Ontario Energy	Commission de l'Energie

Board	de l'Ontario

RP-1999-0031

IN THE MATTER OF APPLICATIONS BY

NATURAL RESOURCE GAS LIMITED

FOR FISCAL YEAR 2000 RATES

DECISION WITH REASONS

2000 MARCH 10

EXECUTIVE SUMMARY

This Decision addresses an Application by Natural Resources Gas Limited for a Board Order approving or fixing rates for the 2000 fiscal year commencing October 1, 1999. Based on the rates then in effect, the Company filed evidence indicating an overall 2000 revenue deficiency of $735,379 (prior to the increase in gas commodity charges approved on December 1, 1999).

On December 1, 1999, the Board issued a EB-1999-0483 Rate Order approving an increase of $0.033048 per m3 for increased commodity costs.

The Company and intervenors reached a comprehensive Settlement Agreement on the 2000 Revenue Requirement, which resulted in a revenue deficiency of $721,470.

The Board finds an overall fiscal 2000 revenue deficiency of $721,470. This revenue deficiency reflects a rate of return on common equity of 9.5% and a Rate Base of $8,825,149.

The Board believes that fully allocated costing is the appropriate method to segregate costs that are not directly assignable into those allocable to utility operations and those allocable to ancillary programs.

The Board will approve the new rate classes – Rate 4 and Rate 5 – on an interim basis for the 2000 fiscal year. The Board will also approve the proposed changes in Rates 1, 2, and 3. The Board agrees that revenue-to-cost ratios should be at or near one and accepts the revenue-to-cost ratios for 2000.

The Board accepts and approves the proposal in the Settlement Agreement with respect to the Company's application for exemption from certain provisions of the Affiliate Relationships Code for Gas Utilities.

The new rates are effective October 1, 1999. There will be a one-time adjustment to customers' bills to reflect an allowance for the rates not being increased as of the effective date of October 1, 1999. There will also be a one-time bill adjustment to reflect the disposition of the balance in the deferral accounts as agreed in the settlement conference.

RP-1999-0031

IN THE MATTER OF the Ontario Energy Board Act, S.O.1998, c. 15, Sched. B;

AND IN THE MATTER OF an Application by Natural Resource Gas Limited to the Ontario Energy Board for an order or orders approving or fixing just and reasonable rates for the sale, distribution and transmission of gas commencing October 1, 1999.

BEFORE:	F.A. Drozd

Presiding Member

J.B. Simon

Member

A.C. Spoel

Member

DECISION WITH REASONS

March 10, 2000

TABLE OF CONTENTS

1.	INTRODUCTION	1

1.1	The Proceeding	1

1.2	Appearances and Witnesses	3

1.3	Summary of the Company's Proposal	5

1.4	The Agreement	5

2.	ANCILLARY PROGRAMS	9

2.1	Cost of Ancillary Programs	9

2.2	Rate of return of Ancillary Programs	17

3.	RATE DESIGN AND COST ALLOCATION	19

3.1	Proposed Rates	21

3.2	Fixed Cost Recovery	35

3.3	Revenue-to-cost Ratios	38

3.4	Long-term Rate Objectives	40

4.	COMPLETION OF PROCEEDINGS AND COSTS	43

4.1	Summary of Board's Findings on Revenue Requirement for fiscal 2000	43

4.2	Completion of Proceedings	43

4.3	Costs	44

APPENDICES

Appendix A	-	Agreement Resulting from the Settlement Conference

and Addendum

Appendix B	-	Impact of the Board's Findings in this Decision

1.	INTRODUCTION

1.1	The Proceeding

1.1.1	Natural Resource Gas Limited ("NRG", the "Applicant", or the "Company") filed an Application with the Ontario Energy Board ("OEB"or the "Board") dated April 26, 1999 (the "Application") pursuant to section 36 of the Ontario Energy Board Act, S.O. 1998, c. 15, Sched. B (the "Act"), requesting an order or orders approving or fixing just and reasonable rates and other charges for the sale, distribution, transmission and storage of gas for the Company's 2000 fiscal year, which commenced on October 1, 1999 and ends on September 30, 2000. In addition, NRG, by way of a letter dated August 25, 1999, applied for an order exempting the Company from certain provisions of the Affiliate Relationships Code for Gas Utilities (the "Code"), which was made part of the same docket.

1.1.2	The Board issued a Notice of Application dated June 25, 1999 along with directions for service of the Notice.

1.1.3	On September 2, 1999, the Board issued Procedural Order No. 1, which specified dates for a technical conference at which a proposed issues list would be developed.

1.1.4	The technical conference was held at the Board's offices on September 14, 1999 to review NRG's prefiled evidence and to discuss the issues relevant to the hearing of the Application.

1.1.5	On September 22, 1999, the Board issued Procedural Order No. 2, which set out dates for the filing of interrogatories, submission of responses to these, a settlement conference and the submission of any agreement reached during that conference.

1.1.6	The Board issued an interim order (EB-1999-0469) on September 30, 1999 directing that the rates and other service charges approved for the fiscal 1999 year be declared interim, effective October 1, 1999, for a period of no longer than one year, and subject to change retroactive to that date.

1.1.7	As a result of the technical conference, Procedural Order No. 3, dated October 5, 1999 was issued listing the Board-approved issues for the proceeding, and setting dates for supplementary written interrogatories and the responses to these.

1.1.8	On October 7, 1999, NRG notified the Board that the Purchased Gas Variance Account ("PGVA") trigger amount of $20 per residential customer had been exceeded and applied for a gas cost increase. On December 1, 1999, the Board issued an order under docket number EB-1999-0483 approving an increase of $0.033048 per m3 for increased commodity costs.

