950810.docx

MEMORANDUM
TO:COMMISSIONER NELSON
COMMISSIONER SMITH
COMMISSIONER HANSEN
FROM:BRAD PURDY
DATE:AUGUST 10, 1995
RE:CASE NO. IPC-E-95-5:  IDAHO POWER’S MOTION TO STRIKE ROSEBUD TESTIMONY
On August 8, 1995, Idaho Power filed a Motion to Strike all of the testimony of Rosebud witness Richard Slaughter on the ground that the testimony is irrelevant and immaterial to the issues pending before the Commission in this case.
Slaughter raises a number of points which he believes generally supports his argument that the Twin Falls plant is not used and useful and should not be included in the Company’s revenue requirement.  Slaughter argues that Idaho Power was never given an absolute guarantee that Twin Falls would be ratebased if conditions, subsequent to the Commission’s original Order, changed rendering the project non-economic.  Slaughter asserts that such changes did occur.  First, the Company’s load did not increase to the extent anticipated in the original Order.  The deficit date contained in Order No. 23357 and which was used to calculate the avoided cost rate to which the Twin Falls project was compared was 1993.  Slaughter notes that Staff witness Tom Faull utilized 1997 as his deficit date knowing that upcoming cases would present later dates.  Faull’s rebuttal analysis was performed in April 1993.  Order No. 25021 was issued in July 1993 and plant construction began in August.  Slaughter argues that the Company’s knowledge and view of avoided cost was significantly different in August 1993 from the Commission’s view in April of the same year.
Idaho Power, through witness John Willmorth, filed avoided cost rates in December 1993 for a 1 MW plant of $41.80/MWh for a plant with a 50 year life expectancy going on line in 1995.  Slaughter contends that these rates proposed by Idaho Power were significantly below the cost commitment accepted by the Commission for Twin Falls and just above the lower cost estimate for the combined plant assuming the risk of loss of the entire site.  
Slaughter notes that Dr. Willmorth makes two points: one, that the 2006 deficit date in the 1993 IRP is in part a function of the Twin Falls plant and; two, that Twin Falls was already in the IRP in 1991.  Slaughter contends that Idaho Power is hiding behind a technicality by arguing that Twin Falls was in the IRP in 1991.  The Company unilaterally selects those resources that go into the least cost plan.  The fact that Twin Falls was already included in the plan means only that it was never rigorously subjected to analysis based on the plan.  
Furthermore, Dr. Willmorth’s exhibits in the 93-28 case, based on the 1993 IRP, indicate a 46 MW surplus in 2003.  Removing the Twin Falls upgrade, and even removing the Meridian QF, would not put the Company into resource deficit until 2003, under the Company’s schedule.  Thus, the surplus period on which to calculate an avoided cost, entirely separate from the fuel cost and capital cost assertions made by the Company in that case, would have a significant effect on the avoided cost against which Twin Falls was measured.
Slaughter further notes that on the same exhibit, Willmorth shows the Twin Falls upgrade increment at only 5 average megawatts in comparison to the Meridian QF plant at 46 average megawatts.  He argues that it is inconceivable that five average megawatts would make an eight year difference in resource deficit.  It also does not comport with Packwood’s use of a 42% capacity factor in the same case.  
Changes in Technology
Slaughter asserts that the Twin Falls upgrade carries a capacity cost of about $1,054/KW.  He further argues that Willmorth’s testimony filed in December 1993 on the basis of the 1993 IRP, shows proposed capacity costs for a CCCT of $652/KW.  The estimated capacity factor of a CCCT is in excess of 90%.  In the initial Twin Falls proceeding, Packwood estimated a year-round, multi-year average capacity factor of 42.7% for the combined plant.  Slaughter argues that this is exaggerated.  He notes in its 1993 position paper, the Company indicated that it was willing, at that time, to abandon the proposed Shoshone Falls upgrade because of changing conditions.  The 30-year levelized cost of Shoshone Falls upgrade, according to the 1993 IRP, was 38.45 mill/KWh.  This is inside the range of 31 to 41 mill/KWh for the Twin Falls plant but based on a 50 year life.
The 1993 position paper goes on to state that non-firm energy has been available in the wholesale market virtually around the clock over the last 10 years and, when firmed by capacity purchase or construction of the peaking unit, such wholesale energy purchases provide equivalent reliability to long-term firm energy plus the cost of affirming resource.  From this statement, Slaughter concludes that firm, 90% plus capacity factor equivalent energy can be purchased at surplus prices plus the cost of the CT at about $350/KW.  Such an option would be cheaper than purchase of the Twin Falls upgrade even including the potential loss of the original 9 MW.  
