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HomeMy WebLinkAbout20060713IPC to ICIP 19, 7, 10, 13.pdfIDAHO POWER COMPANY O, BOX 70 BOISE, IDAHO 83707 RECE\VED 200& JUL \, PM 4: 5 \ IDAHO PUBLIC UT\LlTIES COMMISSION .~-~ An IDACORP Company July 11 , 2006 Jean D. Jewell, Secretary Idaho Public Utilities Commission 472 West Washington Street P. O. Box 83720 Boise, Idaho 83720-0074 Re:Case No. IPC-06- Idaho Power Company s Response to the First Production Request of the Industrial Customers of Idaho Power Dear Ms. Jewell: Please find enclosed for filing an original and two (2) copies of Idaho Power Company s Response to the First Production Request of the Industrial Customers of Idaho Power regarding the above-described case. I would appreciate it if you would return a stamped copy of this transmittal letter to me in the enclosed self-addressed stamped envelope. Very truly yours ~~ (p. Monica B. Moen MBM:sh Enclosures Telephone (208) 388-2692 Fax (208) 388-6936, E-mail MMoen(g)idahopower.com REQUEST FOR PRODUCTION NO. 19: What is the retail rate impact of Mr. Said's request at page 20 for the Commission to approve inclusion of the total project investment in the Company s rate base for ratemaking purposes? Assume for purposes of answering this question that the total project investment includes 60 million dollars for the generating plant and 22.8 million dollars for associated transmission and substation improvements. Please provide supporting work papers. RESPONSE TO REQUEST NO. 19: There is no current retail rate impact associated with the Company s application for a Certificate of Convenience and Necessity. The actual incremental revenue requirement to be requested by the Company will depend upon circumstances that exist at the time of an application for recognition of the Evander Andrews project in the Company s rate base , revenue requirement and rates. The earliest a future retail rate impact would occur would probably be in 2008 once the Evander Andrews power plant is in service. application to change the Company s rates in 2008 to reflect the Evander Andrews power plant could either be a part of a general rate case or a single issue rate case as was the case for inclusion of the Bennett Mountain power plant costs. In that case , the Company identified $50.3 million of power plant costs and $7.7 million of transmission and interconnection facilities costs for a total of $58.0 million in total project costs. The Company quantified the associated incremental revenue requirement associated with the Bennett Mountain project at $13.5 million. This quantification included expenses such as property taxes, property insurance and depreciation expenses , but excluded expenses such as operating and maintenance expenses. Power supply expense impacts were likewise not included , but were IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 21 ultimately captured in PCA computations. The Company has not quantified the incremental revenue requirement associated with the Evander Andrews project. However, assuming the ratio of incremental revenue requirement to total project costs ($13.5 million / $58 million = 23.3 percent) from the Bennett Mountain application might be similar in an Evander Andrews application , an estimated incremental revenue requirement for an $82.8 million project would be $19.3 million. The response to this request was prepared by Gregory W. Said , Manager of Revenue Requirement, Idaho Power Company, in consultation with Barton L. Kline Senior Attorney, Idaho Power Company. DATED at Boise , Idaho, this 11 th day of July 2006. (ft- MONICA B. MOEN Attorney for Idaho Power Company IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER Page 22 CERTIFICATE OF SERVICE I HEREBY CERTIFY that on this 11th day of July, 2006, I served a true and correct copy of the within and foregoing IDAHO POWER COMPANY'S RESPONSE TO FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS OF IDAHO POWER upon the following named parties by the method indicated below, and addressed to the following: Commission Staff Hand Delivered Donovan Walker US. Mail Deputy Attorney General Overnight Mail Idaho Public Utilities Commission FAX 472 W. Washington (83702)----.ll Email Donovan.walker(g)puc.idaho.gov O. Box 83720 Boise, Idaho 83720-0074 Industrial Customers of Idaho Power Hand Delivered Peter 1. Richardson, Esq.US. Mail Richardson & O'Leary Overnight Mail 515 N. 27th Street FAX O. Box 7218 ..x Email peter(g)richardsonandoleary.com Boise, Idaho 83702 Don Reading Hand Delivered Ben Johnson Associates US. Mail 6070 Hill Road Overnight Mail Boise, Idaho 83702 FAX ..x Email dreading(g)mindspring.com Mountain View Power, Inc.Hand Delivered Ronald L. Williams US. Mail Williams Bradbury, P.Overnight Mail O. Box 2128 FAX Boise, Idaho 83701 ---X Email ron (g) willi amsbradbur com Robert D. Looper, President Hand Delivered Mountain View Power, Inc.