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Home My WebLink AboutSutton Glenallen Intertie Deliberative Process 1996O7/11/96 23:18 ID:CVEA FAK: PAGE 2 a COEPes VALLEY ELECTRIC a INC. P.O, Box 45, SmnaE ALASKA 99588 (907) 822-3211 FAX 822-5586 VALDEZ (907) 835-4301 FAX 835-4328 July 12, 1996 William R. Snell, Executive Director Alaska Industrial Development & Export Authority 480 West ‘Tudor Road Anchorage, Alaska 99503 Dear Riley: We have finalized the plans for an informational meeting to be presented by Dr. Robert Jacobsen of Advanced Power ‘Technologies Inc, (APTI). The U.S. Government has contracted with APTI to construct and manage the High Frequency Active Auroral Research Program (HAARP) located at the old Over-the-Horizon Backscatter Radar Site near Gukona, Alaska. Dr. Jacobsen, APT's program manager, is responsible for the project. The meeting will begin at 12 noon on Wednesday, July 31, at the Carriage House in Gakona with lunch hosted by Copper Valley [ectric Association. Following lunch, Dr. Jacobsen will provide an overview of the project status and expected completion schedule for the project, I have asked that he also provide an estimate of the power requirements of the project. Ir. Jacobsen will answer questions. Following lunch and the bricfing, we will proceed ta the praject site (a see the prototype antenna array and control modules. Dr. Jacobsen or one of his staf? will further explain the opcrational aspects of the project. At the conclusion of the tour, the mecting will adjourn. We would appreciate having an estimate of the number of State agency representatives who will be attending by Friday, July 19. You can either call me or my sceretary Jeanie with the information. | believe this meeting can provide valuable information to people working on the review of the Sutton ta Glennallen transmission line relative to the electrical requirements of the project. ‘The meeting will also provide useful information regarding the purpose and use of the project to advance man’s scientific knowledge and understanding of the aurora und the ionosphere. | hope that all the members of the Interagency Review Panel and the Governor, or some representative Serving the Copper River Basin and Valdez 7/12/96 11:22a O7/1196 23:18 ID:CVEA FAK: PAGE 3 Riley Snell July 12, 1996 Page 2 from his staff, will be able to attend. I also believe some of Commissioner Irwin's and your key staff would benefit from attending. If you have any questions, please give me a call. If you need any hotel accommodations, you should secure them carly as hotel space in this area is limited. Attached is a list of the hotels and a map directing the participants to the Carriage Tlouse. Yours truly, bff Plott Clayton | furless General Manager ce: Bob Evans Board of Directors w:\word\cdh\96-077jw.doc 7/12/96 11:22a _ ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY a> ALASKA @@e™ =ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 MEMORANDUM TO: David Ramseur Deputy Chief of Staff OfE h aii rnor FROM: Wi . Executive Director DATE: May 16, 1996 SUBJECT: Petro Star Valdez Refinery Generation Proposal CONFIDENTIAL -- DELIBERATIVE PROCESS On April 25, 1996, Petro Star Chairman and CEO Steve Lewis met with Authority staff to discuss the Valdez Refinery’s generation proposals. Three concepts were discussed in our meeting. Each has different implications for the proposed Sutton-Glennallen Intertie, as well as for the Copper Valley (CVEA) rate payers. The basic proposal (as presented) is for Petro Star to install 2 megawatts ( “MW” ) of diesel generation with sufficient backup generators to ensure nearly 100% self-reliability. Such a system would improve upon existing reliability at a lower cost and allow Petro Star to isolate itself from any connection to the CVEA electrical system. The generators would use an existing Petro Star petroleum product for its fuel supply. The generated energy would be used only for Petro Star’s operations. Current development schedules contemplate having the generating system in service by August 1996. Mr. Lewis advised that material orders, with a 30 day cancellation clause, had already been placed for the diesel units to allow for self generation to occur by the beginning of the fourth quarter of 1996. The project will likely be located on the refinery site and either owned outright by the company or leased from an independent power David Ramseur May 16, 1996 Page 2 producer (“IPP”); most likely Alaska Power Systems, selling power principally to Petro Star. The implications are: 1. Petro Star quotes a O&M cost savings of refinery operations of $600,000 per year with improved reliability. Qe The removal of Petro Star from the CVEA system may cause an increase of up to 1¢(+) per kilowatt-hour (“Kwh”) for CVEA rate payers since fixed costs would be spread over a smaller rate base. (Petro Star currently represents roughly 20% of the CVEA base load.) 3s As calculated in the Intertie Report, the Intertie Alternative benefit-cost ratio would drop substantially below 1.0. The Intertie would not appear to be feasible, all things remaining constant, when compared against other alternatives if Petro Star proceeds with this project and leaves the CVEA system. The second proposal being considered by Petro Star is to install a gas turbine at the refinery site. This arrangement would produce 5MW of power with 2MW used for self generation and the 3MW balance sold as firm energy to CVEA or Alyeska. This concept could be developed either independently or in cooperation with CVEA. The implications are: a. If CVEA participated in the project, some of CVEA’s diesel generation in Valdez could be placed on standby or retired. 2. Petro Star would have to make plant modifications to produce the gas turbine fuel. While initially causing higher capital costs, the long term result would be a new fuel product in the marketplace under competitive price conditions. 3h. Since the surplus power may be sold only to CVEA during the eight (8) months when Solomon Gulch is not providing power to CVEA (Four Dam Pool Power Sales Contract), the rate can be no greater than the CVEA avoided cost of 6.5¢ per Kwh. This could diminish the project economics for Petro Star considerably depending upon the initial capital cost of the gas turbine and its O&M costs. Alternatively, the surplus power could be sold to Alyeska should Alyeska be willing and the cost economical. 4. If the surplus power is sold at CVEA’s avoided cost, the impact on the rate payer would be similar to the base case analysis: If the surplus power can be delivered below avoided cost, the CVEA rate payer cost would be mitigated or even reduced. Mr. Lewis stated that CVEA would be delivering a gas turbine proposal to Petro Star for its evaluation within the next seven (7) to ten (10) days. Development schedules, permitting requirements and regulatory David Ramseur May 16, 1996 Page 3 approvals have not evolved as yet, but it is likely to take much longer to put in service. The third proposal which is conceptual only, is a much larger plant (30MW) at Valdez providing energy for the CVEA service area, Alyeska and into the Railbelt over the proposed Intertie. Considerations are: 1 To sell power into the Railbelt, the Intertie would have to be built. If power were wheeled from Valdez to the Railbelt, the existing distribution (intertie) between Valdez and Glennallen would also have to be improved. 2\s Wholesale power costs on the Railbelt grid are currently about 4¢ per Kwh for firm power and about 2¢ Per Kwh for interruptable energy. It is doubtful that a new plant in Valdez and the necessary Intertie construction and upgrades could be built at a cost which could provide wholesale rates, any time in the near term, which are price competitive with the Railbelt power sources. To properly evaluate this option the Intertie Feasibility Resources and Rate Payer Study (CH2M HILL) would have to be updated to include the new power plant. Furthermore, the analysis would require a much larger scope since retirements and load growth in the Railbelt would have to be evaluated in detail. Based upon our meeting, it is my belief that refinery economics alone will necessitate Petro Star to implement the basic proposal of 2MW of diesel generation. We should anticipate that this will occur by the fourth quarter of 1996 barring any permitting or regulatory approval problems. The pay back to Petro Star will be relatively quick allowing the Company to step out of self generation and into other arrangements should they prove economically attractive within 5+ years. ro mn In ae ibili Findin Inter-Agen Worki Groups Report of November 9, 1995 The Inter-Agency Working Group, having considered the CH2M HILL study and related information and subject to certain preconditions, adopted a finding on November 9, 1995, that the Intertie and the All Diesel alternatives meet the minimum requirements for economic feasibility under 1993 SLA CH 19, Sec. 4. The following were preconditions and conditions necessary for the finding of feasibility by the Working Group: David May 16 Page 4 Ramseur , 1996 Petro Star and CVEA/CEA Agreement A precondition for a finding of feasibility of the Intertie is that an agreement must be executed by the three parties guaranteeing that Petro Star remains a purchaser of energy for an adequate period of time to assure no negative rate impact to CVEA and CEA rate payers. In order to assure the long term revenues which are necessary for the Intertie feasibility, it is proposed that a_ credit enhancement be provided for Petro Star’s payment obligations. Alternatively, an agreement with a replacement or new energy purchaser of equivalent load would suffice to assure the feasibility of the MIntertie. Therefore, either a credit enhancement or the equivalent or greater energy purchase to replace Petro Star will be required. CEA/CVEA Agreement Since June 1995, CEA and CVEA have been considering joint participation in the Intertie. The General Managers have agreed on the principle economic terms of joint participation. The details would be defined in a Power Sales Agreement which would address funding for the supplementary cost, the energy delivery point, cost of operation and maintenance of the Intertie, and proportional sharing of the risk. The agreement would be intended to assure that CVEA and CEA rate payers have equitable minimal risk. The APUC will determine in their review and approval process the ultimate acceptability of this risk. As a condition to the approval of the State loan, an acceptable agreement must first be executed by the Boards of CEA and CVEA. Plan of Finance A financing plan was submitted with the 1994 feasibility study. As a condition for approval of the State loan, the Plan of Finance must be revised and approved incorporating the changes noted in the current study as well as any preconditions and conditions contained in these findings. Repayment Obligations The Intertie has significant legal, environmental, land, routing, community, and engineering issues which have not been resolved. These issues may be difficult to resolve within the economic constraints imposed by the precondition agreements between CVEA and Petro Star, and by the Plan of Finance. As a condition for the State loan, all costs of the Intertie, excluding legal costs which are not eligible State loan costs, must be repaid under agreed loan terms. This condition should apply even if the Intertie is not completed, unless the State were to revoke or substantially modify the terms of the authorizing State loan legislation. David Ramseur May 16, 1996 Page 5 The action by Petro Star clearly voids the one and only precondition of feasibility that was stated as absolute and necessary by the Working Group for a finding of viability for the Intertie. Without a cure or solution to the loss of Petro Stars’ load it is my opinion that the project would not be feasible under the findings required by statutes. NCLUST Petro Star's decision to self-generate has a clear and direct impact on the Working Group's qualified determination of Project feasibility. With the benefit of hindsight, Petro Star's self-generation decision confirms the validity of the conditions established in the November 9 determination. The current studies presented to the Working Group establish that, absent Petro Star's participation, the Intertie is not a feasible alternative. The change in circumstance, however, does not necessarily lead to a final determination that the Intertie Project is not feasible. Were Petro Star to contractually commit to return as a base-load customer once the Intertie is constructed (a commercially conceivable circumstance given Petro Star's short cost-recovery on the diesel self-generating capacity), the Intertie would remain feasible. Alternatively, the Intertie would be feasible if substitute customers or new development occurs -- although the immediate likelihood of currently obtaining binding commitments from such prospective Users is remote. The broader options under consideration by Petro Star are, in my opinion, unlikely to occur for a variety of economic and political considerations. Even if Petro Star elects to move forward in these options, the Working Group would need to undertake new analysis to understand the implications with respect to the determination of whether, and under what conditions, the Intertie is feasible. WRS:bjf h:all\bjf\wrs\petr-mem.doc ee: Mike Irwin, Commissioner March 29, 1996 Frew i Commissioner Mike Irwin Department of Community & Regional Affairs P.O. Box 112100 Juneau, Alaska 99811-2100 Dear Commissioner Irwin: We are in receipt of your letter of February 9 regarding the Sutton to Glennallen Intertie Project. In that letter, you established explicit conditions that Copper Valley Electric Association, Inc. (CVEA) must meet before you will complete project approval. These conditions are a significant departure from the charge given us by the working group and have significantly “raised the bar” the project must clear. By publicly asserting these explicit conditions, you have--perhaps unintentionally--rendered their achievement all but impossible. Let me explain. As you know, CVEA has been involved in diligent business negotiations with both Chugach Electric Association (Chugach) and Petro Star for some time. The goals of these negotiations were to achieve, in arms-length business transactions. two things which we believe are indeed critical to the economic feasibility of the intertie project: (1) the assured availability to CVEA of energy from the Railbelt area at a price that benefits both CVEA members and Railbelt ratepayers and (2) a contractual power supply agreement with Petro Star that benefits both the refiner and CVEA members and removes any incentive Petro Star might have to leave the CVEA system. We believe both of these goals can be met in prudent commercial transactions. Such transactions are common throughout the utility industry and. in this case, could be entered into for the mutual benefit of all parties. The entry of your directive into the mix of what until then had been equitable arms-length business negotiations based on pure economics has changed the entire balance and made equitable dealing impossible. In effect. the State’s edict has removed all incentive the other parties previously had to strike a mutually beneficial deal. Once Chugach learned that you have designated them a specific role in the project, the terms of our pending transaction changed totally. Chugach has acted as any prudent corporation would when Commissioner Irwin March 29, 1996 Page 2 handed an ace by the government--they have played it. Unfortunately. the new proposal Chugach has brought to the table is not remotely equitable nor in the best interest of our members. Negotiations with Petro Star have been equitable and fruitful: however. we are concerned that future negotiations could be adversely impacted if your conditions are seen as conditions precedent to project approval. Whatever the intent of your letter, its result has been to disturb two very promising private-sector negotiations. We believe that these conditions could well place us at the mercy of the other party as we continue to try to achieve a rational and mutually acceptable transaction. Commissioner Irwin, if you wish to achieve the best possible result for both Railbelt and Copper Valley consumers, we urge you to consider replacing your explicit February 9 directive with the following alternative. We urge you to follow another course of action. Only by these actions can you restore the level playing field to our business dealing with Railbelt utilities and our industrial customers. Only by these actions can you ensure that the most economically, rational business decisions impacting the intertie project are made. We propose that you: ie Replace vour specific directives of February 9 with the more flexible goals contained in the working group’s recommendation. Specifically. agree that two conditions necessary for the economic viability of the intertie are: (1) assured availability to CVEA of energy from the Railbelt area at a price which benefits both CVEA members and Railbelt ratepayers and (2) a contractual power supply agreement with Petro Star that benefits both the refiner and CVEA members. NN Negotiate in good faith with CVEA a Loan Agreement that works in these specific circumstances. We feel it would be fair and in keeping with the authorizing legislation to disburse the full principal amount of $35 million upon completion of the Agreement. The agreement could contain provisions that make the uncommitted balance due and payable at some time certain if the intertie has not been approved before that specified date. This is a simple course of action. It returns the details of the business transactions to the parties at interest by removing the State’s edicts that have made normal negotiations impossible. It provides CVEA with the standing in business negotiations that any other corporation would have under the circumstances. And. most importantly, it allows the private sector to establish, in negotiations with one another, whether the intertie in fact makes economic sense in the real world. Alternatively, if you wish to assure that the Sutton to Glennallen Intertie Project is never constructed, we urge you to say so, and we can get on with our primary purpose of serving our region. Due to the seemingly interminable studies, review. restudies, re-reviews, and postponed Commissioner Irwin March 29. 1996 Page 3 decisions, we are at a stage where we cannot continue to delay power supply questions that become more critical to our region every day. We do need a clear decision regarding the intertie. Commissioner, CVEA requests your early attention to this matter and a clear decision as a result of that attention. It is impossible to progress in either direction under the present circumstances. We ask you to be decisive in one of two ways: either levelize the playing field in some manner similar to our suggestion and let the economics of the intertie play out in private sector negotiations or cancel the intertie project. for better or for worse. but once and for all. CVEA’s next Board of Directors meeting will be April 17. If possible, a response to this letter by that date would be helpful for CVEA in making a final decision on this project. Sincerely, Paul Holland Board President cc: Senate President Drue Pearce Speaker of the House Gail Phillips Senator Georgianna Lincoln Representative Gene Kubina Representative Irene Nicholia Senator Bert Sharp Senator Tim Kelly Representative Ramona Barnes City of Valdez Jim Ayers. Governor’s Chief of Staff Riley Snell, Executive Director - AIDEA Roy Ewan, President - Ahtna Gary Brooks - IBEW Gene Bjournstad - Chugach Electric Jim Boltz - Petro Star w:\word\cdh\96-029jw.doe CONFIDENTIAL SUTTON-GLENNALLEN INTERTIE DELIBERATIVE PROCESS Current Status A. Additional work tasks undertaken to address earlier public concerns. Treatment of project subsidy (zero interest loan) for purpose of calculating rate payers cost of power. Verification and reliability of construction costs of all alternatives including risk. Further review of social/economic and environmental issues associated with each alternative. B. Following products will be added to the CH2M HILL updated feasibility report as technical memoranda. e Review of legal/contract issues surrounding Allison Lake’s interconnection to the existing Solomon Gulch project. = Throughput power from Allison Lake would currently require, under the Four Dam Pool Power Sales Contract, a 6.4¢ kWh generation charge. => There would be little or no commercial reason why the participating utilities of the Four Dam Pool would waive the throughput generation charge. Evaluation of cost estimates for Copper Valley Intertie and alternatives including construction cost risk analysis. Feasibility Update Independent CH2M 80th Percentile Revised HILL Base Cost Risk Adjusted Resource Cost Alternative 1993 $1000 1993 $1000 $1000 1994 All Diesel NA NA 55,924 “, Modified 1995 All Diesel 12,125 11,700 49,592 t, Intertie 47,604 49,800 64,227 2. Allison Lake 32,240 NA 55,606 * Silver Lake Option A 54,185 NA 68,109 6. Silver Lake Option C 39,635 37,400 56,895 S Valdez Coal 36,000 NA 83,962 7 => Based up CH2M HILL’s independent construction cost estimates and a risk analysis of the Feasibility Update construction costs, only Silver Lake construction costs are changed and are shown as Option C. All resource costs remain DRAFT unchanged from the Feasibility Update, excluding Silver Lake Option C. Silver Lake Option C now has a resource cost competitive with the most viable other alternatives. Comparative analysis of social/economic and environmental impacts, of the Intertie Project and its alternatives. => Intertie -- Most impacts understood and can be minimized by mitigation. Visual viewshed not easily mitigated, litigation likely. = Silver Lake Option C -- Impacts not understood but can be minimized by mitigation. Protected species and fishery impacts could result in litigation. = Modified 1995 All Diesel -- Local impacts only. Litigation unlikely. Rate payers analysis with $35.0 million applied to not only Intertie but other feasible B/C alternatives identified by resource modeling. Alternative VEA wer (cen rKwh All Diesel 10.82 / Modified 1995 All Diesel 10.23 Intertie 10.09 3 80/20 Integrated