Table of Contents

 

 

 

I. THE SETTLEMENT AGREEMENT

 

B. Legal Basis for Adoption of the Proposed Settlement Agreement as a Resolution on the Merits

C. Terms of the Settlement

1. Distribution of the $100 Million Refund

2. Accounting Proposals Adopted from the ALJPO in Docket 01-0707

3. Hardship Reconnection Program

4. Gas Reconciliation

 

II. THE PROCEDURAL HISTORY OF THIS DOCKET

 

A. Disclosure of Pertinent Information During Discovery

B. Applicable Legal Standards

1. Duty Imposed on North Shore by Statute

2. Burden of Proof

 

III. ENTITIES INVOLVED

 

IV. GENERAL PRUDENCE ISSUES

 

A. The Gas Purchase Agency Agreement

1. Findings of Fact

B. Storage at Manlove Field

1. Findings of Fact

2. Conclusions of Law

C. Hedging

1. Findings of Fact

2. Conclusions of Law

 

VII. AUDITS

 

A. Staff’s Position

B. North Shore’s Position

C. Commission Analysis and Conclusions

 

VIII. FINDING AND ORDERING PARAGRAPHS

 

 

Illinois Commerce Commission, On Its Own Motion,   v.     North Shore Gas Company,   Reconciliation of revenues collected under fuel and gas adjustment charges with actual costs.

: : : : : : : : : :

Docket No: 01-0706

On November 7, 2001, the Commission commenced this docket requiring North Shore Gas Company (“North Shore”) to reconcile the total revenue it collected from the ratepayers under its purchased gas adjustment clause (its “PGA”) with the total cost of gas it incurred. At that time, this Commission specifically required North Shore to present evidence establishing what measures it took to insulate ratepayers from price volatility in the wholesale natural gas markets during the time period in question, which is October 1, 2000, through September 30, 2001. (See, Initiating Order, November 7, 2001).

Leave to Intervene was granted to the Citizens Utility Board (“CUB”), the Cook County State’s Attorney, and the Illinois Attorney General. Pursuant to proper notice, trial in this matter convened before a duly authorized Administrative Law Judge (an “ALJ”) on April 18, 2005 and continued through April 21, 2005. Subsequently, the record was marked “Heard and Taken.” The parties filed post-trial briefs on June 30, 2005. Reply briefs were filed on August 19, 2005.

On January 17, 2006, Peoples Gas Light & Coke Company (“PGL”), North Shore, (collectively “Peoples Companies”), the AG and the City of Chicago entered into a Settlement Agreement and Release (the “Settlement”). CUB formally signed on to the Settlement on February 27, 2006. A copy of the Settlement is attached hereto as Exhibit 1. In the Settlement, the Peoples Companies, the AG, the City and CUB (collectively the “Settling Parties”) agreed to settle globally the outstanding reconciliation dockets pending for Fiscal Years 2001 through 2004 of both PGL (I.C.C. Docket Nos. 01-0707, 02-0727, 03-0705 and 04-0683) and North Shore (I.C.C. Docket Nos. 01-0706, 02-0726, 03-0704, and 04-0682) (collectively “Reconciliation Dockets”).¹ Under the Settlement, the Settling Parties would settle the Reconciliation Dockets and the Peoples Companies would pay a $100 million refund, adopt certain forward-looking management and accounting measures proposed in the ALJPO in Docket No. 01-0707, and meet other requirement defined in the agreement.

On January 23, 2006, the People Companies, the AG and the City filed a Joint Petition for Approval of the Settlement Agreement in each of the Reconciliation Dockets. At its February 8, 2006 Bench Session, after certain Commissioners raised concerns as to whether the terms of the Settlement were fair value in exchange for the settlement of all the Reconciliation Dockets, the Commission asked that the Settling Parties meet with Staff and CCSAO to negotiate settlement terms that all parties could accept.

During the next several weeks, Staff, the CCSAO and the Settling Parties met on several occasions. In addition, Staff issued several data requests to the Peoples Companies, which the Peoples Companies responded to on an expedited basis. Based on those responses, Staff developed an estimate of potential disallowances for reconciliation years other than 2001 that Staff asserted should be considered as part of the Settlement. Based on the above-mentioned discussions, the Settling Parties executed an Amendment and Addendum to the Settlement (the “Addendum”), which modified the terms of the Settlement to include these additional agreements and modifications that the Settling Parties would include if the Commission were to approve the Settlement. A copy of the Addendum is attached hereto as Exhibit 2. Staff and the CCSAO opposed both the Settlement and the Addendum.

On February 28, 2006 and March 1, 2006, the Settling Parties filed statements advising the Commission of the revised settlement terms agreed to by the Settling Parties and requesting that the Commission approve the Settlement as revised by the Addendum. On March 2, 2006, the Commissioners issued data requests to the parties to obtain information about the Settlement and the Addendum. The parties filed verified responses to these Commission data requests on March 3, 2006. On March 6, 2006, the Commission held a Special Open Meeting addressing the settlement during which Commissioners asked questions to and received answers from representatives of the parties and Staff. At that Special Open Meeting, the Commission generally approved the Settlement Agreement.

 

 

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¹  The Settlement also addressed three circuit court cases.

Testifying on behalf of North Shore² were: Thomas Zack, Director of Gas Supply at PGL; David Wear, the Manager of Gas Supply Administration at PGL; Valerie Grace, PGL’s Director of Rates and Gas Transportation Services; and Frank Graves, a Principal at the Consulting Firm of the Brattle Group.

Testifying on behalf of Commission Staff were Dr. David Rearden, a Senior Economist in the Commission’s Policy Division, Steven R. Knepler, A Supervisor in the Accounting Department of the Commission’s Financial Analysis Division and Dennis Anderson, a senior energy engineer in the Gas Section of the Engineering Department of the Commission’s Energy Division. Testifying on behalf of CUB was Brian Ross, a Principal with CR Planning, Inc.

 

I. The Settlement Agreement 

 

A. Outstanding Procedural Matters

 

On January 17, 2006, the Peoples Companies, the AG, the City and CUB filed a Joint Motion to Stay Pending Presentation of and Decision on Petition to Approve Settlement. In light of the Commission’s approval of the Settlement, without addressing or ruling on the merits of these matters, the Commission denies the Joint Motion for Stay as being moot. On March 16, 2006, Staff filed a motion seeking leave to file Exceptions and a Brief on Exceptions. That motion is hereby granted.

 

The Illinois Supreme Court addressed the standard for the Commission’s approval of settlement agreements and for its consideration and adoption of proposed settlement agreements in Business and Professional People for the Public Interest v. Illinois Commerce Commission (“BPI”), 136 Ill. 2d 192, 206-218 (1989). BPI holds that the Commission may approve a settlement agreement as a settlement agreement if there is unanimous support for it. Id. at 217-218. However, if a settlement agreement lacks unanimous support, for the Commission to consider and adopt the proposed agreement as an appropriate resolution on the merits, three conditions must be met: 1) the provisions of the settlement agreement must be within the Commission’s authority to impose; 2) the provisions must not contravene the PUA; and 3) substantial evidence must exist in the record to independently support the provisions of the proposed settlement. Id. It may be observed that the requirements expressed by the Illinois Supreme Court in BPI concerning the Commission’s adoption of a non-unanimous settlement proposal as a resolution of the merits of a case are similar in substance to the standards found in section 10-201 of the PUA that apply generally to the judicial review of Commission orders and decisions.

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²  PGL actually employs North Shore’s witnesses. These witnesses perform the same functions for North Shore as for PGL pursuant to a Commission approved operating agreement.

As noted above, the Settling Parties proposed to resolve eight open dockets with the Settlement and Addendum. The Settlement and Addendum received unanimous support from the parties in six of those dockets³, which the Commission will deal with in separate orders. For the remaining two dockets, 01-0707 and the instant docket, CCSAO opposed the settlement. Given the lack of unanimous support for the proposed settlement agreement here, the Commission must analyze the proposed settlement as described in the above paragraph if the Commission is to adopt the proposal as a resolution on the merits.

First, the Commission must determine if the provisions of the proposed Settlement and Addendum are within the Commission’s authority to impose. Several of the provisions—conservation program funding, debt forgiveness and hardship reconnection—do not require Commission approval to take effect. Because the Settling Parties constructed the proposed Settlement and Addendum so that these provisions will take effect even without Commission approval, the Commission need not analyze these provisions under BPI. However, only the Commission can issue an order imposing refunds in reconciliation proceedings (See PUA Section 9-220 and 83 Ill. Adm. Code 525). The refund provision will not take effect unless the Commission adopts the proposed Settlement and Addendum as a resolution on the merits. Since this provision rests solidly within the Commission’s authority, our adoption of this aspect of the proposed Settlement and Addendum meets the first condition of the BPI analysis.

Second, the Commission must determine whether the provisions of the proposed Settlement and Addendum, if adopted as a resolution on the merits, would contravene the PUA. Upon review of these documents, the Commission discerns nothing that would violate any provision of the PUA. Therefore, the proposed Settlement and Addendum meet the second condition of the BPI analysis.

Finally, the Commission must find that substantial record evidence exists to independently support the provisions of the proposed settlement. Substantial evidence is more than a scintilla, but less than a preponderance. (Citizens Utility Board v. Illinois Commerce Commission, 291 Ill. App. 3d 300, 304 (Ill. App. Ct. 1997)). This requires the Commission to demonstrate that facts exist that, in turn, sustain the provisions of the findings and ordering paragraphs of an order that would adopt, as a resolution on the merits, the provisions of the proposed Settlement and Addendum. The Settlement and Addendum provide for a $100 million refund to be issued to PGL and North Shore customers. For the Commission to consider these documents, which lack the support of CCSAO, to be an adequate resolution on the merits of this docket, the Commission must evaluate the record as it stands in this docket to ensure they support the $100 million refund. This evidence played a significant role in the proceedings and may not be ignored in a decision that considers and adopts the proposed settlement as a resolution on the merits, as we are required to do here. As set forth in the remainder of the order, the Commission finds substantial evidence in the record to support the provisions of this non-unanimous proposed Settlement and Addendum.

 

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³  While Staff expressed opposition to the settlement agreement, Staff is not considered a party under the Commission’s Rules of Practice. 83 Ill. Adm. Code § 200.40 (definition of “party”).

The Commission hereby adopts the provisions of the proposed Settlement and Addendum as an appropriate resolution on the merits, finding that they meet the BPI test.

 

C. Terms of the Settlement

 

The Commission finds that an appropriate settlement has been reached in this docket and in the other Peoples Reconciliation Dockets, the terms of the settlement are set forth in the Settlement (Exhibit 1) and Addendum (Exhibit 2). The Settlement and Addendum are hereby incorporated into and made a part of this Order and the similar orders entered for the other Peoples Reconciliation Dockets.

 

1. Distribution of the $100 Million Refund

 

The Settlement Agreement and Addendum provide the Commission with flexibility in determining how to refund the $100 million to customers in PGL's and North Shore’s service territories. The Commission finds that the $100 million refund should be apportioned to North Shore and PGL customers based on the substantial evidence in the records of Docket No. 01-0706 and Docket No. 01-0707. That evidence demonstrates that North Shore customers suffered significantly less harm than PGL customers.

The Commission finds that the $100 million refund shall be allocated between North Shore and PGL customer accounts based on each utility’s approximate share of the total disallowances recommended by Staff in Docket Nos. 01-0707 and the instant docket. Staff recommended approximately $92 million disallowances in the Docket 01-0707 and approximately $4 million disallowances in the instant Docket. Using those numbers as indicators of the level of harm caused to consumers in each service territory, the Commission finds that $4,000,000 of the $100,000,000 shall be refunded to customer accounts in North Shore’s service territory.

The $4,000,000 refund to North Shore customer accounts shall be allocated to all Service Classifications based on each Service Classification's share of the total PGA gas consumed by all Service Classifications during the 2001, 2002, 2003, and 2004 reconciliation periods (“Reconciliation Periods”).

Each Service Classification’s allocation, with the exception of the allocation to Service Classification No. 3 - Large Volume Demand Service ("SC No. 3"), shall be divided by the total number of customer accounts (both sales and transportation) receiving service under that Service Classification on the date this Order is entered. The result for each Service Classification shall be refunded on a per capita basis to each customer account receiving service under that Service Classification on the date this Order is entered. Refunds to all Service Classifications shall be provided to both sales and transportation customer accounts with the exception of SC No. 3 accounts as outlined below.

Refunds to SC No. 3 customer accounts shall be allocated to individual SC No. 3 customer accounts based on PGA gas usage during the Reconciliation Periods. The amount allocated to SC No. 3 shall be refunded to each individual SC No. 3 customer account, which received service at any time during the Reconciliation Periods and purchased PGA gas at any time during the Reconciliation Periods, based on each customer account’s share of the total PGA gas used during the Reconciliation Periods. If any of these entities are still a going concern but no longer a customer of the Company, then the Company and the customer shall arrive at a mutually acceptable method of administering the refund.

The Commission finds that the allocation methodologies for the different Service Classifications approved herein are equitable and take into consideration the administrative difficulties associated with providing refunds to nearly one million customers with vastly different usage characteristics and levels of service.

Within seven (7) days of the date this Order is served to the parties, North Shore shall file an informational filing with the Commission's Chief Clerk's Office describing the amount to be refunded to each customer in each Service Classification based on the methodology described herein and a plan for administering the refunds.

The informational filing shall include the following information for all Service Classifications except for SC No. 3:

§	The number of customers receiving service on each Service Classification as of the date this Order is entered,

§	The usage of PGA gas by each Service Classification during the Reconciliation Periods, and

§	The amount of the refund to be credited to each customer during the next 30-day billing cycle.

The following information is required for those customers that are on SC No. 3 Service Classification.

§	The number of current and former SC No.3 customers that held customer accounts and consumed PGA gas during the Reconciliation Periods,

§	The amount of PGA gas consumed during the Reconciliation Periods by each current and former SC No.3 customer account,

§	An indication of whether former SC No. 3 customers are still a going concern, and

§	The amount to be refunded to each current and former SC No.3 customer account that received service during the Reconciliation Periods.

The refund shall be issued in one installment and shall be a credit to the customer account. The credit shall be plainly designated on customers’ bills as a refund credit provided as a result of a Settlement and Addendum agreed upon by the City of Chicago, the Illinois Attorney General, the Citizens Utility Board, Peoples Gas, and North Shore and approved by the Illinois Commerce Commission.

Refunds shall be issued to all customer accounts within thirty (30) days of the date this Order is entered. Within forty-five (45) days of the date this Order is entered, the Company shall file an informational filing describing how the refund process was administered, the speed at which the refund process was completed, any problems that were incurred during the refund process, and any other issues associated with the refund process. This filing will also include the total number of customers receiving the refund for each Service Classification and the refund amount for each customer.

 

In the Settlement and the Addendum, the Settling Parties agreed that the Peoples Companies would adopt and incorporate into the Settlement several of the accounting provisions set forth in the ALJPO in Docket 01-0707. Section III.A.2 of the Settlement includes a statement paralleling Finding (13) of that ALJPO. Section III.A.2. states:

For a period of five years, Peoples Gas and North Shore Gas each shall perform an annual internal audit of gas purchasing and submit a copy of the audit report to the Manager of the ICC’s Accounting Department.

(Settlement at 8.)

Amendment Section A of the Addendum states that the Peoples Companies will account future HUB revenues in accordance with 83 Ill. Admin Code 525, stating:

Upon approval of the settlement agreement, Peoples Gas and North Shore Gas and all Peoples Companies shall account for all of their HUB revenues and third party non-tariff revenues, and any other revenues referred to as HUB revenues or non-tariff revenues (as those terms have been used in ICC Docket 01-0707) in accordance with 83 Ill. Admin Code 525.40(d). All such revenues shall serve to offset “recoverable gas costs” to arrive at the “gas charge” as those terms are used in Illinois Commerce Commission rules part 525.40(d) and in accordance with the Public Utilities Act. 83 Ill. Admin. Code 525.40(d); 220 ILCS 5/101 et. seq. The Peoples Gas and North Shore Gas and all Peoples Companies agree that this accounting of these revenues shall apply to all future Purchased Gas Adjustment reconciliation case and rate case filed by Peoples Gas and North Shore Gas.

(Addendum at 1-2.). Therefore, Peoples Gas and North Shore must account for all of their HUB revenues and third-party non-tariff revenues as is set forth above.

