Redacted Public Version BEFORE THE LOUISIANA PUBLIC SERVICE COMMISSION EX PARTE: APPLICATION OF ENTERGY LOUISIANA, LLC FOR APPROVAL TO REPOWER THE LITTLE GYPSY UNIT 3 ELECTRIC GENERATING FACILITY AND FOR AUTHORITY TO COMMENCE CONSTRUCTION AND FOR CERTAIN COST PROTECTION AND COST RECOVERY ) ) ) ) ) ) ) ) ) ) DOCKET NO. U-30192 REPORT AND RECOMMENDATION CONCERNING THE LITTLE GYPSY UNIT 3 REPOWERING PROJECT NOW COMES Applicant, Entergy Louisiana, LLC (“ELL” or the “Company”), and, pursuant to the Commission’s Order No. U-30192-B dated March 13, 2009, respectfully submits this Report and Recommendation Concerning the Little Gypsy Unit 3 Repowering Project (the “Repowering Project” or the “Project”). For the reasons explained more fully below, ELL recommends to the Commission that ELL (i) continue the temporary suspension of the Repowering Project; and (ii) make a filing with the Commission seeking a longer-term delay (three years or more) of the Repowering Project as well as appropriate accounting for the Project costs until the Commission can determine the permanent ratemaking treatment of these costs. A longer-term delay of the Project is appropriate given the uncertainty of various key factors that drive the economics of the Project, including but not limited to: 1) The sharp fall off in natural gas prices, both in the short term but also as projected for the long term by many industry experts, which affects the economics of the Repowering Project; Redacted Public Version 2) The implementation of various new federal energy policies, including a mandatory Renewable Portfolio Standard and other policies that may affect the economics of the Project; and 3) The uncertainties caused by the recent financial crisis and its effects on the U.S. and global economies. The longer-term delay will allow ELL to gain better clarity regarding these uncertainties and better understand the effects of these recent changes on the economic viability of the Repowering Project. This delay is consistent with the direction set forth in the Commission’s Order Nos. U-30192, dated March 19, 2008, to monitor the economic viability of this Project as part of the Commission’s Quarterly Monitoring Plan process. I. Introduction During the past few months, there have been dramatic and unforeseeable changes in the U.S. and world economies, the likelihood of various new federal energy policies, as well as a significant decline in the prices of various commodities, including natural gas and crude oil. While it is not possible to predict accurately what the future holds, the level of uncertainty associated with these issues causes concern and a need to pause when considering a commitment as significant as the Repowering Project. Recognizing these changes, the Commission, at the March 11, 2009 Business & Executive Meeting, issued an Order requiring ELL to suspend, temporarily and to the extent practicable, the current development of the Repowering Project.1 Specifically, the Commission adopted a Motion stating that: 1 Order No. U-30192-B, dated March 13, 2009. 2 Redacted Public Version There have been significant changes that have occurred relating to the Little Gypsy Repowering Project during the past few months, including the recent structural change in the market for natural gas, changes in the capital and financial markets, and the general state of the economy. Given these changes, I move that the Commission direct that Entergy Louisiana, LLC immediately suspend, to the extent possible, on a temporary basis, the Repowering Project and take the steps reasonably necessary to minimize project spending during the period of suspension. I understand that ELL has issued letters formally suspending certain contracts associated with the Repowering Project, and I also move that the Commission direct that these suspensions shall remain in place during the period of suspension. ELL is directed to continue to review the current economics of the Repowering Project and develop a recommendation regarding whether it is appropriate for ELL to make a filing with the Commission to formally delay the Repowering Project for an extended time. By no later than the April 2009 B&E session, ELL shall inform the Commission whether ELL intends to make such a filing.2 For the same reasons that the Commission noted in its Order, prior to the issuance of that Order, ELL proactively responded to the change in the risks and expected value of the Project by taking steps to minimize spending on the Project while the Company conducted further analysis with a view toward determining whether a longer-term delay of the Project would be in the best interest of customers. ELL’s analysis shows that, although there are certain risks associated with the continued volatility of natural gas, the expiration of vendor contracts, and the potential expiration of existing environmental permits for the Project, a longer-term suspension and delay of the Project is nonetheless appropriate and would be a prudent action by ELL. Since the Commission voted to certify the Repowering Project in November 2007, ELL has, as required by Order No. U-30192 and U-30192-A3, continually monitored the economics of 2 Id. 3 Redacted Public Version the Project to ensure that the Project would provide the benefits contemplated by the LPSC when it certified the Project. As part of the Commission-approved Monitoring Plan, ELL has performed and provided to the Commission, through its Staff, ongoing analyses concerning the projected net benefits of the Project to customers, using the latest information concerning a host of assumptions, including but not limited to the projected costs of natural gas, petroleum coke, coal, and carbon dioxide (“CO2”) regulation through allowances and/or taxes. As recently as the January 8, 2009 Supplemental Monitoring Report, the Project continued to show positive net benefits to customers when compared to the alternative of a CCGT facility. In the Monitoring Report for the Fourth Quarter 2008, however, which was submitted to the Commission Staff and the Intervenors on February 16, 2009, the Repowering Project’s economics, using the most recent assumptions, for the first time projected negative net benefits – indicating that the Repowering Project was projected to cost customers more than the hypothetical CCGT alternative on a net present value basis. At about this same time, on February 25, 2009, the LDEQ issued the final air permit for the Project, which otherwise cleared the way for ELL to commence on-site construction activities for the Project. In view of the recent adverse change in the projected economics of the Project and given the significant changes in the economy and the uncertainty created by the potential development of new and in some cases more aggressive federal energy policies under the new Administration, the Company believed that it would be appropriate to further evaluate whether continuing with the Repowering Project at this time would be in the best interest of customers. Thus, the Company undertook steps to minimize spending on the Project while further analysis was performed, including, on March 4, 2009, suspending all activity under three of the four largest 3 LPSC Order No. U-30192-A, dated July 2, 2008. 4 Redacted Public Version contracts relating to the Project, pursuant to the suspension terms of the contracts, and directing the vendor under the fourth contract to take substantial steps to slow the rate of spending. While ELL believes these short-term suspension steps will not immediately delay the in-service date of the Project if the Company ultimately decided to proceed with construction in the near term, the suspension of these contracts allows ELL to minimize spending while it further analyzes whether the Project continues to satisfy the objectives set forth in the Commission’s certification Order U-30192, dated March 19, 2008 given recent events. Since suspending its largest contracts and minimizing the work performed by the Project contractor, ELL has determined that it is in the best interest of customers that the Project be placed into a longer-term delay, that is, a delay of three years or longer. To implement such a delay, it will be necessary for ELL to cancel its current contracts and otherwise terminate the Project activities. However, if total costs to customers are to be minimized under a long-term delay, such steps are immediately necessary. In addition, as ELL will discuss in the last section of this report, a longer-term delay may require ELL to start over in some or all of the permitting processes. Further, if the Project is delayed for an extended period, there is a material risk that one or more permits would not be granted or would be granted subject to conditions that make the Project less attractive economically. 