REPORT TO THE SPECIAL COMMITTEE

EX-99.1 3 dex991.htm REPORT TO THE SPECIAL COMMITTEE REPORT TO THE SPECIAL COMMITTEE

October 28, 2002

The Board of Directors of Nicor Inc.

1844 Ferry Road

Naperville, IL 60563-9600

Dear Directors:

On behalf of the Special Committee of the Board of Directors of Nicor Inc. (“Special Committee”), I am forwarding to you the final Report delivered to us by Sidley Austin Brown & Wood (“Sidley”) on Monday, October 28, 2002.

In addition to their written Report, Sidley provided the Special Committee with an oral summary of the findings and conclusions, and the Special Committee has had the opportunity to discuss extensively with Sidley their Investigation. The Special Committee believes that Sidley’s Investigation raises a number of issues and concerns that require immediate attention by the Company.

The Special Committee hereby recommends that the Board of Directors direct the Company to adopt the recommendations set forth in Sidley’s Report. The Board should direct the Company to make appropriate adjustments to properly account for, and fully address the adverse consequences to ratepayers of, the following issues: (1) the 1999 sale of the Company’s DSS storage; (2) the improperly-accounted for DSS transactions in 2000 and 2001; (3) carrying costs improperly included in the Company’s PBR filing; (4) the metering error that occurred in 2001; (4) the purchase of weather insurance from Aquila for fiscal 2001; (5) the inconsistent recording of in-field transfers during 2000 and 2001; and (6) the improper accounting for storage prefills. The Special Committee also recommends that the Board direct the Company to cause to be conducted a full audit of management fees paid by the Company to third parties during 2000 and 2001.

The Special Committee further recommends that the Board direct the Company to promptly undertake a re-audit of 1999-2001 and first two quarters of 2002, and make any filings with the Illinois Commerce Commission, the U.S. Securities and Exchange Commission, and other regulatory agencies made necessary as a result of that re-audit or any of the recommendations contained in Sidley’s Report. Finally, the Special Committee believes that the Company should be directed to undertake a detailed study and plan to address the various issues and concerns raised by the Sidley Report, including a detailed study of management bonus issues and the adequacy of internal accounting and regulatory controls, and to promptly report back to the full Board and the Audit and Compensation Committees, as appropriate, with recommendations.

We further request that this transmittal letter be included along with the Report in the official proceedings of the Board.

Very truly yours,
Bruce P. Bickner

REPORT TO THE SPECIAL COMMITTEE

OF THE

BOARD OF DIRECTORS OF NICOR INC.

		Scott R. Lassar
		SIDLEY AUSTIN BROWN & WOOD, LLP
		Bank One Plaza
		10 South Dearborn
		Chicago, IL 60603
		312-853-7000

Dated: October 28, 2002

TABLE OF CONTENTS

INTRODUCTION		1
SUMMARY OF CONCLUSIONS AND RECOMMENDED ACTIONS		2
CONCLUSION		7
I. OVERVIEW OF THE PERFORMANCE BASED RATE (PBR) PROGRAM		8
A. Overview of Performance-Based Regulation		8
B. The LIFO Layers		14
II. 1999 SALE OF DSS STORAGE TO IMD		20
A. Summary and Conclusion		20
B. Background And Analysis		21
C. Conclusion		25
III. DSS AND “VIRTUAL STORAGE”		27
A. Summary and Conclusion		27
B. Background and Analysis		27
C. Conclusions		33
IV. 2001 METER READING ERROR		37
A. Summary and Conclusion		37
B. Background and Analysis		37
C. Impact on the PBR		38
D. Options Considered to Correct the Error		39
E. Conclusion		39
V. WEATHER INSURANCE PURCHASED FOR FISCAL 2001		40
A. Summary and Conclusion		40
B. Background and Analysis		40
C. Propriety Of The Transaction		46

D. Costs Incurred By The Ratepayer		47
E. Conclusion		48
VI. IN-FIELD TRANSFERS		49
A. Summary and Conclusion		49
B. Background and Analysis		49
C. Conclusion		55
VII. STORAGE PREFILLS		57
A. Summary and Conclusion		57
B. Background And Analysis		57
C. Appropriateness Of the Accounting For the Transaction		61
D. Costs Incurred By The Ratepayer		63
E. Conclusion		63
VIII. RELATED PARTY TRANSACTIONS		65
A. Summary and Conclusion		65
B. Background and Analysis		65
C. Costs Incurred By The Ratepayer		71
D. Conclusion		71
IX. GAS TRANSACTION LOSSES		72
X. MANAGEMENT FEES		73

iii

INTRODUCTION

Sidley Austin Brown & Wood (“Sidley”) was hired by a Special Committee of the Board of Directors (“Special Committee”) of Nicor Inc. (“Nicor” or “the Company”) to conduct a factual investigation of certain allegations regarding the Performance Based Rate system (“PBR”) under which the Company has been operating since January 2000 and to report on our factual findings and conclusions. Some of these allegations were made by a Nicor employee in a “whistleblower fax,” which we were provided. Other allegations were provided to us by the Company or arose during the course of our investigation. Because the Illinois Commerce Commission (“ICC”) has not provided the Company or the Special Committee with a copy of the whistleblower fax, we have not identified in this Report which allegations originated from the whistleblower. During the course of the investigation we made no attempt to uncover the identity of the whistleblower.

To assist us in the investigation, we hired the accounting firm KPMG LLP (“KPMG”). We and KPMG reviewed thousands of Nicor documents and interviewed numerous current and former Nicor employees, including all current officers. We also interviewed employees of EKT Trading, in Houston, Texas, a successor company to Inventory Management and Distribution LLC and its affiliates (collectively, “IMD”), and had the Company request documents from IMD, which we also reviewed. We conducted a search of the Nicor computer system for relevant e-mails and documents.

The following is our Report on this investigation. We first provide a summary of the issues we analyzed and an overview of the conclusions that we reached. Then, we provide a discussion of the operation of the PBR in order to provide context for the discussion that follows. We then review each of the areas that we investigated and present our conclusions.

Our findings and conclusions are based upon the information and documents that we received and analyzed. In certain instances, discussed in more detail below, our analysis and conclusions are based upon representations and calculations from the Company that we are still in the process of verifying. In the event that we become aware of additional or different information, we may modify or change one or more of our findings and conclusions.

SUMMARY OF CONCLUSIONS AND RECOMMENDED ACTIONS

In the course of our investigation, we reviewed a number of operational, regulatory and accounting issues that were either raised in the whistleblower fax, brought to our attention by the Company, or that arose in the course of our investigation. The issues we reviewed and upon which we express an opinion are the following:

1. Sale of Delivered Storage Services (DSS) Storage in 1999. Nicor sold a significant amount of gas to IMD in December 1999 in connection with the initiation of a new “managed storage” agreement with IMD. We examined whether this transaction was appropriate and its impact on ratepayers.

We conclude that the transaction resulted in a loss to ratepayers in the amount of $13.5 million, which could have been mitigated if the transaction had been delayed until 2000, when, through the PBR mechanism, any losses would have been shared with the Company 50/50. We recommend that the Company address this issue by returning to ratepayers half of the loss incurred in the transaction, or $6.75 million.

2. Virtual Storage and DSS Transactions. In the summer of 2000, Nicor and IMD agreed to a new strategy, termed the “storage strategy,” whereby IMD filled the DSS storage facility and later sold certain of the gas back to Nicor at its acquisition cost. The

Company accounted for this transaction as “virtual storage,” whereby the purchase from IMD was treated as a storage injection and then a simultaneous withdrawal under the PBR. The Company also engaged in transactions with IMD in which it supplied gas to IMD which it agreed to repurchase. We reviewed the appropriateness of this treatment and the strategy and analyzed the consequences to ratepayers.

We conclude that use of virtual storage accounting was improper. We recommend that this gas be properly accounted for; that is, as the sale of flowing gas, not storage gas. In addition, gas sales by the Company to IMD where the Company had an obligation to repurchase this gas should not be treated as sales. The Company has made these adjustments by taking into account the changes in accounting treatment in recalculations of its performance under the PBR. Were the Company not making these adjustments, an additional $4.5 Million would be due the ratepayers resulting from the Company’s virtual storage accounting.

In addition, we conclude that the Company improperly included carrying costs in its PBR filings with respect to the Company’s DSS transactions with IMD. The carrying costs amount to $1 million in 2000 and $3.1 million in 2001. We recommend that the amount of carrying costs improperly included in the PBR filing, or $2.05 million, be returned to ratepayers

3. 2001 Meter Reading Error. In January/February 2002, the Company made its annual PBR filing to the ICC for the 2001 calendar year. In March 2002, the Company prepared another ICC document of reported deliveries and in the process determined that deliveries did not agree with the PBR filing. The Company determined that the difference related to a metering error and that reported volumes in the 2001 PBR filing were incorrect. The Company did not amend the previous filing, opting instead to correct the volumes through the

anticipated 2002 PBR. We analyzed the appropriateness and consequences to ratepayers of that decision.

If the Company follows through with its current intention of correcting this error in the next PBR filing, the error will not have an adverse impact on ratepayers. If the Company does not make a PBR filing in 2002, the Company should return the amount of the remaining overcharge, or $1.15 million, to ratepayers.

4. Weather Insurance Purchased for Fiscal 2001. The Company purchased a weather insurance product from Aquila for the 2001 heating season. The quoted premium was substantially higher than the prior year. Nicor decided to lower the insurance premium by packaging the insurance product with a second transaction in which Nicor transferred gas to Aquila at a $2 million discount, in exchange for a like discount of the insurance premium. We looked at whether this transaction was appropriate and the consequences of the transaction on ratepayers.

We conclude that linking insurance premiums with gas sales was improper and should not have occurred. Quantifying the harm to ratepayers, however, is a distinct issue. Assuming that the Company reverses the LIFO benefit to the ratepayers to correct the improper accounting of Storage Prefill transactions (discussed below), we recommend that the Company return to ratepayers $3.05 million, the amount of the loss realized on the gas supply component of the transaction in the event the LIFO benefit is reversed.

5. In-Field Transfers. In 2001, certain withdrawals were considered to be “in-field transfers,” that is, injections or withdrawals made for operational reasons, such as to

maintain the integrity of Nicor’s aquifers. Because they were not accounted for as “withdrawals” under the PBR, these in-field transfers increased the notional benchmark against which the actual cost of gas is compared. We reviewed the methodology of these transfers and the impact upon ratepayers.

We conclude that there are valid operational reasons for in-field transfers, and that they should not be counted as withdrawals for purposes of the PBR. The Company’s recording of these in-field transfers, however, was inconsistent. We recommend that the Company adjust its PBR results to use a consistent method of recording in-field transfers. Our recommended approach results in a cost having been incurred to the ratepayer in the amount of $4.85 million in 2000, and a benefit incurred to the ratepayer in the amount of $1.4 million in 2001, for a total amount due to the ratepayer of $3.45 million.

6. Storage Prefills. The Company entered into agreements with third parties whereby the third party injected gas into Nicor’s storage fields to be purchased by Nicor at a later date. Pricing was established at the time of injection and included, among other terms, an agreement for Nicor to pay carrying costs. We reviewed whether the gas was properly accounted for and its impact upon ratepayers

We conclude that these transactions were improperly accounted for. We recommend that the Company properly account for these transactions as product financings under FASB Statement No. 49, Accounting for Product Financing Arrangements. The Company has made this adjustment by taking into account the changes in accounting treatment in recalculations of its performance under the PBR.

7. Related Party Transactions. Nicor’s regulated entity conducted transactions with Enerchange, a Nicor unregulated entity. We reviewed whether these transactions were conducted at arms length. We did not find any improper related party transactions.

8. Gas Transaction Losses. We reviewed whether the Company has conducted inappropriate hedging activities in connection with the PBR. We did not find any improper hedging activity.

9. Management Fees. We reviewed whether management fees paid to a third party in connection with gas storage services were excessive. We found that the Company negotiated the management fees paid to IMD at the end of each year, and did not memorialize these agreements in writing. We recommend that the Company conduct a detailed audit of the fees paid by the Company, either by an outside auditor or by Nicor’s internal audit department.

Total Recommended Adjustments: $15.3 Million

CONCLUSION

Under the PBR, Nicor found itself operating in a new and highly complex regulatory environment that was intended to align the Company’s and ratepayers’ interests. We identified several instances in which the Company took actions that had the effect of benefiting the Company and disadvantaging ratepayers. In other instances, the Company made inadvertent accounting errors, sometimes to the benefit of the Company and sometimes to the benefit of ratepayers. We did not find that there was criminal activity or fraud.

I. OVERVIEW OF THE PERFORMANCE BASED RATE (PBR) PROGRAM

A. Overview of Performance-Based Regulation

Prior to 2000, Nicor operated under a traditional regulation plan that allowed the Company to recover the actual costs of gas incurred each year, subject to an annual Purchased Gas Adjustment (“PGA”) proceeding in which the ICC would review costs and prudence issues. The costs reviewed by the ICC included all commodity gas costs, whether resulting from flowing gas purchases or storage gas, transportation costs and storage costs. On March 1,1999, Nicor petitioned the ICC for authority to implement a performance based regulation (“PBR”) plan under Section 9-244 of the Illinois Public Utilities Act (“Act”) (220 ILCS 5/9-244). On November 23,1999, the ICC entered an Order approving the PBR for Nicor’s gas costs. The plan took effect on January 1, 2000.

1. Nicor’s PBR

The tariff rates paid by Nicor’s ratepayers remain unchanged under both the traditional rate plan and the PBR. The tariff rate, as approved by the ICC in Nicor’s last rate case, is the revenue earned by Nicor for each unit of gas delivered to its ratepayers. The tariff rate is designed to compensate Nicor for its operating and maintenance costs, taxes, depreciation, and an allowed rate of return. Nicor’s shareholders bear the risk and/or reward of paying more or less in a given year, depending on variations in demand (i.e., weather risk) and operating costs.

The purpose of the PBR system is to give Nicor an incentive to lower ratepayers’ gas costs. Any savings generated from more efficient gas commodity purchases and other cost-reducing measures under the program are shared equally with ratepayers. Under Nicor’s program, a single market-based benchmark Gas Cost (“Benchmark”) would be established. This Benchmark would reflect commodity costs, transportation costs, storage costs, and credits

generated by gas supply activities to approximate as closely as possible the gas costs that Nicor would have incurred that year under traditional rate regulation. This Benchmark would then be compared to Nicor’s actual gas costs for that year and the difference, either losses or savings, would be shared equally between the Company and its ratepayers.

By sharing the difference between Nicor’s actual gas costs and the PBR Benchmark gas costs, the ratepayer does not recognize an actual discount in gas costs at the end of the year if a PBR “savings” is recognized. The ratepayer is charged Nicor’s actual gas costs throughout the course of the year. If at the end of the year these actual gas costs are lower than the Benchmark-predicted costs, the ratepayer pays additional sums to Nicor, amounting to 50% of the difference between Benchmark-predicted costs and actual gas costs. It should be recognized that under this system, the ratepayer has, in fact, paid more than Nicor’s actual cost of gas for the year when a PBR “savings” is realized. But under the rationale of the PBR system, the ratepayer has still enjoyed a benefit: it has paid less than it would have paid in the absence of the PBR, i.e., the Benchmark-predicted cost. It is worth recognizing that a conclusion that the PBR “savings” were inflated because the Benchmark-predicted costs were incorrectly calculated would practically translate into a conclusion that the ratepayer incurred a cost when it paid Nicor 50% of the difference between the Benchmark-predicted gas costs and Nicor’s actual gas costs. In other words, if the Benchmark-predicted costs are reduced, thereby reducing the PBR savings, the ratepayer was actually harmed through an overpayment in the amount of 50% of the reduction in savings.

2. The Benchmark

In order to determine whether Nicor has achieved a savings or a loss under the PBR, its performance must be measured against a Benchmark which attempts to reflect historical

gas costs. As can be seen from the discussion that follows, calculation of the Benchmark is extremely complicated. The Benchmark for each year is based on the following formula:

Benchmark = (Market Index Cost + Firm Deliverability Adjustment + Commodity Adjustment) - Storage Credit Adjustment

The Market Index Cost represents “the annual gas cost customers would pay if the gas delivered to them was priced at prevailing Chicago city-gate market index prices at the time of delivery.” Northern Illinois Gas Company, Order in Docket No. 99-0127 at Part IV.A.l, 1999 Ill. PUC LEXIS 921 (1999) (“PBR Order”) (Exhibit 1 to Appendix). The Market Index Cost is determined by multiplying Nicor’s actual sales deliveries each month by the Market Index Price for that month and then adding together the twelve monthly totals. Two groups of price indices are used to calculate the Market Index Price. The first group is based on indices reporting “first-of-the-month” (FOM) pricing and the second group is based on indices reporting daily pricing throughout the month. The average prices for each group are then averaged together. The average price for the first group is given a weighting of 65% and the average price for the second group is given a weighting of 35%. The sum of the two group average prices multiplied by their respective weightings results in the Market Index Price.

Once the Market Index Cost is determined, three adjustments are made. The first adjustment relates to the storage component, and is accomplished by means of a Storage Credit Adjustment (“SCA”). The SCA recognizes the effect on the ratepayer’s cost of gas that is caused by the Company’s seasonal patterns for injecting and withdrawing gas from storage over the course of the year. In effect, the assumption underlying the Market Index Cost—that the gas delivered to the ratepayer has a cost equal to the prevailing price at the time of delivery—is incorrect. Nicor purchases and injects gas into storage during the summer, and then withdraws

and delivers that gas to the ratepayer in the winter. This purchasing pattern of injecting in the summer and withdrawing in the winter has an economic impact on Nicor’s cost of gas that differs from the assumptions underlying the Market Index Cost, in that summer prices are generally lower than winter prices.¹ The SCA attempts to capture and consider this difference between summer and winter prices (known as the “summer/winter spread”) which affects Nicor’s actual cost of gas for amounts of gas withdrawn from storage.² In other words, the SCA attempts to correct the Market Index Cost by taking into account the fact that the cost of gas delivered to the ratepayer from storage is historically not the prevailing price at the time the gas was delivered, but the prevailing price at the time the gas was injected into storage.

The SCA is determined by multiplying the actual number of units of gas withdrawn from storage for sales to customers during the year by the Storage Credit Rate (“SCR”). The SCR is the difference between the weighted average Market Index Price for injections and weighted average Market Index Price for withdrawals. The weightings are predetermined over monthly periods and are based upon Nicor’s historical patterns of injections

While the SCA was clearly intended to reduce the notional benchmark, that was based upon the assumption that summer prices are generally lower than winter prices. Logically, if Nicor did not gain a “benefit” from purchasing gas in the summer and then reselling that gas in the winter, the SCA should not reduce the benchmark. In fact, as defined, the SCA does not operate to lower the benchmark, but to calculate the value derived from Nicor’s practice of purchasing and injecting gas in the summer and then withdrawing that gas in the winter. As will be seen later, where Nicor would in fact realize a “loss” from its historical injection and withdrawal patterns, the SCA appropriately reflects that fact and raises the notional benchmark.

By way of example, if Nicor purchased gas in the summer at a price of $3.00/mcf (thousand cubic feet), and then withdrew that gas in the winter when the price of gas was $5.00/mcf, it “outperformed” the market in selling $3.00 gas at a time when the market price for such gas was $5.00. The purpose of the SCA is to incorporate into the notional benchmark this change in price (in this example, a gain) so that Nicor will not “beat” the Benchmark through the simple operation of its historical injection and withdrawal patterns.

and withdrawals.³ Thus, the SCR essentially quantifies the value that Nicor would ordinarily derive on each unit of gas withdrawn due to the difference between injection and withdrawal prices.⁴

The second adjustment is the Firm Deliverability Adjustment. This adjustment reflects “the level of fixed costs incurred by Nicor on an annual basis to reserve firm transportation, purchased storage and other services in order to ensure the availability of gas supplies for its customers during peak periods.” PBR Order at Part IV.A.3. The Firm Deliverability Adjustment is the total amount of costs for transportation reservation and purchased storage reservation minus an amount for Capacity Management Credits, which includes credits related to capacity release, gains from buy/sell transactions, gains from supply sales, and storage credits. The costs for transportation reservation and purchased storage reservation are an average of the projected costs for both the program year and the next year. Capacity Management Credits are computed using the most recent twelve months with an appropriate reduction arising from lower firm reservation costs.

Finally, a Commodity Adjustment is required to account for any historical variation between the Market Index Cost and Nicor’s actual historical gas costs but which is not captured by the SCA or Firm Deliverability Adjustment. Such variations may result from: (1)

Thus, based on Nicor’s historical practice, the SCR assumes that 28.1% of withdrawals occur in January, and 15.27% of injections occur in August. Based on these percentages, the SCR weighs the respective monthly Market Index Prices accordingly.

⁴

Again, in the typical year, when summer prices are below winter prices, the SCR will lower the benchmark for each unit of gas withdrawn from storage. However, in the extraordinary year, when summer prices exceed winter prices, the SCR will raise the benchmark for each unit of gas withdrawn from storage. In both events, the SCR has appropriately accounted and corrected for the Market Index Costs’ assumption that Nicor’s cost for gas delivered to the ratepayer is the prevailing price at the time the gas is delivered to the ratepayer.

the commodity cost associated with reserving firm pipeline supply (a premium that is not captured in published city-gate market index prices); (2) any differences in the timing of purchases, or pricing terms and location; and (3) revenue earned by Nicor through off-system storage arrangements. The Commodity Adjustment is calculated by (1) computing the difference between Nicor’s Actual Gas Costs and the Market Index Cost for a past year(s); (2) subtracting the SCA and adding the Firm Deliverability Adjustment for the year to that result; (3) dividing the remainder by the MMBtus delivered in the year(s) being examined, which results in the per-MMBtu Commodity Adjustment Rate, a rate that remains fixed for the duration of the program; and (4) the total Commodity Adjustment for the calendar year is determined by multiplying the volume of sales for the year by the Commodity Adjustment Rate. The ICC decided that the periods to be used in determining the Commodity Adjustment would be 1994-1998, with the data from 1996 weighted at 50%.⁵

3. Computing the Amount of Savings or Losses for the Program Year

The savings or losses for the program year are calculated by comparing the Benchmark to Nicor’s actual gas costs for the year. If Nicor’s actual gas costs are lower than the Benchmark, the difference will be a savings, but if Nicor’s actual gas costs are higher than the Benchmark, the difference will be a loss. The actual gas costs are the total recoverable costs for the calendar year as calculated and filed under Nicor’s Rider 6⁶ and adjusted to: (1) exclude amortized amounts for the over- or under-collection of gas costs in the past; (2) add back any

⁵

The ICC agreed with the Company that the price spikes and differential between the market prices and the Company’s actual variable commodity cost in early 1996 were highly unusual and that the 1996 data should be given less weight than the other years in the 1994-1998 period in order to perform a reasonable computation.

⁶

To implement the PBR, Nicor filed a new Rider 4, “Gas Supply Performance Program,” which would compare the Company’s actual gas costs for a calendar year, as reflected in its Rider 6, Gas Supply Cost, with the annual costs determined by the market-sensitive Benchmark.

credit attributable to pipeline refunds for periods prior to the effective date of the program; and (3) exclude pipeline transition and take-or-pay costs.

4. Nicor’s PBR Proceeding Before the ICC

During the proceeding approving the PBR, Nicor indicated that one of the reasons for entering into an alternative regulatory plan for its gas costs was to enable it to respond to changes in the gas supply markets, which offered both challenges and opportunities to aggressively pursue cost minimization through innovative, non-traditional means. The Company also indicated the PBR was based on three objectives: (1) an alignment of shareholder and ratepayer interests by providing economic incentives for Nicor to improve its performance in providing ratepayers with the best gas prices available, while recognizing the need for continued reliability and security of supply; (2) encouraging the appropriate use of competitive market opportunities and risk management mechanisms for the procurement of gas supply, transportation and storage services by establishing a reasonable balance between risk and reward; and (3) a reduction of regulatory costs by establishing an objective, market-based standard for evaluating gas supply purchasing, planning, and management, while also eliminating after-the-fact prudence reviews. See generally PBR Order at Part II.

B. The LIFO Layers

1. Storage of Natural Gas

Optimal conditions for a storage facility for natural gas include a high degree of porosity to accommodate a large quantity of gas and a high degree of permeability so that the gas may be injected and withdrawn rapidly. In addition, the facility must be sufficiently sealed to prevent the escape of large volumes of gas. However, no storage reservoir is completely sealed. A miniscule amount of gas is expected to escape each year and will be unrecoverable by the

utility. Natural gas utilities normally withdraw the gas from storage during the winter when the supply and cost for gas are usually high and replenish the storage supply during the summer when the supply and cost for gas are usually low. This is commonly referred to as the “storage cycle.” To provide the pressure necessary to deliver natural gas from storage, a minimum volume of gas known as “cushion gas” or “base gas” must be left in the reservoir. “Cushion” or “base” gas is only recoverable by the utility when the storage reservoir is abandoned.

Nicor has significant underground storage assets and is strategically located on the Midwest natural gas pipeline grid with access to numerous interstate pipelines. This is an important advantage because the Company has the ability to procure competitively priced gas supplies from a number of natural gas producing regions, including Canada. The existence of the storage assets and the strategic location of these facilities on the natural gas pipeline grid also allows Nicor to provide a variety of gas supply services to numerous customers, including the natural gas-fired generation plants located in the Company’s service territory.

2. LIFO Accounting

The value of gas owned by Nicor and kept in its storage fields is determined using a Last-In-First-Out method of accounting (“LIFO”).⁷ Under the LIFO method, the inventory is considered to exist in layers, with each layer priced at its cost in the year it was added to the storage reservoir. When gas is withdrawn from storage, the most recent layer is considered withdrawn for accounting purposes, hence the term “last-in, first-out.” Additional layers are

⁷

Pursuant to 83 Ill. Admin Code Part 505.117(C), withdrawals of gas may be priced according to the first-in, first out (“FIFO”), LIFO, or weighted average cost method, in connection with which a “base stock” may be employed provided the method adopted by the utility is used consistently from year to year and the inventory methods are maintained in accordance therewith. Approval of the ICC must be obtained for any other pricing method, or change in the pricing method adopted by the utility.

added to the inventory only when layers added to the inventory exceed layers withdrawn. At the end of each calendar year, a determination is made whether a layer has been added to Nicor’s inventory or whether there has been a LIFO decrement, that is, a net annual withdrawal from Nicor’s inventory.

3. Nicor’s Stored Gas Is Owned By Its Shareholders

For reasons that will become apparent later, one question that we examined was whether Nicor’s stored gas may be considered to be an asset owned by the Company or owned by ratepayers. We believe that Nicor’s inventory is owned by the Company and its shareholders for the following reasons.

It is well settled law that ratepayers do not become owners of the physical assets of a utility simply because they pay the rates charged by the utility. See, e.g., Board of Pub. Util. Comm’rs v. New York Tel. Co., 271 U.S. 23,32 (1926); Village of Niles, et al., v. City of Chicago, 201 Ill.App.3d 651,669 (1st Dist. 1990). In Board of Pub. Util. Comm’rs, the U.S. Supreme Court noted,

Customers pay for service, not for the property used to render it. Their

payments are not contributions to depreciation or other operating

expenses, or to capital of the company. By paying bills for service they do

not acquire any interest, legal or equitable, in the property used for their

convenience or in the funds of the company. Property paid for out of

moneys received for service belongs to the company, just as does that

purchased out of the proceeds of its bonds and stock.

Id. at 32.

The Citizens Utility Board (“CUB”) has previously argued that Nicor’s ratepayers have an ownership interest in the utility’s LIFO reserve. See Northern Illinois Gas Co., Order in Docket No. 95-0219,1996 Ill. PUC LEXIS 204 (1996). During that proceeding, CUB argued that LIFO reserves represent ratepayer-supplied funds and therefore should be deducted from the

storage inventory. Id. The ICC rejected CUB’s argument and concluded that the LIFO reserve is nothing more than an accounting mechanism and is not reflected in the calculation of the gas charge. Id.

Other cases have indirectly concluded that gas in storage is wholly-owned by the utility. For example, in CNG v. FERC, the court held that gas lost through leaks in the storage reservoir is recoverable by the utility in its base rates or purchased gas adjustment charges. 40 F.3d 1289 (D.C. Cir. 1994). Because the court considered the escaped gas as a cost of the utility’s service, it necessarily must have considered the stored gas to be owned by the utility. Id.

Moreover, a utility may consider the cushion gas in its storage reservoirs to be a capital asset of the utility for tax purposes. See Pacific Enterprises and Subsidiaries v. Comm’r. of Internal Revenue, 101 T.C. 1 (1993). Other decisions have concluded that natural gas in storage is included in the utility’s base rate, and a number of decisions refer to gas in storage as the utility’s “inventory.” See North Shore Gas Co., Order in Docket No. 95-003 1,1995 Ill. PUC LEXIS 73 1 ( 1995); Peoples Gas Light and Coke Co., Order in Docket No. 90-0318, 1991 Ill. PUC LEXIS 21 (1991); North Penn Gas Co. v. FERC, 707 F.2d 763 (3d Cir. 1983); Indiana Gas Co. Inc., Order in Docket No. 37247,1984 Ind. PUC LEXIS 861(1984); Pacific Enterprises and Subsidiaries v. Comm’r. of Internal Revenue, 101 T.C. 1 (1993).

In an investigation involving Nicor’s Customer Select Pilot Program, the ICC concluded that Nicor could only recover gas storage inventory costs for gas in storage that the utility had paid for. See Citizens Utility Board, Order in Docket No. 00-0620 and 00-062 1, 2002 Ill. PUC LEXIS 16 (2002). According to the ICC, “a utility does not have an investment in [gas] inventory that it has not paid for.” See Northern Illinois Gas Co., Order in Docket No. 95-0219,

1995 Ill. PUC LEXIS 732 (1995). Based on this decision, one can reasonably conclude that Nicor, not its ratepayers, has a paid investment in its storage gas.

4. Relationship of LIFO to the PBR

During the course of our investigation, we have determined that one of the primary motivations of the Company in entering into the PBR was to access and share the benefit of delivering the low-cost LIFO gas (that is, gas that was being carried at a low cost in Nicor’s inventory) to the ratepayer. Prior to petitioning the ICC for approval of the PBR, the Company had internal discussions regarding the significant amount of LIFO gas priced at historical prices dating back to 1954. The Company realized that the liquidation of these low-cost LIFO layers under the traditional rate structure would result in the book value of the gas inventory reductions being realized only by Nicor’s ratepayers. The use of the PBR would provide a mechanism for the Company to share in the benefits achieved from the sale of the low-cost LIFO gas to the ratepayer.

There are inherent risks associated with performance-based regulatory plans. Nicor faced such risks in adopting its PBR. One risk faced by the Company was the financial risk associated with the actual performance against the Benchmark. Another risk was the physical risk associated with Nicor, as the provider of last resort, being able to deliver gas no matter what the weather or financial position. Arguably, it has been a challenge for Nicor to accurately account for all of the financial components of the PBR on a real time basis because of the timing of many of the components. As an example, gas is bought monthly, the pipeline contracts are structured on an annual basis, inventory is determined on an end-of-the-year basis and lost and unaccounted for gas is an after-the-fact calculation.