1.1.9	The settlement conference was held by the parties to this proceeding at the Board's offices, beginning on November 8, 1999. A copy of the agreement negotiated between the Applicant, Board Staff and the Heating, Ventilation and Air Conditioning Contractors Coalition Inc. ("HVAC Coalition") was transmitted to the Board Secretary under cover dated November 15, 1999 (the "Agreement").

1.1.10	Procedural Order No. 4, dated November 23, 1999 set December 6, 1999 as the date for commencement of the hearing.

1.1.11	The hearing of the oral evidence began on Monday December 6, 1999 and concluded on Tuesday, December 7, 1999 with a summary of the issues by Board Staff's Counsel.

1.1.12	The Company's Argument-in-Chief was filed on December 15, 1999; the HVAC Coalition filed its Argument on December 20, 1999; and NRG filed its Reply Argument on December 22, 1999. Copies of all the evidence, exhibits and submissions in this proceeding, together with a verbatim transcript of the hearing, are available for public review at the Board's offices.

1.2	Appearances and Witnesses

1.2.1	The participants and their representatives were:

NRG	Peter Budd

Erik Goldsilver

Board Staff	Jennifer Lea

HVAC Coalition	Ian Mondrow

1.2.2	Although not an active participant, Enbridge Consumers Gas ("Enbridge") intervened and was represented by Barbara Bodnar.

1.2.3	Union Gas Limited ("Union") was also registered as an intervenor but did not participate.

1.2.4	Because of the absence of other intervenors, Board Staff took an active role in the proceedings.

1.2.5	Counsel to NRG called W. Blake, the Company's President and General Manager, S. McCallum, the Company's Financial Manager, and R. Aiken, a Principal with Aiken and Associates, as witnesses to testify on behalf of the Company.

1.2.6	Neither HVAC Coalition nor Board Staff called any witnesses.

1.3	Summary of the Company's Proposal

1.3.1	The Applicant's updated prefiled evidence, as of September 21, 1999 (prior to the interim rate increase approved December 1, 1999) was:

Fiscal 2000
Rate Base	$8,909,800
Overall Rate of Return on Rate Base	10.22%
Return on Common Equity	9.50%
Cost of Capital	$910,582
Cost of Service	$5,967,658
Gas Sales Revenue (at existing rates)	$5,911,521
Other Operating Revenue (net)	$494,285
Income Taxes	$296,126
Gross Revenue Deficiency (including income taxes)	$735,379
Note: These figures do not include the impact of the increase in gas commodity charges approved on December 1, 1999.

1.3.2	The rate increase approved on December 1, 1999 resulting from the change in gas commodity rates substantially reduced the gross revenue deficiency shown above.

1.4	The Agreement

1.4.1	The settlement conference was attended by NRG, Board Staff and counsel for the HVAC Coalition. The Agreement was drafted by NRG's counsel in consultation with the parties.

1.4.2	At the start of the oral hearing, the Presiding Member asked the parties to provide additional references to NRG's prefiled evidence and to the interrogatories, as well as a rationale for all issues covered by the Agreement. This additional material was provided in two addenda, supplemented by the oral evidence of NRG's witnesses.

1.4.3	Appendix A to this Decision includes the revised Agreement and an addendum, one providing rationale for the agreed positions and the second providing references.

1.4.4	Twenty-five of the total of 36 major issues were settled, subject to the Board's approval, leaving 11 unresolved in part or in total. Issues on which no agreement was reached during the settlement conference were:

•	C.5	Other Operating Revenue

•	C.6	Rate of Return on Ancillary Programs

•	G.1.4	Revenue to Cost Ratios

•	G.2	Fall Peaking Load Study

•	H.1	Proposed Rate 1 Changes

•	H.2	Proposed Rate 2 Changes

•	H.3	Proposed Rate 3 Changes

•	H.4	Proposed New Rates 4 and 5 for Fall Peaking Service

•	H.6	Long-term Proposals

•	H.7	Fixed Cost Recovery

•	H.8	Seasonal Load Study

Board Findings

1.4.5	Although the panel believes that the parties should have provided a more complete description of the rationale for the agreed upon positions, the panel is satisfied that the Agreement, supplemented by the addenda, is sufficient for the Board's purposes. The Board therefore accepts and approves the Agreement.

1.4.6	The Agreement had the following effect on the Applicant's pre-filed evidence (as described in paragraph 1.3.1):

Fiscal 2000
Rate Base	$8,825,149
Overall Rate of Return on Rate Base	10.23%
Return on Common Equity	9.50%
Cost of Capital	$903,080
Cost of Service	$5,957,777
Gas Sales Revenue (at existing rates)	$5,909,931
Other Operating Revenue (net)	$494,285
Income Taxes	$289,920
Gross Revenue Deficiency (including income taxes)	$721,470
Note: These figures do not include the impact of the increase in gas commodity charges approved on December 1, 1999.

2.	ANCILLARY PROGRAMS

2.0.1	The issues discussed in this Chapter relate to whether the costs of ancillary programs are properly accounted for and whether the ancillary programs are being subsidized by the gas utility business. These issues are relevant to the determination of item C.5 - other operating revenue and item C.6 - rate of return on ancillary programs on the Issues List.

2.1	Cost of Ancillary Programs

2.1.1	Three components of the cost of ancillary programs were raised as issues by the parties:

•	the costing methodology used by NRG;

•	whether the appropriate costs had been allocated to ancillary programs and therefore whether the other operating revenues and rates of return on ancillary programs were properly stated; and

•	whether income tax costs included in the costs of ancillary programs should be calculated by the taxes payable or deferred method.

