Rep: OEB Doc: 12WWN Rev: 0 ONTARIO ENERGY BOARD Volume: 24 10 NOVEMBER 2003 BEFORE: P. SOMMERVILLE PRESIDING MEMBER 1 RP-2003-0063 2 IN THE MATTER OF the Ontario Energy Board Act, 1998, S.O. 1998, c.15 (Sched. B); AND IN THE MATTER OF an Application by Union Gas Limited for an Order or Orders approving or fixing just and reasonable rates and other charges for the sale, distribution, storage, and transmission of gas for the period commencing January 1, 2004. 3 RP-2003-0063 4 10 NOVEMBER 2003 5 HEARING HELD AT TORONTO, ONTARIO 6 APPEARANCES 7 PAT MORAN Board Counsel JAMES WIGHTMAN Board Staff MICHAEL PENNY Union Gas Limited CRAWFORD SMITH Union Gas Limited MARCEL REGHELINI Union Gas Limited BRIAN DINGWALL Energy Probe JAY SHEPHERD Ontario Public School Boards Association 8 TABLE OF CONTENTS 9 PRELIMINARY MATTERS: [18] CLOSING ARGUMENT BY MR. PENNY: [46] INTRODUCTION: [47] WEATHER NORMAL METHOD: [56] DEMAND FORECAST: [131] RISK MANAGEMENT/GAS SUPPLY/GAS COST DEFERRAL AMOUNTS AND RESTRUCTURING: [209] O&M: [286] AFFILIATE TRANSACTIONS: [391] CAPITALIZATION: [461] CAPITAL STRUCTURE AND COST OF CAPITAL: [467] LOAD BALANCING: [486] CLOSING ARGUMENT BY MR. SMITH: [562] CAPITAL ADDITIONS: [564] GDAR/ABC/RATE RIDER: [600] DEFERRAL ACCOUNTS: [632] DSM: [645] LINES OF BUSINESS: [653] COST ALLOCATION: [668] RATE DESIGN: [677] CONCLUSION: [699] PROCEDURAL MATTERS: [703] 10 EXHIBITS 11 EXHIBIT NO. M.24.1: ARGUMENT OUTLINE [376] EXHIBIT NO. M.24.2: DOCUMENT ENTITLED, "UNION'S REQUESTS" [378] EXHIBIT NO. M.24.3: COMPENDIUM FOR UNION GAS ARGUMENT [380] 12 UNDERTAKINGS 13 14 --- Upon commencing at 9:30 a.m. 15 MR. SOMMERVILLE: Thank you. Please be seated. 16 This is the continuation of the Union Gas Limited application for rates for 2004. Today is scheduled for oral argument-in-chief by the applicant. 17 Are there any preliminary matters? 18 PRELIMINARY MATTERS: 19 MR. PENNY: Yes, thank you, Mr. Chairman. Before we start the actual argument, let me touch on a couple of outstanding issues. 20 First of all, there should be before you the affidavit of Michael Packer, he was the author of the lines of the business evidence and since no one wanted to have him here to cross-examine, we've simply had him attest to that evidence. 21 MR. SOMMERVILLE: I have that. Thank you. 22 MR. PENNY: I wanted to advised Board that all of the outstanding undertakings from the oral portion of the evidence, the only outstanding ones are from the rates panel. Those have all been drafted. They're just being finally proofed and they'll all be available today. 23 MR. SOMMERVILLE: Thank you. 24 MR. PENNY: I've prepared, for the assistance of the Board during argument, three bundles. One is simply an argument outline. The second is a list of what specific requests Union is making in this case, so it just itemizes each of the specific issues that we say need to be resolved by the Board in order to decide this case, so it will form a bit of a checklist ultimately for what Union is asking for. And then the third is a series of extracts from the records to avoid having to pop around through binders. So these will not be all the evidence references, of course, that we refer to during argument, but we've put in this compendium a few of the specific or pithier references that we specifically wanted to make reference to during the course of oral argument. 25 Two, the logical structure of the argument is around the argument outline, but to avoid popping up and down because Mr. Smith and I have allocated the argument between us, we'll do it a little bit out of order. So I will be dealing with items 1 through 6 and then continue with items 9, 10, and 13, and then Mr. Smith will carry on with the balance of the items and conclude the argument. 26 So with that, let me start by way of introduction. This is the first -- 27 MR. SOMMERVILLE: Mr. Penny, just so I don't have to interrupt you again, I think it may be as well to put on the record now the timing for argument in the matter as we go forward. I believe that a consensus essentially has been reached, or a substantial one, which would have your argument today, Coral's argument in writing by November the 19th, intervenor written argument following that on November the 24th, Union's response to Coral due on December the 3rd, and finally Coral's reply to all, including Union, on December the 8th. 28 MR. PENNY: As well as Union's -- I don't know if you said that, but also on December the 8th -- 29 MR. SOMMERVILLE: Union's reply to intervenors. 30 MR. DINGWALL: So I understand that, sir, is it intended that the date on which Union replies to Coral's argument is also the date on which intervenors might also reply to Coral's argument? 31 MR. PENNY: Yes, that's correct. 32 MR. SOMMERVILLE: I would think so, yes. 33 MR. PENNY: Yes. That was the intent. 34 MR. SOMMERVILLE: Yes. The note that I have isn't quite that explicit, but I would think that that is so. 35 MR. PENNY: Sorry, let me back up, I don't think -- that's actually not quite right. 36 MR. MORAN: That's right. 37 MR. PENNY: The idea is that Coral files its argument a little bit ahead of all the other intervenors so intervenors who want to comment on the Coral argument -- 38 MR. SOMMERVILLE: Do so on the 24th. 39 MR. PENNY: -- in the course of their argument, and then Union files its argument on Coral a little ahead of the final date so that we can have the whole thing wrapped up on December the 8th, so that Coral gets a right of reply to all intervenors' position on its argument. 40 MR. SOMMERVILLE: Thank you, Mr. Penny. I'm sorry for that confusion. The intervenors opportunity to reply to Coral would occur or would be due by November the 24th as part of its reply to the Union case as well, so that the reply would be to the Coral argument as well as to the Union argument. I think we're back on track. 41 Are there any submissions that arise from that? 42 MR. MORAN: Mr. Chair, just to confirm that, as you've said it, that was the tenor of the discussion that reached the dates that you have before you right now. 43 MR. SOMMERVILLE: Thank you, Mr. Moran. 44 With that, Mr. Penny, I think the record is clear enough, with a little extra work, and if you would like to proceed. We normally take our break at 11:00, and if you could find a break around that time, it would be convenient. 45 MR. PENNY: Yes, thank you. 46 CLOSING ARGUMENT BY MR. PENNY: 47 INTRODUCTION: 48 MR. PENNY: Let me say that by way of overview that this is the first comprehensive cost of service rate setting for Union since the 1999 rates were set through EBRO 499. The Board, in the RP-1999-017 case set Union's 2004 rates by making a number of adjustments to the 1999 approved cost of service, but those were limited adjustments. In that decision, the Board, of course, approved the three-year trial performance-based rate-setting mechanism under which Union has been operating since 2001. 49 In the PBR decision, the Board also decided, however, at the urging of a number of intervenors, that at the end of the trial three-year PBR period there should be a full cost-of-service hearing prior to proceeding with any further PBR, and that was at paragraph 2.798 of the decision where the Board referred to a traditional cost-of-service-based revenue requirement proceeding. 50 So Union has brought forward its application and evidence in response to the Board's directive in RP-1999-0017, and of course the record in this case is quite substantial. This is not surprising when one considers the passage of time since EBRO 499 and the information needed to explain what's happened between 1999 and today and what is forecast for 2004. 51 This is particularly so with respect to rate-based changes which, as distinct from O&M-type charges, reflect largely the cumulative effect of the capital conditions over the intervening years. So Union's forecast 2004 rate base is 3.059 billion. This consists of Union's average investment in the utility plant of a narrow depreciation, plus an allowance for working capital, plus accumulated deferred income taxes, and this compares with Union's approved 1999 rate base of 2.706 billion, and all this evidence is found in the B binder, of course. 52 The change since 1999 is driven by the capital investment necessary to serve the additional customer additions that have come on at a rate of about a little over 20,000 customers per year; secondly, to ensure the continued and safe and reliable operation of the existing facilities; and finally, an increase in working capital driven by significantly higher gas costs both in inventory and for the purposes of balancing direct-purchase customers. 53 So the details of the capital expenditures made since 1999 are found at Exhibit J.17.8 for the years 2000 and 2001; at Exhibit D.5, tab 2 for the year 2004; Exhibit D.4, tab 2 for the year 2003, and lastly, Exhibit D.3, tab 2 for the test year 2004. And more detail on the significant capital additions for the year 2004 will be discussed later in the argument. 54 Union's forecast delivery-related revenue deficiency for 2004 is approximately 104 million. That's at Exhibit J.7.1 updated. This is the shortfall of delivery revenue from delivery costs when revenues are calculated at existing approved 2003 rates and compared with Union's forecast 2004 cost of service. It is the delivery-related cost of service and revenue deficiency that we're concerned with because, of course, the gas supply rates and revenues are dealt with through the quarterly rate adjustment mechanism. Gas supply costs are subject to the gas supply deferral accounts such that gas supply costs are passed through. Over the course of a year, the net impact of QRAMs and gas supply deferral dispositions are that sales-service customers pay only Union's incurred costs for natural gas supply. 55 So the starting point, Mr. Chairman, is operating revenue. This is the revenue derived under approved 2003 rates from Union's 2004 forecast for the general-service demand, the contract-customer or large-volume demand, and revenue from storage and transportation transaction activity from capacity not needed to serve infranchise demand. 56 WEATHER NORMAL METHOD: 57 MR. PENNY: Underpinning the general service demand forecast, of course, is an assumption about normal weather. So starting with the general service demand, before we can even get that, the cloud on the horizon on that forecast is weather normalization methodology. And we say, Why is there weather normalization? And it's relevant to the general service class because heat-sensitive demand is, by definition, affected by weather. So an assumption has to be made about what weather will be. No one can predict the weather and therefore there has to be some benchmark or assumed normal for weather. 58 Now, the question of what is normal weather is neither metaphysical nor merely a matter of academic interest. It has real bottom line financial implications for the utility. And it is, we say, critically important that the method be fair and not biased and that it affords equal opportunity for error on either side and to a roughly equivalent extent. 59 As a result of an exhaustive process undertaken with the assistance of leading climatologists and weather forecasters, Union is proposing a more accurate and less biased means of weather normalization and is proposing to move, for rate-setting purposes, from the 30-year average to the 20-year trend that is already being used for operational purposes. 60 The financial impact of the weather normalization method I mentioned a minute ago can be illustrated with a simple numeric example. Let's assume that we have a weather normal method that produces an assumed 3,000 heating degree days in a normal weather. Now, by way of reminder, every degree below 18 degrees Celsius per way is a heating degree day. And let's assume that we have ten heat-sensitive customers, who, in a winter with 3,000 heating degree days consume a hundred units. Let's also assume that the system to required to deliver gas to those 10 customers, assuming the 3,000 heating degree days in winter costs a thousand dollars a year to build and operate. So the rate needs to be a dollar a unit on the hundred units of forecast demand per customer to recover $1,000 of costs. 61 If the weather is normal and there are 3,000 heating degree days, then customers actually consume the hundred units, so the rate of $1 per unit actually recovers from all 10 customers the $1,000 in costs to operate the system. But if it turns out that the number of heating degree days is normally .700, say, and customers only consume 90 units in a 2,700 heating degree day winter they will pay their $1 per unit rate for 90 units of consumption and Union will recover only $90 from each customer and only $900 in total, so the utility will be $100 short if normal is 2,700 heating degree winters. 62 Since no one can predict the winter in a given year, the concept of normal assumes a midpoint around which there is more or less equal variability both in terms of whether you are above or below the normal or the benchmark, but also in terms of the extent to which the variability occurs from the benchmark. And what you want to see, we say, is that over time, there is no discernible bias resulting from the choice of the benchmark normally used for assumed for rate-making purposes. 63 So in my example where the benchmark normal of 3,000 heating degree days gives rise to an assumed 100 units of consumption, if the reality is that, in fact, in 15 of 18 years weather is warmer than the assumed normal such that there are only 2,700 heating degree days and consumption is only 90 units and in three years, there were, say 3,300 heating degree days and 110 units of consumption, all else equal, because this is purely illustrative to isolate weather normalization, all else equal, Union would consistently in those 15 of 18 years be underrecovering its costs from all 10 customers by $100 a year, and overrecovering its costs by $100 a year in only three years, on my numeric example. So the net would be such that Union would be out by a net of $1,200. 64 And if you layer onto that their variability where the consumption is actually only 75 units or 65 units in some of those 15 warmer years and the variability in the colder years is only 102 or 103 units of annual consumption, then the net shortfall is even greater. And that is, again, because there are two factors operating; whether you are warmer or colder than the benchmark, and then by how much you are warmer or colder. And that, in my submission, is exactly what you see at C.1, tab 4, page 3 and 4, which are reproduced in the compendium at pages 1 and, 2, because this -- what this thermometer chart shows is that under the 30-year average that only 3 of 18 years fell below normal and 15 of 18 years are above normal. What you also see is that the swings are disproportionate. So not only are the numbers disproportionate, but the amount of variability when it's colder is relatively small whereas the amount of variability when it's warmer is extremely high. 65 And you see a similar effect on page 2 of the compendium, at figure 2, which is a graphic presentation of the 30-year average and actual, and what you see there is the -- is a relatively flat line produced by the 30-year average. It's like a stone skipping across the top of the waves, with only limited and small variability above the line and extremely numerous and huge variability below the line, i.e., fewer heating degree days. 66 And while we're on this, what we see as well is that the 20-year trend, while still not tracking down the middle, achieves a more equitable balance of both the number of years warmer and also the extent of the variability. And again you can see that on both the thermometer chart and on the graph; the thermometer chart on the right-hand side showing the 20-year trend in normal, and there is obviously a more equitable numeric distribution of the number of years falling above and below and also a somewhat more equitable distribution of the amount of variability. And you see that exact effect being reflected in figure 2 as well, the dark line being the 20-year trend, which is cutting more down the middle of the variability than the 30-year average which, as I say, is like a stone skipping across the top of the waves. 67 And so what you get in the -- with the 20-year trend is 11 of 18 years warmer and 7 of 18 years colder. 68 And what this is suggesting to us is that there is a trend to warmer weather. In other words, a climatological change that is not being picked up by using a simple 30-year average. This inference is supported by the uncontradicted evidence of external experts who testified in this case. 69 Now, Dr. Andrew Weaver was a professor and Canadian research chair of atmospheric at the School of Earth and Ocean Sciences at the University of Victoria, he testified, and he was contracted to write a paper for Union related to climate change and global warming. This paper, "Global Warming, the Intergovernmental Panel on Climate Change," was produced in February 2001 and it relies on the scientific understanding of climate change that was documented by the intergovernmental panel on climate change in the third assessment report. Dr. Weaver, incidentally, is one of the authors of that report. 70 And in the IPCC report, it is -- it states that there is an observed warming trend and Dr. Weaver's paper, which is in the evidence at C.1, tab 4, appendix AA, expands on the IPCC report and concludes four important -- reaches four important conclusions. 71 One, the major debate in scientific literature is not if climate change is happening but rather how quickly the climate is changing and to what magnitude and with what regional applications. Second, the warming trend in the recent climate record is consistent with what current climate computer models have suggested. Third, in Ontario, there has been a strong warming trend observed, especially in the winter season. And fourth, that projections of future climate change based on different emission scenarios all consistently show that warming will continue in Ontario. 72 And at page 20 of Dr. Weaver's report, he dealt with his -- with the simple method, and I simply refer to that. You'll recall there was a figure 9 with a chart and the simple method projected global and annual mean temperature change relative to 1990 under a wide range of scenarios, and at page 20 he notes that in all cases warming is projected. So that included every one of the 35 scenarios that had been generated by the work of the IPCC. 73 Dr. Weaver says in his report that, while it is not meaningful to pick a particular place on the earth's surface and say unequivocally that it will be warmed by a certain amount over the next century, a number of key conclusions can be drawn. First, land areas warm more than do oceans; second, the interior of continents warm more than do coasts; third, the west coast at northern latitudes tends to warm less than the east coast because of prevailing winds; and fourth, the high latitudes warm more than the lower latitudes due to the powerful albedo feedbacks associated with retreating snow and ice. And as noted, in addition, positive feedback arising from retreating sea ice is that the ocean is no longer insulated from the atmosphere so it can warm it from below. And fifth, that the northern hemisphere warms more than the southern hemisphere as there's more land there. 74 At page 25 of his report he states that the eastern North America region, which includes most of Ontario, showed greater than average warming both in summer and winter for both of the scenarios used, and concludes that the analysis of intermodal consistency in regional relative warming -- sorry, in his diagram of the analysis of intermodal consistency, that's the one where regions were classified as showing either agreement on warming in excess of 40 percent above global average or agreement on warming greater than global average and, of course, Ontario in the far north is much greater than average and Ontario was greater than average in both summer and winter. 75 Union also retained Mr. Steven Root of WeatherBank in Oklahoma. WeatherBank is a private environmental and weather forecasting company which has been in the weather forecasting business for almost 30 years. Mr. Root is the president of WeatherBank and provides the scientific and technical management of WeatherBank's meteorological forecasting services. He studied changes in climate patterns based on a consistent series of weather data available from Toronto Pearson Airport, and the evidence is quite clear that Toronto Pearson weather data has a strong statistical correlation, over 99 percent, to weather experienced at the 12 weather stations throughout Union's franchise area. That's at in Exhibit B, tab 2, page 17. 76 Mr. Root found that since 1960, increases in the variance between actual heating-degree days and the 30-year normal have become quite dramatic, and that the changes in variance values begin displaying wider swings in magnitude. While a few select years saw annual periods colder than the 30-year normal, most years showed annual periods that were warmer than the 30-year average normal. Negative variance years have also been much larger in magnitude than the positive variance years. WeatherBank's evidence was that this trend is directly related to the effects of global warming. WeatherBank also concluded that this trend will continue with negative variance swings becoming more pronounced. They say this remains as clear evidence that employing a statistic or rolling -- static or rolling 30-year average as the weather normal would introduce significant error into the Union Gas price-setting method. That was at page 5 of his written testimony. 77 Dr. Weaver said essentially the same thing during cross-examination. There are a variety of places where that comes up. Volume 3, paragraphs 148, 153, and 1255, and I've reproduced at page 3 of the compendium just one of those examples at 1255, towards the bottom of the page, on page 3 of the -- any bias to the volatility? In other words, is the volatility tending more towards warmer or colder or can one tell?" He says, "I can take a first stab and say there is clearly a trend in the observational network towards warming. This clearly enhanced projection that there will be increased likelihood of more warmth and increased likelihood of decreased cold in any given year in terms of a trend." 78 This, of course, all this evidence that I've just cited, is of course completely consistent with the thermometer at page 1 which is showing exactly the same thing. 79 So Mr. Root's proposal was to use a 20-year trend with 15 years of actual and five years of forecast weather data, and at page 12 of his evidence he says that the 20-year rolling Pearson data, based on his observed and forecast, is a simple trend line for establishing the mean. He says: 80 "The trend line is a simple regression through the 15-year historic and 5-year forecast weather points. Regression is used because the regression line is a line of best fit and is the post likely attempt at a 50/50 likelihood that the actual or forecast weather will fall on one side or the other of this trend line. This approach is forward looking and is not based upon historical average. This approach is superior to a rolling 20-year average because it produces a 50/50 outcome, whereas, even the rolling 20-year contains a bias and this bias results in future years being higher than the best estimate of future weather conditions." 81 Mr. Root made four recommendations, and they're summarized at page 13 and 14 of his report: 82 First, he prefaced his recommendations with the observation that global warming and weather uncertainty will continue to occur. These trends are being observed at such a place that static numerical averages on a 20-year or 30-year rolling average of only past data will no longer reliably estimate the future, impacting the future demand for natural gas and the design and setting of gas delivery rates. 83 "These climate changes," he said, "while exhibiting accelerating patterns, do follow certain trends and these trends can be used to generate forecast future weather patterns." 84 So his first recommendation was to apply a forward-looking method and that backward-looking historical averages do not fairly represent or reflect the global warming influence in energy demand forecasting. 85 His second recommendation was that the time period used to define and estimate normal weather be shortened from 20 to 30 years. His third recommendation was that weather estimates for five forecast years be based upon informed climate and meteorologically sound forecasting methods developed and prepared by recognized reputable weather service organizations, and then the recommendation 4 was that the weather normal estimate for the five-year forecast period be defined by a linear regression trend line that is applied to the entire 20-year period, that is, the 15 years of historical and the five years of forecast, and that would yield the unbiased 50/50 estimates of future weather conditions. 86 So faced with this, Union then evaluated Mr. Root's investigation but also did so with six other weather-normalization methodologies, which included the 20-year trend and a series of other weather-normalization methodologies used in various jurisdictions and included what used to be the 38-year weighted approach that was used by Enbridge. 87 In fact, Mr. Root's recommendation did score the highest in all of the six possibilities analyzed. But in the end, for reasons of transparency, Union elected not to propose adopting Mr. Root's recommendation but adopted the first two of his three elements, 20-year versus 30-year, and a trend line based on a simple regression as opposed to an arithmetic average. 88 So in coming at this, in fact, I'll just observe, by the by, that it's been quite some time since weather normalization was reviewed in a Union case and we looked at historical precedence and could find really very little discussion of the issue in prior Board cases on any substantive level, so as a result the company stepped back and asked itself some fundamental questions about weather normalization, what it was for and what it should do, and it led to five objectives which were outlined at page 15 of Exhibit B, tab 2 of Union's evidence. 89 And the five objectives were as follows in rank order: Symmetry. This, as I've referred to before, this is that the method should result in an unbiased normal weather condition where there are equal expectations of positive variations and negative variations from actual. 90 Secondly, accuracy. The method should result in a point estimate that has a minimum variance over time between normal and actual. 91 The third was stability, that you want some relative stability so it's not swinging wildly from one year to the next. 92 And then the last two were sustainability in the sense that it should be something that can stand the test of time and not require specific amendments in the near future, at least, and simplicity that it should be easy to understand and administer. 93 So using this criteria, Union evaluated several methodologies, as I say, used by other regulators or recommended by the consultants, and this evaluation resulted in Union's proposal to cease the use of the 30-year average for rate-making purposes and to adopt the 20-year trend. 94 So there are -- in terms of the proposal to go to the 20-year trend, there are three key features to Union's weather normalization proposal, and these are outlined at Exhibit B, tab 2, page 16 of the evidence. The heating degree days under the proposal will be calculated each year under -- using three components: A trend equation, that's an equation that represents a straight line drawn through the data using a regression analysis, a simple regression analysis; the second, to use the most recent 20-year historical period of actual heating degree days, so because it's done each year, the 20-year period will change from year to year by dropping the oldest year and adding the most recent year and this means, of course, that the slope of the line will be moving slightly each year as well; and the third component is to use data from Environment Canada for the 12 weather stations that are scattered throughout Union's delivery area. And Union will, as it does now, continue to use a volume-weighted weather measure based on data obtained from these 12 stations. The data is weighted in accordance with the total regional through-put volumes that are associated with the regions in which those stations are located. 95 So the alternatives that I've mentioned, the seven in total alternatives were evaluated using the Toronto Pearson Airport weather data. This station is centrally located relative to Union's franchise area and has a long weather record that provides a basis for the analysis, because there are sufficient years of data available and the station has never been moved. But as I've said, the 12 stations that Union uses for its rates calculations don't have -- first of all, don't have the same length of record, but there is a 99 percent correlation between those 12 stations and the data at Toronto Pearson, and so we say on that basis that it is a reliable measure for evaluating the various options. 96 The seven methods are detailed at Exhibit B, tab 2, starting at page 18, and they were, just to run through them quickly, the current 30-average method, a 20-year average method, a 10-year average method, a 30-year trend method, a 20-year trend method, the Enbridge model, which is a variable year historical-weighted trend, and Mr. Root's method, which was a 20-year trend but using 15 years of historical and 5 years of forecast. Each of these methods was analyzed for their accuracy in forecasting, their symmetry and their stability, and they were also assessed for sustainability and simplicity. 97 Now, the accuracy test is a measure that indicates, over time, the difference between the weather normalization estimator and the actual weather. So the most precise accuracy measurement tool is the root mean squared error. Symmetry is a measure of bias. Bias is, of course, extremely important in the utility rate-making context because, above all, we say, the methodology should neither consistently overforecast nor underforecast heating degree days and thus revenue. Over time, we say the variance on other side of the assumed normal should be roughly equal in both frequency and degree. To measure bias, Union used the mean percent error test and the bias frequency test. 98 And then stability, that's a measure of variation, how wildly is the measure changing from one year to the next? Variation is measured by the standard deviation. Stability, of course, is also a significant factor in a rate-setting exercise because, all else equal, more stability is to be preferred. And then accuracy and stability often operate, to some extent, in opposition such that more accurate means sometimes less stable and more stable would sometimes mean less accurate. 99 The stability, I would also add, is a qualitative assessment of the company being able to understand -- I'm sorry, sustainability is a qualitative assessment of the company being able to understand and maintain the tools underlying the method, and simplicity simply addresses the need for internal and external stakeholders to understand the approach and for it to be somewhat mechanical and not subject to either discretion or non-transparent data. 100 Those are not numeric values, however, and so they were taken into account on the test on the basis of qualitative not quantitative factors. 101 The updated raw test results are -- well, the test results are C.1, tab 4, appendix A, but the update to those results to reflect 2002 actuals was filed at Exhibit J.34.47, and that's been put in the compendium at page 4. 102 I won't go through this in great detail other than to explain under the accuracy test, both the root mean squared error and the mean absolute percentage error, the smaller numbers mean more accuracy. Under symmetry mean percentage error, again, small numbers mean more accuracy. Zero is a perfect score under that. Under the bias frequency ratio, the closer the ratio is to 1:1, the less biased and more symmetrical the method is. And then under finally, under stability standard deviation, again, the smaller numbers mean the method is more stable; the higher numbers mean it is less. 103 So as you -- if you just quickly review these, you see that Mr. Root's method, the 20-year trend with forecast scores the highest because it has the smallest numbers. In the first three tests, the 20-year trend now proposed by Union, actually scores the best on the bias frequency because it has the ratio closest to 1:1. And under standard deviation, in fact, the 30-year average is the most stable and that -- I think the reason for that is obvious. And this is a perfect example of the point I made earlier, where accuracy and stability are somewhat inconsistent objectives because you have Mr. Root's method being the most accurate and of course at the very other end of the spectrum, the 30-year average being the most stable. 