Intertie 9.24 Allison Lake 1063 ¢ Silver Lake Option A 10.78 &@ Silver Lake Option C 992 2 = The Integrated 80/20 Intertie provides the lowest cost energy to the CVEA ratepayer. Silver Lake Option C, adjusted for minimum stream flow requirements, has displaced the CVEA owned Intertie and the 1995 Modified All Diesel as the second lowest cost energy provider to the CVEA ratepayer. Requirement of APUC review and oversight of Intertie Agreements. CVEA’s Power Sales Agreement with Petro Star Valdez Refinery. Chugach Electric Association’s Wholesale Power Sales Agreement. Chugach Electric Association’s Participation Agreement for Intertie Construction. Analysis of business reasonableness of extending Petro Star’s Power Sales Contract from 10 years to 20 years. Il. Decisional Issues Regarding Involvement of CEA h:all\bjfiwrs\sut-glen.doc Page 2 DRAFT Is the Board of Directors of CEA committed to the Project and under what terms and conditions? Rate payer impact analysis -- membership and wholesale customers. Justification to APUC. Position of Board of Directors regarding use of Project Labor Agreement. Il. Decisional Issues Regarding CVEA A. All or nothing risk -- compromise project possibilities viewed as highly unlikely. B. Court challenge means delay and there are cost risks. C. APUC involvement in rate structure decisions -- distribution of benefits. D. PSV exit as base-load customer -- impact analysis. => If Petro Star ceases to purchase power from CVEA, the energy cost to the CVEA ratepayer will increase approximately 1.5 cents per kWh above the current levels. E: Option of other railbelt utility participation. IV. Labor Interest A. All or nothing risk -- compromise project possibilities viewed as highly unlikely. B. Jobs e For Alaskan’s e For Union Members - Project Labor Agreement e Construction start, earliest best case late 1997 e Most likely construction start 1999 e Battle for application of Project Labor Agreements V. Environmental Groups A. All or nothing risk -- willing to discuss compromise project. B. Stay pending court ruling -- in place. C. Throw project back to Legislature for further review and action. h:all\bjfiwrs\sut-glen.doc Page 3 DRAFT D. Want EIS scope to include environmental externalities analysis. Vi. Policy Issues A. State Energy Plan application. B. Good government and process issues. C. Highest and best uses of public funds issue. VII. Political Analysis A. David Ramseur and Pat Pourchot Vill. Recent Developments A. Attack on Project Labor Agreements. B. Issue of Alaska hire vs. dispatching from Lower 48 IBEW hiring halls. C. Petro Star relieved from take-or-pay commitment. Questionable whether or not company will remain on CVEA system as a base load customer. CVEA and PS are working on a plan to keep PS a customer. D. Tension and frustration evident among the project participants -- CVEAICEA. E; Question of power delivery capacity of proposed Intertie. = Energy capacity between Copper Valley and the Railbelt is independent of direction of energy flow. Energy flow could be enhanced by additional provisions in the design of the Intertie but such additions would be imprudent since energy flow to the Railbelt would not be economic in the near term. IX. Alternatives for Proceeding A. Finding of Feasibility e Proceed with issuance of loan commitment to CVEA with appropriate terms and conditions. B. Remand Project back to Legislature for further review and action. e Determine feasibility of Project, as authorized by Legislature, is inconclusive for determining least costs, best energy alternative for supplying power to the region. h:all\bjfiwrs\sut-glen.doc Page 4 DRAFT Cc. B/C and quantitative environmental analysis demonstrate that Intertie Project should not proceed without additional Legislative scrutiny. Flaws of enabling legislation will effect project participants with costly delays and legal expenses unnecessarily. = Three year delay will increase energy costs to CVEA ratepayers by approximately .4¢ per kWh. Business decision of Alyeska not to participate poses economic difficulties. = Forces conservative assumptions for further growth to avoid field of dream rate shock exposure to consumers. => Forces financial reliance on Petro Star Refinery or CEA’s customer base to achieve acceptable project economies. = Reliance on PSV necessitates that most if not all the project savings and benefits to flow to one industrial user. = Reliance on CEA exposes CEA retail and wholesale customers to rate increases while transforming most of the Project benefits to PSV. Further Study of two best alternatives, Intertie and Silver Lake. Assuming the state would not provide a zero interest state loan for diesel generators but would provide a loan for Silver Lake Option C, more detailed analyses could be undertaken on Silver Lake Option C. The purpose would be to raise the confidence level of the Silver Lake construction cost estimates and to raise the public, state, federal agency, and community awareness to allow identification of the critical environmental and social/economic impacts thereby placing the Silver Lake Option C on an equivalent basis to the Intertie. This would require the developer to proceed with the FERC permitting process, provide an actual conceptual design of the proposed project, and public meetings to determine the extent of comments to the project. X. Actions Required A. B. Finalize consultant analysis, including technical memoranda. Public meeting synopsis. Review original findings and recommended conditions from working group report. Changed conditions. DCRA Commissioner issues findings and decision. h:all\bjfiwrs\sut-glen.doc Page 5 TECHNICAL MEMORANDUM CHMHILL Cost Estimates and Risk Analysis for Copper Valley Intertie and Alternatives PREPARED FOR: Dennis McCrohan PREPARED BY: Dave Gray DATE: January 29, 1996 Summary This memorandum presents 1) CH2M HILL’s analysis of cost estimates for the Copper Valley Intertie and other power supply alternatives for Copper Valley Electric Association. (CVEA), and 2) risk assessment of the least cost alternatives and analysis of the potential impact of these risks on project cost and schedule for these alternatives. The power supply alternatives are: e All Diesel generation (including the “1994 All Diesel” and the “Modified 1995” alternatives) Intertie to natural gas generation in Alaska’s Railbelt region Allison Lake hydroelectric generation Silver Lake hydroelectric generation Valdez Coal cogeneration Cost Estimates Construction cost estimates for each alternative and operation and maintenance (O&M) cost estimates for one alternative with relatively high O&M costs (the All Diesel alternative) were evaluated. The cost estimates evaluated were presented in the Copper Valley Intertie Feasibility Study completed in 1994 (referred to as the “Intertie Feasibility Study”); these estimates were subsequently used in the Copper Valley Intertie Feasibility Study Update in 1995 (referred to as the “Intertie Feasibility Update”). Public comment on the Intertie Feasibility Update was made during meetings in held in the first week of December, 1995. A number of the comments made during these meetings reflected concern about the accuracy and consistency of cost estimates for the alternatives evaluated. This memorandum is intended to respond to these concerns. CH2M HILL reviewed the approach taken to develop construction cost estimates for each alternative and checked the consistency among these estimates. Risk analysis to test the probability of cost overruns was conducted for the least-cost alternatives. Summary results of the overall analysis are shown in Table 1. Original cost estimates for the various alternatives were either developed for the Intertie Feasibility Study or taken from other studies. Estimates taken from other studies were adjusted to 1993 dollars, as shown in the first three columns of Table 1. Adjustments CH2M HILL made to these SEA/1002C1F5.00C 1/30/96 1 estimates are reflected in the fourth column. Comparison between the third and fourth columns show that CH2M HILL generally accepts estimates made for the Intertie Feasibility Study. Table 1 Analysis of Construction Cost Estimates for Copper Valley Intertie and Alternatives CH2M HILL Cost Estimate/Review Intertie Feasibility Study Base Estimate Risk-Adjusted Estimates’ Original Cost Estimates 1993 in 1993 20th 50th 80th Dollars (000) Basis Year Dollars’ (000) Dollars (000) Percentile Percentile Percentile All Diesel 11,625° 1993 “41,625° 12,125 9,960 10,840 11,700 Intertie 47,604 1993 47,604 47,604 45,400 47,600 49,800 Allison Lake 30,937 1992 32,240 32,240 na na na Silver Lake Option A 52,496 1992 54,185 54,185 na na na Silver Lake Option C na na na 39,635 34,100 35,600 37,400 Valdez Coal 36,600 1993 36,600 36,000 na na na 1 Risk-adjusted estimates show the level at which actual costs have a given probability of occurring or be in below. For example, there is an 80 percent probability that the construction cost for the Intertie will be at or below $49.8 million. 2 These data were used in the Copper Valley Intertie Feasibility Update for resource cost and cost of power calculations. 3 Construction cost estimates for the All Diesel Alternative as defined in the 1994 Intertie Feasibility Study. CH2M HILL’s evaluation of CVEA’s diesel generation option concluded that 1) construc- tion costs included in the Intertie Feasibility Study are realistic and 2) replacement of CVEA diesel units would result in improvements in generation efficiency and continuation of O&M staff at existing levels. The conclusion regarding operations is consistent with the “Modified All Diesel” alternative evaluated in the Feasibility Study Update. Table 1 also shows costs for a new design proposed for Silver Lake (Option C). This estimate is based on a proposed design by Whitewater Engineering. Cost estimates prepared by Whitewater were evaluated and adjusted to the $39.6 million estimate shown in the table. Risk Assessment and Analysis Risk analysis of Intertie construction shows that the cost to build the project will not likely vary by substantial amounts from the cost estimate. As Table 1 shows, there is an 80 percent chance that the project will cost less than $49.8 million. Risk analysis for the All Diesel alternative indicates that construction costs will likely fall between $10.0 and $11.7 million; there is an 80 percent chance that these costs will be less than $11.7 million: This is about the same as originally estimated by R.W. Beck and slightly less than estimated by CH2M HILL. Two findings from the risk analysis of Silver Lake Option C have significant, but opposite, impacts on the economics of this project. First, it is highly probable that construction costs will be less than estimated by CH2M HILL. Second, the energy output from Silver Lake will not likely be as high as planned. That plan includes a reduction in instream flows during the summer salmon spawning season from about 450 cubic feet per second (cfs) to SEA/1002C1F5.D0C 2 5 cfs. It is likely that regulatory agencies will require 100 to 200 cfs be maintained. This will reduce usable output from the plant by 10 to 20 percent. Conclusions On the basis of these findings, CH2M HILL recommends that analysis included in the Feasibility Study Update not be further refined with the exception of including evaluation of the Silver Lake Option C in the benefit-cost analysis. Based on CH2M HILL/’s cost estimate and Whitewater’s planned output for Silver Lake, this project is one of the least cost alternatives. As shown in Table 2, it compares well with the Intertie and Modified All Diesel alternatives (assuming CVEA loads grow in the medium-low to medium-high range). However, risk analysis indicates that the cost of the project may be lower than estimated and that instream flow requirements for salmon spawning will likely result in lower output than planned. If the Silver Lake were to be built for only $35.6 million but output was limited to 85 percent of Whitewater’s plan, Silver Lake Option C would compare marginally less well with the Intertie: Low Fuel/ High Fuel/ Med. Low Med. High Load Fet. Load Fet. Present Value of Costs (1993$ * 10° Intertie 54,227 59,101 Silver Lake 57,369 61,870 Percentage Difference 5.8% 4.7% On the basis of data currently available, Allison Lake is still not considered as a realistic option because of the Four Dam Pool charge associated with this alternative. (The effects of this charge are not reflected in Table 2.) Following this summary are two sections. The first section contains a description and analysis of the cost estimate for each alternative. The second section is a risk analysis of three least-cost alternatives: the Intertie, the All Diesel, and the Silver Lake Option C alternatives. Each of the two sections begins with a brief review of the approach taken for the analysis in the section. SEA/1002C1F5.00C 3 TABLE 2 Present Value and Benefit-Cost Ratio for Power Supply Alternatives Med. High Med. Low Med. High Med. Low Alternatives Load Fet. Load Fet. Load Fet. Load Fet. Present Value of Costs ($000)*; 1994 All Diesel 60,483 55,924 67,632 61,697 Modified 1995 All Diesel 56,955 49,592 65,054 55,893 Intertie 56,088 54,227 59,101 56,603 Allison Lake ‘ 59,972 55,606 63,223 57,520 Silver Lake-Option A 69,911 68,109 71,056 68,701 Silver Lake-Option C 58,644 56,895 59,780 57,492 Valdez Coal 88,683 83,962 84,499 79,574 Savings Compared to Diesel ($000): 1994 All Diesel 0 0 0 0 Modified 1995 All Diesel 3,528 6,332 2,578 5,804 Intertie 4,395 1,697 8,531 5,094 Allison Lake * 511 318 4,409 4,177 Silver Lake—Option A -9,428 -12,185 -3,424 -7,004 Silver Lake---Option C 1,839 -971 7,852 4,205 Valdez Coal -28,200 -28,038 -16,867 -17,877 Benefit /Cost Ratio: 1994 All Diesel 1.00 1.00 1.00 1.00 Modified 1995 All Diesel 1.06 1.13 1.04 1.10 Intertie 1.08 1.03 1.14 1.09 Allison Lake ‘ 1.01 1.01 1.07 1.07 Silver Lake-Option A 0.87 0.82 0.95 0.90 Silver Lake--Option C 1.03 0.98 . LAs) 1.07 Valdez Coal 0.68 0.67 0.80 0.78 ‘Possible generation resources at Alyeska and Petro Star are excluded from this analysis due to lack of data on resource development costs. *M-H/M-L = Medium-High/Medium Low. Since the difference between the medium high and medium low forecasts is only the length of time Petro Star’s Valdez refinery is in operation, these forecasts are identical if Petro Star is assumed to leave the CVEA system. *1993 dollars based on a 4.5 percent discount rate. “Excludes 4-Dam Pool charge. SEA/1002C1F5.D0C Evaluation of Cost Estimates for Each Alternative Approach Evaluation of the cost estimates for each alternative was conducted through: e Review of reports and other documentation supporting each estimate. This review was performed by experts in the primary technology employed for each alternative e A formal request to the owner or developer of each project alternative for new information pertaining to the given alternative and review of information received. ¢ Aworkshop focusing on the various estimates and consistency among the estimates. Workshop participants included the individuals reviewing the cost estimate for each alternative, individuals who developed the original estimates, and cost estimating and risk analysis facilitators. A checklist was developed as a basis to evaluate the consistency of inclusion of specific cost elements in each estimate. Cross analysis was also conducted. e Analysis of information gained from the supporting documentation and the workshop. On the basis of this analysis, professional opinion was used to determine if adjustments to the cost estimates were warranted on the grounds of either their own merit or for consistency among the estimates. All Diesel Alternative Project Description Currently, diesel generators are being used at Glennallen and Valdez for generating and re- serve requirements above those met by hydroelectric generation at Solomon Gulch. These two sites each have seven machines, as shown in Table 3. The all diesel alternative assumes that Solomon Gulch and diesel generation would con- tinue to be used to meet CVEA generation and reserve requirements. Under this alterna- tive, several new units would be purchased to replace existing units at the time that major overhauls would otherwise occur. New generating units would be chosen as Caterpillar 3600 series engines. The choice of this supplier is intended to avoid support and supply problems exhibited with the existing En- terprise (recently) and Fairbanks Morse (historically) units. The size of engine to be pro- vided is set between 1,650 kW and 2,200 kW, presumably to support ease of installation and provide flexibility in load following. The addition of an additional engine generator at Glennallen can be accommodated with the existing building configuration—additional units would require expansion of facilities. There is presently no room for additions at the Valdez plant. Also, it is assumed that a 300,000-gallon fuel tank would be required at Valdez to supplement the current fuel system. Modifications to plant switchyard systems could certainly be required at either plant, due to the age of the present system and due to the demands of new generating equipment. SEA/1002C1F5.D0C 5 TABLE 3 CVEA Existing Diesel Generation Glenallen Capacity (kW) Valdez Capacity (kW) Unit 1: Fairbanks Morse 300° Unit 1: Fairbanks 600 1959 Morse 1966 Unit 2: Fairbanks Morse 300° Unit 2: Fairbanks 600 1959 Morse 1966 Unit 3: Fairbanks Morse 600 Unit 3: Fairbanks 600 1963 Morse 1966 Unit 4: Fairbanks Morse 600 Unit 4: Enterprise 1700 1966 1972 Unit 5: Fairbanks Morse 600 Unit 5: Enterprise 2500 1966 1975 Unit 6: Enterprise 2200 Unit 6: Enterprise 950 1975 1975 Unit 7: Enterprise 2200 Unit 7: Solar (Turbine) 2800 1975 1976 “Unit is no longer in service. Cost Estimate In the Intertie Feasibility Update, data on diesel generator costs were evaluated from two sources: the Intertie Feasibility Study and CVEA’s power supply study entitled Intertie Final Report, Evaluation of Power Supply Alternatives. Cost estimates included in the Intertie Feasibility Study were judged to be more realistic in this cost estimate review. Engine generator cost estimates developed for the Intertie Feasibility Study are shown in Table 4. TABLE 4 R.W. Beck Diesel Generator Cost Estimates Description Caterpillar 3606 (1993 dollars) Caterpillar 3608 (1993 dollars) Engine 749,560 883,875 Generator 80,500 107,500 Cooling System 50,930 67,540 Exhaust System 10,230 12,210 Air Start System 26,400 26,400 Fuel System 27,500 27,500 Station Battery 7,700 7,700 Switchgear 110,000 110,000 Total Equipment 1,062,820 1,242,725 Engine Cost/kW 592 527 Permitting, Site Prep, Engineering, Installation 255,077 298,254 Delivery 31,885 37,281 Contingency 159,423 186,409 Total 1,509,205 1,764,669 Cost per kW 937 821 $EA/1002C1F5.00C This estimate was performed at a preliminary level of detail, which is not unusual for a facility of this kind. The contingency amount shown is about 15 percent of equipment costs. Delivery is 3 percent of equipment costs, and permitting/site preparation/engineering/installation costs are shown as 24 percent of equipment costs. Costs included in the estimate that may be overestimated or may even not be incurred are: e Costs shown for permitting/site preparation/engineering/installation do not necessar- ily reflect the existing conditions at the sites. Provisions generally exist for new ma- chines, particularly if they replace existing machines. Air permits may be simply revised, site work may be minimal and engineering is limited to building and system changes (engine engineering is included in the purchase price). Installation is partially covered by engine support (provided by the supplier). e Switchgear costs assume upgrade and/or new equipment provided with the new ma- chines. Existing electrical systems may be sufficient, or require minimal changes, to support the new machines. Costs that appear not to be included in the estimate are: e Switchyard improvements are not shown; either site may require substation and other improvements, estimated by R.W. Beck at $550,000. e Engine foundation and structural support systems may not be adequate for the new ma- chines. The area provided for expansion (or developed for expansion) may require foundation preparation or piling to support the new machine. e Air shed capacities are limited at Valdez. Both plants operate above PSD limits and hence Title V air permit requirements apply. This could translate to air modeling and other air permitting work, triggered solely by the addition of modern equipment-the last machine was added at Glennallen in 1975 and at Valdez in 1976. CH2M HILL recommends the All Diesel alternative cost estimate be augmented as shown in Table 5. This cost estimate reflects installation of five 3608 CAT engines (as shown in 1995 CH2M HILL report) at Glennallen (2) and Valdez (3). It assumes retirement of Unit 6 at Glennallen and Units 4, 5 and 6 at Valdez, and relocation of Unit 7 at Glennallen to Valdez. This cost estimate also shows $500,000 in permitting costs, recognizing potential problems at both sites with air shed and permitting to Title V requirements. SEA/1002C1F5.D0C 7 TABLE 5 CH2M HILL Adjustments to R.W. Beck Capital Cost Estimates for All-Diesel Alternatives Cost (1993 dollars) Description R. W. Beck CH2M HILL Structures and Improvements 2,000,000 2,000,000 Engine Generator & Accessories 6,214,000 6,214,000 Substation/Transmission 550,000 550,000 Delivery 186,000 186,000 Total Direct Construction Costs 8,950,000 8,950,000 Permitting 0 500,000 Engineering & Design 1,401,000 1,491,000 Subtotal 10,441,000 10,941,000 Contingency 1,184,000 1,184,000 Total 11,625,000 12,125,000 Possible limitations to this cost estimate are as follows: e Fuel system changes have been discussed for the Valdez plant, but were not acknowl- edged for the Glennallen plant. Cost at either site may not be adequately addressed in the cost estimate. e Electrical substation improvements have not been defined at either plant. The allowance shown in the cost estimate may not be sufficient for both plants. Conclusion The engine generator cost estimates provided for this alternative are reasonable, and typical for projects of this type. However, they may not adequately reflect powerplant building changes, significant fuel system changes or electrical substation improvements, all of which could be required. Copper Valley Intertie Project Description