5 Redacted Public Version II. Summary of the Recommendation The Company recommends that the Project be placed in a longer-term delay in consideration of the significant uncertainty associated with this Project caused by the recent changes that have occurred in the commodity markets, the economy, and in U.S. energy policy. A longer-term delay will allow the Company to gain additional clarity regarding a number of these issues, thus mitigating the risk that the Project will not provide long-term benefits to customers. Perhaps the largest change that has affected the Project economics is the sharp decline in natural gas prices, both current prices and those forecasted for the longer-term. The prices have declined in large part as a result of a structural change in the natural gas market driven largely by the increased production of domestic gas through unconventional technologies. The decline in the long-term price of natural gas has caused a shift in the economics of the Repowering Project, with the Project currently—and for the first time—projected to have a negative value over a wide range of outcomes as compared to a gas-fired (CCGT4) resource.5 The proposed changes in various energy policies by the Obama administration also could have significant effects on the future economics of the Repowering Project. While this administration has only been in office since mid-January, it is becoming more likely that a Renewable Portfolio Standard (“RPS”) soon could be implemented. An RPS will require utilities such as ELL to incorporate various new technologies into their long-term resource 4 The acronym “CCGT” refers to a Combined Cycle Gas Turbine, which is a relatively newer gas-fired technology. 5 Prior to this time, the Project had consistently been expected to provide both fuel diversity benefits and positive net economic value on a present value basis relative to a CCGT. Although the LPSC recognized that the volatility of gas prices could cause the net benefits of the Project to become negative at times, all five of the Company’s prior filings (direct and rebuttal, July 2008 Monitoring Report, December 2008 Supplemental Report, and January 2009 Supplemental Report) pointed to positive net benefits. As such, this was the first time in which the fuel diversity benefit from the Project was expected to come at an additional cost to ELL customers. 6 Redacted Public Version portfolios, including the potential for baseload resources such as biomass facilities and various other intermittent resources such as wind or solar powered generation. The effects of an RPS could mandate that up to 25% of a utility’s total energy requirements be provided by renewable resources. Renewable resources are being evaluated by the Entergy System6 and will be a key consideration in the 2009 Strategic Resource Plan. With regard to CO2 legislation, while the Commission and the Company certainly anticipated that CO2 regulation would be in place over the life of this Project and incorporated CO2 compliance costs into its evaluation, there seems to be an emerging momentum to implement CO2 legislation during the next one to two years. If this occurs, it will allow the Company to gain much greater certainty regarding the cost of compliance with CO2 legislation and how it will affect the Project economics. CO2 costs, as the Company has always made clear, are an important factor in the Project economics, and while the possible implementation of CO2 legislation is not a reason to delay the Project, one of the benefits of the longer-term delay will be greater level of certainty regarding this cost.7 In addition, the changes in the U.S. and world economies have caused great turmoil in the capital markets. This turmoil has affected both the cost of capital and the timing of its availability. As the Commission is aware, in addition to the Repowering Project, ELL is engaged in the Waterford 3 Steam Generator Replacement Project, which is estimated to cost 6 The electric generation and bulk transmission facilities of the six Entergy Operating Companies are planned and dispatched as a single, integrated electric system, referred to as the “Entergy System” or the “System.” In addition to ELL, the six Entergy Operating Companies include Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. Entergy Arkansas, Inc. and Entergy Mississippi, Inc. have provided notice of their intention to terminate their participation in the Entergy System Agreement. 7 There have been recent updates suggesting that CO2 costs may be higher than expected at the time of certification. For example, the 2009 ICF Multi-Client Study reflects CO2 costs that are much higher than ICF predicted in the Multi-Client Study that was presented during the certification proceeding in this matter. A higher CO2 cost would adversely affect the Project economics. 7 Redacted Public Version approximately $511 million. ELL also is in need of acquiring additional CCGT capacity and expects to make various investments in its transmission system during the period of time that the Repowering Project is under construction. When engaging in a large project such as the Repowering Project, which will drive the timing of the need for capital, there could be a constraint in obtaining—at the time it is needed and at rates that are attractive economically—the capital that is needed to fund the Repowering Project as well as ELL’s other resource needs. Given the uncertainties in the economics of the Repowering Project, it would seem to be a more prudent use of capital for ELL to plan to fund these other projects and retain additional liquidity while delaying the Repowering Project until the additional clarity can be gained regarding the Project economics. These revised market outlooks, particularly the sharply lower gas price forecasts, and potential policy outcomes create significant uncertainty in the economics of the Repowering Project. The change in the long-term gas forecasts reduces the value of the fuel savings that the Company and the LPSC anticipated would be provided by the Project. Thus, the “small premium” that the LPSC contemplated could be associated with the Project relative to the cost of an alternative resource such as a CCGT could be much higher—a change from all prior economic analyses, even those performed as late as January 2009. On a more near-term basis, over the first five years of the Project, the net cost to customers of the Repowering Project was originally estimated to equal $145 million; however, the current analysis indicates the total net cost to customers over the initial five years of the Project has more than doubled and is approximately $350 million. Considered together, the uncertainties associated with the recent changes in the Project economics and market forces driving them, as well as the developments in the federal energy 8 Redacted Public Version policy and issues raised by the turmoil in the financial markets, suggest that ELL should delay the Repowering Project for a longer term (three years or more) in an effort to gain more clarity and certainty and allow ELL to better determine whether the Project reflects the lowest reasonable cost alternative for customers or whether other alternatives will be better suited to address customer resource needs. Accordingly, ELL recommends to the Commission that ELL make a filing seeking to delay the Project for an extended period of time. In recommending to the Commission that the Project be delayed for a longer-term, the Company is mindful of the Commission’s guidance in Order No. U-30192 that the volatility of natural gas prices could cause the net benefits of the