104 Union used a multiattribute analysis to evaluate the various methods and it weighted the five criteria based on their importance. Symmetry was weighted 3 because, as I've said, above all else, the method for weather normalization is supposed to make Union's weather risk neutral over the long term. Accuracy was given a weight of 2 because the method should be a reasonably accurate predictor of the long-run future weather. And stability, sustainability, and simplicity were each weighted 1. 105 Now, one quite quibble about the weightings and what they should be. In my submission, Union got it right. At the very least, you can't these weightings are unreasonable. And it doesn't matter in the end anyway, because even without the weighting, the Union-proposed method is still better than the existing method even without the weightings, and better than any of the other methods used by Canadian regulators. And you find that at Exhibit J.26.36. 106 And then the updated multiattribute rankings are shown at, again, J.34.47, and that's at the next page, page 5 of the compendium. That simply shows you that on the weighted multiattribute rankings, the 30-year average score is the lowest, and the 20-year trend with forecast information in Mr. Root's proposal scores the highest, but that the 20-year trend which is now being proposed by Union was second best. 107 The results on this table for symmetry show that the 20-year trend with forecast was the best, and it's only stability that -- where the average methods have any superiority. 108 With the exception of the variable year weighted average and the 20-year trend with forecast information, the methods are all relatively easy to understand and administer because they use historic data published by Environment Canada and simple analysis. The variable year with average trend, which is used by consumers, in our submission, is a complex analysis that is more difficult to understand and administer than those with simpler calculations, and the 20-year trend with forecast information requires a climate-modelling approach that requires an external climate science expert and expertise to understand and to validate. 109 So because the 20-year trend with forecast information is far more complex than the other methods, and because this method is entirely based on a third-party proprietary model, Union was concerned about a weather-normalization method being dependent on such a unique and non-transparent analytical tool, and that those concerns with regard to, perhaps, the lack of sustainability and simplicity and lack of transparency were sufficiently significant that it decided to propose the second best method, the 20-year trend without forecast, even though the WeatherBank method was actually the best predictor. 110 So it was an issue, really, of transparency and simplicity that drove Union to that conclusion. 111 Both Dr. Weaver and Mr. Root reviewed Union's analysis and were in agreement with it. There's no contrary evidence on the record with respect to this analysis. Intervenors have know this is Union's proposal for over two years and so have had amply time to consult their own climate and weather experts to try and rebut the science or Union's specific analysis and proposals. They have not done so. In my submission, it's open to you to draw the inference that the reason that this has not been done is because there is no credible scientific basis upon which Union's evidence could be reasonably contradicted. 112 In the end, it's a pretty straightforward, simple proposition. You want a weather-normal method that is revenue-neutral, i.e., not biased over the long term. You want a weather-normal method that is reasonably accurate, one that is not too wild in its fluctuations, that can be sustained, and is reasonably simple to understand and apply. And in our submission, Union's proposed method meets all of those criteria. The 30-year average does not. All you have to do is look at the thermometer at page 1 of the compendium. There's no weighting of factors here so there's no quibbling about weights. This is, in effect, the sharp end, this thermometer, this is what's actually happened over the last 18 years compared to what would have happened if the 20-year average had been in place. It demonstrates, in my submission, better than any statistical analysis, the unfairness and the bias and the inaccuracy that is inherent in the 30-year average. 113 And one has to presume, I submit, that when the Board has previously used or approved the 30-year average weather normal method, that the Board thought it was employing a method that, while placing weather risk on the utility, was doing so in a manner that was, over the long run, revenue-neutral, that was fair and not biased; that the weather risk assumed by the utility would neither advantage it over time to the detriment of ratepayers, nor disadvantage it over time to the systematic benefit of ratepayers. So the change in weather normal does not, in my submission, involve any change to weather risk. It simply restores the balance to where it was thought to be and where it should be in the first place, which is a method that is revenue-neutral over the long term to both sides, both company and ratepayer. 114 And as Mr. Gardiner said at volume 3, paragraphs 1369 to 1370, which I've reproduced in the compendium at page 6, he was asked the question by Mr. Warren: 115 "...if the method by which you calculate normalization more accurately predicts the number of heating degree days, then the risk of warmer weather in any given year built, the risk is reduced for the companies; is that not fair?" 116 "As a forecaster, what I like to do is get it right, and I have to make an assumption on what is normal, and I want to have equal chance to be wrong, either on the high side or on the low side. So this is the issue of symmetry. And what we found with the old 30-year average is we didn't have symmetry, but with the declining trend, you do, or you have more symmetry. And so by going to the declining trend, we restore the symmetry which has now equal risk on both sides." 117 And the customers, as he went on to say, under the 30-year average method since the '80s, have gotten a pretty good deal, because in 15 of 18 years, the weather-normal method, all else equal, of course nothing ever is all else equal, but if we're just focussing on weather-normalization methodology and trying to assess its impact on a stand-alone or free-standing basis, in 15 of 18 years, the weather normal method was generating a demand forecast and therefore forecast general service revenues that was higher than what was warranted by the weather that was actually being experienced. 118 And that evidence, Mr. Gardiner spoke to at Volume 4, paragraph 480. 119 And as Ms. McShane said in answer to an interrogatory in this case, J.18.148, and I quote: 120 "The premise underlying the risk assessment of any gas distributor whose earnings are subject to variability due to weather is an equal probability of actual weather being warmer or colder than the weather underlying the load forecast. The exhibited negative impact on earnings of warmer-than-normal weather of recent years have called into question the reasonableness of that assumption." 121 Now, there is a rate impact. There is a rate impact to recognizing that the 30-year average is not accomplishing its purpose and switching to a weather-normalization method that does. The reason for this is, again, illustrated by my simple costs are recovered in rates based on volumes consumed. If volumes consumed are turning out to be, on my example, 90 instead of an assumed 100 units over time, then the rates in fact should not be a dollar per unit consumed, but you would divide the thousand dollars of cost by 90 and generate $1.11 per unit consumed. 122 And so that 20.4 million increase for 2004 referenced during the hearing, and this was detailed at Exhibit J.34.54 corrected, arises because the costs are basically the same but they must be recovered over lower anticipated consumption, which means the per-unit rate has to go up. 123 Some intervenors have raised the question of whether it's fair that Union should get less exposure to warm weather while the ratepayers have to receive a $20 annual rate increase. I think I can say unequivocally in this case that, yes, it is fair. It's fair because Union is entitled to recover all reasonably incurred costs. Ratepayers are obliged to pay for the cost of the service they're receiving. The weather normal method is part of the means by which the determination of how these costs are recovered is made. It's fair that there be a reasonably accurate forecast of anticipated heat-sensitive consumption. What is unfair is to use a predictably biased and inaccurate forecast of heat-sensitive consumption. 124 And one cannot forget the operational impacts of using a weather-normal method which consistently overforecasts demand. Today Union is planning its system operating requirements on the basis of the 20-year trend. To plan on any other basis, we say, would result in incurring unnecessary costs in upstream transportation capacity, Dawn-Trafalgar capacity, and sales-service customer commodity purchases. If declining demand is not recognized, Union will end up with unutilized capacity and that will involve costs which will have to be recovered from ratepayers for such things as unabsorbed demand charges, carrying costs for capital investment and excess supply. 125 Today Union is avoiding these costs by employing the 20-year trend and customers are getting the benefits. If the change to using 20-year trend for rate-setting is denied, Union will not be in a position to continue indefinitely using the 20-year trend for planning purposes and the 30-year trend for rate-setting. So if the rates are to be based on 30-year average, then planning will have to be done on the same basis. And in that circumstance, all associated costs will have to be recovered from customers in rates. 126 So that is my submission on the weather-normal methodology. 127 Let me turn to the general-service demand, then, and its application to weather. The general-service forecast for rates M1, R1, and R10 is prepared using natural gas consumption estimates for each customer and each rate class. These assumption estimates are then multiplied by the total number of customers. So the total general service demand forecast for 2004 is at Exhibit C.3, tab 2, schedule 2, and is 5,267,439 units. 128 At the approved 2003 rates, this translates into an operating revenue forecast of $1.439 billion, which is at C.3, tab 2, schedule 1 updated, line 5. You'll find the more detailed revenue breakdowns in the other updated schedules which are also at Exhibits C.3, tab 2. 129 By way of background, the general-service market is made up of approximately 1.2 million customers. They are categorized as residential, commercial, and small industrial. Most but not all of these customers represent heat-sensitive load. General service customers numerically are about 90 percent residential. The general-service market represents about 35 percent of Union's total infranchise demand. Residential customers are about 55 percent of the general service through-put and represent 19 percent of the total of infranchise demand. So that's globally what we're dealing with. 130 There are two basic variables in the calculation of total gas service demand. There's normalized average consumption per customer, or NAC, and then there's the total number of customers. Both variables utilize historic information but must forecast into a somewhat unknown future. So even though the customer numbers are, in part, dealt with in the context of rate base and distribution expansion, let me deal with that aspect of the general service demand forecast now. 131 DEMAND FORECAST: 132 MR. PENNY: The 2004 forecast for numbers of customers is an amalgam of actuals from 2002, partial forecast for 2003, and forecast for 2004. So we start with the existing number of customers and increase it by new customer attachments. In 2002, Union had 1.17 million customers, that's at C.5, tab 2, schedule 1. And the forecast attachments for 2003 based on five months of actuals and seven months of forecast in the update at Exhibit B.1, tab 3, is 26,000, and for 2004, the updated forecast for new customers is 27,000. So the total forecast underpinning the general service demand forecast is customers for 2004 year end of 1.222 million. And you find that at Exhibit C.3, tab 2, schedule 1. 133 So this estimate is essentially developed through a regional market assessment of new housing and construction activity in Union's franchise area and estimates based on the likelihood of conversion from other fuels. Looking back historically, in my submission, there's no evidence of bias in Union's new customer attachment forecast. In fact, when you look at J.7.9, page 2, you'll see that since 1998, Union's forecast has, if anything, tended to be too high. Actual new customer attachments for 2002 were 29,785. The 2002 results were, in that year, considerably higher than the company's forecast, and the forecast had been based on the current -- on the then-current Canadian Mortgage and Housing Corporation reports. 134 At the time the 2002 forecast was made, the company was expecting that interest rates would increase during the early part of 2002 and this was expected to soften new housing growth. Interest rates, however, did not increase to the levels expected and new home construction remained buoyant. In addition, there was more stringent -- there was way more stringent monitoring of the integrity of home oil storage tanks in the company's market area which stimulated greater-than-expected conversion activity in areas which remained oil-based home heating systems. 135 You can find at Exhibit N.14.4 an explanation of why Union believes that the 2003 customer attachments will not match the numbers achieved in 2002. 136 I would also make the point that even large numbers of customer attachments -- variances have relatively little impact on the revenue requirement and on forecast deficiency -- and on the forecast deficiency. 5,000 customers, we know from J.7.11, has only a net impact, because of course there are costs associated with attaching and servicing new customers too, not just revenues, has only -- 5,000 customers has only a net impact of about $100,000 on revenue deficiency calculations. So even when you have relatively large swings in number, it has extremely small impact on the revenue deficiency. 137 So that's the first piece, the customer attachments, and we say that our forecast of 1.222 customers is a reasonable one based on past experience and on the market circumstances. 138 The second variable in the forecast is, of course, the normalized average consumption. The reason, of course, it's normalized, and that's normalized for weather, is because, as you've heard many times in this hearing, Union can't predict what the weather will be in any given winter season so it's required to plan around a benchmark normal. 139 Mr. Gardiner and his group have used historical consumption information to develop equations to calculate NAC. These are based on analyzing consumption variances due to weather, specifically the HDD or heating degree days, energy efficiency and natural gas prices. And these three variables are described in detail in the evidence at Exhibit C.1, tab 1, appendix A. 140 Weather is, by far, the most significant driver, accounting for about 70 percent of the NAC calculation; energy efficiency is the next significant driver, accounting for about 20 percent of NAC variance; and gas prices have the small impact, accounting for about 10 percent of the analysis, and that is, you'll find, at volume 4, paragraphs 134 to 139. 141 Energy efficiency, I should point out, is non-Union sponsored energy efficiency. In other words, it's not Union's DSM. Union-sponsored DSM is specifically excluded in the initial calculation and then specifically taken into account at a later step, which I'll get to in a moment. 142 The energy efficiency factor, I would say, is a function of building code changes, changes in residence size and average number of residents per building and such things as independent technological change which would include demolition of old, poorly insulated houses. It's primarily a factor using historical data to model the overall declining consumption for reasons other than weather. 143 The evidence is quite clear, in my submission, and entirely uncontradicted, that over 98 percent of the historic annual consumption can be explained by the three variables that Union uses in its equations. Put another way, if actual weather prices and efficiency levels are input into Union's model, so if actual weather, prices, and efficiency levels are input into Union's model the equations calculate annual demand within a 2 percent band around actual demand. And this is very significant evidence, in my submission, that the variables that are used in Union's equation are appropriate. And the proof of that tight-type relationship is in the colour handout of J.34.33, which was marked at Exhibit M.5.2 and reproduced at page 8 of the compendium. This was evidence taken from C.1, tab 1, page 6. 144 What I've reproduced here is but one example of separate analysis that was done for each customer group, but it illustrates the point that this is a backcasting exercise using Union's variables but inputting the actuals, did those variables work to reproduce what actually happened. And the answer, of course, is yes, within a 90 percent certainty. So as Mr. Gardiner said, even if there were any concerns about the utility or predictive value of Union's three variables, and there are none, I say, because there's no evidence on the record that they are inappropriate or lack predictive value, but even if there was a concern, it would be completely answered by these exhibits because, if there were a problem with the variables, you would not be getting this tight match at better than 98 percent between actual and calculated consumption. 145 And Mr. Gardiner spoke to us in the evidence, and I've reproduced a passage from volume 5, at page 9 of the compendium, and this is in answer to a question from me in re-examination and the question was simply: 146 "Looking at M.5.2, which is the backcast of your actuals to your forecast, that if the statistical issues associated with T-stat or heteroskedacity or non-stationary, if those issues were of anything more than merely an academic interest, would you be getting this kind of match in 5.2," and Mr. Gardiner responded: "I don't believe I would." 147 Mr. Gardiner also indicated that a practical efficacy of this approach -- sorry. Mr. Gardiner emphasized, I guess I would say, the practical efficacy of his approach when he was asked, for example, whether there was support for the use of some of his techniques in the literature, and Mr. Gardiner responded to that question at pages 10 and 11 of the compendium, also from Volume 5, starting at paragraph 153, and Mr. Gardiner was asked whether there was independent statistical evidence to support his methodology, and Mr. Gardiner replied: 148 "I'm a practicing forecaster. I'm always trying to improve my forecasting tools. Actually, the combination of the two," he's talking about the technique of taking two equations and averaging them, "the combination of the two resulted about two years ago when we started looking at the industrial sector, and we found that the usage equation wasn't performing very well and we discovered the volume. So then we said, Well, let's try it on a residential. We found a very strong relationship. And it makes sense. If you add customers, you get more volume. And then what we found is that because they did come up with different estimates, if we brought them together, could we be closer when the actuals came in? And we found that to be the case. 149 So we said, This is interesting. I have two strong tools. Instead of choosing one, marry them. It's a pragmatic approach, and the results so far are indicating that that approach is a better way of predicting the actual normalized volume." 150 And then he goes on to say at the top of the next page: "It's not classical, it's a little Gothic, I admit, but it's a great tool." 151 And then Mr. Janigan says: "This is something that you've derived, it doesn't seem to have any presence in any sort of statistical literature, but you think it works." 152 And Mr. Gardiner says: "It does work." 153 And that's the uncontradicted evidence before you. 154 After developing the NAC estimates, they are then adjusted for two effects. I alluded to this a few moments ago. They're adjusted for Union's anticipated marketing activities in the test year and those would tend to increase consumption because Union is out there promoting natural gas as a safe, clean and efficient fuel, and there's a second adjustment made for Union's planned DSM activities which, of course, has a tendency to decrease consumption. 155 And then finally, Union applies a reasonableness screen to test the forecast against actual experience, and let me just talk briefly about the reasonableness screen. 156 Historically, Union has found that there is a clearly observable relationship between total annual consumption and the consumption data for the first three months of the year. So since 1990, experience has shown, for example, that in the first three months of the year, that that represents a consistent proportion of annual consumption. For M2 customers, it's only varied and it narrowed down between 44 and 47 percent. So consistently, year in, year out, we know that based on the first three months of consumption, that that is going to represent 44 to 47 percent of total annual consumption. And this has enabled Union to establish a stable relationship which is then used to project consumption for the entire year and to compare that to the consumption forecast prepared independently of that to see how it tracks. 157 So Union takes one standard deviation around the trend projecting from three months of actuals and uses it like goalposts or a maximum/minimum threshold, so that if the forecast is lower than one standard deviation below the projection based on three months of actuals, then it's raised to that level, meaning it's brought within the goalposts from below, and if the forecast is higher than one standard deviation above the projection, it is brought down so that the level fits within the goalposts. 158 So just to summarize, the 2003 forecast using the regression equations that we were talking about a moment ago is adjusted for marketing and DSM activities. Union then takes the rule of thumb goalposts that the first quarter of consumption is always a consistent percentage of total annual consumption, and if the adjusted forecast is high or low of the goalposts, it's brought back to the goalpost level because that is the consistent and historically reliable reality check. Any adjustment to the 2003 forecast is then brought forward to the 2004 forecast on the assumption that the same factors would be influenced in 2004. 159 In 2003, the forecast for two of the seven rate classes as outlined in the blue-page update to the general-service evidence were adjusted for the reasonableness test, but the 2003 forecast as of the update continued to track within 1.2 percent of actual year-to-date consumption. 160 I would also point out on the subject of the general-service forecast that like the attachment forecast, there is no historic pattern of underforecasting. When you look at rate M2 for every year in which there was a rate case since 1991 and compare actual to Board-approved or budgeted forecast which was done in Exhibit J.1.52, page 2, you find that Union's actuals are greater than forecast in only four of ten years and lower than forecast in six of ten years. And that exhibit also explains that the average forecast error for the ten forecasts, and that's of course using a mixture of the old weather-normalization methodology, the transitional 30-year trend that was done for one year, and the two-year trend for the last two years, that that forecast tracked within 2.6 percent, whereas, for the years using -- pardon me, let me back up. I got ahead of myself here. 161 The exhibit explains that the average for the entire ten years which does use the mixture of 30-year average, 30-year trend and 20-year trend, was 2.6 percent of variability, whereas, if you look only at the last two years, using 20-year trend, the forecast error was only 1 percent. So that, in my submission, is further strong evidence to support the reliability of the 2004 general-service demand forecast. 162 There is no contrary evidence before you as to an alternative forecast or any specific aspect of the modelling equations that are not working. No evidence that Union's forecast has historically been exceeded by actual performance on a consistently biased basis and thus no evidence of intent, either intentional or unintentional bias in the forecast. 163 In fact, due to the warming trend and the errors inherent in the 30-year average weather-normalization method, the bias, if anything, has been to overforecasting general-service demand as can be seen from both the thermometer picture and J.1.52. 164 So there is effectively an unchallenged evidentiary foundation for Union's forecast of 1.2 million general service customers translating into 5.267, 103m3 of demand and a $1.439 billion revenue at 2003 approved rates for the general- service forecast. The evidence, therefore, should be accepted for this component of 2004 operating revenue forecast. 165 Now I'll turn briefly to the contract rate class customer forecast. 166 The contract rate class customers, of course, are forecast differently. These are the high-volume consumers and include power generators and heavy industries like steel refineries, and pulp and paper. There are 76 customers in M7, T1 and rate 100. They represent about 68 percent of the total contract customer through-put in 2002. About 65 percent of Union's total infranchise through-put is consumed by contract rate classes. Union is forecasting 9,351, 106m3 of through-put through the contract customers in 2004. This is a net increase of 1 percent over 2003, driven primarily by the net effects of two things: Increases due to incremental high efficiency gas-fired cogeneration coming on and decreases from anticipated displacement of less-efficient generation at Lennox. 167 The forecast, as I've said, is done differently than the general-service market. The contract demand forecast because it involves fewer and larger customers, is developed through the compilation of forecasts for each individual large-volume customer. Each customer is contacted and their plans and business output are reviewed. And there are a number of major market and business factors underlying the 2004 contract demand forecast. The electric power market is probably the single largest factor. Union has one large dual-fuel peaking facility identified during the hearing at Lennox, 11 independent power producers, three new large gas-fired power plants coming on, and a number of existing gas-fired power generation facilities which are embedded in the operations of other industrial and commercial customers, such as hospitals and so on. It is clear that there are some challenges to forecasting industrial and power generation load, and these derive from two things: One is the market and the business environment which is, to some extent, beyond everyone's control, and secondly from customer-supplied information and customer behaviour, which is, of course, beyond Union's control but is, to some extent, within the customer's control. 168 And I would submit that what we see in the fluctuation in the difference between forecast and actual historically in the contract class over the last several years is largely driven by either the market factors, which no one, using all reasonable diligence, could predict with precise accuracy, and the customer behaviour, where the customers perhaps could provide more accurate -- where the customers perhaps could provide more accurate information, or perhaps not, I mean we're not complaining about this, it's just a reality of life; but in any event, where there are circumstances that offset the contract customers' requirements that are not known to Union. 169 So whether they're known to the customers or not, they are at least more within the customers' sphere of knowledge and influence than Union. So at the level of principle that we say in this case you should judge the accuracy of the forecast for 2004 not with the benefit of hindsight looking at previous forecasts or whether they were realized or not, but in the current circumstances facing Union today, the 2004 contract demand forecast is a reasonable estimation of what is likely to occur in 2004. 170 One of the realities facing Union is that while it is a natural monopoly within its franchise area, it is only a monopoly, of course, with respect to the distribution of natural gas. And to the extent that the burner-tip price, in other words, the all-in or fully-loaded cost of natural gas is higher than alternative energy sources, customers with the ability to do so will opt for their lowest cost source of available energy. 171 Natural gas prices, as you've heard, are at historically high levels, and both industrial and gas-fired power generation load have increasingly opted for discretionary rather than firm commitments to natural gas. This is hardly surprising. The whole point of energy deregulation was to try and bring gas, electricity and oil into some kind of competitive equilibrium, and in the natural gas business, recent events have reduced the competitiveness of natural gas. Natural gas prices are high, as I've said, and oil has a price advantage. Enron's financial collapse has had the uncontradicted effect of giving rise to tighter credit requirements, decreased liquidity, and this has also had the effect of creating additional upward pressure on natural gas prices and therefore increasing the competitiveness of alternative fuels. 172 So this divergence in price has been exacerbated by the fading out of the delivery commitment credit which is explained in the evidence at C.1, tab 2, pages 8 and 9, so another factor, another reality in today's marketplace that affects industrial demand. 173 Union must also consider the dampening effects of efficiency and conservation on existing industrial load and the evidence references published industrial statistics which indicate continued demand reductions of more than 2 percent annually from increased focus on process efficiency. Union cited a report in its prefiled evidence, C.1, tab 2, page 8, which indicates that the natural gas user per unit of manufacturing output showed an average annual decline rate of over 6 percent based on the last five years of data. 174 Now, a good deal of the hearing focussed on the demand forecast from Lennox, and Lennox is served under rate 25. It's an interruptible service. And Lennox has burned 15 years' worth of committed minimum annual volume in five years, and this is outlined in the evidence because of, really, three factors: One was unexpected delays in the return of the nukes to service; there were unexpectedly high summer temperatures and gas prices that were favourable over oil, and these you'll find at volume 4, paragraphs 551 and 552. Today, however, Lennox no longer has any contractual commitment to burn gas. It's fulfilled its contractual commitments and has no contractual commitment to burn natural gas. The IMO forecast says that nuclear generation capacity will come online in 2003 and 2004 and this will directly offset the need for gas-fired generation from the Lennox plant, he says. Lennox, I say the uncontradicted evidence before you says, is a somewhat less efficient plant than other OPG units and is therefore more costly to run relative to the lower marginal operating costs of nuclear plants. 175 But there are other reasons why Union believes the Lennox plant will consume less gas than it has in the past. The first is that it is -- it is anticipated that an electricity supply from newer, more efficient gas-fired plants will come onstream in 2004. There are three of those. These were discussed in the evidence: Plants Imperial Oil, TransAlta, and, of course, Brighton Beach. That's at volume 4, paragraphs 588 and 589. 176 Second, unlike in recent years, as I've indicated, oil enjoys currently a price advantage to natural gas, and that evidence you can find at volume 4, paragraph 555. Mr. Rogers' evidence, not contradicted, is that oil, for those with alternate fuel capacity, is cheaper by over a dollar U.S. per thermal unit. That you find at volume 5, paragraph 1356, and again at 1517. Lennox has alternate fuel capability. Their oil tanks are full and oil is cheaper per BTU. That was the uncontradicted evidence. And you'll find that at volume 5, paragraphs 1504 to 1506. 