In comparing the capital costs of Twin Falls to those of a CT or CCCT, Slaughter concludes that the amortization cost of the Twin Falls project is highly dependent on capacity factor.  Twin Falls appears to be economic against the old avoided cost thermal technology with a 42% capacity factor and operating costs below 7 mills/KWh.  At 35% capacity factor, however, it is non-economic.  Thus, given advances in technology performed??? by the Company in this 1993 case, Twin Falls becomes marginal even at 42% capacity factor.  An inefficient CCCT with fuel costs below 20 mills/KWh and operating costs about 3 mills/KWh running at 90% capacity is still cheaper than Twin Falls.  
Changes in the Regulatory Environment
Slaughter contends that there had been two specific changes that have occurred since the Commission issued its original Order in the Twin Falls case.  The first is the advent of retail wheeling which promises to allow customers to acquire energy from suppliers of their choice.  Implicit in this policy is the elimination of the obligation to serve customers from specific resources: an obligation the Commission relied on in its final Order in the original Twin Falls case.  Slaughter projects that larger industrial customers may leave the system and other customers will be stuck with a resource (Twin Falls) that is relatively high cost.  Slaughter argues that Idaho ratepayers will receive no continuing benefit from capacity costs that they have already incurred and will pay for five or ten years of capacity charges at a time when no capacity was needed.  Thus, deliberately bringing Twin Falls into rate base ahead of need is especially damaging to current ratepayers because the anticipated 50 year benefit will not occur.
According to Slaughter, Idaho Power’s position paper notes that the “regulatory compact” may someday be completely eliminated in favor of competition.  Thus, purchasers who commit to long-term obligations at fixed prices without the assurance of corresponding regulatory or customer commitments will suffer.  Slaughter concludes that because investment risks in the future will lie entirely with shareholders and not ratepayers, it will become necessary to base investment decisions on return, not the regulatory compact.  On that basis, the Twin Falls expansion becomes a stranded asset at current retail rates because the market will not “meld asset costs.”  
Slaughter believes there are two dimensions to the FERC policy regarding high cost resources.  First, utilities are required to identify and mitigate potential stranded assets.  Second, the FERC will no longer conduct an economic feasibility analysis in the granting of licenses.  At the same time, no future resources will be eligible for cost recovery.  In essence, if an asset cannot provide a business return on investment, then shareholders will take the hit unless bailed out by state commissions.  Slaughter believes that Idaho Power knew of these impending changes prior to starting construction on the Twin Falls plant based on its position paper published in September 1993.
The second regulatory change involves the Company’s power cost adjustment.  Slaughter argues that estimated output from Twin Falls reached the projected combined capacity factor only once in the last eight years and only six times in the last 18 years.  Prior to 1993, he asserts, Idaho Power’s rates were based on normalized water assumptions with no variation for weather.  Because Idaho Power used normalized water assumptions, ratepayers acquired little additional capacity to compensate for low water conditions.  In March 1993, the PUC authorized Idaho Power’s PCA to compensate for variations in the weather shifting the risk from shareholders to the ratepayer.  Slaughter believes that this affects the value of capacity because formerly, ratepayers realize the benefits of capacity that they have paid for: either there was water in the rive or the shareholders would make up lost output through purchases or use of thermal resources.  Today, however, during dry years ratepayers lose the value of capacity they have paid for in rates.  Unfortunately, Slaughter argues, the reverse is not true, i.e., ratepayers do not make up in wet years for lost benefits in dry years.  During wet years, all of the Snake River hydro systems produce excess energy during the spring months of March through May.  The value of such energy to the ratepayer, however, is limited to the reduction in fuel costs at Idaho Power’s thermal plants or to the spot market value at that time whichever is less.  There is effectively no value for capacity.  
As a result, Slaughter submits, the ratepayer has the worst of both worlds: capacity and hydro systems have no value when there is no water and they have little value during spring runoff during spring runoff during wet years when spot prices fall to near operating costs.  The logical effect is to raise the true capacity costs paid by the ratepayer for used and useful capacity.
Slaughter admits that the Commission refused to provide the recovery of capacity purchases from the PCA.  The capacity component of energy purchases or capacity authorized by the Commission, however, is not excluded.  The PCA allows the recovery of all energy costs whether through fuel costs or energy purchases, provided that there is no explicit capacity purchase.
Value of Twin Falls Capacity
As mentioned earlier, Slaughter believes that the 42% capacity factor estimated for Twin Falls is exaggerated.  This is because it incorporates no adjustment to reflect the shifting of risk accomplished through the adoption of the PCA.  Thus, while it may have been an appropriate calculation at the time the final Order was issued in the original case, it was not appropriate at the time construction was begun in August 1993.
Slaughter argues that Snake River hydro is not the reliable resource it once was.  In 1993, during the peak hour, Snake River hydro produced at 65% of capacity, including Twin Falls at 55%.  Idaho Power’s thermal resources in the area produced at 93% (Bridger 100%, Boardman 0%).  Non-utility generators, including QFs produced at 100% of capacity.