-1L US. Mail 1015 W. Hays Street Overnight Mail Boise, Idaho 83702 FAX Email rlooper(g) spellc.com ~(b. Monica B. Moen CERTIFICATE OF SERVICE , Page IDAHO POWER COMPANY CASE NO. IPC-O6- FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS RESPONSE TO REQUEST NO. DRAFT Joint BP A and Northwest Gas Association Study of Pipes and Wires Executive Summary Both pipelines and electric grid exp mile of each alternative-natura transmission per unit of ener pipeline would be more associated benefits, an case- and site-specific fpipes and wires ell as how ho finances the project? 2) Bonneville Power Administration (BPA) and the Northwest Gas Association (NGA) agreed to stud economics of delivering energy to load centers via electrical transmission lines versus natural One objective was to determine which is more economically efficient. A second objective determine whether the Federal Energy Regulatory Commission s (FERC) pricing rules outcomes that do not comport with economic efficiency; in other words, whether FE tilt the playing field toward a less than optimal economic outcome. The Work Group compared the economic costs, reliability, delivery effic factors associated with energy delivery to a generator located near a I pipeline versus from an electric generator located near a gas pipeli a 100-mile electrical transmission line. A key finding was that making valid comparisons be physics of the two systems. Natural gas pipelines localized effects as a result of capacity expansions interconnected and redundant. etween the two systems and to ost-recovery for capacity as pipelines and electric power ies is t fthe benefits accrue solely to one party, that , in addition to whatever other costs it must pay to probably for most cases, a natural gas pipeline party than an expansion ofthe electric grid. So, the ; one is incremental, the other is rolled in. However, if the eneration interconnection the two cases would be identical; the ts in either case. cons in pricing principles is one thing; assuming that the merchant transmissionnatu s pipeline industry will transfer to the electric industry is quite another. Our bt on e prospects ofFERC's vision of merchant electric transmission springing up to k congestion coming to fruition in the Pacific Northwest. onclude that, the benefits and costs of both systems may vary widely depending on site- lrcumstances. Both systems now are planned and developed separately. We recommend that ver possible, energy planning and development should incorporate both electrical and natural gas s stems to optimize an integrated system, thereby providing the greatest benefits for society. 2/26/2004 Joint BPA and Northwest Gas Association Study of Pipes and Wires Methodology pipeline and use electrical the distribution system.) This is ration of Pipes vs. Wires Bonneville Power Administration (BPA) and the Northwest Gas Association (NG agreed to study the economics of delivering energy to load centers via electric transmission lines versus natural gas pipelines. One objective was to dete more economically efficient. A second objective was to determine wh Energy Regulatory Commission s (FERC) pricing rules could crea not comport with economic efficiency; in other words, whether tilt the playing field toward a less than optimal economic ou Specifically, the Work Group compared the economic efficiency (energy losses), and other factors associated generator located near a load center via a 100- ile na generator located near a gas pipeline deliv electri 100-mile electric transmission line. Staff from BPA's Transmission Busines belong to the NGA began t dy in participants.) This pape s the ical generation is located adjacent to the load es gas from a main interstate pipeline to the lcted in the bottom portion of Figure an , we assumed that the distance to be covered in either scenarioile at is, we compared a pipeline to an electric transmission line, each e further assumed that the amount of power output from the generator 0 MW. Work Group expertise was tapped to determine that: 1) a 20-inch se nearly all costs are determined on a per-mile basis, this is not a critical assumption. There are no omies of scale for distance; i., costs are directly proportional to distance of the line. 2/26/2004 Figure 1 Illustration of Pipes vs. Wires Comparison New 1500 MW Generator Existing Transmission System f/). ;1( ~r500 kV lines Existing 1500 MW Load f/). ::::s New 1500 MW Load :;; ,t' -- -- - - --- -- --- ------- ---- --- New 1500 MW Generator 2/26/2004 diameter pipe would be the optimal size of a pipe capable of