The ability to use lower-level LIFO layers to satisfy ratepayer needs was viewed by many in the Company as a means of mitigating these risks and as providing a form of “insurance policy” with respect to the Company’s performance under the PBR. Thus, as a practical matter, the considerable risks outlined above were, in the view of the Company, effectively mitigated by the certainty of the benefit which could be derived from liquidating low-cost LIFO layers. Naturally, by mitigating risk, the LIFO layers were critical to Nicor’s decision to embark upon the PBR, and we believe Nicor would not have agreed to the PBR had it not known that the low-cost LIFO layers essentially ensured Nicor’s success. We note that Nicor did not inform the ICC during the initial PBR proceedings of any of the specific strategies it intended to employ to lower the ratepayer’s gas costs, including the benefits which could be. derived by accessing and sharing the benefits of delivering low-cost Company-owned gas to ratepayers. In addition, although the Company has filed quarterly reports with the ICC Staff since the inception of the PBR, the benefits realized from the use of the LIFO layers has not been highlighted to the ICC.

II. 1999 SALE OF DSS STORAGE TO IMD

A. Summary and Conclusion

In December 1999, Nicor released its Delivered Storage Service (“DSS”) rights to IMD. The purpose of the release was to initiate a new partnership with IMD whereby IMD would manage DSS on Nicor’s behalf. DSS is storage leased from Natural Gas Pipeline Company of America (“NGPL”). To manage DSS, Nicor was required under applicable FERC rules to transfer its interest in DSS to IMD. Under an agreement dated December 10, 1999, Nicor agreed to sell 19.8 bcf (billion cubic feet) of gas to IMD at $2.20 per mcf and agreed to repurchase the gas over the ensuing four months at the then FOM index price. The December sale was at market rates but below cost, and caused a loss to ratepayers. Because the sale occurred prior to the implementation of the PBR, the Company did not share in that loss; instead, it went through the PGA and was borne by the ratepayer.

We note that the Company has concluded under applicable accounting principles that the transaction should not have been treated as a “sale,” and is contemplating a series of adjustments to its financial statements as a result. We reviewed a variety of approaches for addressing this issue, and conclude that the most appropriate method would be to assume that ratepayers should be compensated as if this transaction had occurred under the PBR—that is, the risks were shared equally with ratepayers, and the Company should incur half of the eventual loss of $13.5 million. We also examined the possible implications of treating the sale as having occurred under the PBR, including the possibility that the sale would have been accounted for as a storage withdrawal and result in the application of the SCR. We do not believe it is appropriate to give the Company the benefit of the inverted SCR to offset any of the losses caused by the

1999 sale. We conclude that the Company should refund to ratepayers half of the loss, or $6.75 million.

B. Background And Analysis

1. The Managed Storage Agreement with IMD

As Nicor approached the implementation date of the PBR towards the end of 1999, Nicor and IMD discussed the possibility of having IMD provide a “managed storage” service with respect to Nicor’s DSS. IMD had previously provided such a service with respect to Nicor’s NSS capacity.⁸ Nicor had been pleased with IMD’s performance and was interested in pursuing the opportunity of a similar arrangement with respect to DSS.

Under the proposed managed storage agreement, IMD would (1) manage DSS; (2) supply gas to Nicor during peak demand periods; (3) suggest methods by which Nicor could reduce the cost of storage gas cost of both DSS and Nicor-owned gas through the use of financial derivatives; and (4) bundle excess storage capacity for sale to others.

2. The December 1999 Sale and Release of DSS Capacity

To accomplish the managed storage arrangement, Nicor was required under FERC rules to transfer title to the gas to IMD. Nicor and IMD entered into an agreement dated December 10, 1999, by which Nicor sold 19.8 bcf of inventory at a price of $2.20 per mcf, the first of month price for December 1999. Under the agreement, Nicor agreed to release all of its DSS transportation and storage effective December 15, 1999. Nicor agreed to repurchase 2.8 bcf

⁸

Nicor has historically contracted for two kinds of leased storage. “NSS” or nominated storage service was 16 bcf of managed service; historically, the Company would maintain title for about 2 bcf, which could be used to make withdrawals as needed for operational reasons. “DSS,” which stands for Delivered Storage Service, was a “no notice” service. DSS storage is off system storage leased from NGPL. DSS is a “balancing account” in the amount of about 24¹/2 bcf which was treated as storage, and which could be injected and withdrawn as needed from the pipeline into Nicor’s system for operational reasons.

of inventory at a price of $2.20 during the month of December, which was the first of month price for December 1999. Nicor also agreed to repurchase from IMD a minimum amount of gas per month between January 2000 and April 2000, in an amount totaling 15.5 bcf. Nicor repurchased the gas at the first of month NGI city gate price. Finally, the agreement indicated that it was “part of a larger overall management agreement that both parties are employing best efforts to negotiate.” That agreement, the PBR Storage Agreement, was eventually consummated with an effective date of April 1, 2000.

We understand from Nicor personnel that the sale was intentionally executed before the PBR began in January 2000 in order to give IMD the ability to “lock in” certain financial hedges for the month of January. This was confirmed to us in interviews with IMD personnel. As discussed below, however, Nicor personnel were also concerned that if the sale was deferred until after the PBR came into effect, the transfer might have a negative impact on Nicor’s performance under the PBR, and hence, a negative financial impact on Nicor.

3. Consideration of Impact on Ratepayers

We have learned that on or about December 8, 1999, a meeting was held at Nicor to discuss, among other things, the impact on ratepayers of Nicor’s sale of its DSS gas to IMD in December⁹. The major topic of discussion was whether the proposed transaction would hurt ratepayers, since Nicor would be selling gas to IMD at market rates, but below its historical cost. This loss would flow through the PGA and would be borne entirely by ratepayers, rather than

⁹

The attendees at the meeting included a supervisor in the Supply Group, David Cyranoski, Chief Financial Officer at the time, Manager Rate Research, , a manager in the Supply Group, Ted Lenart, Assistant Vice President Supply Operations, Jeffrey Metz, Assistant Vice President and Controller, , a Nicor accountant, and Lonnie Upshaw, Vice President Supply and Technical Services.

“shared” with the Company, as it would be under the PBR if the sale were delayed until after January 1, 2000.

The meeting was attended by a number of Nicor officers from both the financial and gas supply areas. At the meeting, , a Nicor accountant, presented a one-page spreadsheet analysis of the overall impact upon ratepayers if the sale occurred during December. (Exhibit 2 to Appendix) Because the sale would “remove” more recent LIFO layers that were at higher cost, Nicor believed it could fulfill ratepayer demand by using older, lower cost LIFO layers and possibly mitigate the harm to ratepayers. spreadsheet projected the actual inventory cost of gas for the month of December under the assumption that Nicor sell its DSS storage to IMD and use additional inventory for ratepayers during the month, and compared the weighted average cost of gas to the then-prevailing market rate of gas. The analysis considered the potential LIFO decrement required to satisfy ratepayer demand assuming both a partial and full sale of the DSS storage and also considered the weather patterns (warm, normal and cold) in December 1999. The spreadsheet indicates that ratepayers would benefit from the use of lower-cost LIFO layers only if December was a cold month and Nicor sold 20 bcf of gas. Handwritten notes from Jeffrey Metz on the spreadsheet indicate that a “negative” to doing the sale in 1999 was the “perception, impression of managing for PBR if we don’t give low price layers.”¹⁰

The first half of December 1999 was warmer than normal, and the second half of December was slightly colder than normal, but the level of (net) withdrawals was not achieved. During the second half of December, Nicor’s storage field activity reports net injections of 2.3

¹⁰

The spreadsheet neglected that part of the transaction with IMD contemplated the purchase of 2.8 bcf from IMD in the month of December. This would have reduced the amount used from storage during the month of December, and reduced the ability of the Company to get into the low-cost LIFO layers. It should have been subtracted from the total amount of gas sold to IMD in December 1999, but was not.

bcf into storage. We have determined that had the Company managed the LIFO decrement by limiting injections during the month, and withdrawing for sale to the ratepayer additional gas of approximately 4.8 bcf during December 1999, the reported LIFO loss would have been eliminated. This did not occur.

It appears that Nicor personnel were concerned that if the sale occurred after January 1, 2000 under the PBR, it would have had an adverse impact upon the Company’s PBR results. That is because of concern that the sale might constitute an SCA withdrawal under the PBR, impacting the SCR. Furthermore, it was understood that the sale would allow the Company to liquidate its high-cost “LIFO” layer before the PBR came into effect. Thus, Nicor would be position to take advantage of lower-cost gas to help meet PBR goals.

As discussed, Nicor was concerned that ratepayers not be adversely impacted by the December 1999 sale. Nevertheless, while Nicor may have hoped that weather conditions would mitigate any adverse impact on ratepayers, there was no assurance at the time of the sale that this would occur. In fact, it did not. Moreover, we have determined that, notwithstanding the actual weather patterns for December, if Nicor had engaged in a different pattern of injections and withdrawals during the month, the loss to the ratepayer could have been eliminated.

One issue raised during the latter stages of our investigation was whether it was appropriate for Nicor to have recognized any revenue from the December 10, 1999 sale under relevant accounting standards in light of its repurchase obligations. We understand that as of the date of this Report, the Company has preliminarily concluded that the recognition of revenue from this transaction was not appropriate because Nicor did not sufficiently transfer the risks and rewards of ownership to the buyer, IMD. See Securities and Exchange Commission Staff

Accounting Bulletin (“SAB”) 101. We understand that the Company is contemplating a series of adjustments to its financial statements as a result.

C. Conclusion

Our investigation has indicated that Nicor actually sold 18.8 bcf (not 19.8 bcf) of gas to IMD and as a result, was committed to repurchasing only 1.8 bcf (instead of 2.8 bcf) in December 1999. Nicor actually repurchased 2.683 bcf during December 1999, which was approximately 1.0 bcf in excess of its stated obligation. The average repurchase price in December was $2.28 per mcf. Nicor did not repurchase all of the gas under the December 1999 agreement. Approximately 2 bcf remained in DSS at the end of April 2000.

The loss incurred in the sale was $13.5 million. This calculation assumes that the impact on LIFO should be measured on 16.1 bcf (18.8 bcf sold less the 2.7 bcf repurchased prior to year end) and the historical LIFO layer costs. The LIFO cost of this gas ranged from $0.3638 to $3.2315 per mcf.

As noted, the Company is currently contemplating a series of adjustments to its financial statements as a result of this transaction. We reviewed a variety of scenarios with a view towards the most equitable treatment of ratepayers to compensate for any improper or inappropriate conduct on the part of Nicor.

First, we considered the possibility of simply treating the 1999 sale as if the loss had been fully absorbed by the Company rather than the ratepayer, with no further adjustments. We note, however, that there were legitimate business reasons for the transaction, in that it permitted the Company to enter into the managed storage relationship with IMD, and permitted the Company and ratepayers to benefit from the sharing of profits from IMD’s ability to “optimize” this storage.

Second, we considered the possibility of treating the sale as having occurred under the PBR rules that went into effect very shortly after the sale occurred. Under this scenario, the loss on the sale—$13.5 million—would be split evenly with ratepayers. This approach, however, raises an additional issue—whether the sale should constitute a storage withdrawal under the PBR, and therefore, whether it would be subject to some form of adjustment under the SCA. As discussed below, 2000 was an unusual year in that the SCR was “inverted,” that is, it would operate to increase the notional benchmark, not lower it. If the withdrawals were matched with the repurchases in January to March 2000, the SCR for 2000 (which was -$0.68) would cause a reduction of the effective loss from the sale from $13.5 million to $2.5 million.¹¹ This amount would be shared equally between the Company and ratepayers, and yields a total loss to ratepayers of $1.25 million. Thus, depending upon whether the SCR applied, the proposed adjustment to be paid to ratepayers would be either $6.75 or $1.25 million.

We believe that the application of the SCR to the 1999 sale would be anomalous under the circumstances, since the underlying purpose of the SCA was to protect ratepayers from the differential between the price spread between gas injected during summer and withdrawn in winter. Here, the purpose of the transaction was to convey to IMD title to gas so that IMD could manage the storage on Nicor’s behalf. This was not a “withdrawal” for purposes of satisfying ratepayer needs during the winter, for which an adjustment would be warranted to account for the fact that this gas had been injected at a lower cost. Rather, the “withdrawal” was in anticipation of a long term strategy with a business partner, and this gas was planned to be repurchased by Nicor over a period of time.

¹¹

This is calculated by taking the volume (16,118,844) times the SCR (-$0.68), which equals $11 million.

III. DSS AND “VIRTUAL STORAGE”

A. Summary and Conclusion

Under the PBR Storage Agreement, IMD was to supply gas from DSS under a Master Purchase Agreement at prices to be established between the parties. For all periods since January 2000, such purchases have been accounted for as flowing gas purchases except during the period from September to December 2000. During this time, prices were “inverted” (see discussion infra at III.B.2), and the Company decided to report the purchase of certain gas under the agreement with IMD as an injection of gas into storage inventory and essentially, a simultaneous withdrawal. These were characterized in Nicor’s accounting system as “virtual storage” because the gas allegedly never went into Nicor’s storage facility. Gas treated as “virtual storage” as opposed to flowing gas impacted the SCA component of the PBR calculation in 2000. We conclude that this treatment was inappropriate. We also examined other DSS transactions between IMD and Nicor, and conclude the certain of these transactions were not properly accounted for.

B. Background and Analysis

1. The PBR Storage Agreement

On or about April 1, 2000, Nicor and IMD entered into a “PBR Storage Agreement” (the “PBR Storage Agreement”) whereby Nicor and IMD committed to “jointly develop strategies to optimize the value” of PBR storage, defined as including Nicor’s onsystem storage and 24.4 bcf of NGPL recallable DSS Capacity that had been released to IMD under a separate agreement. With respect to the DSS capacity, the PBR Storage Agreement sets forth a mechanism by which IMD would propose “PBR Strategies,” to be accepted or rejected by Nicor,

by which IMD would proposed strategies to optimize the value of the storage through the use of financial hedges or third party sales.

The PBR Storage Agreement sets up a fee schedule. With respect to DSS, IMD and Nicor shared the profits and losses from IMD’s activities. In 2000, profits under the Agreement were defined as physical gas profits (calculated using a formula linked to the market price of gas during the year) plus financial profits (all actual realized gains and losses from derivatives transactions) minus expenses (all expenses of executing the strategy, other than the storage leasing cost). In 2001, under the Agreement, profits were calculated in the same manner as in 2000, except that the physical gas profits reflected the actual realized margin on the sales and purchases of gas rather than the market-based calculation used in 2000. In both years under the Agreement, it appears that Nicor and IMD negotiated the final amount of fees at the end of each year. This would not change our analysis, since it appears that IMD still retained price risks under its relationship with Nicor.

2. The Inverted SCR in 2000

As previously discussed, under the PBR, gas delivered to the ratepayer in any given month is supplied either through the purchase of flowing gas or the delivery of storage gas. Generally, gas purchases for storage (injections) are made during the summer months and delivered (withdrawn) during the heating season when market prices are generally higher than during the injection period. Prices typically differ during these time periods, a phenomenon generally referred to in the industry as the summer/winter spread. Under the PBR, a Benchmark Index cost of gas is determined on a monthly basis by reference to established market index rates in the month of delivery and therefore assumes all gas delivered was flowing gas. In order to

account for the winter/summer spread in calculating a notional benchmark against which Nicor’s performance can be measured, the PBR Benchmark Index is adjusted by the SCA.

The mechanics of the SCA consider (1) theoretical injection and withdrawal patterns; (2) published market index prices; and (3) actual storage withdrawals. The weighting percentages were set by the ICC and were based on Nicor’s historical results. Typically, the weighted average “market price” of injections is less than the weighted average “market value” of withdrawals. A normal SCR would reduce the notional benchmark. However, during 2000, as discussed below, the weighted average “market price” of injections was greater than the weighted average “market value” of withdrawals. This created an “inverted” SCR that increased rather than decreased the notional benchmark.

3. IMD and Nicor Agree to Change from a Managed Supply to a Managed Storage Arrangement

As previously discussed, the PBR Storage Agreement entered into in April 2000 was viewed as a “managed service” arrangement. According to Nicor personnel, in or around May 2000, IMD notified Nicor that given the market conditions there was little opportunity and incentive for IMD to continue to pursue the existing “managed service” arrangement whereby IMD, among other things, placed financial hedges for the benefit of Nicor. Ordinarily, the summer is the period during which storage is increased, and prices are typically lower than during the winter. In and around May 2000, however, the forward price of gas in the fall was approximately the same as the then-current price of gas. According to both Nicor and IMD, this meant that it was difficult for IMD to place financial hedges on any gas purchases made at the time, and it meant that there was no particular incentive for IMD to purchase summer gas to place into storage.

Nicor informed IMD that from an operational standpoint, it needed to place gas into storage during the summer of 2000 for use in the upcoming 2000/2001 heating season. Moreover, under the NGPL DSS storage lease and applicable tariffs, IMD was required to fill the leased storage during the summer months. In July 2000, IMD and Nicor agreed to three strategies described below. The three strategies covered the 2000/200l heating season and accounted for a minimum DSS inventory of 23.2 bcf. The agreement provided that IMD would completely fill the DSS storage by October 31, 2000. To accomplish this, IMD was obligated to inject 14 bcf (of which 4.42 bcf was already in the ground as of 6/l/2000; thus, IMD would inject 9.58 bcf between 6/l/2000 and 10/31/2000). For its part, Nicor had an obligation to inject 9.2 bcf. In exchange for filling the DSS storage, Nicor agreed to repurchase from IMD in November 2000, December 2000 and January or February 2001 the amounts injected pursuant to the following three “strategies.”

•

DSS 2000 Cycle (Strategy No. 1) Nicor agreed to buy 8.4 bcf from IMD at a weighted average price of the benchmark during the June—October injection period plus cost of funds (COF). The strategy was amended in August to increase the volume to 9.4 bcf. Under this “managed storage” arrangement, IMD filled the storage in summer and carried the gas cost on IMD’s books, and Nicor purchased the gas from IMD later that year—but at summer 2000 prices rather than at the FOM November and December prices.

•

DSS Flex Cycle (Strategy No. 2) Nicor further agreed to buy 3 bcf in Jan/Feb 01 at a price equal to the weighted average cost of gas plus cost of funds plus financial gains/losses.

•

Jan/Feb 2001 Purchase Volumes (Strategy No. 3) Nicor agreed to buy 9.2 bcf in Jan /Feb 01 at a price equal to FOM index in month of delivery. The agreement appears to have provided for an alternative pricing of IMD cost plus cost of funds plus financial gains/losses.

Under the terms of Strategy No. 1, Nicor purchased approximately 15.6 bcf of gas from DSS from September to December 2000. Approximately 13.5 bcf was accounted for as delivered to the ratepayer in 2000.¹² With respect to the 13.5 bcf of gas, the Company reported an injection and simultaneous withdrawal. This was referenced on the Company’s GasPro accounting system as “virtual storage.” The reporting of the gas purchases as virtual storage in the fall of 2000 increased reported withdrawals by 13.5 bcf. The SCR was inverted (-$0.68), and the Benchmark was increased by approximately $9 million, with the resulting commodity gain shared with the ratepayer on a 50/50 basis. Under the terms of Strategies 2 and 3, gas that was purchased by Nicor from the same DSS storage facility starting in January 2001 was not reported as virtual storage and was accounted for as flowing gas purchases; thus, there was no impact on withdrawal volumes for the SCR.

4. Nicor Decides To Account for Gas as “Virtual Storage”

Based on our interviews and review of internal documents, it appears that there was a very strong disagreement among Nicor personnel as to how Nicor should account for the summer 2000 injections by IMD associated with Strategy 1. A view held by some was that while IMD was injecting this gas for the benefit of Nicor, the purchase of the gas from IMD should be treated by Nicor as flowing gas purchased at the time the volumes were withdrawn from storage. The contrary view was that since it was Nicor that had caused the gas to be placed into storage, and it was merely paying IMD the injection price (plus cost of funds), these volumes should be treated by Nicor as stored gas having come from storage at the time of withdrawal.¹³ We were

^l2

To date the balance of this gas is being accounted for as gas in storage held in a leased facility.

^l3

Various individuals told us that the concept of “virtual storage” was not a new one. For instance, Lenart told us that he believes that the term “virtual storage” comes from the historical

(continued)

told that this method was designed to capture the winter/summer spread that would otherwise apply if the gas had been placed into storage, and to the extent that the summer prices were lower than the winter prices, this treatment provided a benefit to ratepayers.

We reviewed the circumstances behind a September 18, 2000 e-mail from , Manager Rate Research to George Behrens, Vice President Administration and Treasurer (with copies to Jeffrey Metz, Assistant Vice President and Controller and Lonnie Upshaw, Vice President Supply and Technical Services) on the topic of virtual storage. (Exhibit 3 to Appendix) states in this e-mail that he had been asked by Behrens if virtual storage was “acceptable under the PBR.” indicated that he “would not be in favor of this transaction” because, in his view, it artificially inflated the Benchmark, was inconsistent with the Company’s representations to the ICC about the use of storage, and because the transaction did not lower gas costs. After sent the e-mails, he and Upshaw met to discuss position.

Notwithstanding concerns, Upshaw went forward with the strategies. Behrens, to whom e-mail was addressed, told us that he was surprised to have learned in 2002 that the treatment had been followed given opposition.

We also looked into why Nicor did not simply retake title to the DSS storage and accomplish the storage injections on its own behalf. We were informed that this did not occur because of accounting concerns. Specifically, in the summer of 2000, Nicor was working with its outside auditors to “recognize” LIFO inventory decrements in their quarterly financials. As explained above, Nicor typically calculated its LIFO layers at the end of the year. We understand

practice of retaining title to 2 bcf of NSS storage for balancing purposes, which was also accounted for as “virtual storage.” Lenart agreed that the “virtual storage” in 2000 was different in that the Company did not have or take title to the gas.

that the Company’s outside auditor, Arthur Andersen (“Andersen”), permitted Nicor to recognize the benefits of a LIFO decrement on a quarterly basis only to the extent that Nicor could establish with reasonable certainty that such a decrement would actually occur at the end of the year. Although Nicor was, in fact, certain that LIFO decrements would be realized by year end, establishing that fact to the satisfaction of Andersen was difficult. We have been told that Nicor realized that they would be unable to meet their second and third quarter financial targets if the DSS inventory was returned in the Summer of 2000 to their balance sheets as “inventory.” Therefore, the decision was made to hold off on that accounting treatment until the very last moment—when the gas was actually sent to the burner tip to service Nicor’s ratepayers in the fall/winter of 2000.

C. Conclusions

The reporting of the gas purchases under Strategy 1 as “virtual storage” in the fall of 2000 increased reported withdrawals under the PBR by 13.5 bcf. Since the SCR was inverted (-$0.68) the Benchmark was increased by approximately $9 million. The resulting commodity gain was shared with the ratepayer on a 50/50 basis. We do not believe that this treatment was appropriate.

We reviewed a number of possible methodologies to address this situation. In particular, we looked at whether the DSS storage arrangements represented a form of product financing under FASB Statement No. 49. As discussed in more detail in the section regarding Storage Prefills, see infra Part VII.B, a product financing occurs when a party sells a product and agrees to buy it back later at a specified price, or if a party arranges for another party to purchase a product on its behalf and agrees to buy the product from that party at a later date.

We understand that the Company has preliminarily concluded that these transactions should not be accounted for as product financing because the fee payment arrangement in the PBR Storage Agreement provided IMD with some of the risks, rewards and benefits of ownership of this gas.¹⁴ According to the Company, the various DSS transactions should be viewed as a whole under the terms of the PBR Storage Agreement, and that because of the profit sharing fee mechanism provided for by the PBR Storage Agreement, the price paid by Nicor for the gas it receives from DSS would be subject to at least some variability and risk, and therefore, the requirements of FASB Statement No. 49 are not met.

As of the date of this report, we have requested information from IMD to confirm the actual settlement process under the PBR Storage Agreement, and we are in the process of confirming how, in fact, the process worked. Assuming, however, that the Company’s representations to us are correct, we believe that the price risks associated with the PBR Storage Agreement would confirm that the virtual storage PBR accounting with respect to Strategy No. 1 is incorrect—the gas repurchased under Strategy No. 1 should have been treated as flowing gas for purposes of the PBR.

Significant to our conclusion that virtual storage was inappropriate is that under the profit-sharing mechanism contemplated by the PBR Storage Agreement, the economic substance of the transactions contemplated by Strategy No. 1 and Strategies Nos. 2 & 3 would have actually differed little, and there would seem to be no justification for treating them differently for PBR purposes. Under the parties’ interpretation of the PBR Storage Agreement, physical losses or gains on gas were to be returned to the Company minus some form of a

^l4

The Company also determined that with respect to gas sold by Nicor to IMD and subsequently repurchased, these transactions do not represent valid sales under SEC Staff Accounting Bulletin 101.

management fee. Thus, even if the pricing on Strategy No. 1 was established as the injection price, and the pricing on Strategies Nos. 2 & 3 were set under a market-based index, losses or gains that IMD obtained as a result were to be returned to Nicor at the end of the year, minus the agreed-upon sharing percentage. Looking at the transactions as a part of the entire PBR Storage Agreement rather than as discrete transactions, and further assuming that the Company’s payments to IMD were consistent with the Agreement (and we caution that this is an issue that we are still reviewing), we do not believe that it was appropriate for the Company to have treated gas purchased under Strategy No. 1 as a storage withdrawal.

We also note that the Company and IMD actually engaged in various hedging activities with respect to some portion of this gas to protect against a price decline between the time of injection and withdrawal. The effect of the hedge was to convert summer priced gas to a winter index price. This fact is inconsistent with Nicor’s stated rationale behind treating the gas purchased under Strategy No. 1 as “virtual storage”—providing ratepayers with the benefits of the winter/summer spread by paying summer injection prices at the time of the withdrawal in the fall and winter. This eliminated gains derived from the increase in price between the summer and winter—the very summer/winter spread that Nicor was purportedly capturing for the ratepayers by treating these volumes as virtual storage.¹⁵

We further understand that the Company has preliminarily concluded that with respect to gas sales from Nicor to IMD that Nicor repurchased from IMD, the Company should

^l5

In this context, we note again, as discussed supra pp. 24-25, that application of the SCR to volumes of gas withdrawn from storage that do not reflect the impact of the summer/winter spread would be anomalous. The SCA was intended to reflect the fact that volumes of gas withdrawn from storage are generally priced at injection prices, not prices at the date the gas is withdrawn. Nicor’s decision to hedge volumes of gas termed “virtual storage” eliminated the summer/winter spread, and thus the SCR should not be applied.

not record these as sales under SEC SAB 101, discussed above, because Nicor had a “continuing involvement” with this gas.¹⁶ The Company has prepared a financial calculation of the impact of this effect, in conjunction with the effect of correcting the accounting errors regarding prefills, to quantify the harm to the ratepayer. That calculation seeks to determine the amount of under or over-payment by the ratepayer by quantifying the effect of the error on actual gas costs and upon the Company’s performance under the PBR. We are relying upon the Company for this quantification, which is discussed in more detail below in connection with prefills at Part VII.

Finally, included in the payments made to IMD under the various strategies was a cost of carry (i.e. interest component) in the following amounts: 2000—$1 million; 2001—$3.l million. These costs were included with the cost of gas and included in the PGA. Had Nicor obtained the financing on this inventory directly, the related interest cost would not have been recoverable under the PGA. We do not believe it was appropriate to have included these costs in the PGA.

¹⁶

We note that as an accounting matter the conclusion that these transactions were not “sales” would return those volumes of gas to Nicor’s financial statements as inventory, and thus when this gas was flowed to the ratepayer those volumes would be considered withdrawals, not sales of flowing gas. Arguably, however, those withdrawals may not be SCA withdrawals, as Nicor may very well have “hedged” those volumes of gas in the identical fashion that it hedged “virtual storage.” As discussed above, the effect of those financial hedges was to eliminate the summer/winter spread, and thus arguably, application of the SCR to these volumes of gas would, like virtual storage, be anomalous.

IV. 2001 METER READING ERROR

A. Summary and Conclusion

A meter reading error occurred on the NGPL pipeline in early 2001 in which delivered gas volumes were under-reported to Nicor by NGPL. After discovering the problem in June 2001, both Nicor and NGPL quantified the impact and agreed to reduce the DSS storage volumes for the gas actually delivered to Nicor. In August 2002, a final adjustment was made that will correct the error if Nicor makes a 2002 PBR filing. We note that if there is no 2002 PBR filing the error will not be corrected. We further note that the 2001 PBR has not been amended and re-filed, which may be required by the ICC.

B. Background and Analysis

In mid-2001, Company personnel discovered a measurement error at the NGPL meter on the primary pipe used for deliveries to Pontiac, Illinois. It was determined that a valve calibrated by NGPL personnel on March 21, 200l had been left partially open. This action caused the volume of gas sent to Nicor by NGPL to be under-reported for the period Match 21 through May 8, 2001. Once the problem was discovered, both Nicor and NGPL immediately took steps to resolve the billing discrepancy.

Nicor uses one set of data to record PBR results and a second set to invoice customer sales and provide the financial data used in Nicor’s annual reports. We have been told that Nicor records its metered gas volumes on the tenth of each month. The gas amounts for the balance of the month are estimated and reconciled during the next meter-reporting period.

After discovering the metering error, Nicor personnel immediately tried to fix the problem by making a manual adjustment to increase the under-reported volumes impacting PBR results for the affected time period. We were advised that this action reflected an attempt to

preserve the integrity of the PBR data inputs and protect the interests of ratepayers. In June 2001, after the volume adjustments had been made, the corrected volumes automatically flowed through Nicor’s reporting system. However, the manual adjustment made to the PBR data system was never removed, resulting in a double counting of the gas volumes for the March-June 2001 time period. Our investigation supports a finding that this omission was inadvertent.

C. Impact on the PBR

In January/February 2002 the Company filed the PBR for the 2001 calendar year. In March 2002, the Company, in gathering information to compile its quarterly report to the ICC, determined that the recorded gas deliveries did not agree with amounts in the PBR filing. The Company ultimately concluded that the differences were related to the metering error and that the repotted volumes in the PBR filing were incorrect. Company personnel made a decision not to amend the previous filing but have instead opted to correct the volumes in the anticipated 2002 PBR.

The actual cost of gas was corrected by the end of fiscal 2001 and, as such, them was no impact on the gas cost included in the PGA for 2001. However, the volumes were misstated on the 2001 PBR report that resulted in a $2.3 million overstatement of PBR savings in 2001. This overstatement resulted in a $1.15 million PBR savings being charged to ratepayers in 2001. The Company has estimated the gross error to be $2.7 million. This estimation, however, did not include an accurate adjustment to the volumes in the months during which the billing error occurred.

D. Options Considered to Correct the Error

The Company considered the following options to resolve the metering discrepancy: (1) amend and re-file the 2001 PBR; (2) adjust the March 2002 volumes in order to correct the volumes of the prior two years; and (3) adjust the March 2002 volumes and dollars to take into account the pricing differential between the months impacted in 2001 and March 2002. The Company decided to use Option 2 to resolve the discrepancy.

We have determined, through the course of our interviews with Company personnel, that Option 2 did not take into account the pricing differential between the years 2001 and 2002. Option 3 was not chosen because the difference was not deemed to be material. It remains unclear why Option 1 was not chosen. George Behrens has told us that he had ultimate responsibility for these decisions.

E. Conclusion

Because the PBR savings for 2001 and 2002 were still overstated by approximately $460,000 after the adjustment required under Option 2 was made, in August 2002, a further adjustment was made to the PBR which, if Nicor completes a 2002 PBR filing, will fully correct the metering error. We note that absent a 2002 PBR filing, the metering error will not have been corrected. We further note that the 2001 PBR, to date, has not been amended. We cannot predict what action, if any, the Commission will require Nicor to take in light of the fact that, assuming a 2002 PBR filing, Nicor will have corrected the metering errors.

