Order UE93-11 - UE20908 - Maritime Electric - 1993 General Rate Case (Jun 24, 1993)

IN THE MATTER of an application of Maritime Electric Company, Limited for confirmation of its rate base, revision in the allowed rate of return on rate base, approval of revised rates of depreciation, and approval of revised rates and charges for services to customers.

3. For the Minister of Energy and Forestry, Government of Prince Edward Island:

This is an application under the Electric Power and Telephone Act, R.S.P.E.I. 1988, Cap. E-4 (the "Act"), by Maritime Electric Company, Limited (the "Applicant", "Maritime Electric", the "Company") seeking an order or orders of The Island Regulatory and Appeals Commission (the "Commission") approving a number of amendments to the Company's General Tariff.

The application was initially filed in September 1992 and revised in November. Public hearings into the application commenced on November 18, 1992, continued on November 19, 26 and 27, 1992 and then adjourned pending further evidence to be filed in early 1993. Following the filing of an amended application in February, 1993, the hearing recommenced on April 15, 1993 and continued on April 16, 22, 28, 29 and 30. A closed hearing was also held on June 11 and 18, 1993.

Interventions in this case were filed by the Town of Summerside (the "Town", "Summerside"), the Government of Prince Edward Island ("Government") and Cavendish Farms.

The evidence on the matter of return on common equity concluded on November 27, 1992 and is the subject of a separate decision issued by the Commission on December 21, 1992 with reasons following on March 25, 1993. The Commission determined at that time that a maximum rate of return on average common equity of 13.0% was just and reasonable.

The balance of the matters set forth in the application are addressed in this order and reasons for order. Included are the Commission's findings with respect to the sales forecast, the operating expenses budgeted for 1993, financial policy, the financial forecast, the proposed rates and other related matters.

As in all proceedings of this nature, the Commission benefits from the efforts of the interveners. We acknowledge their contributions.

Part 2 of these reasons reviews the revenue-requirement aspects of the Company's proposals. Part 3 discusses the Tariff revisions and related matters. Part 4 addresses other issues.

The revenue requirement is the total revenue forecast to be required by the Company from rates and other sources to provide safe and adequate electric service to its customers while at the same time providing a fair and reasonable return to its shareholders. The revenue requirement forms the basis for all rates and charges of the Company.

Maritime Electric's revenue requirement is generally made up of operating costs and costs associated with capital investment such as interest, depreciation, income taxes and net income. The costs of fuel and purchased energy, which make up approximately one third of the revenue requirement are estimated using a base cost of 4.043 cents per kilowatt hour. Any deviation from this cost is passed on to customers automatically through the Energy Cost Adjustment Mechanism (ECAM).

In the following sections, the Commission will discuss the sales forecast, the budgeted operating expenses and other issues related to revenue requirement.

The sales forecast is critical in determining many of the Company's operating expenses as well as the increase (or decrease) in rates required to meet the revenue requirement. A sales forecast that underestimates growth can, for example, result in rates that are higher than necessary and revenue surplus to the needs of the utility. Maritime Electric has, in fact, generated surplus revenues consistently for a number of years and has refunded the amount to customers in the following year. Conversely, overestimated sales can affect the Company's earnings and result, if sustained over time, in difficulties attracting investment.

In recent years, the Company's sales forecast was based on an economic model using historical sales, customer data, population statistics, provincial economic indicators and other related data. The forecast results were then adjusted for the estimated impacts of Demand Side Management programs. Table 2.1 summarizes the recent forecasting accuracy of the Company by comparing the budgeted annual sales with the actual sales for the year. In Order E91-7, the Public Utilities Commission reviewed the sales forecasting methodology of the Company based on a concern that sales had been underestimated and a pattern of surplus revenues had appeared to evolve. The Commission concluded at that time that there was a positive trend in forecasting accuracy that could be attributed, at least in part, to refinements in the Company's forecasting technique.

Table 2.1 Maritime Electric Sales Forecast History
Year	Forecast	Actual	Actual/Forecast	Sales Growth
1987	552,000	579,800	+5.0%	7.6%
1988	600,000	618,700	+3.1%	6.7%
1989	642,900	651,700	+1.4%	5.3%
1990	679,400	676,300	(0.5%)	3.8%
1991	701,258	685,700	(2.2%)	1.4%
1992	688,965	696,700	+1.1%	1.6%
1993	711,000			Forecast 2.1%

In 1990 and 1991, the Company overestimated its sales growth which—given the downwards trend in growth—might be viewed as underestimating the impact of the recession on the Province. While sales were lower than forecast, particularly in 1991, the Company continued to generate revenues surplus to its needs throughout the period.

In the current case, the Company believes that the econometric model produces sales which are lower than indicated by recent, short-term trends. As a result, the Company initially adjusted the 1993 sales forecast upwards from 695,774 MWh to 700,000 MWh in September 1992. The 1993 forecast was subsequently increased to 708,000 MWh in November 1992 and 711,000 MWh in April 1993. The final increase was attributed largely to higher than forecast sales as a result of a colder than normal winter. The Company, however, does not believe the trend is indicative of accelerating sales growth.

In reviewing the forecast the Commission finds that the projected growth appears to be low in an historical context if one considers that the national and provincial economy are beginning to recover from the recession. At the same time, however, recent indicators are that governments are beginning to actively cut spending. This can have a significant impact on the Prince Edward Island economy which is highly dependent on government expenditures. On balance, the Commission will therefore accept the Company's sales forecast as reasonable in the current economic environment.

The operating expenses of Maritime Electric are made up of production, transmission, distribution and administrative costs. Production costs are separated into costs such as fuel and purchased energy for which fluctuating costs are passed on to customers on a deferred basis through the Energy Cost Adjustment Mechanism (ECAM). Other costs, such as labour, supplies and maintenance, are generally fixed in nature. An exception is the cost of the Point Lepreau plant which has been phased into basic rates through the ECAM over a three year period. For 1993, approximately one third of the total cost of Point Lepreau is included as an ECAM cost.