Project to become negative at times during the construction schedule and that a significant part of the justification for the Project is the fuel diversity benefits it offers – benefits not available from a CCGT alternative. The recent structural change in the natural gas market, however, suggests that, across a reasonable range of assumptions, the economics of the Project will be negative relative to a CCGT. Thus, the small “premium” caused by short-term fuel price volatility that the Commission believed could be offset by the fuel diversity benefit provided by the Repowering Project appears, to be materially larger than reasonably could have been expected. A longer-term delay will allow ELL to determine whether the Project, in fact, represents the lowest reasonable cost alternative available to diversify ELL’s fuel mix to protect customers from volatile natural gas prices.8 8 Although this filing is made on behalf of ELL, it should be noted that these same factors also merit a delay in the decision of Entergy Gulf States Louisiana, L.L.C. (“EGSL”) to participate in the Project at this time. The Commission is considering whether to allow EGSL to participate in the Repowering Project as part of Phase 2 of this proceeding. 9 Redacted Public Version III. Recommendation As noted above, ELL bases its recommendation that the Project be delayed for a longerterm on the recent and significant changes in the Project’s economics. This report therefore begins by setting forth the details concerning the change in the Project’s economics and discusses the uncertainties raised by the current state of the economy and possible changes in federal policy under the Obama administration. Then, to ensure that the Commission is fully informed of the Project status and spending, the report discusses the current status in some detail. Finally, the report details the current status of the various environmental permits for the Project and the effect on these permits of a longer-term delay in the Project. A longer-term delay is likely to require ELL to seek new or significantly modified permit approvals for the Project, and ELL cannot know today whether such approvals will be obtainable or what conditions may be imposed. This risk is one that ELL has considered and the Commission must consider in deciding whether a longer-term delay of the Project is appropriate. A. Project Economics 1. Previous Economics The Repowering Project was undertaken in large part to add supply diversity to the ELL generation portfolio and reduce reliance on gas-fired resources. ELL’s generation portfolio was and continues to be weighted toward natural gas-fired resources. Relative to other utilities, ELL’s natural gas dependency is high. This dependency on natural gas-fired resources exposes customers to risk relating to changes in natural gas prices. Based on the information available at the time of the original decision to proceed, the Repowering Project was the lowest reasonable cost alternative for reducing reliance on natural gas-fired resources. The Commission 10 Redacted Public Version recognized in its Order approving the Project that the Project may result in a “small premium” for customers over its useful life relative to the cost of a CCGT resource – that is, that the cost of the Little Gypsy Repowering Project over its useful life ultimately could exceed the cost of a CCGT.9 Nevertheless, at the time that the Repowering Project was certified, the Company’s analyses indicated that it was more likely than not that the Repowering Project would be a lower cost alternative than a CCGT. The Company’s analysis did indicate that there was a risk that under certain sets of assumptions, the Repowering Project could become a more costly alternative than a CCGT. The Commission found, however, that the fuel diversity benefit provided by the Repowering Project was sufficiently important that the Project should be certified despite this risk.10 The positive economics of the Repowering Project continued through 2008, with each Monitoring Report and a supplemental report prepared by ELL reflecting benefits from the Project. These positive economics continued even though, in 2008, ELL was required to delay the Project in order to obtain additional environmental permitting. Because of then-increasing commodity prices and the additional financing costs for a longer construction period, this delay added to the cost of the Project, increasing the total cost, inclusive of AFUDC, from $1.55 billion to $1.76 billion. However, at this time, gas prices also were increasing and reaching record high levels. Thus, the July 2008 Monitoring Report indicated that the Repowering Project continued to be economic relative to the CCGT alternative. At that time, the Net Present Value of the Repowering Project relative to the CCGT was positive $236 million, similar to the benefit considered by the LPSC when the Project was certified. Gas prices continued to trend upward 9 See LPSC Order No. U-30192 (March 19, 2008) at 17, 24, 10 Id. at 24. 11 Redacted Public Version for the remainder of the Summer of 2008, further affirming the economics of the Repowering Project. 2. Economics Today Recent developments in natural gas market and resulting changes in projections for longterm natural gas price levels have decreased the value of the Little Gypsy Repowering Project since the Commission certification. Thus, while the Repowering Project would provide a physical hedge against high natural gas prices, there now appears to be significant uncertainty as to the value of this hedge relative to a CCGT alternative. Given current forecasts of natural gas prices, it now appears that the CCGT alternative may be more economic than the Repowering Project across a range of assumptions. ELL has prepared several economic analyses of the Repowering Project during the first quarter of 2009. Consistent with prior analyses, the Company used the PROSYM production cost modeling tool along with the current estimate of total Project cost, “sunk” costs, and assumptions about key inputs (forecasted natural gas prices, forecasted petroleum coke, and coal prices, etc.). These analyses compare the 40-year life-cycle economics of completing the Repowering Project with the alternative of canceling the Project and initiating a project to construct a new CCGT facility of equivalent capacity and utilization. The analyses follows the same methodology utilized by ELL in the prior viability analyses as well as the economic analysis presented in Exhibit APW-28 in the Company’s Rebuttal Testimony filed in October 2007 in Phase I of this proceeding. The table below reflects the results of the ongoing Project analyses. 12 Redacted Public Version Table – Results of PROSYM Economic Analyses At Points in Time ($’MM)* EFFECT ON TOTAL SUPPLY COST LG3 COMPARED WITH CCGT ($MM) Direct Testimony (July 2007) With LG3 Repowering Project Total PROSYM Fuel and Purchased Power Incremental Non-Fuel Revenue Requirement Total With Equivalent CCGT Total PROSYM Fuel and Purchased Power Incremental Non-Fuel Revenue Requirement Total Net Benefit / (Cost) of LG3RP over CCGT Less Value of Existing LG3 Unit Add: Committed Cost Net Present Value Rebuttal Testimony (Oct 2007) Quarterly Monitoring Report (July 2008) Supplemental Monitoring Report (Jan. 2009) Sensitivity ICF Fuel / Emission Outlook (2008 / 2009) Quarterly Monitoring Report (Feb. 2009) Current Analysis (March 2009) $81,821 $147,107 $166,300 $163,288 $166,900 $150,660 $155,267 $2,174 $83,995 $2,237 $149,343 $2,420 $168,720 $2,403 $165,691 $2,403 $169,303 $2,403 $153,062 $2,399 $157,666 $83,575 $149,093 $168,214 $165,027 $168,295 $151,964 $156,521 $514 $84,089 $594 $149,687 $694 $168,908 $691 $165,717 $691 $168,985 $691 $152,655 $792 $157,313 $94 $344 ($31) $94 $313 $188 ($31) $80 $236 $26 ($31) $220 $215 ($317) ($31) $243 ($106) ($408) ($31) $274 ($165) ($354) ($31) $291 ($94) * Values for direct testimony represent 25-year NPV. All other analyses reflect 40-year NPV values. The current economic analysis indicates that the Net Present Value of the Repowering Project relative to the CCGT is negative $94 million. That is, as compared to July 2008, the Project economics have deteriorated by $330 million