177 And then finally the evidence is that Lennox is in the east end of Union's franchise area and that more TCPL capacity than is currently available to Union would be required if Lennox were going to burn significant amounts of natural gas during the winter in 2004. 178 Now, Union offered to arrange, you heard, a TCPL exchange to ensure that capacity would be available if the Lennox was to burn natural gas this winter, but OPG declined to commit to any such arrangement. And that was discussed at volume 5, paragraphs 1507 to 1517. 179 So accordingly, having regard to all these factors, Union does not believe that Lennox is a like candidate for high gas consumption in 2004, and in fact, given the level of contracted commitments made or, rather, the lack thereof in that case, there is good reason to accept Union's somewhat reserved outlook for Lennox at 65, 106m3. 180 Mr. Rogers also explained in answer to a question from Mr. Moran that information about the maximum and minimum consumption ranges obtained from the customer itself adjusted for oil competition are consistent with Union's forecast of 65 106m3 for Lennox, and at you'll find at volume 5, paragraphs 1341 and 1342. 181 The independent power producers, or IPPs, also represent a forecasting challenge for Union. That's clearly so. Seven of the 11 IPP customers have only one-year renewable contracts, however. It's Union's expectation that the power purchase agreements between the government and these IPPs may be renegotiated, which would result in lower demand from these customers. That evidence was outlined at C.1, tab 2, page 6, and at volume 4, paragraph 554 of the evidence. 182 And then another contributor to historic variability in the industrial forecast to actual is the question of rate-switching. As Mr. Rogers explained if the last few years, a number of M7 customers have indicated their intention to switch to T1 rate schedules, and so Union, in those years, based on those soft commitments, forecast lower M7 and higher T1 through-put. But then, for whatever reason, these customers decided not to switch rate classes and so this resulted in an apparent overforecast for rate M7, and of course a concomitant underforecast for rate 21. So you can't, as Mr. Rogers said in evidence, look at one in fairness without looking at the other, and that discussion you'll find in volume 4, paragraphs 1322 to 1330. 183 What Mr. Rogers said was that this has been a problem with the forecast in the past but he doesn't anticipate that this will be a forecast for 2004 because three of the very large customers in this category of M7s who have been thinking about T1 have actually now signed contracts which commit them to -- on November 1, 2003, to the T1 rate. So Union does not expect a repeat of that problem in the past -- that it's had in the past. 184 So in conclusion on the industrial forecast, while there may have been variation in forecast to actual previously, the two main factors that were driving that variability are not going to do so again. Lennox no longer has contractual commitments to Union, and, for reasons I've outlined, was unlikely to burn large volumes in 2004, and the main switchable M7s have now signed T1 contracts so they won't be going back. So we believe, Union believes that there are good reasons to conclude that this is a realistic and robust forecast. 185 Now, Mr. Chairman, I was about to switch to the storage and transportation forecast. Is this an appropriate time for a break? 186 MR. SOMMERVILLE: I think it would be, Mr. Penny. 187 Just one -- just as we're finishing that portion, I just bring your attention to paragraph 4 of the Union request document. 188 MR. PENNY: Yes. 189 MR. SOMMERVILLE: I think there's a typographical error. It just refers to 1.791 million as the total operating revenue forecast, and of course I think that should be billion. 190 MR. PENNY: Yes. 191 MR. SOMMERVILLE: I don't think anyone would be confused by it, but we may as well correct it while we're going along. 192 MR. PENNY: Yes. 193 MR. SOMMERVILLE: We'll take 20 minutes and be back at a quarter after. Thank you. 194 --- Recess taken at 10:55 a.m. 195 --- On resuming at 11:15 a.m. 196 MR. SOMMERVILLE: Thank you, Mr. Penny. 197 MR. PENNY: Thank you, Mr. Chairman. 198 So the third component of the demand forecast has to do with the storage and transportation revenues. There are three basic elements of Union's S&T revenue forecast. They are the storage and transportation exfranchise demands. This is Enbridge, GMI, TCPL, M12, C1 customers. There's the long-term peak-storage portion. There we're talking really about the market premium over the M12 cost-based rate. And then there are the transactional services which are essentially short-term services. They involve the transportation, short-term storage, balancing, exchanges, loans, title transfers and similar types of services. 199 The third category, the transactional services, these are opportunities that do not really arise on a planned basis with a balanced portfolio. They tend to become available as a result of weather or market variances from the gas-supply plan. And while warmer-than-normal weather and unique market conditions led to a significant rise in short-term transactional activity a few years ago, the level of S&T transactions and their revenues have declined in recent years. The evidence outlines a number of reasons for that. The Enron fallout simply reduced the number of parties who were transacting in the market. So that was one significant issue that has recently and is expected to continue to suppress transactional revenue. There's reference to that in the evidence at Volume 5, paragraphs 403 and 405. 200 For those who remain in the market, credit is much tighter and this has, again, reduced the number of transactions or opportunities to transact and also increased their cost, and therefore, led to fewer opportunities and transactions. 201 The third factor is the reduced summer/winter price differentials which have reduced year-to-year peak-storage values from historically high levels in 2002. And then, finally, there is the effect of high-commodity prices which have reduced demand for natural gas, and therefore, reduced the number of exfranchise transactional opportunities just at large in the marketplace. 202 So due to these market factors, Union is experiencing and expects to experience in 2004 reduced levels of S&T transactional revenues and fewer transactions. 203 In addition, one specific historical source of transactional revenue, that was the hub-to-hub service was discontinued by Union's western Canada partner in EnCana and Union, therefore, is winding down this service over the 2003-2004 period and does not expect to engage in any new transactions for that reason. 204 So S&T revenues and the long-term storage market premium revenues are, of course, deferred. Historically, in the 499 case, the Board approved a method by which approximately 5.5 million of forecast revenue would be shared. That was the 10 percent to Union and 90 percent to the ratepayers. This was an early form of incentive to provide some reward to Union for maximizing the value of unutilized asset capacity in the short term. So 5 million of that forecast in 1999 was put into rates. Any amount greater was deferred, but Union was at risk for anything below the 5 million. Amounts greater than forecast were to be shared 75/25 after the RP-1999-0017 case were to be shared to enhance Union's incentive to maximize asset utilization, and that principle was extended, as I've said, to long-term storage premium in the RP-1999-0017 case. 205 Union is not proposing any change to the deferral methodology. While there may be theoretical arguments to support a certain amount of rationalization of the treatment of these revenues, Union's experience is that the status quo is actually working well. The incentives created reward Union and are generating significant benefits to the customers to the tune of 75 percent of incremental revenues. And the amounts are, in fact, not trivial. Union has been able to deliver customer benefits of 17 million in 2002, forecasts 6.4 million in 2003, and is expecting 12.83 million in 2004, those all being 75 percent of the deferred amounts. And those you find at Exhibit C.1, tab 3, appendix A updated, and with respect to the last number I mentioned, as updated in N.21.3. 206 So essentially on the deferral structure issue, Union's position is that if it ain't broke, don't fix it, so the system in place has been working well for both parties and Union is, therefore, not proposing to change it. 207 The bottom line on the S&T forecast, therefore, is total S&T revenue of 162.7 million for 2004. That's at C.3, tab 1, schedule 1 updated. And the detail of that is broken down at C.3, tab 4, schedule 1 updated . 208 In conclusion, then, on S&T -- sorry, let me step back. In conclusion with respect to the demand forecast, we say that it is a reasonable one and should be approved as the revenue base. 209 RISK MANAGEMENT/GAS SUPPLY/GAS COST DEFERRAL AMOUNTS AND RESTRUCTURING: 210 MR. PENNY: I then wanted to turn, Mr. Chairman, to gas supply, and I'll deal first with risk management and then with one or two other gas supply issues. 211 One aspect of Union's gas supply activity is, of course, risk management. Union's been engaged in risk management of commodity costs for many years, and the program has obviously grown and evolved. As part of the settlement of all the monetary issues in the last rate case, RP-2001-0029 -- I guess it was two cases ago, excuse me -- Union agreed to engage an independent consultant to evaluate its commodity risk management program. And that was done, of course, in consultation with intervenors as agreed, and Union retained Risk Management Inc., or RMI, to conduct the assessment. And the RMI report is in the evidence at Exhibit D.2, tab 1. Union's evidence on risk management is at Exhibit D.1, tab 2. 212 The founder of RMI testified on day 1 of the hearing, Mr. Snell. He has a post-graduate degree in science and a long history of experience with commodity risk management programs for regulated utilities in the United States. And he's previously been qualified as an expert in risk management matters and has testified before a number of state regulatory commissions and done a number of commission staff presentations on risk management issues as well. 213 There's really two issues when you're looking at risk management. The first is what is RMI's assessment of Union's current self-risk management program, and then secondly, how can it be improved. RMI, I say, conclude -- and I think there's no controversy about this, RMI concluded that Union's program was consistent with industry standards, that its goals and objectives were appropriate, and that it was meeting those goals and objectives. RMI's main conclusion in the report, he says at page 3, focuses on the fact that Union's gas program has proven to emulate industry standards in infrastructure and execution." 214 Page 6, he says: 215 "Even as the natural gas market has seen heightened volatility in the last three years, Union Gas's program continues to meet industry standards in controlling and mitigating market and credit risk." 216 Mr. Snell's report dealt with three structural areas that RMI believed most utility risk management programs tend to encompass, and he says it's a goal or an objective as to the purpose of the program, an established set of internal controls to govern the administration and procedural aspects of the program and the hedging methodology, which underlies transaction execution for the achievement of the goals and purposes. 217 And with respect to this first issue of the goals, the conclusion was that the objectives Union Gas has in its policy are appropriate and in line with those similar regulated utilities. With respect to the second, that is, the internal controls, RMI concluded that the primary element of risk control is the oversight committee that is established to maintain shared accountability. With committee consent required in hedge plan implementation, he said Union Gas mitigates the potential abuse of power stemming from any one executive or department. And he went on to say that in addition to oversight accountability, the segregation of functions within a utility provides a valuable internal control in the ongoing operation of a risk management program, and that Union Gas specifically had a sufficient check and balance system between the gas supply and the accounting finance departments for transaction, verification, and program activity reporting. 218 He went on to say at page 5 of his report that: 219 "The commodity risk management program of Union's has instituted an internal framework to administer the company's policy. The primary element of the company's risk control is its oversight committee, the hedge committee, which consists of experienced senior executives and managers. The committee structure has tight controls in place with a majority of hedge committee members' approval being required on both price and volume targets prior to the execution of any commodity risk management strategy. Speculative positions or transactions are strictly prohibited by this policy. The hedge committee meets on a monthly basis to review past activity and ensure proposed transactions fall within the approved parameters of the program." 220 And then on the third opponent, which is the execution and the actual transaction activity, at page 10, Mr. Snell concluded that: 221 "RMI believed that Union Gas met industry standards in its use of statistical and portfolio analysis, a methodology that is only now becoming widely utilized with regulated utilities. A combination of price forecasting and historical valuation has been an effective hedging tool for Union to minimize volatility while still providing reasonable value to its ratepayers. Union Gas can be comfortable in the fact that it has minimized volatility and provided reasonable value to the ratepayer during a period of unprecedented volatility for natural gas products." 222 So that was step 1. We agreed that we would have this done. It was done. The conclusion is Union has an effective risk management program. Then the question becomes are there recommendations for improvement, and of course the answer is yes, Mr. Snell's recommendations and Union's response to those recommendations is detailed in the evidence. And I'm not going to go through them all because, for the most part, they're actually very minor changes in the process. Mr. Dent described them in the evidence as, I think, tweaking, some of the them are just things like changing the title that someone has to make it clearer where they fit in the process. And they're mostly self-explanatory. There's really only two that represent any significant substantive change, and I do want to talk about those. 223 The first is the recommendation to add market flexibility to the program by permitting the hedge committee to approve price, time, and volume hedge parameters rather than the current process where the committee is required to approve each individual hedge transaction. And this issue is covered in the RMI report at D.2, tab 1, page 15 and appendix 3, and in Union's evidence at D.1, tab 2, page 6. 224 The other which is related is RMI's recommendation to allow for a longer term -- for a longer term transactions by allowing hedgible volumes to include a certain percentage of forecasted future demand, and that discussion is at the RMI report, D.2, tab 1, page 17, and in Union's evidence at D.1, tab 2, page 9. 225 With respect to the first issue, then, having the hedge committee approve parameters rather than each individual transaction, the discussion in the report at page 15 is that one common practice is to have a committee approve broad price and time parameters and allow the gas supply personnel, or hedgers, to work from those guidelines. So under the RMI proposal to allow the establishment of parameters, Union Gas, he says: 226 "Union Gas hedgers will be better equipped to take advantage of opportunities to protect the company from volatile natural gas prices through the application of hedge committee approved price, time, and volume parameter ranges versus the current process where the hedge committee is required to approve each individual hedge strategy." 227 And then the -- so that's a recommendation that was made by the outside experts. Union is proposing to follow that recommendation and to establish parameters which would then allow the hedgers to operate within those parameters, but obviously if they wanted to operate outside those parameters, that they would have to come back and get specific approval for a specific transaction. 228 The RMI report then goes on to deal with the second issue at page 17, and there he says that: 229 "Union Gas's current shorter term physical nature of its hedge program may result in a lost opportunity to secure good natural gas value." 230 This was the issue, you'll recall, that Mr. Snell analogized to buying things on sale. That if you go to the store and milk is usually a dollar and it's on sale for 50 cents, well, sometimes people would buy two, and that's, in essence, the concept that underlies this idea. He says that: 231 The industry standard for most regulated utilities is to design hedge program volumes based on forecasted load. RMI recommends that Union Gas redefine 'Hedgible Volumes' to be a certain percentage of forecasted load (future expected demand). By instituting this change," he recommends, "Union Gas will be better poised to take advantage of price value opportunities as they arise. The actual percentage of forecasted load approved for hedging by an oversight committee is," he says, "typically contingent on the confidence the utility has in its forecast staying firm." And he says, "The current industry range for acceptable hedgible volumes is 80% - 100% of the forecast projection." 232 And then he concludes on this issue at page 18 of his report by saying that: 233 "To create flexible, yet acceptable parameters for the hedging route in securing price value over a long-term period, the hedge committee should consider setting an authorized percentage breakdown of forecasted load for up to a five-year time horizon based on price and time-driven parameters. It is typical for regulated utilities to create a table which staggers the approved volume levels over time, and as market prices reach lower levels, the approved hedgible volume percentages are then incrementally decreased as time increases, for example, the current year approved percentage may be as high as a hundred percent whereas the fourth year may be as low as 20 percent." 234 And this was at appendix 3 of his report where he set out a model for how to do there. And then he says: 235 "As markets prices get further below the historical price median, a greater percentage of forecasting volume will be hedged." 236 So the further out you go, the less -- the less you risk manage, but the lower the price goes, the more you manage. And it's a combination of those two things operating in tandem. 237 This was also discussed in volume 1 at paragraphs 228 to 234. 238 So the first recommendation is, in effect, to streamline the approval process somewhat to provide the implementers of the program with more flexibility to respond to market changes, and that, Union is proposing to do. And the second recommendation is really, in effect, to allow Union to buy for future years when the prices are particularly low, and again the specific parameters of how that would work with detailed in the evidence. Neither recommendation, and I emphasize, involves giving any unfettered discretion to anyone. Both are tightly controlled and, in fact, mechanical in the way that they operate, in the way -- they're mechanical friendly in both concept and implementation. 239 So Union is proposing with only minor exceptions to accept and implement all of RMI's recommendations, but we are seeking acknowledgement that the adoption and implementation of its amended risk management program is a reasonable and appropriate thing to do. 240 Stepping back from the specifics of Union's program and RMI's particular recommendations, there are, perhaps, two larger questions. One is: Should Union engage in risk management at all? And I suppose the second question is: What should it cost? 241 On the first question, I want to refer to an answer to a question put to RMI by Mr. Warren. I'll have to come back to that. 242 The issue of whether Union should engage in risk management at all, I think, is dramatically answered by the evidence of Mr. Snell in appendix 2 of his brief, where there's, you'll recall, a map that shows that 80 percent of the commissions regulating natural gas utilities allow commodity risk management as a tool to stabilize natural gas prices and allow the utilities to fully recover the costs of their risk management activities. 243 On the second question, it is, of course, difficult to be precise about what a risk management program costs in the sense of comparing it to total prices if there had been no risk management activity at all, and the reason for this is simply that it is entirely dependent on the time period that you look at and the balance of any cycle in the life of natural gas prices that you have captured in the time period that you look at. 244 Both Mr. Dent and Mr. Snell spoke to this issue during the oral hearing, and I've extracted it at pages 12 and 13 of the compendium, the passage where this came up. It was in the cross-examination by CME, and the question was whether, over time, the cost of gas to customers without hedging is about the same as the cost with hedging without factoring in the cost of hedging itself, and Mr. Dent says at line 33: 245 "No, I wouldn't say that. What you're seeing in Exhibit J.24.18 is what our experience was over that five and a half year period. I think what you would expect to see is that over a period of time, you would expect to see some costs above what the actual market price was because there tends to be some costs implicit in buying options and in transacting over a bid offer spread. So I would say that maybe our results are a little better than what you might normally expect to see even over a four- or five-year period." 246 "That should be added to the cost of gas?" 247 And Mr. Snell says: 248 "Well, if you look at a cost benchmark it is extremely difficult, because, when you look at a benchmark, I think first you have to look at the objectives of a risk-management program, and as has been stated time and time again, it isn't for profit. And the second issue is reasonable value. When it comes down to comparing that to another strategy called floating with the market and taking the risk associated with being at the whim of the day-to-day fluctuations in gas costs, we're talking about two different strategies. 249 "Now, getting back to the benchmark to quantify a benchmark is difficult. A dollar benchmark or cost is very difficult because you look at the dollar amounts even from the end of the year going back four and a half years, whatever it is, Union is a little bit worse off to the market if you look at that particular exhibit which brings us through July of this year, they're a little better off than the market over that time period." 250 And this makes the point that I was making a moment ago that it is entirely dependent on the time period that you look at. And he goes on: 251 "At the same time, there's drastically reduced price volatilities to the customer, which, again, is the objective of the program. If you go back and look at the objectives and if the objectives seem like they have been addressed and are being met, I think you have a successful program. But to quantify that in a dollar term on any given moment in time is a difficult proposition." 252 There's also discussion of that issue at Volume 1, paragraphs 307 to 308 and 358 to 359. 253 When Exhibit J.24.18 shows, what was referenced in Mr. Dent's answers, is that since the year 2000, Union's costs have been approximately $7 million below the market as measured by the mark to market methodology. I addition to the financial results, in a way more important than that, because Union is not saying that it needs to be 7 million to the good in order for it to be a successful program. As Mr. Snell said, that's entirely dependent on the time period you look at; but more importantly, in addition to the 7 million on the five and a half years, the volatility in Union's portfolio is approximately half of the market volatility as measured by standard deviation. So over the past five and a half years, Union's costs have been just below the market while at the same time only half as volatile as the market, and that, we say, is consistent with the objective of the program. 254 The passage I was looking for a moment ago, which I couldn't find, had to do with whether Union should engage in risk management at all, and I just wanted to return to that because I found the evidence reference, and it's at Volume 1, paragraphs 245 to 247, and the question was -- Mr. Warren asked the question: 255 "Let's assume a universe in which Union were not engaged in risk management. Can you describe for the Board the nature and extent of the risk that would be suffered by system customers if Union did not engage in this kind of risk management?" 256 And Mr. Snell replied: 257 "The concept of not hedging is potentially the most risky position that one might take because you are assuming the total risk of the market in anticipation of trying to get the lowest possible price. And there is, again, a risk reward to the marketplace that makes that extremely risky. You have no price stability, you have no hedge against volatility, and it is statically speaking, a very risky thing to do." 258 So in our submission, risk management is both appropriate and prudent. It is a widely-recognized method of managing price volatility. Union's risk management program has been demonstrated to be working effectively by an independent external consultant. Its total costs are well within a band of acceptable levels of costs that are being experienced in the industry, and the adoption of RMI's recommendations, which is being proposed by Union, will only enhance the program and make it even better. 259 So Union asks, therefore, for the Board to acknowledge that risk management is appropriate and that the specific changes Union is proposing to implement are reasonable ones. 260 Now, briefly on gas supply. Other than the risk management analysis that was done, gas supply issues as such are quite straightforward in this case. The implications of the load-balancing initiative in the March park I will deal with comprehensively in my argument on the load-balancing directive, so I'll come back to those. 261 The blue-page update provides the gas cost deferral balances which include the impacts of EB-2003-0130, Alberta border commodity increase to $6.67 a gJ, which was effective July 1, 2003. And the sum 100 million will be offset by prospective recoveries that were approved by the Board in NEB-2003-0056 and in EB-2003-0130 of 105 million. So this results in a forecast year-end deferral credit of a little over $6 -- sorry, 6.1 million in total. And that you find in the current updated balances based on the October QRAM which were provided in Undertaking N.10.2. And as I said, the prospective recoveries of forecast deferral credit has gone to 6.12 million. 262 The evidence on the gas-supply plan and the deferral balances was not challenged in cross-examination, and, in my submission, should therefore be accepted for purposes of the deferral accounts for purposes of disposition in this case, subject, of course, to the final true-up in 2004 when the final 2003 balances are known. 263 Upstream transportation, this has generated controversy in the past. It was not the subject of certainly any significant cross-examination and perhaps not the subject of any cross-examination, if my memory serves in this case. The portfolio for November the 1st, 2003 is in schedule 1 to Exhibit D.1, tab 1, blue page, and the changes to the portfolio are outlined in the updated evidence at D.1, tab 1, pages 6 and 7. 264 In essence, Union has added some Trunkline and Panhandle for two years and under those contracts, they have the ability to ratchet down the volume in the second year, so this effectively creates a non-renewal option for direct purchasers who are assigned a portion of these contracts in the second year, providing more flexibility in the vertical slice to customers who go direct purchase after November 1. 265 Union also acquired additional capacity on Vector which transports from Chicago to Dawn, and I point out that there was no controversy associated with that because Vector is, of course, no longer an affiliate of Union's. This contract, again while it's for five years, also has a ratcheting-down mechanism that also enables Union or direct purchasers who take on this obligation under the vertical slice the option of not renewing these volumes in the second year, and there are certain specified volumes outlined in the evidence and each year those can be ratcheted down. So this, again, introduces more flexibility into the -- into the vertical slice for the benefit of direct-purchase customers. 266 The additional benefits are that new supply lands at a cost which is competitive to the major alternative, TCPL, and approves overall the diversity and flexibility of the portfolio for system sales service and direct-purchase customers. 267 Due to the expiry of some long-term TCPL contracts in the north, Union was also able to do some reconfiguring of transportation to the north. Basically Union was able to reduce some annual capacity in excess of that required to serve the north while preserving the capacity necessary to meet peak-day demands, and so the net result of that was a more efficient system and reduced exposure to some unabsorbed demand charges in the north. So those were additional incremental gains achieved in the overall rationalization of the gas-supply plan for 2004. 268 I'd only mention two other things briefly. Winter-peaking service. Dawn-Trafalgar expansions, as you've heard, are lumpy in their impact on transportation capacity because large capital outlays are not made for small shortfalls in demand result -- in capacity resulting in incremental growth. In fact, Union waits until there is a critical mass before doing Dawn-Trafalgar expansions, and it's usually for more than current needs rather than needs of economies of scale and efficiency. So you have periods where there are shortfalls where there's not critical mass, and then following a Dawn-Trafalgar expansion, a period of time in which it is excess capacity, and it's just inherent in the nature of major capital expansions. This was all described by Mr. Isherwood at paragraphs 310 and 311, and this has been the case for many years. 269 There is a forecast capacity shortfall for 2003-2004 and for 2004-2005 winters which result from the deferral of Dawn-Trafalgar expansion off the books. The capital expansion aspects, what underlay those decisions, are outlined in Mr. Hyatt's evidence at B.1, tab 4. But in essence, Union is proposing to meet the shortfall in the next two years by the most economic means available, which is not the build option yet because the amounts are still too small, but through the purchase of a winter-peaking service. The 2004 cost of this service is in the plan at Exhibit D.3, tab 2, schedule 1, page 2 updated, and as recorded at a cost of $2.7 million. 270 The only other point I wanted to make has to do with the weather normal method. Union, as you know, is using and has been using for the last two years the 20-year trend method for operational purposes, and that includes such things as the amount of upstream transmission that it acquires and affects the volumes of gas -- the amount of storage required as well to meet infranchise demand. It's Union's position that the 20-year trend enhances operational efficiency and maximizes asset utilization, and it avoids unnecessary costs that would result from overforecasting such as unabsorbed demand charges. This was explained at J.5.4 of, and in volume 10, paragraphs 1001 to 1007 in the evidence of Mr. Isherwood. 271 The benefits of the 20-year trend in avoiding the acquisition of more capacity than necessary affects both direct purchase and sales service customers because the annual DCQs of direct-purchase customers, without using the 20-year trend, would increase and the pipe allocations to direct-purchase customers and also the UDC exposure would also increase as well under the 30-year average. 