The Operating Expense budget of Maritime Electric is summarized in Table 2.2. According to Mr. Reynolds, Company President, a budget objective of the Company is to keep controllable operating expenses for 1993 at the same level as incurred in 1992. Mr. Reynolds believes that, while certain price components are rising, holding the controllable budget at 1992 levels is appropriate to minimize rate increases in the current economic environment. The Company uses Non-ECAM costs less Pt. Lepreau and Amortization costs as their reference for controllable costs. The respective costs for 1991, 1992 and 1993 are $21,239,488, $20,643,703 and $20,628,900.

The operating expenses of the Company were reviewed by the Commission in detail during the past two rate hearings and are also monitored on a regular basis. With the Company holding its budgeted expenses at previously approved levels, we did not find it necessary to repeat this review. Instead, we have focused primarily on the specific budget items discussed in the sections that follow.

Table 2.2 Summary of Actual and Budgeted Operating Expenses
	1991	1992	1993
	Actual	Actual	Budget
ECAM
Power Purchases	19,587,809	19,733,646	18,991,000
Point Lepreau	1,458,918	6,400,879	3,384,000
Dalhousie	3,764,620	4,060,567	4,562,000
Charlottetown & Borden	4,333,464	1,854,612	2,285,000
	29,144,811	32,049,704	29,222,000

NON-ECAM
Point Lepreau	0	2,967,494	5,735,000
Other Production	8,734,695	7,758,692	7,710,000
Transmission	309,238	307,644	307,000
Distribution	3,175,617	2,834,605	2,841,000
General & Administration	9,019,938	9,710,084	9,631,900
DSM Amortization	37,205	120,342	182,000
Load Research Amortization	0	32,678	139,000
Generation Plan Amortiz.	90,443	90,443	90,000
	21,367,136	23,821,982	26,635,900
TOTAL OPERATING EXPENSES	50,511,947	55,871,686	55,857,900

The cost of the Company's participation in Point Lepreau is determined, in part, by the exchange rates related to financing in foreign currency. Between its original application and the February filing, Maritime Electric adjusted the cost estimates from New Brunswick Power to reflect the Company's own estimates of exchange rates. The impact was an increase in operating expenses of approximately $376,000. The various estimates as well as recent published data are summarized in Table 2.3.

Table 2.3 Exchange Rate Estimates Related to Point Lepreau for 1993
	$Can./$U.S.	$Can./SFR
New Brunswick Power Budget: Jan.-Mar.	1.2500	0.8200
: Apr.-Dec.	1.2195	n/a
Maritime Electric Estimate: Jan.-Dec.	1.2760	0.8800
1993 Average (1)	1.2656	n/a
Spot Rate (1)	1.2608	0.8642
Average Year to Date and Forward (1)	1.2660	n/a
Royal Bank Econoscope (April, 1993) (2)	1.2642	0.8078
Conference Board of Canada (Spring 1993)	1.2390	n/a

Maritime Electric's exchange rate estimates appear to be high in comparison with other forecasts. This has the effect of overestimating the costs of Point Lepreau. In addition, the costs for the January to May, 1993 period are $217,520 below budget which indicates that lower costs are being realized. In the view of the Commission, the Company's adjustment to the Point Lepreau budget is higher than we consider reasonable. We will, therefore, reduce operating expenses by $100,000—slightly more than 25% of the adjustment made by the Company—to reflect what appears to be a somewhat high estimate made by Maritime Electric.

The Dalhousie plant has been the subject of some concern in recent years because fuel prices for the plant have escalated rapidly at a time when world coal prices and other energy prices have stabilized or declined. Table 2.4 summarizes fuel costs at the plant for the past few years. For comparison, coal is available on world markets for less than $40.00/ton delivered to the new plant at Belledune, New Brunswick.

Table 2.4 Dalhousie Fuel Costs
	$/ton	% Increase
1988	$69.93
1989	$70.11	0.3
1990	$78.07	11.4
1991	$76.28	(2.3)
1992	$86.18	13.0
1993 Budget	$96.44	11.9

The Company was questioned at some length during both the Advance Plan hearing and the current hearing with respect to the fuel price the Company is paying for Dalhousie. Their comments are summarized as follows:

At issue is whether the budgeted expenditures for fuel at Dalhousie are prudent and reasonable. The Company's position, in summary, is that it is committed to paying its share of the costs incurred by the New Brunswick Electric Power Commission (NB Power) who operates the plant.

Our concern in this case is solely with the consumption of coal costing approximately 200% of world market prices. The fuel purchaser, in this case the New Brunswick Electric Power Commission (NB Power), would normally be expected to obtain fuel at the lowest cost in accordance with good utility practice—a strategy which is complicated when NB Power effectively owns New Brunswick Coal and the Minto mine. While we remain concerned about the high cost of coal consumed at Dalhousie, we will accept that Maritime Electric is paying only its share of the fully allocated costs of coal supplied to the plant. We will expect the Company to strive to incorporate fuel price protection into future contracts.

The Commission has, in recent decisions related to the utilities that it regulates, expressed a belief that salary and wage increases should reflect restraint. We do not believe that regulated utilities should be immune to the pressures placed on the private and public sectors of the economy during the current recessionary period. For comparison, the general increases in the Company's recent salary settlements and the Consumer Price Index (CPI) for Canada are summarized in Table 2.5.

For 1991, the Journeyman-Lineman reflects additional negotiated changes intended to increase productive hours. According to the Company, the more representative general increase would be 5.75%, which excludes the additional adjustment.

The Commission believes that the Company has exercised some restraint by generally holding wages constant throughout 1992. The 1993 increases, while appearing to be somewhat high in comparison with other settlements in the Province, are not considered unreasonable. The Commission will therefore accept the Company's budgeted expenditures for labour.

The Company filed information on overall executive compensation in response to Commission Staff interrogatories, but requested that the details be examined on a confidential basis. The Commission reviewed these expenses and held an in-camera hearing with Company President John Reynolds following the adjournment of the public hearings. Based on this review, we accept the amounts budgeted by the Company for 1993.

Based on the Company's application, the escalation factors forecast for increases in non-ECAM operating expenses, excluding labour, are summarized in Table 2.6.