NRG's Evidence

2.1.2	NRG described its Water Heater Rental Program, Contract Work Program, Service Work Program and Merchandise Sales as "Ancillary programs" and stated that these were seen "as an important part of our business and service to our customers." The Company stated that it does not perceive these areas of its business to be growing, because there are fewer people in the organization and a single sub-contractor with only one employee doing installations. NRG also said that the Company was not actively trying to expand that side of its business.

2.1.3	Pre-filed evidence indicated that members of the HVAC Coalition compete with NRG in all of these areas. NRG's witnesses testified, however, that competition in the Water Heater Rental Program is minimal.

2.1.4	NRG assigned the costs associated with these programs directly (direct costs) and allocates non-direct costs on a marginal cost basis. NRG's definition of marginal costs was "those that would be eliminated if a program were not run".

2.1.5	Among the costs directly assigned to ancillary programs were income taxes, calculated on a flow-through or taxes payable basis.

2.1.6	Pursuant to Board directions contained in EBRO 496 to prepare a "Fully Allocated Cost" ("FAC") study, the Company reviewed the costs incurred to determine if there were additional costs that should be allocated to the ancillary programs.

2.1.7	The FAC study resulted in the additional allocation to ancillary services of the all of the costs that the Company considered to be allocable costs, except automotive and depreciation expense, which decreased. The additional allocation amounted to $35,324.

2.1.8	Regulatory costs, billing service costs, directors' and officers' liability insurance premiums, depreciation expenses on computers, and secondary support activities such as payroll processing, office rent, legal costs, and capital asset allocations with respect to computers and machinery and equipment were not allocated to the ancillary programs. NRG's evidence was that in some cases these items were not required or used in support of the ancillary programs (e.g. office rent on the London office, legal costs), were insignificant (e.g. payroll processing), or added no extra cost beyond that incurred by the utility business (eg. directors' and officers' liability insurance premiums).

2.1.9	Under cross-examination, Mr. Blake conceded that some portion of office supplies and postage did relate to the Water Heater Rental Program billing and should be allocated to this program, but neither a percentage of revenue basis or a Full Time Equivalent basis would be an appropriate allocation driver.

Positions of the Parties

Costing Methodology

2.1.10	The HVAC Coalition's position was that NRG's ancillary programs were benefitting from an unfair competitive advantage in the marketplace because insufficient costs had been allocated to these programs thus allowing NRG to charge lower rates than its competitors.

2.1.11	The HVAC Coalition also submitted that the Board should require NRG to develop a more complete ancillary business cost allocation, on an FAC basis, for review in its FYE 2001 rate filing. The cost of this work should be included in the FYE 2001 allocations to the ancillary businesses.

2.1.12	NRG's position was that any FAC methodology must fairly distribute the benefits of a common cost pool among the monopoly and competitive businesses of the utility, and should not place any competitive business of the utility at a disadvantage solely because it happened to be performed from within a utility.

2.1.13	NRG also submitted that allowing the Company to continue to use the marginal costing method of cost allocation for the 2000 test year would permit it to "assess the viability of these operations and allow time for necessary price adjustments to be implemented".

2.1.14	NRG argued that in preparing the FAC study the Company attempted to find causal relationships as a basis for fairly allocating costs keeping in mind the size of the Company and the market in which it operated.

2.1.15	In its Summation of the Issues, Board Staff noted that the other gas utilities in Ontario were separating ancillary programs from their utility businesses and that consideration of this action might be an issue in the future for NRG.

Appropriateness of Allocations

2.1.16	On the issue of allocation of certain costs to the ancillary services, NRG submitted that:

•	Regulatory costs, directors' and officers' insurance premium costs, depreciation expense on computers and secondary support costs were not allocable to ancillary programs.

•	Some portion of office supplies and postage related to the Water Heater Rental Program billing was allocable to ancillary programs, but neither a percentage of revenue basis or a Full Time Equivalent basis would be an appropriate allocation driver.

2.1.17	The HVAC Coalition submitted that:

•	Certain costs that support and benefit the programs, and of which the programs should bear their fair share, had not been allocated to them.

•	The Board should direct an additional allocation of costs to the ancillary programs in the amount of $34,702 on account of costs that should have been allocated.

Income Tax

2.1.18	The HVAC Coalition submitted that the Board should direct NRG to:

•	add $35,200 to the cost of the ancillary programs on account of deferred tax liability for the test year; and

•	include the full tax expense associated with the Company's ancillary programs in future years in rate of return calculations for these programs.

2.1.19	NRG argued that the issue of deferred income taxes had never been raised prior to the current hearing.

2.1.20	With regard to the method of calculating income taxes, NRG argued that:

•	The Company could not afford to offload its current tax expense to some captive future customer base.

•	Rental rates had been impacted by previous Board decisions, so returns were kept lower.

Other Operating Revenue

2.1.21	NRG submitted that the forecast of other operating revenue (net) should be approved as filed.

Board Findings

Costing Methodology

2.1.22	In EBRO 496, the Board directed NRG to prepare a FAC Study; NRG complied with this order and filed the required study as part of this case. The Board concludes that NRG first assigned those costs that were directly incurred on behalf of utility operations to utility cost of service and those that were directly incurred on behalf of the ancillary programs to the appropriate program. The remaining costs were reviewed and allocated on the basis of cost causality.

2.1.23	The Board notes however that the pricing of NRG's ancillary programs is not cost-
based and is not regulated by the Board. The Board's responsibility with regard to ancillary programs is simply to ensure that the costs associated with these programs are properly assigned or allocated to them, and are not included in utility cost of service.

2.1.24	The Board believes that fully allocated costing is the appropriate method to segregate costs that are not directly assignable into those allocable to utility operations and those allocable to ancillary programs.