even after taking increased committed costs into consideration. The decrease in projected Project economics between July 2008 and today is driven by an assumption of lower long-term gas prices. The July 2008 analysis assumed long-term gas prices of $9.07/mmBtu (2007$ levelized 2013 – 2036). The current analysis assumes long-term gas prices of $7.66/mmBtu (2007$ levelized 2013 – 2036). Although there has been some movement in other assumptions, which, in combination, partially offset the decrease in the gas prices, the reduction in gas prices of $1.41/mmBTU is the principal driver of the change in the overall projected 13 Redacted Public Version economics. The table below reflects the key assumptions used in the economic analysis and how those assumptions have changed over time.11 Table – Key Assumptions Used In Economic Analyses KEY ASSUMPTIONS (Levelized 2007$) Direct Testimony (July 2007) Rebuttal Testimony (Oct 2007) Quarterly Monitoring Report (July 2008) Supplemental Monitoring Report (Jan. 2008) Sensitivity ICF Fuel / Emission Outlook (2008 / 2009) Quarterly Monitoring Report (Feb. 2009) Current Analysis (March 2009) All in Fuel Costs for LG3 ($/mmBtu) 2013 - 2036 1.84 1.84 2.01 2.15 2.15 1.95 1.95 2013 - 2052 N/A 1.85 2.03 2.15 2.15 1.95 1.95 Henry Hub Natural Gas ($/mmBtu) 2013 - 2036 6.35 7.89 9.07 8.82 8.45 7.66 7.66 2013 - 2052 N/A 8.15 9.24 9.07 8.70 7.79 7.79 CO2 Emission Cost ($/ton) 2013 – 2036 10.33* 19.50 30.41 30.41 29.24 30.41 30.41 2013 – 2052 N/A 21.56 31.46 31.46 36.27 31.46 31.46 * Included in the fundamental analysis only. ICF International, a global professional services firm that is recognized as one of the leaders in providing expert opinions regarding the outlook with respect to fuel and emissions pricing, updated its long-term natural gas and CO2 emissions forecast in early 2009. ELL utilized ICF’s 2006/2007 Multi-client previous natural gas and CO2 forecasts in its Rebuttal testimony in October 2007 and, therefore, has presented a sensitivity analysis of the Project economics using the updated ICF Multi-Client information. As shown in the table above, ICF’s 11 The Table reflects the 40 year analysis period used to evaluate the Project economics. Because 40-year commodity price assumptions are not generally available to the Company, ELL simply trends the cost up at an assumed rate of inflation for the years not available through the forecast. 14 Redacted Public Version updated 2008/2009 forecast for CO2 emission cost is more aggressive than ELL’s forecast for CO2 costs on a long-term basis for the period extending through 2052. This higher forecast has a negative effect on the Project economics. It should be noted that, in one sensitivity analysis the Company has prepared, the Project continues to reflect a break even or possibly positive economic value. This scenario assumes that the fuel mix for the Project is 80% pet coke and 20% coal, instead of the 60%-40% fuel mix that the Company has used as the reference case in all of its analyses. Utilizing a fundamental analysis consistent with the methodology used in Direct and Rebuttal testimony, if the Project burned 80% pet coke, the net benefit would improve by approximately $160 million and would, therefore, approach breakeven or, based on the recent PROSYM, be slightly positive. ELL’s most recent analysis suggests that the Repowering Project may no longer be economic relative to a CCGT alternative and addresses the effects of new and significant uncertainties that have emerged in the wake of the current economic crisis and changes that are being contemplated in federal energy policies. Although the economic results of the Project analysis are based largely on the assumed price of natural gas, as discussed subsequently, it appears that it is not unreasonable to assume that natural gas prices will remain significantly lower than the historic highs experienced in 2008. This means that the Project could, in fact, be a relatively costly physical hedge against high natural gas prices, as opposed to the “small premium” that the Commission contemplated as the possible cost of this hedge when it certified the Project. Further, one must consider these economics in light of the uncertainties caused by the current economic and policy changes. 15 Redacted Public Version 3. Changes to the Early Year Project Economics In assessing the potential effect of a long-term delay on the relative economics of the Project, the Company has reviewed the projected customer savings benefit or cost (when negative) over the initial five years of the Project and has compared this metric to previous analysis. As shown in the table below, the net cost to customers over the first five years has increased significantly when compared to the October 2007 Rebuttal testimony analysis. Customer Benefits / (Costs) Over the First 5 Years of the Project ($MM)* Jan 09 July 07 0 -50 Direct w/o CO2* -226 July 08 Oct 07 Rebuttal Monitor Report -145 -147 Sensitivity Dec 08 Fuel / Monitor Emission Outlook Report Feb 09 Monitor Report Mar 09 -100 -150 -322 -335 -348 -403 -200 ƒ Over the initial five years of the project, the cost to customers has increased significantly compared to previous analysis. -250 -300 -350 -400 -450 * PROSYM analysis submitted in direct testimony did not include CO2 emission costs. * Based on PROSYM analysis. Whereas the net cost to customers was originally estimated to equal $145 million over the first five years, the current analysis indicates the total net cost to customers over the initial five years of the Project has more than doubled and is approximately $350 million. The Company recognizes this metric is not applicable when evaluating the overall life-cycle benefits of a 16 Redacted Public Version resource; however, similar to the upward trend seen in the following discussion of the breakeven natural gas price, the trend in this metric indicates there is more risk in relying on the back-end cost benefits of the Project to produce benefits over its life-cycle. The higher customer costs in the first five years of the Project life, stemming mainly from lower expected natural gas prices in these years, supports the rationale for a longer-term delay in the Project. Delaying the Project provides headroom by avoiding substantial costs during the periods when gas prices are projected to be lower, and the Project does not provide customers with total savings. 4. Recent Natural Gas Developments Until very recently, natural gas prices were expected to increase substantially in future years. For the decade prior to 2000, natural gas prices averaged below $3.00/mmBtu (2006$). From 2000 through May 2007, prices increased to an average of about $6.00/mmBtu (2006$). This rise in prices reflected increasing natural gas demand, primarily in the power sector, and increasingly tighter supplies. The upward trend in natural gas prices continued into the summer of 2008 when Henry Hub prices reached a high of $13.32/mmBtu. Since that time, natural gas prices have declined sharply, with recent Henry Hub prices $3.63/mmBtu (nominal).12 The decline in natural gas prices since the summer of 2008 reflects, in part, a reduction in demand resulting from the downturn in the U.S. economy. 12 NYMEX settlement for Henry Hub contracts for April 2009 17 Redacted Public Version Historical Natural Gas Prices and Volatility 16.00 14.00 Real 2006$/MMBtu 12.00 10.00 8.00 1996-1999 Mean = $2.92 6.00 1989-1995 Mean = $2.39 2000- May 2007 Mean = $6.02 4.00 June 2007- Feb 2009 Mean = $7.88 2.00 Ja n-0 9 Ja n-0 8 Ja n-0 7 Ja n-0 6 Ja n-0 5 Ja n-0 4 Ja n-0 3 Ja n-0 2 Ja n-0 1 Ja n-0 0 Ja n-9 9 Ja n-9 8 Ja n-9 7 Ja n-9 6 Ja n-9 5 Ja n-9 4 Ja n-9 3 Ja n-9 2 Ja n-9 1 Ja n-9 0 Ja n-8 9 0.00 However, the decline also reflects other factors, which have implications for long-term gas prices. During 2008, there occurred a seismic shift in the North American gas market. “Non-conventional gas” – so called because it involves the extraction of gas sources that previously were non-economic or technically difficult to extract – emerged as an economic source of long-term supply. While the existence of non-conventional natural gas deposits within North America was well established prior to this time, the ability to extract supplies economically in large volumes was not. The recent success of non-conventional gas exploration techniques (e.g., fracturing, horizontal drilling) has altered the supply-side fundamentals such that there now exists an expectation of much greater supplies of economically priced natural gas in the long-run. From 2001 to 2008, shale gas production in the lower 48 states increased from 1.1 billion cubic feet per day (BCF/D) to 6.1 BCF/D, an increase of more than 450%. 