Table 2.6 Forecast Escalation Factors
Non-ECAM Operating Expense	Escalation Factor	Budget Amount
Material	2.9%	$ 987,800
Transportation	3.0%	604,600
Consulting	2.9%	558,300
Other-Excluding Power Purchases, Dalhousie, Pt. Lepreau and Amortization	2.9%	6,278,300
TOTAL		$ 8,429,000

The Commission considers the escalation factors used by the Company to be high based on the evidence before us and other published forecasts which are summarized in Table 2.7. The estimates in Table 2.7 fall within a band from 2.3% to 2.6% which is approximately 0.5% lower than the estimates of the Company. In our view, the price-related component of the budget should therefore be based on 1993 price escalation of closer to 2.4-2.5%. Applied to the above costs, this would result in a reduction in revenue requirement of $42,145. In recognition that escalation does not necessarily apply to all of these costs, the revenue requirement will be reduced by $30,000.

Table 2.7 Forecast Consumer Price Index
Source	Applies to	Forecast 1993 CPI
Mr. Morrison, Company Witness	Canada	2.5%
Conference Board Economic Forecast, Spring 1993	Canada	2.4%
Conference Board Economic Forecast, Winter 1993	P.E.I.	2.3%
Royal Bank Econoscope, February 1993	Canada	2.6%

The 1993 budget of Maritime Electric includes $70,000 for donations. According to the Company, the donations are targeted at 0.5% of pre-tax income and are made in accordance with their Policy for Charitable Donations which was filed along with draft revisions. The Commission has traditionally allowed the Company to include Charitable Donations in its operating expenses but considers this allowance open to periodic review.

During this proceeding, the Commission felt that the treatment of charitable donations was in need of further review. The focus of the review was on whether the customers of a monopoly should be required to support, through their electricity rates, the various organizations selected by the Company. The position of the Company can be summarized as follows:

The Commission does not consider the amount budgeted for donations to be either extravagant or unreasonable for a Company the size of Maritime Electric. Our concern is primarily with whether donations should be included in operating expenses. If the Company were operating in a competitive environment, we believe that the public would view donations as being made by the owners—that is the shareholders—of the Company. We believe this is also the public's view in the case of Maritime Electric when, in fact, each customer is effectively donating, through his electricity charges, to the causes Maritime Electric chooses to support. The Commission does not, therefore, consider the situation to be the same as if the Company were operating in a competitive environment.

In terms of corporate image, the Company's arguments regarding benefits to customers also apply to the owners of the Company, yet the costs are paid by the customers. In the Commission's view, it is not reasonable for the customers to pay all of the costs through operating expenses for donations which also benefit the shareholders—who do not share in the cost. We will therefore, as an interim measure, reduce operating expenses by $35,000—half of the donations budget—on the basis that the shareholders are expected to share at least equally in the cost. The treatment of donations will be reviewed again when the Company is next before us for a general rate review.

To the extent that charitable donations made out of earnings result in tax benefits, these benefits will also be considered to accrue to the shareholders of the Company.

Capital charges generally include depreciation and financing costs which include interest, preferred dividends, return on common equity and the associated income taxes. Each cost is discussed briefly in the following sections.

The depreciation rates of the Company are reviewed periodically through a detailed depreciation study. The study involves examination of the most current data available on the useful life of assets, the appropriate salvage values and other parameters. The result is a periodic evaluation of whether fixed assets are being appropriately charged to the customers who benefit from their use.

As part of its application, the Company filed its 1991 Depreciation Study based on its plant-in-service at December 31, 1990. The proposed changes in Rates of Depreciation are summarized in Table 2.8.

Table 2.8 Existing and Proposed Depreciation Rates
	Existing Rate %	Proposed Rate %
Charlottetown Steam Plant	2.8	3.0
Borden Gas Turbines	3.8	3.8
Dalhousie Thermal Plant	3.8	3.6
Maritime Interconnection	2.9	2.8
Substation	3.7	3.3
Transmission	2.3	2.3
City Distribution	3.5	3.2
Rural Distribution	3.8	3.9
Transportation	9.0	7.5
Communications & Control	6.4	5.8
Supervisory System	10.0	8.3
Buildings	2.9	3.2
Computer Hardware & Software	7.9	13.8
Other General Property	7.9	3.9
Canelco Acquisition Adjustment	3.8	n/a

The corresponding composite rates of depreciation using 1993 data are 3.63% under existing rates and 3.59% under the proposed rates.

During the hearing, some concern was expressed over the increase in negative salvage value on the rural poles and fixtures from negative (-) 20% in 1985 to negative (-) 40% in the current study which has the effect of increasing depreciation by approximately $100,000. While a downwards trend in salvage value is clearly indicated, it is unclear whether this is an indicator of future expectations or, for example, a result of a distribution system built up largely in the 1950's and 1960's reaching the end of its useful life, a decade of historically high inflation or other related factors. In the absence of evidence to the contrary, however, the Company's estimates are accepted.

The depreciation study also indicates that the accumulated depreciation accounts are $611,694 lower than indicated by the theoretical or estimated amounts. The Company plans to recover this difference by charging $203,898 per year to revenue requirement over three years in a manner consistent with previous Orders of the Commission. The Company further proposes that the difference not be collected on the basis that the estimates are within one percent which is acceptable since the depreciation study is judgmental and therefore imprecise. Company witness Mr. O'Reilly did not believe that any adjustment should be made as long as the study estimate was within 5% of the book value.

The allowable range of +5% would imply that no adjustment is made until the difference between theoretical and book value is approximately $3 million. The Commission believes that allowing the difference to accumulate to such a level is clearly unnecessary and would result in a significant impact on rates. If the current difference of 1% is accepted, then it is possible that future estimates will narrow the difference; however, it is also possible that the difference will continue to widen, which ultimately would result in an even greater adjustment. The Commission believes that, when the Company prepares revised estimates—as it has in this case—it should aim to move towards those new estimates. We believe that this will result in greater stability of rates.

The Commission also believes that the adjustment should be made over a reasonable period. In this case, an appropriate period would appear to be the time between depreciation studies—when the estimates are reviewed—or approximately 5 years.