V. WEATHER INSURANCE PURCHASED FOR FISCAL 2001

A. Summary and Conclusion

The Company purchased a weather insurance product from Aquila for fiscal 2001. The quoted premium for the insurance product was substantially higher than the prior year. Nicor decided to package the insurance product with a second transaction in which Nicor sold gas to Aquila which was initially valued at approximately a $2 million discount. We conclude that the Company knew or should have known that this transaction was improper.

Quantifying the harm to the ratepayer, however, depends upon whether the ratepayer will be permitted to retain the LIFO benefit. Arguably, if it were appropriate for a LIFO decrement to have been used at the Company’s discretion to mitigate the Aquila loss, the ratepayer was not harmed by this transaction. However, we understand that the Company will be making adjustments relating to Storage Prefills and DSS sales, see Part VII, infra and Part II, supra, which would remove any such LIFO decrement. The ultimate harm to the ratepayer will depend upon whether the ratepayer will be permitted to retain the LIFO benefit. If the LIFO benefit was not retained, the ratepayer was harmed by the Aquila transaction in the amount of approximately $3.1 million. If the LIFO benefit was retained, the ratepayer was arguably not harmed by the Aquila transaction.

B. Background and Analysis

Weather insurance is a financial derivative product designed to help recover lost revenue resulting from unpredicted weather variance. Generally, insurance payments are determined based upon variances from a predicted number of “degree days” over the winter. Weather insurance is not a cost that is run through the PGA, but instead is a utility cost that

impacts the Company and shareholders. Indeed, Nicor did not share any insurance payments received in 2000 or 2001 with ratepayers.¹⁷

1. Nicor’s Decision To Purchase Weather Insurance For Fiscal 2001

For the fiscal year 2000, Nicor purchased weather insurance to help manage the risk of unpredicted weather variance. The weather during the 2000 calendar year during the winter months was warmer than predicted, and thus Nicor benefited from the weather insurance it had purchased. Based on that experience, Nicor determined that it would likewise benefit from weather insurance for the 2001 calendar year. Due in part to the larger than predicted pay-outs under the insurance policy in 2000, weather insurance providers sharply increased the premium for similar weather insurance policies that would run for the 2001 calendar year. Nicor investigated the options of weather insurance for 2001, and among the various providers, Aquila offered the most competitive price. That price, a steep increase from the previous year, amounted to a yearly premium of approximately $3.5 million. The net premium represents a call premium paid of $5 million (floor) and a put premium received of $1.5 million. In a warm winter, Nicor would call on the floor to receive insurance benefits and, conversely, in a cold winter Aquila would call on Nicor to pay under the ceiling.

As early as August 2000, Nicor investigated opportunities to lower the cost of the insurance premium by combining the purchase of weather insurance with a “supply deal,” which would provide discounted gas to Aquila. The idea originated with Katherine Halloran, Nicor’s Chief Financial Officer; however, it appears that most of Nicor’s Senior Management, including

^I7

Because insurance is a relatively new financial product, we are unaware of any regulatory body having addressed the treatment of this type of insurance in a rate case. However, given the fact that weather insurance is intended to defray costs that have never been passed on to, and do not affect, the ratepayer, it would seem likely that the ICC would conclude that the costs of such insurance should not be passed on to the ratepayer.

Phillip Cali, George Behrens, and Lonnie Upshaw, were aware of, and involved in, the decision-making and/or structure of the Aquila weather insurance deal. Thomas Fisher approved of the transaction.

The concept was that Aquila would lower the insurance premium it charged to Nicor to the extent of the discount that it received from Nicor on the supply deal. Ultimately, in the fall of 2000, Nicor agreed to sell gas to Aquila in the future months of March and April 2001. Nicor used the futures market (the NYMEX) for March and April 2001 to establish a “market price” for gas in the future months of March and April, and provided discounts from those predicted future prices to Aquila that amounted to $2 million.”¹⁸Aquila, in turn, discounted Nicor’s insurance premium by $2 million.

2. Using Low Cost Gas In Inventory To Offset The Aquila Losses

Senior Management at Nicor were cognizant of the likelihood that the sale of gas to Aquila would have to be run through the PGA, affecting the cost of gas charged to the ratepayer. Nicor also understood that Nicor could not engage in gas supply transactions that harmed the ratepayer. Thus, it was imperative that Nicor somehow “offset” the $2 million predicted loss from the future sale of gas to Aquila. Nicor made the decision, in conjunction with the Aquila deal, to liquidate additional LIFO gas to fund the $2 million predicted loss with Aquila. We were told that in this manner, Nicor assured itself that the Aquila transaction would not harm the ratepayer because sale of the additional LIFO layer would allow the Company to meet its 2001 financial targets.”¹⁹

¹⁸

Specifically, Nicor agreed to sell 1.5 bcf of gas to Aquila in both March and April 2001 at an average price of $3.35, which amounted to a $.69 discount.

¹⁹

Nicor’s assumption that the ratepayer was not harmed by the Aquila transaction turns on the question of who owns the LIFO inventory—the ratepayer or Nicor. If the ratepayer owns the LIFO inventory, then it appears that the LIFO layers that were liquidated to offset the Aquila loss

(continued)

Some Nicor employees believed that Nicor would actually service the supply deal with low-cost LIFO gas. In that scenario, the transaction seems to be a “win-win” transaction, in that Nicor sold gas with a cost of $.30 for $3.35, logically recognizing a profit to the ratepayer of $3.05.²⁰ The impossibility of “tracking” molecules of gas, however, makes the above analysis overly simplistic and inaccurate. In fact, Nicor could not possibly track the molecules of gas that were delivered to Aquila, and thereby ensure that Aquila received the low-cost LIFO gas. As a further complication, because of the manner by which Nicor’s inventory is priced, the exact price for gas sold from inventory could not be definitively settled until the end of the year, when the actual LIFO decrement would be established.

Thus, determining which molecules of gas flowed to Aquila was purely an accounting matter. We believe that Nicor had concluded from the beginning that it would be accounted for as flowing, market-priced gas—not low-cost LIFO gas. As a result, the Aquila transaction appeared on the financial statements as a loss, in that Nicor intended to purchase gas at market prices in March and April, and sell that gas to Aquila at the discounted rate established in the fall of the previous year. Moreover, due to market conditions, by the time Nicor had to

were wasted. By using them to offset a loss, as opposed to recognizing a gain to the ratepayer, arguably the ratepayer lost the value of LIFO gas. Most Nicor employees we interviewed disagreed with this assessment. In their minds, the LIFO inventory is a Company asset, to be used at the Company’s discretion for any purpose. Thus, the ratepayer has no “right” to the LIFO layer benefit, and using them to offset a loss, such as Aquila, is not improper. Based upon our own legal analysis, we believe there is merit to Nicor’s assessment. See infra Part I.

²⁰

Arguably, the ratepayer still lost something—the “opportunity cost” of foregoing the opportunity to sell the very same gas at market prices for a slightly larger profit. Nicor has taken the position that absent the Aquila transaction Nicor never intended to use that additional LIFO gas, and therefore, no opportunity was lost.

purchase that gas in March and April, the apparent loss on the financial statements sheet had ballooned to over $6 million.²¹

However, while Nicor accounted for the gas as flowing, it also intended to use the LIFO gas by selling LIFO gas to ratepayers in an amount sufficient to offset the Aquila loss. In essence, Nicor planned a hybrid approach: (1) provide Aquila with market-priced flowing gas and (2) liquidate additional LIFO gas that would not have been liquidated but for the Aquila transaction to offset that loss.

3. Nicor Discussions Concerning The Aquila Transaction

Every member of senior management we interviewed recalled that a specific discussion took place for the purpose of “airing out” concerns regarding the use of low-cost LIFO gas to help offset the cost of weather insurance purchased by Nicor from Aquila. Cali, Halloran, Behrens, and Upshaw were all in attendance at this meeting, which probably took place on or about August 10, 2000.

At this meeting, it appears that only George Behrens expressed misgivings at engaging in the transaction. This view was based upon his belief that if the LIFO gas was sold under the below-market terms envisioned, the ratepayers would be hurt because they would not have realized the full value of the LIFO gas. Halloran and Cali were both in favor of moving forward with the deal, because in their view Nicor, rather than the ratepayer, owned the LIFO gas. Behrens told us he realized that he could not prevent the Aquila transaction from going forward. The next day, on August 11,2000, Behrens circulated a memorandum attempting to

²¹

Under the assumption that Nicor planned to liquidate low-cost LIFO inventory to offset the Aquila loss, Nicor did not attempt to “hedge” the gas supply component of the Aquila insurance deal. Nicor was comfortable that whatever the recognized loss on flowing gas turned out to be, it could be effectively eliminated by liquidating additional LIFO inventory.

summarize the reasons discussed at the meeting for going forward with the Aquila deal to make sure everyone involved was “on board” with the Company decision. (Exhibit 4 to Appendix) Cali responded to the memo by e-mail on August 15, 2000, in which he explained the various rationales that would support going forward with Aquila. (Exhibit 5 to Appendix)

Once it was determined that the Aquila transaction would go forward, , who reported to George Behrens and was responsible for financial forecasting, banking and financing, began negotiations with Aquila to agree upon the terms of the insurance policy for the 2001 calendar year. At the same time, the Supply Group began working on the gas supply component of the transaction. It appears that , a manager in the Supply Group, worked out the specifics of the deal, at Upshaw’s direction. It appears that , a supervisor in the Supply Group, was aware of, and we believe involved in, the particulars of the Gas supply component.

told us that he discovered the Aquila transaction by accident, during a discussion with . From a regulatory perspective, was troubled by the decision to link weather insurance, a Company derivative product, with a gas supply deal, that would run through the PGA. said he later spoke with Halloran about the deal, and explained to Halloran that in his opinion it was not permissible under the PBR for Nicor to use costs that are passed through the PGA to offset non-PGA costs of the Company.²² told us that he expressed this disagreement to linking a supply deal to weather insurance with Upshaw as well.

In mid-October 2000, Jeffrey Metz, Nicor’s Controller and Assistant Vice-President, became aware of the Aquila transaction. Metz, like questioned the propriety of the transaction, and began asking questions to understand how the transaction was structured.

Metz recalled that at some point he was told by someone (he could not recall who) that he should leave the transaction alone, as it had already been approved “at the highest levels” of the Company. Although he believed the transaction was improper, Metz did not pursue the issue.

C. Propriety Of The Transaction

The Aquila transaction as structured was clearly improper. The Riders on file with the Commission preclude Nicor from running costs through the PGA that are not defined as recoverable gas costs. The theory is that ratepayers should not be harmed by transactions that inure only to Nicor’s benefit—not the ratepayer. Weather insurance is a Company derivative product, and Nicor’s sale of gas to Aquila, engaged in for the purpose of decreasing Nicor’s premium for weather insurance, was run through the PGA. As such, this transaction should not have taken place.

During the investigation, many Nicor employees defended the transaction on the grounds that it did not adversely affect ratepayers. Some Nicor employees believed that the transaction was intended to be a “win-win” transaction, in which both Nicor and the ratepayer were to financially benefit. We do not believe that to be the case. As conceived and enacted, the purpose of the Aquila transaction was to benefit the Company by lowering its weather insurance cash premium, while at the same time ensuring that the ratepayer was not harmed. The purpose was to benefit Nicor, not to benefit the ratepayer. The Riders do not permit otherwise prohibited transactions where the ratepayer’s loss is mitigated through other, offsetting transactions.

²²

Halloran told us that she did not recall this conversation.

D. Costs Incurred By The Ratepayer

Although this transaction was improper and should not have occurred, quantifying the injury to the ratepayer, if any, is a separate and distinct issue. In our interviews, Nicor employees told us that Nicor did liquidate LIFO layers at the end of the year to offset the Aquila loss. Nicor did plan to liquidate additional quantities of LIFO gas to offset the Aquila loss, and Nicor did reach its financial targets at year end.²³ Under this view, there was no harm to ratepayers.

However, we note that it is unlikely that Nicor did in fact access the low-cost LIFO layers in 2001. The Company presently intends to recalculate its PBR filings in light of changes to the accounting treatment of its Storage Prefill transactions and DSS transactions (see supra Part III and infra Part VII.) These changes will effectively eliminate the low-cost LIFO decrement that Nicor recognized in its financial statements for 2001 (as well as 2000) that “offset” the harm to ratepayers realized by the Aquila transaction. If Nicor is permitted to “reverse” the benefit the ratepayers gained from liquidation of low-cost LIFO layers, the ratepayer will not have received any benefit from the low-cost LIFO gas. In other words, if Nicor restates its PBR earnings and reverses the benefits to ratepayers from liquidating low-cost LIFO layers, Nicor will have also reversed the LIFO gas liquidation that arguably “offset” the loss that was realized on the gas supply component of the Aquila transaction. In that event, the Aquila transaction would have harmed ratepayers in the amount of half of the loss it realized on the below-market sale to Aquila that was flowed through the PGA—approximately $3.l million.

²³

We have not undertaken to analyze and do not offer any opinion about potential securities law disclosure issues relating to the Company’s use of the LIFO gas.

E. Conclusion

The Aquila transaction was clearly improper. However, the harm to the ratepayer depends upon whether the ratepayer will be permitted to retain the LIFO benefit. If the LIFO benefit to the ratepayer is reversed, then the ratepayer was harmed by the Aquila transaction in the amount of $3.1 million. If the ratepayer is permitted to retain the LIFO benefit, then arguably the ratepayer was not harmed by the Aquila transaction.

VI. IN-FIELD TRANSFERS

A. Summary and Conclusion

Another allegation we investigated was whether ratepayers were adversely affected under the PBR in 2001 because the amount of withdrawals from storage were artificially decreased by improperly categorizing certain withdrawals as “in-field transfers” undertaken for operational reasons, which would not be counted as withdrawals under the PBR. In-field transfers are defined as those movements of gas within the storage system to provide for the efficient use of the aquifers (to satisfy operational needs) and to maintain the integrity of the aquifers, not to service the ratepayer. We reviewed these reported transfers, and interviewed the Nicor personnel involved in making these decisions. We conclude that an adjustment in favor of ratepayers is appropriate because of inconsistency in the method used by Nicor to account for in-field transfers.

B. Background and Analysis

1. Definition of an In-field Transfer

An in-field transfer is a movement of gas for the benefit of the maintenance of the aquifers in which the gas is stored, as opposed to movements of gas to service the ratepayer. Aquifers are made of porous rocks. If the gas pressure in the aquifers is too low, it would be difficult to withdraw gas when needed. If pressure is too high, gas may be lost by being forced outside the aquifer. Injections and withdrawals of gas are therefore necessary to keep each aquifer within a desirable range of pressure. These injections and withdrawals are not being made to service the ratepayer. During the relevant time period, was the Supervisor of Storage Management and was responsible for maintaining the operational integrity of the

aquifers and track in-field transfers, and was supervised directly by Lonnie Upshaw. Manager of Storage Operations, was also responsible for tracking in-field transfers.

Prior to the PBR, there was no reason to keep track of in-field transfers. Transfers for operational reasons did not affect the financial results of the Company. Under the PBR, however, withdrawals from storage to service the ratepayer are tracked, because pursuant to the PBR Order each unit of gas withdrawn from storage to service the ratepayer affects the notional benchmark through the SCA. Each aquifer is metered at various stations in order to record injections and withdrawals, but these meters do not, and cannot, determine which withdrawals were made for “operational reasons” and which were made to service the ratepayer. In a normal year, the SCR will serve to lower the Benchmark, and therefore categorizing an in-field transfer as a withdrawal to ratepayers will negatively affect Nicor’s performance.

In the year 2000, the first year of the PBR, the Company did not keep track of infield transfers to properly determine the amount of withdrawals that were made for operational reasons as opposed to servicing the ratepayers. Nor was it in Nicor’s interest to do so because, as discussed above, the SCR was inverted during 2000. In other words, Nicor’s performance under the Benchmark was not negatively affected by including operational transfers as storage withdrawals to service ratepayers.

In approximately January, 2001, an accountant in the gas supply group, was requested to develop a definition of in-field transfers. formulated a four- part test to determine whether a withdrawal of gas qualified as an in-field transfer:

1. The transfer volumes did not require a change in the purchase plans for that day.

2. The transfer volumes were unrelated to changes in the demand forecast for that planned day.

3. The volumes related to the in-field transfer can be specifically identified (i.e., it was clear that the field injected or withdrew gas for a specified period of time for operational reasons).

4. Storage Management provided documentation to supply Accounting and Gas Purchasing. The documentation should clearly classify the related volumes as an in-field transfer and specify the fields impacted on a particular day.

The Company prepared a monthly schedule of in-field transfers, certified by and , that incorporated this definition and quantified the amount of in-field transfers on a daily basis. (Exhibit 6 to Appendix) This form, along with the definition, appears not to have been provided to and others in her department until mid-2001.

The definition was unworkable for multiple reasons. First, the terms in the definition—including the “plan”—are insufficiently specific. Nicor has many daily plans, which Nicor prepares on a seasonal basis and updates at various times. Moreover, the concept of defining an in-field transfer based upon whether the movement of gas was “planned” does not necessarily reflect the question of whether the transfer was done for “operational reasons.” was of the opinion that any transfer of gas could be properly defined as an in-field transfer based upon the insufficient definition. The four part definition was never followed in practice.

2. Nicor’s Tracking of In-Field Transfers During 2001

During 2001, the SCR which was to apply to each in-field transfer was significant, and thus each unit of gas withdrawn from storage to service the ratepayers had the effect of significantly lowering the Benchmark and making it more difficult for Nicor to beat. It was therefore in Nicor’s interest to ensure that only those withdrawals which were made to service

the ratepayer were included in the SCA.²⁴ One way to do this would be to keep track of in-field transfers, and thereby decrease the number of withdrawals which would affect the notional benchmark.

said that there were more in-field transfers in 2001 than 2000 because the weather was warmer causing the aquifers to fill too rapidly. Moreover, noted that Nicor’s profit incentive under the PBR put operational pressures on the storage fields that required increased use of operational transfers.

says she felt pressured to record in-field transfers. attended daily meetings where the operational needs of the aquifers and the ratepayer needs were discussed. In the fall of 2001, says individuals from Gas Supply at these meetings made comments that transfers which stated would occur on the given day should be categorized as in-field transfers. said that she could not recall the names of anyone who pressured her at the morning meetings.

²⁴

It is worth noting that the total volume of withdrawals in 2001 (Nicor’s “cycle”) was approximately 45 bcf, well below historic estimates of Nicor’s cycle. We did not find evidence indicating that this was because of improper attempts to manipulate the storage cycle. In January of 2001, based upon concerns regarding Nicor’s ability to service ratepayers for the remainder of the winter, Nicor obligated itself to purchase large quantities of gas. December 2000 was exceedingly cold, and Nicor needed to ensure that it had sufficient stores of gas in the event January 2001 was equally cold. January 2001 turned warm instead, however, and Nicor was forced to purchase large quantities of gas at historically high prices. As a result, Nicor recognized a small withdrawal in January, which was also predicted to be the highest priced gas of the year. Given its withdrawal performance in January, Nicor recognized that it would “under-perform” against the storage component of the Benchmark unless it, at minimum, matched its withdrawals to the SCR weightings. Thus, after January, Nicor planned a greatly reduced storage cycle in an attempt to beat the storage component of the Benchmark. Pricing in the summer and fall further reduced Nicor’s storage cycle. Summer-priced gas proved to be very expensive, in fact mote expensive than future fall/early winter gas prices. Thus, at times when Nicor would normally sell its storage gas to ratepayers (increasing the cycle) to gain the benefit of the summer/winter spread, Nicor chose instead to provide cheaper flowing gas to the ratepayer. That decision resulted in further reductions in the storage cycle.

, a gas supply employee, confirms that she occasionally would say to at the morning meetings, “this is going to be a transfer isn’t it?” According to and many of Gas Supply representatives attending these morning meetings, was stating that the fields required withdrawals of gas above and beyond those required to service the ratepayers. Based on their understanding of in-field transfers, believed such movements of gas should be appropriately defined as in-field transfers. did not understand her comments at these morning meetings as “pressure” on , but appropriate give and take to determine which, if any, transfers should be accounted for as in-field transfers. It should be noted, however, that was a lower level employee than others, including , at the morning meetings.

Upshaw acknowledges that told him that she was getting pressure in the morning meetings to designate withdrawals of gas as in-field transfers. Upshaw says he told her that it was her decision. Upshaw said that he gave the responsibility for deciding whether a gas movement was to be designated as an in-field transfer so that people in the gas supply group would not “game the system.”

recorded withdrawals of gas as in-field transfers for each day beginning October 24th and running through December 17th, with the exception of only one day. The in-field transfers in 2001 totaled approximately 12 bcf, which were then considered to be withdrawals that were not made to service the ratepayer, and thus were not included as withdrawals under the SCA which affected the notional benchmark. Because the SCA in 2001 lowered the notional benchmark for each unit of gas withdrawn, exempting these withdrawals from that calculation resulted in the Benchmark being higher than it would have been had each in-field transfer withdrawal been treated as a withdrawal under the SCA. If these quantities of

gas had been treated as SCA withdrawals, the Benchmark would have been lowered, and as a result the recognized PBR “savings” would have been $33.2 million less. As previously discussed, when a “savings” is recognized, the ratepayer pays its gas costs, plus half of the savings amount. See infra Part I.A.l. Thus, if the in-field transfer withdrawals were considered to be SCA withdrawals, the ratepayer would have paid $16.6 million less in total gas costs.

Upshaw stated that he was not aware that in the fall of 2001 was designating in-field transfers every day, and he did not believe that there could be legitimate in-field transfers that often. Upshaw further said that there were not in-field transfers in 2000 because the weather was colder and that decreased the need for operational transfers.

The method used by to calculate the amount of in-field transfers during this time was to take the total injections and withdrawals for each day, and then “net” them together. Under this approach, the amount of withdrawals that were offset by injections were treated as in-field transfers, and therefore were not noted as withdrawals under the PBR, while the excess amount was considered to be a withdrawal to ratepayers for PBR purposes. Lenart had stated his opinion earlier in the year that “netting” was the most appropriate method to keep track of in-field transfers.

Lenart explained that netting was appropriate because only those withdrawals that were made to service ratepayers should be included as SCA withdrawals. Thus, when Nicor makes withdrawals that exceed the amounts which are delivered to the ratepayer, those additional units of withdrawal are not made to service the ratepayers, but to meet the operational requirements of the aquifers. Under Lenart’s view, when Nicor is injecting gas at a time when its intention is to withdraw gas from storage to deliver to the ratepayer, those injections were made for operational reasons. By way of example, where in a certain day Nicor recognizes 5 bcf of

withdrawals, and 2 bcf of injections, the assumption would be that Nicor only had 3 bcf of withdrawals that were made to service the ratepayers. The remainder, 2 bcf of withdrawals and injections, occurred only because Nicor’s aquifers placed operational demands on Nicor. In other words, in the absence of the operational requirements of Nicor’s aquifers, Nicor would have simply withdrawn 3 bcf of gas and sent those volumes to the ratepayer.

Both Lenart and stated that Upshaw did not agree with this method. Upshaw said this was why he asked to develop specific rules for which withdrawals should be designated as in-field transfers.

C. Conclusion

We believe that withdrawals and injections are necessary and appropriate under certain circumstances to preserve the operational integrity and performance of Nicor’s aquifers. Under the PBR Order, withdrawals should only be considered SCA withdrawals (that affect the notional benchmark) if they are made to service ratepayers, and therefore it seems appropriate to conclude that withdrawals which are made for operational reasons should not be considered SCA withdrawals.

Nevertheless, we note that the Company did not use a consistent method for tracking and reporting in-field transfers. We considered two approaches for quantifying this error. One solution would be to apply the “netting” method discussed above uniformly for all of 2000 and 2001. This results in a cost having been incurred to the ratepayer in the amount of $4.85 million in 2000, and a benefit incurred to the ratepayer in the amount of $1.4 million in 2001. Under this scenario, the total amount due to the ratepayer would be $3.45 million. The alternative approach is that because the PBR does not mention in-field transfers, and because Nicor did not uniformly keep track of in-field transfers, then no in-field transfers should be

recognized. If this approach were taken, a benefit would have been incurred to the ratepayer in the amount of $.25 million in 2000, and a cost would have been incurred to the ratepayer in the amount of $16.6 million in 2001. The net amount due ratepayers under this scenario would be approximately $16.3 million.

We recommend application of the first approach. We note in this regard that the PBR Order expressly states that the only withdrawals which should be subject to the SCA are those withdrawals that are made to service the ratepayers. Thus, under the plain language of the PBR Order, in-field transfers should not be considered SCA withdrawals. The rationale underlying the SCA comports with this treatment, because as discussed previously (See Part I.A.2, discussing the SCA), the purpose of the SCA is to “correct” the Market Index Cost by considering the fact that the cost of gas that Nicor delivers to ratepayers from storage is not the prevailing price at the time the gas is delivered, but the price of the gas at the time it was injected into storage. For those withdrawals which are not being delivered to the ratepayer, Nicor is not recognizing the value of the summer/winter spread, and thus applying the SCR to those withdrawals would be anomalous.²⁵

²⁵

We note a separate issue regarding in-field transfers. The “weightings” of monthly volumes of withdrawals and injections that underlie the SCR figure (i.e. 28.1% of withdrawals in January, 15.27% of injections in August) were intended to reflect Nicor’s pattern of monthly injections and withdrawals for servicing the ratepayer, and were based upon Nicor’s historical practice prior to implementation of the PBR. However, it appears that the PBR Order made no effort to determine which historical withdrawals and injections were “operational,” and which were for the purpose of servicing the ratepayer. Under the reasonable assumption that in-field transfers did occur prior to implementation of the PBR, the historical calculation which underlies the SCR monthly weightings is arguably “skewed,” in that it includes certain historical injections and withdrawals over the course of the year that were made for solely operational reasons, not to service the ratepayer. While we note this arguable anomaly in the SCR calculation, that fact does not alter the PBR Order’s clear statement that SCA withdrawals (which under the SCA are multiplied by the SCR) are those which are provided to the ratepayer. Thus, we conclude that operational withdrawals such as in-field transfers, which are not provided to the ratepayer, are not SCA withdrawals which were intended to affect the Benchmark.

VII. STORAGE PREFILLS

A. Summary and Conclusion

The Company entered into agreements with third parties whereby the third party injected gas into Nicor’s storage fields to be purchased by Nicor at a later date. Pricing was established at time of injection and included an agreement for Nicor to pay carrying costs. The purpose of these transactions was to enable Nicor to lower its gas costs by using lower cost LIFO gas in Nicor’s inventory. We conclude that the accounting for these transactions was improper. Under the requirements of FASB Statement No. 49, Accounting for Product Financing Arrangements, these prefills should have been viewed as “product financing” and should have been included in Nicor’s inventory. The Company has prepared a financial scenario showing the effect, in conjunction with certain DSS transaction discussed above (see Part III supra) on ratepayers under the PBR to correct this error.

B. Background And Analysis

1. The Inventory Value Team Report

The concept of a storage “prefill” was first conceived in 1998. In early 1998, Nicor created an internal “team,” referred to as the Inventory Value Team, whose purpose was to investigate various opportunities available to Nicor to unlock the value of Nicor’s low-cost LIFO inventory layers, estimated to be worth several hundred million dollars.²⁶ In the 1998 pre-PBR environment, Nicor gained no benefit from “accessing” the low-cost LIFO layers, as Nicor gained no financial benefit from lowering the cost of gas to the ratepayer. The Inventory Value

²⁶

Its value lay in its low cost to the Company—approximately $.30—far below even the most conservative estimates of approximate market value if the gas were ever sold on the market.

Team’s undertaking was to investigate strategies whereby it could gain the benefit of these low-cost LIFO layers.

Sometime in the middle of 1998, the Inventory Value Team issued a report, termed the “Inventory Value Team Report,” which analyzed various strategies under which Nicor could gain a benefit from its LIFO asset. (Exhibit 7 to Appendix) The Report was followed by an oral presentation, which was presented at a meeting which included the senior management of Nicor. The general conclusion of the Report was the recommendation that Nicor pursue a PBR mechanism, which would permit Nicor to realize a portion of its LIFO asset, if sold to the ratepayers, through a PBR sharing mechanism.

More specifically, however, the Inventory Value Team Report outlined the concept of a potential method to gain full access to the lower LIFO layers—what would later be termed a storage “prefill.”²⁷ The Report identifies the system by which Nicor could continue to completely liquidate the low-cost LIFO layers: by filling its on-system storage with gas that Nicor would commit to purchase, but for which the “holder” would be an independent third party^.28 Thus, under the scenario presented in the Report, Nicor could continue to fill its storage

²⁷

Such a concept would be required because the “last in, first out” principle that underlies pricing of storage withdrawals is a complicating factor behind any attempt to “monetize” the low-cost LIFO layers. The low-cost LIFO layers were injected into Nicor storage primarily between 1950 and 1970, and as such, under the LIFO principle they are the “first in” and “last out” of storage. As a result, absent prefill arrangements, Nicor could only gain the full benefit of these low-cost layers by completely emptying its storage. Operational constraints prevented Nicor from working its storage fields in this fashion, and in fact, Nicor is operationally required to fill its storage fields before every winter. Thus, absent the concept of prefills, even if Nicor managed to withdraw sufficient volumes of gas to access the low-cost LIFO layers in any particular year, it would be requited to re-fill its storage fields the following year, and thereby likely create a new high cost LIFO layer that Nicor would have to liquidate before gaining the benefit from the remaining low-cost layers. Absent concepts such as prefills, Nicor had great difficulty realizing a significant portion of the total LIFO benefit.

²⁸

The Report considers two alternatives to gaining access to the LIFO layers: “First, a third party (e.g. marketer) can replace the inventory during the injection cycle. Second, Nicor Gas can fill the storage during the injection cycle and then sell the inventory to a third patty. Either way,

(continued)

fields (an operational necessity) without building new high-cost LIFO layers that would prevent continued access to the remaining low-cost layers.

2. Nicor Begins Entering Into Storage Prefill Arrangements

As previously discussed, see Part III.B.4, beginning in the second quarter of 2000, Nicor’s outside auditors, Andersen, began the process of imposing on Nicor additional burdens for quarterly reporting of its LIFO inventory decrement. Andersen intended to ultimately require Nicor to establish to a “reasonable certainty” that a LIFO decrement would occur at year end before Nicor could include that decrement on its financial statements. As the year proceeded, it became clear that the large majority of Nicor’s revenue under the PBR was recognized from the liquidation of the low-cost LIFO layers, and thus meeting the auditing requirements imposed by Andersen was essential to Nicor’s ability to meet its quarterly revenue targets.

Lonnie Upshaw explained that storage prefills were an attempt to create a transaction that would enable Nicor to provide Andersen’s required “confirmation” that a LIFO decrement would be realized by year end, and thereby permit LIFO decrements to be booked on Nicor’s quarterly balance sheets. The purpose of the prefill was to engage in a transaction that would have two essential characteristics: (1) gas that would actually be stored in Nicor’s on-system storage; but (2) gas that would not be “recognized” as a Nicor injection. The first ensured that Nicor could fill its storage fields—an operational necessity, and the second ensured that Nicor did not create a new high-cost LIFO layer through the process of refilling its storage fields.

Nicor Gas has withdrawn and sold the low-cost inventories at market and will not be the holder of market price replacement inventories.” Report, p. 4.