2.1.25	The Board directs NRG to prepare a new FAC Study for submission at NRG's next rate case and to use this as a basis to allocate all possible costs for the development of its proposed rates for that rate case.

Appropriateness of Allocations

2.1.26	The Board is not convinced by HVAC's argument that ancillary programs should bear a share of NRG's regulatory costs. It does, however, agree that some portion of the directors' and officers' liability insurance premiums, office supplies and postage, and secondary support costs may be allocable to ancillary programs in the 2000 test year.

2.1.27	In addition, although depreciation expense related to computers may not be allocable in the 2000 test year, NRG should continue to monitor the situation to ensure that this expense is appropriately allocated in future test years.

2.1.28	Given the size of NRG and its projected costs, the Board is prepared to accept NRG's evidence that a change in allocated costs would not be material in fiscal 2000, and therefore, the Board does not find it necessary to impute additional revenue to ancillary programs.

Income Taxes

2.1.29	As noted by Board Staff, other gas utilities in Ontario are separating their non-utility, competitive services into non-regulated enterprises.

2.1.30	The Board directs NRG, when it does consider the question of whether the Company should place its ancillary programs in a separate entity, to include in its considerations whether or not it is reasonable to expect future income taxes to be collected from the customers of those programs and whether gas utility ratepayers or the shareholder should be required to bear the burden of payment of taxes deferred in prior years.

2.2	Rate of return of Ancillary Programs

2.2.1	NRG's evidence indicated that the rate of return on ancillary programs, under the marginal costing methodology used by the Company was 16.1% and, under the fully allocated costing methodology as submitted by the Company, 12.9%.

Positions of the Parties

2.2.2	The HVAC Coalition argued that the Board should impute sufficient revenues to NRG's test year utility revenue forecast to compensate for the resulting shortfall in the rate of return for the ancillary businesses relative to the requested utility rate of return.

2.2.3	NRG's position was that any justifiable increase in cost allocations to the ancillary programs would not be material (i.e., would not reduce the rate of return of the ancillary programs to less than that of the utility business).

Board Findings

2.2.4	The Board notes that even if the additional costs suggested by HVAC (excluding the deferred taxes) were imputed to the ancillary programs the rate of return on the ancillary programs would be 12.9%, which is higher than the rate of return requested by the Company for its regulated utility business, which is 10.233%. Therefore there is no subsidization of the ancillary programs by the utility business and no material value in imputing additional costs to the ancillary programs.

Other Operating Revenue

2.2.5	The Board approves NRG's projected other operating income (net) as filed.

3.	RATE DESIGN AND COST ALLOCATION

3.0.1	This Chapter deals with:

•	proposed new Rates 4 and 5;

•	the proposed changes to Rates 1, 2 and 3;

•	fixed cost recovery;

•	revenue-to-cost ratios; and

•	long-term rate objectives.

3.0.2	In fiscal 1999, NRG had following rate classes:

•	General Service Rate 1, which includes residential, industrial and commercial customers;

•	Seasonal Service Rate 2; and

•	Special Large Volume Contract Rate 3, which has both firm and interruptible customers.

3.0.3	In EBRO 496, NRG proposed to investigate the possibility of a separate rate class for those Rate 3 contract customers who had a distinctive fall peaking load. A Fall Peaking Load Study was prepared and filed by NRG as part of this proceeding.

3.0.4	In EBRO 496, the Board also directed NRG to review its forecasting methodology with respect to its Rate 1 industrial customers. As part of this review, NRG identified that approximately one half of the Rate 1 industrial customers exhibited the same distinctive fall peaking load profile as some of the Rate 3 customers. This finding is also contained in the Fall Peaking Load Study.

3.0.5	In EBRO 491, NRG described its long-term rate proposals. In particular, NRG proposed to more thoroughly examine the customer load profile for the purpose of determining the block levels for Rate 2 (seasonal service rate). Due to various manpower and timing constraints, NRG was unable to provide the seasonal load study in EBRO 496. At that time, NRG indicated that the study would be available for the next rates case. A Seasonal Load Study was filed in this case.

3.0.6	As a result of these studies, NRG proposed two new rate classes, 4 and 5, and changing the block structure for Rate 3.

3.0.7	NRG's evidence indicated that the Company had investigated the possibility of creating one new rate class rather than the two classes proposed, but rejected that option because "it was both uneconomic and impractical to offer an interruptible service to [the small fall peaking customers currently served under Rate 1]."

NRG's Evidence

New Rate 4

3.1.1	As a result of the Fall Peaking Load Study, NRG proposed to move certain customers from the Rate 1 - General Service class to a new rate class, i.e., Rate 4. The customers are small grain dryers with peak consumption in the October - December period, who use gas for short periods and who do not contribute to the system peak, which occurs in the January-March period. These customers, while substantially smaller than their Rate 3 counterparts, are impacted by the same factors - weather, crop size and crop moisture content - that affect the consumption of the Rate 3 customers. In addition, NRG said that these customers were paying for costs related to the coincident peak that they did not create.

3.1.2	The proposed Rate 4 was a non-contract firm service designed for small customers with a load profile that exhibits a fall peak. The proposed rate included:

•	a monthly customer charge that was $1.25 more than that previously approved for Rate 1 customers and equal to the monthly customer charge in Rate 2;

•	an off-peak rate for the first block that was equal to that charged to Rate 2 customers; and

•	a two block distribution rate structure of which the first block rate was for the first 1,000 m3 of gas used each month and the second block was for all the gas used in excess of 1,000 m3 each month.