272 Now, in this case, Union is asking, as I've outlined, for approval to use the 20-year trend for rate-making purposes in the sense that it is used to underpin the revenue forecasts that I discussed earlier. I simply want to make the point that if Union does not receive the approval for 20-year trend in rate-making purposes, it will not likely continue to operate under two methodologies. The only reason it's done this to date is because it was not able -- Union was not able to introduce the rate impact of the 20-year trend during PBR as the Board ruled that the weather normal method change did not qualify as a non-routine adjustment for the approved formula. So if the Board does not approve the 20-year trend in this, a cost of service year, and keeps the 30-year average, then Union will likely return to 30-year average for planning purposes and would, as I've noted, seek recovery in any future cases of all costs associated with that. 273 And then finally on gas supply, I just wanted to touch very briefly on two resolved or virtually resolved issues; that's the QRAM methodology and the gas cost deferral account restructuring. 274 QRAM. Union, of course, proposed changes to its QRAM mechanism for the purposes of improving efficiency and transparency, and this will be achieved, these improvements will be achieved through the use of more timely and publicly-available price data rather than formerly the use of proprietary forecasts and the use of preapproved standardized customer notices. 275 Secondly, with the formal inclusion of prospective recoveries of deferral balances as part of the QRAM process, the prospect of large out-of-period retrospective recoveries will be significantly reduced. As you know, Union and intervenors agreed to adopt this new QRAM process and the Board accepted that on October 3rd as part of the settlement agreement. So Union will be using the new QRAM process for the January QRAM that will be filed later this month, and there's no further action required by the Board in respect of this issue in this case. 276 The second issue is that the deferral account restructuring that the gas supply panel testified to at volume 9, paragraphs 983 to 1024, Union, as you know, was requesting an expedited approval of the deferral account restructuring so that it could be utilized for the first 2004 QRAM, and through correspondence and discussion with intervenors over the past few weeks, Union was able to resolve the concerns raised and so last Friday, Union faxed to all intervenors and sent to the Board a draft accounting order to facilitate the expedited approval. So the Board, subject to intervenor comment by the end of today -- the day today, should have everything it needs to approve the requested accounting order. And I was asked to advise the Board that receipt of the order by November 19 would allow Union to prepare its January QRAM for use under the new accounting structure. 277 MR. SOMMERVILLE: We had suggested, Mr. Penny, that Union draft the order for circulation. That seems, to us, to have some benefits. Do you have any comment on that proposal? 278 MR. PENNY: When I alluded to the draft order going out -- to the draft correspondence going out on Friday, that included the draft order. 279 MR. SOMMERVILLE: Thank you. I haven't seen that, but that's fine. 280 MR. PENNY: We sent out a covering letter summarized where we're at, and said attached is the draft. The reason I said the end of the day today is we -- this is within the Board's discretion, but we'd asked any parties with comment to let us know by the end of today just so we'd have some point in time -- 281 MR. SOMMERVILLE: Thank you, Mr. Penny. 282 MR. PENNY: We'll obviously be going past the lunch break. If you don't have it, let us know -- in fact, we'll bring an extra copy. 283 MR. SOMMERVILLE: I'm sure Mr. Wightman can provide me with a copy. Thank you. 284 MR. PENNY: Thank you. 285 I'm then going to leave gas supply and turn to O&M. 286 O&M: 287 MR. PENNY: The total O&M budget, total net utility, is 361.9 million. That's a little different from the yellow-page update of 363.6 million, and the reason for that slight difference is N.7.1, which involved a change in the pension deficit cost from 21.4 million down to 19.7 million. So the only change -- the only further update to the yellow pages is the change that is reflected in N.7.1 on the pension cost, and that takes us to a total O&M budget of 361.9. That's, of course, the number without adjustments for capitalization, compressor fuel, and other things of that nature. 288 Now, the O&M budget is one of those things that you can, and some people did, spend days on. I propose, however, to tackle this at a high level and to only focus on what we say are the main drivers of the O&M since the last rate case. 289 The main point I want to make is that for those costs that are within Union's control, Union is forecasting cost increases which are substantially less than the Ontario 2003 and 2004 CPI of 2 percent and 1.8 percent respectively. Union's customer base has continued to grow, and through productivity and efficiency gains, controllable increases to operating costs per customer are forecast to be at a rate that is lower than inflation. And Union submits that its forecast of O&M for 2004 is at the level necessary for Union to maintain safe and reliable service to its customers and to comply with increasing regulatory requirements. 290 And the overall effect of the O&M budget change since 1999 and the issue I just spoke to is shown on table 5 of Exhibit D.1, tab 5, page 8. And at page 14 of the compendium, what we've done is simply, with handwritten notes, updated these numbers to where they are today. So what page 14 shows you is that if you -- and I'm going to come back to this, but if you start with the gross O&M and you back out amounts that relate to benefit pension and post-retirement benefits, insurance costs, pipeline integrity and regulatory compliance costs -- and I'll speak to each of those and why they should be backed out -- if you back those out, and then you inflation-adjust for those five years, '99 to 2004, what you get is a gross O&M cost per customer which is less than it was in 1999 under the 2004 budget. 291 As we've said, this table shows that except for specific costs whose above-inflation increases are explainable by external factors, Union's 2004 inflation-adjusted O&M for customer cost declined on average by, under the new numbers, 1.8 percent since 1999. 292 One final overview point before turning to those four cost drivers which has to do with O&M for FTE, headcount issues and so on. Obviously, with salary costs being such a significant portion of O&M, another method of assessing the reasonableness of Union's O&M is to examine the average compensation cost per full-time equivalent, or FTE. 293 Now, you heard Union's witnesses testified that the concept of FTEs is not one that's embedded in their human resource computer methodology or system, PeopleSoft, and one that's not typically used by management, and as a result Union only had true FTEs on a forecast basis for '99, 2003 and 2004. They had forecasts for '99 because it was a rate case, and in 2003 and 2004, because the forecasts were developed for this rate case. But in the interregnum under the PBR period that such forecasts were not developed because they weren't needed and, as I've said, Union's management systems don't normally track those numbers. 294 But having said that, in spite of the fact that there's no tracking of those on an ongoing basis, given the interest of a number of intervenors in assessing the FTEs in Union's costs during the 2000 to 2002 period, Union did go back and prepare an estimate of FTEs using the data it had on positions and people as at December 31 of each year. And the estimated and actual forecast FTEs are found at Exhibit N.6.11. And I won't take you to it and go through it; a fair bit of time was spent on this at the hearing. But N.6.11 shows over the period 1999 to 2004, the average compensation per estimated FTE increased by 17.2 percent, or about 3.4 percent per year, and the evidence is that Union's growth in salary costs have not exceeded the growth experienced by comparable companies in the marketplace, in the Canadian marketplace. And this evidence is found at Exhibit J.3.11 and at Volume 7, paragraph 975. 295 So we say, as another method of evaluating the reasonableness of the O&M budget, we look at the wage costs and these are within -- that Union's experience has been lower than the growth in salary costs in the universe of comparable companies. 296 Benefits, post-retirement benefits and pension expense. Those have approximately doubled since 1999. And the 2004 budget for these three items is roughly $52 million. This is not the result of a gold-plated pension and benefit package, nor is it a result of deferring expenses from PBR-regulated years into a cost-of-service year. These are costs which are caused by market factors which are beyond the company's control. Cost increases of this kind have been experienced by most companies of the size and nature comparable to Union in Canada, and Union's method of accounting for these costs are in accordance with GAAP as recommended by its accounting and actuarial professional consultants. 297 Let's turn to benefit costs for the moment. Benefit costs account for 25 -- roughly 25 and a half million dollars of the budget amount. The most significant component of these costs are medical and dental. Union has a flexible benefit program where employees can, in effect, spend a certain number of allocated credits on those portions of the benefit plan that meet their needs, and this actually helps Union to manage the escalation in health care benefit costs by using available resources most effectively. And there's a discussion of that at Volume 6, paragraphs 1079 to 1104. 298 But these costs on an economy-wide basis are increasing steeply for everyone. According to Towers Perrin for 1999 to 2002, health and welfare benefit costs increased by 18 percent per year. Union's benefit costs are expected to increase by about 13 percent from 2003 to 2004. And it is Towers Perrin's evidence that these increases are consistent with benchmark data for medical and dental experience across Canada for all industries and for all types of health and welfare benefit plans. They also give evidence that prescription drugs are the single largest component of growing health-care benefit costs, being 70 to 80 percent of health plan costs. But also contributing to these increased costs are, they say, paramedicals such as psychologists costs, shifting from public to private plans, dental fee increases, and higher utilization of more expensive dental procedures. 299 Now, Mr. Witts testified during the oral portion of the hearing on the health and benefit costs at page 15 of the compendium. I've extracted Volume 6, 274, and the question of Mr. Witts was whether Towers Perrin performed any form of audit function to determine whether or not Union was doing better than other similarly situated companies, and this is in the context of health and welfare benefits, and at paragraph 274, you'll see that Mr. Witts said: 300 "Yes, it does. As part of the annual review that we do on behalf of the company, which includes reviewing the proposed renewal rates that the carrier comes forward with, we compare that to our benchmark data to ensure that the levels of increases that are being put forward are appropriate. We look at the experience that has been exhibited over the prior financial year, and indeed, we assist the company in negotiating with the carrier on the pension costs and using the benchmark data that we have in order to arrive at a competitive agreement with the carrier." 301 And then there was a discussion about whether that report be made available, and it was filed at Exhibit M.6.2, and that that analysis, it's called the 2002 financial analysis and 2004 renewal analysis, that was prepared by Towers Perrin, it's an assessment of Union's health and welfare benefit plan and it contains a detailed review of the costs, how the benefit carrier is performing, and whether DEGT Canada of which Union is a part, is getting appropriate value for what it costs. 302 So, in my submission, clearly these expenses are treated very seriously. They are not incurred casually or lightly. And they are scrutinized by competent professionals to ensure that they are prudent. 303 The evidence is there, therefore, that Union is getting good value but is subject to the same upward pressure in this area of expense as is being experienced by everyone else in this economy. And as Mr. Witts said, again in evidence at page 16 of the compendium, volume 6, paragraph 1108, he was asked whether this is gold-plated and he says: 304 "It's a good plan. Is it a Cadillac gold-plated plan? No, by no means. In fact, the plan, as it will be applied in 2004, is a redesigned plan that introduces some cost-sharing elements, a greater level of cost sharing with employees, and it was benchmarked in the medium of Union Gas' comparator group of companies." 305 So it is, in fact, the health -- the health and welfare benefits plan is, in fact, being in the median, is what would classify as what Mr. Thompson called a run-of-the-mill plan. Nothing exceptional about it. 306 Now, post-retirement benefits. Post-retirement benefits make up roughly a little over 5 million of the budgeted cost in this category. The principal driver of the increases in this cost for 1999 is actually a change to The Canadian Institute of Chartered Accountants handbook on methodology, that's the 3461 you heard so much about. In 1999, retiree benefits were booked at cash costs when they were actually incurred. But as of January 1, 2000, the CICA introduced a new accounting standard that required the future cost of retiree benefits to be accounted for during the period the employee was actually employed, so as they accrued, as the liability accrued. And this change was a one-time change of accounting methodology. That accounted for an approximately $5.3 million increase in 2000 to the cost of post-retirement benefits. 307 I might add that this is not the first time that this issue has been before the Board. In RP-1999-0017, there was a good deal of time spent on updating the approved 1999 forecast into 2004, and this issue was squarely raised because it was a -- it was a difference between the 1999 and the 2000 costs, and it was raised and explained by the evidence in that case, and I've reproduced at page 17 of the compendium, an extract from the Board's decision from RP-1999-0017, paragraph 2.201. 308 And there, the Board recognized that Union's proposal to change from a cash basis to an accrual basis for accounting for pensions and post-retirement benefits reflects a change in GAAP that has been adopted by the CICA and accomplishes the objective of matching the costs to the period in which the obligations arose. There was limited opposition to this change and further, in the Board's view, this may remove some potential variation in this expense. The Board accepts this changed practice for rate-making purposes." 309 So it's with respect to that changed practice, as I've said, that that really lies at the heart of the post-retirement benefits change, that roughly $5 million increase. The methodological change that underlies that has already been approved by the Board because it's exactly the same issue. 310 Then turning to -- let me say just a few more things about post-retirement benefits, and this relates back to the issue of industry expense increasing and upward pressure, and the fact that Union's costs are in line with industry experience. That, by the way, there is evidence on this at Exhibit D.1, tab 9, appendix A, that was the Towers Perrin letter, and specifically with respect to post-retirement benefits Towers Perrin said that: 311 "In determining the 2002 expense, it was assumed that the cost of medical services would increase by 5 percent per year. While the company continues to believe that this is a reasonable long-term assumption based on recent experience, it is likely this that these costs will increase by a greater rate in the short term. Accordingly, the assumed rate of increase has been revised to 10 percent in 2003, grading down to an ultimate rate of 5 percent by 2008. This change is consistent with Towers Perrin's benchmark data for other large Canadian organizations. This change in the expected future rate of increase in the cost of medical services is expected to increase post-retirement accounting expense by approximately 1 million per year. They say, however, "That the expense for post-retirement benefits will continue to increase in 2004 and future years primarily as a result of anticipated increases in the health care benefits." 312 And then finally there is the pension costs issue which represents a -- now with the update, approximately 19.6 or 19.7 million of the 2004 budget, again for this group of costs. This particular cost is clearly one -- the one involving the most dramatic change since 1999 having increased from a cost of 5.1 million at that time. And the significant change occurs in 2002 to 2004 and it's described at Exhibit D.1, tab 9, at pages 5 to 7, and appendix A. It's attributable, principally, to two things: Negative returns on pension fund assets due to declines in the equity capital markets and increased pension obligations as a result of a declining trend in long-term bond yields. 313 The Towers Perrin evidence indicates that accounting -- the accounting expense for defined benefit pensions has been determined in accordance with the standards of The Canadian Institute of Chartered Accountants, and specifically section 3461 of the CICA handbook. Union Gas anticipates a substantial increase in its expense for pensions in both 2003 and 2004 compared to 2002, and in particular, the expense for 2003 is expected to be roughly -- well, these are old numbers, but 8 million higher than the expense for 2002 and the expense for 2004 is expected to be approximately 6 million higher than the expense for 2003. And these increases are the result of adverse changes in the economic conditions. And there's three. 314 There's the discount rate used to determine the present value of expected future benefit payments. That change is based on long-term Canadian double-A rated corporate yields, and Towers Perrin has indicated in their evidence that this change -- that their discount rate change is expected to increase expense by approximately 3 million. There's a change in the expected rate of return on assets which expect -- is expected to increase expense by another 2 million. And then declines experienced in capital markets in recent years, which have already had an adverse impact on pension fund assets and on the financial position of the company's pension plan. 315 In essence, the pension benefit expense in 2004 is the product of two factors. I submit it's the application of GAAP and investment performance due to market conditions. Neither of these factors, in my submission, is within Union's control. These are costs that the company is incurring and Union, in my submission, is entitled to recover them in the absence of proof that they are not properly attributable to 2004 or in the absence of evidence that they were imprudently incurred. There is, in my submission, no evidence upon which the Board could come to either conclusion. 316 The issue of prudence was reviewed, at some length, in a different context in the RP-2001-0029 case. I won't go through all the detailed submissions I made on this topic then, but -- particularly from the National Regulatory Research Institute, but I do want to refer briefly to one of the authorities I referred to then and to the Board's decision on the issue of prudence in the Alliance-Vector case, and that starts at the compendium, at page 18. This was a decision of the Federal Energy Regulatory Commission in the New England Power Company case, and I want to refer to two passages which articulate the issue of principle that one has to keep in mind when evaluating prudence. Those appear at pages 21 and 23 of the compendium. 317 At page 21, you'll see in the back-lined portion it says that: 318 "The Supreme Court of the United States early recognized that the determination of what is just compensation for a public utility involves consideration of the utility's conduct in incurring its costs. In discussing what constitutes an adequate rate of return for a public utility, the Court stated that the return 'should be adequate, under efficient and economical management, to maintain and support its credit and enable it to raise the money necessary for the proper discharge of its public duties.' In another opinion issued the same year, the Court held that while a State utility commission had a duty to establish reasonable rates and charges, it was not empowered to substitute its judgment for that of the directors of the company, or to disallow operating expenses unless management had abused its discretion. Justice Brandeis, in a dissenting opinion in that case, stated that a utility should be allowed to earn a fair return on the amount prudently invested in it, and that the term prudent investment is not used in a critical sense. There should not be excluded from the finding of the base investments which, under ordinary circumstances, would be deemed reasonable. The term is applied for the purpose of excluding what might be found to be dishonest or obviously wasteful or imprudent expenditures. Every investment may be assumed to have been made in the exercise of reasonable judgment, unless the contrary is shown. 319 "The Court," it concludes, "subsequently held that regulation cannot be frustrated by requiring a rate to compensate for extravagant or unnecessary costs, but that good faith is presumed on the part of the utility absent a showing of inefficiency or improvidence." 320 Over on page 23, again the black-line passage: 321 "Consistent with the cases discussed herein, we reiterate that managers of a utility have broad discretion in conducting their business affairs and in incurring costs necessary to provide services to their customers. In performing our duty to determine the prudence of specific costs, the appropriate test to be used is whether they are costs which a reasonable utility management (or that of another jurisdictional entity) would have made, in good faith, under the same circumstances, and at the relevant point in time. We note that while in hindsight it may be clear that a management decision was wrong, our task is to review the prudence of the utility's actions and the costs resulting therefrom based on the particular circumstances existing either at the time the challenged costs were actually incurred, or the time the utility became committed to incur those expenses." 322 And then if you would flip in the compendium to page 28, I've taken an extract of the Board's findings from the RP-2001-0029 case where the issue of the prudence of the cost consequences of the Alliance/Vector contract entered into between Union and Alliance and Vector was completely and thoroughly reviewed and decided by the Board, and in the black-lined passages you'll see that: 323 "The Board acknowledged that, implicit in the framework underlying rate regulation, there is a presumption of prudence with regard to the actions of a regulated utility. It would be impractical for any regulator to examine the prudence of all individual business or operating decisions made by a utility. However, when serious questions are raised by stakeholders respecting the prudence of a utility's actions which give rise, as is this case, to material cost consequences to ratepayers, it is necessary for the regulator to examine the prudence of the utility's actions." 324 And then dropping down to the next paragraph: 325 "In every circumstance where the Board is required to consider the prudence of any action by a regulated utility, it is engaged in a review of the reasonableness of the utility's action at a given point of time in the past. The retrospective nature of such a review is inescapable. Utilities that are obliged to take action to address operational requirements must be able to do so with some confidence that their actions will be judged on the basis of circumstances obtaining at the time they are compelled to make the decision, not on the basis of circumstances which emerged afterward. This principle is consistent with the NRRI guidelines." 326 So, Mr. Bodnar testified at some length about the professional pension fund managers used by the DEGT pension administrators, how they're selected, how they're reviewed, how their performance is monitored, and the care with which the pension investment committee carries out its functions and its oversight of its professional managers. And you'll find -- I won't take you to it now. You'll find those discussions at Volume 6, paragraphs 815 to 817; at Volume 7, paragraphs 1059 to 1064 and 1074 to 1080, and also in Volume 7 at paragraphs 1092 to 1093. 327 Pension administrators under the legislation, under the Pension Benefits Act, are entitled to rely on and follow the advice of properly qualified professionals. The only way, in my submission, you could come to the conclusion that the pension plan investment earning declines that were present in this case were not prudent, therefore, is by coming to the conclusion that the pension committee had been negligent in its appointment, management, or oversight of its professional investment managers, and there is simply no evidence on the record on this subject, and therefore, there's no basis upon which you could come to that conclusion. 328 The mere fact that there were investment losses is no evidence of anything, in my submission. It's hindsight. It's common knowledge and there's evidence in this case that virtually every pension plan in North America has suffered investment losses due to market factors following a string of adverse events, like the Enron collapse and September the 11th. The standard plan out there typically is about 80 percent underfunded. That was the evidence of Mr. Witts at Volume 7, paragraph 505, and there's also a discussion about the universality of pension investment losses at Volume 6, paragraph 367. 329 Now, Exhibit J.1.87 contains evidence about investment performance of pension plans, and that is at page 29 of the compendium. And what that indicates is that there was a median rate of return over the same period for Canadian pension plans with pension funds assets greater than 250 million of minus 11 percent, and this exhibit tells us that the experience of the Union pension funds for the same two-year period was minus 18 percent. And so we have a median degrade in the value of 11 percent, and Union's experience being -- of minus 11 percent, and Union's experience at minus 18. 330 Mr. Bodnar explained at Volume 6, paragraph 383, what happened there, and that's at page 30 of the compendium and 31. And what Mr. Bodnar says is: 331 "We expect that when we make a decision, over time, that we will do reasonably well. But it is true that we are looking for certain cost recoveries associated with costs associated with our clients. These decisions that we make were not made in 2002 or 2003. These are longer term decisions that are made in terms of an investment approach, and we hold to that. You know, we tend not to sell low and buy high by chasing the marketplace. When one is dealing with a pension plan, one looks for a mix that we expect, and on advice from our pension advisors, will, over time, be a reasonable mix for a large pension plan." 332 Later, Mr. Bodnar explained that the investment portfolio was widely diversified and that the particular cause of the particular loss in this case, which was also identified in J.18.7, which was international equities, and indeed specifically mid-cap international equities had underperformed in the two-year period ending September 30, 2002, but, he said, they had in prior periods overperformed, thus lending a net funded benefit to the plan at that time. And he gave that evidence at Volume 7, paragraphs 1084 to 1097. 333 So you can't, in my submission, just look at the picture with the benefit of hindsight and say, Well, there were losses from mid-cap international securities, and therefore, they were imprudent. And equally, you can't just look at the median experience for two discrete years and say, if Union was below median experience, that is imprudent. The only basis upon which investment losses could be said to be imprudent is if there were evidence before you in this case that at the time the decisions were made, that the allocation of assets in international equities, or the selection of the particular equities in question was so imprudent that a reasonable pension committee ought not to have followed the advice and the recommendation of its professional fund managers, and there is no evidence before you that comes even remotely close to that. 334 This is, in my submission, a well-run pension plan. A lot of information about this plan has been made available in this case. None of it supports any accusation of imprudence. The fact that Union, along with everyone else, experienced investment losses is, of itself, no basis for denying recovery of the funding costs that are required by law necessary to ensure that the promised benefits -- that this deferred employee compensation is there when the employees retire. 335 Now, there was a question of fairness posed by Mr. Warren and perhaps others that ratepayers have to pay rates which reflect the recovery of deficits but get to corresponding gain when the plan is performing well or is in a surplus position. That was the suggestion that was made. And that, in my submission, is entirely wrong-headed analysis. The issue is the recovery of prudently incurred costs. The years when investments perform at or above expectation, there are no deficits to be funded and therefore no additional costs to be recovered. So like any other cost of operating a company, if it is a cost that's not incurred or is avoided, it's not part of the operating costs and therefore does not become part of Union's revenue requirement. So do the ratepayers get surplus? Of course they don't get surplus. The whole notion discloses a misconceived idea of where ratepayers fit in the overall process. They get service in exchange for paying regulated rates which recover reasonable costs. You can't run a copy without people. You can't run a good company without people. You can't attract good people without adequate compensation. Pension costs are a cost like any other. It's no different from gas costs. They're incurred and they have to be paid. And the only issue, the only issue is whether the costs were prudent. 336 Now, there's therefore no asymmetry or unfairness in Union seeking to recover the costs of funding pension plan deficits provided that they are prudently incurred and accounted for in accordance with GAAP. And there's further evidence on this issue at volume 6, paragraph 396. 337 So then let me turn to the question of the accounting treatment and whether there's been any gaining of the year in which costs are being allocated so as to improperly attempt to defer costs, as I understand the suspicion is, from a PBR period in which recovery could not be sought to a cost-of-service period in which recovery could be sought. 338 The bottom line on this point, Mr. Chairman, is that there is no gaming or inappropriate allocation going on. All these suspicions is that because the number happened to be higher in 2004 than it was a year or two before, that it must have been true to some shell game employed by the company. These suspicions have all turned out to be completely unfounded. The requirements are established by the Pension Benefits Act and the CICA handbook under section 3164 and the testimony, the uncontradicted testimony of Union's professional advisors, Towers Perrin, Mr. Witts, was that those -- the requirements of those -- of the statute and of the CICA handbook are being met. The costs are the costs. They're being booked and paid in accordance with expert professional advice from one of the leading pension consulting firms and individuals in the country. And that advice and the evidence before you is that this is what other companies do and this accounting method is in accordance with GAAP. And to change the result, the Board would have to reject the advice and the evidence of Towers Perrin and Mr. Witts and come up with some home-grown approach to this cost and direct Union to depart from GAAP, leaving entirely aside the propriety of doing that, because I say there's no basis for that, it would have the result that Union would have to note its financial statements in future explaining that it departed from GAAP and why. 339 You heard from Mr. Witts that there are a number of regulatory regimes and rules that have to be accommodated in the administration of the pension plan. There are the funding requirements under the PBA. Those were, among other things, discussed with Mr. Brett at volume 7, paragraphs 813 to 817, and then there are the CICA rules, 3164 and the three-year smoothing rule and the 10 percent corridor. And that is dealt with at some length at Exhibit J.1.88. 