delivering sufficient (250 million cubic feet of gas per day.2 (mmcf/d)) to the plant; and 2) a 500 k would be sufficient to deliver the output of the 1500 MW plant to the load. ibleFor analyzing costs, we considered varied terrain and ownership. to ensure that exactly the same assumptions are used by BP A and NGA companies for gas pipelines, we believe that the f: to afford reasonable comparisons for purposes of this s Pipeline estimates may not reflect the cost of all water terrain being traversed. Significant water cro . ngs pipeline somewhat but have little bearing st elec additional water crossings could add a fe n doll alternative, which is a small percentage i s s is that losses are ignored. We e 100 mile 500 kV line. However ignored. Natural gas pipelines also use fuel for equate pressure in the pipeline. This use is similar magnitude. Therefore the two effects on 'peli es are capital intensive. To test sensitivity, capital costser rs using various interest rates ranging from 7.0 percent to 12.0 P nt rate corresponds approximately to BPA's Treasury borrowing 0 percent rate corresponds closely to the average cost of capital in the r for these projects. Similarly, it is a rate close to what BP A has been quoted mers who have expressed an interest in project financing. Because the 2 This assumes a plant heat rate of approximately 7 000 Btu/kWh. 3 As will be shown below, not only are the projects inherently not substitutable (meaning that an either/or comparison is a false one), the way the costs typically are recovered for pipelines differs from the way transmission costs are recovered. 2/26/2004 Because these projects are than those costs to dete mile of electrical tr unit costs of elec , the pipeline companies who participated in this study have an average weighted cost capital of 8.75 percent, results are shown for that, as well. The costs are shown in Table 1 , Cost Comparison. The transmission the left, the pipeline costs on the right. The top three rows show capital costs per mile, capital costs per 100 miles, and the ann maintenance (O&M) costs (or their equivalent.) The box payment required to payoff the capital investment, bot percent cost of capital. Next, the annual costs are com annual capital payment and the annual O&M c sts. various units and displayed below. Specifi , value and per MWh under various load factors. curre for illustrative purposes. ct into servic typically 24 d compression additions as his period allows for pre- gineering and preparation of process including final iOn equipment and physicalud e required to get commercialtructi f the pipeline, otherwise known as the cess can be as short as two weeks. lines, we assume that planning, which would would nonnally take a year. Environmental work , but would more likely take up to two years. Finally, would take an additional two years. observations in light of the foregoing come to mind. First, this hypothetical smission project is cheaper than current rates. In other words , the dollar per kW-year 4 The costs shown here are economic costs for the purpose of comparing the amount of resources required to develop each alternative. It is not a rate analysis. That means that meaningful comparisons can be drawn among the alternatives concerning the overall cost that society would pay to develop either pipes or wires. However, a quite different analysis would be required to compute actual rates. As such, using these figures as proxies for rates or tolls would be misleading. Although BP A's transmission rate is shown for illustrative purposes, and although the costs shown would roughly approximate rate effects, the two are not strictly comparable. 2/26/2004 Finally, if it were true that one could simp everything else the same it is clear that pi $100 000,000 $6,056,640,51B569, 000000 000 000 000000 056,640 $10516590 $13,414,366 $6,$7,$6, $12,$12,$12, $0.$0,$1. $1.$1,$1. cost of this project is less than what BPA currently charges customers for point-to- transmission service. Thus, the project would meet the "or test"S and would be r into rates. Second, when expressed on an energy basis, this shows how economic can be. Using a 65% load factor, which approximates the typical the fully allocated transmission costs are less than $2 per M line were to reduce re-dispatch costs (or other congestion a of more than $2/MWh, the line would pay for itself, at I (However, the incidence of specific customers' costs co dispatch compared to new transmission capacity. st ("Annual Payment, 30 years ) and "Total Costs per year" is ow natural gas pipelines or their customers would view the cost of mers through a transportation rate spanning the life of a facilities, annual on rate are more representative measures of the customer s obligations, issi n lines are a means of transporting energy, sometimes over oth transport two of the significant energy resources in our s are partially substitutable; either can be used to heat water or But the differences are significant as well. robably most importantly, the physics of the systems differ. In an electrical very thing is integrated-it is one large machine. Any disturbance, anywhere on stem, is "felt" everywhere else on the system, virtually instantaneously. Because of , the system is planned and built on an integrated basis. 