The Commission further believes that the issue of adjusting book to theoretical values may be better resolved in the future by adopting a straight line-remaining life method of depreciation in which the objective is to depreciate the remaining net book value of the assets over their estimated remaining life. This should have the effect of adjusting for changes in estimates over the remaining life of the assets and could be viewed as further improving rate stability. This alternative is to be considered when the next depreciation study is prepared.

Interest expense on long-term and bank debt is typically flowed through, in the case of long-term debt, as a cost which is effectively approved when the debt issue is approved. The interest and related costs of financing included in revenue requirement are summarized in Table 2.9.

The Company reported an error of $49,050 in the calculation of interest on long-term debt. This results in a reduction of $49,402 in revenue requirement, based on Company estimates. Interest on long-term debt also includes estimated interest on a new $10 million, 10.25% bond issue proposed for November, 1993. Based on published yields of current Canadian corporate bonds in the range of 7.5-9.4% (The Globe and Mail, Wednesday, May 26, 1993), the estimated yield for Maritime Electric appears to be somewhat high; however, no adjustment is considered warranted given the uncertainty in interest rates and the relatively small impact on the 1993 revenue requirement.

The Company forecasts its short term borrowing costs based on a prime rate of 7.25%. Current rates are closer to 6% and forecasts for 1993 by the Conference Board and the Royal Bank are closer to 6.5%. According to Company witness Mr. Hughes, a 100 basis point change in prime rate equates to an $18,000 change in revenue requirement. Given the overall operating expenses of the Company, the interest expense budgeted by the Company is considered to be within a range that can be considered reasonable.

Table 2.9 Interest and Related Charges
	As Filed April 19, 1993	Adjustments	Approved by Commission
Interest on Long-Term Debt	$ 5,558,888	($ 49,050)	$ 5,509,838
Interest on Bank Loan	140,347	(352)	139,995
Interest During Construction	(650,000)		(650,000)
Amortization of Financing Costs	68,029		68,029
Discount on Bonds & Shares	(3,000)		(3,000)
Total	$ 5,114,264	($ 49,402)	$ 5,064,862

Income taxes have historically been included in revenue requirement using the deferral method which results in the collection through rates of both actual taxes due and deferred income taxes. For 1993, the budgeted amounts are $6,105,402 and $569,422, respectively.

Deferred taxes represent an amount which is theoretically due to government out of accounting income, but which is not payable to government in the base year because of differences between accounting income and income for taxation purposes. In a regulated company, the result is collection of revenues from customers in excess of those necessary to meet current and past expenditures. In effect, the rate payers "contribute" funds to the Company which are used to finance capital programs in place of debt and preferred and common shares.

The tax policy used by Maritime Electric has been in place for many years. The Commission believes that it is in need of review to ensure that the policy is still in the best interests of the Company and its customers. We prefer, however, to carry out a preliminary review to identify the major issues and the potential impact of a change in policy on customers before initiating a process which could be very costly to all parties. We welcome the Company's suggestions on how such a review might be conducted to be both effective and economical.

Preferred dividends, like interest, are effectively approved at the time of issue. There being no attractive opportunity to refinance at a lower cost or plans for new issues at the time of the hearing, the budgeted dividends on preferred shares outstanding in 1993 of $1,271,400 will be approved.

In Order UE92-17, the Commission approved a maximum return on common equity of 13.0% for Maritime Electric. No new evidence was presented at the hearing nor have economic or other conditions changed to make the Commission believe that this maximum is unreasonable.

At issue in this hearing is whether rates should be set to yield exactly 13.0% or, for example, at a lower level to provide an incentive to the Company to improve efficiency. For most of the past decade, the Company's rate of return has been based on a range with rates set at the midpoint of the range or 1/4-1/2% below the allowed maximum. In fact, at the last General Rate Hearing, the Company proposed a range of 13.5%-14.25% with rates set at 13.75% to

The Company now proposes that the range, at least for the current application, be eliminated and that rates be set at the 13.0% level based on the following principal arguments:

1. The Company has implemented a bare-bones budget and does not have the same opportunities to reduce costs as in previous years; and,

2. The Company is going into a year (1994) of unusually high capital expenditures and setting its rates at a level below that forecast to yield the maximum return could increase the risk of earning below an acceptable level during a period when its financing requirements are high.

The Company's reference to a "bare-bones" budget refers to its holding "controllable" operating expenses to approximately the same level as in 1992. It appears that these expenses would also be approximately equal to 1991 levels, despite inflationary pressures on certain costs. Given the pressures on all sectors of the economy to deliver improved services using the same or fewer resources, the Commission believes that this effort should be regarded as the norm and not the extraordinary measure suggested by the Company. Nor do we believe that the Company's efforts eliminate its budget flexibility. Indeed, Company President and Chief Executive Officer, Mr. Reynolds indicated that there were likely further efficiency improvements that could be identified and implemented even with what the Company considers to be a tight budget. Finally, the Commission believes that there is flexibility in certain of the costs discussed herein.

The Commission has been aware of the Company's anticipated financing requirements for some time. We do not, however, believe that high financing requirements provide justification for setting rates higher than necessary to provide a reasonable return. Nor do we believe that setting rates to provide management with an incentive to further improve efficiencies subjects the Company to unreasonable risks. The Commission has never believed that allowing a rate of return above that at which rates were set should guarantee that the Company will earn such a return, yet the Company has consistently earned the maximum and had excess revenues for a number of years, even when sales were somewhat below target. We do not believe that maintaining a range for rate of return consistent with past practice is unreasonable or places the Company at significant risk.

In conclusion, the Commission believes that a range of rate of return of 12.5-13.0% is just and reasonable and that rates should be set to yield the mid-point of the range, 12.75%. In the view of the Commission, this will result in rates as low as possible while allowing the Company to earn up to a maximum of 13.0% if it can demonstrate further efficiency improvements.