In 1991 Snake River hydro performed slightly better but not by much.  Slaughter calculates that the overall capacity estimates for Twin Falls for 1991, 1992 and 1993 are 11.1%, 8.5% and 27.8%, respectively.  In a normal July, the plant produces 20.2% of its annual output.  In July 1991, the estimate of 7.5% and in 1993, 8.0%.  In 1992 it produced nothing in July.
Slaugher concedes that a hydro facility is more valuable for load shaping and load following than other technologies although no evidence or calculation of the amount of such value was ever presented in this case.  In any event, there is little value and capacity if there is no fuel available.  By contrast, Idaho Power has presented a position paper indicating that both energy and capacity are available on the wholesale market throughout the year at attractive rates.
Slaughter concludes that Twin Falls is a very unreliable plant due to variations in stream flows.  At its highest output, it would have produced 84.4% of capacity but at its lowest, just 8.4%.  Slaughter argues that capacity that cannot be used during dry years should carry a zero value.  Capacity that produces energy when it has little value should likewise be eliminated from the calculation of whether the resource is cost effective.  Thus, the cost of capacity should be based on expected ability to produce energy at times when the energy has market value equal to the total of capacity costs, operating expense and required gross margin.  Slaughter concludes that Twin Falls does not satisfy this standard.
He notes that Staff compared Twin Falls to a coal plant whose capacity is always fully available contrary to a hydro plant with a capacity available only when there is water in the river.  Slaughter recommends that capacity be valued for Twin Falls as follows: first, capacity should have no value until at least 2003, the earliest deficit date in company planning adjusted for removal of Twin Falls and Meridian.  Second, the capacity factor should be adjusted for the effects of wet and dry years.  This is justified by adoption of the PCA which shifts risks from shareholders to ratepayers.  The cost of dry years has always be greater than the benefit from wet years because useful capacity is worth more during dry years.  Slaughter’s calculations yield an average capacity factor for Twin Falls of 35%.  Using the avoided cost model, the 50-year levelized cost of Twin Falls with a 35% capacity factor is just over 57.65 mills/KWh.  Slaughter believes that Idaho Power was aware of this when it began construction in August 1993.
Slaughter concludes there that is a high probability that Twin Falls will become a stranded investment.  He argues that the Commission should give Idaho Power every incentive to mitigate its investment even at the cost of also losing the existing 9 MW of capacity at the site.  He recommends, first, that the Commission defer placing Twin Falls into rate base until the identified year of deficit without Twin Falls (2003).  Because by 2003 Idaho Power may no longer have an obligation to serve its existing customers, Slaughter argues, the investment will by that time be entirely a matter for shareholders.  
Second, he recommends that the Commission signal its approval of efforts by Idaho Power to mitigate its investment in the Twin Falls expansion through the firm sale of energy and capacity or of the physical asset and the FERC license itself.
IDAHO POWER’S MOTION
Idaho Power cites, at length, language from the Commission Orders granting Rosebud’s Petition to Intervene, denying Rosebud’s Motion to Dismiss and denying Rosebud’s Motion to Compel.  Arguing that Rosebud has ignored the pronouncements of the Commission and is attempting to relitigate the issues decided by the Commission in the original case by repackaging its prior arguments in new testimony.
First, Slaughter’s testimony makes no reference to the amount of investment in the Twin Falls project that should be permitted into rate base which, by order of the Commission, was the purpose of this proceeding.  Instead, Slaughter challenges the content of witnesses in the 91-4 case.
Idaho Power also argues that Rosebud’s arguments are substantively defective.  For instance, Slaughter does not demonstrate that demand for power has fallen as he contends.  He simply asserts that Idaho Power’s resource plans show that the type of future resources that may be used to satisfy future demand may be changing.  The Commission has yet to fully consider Idaho Power’s future resource plan, the Company argues.  In any event, that plan speaks to future resources.  The “technology change” Slaughter refers to is not the manner and method of constructing hydro facilities has changed but that regulation as a “technology” may change.  Idaho Power argues that future regulatory issues are irrelevant to the issue of the ratebasing of the Twin Falls investment.  To contend that the possibility of retail wheeling or other possible changes in the regulatory environment falls within the definition of technology change, the Company argues, is totally without merit.
In conclusion, Idaho Power argues that Rosebud does not address the amount of investment in Twin Falls to be included in revenue requirement; does not address any reduction in demand for power by Idaho Power’s customers; does not address the significant reduction in the Twin Falls project costs from the original commitment estimate, and; does not demonstrate that there has been any change in the technology for the construction of hydro projects.  Instead, Slaughter’s testimony is simply a restatement of the arguments in the 91-4 case which the Commission has previously decided against Rosebud and, as such, is irrelevant and immaterial to this proceeding and should be stricken from the record.
vld/M-IPC-E-95-5