The text of those findings from the ALJPO in 01-0707 incorporated into the Settlement by the Addendum is:

(7)

Peoples Gas Light and Coke Company shall update its operating agreement, which was approved by this Commission in Docket No. 55071, prior to filing its petition with the ICC for its next rate case or within sixty days after the date a final order is entered in this docket, whichever occurs first;

(8)

Peoples Gas Light and Coke Company shall account for all gas physically injected into Manlove Field by including the cost associated with maintenance gas in the amount transferred from purchased gas expense to the gas stored underground account, Account 164.1;

(9)

Peoples Gas Light and Coke Company shall account for the portion of gas injected into the Manlove Storage Field to maintain pressure, as credits from Account 164.1, Gas Stored Underground, as charges to Account 117, Gas Stored Underground, in the case of recoverable cushion gas, or to Account 101, in the case of non-recoverable portions of cushion gas;

*  *  *

(11)

Peoples Gas Light and Coke Company shall revise its maintenance gas accounting procedures related to gas injected for the benefit of the North Shore Gas Company and third-parties to require those entities to bear the cost of maintenance gas, and it shall revise its maintenance gas accounting procedures to ensure that all customers/consumers bear equal responsibility for maintenance gas;

(12)

Peoples Gas Light and Coke Company shall submit its revised maintenance gas accounting procedures to the Commission’s Chief Clerk with a copy to the Manager of the Accounting Department within 30 days after the date, upon which, a final Order is entered in this docket;

*  *  *

(14)

Peoples Gas Light and Coke Company shall submit quarterly reports reflecting its use of journal entries regarding maintenance gas to the Manager of this Commission’s Accounting Department within 45 days of the end of each quarter, after the date of a final order is entered in this docket, through the quarter ending September 30, 2009;

(15)

Peoples Gas Light and Coke Company shall engage outside consultants to perform a management audit of its gas purchasing practices, gas storage operations and storage activities. The firm selected to perform the management audit shall be independent of Peoples Gas Light and Coke Company, its affiliates, Staff, and all parties in this docket, and approved by this Commission. Monthly reporting of the progress of the conduct of the management audit shall be submitted to the Bureau Chief of the Commission’s Public Utilities Bureau, with a copy to the Manager of the Commission’s Accounting Department, until the management audit report has been submitted. Completion of this management audit shall occur no later than eighteen months after the date, upon which, a final order is entered in this docket. Upon completion, copies of the management audit reports shall be submitted to the Commission’s Public Utilities Bureau Chief and the Manager of the Commission’s Accounting Department.

( 01-0707 ALJPO at 135-136.)

 

 

 

3. Hardship Reconnection Program 

 

The Peoples Companies agreed to instate a Hardship Reconnection program to allow certain customers who have been disconnected for non-payment to be reconnected and their debt forgiven. The Commission applauds this program and the Companies’ pledge to permanently instate it. The Commission has high hopes for the program’s success. To keep ourselves informed of the success, the Commission finds that the Peoples Companies should file quarterly reports on the progress of the program.

 

4. Gas Reconciliation

 

A reconciliation of North Shore’s total gas revenues with total gas costs for the reconciliation period October 1, 2000, through September 30, 2001 is shown in Appendix A hereto. This Appendix A contains an independent reconciliation for each of the following; Commodity Gas Charge, Non-Commodity Gas Charge and Demand Gas Charge, and Transition Surcharge. Below is an aggregation of the above referenced reconciliations.

1.  Unamortized Balance at 9/30/00 per 2000 reconciliation (Refund)/Recovery		$	7,794,821.26
2.  Factor A Adjustments Amortized to Sch. I at 09/30/00 per 2000 reconciliation (Refund)/Recovery			1,885,194.72
3.  Factor O (Refunded)/Recovered during 2000			0
4.  Balance to be (Refunded)/Recovered during 2001 from prior periods			9,680,015.98
5.  2001 PGA Recoverable Costs			175,017,347.00
6.  2001 PGA Actual Recoveries			194,127,626.25
7.  Interest			95,467.21
8.  Other Adjustments			0
9.  Pipeline Refunds			(34,749.64	)
10.  (Over)/Under Recovery for 2001			(19,049,561.68	)
11.  PGA Reconciliation Balance at 9/30/01 (Over)/Under Collected			(9,369,545.70	)
12.  Factor A Adjustments unreconciled at 9/30/01 (Refund)/Recovery			(3,296,514.13	)
13.  Unamortized Balance at 9/30/01 (Refund)/Recovery		$	(6,073,031.57	)
14.  Requested Ordered Reconciliation Factor to be (Refunded)/Recovered [Factor O]			0

 

 

II. The Procedural History of this Docket

 

A. Disclosure of Pertinent Information During Discovery

 

As is often the case in litigation, the ALJ assigned to this docket set a cut-off date of March 17, 2003 for completion of all discovery, except for the prefiling of testimony.⁴ (See, e.g., Mann v. Upjohn Co., 324 Ill. App. 3d 367, 373, 753 N.E.2d 452 (1^st Dist. 2001); Besco v. Henslee, Monek & Henslee, 297 Ill. App. 3d 778, 781, 701 N.E.2d 1126 (3^rd Dist. 1998)). On February 10, 2004, however, discovery was reopened. In Motions to Compel brought by several parties, parties contended that in discovery, North Shore was asked to provide information about its business dealings with an affiliate, enovate. Recently-released information on the website of the Federal Energy Regulatory Commission (“the FERC”) about Enron’s relationship with PGL, North Shore’s affiliate, and other affiliates, indicated that PGL entered into transactions with enovate that were not disclosed in discovery. (See, e.g., CUB Motion to Compel, February 3, 2004). When reopening discovery, the ALJ permitted the movants to seek additional information through discovery about enovate⁵. (Tr.132-33).

Also on February 10, 2004, the ALJ required parties to adhere to discovery practices in the Ill. Supreme Court Rules, as opposed to the discovery practices in the Commission’s rules.⁶ The Ill. Supreme Court Rules require verification of answers to discovery requests. (See, e.g., S. Ct. Rule 213(i)).

 

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⁴  Administrative Law Judge Erin O’Connell-Diaz was originally assigned to this docket. It was reassigned to Administrative Law Judge Claudia E. Sainsot on April 30, 2003.

⁵  North Shore purchases storage field space at Manlove Field through an affiliate interest agreement with PGL. PGL’s transactions with enovate involving the use of Manlove Field could have affected costs to North Shore’s PGA customers.

⁶  Commission rules require full disclosure of all information that is relevant and material. (See, e.g., 83 Ill, Adm. Code 200.340). Commission rules do not require any person to verify discovery responses. And, Commission rules provide no penalties for failure to provide discovery or for inaccurate discovery responses.

B. Applicable Legal Standards

1. Duty Imposed on North Shore by Statute

Generally, base rates include a utility’s administrative costs and its Commission-approved rate of return, which is the cost of investor capital. (See, e.g., Ill. Power Co. v. Ill. Commerce Comm., 339 Ill App. 3d 425, 434, 709 N.E.2d 377 (1^st Dist. 2003)). This proceeding, however, is a reconciliation, which determines the propriety of North Shore’s purchased gas adjustment tariff (“PGA”), which allows it to pass its gas costs on directly to consumers.⁷ (Id. at 427). Those charges are the cost of gas supplied to consumers, as well as the related expenses incurred, including but not limited to, expenses related to assets used by North Shore in supplying gas to consumers. (83 Ill. Adm. Code 525.40(a)). With respect to gas costs, consumers pay North Shore whatever price North Shore paid for gas, with no markup for profit on the gas. (Tr. 782).

Recoverable gas costs include the cost(s) of gas, cost(s) of storage, transportation costs and other non-commodity costs. (83 Ill Adm. Code 525.40(a)). If North Shore derived revenues from any transactions with costs associated with costs recoverable under the above-mentioned section, any associated revenues must be used to offset those costs. (Id. At 525.40(d)). When engaging in such transactions, North Shore must “refrain” from doing anything that would increase the gas charge. (Id.).

Although North Shore’s tariff allows it to pass on the cost of gas to consumers without Commission approval, the Commission is required annually by statute to determine whether the charges North Shore imposed reflect the cost of gas, and to determine whether such purchases were prudent. (220 ILCS 5/9-220). In this context, prudence has been defined as [t]hat standard of care which a reasonable person would be expected to exercise under the same circumstances encountered by utility management at the time decisions had to be made. (Illinois Power Co. v. Ill. Commerce Comm., 245 Ill. App. 3d 367, 371, 612 N.E.2d 925 (3^rd Dist. 1993)). Thus, only what the decision-makers actually analyzed, or should have analyzed, can be considered here. (Id.).

If, after a hearing, the Commission finds that a utility has not established that the costs it passed on to consumers in a PGA clause were prudently incurred, the difference determined by the Commission must be refunded, along with any interest or carrying charge authorized by the Commission. (83 Ill. Adm. Code Sec. 525.70(b)). Section 9-220 and its predecessor, Section 36 of the previous Public Utilities Act, confer a broad grant of authority on this Commission. (Business and Professional People for the Public Interest v. Ill. Commerce Comm., 171 Ill. App. 3d 948, 957, 525 N.E.2d 1053 (1^st Dist. 1988)).

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⁷  The word “consumer” is used here to mean PGL’s rate-paying customers, including both residential customers and businesses.

 

2. Burden of Proof

 

The Commission commenced this reconciliation proceeding, as it does every year. However, the burden of proof is on North Shore to establish the prudence of its costs of gas purchases and related costs. (220 ILCS 5/9-220(a)). North Shore has the burden to prove this by the preponderance of the evidence. (5 ILCS 100/10-15). Preponderance of the evidence has been defined as the evidence that is more probably true than not. (See, e.g.,Witherell v. Weimer, 118 Ill. 2d, 321, 336, 515 N.E. 2d 68 (1987)).

 

III. Entities Involved

 

As the record demonstrates, several entities are involved in this rather complicated fact patter. Of primary importance is North Shore, a local distribution company (“LDC”) and the subject of this proceeding. It distributes gas to consumers that are within its service territory, chiefly the suburbs directly north of Chicago. North Shore must purchase the gas that it distributes to consumers. Peoples Energy Company (“PEC”) is North Shore’s parent company. Affiliated with North Shore and PEC are Peoples Energy Resources Company (“PERC”) and The Peoples Gas Light and Coke Company (“PGL”). Enron North America Corp. (“Enron NA”) is wholly-owned by Enron Corp.⁸ (Staff Ex. 2.00, Attachments, Guaranty, at 1).

 

IV. General Prudence Issues

 

A. The Gas Purchase Agency Agreement

 

1. Findings of Fact

 

a. Background

In October of 1998, North Shore filed a petition with the Commission requesting permission to impose a fixed gas charge of 31.08 cents per therm. In December 1998, North Shore issued a “request for qualification” (“RFQ”) to nine gas marketers to examine their ability to package a full-requirement, fixed-price, gas supply proposal and to evaluate capabilities to act as asset manager of North Shore’s supply portfolio. (North Shore Ex. C, pp 4-5). Enron NA participated in the RFQ. North Shore selected Enron NA over the other RFQ participants. According to North Shore, Enron NA possessed “superior” managerial skills and “excellent” assets.

 

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⁸  The parties and Staff also make references to enovate in the context of enovate’s relationship with PGL. The record here demonstrates North Shore had little or no involvement with enovate. For a complete description of enovate and its relationship to the Peoples companies, see the final order in Docket 01-0707.

In an Order in Docket 98-0820 dated June 7, 1999, the Commission allowed North Shore to impose a fixed gas charge, but it authorized North Shore to charge a fixed rate of 25.63 cents per therm. In reaching this decision, the Commission concluded that North Shore included several items in its proposed charge at erroneous amounts or improperly included those items. The Commission found that the proposed charge included payment for a set of premiums for the acquisition of natural gas options with delivery months extending out for several years into the future, which violated Section 9-220(d) of the PUA. Additionally, the Commission ruled that North Shore’s proposal improperly normalized day-to-day variations in demand through the spot market, instead of relying on storage. The Commission further concluded that North Shore undervalued the credits consumers received for the net revenue from off-system transactions. (See, North Shore Gas Company, Proposal to Eliminate its Purchased Gas Adjustment (PGA) Clause and Include Gas Charges in Base Rates, 1999 Ill. PUC Lexis 413 at *16-18).

North Shore never implemented a fixed gas charge. (North Shore Ex. C at 4-5). North Shore believed the Commission decision on the fixed gas charge to be too low to obtain the necessary supply contracts. Instead, it continued utilizing a PGA Rider, which imposes gas charges and related costs on consumers on a monthly basis. North Shore also decided not to use a full requirements contract that included outside management of storage services.

On September 16, 1999, North Shore entered into a five-year agreement with Enron NA. Pursuant to this contract, effective October 1, 1999, Enron NA supplied North Shore with approximately 64% of its gas supply. (Staff Ex. 2.00 at 6, Attachments, GPAA). This contract was called the Gas Procurement Agency Agreement (“GPAA”). (Id.). Before entering into the GPAA, North Shore did not seek competitive bids. Rather, it engaged in private negotiations with Enron NA. (North Shore S Ex. C at 4). Historically, North Shore obtained its supply from several suppliers through contracts for smaller volumes of gas with terms ranging from four months to five years. (Staff Ex. 2.00 at 11).

The person primarily responsible for entering into the contract with Enron NA was William Morrow, Vice President of PGL, Vice President of Peoples Energy Corporation and the President of Peoples Energy Resource Company. Mr. Morrow also oversaw the negotiations. (North Shore Ex. C at 10). Mr. Morrow and David Delainey, Managing Director of Enron NA, executed the GPAA. (Staff Ex. 2.00, Attachments, GPAA, at 36).

b. The Terms of the GPAA

Mr. Wear testified as to the terms of the GPAA. Mr. Wear has been the Manager of Gas Supply Administration at PGL since April of 2000. (North Shore Ex. B at 2). The Gas Supply Division includes the Gas Supply Planning Departments and it is responsible for entering into and administering contracts for gas supply and for purchasing transportation and storage services. (North Shore Ex. B at 3). Mr. Wear’s involvement in the negotiations with Enron NA regarding the GPAA was to provide information to the decision-makers determining whether the GPAA would be a reliable supply of gas when needed. Mr. Wear was not one of the persons at North Shore who actually decided whether to enter into the contract with Enron NA. Previous to the GPAA, North Shore’s gas supply contracts provided that North Shore would purchase the same quantity for a fixed five-month period (November through March) or for a period of one year. ( Staff Ex. 2.00 at 9).

In general, the GPAA had three main provisions through which Enron North America provided North Shore with approximately 64% of its gas supply. Those provisions where for Baseload Quantity gas, Summer Incremental Quantity gas (“SIQ”), and Daily Incremental Quantity gas (“DIQ”). (Staff Ex. 2.00, Attachments, GPAA, at 9). The GPAA also required North Shore to release pipeline capacity to Enron North America. (Id. at 12).

According to Mr. Wear, when North Shore negotiated this contract with Enron NA, the following were North Shore’s objectives:

-market-based pricing with no demand or reservation charges;

-flexible pricing options;

-preservation of transportation capacity in the face of projections of shrinking basis;

-flexibility to meet weather under normal conditions, colder than normal conditions and warmer than normal conditions; and

-the contract should substitute for the aggregate of what North Shore previously had with other suppliers.

(North Shore EX. D at 7-30). Later, Mr. Wear asserted that the GPAA also conferred certain non-quantifiable benefits on North Shore, like technical support provided by Enron North America and training as to the use of financial hedging instruments, like energy derivatives and options. (Id. at 7-10). North Shore has never proffered any reasons other than these for entering into the GPAA. Other than expressions of concern over mitigating the decline in value of its pre-existing pipeline contracts (basis), this record is devoid of any evidence indicating that decision-makers at North Shore were concerned that the GPAA could increase the gas costs it passed on to its PGA customers.

1) Baseload Quantity Gas

This provision refers to the established daily volume of gas North Shore was required to purchase from Enron NA by month from October 1999 to October 2004. Daily baseload purchases are ones that North Shore made in order to meet its overall supply requirements. (Staff Ex. 2.00 at 22; North Shore Ex. B at 5). The GPAA had a fixed, predetermined schedule of baseload quantities. (Staff Ex. 2.00, Attachments, GPAA, Schedule 2.1). However, the parties could meet annually to discuss changes to the baseload quantity or to the SIQ quantity. (Staff Ex. 2.00, Attachments, GPAA, Art. 2.8).