18 Redacted Public Version North American Shale Gas Source: PIRA 5. Breakeven Gas Price In order to assess further the implications of current gas price projections on the longterm Project economics, the Company has assessed the “breakeven” gas price for the Project over the course of the Project. The “breakeven” gas price is the gas price at which the economics of the Project would match those of a CCGT alternative, that is, the gas price that would give the CCGT alternative the same net present value as the Repowering Project. If the price of natural gas is expected to exceed the breakeven price, then the Project would be 19 Redacted Public Version economic (less expensive) relative to a CCGT alternative. If the price of natural gas is below the breakeven price, then the Project would be uneconomic (more expensive) relative to a CCGT. The breakeven analysis relies on a fundamental analysis consistent with the methodology used in ELL’s Direct and Rebuttal Testimony. The analysis indicates that, given current assumptions, including accounting for the Project’s sunk cost, the breakeven gas price is approaching $8.24/mmBtu (in real 2007 $s). In other words, the Repowering Project is economic relative to the CCGT only if gas prices average above this level on a real, levelized basis over the life of the Project. Below is a chart comparing the breakeven price of natural gas that is required to cause the Project to be economic relative to a CCGT alternative across several different points in time. Breakeven Gas Price ($/mmBtu) 10 9.55 Gas Price Assumption 8 10.06 9.28 8.87 9.06 6 4 8.89 9.06 9.52 8.67 ƒ Since the original economic viability analysis filed in direct testimony in July 2007, the breakeven gas price has increased while projected gas prices have come down 8.24 7.42 6.96 Breakeven Gas Before Accounting for Sunk Costs 2 0 * Breakeven Gas After Accounting for Sunk Costs July 07 Oct 07 July 08 Dec 08 Jan 09 Feb 09 Mar 09 Direct Rebuttal Monitor Monitor Sensitivity Monitor Report Report w/CO2* Fuel / Report Emission Based on fundamental analysis with Reference CO2 scenario Outlook Notes: 1. All gas prices quoted in real 2007 dollars. 2. Direct and Rebuttal Testimony based on 30-year fundamental analysis for 2012 – 2041. All other analysis based on 40-year analysis for 2013 – 2052. 20 Redacted Public Version As shown in the above chart, the analyses conducted over the course of the Project indicated that long-term gas price projections were above the Project’s breakeven gas price until early 2009. This relationship suggested that the Repowering Project was likely to be economic relative to a CCGT alternative in the long-run. In the current analysis, however, the relationship has reversed. The breakeven gas price is now above projected long-term gas prices. Moreover, the gap between projected long-term gas prices and the breakeven gas price is $0.45/mmBtu ($7.79 projected compared with $8.24 breakeven) in real 2007 dollars when including sunk costs and over $1.00/mmBtu when excluding sunk costs. The conclusion from the breakeven analysis is that one must believe that the levelized price of natural gas must remain higher than $8.24 (real 2007 dollars) over the life of the Project if it is to provide economic benefits to customers. In this case, however, as discussed previously, there is a reasonable basis to question this assumption due to the enormous potential of nonconventional resources and other forces that will help to lower natural gas prices. Thus, the breakeven analysis supports a longer-term delay of the Project. 6. Conclusions Regarding Economic Analysis The cost of the Repowering Project and that of other baseload generation alternatives are subject to significant uncertainties that can change materially their relative economics. In the case of the Repowering Project, a chief uncertainty is long-term natural gas price levels, but the Project also is influenced by the effects of potential energy, environmental and policy issues, which are discussed in the next section, and by whether the timing of this investment is appropriate given the current capital markets. As recognized in the Commission’s Order certifying the Project, “the cost-effectiveness of the Repowering Project remains very uncertain 21 Redacted Public Version because one cannot predict with certainty the ultimate cost of possible CO2 regulation and natural gas prices over the next 30 years.”13 At the time of the certification proceeding and through the beginning of 2009, the Project was expected to produce both fuel diversity benefits as well as net economic benefits relative to a CCGT supply alternative. Thus, the important fuel diversity benefit of the Project was expected, under most assumptions, to be economic relative to a CCGT alternative. Today, this conclusion is uncertain, and this uncertainty is the reason that ELL seeks a longer-term delay of the Project. Recent significant changes in the natural gas market and resulting structural declines in projections of long-term gas prices now make the expected economics of the Repowering Project less attractive relative to a CCGT alternative. Given the current cost of the Project and projected long-term natural gas prices, the Repowering Project does not appear to represent the lowest reasonable cost alternative for meeting ELL’s baseload needs at this time. Further, there are new risks to the Project’s long-term economics raised by the structural change in the natural gas market and ongoing economic crisis and emerging federal response and potential policy initiatives and timing, which were not knowable at the time of the earlier Project decisions. These new uncertainties pose additional risks to long-term electricity demand and supply requirements that suggest the timing of the Project should be reconsidered. Of course, it should be noted that it is not possible to predict natural gas prices with any degree of certainty, and ELL cannot know whether gas prices may rise again. Rather, based upon the best available information today, it appears that gas prices will not reach previous levels for a sustained period of time because of the newly discovered ability to produce gas through non-traditional recovery methods. Thus, the cost premium that the LPSC believed might be 13 Order No. U-30192 (March 19, 2008) at 28 (referring to testimony of Staff witness Matthew Kahal). 22 Redacted Public Version “small,” as stated in its Order,14 could be much higher. Under these circumstances, ELL believes that it is appropriate to delay the Repowering Project at this time and revisit this option in the future. C. Uncertainties that May be Resolved During the Longer-Term Delay Although changes in the natural gas market (and the associated changes in the expected future path of natural gas prices) is a key driver of the Company’s recommendation at this time, the ultimate economics of the Repowering Project are also a function of the outcome of a variety of additional factors, each of which is highly uncertain. These include the long-term effects of the current global recession on the demand for energy; the possible imposition of federallymandated RPS, which could change the structure of ELL’s portfolio and further depress the long-term price of natural gas; the sustainability of the long-term non-conventional natural gas supply, which is a key driver of the expected lower natural gas costs; additional clarity regarding the cost of CO2 compliance; the possibility of capturing lower long-term commodity costs in a future project; and, other factors. Continuing with the Repowering Project at this time would result in an irreversible investment decision based on the significant capital requirements associated with this Project, yet the resolution of the various uncertainties could produce scenarios in which the outcome of a decision to proceed would not benefit the Company’s customers. At this time, because of lower natural gas prices, the Commission and the Company have the ability to mitigate the effects of these uncertainties by exercising flexibility and delaying decisions that otherwise would result in irrevocable capital expenditures. Delaying a final 14 Order No. U-30192 (March 19, 2008) at 24. 