3. The Terms Of The Prefill Arrangements

The terms of the different prefill arrangements, although differing slightly in form, are identical in substance. Nicor agreed with various third parties to purchase quantities of gas at a pre-determined price (the price of the gas at the time of injection), but at times over a pre-set future time period. Nicor also agreed to pay the third party its “carrying costs,” or interest, running from the date the agreement was settled until Nicor actually exercised its option to purchase. Finally, Nicor also agreed to pay all storage costs associated with storing the prefill gas in its storage fields. In return, the third party agreed to inject the gas into Nicor’s storage fields, where it would remain until Nicor exercised its option to purchase the gas at the agreed upon terms. The third party also agreed to give up any rights it might have to withdraw the prefill gas once it was injected into the storage field. In some cases, the end of the future time period was reached, and Nicor still did not wish to exercise its option to purchase. The parties renegotiated the terms at that time.

We have been informed that Nicor’s Supply Group, including Upshaw, was expressly told that the essential aspect of the transaction, from an accounting perspective, was the retention of title by the third party. Every person in Nicor’s internal accounting department we spoke with indicated that if the third party retained title to the gas, that gas was appropriately excluded from Nicor’s financial statement, notwithstanding the other terms of the transaction. The accounting of this transaction was apparently not discussed in any detail by anyone within the Company. It is unclear what role, if any, Nicor’s outside auditors had in the accounting decisions for prefill transactions.

4. Using Storage Prefills to Meet PBR Targets

Prefills provided Nicor with a measure of control over its balance sheet and the amount of profit sharing. By entering into significant volumes of prefill transactions during the summer months, Nicor could choose to “exercise” its option to purchase any portion of the prefill transactions at year end, and thereby determine the quantum of the LIFO decrement (and therefore, its yearly performance under the PBR). Nicor had long, daily meetings at the end of the year, including December 30 and 31, during which it would determine what level of LIFO decrement was required in order to meet its PBR financial targets. Working backwards, the LIFO decrement that must be realized to meet financial targets established the year-end inventory levels that Nicor had to achieve. Taking one further step back, Nicor then achieved this inventory level by exercising its option to purchase the appropriate number (if any) of prefill transactions.²⁹ The remainder of Nicor’s prefills were deferred to the following year, and did not affect Nicor’s earnings. In this fashion, Nicor was effectively able to recognize any size LIFO decrement it required, and as a result, Nicor met its yearly performance under the PBR.

C. Appropriateness Of the Accounting For the Transaction

Prefills were conceived for the purpose of engaging in transactions with certain accounting ramifications that benefited the Company (and the ratepayer). Nicor engaged in prefill transactions for the accounting benefits it believed such transactions afforded: (1) easing the pressure on Nicor to establish quarterly LIFO decrements to a “reasonable certainty”; (2) providing Nicor with a method to fill its on-system storage without recognizing storage injections

²⁹

Once Nicor exercised its rights to purchase a prefill, it would then appear on Nicor’s books as inventory. By purchasing prefills, Nicor had complete control over the actual size of its year-end inventory.

(that would affect its access to low-cost LIFO layers); and (3) providing Nicor with a method to ensure that it could met its estimated yearly PBR performance.

The Company has now concluded that Nicor’s accounting methods for prefill transactions was inappropriate. The assumption that the prefill transaction would not appear on the balance sheet as a Nicor storage injection simply due to the fact that title to the gas remained in the hands of the third party was erroneous.

In fact, whether or not the prefill transaction should be booked as a storage injection does not turn on which party holds title to the gas, but on the application of accounting principles set out in FASB Statement No. 49, which governs the accounting treatment of “product financing” agreements. In general, FASB Statement No. 49 addresses the question of which entity—in this case Nicor or the third party—retains the benefits/risks of ownership of the product in question—in this case the gas injected into Nicor’s storage. See FASB Statement No. 49, Accounting for Product Financing Arrangements. Under the analysis of FASB Statement No. 49, even where the actual “purchase” of a product is deferred in time, the purchase is recognized from an accounting perspective at the date the benefits/risks of ownership are transferred.

With regard to Nicor’s prefill transactions, the following factors are relevant to this consideration: (1) Nicor agreed to purchase the gas at a price certain; (2) to the degree Nicor deferred the sale by exercising its option at a later date, Nicor agreed to pay the third party its “carrying costs,” or interest, for each day the sale was deferred; (3) Nicor paid all storage fees associated with the gas; and (4) the third party gave up any right it had to withdraw the gas once it was injected into storage. These factors support the conclusion that the prefill transaction constituted product financing.

D. Costs Incurred By The Ratepayer

Storage prefills were the foundation of Nicor’s PBR strategy, and changing the accounting treatment of these prefills has a dramatic effect on Nicor’s performance under the PBR. In effect, without the benefit of Nicor’s assumed accounting treatment of prefill transactions, Nicor cannot access the low-cost LIFO layers it recognized on its financial statements. After adjusting to account properly for prefills, Nicor will not have sold the ratepayer $.30 LIFO gas, but in fact much higher market-priced gas.

E. Conclusion

Nicor’s accounting treatment of prefill transactions was improper. We did not uncover any evidence that this accounting mistake was intentional or knowing. The Company has attempted to quantify the harm to ratepayers from this error in preparing the scenario discussed above at Part II.C.

In order to quantify the harm, if any, to the ratepayer as a result of this misstatement, as well as the improper accounting for the DSS transactions that should not be treated as sales, the Company has put together a financial scenario. Note that performance under the PBR is determined by looking at actual gas costs as compared to the Benchmark. In order to take into account the effect of the errors, it is necessary to calculate how the errors affected both variables. The Company made certain assumptions, as follows: First, the Company calculated the difference in actual gas costs created by the errors. Taking the example of prefills, prefills permitted the Company to use lower-cost LIFO gas to meet ratepayer demand. Therefore, eliminating prefills means that the Company would have been forced to satisfy ratepayer demand with higher-cost LIFO gas. Correcting the accounting for this means that ratepayers would have been undercharged for actual gas costs. Second, the Company calculated the difference in the

PBR results caused by the errors. Using the example of the DSS transactions, the Company is assuming that these transactions should not constitute sales, but instead should have continued to have been treated as Nicor inventory. When this gas was sold to the ratepayer, the scenario assumes that this was as withdrawal that would impact the SCR. The application of the SCR to these volumes has the effect of altering the SCA and, thus, the Benchmark itself. This has a dramatic impact in 2001, where the SCR was positive, since it has the effect of increasing the effective cost of gas withdrawn as compared against the Benchmark, and means that the Company would have performed much worse than reported under the PBR.

These two numbers—the difference in actual gas costs, and the difference in PBR results—are compared against each other. This figure allows a determination of the total amount that ratepayers were actually over or under-charged as a result of the errors.

We note one extremely important caveat regarding this calculation. These calculations assume that overcharges and undercharges may be netted against each other in determining the ultimate harm to ratepayers. We offer no opinions as to whether this is permissible as a regulatory matter, or whether the ICC will accept this methodology. If, in fact, only overcharges to ratepayers were to be considered here for purposes of calculating a potential refund, these numbers would be significantly different.

VIII. RELATED PARTY TRANSACTIONS

A. Summary and Conclusion

Nicor has a FERC tariff and an Illinois Rate 21 (Interruptible Transportation and Storage Services) tariff that permits it to “sell” storage services to third parties when excess capacity becomes available. Nicor has a separate corporate entity—Enerchange—that runs this segment of Nicor’s business. Enerchange has a “Hub Administration Agreement” with Nicor, under which it sells Nicor’s excess capacity to third parties, generally marketers such as BP Amoco and Aquila, on behalf of Nicor. All sales of gas by Enerchange are fully interruptible; that is, Nicor can recall any amount of the gas released to third parties at any time to meet ratepayer demand. The Hub Administration Agreement operates as a profit sharing arrangement with Nicor, under which Nicor receives 30% of the first $1 million in revenue, 20% of the second $1 million in revenue, and 10% of any revenues in excess of $2 million.³⁰ We noted that in January 2000, Nicor sold 2.4 bcf of gas to Enerchange at a price that was slightly below the daily price for gas for that day. While Nicor engaged in the identical transaction with third parties, the size of those transactions were significantly smaller, amounting in total to only 0.6 bcf of gas. The details underlying the January 2000 transaction are discussed below. We did not note any improper related-party transactions by Nicor.

B. Background and Analysis

1. Establishing Market Prices

Enerchange has enacted specific procedures to ensure that any transaction with Nicor occurs at “arms length.” Enerchange collects market data at the Hub regarding prices in

³⁰

As an example of scope, we were informed that Enerchange earned approximately $16 million in 2001.

similar transactions with third parties, and thereby establishes an estimate of the actual “market price” for any transaction that will occur with Nicor. Enerchange then requires that any transaction with Nicor take place at the Hub-established market price. In other words, Nicor cannot engage in a transaction with Enerchange that it has not also engaged in with independent third parties. As an estimate, approximately 10-15% of Enerchange’s revenue is derived from deals between Nicor and Enerchange.

2. The January 2000 Transaction

a. Nicor Is “Long” On Gas In January 2000.

In January 2000, at the beginning of the PBR, Nicor was “long on gas.” In other words, it had already agreed to purchase gas in excess of its needs for the month, with warmer weather in January 2000 as the culprit.³¹ The ramifications of this event under the PBR for Nicor were two-fold: (1) the risk that Nicor would fail to match the 65/35 split for the commodity component of the PBR (gas purchases)³²; and (2) the risk that Nicor would fail to recognize the proper percentage of withdrawals under the storage component of the PBR (withdrawals from

³¹

Predicting monthly gas needs is critical under the PBR, as the benchmark is established under the assumption that 65% of gas purchases for the month will occur at FOM (first of the month) prices, while the remaining 35% will occur at daily prices. In months in which Nicor forecasted that FOM prices would be high in relation to the remainder of the month, Nicor made FOM purchases based upon predicted gas needs for the month to ensure it met or exceeded the 65/35 split under the benchmark. In the event weather is warmer than predicted, and thus gas needs are less than predicted, Nicor’s agreed upon purchases could exceed Nicor’s actual demand. In other words, the FOM purchases would exceed 100% of Nicor’s needs. Nicor described this situation, where purchases of gas by Nicor exceed its total needs, as being “long” on gas.

³²

Ordinarily, warmer than expected weather is likely to adversely affect Nicor’s performance under the commodity component of the benchmark, because as demand declines, daily prices are likely to drop. Thus, Nicor’s FOM commitment will be at the highest price of the month, and will also be greater than the 65% benchmark allocation for FOM prices. However, January 2000 was a unique month, in that despite low demand, prices continued to rise throughout the month. Thus, Nicor was not concerned about the likelihood that its actual FOM purchases were going to exceed the benchmark established 65%.

inventory). Nicor’s concern over the second factor provided the basis for the January 2000 transaction with Enerchange.

b. Matching The Storage Component Of The PBR.

In addition to the commodity component, the PBR also tracks storage withdrawals under the PBR. Based largely upon historical figures, the PBR assumes that Nicor will not service all of its needs through purchases of gas, but will also withdraw gas from its inventory held in its storage fields. The PBR assumed that a certain percentage of yearly withdrawals would occur each month.³³ Nicor had predicted that it would withdraw roughly 70 bcf of gas from its inventory in 2000, and under the storage component of the PBR, roughly 30% of those withdrawals were to occur in January. As a result of the warmer weather in January, Nicor was concerned that it would fall far short of the 21 bcf of withdrawals it needed to recognize in January in order to hit its 70 bcf planned yearly pace.

c. Nicor’s Strategies To Increase Withdrawals In January 2000.

By mid January, Nicor believed that it was confronting a PBR problem that threatened to seriously affect its performance over the year. It seemed plausible that due to the warm January weather Nicor would fall well short of its withdrawal plan for January. To address this problem, Ted Lenart met with to discuss whether there was anything that could be done to increase storage withdrawals. At the conclusion of the meeting, Lenart concluded that

³³

In general, the storage component of the PBR functions in much the same way as the commodity component, but spread over the entire year, as opposed to in each month. Under the storage component, approximately 65% of the withdrawals are to occur in the first four months of the year, with the remaining approximately 35% to occur in the last four months of the year. Similar to the commodity component, Nicor was cognizant of the risk of severely deviating from this assumed 65/35 split where its forecasts of future prices were uncertain. Thus at the beginning of the year, Nicor tried to roughly equalize its storage withdrawals to the assumed 65/35 storage split. Depending upon the gas prices in later months of the year, Nicor would then deviate from the 65/35 split to beat the benchmark.

Nicor would investigate opportunities to sell gas to third parties, and thereby recognizing greater withdrawals under the PBR. As envisioned, the plan provided for the sale of Nicor’s committed gas purchases.

While Nicor wished to recognize greater withdrawals, it also was concerned about its ability to service the ratepayers for the remainder of the winter in the event of a peak cold day when demand would be highest. Nicor therefore investigated strategies that would permit it to recognize greater withdrawals, while at the same time retain sufficient stores of gas to provide it the flexibility it needed to meet ratepayer demand in the event of a peak degree day when gas needs would be highest.

Lenart recognized that the futures market for gas was extremely high, with futures prices for September gas that were almost equivalent to, although slightly lower than, the present January market price.³⁴ Nicor concluded that triggering a sale at the September futures price might permit Nicor to retain possession of the gas throughout the winter. Moreover, Nicor’s committed purchases in January were priced at January FOM prices, and thus the September futures price was at or above the January FOM price that Nicor was obligated to pay. Thus, a sale by Nicor priced at the September futures price would avoid recognizing any loss by Nicor on the sale. Nicor’s Supply Group began developing strategies for sales of its committed gas purchases for delivery in September 2000, structured in a manner that permitted Nicor to

³⁴

This was a marked departure from historical figures, as January prices are generally well in excess of future September prices. By way of example, the following year in January 2001 the market price was approximately $10, while the futures price for September was trading at only $6.

recognize greater withdrawals in January despite the fact that delivery would be deferred until September 2000.³⁵

Nicor implemented its strategy to sell a portion of its storage gas to third parties at the September futures price. As the transaction was planned, these volumes of gas would remain in Nicor’s storage, earmarked for the Hub as third-party gas. By earmarking the gas in this fashion, Nicor was able to alter its monthly withdrawals. The gas was recognized as third-party gas, with title in the hands of the third party. Although retaining title, under the terms of the sale, the third party had restricted withdrawal rights until September 2000, thereby permitting Nicor to retain possession of the gas in its storage fields throughout the winter. The price for the gas to be sold was the “market price” for September 2000 as established by the September futures market index price (NYMEX). The price was slightly lower than the January 2000 daily market price, but was greater than Nicor’s January 2000 committed FOM purchases.

d. Engaging In The Transaction With Enerchange

Once the details of the transaction had been worked out, Lenart gave express “approval” to engage in a portion of this transaction with Enerchange. Concerned by the impression of impropriety, and pursuant to Enerchange’s related-party practice, Lenart expressly cautioned that Enerchange could only be involved in the deal if Nicor engaged in the identical transaction with independent third parties. While Nicor did engage in the transaction with third parties as well as Enerchange, the volume of the transaction with Enerchange proved to be quite large by comparison—four times the volume of all the third party transactions combined. Lenart acknowledged direct responsibility for these decisions.

³⁵

Determining which volumes of gas were being sold to third parties was an accounting matter. As previously discussed, it is not possible to track molecules of gas to determine whether flowing gas purchases, or storage inventory, were sent to a particular party.

C. Propriety Of The Transaction

Nicor’s decision to engage in the January 2000 transaction with Enerchange was not based upon an attempt to benefit its related party (Enerchange) at the expense of the ratepayer. Rather, the January 2000 transaction was premised upon efforts envisioned by the PBR—attempts to outperform the storage component of the Benchmark. While Nicor’s strategy of engaging in transactions to match the storage component of the PBR benchmark can be questioned with hindsight as the correct business decision, we believe it was a reasonable business decision at the time.

Although the transaction was below the daily market price in January, that alone does not make the transaction improper. Nicor had a pressing need to eliminate the overflow of gas it experienced in January 2000. It agreed to sell its committed gas purchases at the September 2000 futures price, which met or exceeded its January FOM gas costs. Thus, the ratepayer did not suffer a loss on the transaction.

Arguably, the ratepayer did lose an “opportunity” by selling the gas at the September futures price, in that the September futures price was slightly below the January daily spot price. In other words, while the ratepayer did not recognize a loss on the transaction, the sale had an “opportunity cost”—the ratepayer lost the opportunity to derive the additional revenue which could have been realized had Nicor sold its obligated FOM gas purchases at the higher daily price. But Nicor recognized an offsetting benefit by linking the sale of gas to the September 2000 futures price. As a part of the transaction, Nicor severely restricted Enerchange’s (and the third parties’) withdrawal rights until September 2000, which gave Nicor added flexibility. Nicor gained the benefit of having the gas in its storage fields through the

winter of 2000, where it could be “borrowed” on peak demand days in February and March to better service the ratepayer.

C. Costs Incurred By The Ratepayer

The ratepayer was not harmed by the January 2000 transaction. First, our investigation did not reveal that the transaction was consummated to benefit Nicor’s related entity at the expense of the ratepayer. Nicor did engage in the identical transaction with independent third parties.

While the Enerchange transaction was four times the combined value of all the transactions with independent third parties, we do not believe the transaction was for an improper purpose. First, the transaction was premised upon Nicor’s need to sell off excess capacities of gas that threatened its performance under the storage component of the benchmark. Second, Nicor was careful to ensure that the transaction did not result in the recognition of a “loss” to the ratepayer. Third, while technically the transaction imposed a small “opportunity cost” on the ratepayer, as a result the ratepayer also recognized an offsetting gain—added flexibility for Nicor to provide optimal gas service to the ratepayer for the remainder of the winter.

D. Conclusion

We did not note any improper related-party transactions by Nicor.

IX. GAS TRANSACTION LOSSES

We investigated whether Nicor, operating under the PBR program, suffered inordinately high losses through hedging and through buying gas at FOM prices. Hedging refers to using derivative instruments, including swaps, options and gas futures contracts to protect against unfavorable movements of the price of gas. Under the PBR, hedging was a method used to try to lower the cost of gas.

As part of the investigation, we looked at the composite characteristics of open and closed hedged positions taken by Nicor during 2000 and 2001. The pattern of activity was consistent with appropriate hedging activity and, taken as a whole, did not indicate an attempt to speculate on gas prices. The fact that money may have been lost on financial trades is not an indication that the hedging was improper. We note that we did not review the trading rationale of individual financial positions taken during this period.

It has also been alleged that by buying at first of the month prices, Nicor lost an inordinately large amount of money. Under the PBR, the Benchmark price was established 65% by FOM prices and 35% by daily prices during the month. Nicor usually tried to forecast the market and time its purchases accordingly. Sometimes buying gas at first of the month prices was advantageous to Nicor and other times it was not. We have no reason to believe that the judgment used by the Gas Supply section was inappropriate.

X. MANAGEMENT FEES

We reviewed whether management fees paid to third parties for gas storage and transportation were excessive. In particular, we examined payments from Nicor to IMD under the PBR Storage Agreement. We conclude that Nicor did not pay IMD pursuant to the terms of the PBR Storage Agreement, but rather the fees were negotiated at the end of each year.

We have requested and are in the process of reviewing materials provided to us late last week from IMD to ascertain whether IMD may have been overpaid. It appears that the documentation, along with the documentation supplied by the Company, does not currently provide us with sufficient information to enable us to form a conclusion on this issue. In particular, we have been informed that much of the negotiations over fees was done verbally and was not memorialized in writing. We find this fact troubling in its own right, and we are obviously concerned about the current inability of the Company at this late date to provide us with a clear explanation of the method by which IMD was compensated. We recommend that a detailed audit, conducted by an outside auditor or by Nicor’s internal audit department, be commenced to determine (a) the amounts actually agreed to by the parties; (b) whether those amounts are appropriate under the circumstances; and (c) whether those amounts were, in fact, paid to IMD.

Respectfully submitted,


Scott R. Lassar SIDLEY AUSTIN BROWN & WOOD Bank One Plaza 10 S. Dearborn Street Chicago, Illinois 60603 Telephone: (312) 853-7000 Fax: (312) 853-7036

APPENDIX OF DOCUMENTS

STATE OF ILLINOIS

ILLINOIS COMMERCE COMMISSION

Northern Illinois Gas Company d/b/a	:
NICOR Gas Company	:

Petition for permission to place into effect	:	99-0127
proposed Rider 4, Gas cost, pursuant to	:
Section 9-244 of the Illinois Public Utilities Act.	:

ORDER

By the Commission:

I. Introduction and Procedural History

On March 1, 1999, Northern Illinois Gas Company d/b/a Nicor Gas Company (“Nicor Gas” or “Company”) filed a verified Petition seeking this Commission’s approval, under Section 9-244 of the Illinois Public Utilities Act (“PUA” or “Act”), of an alternative rate regulation program for gas costs, which it termed the Gas Cost Performance Program (“GCPP” or “Program”). Nicor Gas is an Illinois corporation with its corporate headquarters in Naperville, Illinois. It serves as the local distribution company (“LDC”) for its service territory in the northern portion of Illinois.

Pursuant to notice, as required by law, prehearing conferences were held before a duly authorized Hearing Examiner of the Commission at its Chicago offices on March 30, 1999 and July 13, 1999. The staff of the Commission (“Staff”) participated in the proceeding, and petitions to intervene were granted for the Citizens Utility Board (“CUB”) and the People of Cook County (“Cook County”) (collectively referred to as the Consumer and Governmental Intervenors (“CGI”)), and Natural Gas Pipeline Company of America.

An evidentiary hearing was held on July 21, 1999. The following witnesses submitted testimony: on behalf of Nicor Gas, Brian C. Elliott (Vice President Engineering and Technical Services), Albert E. Harms (Manager Rate Research), and Leonard M. Gilmore (Manager Pipeline Regulation and Supply Planning) (Mr. Gilmore adopted the direct testimony of Mr. Edwin M. Werneke (Vice President Supply Ventures)); on behalf of Staff, Charles C. S. Iannello (Economic Analyst), Mark Maple (Engineering Department of Energy Division), and John A. Link (Accounting Department Financial Analysis Division); and on behalf of CGI, Jerome D. Mierzwa of Exeter Associates, Inc. At the close of the hearing on July 21, 1999, the record was marked “Heard and Taken”.

Initial briefs and Reply Briefs and/or Proposed Orders were filed by Nicor Gas, Staff and CGI. On September 23, 1999 the Hearing Examiners issued their Proposed Order.

Staff, the Company and CGI, all filed Briefs on Exceptions and Reply Briefs on Exceptions. In addition, Nicor requested oral argument and its request was granted by the Commission on October 20, 1999. A Post-Exceptions Proposed Order issued on October 22, 1999 was duly served on the parties. The Commission, sitting en banc, heard oral argument on November 2, 1999 and took the matter under advisement.

II. Background

The Illinois General Assembly has authorized the Commission to approve alternative rate regulation programs for electric and gas utilities as substitutes for traditional rate regulation. Specifically, Section 9-244(b) of the PUA allows the Commission to adopt such programs if they satisfy a list of criteria. Nicor Gas seeks approval of a GCPP under Section 9-244 as an alternative to traditional regulation of its gas costs.

Under traditional regulation, the Company is allowed to recover the actual gas costs it incurs each year, subject to an annual Purchased Gas Adjustment (“PGA”) proceeding in which the Commission reviews costs and prudence issues. Under the GCPP, by contrast, Nicor Gas’ recoverable gas costs would be determined by reference to a market-based “Benchmark” (or “Benchmark Gas Cost”). This benchmark is intended by Nicor to be calibrated to reflect what gas costs would have been under traditional regulation. To the extent Nicor Gas’ actual gas costs (“Actual Gas Costs”) are lower or higher than the Benchmark, it would share the savings or losses with ratepayers 50/50 to $30 million, after which ratepayers would be allocated 90% of the savings or losses and the Company 10%. Savings or losses would be shared with ratepayers in the following year.

Nicor Gas’ proposal is one way in which it has responded to changes in gas supply markets brought about by restructuring of the natural gas industry under a series of Federal Energy Regulatory Commission (‘FERC”) Orders. FERC’s deregulation of wellhead gas prices and services and the termination of the merchant function of interstate pipelines has required LDCs, including Nicor Gas, to assemble and manage their own portfolios of wellhead gas supplies and transportation services. These market changes offer both challenges and opportunities for Nicor Gas to aggressively pursue cost minimization through innovative, non-traditional means. According to the Company, however, traditional PGA regulation provides no objective economic incentive to do so and, indeed, may discourage such activity. The Commission itself has recognized this shortcoming. While we declined to establish incentive mechanisms as part of the revision to the Uniform Purchased Gas Adjustment rule (83 III. Adm. Code 525), our Order in Docket 94-0403 specifically encouraged utilities to utilize Section 9-244 proceedings to propose performance-based mechanisms that respond to the new market challenges.

The Company states that its proposal responds to the Commission’s invitation and is based on three major objectives. First, the Program would align the interests of ratepayers and the Company by providing appropriate economic incentives for Nicor Gas to improve its performance in providing customers with the best gas prices available, while recognizing the need for continued reliability and security of supply. Second, the Program would encourage the appropriate use of competitive market opportunities and risk management mechanisms for procurement of gas supply, transportation, and storage services by establishing a reasonable balance between risk and reward. Third, the Program would lower regulatory costs by establishing an objective, market-based standard for evaluating gas supply purchasing, planning, and management, while also eliminating after-the-fact prudence reviews.

To implement the Program, Nicor Gas proposes a new Rider 4, “Gas Supply Performance Program,” which would compare the Company’s Actual Gas Costs for a calendar year, as reflected in its Rider 6, Gas Supply Cost, with the annual costs determined by the market-sensitive Benchmark. Nicor Gas further proposes to revise its existing Rider 6, to eliminate the prudence review process. The Petition asserts that with an annual comparison between actual and market costs, there is no need to conduct annual prudence reviews because the market will function as an objective prudence standard. If the Company betters prevailing market costs, it would be rewarded. If the Company cannot match or better the market, it would absorb increased costs.

III. Applicable Statutory Authority and Requirements

This case is governed by Section 9-244. As amended by the General Assembly in 1997, Section 9-244 states:

Section 9-244. Alternative rate regulation. (a) Notwithstanding any of the ratemaking provisions of this Article IX or other Sections of this Act, or the Commission’s rules that are deemed to require rate of return regulation, and except as provided in Article XVI, the Commission, upon petition by an electric or gas public utility, and after notice and hearing, may authorize for some or all of the regulated services of that utility, the implementation of one or more programs consisting of (i) alternatives to rate of return regulation, including but not limited to earnings sharing, rate moratoria, price caps or flexible rate options, or (ii) other regulatory mechanisms that reward or penalize the utility through the adjustment of rates based on utility performance. In the case of other regulatory mechanisms that reward or penalize utilities through the adjustment of rates based on utility performance, the utility’s performance shall be compared to standards established in the Commission order authorizing the implementation of other regulatory mechanisms. The Commission is specifically authorized to approve in response to such petitions different forms of alternatives to rate of return regulation or other regulatory mechanisms to fit the particular characteristics and requirements of different utilities and their service territories.

(b) The Commission shall approve the program if it finds, based on the record, that:

(1) the program is “likely” to result in rates lower than otherwise would have been in effect under traditional rate of return regulation for the services covered by the program and that are consistent with the provisions of Section 9-241 of the Act;

(2) the program is likely to result in other substantial and identifiable benefits that would be realized by customers served under the program and that would not be realized in the absence of the program;

(3) the utility is in compliance with applicable Commission standards for reliability and implementation of the program is not likely to adversely affect service reliability;

(4) implementation of the program is not likely to result in deterioration of the utility’s financial condition;

(5) implementation of the program is not likely to adversely affect the development of competitive markets;

(6) the electric utility is in compliance with its obligation to offer delivery services pursuant to Article XVI;

(7) the program includes annual reporting requirements and other provisions that will enable the Commission to adequately monitor its implementation of the program;

(8) the program includes provisions for an equitable sharing of any net economic benefits between the utility and its customers to the extent the program is likely to result in such benefits.

The disputes here focus primarily on requirements (1) and (8). Requirement (6) applies only to electric utilities and thus is irrelevant to this proceeding.

As a matter of policy, the Commission encourages utilities to utilize Section 9-244 proceedings to propose performance-based pricing mechanisms that respond to the market changes in the gas industry in recent years. (See e.g. Docket 94-0403.) The Commission will review the evidence and arguments in order to determine the program proposed by the Company in its GCPP meets the statutory requirements listed above

IV. Description of the GCPP

According to the Company, the GCPP would work as follows:

(1) The Benchmark Gas Cost. As a starting point, a “Benchmark” would be established to approximate as closely as possible the gas costs that Nicor Gas would incur each year under traditional PGA regulation. The Benchmark would begin with the Market Index Cost for the calendar year, which would be based on actual sales volumes and various price indices at the Chicago city-gate. The Benchmark would then be modified by a Storage Credit Adjustment, a Firm Deliverability Adjustment, and a Commodity Adjustment. These adjustments account for other factors that affect Nicor Gas’ overall gas cost, such as the costs of reserving firm transportation service from pipelines and storage service from storage operators, the benefits of managing gas storage, and the historical difference between Benchmark Gas Costs and Actual Gas Costs.

(2) Comparison to Actual Gas Costs. The Benchmark then would be compared to Nicor Gas’ Actual Gas Costs for the calendar year, as currently computed under the PGA. If Actual Gas Costs are lower than the Benchmark Gas Costs, there would be “savings” to share with ratepayers. If Actual Gas Costs exceed the Benchmark, there would be “losses” to share with ratepayers.

(3) Sharing. A specific sharing percentage would be applied to any savings or losses to determine the dollar amounts to be allocated to ratepayers and the Company. Under the Company’s proposal, savings or losses would be shared 50/50 with customers up to $30 million, and 90/10 (with customers receiving 90%) for savings or losses that exceed $30 million. For example, if Nicor Gas’ actual gas costs were $10 million lower than the Benchmark, ratepayers would receive $5 million in savings and the Company would receive $5 million in savings.

The savings received or losses incurred by the Company would be recorded “below the line” for accounting purposes, meaning they would not be reflected in distribution operating income. Savings or losses allocated to customers would be flowed back in the following year. The details of each aspect of the Program are described below.

A. The Benchmark

Nicor Gas has proposed a single, market-based Benchmark, which it believes is the easiest type of Benchmark to understand and administer (as opposed to multiple benchmarks for different costs). A single benchmark also recognizes the interrelationship between various cost elements and thereby avoids questions of cross-subsidization and conflicting utility incentives. (Werneke Direct at 3). In addition, a single benchmark is

easier to apply from an accounting perspective and easier for Staff to review, as all the key elements affecting gas costs—commodity costs, transportation costs, storage costs, and credits generated by gas supply activities—are reflected in a single number. (Id. at 3-4). The Benchmark Gas Cost during each year of the Program (the “GCPP year”) would be based on the following formula (Id. at 4):

Market Index Cost,

Minus Storage Credit Adjustment,

Plus Firm Deliverability Adjustment,

Plus Commodity Adjustment

= Benchmark Gas Cost

1. Market Index Cost and Market Index Price

The Benchmark begins with the Market Index Cost. The Market Index Cost is intended to represent “the annual gas cost that customers would pay if the gas delivered to them was priced at prevailing Chicago city-gate market index prices at the time of delivery.” (Id. at 4). The Market Index Cost is determined by multiplying Nicor Gas’ actual sales deliveries each month by the Market Index Price for that month and then adding together the twelve monthly totals. (Id.)

The Market Index Price is determined by averaging two separate groups of published Chicago city-gate price indices. One group is based on indices reporting “first-of-the-month” pricing; the other group is based on indices reporting daily pricing throughout the month. (Id. at 5). The indices used for the first-of-the-month average price are:

(1) The month’s Chicago city-gate index price as published in Inside FERC’s Gas Market Report.