5 The "or test" is discussed below. 2/26/2004 One planning criterion unique to electrical systems is known as the N-1 criterion. this criterion, the system (including new system additions or capacity expansi planned such that if the worst possible contingency occurs, the system wil deliver power to load. In other words, if the worst possible thing happ in the case at hand, the new line fails--the system can still meet exists in the natural gas pipeline system. The natural gas delivery system also is planned on an i account what is there already, and recognizes options fI system is arterial. It resembles, at least in so respect flows from large pipelines to ever-smalle eventu the network ( cal) are rt shows the si ation for an load via two 500 kV , it has two 500 kV lines s down, the load can still be . n this example is 3000 W. Adding a third 500 kV able capacity to 3000 MW. ation differs. The bottom part of the figure (in this case represented by 250 mmcf/d of gasIe ith an additional 250-mmcf/d load, one newto e expanded loads. In this case, if either pipeline shuts loa can be met, except to the extent storage is available at the ical system is planned for single and credible double line outages (these are a e event that could take out two facilities). Lines typically experience 1.75 outages er year. They are involved in overlapping outages with another line 0.01 times per year. 6 A more commonly used tenn in the natural gas industry is LDC, which stands for Local Distribution Company. Generically speaking, however, both gas and electric companies serye loads and therefore may be tenned Load Serying Entities. 7 This is a simplified view from both the electric and gas point of view. It is used only for illustrative purposes for the points in the text. 2/26/2004 A single gas pipeline experiences 0.03 outages per year, which is comparable to the for double transmission line outages. Although pipelines experience fewer outa transmission lines, the outages are often more catastrophic and the duration outages is typically much longer. Single line outages typically last 220 double line outages last 108 minutes. Although specific data on pipe available, they are expected to last several days to weeks. This ti the storage availability. Therefore, the overall reliability/avail arguably is lower than the transmission system. (These stat' Statistics " Office of Pipeline Safety (US. Department of! Special Programs Administration). http://ops.dotgov/sta If risks of line failures were equal, the electric as compared to the gas arteriaL However compared and, in both cases, are miniscule failure are situation-specific and depend 0 study. the past, what we are er) appears to be heading y, they are 1) Financing- Funding - Who actually current ratepayers? 4) What ssues are described in the following em based on forecasts of load and resources. BP A, un ook the transmission investments it determined were ith a high degree of probability. Some transmission uded in the network's costs. These included, for example, the ery facilities. So , " network" refers to the high voltage grid in the less of where on the network an investment was made it was financed by ed into rates charged to all network customers. Because the network is ted, upgrades help to provide backup transmission and to maintain voltage ut the system, so that all customers benefit from maintaining reliability. Since stomers benefit, all customers pay. FERC historically has been supportive of this d of pricing for all electric utilities. 