The price of baseload quantity gas purchased pursuant to the GPAA was the price published in Natural Gas Intelligence Chicago citygate⁹ First-of-the Month (“FOM”) price, less a two-cent per MMBtu discount.¹⁰ (Staff Ex. 2.00. Attachments, GPAA, at 8). Staff determined that this discount saved consumers $270,959. (Staff Ex. 3.00 at 27).

2) The SIQ and DIQ Provisions

Two of the GPAA provisions allowed North Shore to purchase gas supply to meet its incremental needs. Gas purchased pursuant to the Summer Incremental Quantity (“SIQ”) clause was used to fill North Shore’s storage facilities from the months of April through November. SIQ gas was used to create a supply of less expensive summer gas to meet North Shore’s needs in the winter, when gas prices would be higher. ( North Shore. Ex. C at 18).

Pursuant to the GPAA’s SIQ clause, Enron NA agreed to supply gas to North Shore at the Natural Gas Intelligence Chicago citygate FOM price, minus two cents per MMBtu.¹¹ (Staff Ex. 2.00, Attachments, GPAA at 2). During the months of April through November, Enron NA was required to provide at least 5,000 MMBtu of gas per day to North Shore. (Id. at pp. 6, 9). Enron NA could, at its sole discretion, deliver an additional 5,000 MMBtus of gas. (Id. at 6; North Shore Ex. C at 15). Also during this period, whenever Enron delivered more than the minimum 5,000 MMBtus of gas, North Shore was obliged to purchase it. (Id.). Enron NA had the option to, but not the obligation to, deliver up to 5,000 MMBtus of gas to North Shore over and above the contractual minimum of 5,000 MMBtus, thus requiring North Shore to potentially purchase up to 10,000 MMBtus per day. (Id.). On any given day, North Shorehad no control over the amount of gas it received pursuant to the SIQ clause. (Staff Ex. 2.00 at 23).

 

 

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⁹  The Chicago citygate is a term that refers to the delivery points on the systems of PGL, North Shore and Nicor Gas. It is the point at which the gas is no longer transported on a pipeline but instead is on North Shore’s distribution system. (NYMEX.com/glossary).

¹⁰  FOM pricing is driven by the market activity during the preceding month, and is, therefore, less susceptible to price fluctuations that occur subsequent to the first of the month. It is, therefore, generally, less expensive than daily index pricing. (See, Staff Ex. 2.00 at 25).

¹¹  Citygate pricing includes the cost of transporting the gas to Chicago. (See, e.g., Staff Ex. 2.00 at 20).

The Daily Incremental Quantity (“DIQ”) clause gave North Shore the right to purchase gas at the Gas Daily Chicago citygate Daily Midpoint Price, up to a certain specified level. North Shore purchased DIQ gas with no discount. (Staff Ex. 2.00, Attachments, GPAA, at 3). Pursuant to the DIQ clause, North Shore could nominate any portion or no portion of the DIQ. The amount of gas that North Shore could purchase on any given day pursuant to the DIQ clause was determined by subtracting the total pipeline capacity that North Shore released to Enron NA on that day from the sum of gas purchased that day through the baseload and SIQ provisions. (See, e.g., Staff Ex. 2.00, Attachments, GPAA, at 3).

The DIQ provision replaced what is known as “swing gas,” for which there is usually an added premium called a “demand charge” paid by a gas buyer like North Shore.¹² The DIQ clause, however, did not impose this added premium. (Id.). Staff determined that the avoided demand charges were $87,594. (Staff Ex. 3.00 at 28).

Staff witness Mr. Anderson opined that the combination of the SIQ provision and the DIQ provision gave Enron NA the incentive to force North Shore to pay higher gas prices. The SIQ was priced at lower FOM index prices, minus two cents per MMBtu. The DIQ, on the other hand, was priced at no discount and it was based on the generally higher Daily Midpoint Price. Often when the Daily Midpoint Price rose above the FOM price, Enron NA had the economic incentive not to sell North Shore the full 10,000 MMBtus of SIQ gas, irrespective of North Shore’s needs, forcing North Shore to purchase gas at higher prices. (Staff Ex. 2.00 at 24-25). Staff determined that Enron’s manipulations of these two provisions cost consumers $302,360. (Staff Ex. 7.00 at 27-29).

Before entering into the GPAA, North Shore personnel performed no analysis of the effect of the DIQ or SIQ provisions on consumers. North Shore also did not assess the value that Enron NA received as a result of its ability to manipulate the SIQ clause. (Tr. 911-12).

 

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¹²  A demand charge is a premium for being “on call” on short notice for the possibility of delivering gas with no assurance that the buyer will ever actually take the gas. (PGL Ex. C at 17). 

 

 

According to Staff, the GPAA contained several provisions that allowed Enron NA to unilaterally increase the cost of North Shore’s gas supply. Pursuant to Articles 4.2(b) and 4.2(c) of the GPAA, Enron NA could change the price of gas without any input from North Shore. (Staff Ex. 2.00, Attachments, GPAA, Articles 4.2(b) and 4.2(c)). Article 4.2(b) gave Enron NA the right, during December through March, to change the price of baseload gas from the contractual price to the daily midpoint Gas Daily Chicago citygate price for up to 3,750 MMBtus per day of gas. Pursuant to Article 4.2(b), Enron NA could elect to change baseload purchases from the Natural Gas Intelligence Chicago citygate FOM price to the daily midpoint Gas Daily Chicago citygate price for a portion of the baseload gas equal to 2000 MMBtus per day. (Staff Ex. 2.00 Attachments, GPAA, at 3, 10).

 

4) Released Pipeline Capacity and Foregone Demand Credits

North Shore articulated several reasons for its decision to enter into the GPAA. These reasons will be discussed more fully below. Two of North Shore’s reasons for executing the GPAA were to prevent the erosion of basis and to eliminate demand charges. As part of North Shore’s plan to prevent the erosion of basis, it agreed to relinquish certain pipeline capacity rights, and to forego certain demand credits.

The GPAA required North Shore to release all of its rights, title and interests to certain pipeline capacity to Enron NA. (Staff Ex. 2.00, Attachments, GPAA, Art. 4.3, Schedule 6.3; NS Ex. B at 4). According to Mr. Wear, Enron NA sold gas to North Shore at the city gate to meet North Shore’s requirements. To facilitate this, North Shore released pipeline capacity to Enron NA on two interstate pipelines, Midwestern Gas Transmission (“MG”) And Northern Border Pipeline Company. (See, e.g., Staff Ex. 3.00 at 22; Staff Ex. 2.00, Attachments, GPAA, Schedule 6.3). Enron NA paid the pipelines directly and then North Shore reimbursed Enron NA for all the pipeline transportation costs that it paid. (Staff Ex. 2.00 at 17-19; Attachments, GPAA, Article 4.3). North Shore, though, was entitled to all credits, refunds and reimbursements due it from any pipelines for demand or reservation charges. (Id. at 10-11). North Shore also bore the cost of any increase or decrease in variable transportations costs and fuel, when those increases or decreases resulted from its usage and were created due to changes in the applicable tariffs. (Id. at 11).

Staff witness Mr. Anderson pointed out that North Shore traded the use of its pipeline capacity in exchange for citygate prices. However, citygate prices include the cost of transporting the gas to Chicago. North Shore paid twice for transporting gas to Chicago, and it gave away its excess capacity to Enron NA. (Staff Ex. 2.00 at 18). In Mr. Anderson’s opinion, the GPAA did not protect North Shore from eroding basis. (Id. at 18, 20).

North Shore did not achieve its goal of eliminating demand charges by executing the GPAA. According to Mr. Anderson, the GPAA contained certain embedded demand charges. (Staff Ex 2.00 at 20). The GPAA required North Shore to reimburse Enron NA for all pipeline demand charges Enron NA paid the pipelines. (Staff Ex. 2.00, Attachments, GPAA, Art. 4.3). North Shore failed to provide an analysis of the cost components of the GPAA; therefore, there is no evidence to show that North Shore isn’t paying demand charges. Mr. Anderson avers that mere statements concluding that the GPAA contains no demand charges are not enough.

Mr. Wear testified that the number of off-system transactions declined after North Shore entered into the GPAA. The reason for the decline, according to Mr. Wear, was the fact that North Shore had released some its transportation assets to Enron NA pursuant to the terms of the GPAA. Many of the off-system transactions in previous years involved use of those assets. (North Shore Ex. C at 31-32). Staff determined that, as a result of the GPAA, North Shore lost $250,823 in income from these demand credits during the reconciliation period. (Staff Ex. 3.00 at 28).

As more fully articulated below, one of North Shore’s reasons for executing the GPAA was that it allowed for flexible pricing options. Article 4.2 of the GPAA allowed North Shore to request different pricing for gas from that enunciated in the GPAA for all or any portion of baseload, SIQ or DIQ gas. Enron NA, however, was under no obligation to furnish gas at a lower price than the terms of the GPAA. Instead, the price of gas could only be changed upon mutual assent by both parties. (Staff Ex. 2.00, Attachments, GPAA, Article 4.2). There is no evidence that North Shore personnel ever attempted to arrive at a mutually agreed-upon alternative price.

 

 

Article 2.4 gave North Shore the right to resell gas to Enron NA. However, the GPAA imposed certain specified penalties on resales. The amount of the penalty was contingent upon how timely North Shore was at nominating the resale and the amount of the resale. (Staff Ex. 2.00, Attachments, GPAA, Art. 2.4).

Staff witness Rearden provided an explanation of Staff’s interpretation of this provision of the GPAA. Dr. Rearden opined that the existence of this provision is indicia that North Shore expected to have an oversupply of gas. (Staff Ex. 3.00 at 24). Dr. Rearden opined that, if North Shore had entered into a contract that did not require it to make excess purchases pursuant to the SIQ clause, it would not need such a provision. (Staff Ex. 7.00 at 33).

North Shore witness Wear explained why North Shore wanted this provision to be included in the GPAA. Mr. Wear stated that when negotiating the GPAA, North Shore required a sell-back provision in the contract because a sell-back provision created a firm market that North Shore could turn to when it had an oversupply. (North Shore Ex. C at 23). By establishing a contractual right to resell gas to Enron NA, North Shore substantially eliminated the uncertainty associated with finding a market for excess gas on short notice, when North Shore had an oversupply. A standing firm bid to purchase oversupply, which would likely be executed under excess conditions in the marketplace, is valuable. (Id. at 20-21). According to Mr. Wear, it was not advantageous to be in a position to unload a large amount of gas. In such an instance, the counterparty is often aware of the need to unload the gas. As a result, North Shore would receive less money than it would have received otherwise. (North Shore. Ex. D at 16; C at 23). Mr. Wear testified that most spot transactions are 5,000 to 10,000 MMBtus. The more gas North Shore has to unload, the more time it could take to accomplish that goal. Mr. Wear stated that the resale provision was not placed in the GPAA in anticipation of an oversupply. Rather, North Shore personnel recognized that sales might be necessary. (North Shore Ex. D at 17-18). An oversupply can also cause a pipeline overrun, which could lead to substantial penalties. (North Shore Ex. C at 25).

North Shore did not resell any gas to Enron NA during the reconciliation period. Staff’s disallowance for this provision is, therefore, $0. (Staff Ex. 3.00 at 28).

 

7) Annual Review

Article 2.8 of the GPAA required the parties to meet annually to discuss any necessary or appropriate adjustments to baseload quantity gas and SIQ gas. (Staff Ex. 2.00, Attachments, GPAA, Art. 2.8).

8) Conversion to Performance-Based Rates

Article 4.5 of the GPAA provided that, if during the term of the GPAA, North Shore filed, pursuant to Section 9-220(d) of the Public Utilities Act, a petition seeking authority for performance-based rates, thus eliminating its PGA, or if it sought alternative regulation pursuant to Section 9-224 of the Act, the parties could re-negotiate pricing terms of the GPAA. (Staff Ex. 2.00, Attachments, GPAA, at 12).

9) Books and Records

Article 19.9 of the GPAA required North Shore and Enron NA to maintain all books and records related to Transaction Agreements for a period of three years from the end of the terms of the GPAA, or three years from termination of the GPAA. (Staff Ex. 2.00, Attachments, GPAA, at 34).

b. Economic Analyses Made of the GPAA Just Before it was Executed

During discovery, Staff and the AG requested any studies, analysis or like information used by North Shore to determine the economic benefits of the GPAA. Initially, North Shore denied that any economic analysis of the effect of the GPAA on consumers had ever been performed. (See, e.g., NS Ex. D 11, at 13). In fact, North Shore’s chief witness, Mr. Wear, the Manager of Gas Supply Administration at North Shore, testified that no economic analysis of the GPAA was performed. (Id.).

However, after discovery reopened, a study called the “Aruba Analysis”¹³ surfaced. Roy Rodriguez, who was employed in Peoples Energy Company’s Risk Management Department, prepared this document in August and September of 1999. The Aruba Analysis only evaluated certain terms of the GPAA, not the entire agreement. (Group Ex. 1 at ST-PG1-25). Using information gathered by PGL personnel, Mr. Rodriguez analyzed the projected economic value conferred on Enron NA by PEC and the projected effect of the GPAA gas prices on customers. (Staff Ex. 7.00 at 9). ¹⁴ 

In the Aruba Analysis, Mr. Rodriguez compared the GPAA FOM price, minus PGL’s three-cent discount, with the NYMEX cost of gas in the field, plus the forecast field-Henry Hub basis differential and the variable cost of transportation to Chicago.¹⁵ (See, e.g., Staff Ex. 7.00 at 9). Mr. Rodriguez calculated two scenarios to determine the effect of the GPAA on consumers. One scenario used a high amount of SIQ volumes and the other used a low amount of SIQ volumes. He determined, using different scenarios, that the extra costs resulting from the GPAA would be in a range between approximately $19 million to approximately $24 million. In both scenarios that Mr. Rodriguez used, the results indicated that the GPAA would increase consumer gas costs. (Group Ex. 1 at ST-PG-1-25). Mr. Rodriguez’s study was based on same data that PGL personnel collected before it entered into the GPAA, which is the same data contained in North Shore Exhibits 2 and 3, attached to Mr. Wear’s testimony. (Staff Ex. 7.00 at 7, Attachments 2, 3).

 

 

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¹³  The Aruba Analysis surfaced in Docket 01-0707, PGL’s reconciliation docket. The Aruba Analysis analyzed certain PGL GPAA provisions.

¹⁴  North Shore’s contract with Enron NA was very similar to the GPAA contract that PGL entered into with Enron NA. The primary difference between the two contracts was that North Shore had a two-cent discount on purchases of baseload and SIQ gas, which shall be discussed herein, whereas PGL had a three-cent discount on these two types of purchases. Also, some of the amounts of gas supplied by Enron NA, such as baseload quantities and summer incremental quantities, differed. (See, e.g., 01-0707, Staff Ex. 2.00 Attachments, GPAA).

¹⁵  The Henry Hub, in southern Louisiana, is the largest centralized point in the U.S. for purchasing gas, or, for purchasing gas futures contracts. It is a nexus of 16 natural gas pipeline systems that draw supplies from the region’s gas fields. (Nymex.com\glossary).

Mr. Wear also performed an analysis of the economic costs of the GPAA, labeled for this proceeding as Wear Cross Exhibit 1. This document was taken from Mr. Wear’s computer and it was in a file created by Mr. Wear. It simulated what total gas costs would have been pursuant to the GPAA compared to PGL’s supply practices for the previous four years. It was created on September 8, 1999 and it was last modified on September 10, 1999, six days before the GPAA was executed by Delainey and Morrow.

Wear Cross Exhibit 1 indicated that certain gas costs passed on to consumers would increase by approximately $50 million throughout the first four years of the five-year life of the GPAA. (See, Wear Cross Exhibit 1). Like the Aruba Analysis, Wear Cross Exhibit 1 did not evaluate all of the GPAA provisions. However, both analyses demonstrated that the GPAA would result in higher gas costs being passed on the consumers. (Wear Cross Ex. 1; Group Ex. 1 at ST-PG-1-25).