23 Redacted Public Version investment decision can create value for ELL customers by providing time to clarify and resolve uncertainties, increasing the likelihood that the Project, if ultimately undertaken, will produce net benefits for ELL customers over its lifetime. For instance, during a two or three year delay period, ELL is likely to learn whether we are in a severe but short recession or a long-term period of slow growth; whether the U.S. Congress will pass RPS and/or CO2 legislation and, if so what the cost of compliance might be and the effect on ELL’s resource needs; and, the extent to which the development of North American non-conventional gas reserves will constrain domestic natural gas prices for an extended period of time. Greater clarity on all of these uncertainties, about which much will likely be learned over the next two to three years, will allow a better final investment decision to be made. Because it is reasonable to expect that at least some additional clarity regarding these key issues will emerge over the next few years, a decision to delay is reasonable and prudent. D. Capital Considerations As the Commission is no doubt aware, the United States and world are in the midst of a severe economic crisis. The capital markets have become increasingly constrained, and investors are charging large premiums to invest in bonds, even in the case of utilities, which traditionally have been considered so-called “safe harbor” investments. While ELL cannot know today how the financial turmoil will affect the funding of the Project, it is reasonable to expect challenges and possibly added cost, which would weaken further the Project economics. Given the uncertainties in the economics of the Repowering Project, it would seem to be a more prudent use of capital for ELL to plan to fund these other projects and preserve its liquidity for 24 Redacted Public Version unexpected events while delaying the Repowering Project until the additional clarity can be gained regarding its economics. ELL discussed issues involving access to capital in its Direct Testimony in Phase 2 of this proceeding. However, at the time of that filing, ELL did not know whether the current tightening of the credit markets would be sustained. It now appears that it could take several years for the financial markets to recover. The turmoil in the financial markets must cause ELL to consider the timing of investing in a capital project of the size of the Repowering Project given its uncertain economics and ELL’s need to fund a number of other large investments. ELL is engaged in the Waterford 3 Steam Generator Replacement Project, which was recently certified by the Commission, and is estimated to cost approximately $511 million. ELL also is in need of acquiring additional CCGT capacity and has opportunities currently available to it. ELL expects to make various investments in its transmission system during the period of time that the Repowering Project is under construction. On top of these capital needs, ELL must seek recovery for its costs associated with the 2008 Hurricanes Gustav and Ike. The current estimated cost of these storms to ELL is $390 to $405 million, and there is a need to fund the depleted storm reserve. Although ELL expects that it will be permitted to recover its prudently incurred storm costs, that recovery is not likely to begin until 2010, and ELL is, therefore, entering the 2009 hurricane season with no storm reserve and no funding in place for its outstanding storm costs. Taken together, the projects that ELL needs to complete and ELL’s need to ensure that it has adequate liquidity to address storm events counsel against undertaking an investment of the size of the Repowering Project at this time given its declining economics. 25 Redacted Public Version The longer-term delay of the Repowering Project will allow ELL to concentrate its financial resources on projects such as the Waterford 3 Steam Generator Replacement Project and on CCGT and transmission investment, all of which will provide benefits to customers. The delay also will permit ELL to resolve its cost recovery for Hurricanes Gustav and Ike. Given the uncertain economics of the Repowering Project, ELL believes that it is prudent to concentrate its resources on these other projects and preserve its liquidity for unexpected events until additional clarity can be gained regarding the economics of the Repowering Project. E. Potential Supply Options As part of the ongoing supply planning process and in light of the uncertainty associated with this Project, the Entergy System currently is pursuing the following initiatives to evaluate other supply options: • Renewable Resources – The Entergy System issued a Request for Information (“RFI”) for Renewable Resources to the market on March 31, 2009 in an effort to obtain information from third parties regarding the potential for the development of renewable generation resources in the area in which the Entergy System provides service. This information will prove valuable as ELL assesses the effects of a likely RPS as discussed herein and which technologies may be most appropriate to meet the needs of customers as well as the RPS. • Energy Efficiency – The System currently is pursuing various initiatives regarding energy efficiency, including fulfillment of a commitment in this proceeding to complete a study of the DSM potential in the areas served by 26 Redacted Public Version ELL and Entergy Gulf States Louisiana, L.L.C (“EGSL”).15 The role of DSM in long term planning also is included in the LPSC’s ongoing Integrated Resource Planning (“IRP”) Docket. Finally, demand response programs and time-of-use rates were piloted by EGSL in 2008 and will be further evaluated in 2009 as part of the second phase of the advanced metering infrastructure (AMI) pilot in Baton Rouge. • Long Term CCGT Resources – The System continues to evaluate opportunities for the procurement of long-term CCGT resources and, on March 31, 2009, posted notice that it intends to move forward with a longterm RFP for these resources. This RFP will include a self build CCGT option at the Company’s Ninemile site, which will be compared against other market alternatives. In addition, the System continues to be in discussions with various suppliers for resources that may provide compelling benefits to customers. IV. Status of Project Development and Spending ELL has incurred approximately $160 million of cost through February 28, 2009 on a life-to-date basis for the Repowering Project. ELL estimates that, should it cancel the Project, the total cost of the Project would be approximately $300 million, including actual spending and estimated contract cancellation costs, although the total cost could be higher depending upon when the contracts are cancelled. The portion of this figure attributable to contract cancellation 15 As previously discussed in testimony before the LPSC, DSM is not a substitute for the supply role that would be provided by the Repowering Project. However, it will help meet the Companies’ resource needs and may, with other initiatives, affect the total resource portfolio. 