2/26/2004 Today s world is different. Now there are a variety of customers-generators, LSEs marketers who buy and sell power and move it across the network. Under the Ope Access Transmission Tariff (OA TT) customers generally fall into two categori Network customers (served under the Network (or NT) rate) and Point-to- customers (served under the PTP rate.) All customers pay for usage of depending either on their load (NT) or their reserved capacity (PTP BP A continues to make investments on behalf of its treaty including the expected load growth of its NT customers. consideration. In the simplest terms, reliability projects improve (or avoid degradations in) reliability. lternati according to a variety of factors, including c 0 dete returns the greatest economic benefit in a the r mer has the option of the cost of capacity finance the costs of the n behalf of its other needed only to meet specific era!. Because the investment stomer, that customer must come ERC's so called "or test." According to that ge its customer under these circumstances either theme ost, but not both. The "but for test" is about who e "or test" is about how much they pay. ts fi ial investment, the customer receives a credit on its transmission credit is sufficient to repay the customer for its financial investment because ould be applied according to prevailing transmission costs. In other words g transmission rates are credited to the customer s account to repay its financial ment. In the case at hand, for example, the customer would invest $186 million us interest) to finance the new 10O-mile capacity addition. At current rates of 8 Or, more precisely, who takes the risk. 2/26/2004 $12. 16/kW-year, the customer s bill would be credited with that price times the amo nt of transmission acquired until such time as the principal and interest were repaid F or the other network c principal), had BP A would be the diffe project than the U then be re aid, wi enew the $186 ts books repays gainst s paymg To the customer the investment becomes a sunk cost and transmission is as long as it takes to repay the investment. Thus , there is a tangible ec the customer for its investment. As we will see, this is similar to h financed and funded. Note that while the customer takes the risk by financing project. The distinction is important and, as we will se world envisioned by FERC. Let's say the Hoozit Gen million project that is the subject of this repo 9 BPA including interest charges, and adjusts its the investment (and investor, Hoozit) by Hoozit's transmission usage. Once the i for subsequent transmission usage. generation (or load) recover costs and all re ratepayers on the e if the "OR" test ew service exceeded the e incremental cost exceeded the ew customer.rnl future direction. How does Hoozit benefit byall eive any money for its investment, just a creditill. y a tangible economic benefit? The answer is yesf e eneurial decision-making. It is instructive to compare ther ellers. Some other sellers may have purchased long-term ission out of existing capacity. Like Hoozit, these sellers ission costs as "sunk " because they are required to pay for the egar ess of whether they use it. Other sellers may connect to the system transmission rights and take the risk of using non-firm transmission as n average, at today s rates , " free" transmission means that Hoozit has about advantage over these other sellers who to pay for transmission as they use it. sellers would then avoid the $186 million investment, but would have to pay about /MWh for transmission, when transmission is available and it is economic for the 9 Assume the "or test" does not trigger. That is the usual case. 2/26/2004 Predicting where FE , but the general FERC Standard M related ac ' . ties, b not up fthe est of the sellers to run their generators. If transmission were not available at any time, the se that depend on nonfinn transmission could not sell the power from their generat Note that whether Hoozit sees the transmission investment as a sunk cos when the decision is made. Prior to undertaking the project financin , question Hoozit faces is whether paying up front for the new tran worth it compared to facing the congestion costs and risks it expansion not made. At that point, there is no sunk cost. undertakes the financial investment, it owns transmissio Moreover, on the path in question, because Hoozit has congestion costs, while any other party withou Inn rig in time, the transmission appears to be free gener initial investment (financing the 1500 M 'ty exp transmission service clearly was not free. ork. FERC proposes that etwork. (By this, they on rates.) Generatorsit s-LSEs, generators, and costs, primarily redispatch costsan edge congestion cost risk by the acquisition ofts , in the case ofRTO West, CatalogueRs) can be acquired through existing rights, by auction , or by funding the investment in transmission capacity nding is envisioned by FERC to be the key to developingex ns. This is more than participant financing, as is possible in. Th ustomer pays for the project and receives in return an amount of e period. Regardless of how a customer acquires its CRRs, their value is as mst congestion costs. , Hoozit gets a financial credit worth about $2/MWh over the life of its contract. morrow, Hoozit gets CRRs as a hedge against congestion costs. Economically, there 10 Other costs such as those equivalent to today s Transmission Scheduling charges applicable to all schedules may apply, but are not relevant to this analysis. 