340 And then the third piece is there is the amortization of actuarial gains and losses over the expected average remaining service life which ranges, in Union's case, from 10 to 17 years depending upon which plan you're looking at. And these accounting rules were also discussed in general at -- by Mr. Witts at volume 6, paragraphs 528 to 532. 341 The adoption of the smoothing rules, the universality of this practice among pension plan sponsors, and the need to continue this practice, once adopted, for consistency and financial presentation and disclosure, were described further by Mr. Witts and Mr. Broeders, volume 6, paragraphs 346 to 359, and volume 7, paragraphs 880 to 888, and paragraphs 1244 to 1250. 342 And then there was the exhibit prepared by Mr. Witts, Exhibit M.6.1, which illustrated the application of the three accounting techniques, the smoothing, the 10 percent corridor, and the amortization over the service life. And that was discussed by Mr. Witts at volume 6, paragraphs 1198 to 1203. And in my submission, M.6.1 makes it clear that Union has consistently followed the same pension accounting methods since 2002. It's got nothing to do with PBR versus cost of service. The same method is followed throughout. The only difference is that the market conditions changed and the plan experienced investment losses in 2001 and 2002 which gave rise to the necessity to make that underfunding up and make it up in accordance with applicable accounting rules. And that is being done based on expert actuarial and accounting advice from Towers Perrin in accordance with GAAP and consistently throughout the period. 343 Just to be clear, Mr. Reghelini thinks I may have misspoken myself, that Union has followed the same pension accounting methods since 2000. I think I may have said 2001. But the same rules have been applied since 2000. That was, of course, the year in which 3461 was inaugurated and -- 3164 was inaugurated, and the year that the Board approved Union's adoption of it with respect to post-retirement benefits. 344 So it has nothing to do with PBR versus cost of service, and it results exclusively from the application of generally accepted accounting principles. 345 As Mr. Witts said, it's simply the application of the methodology that's prescribed under 3461 of the CICA handbook which prescribes the timing and method of recognition of those 2001 to 2002 losses. And you can find that at volume 6, paragraph 1203, and it's also dealt with in volume 7, paragraphs 1354 to 1359 and I've reproduced that at page 32 of the compendium. 346 This was in re-examination. Starting at 1354, Mr. Witts was directed to M.6.1, and the question is: 347 "... whether there's any difference in the application of the pension accounting rules to Union between the 2001 to 2003 period, on the one hand, and the 2004 period on the other, is there any methodological difference in the application of the rules to those two periods of time?" 348 And the answer is: "No, the same methodology has been applied to each of the years that have been presented in the analysis." 349 Question: "And what would the impact on 2004 revenue deficiency be if there were no smoothing techniques applied insofar as it would result from pension expense matters?" 350 Answer: "The impact would actually be to increase the level of pension expense in that year by approximately $3 million." 351 "Can you explain why that is so to the Board?" 352 Answer: "Because the experienced gains and losses that are effectively being deferred into the future by the smoothing mechanisms, if they were not applied, we would have to recognize and begin to amortize the outstanding balance," and he means there, of course, the entire outstanding balance, "beginning at the beginning of 2004." 353 And this issue was also addressed in an undertaking of Mr. Witts at N.6.3, which is at the -- page 33 and 34 of the compendium. The bottom line, and I won't take you through it all, but the bottom line on the last page, in the last paragraph, indicates that the net -- that the net effect of the two smoothing methods is to decrease the 2004 expense by approximately 2.2 million. 354 "In other words, the total expense for defined benefit and defined contribution plans 19 million as stated in the original evidence and in Exhibit J.3.4 would have been approximately 21.2 million if no smoothing methods had been employed." 355 So the irony of all these suspicions about inappropriate costs shifting as a result of the smoothing method is not only is there no basis for it what sorry, but even if you ignored the accounting rules and engaged in no smoothing, the 2004 expense would actually increase over what it is today, or what it is proposed to be today. 356 Finally, I would simply make the point that there is no -- there's no support for some suggestion we heard a little bit of in the course of the hearing that the company somehow got a free ride during PBR. The 1998 -- the 1999 base for pension expense, remember, was only $5.1 million. You can see that at D.1, tab 9, page 3. And as Mr. Witts noted at Volume 6, paragraphs 532 -- at paragraph 532, excuse me: 357 "The late 1990s were buoyant and the plan was in a very healthy financial position. Costs were low and as a result rates only reflected the 5.1 million." 358 The company's actual pension plan contributions on a cash basis, though, are shown at -- in the period subsequent to that in '99 and following, and during the PBR period, are shown at N.7.11. And even though there was only 5.1 million in rates, what that shows is that the company actually paid out 7.8 million in '99, 12 million in 2000, 8.3 million in 2001, 13.2 million in 2002, and 15.9 million in 2003. So there is simply no basis for any suggestion that the company was trying to get a free ride during the PBR and to offload costs into the cost of service. 359 Let me then -- Mr. Chairman, I'm almost finished O&M, and maybe after that would be an appropriate time to take a break because then I will only have affiliates and load balancing and a couple of smaller issues. 360 Let me turn briefly, between 1999 and 2004, and those are effectively insurance and regulatory compliance. 361 Insurance costs are dealt with at D.1, tab 5 of the prefiled evidence, starting at page 9, and in essence, what the evidence says is that as a result of catastrophic claim losses and lower investment returns, the insurance market, in recent -- that the insurance market experience, that there have been increased coverage costs. Premiums of 50 to 100 percent on property and casualty policies have been common. The energy industry specifically is experiencing 100 to 200 percent increases despite larger deductibles and lower coverage limits. 362 And we also have, as a result of increased cost of litigation and high-profile bankruptcies and the concern over corporate accounting and financial reporting, directors and officers' insurance rates going up by 75 and 100 percent. And you'll find in appendix A in D.1, tab 5, some articles from the industry that detail those changes and the basis for them. 363 So Union has forecast a 45 percent increase in its insurance costs for 2003, but no additional increase for 2004. Through the use of substantially increased deductibles, Union is planning to contain the 2003 increases at a flat level. 364 Now, Mr. Birmingham explained that insurance is one of the areas in which affiliate relationship helps to contain costs. With respect to the D&O insurance, up to June 2002, you'll recall, Union had some protection, some contractual protection against rising costs, because Westcoast had, in effect, a fixed-price contract for three years for that type of insurance and that expired in 2002. 365 And what Mr. Birmingham said was that under today's market conditions, Westcoast alone would not have been able to obtain the level of coverage it did at all, and that the premiums for what it could have obtained would have been lower. You'll find that evidence at Volume 12, paragraphs 1322 -- would have been higher, excuse me. I said lower. Would have been even higher. And that's at Volume 12, paragraphs 1322 to 1333. 366 Then the two areas of increased costs due to external regulatory constraints, Mr. Smith will deal with in more detail. But pipeline integrity, that evidence is at D.1, tab 5. These are regulatory compliance costs related to the safety of pressurized pipelines, and they involve inspection and improvement costs. The significant increases arise from changes in government regulations which were enacted in 2001, and you've heard about this before because the issue came up during PBR, because of the regulatory change, these costs qualified as non-routine adjustments and they were subject, under the framework of PBR, non-routine adjustments were subject to deferral treatment. 367 But those costs haven't gone away, they're still there. It's a long-term program. The regulation is still there and requires Union to continue to serve a benchmark and to improve. And so now that we're moving to a cost-of-service year, those costs have to be accounted for outside of the context of deferrals because they are now ongoing costs that are embedded in Union's operations. They show up as increases since 1999, of course, because the program wasn't required in 1999. 368 Then GDAR and rate rider, again Mr. Smith will deal with these two issues, but essentially, the GDAR evidence is at D.1, tab 12 and the rate rider evidence is at D.1, tab 10. 369 But in essence, like pipeline integrity, these are two new regulatory compliance issues which didn't exist in 1999. 370 So with respect to the O&M budget, in our submission, if you adjust for these unique items which are outside of management's control, the pension and related benefit costs, the insurance costs, pipeline integrity and regulatory requirements, and then adjust for inflation, as of course, one has to do, Union's O&M cost per customer are, in fact, going down and the budget is necessary for the company to continue to provide safe and reliable service and ought to be approved. 371 Those are my submissions on O&M. If we take the break now, then we can proceed with affiliate relations and load balancing immediately after lunch. 372 MR. SOMMERVILLE: Thank you, Mr. Penny. 373 It occurs to me that we should probably enter the documents that you filed this morning as exhibits. 374 MR. PENNY: Sure. 375 MR. SOMMERVILLE: And I think that would mean, Madam Reporter and Mr. Wightman, that the argument outline would be Exhibit 24.1. 376 EXHIBIT NO. M.24.1: ARGUMENT OUTLINE 377 MR. SOMMERVILLE: The document entitled, "Union's Requests" would be exhibit -- I guess that's M.24.2. 378 EXHIBIT NO. M.24.2: DOCUMENT ENTITLED, "UNION'S REQUESTS" 379 MR. SOMMERVILLE: And finally, the compendium for Union Gas argument would be Exhibit M.24.3. 380 EXHIBIT NO. M.24.3: COMPENDIUM FOR UNION GAS ARGUMENT 381 MR. PENNY: Thank you. 382 MR. SOMMERVILLE: Thank you. We'll adjourn until 2:00. 383 MR. PENNY: Thank you, sir. 384 --- Luncheon recess taken at 12:45 p.m. 385 --- On resuming at 2:00 p.m. 386 MR. SOMMERVILLE: Thank you. Please be seated. 387 Mr. Penny. 388 MR. PENNY: Thank you, Mr. Chairman. 389 Coming back to the argument outline, we broke at lunch at the end of O&M, and so I'll turn to affiliate transactions. I'll have a few brief words on capital addition and capital structure, then to load balancing, and then Mr. Smith will proceed with the balance of the issues. 390 MR. SOMMERVILLE: Thank you. 391 AFFILIATE TRANSACTIONS: 392 MR. PENNY: Affiliate relationships. Obviously a lot of evidence on this topic in Exhibit D, tab 14, many interrogatories, and three days of oral testimony. 393 By way of background, prior to 1998, the OEB Act was entirely silent on the issue of affiliate relationships and Union in premerger of Centra and Westcoast are all subject to the terms and conditions of undertakings that were given to the lieutenant governor in council. Those provided that for transactions with an affiliate over $100,000, prior approval was required by the Ontario Energy Board, that the language that was adopted provided as follows: 394 Any affiliate transaction aggregating $100,000 or more annually shall require approval of the OEB, which approval shall not be withheld if the transaction is shown to be of benefit to Union Gas," in the case of Union "and not to the detriment of any of its customers, or if purchase takes place at or below market or if a sale takes place at or above fair market value." 395 So the old undertakings had two tasks, either of which was sufficient for prior approval. It had to be shown either that the transaction was of benefit to Union and not to the detriment of ratepayers, or that if a purchase or sale, it had to be at or better than fair market value from Union's perspective. 396 And then in 1998, those undertakings were cancelled and replaced with new undertakings of a much more limited scope which make no provision for affiliate transactions at all, and instead what happened was that the Act was amended to provide for the Board to institute codes or guidelines, including a code governing relationships between a regulated utility and its affiliates. So the requirement for prior approval was dropped and replaced with a code regulating affiliate relationships for gas utilities. 397 And I guess the only point there is to make -- well, there's two points really, just looking historically. One is that at the point in time of a regulatory change of this issue, it was not thought necessary to eliminate affiliate relationships, and indeed the requirement of prior approval was dropped and replaced with a more comprehensive code that set out the terms and conditions on which -- which should obtain when assessing affiliate relations. 398 The two relevant provisions of the code, at least from our perspective, I've reproduced at pages 35 and 36 of the compendium. Just focusing on the purpose, I want to draw your attention and rely on page 35, under 1.1, Purpose of This Code, the passage: 399 "The principal objective of the code," this is in the middle of the introduction, "The principal objective of the code is to enhance a competitive market while saving ratepayers harmless from the actions of gas distributors, transmitters, and storage companies with respect to dealings with their affiliates." 400 And we're not dealing here so much with competitive markets, in my submission, but with saving ratepayers harmless. 401 And then it goes on to have three standards or -- three objectives or standards that the code is directed to, and the first, (A), is the one that's most relevant in this case. That's to "minimize the potential for a utility to cross-subsidize competitive or non-monopoly activities." 402 So for our purposes, the relevant purpose of regulating affiliate relations is the prevention of cross-subsidy between the utility and its affiliates, and the reason that this is of concern, of course, is because ratepayers pay in their rates for all the costs of operating a utility service. And if a cost associated with an affiliate service is higher than it would be if provided by an independent third party or by the utility itself, then the ratepayer should not have to pay that higher cost. 403 Again, for our purposes, the relative operative provision of the code is section 2.3.3, and that I've reproduced at page 36 of the compendium, and of course 2.3.3 provides that: 404 "Where a fair market value is not available for any product, resource or service, a utility charge no less than a cost-based price, and shall pay no more than a cost-based price. A cost-based price shall reflect the costs of producing the service or product, including a return on invested capital. The return component shall be the higher of the utility's approved rate of return or the bank prime rate." 405 I'll say that is the relevant provision, I'll come back to this later, but I say, with respect, that that is the relevant provision because section 2.3.2 and 2.3.1 are not applicable. And, in essence, the reason they are not applicable, in particular 2.3.2 I'm focusing on, is because they require there to be a purchase of a service, and it's Union's evidence and Union's position in this case that Union is not purchasing "a service" in any normally accepted meaning of the word. It is really purchasing pieces of services from an integrated organizational structure. And so the reason this is relevant is because there are no market comparables for the pieces of services that Union is purchasing. 406 So Union relies on the evidence at D.1, tab 14, and all the interrogatory responses dealing with this, to support the proposition that the cost it is paying to affiliates for affiliate-supplied services is a cost-based price. And further, not only is it a cost-based price, but it is a cost-based price which is less than Union's stand-alone cost. So what Union is paying for affiliate services, therefore, we say is reducing O&M by about $8 million from what it would otherwise be. And its affiliate transactions as a whole, including the outbound services, are contributing to a reduction of O&M by over $10 million in total. 407 I would also say by way of background that Union and its ratepayers have had a -- both a responsible and a positive experience with affiliate relationships in the past. Union has sought Board approval for very significant affiliate transactions on a number of occasions and had them approved. Each of these transactions, whether they were -- whether they required prior approval or not, under the applicable rules and guidelines at the time, delivered concrete benefits to ratepayers in the form of reduced costs. 408 For example, the shared services approval for the sharing of services between Union and Centra, under common Westcoast ownership was approved in EBRO 486/489, and it delivered ratepayer benefits of some $13.5 million. Approval for the merger of Union and Centra was also sought and obtained from this Board to complete, in effect, complete the process that had begun by shared services, and that was also approved and also resulted in reduced costs to ratepayers in some 2.1 million per year, and that was in the EBO 195 decision. And then even more recently, the divestiture of Union's ancillary businesses resulted in -- which was approved by the Board in EBO 177-17, that reduce a further ratepayer benefit of $12 million. 409 So Union's experience with these types of transactions in the past has been that they have contributed to concrete -- to very concrete ratepayer benefits. 410 Over the course of time, of course, the rules and the context have changed, but Union is approaching this package of affiliate transactions in the same forthright manner as it has in the past and, as it has in the past, the affiliate relations proposed more than hold ratepayers harmless. They, in fact, deliver ratepayer benefits to, as I've said, the tune of about $10.1 million by increasing efficiencies through economies of scale and by reducing cost. 411 Now, as Mr. Birmingham explained early in his cross-examination, I think, to Mr. Warren, Duke Energy employs a shared services model. Duke is the owner -- I think it's important to realize that Duke is the owner, in addition to Union, of any B-regulated assets in Canada, and FERC-regulated pipelines, and also state-regulated utilities in the United States. And Duke, Mr. Birmingham explained, has adopted the same approach to its new Canadian acquisitions as it has already done with its regulated assets in the U.S. And the manner in which it has done so, we submit, meets all of the requirements of both the Ontario Energy Board Act and the code, and also meets the requirements included in the additional gloss on the formal requirements that were articulated in other recent cases by the Board. By that I mean the proof of ratepayer benefit. So we not only hold ratepayers harmless, but we have demonstrated ratepayer benefit. 412 The detailed evidence on all of the background of the affiliate relations and the analysis that was done is at Exhibit D.1, tab 14. The Duke corporate structure, you'll find at Exhibit A, tab 7, and the oral evidence was heard over three days, days 11, 12, and 13, on October 21, 23, and 24 respectively. 413 We submit that this record, including the written interrogatories, the transcript undertakings, the in-camera proceedings, represents a significant record of full and frank disclosure of all material facts and circumstances that has been presented by the company in an open and forthright manner. 414 Union remains a separate legal business unit. It's a company incorporated under the laws of Ontario. It has its own board of directors which include Union's president. Forty percent of the directors are independent from Union, 40 percent, and from any affiliate, and that, in fact, exceeds the conditions set out in 2.1.3 of the code which only requires that one-third be independent. And you'll find a listing of Union's directors and officers at Exhibit A, tab 7, schedule 3. 415 Now, Union and Duke services fall into two categories. There's outbound services and inbound services. Just very briefly on the outbound shared services, the forecast recovery there is roughly $3 million for 2004, with an associated ratepayer benefit of about $2.3 million. Outbound shared services are, in fact, smaller than they used to be and that is simply because a number of the affiliates to which Union used to provide services have been divested, and that includes Empire State Pipeline, Enlogix, and Union Energy. 416 It's really the inbound shared services that generate the interest in this case, I think, and they are forecast to be $28.7 million and that is obviously an increase from what they were under Westcoast. But Union's position and evidence is that this involves a net $7.8 million benefit, in other words, that this cost of $28.7 million is $7.8 million lower than the cost to Union of providing the same services for itself and that, therefore, results in the ratepayer benefit in that same amount. 417 The principal benefits of the outbound shared services are that Union is able to maximize usage of existing staff and assets with little or no requirement to increase the staffing level to meet the service requirements of the affiliate. So increasing the utilization of staff reduces the costs related to necessary but underutilized capacity that may occur at moderately low levels of activity. And so by using cost-based pricing, Union is able to fully recover the direct costs of existing staff plus the cost of any additional support required. 418 And then turning to inbound, the principal benefit of inbound shared services is effectively the same only at a larger corporate level, and it is the ability to integrate activities and avoid duplication of effort within separate business units. This, again, increases the utilization of staff and assets while sharing fixed costings across more business units, and that, of course, then produces lower overall costs and economies of scale. And as I've said, for 2004, the ratepayer benefit associated with this is 7.8 million on the updated evidence. 419 Now, the reason I said earlier that it is section 2.3.3 that applies, that is, the cost-based approach, rather than 2.3.2, using fair market value, is because this is not the purchase of an entire free-standing service; that one could or even would be prepared to acquire from arm's length third party. In most cases, only a portion of an activity is being completed by the affiliate. Also, some aspects such as management oversight could and would not be tendered to a third party for all kinds of reasons; security, confidentiality, et cetera. 420 We are dealing, in my submission, with partial low-volume and, in many cases, unrelated activities and pieces of services, pieces of activities, for which there is no counterpart in the open market. And you'll find a discussion of that in a number of places, but I'll cite J.23.8, Volume 11, paragraphs 1028 to 1029 and 1035, and Volume 13 at paragraphs 673 to 675. 421 Now, there is evidence on the fact that consideration was also given to the possibility of trying to benchmark some of these services so that there would be some, albeit not free-market existing alternative, but some kind of construct that would be a proxy for a free-market alternative. But this would necessarily have involved comparing the proposed charge with industry-wide charges for similar services, if they were available. And there were several reasons why this approach was rejected, and they're all detailed at tab 14 of Exhibit D.1. 422 But the main one, I just want to emphasize that the main one was that it would be extremely difficult to determine and even more difficult to prove the validity of any comparator given the partial or what I'm calling an interstitial nature of the services that are being provided here. In other words, the type and level of service being shared would inevitably be different from anything that you would ever see occurring in any other business because it's unique to the operations of Duke and Union. And a lot of what the inbound shared services is made up of is, in effect, management services made up of unique pieces of varies operational functions and chains of command. 423 So to give an example, Union no longer has its own general counsel, but the most senior lawyer in the Duke organization performs this role for all Duke companies, including Union Gas. Now, obviously, general counsel of Duke doesn't spend all of his or her time on Union matters, but corporate and management accountability needs to be there and there needs to be a senior legal officer within a large and sophisticated organization like this one. 424 So say, for the sake of argument, that Union benefits to the extent of 10 percent of the cost of the general counsel's office, it's simply not possible to acquire a service of that kind, 10 percent of a knowledgable general counsel's time, from a third party, nor, as I said before, would you want to. You need somebody who is au courant with everything that's happening. 425 So the benefit to Union and its ratepayers is therefore reduced cost resulting from the ability to rely upon a central general counsel's office for senior management oversight and support of all legal affairs within the organization, and not having to supply a hundred percent of that oversight and support and thus incur a hundred percent of the cost of that oversight and support of doing it alone. I should add that about 10.5 million of the inbound charges of that 28.7 number that we mentioned earlier, about 10.7 million of that relate to services provided to Duke by third parties, so that's the other piece. A big chunk of it is kind of bits and pieces of management oversight. The other big piece is services provided by third parties. You'll find that at J.1.114. 426 With respect to these charges, Union is really getting the benefit of economies of scale. It's just that simple. Economies of scale and purchasing power or, in effect, as was described in the evidence, a group discount. That's at Volume 11, paragraphs 1143 to 1144. And the evidence is that Union would simply not be able to achieve these kinds of cost reductions, that is, it wouldn't get those group discounts, if it were purchasing those services on its own. That is at Volume 11, paragraphs 1153 and 1154. 427 Now, coming, then, to the methodology, Union's approach to the cost-based price charged by Duke, as required by section 2.3.3, has four features, and I'll just outline them briefly. They're in the evidence at tab 14, starting at around page 38. It's a cost-based price approach that relies upon fully-loaded costs, and in this context, fully-loaded costs means that all of the service provider's cost associated with delivering a particular service, including Union's improved return on invested capital, are identified for transfer-pricing purposes. 428 The second feature was that the approach relies upon the embedded or accounting costs, which is the same approach as that used for rate-making purposes. 429 Third is that it relies upon direct assignment and cost-driver attributions. And fourth, the approach determines Union's avoided cost which is based on historical and forecast cost of retaining the services on a stand-alone or in-house basis. And that produces a point-in-time determination of the utilities' cost of a service which is then used to assess the reasonableness of inbound charges. 430 So I've reproduced at page 37 of the compendium Exhibit K from Exhibit D.1, tab 14, and this is the analysis of the storage service cost, stand-alone service cost, Union's internal cost, Union's avoided costs, the inbound service charge and the cost reduction, and that's where you see in the lower right-hand corner the $7.8 million ratepayer benefit through cost reduction. 431 Just walking through these briefly to understand what happens. The methodology was to start with Union's historic 2002 budgeted costs for activities that would become shared services, and that's column A. 432 And then the next step was to determine what Union's stand-alone 2004 cost would be if it had not adopted the shared services model. And that was done by adjusting the 2002 budget for inflation and for any specific changes in cost or level of activity that was known to have taken place. The only specific adjustment, in fact, was for insurance coverage. So that's column B. 433 And then the next step was to determine Union's internal 2004 costs, that is, the 2004 costs of all activities in 2004 that would continue to be carried out and completed by Union, because of course not all services are going to shared services, only some. So -- and appendix M, I won't take you to it, but appendix M in D.1, tab 14, show how those were derived, but the result is shown under column C. 434 And then the next step is the calculation of Union's avoided cost by simply subtracting C, because that's the remaining cost, from B, which is the stand-alone service cost, and that then gives -- what gives you column D, which is the avoided cost. 435 And then step 5 is the determination of the in-bound service charges which are based on the provider's fully loaded cost, and it's done in much the same way, and you can see that at appendix I. The details in appendix I, at the next page in the compendium, it's several pages because it goes through each of the services, so just for illustrative purposes I've taken the last page which gives the totals, and that process is described in the prefiled evidence in some detail at pages 52 to 56. 436 But what we've got here, again just to describe the process is, under column A, we have the total pool of costs being incurred by the affiliates providing the services, so it's 849 million, and then under column B, you get a portion of the total budget that relates to shared services throughout the Duke corporate group. So that's the portion of the total budget that's going to actually be allocated. So not a hundred percent of the total cost of Duke is being allocated, only a subset of that. And then you have column C, which is the method of allocation, and since most of these services are in the nature of management and oversight, the percentage of time is almost always the allocation method. And so based on the percentage of time, you then go to column D which is the overall percentage of the allocable budget being assigned to Union, and it varies from service to service, but the total is 3.69 million, or I should say the average. 437 And then having established the allocation percentage based on percentage of time, column E is the budget that is actually allocated to Union. That's simply column B times column D, so it's the total allocated -- allocable budget times the allocation percentage generates the 24 million. And then under column F, since the budget allocated to Union includes only direct costs, there has to be a further adjustment for overhead, such as the cost of assets being employed, office space, computers, that kind of thing. And the average -- again, it varies from service to service, but the overall average is roughly 20 percent. 438 So then you take 20 percent of the budget being allocated, so that's E times F, and that generates the overhead charge, which is in column G, and then you add E into G to get the total and that's what gives you the 29 million of cost. 439 So the total charge to Union which is contained in column H of appendix I is therefore the sum of the budget allocated to Union and the overhead charge to Union, and I want to note that that 29.2 million is -- there's 3.4 percent of the total service provider's budgets, so total Duke budgets, 3.4 percent, and it represents less than .5 percent of Duke's 2002 consolidated operating and maintenance expense. 440 So those, just to give you a sense of the magnitude, are a bit of a reality check, and I'll come to a couple of other in a moment. So not a disproportionate or, indeed, inordinate percentage of the parent budgets. 