27 Redacted Public Version costs is only an estimate, as ELL must negotiate with many of the Project vendors in order to determine the actual cancellation costs. ELL has necessarily focused its discussions to date with vendors on issues surrounding the temporary suspension of the contracts; as such, ELL is not yet in a position to report on the status of the negotiation of cancellation costs for those contracts. ELL plans to begin canceling these contracts over the next few weeks and will be able to develop a complete cost estimate after it completes these cancellations and can determine the full costs to which it is obligated. During February 2009, the Company determined that, in light of the deterioration in the Project’s projected economics and other factors, including recent changes at the federal level, it would be appropriate to slow the rate of spending on the Project while further analysis was undertaken concerning the continued viability of the Project. During this time, the Company directed the Project Team to take necessary steps to minimize the costs incurred for the Project while also balancing the necessity of maintaining the projected in-service date. The Project Team analyzed the four largest contracts where the majority of dollars were being expended and identified discretionary steps that it could take to minimize spending during this period without immediately affecting the Project’s construction schedule or projected in-service date. The Project Team also suspended entering into any new contracts unless they were required to maintain the construction schedule. For those that were required to maintain the construction schedule, when feasible, the Project Team bifurcated the new contracts to enter into only the required portions and to defer the remainder. On March 4, 2009, as part of the above-described effort to slow Project spending, the Company instructed the Project Team to suspend substantially all activity under three of the Project’s four largest contracts in order to minimize cost. The terms of these contracts permit 28 Redacted Public Version ELL to suspend activity under the contracts for a limited period of time, as it deems necessary, without having to cancel the contracts and renegotiate new contracts if the Project were to move forward. In addition, as of early March 2009, work under each of these contracts had progressed to a point that suspension would not be expected to affect the construction schedule significantly. However, the maximum time that these contracts may remain under suspension ranges from three months to one year. If the suspension exceeds the maximum time allotted, the contracts accord the vendors a right either to cancel their contracts or require a renegotiation of terms. Suspensions longer than three months are therefore impracticable, as the resulting contract cancellations would require that new contracts be negotiated and priced with either the same or new vendors. Further, ELL is generally responsible under the contract terms for reimbursing incremental costs incurred during suspension. These incremental costs could include costs of storage, transportation to storage, and corrosion protection, among other items. In addition to the above efforts to suspend activities under significant contracts, ELL directed its Engineering, Procurement, and Construction (“EPC”) contractor, which is the principal contractor for the Project, to slow spending, including, specifically to do the following: • defer any planned personnel moves, site mobilization, or additions to the project team; • allow project team reductions for all personnel not listed as key personnel (reduction in key personnel must have ELL approval, per the contract); • continue requests for proposals and evaluations of pending purchase orders and subcontracts, but not to approve any additional subcontracts or purchase orders without ELL approval; • demobilize the site preparation subcontractor as required to limit activities to returning the site to an acceptable condition, and, further, to demobilize all personnel and equipment not required for this activity; and 29 Redacted Public Version • work with ELL to determine other cost control actions to reduce cost commitments and evaluate the requirements to maintain Work and Agency Orders that ELL suspends. ELL believes that it should manage the Project spending consistently with the objective of obtaining a longer-term delay and further minimizing costs to customers, unless otherwise directed by the Commission. Thus, ELL plans to take immediate steps to minimize spending further on the Project, including the termination and/or cancellation of current contracts with vendors. The timing of the cancellation of the contracts is important; in general, the sooner the contracts are cancelled, the lower the cancellation costs. The Project contracts have limited suspension periods, generally ranging from three months to one year, and contract provisions allow vendors to be compensated to maintain the suspensions. Thus, ELL must establish a timely suspension management plan. As part of this plan, ELL intends to cancel its contracts in April 2009. It is important to understand that the management of the Project spending and contracts would differ if the contracts were being managed with a view to being able to restart the Project in the next three months to one year and that, if the Project were to be restarted within this time, there could be additional costs beyond those contemplated by the current Project estimate such as, for example, storage costs and costs to treat and protect fabricated materials so that they would be available for use when the Project resumed. However, given the high probability that the economic viability of the Project will not materially improve over the near term and considering the need to minimize overall costs for ELL and its customers, ELL believes that it is appropriate to implement a longer-term delay and immediately begin the orderly winding down of Project activities 30 Redacted Public Version V. Status of Environmental and Other Permits ELL has obtained all major environmental permits required to begin construction of the Project. As detailed below, however, a delay in the Project places these permits at risk and may adversely affect the Project’s economics and technological feasibility in the event the Project were later re-initiated. Below is a list of the major environmental permits that it needs to commence construction, including the following: Type Permit Issuer Air Prevention of Significant Deterioration Permit To Construct Title V Operating Permit, including case-by-case Maximum Achievable Control Technology (“MACT”) analysis Title IV Acid Rain Permit Section 404 Dredge and Fill (“Wetlands”) Permit/Section 10 Rivers and Harbors Act Permit Section 401 Water Quality Certification Coastal Use Permit Louisiana Department of Environmental Quality (“LDEQ”) LDEQ Air Air Water Water Water Water Land Use Stormwater Control Permit/General Permit Coverage Project Approval LDEQ U.S. Army Corps of Engineers LDEQ Louisiana Department of Natural Resources (“LDNR”) LDEQ Lake Ponchartrain Levee Board In addition to the above permits, which have been obtained, additional permits – (i) for modifications to wastewater discharges (Louisiana Pollutant Discharge Elimination System 31 Redacted Public Version permit modification) and (ii) for the proposed post-combustion product landfill (solid waste permit) –must be obtained. These last two permits are not required to commence construction on the Project but would be required prior to operation of the new generating unit (for the wastewater permit) and prior to the start of landfill construction (for the solid waste permit). Importantly, a short-term or longer-term delay in the Project would affect the abovedescribed permits in a variety of ways. A short-term delay in the Project – lasting approximately 60-90 days – would affect only the Prevention of Significant Deterioration Permit To Construct. Specifically, if construction on the Project does not begin by May 30, 2009, an extension of the required start-by construction date included in the Prevention of Significant Deterioration Permit To Construct would be required. LDEQ originally issued this permit on November 30, 2007, and it expires on May 30, 2009 unless construction has begun or binding commitments to begin construction have been entered by that date. However, an extension of the construction start date requirement can be requested from LDEQ. Nonetheless, this is the most pressing deadline related to the environmental permits. A suspension or multi-year delay in the Project would affect the permits in other, more significant ways. ELL would be required to seek renewal of existing permits, permit extensions, or new