2/26/2004 That's not all. Once Hooz increased and congesti nodes) may increas one location to red congestion costs of WInners osers. on the rofit from funding the zit waits, someone else may n the latter case, it wouldn' may be reduced as a result of lower shouldn t be much difference, at least in principle. Both represent advance purchases transmission services. In fact, differences may and probably will arise. One obvious difference is that today Hoozit knows that other similarly situ will incur essentially the same level of transmission costs, either as up fr new construction with credits, take or pay transmission payments fo transmission out of existing capacity, or pay as you go transmissi term firm and nonfirm transmission. Tomorrow, Hoozit will investing a known amount for a network expansion and re facing an uncertain amount of congestion costs in the fu congestion costs it faces when it makes its investment, b congestion costs it faces subsequently. In addif , its in transmission capacity) will have its own eft! other some predictable, some not. On top of tha capaci generation) will further change the various ion co the value of the CRRs, as compared to cre ay oday s system, for the same reasons. ozit would have a clear $2/MWh advantage over d be greater under the SMD proposal, or less; but it of aying for the rolled in costs of the transmission system is thatt pa r the embedded costs of transmission. There is really no such r test." If the generator determines that the avoided congestion costs are finance and fund the capacity expansion, regardless of how that cost average embedded costs. y, FERC contemplates that regional state advisory boards would inform nsmission providers when new generation capacity is required to meet resource 2/26/2004 adequacy standards as loads grow. This would be similar to today s network planni reliability. These costs would be rolled into the transmission provider s compan and passed along to all LSEs. This is viewed by FERC as a backstop. It beli avoiding congestion costs will provide sufficient economic incentives to participants to fund transmission capacity expansion. For the case at hand is for the transport of the new 20" pip pays for the embearteria for Natural Gas Pi eline Fundin and Pricin FERC defines three types of pipeline projects: an expa (such as the case that is the basis for this report), a proj customers (analogous to transmission upgrades for reli two. The Commission s policy is that no sub' ies sh benefit must fund expansions for addition ice. I cannot be demonstrated, existing custom 0 be h Expansion shippers must be willing to p of the project. (See Appendix 2, Curren for more detail.) al service existing n of the ewho sts) SlOn. 11 costs ipelines r who pays the average, or customers benefit from the enerator pays only the embedded ower transmission pricing construct for new customers is that the shipper does not necessarily does have to fund the project. If the pipelinere tract tenns, the pipeline owner, perhaps using a variety shi ers, undertakes the financing and funding for the project.ne aid by the rates that are charged to the shipper(s.) No shippers e s will pay any of the costs of the capacity addition. It will beby e shipper. This corresponds to financing, funding and paying for ities on the electric grid, but not to the hypothetical network expansion where. 11 If, however, the pipeline expansion can be achieved by looping an existing line and the toll is less than the existing toll, the costs are rolled into existing rates. This would be similar to expansions ofthe electric grid for reliability purposes. 2/26/2004 nes and electric power tab1ish clear and As stated previously, there is no perfect analogy or substitutability between a pipeline a transmission line. The closest thing to an electric network would be the main t the pipeline system. All gas must pass through these arterials. Branching pipe however, have a clearly defined physical point of delivery and mayor may interconnect with other pipelines. Expansion shippers mayor may not increase the capacity of an e . analogous to expanding electrical network capacity. Generall would be at least some benefit to existing customers. Ther expanded service mayor may not have to pay an increme case that most closely resembles the hypothetical case at i Although this pipeline-pricing concept differs transmission capacity expansions, it appear under FERC's SMD NOPR. Shippers who pipeline rate, regardless. It is a sunk cost i equivalent to saying there is zero cost for would face zero cost transmi nder