3.1.3	The proposed rate charges were:

Proposed Rate 4 - General Service Fall Peaking
Jan-Mar
Fixed Monthly Charge ($)	9.20	9.20
First 1000 m3 per month Delivery Charge (¢/m3)	16.2415	18.5648
Above1000 m3 per month Delivery Charge (¢/m3)	10.8220	16.6254
Gas Supply (¢/m3)	15.7657*	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

Fiscal 2000 Proposed Rate 1 and Proposed Rate 4
Rate 1

Rate 4

Jan-Mar
Fixed Monthly Charge ($)	7.95	9.20	9.20
First 1000 m3 per month Delivery Charge (¢/m3)	17.0246	16.2415	18.5648
Above1000 m3 per month Delivery Charge (¢/m3)	11.0246	10.8220	16.6254
Gas Supply (¢/m3)	15.7657*	15.7657*	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

3.1.4	NRG's witness confirmed that it would be possible to designate Rate 4 as a rate for interruptible service as "Rate 4 customers would also provide a benefit to the NRG system [by] being interruptible, but they are so much smaller that it would be even harder to measure" and that "the [potential customers] would tend to be able to accommodate a small interruption."

3.1.5	The Company's witnesses also said that, while NRG had not yet lost any of the Rate 1 customers that would be eligible to move to Rate 4, the Company anticipated doing so, unless the customers had the opportunity of obtaining the decrease in cost of utility service that Rate 4 represented when it was compared to Rate 1. In addition, they indicated that there was"an attraction to having a separate rate for someone who has installed a larger application for gas usage" as opposed to intermingling this customer with residential customers.

New Rate 5

3.1.6	The Fall Peaking Load Study filed by NRG also identified fall peaking customers in Rate 3. These customers generally had a peak consumption in the period mid- October to mid-November. As a result of the study, NRG proposed to move these customers out of the Rate 3 class and create a new rate class for them, i.e., Rate 5.

3.1.7	The proposed Rate 5 was an interruptible contract service designed for large customers with a distinctive fall peaking load. These customers were "highly susceptible to changes in their annual use."

3.1.8	The primary differences between Rate 3 interruptible customers and the proposed Rate 5 were that:

•	the Minimum Annual Volume ("MAV") requirement to qualify for Rate 5 will be 50,000 m3 as compared to the 113,000 m3 requirement for Rate 3;

•	the removal of any requirement to contract for a MAV, rather than the requirement that Rate 3 customers must take or pay for at least 80% of their contracted MAV; and

•	the introduction of a penalty if the customer uses less than 50,000 m3 annually, rather than if the customer uses less than the contracted MAV.

3.1.9	The proposed rate charges were:

Proposed Rate 5 - Interruptible Fall Peaking Contract
Fixed Monthly Charge ($)	50
Interruptible Delivery Commodity Charge (¢/m3)	5.4412 - 8.4412
Gas Supply (¢/m3)	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

Changes to Rate 1

3.1.10	NRG's proposal to recover the deficiency included an increase of $0.2745 per m3 in both blocks of the delivery charge. No changes were proposed for the monthly customer charge.

3.1.11	In previous hearings, the Board had expressed concern that the Rate 1- residential rates not increase more than the expected rate of inflation. NRG stated that, for fiscal 2000, the Company was anticipating inflation rates of from 0.5 to 2.0 percent, and that the proposed increase in the rate to Rate 1 residential customers, after removing the cost of gas flow-through, was within that range.

3.1.12	The proposed rate charges were:

Rate 1 - General Service
Current (EBRO 496)	Proposed (RP-1999-0031)
Fiscal 1999	Fiscal 2000
Fixed Monthly Charge ($)	7.95	7.95
First 1000 m3 per month Delivery Charge (¢/m3)	16.7501	17.0246
Above1000 m3 per month Delivery Charge (¢/m3)	10.7501	11.0246
Gas Supply (¢/m3)	12.4006	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

Changes to Rate 2

3.1.13	With regard to the Rate 2 class, NRG's witnesses stated that the most significant change was in the block structure, which was based on the findings of the Seasonal Load Study.

3.1.14	The Seasonal Load Study dealt with NRG's rates to customers who are tobacco curing customers using the majority of their gas in the months of August and September.

3.1.15	According to NRG, the Seasonal Load Study examined the customer load profile for the purpose of determining the block levels for Rate 2. In reviewing the size of the various blocks, NRG sought to balance a number of objectives:

•	Any change to the block structure should not have a significant negative impact on any group of customers within Rate 2;

•	Any change in the block structure should reflect the differences, if any, in load profiles;

•	Any changes should reflect, if possible, the competitive reality that exists in this market from other fuels.

3.1.16	Based on the study, and after balancing the objectives, NRG concluded that:

•	no changes should be made to the first block, i.e., it should remain as the first 1,000 m3 consumed each month; and

•	the third block's starting point should be increased from 10,000 m3 to 25,000 m3.

3.1.17	NRG proposed to increase the first block rate in the summer season to increase recovery of fixed costs. The Company also proposed to set the rate for the third block equal to the Rate 3 firm delivery commodity rate. No changes were proposed to the monthly customer charges or to the winter rates.