permits for the Project, including new air permits. Moreover, it is possible that any extensions, renewals, or new permits would contain new provisions that would have a significant effect on the economics or technological feasibility of the Project. If it proceeds with implementing a longer-term delay in the Project, ELL would seek extensions or renewals of the permits, when allowed by law or regulation and when beneficial to continuing Project viability, but it is not possible to know whether such extensions would be granted or for what period of time. Thus, if a decision is made to delay the Project for an extended period, that choice should 32 Redacted Public Version be made with an awareness and acceptance of the fact that, as a result, ELL may be required to start over in some or all of the permitting processes. Further, if the Project is delayed for an extended period, there is a material risk that one or more permits would not be granted or would be granted subject to conditions that make the Project less attractive economically. In particular, and in addition to the effects described above, the longer-term delay of the Project would affect the various permits as follows: • Title V Operating Permit: LDEQ issued this permit initially on November 30, 2007 (without the MACT determination, which was added later as a modification). The permit expires on November 30, 2012 unless an application for renewal is filed on or before May 30, 2012. The permit also requires that construction begin within two years of permit issuance, or by November 30, 2009. ELL can request an extension of this deadline. • New Regulatory Requirements: ELL may be required to comply with new regulatory requirements relating to air emissions that become effective before the onset of construction or before permits are extended or renewed. Examples of these requirements are limits on the emission of carbon dioxide and other greenhouse gases, technological standards for mercury and similar emissions, and additional controls required by tightened national ambient air quality standards for ozone that may affect St. Charles Parish. In particular, a designation of St. Charles Parish as not in attainment of EPA’s new ozone standard could require LDEQ to deny an extension of the construction startdate requirement in the PSD permit in favor of requiring a new permitting process. • Wetlands Permit/Section 10 Rivers and Harbors Act Permit: The Corps of Engineers permit expires on February 28, 2014. ELL would require an extension to continue construction operations regulated by this permit after that date. • Coastal Use Permit: This permit expires on January 9, 2014. Extensions are not provided for this type of permit, so a new permit may be required if construction activities allowed by the permit are not completed by that date. The permit requires that “reasonable progress” continue to be made on the project during the life of the permit. If a new permit were required, new proposed regulations that would require the “beneficial use” of dredged materials could apply to the project, increasing mitigation costs. Recently, new issues have arisen regarding EPA’s jurisdiction over CO2 emissions. In the wake of the United States Supreme Court’s decision in Massachusetts v. EPA, EPA is 33 Redacted Public Version expected to publish a determination in April 2009 that CO2 emissions cause or contribute to an endangerment to human health and welfare. This “endangerment finding” is a condition precedent to EPA’s regulation of CO2 emissions from mobile sources, such as automobiles and trucks, under Title II of the Clean Air Act, § 201(a)(1). Once EPA makes the endangerment finding, the agency must then develop applicable emissions standards for mobile sources. These emission standards are not to take effect, however, until “after such period as the Administrator finds necessary to permit the development and application of the requisite technology, giving appropriate consideration to the cost of compliance within such period.” CAA § 202(a)(2). It is unknown whether the endangerment finding would have an effect on the pending permit; however, assuming that the Company was able to gain an extension of the PSD permit, if construction did not begin by the expiration of the extension period, and a new PSD permit was required after the promulgation of CO2 regulations, that permit likely would include CO2 limits or technology requirements that differ from those present under the existing PSD permit. 34 Redacted Public Version VI. Conclusion and Recommendation For the reasons set forth above, ELL recommends to the Commission that ELL (i) continue the temporary suspension of the Repowering Project; and (ii) make a filing with the Commission seeking a longer-term delay (three years or more) of the Repowering Project as well as appropriate accounting for the Project costs until the Commission can determine the permanent ratemaking treatment of these costs. Respectfully submitted, By: _____________________________________ Kathryn J. Lichtenberg, Bar # 1836 Karen H. Freese, Bar #19616 Matthew T. Brown, Bar # 25595 Michael J. Plaisance, Bar # 31288 639 Loyola Avenue Mail Unit L-ENT-26E New Orleans, Louisiana 70113 Telephone: (504) 576-4170 Facsimile: (504) 576-5579 ATTORNEYS FOR ENTERGY LOUISIANA, LLC 35 Redacted Public Version CERTIFICATE OF SERVICE I, the undersigned counsel, hereby certify that a copy of the above and foregoing has been served on the persons listed below by facsimile, electronic mail, hand delivery and/or by mailing said copy through the United States Postal Service, postage prepaid, and addressed as follows: Melissa Watson - LPSC Staff Attorney Melanie Verzwyvelt - LPSC Staff Attorney Louisiana Public Service Commission P.O. Box 91154 Galvez Building, 12 Floor 602 North Fifth Street Baton Rouge, LA 70802-9154 Donnie Marks – LPSC Utilities Division Louisiana Public Service Commission P.O. Box 91154 Galvez Building, 12 Floor 602 North Fifth Street Baton Rouge, LA 70802-9154 Tulin Koray – LPSC Economics Division Louisiana Public Service Commission P.O. Box 91154 Galvez Building, 12 Floor 602 North Fifth Street Baton Rouge, LA 70802-9154 Matthew Kahal Tom Catlin Exeter Associates 5565 Sterrett Place Suite 310 Columbia, MD 21044 Commissioner Eric Skrmetta Office of the Commissioner 100 Lilac Street Metairie, LA 70005 Commissioner James M. Field Office of the Commissioner District 2 – Baton Rouge 617 North Boulevard, Suite B Post Office Box 2681 Baton Rouge, LA 70821 Commissioner Lambert C. Boissiere, III Office of the Commissioner District 3 – New Orleans 1100 Poydras Street Suite 1020 New Orleans, LA 70163 Commissioner E. Pat Manuel Office of the Commissioner District 4 – Eunice 300 Bobcat Drive Post Office Box 928 Eunice, LA 70535 Commissioner Foster L. Campbell Office of the Commissioner District 5 – Shreveport One Texas Centre 415 Texas Street, Suite 100, 71101 Post Office Drawer E Shreveport, LA 71161 Mark D. Kleehammer Entergy Services, Inc. 4809 Jefferson Highway Mail Unit L-JEF-357 Jefferson, LA 70121 36 Redacted Public Version Katherine W. King J. Randy Young Lauren M. Walker Kean, Miller, Hawthorne, D’Armond, McCowan & Jarman, LLP P.O. Box 3513 Baton Rouge, LA 70821 Luke F. Piontek J. Kenton Parsons Gayle T. Kellner Cori M. Blache Roedel, Parsons, Koch, Blache, Balhoff & McCollister 8440 Jefferson Highway, Suite 301 Baton Rouge, LA 70809 John H. Chavanne Chavanne Enterprises 111 West Main Street, Suite 2B P.O. Box 807 New Roads, LA 70760-0807 Jennifer J. Vosburg Director of Regulatory & Gov. Affairs NRG Energy 112 Telley Street New Roads, LA 70760 Jill Witkowski Tulane Environmental Law Clinic 6329 Freret Street New Orleans, LA 70118 Ray Cunningham SUEZ Energy 1990 Post Oak Blvd., Suite 1900 Houston, TX 77056 Stephen W. Chriss Wal-Mart Stores, Inc. 2001 SE 10th St. Bentonville, AR 72716-0550 Eric J. Krathwohl Rich May, a Professional Corporation 176 Federal Street, 6th Floor Boston, MA 02110 Adam Babich Tulane Environmental Law Clinic 6329 Freret Street New Orleans, LA 70118 Cyrus S. Baldwin, Jr. Marathon Oil Company P. O. Box 4813 Houston, TX 77210-4813 New Orleans, Louisiana, this 1st day of April, 2009 ___________________________________________ 37