441 Now, we then have two -- so having gone through this exercise, we then have two reasonableness checks, if you will, well, at least two formal ones and then a couple of others I'll make reference to. 442 The first is to compare -- the first that Union did by way of reasonableness check is to compare the provider's overhead charge to that which Union would expect to charge for similar services. So in this case, Union is not a stranger to this arrangement. It does this itself. Union itself charges affiliate charges to affiliates and those are the outbound services, and it does its -- it does it on a cost-based basis, and so Union, of course, has experience with this and therefore knows how to go about this and so it analyzes these services and the overhead charges and says, Well, if we were doing this, what would we charge, as a check against whether what they're being charged by Duke is reasonable. 443 At Exhibit D.1, tab 14, appendix J, it has that analysis. Again, I won't take you to it, but line 69 of column F in appendix J shows that the provider's overhead on the inbound shared services is actually half a million dollars lower than what Union would charge to an affiliate party if it was -- if the same service was an outbound service from Union. That gives a sense that what Union is being charged by Duke at least for the overhead charge portion is not out of line because Union is saying, You know, if we were doing this we'd actually be charging a little more. So they're getting a deal on that basis. 444 And then the second and perhaps fundamental, perhaps almost self-evident, but the most fundamental reasonableness check is to compare the provider's inbound charge to Union's avoided cost, and of course the expectation is that the provider's cost will be lower than the stand-alone cost and that's, of course, consistent with the concept that shared services would only occur if there are benefits in the form of cost savings or improved quality of service. And that, of course, is the case here to the tune of $7.8 million on the inbound portion. 445 Now, it's also worthy to note that looking at Union compared to the overall Duke entity at this, Mr. Birmingham testified that by any measure, whether you look at revenue, at assets, or something like payroll, just to choose those, Union represents about 7 percent of the Duke group. So you take Duke as a whole, and if you look at revenue, if you look at their assets, if you look at their payroll, all of those produce Union at about 7 percent of the Duke group. But Union is only being allocated about 3 percent of the allocable consolidated costs, and that evidence is at volume 11, paragraphs 1201 and 1202. 446 So that, again, gives you a sense of whether something is badly awry here or not, and we say that it's just further evidence that there's nothing badly awry here, it's further evidence of the reasonableness of what's being done. Union represents 7 percent of the Duke group. It's only being allocated 3 percent of the allocable costs. 447 And with respect to the Duke costs themselves, there were questions about, you know, the reliance on Duke's financial systems and controllers office. I mean, it's certainly true that Union did rely upon that. But I think it's an important point to make that these costs are taken from Duke's financial systems which are used to support the entire company. They're used for their external financial report, for their audited financial statements, for reporting to the Securities and Exchange Commission; for financial reporting to FERC, to state regulators in both North and South Carolina, and for that matter, to the National Energy Board. So it's the same system that's used to allocate corporate center charges, in effect, to all Duke's other regulated entities in the U.S. and Canada. 448 And that evidence you'll find, by the way, at Volume 11, paragraph 1204. 449 So let me conclude on this issue of the reliability of the data, with a quote from the testimony of Mr. Birmingham at Volume 13, paragraph 689 to 693, and that I have reproduced at pages 39 and 40. And this is yet a further reality check against the integrity and reliability of these financial systems, because the question arose in cross-examination by CME, an issue arose as to the involvement of tax authorities in cross-border affiliate relationships and so this subject was returned to on re-examination. I asked Mr. Birmingham to explain what role the tax authorities play with relation to the affiliate transactions and what the risk is if the affiliate doesn't charge at its real cost? And the answer is: 450 "The tax authorities require an appropriate methodology to be used for the pricing between affiliates. The reason for that is, I think you can probably come up with yourself, to the extent that an organization wanted to charge one of their affiliates a particular price, they could price that in a way that would give the most taxable income in the jurisdiction that had the lowest tax rates. So one of the things that the tax authorities want to make sure is that, in fact the fully-loaded cost for the service provider is being charged for the service to make sure that there isn't any gaming, if you will, between tax jurisdictions. 451 "The methodology that we're using with respect to the services that we are receiving from our affiliates and the methodology that we're using to provide services to our affiliates meet with the approval of the tax authorities and agree with their methodology." 452 And then I say: "And what's the risk if that -- if that methodology isn't followed?" And the answer is, over the next page: 453 "Well, clearly the risk is that the deductions for these costs would be disallowed and would effectively result in the double taxation of these transactions in each country." 454 So, again, it goes to the point that you can't just pass off Duke's financial systems as being irrelevant or suspect in this context. They are the financial systems that are used for securities and exchange reporting, for regulatory reporting, and for tax purposes, and of course, it goes without saying that there would be significant consequences for gaming of those processes under any of those jurisdictions, SEC, regulatory, or tax. 455 So this, I say with respect, gives additional comfort to the Board around the accuracy and reliability of the fully loaded costs. The most important point there, of course, is in a sense, it almost doesn't matter what Duke's fully loaded costs are as long as one can say with confidence that the ratepayers are better off under the shared-services arrangement than they would be on a stand-alone basis. 456 In conclusion, then, on affiliates, let me just say that these are higher charges than under Westcoast, there's no doubt about that, but they are of a similar ilk. They consist of about a little over one-third buying power on IT licences and some other third-party supplier transactions. That's the volume discount point, in effect. And really the rest is centralized operational management services and oversight. 457 These are not services, I emphasize, that Union would or even could purchase from third parties, and the only reasonable alternative to what's proposed is what Union was doing before, which was providing these services largely to itself. And the evidence is that the cost of providing those services itself would be, on the inbound stuff, 7.8 million more than Union is paying in the shared-services charges to Duke. 458 So there is a demonstrable benefit to the affiliate inbound transactions, as there is with the outbound transactions, because there's a net benefit there of some 2.3 out of $3 million of charges. 459 So net affiliate transactions lower costs by 10.1 million, and in my submission, should be approved on the basis of compliance with 2.3.3 of the Affiliate Code. 460 Turning briefly to capital structure, and then load balancing. 461 CAPITALIZATION: 462 MR. PENNY: On the capitalization front, Union's evidence on capitalization is at D.1, tab 6. The forecast 2004 capitalization is 42.9 million, and you find that at D.3, tab 3, schedule 2, page 1 updated. And this is comprised of indirect capitalization of 38.4 million and direct capitalization of 4.4 million. Indirect capitalization is overhead costs incurred by groups that support both capital and operating work, and is therefore an apportionment of the cost of such groups, and there's a more detailed description of that at J.7.25. Direct capitalization are costs that are incurred specifically for specific capital projects. 463 So what's the issue? Well, Union capitalizes a portion of its gross O&M expense to reflect the fact that many of the corporate support functions support employees that work on capital projects, for example, a portion of the goods purchased by the procurement group is for capital projects, so a proportion of the cost of having the procurement group is recorded as being on account of capital. And this process of capitalizing expenses is a standard utility practice. Union's capitalization method is consistent with the Board's uniform system of accounts and consistent with GAAP. And frankly, the method is unchanged since EBRO 493/494, and that was a proceeding where Union brought forward a study by Arthur Andersen that established a cost-driver approach to capitalizing costs and Union has used that approach ever since, and is still using it. The only change is that in preparing for this application, Union conducted a review of the cost drivers and updated them. So same methodology, just an updating of the cost drivers. And they updated them to reflect the forecast 2004 activity levels and organizational structure. 464 The reason that they hadn't done that review since 499 is simply that, under PBR, it wasn't necessary, because through the PBR term, the drivers remained constant as reflected in the 1999 rates. So, Union's level of capitalization has been in the range of 49 to 52 million between '92 to 2003, so that's the PBR period, basically, and the capitalization declines in 2004 to 42.9 million, that's a drop of roughly 16 percent, are primarily because capital activity has declined by about 18 percent compared with the 1999 to 2003 period. And you'll find that at Exhibit N.15.5. 465 Now, there's been a suggestion, at least in cross-examination, that Union should maintain the cost drivers as they were in 2002, the last year for which actual results are available. And while this would produce a higher level of capitalization at a level similar to the prior years, so back up in the 49 to 52 million range, it ignores the fact that the 2004 drivers reflect what's happening in 2004 and those are principally the significant reorganization to align Union with DEGT and Duke Energy organizations and, I think even more significantly, the significantly lower level of capital spending in 2004 than in prior years. And, again, that's N.15.5, and you'll also find evidence on this at Volume 16, paragraph 70. 466 So there's no evidence on the record to suggest that the Arthur Andersen method that was accepted in 493/494 is no longer appropriate, and indeed, in my submission, the evidence indicates that the level of capitalization should be coming down in response to a reduced capital spending program. And we therefore submit that Union's capital capital -- sorry, forecast capitalization is appropriate and should be approved. 467 CAPITAL STRUCTURE AND COST OF CAPITAL: 468 MR. PENNY: I want to deal with capital structure briefly. The capital structure requested is in Exhibit E.3, tab 1, schedule 1 updated, and it's comprised of long-term debt. Let me do it the other way around, it's the common equity, 35 percent; preferred shares 3.58 percent; long-term debt, 65.69 percent; and then what's always the plugged number, the short-term debt, that in -- forecast for 2004 is a negative 4.28 percent, which is -- reflects a positive cash position. 469 And just to break those out a little bit, the equity -- of course, the approved equity level is 35 percent, and it's been like that for a number of years. Union does have some preferred shares outstanding. Their cost is fixed and they're also not new. Union's long-term debt debentures, there's no new issue forecast for the test year, but there is a redemption of 125 million forecast in December of 2004, and you'll find that at Exhibit E.3, tab 1, schedule 2, line 10 updated, in August. And then finally, there's this average positive cash position of about 131 million for 2004. 470 Now, the average cash position of 131 million in the capital structure is the amount -- is really the amount required to balance to total rate base. As I said, the short-term debt is the plugged number. But let me explain the context in which that occurs. 471 In 2004, Union's credit facility provides capacity to borrow 365 million of which 54 percent or 197 million is -- has to be used in December. So the average position for the year is cash of 68 million, and all this is shown in N.16.8, the capacity available under the credit facility is required to manage the impact of variations in the forecast, and those are most notably the impact of warmer weather, which results in higher inventory carrying costs and reduced cash flow, and the potential for increases in gas costs. 472 So the proposed capital structure on the evidence, including the long-term debt and cash position, provides Union with sufficient financing flexibility in 2004 to manage the impact of warm weather and of increasing gas prices. 473 So -- but then coming back to this cash position. Some questions were raised during the hearing about this net average cash position, and the suggestion seemed to be that an average cash position is somehow inappropriate and implies that the level of debt issued by Union in 2002 was too large. This simply is not so, in our submission. Unfunded short-term debt or, in this case, cash position simply reflects the seasonal cash flow of the business. And you can see this in exhibit -- where Union is in a cash position during the summer and shoulder months and then draws on its lines of credit in the winter. For December of 2004, Union is forecast to have drawn on 197 million of its available bank lines of credit, leaving 168 million to draw on to deal with unforeseen circumstances. 474 And it's important to note that Union can't issue debt effectively in small amounts, so to deal with this kind of issue, in that respect, really, issuance of debt is really like Dawn-Trafalgar expansions. You have to make due with what you've got until there's a critical mass, and so it happens in lumps, and you wait until your capital needs are such that you have more need for long-term debt financing and then you go out and get it and you get -- if you can get it at good rates, then you perhaps get a little more than you might need in the short term. But it's not indicative of the fact that the company is issued too much long-term debt. 475 Ms. Elliott spoke to that, and I'll find that reference in a moment, in re-examination where it was indicated that if the long-term debt had not been issued in the amount that it had in 2002, that Union would be short on the short-term debt in 2004. 476 It's also important to note that a significant factor in the movement to a net cash position has been a change in the regulatory treatment of gas costs, and Ms. Elliott spoke at volume 16, paragraph 418, about the fact that Union, in 2002, had been carrying significant deferral account balances. This, you'll recall, was the accumulation of deferred charges for a couple of years and before prospective recovery was explicitly approved. And at paragraph 459 of volume 16, Ms. Elliott also noted that: 477 "It wasn't until 2003 that Union was clearly permitted to collect deferred receivables on a prospective basis." 478 So in 2003, that's -- in 2003, that's when Union applied for and received approval to recover balances prospectively, and so -- and it wasn't until EB-2003-0056 that the issue of prospective recovery was squarely addressed by the intervenors and the Board. It's only been since then that prospective recovery has been explicitly approved. 479 Now, the point is that that development and its impact on Union's short-term borrowings couldn't have been anticipated in 2002 when Union was carrying a high level of deferred receivables and was issuing long-term debt. I guess the point is that at the time Union was issuing the long-term debt, it had this significant deferral account issue and that was one of the factors that caused Union to issue the debt. The fact that that is now forecast, with the benefit of hindsight, now forecast not to be such a significant problem because the Board allows prospective recovery, couldn't have been foreseen. 480 So in my submission, there's no evidence that Union was, in any way, imprudent in raising its 2002 debt. Union had an opportunity to raise debt capital at favourable rates and they took it. It's as simple as that. Union's capital structure, therefore, in my submission, should be approved. 481 Now, on the question of cost of capital, I simply wanted to say -- point out the evidence references for the various provisions. Long-term debt, the cost of long-term debt is the actual debt issues that Union will have outstanding in 2004. Those equate to a blended interest rate of 8.45 percent. You'll find those references at E.3, tab 1, schedule 2, line 16 updated, August 2003. 482 The pref shares, that's the cost of existing pref shares that Union will have outstanding in 2004. That equates to a cost rate of 5.44 percent. You'll find that at E.3, tab 1, schedule 3, line 14, updated August. 483 And then there's the unfunded short-term debt, that Union is requesting a short-term debt rate of 4.15 percent. That's at E.3, tab 1, schedule 5, updated August 2003. This rate has been used to calculate the contribution of the net cash position to the capital structure and is the requested short-term debt rate to be applied to the outstanding monthly balances of deferral accounts in 2004. So we've just chosen the 4.15 percent for both the -- for both Union's cash position and the accumulation of deferral account debits or balances for 2004. 484 And then return on equity, well, that's the RP-2002-0158 case. In this case, Union is -- is simply requesting the Board to approve an allowed rate of return based on the Board's findings in the generic ROE proceeding. The cost of service as currently filed reflects a common equity return of 124 million based on the requested ROE of 11.625 percent in the 0158 case. And that's simply derived by taking the 3.059 billion rate base, times 35 percent common equity, times the requested ROE of 11.625 percent. And as you know, Union is proposing that the Board use the most current consensus forecast of long-Canadas available at the time the decision is issued for the purposes of establishing ROE. So the 124 million that I mentioned a moment ago would change based on three potential factors: First, any change to the benchmark return approved from the ROE hearing; second, based on any change to the adjustment formula in the ROE hearing; and then finally, the impact of the most recent consensus forecast of long-Canada bonds at the time the Board issues its decision. 485 So that's my brief summary of the capital structure issues, and I'm now going to turn to the load balancing question. 486 LOAD BALANCING: 487 MR. PENNY: Deregulation of natural gas commodity almost 20 years ago was, I think it's fair to say, a dramatic and innovative step that put Ontario ahead of most jurisdictions in North America. But it had many implications and led to a certain number of clusters or barnacles of residual difficulties, problems, anomalies, which took time to resolve as better and more efficient methods were developed over time through experience and experimentation to deal with this feature of the industry. And an example is the buy/sell arrangement. That was a way to permit marketer sales to small-volume customers in Ontario, and it got round what was then a huge legislative obstacle that no one could sell gas or distribution service in Ontario without an order from the Board approving the just and reasonable rate. And so the buy/sell arrangement was an expedient means of dealing with that problem, but it was, frankly, a cumbersome business technique from the business side, and also permitted effectively no regulatory oversight of that aspect of the business. But direct purchase operated under that model for many years quite successfully. 488 But the process, coming back to my barnacle analogy, I mean, that was a somewhat cumbersome approach. It wasn't true deregulation. And that process was rationalized by legislative amendment in 1998, and then, of course, legislation was amended to permit sales to end users, but imposed a licensing regime to ensure appropriate consumer protection. 489 Upstream transportation, that was another anomaly, particularly because there were these old long-term TCPL contracts that were held by many utilities that dated back to the days when there was no or limited competitive alternatives. And also, you'll recall that incremental direct purchase used to be served by assignments of TCPL capacity, and when TCPL capacity was cheap, this was an advantage to direct purchase and a disadvantage effectively to sales-service customers because it left, increasingly, proportions of higher cost alternatives in the system sales portfolio. And there, the advent of the vertical slice was one response to this situation. So that was another evolving response to the changes brought by deregulation that were gradually being worked out over time. 490 Load balancing and flexibility are similarly both byproducts and relics of the transition from regulated to deregulated commodity sales and service and they result from the move to direct purchase. 491 Flexibility costs were those costs associated with Union having a diversified supply portfolio, and so flexibility costs were, in effect, costs that were associated with any variance between the landed cost of TCPL and all other sources of supply. 492 Load balancing, as you've heard in this case, is the management of planned and unplanned seasonal variability in supply and demand, so load balancing costs, as we're using that term in this context, are the costs associated with unplanned variability and are determined, or have been determined by multiplying the volumes of spot purchased in winter to meet unplanned demand times the summer/winter price differential, and that premium was then recovered from all customers. But I'll get to that in a moment. 493 Both flexibility and load balancing costs for some years have been recovered in delivery rates on a rate-class basis from all customers, both direct purchase and sales service. And for flexibility, this was on the theory that all customers benefited from a diversified portfolio. And for load balancing, the theory was that incremental supplies purchased in the winter to meet actual winter demand were purchases that benefited and were consumed by all customers, again both direct purchase and sales service. 494 But I guess the truth of the matter is that these were blunt instruments because, while they achieved a kind of direction equity in the allocation of costs, they were not tailored or even capable of distinguishing between direct purchase and sales service on the one hand, because delivery charges are recovered from everyone, and also not capable of distinguishing between direct-purchase customers inter se because the costs were recovered on a rate class basis. And that is significant because the delivery-rate approach was not capable of reflecting individual customer requirements and consumption on an actual basis. 495 And I'll talk about this more in a minute. But you would have situations where a customer, a particular individual customer would balance to forecast but then be levied with imbalanced charges, what were effectively load-balancing charges, on a rate-class basis. 496 Another aspect of the blunt instrument point on the historic treatment of load balancing and flexibility costs is that they were deferred costs, and that inevitably led to out-of-period adjustments. And when the numbers are not huge, the out-of-period adjustments are not as painful, but when the numbers are large, of course, they create more controversy. Flexibility and load-balancing costs were recorded in the other purchase gas costs account under the old structure, and when prices spiked in 2000 and 2001, this led, you'll recall, to large deferral balances on account of flexibility and load balancing. You may recall from the May QRAM application that it was about 80 percent of the $120 deferred charge to residential customers was made up of load balancing and flexibility costs that had to be recovered in 2003. 497 So with respect to the old system, it was directionally accurate, or was moving in the right direction but was not fine tuned, or was not a fine-tuned instrument. 498 Now, with respect to the flexibility cost directive, as was discussed in the May 1 QRAM in 0056, the advent of the vertical slice and the expiry over time of the historically allocated upstream capacity to direct purchasers has led to the result that direct purchasers, when they go to direct purchase now, they take on the responsibility for costs of Union's diversified portfolio, so they are, in that sense, no longer causing the cost of the remaining portfolio used for sales-service customers to increase. They're taking their proportionate share with them when they go, and for that reason it's no longer necessary or appropriate to recover those costs from direct-purchase customers. 499 So as proposed in the May QRAM and in this case, the flexibility side of the equation is being dealt with on the basis that what used to be called flexibility costs are now only being incurred on behalf of sales-service customers because only sales service customers are consuming and getting the benefit of the diversified portfolio. These direct-purchase customers, when they go, they take it with them and impose no disproportion of costs on the system. 500 So, in effect, what this means on the flexibility side is there really are no more flexibility costs. All supply costs merely accumulate in the southern PGVA for disposition to sales-service customers. And all that evidence you can find at D.1, tab 1, on deferral accounts, and H.1, tab 4, page 3 and supplemental evidence. 501 So that leaves load balancing costs which is the subject of Exhibit H.1, tab 4, and was the subject of oral testimony of Ms. VanDerPaelt, Mr. Isherwood, and Mr. Kitchen on days 17 and 18. 502 Now, as I've said, the prior system of accumulating the cost of season balancing and recovering that in delivery rates on a rate-class basis based on March 31 imbalances, that was directionally appropriate but was rough justice, if you will, because it did not distinguish between DP and sales service on any precise basis as to who was really causing the costs, nor did it distinguish between customers, those in balance or out of balance, as to who was causing those costs. 503 So there was a recognition when this means of recovering load-balancing costs was introduced, that is, the old system, when it was introduced, there was a recognition that it was adequate but not a full solution and that's why, in past Board decisions, we've had a continuing interest in this issue and a desire on the part of the board and on the part of the direct-purchase community to look for ways to come up with something better. We see that in particular in the 493/494-06 decision and in the 499 decision, which are quoted at page 4 of the evidence. 504 In the compendium, at page 41 and 42, we've excerpted those pages from the evidence. You'll see that the Board, in the 493/494-06 case, in discussing the load-balancing issue, said: 505 "The Board considered other possible allocation methods such as direct allocation and direct charging based on cost causality by type of service which is consistent with Union's current practice in charging system-supply customers, a gas supply administration charge. At this time the Board concluded that the administrative problems that may be encountered in implementing such different proposals in a timely manner may outweigh any advantages such proposals may have." 506 And then they go on to say that: 507 "A possible model might include the following features: Preparation of a monthly supply/demand inventory forecast for each type of service, calculation of monthly differences in the supply/demand balance, comparison of monthly actual results to forecast amounts to isolate variances by type of service at the end of the forecast period; and a true-up mechanism." 508 And over the page, there's an additional comment from the Board in the 499 case, again indicating that: 509 "Although there are good reasons to continue the current methodology, the Board's approval is a temporary measure. The Board expects that a new load-balancing service will be brought forward as soon as the company has completed its work on the unbundling of its services. The company is directed to report to the Board as soon as it is in a position to present a new load-balancing proposal." 510 So, I mean, it's Union's submission that the proposal in this case to deal with the load-balancing costs is entirely responsive to the features that the Board identified in 493/494-06. It involves the preparation of monthly supply/demand inventory forecasts for each customer, in fact; it involves the calculation of monthly differences in the supply-demand balance; it will involve a comparison of monthly actuals to forecast on a customer-by-customer basis; and it involves a true-up mechanism. 511 Of course, that true-up mechanism is really at three points, although it -- it's really two that are associated with the proposal. The two associated with the proposal are a true-up at February 28th to forecast consumption; and a true-up to September 30 to forecast inventory levels; and the third, which is already in play and will stay the same, is that there is a requirement to balance to plus or minus 4 percent at the contract year-end. 512 Under the proposal, Union will continue to provide a basic load-balancing service for both direct purchase and sales service customers, and that's based on planned consumption. If the weather is normal and the consumption is as planned, Union will manage the seasonal variation for all customers just as part of the basic load-balancing service and that will be simply part of what you get for paying basic delivery rates. And Union is able to do that by utilizing existing assets. It doesn't need to go and incur any costs to do that. It uses primarily storage space and deliverability, balancing gas and inventory, and plant gas purchases using upstream transportation capacity. 513 This is, as I've said, part of existing service today and will continue as before. 514 How it works today is illustrated in the compendium by -- at page 43. This is part of Exhibit M.17.1. And this assumes a customer DCQ of 500 a day. What it shows is that Union knows that in a normal winter and on a planned basis, that customers will produce X percent more from November to the end of March, and X percent less from April to the end of October than 500 -- 500 units a day. And on a planned basis, 500 a day will net to roughly a zero imbalance on this diagram on October 31 which is, for most people, the contract year-end. 515 So Union -- that's the top diagram. And the bottom diagram illustrates the banked gas account that Union assumes. Again, Union knows what the banked gas account will look like and it will plan in its gas-supply plan to manage the forecast on that basis. 516 It's the variability that creates the issue, and so the proposal is done -- designed to address the allocation of responsibility and cost for that portion of consumption that deviates from the forecast pattern. 517 Now, you'll recall from the evidence that Union established a number of principles against which the load-balancing proposal was to be measured, and I want to focus in particular on the two -- on two which are, in my submission, in effect, the embodiment of the substantive and practical features of all of them, and those two are that Union -- first, that Union is not a gas supplier for direct-purchase customers; and second, that supply imbalances should be dealt with on a customer-specific, not a rate-class basis. And there's an explanation of these at pages 7 and 8 of the evidence, H.1, tab 4. 