 

North Shore articulated several reasons for its decision to execute the GPAA. Industry studies indicated that basis would begin to decline. North Shore believed the GPAA would protect against the erosion of basis. Additionally, North Shore averred that the GPAA provided certain unquantifiable benefit. The discussion below fully outlines North Shores' reasoning for entering into the GPAA.

1) The Eroding Value of Basis

“Basis” is the difference in gas price at a location in the field area (either at the wellhead or at a specific trading point) and gas prices at another market point. In this case, that other market point is the Chicago citygate. (North Shore Ex. C at 5-6). It is, essentially, the cost, as is reflected in the marketplace, of transporting the gas to the Chicago citygate. (Id.). Basis has two elements, the variable transportation cost and a certain percentage of gas taken off at the top by a pipeline to maintain pressure in the pipelines and to account for lost gas. As the price of gas increases, so does basis. (Staff Exs. 3.00 at 24; 7.00 at 20-21).

At the time the GPAA was executed, several pipeline construction projects were underway that would soon increase the natural gas supply to the Chicago area. (North Shore Ex. D at 4). Two projects were planned for Chicago that would increase capacity to the Chicago area by almost 2.0 Bcf of gas per day. (North Shore Ex. C at 5-6). The effect of these projects would be to erode the value of North Shore’s existing transportation contracts. (Id.). North Shore witness Wear testified that one reason North Shore entered into the GPAA was to counteract the predicted decline in basis from a field location to Chicago. (North Shore Ex. C at 7-9). As basis declines, a citygate purchase becomes more attractive; in such a scenario, the difference in price between the field gas and transportation costs and citygate gas decreases. (North Shore Ex. D at 4). Mr. Wear stated that North Shore did not enter into the GPAA to capture a small decline in basis. Rather, the GPAA hedged a significant decline in basis. (North Shore. Ex. D at 23).

Before signing the GPAA, North Shore purchased a portion of its portfolio at citygate prices. According to Mr. Wear, these citygate purchases mitigated some of the effect of a decline in basis. However, in order for the citygate delivery price to be profitable, the average basis would have to fall below the transportation costs. (North Shore Ex. D at 4).

Additionally, in the past, North Shore personnel were able to “optimize” its transportation assets on days when they were not needed to meet system requirements.¹⁶ (Staff Ex. 2.00 at 15). A decrease in basis might also result in a decrease in the amount of demand credits North Shore received through “optimization” of its firm transportation contracts through off-system transactions. (North Shore Ex. C at 8).

Mr. Wear testified that North Shore decision-makers determined that Enron NA’s proposal for a substantial gas supply contract would remove the risk of a decline in basis by ensuring index-based market pricing for gas supply and guaranteeing demand credits. (North Shore Ex. C at 6). According to Mr. Wear, declining basis was a reason North Shore personnel decided to enter into the GPAA with Enron NA. (North Shore Ex. C at 6-8). According to Mr. Wear, purchasing gas at the citygate index price would lower the cost of gas. Mr. Wear projected the decline in basis to be slightly more than $0.01 per MMBtu per year. (North Shore Ex. C at 8-9). There is no credible evidence that any of the North Shore decision-makers contemplated that basis would decline more than this amount.

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¹⁶  The term “optimize,” as it is used here, means to rent those facilities out to others for a fee, when they are not being used. (See, e.g.,Staff Ex. 2.00 at 15).

Staff witness Dr. Rearden testified that the most important evaluation of the GPAA is a comparison between what North Shore did before entering into the GPAA—buy gas in the field and pay the cost of variable transportation—with the cost of gas pursuant to the GPAA, which provides for gas transported to the Chicago citygate, less two cents per MMBtu. To acquire a “hedge” against basis, North Shore agreed to several terms that raised prices for consumers. According to Dr. Rearden, for the GPAA to be a prudent decision, the decline in basis must exceed the increase the consumers incurred in the cost of gas as a result of the GPAA. (Staff Ex. 3.00. at 23-24).

Staff Witness Mr. Anderson testified that North Shore had other options with which it could avoid a loss in capacity revenues and demand credits due to eroding basis. At the time in question, North Shore had a portfolio of transportation contracts with various pipelines that expired, or would expire shortly, that it could have negotiated at a lower cost, as eroding basis causes pipeline transportation to be worth less. Just before the time when North Shore entered into the GPAA, it renegotiated four pipeline contracts. Mr. Anderson opined that there is no evidence that North Shore personnel were unaware that potential basis erosion was on the horizon at that time. To combat the decline in basis, North Shore could have negotiated shorter-term contracts, to be re-negotiated as competition reduced pipeline rates. (Staff Ex. 2.00. at 18). Mr. Anderson also opined that load-shifting was another way to mitigate the financial effect of declining basis. Load-shifting is a common practice in the industry. When a gas company puts more load on a pipeline, it can receive discounts from the pipeline at rates below the maximum FERC rate. (Staff Ex. 6.00 at 22).

Staff believes that to properly evaluate the prudence of the GPAA, one must consider the information available to North Shore at the time it executed the GPAA. Dr. Rearden opined that, in order to determine what the decline in basis actually was, one must determine the difference between the price of gas bought in the field and delivered, versus the Chicago citygate price. Using the information that Mr. Wear used to prepare his Ex 2 , Dr. Rearden calculated the difference between the two and concluded that the citygate price did not offset any decline in basis. He determined that the gas purchased through the GPAA, using the GPAA prices, would increase gas prices by approximately $1,519,090. (Staff Ex. 7.00 at 16-20). Dr. Rearden used the same data as that used by North Shore witness Mr. Wear. However, Mr. Wear’s calculations showed the projected decline in basis to be approximately one cent per MMBtu per year. (See, e.g., Staff Ex. 12.00 at 8).

Dr. Rearden testified that, in order to accurately determine basis for delivered gas, one must determine both the Chicago-Henry Hub basis and the weighted average basis from Henry Hub to the field zone. This method is how Mr. Rodriguez determined basis when preparing the “Aruba Analysis.” In Dr. Rearden’s opinion, North Shore witness Mr. Graves’ calculation of basis was incorrect; Mr. Graves only examined the effect of changing Chicago-Henry Hub basis. Mr. Graves did not consider the changes to the weighted average basis from the field to the Henry Hub that are implied by using the alternative projected basis for Chicago-Henry Hub. (Staff Ex. 12.00 at 15-16).

2) The CERA Report and Other Industry Information

At the time the contract with Enron NA was being negotiated, there was some speculation in the industry that basis would decline dramatically. (North Shore Ex. C at 7). Information, such as a report issued by the Cambridge Energy Research Associates, (“CERA”) was available to North Shore decision-makers at the time it was negotiating the GPAA indicated that basis would decline. The CERA Report, however, contains information about the value of basis declining in locations that are not pertinent to North Shore. (Staff Exs. 12.00 at 17; 7.00 at 25).

Mr. Graves testified that Dr. Rearden’s calculations of basis were incorrect because several scenarios were possible, given the information that was known to persons in the industry, and some of those scenarios suggest that the GPAA could have a net savings with respect to the basis-variable transportation cost component. ( North Shore Ex. F at 41-44. Mr. Graves admitted that whether the GPAA would “pay off” for North Shore was not a certainty. ( North Shore Ex. F at 43). There is no evidence indicating that decision-makers or anyone else at North Shore considered the CERA Report or other industry data indicating the possibility of a steep decline in basis, when deciding to enter into the GPAA.

3) A Liquidity Premium

A liquidity premium is an adjustment made in order to take into account the fact that North Shore, when buying large amounts of gas, can be required to buy gas to meet the needs of consumers, irrespective of market conditions. In other words, in such a situation, North Shore must meet consumer needs; it cannot wait until gas prices fall. (North Shore Ex. H at 5). Mr. Graves opined that, when calculating basis, a liquidity premium must be used. (See, North Shore Ex. F at 19). Mr. Rodriguez used a liquidity premium when he prepared the “Aruba Analysis.” Using .5% of the Henry Hub price, Mr. Graves determined that a liquidity premium reduced Dr. Rearden’s calculated delivered price of gas, versus the citygate cost disadvantage, by $5.7 million. ( North Shore Ex F at 19). Mr. Graves never stated why he determined that .5% was the correct amount of his liquidity premium.

Dr. Rearden opined that a liquidity premium should not be used. He pointed out that while in some instances, North Shore may be subject to increased prices due to its need to purchase gas, the converse is also true. That is, a large purchaser, such as North Shore, can have a superior ability to buy gas below that which other buyers pay. (Staff Ex. 12.00 at 13).

4) Unquantifiable Benefits

According to North Shore, the GPAA also provided certain unquantifiable benefits. In September of 1999, Enron NA was a large company that dominated the marketplace. It was a well-established gas supplier. Pursuant to the GPAA, Enron NA supplied PGL, North Shore’s affiliate, with some technical support, such as a secure webpage that allowed PGL and Enron NA to exchange information about daily activity, a database on weather, and training regarding hedging instruments, like energy derivatives and options. (North Shore Ex. D at 8-9). However, there is no evidence that North Shore or PGL’s employees ever used any of these services. Because neither company traded options or derivatives at all during the time period in question, PGL’s employees never used the training regarding options and derivatives for the benefit of ratepaying consumers. There is also no evidence that PGL’s use of these benefits would confer a benefit on North Shore.

2. Conclusions of Law

Staffs proposed a total cost disallowance for the GPAA is $1,713,720. This represents $1,519,090 for increased costs due to citygate versus field-delivered gas; $250,823 for foregone demand credits; $302,360 in increased gas costs for purchases under the SIQ clause; for a total of (check this)$2,072,273. From this, Staff recommends including certain offsets for amounts saved under certain provisions of the GPAA. Staff recommends subtracting $270,959 for the value of the two-cent discount, and $87,594 for saved under the DIQ clause, for a total of $358,553. (Staff Init. Brief at 38-39). Staff and the AG raise several issues regarding the prudence of the GPAA, in light of what North Shore decision-makers knew or should have known when the contract was executed.

a. Ignoring Unfavorable Economic Analyses

1) Staff’s Position

Two internal economic analyses performed just before North Shore entered into the GPAA indicated that the GPAA would raise the price of gas borne by consumers through North Shore’s PGA. North Shore witness Mr. Wear performed an economic analysis of the financial impact the GPAA that indicated a possible increase in the price of gas passed on to consumers in the amount of $50 million for the four-year period he analyzed. (Wear Cross Exhibit 1). Mr. Rodriguez’s “Aruba Analysis” determined the extra costs imposed on consumers to be in a range between approximately $19 million and $24 million. (Group Ex. 1 at ST-PG-1-25).

According to Staff, the GPAA is imprudent because North Shore failed to conduct any analysis of the economic impact of the GPAA prior to its execution. The two analyses that existed established that the GPAA would be more costly than North Shore’s supply purchasing practices in previous years. Nevertheless, North Shore ignored these analyses and entered into the GPAA. (Staff Init. Brief at 26).

Staff posits that North Shore presented no evidence that it considered any alternative to the GPAA or that it conducted any competitive bidding process, which was a dramatic departure from its gas-buying practice in prior years. (Staff Init. Brief at 26). Prior to the GPAA, North Shore purchased gas in the field and paid for transportation to the Chicago citygate. In contrast, the GPAA represented 64% of North Shore’s system supply purchases for the time period in question. Another major difference between the GPAA and North Shore’s previous supply contracts was the length of the contract. The GPAA was a five-year contract. Typically, North Shore’s gas supply contracts ranged from four months to five years in duration. (Id. at 26-28). Thus, Staff argues that a change in purchasing method requires evidence, perhaps in the form of a request for proposal (“RFP”) or in the form of an economic study, establishing the prudence of North Shore’s decision to enter into the GPAA. (Id. at ). Staff views the lack of any qualitative analysis supporting the GPAA as indicia of imprudence.

2) North Shore’s Position

North Shore concedes that Mr. Wear “may have looked at the economics of the GPAA.” It asserts that Mr. Wear was “unable to testify about the substance” of his analysis, or, with whom he may have discussed this analysis. According to North Shore, Mr. Wear’s analysis (Wear Cross Ex. 1) showed that the characteristics of the GPAA were, in fact, increasingly favorable over the four-year period Mr. Wear analyzed. North Shore argues that this exhibit showed directionally improving results, when comparing the last year of historical figures used for comparison purposes (1999) in that document with the fourth year the GPAA would be in effect. From this single year of a four-year comparison, North Shore asserts that its expectations with regard to the effect of declining basis were correct. North Shore also asserts that its Ex.8, which was prepared by Mr. Wear, establishes that the GPAA would beneficial to consumers. (North Shore Init. Brief at 43-45).

North Shore Exhibit 8 compares North Shore’s actual monthly gas costs for the two fiscal years before the GPAA (1998 and 1999) to the monthly gas purchase volumes, using the citygate indices in the GPAA. It shows that North Shore’s actual average total purchases of gas cost to be $0.0287 per MMBtu more than a comparable Chicago citygate index price, weighted with 35% of purchases at a daily index price and 65% at the FOM index price. (See, North Shore Ex. C at 27). According to Mr. Wear, North Shore decision-makers did not consider the type of analysis in North Shore Exhibit 8 to be the definitive way to assess the GPAA. (Id.).

North Shore further claims that the Commission should not consider the “Aruba Analysis” because North Shore decision-makers did not consider it when deciding to enter into the GPAA. Also, the “Aruba Analysis” is not consistent with conclusions drawn by North Shore’s expert, Mr. Graves, after the GPAA was executed. (North Shore Init. Brief at 45, footnote 44). North Shore maintains that Staff and the AG place far too much emphasis on the “Aruba Analysis” and Wear Cross Ex. 1, as there is no evidence that North Shore decision-makers were privy to these analyses. Further, even though North Shore did not object to admission of the “Aruba Analysis” into evidence at hearing, Staff could have but did not, subpoena Mr. Rodriguez to testify at hearing. (Id.).

 

Both Staff witnesses Dr. Rearden and Mr. Anderson criticized North Shore for not implementing an “RFP” bidding process and not relying on a written qualitative analysis when electing to execute the GPAA. This does not demonstrate North Shore’s imprudence. RFPs are most beneficial for evaluating contracts with a narrow scope. RFPs require time to issue and evaluate the responses, especially since bidders often offer customized features in their bids. The GPAA was too complex to conform to an RFP. (North Shore Init Brief at 43).

In its Reply Brief, North Shore argues that Staff and the AG’s insistence that North Shore should have performed an economic analysis before executing the GPAA represents an attempt to establish a particular means for establishing prudence rather than applying a broad standard. Prudence requires North Shore to demonstrate that the GPAA was “reasonable” based on the information available to North Shore at the time of the GPAA’s execution. Over the course of the nine months prior to the execution of the GPAA, which included the RFQ, North Shore evaluated the qualifications of potential suppliers and the impact of the Commission’s decision in Docket 98-0820. This evaluation process demonstrates the prudence of the GPAA. (North Shore Reply Brief at 13-15).

Also in its Reply Brief, North Shore disputes the AG’s assertion that Mr. Wear should not be considered a credible witness. Mr. Wear first saw Wear Cross Exhibit (a one page document) on the witness stand, where he stated that he did not recall creating the analysis performed therein. No one should be surprised by this since it was created six years prior to hearing. (North Shore Reply Brief at 13).

3) The AG’s Position

The AG states that the GPAA represented a dramatic departure from North Shore’s previous buying practices. Through the GPAA, North Shore agreed to purchase a large portion of its supply from one supplier for a period of five years. Before the GPAA, North Shore purchased gas from several suppliers in a series of small volume contracts with durations of four months to five years. Yet for this single large cost item, North Shore claims it performed no quantitative analysis to determine whether the GPAA was an economically advantageous proposition for PGA customers. (AG Init. Brief at 12-13).

North Shore’s claim that the GPAA was too complex to analyze leads one to question why a prudent utility would enter into such a contract. A company with North Shore’s sophistication and affiliations should possess the ability to perform some type of economic analysis. The existence of the Aruba Analysis and the Wear Cross Exhibit belie North Shore’s claims. The AG argues that entering into the GPAA in the face of two analyses indicating that the GPAA would raise gas costs was imprudent. (AG Init. Brief at 12-17).

The AG calls into question the credibility of North Shore Witness Wear. The AG points out that Wear Cross Ex. 1 impeached Mr. Wear’s testimony stating North Shore performed no economic analysis of the GPAA. The Wear Cross Ex. 1 is a one page document, prepared by Mr. Wear, showing a quantitative analysis of the monetary effects of the GPAA, which turned out to be unfavorable. (AG Init. Brief at 13-15).