th alleviate the costs of con ey in expansion, just as as 0 inc alleviate "congestio cost where from 40% to 50% less of energy via electrical vanta of pipelines increases directly as distances-and 100 miles is reasonably lly efficient.ies be consistent across both pipelines and electric In ases, existing consumers are protected against the pan ns. If they benefit from the expansion they will pay costs; if they don t benefit, they will pay nothing additional. clear that merchant electrical transmission will be forthcoming env ons. c and gas transmission systems are planned independently. Planning the y system in a more integrated fashion could bring additional benefits to nsumers. Generally, it will be cheaper to transport gas to load centers, but there 2/26/2004 Consistent with our findings, we do see plants and building pipe, but fewer cases of locatin transmission; for example, the Gray s Har pipeline spur was built from the I-5 corrid sometimes dominate decisions about plant effect is. As it was beyond the ope of t which to rely. are many circumstances in which electrical transmission upgrades would be economIC. Recommendations and Next Steps As the region s energy needs continue to grow and change, consume integrated planning and development of the energy delivery syst pipelines will be cheaper than electric transmission lines, esp but as we found, there are numerous instances where elec even the only alternative. ocess to identify tnering of electric prospective generators. The I time and for system planners. er one, but in both systems working inng natural gas pipelines and for electricnd be consistent. However, while merchantnd developed in the pipeline industry, it is not in the stry. It remains to be seen whether FERC's vision of network ted largely by merchant transmission will be fulfilled. ed at FERC's decisions and how utilities are required to finance and fund nsions. We did not, however, examine actual cases of merchant n. On the electrical side, in the Pacific Northwest, there are practically none. notable exception is the transmission required for generation interconnection looks very much like merchant pipeline additions. However, that is far removed m merchant transmission on the electric grid, an unproven concept in the region. 2/26/2004 As we noted, it is often the case that the direct beneficiaries of a pipeline addition ca identified. Because they have a property right with a clear economic value, fina requires rates of return somewhere in the 8 to 12 percent range, depending 0 equity costs. In other words, it is a fairly low risk transaction. Such is not the case for merchant electric transmission. Recall tha transmission in the future goes beyond financing the investme credits on one s bill. In the future, merchant electric trans fund the investment and receive Congestion Revenue Ri transmission owner thereby acquires a property right, w unknown economic value. It is easy to imagine that the would be much higher than we observe with line ow willing to undertake such investments in t Although R TO West, the proposed regio Northwest, will have backstops to ensure when or even whether R T will ac owners will always be C' s jur merchant transmiss We recommendfu about the charact ordi uld be useful t ose that create ne model to th c Northwest, gas pipelines gy. However, we did not ver such a distance, the i s become more economic than ions a uired as are with Alternating lower. ffsetting that, a converter station is n fact, their cost prevents DC lines from being ot Ii the regional transmission grid, TransCanada g t ssibility of building a DC line from Northern Alberta to While that project is not to transmit electric power generated byces it is not far-fetched to imagine another Canadian entity proposingrectI the gas field and transmitting electric power via DC lines to the est, or even California. Whether it would be economic to do so is unknown. mend that the same regional body consider long distance energy transport in y and to report on its findings. We also caution readers of this report to limit our mgs to the Pacific Northwest region. 