518 On the first, Union is not the supplier of gas for the direct-purchase customer, and the principle was Union should not make gas purchase decisions that impact direct-purchase customers' supply costs. And this, Union said, became very evident through customer feedback received when after-the-fact rate adjustments were implemented in the fall of 2002, and customers were questioning why Union continued to purchase gas supplies on their behalf when they clearly elected a marketer to manage that activity for them. 519 And then the second informing principle is that the desire to recognize that supply imbalances outside of the forecast should be attributable to a specific customer or contract and not to a rate class. Again, Union got feedback from customers in the fall of 2003 on retroactive rate adjustments, the ones that were approved in the 0029 case, indicating that customers had -- that a number of customers had actually taken action to ensure that their bundled-T contract was balanced, yet they were still subject to additional load-balancing costs as a result of the rate class method of disposition of those costs. 520 So we don't want Union buying gas for DP customers, and customers who are imbalanced to plan are not causing additional costs and therefore should not be providing additional load-balancing costs beyond what is embedded in rates for the basic service that Union provides. 521 Union's proposal, therefore, throughout its contract terms and conditions, is to require direct-purchase customers to purchase their own requirements when out of balance. And those who do so will incur no additional costs from Union. The only cost they will incur is whatever costs they incur to bring themselves to balance at forecast. But those who do not will then have to pay the cost of incremental supply that Union incurs on their behalf to bring them into balance. 522 Now, the way this works is it's based on two key operational periods in Union's system: March and October. In March, Union has subdivided down to two further critical control points: March 1, Union needs to ensure that there's sufficient gas in storage to meet deliverability requirements; March 31, Union has to have enough gas available to meet late season weather variances after March 31. And so to meet the March 1 control point, the new terms and conditions that are proposed will require a bundled-T customer to meet a forecast banked gas account balancing checkpoint on February 28, and so that means that they'll have to balance to forecast consumption. Ensuring that bundled-T customers are balanced to forecast by February 28th will enable Union to meet the March 1 storage deliverability requirement that the overall system imposes on it. No action is required in February if consumption is equal to or less than the forecast amount. 523 And then the other critical control point, though, is actually October 31, and if a bundled-T customer has consumed less than forecast, the new terms and conditions will require the contract customer to shed additional gas by September the 30th. By ensuring that customers don't have incremental gas and storage at the end of September, Union is then able to meet the firm injection rights of other Union customers and ensure that sufficient gas will be available to meet winter needs. And again, no action is required by anyone in September if consumption is equal to or greater than forecast. And that's because, through the changes to the bundled-T balancing obligations, customers will cover their own incremental load balancing requirements from November through February. 524 So in summary, then, under the new contract balancing provisions, customers consuming more gas than forecast will have to balance back to their forecast by the end of February by bringing in additional gas; and conversely, should customers consume less gas than forecast, they will be required to remove the excess gas from the system by the end of September. 525 These new terms and conditions combined with the March park, which I'll come to in a moment, will cover any potential consumption variances, and this will result in Union not buying spot purchases for southern bundled-T customers to cover consumption variances that differ from forecast. And it's proposed, as you know, to take effect not this winter but the winter of 2004-2005. 526 Now, the graphic representation of how this work is at pages 3 and 4 of M.17.1, and page 3 is at page 44 of the compendium. And this page, page 44 of the compendium, deals with the situation where there is unplanned higher consumption. And so the black line in the top part of the diagram is planned consumption; the red line is showing actual consumption tracking at greater than forecast, and what happens is that the customer has to balance to the black line by or on February 28. And the blue block in the top portion of the diagram, therefore, represents the amount of gas that the customer must supply to return to planned balance by February 28th. 527 Below, showing the banked gas account, the delta between the red line and the purple line is actual consumption. That's the overdraft on the banked gas account, in effect, which again must be repaid by February the 28th, so they have to come back to the purple line February 28th. 528 And then page 4 deals with the opposite situation, that's at page 45 of the compendium, which is lower than planned consumption. This is not a problem in the winter but potentially a problem in the fall because this is when customers exercise their injection rights. So if one customer has more than its forecast level of gas in storage already, it's potentially depriving others of their contractual entitlements, and so oversubscribed customers will have to shed gas and balance by September 30th. You can see in the banked gas account portion of page 45 of the compendium, that here the delta between the red actual consumption and the purple planned forecast is more gas in the account than planned, and that's okay on February 28th because of the operating constraints in the winter where more gas is being burned, but it creates a problem in the fall in advance of the winter, so it has to come to balance by October the 28th. 529 And so then what you see in the black square off the 500 DCQ is the amount that the customer had to shed to come into balance by the end of September. So that's that aspect of the proposal and the reasons for it. 530 MR. SOMMERVILLE: Mr. Penny, an overusing customer at March, if Union does have to provide gas, is that gas at a deemed price, the highest price in the previous 30 days? Is that the formula? 531 MR. PENNY: I think yes, but it's -- I know it's not the WACOG. I just want to double check on that. 532 Sorry for the ten-Guinea con there. The way this works is an imbalance in March is dealt with by the March park, which I'm going to come to. 533 MR. SOMMERVILLE: Right. 534 MR. PENNY: It's the February 28th imbalance that generates the penalty rate, if you will. And if a customer fails to balance by February 28, then Union goes out and buys the gas. What the customer pays for that gas is the highest spot price either in the month it was bought or the month following the month in which it was bought. 535 MR. SOMMERVILLE: The month following? 536 MR. PENNY: Yes. 537 MR. SOMMERVILLE: Okay, thank you. 538 MR. PENNY: And that's to avoid, frankly, strategic imbalances and relying upon WACOG or whatever. 539 MR. SOMMERVILLE: Thank you. 540 MR. PENNY: Now, the March park, then. Union's proposal solves all problems but one, and that's the remaining uncertainty during the month of March. And that gives rise to a limited need for Union to potentially acquire supply for load balancing in a colder-than-normal March and a continuing need for Union, in any event, to address this potential system problem. 541 The reason that this one month is not covered by the proposal arises from the fact that there are, as I said before, two critical points in March. On March 1, what the proposal deals with is ensuring there's sufficient gas in storage to meet March deliverability requirements, because the system is tapped out at that time of year and balances are low and Union needs to make sure that there's enough in storage to provide storage deliverability throughout March. But March 31, Union also needs to have enough gas available to meet weather variability after March 31, because as we all know, April is the cruelest month and things can happen in April that require unplanned spot purchasing. 542 So once the load-balancing initiative is implemented starting November 1, 2004, the southern bundled-T customers will have to balance their own supply to demand on a predetermined level at February 28 and that will cure the March 1 problem. But it's really the month of March that's left to be dealt with. And except for customers who are daily metered, Union just has no way of monitoring or requiring compliance to balance consumption to balance consumption to plan over as short a time frame as a month. 543 In addition, there's, in any event, a systemic time lag for most customers between having raw consumption data, assembling it, disseminating it to customers and having customers respond by going to the market to acquire incremental supply. So it's just not practical or feasible to require direct-purchase customers to balance over as short a space of time as a month; and frankly, even if it was, storage and deliverability in March are low such that, frankly, the margin for error or non-performance if the customer fails to balance is small because the operating constraints are tight at that time of year. So system integrity at this point in the year just requires the certainty of Union being able to acquire supply as needed and not wait until the eleventh hour to see if the customer is going to fulfil a March balancing obligation. 544 So as a practical matter, even with customers balancing on February 28th, the March 31 control point remains at risk from the perspective of increased volumes due to either colder-than-normal weather or other consumption variances caused for other reasons. 545 So the protection against this unforecast demand variance for March is proposed to be achieved by the March park, parking gas in March to be repaid the following May. And a park is a gas supply instrument where you borrow molecules from a third party and return them later, in this case in May. And by purchasing a park for March, Union avoids having to buy spot gas in March for sales service or bundled-T customers at a time when prices are most volatile. 546 The volume for the March park was determined by assessing the March weather risk for general service heat-sensitive markets in the north and the south. As well, for the bundled contract classes, Union examined variations between actual and forecast consumption over the past four years for the month of March, and that reviewed indicated that a total March park volume of approximately 6.5 pJs would be required to cover March volume variances, but then Union applied a risk adjustment of 80 percent to recognize diversity of consumption among the customer base and that resulted in the proposed March park volume of 5.2 pJs. The cost of the park, of course, depends primarily on the price differential between the month the gas is borrowed and the month the gas is returned. So between May 15 and June 15 of this year, the cost of a March park averaged about a $1.60 a gJ. Accordingly, Union is proposing to recover 8.4 million, that's the 5.2 pJs times 1.60 a gJ. The March park, however, will be deferred so that only the actual cost of the March park will be recovered by customers. 547 Now, you heard some evidence that Union considered several options. These were outlined at J.7.70 and were discussed at volume 17, paragraphs 275 to 298 and 340 to 355. 548 Bottom line: Economically and practically, the March park option is the best solution available to solve the issue posed by this one month. And using the March park that Union has proposed has basically three advantages: First, by including the March park in delivery rates, Union will not have to purchase spot gas on behalf of southern bundled-T customers, so that will eliminate out-of-period adjustments related to load balancing for bundled-T customers. Any south bundled-T volume variance in March will be covered by the March park. This is what I said a moment ago in response to your question -- on a temporary basis and then they can deliver the shortfall at a later date. 549 Second, by using the March park and eliminating March spot purchases, the deferral recovery adjustments relating to spot purchases will be minimized, so that deals with the retroactivity or retrospectivity issue. 550 And then finally, the evidence was that the month of March represents the period of highest volatility in the day market for spot gas, and so volume variances in the month of March, if you're in the spot market and hadn't made prior arrangements, would have to be bought in March on the day required. And as Union's evidence shows, day markets are the most volatile gas markets. And in March of 2003, for example, day prices at Dawn ranged between -- about roughly 5 bucks a U.S. MMBTU and 16 bucks a U.S. MMBTU? So that's an indication of very high volatility. So part of the purpose of the March park is to protect unbundled customers against -- sorry, protect bundled and unbundled customers from this volatility exposure. And that evidence you'll find -- you'll find -- sorry, I just misspoke myself. It's bundled customers, sales service and direct purchase. You'll find that evidence at J.23.15. 551 So the net effect of the proposal is to eliminate 6 million of load-balancing costs from rates. Spot purchases may have to be made in March on behalf of all customer if it's colder than normal. If those purchases are left to the last minute, customers are exposed to volatility in the day market. The March park is really simply a way of dealing with exposure to that risk. It's a way of ensuring the integrity of Union's system operations, it's a way of -- it's a form of insurance against high March prices, it's a way of avoiding out-of-period adjustments due to unplanned spot purchases, and it's a way of avoiding uncertainty and controversy around the allocation of deferred spot charges if they were, in fact, incurred by just going out onto the spot market on the day of need. 552 The issue of having sufficient inventory on March 31 to meet late season weather variability is an important issue of operational system integrity. It just can't be ignored. So it has to be dealt with. And then the question is -- it won't go away, so then the question is: What's the best way of dealing with it? It's Union's submission, as outlined in J.7.70 that the March park represents the best alternative of the various alternatives available. And it's therefore a necessary and important part of the proposal. 553 In conclusion, Union has proposed an appropriate solution to an issue that's been outstanding for a long time, it responds to the factors outlined by the Board in 493/494-06, and it fulfills Union's business principles of not buying gas for direct purchasers and not visiting costs of load balancing on customers who have, in fact, balanced. 554 Under the proposal, Union will continue to provide a basic load-balancing service based on normal weather and forecast consumption, and it's only the portion of supply that overdraws on the banked gas account that direct purchasers are responsible for bringing into balance at the two checkpoints. March represents an operational issue which can't be resolved in the same way and Union's solution for dealing with March is the best solution available. So Union has developed -- and is just finishing the systems to enable full information to flow to customers about where they stand on their consumption forecast. The way this will work is that Union and the customers, by next summer, will have the access to the information. The systems will be in place, people can see what's happening, they can follow along with their account and work out any bugs in the period leading up to the winter, and so the implementation in the winter beginning 2004 for 2005 will enable everyone to ensure that the flow of information and the planned system meets parties' planning needs and enables appropriate decisions and actions to be taken. 555 For these, Union submits that the proposal should be approved. 556 I'll turn it over to Mr. Smith for the remaining issues. 557 MR. SOMMERVILLE: Thank you, Mr. Penny. We'll take 10 minutes and reconvene at 20 minutes to 4:00. 558 --- Recess taken at 3:30 p.m. 559 --- On resuming at 3:40 p.m. 560 MR. SOMMERVILLE: Thank you. Please be seated. 561 Mr. Smith. 562 CLOSING ARGUMENT BY MR. SMITH: 563 MR. SMITH: Smith Mr. Chairman, as Mr. Penny indicated at the outset, I'll be dealing with issues 7 and 8 on the first page of the outline, and items 11 and 12, 14, 15, 16, and 17. 564 CAPITAL ADDITIONS: 565 MR. SMITH: Starting first with the capital additions, that was the panel comprised of Mr. Shervill, Mr. Hyatt, Mr. Sanders and Mr. Faye who testified on October 27 and October 28th, and the first issue I would draw your attention to is the issue of system planning and that was Mr. Hyatt's evidence. His evidence is contained at Exhibit B.1, tab 4. 566 You'll recall that what Mr. Hyatt does, at a high level, is look at what Union's system capacity is compared to what Union's system requirements are based on design-day needs, and he determines whether or not system growth is necessary on either the Dawn-Trafalgar or the Panhandle systems. The actual allocation of design-day needs is -- the actual calculation of design-day needs is a complex calculation. Mr. Hyatt reviewed it with Mr. Thompson, and the evidence reference for that is paragraph 1190 on October 27. But for ease of reference, I don't propose to take you through it, but if you are interested, it's at J.136, and that's included at the compendium at pages 56 through to 58, and there Mr. Hyatt has set out the entire steps he goes through, and there are quite a few of them, to calculate his design-day demand. 567 Now, the evidence from Mr. Hyatt is the results of his calculations, which are reflected in the blue-page update, is that the major facilities work that was included in the white- page evidence is no longer necessary and that will be deferred and is not included in the 2004 capital budget. And just by way of reminder, the major facilities work that was originally included in the white-page evidence is made up mostly of a $73 million expenditure on the expansion from Brooke to Strathroy on the Dawn-Trafalgar system, and a $3 million facilities expansion from Lemington on the Panhandle system, and neither of those are going to be incurred. 568 So the result of Mr. Hyatt's calculation is that there's a small non-facilities need of 33,200 gJs per day, and Mr. Penny addressed that, and that will be dealt with through a non-facilities option that will be acquired by the acquisitions group. 569 Now, I should say that not all transmission expenditures have been deferred, but certainly the lion's share comparison between the white page and the blue page has been deferred, and that evidence is at B.3, tab 2, schedule 2. 570 Now, with respect to the remaining transmission capital expenditures, with the exception of the pipeline integrity management program, which I'll come to in a minute, there was no cross-examination on any of these items at all, and in my submission, the evidence respecting system growth should be accepted by the Board in its entirety. 571 The next aspect of the capital additions evidence is Mr. Fay's evidence relating to storage projects, and Mr. Fay's evidence is set out at B.1, tab 6. And the impact on capital expenditures in 2004 is set out specifically at Exhibit B.3, tab 2, schedule 2, page 2 of 6. The total capital cost of storage projects in 2004 is forecasted to be 3.684 million, which is driven primarily by the cost of installing gas chromatographs at each of Union's storage pool measurement and control stations, and that's $2 million of the 3.684 million. 572 The evidence is clear, in my submission, that gas chromatographs are necessary for Union to keep pace with the natural gas industry in terms of being able to convert gas transactions from a volumetric to an energy basis, and the evidence is that customer transactional business is being done on an energy-units basis. That's at paragraph 46 of October 28. 573 Chromatographs will allow Union the ability to more accurately track, account, and reconcile the working inventories of each pool in energy-based units, and in my submission, the installation of gas chromatographs was virtually unchallenged by the intervenors as a reasonable step for Union to undertake. The storage projects forecast for 2004 of 3.684 million, in my submission, therefore, should be approved. 574 The next aspect of capital additions is pipeline integrity, and you'll recall that was the evidence of Mr. Sanders. His evidence is set out at B.1, tab 5. A detailed breakdown of the 2004 costs is contained at B.1, tab 5, appendix D, as well as J.7.16. And I've included at page 59, just for ease of reference, Mr. Sanders' appendix D, and that shows the breakdown of the 2004 capital and O&M costs under various categories. That's going horizontally across the page through various items of capital and O&M, and then from the top to the bottom on the left-hand side, between that which is required to meet the 2001 regulation, which I'll come to, and other integrity-related costs, and just simply, I'll come to this, but by way of observation, you'll see that by far and away, the majority of costs, both in capital and O&M, are related to complying with the 2001 regulation 210/01. So of the capital, for example, of 9,349,000, 9.46 million of that was directly related to the regulation. 575 In addition to the capital of 9.349 million and the O&M costs of 9.52 million, the company is also seeking approval of the 2003 deferral account balance of 3.302 million. I may have misspoken. I meant to say O&M of 6.52 million, if I didn't. The deferral account balance of 3.302 million, and I will come to that when I deal with deferral account balances. The company is also seeking approval after 2003, so in 2004, to discontinue this deferral account. 576 The 2004 pipeline integrity management program is in year 3 of a ten-year integrity management program that Union has put in place in order to respond to Ontario regulation 210/01. That regulation was enacted in June of 2001. 577 Under the regulation, Union was required to expand its pipeline integrity management program to all steel pipelines operating at a pressure of 30 percent or more of the specified minimum yield strength, and that's the acronym SMYS that's found in the evidence. What this means is that Union is required to assess the condition of approximately 2,800 kilometres of pipe and, where necessary, implement the mitigation program. 578 The primary method for inspecting the lines is through what's called pigging. The pigging process, and you heard Mr. Sanders talk about that, the cost is making the lines piggable. Now, also included in the totally integrity management program is Union's stress corrosion cracking program, and that has a capital cost of $280,000 and that's set out in appendix D. And there's two other additional items. One is practice enhancement costs, and by that what I mean is, in developing its integrity management program, Union identified several operational aspects in its program that could be adjusted and enhanced, those being, among others, emergency response, records management, and training, and the total O&M costs of these enhancements is approximately $890,000, also set out on appendix D. 579 And secondly, integrity costs relating to storage downhole piping, and these costs are driven by a need to comply with CSA Z 3.41 which is the latest code for storage of hydrocarbons in underground formations, and the total cost of these expenditures is forecast at 203,000 in capital and $1.28 million in O&M expense. 580 In my submission, the evidence shows that the costs of the integrity management program are reasonable. 581 Now, to the extent there was any concern about whether Union will actually incur the costs forecast, Mr. Sanders clearly indicated that the regulator, the TSSA, would have preferred that the program, rather than ten years, be completed in a shorter period of time with a concomitant increase on a yearly basis. Further, the TSSA will, and does already, audit Union to ensure compliance with the integrity management program to make sure Union remains on track. As Mr. Sanders identified, the TSSA actually has the authority to fine Union for non-compliance, and that authority is set out in section 37 of the Technical Standards Safety Act. 582 There was also the suggestion by Mr. Janigan on behalf of VECC that the integrity costs should be amortized over four years, as was the practice previously. And with respect to that suggestion, I have two responses. 583 First, in my submission, it's inappropriate to amortize an expense which a party knows is recurring in roughly equal installments year over year. And second, the suggestion will mean greater costs in later periods and take what is a ten-year program and extend it out beyond its ten years to 13 years, and that is set out at Undertaking 14.5, the simple math of which is you take the final amortized costs and spread them over, you're going to be out of period -- out of the ten years. 584 The final issue with respect to the integrity management program is Union's proposal to discontinue the pipeline integrity deferral account. And with respect to that issue, I think it's important to go back to first principles and consider why the deferral account is there in the first place. The origin goes back to the Board's decision in RP-1999-0017, the PBR decision, and the ADR agreement between the parties in RP-2001-0029. In RP-1999-0017, the Board expressed the view that variance accounts for non-routine adjustments were appropriate, with non-routine adjustments being unusual or unexpect the events. And I've set that decision out at pages 60 to 63 of the compendium, and I would just simply draw your attention to paragraph 2.323, the second sentence in that paragraph on page 62. 585 MR. SOMMERVILLE: Thank you. 586 MR. SMITH: The second sentence: 587 "The Board is of the view that non-routine adjustments relating to events or changes should reflect actual costs to the maximum extent possible. By definition, non-routine events are unusual and unexpected, and the ability to forecast them is poor at best. However, the continuing flow of costs relating to a non-routine event once it has occurred may be more easily forecast from then on, and incorporated into rates." 588 The parties agreed in RP-2001-0029 that in fact the regulation 210/01 qualified and the integrity management cost qualified as a non-routine adjustment and a deferral account was set up. And I don't need to take you to that, but that's also in the compendium, and the parties' agreement is set out at page 64, second sentence of paragraph 3.54: 589 "The parties agreed that the resulting costs should qualify as a non-routine adjustment for rates commencing in 2002." 590 But as Mr. Sanders testified to on a number of occasions, in answers to questions from both Mr. Warren and Mr. Janigan, in particular, at paragraph 165 on October 27th, Union is now in the third year of this program. Its ability to forecast these costs is good. It has confidence in the forecast and feels comfortable that there will be no material deviation from these costs. And just returning to the rationale for non-routine costs in the Board's decision in RP-1999-0017, I say the Board specifically contemplated that once non-routine costs had become a known recurring event, they should be included in the rates. 591 I also say that the decision to eliminate the deferral account, not only being consistent with RP-1999-0017, is consistent with the Board's decision in the Enbridge case, RP-2000-0040, and that is set out at pages 66 to 68 of the compendium. On page 67, the Board addresses the issue of deferral accounts, paragraph 2.2.24 and says in the second sentence: 592 "In general, the Board is concerned with the proliferation of deferral and variance accounts. Deferral accounts should represent the exception rather than the rule in the current prospective test year rate-making regime, since they tend to distort the true cost of the services and represent intergenerational cross-subsidies." 593 I would say, with respect, that now in the third year of the program, the usefulness of the deferral account has run its course and we should be returning to what the Board has indicated should be the usual case, which is to forecast these costs, treat them like any other program, and include them in rates. 594 MR. SOMMERVILLE: Mr. Smith, there was a question posed to one of the witnesses related to a challenge of the regulation by TransCanada PipeLines. Do you recall that? I'm just wondering if you knew -- 595 MR. SMITH: I believe my recollection of that is whether or not Union was a party to that proceeding, and I believe Mr. Sanders' evidence was he wasn't sure and I actually don't know anything beyond that. 596 MR. SOMMERVILLE: I don't think a lot turns on it, just if you have it. 597 MR. SMITH: Mr. Reghelini's recollection is -- the question was whether or not Union was challenging TCPL's costs of complying with the regulation in TCPL's proceeding, and Mr. Sanders wasn't aware of that and neither are we. 598 MR. SOMMERVILLE: Okay. 599 MR. SMITH: That brings me to the next issue which is GDAR and ABC. 600 GDAR/ABC/RATE RIDER: 601 MR. SMITH: That is the evidence is at D.1, tab 12, the evidence of Mr. Wayne Andrews, and he testified on October 30 and 31st. Dealing first with GDAR, just by way of overview, on December 11th, 2002, the Board issued the final version of the gas distribution access rule. Union has completed a detailed compliance review to determine the impact of the rule on its business. The review indicates that Union is largely compliant with the rule with the exception of chapter 4 and its -- well, chapters 3 and 4, but it's only chapter 4 in respect of which Union is seeking to recover costs. Chapter 4 relates, you'll recall, to what are called service transaction requests, or STRs, as they are in the evidence. 602 The evidence is that Union will incur, in complying with the rule, $4.78 million in capital costs and $1.3 million in O&M costs in 2004. And these costs have been included in the 2004 revenue requirement. Union is also seeking approval of a deferral account to capture variances from the forecast costs included in rates and the actual costs incurred. And more specific evidence relating to the deferral account can be found at Exhibit D.1, tab 4, page 8. 603 With respect to costs in total, Union's forecast decreased considerably from white page to blue, and that was driven primarily by a decrease in the capital cost estimate or forecast from 8.12 million to 4.78 million. And the reason for the change is that Union has now had the opportunity to sit down with its principal consultant, Sapient, and do a thorough review of what exactly is required under chapter 4 and how those requirements will require changes to Union's online system, Union Line. 604 It was the evidence of Mr. Andrews that compliance with chapter 4 will drive both process and system changes to the way Union currently handles service transaction requests. The majority of these process and systems changes needed to comply with chapter 4 will impact Union Line, which, as you'll be aware, is the online customer transaction system currently used to manage and direct -- to manage direct purchase transactions, including STRs. 605 Union will versus need to make some changes to its contract administration and customer information systems as well. 606 Union has now initiated a phased approach to addressing the compliance requirements and these phases are set out in Mr. Andrews' evidence and they are project planning, scope and analysis, design, test, build, and implementation. Union has now completed the project planning, scope and analysis, and design phases, and is about to begin the test phase -- sorry, the build phase. It's actually completed the test phase as well. 607 Union is also, and will continue to have discussions with Enbridge and the gas vendor community to help facilitate a successful implementation of GDAR. 608 As I said before, working with Union is Sapient, the consultant who designed and implemented Union Line. Mr. Andrews testified that using Sapient and Union line as a platform has allowed Union to minimize its costs. Mr. Andrews said to Mr. Janigan, essentially in a question -- the question was put to him: Why did you not tender this? And Mr. Andrews' evidence, which I think makes eminent sense was: 609 "Once the decision was made that it was possible to use Union Line as the starting point, it made absolute sense to use Sapient because, one, as the architect of the system, they know the system better than anyone else; and two, Sapient had taken the time to inform themselves regarding the GDAR. They were working with Enbridge and were well ahead of the game." 610 And Mr. Andrews' evidence with respect to that is in Volume 10, at paragraph 1242. 