The proposed 138-kV transmission line between the towns of Sutton and Glennallen would allow the Copper Valley Electric Association (CVEA) to purchase relatively low-cost power from the generating utilities of Alaska’s Railbelt region. The approximately 134-mile-long intertie project would connect CVEA’s 138-kV system to the 115-kV Matanuska Electric Association (MEA) transmission system. MEA is served by the Chugach Electric Associa- tion transmission grid which is interconnected with Chugach and Anchorage Municipal Light and Power gas-fired generation resources. $EA/1002C1F5.D0C 8 Cost Estimate Table 6 shows a summary of the cost estimate of the intertie prepared by R.W. Beck as part of the 1994 Copper Valley Intertie Feasibility Study. This estimate was intended to be an appropriately accurate representation of the total cost to develop and construct the project, so that fair economic comparisons can be made with the other power supply options. The estimate was based on investigations conducted by R.W. Beck and its consulting part- ners. The estimate was based on consideration of the electrical system impact, the preferred line route, and a specific construction concept. Dames and Moore. Inc., was responsible for the environmental analysis, and Power Technologies, Inc. (PTI) was responsible for the elec- trical system analysis. PTI modeled the Railbelt system with the CVEA system connected through the intertie. Numerous loading and system switch positions were used in com- puter simulations to determine the limitations imposed by the intertie. PTI found that with one Chugach 115-kV line segment out of service, CVEA loads above the planning load level of approximately 15 MW would require the addition of a Static VAR Compensator (SVC) at the new Sutton substation. To avoid the installation and the expense of the SVC, CVEA has elected to sever the intertie under these conditions and meet system load with a mix of available resources of including load shedding, if necessary. This approach is consistent with historic Railbelt utility practices. The R.W. Beck study includes estimates of the construction cost for four candidate line routes and recommends an “apparent preferred” route, as mentioned above. These esti- mates are both comprehensive and highly detailed. The analysis supporting the estimate begins with basic construction concepts and then uses numerous linked spreadsheets for the extension of material and labor costs. For example, the study considers the overall cost impact of several conductor types that meet the economic conductor size. The study also includes preliminary design of the strength, weight, and cost of several types of structures. The estimate itemizes the quantity and distribution of structure heights, span lengths, and construction assemblies, including insulators, nuts, and bolts, for each of the four distinctly different segments of the line route. The four line segments are referred to as structural Loading Zones that are distinguished by the weather exposure, terrain, vegetation, and soil conditions . Cost estimate contingencies are normally included to provide funds for additional costs that cannot be anticipated at the time of the estimate but could reasonably be expected. Such costs might include material and labor cost increases, changes during construction due to soil conditions, regulatory rule changes, or inadvertent design omissions. The R.W. Beck estimate includes contingencies that include all of these categories. SEA/1002C1F5.00C 9 TABLE 6 Copper Valley Intertie Cost Estimate Description Transmission Line Construction Structures Foundations Guys and Anchors Framing Conductor Right-of-Way Clearing Mobilization Subtotal Transmission Line Construction Substation Construction New Sutton Substation Bump Station No. 11 Substation Subtotal Substation Construction Direct Construction Cost Engineering Services Construction Management Environmental Services and Permitting Right-of-Way Acquisition Owner's Costs Subtotal Contingency Total Cost Cost (1993 dollars) 7,717,699 7,598,190 1,226,521 2,642,195 6,503,487 2,792,960 1,284,405 30,765,457 1,824,316 1,793,903 3,799,130 34,564,587 3,337,900 2,159,352 1,405,000 713,000 1,360,392 43,540,231 5,245,036 47,604,356 ‘Preferred Route Alternative D. SEA/1002C1F5.D0C 10 Evaluation of Cost Estimate The Power Engineers study of 1993! developed a total Intertie project cost estimate (1993 dollars of $40,428,919 compared with the R.W. Beck total of $47,604,356). Power’s estimate appears to be somewhat less comprehensive and somewhat less detailed in itemizations. Because the line routes assumed by the two estimates are different?, differences occur in right-of-way clearing, access, and judgments of construction efficiencies. The assumed design configurations for both estimates are similar. However, several design assumptions make the Beck estimate higher than that by Power Engineers. First, because of access problems at the existing O’Neil Substation, Beck determined that the Sutton terminus would require a new substation some distance from the old substation. Second, Beck assumed a somewhat larger and stronger ACSR conductor (605 kcmil Teal) compared to the conductor (556 kcmil Dove) that Power used in their estimate. These design differences probably account for approximately $1,000,000 of the estimate difference. A large difference also appears in Right-of-Way acquisition while Beck estimates $2,118,000 and Power estimates $449,000; a $1,669,000 difference. Beck included an Environmental Impact Study that was not anticipated as necessary by Power at the time of their estimate. Beck included 12 percent for overall contingencies (construction and other cost) while Power included 10 percent. This difference accounts for or about $1,000,000 of the difference between the Beck and Power estimates. The Beck contingency includes 15 percent on direct construction costs and 10 percent on other costs. A 10 percent contingency on construction is often appropriate for projects that are designed and ready for bidding. However, because the geotechnical survey and detailed design has not been completed for this project, and because the foundation work is such a large part of this project, the Beck 15 percent contingency on construction is appropriate. Adding the above estimate differences to the Power estimate brings the Power estimate to about $45,000,000 which is within 5 percent of the Beck estimate. During public meetings regarding the intertie in early December 1995, two questions were raised about specific aspects of the intertie cost estimate. Answers to these questions are: Helicopter costs : R.W. Beck includes the use of helicopters in their construction estimate where they are either required or economical to use. Beck estimates 683 hours at $239/hr for a Bell personnel helicopter and 573 hours at $3000/hr for a heavy-lift Vertol 107-2 heli- copter. Comparison with other 115-kV or 138-kV Construction Projects in Alaska: The Beck estimate divides the line route into four loading zones that result in differing costs per mile depend- ing on the construction, terrain, and access constraints. These costs are $227,000/mile for Zone 1, $223,000/mile for Zone 2, $245,000/mile for Zone 3, and $377,000/mile for Zone 4. These costs compare favorably with actual costs that were incurred for other projects with similar construction conditions in Alaska. 1 Power Engineers, Sutton to Glennallen 138kV Transmission Intertie Project, Volume 2, Final Report, prepared for the Copper Valley Electric Association, Dated January, 1993. 2 The Beck and Power Engineers routes are similar over the western-most 40 miles. At Syncline Mountain, the route assumed by Power Engineers travels to the south and that assumed by R.W. Beck travels to the north. From that point to the east end of the project, Beck's route remains 2 to 5 miles to the north of the Power Engineers route. The Power Engineers route runs just to the North and parallel to the Glenn Highway. SEA/1002C1F5.D0C an) Given that the two estimates are for different line routes, these estimates are considered to be comparable. Conclusion The R.W. Beck estimate is an adequate and credible representation of the itemized and overall Intertie costs for the purpose of economic comparison with other power supply options. Allison Lake Hydroelectric Project Alternative Project Description Allison Lake is located about 2 miles southwest of Solomon Gulch Reservoir. The Allison Lake Project evaluated in the 1994 Intertie Study and the 1995 update, would divert water from Allison Lake to the Solomon Gulch Reservoir during the winter months in order to provide additional generator at the Solomon Gulch Project. Several design options at Alli- son Lake were reviewed in the Allison Lake Reconnaissance Study, prepared by HDR Engineering, Inc. (HDR) in September 1992. The preferred option identified in this study consists of an 11,950-foot-long tunnel from Allison Lake to the Solomon Gulch Reservoir, a lake tap approximately 2,100 feet below the surface of Allison Lake, and a 3,145-kW hydroelectric generation facility located at the discharge from the tunnel into the Solomon Gulch reservoir. Water would be withdrawn from Allison Lake, flow through the tunnel, and then pass through the generation facility and discharge into Solomon Gulch Reservoir. This water from Allison Lake would then be available to provide additional generator at the existing Solomon Gulch generation facility. The total expected average annual energy to be produced from the new powerhouse plus the increased production from the existing Solomon Gulch facility was estimated to be about 27,400 MWh. Another alternative, that would not require the passing of Lake Allison water into the Solomon Gulch reservoir or any other modifications to the Solomon Gulch hydroelectric project, would be a stand-alone project on Allison Creek. The U. S. Army Corps of Engi- neers studied such a project in 1981 and their construction cost estimate was subsequently updated by HDR in 1992. The project would consist of an Allison lake tap and a combina- tion of tunnel and pipeline to convey water down to a new powerhouse on Allison Creek just above its mouth near sea level. The estimated project cost was substantially higher than the preferred option ($53,666,932 in 1992 dollars) and the expected average annual energy was assumed to be somewhat lower (25,900 MWh). Currently the Alaska Business and Industrial Development Corporation (ABIDC) holds a FERC Preliminary Permit to study a standalone project on Allison Creek. The project con- cept is similar to that studied by the Corps of Engineers in 1981 except for the following: e A trench and siphon intake would replace the lake tap. e The water would be conveyed down to the powerhouse by pipeline only, rather the tunnel /pipeline combination. ABIDC is currently proposing a 5-MW installation at this site. A cost estimate has not been prepared by ABIDC. seA/1002C1F5.00¢ 12 Cost Estimate Table 7 provides a summary construction cost estimate for the Allison Lake project. It is a summary of a more detailed cost estimate prepared in 1992 by HDR as part of their Allison Lake Reconnaissance Study. Table 7 Allison Lake Project Summary Construction Cost Estimate i Land and Land Rights Structures and Improvements Reservoirs, Dams, and Waterways Description Turbines and Generators (Incl. Gov. & Exciter) Accessory Electrical Equipment Miscellaneous Mechanical Equipment Structures and Improvements (Trans. Facilities) Substation Equipment & Structures Fixtures, Conductors & Devices Total Direct Construction Costs Design Engineering (9%) Geotechnical , Borings, & Seismic Surveys FERC and Other Licensing Construction Management (8%) Subtotal Contingency 1992 Estimated Construction Cost 30,000 112,000 300,000 20,547,250 1,849,253 500,000 400,000 1,643,780 24,940,283 5,996,975 30,937,258 Evaluation of Cost Estimate The level of cost detail provided for this alternative was ample for a reconnaissance-level investigation. The estimate included a cost contingency of approximately 24.0 percent of construction and other costs. This appears appropriate for this level of study. The major uncertainty with this alternative is with the construction of the “lake tap” underneath Allison Lake. Considerable amount of debris apparently exists on portions of the lake bottom, and to the extent that it exists at the proposed lake tap location is unknown $EA/1002C1F5.D0C 13 at this time. No cost allowance for any dredging was included in the estimate. In addition the exact location at which the lake tap is to be made is of critical importance and considerable subsurface investigation and analysis will be required before construction can begin. Poor rock conditions could even potentially render this alternative unfeasible. Conclusions In our opinion, the cost estimate as developed by HDR is reasonable and the project, as configured, appears to provide for a “utility grade” (50-year) facility, consistent with the standards we believe are necessary. Silver Lake Hydroelectric Project Alternative: Option A Silver Lake is situated about 15 miles southwest of Valdez. The outlet from the lake forms the Duck River which flows into Galena Bay. The Allison Lake Reconnaissance Study briefly reviewed two options for project development: Option A , proposed by Stone & Webster in 1982 and 1983, and Option B proposed by Whitewater Engineering Corporation (Whitewater) in 1992. Following is an evaluation of Option A. Project Description This option includes a 125-foot high roller-compacted concrete (RCC) dam, 6,000 feet of 108-inch pipeline, and a 15-MW powerhouse located at elevation 65 on the Duck River. The powerhouse would be equipped with three 5-MW Francis turbines. Transmission to the Solomon Gulch Project would be accomplished with a 22-mile-long overhead transmission line. The total expected average annual energy to be produced by this option was estimated to be about 44,800 MWh. Cost Estimate Table 8 provides a summary construction cost estimate for the Silver Lake (Option A) proj- ect. It is a summary of a more detailed cost estimate prepared in 1992 by HDR as part of their Allison Lake Reconnaissance Study. Evaluation of Cost Estimate The original cost estimate for this option was prepared in 1982 by Stone & Webster as part of a Cordova power supply interim feasibility assessment. HDR developed the costs con- tained in Table 2 by using the quantities previously developed by Stone & Webster and applying their own unit prices. HDR presented the estimate in about the same level of detail as provided in their Allison Lake estimate. In recent discussions with HDR it was agreed that a cost allowance for geotechnical investigations should by added to their 1992 estimate and that has been done, as shown in the table. This estimate included a contingency of approximately 22.5 percent on the construction and other costs, which again appears appropriate for this level of study. The Silver Lake site is more remote than the Allison Lake which will make access for diffi- cult and expensive. However there doesn’t appear to be any major technical barriers to development of a project at Silver Lake. SEA/1002C1F5.D0C 14 The Duck River and surrounding lagoon area is reported to be a very productive region for pink salmon. The elevation 65 site for the powerhouse is above what has been considered to be an impassable fish barrier. Thus the environmental impacts on the fishery have been viewed as minimal. Table 8 Silver Lake (Option A) Project Summary Construction Cost Estimate ost Description (1992 dollars) ___ Land and Land Rights 1,175,000 Structures and Improvements 2,571,250 Reservoirs, Dams, and Waterways 20,619,500 Turbines and Generators (Incl. Gov. & Exciter) 4,095,000 Accessory Electrical Equipment 440,000 Miscellaneous Mechanical Equipment 50,000 Structures and Improvements (Trans. Facilities) 30,000 Substation Equipment & Structures 300,000 Fixtures, Conductors & Devices 6,600,000 Total Direct Construction Costs 35,880,750 Design Engineering (9%) 3,229,268 Geotechnical , Borings, & Seismic Surveys 500,000 FERC and Other Licensing 400,000 Construction Management (8%) 2,870,460 Subtotal 42,880,478 Contingency 9,615,725 1992 Estimated Construction Cost 52,496,203 Conclusions The cost estimate for this option, as developed by HDR, in our opinion is reasonable and the level of accuracy appears consistent with the Allison Lake Project estimate. This Silver Lake option appears to also provide for a “utility grade” installation. SEA/1002C1F5.00C 15 Silver Lake Hydroelectric Project Alternative: Option C Project Description As mentioned above, Option B to hydroelectric development at Silver Lake was developed by Whitewater Engineering in 1992. Whitewater updated its plan and related cost estimate ina letter to AIDEA, dated November 13, 1995. The updated Whitewater plan is referred to as Silver Lake Option C. It is similar to the Silver Lake Option A, except the powerhouse site would be lowered from elevation 65 to elevation 35 and a submarine transmission cable would be substituted for the overhead transmission line. By locating the powerhouse down at elevation 35 there would be some increase in energy production over the elevation 65 site, but that value has not been calculated yet. Whitewater recently received a FERC Preliminary Permit to further study the site. Cost Estimate A summary of Whitewater’s current construction cost estimate for Silver Lake (Option C) is shown in Table 9. This estimate was provided in Whitewater’s November 13, 1995, memo which it updated on January 18, 1996. Some adjustments to the latest estimate were made by CH2M HILL. The January 18 Whitewater estimate as adjusted by CH2M HILL is also shown in Table 9 (in the column entitled “CH2M HILL”). Evaluation of Cost Estimate It is our understanding that Whitewater’s costs are based upon their recent experiences on the Black Bear and Power Creek projects in southeast Alaska plus some reliance on the costs developed by HDR for the Silver Lake (Option A) alternative. The estimate contained a $300,000 allowance for two operators residences which was deliberately excluded from the table for consistency because this was not included in the Silver Lake (Option A) estimate. The CH2M HILL costs provided in the table are Whitewater costs with the following modifications: e Anallowance of $1,000,000 was added to acquire the necessary land rights to develop the project. This is the same figure used in the Silver Lake (Option A) estimate. Whitewater assumed that the affected property owner(s) would be paid a royalty on power sales revenues and this would become an operating expense. It was assumed that this would be equivalent to the $1,000,000 up-front payment. e Whitewater’s estimate includes an allowance of $250,000 for a prefabricated metal building for the powerhouse superstructure. The Silver Lake (Option A) estimate con- tains a $600,000 allowance for a more substantial concrete/masonry building super- structure. For consistency between the two alternatives, the difference ($350,000) was added to our estimate. (If a prefabricated metal building were installed, maintenance would increase above assumed levels.) e Whitewater’s November 13, 1995, costs for installation of the penstock were adopted. s€a/1002c1F5.00¢ 16 Table 9 Silver Lake (Option C) Project Summary Construction Cost Estimate Cost (1995 dollars) Description Whitewater CH2M HILL Land and Land Rights 215,000 1,215,000 Structures and Improvements 1,462,500 1,512,500 Reservoirs, Dams, and Waterways 12,859,000 14,059,000 Turbines and Generators (Incl. Gov. & Exciter) 3,060,000 3,900,000 Accessory Electrical Equipment 910,000 910,000 Miscellaneous Mechanical Equipment 50,000 50,000 Structures and Improvements (Trans. Facilities) 68,000 68,000 Substation Equipment & Structures 325,000 325,000 Fixtures, Conductors & Devices 6,440,000 6,440,000 Mobilization 2,000,000 2,000,000 Total Direct Construction Costs 27,389,500 30,479,500 Design Engineering 750,000 750,000 FERC and Other Licensing 800,000 800,000 Construction Management 1,000,000 1,000,000 Subtotal 29,939,500 33,029,500 Contingency 4,535,925 6,605,900 1995 Estimated Construction Cost 34,475,425 39,635,400 e Whitewater’s November 13, 1995, costs for purchase and installation of the turbine and generator equipment was also adopted. e Whitewater’s contingency was increased from 15 to 20 percent . Given Whitewater’s approach to the project, it is reasonable to use a 20 percent contingency rather than the 24 percent figure used in the Allison Lake estimate and 22.5 percent used in the Silver Lake Option A estimate. Locating the powerhouse down as low as elevation 35 could result in adverse impacts on the salmon fishery. Whitewater has indicated that the upstream migrating salmon turn in Bennett Creek before they reach the proposed powerhouse; but this will require further study. $EA/1002C1F5.00c Also the swift currents and rough bottom conditions in Prince Williams Sound may make it quite difficult to build and maintain the submarine transmission cable as proposed by Whitewater. However the cost allowance for this cable is probably adequate to build an overhead transmission line. Conclusions Whitewater’s cost estimate presumably reflects the intent of a private power developer and engineer to take full financial responsibility for the planning, design, construction, and perhaps even the operation of this project. Therefore it is difficult to draw a direct cost comparison between this and the other alternatives whose estimates were developed by independent engineers. However, in our opinion, Whitewater would be capable of developing this project to “utility-grade” standards (50-year life) for $39.6 million. Valdez Coal Plant Alternative Project Description Coal-fired powerplant to be located in Valdez, adjacent to CVEA's existing diesel powerplant. The project, proposed by a private developer (Alaska Cogeneration Systems, Inc. [ACSI]) includes twin boilers (coal-fired and oil-fired), twin steam turbines (6 MW and 12 MW), a district heating system, limestone dry scrubber/baghouse dry scrubber system, 3 cell cooling tower, ash handling system and coal storage and feed system. The coal-fired boiler will be converted from a 26-year-old stoker unit to a fluidized bed unit, and the steam turbines (850 F/900 psig) will be reconditioned. The district heating