The AG avers that Wear Cross Ex. 15 and the “Aruba Analysis” establish that entering into the GPAA would increase the cost of gas borne by consumers. North Shore produced no analyses made at the time the GPAA was entered into indicating that that the GPAA would not increase the cost of gas. The AG contends that, because contemporaneous analyses were performed that demonstrated the imprudence of the GPAA, North Shore’s justifications of its failure to conduct a favorable economic analysis are no longer relevant, except to demonstrate a lack of credibility. (AG Init. Brief at 13-15).

4) Commission Analysis and Conclusions

After the ALJ reopened discovery in this matter, two economic analyses of the GPAA, performed by employees of North Shore/PEC¹⁷, magically emerged. These analyses are the Wear Cross Ex. 1 and the colorfully titled “Aruba Analysis.” While these analyses did not evaluate all of the cost terms of the GPAA, both analyses indicated that the GPAA would cause gas prices borne by consumers to increase.¹⁸ 

The “Aruba Analysis” included a liquidity factor and it had two different scenarios regarding a decline in basis. Under both of these scenarios, the GPAA increased the gas costs that are borne by consumers. In the face of these unfavorable analyses, and with no other information indicating that the GPAA would not increase consumer costs, North Shore chose to execute the GPAA. This alone gives the Commission pause when considering the prudence of North Shore’s decision.

 

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¹⁷  The Commission notes that these analyses were conducted using certain terms of PGL’s GPAA, which is the subject of Docket No. 01-0707. The people who conducted these analyses hold the same positions within North Shore and PGL.

¹⁸  The “Aruba Analysis” included transportations costs and basis. Wear Cross Ex. 1 merely compared past base gas prices with the base prices in the GPAA. Neither one of these analyses covered such items as the economic impact of the DIQ clause, the possible effects of Enron changing the price of baseload gas pursuant to the GPAA, and various other provisions that had an obvious impact on the price of gas borne by consumers. (Wear Cross Ex. 1; Staff Group Ex. 1 at ST-PG-1-25).

The Commission notes that North Shore’s error is not in failing to perform a certain type of study or in failing to solicit a certain type of bid. Rather, North Shore error is its lack of evidence indicating consideration by its personnel of the economic impact of the GPAA on consumers when the GPAA was executed. We agree with the AG that the importance of North Shore’s assertions that it should not be required to conduct an economic analysis has to do with credibility, given the fact that there were unfavorable economic analyses.

While the Commission does not require utilities to perform any particular type of analysis or bidding process, we do require utilities to provide evidentiary support demonstrating the prudence of all gas supply contracts for which the costs are passed on to PGA customers. Here, North Shore embarked on an encompassing venture with Enron North America when it executed the GPAA. At the time of execution, the GPAA governed approximately two-thirds of North Shore’s gas supply for a period of five years. North Shore had an obligation, pursuant to statute, to mitigate rising gas costs. (220 ILCS 5/9-220). Yet, here, North Shore presented no evidence that its decision-makers made any attempt to consider the effect of the costs it incurred through the GPAA on ratepaying consumers. What we are requiring is that utilities must be able to prove that their expenditures were not, as was often the case here, money spent unnecessarily. (See, e.g., the portions of this Order concerning the impact of foregone demand credits, and the economic impact of the SIQ provision in the GPAA).

While North Shore cites its Exhibit 8, prepared by Mr. Wear, as evidence of economic analyses of the GPAA, this document does not aid it. There is no evidence in this record establishing that North Shore Ex. 8 was created at the time the decision was made to enter into the GPAA. Therefore, it is not probative as to what North Shore decision-makers consulted, or should have consulted, when entering into the GPAA. Similarly, Mr. Graves’ conclusions were drawn after the time North Shore entered into the GPAA, and his testimony does not establish what information decision-makers at North Shore considered when entering into the GPAA.

North Shore’s assertion that Wear Cross Exhibit 1 establishes that its expectations with regard to the effect of declining basis were correct is without merit. North Shore overlooks the fact that, in Wear Cross Exhibit 1, Mr. Wear did not analyze basis. He merely compared North Shore’s historical purchases of gas with four years of previous gas purchases North Shore made (from October, 1995 to September, 1999) using GPAA purchase prices, like FOM minus three cents per MMBtu¹⁹. (Wear Cross Ex. 1). Mr. Wear’s analysis proves nothing with regard to the impact of basis and the GPAA.

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¹⁹  The Commission reiterates its recognition that Mr. Wear performed his analysis using PGL’s GPAA terms.

Mr. Wear projected an approximate loss of $50 million over the four-year period he analyzed. Mr. Wear also projected a gain calculated in the fourth year (1999) of $10,920,308. (Id.). North Shore does not explain how incurring a loss of $50 million over four years is offset by approximately $11 million in the last of one of these four years.

The record evidence shows that Mr. Wear was not a credible witness. At hearing, he often evaded answering the questions asked of him, and many times he changed his testimony in significant ways. Mr. Wear also contradicted his own testimony on several occasions. Additionally, Mr. Wear often made factual conclusions without stating the factual foundation for those conclusions. This Commission need not consider factually unsupported conclusions of fact. (Fraley v. City of Elgin, 251 Ill. App. 3d 72, 77, 621 N.E.2d 276 (2^nd Dist. 1993)).

        Furthermore, Wear Cross Exhibit 1 impeached Mr. Wear’s credibility, as Mr. Wear stated that no economic analysis was performed. However, Wear Cross Ex. 1 established, at a minimum, that Mr. Wear created a document on his computer approximately one week before North Shore executives signed the GPAA. (Wear Cross Ex. 1; Staff Ex. 2.00, GPAA). Any statement made by Mr. Wear that he did not recall Wear Cross Ex. 1, or that he did not recall with whom he spoke regarding this document is not credible.

The Commission concludes that North Shore presented no evidence establishing that it had a prudent reason for ignoring these two unfavorable analyses. Mere statements that decision-makers did not consider these analyses do not absolve North Shore from its obligation to incur only those costs that are prudently incurred. (220 ILCS 5/9-220). And, any objection North Shore had to the failure of Staff to subpoena Mr. Rodriguez should have appeared at hearing. It cannot do so now. (See, e.g., People v. Robinson, 157 Ill. 2d 68, 79, 623 N.E.2d 352 (1993); Fleeman v. Fischer, 244 Ill. App. 3d 753, 755-56, 244 N.E.2d 836 (5^TH Dist. 1993)).

It is unfathomable to the Commission that North Shore executed the GPAA when at least two analyses showed an increase in costs to PGA customers. It would seem that any negative attributes of a supply contract would be an integral part of the decision-making process, especially given that Commission rules require North Shore to “refrain” from actions that lead to an increase in costs for consumers. The fact that North Shore decision-makers did not consider them actually shows that North Shore acted imprudently when entering into the GPAA. Failure to consider what increases in gas costs, actual or potential, as a result of entering into the GPAA, constitutes an exercise in judgment outside the standard of care that a reasonable person would be expected to exercise under the same circumstances encountered by utility management at the time decisions had to be made. North Shore’s decision was, therefore, imprudent. (Illinois Power, 245 Ill. App. 3d at 371).

Several of North Shore’s other arguments greatly disturb the Commission. North Shore would have the Commission believe that it carefully evaluated its decision to procure gas supplies from Enron NA because on an RFQ process, therefore no economic analysis was necessary. North Shore completely revamped its purchasing practices when it decided to procure two-thirds of its supply needs through a long-term contract with one supplier. Setting aside the stigma associated with the Enron name, it makes no sense to the Commission why North Shore would embark on such a dramatic change without completely analyzing the potential effects on PGA customers. Furthermore, North Shore paradoxically argues that the complexity of the GPAA defies economic analysis. This argument clashes with North Shore’s apparent attempt to simplify its purchasing practices by using the GPAA. The Commission agrees with the AG that North Shore is sophisticated enough to undertake such an analysis. If the complexity of GPAA truly defies economic analysis, the Commission questions why North Shore would agree to it in the first place. One would think North Shore would want to know what it is getting itself into, for its own financial well-being as well as that of the ratepayers.

To reiterate, the Commission finds North Shore’s decision to execute the GPAA in the face of two unfavorable analyses to be imprudent. Disallowances based on the specific increases in costs caused by North Shore’s imprudent decision will be discussed in detail below.

 

                            1) Staff’s Position

Staff contends that Articles 4.2(b) and 4.2(c) of the GPAA allowed Enron NA to unilaterally increase the price of baseload gas in wintertime. Staff acknowledges that no harm actually resulted from these two clauses, as Enron NA never actually changed the price of gas pursuant to these two clauses during the reconciliation period. Staff avers that it was imprudent for North Shore to enter into a contract, pursuant to which a supplier could increase the amount of money charged. This holds especially true for baseload gas, which North Shore needs to meet customer demands. (Staff Init. Brief at 33). Staff seeks no disallowance. (Id.).

                            2) North Shore’s Position

North Shore acknowledges that Articles 4.2(b) and 4.2(c) clauses allowed Enron NA to choose to price up to 45,000 MMBtus per day of the baseload quantity at a daily price, rather than the FOM price, during December through March. It argues that the emphasis on the existence of these clauses is misplaced because Enron NA never invoked these clauses. (North Shore Reply Brief at 21).

                            3) The AG’s Position

The AG also takes note of these provisions that would allow Enron NA to unilaterally change the price of portions of baseload gas. With these provisions, Enron NA could track the market and use the price that was to its advantage. North Shore’s grant of unilateral pricing changes was imprudent. (AG Init. Brief at 28-29).

                            4) Commission Analysis and Conclusions

The Commission agrees with Staff and the AG that facts were known to North Shore decision-makers at the time the GPAA was negotiated establishing that these clauses could have resulted in harm to ratepaying consumers. A simple review of these two clauses in the GPAA would have revealed that Enron NA could have imposed unnecessary costs on consumers. Baseload gas is critical for North Shore to meet the demands of its customers. It is, therefore, a critical amount of gas. Because North Shore is required by law to pass on only those costs that are prudently incurred, price of baseload gas (or any supply of gas) should always be a concern for North Shore. (220 ILCS 5/9-220). Yet, conspicuously absent from this record is evidence that anyone at North Shore was concerned that Enron NA could increase the price of gas, if Enron NA decided to do so.

The Commission finds that North Shore acted imprudently by entering into a contract with two provisions that allowed Enron NA to increase the price of baseload gas, which is the quantity of gas North Shore needs to satisfy its customer demands. However, Enron NA did not actually invoke its rights pursuant to these provisions. No harm to ratepaying consumers actually occurred. The fact that Enron NA did not invoke these clauses only has to do with the level of economic harm North Shore caused by failing to analyze the GPAA. It is simply imprudent to enter into a contract with these provisions when the potential for harm is so patent.

c. Baseload, SIQ and DIQ Gas

                            1) Staff’s Position

Staff argues that the baseload, SIQ and DIQ gas clauses lend further support for finding the GPAA to be imprudent.

North Shore indicated that it established baseload requirement through negotiations with Enron NA and did not necessarily reflect demand. North Shore stated that baseload quantities included in the GPAA were similar to baseload purchases prior to the existence of the GPAA. Finally, North Shore claimed that baseload quantities were based on normal weather conditions, although daily and monthly purchases might be based on other factors. According to Staff, none of North Shore’s explanations justify the contracted amount of baseload included in the GPAA. (Staff Init. Brief at 22-23).

Baseload requirement represent the portion of customer demand that a gas utility can take on its system. If a gas utility purchase baseload based on normal weather conditions, its goal is to obtain supplies that meet the load requirements of its customers. Sound business practice dictates that North Shore would provide some sort of study or analysis to support its decision to use normal weather conditions to establish baseload requirements. North Shore did not do so here. Staff believes North Shore to be unreasonable in committing to purchase baseload requirements without first analyzing the needs of its customers. (Staff Init. Brief at 24-25).

Pursuant to the SIQ provision, Enron NA chose the amount of gas it delivered to North Shore during the summer period defined in the GPAA. Enron NA sold SIQ gas to North Shore at the FOM price less a two-cent per MMBtu discount. However, the GPAA enabled Enron NA to force North Shore to purchase maximum SIQ volumes of gas when the Gas Daily price was less than the FOM price. According to Staff, Enron could, and did, deliver large amounts of SIQ gas to North Shore when the FOM price was higher than the daily price, which forced North Shore to buy gas it did not need at a higher price than what was available in the marketplace at the daily price. Staff estimates that 96% of the time Enron NA supplied North Shore with the minimum amount of SIQ gas, North Shore needed to find supplies to replace the reduced SIQ volume. Staff argues that it was imprudent for North Shore to allow Enron NA to determine how much gas North Shore would receive. (Staff Init. Brief at 25).

Staff sets forth that DIQ gas was sold at daily prices, which are usually higher than FOM prices, with no discount. Thus, when the daily price was above the monthly price, Enron NA had the incentive to deliver the minimum SIQ volumes allowed by the GPAA. By merely delivering a small amount of SIQ gas, Enron NA forced North Shore to purchase the remainder of what it needed, either through the DIQ clause, or from another source at the higher daily prices. In other words, when Enron NA elected not to sell the full 10,000 MMBtus of gas to North Shore, and if North Shore needed that amount of gas, North Shore would be required to purchase gas at a higher cost. North Shore submitted evidence establishing that on only 6% of the days in which Enron NA made such a decision, Enron NA did not manipulate the difference between the daily price and the FOM price. (North Shore Ex. H at 10). On only 4% of the time when Enron NA provided the minimum SIQ, North Shore did not replace that difference with gas purchased at the higher-priced daily index. (Id. at 11). Staff determined that the SIQ increased consumer costs during the year in question in the amount of $302,360, which represents the difference between the daily price index and the FOM index price, times incremental SIQ gas volumes. (Staff Init. Brief at 24-25).

2) North Shore’s Position

North Shore contends that the SIQ provision in its GPAA was prudent because relinquishing control over how much SIQ gas was delivered to it was done in exchange for the two-cent discount. (See, e.g., North Shore Init. Brief at 15). According to Mr. Wear, the three-cent per MMBtu discount in both the baseload clause and the SIQ clause saved consumers $2.7 million.²⁰ ( North Shore Ex. C at 16).

North Shore argues that Staff and the AG exaggerate the effect of the SIQ provision which North Shore acknowledges “allowed Enron some control over the timing and amount of gas sold to North Shore under the GPAA.” (North Shore Reply Brief at 25). North Shore points out that Enron NA had no control over the amounts of its higher-priced purchases pursuant to the DIQ clause. Also, citing Staff’s Initial Brief and Mr. Anderson’s testimony, North Shore argues that Enron NA never forced North Shore to take the maximum amount of SIQ gas. (Id.).

3) The AG’s Position 

The AG commented on both the SIQ and the DIQ clauses. The AG states that the SIQ clause virtually guaranteed Enron NA would benefit anytime the Daily Price was below the FOM price. And depending on how Enron NA structured its own purchasing commitments, Enron NA would benefit even if the Daily Price was above the FOM. The AG further states that the DIQ clause merely gave North Shore the same access to the spot market that it already had-- the same access that all buyers have. (AG Init. Brief at 29-30).

4) Commission Analysis and Conclusions

As an initial matter, the Commission agrees with Staff that North Shore should have performed some sort of analysis to determine its baseload requirement prior to executing the GPAA. Contracting for baseload requirements without an idea as to what demand might be defies logic. The Commission notes that no party proposes a disallowance for the baseload provision of the GPAA. However, we find North Shore simply acted imprudently by not performing a quantitative analysis.

The Commission will now consider the effects of the SIQ and DIQ clauses. Normally, price and amount are essential terms in a contract. (See, e.g., Butler v. Butler, 275 Ill. App. 3d 217, 225-29, 655 N.E.2d 1120, (1^st Dist. 1995), upholding refusal to grant specific performance when the contract that the plaintiff sought to enforce did not have a specific price). Mr. Wear testified that having an oversupply can produce undesirable consequences for North Shore. Yet, the SIQ provision relinquished North Shore’s control over the amount of gas North Shore would receive, on any given day, to Enron NA.

 

 

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²⁰  Mr. Wear conducted his analysis of the SIQ clause in PGL’s GPAA, which included a three-cent per MMBtu discount. No such analysis was performed of North Shore’s SIQ clause.