611 The specific changes chapter 4 compliance requirements are set out in Mr. Andrews evidence at page 5. Briefly, chapter 4 is driving the need to process STRs differently than how Union currently processes them; to add new transaction and to increase communications with vendors and consumers. As Mr. Andrews identified, chapter 4 will, one, significantly alter the way Union processes STRs; two, create new STRs, and by this I mean primarily consumer-initiated STRs, which is something that, until now, hasn't been contemplated; three, require Union to communicate more frequently with gas vendors and consumers. And in respect of vendors, that will be done through Union Line, and with respect to consumers that will be done through telephone, e-mail, mail. Four, it will alter the way Union handles STRs, directing a change from one gas vendor to another gas vendor. 612 Now, in response to suggestions throughout cross-examination that function -- GDAR functionality should have been built into Union Line at some earlier time, it's important to recognize the significance the specific rules contained in the GDAR will have on the way in which Union will process STRs compared to the way STRs have traditionally been processed. 613 And I say that, and it's important, and this will also be an issue with respect to rate rider, it's incorrect to believe, as some cross-examination would suggest, that because Union now processes STRs through Union Line, that the GDAR contemplates STRs, that no cost will be incurred in complying with the form of STRs contemplated by GDAR. And the thrust of Mr. Andrews' testimony on this is clear that when it comes to designing an information technology system, the devil is in the details. This is clearest at Volume 11, paragraphs 207 to 211, and it's in response to a question from Mr. Moran, and I've included that at pages 47 to 48 of the compendium. 614 First, at paragraph 206, Mr. Moran puts to Mr. Andrews, he's talking about: 615 "Those very same rules, unwritten as they were at the time." 616 "...'the same rules', and from the perspective of designing systems, you have to be very careful, I wouldn't necessarily say they were the same rules. There were rules around service transaction requests, even though when didn't call them that; that when you are designing a system, you have to be absolutely crystal clear and very specific with respect to each one of those rules. And if you've read the gas distribution access rule, there's something like 60 articles in chapter 4 and none of those were in effect at the time." 617 And the answer continues, and then over at page 48, Mr. Moran effectively puts the suggestion to him again and says: 618 "Right, and when you look at chapter 4, those are the things that you have to be able to do; right? You have to be able to switch customers from system to marketer, from marketer to marketer, and from marketer back to system. Right." 619 And he's talking about previously, you've always had to do this. 620 Mr. Andrews' response: 621 "Well, that's correct, Mr. Moran, but there can be a world of difference between the 'how' you make those transactions work. And the chapter 4 requirements impose a great deal more process on -- on those transactions than the current rules that we currently work by." 622 So in my submission, it is incorrect to suggest that simply because Union currently processes STRs, although they haven't called them that, that there will be no costs at all in changing Union Line to be able to accommodate what are now known as STRs in GDAR. 623 And a similar suggestion was also put that Union should have built -- it's not just that Union should have built the flexibility in earlier, but that the flexibility -- or that there should be no cost now in changing the Union Line system. In other words, the suggestion is what you sold us before was a flexible system, and isn't this evidence of the fact that it is not flexible. And that was rebutted again by Mr. Andrews both in N.11.1 -- I suppose most clearly in N.11.1. I'm sorry, I was going to say at page 48 of the compendium, and it's really paragraph 211 through to the end, but it's virtually the same exchange with Mr. Moran where he responds and says the system is flexible, but flexibility is something that does come with cost when you're layering additional requirements on top of that. 624 Now, the final suggestion I wanted to take you to, and that is N.11.1, is that while GDAR was going on, earlier stages of GDAR, Union should have been able to include or predict the way GDAR would have turned out and included in Union Line the flexibility to deal with STRs. And if I could draw your attention to paragraph -- just at page 49 of the compendium, and that is Exhibit N.11.1, and it's an undertaking from Mr. Andrews to Mr. Moran and it's to advise what the material changes were to chapter 4 between the second last draft and the final rule. 625 And it's a fairly lengthy answer, but what comes out of that rule, in my submission, is the only time -- really, the crux of it is on page 1, third line from the bottom: 626 "The only unbundling/Unionline project phase where Union could, hypothetically, have taken into account the prospect of a GDAR," and you'll recall that the unbundling process was going on earlier, "The only unbundling/Unionline project phase where Union could, hypothetically, have taken into account the prospect of a GDAR, would have been the design phase during April to June of 2001. The GDAR draft available at that time was the early February 2001 version of Draft Rule 1. By the time the June 2002 draft Rule was issued, Union had already implemented Unionline." 627 And you'll respond Mr. Andrews responding quite clearly to Mr. Moran that business had to go on. And of course, Union would not have know in June of 2002, when the Board was going to issue the final version of GDAR, as Mr. Penny points out, if ever. 628 So in my submission, the evidence is quite clear that the GDAR costs are reasonable and necessary to comply with the gas distribution rule, particularly chapter 4, and the capital costs of $4.78 million and the O&M costings of $1.3 million should be added. And that paragraph 969 on October 27th. 629 In fact, Mr. Shervill went further than that. He testified that it would have been imprudent for Union to have built rate-rider functionality in previously absent a customer need for it. In other words, customers would have been paying for something they were not using, and that reference can be found on October 28th, paragraphs 306 to 308, and in the compendium at page 74. 630 In my submission, the rate-rider issue really comes down to transparency on the bill and the cost of that transparency. The evidence is that it will cost $3.8 million to develop the full rate-rider functionality sought by the parties, and Union asks that that cost be approved. 631 The next issue is deferral accounts. 632 DEFERRAL ACCOUNTS: 633 MR. SMITH: The gas supply deferral accounts that Mr. Penny discussed in the gas supply section of the argument, and as mentioned earlier, Union is requesting disposition of gas cost deferrals net of approved prospective recoveries totalling a credit to customers of 6.12 million. 634 That leaves the non-gas supply deferral accounts to deal with. The non-gas supply deferral account balances total 14.8 million, and they are found at Exhibit N.10.2, page 2 of the attachment. And the balance is comprised primarily of net S&T deferral credit of 8.3 million, deferred rebates and charges of 2 million charges, direct purchase revenue and payments of $3.9 million, LRAM of 1.2, interperiod WACOG of 12.5, and pipeline integrity of 3.4 million. 635 The description of the deferral accounts is set out at D.1, tab 4. 636 The S&T deferral balance arises from the transactional storage and transportation business Union conducts to maximize utilization of the system, and as you're aware, the credit is disposed of 75 percent to customers and 25 percent to Union. 637 The deferred rebates and charges are amounts from the RP-2001-0029 the and RP-2002-0130, recoverable from customers for deferral disposition and retroactive adjustments that were less than $10 or amounts for which the customer had been final-billed and could not be located. 638 The direct purchase revenue and payments account is recorded the higher cost of the delivery commitment credit payments than has been recovered in rates. The LRAM balance, as you know, is the amount of revenue lost as a result of the impact of Union's DSM programs. The forecast amount is subject to a true-up next year. 639 The intraperiod WACOG account is the largest component of non-gas supply deferrals, and that is at $12.5 million. And these amounts arise as a result of the impact of the higher cost of gas experienced in 2003 on UFG, or unaccounted for gas. 640 Compressor gas, own-use gas and inventory carrying costs, as you're aware, I covered it before, but the integrity management deferral account, the TSSA introduced new regulations dealing with pipeline integrity. The parties agreed to a deferral account to record the incremental cost of compliance with the new regulations for a collection from customers as a non-routine adjustment. Non-routine adjustments are subject to a materiality threshold of $1.5 million. Union's 2003 cost of 3.4 million exceed the materiality threshold, and Union is requesting recovery of these incremental costs. And as I indicated before, Union is also seeking to close this deferral account. 641 There are a number of other deferral account changes in 2004. Union is requesting a new deferral account in which to record the differences between forecast costs included in 2004 rates and actual costs for complying with chapter 4 of GDAR. I mentioned that before. 642 Union is also proposing to combine the S&T accounts 179-70 and 179-71 because the services recorded in these accounts are similar in nature and the allocation method approved for these accounts is the same, and combining these accounts will simply make administration easier, with no impact on customers. 643 And finally, in 2004, Union has included the impact of its 2004 DSM programs on gas demand in its 2004 demand forecast. As a result, the 2004 LRAM requires revision such that it is used to record only variances in actual lost revenue from that already recorded in approved 2004 rates. 644 Now, on the topic of LRAM, that brings me to the next topic which is DSM. 645 DSM: 646 MR. SMITH: As you're aware, this is a partially settled issue. The ADR agreement is contained at Exhibit A, tab 3, and with respect to DSM, pages 7 and 8. The only issue that remains in dispute is with respect to the 2004 target and the 2004 O&M budget. And on these two issues, all parties, except Pollution Probe, have reached an agreement. The agreement is for an O&M budget of $4 million and a target of 58.1 million metres cubed. When I say all parties, I include in that the Green Energy Coalition, and you'll recall that that was the party the retained Mr. Neme to give evidence. 647 Now, with respect to Pollution Probe's position that the targeted budget should be higher, I say that this is completely unsupported by the evidence. 648 You will recall that Mr. Klippenstein asked Mr. Shervill whether Union can achieve the savings of 85.8 million metres cubed, and this led, in my submission, to a very heavily qualified undertaking. That undertaking is N.11.4, and the long and short of Mr. Shervill's answer on that undertaking is that the target suggested by Mr. Klippenstein of 85.8 million metres cubed is a completely unrealistic target. 649 But the question went on to guess at what sort of budget might be necessary to achieve that target notwithstanding the response that it was unrealistic, and Mr. Shervill's evidence is -- Mr. Shervill's evidence and Mr. Farmer's evidence as well, I suppose, is it would take approximately, and he guessed again, $10 million to achieve that target, or more than a doubling of what the parties had agreed to. And even at that, Mr. Shervill and Mr. Farmer could not be sure that they would yield the savings in 2004; indeed, it might not yield any savings until 2005 or beyond. 650 In my submission, Mr. Shervill and Mr. Farmer's answer is consistent with the evidence of Mr. Neme himself in response to questions from Mr. Klippenstein, and you might recall that Mr. Neme was asked to testify in response to whether the company spent -- if the company spent more on research or in total, whether that would yield additional savings, and Mr. Neme's answer was he was not certain how far one could go before the marginal costs went beyond the marginal benefits. And the evidentiary cites for that: Volume 11, paragraph 849 and 856. 651 So on this issue, I would say in summary, the settlement is supported by virtually all of the parties, including parties who traditionally had widely divergent opinions on DSM. It is reasonable and should be accepted by the Board. 652 Next issue is lines of business. 653 LINES OF BUSINESS: 654 MR. SMITH: On that, Union is an integrated operation. It does not have lines of business per se. Union has filed a cost allocation study by notional line of business in binders I.1 and I.2. The costs are allocated between Union's two notional lines of business; one, storage and transportation, and two, distribution which includes the sale of the gas commodity. 655 The sale of commodity is not a separate line of business for Union because the service is only offered on a bundled basis with distribution, and Union is prohibited by Board regulation from earning a profit on the sale of gas, and for that reason, for Union, commodity is not really a business at all. If anything, it's an implied requirement of the distribution service to meet the supply needs of Union's general service customers that elect not to be served by a gas vendor. 656 Union has filed this cost of service study by lines of business in response to a Board directive issued in RP-1999-0017 and RP-2002-0130, and I'll just read the original directive which is at paragraph 2.770 in the RP-0017 case: 657 "The Board directs Union to file with the Board and the customer review process information on revenue-to-cost ratios for rate classes, financial information, segregated by line of business, and then at paragraph 2.798: 658 "The Board expects Union to file in a timely manner at a minimum, a traditional cost-of-service-based revenue requirement, a cost allocation study as a guide for evaluating cost responsibility by line of business." 659 Now, as part of the 2002-0130 proceeding, Union filed a status report on its efforts to comply with the Board's directive. Through this report, Union identified that after considerable analysis, the company was not, for management purposes, going to separate into lines of business as there was no apparent advantage to the business or to ratepayers, but the company confirmed that it would nevertheless comply with the directive. However, since the company was not going to use this information for anything other than compliance reporting and compliance was going to require a significant ongoing expense, Union requested clarification from the Board of what the lines of business information was to be used for. Union also asked for relief of the directive if the Board did not have a use for this information. 660 In the Board's decision in RP-2002-0130, the Board said: 661 "The Board will defer the implementation of the directive pending the outcome of the cost allocation study for the 2004 rate case. In confirming the Board's directive to file the financial information segregated by lines of business is appropriate to restate the original rationale for giving it." 662 And the Board's decision continued on. 663 Union noted in its evidence that preparation of the line of business cost of study was a significant expense and exercise. It more than doubled the extent of the cost allocation evidence that was required. The exercise also created difficulties in ensuring that the cost allocation to rate class study was consistent with the allocation to lines of business." 664 This is not for dramatic effect, but they are large binders and not a single interrogatory was asked in respect of the evidence, nor was Mr. Packer called to testify, as no one intended -- no one did cross-examine him. 665 Union is aware that the Board stated its rationale for requiring it to be produced in RP-2002-0130. Union, however, respectfully submits that it is not clear what this effort was for or how it can be meaningful used. A line of business study produces essentially the same result as the traditional cost of service and cost allocation study. When it comes to the rate class, Union's rates are set by rate class and the effort expended on the line of business study contributed nothing to setting 2004 rates. 666 As Union stated previously, it does not intend to move its storage and transmission facilities business into a separate company or even business division for its distribution business, and while some of the prices charged exfranchise customers for S&T services or market based, all of Union's storage and transmissions are regulated by the Board. Therefore, it is unclear to Union what the Board was referring to in terms of separation of utility operations between regulated and unregulated activities in its directive I referred to earlier, and Union respectfully submits that there's limited benefit, if any, to implementing the process to track and report costs by lines of business and asks that it be relieved of the directive so that in future rate cases, it only be required to prepare and file the traditional cost allocation study, and that compliance reporting not include an important aspect to track an important amount of business basis. 667 Which brings me to the last two topics, cost allocation and rate design. 668 COST ALLOCATION: 669 MR. SMITH: This was, as you will recall, the evidence of Mr. McMahon and Mr. Kitchen, and their evidence first with respect to cost allocation is contained in Exhibit G, volumes 1 and 2. Mr. McMahon's written evidence in chief is at G.1, tab 1. Rate design evidence is contained in Exhibit H. Mr. Kitchen's written evidence is behind H.1, tab 1, and you'll no doubt recall that there are many iterations of Mr. Kitchen's evidence. But at this stage, my intention is to deal solely with his original evidence as updated and to leave both the evidence relating to Coral and Energy Objective to reply, as necessary. 670 Turning first to cost allocation, in EBRO 499, Union's last cost-of-service case, Union indicated that in its next cost-of-service case, it would file an integrated cost study. Union's intention to file this integrated cost study was accepted by the parties in the settlement agreement in that case. And consistent with the parties' agreement, Union has prepared or did prepare and file an integrated cost study in this proceeding. The cost study is contained in Exhibit G.3, tabs 1 through 5. 671 The cost study reflects how Union operates its business on an integrated basis and was prepared to support its 2004 rates proposal. Subject to a few exceptions, the methodology used to prepare the cost study was the same as previous studies that were approved by the Board. The few methodological changes that were made are identified in Mr. McMahon's evidence at G.1, tab 1, and at this stage, it's unnecessary to review them in any detail. 672 One change I would point out is the allocation of distribution capacity-related costs. This change is explained in Mr. McMahon's evidence in chief at G.1, tab 1, pages 9 to 13. And what is occurring here is that Union is proposing to change the allocation of capacity-related distribution costs in the southern operations area from an allocation to rate classes based on peak-day demand of all customers, including those customers served directly off transmission facilities, to an allocation to rate classes in proportion to demands of only those customers served using distribution facilities. 673 And you'll recall that this change has been proposed to allow the cost study to catch up to what is in rates, and Mr. Kitchen testified to that. What I mean is that the proposal was brought forward in 499, 493/494, and the Board, in those decisions, approved the rates on the basis of the inclusion of these costs but denied the cost allocation change at that time. The result of which is that rates, if not the cost study, already reflect the proposal. As I said, Mr. Kitchen testified to this in a number of places, but the easiest reference is perhaps volume 19, paragraph 347. 674 Now, in terms of how this proposal will be reflected in the integrated cost study, the evidence is that within the cost study, Union will have to maintain two different methodologies. Separate planned accounting records will have to be maintained in the north and in the south. Unfortunately, it's simply not possible to go to a harmonized system. You'll recall in the north area the allocation of distribution main costs are done on the basis of customer attribute, whether the customer is a sole, joint, or grid-use customer, and in the south this tracking is not possible. In the south, plant records are kept on the basis of physical attributes, such as pressure, pipe size, and it's not possible to track based on customer attributes. 675 What the Board should be aware of, however, is that the proposal does make the allocation of distribution in the north and in the south on the same -- on roughly the same basis by applying the same cost causation principles, and that is the demands of customers served off transmission would not cause Union to incur distribution capacity are excluded from the allocation and distribution capacity costs, but that's also not to say that those customers that -- that those in the T1 rate class -- or that the T1 rate class will not attract any distribution costs, because the principle of class-based rate-making, they will. But they will attract them only in proportion to the demands of those customers in the class whose demands cause Union to incur those costs. 676 Which brings me to rate design. 677 RATE DESIGN: 678 MR. SMITH: The restated total revenue deficiency for rate design purposes is $98.727 million, and that's at H.1, tab 1, updated, page 3 of 5. The proposed recovery of the 2004 revenue requirement by rate class, the proposed recovery and the revenue-to-cost ratios are provided in Exhibit H.3, tab 1, schedule 1 updated. H.3, tab 1, schedule 2 updated provides detailed infranchise and exfranchise rates. And what I propose to do is review Union's main rate design proposals, and those changes are, first, a change in the rate M2/rate 01 monthly charge from $10 per month to $14 per month. As the evidence indicated, this change has been proposed to better align the recovery of fixed customer costs with their incurrence, while at the same time retaining parity in the monthly charges in the north and in the south. Currently, Union recovers 41 percent of customer-related M2 class customer costs, and 64 percent of customer-related costs in the rate 01 class. 679 With this proposal, Union will increase the M2 fixed costs recovery to 57 percent and the rate 01 recovery to 90 percent. At the same time, Union's proposal is kept in mind, and this relates only to the M2 class in the south, the integrity of the block structure in that class. 680 The bill impacts of the change are set out at tab 3 of H.1, tab 1, and they illustrate, in my submission, the impact of the change will be extremely modest, but from Union's perspective, you should know that there is no change in total recovery by rate. 681 Now, with respect to the M2 class, and I suspect we'll have to deal with this more in reply, but there was suggestion in cross-examination about splitting the class into two categories based on residential versus commercial/industrial lines. And Mr. Kitchen addressed this issue in his evidence, and I expect I will have to deal with it in more detail, but what the Board should be aware of at this time is that there are a number of problems with that suggestion. 682 The first is Union does not design rates, and in fact, Mr. Kitchen said on a number of occasions quite strongly, does not design rates along end-use, and a good reference for that is at Volume 20, paragraph 463. So Union would not design -- even if it were splitting the rate, it would split it along volume lines rather than end use. 683 Second, looking at load factor, one of the two primary rate considerations Mr. Kitchen looks at in determining whether to establish a separate rate class, the M2 class on the whole exhibits a fairly homogenous load factor profile. 684 Third, even if the Board were inclined to split along end-use lines, i.e., residential versus industrial/commercial, the cost allocation study as testified to by both Mr. McMahon and Mr. Kitchen, is not necessarily, at this stage, a reliable source of data for the purposes of splitting that class. And you'll recall the evidence that at the lower volumes, Union does not have precise information on who's residential versus who's industrial or commercial. And the only way that information can be obtained is by conducting a detailed intraclass study, and that intraclass study would also set out the appropriate volume levels at which to set the block breaks. And the evidence for that is at Volume 20, paragraph 744, and Volume 22, paragraph 1158. 685 And finally, it is simply not possible, as Mr. Kitchen testified, in the near term to build the M2 class as two separate classes. You'll recall his evidence, and there will be an additional undertaking coming in respect to this in response to a question from Mr. Moran, but I can advise the Board, consistent with Mr. Kitchen's evidence, that to build the necessary functionality into the billing system will come at considerable cost and take anywhere up to a year to complete the necessary reprogramming. And the evidence for that can be found at Volume 20, paragraph 698. Again, there will be an undertaking coming. 686 The second major rate design proposal is to change the R10 monthly charge from $50 per month to $70 per month, and the rationale for that is precisely the same as the rationale for the M2/R01 monthly class change, and that's to better align the customer-related costs with their incurrence. At the same time Union is proposing to decrease the delivery charge such that the total recovery for R10 will be unaffected. 687 Third, there's a proposed redesign of the T1 rate. In the T1 rate, currently Union charges a single firm transportation demand charge applicable to the firm daily contract demand and a single firm transportation commodity charge applicable to all volumes redelivered to the customer. And this structure was appropriate when the T1 class was smaller in number and was more homogenous in terms of volumes consumed. However, the evidence is clear that significant growth in the number of customers as well as significant divergence in the quantities consumed and load factors of the customers has occurred over time. 688 By way of example, one of the examples provided is that the volumes consumed in the T1 class now range, on an annual basis, from 5,000, 103m3 to 400,000, 103m3. As a result of these changes, Union is proposing to switch to a two-demand, two-commodity block rate structure, and the structure is set out on table 6, page 19 of Mr. Kitchen's evidence, and the proposed redesign is similar to the redesign of rate 20, which was approved by the Board in RP-2002-0130. 689 Union is also proposing a common customer charge for all customers of $1,800 per month. And as with the other changes, the proposed redesign will better align cost occurrence with cost recovery and will reduce intraclass cross-subsidization in the T1 class. The redesign will also prevent inappropriate rate switching by eliminating the rate distortions of the boundaries between T1, M4, M5A, and M7. 690 The fourth charge is the introduction of a monthly charge to the rate M5, which is an interruptible rate, the rationale again being to match cost recovery and cost occurrence. Customer charge is proposed at $500, whereas previously, all charges, including customer charges, were recovered through commodity price. 691 Fifth is a change to the M6A seasonal service, and consistent with the requirements of M4 and M5A rates, Union is proposing to add an annualized minimum volume that is at 400,000, which is the seasonal equivalent of 700,000 for the M4, M5A rates. 692 Six, consistent with Union's response to the load balancing directive that DB customers balance their demands at contract anniversary in February 28, Union is proposing to add to the R1 rate schedule a discretionary gas service. This service will allow direct-purchase customers who are unable to access supplies to meet their February 28 checkpoint, the ability to buy gas -- sorry, to meet their February 28 checkpoint in order to buy gas from Union at Union's cost plus an administration charge, provided they advise Union of that desire. 693 Seven, M12 transmission fuel rate changes, and there are really two of them, the addition of a Dawn compressor fuel requirement in April and October be included in the easterly fuel ratios, and two, the addition of a Parkway compressor overrun charge to recover incremental fuel incurred when people overdeliver. 694 Union is also proposing a change to schedule C of the M12 rate schedule to clarify the applicability of the VT1 easternly fuel ratios. 695 Eight is a change in the M13 and M16 monthly charge. Union is proposing to apply the rate M13 monthly charge on the basis of the number of stations related to each customer, and this change has been proposed because, with consolidation in the local producer market, the number of producers has decreased but the number of stations has not. So to match or keep pace with that rationalization, it's appropriate to make the switch. 696 And nine, the M15 rate schedule is going to be eliminated as their joint venture which related to, the Dow Chemical joint venture has terminated. 697 Finally, there will be some changes to the rate schedules which are reflected in the black-lined version of the 2004 rates schedule found at Exhibit H.3, tab 3, schedule 1. 698 Which concludes rate design. 699 CONCLUSION: 700 MR. SMITH: Now, in conclusion, you have at Exhibit 24 -- M.24.2 Union's requests. Union has filed in this cost-of-service proceeding evidence that, in my submission, supports each of the requested items. Union's witnesses have attended before this Board over the past five or six weeks and have testified, in my submission, in a full and frank manner with respect to their evidence. Intervenors, over this period of time, have had a full opportunity to test the evidence of Union through cross-examination. Intervenors have also had the opportunity to ask interrogatories, as well as the opportunity to file evidence of their own if they so chose. And I say on this last issue that there is a noticeable lack of any contrary evidence from the intervenors, and that is particularly the case, as Mr. Penny pointed out, with respect to such issues as weather method, NAC, and pension costs, to name but a few. 701 And it is Union's position, in summary, that the evidence in this case, including evidence given in cross-examination, through undertakings, and interrogatories, amply supports Union's request, and therefore Union respectfully requests a decision which contains all of the requested items on Exhibit M.24.2. 702 Subject to any questions, those are our submissions. 703 PROCEDURAL MATTERS: 704 MR. SOMMERVILLE: Thank you, Mr. Smith. 705 MR. SMITH: They are not all the matters to be dealt with, though. I'm advised that the final 30 undertaking responses are about to be provided. 706 MR. SOMMERVILLE: What timing. 707 MR. SMITH: Perhaps I should read those into the record. 708 MR. SOMMERVILLE: I think that would be prudent. 709 MR. SMITH: I understand these are being sent to all intervenors, or will be sent to all intervenors tomorrow. In fact, Mr. Reghelini points out to me that a CD with all undertaking responses from number 1 right through to the end is going to be sent to all intervenors tomorrow. 710 MR. SOMMERVILLE: That will be very useful, I'm sure. 711 MR. SMITH: And the undertakings being answered now are 19.3, 19.7, 19.10, 19.13, 19.15, 19.2 -- sorry, 20.2, 20.3, 20.4, 20.5, 21.1, 21.2, 21.3, 21.4, 21.5, 21.6, 21.7, 21.8, 21.9, 21.10, 22.1 all the way through to 22.10, and 23.4. 712 MR. SOMMERVILLE: Thank you, Mr. Smith. 713 The Board is certainly greatly assisted by such a comprehensive and detailed submission. I appreciate the effort. 714 MR. SMITH: Thank you, Mr. Chair. 715 MR. SOMMERVILLE: I'd like to thank the court reporter for diligent service today and every other day of the case where she's been here. Without further ado, we'll adjourn sine die, and look forward to the remaining incidents in this matter, which include argument, reply argument, and ultimately a decision. 716 Thank you very much. I appreciate your effort. Thank you. 717 MR. SMITH: Thank you. 718 --- Whereupon the hearing concluded at 5:00 p.m.