(2) The month’s Midwest-Illinois index price for Natural Gas Pipeline Company of America deliveries as published in Natural Gas Intelligence Gas Price Index.

(3) The month’s Chicago city-gate index price as published in Natural Gas Week.

(4) The month’s Chicago city-gate index price for LDCs and large end-users as published in Gas Daily.

(Id. at 6).

The indices used for the monthly daily-average price are:

(1) The month’s average of the daily Chicago city-gate index price as published in Btu Daily Gas Wire

(2) The month’s average of the daily Chicago city-gate midpoint index price for LDCs and large end-users as published in Gas Daily.

(3) The month’s average of the daily Chicago city-gate average index price as published in Natural Gas intelligence Daily Gas Price Index.

(Id.)

The average prices for each group are then averaged together to establish the Market Index Price. Although Nicor Gas initially proposed a 50/50 weighting of the two group averages, it later agreed to a weighting of 65% first-of-the-month /35% daily pricing. (Gilmore Surrebuttal at 1).

Thus, the formula for the Market Index Cost is:

Average of first-of-the-month Chicago city-gate price indices x 65%

+ Average of daily Chicago city-gate price indices x 35%

= Market Index Price, then

Market Index Price x Nicor Gas delivered sales volumes for each

corresponding month in GCPP year, summed for the year

= Market Index Cost

The Company states that the Chicago city-gate location is a very large, very liquid market, and includes other trading locations besides Nicor Gas, such as The Peoples Gas Light & Coke Company, North Shore Gas Company, and Northern Indiana Public Service Company (Werneke Direct at 7-8), and that the Market Index Price therefore reflects an unbiased measure for use in the Benchmark. The Company’s regression analysis shows an extremely high correlation between the Market Index Cost and Nicor Gas’ actual variable commodity costs in 1997 and 1996. (Werneke Direct at 7 and Ex. EMW-2).

2. Storage Credit Adjustment

Once the Market Index Cost is determined, three adjustments are made to establish the ultimate Benchmark. The first is the Storage Credit Adjustment, which is intended to recognize the annual benefit that Nicor Gas’ customers receive as a result of the Company’s purchase of gas supplies during off-peak periods, when prices are typically lower, the injection of that gas into storage, and the withdrawal of those supplies

to meet demand during peak periods, when prices are typically higher. (Id. at 8). The Storage Credit Adjustment would be subtracted from the Market Index Cost to reflect the fact that storage injections and withdrawals influence the Company’s gas costs.

The Storage Credit Adjustment is determined by multiplying the actual number of units of gas withdrawn from storage for sales to customers in the GCPP year by the “Storage Credit Rate.” The Storage Credit Rate is the difference between the weighted average Market Index Price for injections (weighted by Nicor Gas’ actual 1997 monthly injection amounts) and the weighted average Market Index Price for withdrawals (weighted by Nicor Gas’ actual monthly withdrawal volumes in the GCPP year). (Id.)

Nicor Gas states that the Storage Credit Adjustment will vary from year to year because it represents the “seasonal price differential” associated with storage withdrawals, which depend on variable factors. (Id. at 10). The Company proposes to use historical injection weightings (from 1997) to establish a figure that is based on actual experience, reflects normal weather, and cannot be manipulated or influenced by the Company. (Id.) On the other hand, the Company would rely on actual withdrawal volumes each year because it has very limited ability to adjust the timing of storage withdrawals, which “are determined largely by weather and operational requirements” and therefore cannot be manipulated. (Id.)

3. Firm Deliverability Adjustment

The second adjustment to the Market Index Cost is the Firm Deliverability Adjustment. The Firm Deliverability Adjustment reflects “the level of fixed costs incurred by Nicor Gas on an annual basis to reserve firm transportation, purchased storage and other services in order to ensure the availability of gas supplies for its customers during peak periods.” (Id. at 10-11). The Firm Deliverability Adjustment would be an addition to the Market Index Cost because it represents additional costs of procuring gas supplies.

The Firm Deliverability Adjustment is computed as:

The total amount of costs for transportation reservation and purchased storage reservation,

minus an amount for “Capacity Management Credits,” which includes credits related to capacity release, gains from buy/sell transactions, gains from supply sales, and storage credits.

Nicor Gas originally used a Firm Deliverability Adjustment of $130.7 million but, based on subsequent events—primarily the negotiation of new contracts with certain major pipelines—later reduced its overall proposal to $121,763,384. (Gilmore Surrebuttal, Ex. LMG-8). The largest revisions involved the costs for firm transportation

and storage reservation, which were reduced from $143 million to $129 million.¹ This reduction resulted from a renegotiated contract with Northern Natural Gas Company (“Northern”), which will become fully effective on November 1, 1999, and a renegotiated contract with Natural Gas Pipeline Company of America (“Natural”), the major terms of which (duration, level of service, and annual cost) have been agreed upon. The reduction also takes into account a preliminary offer for a new contract with Midwestern Gas Transmission Company. (Id. at 3-4). The $129 million amount is based on projected firm transportation and storage reservation costs for calendar year 2000. The Company based costs on the year 2000 because that will be the first year of the Program and is representative of expected future costs. (Id. at 1-2).²

The other significant change to the Firm Deliverability Adjustment involved the amount of “Capacity Management Credits,” a category that includes capacity release credits, gains from buy/sell transactions, gains from supply sales, and storage credits. This figure was reduced from $12 million (based on 1998 data) to $7 million (forecast for the year 2000). The Company states that this reduction is appropriate because of the increase in incremental pipeline capacity serving the Chicago market since late 1998 and because it corresponds to the decrease in firm transportation costs. The increase in pipeline capacity, the Company argues, has exerted downward pressure on the value of the transportation price “spread” from the production areas to the Chicago city-gate, and thus reduces the potential for Nicor Gas to generate credits from selling supply, purchased storage, or pipeline capacity to other entities. (Id. at 4). The Company determined the amount of this reduction by computing the percentage of Capacity Management Credits obtained in the first five months of 1998 as a percentage of the Credits for 1998 as a whole, then used that percentage and the actual Capacity Management Credits obtained in the first five months of 1999 to project a figure for 1999 as a whole, which it believes is representative of credits for the year 2000. (Id. at 5).

4. Commodity Adjustment

The third and final adjustment to the Market Index Cost is the Commodity Adjustment, which would be an addition to the Market Index Cost. It is intended to account for any historical variation between the Market Index Cost and Nicor Gas’ actual historical gas costs that is not otherwise accounted for by the Storage Credit and Firm Deliverability Adjustments. This remaining variation may result from a variety of factors, including: (1) the commodity cost associated with reserving firm pipeline supply (a premium that is not captured in published city-gate market index prices); (2) any

This reduction of approximately $14 million exceeds the overall reduction of approximately $9 million ($130.7 million—$121.7 million). This occurs because of a corresponding adjustment to Commodity Management Credits.

The Company also eliminated an item referred to as “Storage injection/withdrawal costs” from the Firm Deliverability Adjustment because those costs related principally to a storage service which has expired. (Gilmore Supp. Rebuttal at 4).

differences in the timing of purchases, or pricing terms and location; and (3) revenue earned by Nicor Gas through off-system storage arrangements. (Id. at 14).

The Commodity Adjustment is calculated by:

(1) Computing the difference between Actual Gas Costs and the Market Index Cost for a past year or years

(2) Subtracting the Storage Credit Adjustment and adding the Firm Deliverability Adjustment for the year to that result

(3) Dividing the remainder by the MMBtus delivered in the year(s) being examined, which results in the per-MMBtu Commodity Adjustment Rate, a rate that remains fixed for the duration of the Program

(4) The total Commodity Adjustment for the calendar year is determined by multiplying the volume of sales for the year by the Commodity Adjustment Rate.

(See Werneke Direct, Ex. EMW-5 and Gilmore Surrebuttal, Exs. LMG-6 and LMG-7).

Nicor Gas originally proposed a Commodity Adjustment Rate of $0.06 per MMBtu, but later changed that figure to $0.049 per MMBtu based on recommendations from Staff and the subsequent changes to its Market Index Price weighting.

B. Computing the Amount of Savings or Losses for the GCPP Year

Once the Benchmark Gas Costs for a particular year are computed (based on the Market Index Cost and the three adjustments), the next step is to compare those costs to Nicor Gas’ Actual Gas Costs for the year. These Actual Gas Costs are the total recoverable costs for the calendar year as calculated and filed under Nicor Gas’ Rider 6, (i.e., the costs that would be reflected in a PGA reconciliation case under traditional regulation), adjusted to (1) exclude amortized amounts for the over- or under-collection of gas costs in the past (which is irrelevant to the GCPP); (2) add back any credit attributable to pipeline refunds for periods prior to the effective date of the GCPP; and (3) exclude pipeline transition and take-or-pay costs. (Id. at 15-16). Nicor Gas does not expect to receive any benefit under the GCPP from any of these items (Id. at 16) and they have not been challenged by any party. The difference between the Benchmark Gas Costs and Actual Gas Costs represents the savings or losses for the GCPP year.

C. Allocation of Savings or Losses Between Nicor Gas and Customers

After the amount of savings or losses for the GCPP year is determined, they must be allocated to create an “equitable sharing” between the Company and customers. See 220 ILCS 5/9-244(b)(8). Nicor Gas proposes a 50/50 sharing of all savings and losses up to $30 million, and 90/10 sharing for amounts above $30 million (with 90% allocated to ratepayers). (Elliott Direct at 5-6). The Company chose these percentages because it believes they will produce an equitable result and create an appropriate incentive to outperform the Benchmark, given the additional risks Nicor Gas would incur under the Program as opposed to traditional regulation. The $30 million threshold for 50/50 sharing reflects Nicor Gas’ judgment as to the reasonable level of risk that the Company can assume under the GCPP. (Id.)

D. Mechanism for Sharing Savings or Losses With Customers

Nicor Gas proposes to share savings or losses under the Program with customers through a new Rider 4. (Harms Direct at 2 & Ex. AEH-1). Under Nicor Gas’ proposal, the determination would utilize five components: the Actual Gas Costs (“AGC”) for the year; the Benchmark Gas Cost (“BGC”) for the year; the adjustment factor (“AF”) related to sharing of savings or costs between the Company and its customers; the percentage of total gas costs that were incurred the preceding year as commodity gas costs (“PCGC”), and the percentage of total gas costs that were incurred the preceding year as demand gas costs (“PDGC”). Rider 4 would utilize actual data to develop the cost components. Because the determination of the Benchmark is dependent on actual delivered sales to customers, actual city-gate index prices, and actual storage withdrawal volumes for sales to customers, all final determinations would be completed after the end of the calendar year. (Harms Direct at 2-3).

For purposes of the GCPP, the AGC would equal total recoverable gas costs, as defined pursuant to Section D(a) through (d) and (f) of Rider 6, for the prior calendar year, adjusted for the amortization of reconciliation balances, transition costs, any new FERC-ordered surcharges, and amortized pipeline refunds relating to periods prior to the effective date of Rider 4; (Id. at 4).

The BGC is comprised of four parts: Market Index Cost, Storage Credit Adjustment, Commodity Adjustment, and Firm Deliverability Adjustment. (Id. at 3).

Under Rider 4, Nicor Gas would compare the AGC to the BGC to determine the annual savings or costs to be shared between customers and the Company as a result of the GCPP. Factor AF, representing the applicable level of sharing, would be applied to the annual savings or costs generated by the GCPP. Factors PCGC and PDGC would be applied to the Company’s share of the annual savings or costs to yield the Gas Cost Performance Commodity cost (“GCPC”) and the Gas Cost Performance Demand cost (“GCPD”), respectively. The GCPC would be added to and amortized as part of the Commodity Gas Charge (“CGC”), filed under the provisions of Rider 6. The GCPD would

be added to and amortized as part of the Demand Gas Charge (“DGC”), the Non-Commodity Gas Charge (“NCGC”), and the Aggregator Balancing Service Charge (“ABSC”) also as filed under the provisions of Rider 6. (Id. at 4-5).

The GCPC and the GCPD would be estimated on a year-to-date basis and incorporated into the Gas Supply Cost if those figures are known and measurable and if material changes occurred during the course of the calendar year which were reflected in the accounting books of the Company. (Id. at 6).

Nicor Gas would make interim adjustments to the Gas Supply Cost as a result of the GCPP in order to provide better matching of costs and their recovery. Because the sharing of performance costs or benefits achieved by the Company would be more closely aligned with the period in which the gas costs would be incurred, this would benefit both customers and the Company. (Id.)

The Company’s share of savings or costs resulting from the GCPP would be allocated between the GCPC and GCPD in whole dollars and not on a per-therm basis. The dollars allocated to the GCPC would be added to and included as part of the CGC. The dollars allocated to the GCPD would be added to and included as a part of the DCG, NCGC, and ABSC. The allocation of dollars to the GCPD would be based on its percentage of total gas supply costs with the remaining dollars allocated to the GCPC. (Id.)

The GCPC would be incorporated as part of Factor A for the calculation of the CGC, and the GCPD would be incorporated as part of Factor A for the calculation of the DGC, NCGC, and ABSC. Allocating a portion of the shared savings or costs from the GCPP to the DGC, NCGC, and ABSC would allow customers purchasing Firm Backup or Balancing Services from Nicor Gas to share equitably in the effects of the GCPP. (Id. at 7).

V. Analysis of Disputed Issues

The issues in dispute here center on the GCPP’s satisfaction of Section 9-244(b)(1), which requires that the Program be “likely to result in rates lower than otherwise would have been in effect under traditional rate of return regulation for the services covered by the program,” and Section 9-244(b)(8), which requires that the Program include “provisions for an equitable sharing of any net economic benefits between the utility and its customers.” CGI also raises concerns with respect to other parts of Section 9-244(b).

A. Market Index Price and Market Index Cost

By the end of the proceeding, there was no dispute regarding computation of the Market index Cost and Market Index Price. All parties agreed that in computing the Market Index Price the market-price indices should be weighted at 65% first-of-the-month pricing and 35% daily-average pricing. (Iannello Tr. 78-79) (Surrebuttal Mierzwa at 4) Accordingly, we approve the Company’s proposal with regard to the Market Index Cost and Market Index Price.

B. Storage Credit Adjustment

All parties agree that the Storage Credit Adjustment should be computed using the Market Index Price. The primary disputes concern the period to be used for determining injections and withdrawals and the method of making those computations.

Company’s Position

The Storage Credit Adjustment is intended to recognize the annual benefit that Nicor Gas’ customers receive as a result of the Company’s purchase of gas supplies during off-peak periods, when prices are typically lower, the injection of that gas into storage, and the withdrawal of those supplies to meet demand during peak periods, when prices are typically higher. The Storage Credit Adjustment is determined by multiplying the actual number of units of gas withdrawn from storage in the GCPP year by the Storage Credit Rate. After the Storage Credit Adjustment is calculated by using the Storage Credit Rate, under the Company’s proposal, it would be subtracted from the Market Index Cost to reflect the fact that storage injections and withdrawals influence the Company’s gas costs.

The Company would use historical injection amounts from 1997 and actual withdrawal amounts for each GCPP year. This both prevents any claim that injections can be manipulated and accounts for the variability of withdrawal amounts from year to year.

Staff’s Position

Staff believes under certain circumstances, the Storage Credit Adjustment could, give the Company an incentive to create false savings by shifting withdrawals to months when Market Index Prices are low, and meet demand with current purchases when Market Index Prices are high. By so doing, Staff avers that the Company could reduce the Storage Credit Rate and raise the Benchmark, thereby enabling the Company to share in greater “savings” or fewer “losses”. The net result, according to Staff, could be an increase in the cost of gas to ratepayers.

To counteract the incentives for the Company to shift withdrawals, Staff proposed either a Regression Method or a Ratio Method to be used to estimate the Storage Credit Adjustment. The Regression Method, as proposed by Staff, would provide an estimate of

the Storage Credit Adjustment by regressing historical savings from storage use on the Withdrawal/Injection (“W/I”) Price Differential. To develop the W/I Price Differential, at the end of each year, Market index Prices for each month would be calculated to determine the Market Index Cost component of the Benchmark. These same Market Index Prices would then be weighted by a five-year average of the withdrawal and injection patterns for 1994 through 1998. The difference between the weighted-average withdrawal and injection prices would be the W/I Price Differential. The W/I Price Differential then would be inserted into the regression equation to arrive at the Storage Credit Adjustment for the year.

The Ratio Method, as suggested by Staff, would apply a ratio—the historical average of savings from storage use to the W/I Price Differential for any given year. Staff contends that the Ratio Method is the most accurate available and should be acceptable to the Company.

In its reply brief, Staff points out that during the pendency of the hearing, Nicor submitted revised data and revised computation methods which impact upon the accuracy of the parties’ respective methods of estimating the Storage Credit Adjustment. Specifically, Staff notes that the Company 1) corrected a mistake in the reported numbers for December 1997; 2) changed its weighting method from an average of 1997 and 1998 injections to the adjusted levels for 1997 alone; and 3) changed its Market Index Price weighting to 65% first day of the month/ 35% average daily price from its originally proposed 50/50 weighting.

Staff argues that incorporating these changes demonstrates that the ratio method varies least from the actual savings recorded. CGI’s method produced a variation of as much as $20 million from actual values for storage from 1994 through 1998. The Company method produced a variation of $8.7 million. Staff’s regression method varied by $7.6 million, while the ratio method was most accurate at $6.7 million. (Staff EX 7.0 Supp. Sch 5).

CGI’s Position

CGI contends that the Storage Credit Rate should be determined using projected injections under normal weather and actual withdrawals. CGI also recommends using net injection and withdrawal amounts rather than gross amounts as proposed by Nicor Gas. (CUB’s initial brief at 16 and Mierzwa Surrebuttal at 5) CUB maintains that gross numbers fail to represent storage activity under normal conditions and fails to reflect that Nicor records net amounts for financial reporting methods.

Company’s Response

As an initial matter, the Company pointed out that Staff recognized and admitted that the Storage Credit Adjustment would provide an accurate estimate of actual savings. (See lannello Direct at 11).

In addition, Nicor Gas disputes Staff’s assertion that the Storage Credit Adjustment creates an incentive for the Company to shift withdrawals. The Company states that in order for it to manipulate the system as Staff suggests, the Company would have to be able to predict Market Index Prices, actual variable commodity costs, and the relative difference between the two, and do so for multiple monthly periods. The Company denies having any ability to make such accurate predictions. According to the Company, to the degree that it currently makes estimates regarding future gas prices, those estimates are made for financial planning purposes and not for the timing of gas purchases. The Company states that the examples Staff used purportedly to show that shifting could occur were developed only with the benefit of 20/20 hindsight.

Moreover, the Company states that the steps it would need to take to manipulate the system as Staff suggests would, in fact, be bad business decisions. For instance, the Company states that the timing of withdrawals is largely determined by weather and operational requirements. As such, the Company states that peak day delivery could be impaired if the Company were to alter the timing of withdrawals arbitrarily. Likewise, the Company states that required inventory cycling could be adversely by delaying withdrawals, which could affect deliverability negatively in the succeeding heating season. The Company states that because it is required to provide reliable service, tinkering with the operational characteristics, which could have a negative impact on the performance of storage fields, would not be a sound business practice. For this reason, the Company concludes that it would have compelling incentives not to abuse the system in the manner Staff suggests (even if it were able to do so).

The Company added that any action that would increase the customer’s cost would be contrary to its long-term business objectives. For example, the first stated objective in Nicor’s Petition in this proceeding is to “align the interests of ratepayers and the Company by providing customers with the best prices available.” (Petition at 3). The Company claims that it specifically “structured its calculation of the Storage Credit Adjustment in order to pass along to customers the full seasonal benefit from storage.” (Gilmore Rebuttal at 4). Nicor Gas indicates that Staff offered no evidence to contradict this testimony.

The Company next states that both Staff alternative methods are inferior to the Storage Credit Adjustment. The Company claims the Regression Method is an unattractive alternative because the equation includes a $1.1 million intercept. As a result, even if the W/l Price Differential for a year is zero, Nicor Gas would be subject to an estimated Storage Credit of $1.1 million. The Company, therefore, states the Regression Method leads to an illogical result. Similarly, the Company states that the Ratio Method is flawed. According to the Company, because the Ratio Method relies

only on historical figures and its proposal relies on actual figures, the Company’s method is superior. The Company does not address the variation from actual injection volume numbers noted by Staff in its Reply Brief caused by the changes in data and methodology which occurred during the hearing.

With respect to CGI, the Company states that using net injection and withdrawal amounts is improper and would distort the Storage Credit Adjustment because it excludes significant injection volumes and therefore would overstate dramatically the Storage Credit Adjustment in every year.

Commission Analysis and Conclusion

The purpose of the Storage Credit Adjustment is to return to ratepayers the seasonal benefit associated with storage. Such an adjustment is reasonable because gas withdrawn from storage may not have been purchased during the month in which it is being used to meet demand.

Staff tells us that both the Company’s and CGl’s proposed methods for estimating the Storage Credit Adjustment, however, provide an incentive for Nicor to shift withdrawals to months when Market Index prices are low and meet demand with current purchases when Market Index prices are high. According to Staff, its proposed Ratio method is far better for the task in that it is calculated independent of the Company’s actions and, therefore, negates the incentive to manipulate withdrawals.

The Company maintains that its proposal is superior to Staff’s Ratio Method primarily because it relies on actual data. Moreover, Nicor claims that it has neither the incentive nor the ability to profit from shifting withdrawals. Indeed, Nicor asserts that there are practical constraints in place, such as the sheer impossibility of making key predictions, which prevent the Company from engaging in the type of behavior suggested by Staff.

Although the Commission agrees that both practical and legal constraints exist to prevent the Company from manipulating or inappropriately shifting withdrawals under its proposed Storage Credit Adjustment, we recognize that some potential for manipulation may exist. Accordingly, on this basis we conclude that Staff’s Ratio Method should be adopted as the means for computing the Storage Credit Adjustment.

We agree, however, with the Company’s assertion that this Ratio Method must be modified to some degree. Staff’s methodology relies on historical injections and withdrawals to derive what is called the W/I Price Differential. Reliance on such historical data should eliminate or, at the least, substantially reduce any concerns with respect to the manipulation of withdrawals. The ratio method, however, also uses historical injections and withdrawals to create a fixed coefficient (of approximately 16 billion, or about 116 BcF) by which the W/I Price Differential is to be multiplied each year.

Given that withdrawals are driven by weather which varies from year to year, Nicor argues that the W/I Price Differential (derived from historicals) should be multiplied by the

actual withdrawal level in each GCPP year. (Nicor Brief on Exceptions at 7). While Staff opposes this change to its methodology, it does not raise any meritorious claims and expresses no concern of possible manipulation. (Staff Reply Brief on Exceptions at 2-5 ).

To the extent that this modification to the Ratio Method embraces both historical data and actual data we believe that it is both reasonable and in keeping with the purpose of the Storage Credit Adjustment, i.e, to pass along to customers the full seasonal price benefit from storage. Thus, we adopt Staff’s ratio method with the modification proposed by the Company as appropriate to calculate the instant adjustment.

C. Firm Deliverability Adjustment

The issues regarding the Firm Deliverability Adjustment are what period to use to determine costs and credits, and how to account for new contracts between the Company and pipelines. The final proposals are:

Nicor Gas	Staff	CGI
$121,763,384	$113,301,109	$117,012,731 in 2000
		$110,466,628 in 2001

Company’s Position

As explained above, the Firm Deliverability Adjustment is an addition to the Market Index Cost and is based on the Company’s pipeline transportation and storage reservation costs, minus Capacity Management Credits. The Company made a final proposed Firm Deliverability Adjustment based on projected firm reservation costs and Capacity Management Credits for the year 2000. The Company states that it relied on figures for the year 2000 because that is the first year the GCPP would be in effect and because these are the most reliable projections available. In particular, the year-2000 projections account for known and measurable changes to the Company’s pipeline contracts and adjust Capacity Management Credits in light of recent developments, including the addition of substantial new pipeline capacity to the Chicago area and the reduction in firm transportation costs.

Staff’s Position

Staff recommends that the Company’s Proposal be reduced substantially based on modifications to the various components of the Firm Deliverability Adjustment. (Maple Supp. Direct at l-2).

Transportation and Storage Reservation Costs. Staff does not agree with the Company’s value for transportation and storage reservation costs. Staff bases its projection on: (1) the time period chosen to evaluate the costs associated with transportation and storage reservation, and (2) the projected costs for the transportation

contracts with Midwestern Gas Transmission Company (“Midwestern”) and Tennessee Gas Pipeline Co. (“Tennessee”).

Staff claims that the Company’s use of only year-2000 costs to determine the transportation and storage reservation costs is unfair to the ratepayers. If the Commission accepts the GCPP, it is scheduled to be in place until at least the end of 2001. Therefore, Staff contends, it is only logical to use costs for both 2000 and 2001 to determine the transportation and storage reservation costs. Staff claims that the Company’s contracts that are in place or that are currently being negotiated will run through 2001. The majority of these contract costs are known. Staffs argument for using a two year average is due to the fact that new contracts will go into effect in late 2000. Staff therefore proposes to use an average cost from 2000 and 2001 to determine the transportation and storage reservation value. (Id. at 4).

Staff also disagrees with the costs projected for the Company’s new transportation contracts with Midwestern and Tennessee. At the present time, these contracts are not signed, but rather are in the negotiation process. (Id. at 5). In order to project the future costs associated with these contracts, the Company used the initial offer presented by Midwestern and Tennessee. Staff believes that once the Company completes the negotiation process, it will have received a significant reduction in rates from the initial offer. Staff contends that the Company traditionally does not accept the first offer from a pipeline and tries to negotiate lower rates. For example, Nicor Gas recently came to terms on a contract with Natural in which it received a discount on the transportation portion from the initial offer. (Tr. 66) Staff therefore contends that the Company is incorrect to rely on the initial offer from Midwestern and Tennessee when, calculating the transportation and storage reservation value. Staff therefore recommends that the proposed costs for the new Midwestern and Tennessee contracts reflect the same percentage discount as National from the initial offers. (Id. at 6).

Capacity Management Credits. Capacity Management Credits (which Staff calls Transportation credits) consist of Capacity Release Credits, Gains from Buy/Sell Transactions, and Gains from Supply Sales. These credits offset the cost of the transportation and storage reservation costs. Staff does not agree with the Company’s proposal to compute these credits based on projections for 2000. Instead, Staff believes that the most recent twelve months of actual credits should be used as a proxy for future numbers. Staff therefore proposes Capacity Management Credits which are significantly higher than the Company’s proposal.

Staff asserts that the Company’s method of forecasting Capacity Management Credits is based on the assumption that the proportion of revenues received in each individual month will be the same for both 1998 and 1999. Thus, the Company uses both 1998 and 1999 data to make its forecast. In the year 1999, the Company had actual values only for the months January through May. To project the revenue for the rest of calendar year 1999, the Company uses 1998 as a guide. The Company determined the percentage of total 1998 revenue that had been realized by May of 1998. The Company

then divided the 1999 totals through May by the 1998 percentage to get its forecast. (Id. at 8)

Staff does not agree with this methodology for several reasons. First, the Company chose to group Capacity Release Credits with Buy/Sell Transactions to compute one percentage even though, according to Staff, they are two separate categories. Then the Company broke down Gains from Supply Sales into two separate categories, (1) Sales and (2) Linked Purchase/Sales, in order to compute two different percentages for which Staff believes there should be one category. Staff argues that this results in a forecast that understates Capacity Management Credits for 1999.

Specifically, Staff claims that, by using the Company’s method, it is possible to manipulate the numbers just by choosing which categories are grouped together and which categories are split apart. For instance, if gains from supply sales were kept in one group, the 1999 forecast would be about $30,000 higher than the Company forecasted. Staff also states that by combining Capacity Release Credits with Gains from Buy/Sell Transactions, the Company understated the forecast by another $30,000. The most obvious error, Staff asserts, is the forecast for Gains from Buy/Sell Transactions. The Company’s realized revenue in the months of January through May of 1999 almost equaled the Company’s total 1999 forecasted revenue. (Id. at 10). Even grouping all of the categories into one would result in a forecast that is over $70,000 higher than that of the Company. (Id.)

Based on these concerns, Staff proposes that the Commission use the most recent twelve-month period. Staff claims that the use of actual data avoids the use of arbitrary groupings and manipulations, utilized by the Company, to make a case for one number or another.

Second, Staff contends that the Commission traditionally has used the latest twelve-month historical period as a basis for forecasting these types of revenues. For example, Staff asserts that the Commission recently ruled in Dockets 98-0819 and 98-0820 that Peoples Gas and North Shore must use the latest twelve months of capacity release and off-system transaction credits as their forecast.

CGI’s Position

CGI witness Mierzwa recommends that the Company’s proposed Firm Deliverability Adjustment be substantially reduced and that it maintain its original proposal for Capacity Management Credits, which would also reduce the Firm Deliverability Adjustment. (Mierzwa Supp. Surrebuttal at 5-6).

CGI contends that firm transportation and storage reservation costs should be adjusted in 2001 based on actual figures, rather than projections. CGI argues that this is necessary to account for the new contracts that the Company will sign with Midwestern and Tennessee. (Id. at 5).

Company Response

Transportation and Storage Reservation Costs. The Company asserts that Staff’s proposal to use the average of costs for 2000 and 2001 is flawed because Staff includes decreased costs for 2001 but does not account for any increased costs that the Company might also incur in that year. For example, Nicor Gas states that it expects growth in peak-day demand to continue while the Program is in effect, which exposes the Company to greater risks and increases the need for firm transportation and storage reservation. (Gilmore Surrebuttal at 7-8). In addition, Nicor Gas states that Staff failed to include any costs for Nicor Gas’ precedent agreement for capacity on Horizon Pipeline, even though that pipeline is scheduled to commence operation in 2001. (Id. at 8). By failing to account for all aspects of 2001 costs, the Company argues, Staff has inflated improperly its proposed reduction to the Firm Deliverability Adjustment.

Nicor Gas also states that there is no credible basis for Staff’s assumption that the Company will obtain the same discounts from Midwestern and Tennessee as it did from Natural. First, as Mr. Gilmore explained, Nicor Gas’ contract with Natural “is for an overall package of services, including firm transportation capacity, purchased storage services and market area transportation. When negotiating a discount offer for a package of services, a decrease in the cost of one service (such as transportation) may be offset by an increase in the cost of another service (such as storage). When properly viewed as a total package, Nicor Gas received only small a discount from Natural’s initial offer. Further, every contract and every pipeline are different, so any assumption that pipelines negotiate generically and make the same trade-off and concessions is unfounded.” (Gilmore Surrebuttal at 7). Thus, the ultimate terms, services, and costs in the contracts with Midwestern and Tennessee may bear little resemblance to the contract with Natural.

Second, Nicor Gas explains how it calculated the Firm Deliverability Adjustment. The proposal selected already reflected a substantial discount (Id.) Thus, the Company asserts there is no basis for presuming that any additional discount will be achieved in the final contract, let alone the large additional discount assumed by Staff. (Id.)

The Company argues that CGI’s proposal to modify the Firm Deliverability Adjustment to reflect actual costs in 2001 is similarly flawed. Like Staff, CGI fails to account for likely increased costs in 2001. CGI also overlooks the fact that the Benchmark is a single, comprehensive total. The Company states that treating firm reservation costs differently from all other gas costs (by using actual figures rather than historical or projected) would ignore the inter-relationship among the various components of the Program and raise the possibility of cross-subsidization among components. (Gilmore Surrebuttal at 10). Further, Nicor Gas claims that CGI’s proposal directly

conflicts with Staff’s position that actual, contemporaneous costs should not be used in computing the Benchmark. (Ianneli Direct at 4).