3.1.18	The proposed rate charges were:

Rate 2 - Seasonal Service
Apr-Oct Current	Apr-Oct Proposed	Nov-Mar Current	Nov-Mar Proposed
Fiscal 1999	Fiscal 2000	Fiscal 1999	Fiscal 2000
Fixed Monthly Charge ($)	9.20	9.20	9.20	9.20
Size of First Block (m3)	1,000	1,000	1,000	1,000
Delivery Charge for First Block (¢/m3)	15.2415	16.2415	17.5648	18.5648
Size of Second Block (m3)	10,000	24,000	10,000	24,000
Delivery Charge for Second Block (¢/m3)	10.7415	10.5720	15.6254	16.6254
Third Block for Monthly Volumes Exceeding (m3)	11,000	25,000	11,000	25,000
Delivery Charge for Third Block (¢/m3)	7.2415	5.8706	15.1952	16.1952
Gas Supply (¢/m3)	12.4006	15.7657*	12.4006	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

Changes to Rate 3

3.1.19	For Rate 3 customers, the Company said that there was considerable similarity between this rate class and the newly proposed Rate 5 class, with the primary differences being that Rate 3 has both "firm" and "interruptible" components, while Rate 5 was only for interruptible loads, and that the minimum annual demand requirement was higher under Rate 3 than under Rate 5.

3.1.20	The proposed rate charges were:

Rate 3 - Special Large Volume Contract
Proposed
Fixed Monthly Charge ($)	50	50
Monthly Demand Charge (¢/m3)	20.9419	22.6960
Firm Delivery Commodity Charge (¢/m3)	5.8706	5.7556**
Interruptible Delivery Commodity Charge (¢/m3)	6.058 - 9.0583	5.49412 - 8.49412
Gas Supply (¢/m3)	12.4006	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

**Originally proposed as 5.8706. Reduced post Settlement Conference. (H2T1S1 ADR Impact)

3.1.21	A comparison of the proposed charges for the Rate 3 class and the proposed Rate 5 class:

Fiscal 2000 Proposed Rate 3 and Proposed Rate 5
Rate 3	Rate 5
Fixed Monthly Charge ($)	50	50
Monthly Demand Charge (¢/m3)	22.6960	NA
Firm Delivery Commodity Charge (¢/m3)	5.7556	NA
Interruptible Delivery Commodity Charge (¢/m3)	5.49412 - 8.49412	5.4412 - 8.4412
Gas Supply (¢/m3)	15.7657*	15.7657*
*As per filing of Sept. 21, 1999. EB-1999-0483 approved effective Nov. 1, 1999 a gas commodity increase of 3.3048 ¢/m3 to increase the commodity charge to 15.7054 ¢/m3.

Results of Changes to Rates 1,2 and 3

3.1.22	The changes proposed by NRG result in the following percentage increases in rates for the average customer:

Customer Classes	2000
Total	Gas Cost Only
Rate 1 - Residential customers	11.1%	10.1%
Rate 1 - Commercial customers	14.0%	12.7%
Rate 1 - Industrial customers	18.3%	16.9%
Rate 2 - Seasonal customers	16.4%	17.2%
Rate 3 - Firm customers	11.2%	9.8%
Rate 3 - Interruptible customers	14.3%	9.8%
Source: Exhibit H2/T1/S1 updated September 21, 1999

3.1.23	The increase in the cost of gas accounts for the majority of the projected increase in the Rate 1 and 3 classes and more than the total projected increase for the Rate 2 class.

Positions of the Parties

3.1.24	In their summary, Board Staff noted that Rate 4 would be an attractive option to Rate 1 - industrial customers who were currently being assigned costs for which they were not responsible; that is, they use no gas during the system peak but were currently assigned coincident peak-related costs.

3.1.25	The HVAC Coalition made no specific submission on the proposed new rate classes.

3.1.26	NRG submitted that:

•	the proposed increases in Rate 1 were just and reasonable in light of the overall deficiency projected by the Company;

•	the proposed Rate 2 changes reflected the findings of the Seasonal Load Study and more equitably recovered the costs to serve these customers in light of that study;

•	the proposed increase in the Rate 3 monthly demand charge reflected the increase charged to NRG by Union Gas under Union's M9 Rate;

•	the proposed decrease in the firm delivery commodity charge for Rate 3 customers helped NRG to maintain the revenue-to-cost ratio for Rate 3-firm customers within the 120 percent range;

•	the proposed changes in the interruptible delivery commodity charge allowed the Company to recover a greater percentage of the costs assigned to the Rate 3 customer class while being more competitive with competing fuels;

•	the minor proposed changes to the MAV charges and the transportation charge reflected the change in the underlying costs related to these Rate 3 charges; and

•	that Rate 1- industrial customers who were eligible to transfer to Rate 4 "would be treated more equitably ..." there.

3.1.27	As indicated under cross-examination, the Company agreed that Rate 4 could be an interruptible rate and submitted a proposal that the following clause be inserted in the "Character of Service" section of the Rate 4 rate schedule under "Who may take service":

Rate 4 is a non-contract interruptible service that is available to all customers whose operations, in the judgement of Natural Resource Gas Limited, can readily accept interruption and restoration of gas service with 24 hours notice.

3.1.28	NRG submitted that there was no financial impact from moving Rate 3 customers who met these criteria to Rate 5, and that this change would "avoid penalizing customers for failing to use their contracted minimum annual volume of gas."

Board Findings

3.1.29	The Board agrees with the Company that justification for creating one or more proposed new rate classes has been demonstrated by the Fall Peaking and Seasonal Load studies. The Board also notes that the Company anticipates minimal impact on the customers who are not eligible for transfer from an existing rate class to a new rate class. In addition, the Board is aware that NRG expects not only to be able to keep customers as a result of the new rate class creation, but also expects to be able to attract new customers.

3.1.30	However, in view of the fact that the Company has agreed to make Rate 4 a rate for interruptible service, it appears that there is no longer any substantial justification for having both new rate classes.

3.1.31	Nevertheless, the Board will approve the new rate classes -- Rate 4 and Rate 5 -- and the charges proposed -- on an interim basis for the 2000 fiscal year.