It defies logic to contend, on the one hand, that the GPAA was prudent, yet on the other hand to contend that an oversupply was undesirable. The record clearly demonstrates that the SIQ clause not only created an oversupply, but created an oversupply beyond North Shore’s control. Without control over the amount of gas Enron NA delivered to North Shore on any given day, it is difficult to imagine how North Shore could effectively plan how to meet its responsibilities. Too little gas, also, would bring about undesirable consequences, as it would require North Shore to buy gas at the higher DIQ price from Enron NA, or elsewhere at a daily price. The SIQ clause allowed Enron NA to force North Shore to pay more for gas when Enron NA manipulated the difference between the price in the SIQ clause and the DIQ clause. And, there is simply no evidence substantiating North Shore’s claim that this provision would be offset by the two-cent discount. The Commission finds this provision to be imprudent.

North Shore’s reference to Staff witness Mr. Anderson’s testimony in support of its claim that Enron NA never forced North Shore to take maximum SIQ gas is taken out of context. So is its reference to Staff’s Initial Brief in support of its contention that Enron NA never forced North Shore to take the maximum amount of SIQ gas. In fact, Staff argued on page 25 of this Brief that when Enron NA delivered only the minimum SIQ gas, North Shore was required to find volumes to replace SIQ gas. Staff averred that Enron NA forced North Shore to take minimum volumes approximately 96% of the time. (Staff Init. Brief at 25).

The Commission notes that Section 4.5 of the GPAA allowed North Shore to renegotiate the price of gas, if North Shore were to discontinue use of a PGA rider and therefore would no longer be directly passing the price of gas directly on to consumers. (Staff Ex. 2.00, Attachments, GPAA, Par. 4.5). The existence of this clause is some indicia that if the prices in the GPAA were not passed on directly to consumers, North Shore would not find those prices to be satisfactory. If, however, North Shore were required to account to its shareholders for those costs, the prices would be re-negotiated. This is further evidence that North Shore did not have its customer’s best interests in mind when negotiating the GPAA.

d. Foregone Demand Credits

1) Staff’s Position

Staff contends that, by releasing pipeline capacity pursuant to the GPAA, North Shore surrendered its ability to engage in demand-credit transactions. Before the GPAA, North Shore obtained revenues that were flowed through its PGA, offsetting costs passed on to consumers. These revenues were obtained in two ways. Either North Shore released pipeline capacity, earning a fee, or it engaged in demand credit transactions, in which, it purchased gas at one point in a pipeline and sold it at another. The margin on such a sale covered other demand charges imposed, which reduced the costs passed on to consumers in the PGA. Staff maintains that releasing this pipeline capacity unnecessarily increased consumer costs. (Staff Ex. 3.00 at 34; Staff Init. Brief at 32).

2) North Shore’s Position

North Shore asserts that it is not possible to calculate the demand credits it would have earned, if it had not entered into. It contends that there are many unpredictable factors in these types of transactions.

3) Commission Analysis and Conclusion

Even assuming that North Shore is correct in its contention that it is not possible to determine the amount of foregone demand credits with certainty, North Shore was imprudent in relinquishing the revenues and credits from the pipeline capacity to Enron NA with no benefit conferred upon consumers as a result of this relinquishment. Record evidence establishes that the pipeline capacity North Shore ceded to Enron NA, pursuant to the GPAA generated income before the GPAA was executed. (North Shore Ex. C at 21; Staff Ex. 3.00 at 34). After the GPAA was executed, this pipeline capacity generated no income. And, it would have been obvious to North Shore that this capacity could generate no income. (Staff Ex. 2.00, Attachments, GPAA, Art. 4.3). The Commission finds the inclusion of this component in the GPAA to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for this provision is included in the Settlement Agreement and Addendum.

e. Penalties for Resales of Gas

1) Staff’s Position 

Dr. Rearden opined that the existence of this provision is indicia that North Shore expected to have an oversupply. However, since North Shore did not resell gas to Enron NA, Staff’s recommended disallowance is $0.

2) North Shore’s Position

North Shore argues that the resale provision, even with its penalties, was beneficial. An oversupply creates significant issues, as it is difficult to unload large amounts of gas, and, an oversupply can create an overpressure situation. (North Shore Init. Brief at 36). North Shore maintains that Staff continues, wrongfully, to characterize the financial onus imposed by the GPAA on consumers whenever North Shore resold gas to Enron North America as a “penalty.” According to North Shore, Staff ignored the dynamics of the marketplace. Also, Dr. Rearden incorrectly assumed that when selling gas, one can always find a bid that is no worse than the daily midpoint price. According to Mr. Wear, Dr. Rearden incorrectly assumed that the amount of gas being sold, the weather, supply surpluses and the number of sellers exceeding the number of buyers would have no bearing on the price of gas. (North Shore Ex. D at 15-18). Mr. Wear opined that this provision was really a standing bid for a quantity of supply that would likely be executed under supply surplus conditions, which is rare. (North Shore Ex. D at 15, 19).

3) Commission Analysis and Conclusion

North Shore asserts that unloading excess gas can be a very difficult task. However, to counteract the difficulties encountered by an oversupply, a reasonably prudent person would have placed himself in a position in which an oversupply is rare. If North Shore personnel were truly concerned with the detrimental effect of an oversupply, logic would dictate that it would not have allowed Enron NA to control the amount of SIQ gas that it received on a daily basis.

Mr. Wear’s testimony regarding one single two-year contract with an unnamed supplier for an unspecified amount of gas does not aid North Shore. Mr. Wear mentions but one contract, which is not an industry-wide practice. There is no evidence that this unspecified contract contained provisions like the SIQ clause in the GPAA which forced North Shore to accept excess gas. Finally, there is no evidence that this unnamed contract involved the supply of 64% of North Shore’s total intake of gas, which is the situation here. North Shore did not establish that the potential to pay penalties on any resales of gas to Enron NA was beneficial. The Commission agrees with Staff that the existence of this provision is indicia that North Shore personnel knew that the GPAA would cause an oversupply; this provision is a mechanism to handle that oversupply. The existence of this provision lends further support to the Commission’s finding of imprudence for the GPAA.

f. Released Pipeline Capacity 

1) Staff’s Position

Staff argues that, when North Shore released pipeline capacity to Enron NA, it surrendered an item for which consumers paid for through the PGA. However, Staff recommends no specific disallowance for this provision. Staff estimates that the cost to ratepayers for this component is zero since the data do not indicate large changes in demand credits after the GPAA was signed. (See, Staff Init. Brief at 32).

2) North Shore’s Position

North Shore released pipeline capacity to facilitate gas purchases at the Chicago city gate. FERC rules require that when pipeline capacity is released, the released shipper receives a credit on its pipeline invoice in an amount equal to the charges paid by the replacement shipper. Pursuant to the GPAA, Enron NA paid North Shore whatever North Shore was required to pay the pipelines. (See, 18. C. F. R. 284.8(f); North Shore Init. Brief at 16).

3) Commission Analysis and Conclusions

The regulation cited by North Shore provides that:

 

 

unless otherwise agreed to by the pipeline, the contract of the shipper releasing capacity will remain in full force and effect, with the net proceeds from any resale to a replacement shipper credited to the releasing shipper’s reservation charge.

(18 C.F.R. 284.8(f)). Thus, this regulation contemplates a situation akin to a tenant’s sublease, in which the subleasing tenant actually pays the landlord, as the subleasing user of the pipeline pays the pipeline. However, it is not disputed that pursuant to the GPAA Enron NA has the responsibility to pay shippers. Rather, Staff has maintained that because the GPAA required North Shore to reimburse Enron NA for those charges, North Shore still paid those pipeline charges. (See, e.g., Staff Ex. 2.00 at 18, 20). 18 C.F.R. 284.8(f) is therefore not relevant.

 

North Shore bears the burden of proof here, which it failed to meet. It did not provide evidence at trial establishing that the pipeline capacity it released was not paid for by consumers pursuant to the terms in the GPAA. Enron NA had use of that pipeline capacity for its own business purposes above and beyond facilitating supply to North Shore. Enron NA paid nothing for the use of that pipeline. (Staff Ex. 2.00, Attachments, GPAA, Arts. 6.1, 6.4). The Commission concludes, therefore, that this clause also was imprudent.

g. Eroding Basis

1) North Shore’s Position

The cost of transporting gas to Chicago is passed on to consumers in North Shore’s PGA. (83 Ill. Adm. Code 525.40(a)). Based on Mr. Wear’s and Mr. Graves’ testimony about an industry concern regarding the impending decline in pipeline transportation value, North Shore contends that it entered into the GPAA to protect itself, and therefore consumers, from a decline in the value of North Shore’s preexisting transportation contracts (“basis”). Because more pipelines were being built to Chicago, people in the industry began to speculate that there would soon be excess pipeline capacity, causing the value of pipelines to decrease.

It is not contested by any party that, if basis shrunk enough, it would be less expensive to buy gas at the citygate price than to buy it in the field and pay to transport it. (North Shore Init. Brief at 33-35). Also, as basis declined, so would North Shore’s revenues from “optimizing” transportation assets. According to Mr. Wear, purchasing gas at the citygate price, as well as the two-cent discount on baseload and SIQ gas, offset the impact of a decline in basis. Citing this testimony, North Shore argues that the two-cent discount “guaranteed” value for its transportation assets and offset the expected decline in basis. (North Shore Init. Brief at 33-35).

2) Staff’s Position

Staff maintains that buying gas at the citygate price, as opposed to buying it in the field, and delivering it, increased the price of gas in the amount of $5,5676,986. (Staff Ex 7.02). Staff argues that North Shore did not demonstrate that the GPAA preserved the value of transportation assets against a falling basis of its transportation contracts. Staff avers that North Shore negotiated new pipeline contracts in September of 1999, just before it executed the GPAA. If North Shore decision-makers were truly concerned about the decline in basis, they could simply have renegotiated those pipeline contracts to reflect the decline in market value of those contracts, but they did not. (Id. at 16-19).

Staff points out that North Shore had other options available to it that would offset the effect of eroding basis. Utilities often shift the load between pipelines to negotiate lower transportations costs. In fact, North Shore has used this practice in the past. However, North Shore presented no evidence that it considered this alternative before it executed the GPAA. (Staff Init. Brief at 16-19). Staff states that it is not requiring North Shore to investigate these two alternatives. Instead, the evidence indicates that North Shore did not even consider alternatives available to it when negotiating the GPAA. Staff contends that the strategic partnership between PEC, Enron NA and affiliates is the real reason North Shore entered into the GPAA. (Id. at 19).

Staff also argues that the GPAA did not offset any decline in basis because it caused North Shore to pay twice for transportation. Consumers paid once for delivery of gas to the citygate, and again when the GPAA required it to release transportation capacity to Enron NA at no cost to Enron NA. (Id.).

Staff avers that there is no evidence that North Shore decision-makers actually contemplated a steep decline in basis when the GPAA was signed. Staff contends that North Shore failed to present evidence that before signing the GPAA, North Shore conducted an evaluation of the probability of a steep decline in basis. (Staff Reply Brief at 27).

3) Commission Analysis and Conclusions

North Shore professes to be concerned about the value of preexisting transportation contracts. However, the record indicates otherwise. The terms of the GPAA contract actually increased the cost of transportation that was passed on to consumers. Pursuant to the GPAA, North Shore relinquished pipeline capacity to Enron NA to “facilitate the citygate supply relationship.” (North Shore Ex. C at 2). Consumers also paid the citygate price of gas, which includes the cost of transportation to Chicago. North Shore does not explain how the GPAA could offset a decrease in previously contracted-for transportation costs when consumers actually paid twice for transportation. Nor is it obvious. In contrast, Dr. Rearden’s testimony established that the GPAA increased gas costs to a point at which purchasing gas at the citygate prices, even with the two-cent discount, did not offset the decline in basis.

Further, the evidence did not establish that the citygate prices and the two-cent discount on baseload and SIQ gas actually protected North Shore, and thus consumers, from declining basis. This is true because, as previously set forth herein, North Shore had no control over the amount of SIQ gas it received pursuant to the GPAA. The presence of the SIQ clause and other clauses previously mentioned herein, which increased the price consumers paid for gas, eroded the value of the two-cent discount to the point of non-existence. Given the amount of extra costs that the GPAA imposed, it makes no sense to focus on basis without looking at the substantial increases in costs that the GPAA imposed.

North Shore contends that it did not consider any other economic aspect of the GPAA, such as the interplay between the SIQ and DIQ provisions. In so arguing, North Shore merely admits that its decisions-makers did not act in a manner in which a reasonable person would under the same circumstances encountered by utility management at that time. (Illinois Power, 245 Ill. App. 3d at 371). In other words, in so arguing, North Shore admits that it entered into the GPAA imprudently. (Id.).

North Shore cites no authority, and indeed, there is none, that allows utilities to engage in contracts that pass on costs to consumers without considering the effect of those costs on consumers. When determining whether the provisions in the GPAA passed on prudently-incurred costs, the Commission cannot be limited to what North Shore decision-makers claim to have considered when executing the GPAA. (Illinois Power, 245 Ill. App. 3d at 371).

There are also other reasons in this record that cast doubt on North Shore’s contention that the GPAA was entered into to protect against declining basis. Just prior to the time when North Shore executed the GPAA, it re-negotiated four pipeline contracts. (Staff Ex. 2.00 at 16-17). As Staff witness Mr. Anderson pointed out, North Shore could have simply have renegotiated transportation contracts at lower costs, since if pipeline capacity was worth less, North Shore should have been able to just pay less for it. Certainly, North Shore had other well-known and simpler alternatives available to it. Yet, there is no evidence that North Shore personnel even considered these alternatives.

North Shore argues that it could not engage in load-shifting among pipelines to reduce costs due to the nature of the pipelines with which it connects. But this does not explain why other, more commonly used methods of mitigating a decline in basis were not explored. While the Commission is not requiring North Shore to explore alternatives to the GPAA, the fact that North Shore did not explore any of these alternatives casts doubt on the credibility of its contention that the GPAA was executed to offset the effect of a decline in basis.

In sum, the Commission finds North Shore’s failure to fully evaluate its options to combat eroding basis, if indeed this was a reason to execute the GPAA, to be imprudent. Amply evidence exists showing that the costs of the GPAA far out-stripped any benefits to be gained by purchasing gas at the citygate instead of the field. Any disallowance associated with the Commission’s finding of imprudence for this provision is included in the Settlement and Addendum discussed above.

 

1) North Shore’s Position

North Shore’s expert witnesses Mr. Graves and Mr. Wear testified that, at the time the GPAA was being negotiated, there was information within the industry projecting that basis could decline sharply. (North Shore Ex. D at 7-8). For example, the Cambridge Energy Research Associates (“CERA”) issued reports in the Spring and Summer of 1999, projecting that in many parts of the United States, basis in 2000 and 2001 would be negligible.²¹ (See, e.g., North Shore Ex. F, Spring 1999 CERA Report). Based on information that existed at the time North Shore executed the GPAA, North Shore argued that when comparing basis with actual transportation costs, Staff witness Dr. Rearden improperly determined that an average decline in basis was $0.01 per MMBtu per year.²² However, North Shore admits that there is no evidence establishing that the CERA Report was considered by North Shore decision-makers when entering into the GPAA. It argues that Mr. Graves’ estimates are still valid. (North Shore Reply Brief at 28-29).

North Shore also argues that this Commission should not consider Staff’s estimate of the harm caused by the GPAA because Dr. Rearden did not use a liquidity premium in his calculations. Mr. Graves used a liquidity premium of .5 cents when calculating his estimate of harm caused by the GPAA.

Even though North Shore has repeatedly asked the Commission to ignore the “Aruba Analysis,” it contends here that because Mr. Rodriguez used a liquidity premium when preparing the “Aruba Analysis,” the “Aruba Analysis” is evidence that a liquidity premium should be used. North Shore argues that illiquidity is a phenomenon that it experiences in the field. Dr. Rearden used field prices in his basis calculations, which underestimated the actual field prices because field areas are not as liquid as trading hubs. (North Shore Reply Brief at 29-31). North Shore also argues that Mr. Graves “followed Dr. Rearden’s lead” when calculating its basis basis analysis.

_______________

²¹  At trial, none of the parties objected to the admission of this testimony and documents into evidence.