Capacity Management Credits. The Company maintains that Staff’s approach to Capacity Management Credits is not well-founded. First, Staff rejected the Company’s approach because of the alleged danger of arbitrary groupings of cost categories; but, the Company notes, Staff admits that any such arbitrary grouping would understate Capacity Management Credits by at most $70,000. (Maple Supp. Direct at 10; Tr. 35). Rather than make a simple $70,000 adjustment, however, Staff proceeded to adopt an entirely different approach, resulting in a substantial increase. The Company views this as an unwarranted overreaction. Further, the Company states that it grouped capacity release credits together with buy/sell transactions because of the similarity between those categories, which made it logical to project future amounts using the same assumptions. (Gilmore Surrebuttal at 9). The Company contends that this approach is not arbitrary at all, much less so arbitrary that Staff had to abandon the Company’s approach altogether.

Second, the Company asserts that the rationale underlying Staff’s alternative methodology is erroneous. Staff claims that the Commission “traditionally” has used twelve-month historical data to forecast these types of revenues. When cross-examined, however, Staff’s witness was unaware that large LDCs in Illinois—including Nicor Gas—have used forecasted test years in their rate cases for decades. (Tr. 35-36). The Company states that, because Staff’s basic assumption is wrong, Staff’s proposal has no valid underlying rationale.

The Company further notes that the “tradition” Staff relies on comes from a total of two related cases, the Peoples Gas and North Shore Gas decisions in Docket Nos. 98-0819 and 98-820. (Maple Supp. Direct at 11). The Company states that two cases (one, really, since the decisions were identical), hardly constitute a tradition, and that the Commission made no affirmative finding in those cases that, as a policy matter, historical data are preferable to forecasts. To the contrary, while they approved the use of recent historical data for certain items, those Orders also stated that the Commission “(recently . . . has supported proposals [regarding gas costs] which are based upon a future test period.” In fact, the Commission has stated that, when it is setting rates for the future, it “can only support a proposal which is based upon a future test period.” The Peoples Gas Light and Coke Co., Docket No. 98-0820 at 8; North Shore Gas Co., Docket- No. 98-0819 at 8. Nicor Gas argues that the Commission is setting rates for the future in this case, and the use of forecasted data is entirely appropriate.

Third, the Company states that the use of twelve months’ reported data for each of the categories included in Capacity Management Credits would lead to inaccurate results. Nicor Gas has proposed figures for the year 2000 based on actual results in 1999 that reflect the most recent information, including completion of the Northern Border Pipeline expansion, which began delivering gas to the Midwest market in December of 1998. (Gilmore Surrebuttal at 9-10). Data from the most recent twelve months would only partially reflect the impact of this capacity on the market, whereas the Company’s use of a ratio of the current year to the same period in 1998 captures the impact of this new capacity. (Id. at 10).

Fourth, the Company asserts that Staffs use of a different time period (as opposed to the average of 2000 and 2001) shows the “pick and choose” nature of its recommendations on this issue and ignores both the direct relationship between the level of firm transportation costs and the level of Capacity Management Credits. There is no reason to suddenly eschew all reliance on forecasts when it comes to Capacity Management Credits.

Finally, the Company states that, if the Commission decides to rely on the most recent twelve months to compute Capacity Management Credits, it should authorize the Company to submit results through October of 1999. Staff did not object to that proposal. The Company also stated that Staffs proposed Capacity Management Credits would have to be further reduced to account for the decrease in firm reservation costs recommended by Staff, as a reduction in firm reservation costs will also reduce Capacity Management Credits.

The Company also objects to CGl’s proposal on Capacity Management Credits. First, CGI has proposed the use of actual firm reservation costs in future periods, yet also proposed to compute Capacity Management Credits based on historical figures from 1998. The Company finds this internally inconsistent, as firm reservation costs are closely related to Capacity Management Credits. In addition, although CGI proposes to use actual costs resulting from any future agreement between Nicor Gas and Midwestern and Tennessee, the terms of any such agreement are not known, and provisions related to capacity release within a discount agreement can vary significantly between pipelines and between agreements. Nicor Gas has not received any proposal from Midwestern and Tennessee which addresses capacity release. Therefore, the Company states that it is highly speculative to assume that credits under an assumed discount agreement with these pipelines will be the same as historical amounts. (Gilmore Surrebuttal at 11).

Second, the Company states that CGl’s contention that warmer than normal weather produced lower credits in the first part of 1999 is misleading. While it is true that warmer weather reduces the value of capacity release, colder weather reduces the ability of the Company to release capacity, since it is needed to serve system demand. Therefore, Nicor Gas states that it would be less able to release this capacity in colder weather, so there is no guarantee that colder weather would mean more credits for the Company.

Third, CGI assumes that the possible entry of Vector Pipeline into the marketplace will allow Nicor Gas to maintain past levels of Capacity Management Credits. (Mierzwa Errata Supp. Surrebuttal at 6). However, the Company responds, Vector Pipeline, even if constructed, will not influence the value of capacity release prior to the Commission’s opportunity to review the GCPP. To begin with, new capacity to the Chicago market has either been constructed (Northern Border with over 600,000 MMBtu/d of capacity) or is under construction (Alliance Pipeline with 1.2 Bcf/d of capacity) and scheduled to be in service by November 2000. (Gilmore Supp. Surrebuttal at 2). Vector Pipeline has not begun construction. The capacity of Vector also is about half that of Northern Border and

Alliance combined, and Vector will be used to access storage capacity in Michigan. (Id.) Thus, the Company states that Vector may actually serve as a supply source to the Chicago market, further reducing potential Capacity Management Credits. (Id.)

Commission Analysis and Conclusion

This adjustment is based on the Company’s pipeline transportation and storage reservation costs minus capacity management credits and is an addition to the Market Index cost. While the Company proposes to use only year 2000 costs to determine the transportation and storage reservation costs, Staff argues that an average of year 2000 and 2001 cost is more appropriate given that new contracts will go into effect in late 2000 and those now in place or under negotiation, will run through year 2001. The Commission finds Staff’s proposed modification to the Company’s proposed Firm Deliverability Adjustment that incorporates projected costs for 2000 and 2001 to be reasonable and in accord with Section 9-244(b) of the PUA. The Company’s proposal based only on projections for the year 2000, the first year the GCPP will be in place, fails to take into account the likely lower cost contracts which will come on line in 2001.

While we agree with Staff’s proposal to use projected costs for both 2000 and 2001, we do not believe that Staff’s estimate accurately reflects the costs the Company is likely to incur. As pointed out by Nicor Gas, Staff’s proposal accounts for projected decreases in firm reservation costs in year 2001, but does not correspondingly account for possible increased costs from such factors as growth in peak demand or the costs of the Company’s agreement with Horizon Pipeline scheduled to begin service in November 2001. In addition, while the Company may obtain cost reductions in its pipeline contracts taking effect in 2001, the record does not support Staff’s estimates of the size of those reductions. To the extent that such estimates can rationally be used at all when dealing with unique contracts and with distinctly individual pipelines, we agree with the Company’s showing and assertions that the reductions to be obtained are likely to be half of Staff’s estimate. Accordingly, we direct the Company to include its estimates for firm reservation costs and storage costs.

The Commission finds reasonable the Company’s suggestion to rely on the most recent twelve months to compute Capacity Management Credits with an appropriate reduction arising from- lower firm reservation costs. The Commission, therefore, authorizes the Company to submit results through October of 1999 as proposed by Mr. Gilmore and explained in the Company’s briefs. (See, Nicor Gas Reply Brief at 10-l1). If future events should affect the accuracy of the Firm Deliverability Adjustment, the Commission will be able to revisit the issue soon enough in its two-year review of the GCPP. At this time, however, the Staff’s proposal appears to be both reasonable and accurate and will lead to an appropriate Benchmark against which to measure Nicor Gas’ performance.

As for CGI’s proposals, we find that CGI inconsistently relies on a future period to project firm transportation and storage reservation costs, but a historical period for Capacity Management Credits. Because these cost categories both go into the same

Firm Deliverability Adjustment, they should be treated the same. In addition, we do not agree with CGl’s criticisms of the Company’s use of 1999 data to project Capacity Management Credits or its claims about the impact of Vector Pipeline on the Company’s ability to generate Capacity Management Credits. These allegations are not supported by the record.

For these reasons, we accept Staff’s Firm Deliverability Adjustment as modified by the computation of capacity management credits from data for the twelve months ending October 31, 1999. While Staff does not object to using the most recent 12 months of data as Nicor proposed, it does take issue with any reductions being made to those figures on grounds that this data already reflects changes in the market. (Staff Brief on Exceptions at 2). On this point, we agree with Nicor that such an adjustment is necessary to maintain a reasonable relationship between the level of firm reservation costs and the level of attainable capacity management costs. Staff’s own evidence shows that firm reservation costs and Capacity Management Credits have moved in the same direction. Thus, the Capacity Management Credit will be reduced to account for the lower firm reservation costs as discussed above.

D. Commodity Adjustment

As explained above, the Commodity Adjustment accounts for factors that affect the cost of gas but which are not captured by the Storage Credit Adjustment or Firm Deliverability Adjustment. There is no real dispute about the need for a Commodity Adjustment. Rather, the debate has centered on (1) what year(s) results should be used to compute the Commodity Adjustment Rate, and (2) whether the Commodity Adjustment Rate should be further reduced by an “X-factor.” The competing proposals for the Commodity Adjustment Rate are:

Nicor Gas		Staff		CGI
$0.049 per MMBtu		($0.006) per MMBtu		($0.049) per MMBtu

Company’s Position

Nicor Gas computes the Commodity Adjustment Rate based on the average of the actual Commodity Adjustment Rates for 1994, 1995, 1997, and 1998. (Gilmore Surrebuttal at 12). The Company had originally proposed to use the average of the actual Commodity Adjustment Rates for 1997 and 1998 alone, but eventually agreed to include 1994 and 1995 as well based on recommendations made by Staff. (Id.) The Company states that the results for 1996 have been excluded from this calculation because that year, due to extremely abnormal weather and certain market factors that have since been eliminated, was an anomaly that would unduly distort the ultimate result. The Company also states that, if the Commission were to decide to use 1996, it must be properly weighted at 6.25% to reflect its anomalous nature as the coldest year in the prior 16 (6.25% l/16). (Gilmore Surrebuttal at 13).

The Company states that the key factors which contributed to the difference between the Market Index Price and its actual variable commodity costs in early 1996 have since been eliminated. First, the Company explains that in early 1996 there was a constraint on deliverability to the Chicago Market. This contributed to the differential in the cost of gas in Chicago versus gas purchased in the producing regions. With the construction of new pipeline capacity into the Chicago area, it is highly unlikely that the deliverability constraints that existed in early 1996 will recur during the term of the GCPP. This additional pipeline capacity substantially exceeds projected growth in the Company’s service territory. In addition, because of its 1996 experience, the Company has established, for planning purposes, multiple design peak days extending later into the heating season, which will forestall the type of deliverability constraints experienced in 1996.

Second, in early 1996 there was a significant difference among Chicago area utilities in the charge to transportation customers for unauthorized gas usage. This difference led to artificially inflated market prices in early 1996 as Nicor Gas and/or its customers had to outbid marketers who were diverting supply to Peoples Gas to avoid Peoples’ higher unauthorized use charges. This difference no longer exists, as Nicor Gas’ unauthorized use charge is now the same as Peoples’.

Third, in early 1996 there was a five-day nomination lockout prior to the first day of each month. This made it difficult for the Company to obtain supply when the weather was much colder than expected on February 1, 1996 and to manage storage thereafter. As a result, the Company had to rely on storage when it had not planned to do so, which forced prices higher in February 1996. The first-of-the-month lockout no longer exists. (Gilmore Rebuttal at 14-15).

In addition, the Company argues that including 1996 data would badly distort the Commodity Adjustment. The actual Commodity Adjustment Rate as computed for 1996 varies dramatically from the actual Commodity Adjustment Rates for all other years from 1994 through 1998, which are fairly consistent. (Gilmore Surrebuttal at 13 and Ex. LMG-6). The Commodity Adjustment Rate for each of those years would be as follows:


1994		$0.051
1995		$0.068
1996		negative $0.227

1997		$0.028
1998		$0.051

The figures for years other than 1996 average $0.049, with a maximum variance from the average of $0.021. By contrast, 1996 departs from that average by $0.276—more than 10 times the maximum variance in any other year. (Gilmore Surrebuttal at 13). Thus, the Company concludes, 1996 undeniably was highly unusual. Consequently, the Company states that including 1996 in deriving the Commodity Adjustment Rate would result in a

Benchmark that is unreasonably low and most likely unattainable, and therefore unduly biased against the Company in terms of risk. (Id. at 14).

Staff’s Position

Use of 1996 Data. Staff originally proposed to base the Commodity Adjustment Rate on 1997 alone, 1997 being a relatively normal weather year. (Iannello Direct at 13). In its rebuttal testimony, however, Staff recommended using results from 1994-1998. Staff contends that 1996 is appropriately included because the factors that contributed to the extremely high prices for gas in 1996 have not been totally eliminated. (Iannello Rebuttal at 15-l 7).

Staff replies to the Company’s arguments for exclusion of 1996 in three ways. First, Staff claims that the Company’s three factors do not all have the effect on prices and Nicor Gas’ variable commodity costs that the Company claims. Second, Staff asserts that a deliverability constraint may still exist or may arise in the future. Third, Staff alleges that factors other than those identified by the Company affected the Market Index Price and Nicor Gas’ variable commodity costs and contributed to the particularly low residual in 1996.

Staff asserts that Mr. Gilmore’s testimony regarding the effect of a pipeline capacity deliverability constraint is unsubstantiated by the record. Staff contends that while Mr. Gilmore points out that pipeline capacity to the Chicago market area has increased, he provides no convincing evidence that the deliverability constraint on pipeline capacity was the cause of the unusual results in 1996.

Regarding the difference in critical day unauthorized-use charges between Nicor Gas and Peoples in 1996, Staff claims that it was the magnitude of the Peoples charge ($60 per MMBtu vs. Nicor Gas’ $10 charge), not its relative size compared to the Nicor Gas charge, that raised the Market Index Price relative to Nicor Gas’ variable commodity costs in early 1996. To support this claim, Staff quotes the rebuttal testimony of its witness:

the fact that Nicor Gas’ unauthorized use charge on critical days is now $60 per MMBtu rather than $10 per MMBtu could contribute to an even greater difference between the Chicago market and producing regions where Nicor purchases commodity supply. In 1996, transportation customers on Peoples Gas, Light & Coke Company’s distribution system were willing to pay up to $60 per MMBtu to avoid unauthorized use charges. Transportation customers on Nicor Gas’ distribution system were only willing to pay up to $10 per MMBtu to avoid unauthorized use charges. In 1996, Nicor customers would have placed a higher demand for Chicago-provided unauthorized use gas than they would today under similar circumstances. Thus, in 1996, with a $10 unauthorized use charge

versus today’s $60 charge, there would have been greater upward pressure on Nicor Gas’ variable costs.

(Iannello Rebuttal at 16-17). Staff also claims that, given Nicor Gas’ now-higher unauthorized use charge, a panic situation similar to that which apparently occurred in 1996 is likely to have an even greater effect on market prices and the difference between the Market Index Price and Nicor Gas’ own variable commodity costs.

Staff’s third argument is that the five-day nomination lock-out period that existed prior to the beginning of each month in 1996 at best only explains high Market Index Prices versus Nicor Gas’ variable commodity costs for a day or two after the first of the month in February of 1996. Staff claims that prices should have quickly recovered if the five-day lockout was the factor affecting gas prices, yet prices at the Chicago city-gate were persistently higher than Nicor Gas’ variable commodity costs throughout the year. (Iannello Rebuttal at 16-17).

Responding to the Company’s assertion that none of the three factors driving 1996 prices will recur, Staff claims that deliverability constraints on pipeline capacity could arise in the future. For instance, Staff states, the Company predicts substantial growth in peak-day demand in its service territory over the next five years. Growth in peak-day demand could constrain pipeline capacity in future periods leading to results similar to those in 1996. Furthermore, Staff claims that the Vector Pipeline will move gas out of the Chicago area, thereby reducing the amount of available capacity. Staff therefore states there is no reason to believe that similar constraints will not develop in future periods.

Finally, Staff contends that some of the factors affecting the difference between Nicor Gas’ costs and the Market Index Price are not even related to cold weather. Staff claims that in July of 1994, the Market Index Price was 128% of Nicor Gas’ variable commodity costs per MMBtu, which is approximately the same percentage difference that it was for several months during the winter of 1996. (Iannello Rebuttal at 17). Staff claims that the fact that such significant difference show up in July is significant because the three factors identified by the Company are largely related to cold weather and periods of extreme demand, yet this difference occurred in the middle of the summer. Staff concludes that factors other than those identified by the Company have influenced the price differences, and there is no reason to believe that these factors will not have a similar effect in the future.

X-factor. Staff also proposed an additional reduction in the Commodity Adjustment Rate of $0.008 per MMBtu to reflect its theory that the Company operates inefficiently under traditional regulation and that ratepayers therefore should expect gains in switching from traditional PGA to incentive regulation. Staff calls this reduction the “X-factor.”

Staff argues that the Company has not explained how or why Staffs X-factor justification is somehow irrational. Staff also asserts that the X-factor accounts for a very modest expectation of savings. An X-factor of $0.008 per MMBtu, when applied to 1997 normalized sales volumes, amounts to only 0.2% of the 1997 PGA costs. (Iannello Direct

at 14). While recognizing that precise computation of an X-factor is unrealistic, Staff claims that it is neither unrealistic nor unreasonable for the Commission to impose an expectation for savings to reach this bare minimum of 0.2%.

CGl’s Position

CGI proposes to use the years 1998-1998 to compute the Commodity Adjustment Rate. (Mierzwa Surrebuttal at 8). CGI contends that including 1996 is appropriate because the main factor making that year anomalous was extremely cold weather, and such weather could occur again. (Mierzwa Surrebuttal at 7-8). CGI also claims that including 1996 is necessary to reduce the Commodity Adjustment Rate and ensure that Nicor Gas does not benefit from a spike in gas prices. Based on its inclusion of 1998 data, CGI proposes a negative Commodity Adjustment Rate that would reduce the Benchmark by $11.9 million, as opposed to the $11.9 million increase to the Benchmark computed by Nicor Gas.

Company Response

Use of 1996 Data. In response to Staff’s arguments on the inclusion of 1996 in computing the Commodity Adjustment Rate, Nicor Gas reiterates its earlier arguments on the unusual nature of that year, the elimination of the factors driving market prices at that time, and the distorting effect of including 1996 data. The Company also notes that Vector Pipeline is likely to bring gas into the Chicago area, not take it away, and therefore will not create a deliverability constraint. The Company further explained that the term “deliverability” does not apply only to pipeline deliveries, as Staff assumes, but rather refers to the ability to deliver gas to customers at a given time, regardless of whether the gas comes from a pipeline or from storage. Thus, the Company’s addition of design peak days since 1996 will help ensure sufficient gas in storage and help prevent a repeat of the 1996 deliverability constraint.

X-factor. Nicor Gas contends that Staff’s proposed X-factor reduction to the Commodity Adjustment Rate is not based on any factual or economic analysis. Rather, Staff simply believes that” [t]he desirability of a [PBR program] depends on a presumption that there is something to gain” over traditional regulation, meaning that there is some existing inefficiency that keeps the Company from completely minimizing its gas costs. Based on the presumption that the Company should not be rewarded for eliminating such hypothetical inefficiency, Staff proposes to reduce the Commodity Adjustment by approximately $2.4 million dollars. (Gilmore Rebuttal at 13). In other words, the Company states, applying the X-factor would require Nicor Gas to reduce its gas costs by $2.4 million below traditional levels before any savings would be eligible for sharing under the GCPP.

The Company maintains that there is no legal, factual, or policy basis for such a reduction. First, the X-factor itself is a completely arbitrary number, based on no analysis of prior gas costs, likely savings, or any other data. The X-factor has no basis other than as an excuse to round the Commodity Adjustment Rate down to the next whole number and put Nicor Gas $2.4 million in the hole before even beginning the Program.

Second, Staff contends that “the X-factor simply accounts for the expectation that the Company will operate more efficiently under the GCPP than under the traditional PGA.” (Iannello Rebuttal at 19). Nicor Gas states that Staff’s logic is at odds with the very concept of alternative rate regulation. Although Mr. Iannello testified that he was not philosophically opposed to incentive regulation (Tr. 86), the only purpose of the X-factor is to make it much more difficult for the Company to receive any reward for increasing its efficiency, even though such rewards are the essence of incentive regulation. Furthermore, Nicor Gas states, Staff’s X-factor works only against the Company: Nicor Gas could actually beat the Benchmark (computed without the X-factor) by $2.39 million and yet have to treat the entire amount as losses. (Gilmore Rebuttal at 13.) Nicor Gas argues that asymmetrical regulation is not consistent with the requirement of Section 9-244(b)(8) that sharing of benefits be “equitable.”

Commission Analysis and Conclusion

The Commodity Adjustment accounts for past historical variations between actual gas costs and Market Index Costs which stem from factors not accounted for in other parts of the Benchmark formula. It adjusts the Benchmark for, among other things, the differences “in the timing of purchases, or pricing terms and locations” and thus accounts for the possibility of purchases outside Chicago. (Wernecke Direct at 14).

With respect to this adjustment, the real question is what year or years should be used to compute the Commodity Adjustment Rate. Initially, the Company proposed to average the rates for 1997 and 1998, while Staff proposed the use of only the 1997 year rate. In subsequent testimony, however, Staff recommended using the result derived from averaging data from the years 1994-l 998.

Staff’s recommendation drew opposition from the Company insofar as the 1996 data was concerned because both the weather and certain other market factors conspired in that year to produce a highly abnormal result, when compared to the results from the other years being considered. Thus, the Company urges the elimination of the 1996 data such that the computation would be based on the average of 1994, 1995, 1997 and 1998 actual rates. Staff and CGI maintain that the 1996 results, however unusual, should be included because the factors which contributed to those results have not been totally eliminated.

Regarding the use of 1996 data, we agree with the Company that the price spikes and differential between market prices and the Company’s actual variable commodity cost in early 1996 were highly unusual. Indeed, the Commission subsequently conducted a special investigation to determine exactly what happened in those first few months of the year. Extreme weather and periodic price spikes in natural gas, however, are a recurring phenomenon that cannot be eliminated in a free market economy. Therefore, we believe that it is appropriate, as Staff and CGI propose, to include 1996 data in computing the Commodity Adjustment Rate.

We are not convinced, however, that the 1996 data should be given the same weight in the computation as the data from the other years in the 1994-1998 time period. Where it is evident that 1996 was an unusual year for gas prices, giving it equal weight in the averaging process of such a small sample, produces a wholly distorted result. On this point, we observe that when Staff weighs the 1996 data equally, its computation results in a negative number. Yet, of the five years included in the calculation, only year 1996 produces a negative rate. In other words, the rate for four out of five years was positive. To us, this means that using a negative rate for each year of the program would not in any way be representative of the norm being sought by use of the averaging process.

It becomes obvious that the 1996 data must be given less weight than the other years in the 1994-1998 period in order to perform a reasonable computation. As an alternative to disregarding the 1996 data altogether, the Company proposes that we weight the 1996 data at 6.25% or one-sixteenth, to reflect its assertion that 1996 produced the coldest weather in 16 years. While this concept has some merit, we are not persuaded that it is the most appropriate for the situation. As pointed out by CGI, weather is only one of the factors which contributed to the 1996 situation and while the winter weather in 1996 was cold, it was far from the coldest in recent history. Indeed, in their Reply Brief on Exceptions, CGI look to. many years of historical weather data to make this point. This suggests to us that use of a longer time frame might have been the way to arrive at a more accurate and representative rate.

Both reason and experience support the premise that if the data for ten years were to be averaged, then the inclusion of one abnormal number could more easily be absorbed into the mix and might not produce a distorted result. In this instance, where only five years data is being averaged, the result of including highly abnormal data from 1996 has inevitably and unreasonably skewed the average.

In line with our premise and analysis, we believe that the 1996 data should be weighted at 50%,which is roughly equivalent to including it at full weight in a ten year average. Upon our considerable review of the issue, we find this to be the most reasonable way to treat the 1996 data. According to our computation, this will result in a Commodity Adjustment Rate of .0168 per MMBtu.

The Commission also finds Staff’s proposed X-factor adjustment to be unsupported and unnecessary. The X-factor is not based on any mathematical, statistical, or economic analysis. Nor is it based on any legal concern or alleged need to reduce the Commodity Adjustment Rate to satisfy the Act. Instead, the X-factor simply rounded the Company’s original proposed Commodity Adjustment Rate down to the next whole number. The only rationale for doing so was Staff’s assertion that there must be something to gain for the Company in switching from traditional PGA regulation to incentive-based regulation. That may be so, but that also is the very point of incentive regulation-that utilities may be able to improve their performance if given an appropriate incentive to do so, and that improved performance benefits customers and the utility alike. The X-factor seeks to deprive Nicor Gas of at least some of the benefits of incentive regulation before the GCPP even begins. We decline to do so.

E. Sharing Percentage for Savings or Losses

The competing proposals for sharing of savings or losses under the GCPP are as follows:

Nicor Gas		Staff		CGI
50/50 for first $30 million of all savings or losses, 90/10 (90% to ratepayers) for amounts exceeding $30 million		90/10 (90% to ratepayers) for all amounts		90/10 for all amounts (90% to rate payers) or 50/50 for all amounts, but no sharing of savings by the Company until savings exceeds a “deadband” based on certain costs

Company’s Position

Under the Company’s proposed GCPP; savings and losses would be shared with customers on an equal basis up to a total of $30 million, and amounts in excess of plus or minus $30 million would be allocated 90% to customers and 10% to the company. Nicor Gas states that it chose these percentages because they produce an equitable result and create an appropriate incentive to outperform the Benchmark, given the additional risks Nicor Gas would incur under the Program as opposed to traditional regulation. Nicor Gas further states that the Company’s proposed graduated sharing formula fairly balances the risks borne and the benefits received by both customers and Nicor Gas. (Elliott Direct at 6).

Nicor Gas asserts that equal sharing of the first $30 million of GCPP gains and losses is inherently fair to both the Company and the customers, as it recognizes the substantial risk that the Company would face under the program relative to traditional regulation, and it rewards the Company for improving upon past performance. Nicor Gas states that the increased risks assumed under the Program include the risk of increased capacity costs resulting from growth in design peak day demand, the risk of decreased revenues from Capacity Management Credits and continuing to purchase gas in the same relative position in the market. Nicor Gas further argues that the 50/50 sharing mechanism is consistent with the sharing of benefits which customers already enjoy as a result of other initiatives developed by the Company and approved by the Commission. (Id. at 5).

With respect to the sharing of savings and losses after the first $30 million, the Company asserts that its proposal reasonably provides that customers receive 90% of the benefits when such significant savings occur and, conversely, that customers are at risk for 90% of any unfavorable variance exceeding $30 million. (Id. at 6). Nicor Gas argues that the $30 million threshold reflects the reasonable and responsible level of risk that the Company is willing to assume under the Program. (Id. at 5). According to Nicor

Gas, the 90/10 split after the first $30 million would protect the Company if significant losses occur by limiting losses to a level that would not undermine the Company’s financial integrity or its ability to raise capital, as is required by Section 9-244(b)(4). (Id. at 6). This would assure that the Company’s duty to provide essential utility services to the public is not impaired. (Id.) In addition, customers would reap the benefits of the 90/10 split for all savings that exceeded $30 million.

More significantly, Nicor Gas argues that the ultimate effect of the risks and rewards under the Company’s proposal is to create the appropriate economic incentives to reduce gas costs below their already low levels. To obtain any benefit under the GCPP, Nicor Gas is required to achieve greater gas cost savings, relative to a market-based Benchmark, than it historically has experienced. According to Nicor Gas, its proposed sharing mechanism creates a strong, objective economic incentive to take the additional steps, and assume the economic risks, necessary to achieve such savings. (Id. at 12). The Company claims that its proposal will promote innovation and improve performance, thereby providing benefits to customers while creating a balanced approach to risk and reward.

Staff’s Position

Staff proposes that ratepayers receive 90% of all savings and losses and the Company receive 10%. Staff argues that its 90/10 split is superior to the Company’s sharing proposal for two reasons. First, Staff claims that a 10% share of savings will provide ample incentive for the Company to reduce gas costs. Second, Staff claims that, given the relative uncertainty over the precision of the Benchmark for a new and untested program, its proposed sharing rule provides a less rash deviation from the current 100%/0% sharing mechanism implicit in the traditional PGA. Staff argues that the Company, by contrast, has presented no valid rationale for its 50/50 sharing proposal.

With respect to its argument that a 90/10 split provides ample incentive to the Company, Staff asserts that the Company will reduce gas costs as long as the sharing mechanism allows the Company to recover slightly more than the cost of any efficiency-enhancing efforts that the Company undertakes under the Program. In other words, as long as there is an expected positive return on any costs incurred by the Company, the sharing mechanism will provide ample incentive for the Company to reduce PGA gas costs. According to Staff, because the Company expects to reduce gas costs from levels experienced under traditional regulation without incurring any additional gas supply purchasing expenses, it will have no costs to recover, and any share of the savings under the GCPP will be profit to the Company. 35).

Staff further argues that, if the Company were to incur any costs associated with cost-reducing efforts in the future, these costs could be incurred in one of two ways. First, the Company may enter into financial arrangements or management agreements in its efforts to manage gas costs. Staff contends that these new types of costs, because they would be passed through Rider 6, would be shared with ratepayers at the same rate at which any savings generated from these expenditures would be shared. Therefore, Staff

claims the Company will exert the same level of gas cost-reducing effort regardless of the sharing percentage. Second, if the Company decides to increase gas cost-reducing efforts ‘in-house,” it would initially incur 100% of these costs. However, Staff maintains that, if gas costs are reduced, and both the Company and ratepayers realize savings, the Company would have a strong argument to recover these costs through base rates in its next rate case.

Staff also asserts that any costs associated with gas cost-reducing efforts that the Company may incur under the GCPP would pale in comparison to the level of Nicor Gas’ annual PGA cost. Staff states that Nicor Gas’ average of 1997-98 total PGA recoverable costs were $865,062,288, while its average of 1997-98 Gas Supply Purchasing Department expenditures were $565,000. Staff argues that, even if the Company doubled its Gas Supply Purchasing Department expenses (in its pursuit of lower gas costs), a gas cost decrease of merely 0.7% would be sufficient to cover the Company’s added expenses.

Staff’s second argument is that its proposal provides a more cautious approach to a new program. Staff asserts that no one can guarantee that the proposed Benchmark is a perfect representation of the level of gas costs that would exist in the absence of the PBR program. Therefore, Staff claims there is a potential for the Company to share in savings without expending any gas cost-reducing effort.

In further support of its argument for a “cautious” approach, Staff asserts that there is no evidence in the record to suggest that ratepayers are presently suffering under the traditional PGA or are ill served by Nicor Gas’ existing gas purchasing strategies. Therefore, Staff argues, there is no pressing need for a dramatic shift from the current 100% ratepayer/0% company split.

Last, Staff argues that the Company has presented no valid rationale for its 50/50 sharing proposal. Staff also disagrees with the Company’s claim that the Company can justify a particular sharing percentage based on risk. According to Staff, the level of risk facing the Company under the GCPP cannot, be determined without first knowing the rate at which savings and losses are shared. In other words, Staff claims that the sharing percentage that the Commission approves will determine the level of risk that the Company faces under the GCPP. Staff argues that, given the different ways of sharing observed in the economy at large, it is unreasonable to presume that 50/50 sharing is inherently fair in every situation.