The Company requests approval of its rate bases for the years ending December 31, 1990, 1991 and 1992 as summarized in Appendix 1. The Company's filing differs from their financial statements as follows:

1. Deferred income taxes in the rate base calculation are $524,171 lower than reported on the financial statements. This balance relates to the Fredericton, New Brunswick assets which were disposed of in 1969 and, according to the Company, represents a permanent exclusion from rate base. No adjustment is necessary.

2. Deferred income in 1990 was recorded on a net-of-tax basis which appears to be inconsistent with other years. Based on correspondence with the Company, this amount has been adjusted to correspond with the financial statement balances.

3. The component of working capital related to income taxes also differs in 1990 and 1991 from calculations made directly from the financial statements as a result of refunds of taxes from prior years. While the Company does not consider it necessary to make the adjustment which is relatively minor, we believe that the adjustment should be made to provide consistency with the Company's financial statements. The rate base has been adjusted accordingly based on the information provided by the Company.

The rate base calculation reflecting these adjustments is included in Appendix 2.

In responding to questions related to the last adjustment above, the Company made the following comment:

The Company appears to be indicating by this comment and by other references that have been made over the years that the Rate Base calculation is a residual calculation and not of primary importance. While the approach of the Commission on rate of return has, for practical purposes, moved away from an emphasis on Rate Base, we remain aware of our statutory responsibility to determine a rate of return on Rate Base and so disagree with the Company's position. At the same time, we believe the method for determining the Rate Base could be improved. For example, working capital is now determined based on a hypothetical calculation rather than the actual needs of the Company. In addition, the Company has certain fixed assets—deferred charges for example—which are not included in Rate Base or approved by the Commission but which the Company must finance. The Company is therefore implicitly earning a rate of return (interest, dividends, etc.) associated with these assets.

The Commission wishes to review the implications of modifying the Rate Base calculation to more accurately reflect the actual capitalization of the Company and therefore the capital on which the Company is entitled to earn a rate of return. An example of the calculation of the rate base which might achieve this goal is given in Appendix 3. We are open to the Company's comments on the proposed modifications to the Rate Base calculation. We plan, if appropriate, to have changes implemented for future Rate Base confirmations.

Table 2.10 summarizes the forecast capitalization and rate of return for 1993 as determined and adopted herein.

Table 2.10 Forecast Capitalization and Rate of Return for 1993
	Ratio	Average Cost	Weighted Cost
Long-term Debt	43.7%	10.87%	4.75%
Preferred Equity	12.5%	8.48%	1.06%
Common Equity	43.8%	12.5-13.0%	5.48-5.69%
	100.0%		11.29-11.50%

These returns equate to a rate of return on average forecast rate base for 1993 of 10.74% to 10.94%.

The adjustments to revenue requirement ordered herein are shown in Appendix 4 and summarized in Table 2.11 which follows:

Table 2.11 Revenue Requirement Summary, 1993
	As Per Application	Commission Adjustments	Approved
OPERATING EXPENSES
ECAM	29,222,000	0	29,222,000
Non-ECAM	26,635,900	(165,000)	26,470,900
	55,857,900	(165,000)	55,692,900
CAPITAL RELATED CHARGES
Depreciation	6,656,719	0	6,656,719
Depreciation-Adjustment	203,898	(81,559)	122,339
Interest-Long Term Debt	5,558,888	(49,050)	5,509,838
Interest-Bank Loan	140,347	(352)	139,995
Interest-AFUDC	(650,000)	0	(650,000)
Interest-Amort. of Financing Costs	68,029	0	68,029
Interest-Disc. on Bonds and Shares	(3,000)	0	(3,000)
Income Tax-Current	6,105,402	(108,207)	5,997,195
Income Tax-Deferred	569,422	0	569,422
Preferred Dividends	1,271,400	0	1,271,400
Return on Common Equity	6,825,792	(131,265)	6,694,527
	26,746,897	(370,433)	26,376,464
REVENUE REQUIREMENT	82,604,797	(535,433)	82,069,364
Fuel Clause Revenue	(244,981)	0	(244,981)
Deferred ECAM	2,570,781	0	2,570,781
Other Revenue	(508,000)	0	(508,000)
BASIC RATE REVENUE	84,422,597	(535,433)	83,887,164

The Tariff of Maritime Electric establishes the rates to be charged to each customer class and effectively determines the amount of the Company's total costs that are to be recovered from each customer group. The allocation of costs is determined largely by a detailed rate calculation for the Town of Summerside, Transmission Voltage and Large General Service (Interruptible) rates and from the forecast Cost Allocation Study for the remaining classes. Historically, rate movements have been limited to prevent "rate shock" or "rate instability" to any customer class.

In the current application, the Company proposes only one major change to its established rate methodology which is a change to the calculation of the interruptible credit discussed in Section 3.3. Interveners raised a number of issues which are discussed in Section 3.4.

The Cost Allocation Study (the "Study") provides a detailed estimate of the fully allocated cost of serving each customer class in comparison with the revenues received from that class. In recent years, the Company has been required to file a forecast Study for the target year. The current Study includes a modification to forecast revenues based on the rates proposed by the Company in contrast to past years when the existing rates were used (with necessary adjustments). In order to fully understand the proposals of the Company, the Commission has found it useful to adjust the Study results to estimated 1993 revenues prior to the adjustments to move the revenue/cost ratio towards unity. The resulting changes are shown in Table 3.1.

Table 3.1 indicates that the Company, through its rate proposals, is attempting to move most rate classes towards a revenue-cost ratio of unity. While this complies with directions given by the Commission, the movement is in certain cases at a slower rate than we consider appropriate. We will comment further in the sections that follow.

The Large General Service (Int.) class is the only class that is moving significantly away from a revenue-cost ratio of one. According to the Company, this apparent discrepancy results from a difference in methodologies which will be eliminated when Rate Areas are phased out. The Commission accepts the detailed rate calculation as being the more appropriate for this customer class.