²²  North Shore stated in its Initial Brief that its review of projections for the GPAA showed that basis “likely would declining,” implying that North Shore analyzed basis when the GPAA was negotiated and projected a steep decline in basis. (See, North Shore Init. Brief at 33). However, there is no evidence in this record that the projections it cites were made when the GPAA was negotiated and are, therefore, relevant. (See, also, North Shore Ex. C. at 7, where Mr. Wear stated that the CERA Reports existed at the time when North Shore negotiated the GPAA. He never stated that anyone at North Shore actually read that report.

2) Staff’s Position

Staff maintains that there is no evidence, in this record, that any North Shore decision-maker considered steep basis projections, like those found in the CERA Study, before entering into the GPAA. Also, the locations in the CERA Study are not the same as the pertinent North Shore delivery points. Therefore, Staff concludes that the CERA Study is not relevant because the information therein is not comparable to the facts here. Mr. Graves’ projections only examined basis from a hub to the Chicago citygate, which is not an accurate depiction of the basis at issue because it does not account for transportation from the field to Hub. (Staff Ex. 12.00 at 15-17).

Staff also points out that the CERA report only contained information regarding regional markets, not delivery points such as Chicago. Thus, in order for the information in such a study to be useful, a person would have to perform calculations tying the information in that report to a delivery point on its interstate pipeline service. That was not done here. (Staff Reply Brief at 21-22).

3) Commission Analysis and Conclusions

The portion of Mr. Graves’ testimony that North Shore cites is not an analysis of the GPAA. As is set forth herein, many other clauses in the GPAA passed on unnecessary costs to consumers, or placed consumers at unnecessary risk increased gas costs. Even if the Commission were to accept North Shore’s contention that its decision-makers thought that basis could be much steeper than it was, that alone does not justify entering into many other provisions in the GPAA. A steep decline in basis would not offset the increase costs borne by consumers through the SIQ clause, foregone demand credits, paying twice for pipeline transportation to Chicago and other costs that have been set forth herein. And, a steep decline in basis does not excuse North Shore personnel from entering into a contract that contained clauses with an obvious potential to cause economic harm to consumers.

The Commission finds North Shore’s reliance on the “Aruba Analysis” as evidence of the effects of the decline in basis rather curious, if not disingenuous. First North Shore wants us to ignore it since North Shore decision-makers did when executing the GPAA. Now North Shore wants the Commission to consider the “Aruba Analysis” as evidence that North Shore’s efforts to combat eroding basis were legitimate. Interestingly, North Shore’s request does nothing to strengthen its case. In the “Aruba Analysis,” Mr. Rodriguez used a high and low projected basis. Both sets of projections indicated that the GPAA would increase consumer costs. Even including a liquidity premium, a well as a steep decline in basis, as Mr. Graves recommends, and as Mr. Rodriguez did in the “Aruba Analysis,” the disadvantages of the GPAA, in total, are not outweighed by any effect it had on declining basis. As discussed previously herein, the GPAA provisions produced many, many unwarranted costs on consumers, with no offsetting benefit to consumers.

Further, Mr. Graves never explained why he determined that the liquidity premium he used was the proper amount. Nor did he explain how he calculated the liquidity premium he used. Therefore, the Commission agrees with Staff that use of Mr. Graves’ liquidity premium is not substantiated.

As stated earlier, the GPAA actually increased the pipeline transportation costs, because consumers paid twice for transportation costs. The citygate price included the cost of transportation to Chicago; consumers paid again for the pipeline capacity North Shore released to Enron NA to “facilitate the citygate supply relationship.” Enron NA paid nothing to North Shore for the privilege of using this capacity for its own business purposes, although Enron NA only used this capacity when North Shore did not use this capacity. (See, e.g., Staff Ex. 2.00, Attachments, GPAA, pars. 6.1, 6.4, North Shore Ex. C at 42). Thus, the GPAA did not offset the effect of any decline in preexisting transportation costs.

North Shore is asking the Commission to make determinations about facts without presenting evidence that those facts were considered by its decision-makers when entering into the GPAA. In so doing, North Shore ignores the fact that we are required, by law, to consider only what decision-makers considered at the time a decision was made. (Illinois Power, 245 Ill. App. 3d at 371). There is no evidence in this record that decision-makers at North Shore knew of or should have considered, possible projections in industry publications, such as the CERA reports, as to the possible decline in basis.

Additionally, Mr. Wear’s testimony that North Shore entered into the GPAA to protect the value of this capacity is not credible. As stated earlier, Mr. Wear was not a credible witness. And, Mr. Wear did not make the ultimate decisions regarding the terms of the GPAA. There is no evidence that someone like Mr. Morrow, who executed the GPAA, considered declining basis when he negotiated this contract.

Moreover, Mr. Graves’ calculations as to basis are inaccurate. North Shore’s transportation is from the field to a hub such as the Henry Hub, in Louisiana, and then to the Chicago citygate. Yet, Mr. Graves only considered transportation from a hub to the Chicago citygate. Contrary to North Shore’s assertion that Mr. Graves “followed Dr. Rearden’s lead” and calculated basis from the Henry Hub or Ventura to the Chicago citygate, North Shore’s own brief asserts that this statement is incorrect, and states that Dr. Rearden calculated basis from the field to the pertinent Hub and then to the Chicago citygate.

i. North Shore’s Previous Reconciliation

1) North Shore’s Position 

North Shore points to its previous PGA reconciliation, Docket 00-0719, which concerned its gas purchases from October 1, 1999, through September 30, 2000, and therefore concerned North Shore’s gas purchase practices pursuant to the GPAA during the first year of its existence. In that docket, however, Commission Staff found no imprudence on the part of North Shore. (See, Ill. Commerce Commission, on its own Motion, v. Peoples Gas Light and Coke Co., 2002 Ill. PUC Lexis 912). North Shore reasons that finding the GPAA imprudent here, after having found it prudent in North Shore’s previous reconciliation, is unreasonable and such a conclusion would “stand the Commission’s prudence standard on its head.” North Shore points out that an unexplained and unsupported departure from past practice is contrary to Commission policy and Illinois case law, citing Ill. Power Co. v. Ill. Commerce Commission, 339 Ill. App. 3d 425, 790 N.E.2d 377 (1^st Dist. 2003). (North Shore Reply Brief at 6). North Shore maintains that Commission past practices may not be binding on it, but prior decisions of the Commission are not ignored by the appellate courts, and they should not be ignored by the Commission. (North Shore Reply Brief at 6-7).

2) Staff’s Position

Staff contends that allowance of a cost item in one year does not guarantee that the Commission will allow that cost item in future years, citing Governors Office of Consumer Services v. Ill. Commerce Comm., 242 Ill App. 3d 172 (1^st Dist. 1993) and Ill. Commerce Comm. on its own Motion, v. Ill. Power Co., Reconciliation of FAC and PGA Clauses, 2004 Ill. PUC Lexis 101 at *13, 16-17). Commission orders have no res judicata effect. (Staff Init. Brief at 13-44).

Section 9-220 of the PUA requires the Commission to reconcile the costs of gas purchases with costs prudently incurred. 220 ILCS 5/9-220. (See, Business and Professional People for the Public Interest v. Ill. Commerce Comm’n, 136 Ill. 2d 102, 219-220 (1990)) [in general rate cases, a test-year must be used, thus the multi-year approach taken in BPI was improper]. The fact that the GPAA contract spanned 5 years does not change the PUA’s requirement. It is plausible that the Commission to find the GPAA to be prudent in one reconciliation year, but not the next. (Staff Init. Brief at 14).

Another reason to review the GPAA anew in this docket is because new evidence surfaced during the re-opened discovery phase of this docket pertaining to the previous reconciliation. Staff maintains that new evidence, such as the “Aruba Analysis” and Wear Cross Ex. 1, came to light for the first time in this docket, even though this evidence was under PGL’s, North Shore’s affiliate, control. (Staff’s Init. Brief at 14).

3) The AG’s Position

The AG posits that the reason previous Commission decisions do not bind it is because the Commission has quasi-legislative powers, as well as judicial functions. It cites Business and Professional People for the Public Interest v. Ill. Commerce Comm., 1171 Ill. App. 3d 948, 525 N.E.2d 1053 (1^st Dist. 1988)). The AG additionally maintains that reconciliation proceedings like this one are single-year proceedings. The Commission’s determination in each reconciliation proceeding is confined to relevant evidence presented regarding the costs incurred in that 12-month period.

The AG argues that North Shore incorrectly interprets the Commission’s authority to review it prior decisions. The Commission is not bound by its past holdings and may revisit prior orders. (See, Mississippi River Fuel Corp. v. Illinois Commerce Cmm’n 1 Ill. 2d 509, 513 (1953)). The PUA requires the Commission to render its decisions based on the record of the proceeding, even when the Commission has previously addressed the same or similar issues. (See, Governor’s Office of Consumer Services v. Illinois Commerce Cmm’n, 242 Ill. App. 3d 172, 189 (1st Dist. 1993). This becomes especially true when the record in the previous docket shows the prior decision was incorrect or the record contained incomplete information. (AG Reply Brief at 13-14).    

4) Commission Analysis and Conclusions

The Commission concludes that Illinois Power does not apply here. In Ill. Power, the Appellate Court reversed a Commission ruling that Ill. Power’s decision to retire a propane plant that it used at peaking times was imprudent for failure to conduct a study, specifically, a Present Value Revenue Requirement Study, supporting that decision. Both Commission Staff and Ill. Power agreed, however, that Ill. Power would be required to expend $1.873 million to keep that plant safe and operational. Ill. Power had retired four other propane plants prior to the reconciliation year and Commission Staff never raised any issue regarding a Present Value Revenue Requirement Study and those other propane plants in Ill. Power’s previous reconciliations. (Ill. Power, 339 Ill. App. 3d at 437).

In reversing the Commission, the Appellate Court noted that it there was nothing in the record establishing a difference between the first four propane plant retirements and the one at issue, the Freeburg Plant. The Court concluded that it was not disputed that significant capital expenditures were needed to keep that plant operation and safe. And, Ill. Power had the prior experience of retiring four propane plants within the previous six years without needing the Present Value Revenue Requirement Study to justify these retirements. The Court noted that the Commission did not adopt a new standard or policy. It decided, after the fact, that this analysis should have been conducted. In so reasoning, the Appellate Court noted that the Commission considered each of the factors Ill. Power considered in isolation, rather than viewing those factors in their totality. (Id. at 437-39).

        The Commission concludes that Illinois Power only supports a finding of imprudence here. North Shore correctly points out that in the previous reconciliation, Commission Staff did not voice a concern with North Shore/North Shore affiliates’ relationship with Enron NA. However, as the Ill. Power Court noted, in order to determine whether a decision is prudent, a fact-finder must view the circumstances in their totality. Commission Staff and other parties to this proceeding did not know the true set of circumstances, such as the profit-sharing arrangement between PEC and Enron, or the existence of “Aruba Analysis” until February of 2004, when discovery was reopened.

North Shore is required by law to petition the Commission for approval of affiliated-interest transactions. North Shore did not divulge pertinent information to Staff in this proceeding before discovery was reopened. (See, 220 ILCS 5/7-101; 102). Documents such as the “Aruba Analysis” and Wear Cross Exhibit 1, which both establish that North Shore personnel had actual knowledge that the GPAA would unnecessarily increase consumers’ costs were only tendered to Staff and other parties here after discovery in this docket was reopened. Unlike the situation in Ill. Power, North Shore’s failure to disclose pertinent facts distinguishes this case from North Shore’s previous reconciliation. In contrast, in Illinois Power, the Commission’s approval of Ill. Power’s three prior reconciliations was not based on Ill. Power’s withholding information from Staff perusal.

In Ill. Power, the Commission required a utility, for the first time, to obtain a certain type of study to document the validity of its decision to retire a peaking propane plant, even though Ill. Power was not required to obtain this study in prior years when it retired four other propane plants in three previous reconciliations. (Ill. Power, 339 Ill. App. 3d at 437). When finding imprudence here, the Commission is not imposing a new standard. Rather, it is imposing the standard it would have been imposed if pertinent information had been disclosed properly by North Shore.

At best, North Shore has demonstrated that regulation, like any other sort of litigation, is not a perfect system. North Shore cites no applicable law requiring this Commission to do what it did previously, when it lacked vital information.

The Commission reiterates that Section 9-220 of the Public Utilities Act puts the burden of proof of prudence on North Shore. Section 9-220 does not give North Shore a presumption of prudence from the prior Docket 00-0720. The prior docket does not give rise to the presumption of prudence to the GPAA for several reasons. First, this Commission is not a judicial body; there is no res judicata here. Second, Section 9-220 calls for annual reconciliations before this Commission. A utility cannot escape the annual reconciliation provision of the statute. In the Illinois Power case, in Docket 01-0701, the Commission ruled that the fact that we had disallowed a contract in a prior year did not mean that we could not, on evidence, allow it in a subsequent year. And, in this case, the same argument applies: Section 9-220 does not give any utility a presumption, just because the items have been looked at before.

j. Proxy for Historical Gas Purchase Practices

1) North Shore’s Position

 

North Shore avers that, when it is compared to its past practices, the GPAA was a good proxy for its historical purchases. (North Shore Ex. D at 10). The mix of baseload and swing gas, as well as index-based pricing, were the same as the contracting approach it used prior to the GPAA. (Id.).

North Shore Exhibit 8 was prepared by Mr. Wear. When preparing it, he weighted the average price paid, during the two previous years, with 35% of purchases at a daily index price and 65% of purchases at an FOM price. He concluded that the cost of gas prior to the GPAA was comparable to the average of what was paid pursuant to the GPAA. Mr. Wear testified that North Shore did not use this type of analysis when assessing the GPAA’s value when this contract was being negotiated because changing market conditions “dictate” a more forward-looking approach to negotiations. (North Shore Init. Brief at 37-38).

 

North Shore also cites its Ex. 9, which is attached to Mr. Wear’s testimony, North Shore Exhibit D. It contends that the GPAA “outperformed” all other purchases by 25%. Finally, North Shore cites its Ex. 10, which is also attached to North Shore Exhibit D. It is a comparison between its GPAA gas purchases and its non-GPAA purchases. North Shore’s GPAA purchases, which comprised approximately 66% of the total in Ex. 10, were approximately 14% less expensive than its non-GPAA gas purchases. (North Shore Ex. F, Attachment 10; North Shore Init. Brief at 38).

2) Staff’s Position

Staff points out that, in the past, North Shore had multiple contracts with many suppliers for both supply and transportation. A single, five-year contract with one vendor is not equivalent to those previous contracts. (See, e.g., Staff Init. Brief at 21; Staff Ex. 2.00 at 27). Staff maintains that, according to the basis projections North Shore provided Staff, it would not have been less expensive to buy gas at the citygate price than it would have been to buy gas at the field and pay for delivery to the Chicago citygate. Staff concludes that the GPAA was not a proxy for what North Shore did in previous years. (Staff Ex. 3.00 at 22-24; Staff Ex. 7.00 at 20-21).

3) The AG’s Position

The AG argues that the GPAA is not a reasonable proxy for historical purchasing practices because it represents an imprudent departure from those practices. North Shore failed to demonstrate that the GPAA meets any of the factors that North Shore claims support its execution. Even if the GPAA met these factors, it would not be a reasonable proxy since the GPAA cost ratepayers more than past practices. (AG Init. Brief at 27).

4) Commission Analysis and Conclusions

While the GPAA provided both baseload and swing gas, it did so in a manner that harmed consumers, as Enron NA could change the price of baseload gas. North Shore provided no evidence that, in the past, gas sellers could change the price of gas. Additionally, Enron NA could, and did, determine the amount of SIQ and DIQ gas, which forced North Shore to buy gas on the spot market on some occasions and left North Shore with gas to unload on other occasions. When North Shore unloaded the excess gas by selling it back to Enron NA, North Shore paid a penalty ever time it made a resale. North Shore makes no showing that its previous gas purchases contained such provisions. The GPAA was not a prudent proxy for North Shore’s previous gas contracts.

Moreover, North Shore’s Exhibit 8 does not establish that the GPAA was prudent. While North Shore cited this document for the proposition that the GPAA was a reasonable proxy for what was done in previous years, the fact that this document shows the average cost of gas under the GPAA was fairly comparable to the cost of gas in previous years, does not establish that the costs imposed by the GPAA were reasonable. North Shore Exhibit 9 also does not aid it; the amount of costs passed on to consumers has no relevance to the issue here-- whether the GPAA was prudent. An imprudent cost can be in any amount.