hot water system is intended for government buildings, commercial and dockside facilities, but there are no agreements in place to support such a system at this time. Coal for this project is provided from a mine in the Matanuska Valley near Sutton, operated by the project developer. Coal would be containerized from the mine and shipped over-the- road to the railhead, then transported to Whittier for truck transport to the site. The cost of coal (estimated at $50/ton) includes mining, all transportation and delivery to the site. The site is reported to be suitable for construction of a powerplant (bedrock), has nearby sewer and water supplies from Valdez, and is near the diesel plant switchyard for power sales. Ash removal will be to a nearby landfill or backhaul to the mine. The developer has air permits filed for a former project that he feels will apply to this project. Operation of the plant will be primarily on coal fuel, 10 months of the year. Output will vary from 10 MW firm capacity to 1 - 1.5 MW during late spring. Shutdown will be during the summer periods (June - August). Maintenance of the plant will be performed primarily during the shutdown. Projected schedule for construction is 18 months. Cost Estimate Costs submitted by ACSI have been summarized by R.W. Beck in their 1994 report, as shown in Table 10. The contingency amount shown is 8 percent of total costs. SEA/1002C1F5.D0C 18 Evaluation of Cost Estimate The estimate provided has good detail in most areas and can be compared and evaluated easily with other powerplant estimates. The contingency shown for this project is 7.5 per- cent of construction and other costs; CH2M HILL recommends at least 15 percent of construction and other costs for a well-defined project. TABLE 10 ACSI Cost Estimate for Valdez Coal Alternative Cost Description (1993 dollars) Site Acquisition 500,000 Foundation and Buildings 1,200,000 Boilers 4,000,000 Turbine Generator 2,000,000 Utility Work 500,000 Other 1,000,000 Piping 1,000,000 Electrical 2,200,000 Subcontractor Services 600,000 Miscellaneous Equipment 400,000 District Heating System 3,000,000 Water Supply and Treatment 500,000 Contractor Overhead and Profit 1,600,000 Total Direct Construction Costs 18,500,000 Permitting 150,000 Engineering and Design 850,000 Construction Management 1,000,000 Coal Reserves 2,300,000 Legal & development costs 1,900,000 Subtotal 24,700,000 Contingency 2,000,000 Total 26,700,000 Costs ACSI included in the estimate that may be overestimated or may even not be incurred include the following: e Engineering & Design: the developer intends to rely heavily upon the design documents done for the proposed Air Force OTH-B project. If this is possible, engineering costs would be minimal. $EA/1002C1F5.00C 19 Permitting: the developer hopes to use existing air permits from the OTH-B project. If true, permitting costs would be minimal. Costs that appear not to be included in the estimate include the following: Coal handling equipment: not specifically called out in the estimate, may not be ade- quately provided for. Ash handling and disposal: not shown in the estimate; equipment and disposal costs could be significant. Startup, commissioning and training costs: not shown. Contractor overhead and profit appears low for a project of this type. CH2M HILL recommends the Valdez Coal Project cost estimate be adjusted to the amounts shown in Table 11. There are several potential "fatal flaws" related to this project. They include: ACSI apparently has little or no experience in coal mine operation, powerplant opera- tion and district heat operation. The complicated fuel delivery scheme (road, rail, barge) and sophisticated powerplant design (coal-fired fluid-bed boiler and steam turbines) would challenge even the most experienced developer. Refurbishment costs for the boilers and turbines are almost impossible to verify, but are well below new equipment costs. If these equipment items cannot be refurbished, the need for new equipment will make the project more costly than construction with new equipment. The lack of contracted district heating customers could severely hamper the economics and operations of the coal plant. Steam demands determine the power levels possible from the turbine generators. Revenue dollars from the heating plant offset project costs and substantiate the cogenerator status of the project. Without full development of the steam market, revenue requirements from the electric operation would increase to pro- portionately higher levels. The technical basis of the project is questionable, in several areas. First, operations of a coal plant on a part-time or reduced load basis is unprecedented and will result in fuel handling problems and early deterioration of equipment. Second, conversion of an old stoker boiler to a fluid-bed boiler cannot be verified or guaranteed to any acceptable level of confidence. Third, the planned goal of electrical interconnection of the plant at the existing diesel plant substation may well be impossible (since both plants may be required to operate at the same time), resulting in unplanned substation and distribu- tion system costs. The proposed transfer of air permits from past projects and equipment may not be ac- cepted on a new project. Permitting in the Valdez area is anticipated to be difficult due to the number of emission sources currently in operation. The proposed re-use of engi- neering documents for this project may be flawed due to changes necessary for this project. SEA/1002C1F5.00C 20 TABLE 11 CH2M HILL-Adjusted Cost Estimate for Valdez Coal Alternative Cost Description (1993 dollars) Site Acquisition $1,000,000 Foundation and Buildings $1,300,000 Boilers $4,000,000 Turbine Generator $2,000,000 Utility Work $1,000,000 Other $4,000,000 Piping $1,000,000 Electrical $2,200,000 Subcontractor Services $600,000 Miscellaneous Equipment $400,000 District Heating System $3,000,000 Water Supply and Treatment $500,000 Contractor Overhead and Profit $4,000,000 Total Direct Construction Cost $25,000,000 Permitting $250,000 Startup, Commissioning and Training $100,000 Engineering and Design $850,000 Construction Management $1,000,000 Coal Reserves $2,300,000 Legal & development costs $1,900,000 Subtotal $31,400,000 Contingency $4,600,000 Total $36,000,000 SEA/1002C1F5.00C 21 Conclusion The cost estimate provided by the project developer is substantially low, when compared against projects of similar complexity and technology. Construction costs alone for a project of this type should be on the order of $25 million (as shown in Table 11), assuming used equipment. New equipment would raise the cost much higher. Total costs for this project should be on the order of $36 million. All Diesel Alternative--Operation and Maintenance Description As described in the discussion of the construction cost for the All Diesel alternative, the All Diesel alternative assumes that Solomon Gulch and diesel generation would continue to be used to meet CVEA generation and reserve requirements. Under this alternative, several new diesel units would be purchased to replace existing units at the time major overhauls of the existing units would otherwise occur. Full capacity to meet local peak loads and reserve requirements would be continue to be maintained at both Glennallen and Valdez. Staffing levels at Glennallen presently total six persons: a chief operator, four engine opera- tors (three operators / three shifts per day and one operator on rotation) and one engine mechanic. Due to the isolation location of Glennallen, additional CVEA staff are not easily available. Valdez maintains a plant staff of four persons: a chief operator, two engine operators and one engine mechanic. The Valdez plant is close to the Solomon Gulch hydro plant, which has additional CVEA staff for that operation and a dispatch control center (including SCADA system monitoring). Hydro plant staff are cross-trained in diesel plant operations, and hence offer additional manpower to the Valdez plant as needed. For the All-Diesel Alternative, the 1994 RW Beck study indicated that three new operators would be added to the Valdez plant by 1997, to support new equipment and the increased generation role. The 1995 CVEA Power Supply Study assumed staffing requirements, indicating the termi- nation of five operators (four at Glennallen and one at Valdez). This was assumed due to installation of new, more reliable engine generators and the installation of supervisory SCADA equipment in both plants. This can be summarized as follows: All Diesel Alternative Case Glennallen Plant Staffing Valdez Plant Staffing Status Quo five four 1994 Study five seven 1995 Study one three $EA/1002C1F5.D0c 22 Evaluation The All Diesel Alternative must have an appropriate number of plant operators available for engine (or gas turbine) generators that run in a primary power mode. Current staffing levels (five at Glennallen and four at Valdez) are appropriate for this alternative. The instal- lation of SCADA monitoring and newer generating equipment does not eliminate the need for close supervision of equipment, particularly if CVEA wants to control damage to equipment in an expeditious manner. However, the SCADA system would allow CVEA to proceed with the All Diesel alternative without any increases in operation and maintenance staff. Conclusion An increase in staffing levels for the All Diesel Alternative (as recommended in the 1994 study) is not warranted, even with the increased power generation. Similarly, a reduction in staffing for this Alternative could seriously endanger the availability of generators at the diesel plants. Risk Assessment and Analysis of Costs and Schedule for Selected Alternatives As noted above, the least cost alternatives for new power supply at CVEA include the Copper Valley Intertie, the All Diesel, and the Silver Lake Option C. In this section, project uncertainties regarding construction costs for these alternatives are examined and cost estimates associated with each adjusted to a “risk adjusted” range. Within this range, probabilities of actual costs being at or below certain levels are calculated. In addition, risk analysis was conducted for the operating costs of the All Diesel alternative. This was because the operating costs associated with this alternative are the major component of its life-cycle cost. Risk-adjusted construction costs estimates for the Copper Valley Intertie, the All Diesel, and the Silver Lake Option C alternatives are shown in Table 1. Risk-adjusted costs for All Diesel operation are discussed later in this section. Approach The analysis proceeded in a two-step process. First, uncertainties (defined as conditions or events that might affect either the project’s cost or schedule) are identified, categorized, and measured as of high, medium, or low risk or as a potential fatal flaw. Mitigation ideas are also developed for risks assessed as either high or medium. For each project alternative studied, assessments for each of uncertainty factor were developed, typically in a day-long workshop with experts familiar with the project or critical aspects required for project construction and, in the case of All Diesel alternative, operations. Second, on the basis of the risk assessment in step 1, risk analysis was performed to determine probability-based cost estimates for each alternative. This analysis included: e Integrating the results of the risk assessment workshop into the cost estimates (for example, the cost of mitigation of risks was added to the cost estimates) SEA/1002C1F5.D0C 23 e Identifying a realistic range of cost for each of the primary cost categories included in the cost estimate e Performing a simulation analysis of total costs based on the range of probable cost for the primary cost categories. The result of this analysis is a risk-adjusted or probabilistic range of the total cost for each given alternative. This range represents the likely cost result of risks considered in our assessment. However, not all risks can be identified and those that can are estimated on the basis of experience and professional judgment. Therefore, actual costs can occur outside the ranges shown in the risk analysis figures (Figures 1, 2, and 3). Risk analyses presented in this technical memorandum are not meant as a guarantee as to the ultimate cost of any project. Given the risk-adjusted range of probable costs, a cost estimate can be adopted on the basis of one’s tolerance for potential budget overruns. For example, budgeting an amount that has only a 20 percent chance to be at or above actual costs may be considered to be too risky, since there is only one chance out of five of the project being below actual costs. On the other hand, budgeting an amount that has more than an 80 percent chance to be at or above actual costs may be considered to be too conservative, since there is less than a one in five chance of actual costs being above this amount. In addition to the direct impact of risk on project costs, the risk of impacting the project schedule was also assessed and evaluated. This was done from the perspective of whether the schedule included a reasonable allowance for time delays associated with each of the risks. Copper Valley Intertie Risk Assessment In the risk assessment workshop, the risk assessment team identified 60 potential risks to project cost and schedule. These risks were further discussed and then designated as potential fatal flaws or as high, medium or low risks in terms of their potential impact. Extraordinary (extremely low probability) events were not included, but events outside the control of the owner/project team were included. This process resulted in the identification of the following risk factors for project construction: e 2potential fatal flaws (major risks that might result in project termination), e 2high risks (major risks with likely cost and schedule implications but not likely to result in project termination), e 20 medium risks (important but manageable risks), and ¢ 36 low risks (possibly important risks but with small likely impacts). These risks are summarized in Table 12. Also included in this table is an indication (check mark) as to whether the risk was integrated into the risk-adjusted cost estimate and notes on potential mitigation for these risks. SEA/1002C1F5.00C 1/30/96 24 TABLE 12 Copper Valley Intertie Project Project Risk Assessment Summary Worksheet Category of Risk Potential Cost Risk A Management and Administration Issues Changing Govemment Regulations (State, Local Communities) Medium — Medium y EIS and Public Involvement Govemmental Support FF Public Perspective (Natural Environment, Socioeconomics) High Medium - EIS and Public Involvement Site Acquisition (BLM, Native Corps., MatSu Borough) Medium Medium y EIS and Public Involvement ent tion (CVEA) Low ___Low B. Finance Availability Issues Pre-Construction (CVEA Funding) Low Low Construction (State Grant) FF Copper Valley Feasibility Study Update Operations Cash-Flow (rate impacts and REA Terms Low Low c. Regulatory and Permitting Issues Permit Acquisition State DNR, Mental Health Lands Medium — Medium Y EIS and Public Involvement Federal (BLM and COE) Medium = Low y EIS MatSu Borough Medium — Medium v EIS and Public Involvement Native Regional Corp. (CIRI, AHTNA) Medium — Medium Y EIS and Public Involvement APUC (Power Sales) Low Low D. Environmental and Geotechnical Issues Weather Conditions Medium Medium v Risk Adjusted Cost Estimate Environmental Restriction on Construction Medium Medium Y Risk Adjusted Cost Estimate Availability of Subgrade Testing to Date Medium — Low Y Risk Adjusted Cost Estimate Archaeological and Historical Findings Low Low v Cultural Resources Survey E. Engineering Planning and Design Issues Design Approvals and Changes Low Low v Route Selection High High v EIS and Public Involvement Weather Design Criteria Medium — Low v Risk Adjusted Cost Estimate System Performance Identity during Preliminary Engineering Communication System Low Low Integration (Need for SVC/Shunt Reactor) Medium — Low Final Electrical System Analysis Intertie to Fairbanks Low Low MEA Substation Low Low Construction Management Low Low v Project Team Continuity Low Low Packaging of Bids Low Low F. Contractor Issues Competitive Availability of Qualified Contractors Medium Low Timing of Project Construction Level of Specification Detail in Design Drawings Low Low Labor Negotiations/Stoppages (Union Contract Expiration) Low Low Management of Subcontracts Low Low Change Orders (e.g., Structure relocate, realignment) Medium Low Y Risk Adjusted Cost Estimate Worker Safety (Construction in dark) Low Low Ny MEA Line Tap - Safety Low Low Pump Station 11 Tie - Safety Low Low G. Existing Structures and Equipment and Material Availability Equipment Availability (Helicopters) Medium — Medium v Timing of Project Construction Materials Availability Low Low Rejects and Defects Low Low Equipment Malfunctions and Failures Low Low Condition of Existing Structures Low Low Material Cost Fluctuations Low. Low y H. ‘Construction Logistics and Transportation Laydown Area Limitations Low Low Traffic Congestion during Construction Low Low Access to Site (Physical) Medium Medium Vv Risk Adjusted Cost Estimate Access to Site (Right of Entry) Medium Medium v EIS and Public Involvement Equipment Delivery Eastem Construction Zone Medium Medium v Risk Adjusted Cost Estimate Wester Construction Zone Low Low Materials Delivery Low Low Maintenance of Service during Construction Low Low Mobilization (Crew Lodging) Medium Low A) EIS and Public Involvement Demobilization Low Low 1. Start-Up and Commissioning Issues Final Inspection Low Low Substation-Sutton Low Low Substation-Glenallen Low Low 4 Operating Company Issues Maintenance of Line/Access for Maintenance (Contract Services) Medium : EIS and Public Involvement Availability of Line (Outages) Medium - Final Electrical System Analysis Power Sales Agreements Low ° Back Feed to Sutton Low : Spare Materials and Parts Low : Identity in Preliminary Engineering Category of Risk: FF: Major Risk that Might Become a Fatal Flaw High: Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw Medium: Important but Manageable Risk Low: Possibly Important but with Small Impact NA: __ Not Applicable $EA/1002C1F5.00C 1/30/96 25 The two potential fatal flaws and 22 medium to high risks? are discussed below. This discussion is organized according to the same risk categories as shown in Table 12 and includes a description of risks, costs and schedule impacts, and suggested methods to mitigate the risks. A discussion on potential schedule risk is also follows. A. Management and Administration Issues. The following are three key management and administration risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk A-1 Changing government regulation, particularly the potential for communities along the transmission route to assert zoning control over the location of the route represents a project risk. If the members of local communities stay mobilized against the project, it is likely to cost more and take longer to implement. (Medium Risk) Risk A-2 The governmental support for this project is uncertain and is related to cost- effectiveness of investment from the perspective of both resource use and utility rates. Without broad local and state support, the intertie is not likely to be implemented. (Potential Fatal Flaw) Risk A-3 The public support for this project is currently mixed. Opposition to the project is multi-faceted. (High Risk) Risk A-4 Right-of-way acquisitions for transmission line corridors can be time consuming. For this project there will need to be hundreds of easements and rights-of-way acquired. (Medium Risk) The risk assessment team concluded that the key natural environment and socioeconomic impact issues identified by the public thus far will be addressed in an environmental impact statement. Mitigation developed as part of that decision making process (particularly on transmission line routing and construction mitigation) will contribute to obtaining public support. Right-of-way acquisition needs to be started as soon as a route has been selected and the project has received permits for construction. A coordinator for acquisition is recommended due to the potential difficulty in obtaining them in a timely manner. B. Finance Availability Issues. One key finance availability risk issue was identified. The potential financial impact of this risk issue has not been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk B-1 The State of Alaska construction loan for the Copper Valley Intertie Project is considered to be vital. Without the loan, this project is considered to be highly unlikely. (Potential Fatal Flaw). 