3.1.32	Since no evidence was presented on a rate class that blends the characteristics of the proposed rate classes, the Board directs NRG to review its decision to create two rate classes and to present for the Board's consideration at the next rate hearing, a proposal for a single rate class that integrates customers served under Interim Rates 4 and 5.

.

3.1.33	In light of the fact that NRG expects the existence of these rate classes (or class, if ultimately so decided) to assist the Company in competing with alternative fuel sources, the Board directs NRG to file, at its next rate hearing, a schedule of customers gained or lost in the(se) rate class(es), as well as information about the potential market for these types of services and the share of the market held by NRG for these types of customers.

3.1.34	The Board is concerned about the size of the rate increases proposed for Rate classes 1, 2, and 3 but recognizes that the major portion of these increases is in the cost of NRG's gas supply, which is a straight pass-through.

3.1.35	In light of the evidence that NRG has carefully sought to balance the achievement of its rate objectives and minimize, where possible, the impact of the changes on its captive customers, the Board finds that, subject to its subsequent finding in this Decision on fixed cost recovery for Rate classes 1 and 3, the rates for classes 1, 2 and 3 are appropriate for fiscal 2000.

3.1.36	The Board directs NRG to develop rates for the 2000 fiscal year based on the findings stated in this Decision and to provide these and the resulting revenue-to-cost ratios and supporting documentation to the Board for its review as part of its draft Rate Order.

3.2	Fixed Cost Recovery

NRG's Evidence

3.2.1	Fixed costs were described as those which were dependent on the number of customers, rather than the amount of throughput. The fixed cost recovery was the proportion of fixed costs assigned or allocated to a class that were recovered through a monthly service charge as opposed to through a volumetric charge. NRG's evidence indicated that the Company recovered:

Customer Classes	Percentage of Fixed Costs Assigned or Allocated to Class that were recovered from that Class through fixed charges
Rate 1 - Residential, Commercial and Industrial	27%
Rate 2 - Seasonal customers	89%
Rate 3 - Firm customers	71%
Rate 3 - Interruptible customers	43%
Rate 4 - Firm fall peaking customers	100%
Rate 5 - Interruptible fall peaking customers	96%
Source: P.16, NRG Argument-in-Chief, December 15, 1999

3.2.2	The Company's rationale for not moving all of the cost recovery percentages to one was to:

•	minimize or avoid increases to low-volume users, particularly Rate 1 residential customers;

•	minimize the possibility that customers would disconnect gas service for part of the year in order to avoid paying monthly charges;

•	ensure that gas remained competitive with alternative fuels; and

•	ensure that the Company remained competitive with other gas utilities.

3.2.3	The Company's witnesses also said that if NRG increased its rates substantially then it was more likely to get complaints from customers who want to know why their rates were so much higher than Union Gas'.

Positions of the Parties

3.2.4	Board Staff summarized the issue as being:

.... a question of balancing what might be pure rate design against the risk of shocking captive customers and losing non-captive customers. However, there is a fairness issue also where fixed costs are not ..... properly collected by fixed charges there could be the issue of the subsidization of low users within a rate class by high users within that same class.

3.2.5	The HVAC Coalition did not submit argument on the issue of fixed cost recovery.

3.2.6	NRG argued that it might not be practical either to recover the same percentage of customer costs through the customer charge for all classes, by either reducing the Rate 1 charge to bring it to a level that was more consistent with those of other rate classes, or increasing those of other rate classes to be consistent with that of the Rate 1 class.

3.2.7	NRG also submitted that the monthly customer charge was a highly visible charge, especially for those customers who used gas for only two months a year, e.g., the customers in Rate classes 2, 4 and 5.

Board Findings

3.2.8	The Board notes that, for those customer classes in which the monthly customer charge was described as "highly visible", recovery rates are between 89 and 100 percent. The Board's concerns focus on the percentages of fixed costs recovered through fixed charges to customers in Rates 1 and 3 - Interruptible.

3.2.9	The Board approves the fixed cost recovery percentages for Rates 2, 3 - Firm, 4 and 5 for fiscal 2000. It expects, however, that a higher recovery percentage for Rate 3 - Firm customers will be achieved in the future, i.e., 2001 and beyond.

3.2.10	With regard to Rate 1 and Rate 3 - Interruptible customers, the Board directs NRG to ascertain the impact of moving recovery percentages for these rate classes to 30 percent and 50 percent, respectively, in fiscal 2000 with additional forward movement in future years. Provided that the change in the fixed charges to the Rate 1 and Rate 3 - Interruptible customers, when coupled with the resulting decrease in variable charges to these customer classes, does not result in an average annual increase in their utility services billing from NRG, the Board approves this change in the fixed cost recovery program.

3.3	Revenue-to-cost Ratios

NRG's Evidence

3.3.1	NRG identified its proposed revenue-to-cost ratios, after including the impact of the new rate changes and settlement agreement as:

Customer Classes	2000 at 1999 Rates	2000 Proposed
Rate 1 - Residential customers	.885	.896
Rate 1 - Commercial customers	1.350	1.386
Rate 1 - Industrial customers	1.045	1.133
Rate 2 - Seasonal customers	.918	.954
Rate 3 - Firm customers	1.203	1.209
Rate 3 - Interruptible customers	.605	.691
Rate 4 - Firm fall peaking customers	.755	.746
Rate 5 - Interruptible fall peaking customers	.745	.799
Source: P.10, NRG Argument-in-Chief, December 15, 1999

3.3.2	Mr. Aiken, NRG's witness, said that it was NRG's aim to have the revenue-to-cost ratios of all rate classes within the range of .95 to 1.05. Mr. Aiken also indicated that the justification for the revenue-to-cost ratio of Rate 3 customers being less than one was the fact that there was competition for these customers from alternative fuel sources so that maintaining them as NRG customers was of value to NRG's system.