CGI’s Position

CGl’s proposed sharing mechanism provides for a 90% ratepayer/10% utility sharing for all costs above or below the Benchmark level. Alternatively, CGI recommends a 50% ratepayer/50% utility sharing mechanism whereby Nicor Gas would not be eligible to share in any savings until savings exceed 12% of the firm transportation reservation charges incurred by the Company during the previous year.

CGI bases this proposal on its claim that firm transportation reservation charges have declined by approximately 12% each year, on average, since 1997.

Company’s Response

Nicor Gas argues that the sharing mechanisms proposed by Staff and CGI are less reasonable than the sharing mechanism proposed by the Company and should be rejected. Nicor Gas asserts that Staff’s and CGl’s proposals are not in keeping with the rationale for having a sharing mechanism, which is to provide an appropriate incentive for the Company to reduce gas costs below their already low levels. According to the Company, Staff’s and CGl’s proposals provide inadequate incentive for Nicor Gas to move forward with the program, as they offer little or no reward for outperforming the Benchmark while assigning to the Company additional risk for under-performance. (Elliott Rebuttal at 14).

More specifically, Nicor Gas argues that, under Staff’s 90/10 proposal, the Company would have to generate significant savings in order to realize even minimal benefits. (Elliott Surrebuttal at 9). For example, to obtain a $1 million benefit under the Program, Nicor Gas would, under 50/50 sharing, have to beat the Benchmark by $2 million. Under Staff’s 90/10 proposal, by contrast, Nicor Gas would have to beat the Benchmark by $10 million to achieve the same $1 million benefit. According to Nicor Gas, Staff’s proposed split substantially reduces, if not eliminates, the Company’s incentive to aggressively pursue new strategies to lower gas costs. (Elliott Surrebuttal at 9). Thus, Nicor Gas asserts that Staff’s proposal would not foster an environment where the utility is rewarded for accepting risks that lead to customer benefits and, therefore, it is unacceptable.

Nicor Gas argues that Staff incorrectly presumes that its 90/10 sharing proposal provides adequate incentive to reduce gas costs. First, Nicor Gas asserts that Staff’s argument is based on the erroneous assumption that Nicor Gas will not have any costs to recover. Although Nicor Gas expects to reduce gas costs from levels experienced under traditional regulation without incurring any additional gas supply purchasing expenses, Nicor Gas states there is no guarantee that this will occur. Nicor Gas also argues that Staff overlooks the common sense notion behind incentive regulation which is that companies behave differently when given different incentives. Nicor Gas argues that incentive regulation is designed to cause a utility to behave differently. Generally, the greater the potential gains, the more incentive there is to take the risks necessary to achieve those gains. Nicor Gas argues that it clearly will have more incentive to cut costs and assume risks if it will share in 50% of the saving, as compared to sharing in only 10% of those savings. Nicor Gas concludes that any material change to its comprehensive proposal would alter the benefits and risk involved to the extent that the potential rewards would not justify assuming the risk.

Nicor Gas rejects Staff’s argument that 100% of any additional costs incurred under the GCPP would be recoverable in the Company’s next rate case. Nicor Gas states that Staff’s argument has no legal or factual basis. Costs cannot be recovered

through base rates unless and until those costs are approved in a general rate case. (Gilmore Rebuttal at 17). Nicor Gas argues it would be inappropriate to adjust the GCPP before it is known whether recovery of such costs in base rates will be allowed. (Id.). There is no evidence in the record concerning the type of costs which Nicor Gas will incur under the Program or how the Commission will treat those costs. As such, Nicor Gas claims that any assumption that certain costs will be recoverable is pure speculation.

Nicor Gas also argues that Staff’s assertion that the Company can double the expenses of its Gas Supply Purchasing Department and only need a decrease of 0.07% in gas costs to offset its expenditure is misleading. Nicor Gas states that under Staff’s 90/10 proposal, it would have to generate $l,000,000 of savings in order to offset each $100,000 of expenses that it incurs. (Elliott Rebuttal at 10). (Id.) Thus, in Staff’s example, the Company would have to generate $5,650,000 of savings to offset the expense the Company would incur in doubling its expenses associated with its Gas Supply Purchasing Department. (Id. at 11). Nicor Gas argues that this further demonstrates that the Company’s sharing mechanism of 50% ratepayer/50% utility (for amounts under $30 million) is more equitable than Staff’s proposal.

In response to Staff’s argument that a cautious 90/10 split is appropriate for new and untested programs, Nicor Gas argues that the uncertainties inherent in first-time programs do not justify such a sharing arrangement. Nicor Gas cites decisions in other dockets where this Commission ordered 50/50 sharing in first-time programs. For example, Nicor Gas points out that 50/50 sharing arrangements were approved with respect to Non-Gas Meter Reading Service, License Agreement with T.D. Williamson (Docket 94-0221), Accounting Treatment Related to Certain Management Services (Docket 91-0239), and License Development and Marketing Agreement with Corrpro Companies, Inc. (Docket 95-0422). With respect to Non-Gas Meter Reading Service (Docket 89-0089), this Commission stated that “equal sharing of benefits is reasonable, and” acts as “an incentive for utility managements . . . to pursue other endeavors of a creative nature that could benefit both ratepayers and shareholders in the future.”

Nicor Gas also argues that Staff’s concerns about the accuracy of the Benchmark are unwarranted. The Company has proposed a comprehensive approach that utilizes market-driven standards to establish a single Benchmark against which to measure the Company’s performance. Thus, Nicor Gas will measure its performance against the market. Moreover, the Company notes that this Program will be subject to review after two years.

Nicor Gas also rejects Staff’s argument that, because ratepayers are not presently suffering under the traditional PGA, there is no pressing need for a dramatic shift from the current 100% ratepayer/0% company split. Nicor Gas states that, under Section 9-244(b), the only two requirements relevant to sharing are subsections,(b)(8) and (b)(4). Neither of these sections requires proof that ratepayers are presently suffering or are ill served in order for a utility to go forward with a PBR program. To the contrary, under Sections 9-244(b)(8) and (b)(4), a PBR sharing proposal should be adopted if it includes provisions for the equitable sharing of any net economic benefits between the utility and

its customers, and if it will not result in the deterioration of the utility’s financial condition. Nicor Gas asserts that its proposed PBR program meets these two requirements/

Nicor Gas argues that CGl’s 90/10 sharing proposal suffers from the same shortcomings as Staff’s proposal. Nicor Gas adds that CGl’s alternative proposal (a 50% ratepayer/50% utility sharing mechanism with a “deadband”) is inappropriate because it makes it unreasonably difficult for Nicor Gas to participate in sharing benefits, yet places more risks on the Company. (Elliott Rebuttal at 13). Nicor Gas argues that preventing the Company from participating in the first $13.1 million of savings (12% of firm reservation charges based on 1998’s data) fails to create any incentive for the Company to cut costs. (Id.) Under such a proposal, Nicor Gas would have to begin sharing losses with customers as soon as they exceeded the Benchmark, without the benefit of a similar deadband applied to losses. According to the Company, that is not “equitable” as required by Section 9-244(b)(8). (Id.)

Commission Analysis and Conclusion

The Commission finds that the Company’s 50/50 sharing of the first $30 million in savings or losses is equitable and meets the requirements of Sections 9-244(b)(4) and 9-244(b)(8). In our opinion, such a sharing arrangement creates the proper incentives for Nicor to act in pursuit of greater savings as the Company will have as much too lose from any failures as it has to gain from any achievements.

The Commission, however, shares CGl’s concerns regarding Nicor’s proposal to share any losses over $30 million on a 90/10 basis. Such a sharing arrangement would allow Nicor to shift the risk of so-called “catastrophic” losses to its gas customers and, therefore, would provide little incentive for the Company to carefully consider its actions. Indeed, as CGI witness Mierzwa noted, under one example, Nicor’s customers would incur $168 million of a $200 million loss under the Company’s proposal. Furthermore, the 90/10 sharing of losses and savings over $30 million is inconsistent with the requirements of Section 9-244(b)(8), which requires the GCPP program to include provisions for the equitable sharing of any net economic benefits between the utility and its customers. Consequently, the Commission now must consider the modifications proposed by the parties.

The Commission must also reject the 90/10 sharing of all savings or losses, as proposed by Staff and CGI, for virtually the same reasons it rejects 90/10 sharing aspect of Nicor’s proposal. The Commission believes that such a 90/10 split provides insufficient incentives for the Company to pursue cost reduction measures and an insufficient penalty to the Company if those measures fail to achieve cost savings. In our view, innovation in cost saving strategies will neither be promoted nor ensured under a 90/10 sharing arrangement. Thus, this split will not produce the appropriate incentive for a meaningful alternative regulatory program. The Commission, therefore, finds that Staff’s 90/10 sharing proposal violates the requirements of Section 9-244(b)(8).

As an alternative to its 90/10 sharing proposal, CGI recommended a 50% ratepayer/50% utility sharing mechanism whereby Nicor Gas would not be eligible to share in these amounts until savings exceed 12% of the firm transportation reservation charges incurred by the Company during the previous year. Since this proposal was later withdrawn by CGI, the Commission will not consider its merits.

Having reviewed the record and the modifications proposed by the parties, the Commission believes that the concerns raised by CGI can be resolved by eliminating the 90/10 sharing of losses and savings in excess of $30 million from Nicor’s proposal. As noted above, a 50/50 sharing of savings and losses up to $30 million is equitable, would create a balanced level of incentives and disincentives for Nicor and, therefore, would meet the requirements of Sections 9-244(b)(4) and 9-244(b)(8). The Commission also believes that a 50/50 sharing of savings and losses in excess of $30 would be just as equitable, would create a balanced level of incentives and disincentives and would also meet the requirements of Sections 9-244(b)(4) and 9-244(b)(8). Therefore, the Commission will modify Nicor’s proposal to eliminate the 90/10 sharing of losses and savings in excess of $30 million, thereby leaving a 50/50 sharing of all savings and losses. Furthermore, the Commission rejects CGI’s proposal to hold prudence reviews if losses exceed $30 million. Instead of the traditional prudence review, Section 9-244(c) requires that the Commission review the program two years after its implementation to determine whether it is meeting its objective.

The Commission believes that one very important aspect of the proposed sharing mechanism is that it is consistent with the basic premise of incentive regulation, that companies with rate incentives are likely to be more efficient and productive than if there were no incentives. The risks and rewards inherent in the proposal, as modified by this Order, create the appropriate economic incentives for Nicor Gas to reduce gas costs. As such, the sharing mechanism produces a strong, objective economic incentive for the Company to take the additional steps, and assume the economic risks, necessary to achieve savings and avoid losses. Economic incentives such as those contained in the program, in turn, promote innovation, encourage efficiency, lower regulatory costs and encourage utilities to respond to new market challenges. The Commission therefore concludes that these benefits are substantial and identifiable benefits that will be realized by customers under the program that would not be realized in its absence as required by Section 9-244 (b) (2).

Furthermore, we find that the implementation of the program will encourage competitive gas markets. Therefore, the program is not likely to adversely affect the development of competitive markets in keeping with the requirements of Section 9-244 (b)(5).

Staff expresses concern about the accuracy of the Benchmark. The Commission, however, does not share these concerns. The record demonstrates that the Benchmark will be a useful tool to measure the level of gas costs that would occur in the absence of the PBR program. Moreover, as pointed out by Nicor Gas, this program will be subject to review after two years.

F. Mechanism for Computing Savings or Losses With Customers

Nicor Gas proposes to share savings or losses under the Program with customers through a new Rider 4. (Harms Direct at 2 & Ex. AEH-1). Rider 4 describes the method of computation of the Benchmark and states the percentages for sharing savings and losses with customers. The Commission concludes that Rider 4 should be amended to reflect the terms of this Order

G. Additional Issues

CGI raises a number of issues directed at the GCPP as a whole rather than any component of the GCPP. CGI contends that customers will not be better off under the GCPP because Nicor Gas would have to be twice as efficient as under traditional regulation for rates to truly be lower. CGI also claims that the Commission cannot approve the GCPP without knowing exactly what steps Nicor Gas will take to reduce gas costs. For example, CGI contends that the Company could engage in high-risk derivatives trading, potentially incurring great losses that would largely be passed along to customers. CGI also believes that any reduction in costs from traditional regulation will more likely be the result of increased pipeline competition than anything else. In addition, CGI asserts that the Company could reap a “windfall” under the GCPP by purchasing gas at field prices outside Chicago, while setting the benchmark based on prices at the Chicago city-gate. Finally, CGI claims that Staff should have the unilateral power to revoke the GCPP if it deems it necessary.

The Company responds to these allegations one by one. With regard to the claim that it must double its efficiency for customers to be better off under the GCPP, the Company explained that the Benchmark is designed as an accurate proxy for costs under traditional regulation, and that customers begin sharing in the benefits with the first dollar reduction from those costs. Thus, there is no need to double efficiency. Rather, the Company states, CGI assumes that Nicor Gas would obtain the same gas costs with or without the GCPP, which simply is not the case and which ignores the premise behind incentive regulation, i.e., that incentives drive companies to find new ways to improve performance from the status quo. CGI responds that Nicor’s benchmark is not an accurate proxy for existing regulation under all relevant market conditions.

As for specifying what steps it will take to reduce gas costs, the Company states that Section 9-244 contains no such requirement. The Company also states that imposing such a requirement would unnecessarily complicate and prolong cases under Section 9-244 and would impede the flexibility that incentive regulation is supposed to create.

The Company states that CGl’s remaining claims are not supported by anything in the record and rest on speculation alone. In addition, the Company argues that CGl’s proposal to allow Staff to terminate the GCPP directly violates Section 9-244.

Section 9-244 (b)(7) requires that the program include annual reporting requirements and other provisions that will enable the Commission to adequately monitor its implementation. The Company is proposing to file statements on or before March 20 showing the final results of the GCPP (Direct Harms p 7, 8) and to include the results with the annual statement of total costs and total recoveries in the PGA reconciliation along with a statement certified by the company’s independent accountants and verified by a company officer. (Company Exhibit A, Rider 4, p.1)

Staff recommends: 1) that the final results be filed according to the schedule in the Commission’s PGA Citation Order each year; and, 2) that the Company’s work papers for the final determination be submitted to Staff in the same time frame as requested by staff in the PGA dockets.

Commission Analysis And Conclusion

The Commission agrees with the Company’s argument and rejects CGI’s that the GCPP will cost customers money as it is structured unless the company is twice as efficient as it is now. The Benchmark, as modified by this Order, is designed as an accurate proxy for costs under traditional regulation, and that customers begin sharing in the benefits with the first dollar reduction from those costs. The Commission finds that the GCPP is likely to result in rates lower than those under traditional regulation as required by Section 9-244(b)(1).

The Commission also rejects the argument by CGI that it cannot approve the GCPP without specific information about the steps which Nicor will take to save money. Section 9-244 does not require that mechanisms which may generate customer savings be specifically articulated.

The Commission rejects the suggestion by CGI that Staff should have the unilateral power to revoke the GCPP if it deems necessary as inconsistent with Section 9-244 and other law. The Commission finds that there is no language in Section 9-244 authorizing such a delegation of authority.

The Commission finds that the reporting requirements proposed by the Company as modified and supplemented by Staffs recommendations noted above (Direct Testimony Link p 5), meet the requirements of Section 9-244 (b)(7).

VI. Undisputed lssues

No party disputes that the GCPP, as proposed by Nicor Gas, satisfies Section 9-244 (b)(3) (Company compliance with reliability standards) and 9-244 (b)(4) (impact on financial condition). We do not believe that the modifications to the program proposed by this order will affect the ability of the program to comply with those sections of the Act. We therefore find that the program is in compliance with Sections 9-244 (b)(3) and (b)(4). We further conclude that Section 9-244(b)(6) is not applicable in this case, which involves a gas utility and not an electric utility.

VII. Findings. and Ordering Paragraphs

The Commission, having considered the entire record herein and being fully advised of the premises, is of the opinion and finds that:

(1) Northern Illinois Gas Company d/b/a Nicor Gas Company is a local gas distribution company certificated to provide gas services in the State of Illinois; and such, is a public utility within the meaning of the Act;

(2) the Commission has jurisdiction over the parties hereto and the subject matter hereof;

(3) Nicor Gas requests approval of its Gas Cost Performance Program under Section 9-244 of the PUA; the GCPP will go into effect in the year 2000 and be subject to review by the Commission after two years;

(4) the findings of fact and conclusions of law set forth in the prefatory portion of this Order are supported by the record herein and are hereby adopted as findings of fact and conclusions of law;

(5) the Gas Cost Performance Program, on the terms proposed by Nicor Gas, as modified by the terms of this Order, satisfies all of the requirements of Section 9-244(b), as follows:

(i) the GCPP is likely to result in rates lower than otherwise would have been in effect under traditional rate of return regulation for the services covered by the program and is consistent with the provisions of Section 9-241 of the Act;

(ii) the GCPP is likely to result in other substantial and identifiable benefits that would not be realized by customers served under the program and that would not be realized in the absence of the program;

(iii) Nicor Gas is in compliance with applicable Commission standards for reliability, and implementation of the GCPP is not likely to adversely effect service reliability;

(iv) implementation of the GCPP is not likely to result in deterioration of the Company’s financial condition;

(v) implementation of the GCPP is not likely to adversely affect the development of competitive markets;

(vi) Section 9-244(b)(6) does not apply to Nicor Gas;

(vii) the GCPP, as modified by this order, includes annual reporting requirements and other provisions that will enable the Commission to adequately monitor implementation of the program; and

(viii) the GCPP, as modified by this order, provides for an equitable sharing of any economic benefits between Nicor Gas and its customers to the extent the program results in such benefits.

(6) the materials submitted by the parties in this proceeding on a proprietary or confidential basis or for which proprietary or confidential treatment was requested are hereby considered proprietary and should continue to be accorded such treatment; and

(7) any petitions, objections, or motions in this proceeding that have not been specifically disposed of are hereby disposed of in a manner consistent with the Commission’s conclusions herein.

IT IS THEREFORE ORDERED, that the proposed Gas Cost Performance Program, as set forth in the verified Petition filed in this proceeding, and as modified by Nicor Gas through its testimony in this proceeding, and as further modified in the prefatory portion of and by the terms of this Order, shall be approved.

IT IS FURTHER ORDERED, that any materials submitted in this proceeding for which proprietary treatment was requested shall be accorded such treatment.

IT IS FURTHER ORDERED, that any petitions, objections, or motions made in this proceeding and not otherwise specifically disposed of herein are hereby disposed of in a manner consistent with the conclusions contained herein.

IT IS FURTHER ORDERED, that subject to the provisions of Section 10-l13 of the Public Utilities Act and 83 III. Adm. Code 200.880, this Order is final; it is not subject to the Administrative Review Law.

By Order of the Commission this 23rd day of November, 1999.

Chairman

Jeff Metz—Virtual storage

From:

To: George Behrens

Date: Mon, Sep 18, 2000 4:02 PM

Subject: Virtual storage

You asked me if I felt the transaction you described as virtual storage was, in my opinion, acceptable under the PBR. I talked with Jeff briefly to further understand the transaction that was being proposed. I would not be in favor of executing this transaction for the following reasons:

1. My understanding of the transaction is that it increases withdrawals to take advantage of the inverted storage credit. By increasing withdrawals, the benchmark is inflated. Our actual gas costs remain unchanged. We make more money and the ratepayers charges go up. The Adm. Code and the PGA tariffs state that we should not enter into transactions that will raise costs. In this case, costs are definitely raised and we would be violating both the Code and our tariffs.

2. In the PBR case we testified that the company had very little control over withdrawals, they were a function of weather and operations. It would appear with this transaction that we can manipulate withdrawals.

3. The PBR was approved on the basis that we would be benefiting both ratepayers and shareholders. Staff (lannello) was concerned we would try to manipulate storage to raise the benchmark with customers paying higher costs. We testified that doing so would be bad business practice. Our goal was to lower costs and obtain a benefit for shareholders. This transaction would be the opposite of our testimony.

4. This is the first year under a PBR for any utility in Illinois and many people will be interested in our results and what we did to achieve them. I think we will have to respond to a number of questions from staff on how we changed our buying to beat the benchmark. If staff were to find and understand this transaction, how would our chances of continuing the PBR be impacted?

As I understand it, this transaction does not lower gas costs to customers. With gas prices at record levels and if we make a lot from the PBR, if our gas costs are not the lowest in the State, we could have a lot of scrutiny. I would think that this transaction would justify staff’s concern about PBRs and damage our credibility.

cc: Jeff Metz, Lonnie Upshaw

Arguments for Linking a Sale of Inventory to a Marketer & a Weather Hedge

1. Nicor Gas has an asset (natural gas inventory) that a marketer can use more effectively than Nicor Gas to generate value.

2. The marketer or its affiliate has insurance/ hedge products that Nicor can derive value from through reducing the risk of earnings downsides and reducing earnings volatility.

3. These valuable assets/capabilities/products provide an opportunity for Nicor and the marketer to each gain value and to enter into a barter or exchange.

4. Negotiations on the terms of the barter should allow Nicor Gas to realize value from the inventory that it will not be able to generate on its own.

5. For Nicor Gas to realize some of the value that the marketer can generate the natural gas inventory must be owned by the marketer.

6. A limited amount of inventory is excess and unnecessary for Nicor Gas’ to support its declining numbers of sales customers.

7. The inventory cannot be sold without providing a marketer with an incentive/a discount (an opportunity to generate value).

8. The current price of natural gas at this time makes it a good time for Nicor Gas to sell the excess inventory (because prices are at historically high levels and could go down).

9. Nicor Gas’ does not need to replace this inventory.

10. Nicor’s shareholders paid for the inventory and should realize a benefit from its sale.

11. The rate case method of providing a return to shareholders on this excess inventory asset results in an allowed return applied to a small historical cost (LIFO basis) inventory (versus the higher current value that exists today), providing an added incentive to obtain current value for the shareholders.

12. The PBR mechanism provides an opportunity to realize some of the inventory value for the shareholder.

13. The ratepayers did not pay for this excess inventory.

14. The ratepayer will benefit from the gain (sales price over LIFO cost) on the sale of the excess inventory.

15. The excess inventory sales price will result from negotiations that include consideration of the market for natural gas, the optionality Nicor Gas is losing, the weather hedge, and other factors that generate value for each party.

16. These considerations can be viewed under the GSC as “other out-of-pocket” costs that are related to supply or price management.

17. Including these considerations does not increase the cost of gas to the ratepayer because the transaction to sell excess inventory would not happen at this time without these considerations.

NIC-SA 001507

From: Phil Cali

To: George Behrens

Date: Tue, Aug 15, 2000 9:44 AM

Subject: Re Supply/Weather Hedge Link

George

I have a few thoughts on your arguments:

1) The storage inventory we’re discussing has been a long held asset that was formerly necessary to support winter deliveries from storage to sales customers. At the time it was acquired, it was believed to be virtually a “permanent” investment similar to pipe in the ground. Unbundling has now progressed to a point where a limited amount of this inventory is no longer required to be held by the company.

2) Working with a marketer allows a systematic way to reduce this inventory within the practical constraints of operational needs.

3) Reducing this inventory lowers holding costs for the company which ultimately is beneficial for the customer.

4) This barter arrangement offers the company a unique opportunity to reduce its cost of operations while providing an immediate benefit to both customers and shareholders.

5) Current forward prices for gas are at historical highs and this mechanism provides a low risk means for benefiting from them.

6) The terms of the barter arrangement include tangible and intangible consideration including cash, insurance, delivery constraints, timing, point of take, etc.

Phil

>>> George Behrens 08/l 1 8:42 AM >>

I’d appreciate some input on this attempt to capture our discussion from yesterday. These are what I heard as arguments that cost impacts of the weather hedge should go through the PGA. thanks—gmb

cc: Kathy Halloran, Lonnie Upshaw

NIC-SA 001508

		*(Injection)/Withdrawal
[LOGO]		**Projected Volumes/Actual Volumes
		***All volumes are in MMcf/d

IN-FIELD STORAGE TRANSFERS

The following transfers were performed for operational reasons:

OCTOBER Monthly Summary

DATE	Ancona		Hudson		Lexington		Lake Bloom		Pon Gales	Pon MS	Pecatonica	Troy Grove	Storage Net Activity	Injections	Withdrawals
10/01/2001													0.000	0.000	0.000
10/02/2001													0.000	0.000	0.000
10/03/2001													0.000	0.000	0.000
10/04/2001													0.000	0.000	0.000
10/05/2001													0.000	0.000	0.000
10/06/2001													0.000	0.000	0.000
10/07/2001													0.000	0.000	0.000
10/08/2001													0.000	0.000	0.000
10/09/2001	(0.763	)								0.763			0.000	0.763	(0.763	)
10/10/2001	(74.887	)								74.887			0.000	74.887	(74.887	)
10/11/2001	(2.687	)								2.687			0.000	2.687	(2.687	)
10/12/2001													0.000	0.000	0.000
10/13/2001													0.000	0.000	0.000
10/14/2001													0.000	0.000	0.000
10/15/2001													0.000	0.000	0.000
10/16/2001			(76.744	)	(6.221	)						82.965	0.000	82.985	(82.985	)
10/17/2001	2.942		(75.536	)	(22.435	)						96.029	0.000	98.971	(98.971	)
10/18/2001	2.894		(78.584	)	(19.325	)						95.015	0.000	97.909	(97.909	)
10/19/2001													0.000	0.000	0.000
10/20/2001													0.000	0.000	0.000
10/21/2001													0.000	0.000	0.000
10/22/2001													0.000	0.000	0.000
10/23/2001													0.000	0.000	0.000
10/24/2001					(3.954	)						3.954	0.000	3.954	(3.954	)
10/25/2001	2.944		(49.927	)	(92.723	)	(55.516	)	105.666			89.556	0.000	196.106	(196.106	)
10/26/2001	2.976		(81.472	)	(42.515	)			71.811			49.200	0.000	123.967	(123.967	)
10/27/2001	2.960		(24.226	)					21.266				0.000	24.228	(24.228	)
10/28/2001	2.889		(104.043	)	(19.443	)			70.092			50.505	0.000	123.488	(123.488	)
10/29/2001	29.510		(86.797	)					4.603			52.684	0.000	86.797	(86.797	)
10/30/2001	(188.077	)	(95.178	)	(84.327	)			71.540			296.042	0.000	367.582	(367.582	)
10/31/2001	(223.034	)	(10.326	)					6.755			226.605	0.000	233.360	(233.360	)
Total	(442.334	)	(683.833	)	(290.942	)	(55.516	)	351.733	78.337	0.000	1042.554	0.000	1519.739	(1519.739	)

Storage Management may transfer gas from one field to another for operational reasons, and Accounting will treat such volumes as an in-field transfer, provided that:

1. The transfer of volumes did not require a change in the purchase plan for that day

2. The transfer of volumes was unrelated to changes in the demand forecast for that plan day

3. The volumes related to the in-field transfer can be specifically indentified. (i.e. it was clear that the field injected or withdrew gas for a specified period of time for operational reasons)

4. Storage Management provided documentation to Supply Accounting and Gas Purchasing. The document should clearly classify the related volumes as an in-field transfer and specify the fields impacted on a particular day.

Supervisor Storage Management

Manager of Storage Operations

		*(Injection)/Withdrawal
[LOGO]		**Projected Volumes/Actual Volumes
		***All volumes are in MMcf/d

IN-FIELD STORAGE TRANSFERS

The following transfers were performed for operational reasons:

NOVEMBER Monthly Summary

DATE	Ancona		Hudson		Lexington		Lake Bloom		Pon Gales		Pon MS		Pecatonica	Troy Grove		Storage Net Activity	Injections	Withdrawals
11/01/2001	(54.692	)												54.692		0.000	54.692	(54.692	)
11/02/2001	(50.328	)												50.328		0.000	50.328	(50.328	)
11/03/2001	(0.614	)												0.614		0.000	0.614	(0.614	)
11/04/2001																0.000	0.000	0.000
11/05/2001	(150.208	)												150.208		0.000	150.208	(150.208	)
11/06/2001	227.525		(56.621	)										(170.904	)	0.000	227.525	(227.525	)
11/07/2001	122.733								25.492					(148.225	)	0.000	148.225	(148.225	)
11/08/2001	219.975		(69.600	)	(84.867	)	(73.644	)	(3.888	)	(59.183	)		71.207		0.000	291.182	(291.182	)
11/09/2001	24.197		(73.443	)	(86.394	)	(73.069	)	11.925		(50.579	)		247.363		0.000	283.485	(283.485	)
11/10/2001	223.696		(66.756	)	(87.250	)	(66.940	)			(34.749	)		31.999		0.000	255.695	(255.695	)
11/11/2001	71.513		(53.097	)	(84.672	)	(74.364	)			(58.232	)		198.852		0.000	270.365	(270.365	)
11/12/2001	78.781		(53.001	)	(88.868	)	(73.827	)			(58.081	)		194.996		0.000	273.777	(273.777	)
11/13/2001	282.792		(56.039	)	(0.259	)	(74.878	)	50.405		(57.860	)		(144.161	)	0.000	333.197	(333.197	)
11/14/2001	103.168				51.648				12.708					(157.524	)	0.000	167.524	(167.524	)
11/15/2001	25.390				51.394				30.419					(107.203	)	0.000	107.203	(107.203	)
11/16/2001	159.452		(16.432	)	52.279		(75.177	)	72.735					(192.857	)	0.000	284.466	(284.466	)
11/17/2001	86.934		(12.896	)	51.773				67.805					(193.616	)	0.000	206.512	(206.512	)
11/18/2001	51.888				37.947				16.278					(106.113	)	0.000	106.113	(106.113	)
11/19/2001	255.546		(78.399	)	(53.367	)	(75.560	)	113.729		(3.921	)		(168.328	)	0.000	379.575	(379.575	)
11/20/2001			(78.450	)	(69.673	)	(2.247	)	(3.382	)				153.752		0.000	153.752	(153.752	)
11/21/2001	237.009		(79.344	)	(15.811	)	58.157				(38.716	)		(161.295	)	0.000	295.166	(295.166	)
11/22/2001	116.785				64.788		76.000				(48.251	)		(209.322	)	0.000	257.573	(257.573	)
11/23/2001	4.589				64.242		76.019							(144.850	)	0.000	144.850	(144.850	)
11/24/2001	(140.600	)			64.670		75.930									0.000	140.600	(140.600	)
11/25/2001	237.890		(76.653	)	(1.885	)					(50.981	)		(105.371	)	0.000	237.890	(237.890	)
11/26/2001	66.045		(40.713	)	60.488		76.822				(57.019	)		(105.623	)	0.000	203.355	(203.355	)
11/27/2001	(58.922	)	(78.914	)							(9.837	)		147.673		0.000	147.673	(147.673	)
11/28/2001	77.474		(77.474	)												0.000	77.474	(77.474	)
11/29/2001	62.867		(0.078	)	(0.140	)			(62.649	)				297.261		0.000	62.867	(62.867	)
11/30/2001	(270.347	)					69.448		(73.820	)	(22.542	)				0.000	366.709	(366.709	)
																0.000	0.000	0.000
Total	2020.838		(967.910	)	(73.957	)	(157.330	)	257.756		(549.951	)	0.000	(529.446	)	0.000	5678.596	(5678.596	)

Storage Management may transfer gas from one field to another for operational reasons, and Accounting will treat such volumes as an in-field transfer, provided that:

1. The transfer of volumes did not require a change in the purchase plan for that day.

2. The transfer of volumes was unrelated to changes in the demand forecast for that plan day.

3. The volumes related to the in-field transfer can be specifically identified. (i.e. it was clear that the field injected or withdrew gas for a specified period of time for operational reasons)

4. Storage Management provided documentation to Supply Accounting and Gas Purchasing. The documentation should clearly classify the related volumes as an in-field transfer and specify the fields impacted on a particular day.