2/26/2004 Supporting Members ofNGA Appendix 1 Participants in BP AlNGA Study Bonneville Power Administration Northwest Gas Association (NGA) A vistacorp Duke Ener Kevin Christie Jan Caldwell 2/26/2004 Appendix 2 Current FERC Expansion Rate Policy for Gas Pipelines In the Policy Statement, the Commission defined three projects: an expansion project to provide additional se to existing customers by replacing existing fa . ities, i additional flexibility; and a project that co s an e improvements for existing customers. U Com existing shippers should not have the rat their the pipeline has built an expansion to pr ice t customers ' rates can be inc for pr imp project combines an ex 'th im to increase existing line facilities are need -Ill The Commission s September 15 , 1999 Policy Statement12 on proposed gas pr . established a no-subsidy policy favoring incremental pricing of pipeline ex thereby changing the Commission s previous policy of giving a presum rate treatment for pipeline expansions. The Commission found that r sends the wrong price signals by masking the true cost of capaci shippers seeking the additional capacity. et finds an ex IOn project urchase capacIty at a rate xi sting shippers through the subsidy is necessary to er the pipeline or its ddition, the no-subsidy s 0 not receive unfair advantage in ntrant pipelines. hat is made possible because of earlier, costly disadvantaged because incremental pricing Iving a subsidy from existing customers becauseno the full cost of the construction that makes their new mm sion indicated that the issue of the rate treatment for suchili e that always should be resolved in advance, before thethe ine. Typically, pipelines file to apply current system rates for the agr e to address rate issues in the pipelines next rate case. 12 Citing Certification of New Interstate Natural Gas Pipeline Facilities (Policy Statement), 88 FERC ~ 227 (1999), clarification, 90 FERC ~ 61 128 (2000), further clarification, 92 FERC ~ 61 096 (2000). 2/26/2004 IDAHO POWER COMPANY CASE NO. IPC-O6- FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS RESPONSE TO REQUEST NO.1 0 Customer Relations & Research DSM Programs January 2004 r---Energy Efficiency Leader Program Specialist - Residential Program Specialist - Residential Customer Relations & Research DSM Programs January 1 2005 Energy Efficiency Department Leader I---Assistant Economic Analyst Program Specialist - Industrial Program Specialist - Commercial Program Specialist - Special Needs Program Specialist - Residential Program Specialist - Residential L - - -- -- - -- - --------- ---- Market Segment Coordinator - Irrigation Customer Relations & Research DSM Programs January 2006 Energy Efficiency Leader Department Assistant Economic Analyst Program Specialist - Industrial Program Specialist - Commercial Program Specialist - Special Needs Program Specialist - Residential Program Specialist - Residential Program Specialist - Irrigation L______-- -- -- - -- - - --- ---- Market Segment Coordinator - Irrigation Customer Relations & Research DSM Programs Brief Job Descriptions Energy Efficiency Leader: The Leader position is responsible for supervising all aspects of development, implementation , and management of the Company s demand-side management programs, including regulatory reporting and regional representation of the Company in energy efficient associations. Program Specialist-Residential: Responsible for energy efficiency and/or demand response programs for residential customers including program design, process development, system integration, marketing and communications, contract management, and daily operations. Program Specialist-Industrial: Responsible for energy efficiency and/or demand response programs for industrial customers including program design, process development, system integration , marketing and communications , contract management, and daily operations. Program Specialist-Commercial: Responsible for energy efficiency and/or demand response programs for Commercial customers including program design , process development, system integration , marketing and communications, contract management, and daily operations. Program Specialist-Special Needs: Responsible for energy efficiency and/or demand response programs for customers with special needs including program design , process development, system integration , marketing and communications, contract management, and daily operations. Market Segment Coordinator -Irrigation: Responsible for representing irrigation customers interests in programs and other Company activities. Responsible for energy efficiency and/or demand response programs for irrigation customers including program design , process development, system integration , marketing and communications, contract management, and daily operations. Economic Analyst: Responsible for demand-side management analysis , financial , statistical, and economic analyses to determine company, customer, and societal impact of DSM programs. Department Assistant: Responsible for administrative support for the energy efficiency and demand- side management staff. ID AH POWER CO MP ANY CASE NO. IPC-O6- FIRST PRODUCTION REQUEST OF INDUSTRIAL CUSTOMERS RESPONSE TO REQUEST NO. Response to Request No. The information requested is CONFIDENTIAL and is not provided to Mountain View Power