic assumption that annual DPV2 energy benefits will remain constant in real terms after 2013 would decrease the CAISO's benefit-cost ratios for DPV2 by about 9%.

Nor are we persuaded that the capacity benefits that the CAISO attributes to DPV will be realized, for reasons we discuss in Section III.A.6. With the expectation that generation capacity that meets the Southwest's summertime peak needs will continue to allow significant amounts of economical surplus energy to be available to California during non-peak periods, it is not clear that DPV2 will provide sufficient incentives to cause additional generation to be built east of Devers to provide firm capacity to California.

Finally, we note that the cost of DPV2 may change depending on routing choices and other factors, which would have a direct impact on the project's cost-effectiveness. As described in Section III.A.5, construction of the authorized Devers-Valley No. 2 route alternative is expected to increase benefit-cost ratios for DPV2 by about 3.3%. Termination of the DPV2 project at Harquahala Junction could increase benefit-cost ratios by about 5.0%, whereas use of the Alligator Rock-North of Desert Center route alternative could reduce benefit-cost ratios by about 1.5%.

Based on the parties' economic evaluations of DPV2 submitted in this proceeding, we conclude that DPV2 would provide significant economic benefits for CAISO ratepayers. It is our judgment that the described concerns about individual aspects of the parties' economic evaluations, taken together, strengthen rather than weaken this conclusion.

The benefit-cost ratios reported by SCE, CAISO, and DRA do not include certain potential benefits of DPV2 that do not lend themselves to economic quantification. DPV2 would expand the interstate regional transmission network and increase its reliability. With DPV2, the CAISO would have more flexibility in operating California's transmission grid and more options to respond to transmission and generation outages. Additionally, as indicated by several contingency scenarios reported in this proceeding, DPV2 would provide insurance value as an economic hedge against low-probability, high-impact events that could affect the availability and price of energy to southern California, including unexpected transmission and generation outages or increases in natural gas prices.

DRA voices a concern that the parties' economic evaluations do not reflect the possibility that there may be an unanticipated long-term trend away from recent system conditions, which DRA calls a paradigm shift. We agree that there is a risk that DPV2 would prove uneconomic due to unanticipated shifts in market conditions. However, DPV2 would also provide insurance value against other unexpected events that could greatly increase costs to CAISO ratepayers.

The record contains limited information regarding potential economic impacts of DPV2 in Arizona and other areas outside of California. SCE's 2004 economic evaluation shows negative energy benefits for Arizona (Table 3), such that Arizona electricity costs could increase slightly with DPV2's operation. However, SCE's evaluation assumes that no additional generation is built in Arizona to take advantage of the 1,200 MW of transfer capability added by DPV2. Nor does SCE's evaluation recognize that, with DPV2, the increased ability to pool resources could provide benefits to Arizona as well as to California. The increased transfer capability could be used to provide emergency support to Arizona as well as to California during unanticipated conditions such as the loss of a major generating facility or of another high-voltage transmission line, or during natural disasters. DRA's contingency scenario assessing a Palo Verde outage indicates the benefits of DPV2 to Arizona in that event.

In Section III.C, we determine that energy efficiency, demand response, and renewable generation do not hold sufficient near-term promise to provide a feasible or cost-effective alternative to DPV2. Nor would they offer the operational and other system benefits expected due to DPV2. New transmission and generation options, in addition to demand side resources, should be pursued to meet the need for new energy supply in southern California. We agree with SCE and the CAISO that DPV2 is the preferred new transmission project to increase transfer capability between southern California and Arizona.

As we describe in Section IV below, even with the mitigation measures made a condition of the CPCN, the DPV2 project would have significant unmitigable effects on visual resources, wilderness and recreation resources, cultural and paleontological resources, agriculture, noise levels, and air quality. Weighing the economic and other benefits that we expect DPV2 to provide and the identified environmental effects, we conclude that the substantial benefits expected due to DPV2 outweigh the environmental impacts of the project. We conclude that the DPV2 project is needed and in the public interest, and that we should grant SCE a CPCN to construct the DPV2 project, subject to the routing modifications and mitigation measures adopted in this decision.

9 As noted in D.06-11-018, while CAISO ratepayers include some non-jurisdictional entities, consideration of all CAISO ratepayers is an analytical convenience with minor effects on the economic evaluation.

10 On January 3, 2006, SCE and DRA submitted a joint recommendation in which, among other things, they recommended that the Commission find that DPV2 is needed based on its cost-effectiveness, and SCE withdrew its Phase 1 rebuttal testimony.

11 For simple cycle combustion turbines, the CAISO estimates that capital and fixed operating costs would be about 30% higher in California than in Arizona. This conclusion is based on assumptions that California has 43% higher labor costs, 67% higher land costs, and, accounting for most of the differential, air emission and water control technology costs that are more than triple the costs in Arizona.

12 We address DPV2 project costs in Section III.A.5 and DPV2 route alternatives in Section IV of this decision.

13 EAP II, a policy statement issued jointly by the Commission and the CEC, established a set of priorities for the energy policy for the State. See http://www.cpuc.ca.gov/PUBLISHED/REPORT/50480.htm.

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