Supervisor Storage Management

Manager of Storage Operations

[LOGO]

*(Injection) Withdrawal

**Projected volumes/Actual Volumes

***All volumes are in MMcf/d

IN-FIELD STORAGE TRANSFERS

The following transfers were performed for operational reasons:

DECEMBER Monthly Summary

DATE	Ancona		Hudson	Lexington		Lake Bloom		Pon Gales		Pon MS		Pecatonica	Troy Grove	Storage Net Activity	Injections	Withdrawals
12/01/2001	(156.520	)						(68.315	)	(21.980	)		247.815	0.000	247.815	(247.815	)
12/02/2001	(243.734	)		32.749		77.563		(71.157	)	(25.842	)		230.421	0.000	340.733	(340.733	)
12/03/2001	(194.619	)	52.977	66.878		74.748							0.016	0.000	194.619	(194.619	)
12/04/2001	(175.372	)	74.940	0.001									100.531	0.000	175.372	(175.372	)
12/05/2001	(217.945	)	21.085										196.860	0.000	217.945	(217.945	)
12/06/2001	(2.638	)		(77.020	)	(83.432	)			(76.883	)		239.973	0.000	239.973	(239.973	)
12/07/2001				(75.550	)	(77.687	)			(53.568	)		207.805	0.000	207.805	(207.805	)
12/08/2001				(75.607	)	(76.464	)	(20.248	)	(54.479	)		226.798	0.000	226.796	(226.796	)
12/09/2001				(71.134	)	(76.542	)	(14.478	)	(56.560	)		218.714	0.000	218.714	(218.714	)
12/10/2001				(72.220	)	(54.791	)	(0.014	)	(50.822	)		177.847	0.000	177.847	(177.847	)
12/11/2001				(69.117	)	(76.493	)	(0.001	)	(45.424	)		191.035	0.000	191.035	(191.035	)
12/12/2001						(77.522	)	(3.419	)	(47.090	)		128.031	0.000	128.031	(128.031	)
12/13/2001	66.072							(19.655	)	(46.417	)			0.000	66.072	(66.072	)
12/14/2001	15.841									(15.841	)			0.000	15.841	(15.841	)
12/15/2001	9.353									(9.353	)			0.000	9.353	(9.353	)
12/16/2001	105.032			(60.358	)					(44.674	)			0.000	105.032	(105.032	)
12/17/2001	5.124			(4.893	)			(0.001	)	(0.230	)			0.000	5.124	(5.124	)
12/18/2001														0.000	0.000	0.000
12/19/2001														0.000	0.000	0.000
12/20/2001														0.000	0.000	0.000
12/21/2001														0.000	0.000	0.000
12/22/2001														0.000	0.000	0.000
12/23/2001														0.000	0.000	0.000
12/24/2001														0.000	0.000	0.000
12/25/2001														0.000	0.000	0.000
12/26/2001														0.000	0.000	0.000
12/27/2001														0.000	0.000	0.000
12/28/2001														0.000	0.000	0.000
12/29/2001														0.000	0.000	0.000
12/30/2001														0.000	0.000	0.000
12/31/2001														0.000	0.000	0.000
Total	(789.406	)	148.902	(407.271	)	(370.620	)	(198.288	)	(549.163	)	0.000	2165.846	0.000	2768.109	(2768.109	)

Storage Management may transfer gas from one field to another for operational reasons, and Accounting will treat such volumes as an in-field transfer, provided that:

1. The transfer of volumes did not require a change in the purchase plan for that day.

2. The transfer of volumes was unrelated to changes in the demand forecast for that plan day.

3. The volumes related to the in-field transfer can be specifically identified. (i.e. it was clear that the field injected or withdrew gas for a specified period of time for operational reasons)

Supervisor Storage Management

Manager of Storage Operations

Inventory Value Team Report

Jeff Metz

Proposal to Restructure Ratemaking for Gas Costs


I.	LIFO Inventory Opportunity	2

II.	Recommendation	2

III.	Analysis and Management of LIFO Inventory Layers	3

IV.	Ways to Release Inventory Value	3

V.	Ways to Capture the LIFO Inventory Value	5

VI.	PBR Legislation and History	8

VII.	GRPP Specifics	9

VIII.	Risks and Mitigation	10

IX.	Collateral Benefits	13

I. LIFO Inventory Opportunity

Nicor Gas values it’s inventory on a LIFO (last-in first-out) basis Under this method, the inventory consists of gas priced at historical prices from 1954 to 1996. At December 31,1997, there was about 110 BCF of gas in inventory. The “top” 30% of our LIFO layers are priced at close to market value. The “bottom” 70% of our LIFO layers are priced significantly below market value. There is about 75 BCF of gas in these lower priced layers, with market value of about $100-200 million in excess of cost.

Due to unbundling, it is likely that we will liquidate some of our LIFO inventory and reduce or eliminate the low priced LIFO layers, thus “releasing” some of this value. Under our current rate structure, book value of gas inventory reductions would be included in the PGA. We considered various alternatives of both releasing this value and capturing this excess market value (discussed in Sections IV and V).

II. Recommendation

We recommend that the company “capture” the LIFO inventory value by filing and implementing a Gas Rate Performance Plan (GRPP) related to gas costs. We think the best way to release this value is to continue to unbundle our services to our customers (Customer Select) together with the use of 3rd parties (marketers). There is a critical need to act quickly with the inventory value issue since the pace of unbundling may cause us to start withdrawing the low-priced gas in two or three years. The GRPP meets the timing requirement in that the legislation is in place (unlike eliminating the PGA), the ICC staff has effectively supported the concept of a GRPP in the recent CILCO hearings, and a GRPP does not require a fundamental change in the way we conduct our business.

Our approach was to determine the best strategy to capture the value of the LIFO layers. We recognize that a GRPP may also serve as an interim step towards the establishment of customer choice, unbundling of services and potential elimination of regulated sales service and the PGA

III. Analysis and Management of LIFO Inventory Layers

The LIFO layers, as they existed at December 3 1, 1997, can be stratified as follows:

Layer Years	BCF	Book/Tax Value ($mil)	Book/Tax $/MMBtu	Excess Market Value ($mil)
1984-1996	34	$105	$3.09	$(37)-(3)
1969-1973	46	$ 14	$ .30	$78-124
1954-1968	30	$ 9	$ .30	$ 51-81

	110		$ 128	$93-203

* at $2.00 to $3.00 per MMBtu.

Exhibit 4 attached shows a more detailed layering of the Nicor Gas owned inventory at December 31, 1997. December 31 of each year is important because it is the date whereby quantities of gas are compared between years to determine if we have removed a LIFO layer or added a LIFO layer. Any reduction in the total inventory would first be valued at the price of the most recent layer(s), which in our case is 1996. Therefore, our inventory would have to be reduced by about 30% before we begin liquidating the low-priced layers.

IV. Ways to Release Inventory Value

Customer Select:

One of the ways Nicor Gas can release the value of its inventory, market price less historical cost, is by expanding the Customer Select program. Expansion of Customer Select would allocate storage assets to participating suppliers in the program. Suppliers would replace Nicor Gas’ inventory with their own inventory. This is not a new concept. Suppliers have been replacing Nicor Gas’ inventory since the beginning of transportation in 1986. As inventory is replaced by suppliers, any gains or losses from historical cost levels have flowed through the Gas Supply Cost (GSC). Up to this point, the replacement of inventory by suppliers has not yielded significant gains or losses as company owned layers of natural gas being replaced by supplier owned gas have been priced at close to market value. As Nicor Gas dips further into its inventory layers, the gains from these older layers will be much more material. See the Analysis and Management of LIFO Inventory section of this report.

During the first year of the Customer Select program, over 20,000 customers signed up for the program. These customers use approximately 12 Bcf annually and their storage levels approximate 5 Bcf annually. Customer Select is being expanded during the second year to allow another 40,000 commercial and industrial customers to participate along with 80,000 residential and about 4,800 Rider 25 customers. Estimates are that company owned storage levels may drop by an additional 7-10 Bcf annually depending on customer acceptance of expansion of the program. Such reductions would be contingent upon the number of customers allowed to participate in the program and customer acceptance of transportation.

Release Storage to Marketers:

A third party or parties can be involved to release the value of the storage levels. This can be done in two ways. First, a third party (e.g. marketer) can replace the inventory during the injection cycle. Second, Nicor Gas can fill the storage during the injection cycle and then sell the inventory to a third party. Either way, Nicor Gas has withdrawn and sold the low cost inventories at market and will not be the holder of market price replacement inventories. Nicor Gas could contract with the third party for gas purchases out of the third party’s inventory for its withdrawal requirements.

The principal advantage of using a third party is control over the rate of withdrawing the low cost layers and having the third party replace it. It could even be done in a single year or could be done over a number of years. Inventory replacement by a third party could also be used to supplement replacement by customers under Customer Select or other unbundling programs. For example, if only 70% of the available customers take advantage of Customer Select, then Nicor Gas could contract with a third party to fill the inventory to the desired level. A third party might also pay us to be able to fill our storage, depending on the market. Use of a third party to refill storage might also be viewed as a deliberate scheme to add shareholder value, as opposed to Strictly using Customer Select to refill the storage inventories after the low-cost inventories have been withdrawn.

V. Ways to Capture the LIFO Inventory Value

GRPP

Using a performance based program for gas costs is the recommended method for the Company to capture the value from the LIFO layer. As discussed below, a GRPP offers advantages as compared to the alternative methods of establishing a fixed gas cost, eliminating the PGA and outright sale of the storage inventory along the same line as selling real estate.

Fixed Gas Cost (Gas Cost in Base Rates):

Recent legislation enables LDCs to file for a fixed gas cost. Once filed, the Commission must issue an Order within 240 days of the filing. After receipt of the Order, the utility has seven days in which to accept or reject the Commission’s Order. During five years following the date of the Commission’s Order, a public utility company may not file to reinstate a PGA clause. However, during that five-year period, the Company may request a rate increase in the normal process because of higher gas costs.

This method is similar to a GRPP with some significant differences. It is similar in that a prudence review should be either eliminated or significantly reduced. However, under this option, the PGA would be fixed for five years. Second, fixing the PGA does not provide for sharing. Any net losses would be borne by the utility, and all net gains would be to the benefit of the utility (although the utility could agree to share the gain). However, if experienced or forecasted losses under a fixed PGA are significant, the utility is permitted to request a change in its gas supply charge as part of a full rate case.

A fixed PGA does, in theory, allow a more opportunistic means of using hedging tools to lock in a gain than would be available under a GRPP. Under a GRPP, future gas prices are hedged when they are “acceptable”; there is no certainty the futures price will be lower than the performance benchmark price, which will be a function of a market price. With a fixed PGA, the “benchmark” is a known value. If future prices are below the fixed PGA (and that’s a big if) a known “gain” can be locked-in. If future prices are greater than the fixed PGA, a decision can be deferred or a known loss can be locked in.

In summary, a fixed PGA has some advantage over a GRPP (mainly that the performance benchmark is a known quantity) and some disadvantage (the unlimited risks). We believe the risks outweigh the advantage due to the following:

1. Limited Future/Forward Market: The futures market has very little liquidity beyond 2 years. In addition, the cost of forward price gas begins to increase as the term of the contract increases. Therefore hedging (through the futures market or forward contracts) is practical for only a one to two year forward period.

In addition, relative to the volume of gas purchased by Nicor Gas, the futures market has limited liquidity even in the near term. Nicor Gas’ purchase volumes would be 15 to 20% of the open position futures contracts 6 to 12 months forward and an even greater portion of longer term activity. The price impact of Nicor Gas contracting for significant volumes of

futures contracts or forward priced gas could be significant. Nicor Gas could attempt to hedge its future gas purchases via a gradual entry. However, it is not clear if this would be an effective means of avoiding market impacts.

2. Volume Risk: A volume risk exists whether gas prices move up or down. For instance, if our fixed price is 30¢, but market price is 40¢, it is likely that transportation customers would elect to return to sales service. This would necessitate increased gas purchases, at the current market rate (i.e. gas purchases in excess of the hedged volumes). This would result in a loss to Nicor Gas. A possible mitigation strategy is to limit transportation customers’ ability to return to sales service, or to establish a separate, non-fixed PGA for such customers.

Similarly, if our fixed gas price is 30¢, but market price is 20¢, it is likely that some customers would leave us to purchase gas at prevailing market rates. This could cause us to have hedged volumes in excess of those required to meet customer needs. These excess volumes may need to be sold on the open market, once again causing Nicor to suffer loss. It is doubtful that the commission would allow Nicor to prohibit customers from leaving us if they would ordinarily have that option as unbundling progresses.

3. ICC Response: Finally, the largest hurdle to freezing the PGA may be commission Staff opposition. In the CILCO case, Staff has claimed that freezing the PGA does not provide incentives to lower gas supply costs, as does a GRPP. It simply establishes an opportunity, if the fixed gas price is set high enough, for the utility to generate revenue with no particular effort.

As of today, the only Illinois utility filing to apply for a fixed gas cost has been CILCO. The Commission issued its order on September 18th. The order did not approve of CILCO’s proposed rates. The order effectively called for NYMEX futures prices at or about the time of the order to be the basis for a refiling by CILCO. It should be noted that the staff effectively suggested that a GRPP based on market rates would be more appropriate than a fixed gas cost MichCon and Consumers Energy as well as a few other LDCs outside of Illinois currently have fixed gas costs.

Eliminate PGA:

Another way for potential profit from gas sales is to have our gas costs unregulated, similar to the way marketers currently operate. This option has the benefit of significant profit potential while not attracting many of the risks associated with the fixed gas cost alternative. However, while this option may be where we ideally would like to go, it may be unrealistic within the next few years.

Legislation is currently not in place to allow for this option. Thus, a legislative effort, the success of which would be uncertain would be needed. Assuming the legislative effort is successful, we would then have to file with the ICC, causing additional delay. From the Commission’s view point, two things would have to happen for this alternative to be acceptable. First, the Company would have to open up its residential market to all marketers. Secondly, a viable competitive market would need to be developed by the various marketers. That is, the market could not be held or controlled by one or two major marketers. Once the residential market is open, it would

probably be several years before the ICC could be convinced that a competitive market existed. Therefore, from the Commission’s view point this is not an alternative that is available to the Company in the short term.

In addition to the Commission’s concern to the full development of the market, there will be concerns from the Company’s view point of still being required to have a regulated gas supply function as there is for electricity. A number of business issues need to be resolved before the Company could move into this position, such as, supplier of last resort, handling of credit customers, allocation of storage and pipeline transportation assets, and other business items. Other legislative authority would be needed in order for the Commission to deal with these issues. Legislative action is not preferred because of the risk of having to give up something in return, such as a revenue reduction. Further analysis of the competitive gas supply will occur as unbundling proceeds, and as gas legislation is instituted to encourage the development of unbundling.

Real Estate as an Analogy for Inventory Value:

Like land, top gas inventory is non-depreciable. Therefore, a possible means of capturing the below market value of the gas inventory could be a filing with the Commerce which argues that any revenue gained from such a sale should accrue to the benefit of the shareholders, not the ratepayer. In 1990, the Illinois Commerce Commission ruled that the revenue gained from Nicor Gas’ land sales should not be amortized over a period of time for the purpose of preserving the effect of the sale (the revenue gain) for rate making purposes. The below-market valued base gas in inventory bears some, but not perfect, resemblance to land.

This potential means of releasing and capturing inventory value was considered a low risk approach with little possibility of success. It is low risk since we would be making a request to the Commission for specific authorization. It would have a low probability of being successful since storage inventory value is a function of gas costs, which is governed by the GSC.

VI. PBR Legislation and History

The Company in 1996 made an incentive based rate filing (PBR). In that filing the Company requested that it be allowed to more actively manage its PGA without a prudence review, so that it could create benefits for both the shareholders and the sales customers. Under the PBR, the Company established a benchmark for comparison of its purchased gas cost on an annual basis. Any savings below the benchmark would create benefits for both the shareholders and customers. Any cost above the benchmark would also be shared. The sharing was established as 50/50 for the first $30 million of profit or loss and 90% to the sales customer and 10% to the Company for amounts outside this range. The PBR was ultimately withdrawn in January of 1997. One of the sticking points during the process was the law which indicated that customers “will benefit” under the provisions of an incentive based plan. The Commission, in reviewing the Peoples Gas Light and Coke Company’s proposed plan, felt that the “will benefit” was a mandatory finding that they had to achieve.

Effective in December of 1997, the State Legislature passed the electric deregulation law which includes two sections addressing alternative rate regulation—one relating to performance based rates and the other to fix the purchased gas cost. The law relating to these two items is attached as Exhibit 1.

With respect to performance based rates, the new law stipulates that the Commission needs to find that the program is likely to result in rates lower than otherwise would have been in effect under traditional rate of return regulation. This wording is different and easier to achieve than the mandatory “will benefit” section under the old law. Under the new legislation, the Commission may issue an Order no later than 270 days from the date of the filing. The Commission must specify in the Order reasons why the proposed program, if not accepted, does not meet the required criteria and has to identify appropriate modifications. The utility has fourteen days following the Order to either accept or reject the modified program. Thus, the new law appears to permit utilities to make filings without any obligation to accept the revised findings of the Commission. This eliminates one of the concerns the Company had as to whether we would be mandated to accept any modified program that the Commission would issue.

For any utility accepting such a performance based plan, the Commission is required to review the plan results two years after the program is first implemented. This review may take up to 9 months. In essence, the utility has approximately two years and nine months before a change could be ordered. If the Commission does order a program revision, the utility may elect to discontinue the program. The Commission can not otherwise direct the utility to revise a program except to insure system reliability. During the period of the program, the Company may file to revise the plan subject to Commission approval under the same constraints as the initial filing.

VII. GRPP Specifics

We are proposing a Gas Rate Performance Plan that is similar to, but not exactly the same as, the PBR program Nicor Gas filed for in 1996. Changes were made to address certain issues raised by staff and others in the original filing, and to eliminate certain performance risks.

Under this proposed Gas Rate Performance Plan (GRPP), Nicor Gas’ total annual purchased gas costs (“Actual Gas Costs”) would be compared against an annual gas cost benchmark (“Benchmark Gas Cost”) that is market sensitive. The difference between Actual Gas Costs and the Benchmark Gas Cost would be shared equally between the Company and its customers until the difference reached $30 million. The amount of the difference in excess of $30 million would be allocated 90% to customers and 10% to the Company. Exhibit 2 outlines the proposed structure of the GRPP in terms of the calculation of the Benchmark Gas Cost and Actual Gas Costs.

Benchmark Gas Cost:

The Benchmark Gas Cost reflects published city-gate market index prices at the time of sale to the customer (Market Index Cost”). The Market index Cost is then adjusted for the actual seasonal differential in gas prices of inventory injections and withdrawals (“Storage Credit Adjustment”) and a fixed amount related to firm supply, firm transportation and purchased storage capacity (“Firm Deliverability Adjustment”)

The Market Index Cost represents the annual gas cost that the Company would expect to incur if all gas supplies were purchased at prevailing Chicago city-gate market index prices at the time gas is delivered to customers. It is determined by multiplying Nicor Gas’ sales deliveries on a monthly basis by a Market Index Price for that month, and adding together the resulting twelve monthly amounts.

The Storage Credit Adjustment is intended to recognize the annual benefit that results from the purchase of gas supplies during off-peak periods, when prices are typically lower, the injection of that gas into storage, and the withdrawal of those supplies to meet demand during peak periods, when prices are typically higher. Nicor Gas expects to receive no significant gain or loss through the GRPP from the Storage Credit Adjustment.

The Firm Deliverability Adjustment represents the level of fixed costs incurred by Nicor Gas on an annual basis to reserve firm supply, firm transportation and purchased storage in order to ensure the availability and reliability of gas supplies for its customers during peak periods. The Firm Deliverability Adjustment would remain fixed during the term of the GRPP.

Actual Gas Costs

Actual Gas Costs would consist of total recoverable costs for the year as calculated and filed under Nicor Gas’ Rider 6—Gas Supply Costs, adjusted for items not pertinent under a GRPP.

Exhibit 3 provides a comprehensive example of the application of the proposed GRPP using hypothetical annual data.

VIII. Risks and Mitigation

Regulatory Risk

First we must consider whether filing under a GRPP in 1999 would subject the Company to a rate case. While this concern is legitimate, there are several items that mitigate this risk. First, the ICC has been tied up with concerns over electric deregulation so now is a better time to approach the ICC with an alternative gas pricing mechanism than in a few years.

Under the new legislation which permits a GRPP, much of the regulatory risk has been eliminated in comparison to the Company’s first GRPP filing. One of the concerns up front would be any modification that the Commission may institute in the program. The Company may not feel comfortable with the level established that it needs to meet. However, the new law makes it very clear that the public utility can turn down any modifications to the program and continue providing service under its existing tariff. The second regulatory risk would be that which occurs at the two year review. The Commission after two years may find that the utility needs to make modifications to continue with its GRPP. However, again the utility has the option of accepting or rejecting the modification proposed by the Commission. To reject those modifications would require elimination of the GRPP entirely. Regulatory risk also declines as part of a GRPP since the prudence review of the Company’s existing gas supply purchases would be eliminated. Under a GRPP, the Company has incentive to purchase at the cheapest cost possible. The Commission Staff should not insist on maintaining their current level of annual prudence review as there is an incentive for the Company to do its very best because the shareholders will benefit or be penalized. Any review should be an accounting review to make sure that transactions are properly accounted for and the benefits are properly calculated. This eliminates the concern that gas cost could be found to be imprudent and eliminated from our recovery mechanism.

The last regulatory risk would be that of earning in excess of the Company’s allowed rate of return. Under a GRPP it is possible that the Company could make additional dollars such that the Commission may want to review the Company’s overall earnings. However, this should be able to be mitigated by properly managing the earnings under the GRPP. The Company should also be able to argue that the more money it makes under the GRPP mechanism, the more benefit is immediately being shared with the sales customers.

In summary, regulatory risk under the new Legislative Law that went into effect in 1997 has substantially reduced the Company’s regulatory risk.

Role of Third Parties

Various third parties would be very interested in partnering with Nicor Gas to achieve success under a GRPP. Substantial progress was made to establish Clearinghouse (now Dynegy) as our asset alliance partner in conjuncture with our prior GRPP effort. These third parties are very willing to insulate Nicor against losses under a GRPP in return for a share of any upside. However, we would be assuming a credit risk with such third parties. This could be mitigated by monitoring and modifying the credit risk, based on size and financial viability of the third party.

GRPP Performance Risk

Inventory Credit:

The GRPP benchmark is based on the market price of gas at the time of delivery. The Storage Credit Adjustment in the GRPP formula is intended to recognize that some gas supplies are purchased in off-peak periods when prices are typically lower and to eliminate any benefit to Nicor Gas through the GRPP from this price arbitrage. Since the Storage Credit Adjustment is computed based on inventory withdrawals, its effect is to convert the value of our LIFO inventory from 1) the difference between the price at the time of delivery and book value to 2) the difference between the price at the time of current year purchases and book value. Therefore, we have reduced the potential value of LIFO inventory that can be captured via the GRPP formula. We have determined that this is a necessary and acceptable consequence to capture any of the inventory value. However, it highlights the need for prudent inventory management.

Transportation Costs

Pipeline transportation costs present risk relative to Nicor Gas’ ability to meet a GRPP performance target, since these costs are included in the Firm Deliverability Adjustment which will remain fixed during the term of the GRPP. Nicor Gas’ estimated 1998 fixed transportation and purchased storage costs (excluding take-or-pay and Order 636 GSR and Account 858 surcharges) are $144 million. The excluded surcharges amount to only $8 million in 1998, and will be essentially eliminated over the next year.

There are several factors which could increase transportation costs in future years. First, all of our pipeline contracts will expire prior to October 2000. If renewed at current contract levels and at maximum rates, Nicor’s fixed pipeline costs would increase by $38 million. Second, maximum pipeline rates can increase through regulatory action. Northern has filed a rate increase and rate design request that is expected to be acted on by November 1999. If granted, this could increase our fixed costs by $9 million annually. In addition, although Natural and Tennessee have not filed a rate case, Natural may do so in March 1999, and Tennessee may do so in January 2001. Both requests may be substantial, given the potential level of capacity turn-back on each pipeline. Third, Nicor Gas continues to experience significant design growth (approximately 1.5% or 75,000 MMBtu/d annually). The cost of pipeline capacity to meet this growth could be $6 million annually. Over three years, the annual cost could be as high as $18 million. Thus in a worst case scenario, our transportation costs, before mitigating items, could increase by $65 million.

Several factors can act to mitigate the potential increase in pipeline transportation costs. First, the degree of unbundling should offset some of the load growth impact. Second, although we should expect the cost of services to increase significantly on Northern Natural and NGPL, we should be able to reduce our costs From Midwestern and Tennessee by $5 million if competitive alternatives such as Northern Border and Alliance Pipeline are built. Third, as an alternative to pipeline firm services, we will have the ability to switch to more city-gate firm services. Although we do not know that these services will be less costly, we will have several contracting options that may be less costly. Fourth, in the last GRPP filing, Nicor Gas proposed to establish the benchmark based on actual fixed pipeline costs adjusted by known near-term events. However, given the degree of uncertainty, it would be more appropriate to base the fixed pipeline costs on a true forecasted basis. This estimate would reflect the uncertainties noted above.

Other options may also be available. We could exclude pipeline capacity related fixed costs from the GRPP. We would argue that such costs are long-term in nature and largely regulated, and therefore not appropriate for a GRPP. However, excluding any part of recoverable gas supply costs would (1) focus all prudence review effort on these costs and (2) raise the potential claim that we were shifting costs from variable (GRPP) costs to fixed (PGA recoverable) costs. We could wait until contracts have been renegotiated. This would delay the GRPP implementation until mid-year 2000. Although all of our contracts do not expire until mid-year 2000, we could accelerate the negotiation of contracts so that the costs are known, or largely known, before the GRPP benchmark is set. Although this would mitigate the contract renewal risk, it would not address increased costs that could result from pipeline rate increases or peak day growth.

In addition, Nicor could attempt to reduce its fixed pipeline costs by reducing pipeline services, such as reducing upstream pipeline capacity or summer capacity. Although this would serve to reduce fixed pipeline costs, it would also reduce our supply purchasing flexibility and could increase the cost of gas purchases. Also, Nicor could elect to meet its transmission system growth needs through contracted services, such as Voyageur Pipeline, rather than by capital investment. Purchased services would be reflected in Actual Gas Costs in the GRPP formula.

Other Costs and Revenues

An additional cost to include in setting a benchmark is the supply reservation. It is forecasted that this cost will be $11.0 million in 1998 and $8.7 million in subsequent years given the same level of supply needs by Nicor Gas. Obviously, unbundling would reduce the costs to Nicor.

Revenues that lower the benchmark are capacity release revenues (includes buy-sells, linked purchases and sales) and storage management credits. Capacity release credits for 1998 are forecasted to be $9.5 million and 1998 credit from storage management will be about $5.2 million. Subsequent years should generate similar credits

IX. Collateral Benefits

It should be noted that the following benefits will be realized if the inventory levels are reduced, independent of whether they are in conjunction with a GRPP.

Carrying Costs

A reduction in inventory levels brings with it a reduction in the cost of money to carry the inventory. Assuming inventory value can be reduced by $100 million, we could see a $5 million reduction in annual interest expense.

Cash Flow from Current Tax Deduction

To the extent inventory is reduced below current levels, sunk costs that were previously capitalized (i.e. the actual gas inventory) would be deducted. Therefore, we would get a cash flow benefit from the tax deduction, without a corresponding current out of pocket expense. For instance, lowering LIFO inventory by about 80 BCF would yield a current cash flow benefit of about $32 million.

Exhibit 1

(d) A public utility providing electric service, or a public utility providing gas service may file with the Commission proposed tariff sheets that eliminate the public utility’s fuel or purchased gas adjustment clause and adjust the public utility’s base rate tariffs to provide for recovery of power supply costs or gas supply costs that would have been recovered through such clause; provided, that the provisions of this subsection (d) shall not be available to a public utility described in subsections (e) or (f) of this Section to eliminate its fuel adjustment clause. Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section, or in any rules or regulations promulgated by the Commission pursuant to subsection (g) of this Section, the Commission shall review and shall by order approve, or approve as modified in the Commission’s order, the proposed tariff sheets within 240 days after the date of the public utility’s filing. The Commission’s order shall approve rates and charges that the Commission, based on information in the public utility’s filling or on the record if a hearing is held

by the Commission, finds will recover the reasonable, prudent and necessary jurisdictional power supply costs or gas supply costs incurred or to be incurred by the public utility during a 12 month period found by the Commission to be appropriate for these purposes, provided, that such period shall be either (i) a 12 month historical period occurring during the 15 months ending on the date of the public utility’s filing, or (ii) a 12 month future period ending no later than 15 months following the date of the public utility’s filing. The public utility shall include with its tariff filing information showing both (1) its actual jurisdiction power supply costs or gas supply costs for a 12 month historical period conforming to (i) above and (2) its projected jurisdictional power supply costs or gas supply costs for a future 12 month period conforming to (ii) above. If the Commission’s order requires modifications in the tariff sheets filed by the public utility, the public utility shall have 7 days following the date of the order to notify the Commission whether the public utility will implement the modified tariffs or elect to continue its fuel or purchased gas adjustment clause in force as though no order had been entered. The Commission’s order shall provide for any reconciliation of power supply costs or gas supply costs, as the case may be, and associated revenues through the date that the public utility’s fuel or purchased gas adjustment clause is eliminated. During the 5 years following the date of the Commission’s order, a public utility whose fuel or purchased gas adjustment clause has been eliminated pursuant to this subsection shall not file proposed tariff sheets seeking, or otherwise petition the Commission for, reinstatement or adoption of a fuel or purchased gas adjustment clause. Nothing in this subsection (d) shall be construed as limiting the Commission’s authority to eliminate a public utility’s fuel adjustment clause or purchased gas

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adjustment clause in accordance with any other applicable provisions of this Act.

(e) Notwithstanding any contrary or inconsistent provisions in Section 9-201 of this Act, in subsection (a) of this Section, or in any rules promulgated by the Commission pursuant to subsection (q) of this Section, a public utility providing electric service to more than 1,000,000 customers in this State may, within the first 6 months after the effective date of this amendatory Act of 1997, file with the Commission proposed tariff sheets that eliminate, effective January 1, 1997, the public utility’s fuel adjustment clause without adjusting its base rates, and such tariff sheets shall be effective upon filing. To the extent the application of the fuel adjustment clause had resulted in net charges to customers after January 1, 1997, the utility shall also file a tariff sheet that provides for a refund stated on a per kilowatt-hour basis of such charges over a period not to exceed 6 months; provided however, that such refund shall not include the proportional amounts of taxes paid under the Use Tax Act, Service Use Tax Act, Service Occupation Tax Act, and Retailers’ Occupation Tax Act on fuel used in generation. The Commission shall issue an order within 45 days after the date of the public utility’s filing approving or approving as modified such tariff sheet. If the fuel adjustment clause is eliminated pursuant to this subsection, the Commission shall not conduct the annual hearings specified in the last 3 sentences of subsection (a) of this Section for the utility for any period after December 31, 1996 and prior to any reinstatement of such clause. A public utility whose fuel adjustment clause has been eliminated pursuant to this subsection shall not file a proposed tariff sheet seeking, or otherwise petition the Commission for, reinstatement of the fuel adjustment clause prior to January 1, 2005.

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