Table 3.1 Revenue to Cost Ratios Based on the Average and Excess Demand Methodology
	Revenue as	Proposed	Revenue
	% of Cost	Rate	as % of
	Before Rate	Increase	Cost
	Adjustments (1)	(Ex. M-24)	(Ex. M-22)
Residential	97.1%	2.5%	97.3%
Small General Service	100.6%	2.0%	100.5%
Street and Yard Lights	106.9%	1.0%	106.2%
	98.3%		98.4%

Large General Service (Firm)	104.3%	1.6%	104.0%
Large General Service (Int.)	105.2%	3.1%	106.0%
All Electric General Service	100.4%	2.3%	100.5%
Industrial	98.1%	2.8%	98.6%
Flat Rate	104.5%	1.0%	103.4%
Transmission Voltage	105.6%	1.0%	104.8%
Town of Summerside	106.1%	1.0%	105.3%
	104.3%		103.9%
	100.1%		100.0%

(1) Adjusted to reflect rate increase of 2.1% effective May 1, 1993 for each class.

The detailed rate design of the Company has attracted a fair degree of scrutiny over the years, particularly with respect to how rates are established for interruptible customers. The Company has proposed only one significant change to the established methodology which involves a shift in the calculation of the interruptible credit from the transmission output level to the transmission input level. According to the Company, this change equates interruptible capacity with generation and has the overall effect of reducing the interruptible credit from $1,442,196 to $1,367,177. The interveners did not comment on this change and it appears to the Commission to be consistent with the intent of the approved methodology.

The Town of Summerside claimed that there was an inconsistency in the calculation of their rate related to the impact of the new Goods and Services Tax Centre on their demand. The Company subsequently filed a letter addressing the Town's concern and undertaking to adjust the calculation when final rates are determined. We believe this should address the issue raised by Summerside.

No other issues with respect to the detailed rate design were brought to the attention of the Commission.

The focus of the interventions of the Town of Summerside and Cavendish Farms were on issues related primarily to rates.

The Town's intervention focused on the Commission's requirement that the movement in rates for any class of customers be limited to within the range from 0.5 to 1.5 times the general rate increase: in this application a range from 1.0% to 3.1%. The impact of this rule on the Town is to limit the movement in their estimated total bill from $5,135,987 under their existing rates to $5,188,452 (the lower limit). For comparison, the detailed rate calculation indicates a total bill of $4,863,387. The Town therefore believes that it is paying too high a proportion of Maritime Electric's costs.

The Town proposed a number of mechanisms for determining what it believes to be a more equitable rate. The effect of all of the proposals would be to modify or eliminate the restriction on downward movement of rates. The Town submits that while there may be good reason to have an upper limit on rates to alleviate rate shock, a lower limit is not necessary.

After reviewing all of the evidence and arguments, the Commission continues to believe that limiting rate movement using the 0.5 to 1.5 times rule is an appropriate method for achieving rate stability and avoiding rate shock. It is clear that, where upwards movement is to be limited, there must also be a limit on rates targeted for a reduction, albeit the limits may be different depending on the sizes of the various customer classes. We also believe that a revenue-cost ratio of one for each rate class is a reasonable target but not a target that is defined with precision. As with any target whose derivation is based on a large degree of judgment, it is prudent to use it as a guide to directional rather than absolute movement. To do otherwise could increase both rate instability and rate shock if the target moves as new estimates are made.

The Commission does, however, on a case by case basis deviate from the 0.5 to 1.5 times rule in order to adjust rates which appear to be unreasonably high or low. In this case, the detailed rate calculation indicates that the Street Lighting, Transmission Voltage and Town of Summerside rates should all be reduced, yet the 0.5 times limit results in them being increased. We believe that this effect occurs, in part, because we are looking at a relatively small rate increase and therefore a narrow band within which to adjust rates. We therefore believe that it is reasonable to deviate from our general rule limiting rates and to determine the rates for the above classes based on a 0% increase. This will, we believe, move them closer to the cost of service while not unduly affecting other customer classes.

2. That the existing demand charge of $7.62 per kVa be maintained and the proposed usage charge be reduced to 4.639 cents per kWh (the new rate proposed);

4. That Maritime Electric contribute to the Demand Side Management activities of Cavendish Farms.

Cavendish Farms is currently served under the Transmission Voltage rate. This class includes a small number of large customers who, according to Maritime Electric, have load characteristics similar to Cavendish Farms. New customer classes are normally established only when the load characteristics of one or more customers are sufficiently distinct from those in existing classes. We have not seen evidence to indicate that this is the case for Cavendish Farms and do not, therefore, consider a new class to be justified.

The rate proposal of Cavendish Farms in effect proposes that they be charged the lowest of the existing and proposed energy and demand charges. The fact that one charge is increasing while the other is decreasing results from the Company rebalancing the energy and demand charges of its customers to more closely match costs. It is not possible to select the more favourable of each and still cover the cost of service. We cannot, therefore, accept Cavendish Farm's proposal.

Placing a cap on the ECAM might be acceptable in the short-term only if the Company remained able to recover its cost of service in the long-term. The Commission did not understand Cavendish Farms to be objecting to paying its cost of service but rather to prefer rates that were more predictable. The Commission does not see any reason why Cavendish Farms could not pursue with the Company a mechanism similar to a level billing mechanism to stabilize rates. Should Cavendish Farms wish to pursue such an option, it should approach the Company.

The Commission has already directed the Company to review its Demand Side Management programs and file a report with the Commission later this year. We believe that the DSM proposals of Cavendish Farms might best be incorporated into that process.

In the February application, the Company proposed a 2.1% increase in basic rates to be effective May 1, 1993. This was subsequently revised to 1.9% based on first quarter sales and 1.8% to adjust for an inconsistency in the calculation of interest expense. The effect of the final increase is to increase revenues from Basic Rates by $960,586 over the last eight months of 1993. Based on the adjustments made herein, the objective for the rates to be effective July 1, 1993 is to recover approximately an additional $474,555 over the second half of 1993 for a rate increase of approximately 1.1%. The actual increase in rates to individual customer classes will also reflect movements towards the cost of service and uniform rates.

The next step in the movement towards uniform City/Town/Rural rates is scheduled for rates effective August 1, 1993. The Company proposes to incorporate this adjustment in the new rates to be effective July 1, 1992 and the Commission agrees with this proposal.