3.3.3	In a discussion about revenue-to-cost ratios, Mr. Aiken agreed that "you can risk having higher revenue-to-cost ratios with (captive) classes [of customers] because they can't go anywhere, but for those where there is a danger of competition you consider it a wiser strategy to have lower revenue-to-cost ratios for those classes". He also said that "the alternative is to have a zero revenue-to-cost ratio" because the non-captive customers have left the system.

Positions of the Parties

3.3.4	In their summary, Board Staff noted that:

.....the Rate 1 residential, the Rate 2 and the Rate 3, both firm and interruptible will, under the utility's final proposal, move in accordance with the long-term objective of the utility [i.e., towards the desired revenue-to-cost range]. Rate 1 commercial/industrial will move marginally away from the long-term ... objectives; that is, they will get slightly higher, outside the range.

3.3.5	The HVAC Coalition made no specific submission on revenue-to-cost ratios for utility services.

3.3.6	NRG noted that the revenue-to-cost ratios of Rate 1 residential customers and Rate 2 customers moved slightly closer to one under the proposed rates, as did that of the Rate 1 customers in total. The Company indicated that customers in the three classes whose rates moved slightly away from the desired ratio (Rate 3 -Interruptible, Rate 4 and Rate 5) "do not create any additional demand on the NRG system during a peak period" and that "they have competitive alternatives to using natural gas". According to the Company, customers in Rate classes 4 and 5 also had the ability to move the processes for which they use natural gas to outside of NRG's service area.

Board Findings

3.3.7	The Board agrees with the Company that revenue-to-cost ratios should be at or near 1, but also recognizes that there are circumstances in which this is not practical.

3.3.8	The Board recognizes that there is a benefit to NRG's customers in having interruptible customers on NRG's system, and therefore accepts, for fiscal 2000, the lower revenue-to-cost ratios for those classes.

3.3.9	While the Board accepts the revenue-to-cost ratios for 2000, it is concerned about the deterioration in the ratios and directs NRG to file trend information on revenue-to- cost ratios as part of its filing for the next rate case and to make and file plans for measured progress towards cost-based rates.

3.4	Long-term Rate Objectives

NRG's Evidence

3.4.1	NRG's prefiled evidence listed its long-term rate objectives, which remained unchanged from previous years.

Positions of the Parties

3.4.2	NRG submitted that "the long-term objectives are not independent of one another" and that "the long-term proposals remain appropriate."

Board Findings

3.4.3	The Board agrees that NRG's long-term rate objectives remain appropriate.

4.	COMPLETION OF PROCEEDINGS AND COSTS

4.1	Summary of Board's Findings on Revenue Requirement for fiscal 2000

4.1.1	The Company's prefiled evidence showed an overall revenue deficiency of $735,379 for fiscal 2000. Of this amount, $658,153 was related to gas cost increases. The Board's findings indicate an adjusted overall delivery revenue deficiency of $63,743, which requires an increase in rates for the 2000 fiscal year. The regulatory financial statements reflecting the Agreement and Board-approved 2000 revenue requirement are set out in Appendix B.

4.2	Completion of Proceedings

4.2.1	By Orders dated September 30, 1999 and December 1, 1999, NRG's rates and other charges were declared interim pending final disposition of the Application. The Board finds that the effective date for a change, as a result of this Decision, in the Company's rates shall be October 1, 1999 for the 2000 fiscal year.

4.2.2	A one-time adjustment shall appear on the customer's first bill issued on or after the implementation date of this Decision, which will incorporate:

•	the difference between NRG's rates as charged prior to this Decision and the rates approved for fiscal 2000, for the period from October 1, 1999 to the date of implementation ("the interim period"), without interest; and

•	the impact of clearing the balances in the deferral accounts, as agreed in the settlement conference.

4.2.3	The Board directs NRG to file a draft Rate Order within 15 days from the receipt of this Decision. The draft Rate Order shall also include:

•	details supporting the disposition of the 1999 deferral accounts;

•	deferral account descriptions for fiscal 2000 Board-approved accounts;

•	a listing of the Board's directives contained in this Decision;

•	the rate schedules;

•	proposed notices to customers; and

•	rate base continuation schedules impacted by the findings in this Decision.

4.3	Costs

4.3.1	Enbridge, Union and the HVAC Coalition were intervenors in these proceedings. Enbridge, and Union, however, did not take an active role, submit argument nor request costs.

4.3.2	The HVAC Coalition asked a small number of interrogatories and took an active role in the settlement conference and the hearing on the issue of allocation of costs to NRG's ancillary businesses.

4.3.3	The HVAC Coalition requested that the Board order NRG to pay its reasonably incurred costs.

Board Findings

4.3.4	The Board concludes that the participation of the HVAC Coalition on the issue of allocation of costs to ancillary programs will benefit the customers of NRG. The Board therefore finds that the HVAC Coalition is entitled to recover its reasonable costs of participating in those parts of the proceeding that related to the allocation of costs to ancillary programs.

4.3.5	The Board directs NRG to pay the cost award, subject to the Board's findings in this Decision, the specific amount of which will be fixed by the Board following the assessment and recommendations of the Board's Cost Assessment Officer.

4.3.6	The Board also finds that the Applicant shall bear the Board's costs of these proceedings. Accordingly, NRG shall pay the Board's cost of, and incidental to, this proceeding immediately on receipt of the Board's invoice.

DATED at Toronto March 10, 2000.

_________________________

F.A. Drozd

Presiding Member

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J.B. Simon

Member

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A.C. Spoel

Member