3 These 22 risks represent the team's recommended priority list for management action based on potential schedule and cost impacts to the project. The medium risks can usually be managed by direct integration into typical preliminary engineering or environmental impact analysis. The potential fatal flaws and high risks generally require more focused management, such as directed public involvement or newsletters. $EA/1002C1F5.00C 26 C. Regulatory and Permitting Issues. The following are four key regulatory and permitting risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk C-1 Permit acquisition from State of Alaska Department of Natural Resources, and State Mental Health Lands is considered uncertain pending completion of the environmental impact statement process. (Medium Risk) Risk C-2 Permit acquisition from Federal Bureau of Land Management and Corps of Engineers is considered uncertain pending completion of the environmental impact statement process. (Medium Risk) Risk C-3 Permit acquisition from the MatSu Borough is considered uncertain pending completion of the environmental impact statement process. (Medium Risk) Risk C-4 Permit acquisition from Native Regional Corporations (CIRI and AHTNA) are considered uncertain pending completion of the environmental impact statement process. (Medium Risk) The risk assessment team believed that permit acquisition was a medium risk and that completion of the environmental impact statement process would result in permits for the project. The risk-adjusted project budget has been adjusted to reflect the costs of the environmental impact process. D. Environmental and Geotechnical Issues. The following are three key environmental and geotechnical risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk D-1 Winter weather conditions along the transmission corridor will result in reduced construction efficiency. The impact is uncertain, but a contract clause allowing for some sharing of this risk between contractor and owner should be evaluated as a means of reducing the contract bid price. (Medium Risk) Risk D-2 Restrictions on construction due to maintenance of environmental quality/limited stream crossings will lead to reduced construction efficiency. This impact is somewhat uncertain at this time, since a final route has not been selected. (Medium Risk) Risk D-3 The foundation construction cost is uncertain at this time due to a lack of information about subgrade conditions. This is typical at this stage of a project and may not be fully addressed for each location until construction begins. (Medium Risk) The risk assessment team evaluated the existing cost estimates to verify that allowances for severe winter weather conditions had been included in the crew productivity assumed in the cost estimate. Range estimates were further increased to account for this risk. E. Engineering Planning and Design Issues. The following are three key engineering planning and design risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk E-1 The final route selection for the transmission line has not been made. The routes evaluated to date have been compared on a construction cost basis and $EA/1002C1F5.00¢ 27 the least expensive was selected. Pending the findings of the environmental impact process, during which a final route selection should be made, these costs may increase. An increased allowance for route selection is included in the risk- adjusted cost estimate. (High Risk) Risk E-2 The weather design criteria have not been finalized as yet and remain somewhat uncertain. They need to be finalized during preliminary engineering with the assistance of a meteorological survey; a contingency allowance is added in the interim. (Medium Risk) Risk E-3 Additional system performance evaluations (final electrical systems analysis) are recommended to address the current questions about the need and benefit for equipment currently not included in the project. Final decisions are needed during preliminary engineering on whether to include communications links and certain substation equipment (Static VAR Compensator and Shunt Reactor) as part of this project. (Medium Risk) The risk assessment team believed that the route selection would be made on the basis of weighted criteria, including impact on natural and human environment. Since the final route selection might result in a route that is not the least costly (as currently used in the cost estimate), a specific adjustment was included in the risk-adjusted cost estimate to allow for this uncertainty. The project as currently envisioned does not include certain features that are sometimes included in similar projects. The benefits of including them need further evaluation. It is important that these evaluations should take place early in the preliminary engineering phase of the project to assure integration into design features if needed. F. Contractor Issues. The following are two key contractor risk issues. The potential financial impact of these risk issues has only partially been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk F-1 The availability of a number of qualified contractors to bid on this project is uncertain at this time. Construction is not currently envisioned earlier than 3 years from now, and competing projects may result in a low number of bids received. This risk may result in higher than anticipated bids. (Medium Risk) Risk F-2 Change orders due to field conditions not being reflected in design drawings are to be expected. A specific allowance for extra work, separate from project contingency, is included in the risk-adjusted cost estimate. (Medium Risk) The risk assessment team was concerned about the potential conflict of other Alaska construction projects with this transmission line project. No budget allowance was, however, included to reflect the potential of non-competitive bids. Alternative project delivery methods (such as negotiated design-build) should, if necessary, be considered during preliminary engineering as an alternative to traditional low bid award. G. Existing Condition of Structures and Facilities and Equipment and Material Availability Issues. The following key risk issue was identified for this category. The potential financial impact of this risk issue has only partially been incorporated into the assumed ranges of the risk-adjusted project cost estimate. SEA/1002C1F5.D0C 28 Risk G-1 The availability of a number of different types of helicopters needed for material, crew, and equipment delivery has been assumed in the cost estimate. The actual availability at the time of the construction is conjectural at this time, and an allowance for alternative delivery methods will be left to the contractors. (Medium Risk) The key equipment needs for this project include different types of helicopters. Each has different uses and capacities, and the costs vary greatly. The availability of the least cost options is unknown (unknowable) at this time. This risk issue is considered in the contractor’s domain and did not affect project budget. H. Construction Logistics and Transportation Issues. The following are four key construction logistics and transportation risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk H-1 The physical access to the transmission line site presents certain constraints that need to be reflected in the project implementation plan and cost estimate. The uncertainty of the route leads to uncertainty in physical access options. An allowance for this uncertainty is recommended to be included in the cost estimate until a final route is selected. (Medium Risk) Risk H-2 In addition to physical constraints, the right of entry and reasonable access to the site may be limited by the mitigation conditions of the permits. Since they are unknown at this time, an allowance for additional access costs included in the risk-adjusted project cost estimate. (Medium Risk) Risk H-3 Equipment delivery to the eastern construction zone in the summer months may be more difficult than currently envisioned (wetland issues.) An allowance for this uncertainty and further evaluation during preliminary engineering is included in the risk-adjusted cost estimate. (Medium Risk) Risk H-4 The lodging for transmission line construction crews is assumed to be in motels along the construction route. The implications of this assumption (reality of supply/demand and impact on tourism) will be addressed during the environmental impact statement process. Separate worker lodging facilities (camps) are not anticipated to be needed as currently envisioned. (Medium Risk) The risk assessment team was concerned about the likely site access restrictions to be placed on the construction work. A range of costs has been included in the cost estimate to reflect this potential cost uncertainty, which will not be fully understood until final permits are obtained. Schedule. The risk issues discussed above have both potential project cost and project schedule impacts. The current schedule for project planning is up to 36 months, followed by a 24- to 31-month construction schedule. After reviewing each schedule risk, the team determined that this schedule adequately reflected the potential risks identified. SEA/1002C1F5.D0C 29 Risk Analysis A construction cost risk analysis conducted for the Copper Valley Intertie included: e Integrating the results of the risk assessment workshop into the cost estimates, e Identifying a realistic range of costs for each of the major expenditures for the project based on level of design detail, and e Performing a simulation analysis of the range-based cost estimate. The results of the risk analysis are shown in Table 13 and Figure 1. Table 13 presents the cost estimate as originally estimated and as a risk-adjusted cost estimate. As shown at the bottom of the table, the risk analysis for each cost component replaces the provision of a general contingency like that included in the original estimate. The risk-adjusted cost estimate shows the expected value of the estimate based on the recommended cost percent ranges shown. For example, for Structures the original cost estimate was $7.7 million and the risk-adjusted estimate is $8.1 million. The $8.1 million estimate is the expected value of the range between $6.9 million (which is calculated from $7.7 million times 90%) and $9.3 million (which is calculated from $7.7 million times 121%). Two types of distributions were used in the analysis. A triangular 10/90 distribution is basically a triangular distribution between the 10th and 90th percentile, with the peak of the triangle being the most likely estimate. This distribution is commonly used as a means of avoiding the need to include events with very little probability of occurring. Another distribution type used was the uniform distribution, which is a distribution evenly divided between two values. This type of distribution is preferred when very little is known about the potential shape of the distribution but the end points are fairly well known. As shown in Figure 1, the risk-adjusted cost estimate ranges from $45.4 to $49.8 million for probabilities of 20 to 80 percent. The high end of this range can largely be traced to four factors: e The new inclusion of an alternate route allowance, which is a mitigation for the risk that the least costly construction route will not be the final route selected through the environmental impact statement process. ¢ The increased allowance for owners’ costs, which will be needed to secure public support for the project. e The increased expected value estimate for foundations, which reflects the wide cost range and uncertainty about this cost estimate. e The increased expected value estimate for conductors, which also reflects the wide cost range and uncertainty about this cost estimate. The risk-adjusted expected value of project costs is $47.4 million (1993 dollars). It is only a coincidence that this is the same number as the original cost estimate. SEA/1002C1F5.00C 30 TABLE 13 Copper Valley Intertie Project Risk Adjusted Cost Estimate (1993 Dollar Values) Cost A. Transmission Line Construction ‘Structures Foundations Guys and Anchors Framing Conductor Right-of-Way Clearing Mobilization Extra Work Allowance Alternate Route Allowance ‘Subtotal Transmission Line Construction B. Substation Construction New Sutton Substation Bump Station No. 11 Substation Extra Work Allowance Subtotal Substation Construction C. Engineering Services/Construction Management Engineering Services Construction Management Subtotal Engineering and Const. Mgmt. D. Environmental Services & Permitting E. Right of Way Acquisition F. Owners Costs Total Project Cost (w/o contingency) Project Contingency Allowance Total Project Cost Total Project Cost: Expected Value From Risk Analysis Extra Risk Allowance Total Porject Cost: At 80th Percentile of Risk SEA/1002C1F5.D0C Original Estimate 7,717,699 7,598,190 1,226,521 2,642,195 6,503,487 2,792,960 1,284,405 1,000,000 ° 30,765,457 1,824,316 1,793,903 180,911 3,799,130 3,337,900 2,159,352 5,497,252 1,405,000 713,000 1.360.992 43,540,231 — 4.064.125 47,604,356 Cost Estimate 8,073,801 8,915,972 1,252,856 2,642,195, 7,631,398 2,992,586 1,367,420 914,033 900,000 34,690,262 1,824,316 1,793,903 180,911 3,799,130 3,288,184 2,116,917 5,405,100 1,314,428 784,300 Risk-Adjusted Ranges Risk-Adjusted ——as % of Original Cost Estimate) __ Low Most Lil High 90% 102% 121% 90% 100% 150% 80% 100% 90% 100% 110% 84% 110% 154% 90% 105% 125% 90% 100% 125% 50% 100% 130% 400,000 2,000,000 80% 100% 120% 80% 100% 120% 85% 105% 110% 5% 6% 60% 100% 125% 95% 125% 2% 5% 1,609,763 47,602,983 49,834,000 Distribution Ty Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Uniform (between values shown) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Uniform (as a % of Construction) Triangular (10th, 90th Percentile) Uniform (between % shown) Unitorm (as a % of Total Costs) 31 117526.C0.10 » Risk Simulation 1/23/96 * GM <A-T--wPSrwonvv <A-TF-wrwonvv @RISK Simulation Sampling= Monte Carlo PROJECT COST #Trials=1000 15% [o> 9.00%-"----- 3% pu O% 35 20% Probability. | $ 45.4 Million > | 37.55 40 42.5 45 47.5 | <_! : | $ 47.4 Million wens deceeee -- oeee eee 50% Probability 50 52.5 55 57.5 60 Values in Millions @RISK Simulation Sampling= Monte Carlo PROJECT COST 1007 80%, 777 \10)/4s eee 40%) 0-77 -> 20%) 1 55 T 1 T 1 I 37.55 40 42.5 45 47.5 T T 1 50 52.55 55 57.5 60 Values in Millions Figure 1 Copper Valley Intertie Project Cost Simulation All Diesel Alternative Risk Assessment As shown in Table 14, the risk assessment team identified 34 potential risks to project cost (including operations cost) and schedule. These risks were further discussed and then designated as potential fatal flaws, high, medium or low risks in terms of their potential impact. As in risk assessments for other power supply alternatives, extraordinary (extremely low probability) events were not included. This process resulted in the identification of: ¢ No potential fatal flaws (major risks that might result in project termination), ¢ No high risks (major risks with likely cost and schedule implication but not likely to result in project termination), ¢ 17 medium risks (important but manageable risks), and © 16 low risks (possibly important risks but with small likely impacts). Also included in Table 14 is an indication (check mark) of whether the cost estimate was adjusted to account for a particular risk, and notes on potential mitigation. The 17 medium project risks are discussed below. A. Management and Administration Issues. No key management and administration risk issues were identified. B. Finance Availability Issues. No key finance availability risk issues were identified. C. Regulatory and Permitting Issues. One key regulatory and permitting risk issue was identified. The potential financial impact of this risk issue has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk C-1 State Air Quality Permit acquisition from State of Alaska is considered uncertain at this time due to the current non-attainment classification of the airshed at Valdez. The risk is that considerable modeling would be required for the permit with increased time and cost. (Medium Risk) D. Environmental and Geotechnical Issues. No key environmental and geotechnical risk issues were identified. E. Engineering Planning and Design Issues. One key engineering planning and design risk issue was identified. The potential financial impact of this risk issue has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk E-1 The existing electrical system quality (transmission and distribution) is uncertain and needs to better understood as part of the preliminary engi- neering activities. The purpose would be to include all needed system upgrades at the same time as new diesel units are installed. (Medium Risk) The risk assessment team believed that an electrical relay protection study and a switchyard upgrade study would be appropriate during preliminary engineering. SEA/1002C1F5.D0C 33 Table 14 Copper Valley All Diesel Alternative Project Risk Assessment Summary Worksheet Category of Risk Potential Cost Risk Description of Risk Issue Fatal Flaw __Cost__Schedule _ Adjustment Notes on Mitigation A Management and Administration Issues Changing Goverment Regulations (State Air Quality) Low Low vi Title 5 Compliance Changes Governmental Support Low Low ¥ Public Perspective (Natural Environment, Socioeconomics) Low Low v Site Acquisition NA NA Project Management Organization (CVEA) NA NA B. Finance Availability Issues Pre-Construction (CVEA Funding) Low NA Construction (RUS Loan/Rates) Low NA Cash-Flow (rate i and RUS Terms) Low NA c. Regulatory and Permitting Issues Permit Acquisition (State Air Permit) Medium — Medium a Permit Acquisition (Federal REA) Low Low vs o. Environmental and Geotechnical Issues Weather Conditions NA Low Environmental Restriction on Construction NA NA Availability of Subgrade Testing to Date Low Low ts ‘Archaeological and Historical Findings NA NA. Ee. Engineering Planning and Design Issues : Design Approvals and Changes Low Low Site Availability and Suitability Low Low Site at Valdez is Questionable Existing System Performance (Electrical Trans. and Dist.) Medium — Medium v Elec. Relay Protection/Switchyard Upgrade Construction Management NA NA Project Team Continuity NA NA Packaging of Bids NA NA F. Contractor Issues Competitive Availability of Qualified/Skilled Contractors Medium Medium Level of Specification Detail in Design Drawings Low Low Labor Negotiations/Stoppages (Union Contract Expiration) NA NA Management of Subcontracts NA NA Change Orders NA NA Worker Safety NA. NA G. Existing Condition of Structures and Electrical Systems Condition of Existing Structure/Foundation Low Medium ie Usability of Existing Structure Medium — Medium vw Condition of Existing Fuel Storage Medium — Medium v Condition of Existing Diesel Generators Medium — Medium wv Condition of Existing Electrical Systems Medium Medium. x H. Equipment and Material Availability Construction Equipment Availability NA NA Diesel Engine Availability Medium — Medium A Long (6 month) Lead Time Needed Diesel Engine Cost Fluctuation Low NA v Rejects and Defects NA NA IL Construction Logistics and Transportation Laydown Area Limitations-Diesel Engines Medium — Medium Ss ‘Sequencing of Materials/Covered Storage Laydown Area Limitations-Electrical Equipment Medium — Medium ¥ Covered Storage ‘Access to Site (Physical and Right of Way) NA NA Mobilization of Material Low Low Maintenance of Service during Construction Medium — Medium ¢ Demolition/Salvage of Existing Diesel Engines Low Low v High Salvage Value Expected DemobilizatiowSalvage of Existing Electrical Systems Medium Medium vw Scrap Value Expected J. Start-Up and Commissioning Issues Final inspection NA NA K. Operating Company Issues Operating Labor Needed Medium = NA Availability of Diesels (Existing and New) Medium = NA Mechanical Age of Existing Diesels Fuel Costs Low NA Range Included in Base Analysis Spare Parts and Labor Support Service (Existing Diesels) Medium = NA Poor Manufacturer Support Currently Spare Parts and Labor Support Service (New Diesels) Low NA Good Manufacturer Support Envisioned Maintenance of Diesels (Existing and New) Medium __NA Mechanical Age of Existing Diesels/High Cost Category of Risk: FF: Major Risk that Might Become a Fatal Flaw High: Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw Medium: Important but Manageable Risk Low: Possibly Important but with Small Impact NA: __Not Applicable SEA/1002C1F5.D0C 34 F. Contractor Issues. One key contractor risk issue was identified. The potential financial impact of this risk issue was not incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk F-1 The availability of a number of qualified/skilled contractors to bid on this project is uncertain at this time. Construction is not currently envisioned earlier than 3 years from now, and competing projects may result in a low number of bids received. This risk may result in higher than anticipated bids. (Medium Risk) The risk assessment team was concerned about the potential conflict of other Alaska con- struction projects. The need for a qualified and experienced contractor is high to ensure project success. No budget allowance was, however, included to reflect the potential of non- competitive bids. Alternative project delivery methods (such as negotiated contracts) should, if necessary, be considered during preliminary engineering as an alternative to traditional low bid award. G. Existing Condition of Structures and Facilities. Five key risk issues were identified for this category. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk G-1 The condition of the existing structure and foundation is currently uncertain and needs to be ascertained as part of preliminary engineering. (Medium Risk) Risk G-2 The usability of the existing structure to house additional generation units is currently uncertain and needs to be ascertained during preliminary engineering. (Medium Risk) Risk G-3 The condition of the existing fuel storage system is currently uncertain and needs to be ascertained as part of preliminary engineering. (Medium Risk) Risk G-4 The condition of the existing diesel generators is currently uncertain and needs to be ascertained as part of preliminary engineering. (Medium Risk) Risk G-5 The condition of the existing electrical system is currently uncertain and needs to be ascertained as part of preliminary engineering. (Medium Risk) H. Equipment and Material Availability. One key equipment and material availability risk issue was identified. The potential financial impact of this risk issue was not incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk H-1 The diesel generators need to be delivered over a period of 5 years and consistency in design/replacement parts need to be reasonably assured. Also a reasonably long lead time is needed for ordering the diesel generators (6 months). (Medium Risk) The risk assessment team was concerned about the potential for ordering a number of gen- erators over an extended period of time (5 years.) Maintenance and operational ease will be based on having similar units available when needed. SEA/1002C1F5.D0C 35 |. Construction Logistics and Transportation Issues. The following are four key construction logistics and transportation risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk I-1 The availability and usability of a laydown area for the diesel generators is currently uncertain but can be ascertained during preliminary engineering investigations. Covered storage will be needed. (Medium Risk) Risk I-2 The availability and usability of a laydown area for the new electrical equipment is currently uncertain but can be ascertained during preliminary engineering investigations. Covered storage will be needed and adequate space for sequencing of materials will be needed. (Medium Risk) Risk I-3 The maintenance of service during construction is essential and a plan will need to be developed during engineering. (Medium Risk) Risk I-4 Demolition and salvage of existing electrical equipment is currently uncer- tain. It is likely that the equipment can be sold for scrap value without disposal cost but this will need to be verified. All allowance for this risk has been included in the risk-adjusted cost estimate. (Medium Risk) The risk assessment team was concerned that the current site is fully used and that suitable staging /laydown areas might be difficult to find. Similarly, disposal/salvage of existing generators and equipment is typically not an issue, but because of the location, may pose a risk. A range of costs have been included in the cost estimate to reflect this potential cost uncertainty which will not be fully understood until preliminary engineering. J. Start-Up and Commissioning Issues. No key start-up and commissioning issues were identified. K. Operating Issues. Five key operating company issues were identified. Recommendations for risk-adjusted operating costs have been included. Risk K-1 The number of workers required to operate and maintain the system is somewhat uncertain at this time. The emergency response requirement for the diesels may require a larger number of staff than would otherwise be required. (Medium Risk) Risk K-2 The availability (reliability) of the existing diesel generators is currently uncertain due to their age. This information will be more easily estimated once a condition survey is completed. (Medium Risk) Risk K-3 The uncertainty of future fuel costs is considered a risk for this project. The current range of forecasts are used in a scenario planning process as a means of estimating their effect. Although no risk-adjusted fuel cost estimate is used, the risk is acknowledged. (Medium Risk) Risk K-4 The future spare parts availability for the existing diesel generators is cur- rently uncertain due to their age. This information will be more easily estimated once a condition survey is completed. (Medium Risk) SEA/1002C1F5.00C 36 Risk K-5 The future maintenance needs for the existing diesel generators is currently uncertain due to their age. This information will be more easily estimated once a condition survey is completed. (Medium Risk) Schedule. The risk issues discussed above have both potential project cost and project schedule impacts. The project schedule was evaluated from the perspective of whether it included a reasonable allowance for the time delays associated with each of the risks. The current schedule for project planning is 9 to 12 months, followed by a7 to9 month construction schedule (for the first generating units). After reviewing each schedule risk, the team determined that this schedule adequately reflected the potential risks identified. Risk Analysis The results of the risk analysis are shown in Table 15 and Figure 2. Table 15 presents the cost estimate as originally estimated and as a risk-adjusted cost estimate. As shown in Figure 2, the risk-adjusted project cost ranges from $10.0 to $11.7 million. This range is generally lower than the $11.6 million estimated by R.W. Beck and the $12.1 million estimated by CH2M HILL. The difference can be largely traced to two factors: e The new inclusion of salvage value of the replaced diesel generators and electric equipment. e Ahigh original estimate for permitting and engineering. The distribution of the project cost range is shown in Figure 2. As shown on this figure, a range between $9.96 million and $11.70 million represents our recommended risk-adjusted budget for conditions likely to occur. SEA/1002C1F5.D0C 37 TABLE 15 All Diesel Alternative Risk Adjusted Cost Estimate (1993 Dollar Value) Risk-Adjusted Ranges (as % of Original Cost Estimate) Original Risk- Cost Category Cost Estimate Adjusted _Difference_Low Most Likely High _ Risk Distribution Type Contractor Costs Structures and Improvements 2,000,000 2,172,603 172,603 90% 100% 130% Triangular (10th, 90th Percentile) Engine Generator & Accessories 6,214,000 6,214,000 0 80% 100% 120% Triangular (10th, 90th Percentile) Substation é& Transmission 550,000 621,199 71,199 85% 100% 145% Triangular (10th, 90th Percentile) Delivery 186,000 186,000 0 90% 100% 110% Triangular (10th, 90th Percentile) Subtotal Contractor Costs 8,950,000 9,193,801 243,801 Demolition and Salvage Existing Diesels and Electrical Equipment 0 (413,951) (413,951) (700,0 (500,000) (100,0 Triangular (10th, 90th 00) 00) Percentile) Permitting 500,000 400,000 (100,000) 60% 100% Uniform(as a % of Original Cost) Engineering, Design, & Construction Management 1,491,000 1,267,350 (223,650) 70% 100% Uniform(as a % of Original Cost) Owners Costs 0 365,652 «365,652 -2% 5% Uniform(as a % of Total Cost) Subtotal Project Cost (w/o contingency) 10,941,000 10,812,852 (128,148) Project Contingency 1,184,000 0 Project Risk Allowance (See Note 1) 0 888,148 (295,852) Total Project Cost 12,125,000 11,701,000 (424,000) $EA/1002C1F5.D0C 117526.CO.10 + Risk Simulation Fig.2 + 1/30/96 * GM <AT-T--owrwovv <iAT-C--wrwonvnv @RISK Simulation Sampling= Monte Carlo PROJECT COST 7 #Trials=1000 15% Porc rrr retro snes ssn nesses cece sac sec see ces sores eee | 20% Probability | ‘ | 50% Probability $ 9.96 Million > <—_ $ 10.84 Million EDs Se cin seins Sie a ie Se tie is Seas See Sees |e Sea 5° © | 0) ies | : | < 80% Probability | $ 11.70 Million 5 6 7 8 9 10 11 12 13 14 15 Values in Millions @RISK Simulation — Sampling= Monte Carlo PROJECT COST ___ #Trials=1000 100- pons = BO% p= amen 60%] 40%- 5 6 7 8 9 10 11 12 13 14 15 Values in Millions Figure 2 All Diesel Alternative Project Cost Simulation Silver Lake Option C Risk Assessment In the risk assessment workshop, the risk assessment team identified 31 potential risks to project cost and schedule. These risks were further discussed and then designated as potential fatal flaws or as high, medium or low risks in terms of their potential impact. Extraordinary (extremely low probability) events were not included. This process resulted in the identifica- tion of the following risk factors for project construction: e 2 potential fatal flaws (major risks that might result in project termination), e 11 medium risks (important but manageable risks), and e 18 low risks (possibly important risks but with small likely impacts). These risks are summarized in Table 16. Also included in this table is an indication (check mark) as to whether the risk was integrated into the risk-adjusted cost estimate and notes on potential mitigation for these risks. The two potential fatal flaws and 11 medium to high risks are discussed below. This discussion is organized according to the same risk categories as shown in Table 13 and includes a description of risks, costs and schedule impacts, and suggested methods to mitigate the risks. A discussion on potential schedule risk is also follows. A. Management and Administration Issues. The following are three key management and administration risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk A-1 The public perspective on developing the project will be expressed primarily through the FERC licensing process and the Chugach Native Corporation’s ownership of the principal project lands. No known project opposition currently exists, but could develop as planning proceeds. (Medium Risk) Risk A-2 Site acquisition of the required land rights from the Chugach Native Corporation are vital to the development of the project. Chugach has apparently expressed an interest to negotiate on this matter. (Medium Risk) Risk A-3 This project alternative has assumed that Whitewater Engineering Corporation will be responsible for full development. If a public agency were to assume this responsible additional costs and scheduling delays could occur. (Medium Risk) B. Finance Availability Issues. One key finance availability risk issue was identified. The potential financial impact of this risk issue has not been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk B-1 The project developer may have difficulty in acquiring sufficient financing to carry the project through the FERC licensing process. The most likely risk will be project delays when the required financing is being pursued. (Medium Risk) SEA/1002C1F5.00C 40 TABLE 16 Silver Lake Option-C Project Project Risk Assessment Summary Worksheet Category of Risk Potential Cost Risk Description of Risk Issue Fatal Flaw Cost__ Schedule Adjustment Notes on Mitigation A. — Management and Administration Issues Changing Government Regulations Low Low Goverment Support Low Low Public Perspective (Natural Environment, Medium Medium Vv Chugach Native Corporation, FERC. Socioeconomics) Site Acquisition (Chugach Native Corp.) Medium Low qv Negotiate with Native Corporation Project Management Organization (Whitewater Medium Medium Vv Cost if Publicly Developed Development) B. Finance Availability Issues Pre-Construction (Developer Funding) Low Medium v Initial Capital Needed Construction (Developer Funding) Low Low Available if Project Proceeds C. Regulatory and Permitting Issues Permit Acquisition Federal (FERC License Process) FF Stream Flows Archaeological and Historical Findings _ Low Low D. Weather Conditions (During Construction) Medium Medium Vv Two Months to Build Dam Environmental Restriction on Construction Low Low Availability of Subgrade Testing to Date Medium Medium Vv Risk Adjusted Cost Estimate —. Engineering Planning and Design Issues ‘ Route Selection Low Low Options Available Weather Design Criteria Medium Medium Vv Weather-Sensitive Materials System Performance FF Overstated Energy Construction Management (Developer) Medium _ Medium Vv Risk Adjusted Cost Estimate F. Contractor Issues Competitive Availability of Qualified Contractors Low Low Level of Specification Detail in Design Drawings Low Low FERC to Review Design G. Existing Structures and Equipment and Material Availability Equipment Availability Low Low Materials Availability (Concrete Aggregates) Medium Medium Vv Import Materials/Redesign Equipment Malfunctions and Failures Low Low Material Cost Fluctuations Low Low H. — Construction Logistics and Transportation Laydown Area Limitations Low Low Access to Site (Blasting Requirements) Medium Medium Vv Risk Adjusted Cost Estimate Materials Delivery Low Low Maintenance of Service during Construction Low Low Mobilization Low Low Demobilization Low Low 1 Start-Up and Commissioning Issues Final Inspection Low Low J. Operating Company Issues Maintenance of Facilities Low Low Power Sales Agreements Medium Medium V Risk Adjusted Cost Estimate Category of Risk: FF: Major Risk that Might Become a Fatal Flaw High: Major Risk with Likely Cost and Schedule Implication but Not Fatal Flaw Medium: Important but Manageable Risk Low: Possibly Important but with Small Impact SEA/1002C1F5.D0C 4 C. Regulatory and Permitting Issues. One permitting issue was identified; it is a potential fatal flow for this project alternative. Risk C-1 The FERC licensing process will establish both the amount of flow that will need to be maintained in the diverted reach of Duck Creek and the seasonal flow patterns to be maintained in the reach of Duck Creek below the proposed powerhouse site. Adverse rulings on either issue, particularly the latter, could restrict power generation to point that the project becomes economically infeasible (Potential Fatal Flaw) D. Environmental and Geotechnical Issues. The following are two key environmental and geotechnical risk issues. The potential financial impact of these risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk D-1 Typically there is only about two months of predictably dry weather at the site, late spring, which is suitable for construction of the proposed roller compacted concrete dam. While this amount of time should normally be sufficient, unexpected rains could add significant delays and costs to the project.. (Medium Risk) Risk D-2 Reportedly, little subsurface site investigation has been done to date. These studies are critical to establishing the local availability of suitable aggregates for constructing the dam and the amount of rock blasting that will be required for constructing the access road and pipeline.. (Medium Risk) E. Engineering Planning and Design Issues. The following are three key engineering planning and design risk issues. One of these is a potential fatal flaw. The potential financial impact of the other two risk issues has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk E-1 Site weather conditions and the availability of low weather-sensitive aggregates for construction of the dam are critical to this project alternative. The availability of suitable aggregates can be determined during the early explorations phases of project development. (Medium Risk) Risk E-2 The projects feasibility is extremely sensitive to the amount of annual flows entering Silver Lake. To date, accurate flow gaging data is virtually non- existent. If the actual flows that have been assumed have been overstated by 10 to 15 percent, this project could be unfeasible. (Potential Fatal Flaw) Risk E-3 The entities that will actually construct the project, manage the construction and ultimately own the facility have not been fully identified yet. (Medium Risk) G. Existing Condition of Structures and Facilities and Equipment and Material Availability Issues. The following key risk issue was identified for this category. The potential financial impact of this risk issue has only partially been incorporated into the assumed ranges of the risk-adjusted Project cost estimate. SEA/1002C1F5.D0C 42 Risk G-1 The availability of suitable local aggregates is critical to the construction of the roller-compacted concrete dam. If the materials have to be hauled any appreciable distance or just aren’t readily available, both the cost and schedule will be adversely impacted. (Medium Risk) H. Construction Logistics and Transportation Issues. The following key construction logistics and transportation risk issues was identified. The potential financial impact of this risk issue has been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk H-1 The amount of blasting that will be required for construction of the project access road and installation of the buried piping is generally unknown at this time. Some blasting has been assumed. It has also been generally assumed that the excess excavation materials can be readily disposed of on site. Both assumptions could effect project cost and schedule. (Medium Risk) J. Operating Issues. The following key risk issue was identified for this category. The potential financial impact of this risk issue has only partially been incorporated into the assumed ranges of the risk-adjusted project cost estimate. Risk J-1 The final power sales agreement for the project will include the power purchaser’s requirements for the design, construction, and the ultimate operation of the project. This will probably have some effect on the design and construction of the project. (Medium Risk) Schedule. The risk issues discussed above have both potential project cost and project schedule impacts. The current schedule for project planning is up to 36 months, followed by a 24- to 31-month construction schedule. After reviewing each schedule risk, the team determined that this schedule adequately reflected the potential risks identified. Risk Analysis A construction cost risk analysis conducted for Silver Lake Option C. The results of this risk analysis are shown in Table 17 and Figure 3. Table 17 presents the cost estimate as originally estimated and as a risk-adjusted cost estimate. The distribution of the project cost range is shown in Figure 1. As shown on this figure, a range between $34.1 million and $37.4 million represents the risk adjusted cost estimate for conditions likely to occur. SEN/1002C1F5.D0C 43 TABLE 17 Whitewater Silver Lake Hydropower Alternative C Risk Adjusted Cost Estimate (1993 Dollars) Cost Land and Land Rights Structures and Improvements Reservoir, Dams, and Waterways Turbines and Generators Accessory Electrical Equipment Miscellaneous Mechanical Equipment Structures and Improvements (Trans. Facilities) Substation Equipment and Structures Fixtures, Conductors, and Devices Mobilization Direct Construction Cost (Include. Land Rights) FERC and Other Licensing Cost Design Engineering Construction Management Owners Cost Allowance ‘Subtotal Project Cost (w/o Contingency) Contingency (20%) Total Project Cost Total Project Cost: Expected Value From Risk Analysis Extra Risk Allowance Total Project Cost at 80th Percentile of Risk Original Cost Estimate 1,215,000 1,512,500 14,059,000 3,900,000 910,000 50,000 68,000 325,000 6,440,000 —2.000,000 30,479,500 800,000 750,000 1,000,000 ————l 33,029,500 6.805.900 39,635,400 Risk-Adjusted Cost Estimate 1,615,000 1,577,574 15,063,548 4,067,795 949,152 52,151 70,926 338,983 6,716,697 —1L827.902 32,279,729 1,266,667 750,000 1,000,000 — 352.264 35,649,360 —1.286.540 37,435,980 Risk-Adjusted Ranges {as a % of Original Cost Estimate) Low Most-Likt High 1,215,000 1,415,000 2,215,000 90% 100% 120% 94% 110% 136% 90% 100% 120% 90% 100% 120% 90% 100% 120% 90% 100% 120% 90% 100% 120% 80% 100% 130% 60% 100% 120% 800,000 1,000,000 2,000,000 90% 100% 110% 90% 100% 110% 1% seal002C1F5.doc $SEA/1002C1F5.00C Risk Distribution T) Triangular Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Triangular Triangular (10th, 90th Percentile) Triangular (10th, 90th Percentile) Percent of Project Cost 117526.C0.10 » Risk Simulation Fig.3 + 1/30/96 * GM <i---wrwowvv <i---wrwovv | ___—@RISK_ Simulation Sampling= Monte Carlo PROJECT COST . #Trials=1000 20% Probability | Bell 50% Probability $ 34.05 Million. —> | —r $35.69 Million fa freee nena | | 80% Probabili << 837.44 Millon” 9.00%) ">>> 7 77> ns -1 a ~~ . 6% OT ~ eo a a ~~ 7 3% OT ~ anita teeta - a = | 100 80% 60%7 40Z%- 25 26 29 52 35 38 41 44 47 50 Values in Millions @RISK Simulation Sampling= Mente Carlo PROJECT COST 20% 7-777" 20 25 26 29 52 55 Values in Millions 38 41 44 47 50 Figure 3 Silver Lake Option C Project Cost Simulation DEC-20-95 WED 04:15 PM AG’S ANC GOVT AFFAIRS FAX NO. 907 258 4978 P, 02 ” ‘MEMORANDUM State of Alaska Department of Law tro: William R. Snell oate: December 20, 1995 Executive Director Alaska Industrial Development and Export Authority TEL.NO: 269-5200 . SUBJECT: APUC Review of Intertie 1) Agreements FROM: Virginia A. Rusch Assistant Attorney General Fair Business Practice Section-Anchorage You have asked for a general analysis of the regulatory review by the Alaska Public Utilities Commission that would be vequired for various contractual arrangements related to the proposed Anchorage-Valdez intertie. Although this analysis must be very general given the rather vague information about the proposals and the novel questions they present, this memo sets out suggestions about several aspects of the project. 1) Copper Valley Electric Association’s power sales agreement with the Petro Star refinery. An agreement by Copper Valley Electric Association (CVEA) to sell power to the Petro Star refinery under contract terms that are not available to the general public under CVEA’s tariff would be a "special contract" which must be filed with and approved by the Commission under AS 42.05.361 and 3 AAC 48.390. Such a contract would be subject to the usual "just and reasonable" test for rates and other conditions of service, but the interpretation of these tests would take into account the advantages that sales to the customer might have for the utility. The Petro Star contract may be similar to the special contract with a refinery that the Commission considered and approved in Re Homer Electric Association, Inc., U- 88-25(11), 9 APUC 287 (1989). In that case the Commission approved the proposed contract because the refinery was capable of generating its own power, and would have left the system without a rate reduction. The Commission said: First, there are instances in which it is appropriate to establish rates based on value of service pricing in order to discourage the uneconomic bypass of the electric public utility system. Second, in no instance should rates based on value of service be allowed which are lower than the utility’s variable costs and which do not make some contribution toward the utility’s fixed costs. DEC-20-95 WED 04:15 PM AG’S ANC GOVT AFFAIRS FAX NO. 907 258 4978 P, 03 » William R. Snell December 20, 1995 Executive Director Page 2 Alaska Industrial Development and Export Authority 2) Chugach Electric Association’s power sales agreement. Any agreement by Chugach Electric Association to sell wholesale power to CVEA would be reviewed under AS 42.05.431(hb), which requiree the Commission’s advance approval of a wholesale power agreement. In addition to advance approval, this section provides for some limited continuing oversight. The Commission may not invalidate a contract obligation after initial approval. But the Commission may order the parties to negotiate an amendment or follow contractual dispute resolution procedures if it finds that rates set under the agreement are not just and reasonable. 