The Company has, for a number of years, filed a summary of productivity studies with the Commission and commented that they show an irregular but generally downward trend in total corporate input costs. The supporting evidence indicates that the Energy Source and Transmission costs have declined from more than $0.09/kWh (1991$) in the 1970's to slightly more than $0.07/kWh in recent years. These costs are, in many respects, beyond the control of the Company and are based in large part on oil and other energy prices.

The costs which are more directly controllable by management, Distribution and General & Administration, show little if any improvement since the early 1970's. The Commission therefore finds it difficult to conclude from the study that productivity gains have been made. Indeed, the fact that the Company is distributing power today for the same cost (after adjusting for inflation) that it was 20 years ago might be viewed as poor performance in comparison with other sectors of our economy. While it is possible that the province is now supplied with more reliable power at the same price, the Commission believes the Productivity Study needs some modification if it is to provide an indicator for improved performance as the Company suggests.

During the hearing, Mr. Reynolds expressed the Company's interest in carrying out a study to evaluate Demand Side Management (DSM) incentives. Such incentives might be viewed as a mechanism to reduce the perceived risk of investing in sales reduction activities or to increase the Company's emphasis on DSM. The Company did not, however, wish to commence such a study without first having some direction from the Commission.

The current literature on DSM incentives tends to focus on two general areas: mechanisms to provide an investment incentive and mechanisms to recover revenues lost as a result of DSM programs. Maritime Electric is currently allowed an investment incentive to the extent that DSM costs are included in rate base and therefore earn a return comparable to any other investment made by the Company. Whether this return should be higher (lower), for example through a bonus (penalty) mechanism, is a complex issue and should possibly be viewed from the perspective of providing different returns for all investments (generation, transmission, distribution, etc.) based on their risk and other characteristics. In terms of revenue recovery, Maritime Electric also effectively receives some adjustment through the setting of rates based on sales net of estimated DSM effects.

With the treatment of DSM costs now in effect, the Commission is of the view that further incentives would be of limited benefit to the Company or its customers. We also believe that it would be premature to study incentives further at this time when the Company is in the process of evaluating its overall DSM program. Once this evaluation is complete and the full potential for load reduction through DSM is identified, we may wish to reevaluate our position.

The Commission is open to considering other forms of incentive regulation. We have continued to encourage the Company to improve the level, quality and value of service that it provides and believe that continuing improvements can be encouraged through appropriate incentives. Our reservations occur, in part, because we have not had reasonable indicators with which to assess the performance of the Company. In the absence of such indicators, it is difficult to judge, first, whether service has actually improved and, then, whether the improvement will continue to be realized on a long-term basis. It is our view that such indicators must be established to provide a baseline before we can reasonably assess whether the Company has achieved improved performance. This might then permit us to allow, as prudent and reasonable, costs associated with performance incentives. We are, however, open to considering proposals that the Company might wish to make in this area.

If the proposed Tariff is acceptable to the Commission, a further Order will be issued approving and declaring the Tariff effective on July 1, 1993.

WHEREAS Maritime Electric Company, Limited (the "Company") by application dated September 14, 1992, applied to the Commission for an order or orders of the Commission approving a number of amendments to the Company's General Tariff;

AND WHEREAS the Commission issued Order UE92-17, dated herein December 21, 1992, establishing a maximum rate of return on average common equity;

AND WHEREAS the Company filed an amended application on February 16, 1993 revising its budget for operating expenses and other components of the application;

AND WHEREAS the Commission has heard and considered the evidence of the Company and the submissions of the interveners at public hearings conducted in Charlottetown during November 1992, and April 1993 after due public notice;

AND WHEREAS the Commission has issued its findings in this matter in accordance with the Reasons for Order issued with this Order;

NOW THEREFORE, pursuant to the Island Regulatory and Appeals Commission Act and the Electric Power and Telephone Act

Appendix 1
Rate Base Calculation as Proposed by Maritime Electric.
	1989	1990	1991	1992	1993
	$	$	$	$	$
Plant in Service
Plant in Service - Closing Balance	146,434,000	155,664,236	176,384,713	187,276,596	201,761,667
Less: Accumulated Depreciation	(49,373,500)	(53,469,539)	(58,433,545)	(63,746,339)	(69,630,425)
	97,060,500	102,194,697	117,951,168	123,530,257	132,131,242
Plus: Unamortized DSM	0	214,593	540,827	779,863	1,294,863
Less: Unamortized Contributions	(7,543,497)	(7,987,424)	(8,578,238)	(8,791,457)	(8,564,487)
Less: Deferred Income Tax	(7,640,186)	(8,743,582)	(9,128,046)	(10,324,975)	(10,894,397)
	81,876,817	85,678,284	100,785,711	105,193,688	113,967,221
Plus: Working Capital
Material and Supplies at Cost	3,276,829	4,087,528	3,013,019	3,092,648	3,659,000
12.5% of Operating Expenses	5,745,998	6,402,262	6,310,763	6,983,961	6,982,238
12.5% of Income Taxes Paid	391,517	665,505	597,522	688,415	685,867
Deferred Income	(845,687)	441,087	(1,092,664)	800,757	(1,770,024)
	8,568,657	11,596,382	8,828,640	11,565,781	9,557,081
Rate Base - Year End	90,445,474	97,274,666	109,614,351	116,759,469	123,524,302

Rate Base - Average	85,110,000	93,860,070	103,444,509	113,186,910	120,141,886


Appendix 2
Rate Base Calculation as Adjusted and Approved by the Commission.
	1989	1990	1991	1992	1993
	$	$	$	$	$
Plant in Service
Plant in Service - Closing Balance	146,434,000	155,664,236	176,384,713	187,276,596	201,761,667
Less: Accumulated Depreciation	(49,373,500)	(53,469,539)	(58,433,545)	(63,746,339)	(69,630,425)
	97,060,500	102,194,697	117,951,168	123,530,257	132,131,242
Plus: Unamortized DSM	0	214,593	540,827	779,863	1,294,863
Less: Unamortized Contributions	(7,543,497)	(7,987,424)	(8,578,238)	(8,791,457)	(8,564,487)
Less: Deferred Income Tax	(7,640,186)	(8,743,582)	(9,128,046)	(10,324,975)	(10,894,397)
	81,876,817	85,678,284	100,785,711	105,193,688	113,967,221
Plus: Working Capital
Material and Supplies at Cost	3,276,829	4,087,528	3,013,019	3,092,648	3,659,000
12.5% of Operating Expenses	5,745,998	6,402,262	6,310,763	6,983,961	6,982,238
12.5% of Income Taxes Paid	359,530	640,274	597,522	688,415	685,867
Deferred Income	(845,687)	785,411	(1,092,664)	800,757	(1,770,024)
	8,536,670	11,915,475	8,828,640	11,565,781	9,557,081
Rate Base - Year End	90,413,487	97,593,759	109,614,351	116,759,469	123,524,302

Rate Base - Average		94,003,623	103,604,055	113,186,910	120,141,886


Appendix 3
Proposed Revision of Rate Base Calculation.
	1989	1990	1991	1992	1993
	$	$	$	$	$
Plant in Service
Plant in Service - Closing Balance	146,434,000	155,664,236	176,384,713	187,276,596	201,761,667
Less: Accumulated Depreciation	(49,373,500)	(53,469,539)	(58,433,545)	(63,746,339)	(69,630,425)
	97,060,500	102,194,697	117,951,168	123,530,257	132,131,242
Plus:
Property Under Construction	3,419,005	10,482,338	5,035,351	6,398,071	3,000,000
Unamortized DSM	0	214,593	540,827	779,863	1,294,863
Unamortized Financing Costs	241,071	445,271	698,771	702,896	774,868
Unamortized Load Research Study	0	0	59,025	541,417	982,056
Unamortized Generation Studies	361,771	281,328	190,885	100,443	"
Unamortized Engineering Studies	492,277	251,919	318,563	364,828	"
Less:
Unamortized Contributions	(7,543,497)	(7,987,424)	(8,578,238)	(8,791,457)	(8,564,487)
Deferred Income Tax	(8,164,357)	(9,267,753)	(9,652,217)	(10,849,146)	(11,418,568)
	85,866,770	96,614,969	106,564,135	112,777,172	118,199,974
Plus: Working Capital
Current Assets	8,841,831	11,873,395	14,961,341	11,851,100	18,243,111
Less: Current Liabilities (Excl. LTD)	(22,603,153)	(14,875,487)	(11,184,850)	(10,834,805)	(11,030,397)
	(13,761,322)	(3,002,092)	3,776,491	1,016,295	7,212,714
Rate Base - Year End	72,105,448	93,612,877	110,340,626	113,793,467	125,412,688

Rate Base - Average		82,859,163	101,976,752	112,067,047	119,603,078

Common Equity and Retained Earnings	36,540,387	39,424,877	46,212,627	50,390,468	54,624,688
Preferred Shares	10,300,000	17,600,000	15,600,000	15,000,000	15,000,000
Long-term Debt	27,418,000	36,588,000	48,528,000	48,403,000	55,788,000
Property Pending Approval	(2,152,940)	0	0	0	0
	74,258,387	93,612,877	110,340,627	113,793,468	125,412,688

Appendix 4
Maritime Electric Revenue Requirement 1993
Account	As Per Application Sept. 1992	As Amended In Course of Hearing	As Revised by Application Feb. 1993	As Adjusted By Commission	Commission Approved
Sales (MWh)	708,000		711,000		711,000
ECAM
Power Purchases (M-1, M-24)	18,638,000	353,000	18,991,000	0	18,991,000
Point Lepreau Entitlement (M-1, M-24)	3,262,000	122,000	3,384,000	0	3,384,000
Dalhousie Plant (M-1, M-24)	4,628,000	(66,000)	4,562,000	0	4,562,000
Charlottetown Plant (M-1, M-24)	2,371,000	(301,000)	2,070,000	0	2,070,000
Borden Plant (M-1, M-24)	296,000	(81,000)	215,000	0	215,000

NON-ECAM
Production	13,550,000	(105,000)	13,445,000	(100,000)	13,345,000
Distribution	3,030,000	(189,000)	2,841,000	0	2,841,000
Transmission	343,000	(36,000)	307,000	0	307,000
General
Amortization	312,000	99,000	411,000	0	411,000
Donations	73,000	(3,000)	70,000	(35,000)	35,000
Other	9,740,000	(178,100)	9,561,900	(30,000)	9,531,900
	27,048,000 56,243,000	(412,100) (385,100)	26,635,900 55,857,900	(165,000) (165,000)	26,470,900 55,692,900
CAPITAL RELATED CHARGES
Depreciation	6,755,487	(98,768)	6,656,719	0	6,656,719
Depreciation - Adjustment	203,898	0	203,898	(81,559)	122,339
Interest - Long-Term Debt	5,388,055	170,833	5,558,888	(49,050)	5,509,838
Interest - Bank Loan	335,318	(194,971)	140,347	(352)	139,995
Interest - AFUDC	(650,000)	0	(650,000)	0	(650,000)
Interest - Amortization of Financing Costs	63,230	4,799	68,029	0	68,029
Interest - Discount on Bonds and Shares	(3,000)	0	(3,000)	0	(3,000)
Income Tax - Current	6,028,969	76,433	6,105,402	(108,207)	5,997,195
Income Tax - Deferred	428,973	140,449	569,422	0	569,422
Preferred Dividends	1,271,400	0	1,271,400	0	1,271,400
Return on Common Equity	6,771,275	54,517	6,825,792	(131,265)	6,694,527
	26,593,605	153,292	26,746,897	(370,433)	26,376,464
TOTAL REVENUE REQUIREMENT	82,836,605	(231,808)	82,604,797	(535,433)	82,069,364
Fuel Clause Revenue	(226,688)	(18,293)	(244,981)	0	(244,981)
Deferred ECAM	2,049,889	520,892	2,570,781	0	2,570,781
Other Revenue	(485,000)	(23,000)	(508,000)	0	(508,000)
REVENUE FROM BASIC RATES	84,174,806	247,791	84,422,597	(535,433)	83,887,164