3) Chugach Electric Association’s agreement to participate in intertie construction. The authority for, and timing of, the Commission’s review ef such an agreement is a question for which I know of no precedents in Alaska. The question is novel partly because, in Alaska, most transmission lines owned or financed by a utility have been within the utility’s own certificated service area. The Commission has not typically reviewed a certificated utility’s decision to add plant within its own service area. However, an intertie outside the service area of any participating utility and not owned by a state agency may trigger a certification requirement under AS 42.05.221. This statute authorizes the Commission to grant a certificate or expand a certificated utility’s service area if it finds the "public convenience and necessity "so require. This standard is broad. It could probably encompass a review of any contractual arrangements made for the construction and operation of the intertie, including the rate impact on customers of a utility participating in the project. The same kind of review might occur as part of an examination of a wholesale power agreement, or might be initiated on a complaint under the Commission’s AS 42.05.511 authority to review a utility’s management practices. vR\mgh ce: Don Schroer, Chairman APUC Bob Lohr, Executive Director, APUC TECHNICAL MEMORANDUM CHMHILL Projected CVEA Cost of Power Assuming State Loan Is Available for Any New Power Supply Alternative PREPARED FOR: Dennis McCrohan PREPARED BY: Dave Gray DATE: January 29, 1996 Summary At your request, CH2M HILL has calculated the projected cost of power for CVEA under the hypothetical condition that the $35 million, interest-free State of Alaska loan for the Copper Valley Intertie could be reappropriated for construction of an alternative power supply project. Use of loan proceeds for projects other than the Intertie is not allowed by the enabling legislation for the loan, but analysis of the effect of reappropriation may be helpful in deliberations on the feasibility of power supply alternatives for CVEA. As shown in Table 1 and Figures 1 through 4, the 80/20 Integrated Intertie produces the lowest cost of power for CVEA regardless of whether the State loan could be used for alternative projects. TABLE 1 CVEA Cost of Power’ for Power Supply Altematives: State Funding for Intertie Only Vs. For Any Alternative (Levelized Cents per kWh, 1999-2013) Low Fuel Cost Forecast High Fuel Cost Forecast Loan for Intertle Only Loan for Any Alternative Loan for Intertie Only Loan for Any Alternative Difference Difference Difference Difference Costper from80/20 Costper from80/20 Costper from80/20 Costper from 80/20 Alternative kWh Intertie kWh Intertie kWh Intertie kWh Intertle 1994 All Diesel 11.24 2.00 10.82 1.58 icra 2.32 11.29 1.90 Modified 1995 All Diesel 10.38 1.14 10.23 0.99 10.91 1.52 10.76 1.37 Intertie 10.09 0.85 10.09 0.85 10.31 0.92 10.31 0.92 80/20 Integrated Intertie 9.24 0.00 9.24 0.00 9.39 0.00 9.39 0.00 Allison Lake* na na 10.63 1.39 na na 10.81 1.42 Silver Lake Option A na na 10.78 1.54 na na 10.82 1.43 Silver Lake Option C na na 9.59 0.35 na na 9.63 0.24 Silver Lake Option C-- na na 9.92 0.68 na na 10.01 0.62 Adjusted* ‘Based on Medium-High/Medium-Low load forecast. “Includes generation charge of 6.4 cents per kWh for generation at Solomon Gulch. “Adjusted for probability that generation will be reduced by 15 percent to maintain adequate in-stream flows during pink salmon spawning season. SEA/$35MILL.DOC 1 PROJECTED CVEA COST OF POWER ASSUMING STATE LOAN IS AVAILABLE FOR ANY NEW POWER SUPPLY ALTERNATIVE Analysis CVEA’s cost of power was calculated for the following alternatives under the assumption that the $35 million State loan would be available for the capital cost of any power supply alternative: e 1994 All Diesel ¢ Modified 1995 All Diesel ¢ _Intertie (with sole financial responsibility by CVEA) ¢ 80/20 Integrated Intertie e Allison Lake e Silver Lake Option A e Silver Lake Option C The definition of each of these alternatives, except for Silver Lake Option C, is included in the Copper Valley Intertie Feasibility Study Update (November 1995); these definitions are not repeated here. Silver Lake Option C is based on a design concept developed by White- water Engineering in November, 1995; it is discussed in CH2M HILL’s technical memo- randum on cost estimates and risk analysis for the Copper Valley Intertie and alternatives (January 29, 1996). Consistent with the Intertie Feasibility Update, CVEA’s cost of power for each alternative was projected for the 15-year period of 1999 through 2013. This analysis was limited to conditions assumed for the medium-high and medium-low forecasts of CVEA loads. How- ever, analysis was conducted to test the cost of power under both high and low fuel price forecasts. Also like the Intertie Feasibility Update, the cost of power calculations associated with each alternative include all generation and purchased power costs projected to be in- curred by the utility. By taking all costs into account, differences among alternatives can be directly translated into differences in CVEA rates. As noted above, results of the calculations are shown in Table 1 and Figures 1 through 4. As shown, the 80/20 Integrated Intertie alternative produces the lowest cost of power for CVEA regardless of whether the state loan could be used for alternative projects. With the state loan limited to the Intertie only, the 80/20 Integrated Intertie would result in a cost of power ranging from 1.1 to 2.3 cents per kWh less expensive than the All Diesel alternatives shown in the table. If the state loan were available for any power supply alternative, the 80/20 Integrated Intertie would range from 1.0 to 1.9 cents per kWh less expensive than these All Diesel alternatives. As noted above, these calculations are based on the assump- tion that the loan would be available only for capital investment in new plant and equip- ment. Since the investment in diesel generation is relatively low ($12 million every 20 years in the 1994 All Diesel alternative), the availability of the state loan for this alternative has less of an impact on the associated cost of power for CVEA it does for other alternatives. Even if the state loan were available for the Allison Lake alternative, its associated cost of power would be 1.4 cents per kWh higher than that for the 80/20 Integrated Intertie. A contributing factor to this relatively large difference is the generation charge of 6.4 cents per kWh for the portion (about half) of generation that would occur at Solomon Gulch with this alternative. SEA/$35MILL.DOC 2 PROJECTED CVEA COST OF POWER ASSUMING STATE LOAN IS AVAILABLE FOR ANY NEW POWER SUPPLY ALTERNATIVE Silver Lake Option A is the same alternative evaluated in the Intertie Feasibility Update. Even with the state loan, CVEA’s cost of power with this alternative would be 1.4 to 1.5 cents per kWh more expensive than with the 80/20 Integrated Intertie. Silver Lake Option C is a relatively low cost design for this alternative. However, in-stream flow requirements from regulatory agencies are likely to result in a 10 to 20 percent reduction in useful generation capability of the project. This is discussed in more detail in CH2M HILL’s January 22, 1996 technical memo on the environmental effects of the Copper Valley Intertie and alternatives and in CH2M HILL’s January 29 technical memorandum on cost estimates and risk analysis for the Copper Valley Intertie and alternatives. Figures 1 and 2 show CVEA’s projected cost of power if in-stream flows are not restricted and if the state loan were available for the Silver Lake Option C project. The associated cost of power would be only 0.2 to 0.4 cents per kWh higher than that with the 80/20 Integrated Intertie. Most of the difference would occur in the first 6 years of Intertie operation (1999- 2005). Thereafter, the cost of power with the Intertie or Silver Lake Option C would be roughly equivalent. Figures 3 and 4 show CVEA’s projected cost of power if in-stream flow requirements result in a 15 percent reduction in useful power generation from the Silver Lake Option C project. Under these circumstances, the associated cost of power would be 0.6 to 0.7 cents per kWh higher than that with the 80/20 Integrated Intertie. SEA/$35MILL.DOC 3 14.0 12.0 ), = ° Cost of Power (cents/k Wh a 3° _ ° 2.0 0.0 1995 1996 Figure 1 Projected CVEA Cost of Power Assuming a State Loan for the Capital Cost of Any New Power Supply Alternative --_Low Fuel Cost_-- 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Year —— 1994 All Diesel — Allison Lake — Modified '95 All Diesel — Silver Lake (Option A) —— Intertie — Silver Lake (Option C) — 80/20 Integrated Intertie Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period. (2) Assumes Medium-High/Medium-Low Load Forecast. 2012 2013 2014 Figure 2 Projected CVEA Cost of Power Assuming a State Loan for the Capital Cost of Any New Power Supply Alternative -- High Fuel Cost _-- 14.0 12.0 10.0 = ° Cost of Power (cents/k Wh) a 3° > ° 2.0 00 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Year —— 1994 All Diesel — Allison Lake — Modified '95 All Diesel — Silver Lake (Option A) — Intertie — Silver Lake (Option C) — 80/20 Integrated Intertie Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period. (2) Assumes Medium-High/Medium-Low Load Forecast. 1 1 Cost of Power (cents/k Wh), = ° 40 2.0 2.0 0.0 Figure 3 Projected CVEA Cost of Power Assuming a State Loan for the Capital Cost of Any New Power Supply Alternative -- Low Fuel Cost & Adjusted Silver Lake Generation -- + 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Year — 1994 All Diesel — Allison Lake — Modified '95 All Diesel — Silver Lake (Option A) —— Intertie — Silver Lake (Option C) — 80/20 Integrated Intertie Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period. (2) Assumes Medium-High/Medium-Low Load Forecast. 1 fl Cost of Power (cents/k Wh), 40 2.0 2 o 2 ° 2 o = ° 2.0 0.0 Figure 4 Projected CVEA Cost of Power Assuming a State Loan for the Capital Cost of Any New Power Supply Alternative -- High Fuel Cost & Adjusted Silver Lake Generation -- 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Year — 1994 All Diesel — Allison Lake — Modified '95 All Diesel — Silver Lake (Option A) —— Intertie — Silver Lake (Option C) — 80/20 Integrated Intertie Notes: (1) Assumes up to $35 million in State loans at 0-percent interest over a 50 year period. (2) Assumes Medium-High/Medium-Low Load Forecast. TECHNICAL MEMORANDUM Copper Valley Intertie Power Flow PREPARED FOR: Dennis McCrohan Alaska ldustiicl Development PREPARED BY: Dave Gray nck Expet Autibttty DATE: January 28, 1996 At your request, CH2M HILL has reviewed power flow limitations, by direction of flow, on the proposed Copper Valley Intertie. This memorandum briefly presents the findings from this review. Power Flow Limitations The current design criteria for the Copper Valley Intertie (from Sutton to Glennallen) is based on the transmission of about 15 MW from generating utilities in the Railbelt to serve loads of the Copper Valley Electric Association (CVEA), primarily in Glennallen and Valdez. The 15-MW capacity limitation is imposed by the design of the Railbelt transmission network, not the Intertie. This transmission capacity will meet CVEA’s present load and allow for some load growth. The Copper Valley Intertie Feasibility Study, completed by R.W. Beck in April 1994 included a detailed transmission system electrical analysis that identified this limitation. This analysis concluded that under certain abnormal conditions on the Chugach Electric Association (CEA) transmission system, CVEA loads greater than about 15 MW will cause unacceptably low voltage conditions on parts of the CEA and Matanuska Electric Association (MEA) 115-kV systems. These abnormal conditions could include line outages for emergencies or for maintenance. In planning for these conditions, CVEA would have three options: (1) it could limit Intertie loads to 15 MW; (2) it could allow for its connection to the Intertie to be severed from the Railbelt grid when loads reach 15 MW,, or (3) it could install and operate Static VAR Compensators (SVC) at one or both ends of the Intertie. With the addition of one or more SVC’s, power flow beyond the 15 MW limit is possible. The SVC is a high-voltage, high-speed, solid-state switching device that can manipulate the power factor of the transmission line load, and thus control the transmission voltage. SVC’s are both complicated and expensive, and are usually installed in specially designed substation buildings where operation and maintenance conditions can be controlled. CVEA has opted to keep its loads on the Intertie below 15 MW and allow for its connection to be severed from the Railbelt grid if its loads surpass the 15 MW limit. Historically this has been a common practice among Railbelt utilities. Once CVEA loads require that CVEA take more than 15 MW over the Intertie, it may install the SVC (and pay for it with revenues from the new load requirements). On the other hand, by the time loads on the Intertie reach this level, transmission conditions on the CEA system may have changed and no longer cause the need for SVC on the Intertie. cvo 1 117526.C0.10 COPPER VALLEY INTERTIE Reverse Power Flow The Copper Valley Intertie could transmit power in either direction. While the power flow capacity from Sutton to Glennallen was established in the Copper Valley Intertie Feasibility Study, the capacity of a reverse flow from Glennallen to Sutton has not been established. A power flow study would be needed to establish the exact reverse power flow limitations with and without SVC. However, it is likely that the reverse flow capacity without SVC will be at least equal to the 15 MW for flows from Sutton to Glennallen. In fact, the reverse flow capacity may well be significantly greater than 15 MW because power flowing into the Railbelt would support voltage on the Railbelt transmission grid. While substantial reverse flow capacity would exist on the Intertie, it is not likely to be used for the foreseeable future. As stated in the Copper Valley Intertie Feasibility Update completed by CH2M HILL in November, 1995, there is little market opportunity for reverse flows on the Intertie. Given the substantial surplus of low-cost gas-fired generation in the Railbelt, there would not be opportunity to market energy priced above 3 to 4 cents per kWh. As indicated in the Copper Valley Intertie Feasibility Update, there are not any identified generation projects in or near the CVEA system with costs as low as in this range. cvo 2 CONFIDENTIAL SUTTON-GLENNALLEN INTERTIE DELIBERATIVE PROCESS Additional Work Requirements Synopsis of Public Meetings Record Construction cost verification and risk analysis of all alternatives Analysis of Allison Lake -- 4 Dam Pool Issues Review Intertie reliability and risk analysis associated with Thompson Pass alignment Briefing on APUC standards for evaluating and approval of the various contracts. => Petro Star => CEA = Rate Payer Tariff Among Classes of CVEA Customers Reasonableness of extending Petro Star's Power Sales Contract beyond 10 years Process and schedule of DCRA -- DOE issuing loan commitment Review and suggest appropriate standards for environmental analysis = Commissioner's Record of Decision (12/31/95 -- Late Finish Date) Decisional Issues Regarding CEA Is the Board of Directors’ of CEA committed to the project and under what terms and conditions? Rate payer impact analysis Justification to APUC Position of Board of Directors regarding use of Project Labor Agreement Need and commitment for environmental offsets and mitigation actions Scope of environmental analysis to properly consider all alternatives on equal basis Decisional Issues Regarding CVEA All or nothing risk -- compromise project possibilities Court Challenge Future Legislative review and action CVEA Rate Structure - distributions of benefits Need and commitment for environmental offsets and mitigation actions Scope of environmental analysis to properly consider all alternatives on equal basis 4. Labor Interest e All or nothing risk -- compromise project possibilities e Jobs = No jobs © Earliest “Best Case” 1997 ® Most likely 1999 e Application of Project Labor Agreement 5: Environmental Groups All or nothing risk -- compromise project possibilities Stay pending court ruling Throw it back for Legislative review and action Scope for environmental analysis to include measurement of environmental externalities = There is no uniform objective standard with which to study and analyze environmental externalities on their affects on given project. Utilities will strongly oppose in all likelihood 6. Concerns Expressed with Analysis to Date e Treatment of subsidies for purpose of calculating rate payers cost of project -- flows only to one of three feasible alternatives from the resource analysis Rather than reflecting a balance & fair consideration of benefit/costs among feasible alternatives, $35.0 million appropriation for Intertie starts out analysis on a skewed bases in favor of the Intertie project. Reliability of construction and operating costs for all alternatives Inadequate review of the social/environmental issues of each of the alternatives as called for at this stage of feasibility review Te Policy Issues e State Energy Plan application e Good government and process issues e Highest and best uses of public funds for legislative intended purpose 8. Alternatives e Finding of feasibility of Intertie and proceed with issuance of loan commitment to CVEA with appropriate terms and conditions e Terminate project and remand back to legislature for future review and action Page 2 h:all\bjfiwrs005.doc e Consensus project (other than Intertie) emerges supported by CVEA, environmental groups, and organized labor e Quarterback audible -- deliberative process call > => => Recognize process is flawed Complete additional work requirements Update analysis and select three(3) best alternatives from resources calculation and run rate payer analysis applying $35.0 loan to all alternatives Select best two or three alternatives, depending on closeness of benefit/cost modeling and proceed with environmental analysis Best project determination made -- receives administration backing (with appropriate terms and _ conditions applied) including legislative modifications as required OTHER ISSUES: Sa Deadline under Petro Star MOU for state to take action on Intertie by 12/31/95 ¢ Legal Concerns = Use of project monies = Application for applying loan benefits to alternatives other than Intertie h:all\bjflwrs005.doc Page 3 The Sutton-Glennallen Intertie A Case Study in Circular Reasoning, Mistaken Assumptions, and Poor Use of Scarce Public Resources Prepared by: Mark A. Foster MAFA November 21, 1995 Rev. | The views and opinions expressed by the author herein have been independently developed and to not necessarily reflect the views, opinions, or policies of any client. Sutton-Glennallen Intertie Conclusion The proposed Sutton-Glennallen Intertie is a poor investment of scarce public capital dollars because it is unlikely to create economic wealth in light of the more economic alternatives that appear available to Copper Valley. Key Findings 1. The Intertie is not a prudent economic investment. The Intertie only appears to become economic under an optimistic set of assumptions that stretch out across the next fifty years. As such, it may well destroy public wealth because more economic power supply alternatives appear to be available. 2. The optimistic set of assumptions required to justify the Intertie on paper, which would not be sustained under a “business case” approach include: e Optimistic and sustained demand growth; requiring PetroStar or a new major industrial facility to stay on the CVEA grid until well into the 2020's. e That the State has an abundance of capital dollars so it doesn’t need to look for the project that makes the best use of its money 3. The Governor’s “working group” fell short of providing adequate assurance that ; : ; wi ad the project is a prudent investment of public dollars. The working groups’s of © recommendation for a ten year take or pay contract with PetroStar does not push the fee Owns wd- Intertie to a break-even proposition under the CH2M-Hill study. 4. Chugach Electric residential ratepayers are slated to pay more; around 80% of the cost of the intertie, resulting in higher rates for them, modestly lower rates for CVEA residential ratepayers, and significantly lower rates for PetroStar. It is unclear. what benefitsthe-residential ratepayers.of- t from these higher higher rates. atron 5. At the present time, the prudent approach to Copper Valley Electric’s power supply appears to be the pursuit of: ‘ YJ? Jv ow moste eulde! t. e Incremental improvements in hydroelectric generation, such as Silver Lake or enhancements to Allison Lake, and e Replacement of existing inefficient diesel generating units with modern, Cost @ efficient units. Mark A. Foster & Associates page 2 11/21/95 Sutton-Glennallen Intertie Introduction The justification for the Sutton-Glennallen Intertie is built upon a house of cards. The card at the bottom of that house is a legislative appropriation for a $35 million, zero interest, fifty year loan to Copper Valley for an electric Intertie between Sutton and Glennallen, subject to a feasibility study acceptable to the Commissioner of the Department of Community and Regional Affairs. Not surprisingly, the efforts to conduct an independent and unbiased feasibility study have been fraught with difficulty. Not the least of which has been the existence of various groups lined up in support of the Intertie, each churning out “justification” to support the project and assure themselves a piece of the pie, which in this case amounts to a $26 million grant.' The CH2M-Hill Feasibility Study Update, the Governor’s “working group” recommendations, and comments made by government officials and electric cooperative representatives reveal their basic justification for the project is the existence of a conditional appropriation, not whether the project is economically feasible. A poor investment is still a poor investment whether you throw public money at it or not. As the appropriation is explicitly subject to a feasibility study, the Administration should ask the fundamental question: Is this a good use of State money? Under that test, the S-G Intertie fails as it is unlikely to yield benefits compared to other power supply alternatives. Unraveling the knots, one finds a long string of circular reasoning and mistaken assumptions used to justify the Intertie. They include the following: Circular Reasoning “We were only supposed to look at whether the intertie was feasible, not whether it was hs \s hec F : sad . ; the best alternative alterna five quer e Economic feasibility requires that the “feasible” alternative be a better investment than the other 4.» i ches. Po wt alternatives. Alternatives are compared to find the best one. Anything else is a sham. aa 7 £ wake wag e Intuitively people will invest in the alternative that will give them the best return, balanced against the ¢ bove d risk. If there are three banks in town offering interest rates of 3%, 4%, and 7%, which one would you wa teas 4 consider the best investment? Somehow the state bureaucrats have become confused and are basically ke vot ' recommending that the state invest in the bank with 4% despite the fact they were able to find an e lo stop , interest rate of 7% somewhere else. we we e Investing in projects that are admittedly not the best alternative will likely destroy wealth over time, not create it. ' At today’s interest rates for long-term investments, a $35 million, zero interest, fifty year loan is roughly equivalent to a $26 million grant. ? Public comments of Riley Snell, AIDEA and Mike Irwin, Commissioner of the Department of Community and Regional Affairs. Mark A. Foster & Associates page 3 11/21/95 Sutton-Glennallen Intertie “If we don’t spend it on this project, it will just get wasted on something else not as important.” ¢ Without knowing what the “something else” is, it is impossible to know whether one alternative is more or less important than another. th Yes, youhaug | . is amounts to a “I’ ine” and “I don’t ho might need it ” attitude. < 2 a “I’ve got mine” and “I don’t care who might need it more” attitude. ou wetie } e Even kids in kindergarten get past this shortsightedness when they learn to share and look for solutions where everyone can benefit. “This project is superior to other alternatives because it will have lower rates due to the state zero interest loan”* e This is simply a reflection of the self-fulfilling prophecy of the subsidy, not whether the particular project is a more efficient use of scarce public capital. e A poor investment is still a poor investment whether you throw public money at it or not. “If Chugach Electric assumes 80% of the cost of the Intertie, the risk to Copper Valley Electric ratepayers will be reduced za e Yes, but the risk is transferred to Chugach Electric ratepayers. It does not go away. e This amounts to a tax upon Chugach Electric customers to pay for Intertie jobs and marginally lower rates for Copper Valley Electric, especially users like PetroStar who have bargaining power to get significantly better rates than residential customers. e Finally, the overall risk that this project is not the best economic alternative, is not reduced. The risk is merely redistributed. If one person loses $100 it hurts a lot. If one hundred people loss $100, it hurts less individually, but the overall economy still loses. In the end, these nickel and dime taxes do add up. Mistaken Assumptions “Requiring a ten year commitment by PetroStar to purchase power makes the project |. Qovl way -27,16 feasible \ oy mets e PetroStar is indeed critical to the economic feasibility of the project under the consultant study. repak 7 e However, under the overly optimistic assumptions consultant study, a ten year commitment to buy power does not make the project feasible. PetroStar needs to stay on the Intertie for a cumulative # a Cae total of around 25 years (past 2020) for the intertie to yield net economic benefits. A simple ' a break-even analysis highlights this problem. > Assorted Intertie proponents. * Rational provided by the Feasibility Study Update, AIDEA, the Governor’s Working Group, and other proponents. Feasibility Study Update. ° Implicit finding of Governor’s Working Group. Mark A. Foster & Associates page 4 11/21/95 Sutton-Glennallen Intertie e Absent a commitment from PetroStar that it will stay on the intertie beyond the time when many have estimated the TransAlaska Pipeline will shut down, one has to rely on a “build it, they will come” mantra to believe that the intertie is feasible. e Even if you believe that significant growth is likely and will be sustained over several decades, smaller incremental approaches to meet that demand are likely to be a more prudent investment strategy.’ “APUC will review the power sales agreements and determine the ultimate acceptability 8 of risk e At best, the APUC is likely to review the power sales agreement for whether customer classes are not unduly discriminated between, not whether the project is a good use of scarce public capital. e Even then, APUC precedents allow large industrial customers to get a discount if they can claim they have a cheaper alternative. Discounts to large customers aren’t free. The difference typically gets reassigned to the residential customers. “The consultant study reaffirmed that other alternatives, such as Silver Lake ’ hydroelectric, are more costly than the intertie. 2 were ladle e & of e This is misleading at best. The feasibility study update reaffirmed that the old expensive designs for new ds. Chl Allison Lake and Silver Lake appear more costly than the intertie under some scenarios. not f Ll e e The feasibility study update consultants acknowledged that less expensive hydroelectric designs could change those conclusions. e The real story is that hydroelectric power offers Copper Valley a competitive alternative that deserves an honest appraisal by the State. The Hydroelectric Story The consultants have simply taken the hydroelectric estimates from earlier cost estimate studies which in JC yer" vse turn where based on designs from earlier studies. When one unravels the thread, the following emerges. a t : nen9 a) Ss The hydroelectric designs used for the cost estimates are based on drilling a whole in the bottom of the My | lake, a methodology more suited for larger scale developments like Bradley Lake. Ne ref to Cont Bey Preliminary value engineering strongly suggests that a siphon design would be better suited for the scale of Peer whedve the developments at Silver Lake and result in considerable cost savings. ”" i: Silver Lake is a competitive alternative that deserves an honest appraisal - an appraisal that has not been done by the State. 1s me ack ouquall Jomo dg os. AM word he es Tae cule . ; Compare a bet on the permanent fund to a bet on the intertie. If they both appeared to be equal in a net present value calculation, were would you put your money? The prudent investor would put the money into the permanent fund because it is a diversified portfolio with lower risk than a one shot capital project. s Finding of the Governor’s Working Group. ° Press release which accompanied the Governor’s Working Group report. Mark A. Foster & Associates page 5 11/21/95 Sutton-Glennallen Intertie “Copper Valley residential ratepayers will see a significant benefit ud ¢ The feasibility study update estimates that CVEA ratepayers benefits average over the first fifteen years of the intertie, around 1.1¢/kWh when compared to the diesel alternative." e But PetroStar is involved in negotiating a special power sales agreement for around 8¢/kWh, well below the average rate. e Every dollar of overhead that PetroStar avoids by negotiating a discount off the average rates is a dollar of overhead that will picked up by other customers - primarily residential and small commercial. e At best, under optimistic assumptions and a state grant worth $26 million, the intertie provides a very modest benefit to residential customers e The ratepayers that stands to benefit from the Intertie is PetroStar. “The appropriate discount rate is the estimated long-term real cost of money calculated based on real interest rates for long-term taxable bonds. ae e The discount rate used in the analysis has a significant impact on the findings." e The discount rate used in the feasibility study update, 4.5%, is too low, because it ignores the real cost of money, including its opportunity cost. This significantly skews the results in favor of the Intertie. Ws Wi i nt R: ed in the Feasibili di at e First, it implicitly and erroneously assumes that capital is plentiful. e The State of Alaska does not have an abundance of public dollars for capital spending." e Since capital is scarce, the acceptance of a proposed investment that has a low prospective discount rate will inevitably cause the rejection or postponement of some other proposed investments with a higher rate of return.’ e Second, it implicitly assumes that each alternative has the same risk. e The use of the 4.5% discount rate in the CH2M-Hill feasibility study update would be characterized as “Neolithic” in business school today because it ignores risk.’ e The intertie is a single large capital outlay that is designed to take care of CVEA for 50 years. The alternative projects, hydro and diesel, can be added in smaller '° The litany from the electric cooperative. "| Consultant Study, ES-4, During the first 15 years of intertie operation, if Chugach picks up 80% of the cost of the intertie, CVEA’s rates would average 1.1 to 1.5 cents per kWh less than the diesel alternative. "2 CH2M-Hill Feasibility Study Update 3 See CH2M-Hill Feasibility Study Consultant Study, ES-3. 4 This is particularly noteworthy since State of Alaska capital budgets have been slimmed down to the $100 to $150 million range in the past few years. 'S See Grant, Ireson, Leavenworth, Principles of Engineering Economy, 8th edition, Ronald Press, New York, 1990, Chapter on “Studies for Government Activities.” ' See Lecture 2, page 2, Class Notes, BA 234, Corporate Finance, Professor Hayne Leland, Haas School of Business, University of California, Berkeley, 1995. Mark A. Foster & Associates page 6 11/21/95 Sutton-Glennallen Intertie increments to match demand as it arises. Utilities are finding that the value of flexibility to meet demand as it arises can be large and that standard net present value methods which discount each alternative at the same rate, effectively ignore flexibility and can be extremely misleading, typically overvaluing large projects with higher risk.'” e Third, the discount rate used ignores the opportunity costs outside the government. Desirable investment opportunities may be foregone by the private sector of the economy. Consider, for instance, certain investment opportunities that are being foregone by those paying taxes to fund a low return project. The appropriate discount rate should take into account the ° ° . . 18 opportunity cost of displaced private spending. e Fourth, interest rates at which government can borrow money do not always reflect the adverse consequences of borrowing. Many borrowings have a concealed subsidy because of the exemption of interest on the debt from federal income taxes.'? Given the current level of interest in the national debt and its consequences, a project which will use government subsidies should recognize the opportunity cost of that borrowing. laws wi itivi is Presented in t e The Feasibility Study Update looks at discount rate sensitivity only on the downside of the inflation adjusted interest rates for long-term taxable bonds. This is extremely misleading and is likely to bias decision makers toward investments that will ultimately destroy public wealth, not create it. e The consultant study tested sensitivity by Jowering the discount rate, suggesting first that there is no cost associated with nontaxable financing subsidized by the federal government.” e The consultant study even went to far as to use a discount rate of zero - which assumes that this project has no risk. In addition, it assumes that there is no opportunity cost for spending public capital on this project. This should receive an award for outstanding bias and a failing grade in capital investment analysis. e At the very least, the sensitivity analysis of discount rates should have included discount rates well above 5%. Higher discount rates place the Intertie further and further behind other alternatives, essentially revealing that the benefits of the Intertie do not occur until considerably into the future. rid “Busi ” i nt Rat e Inthe real world, the true long-term real cost of money is equal to the cost of capital adjusted for the project risk. Otherwise, the net present value method always favors junk bonds over treasuries! 7 See Thomas Kaslow and Robert S. Pindyck, “Valuing Flexibility in Utility Planning,” The Electricity Journal, March 1994, pp. 60-65. 8 See Economic Analysis of Public Investment Decisions, A Report of the Subcommittee on Economy in Government in the Joint Economic Committee, Congress of the United States, together with Separate and Supplementary Views. Washington, D.C.: U.S. Government Printing Office, 1968. ' Note that the state loan is insufficient to fund the entire cost of the intertie. Additional money will likely be raised through some form of subsidized loan from the government. ?° See Table 4, page 29 of the consultant study. Assuming federally subsidized “tax free” financing is free is short sighted given the efforts to cut the federal budget deficit which are likely to be felt in Alaska. Mark A. Foster & Associates page 7 11/21/95 Sutton-Glennallen Intertie Treasuries vs. Junk Bonds Present Value of Expected Proceeds per $1000 face value using the same discount rate Junk Bond (16% Coupon) Treasury Bond (7% Coupon) $160 $70 $160 $70 $160 $70 $160 $70 $160 $70 $160 $70 (discounted at 12%) Qo a we ° ae” wok Present Value $1164 $794 Without any adjustment for risk between the alternative projects, the net present value approach always favors “junk bond” projects. In the business world, discount rates (a.k.a. hurdle rates or minimum attractive rate of return) typically recognize the cost of debt, the opportunity cost of equity, and project risk. In the late 1980’s, surveys of the hurdle rates used in private industry reveal averages in the 15% to 17% nominal range (11-13% when adjusted for inflation).”" More recent studies have confirmed that managers regularly and consciously set hurdle rates that are often three or four times their weighted average cost of capital. a “In modem government finance, discount rates typically recognize the opportunity costs of capital and ‘Veake into account project risk either through risk adjusted cash flows or risk adjusted discount rates. Neither approach was used in the Feasibility Study Update. “The intertie will improve reliability eg Compared to what? The S-G Intertie will only improve reliability if it is more reliable than another alternative. The S-G Intertie might improve reliability to Glennallen, but it leaves in place an historically unreliable existing link between Glennallen and Valdez. Given that Valdez is the larger load and a more likely source of industrial loads compared to Glennallen, local power supply resources located in and around Valdez may provide more overall reliability than the S-G Intertie.” 2! See Lawrence H. Summers, “Investment Incentives and the Discounting of Depreciation Allowances,” in The Effects of Taxation on Capital Accumulation, ed. Martin Feldstein, University of Chicago Press, 1987. 2 See James M. Poterba and Lawrence H. Summers, “Time Horizons of American Firms: New Evidence from a Survey of CEOs,” MIT Working Paper, October 1991; Michael L. Dertouzos, Richard K. Lester, Robert M. Solow, and the MIT Commission on Industrial Productivity, Made in America, Harper Paperback, 1990, p. 61. > The litany from the electric cooperative. Mark A. Foster & Associates page 8 11/21/95 Sutton-Glennallen Intertie ¢ — PetroStar may wish to consider the value of reliable power if it sign s up for a purchase power agreement with the S-G Intertie.”* “The Intertie Capital Cost Estimate is robust’”° e The Intertie Capital Cost Estimate appears low, given: e The size and variability of labor estimates that R.W. Beck found in its phone survey of contractors in its 1994 study. Adjusting for the mid-range of the these labor estimates raises the overall Intertie project cost roughly $15 million, resulting in an overall project cost in the range of $68 million, not the roughly $53 million used in the CH2M-Hill Feasibility Study Update.” e The likely need for a Static VAR Compensator (SVC, roughly $5.6 million in 1993) to permit reliable transfers of power in excess of about 15 MW. Ironically, the high demand growth scenarios which appear to lend support to the Intertie may require the SVC, but its cost has not been included in this feasibility study, which is supposed to take into account a 50 year time horizon. e Even accepting the optimistic demand projections of the feasibility study update, these capital cost adjustments clearly put the Intertie out of the feasibility picture. ** Some have argued anecdotally that the net flow over the existing link between Valdez and Glennallen is toward Glennallen and that the incremental improvements in reliability for Glennallen due to the S-G Intertie will exceed the incremental improvements in reliability for adding additional capacity in Valdez. Absent an analysis which places some discrete value on reliability, it is difficult to know whether the incremental difference in reliability between a hydro and diesel alternative vs. the S-G Intertie and diesel alternative is sufficient to overcome the other cost advantages of the hydro and diesel alternative given a reasonable set of assumptions. *5 The Memorandum of Understanding dated October 31, 1995, between Chugach Electric, Copper Valley Electric, and PetroStar does not specifically address reliability. 26 Implicit assumption of CH2M-Hill Feasibility Study Update by accepting the R.W. Beck Estimate without review. 7 1995 dollars. Mark A. Foster & Associates page 9 11/21/95 Sutton-Glennallen Intertie The Past and Future The Past The Sutton-Glennallen intertie represents a long and dubious tradition that grew out of the hemorrhage of state spending from the oil boom. This has lead to an overcapitalized electric generation and transmission system due to extensive and excessive government funding based on feasibility studies fraught with optimism, circular reasoning, and mistaken assumptions. In light of dwindling state budgets, that tradition should be buried. The Future In contrast, our /ong-distance telecommunications network, which is of vital strategic importance to Alaska due to our vast distances and unique geography, is relatively undercapitalized. This is because the market is competitive and investors require a return on their investment. They need to find sufficient customer demand to generate enough revenue to earn the cost of capital of the firm plus the risk of the individual projects. In short, their projects have to make business sense in a divided market. If the State were serious about leveraging public capital to provide a real possibility of delivering significant public benefits into the next century, it would explore policies aimed at reducing the cost of capital and increasing the infrastructure investments of the telecommunications and information industry.” ?8 The externalities of investments in telecommunications tend to be rather significant. The National Telecommunications Information Administration (NTIA) grants made to communities in Alaska should provide ample local demonstration of targeted efforts. An example of a state that has recognized this and is working to translate the notion into action is Connecticut. There the regulatory commission has recommended that the equivalent of Alaska’s AIDEA be constituted and targeted at developing a superior telecommunication infrastructure in that state. Mark A. Foster & Associates page 10 11/21/95 Sutton-Glennallen Intertie Appendix D dential t fit fi he I #29 That depends upon how tightly one draws the circle of things to consider. One particularly revealing test is to compare residential rates between the following scenarios: 1. Construction of the S-G Intertie with a $35 million loan at zero interest, with a fifty year payback. 2. Invest the $35 million in financial instruments and pay out the difference between earnings and the loan repayment as a dividend to Copper Valley Electric ratepayers. Assume power supply requirements are met by the diesel base case with reasonable financing by means other than “free state money.” a) Pay dividend to all ratepayers based on a flat rate per kilowatt hour, or b) Pay dividend to all residential ratepayers based on a flat rate per kilowatt hour (a variation on the Power Cost Equalization program) How do customer rates compare?” Positive numbers represent the net benefit of the Financial Investment Dividend + Diesel Alternative has over the Intertie Alternative. If the dividend were paid to all kilowatt hours equally, the Financial Investment Dividend + Diesel Alternative provides net rate benefits for many years. Financial Investment Dividend + Diesel Base Case vs. Intertie Investment Net Rate Benefits (All Customers) ¢/kWh Annual Amount 4.9¢/kWh $345 residential, $5300 commercial ~ 1.0¢/kWh $70 residential, $1060 commercial -1.0¢/kWh -$70 residential, -$1060 commercial If the dividend was paid to residential customers based on kilowatt hours, the Financial Investment Dividend + Diesel Alternative provides net rate benefits well into the next century. Financial Investment Dividend + Diesel Base Case vs. Intertie Investment Net Rate Benefits (Residential Customers) ¢/kWh Annual Amount 15.5¢/kWh | $1100 residential 10.2¢/kWh | $720 residential 5.7¢/kWh $404 residential In short, the S-G Intertie represents an investment whose primary beneficiaries are not residential ratepayers. 2° Estimate of the difference between intertie case and diesel case with a dividend from the financial investment. Based on R.W. Beck Study Estimates. Nominal dollars. Mark A. Foster & Associates page 11 11/21/95 01/23/97 09:20 S 222 AIDEA Boo2 Ce COPPER VALLEY ELECTRIC ASSOCIATION, INC. food P.O. Box 45, GLENNALLEN, ALASKA 99588 (907) 822-3211 FAX 822-5586 VALDEZ (907) 835-4301 FAX 835-4328 January 16, 1997 Mr. Mike Irwin, Commissioner Department of Community and Regional Affairs PO Box 112100 Juneau, Alaska 99811-2100 SUBJECT: CH2M Hill Study Update Dear Commissioner Irwin: nanan ree the Copper Valley tertie project in favor of a combustion turbine “omen operational, and financial consideration: of the plan. A critical ingredient to achieving rate recoatiata under the new plan is to receive some form of state financial assistance for acquisition of the combustion turbines. CVEA intends to seek state assistance for purchase of the turbine generation. As a means to validate our internal economic analysis and as a means to support our request for state participation, CVEA requests that DCRA prepare an update to the CH2M Hill report to assess the economic feasibility of the turbines. I have enclosed a copy of our strategic plan for your information. I will forward a copy of our detailed plan to you in further support of this request in the near future. Serving the Copper River Basin and Valdez 01/23/97 09:21 S +2» AIDEA {oo3 CH2M Hill Study Update January 16, 1997 Page 2 Commissioner, CVEA is grateful for your concern and understanding of the power supply dilemma we face. Your support of a solution to assist CVEA with our high-rate problem would be greatly appreciated. If I can provide additional information relative to this request, please call me. Thank you for your consideration. Very truly yours, 3 Robert A. Wilkinson, CPA Interim General Manager ce: Randy Simmons, AIDEA w:\word\raw\97-015nh.doc