North Shore cites no authority that would require the Commission to consider that which has been done under different circumstances, i.e., a different year, with different climate and very different contractual obligations and supplies, which is relevant when establishing prudence. North Shore also cites no authority establishing that a comparison between the costs passed on to consumers in the year in question and what it passed on 1998 or 1999 is relevant in the context of passing on only prudently-incurred costs to consumers. It should also be pointed out that, according to Mr. Wear, North Shore did not perform an analysis like Exhibit 8 before executing the GPAA.

 

1) North Shore’s Position

North Shore maintains that one of the key elements in the GPAA was market-based pricing. All three quantity components in the GPAA, baseload, SIQ, and DIQ, were market-based. North Shore has used market-based contracts in the past. (North Shore Init. Brief at 32-33). Market-based pricing results in gas costs that track market conditions. ( North Shore Ex. C at 28).

Also, the GPAA had no reservation or demand charges with respect to any quantity of gas. Demand charges are typical for swing services, and the DIQ clause, essentially, provided a swing service. In the past, however, North Shore has paid demand charges for swing services. North Shore points out that not paying demand charges for swing gas saved consumers money. (North Shore Init. Brief at 32).

North Shore avers that reference by Staff to pipeline demand charges is disingenuous. One of North Shore’s goals in negotiating the GPAA was to achieve market-based commodity pricing without reservation or demand charges. The GPAA contained no demand or reservation charges. (North Shore Reply Brief at 24-25).

2) Staff’s Position

Staff contends that, pursuant to the GPAA, North Shore continued to pay pipeline demand charges. (Staff Init. Brief at 20; Staff Ex. 2 at 25). Reservation or demand charges, which are incurred whether gas is delivered or not, are fixed costs that reserve space on a pipeline. North Shore’s claim that it did not incur any swing load demand charges is unsupported. North Shore was unable to disaggregate the components of the GPAA to determine if it includes demand or reservation charges to cover swing capability. (Staff Init. Brief at 20).   

3) The AG’s Position 

The AG argues that North Shore failed to show that the GPAA provided market-based pricing without demand or reservation charges. Avoidance of these charges only becomes significant if the overall cost of the GPAA would be less than historical purchasing practices. Like Staff, the AG avers that North Shore provided no analysis of the individual GPAA provisions to show they did not contain imbedded demand or reservation charges. (AG Init. Brief at 25).   

4) Commission Analysis and Conclusions

The GPAA eliminated the demand charges that would have been incurred for swing gas. While Staff has provided evidence that North Shore continued to pay pipeline demand charges pursuant to the terms of the GPAA, Staff did not provide an amount paid. (Staff Ex. 2.00 at 20). North Shore asserts that for the year in question, the amount of saved gas demand charges is $800,000. (See, e.g., North Shore Ex. C at 18). Based on the evidence provided, it appears that the GPAA provided this benefit to consumers.

North Shore’s argument that Staff disingenuously raises the issue of pipeline demand charges is a party-admission. North Shore is required by statute to consider the effect of all costs it passed on to consumers, including pipeline charges. (220 ILCS 5/9-220). The Commission concludes that North Shore’s assertion that it did not consider these charges when entering into the GPAA is just an admission that it acted imprudently.

l. Flexible Pricing

1) North Shore’s Position

North Shore argues that the GPAA was beneficial because, pursuant to the GPAA, the parties could agree to an alternative to the index pricing set forth in the GPAA. North Shore argues that the GPAA’s flexible pricing options provided a benefit for consumers. Beginning in May, 2001, North Shore locked-in the price of certain baseload quantities under the GPAA. (North Shore Init. Brief. at 33).

In its Reply Brief, North Shore rejects Staff’s and the AG’s criticisms of the flexible pricing provisions. Enron NA did not exercise these pricing provisions, which expired during fiscal year 2000. (North Shore Reply Brief at 21).

2) Staff’s Position

Staff posits that North Shore did not demonstrate that the GPAA was equal, much less superior, to North Shore’s historical methods of meeting customer demand. Staff believes a five-year contract with a single vendor provides less flexibility than multiple shorter term contracts with multiple vendors. (Staff Init. Brief at 21).

In its Reply Brief, Staff argues that North Shore failed to show how Article 4.2(a) added a benefit other than what North Shore would have without the GPAA. Further, any perceived benefit is tainted by the need for Enron NA’s agreement before any price change took effect. Presumably, Staff contends, Enron would only agree to a price change if it benefited from that change. (Staff Reply Brief at 18).

3) The AG’s Position 

The AG describes the flexible pricing provisions to be of a “dubious nature.” These provisions actually raise the cost of gas for consumers, much to their detriment. Further, these provisions allowed for North Shore to request a change in price, but did not obligate Enron NA to accept. North Shore failed to demonstrate that the flexible pricing provisions represented a superior option to its historical purchasing practices. (AG Init. Brief at 25-26).

In its Reply Brief, the AG argues that the GPAA only superficially meets the flexible pricing factor. Enron NA possessed the unilateral ability to change pricing under the Flexible Pricing provisions. North Shore did not enjoy such ability. (AG Reply Brief at 21).

4) Commission Analysis and Conclusions

North Shore’s argument does not square with basic contract law. Irrespective of what was in the GPAA, a written contract can always be modified upon the written assent of both parties, provided that such mutual modification does not violate the law or public policy. (See, e.g., Schwinder v. Austin Bank, 348 Ill. App. 3d 461, 468, 809 N.E.2d 180 (1^st Dist. 2004); Nebel v. Mid-City National Bank of Chicago, 769 Ill. App. 3d 957, 964, 769 N.E.2d 45 (1^st Dist. 2002)). This term in the GPAA merely reiterated what North Shore would be entitled to pursuant to the law. Because the law has provided this right, any clause in the GPAA setting forth this same right has no value except the nominal value of reminding the parties what the law is.

The Commission notes that the so-called Flexible Pricing provisions allowed Enron NA to unilaterally change the price of gas. North Shore admits this but attempts to smooth things over by noting that Enron NA did not exercise its right under these provisions. In the Commission’s view, the GPAA conferred Enron NA, not North Shore, with pricing flexibility. It makes no sense to argue that the GPAA afforded North Shore with its goal of pricing flexibility when the Flexible Pricing Provisions allowed another entity to control the pricing. North Shore acted imprudently when executing a contract containing such a provision.

m. Load Flexibility

1) North Shore’s Position

North Shore argues that the GPAA also provided it with flexibility. North Shore points out that its load is weather-sensitive and its day-to-day requirements can fluctuate substantially. The negotiation of baseload, SIQ, and DIQ gave North Shore the flexibility to address these fluctuations. (North Shore Exs. C at 14; Ex. H at 14-15).

Also, the GPAA gave North Shore the right to resell gas to Enron NA. According to North Shore, this right substantially eliminated the uncertainty associated with finding a market for gas, often on short notice. North Shore contends that the need to sell gas is substantially influenced by variables, over which North Shore has little or no control, such as weather, customer usage and transportation customers’ deliveries. North Shore points out that an oversupply can cause pipeline imbalance, which can result in penalties that it must pay. (Init. Brief at 35-36).

North Shore maintains that the penalties it incurs when selling gas back to Enron North America are not really penalties. The sell-backs in the GPAA are based on actual daily prices. (See, Staff Ex. 2.00, Attachments, GPAA, at 9-10). However, according to North Shore, it is not always possible to receive bids at the daily midpoint price. Often, to attract buyers, it is necessary to offer a discount from that price. Then, too, unloading a large amount of gas can be a formidable task. (North Shore Init. Brief at 36-37).

 

2) Staff’s Position

Staff contends that North Shore presented no evidence establishing that the GPAA was equal to, much less superior to, North Shore’s previous contractual arrangements. A five-year contract with one vendor is not as flexible as multiple contracts for supply and transportation with multiple suppliers and varying expiration dates. (Staff Init. Brief at 21; Staff Ex. 2.00 at 26). Staff points out that North Shore had no control over the amount of gas Enron delivered to it pursuant to the SIQ provision. As a result, North Shore had too much gas on its hands. Without the GPAA, the need to unload excess gas would have been occasional and in small quantities. (Staff Ex. 7.00 at 33).

In its Reply Brief, Staff contends that North Shore provided no analyses to demonstrate that the GPAA provides the flexibility North Shore experienced under its historical supply purchasing strategies. The fact that the GPAA contained three supply pricing options does not change the fact that this supply came from only one supplier. (Staff Reply Brief at 19).

3) The AG’s Position

The AG states that certain GPAA provisions require North Shore to use the flexibility when buying additional gas and reselling gas. North Shore’s use of normal weather to establish baseload quantities caused it to have excess supply. Additionally, the SIQ clause allowed Enron NA to require North Shore to purchase certain supply without regard for North Shore’s supply needs. Where cost is not a concern, the GPAA provides a certain flexibility. However, the GPAA did not allow North Shore to respond to various weather conditions. Additionally, North Shore provided no analyses to indicate its decision to abandon historical gas procurement practices was prudent. (AG Init Brief at 27).

In its Reply Brief, the AG argues that the GPAA itself necessitated load flexibility. Allowing Enron NA to dictate North Shore’s supplies through the SIQ and Sellback provisions merely made matters worse. (AG Reply Brief at 22).

4) Commission Analysis and Conclusions

While the arrangement in the GPAA (the mix of baseload, SIQ and DIQ gas) provided North Shore with flexibility, it did so in a manner that passed unnecessary costs on to consumers. As has been previously discussed, the harm this contract passed on to consumers outweighs any benefit conferred by the mix of baseload, SIQ and DIQ gas.

Finally, the Commission previously determined that North Shore failed to prove that the resale provision was beneficial. There is no evidence, given the amount of SIQ gas that Enron NA was allowed to control, that this provision conferred any benefit on North Shore or on consumers. When weighed against the harm that the provisions North Shore cites in support of its contention that it had load flexibility, North Shore has not sustained its burden to establish that the beneficial aspects its cites outweigh the harmful aspects of these provisions.

n. Unquantifiable Benefits

1) North Shore’s Position

North Shore contends that the GPAA conferred benefits on it that are not easily quantified. A large contract with a single supplier allowed it to conduct its daily purchases while remaining hidden from the larger market. Without direct knowledge of North Shore’s purchase plans in that marketplace, daily prices might tend to rise less dramatically than if North Shore were out in the open market soliciting offers from dozens of counterparts. (North Shore Init. Brief at 40; North Shore Ex. D at 8).

North Shore also argues that the GPAA preserved the reliability of its supply. When it negotiated the GPAA, Enron NA was the dominant gas trader in the United States. And, Enron had a presence in the Chicago market. (North Shore. Ex. D at 8). According to North Shore, Enron NA provided other benefits, benefits it would not have received with a portfolio of smaller contracts. Enron NA supplied North Shore with technical support to facilitate operations, including a secure webpage that allowed North Shore personnel and that of Enron NA to exchange information about daily activity. Enron NA also created a database for North Shore’s gas controllers. This database retrieved historical system send-outs based on weather outputs. (North Shore Ex. D at 9).

2) Staff’s Position

Staff contends that North Shore offered no facts or concrete examples to demonstrate the value of those unquantifiable benefits. Instead, according to Staff, North Shore asserted only vague generalizations. And, these benefits did not provide direct results for consumers. (Staff Init. Brief at 35).

3) The AG’s Position

The AG argues that none of the alleged unquantifiable benefits support North Shore’s contention that the GPAA was a prudent supply contract. The AG takes quarrel with North Shore’s assertion that the GPAA shields its daily from the open market. Any cost savings North Shore could achieve with this would have to be very large to affect the open market. North Shore provided no evidence to support that this would be the case. (AG Reply Brief at 25).

The AG further takes further issue with North Shore’s assertion that the GPAA preserves North Shore’s reliability. The AG believes the opposite is true. A contract for two-thirds of supply from one vendor puts consumers at great risk if that supplier defaults. (AG Reply Brief at 25).

Finally, the AG disagrees with North Shore’s contention that the GPAA provided certain increased efficiencies and information. Mr. Wear originally offered this representation. He provided no evidence that this was a factor in the decision to execute the GPAA. In actuality, Mr. Wear’s statements seemed to work more in North Shore’s favor than ratepayers. Mr. Wear expected the GPAA to improve North Shore’s processes and “allow for better decision-making” “lead[ing] to lower gas costs.” (AG Reply Brief at 26).

4) Commission Analysis and Conclusions

North Shore’s contention that the GPAA hid its supply purchasing practices from the larger market is simply too vague to be given any evidentiary weight. North Shore offers no examples, and the phrase “might tend to rise” is speculative. North Shore did not explain what it would be doing in the open marketplace soliciting bids, or why. And, North Shore points to no information establishing that previously, North Shore’s baseload gas was purchased on a daily basis in the open marketplace.

There is no evidence establishing how training PGL employees on futures and financial derivatives provides a benefit to North Shore. North Shore has a Commission-approved contractual relationship with PGL, but North Shore did not state what services PGL employees performed, as a result of these unquantifiable benefits, that aided North Shore. Nor is it obvious.

The Commission agrees with the AG that the alleged increase in reliability rings hollow. North Shore fails to explain how a contract with one vendor for two-thirds of its supply would improve system reliability in the event that the vendor defaulted. The Commission also agrees with the AG that these unquantifiable benefits seem to favor North Shore rather than the PGA customers.

B. Storage at Manlove Field

 

1. Findings of Fact

 

During the reconciliation period, natural gas storage was the only means through which North Shore could accommodate for a force majeure and situations in which gas suppliers provide a different amount of gas than that which was agreed upon.²³ North Shore contracts with PGL to use a portion of PGL’s Manlove Field (“Manlove”)²⁴ for North Shore’s storage.²⁵ (North Shore. Ex. H at 19).

Record cold conditions existed in Chicago in the months of November and December of 2000. Heating degree-days were 6% higher than normal at Midway Airport and 11% higher than normal at O’Hare International Airport. In December of 2000, heating-degree days were 28% above the normal at Midway Airport and 27% at O’Hare.

In November of 2000, North Shore personnel planned to withdraw 279 MDths of gas from Manlove for consumers at a rate of approximately 9000 Dths per day.²⁶ North Shore actually withdrew less gas supply from Manlove for its PGA customers than planned. Instead, North Shore injected about 1,500 MDth of additional gas and purchased gas for PGA customers on the open market. ( In December, despite record cold temperatures, North Shore personnel injected 34.7 MDth (net) of gas. (Staff Ex. 6.00 at 5; 7.00 at 30-31). By purchasing higher priced spot gas rather than using Manlove storage reserves, North Shore caused its PGA customers to pay excessive gas costs. (Id.).

North Shore admits withdrawing less than planned from Manlove in December 2000. Mr. Wear testified North Shore made the decision to decrease withdrawals from Manlove Field was based on forecasting errors and unexpected decreases in demand. (North Shore Ex. H at 15-17). Without these forecasting errors, actual withdrawals from Manlove would have been closer to the planned withdrawals. (Id.).

To meet its projected daily projected flow needs, North Shore must acquire supply and schedule deliveries no later than 11:30 A.M. on the day before. Once North Shore commits to a daily purchase, it cannot go back. North Shore uses weather forecasts to estimate its demand needs. Given the imperfect nature of weather forecasts, North Shore’s load is difficult to predict. One heating degree day in December and January approximates 3990 MMBtus of demand on its system. North Shore uses storage to accommodate differences between forecasted weather and actual weather. (North Shore Ex. H at 16).

 

 

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²³  A force majeure is an unforeseen act of God, or man, such as flooding, war, or vandalism. (Kahara Bodas Co. v. Perusahaan Pertambangan, 335 F.3d 357, 360 (5^th Cir. 2003)).

²⁴  PGL uses Manlove, an aquifer, to store gas supplies for its PGA customers and for third party storage.

²⁵  North Shore and PGL obtained Commission approval of this affiliated interest agreement.

²⁶  One Dth is approximately 1000 cubic feet and one MDth is 1000 dth.

North Shore must also adjust its PGA customer deliveries to account for transportation customers’ deliveries. Transportation customers frequently change actual deliveries from estimated deliveries. Other factors that may cause actual system consumption to vary from forecasted consumption include changes in industrial customer demand due to changes in production activity, heating customers changing thermostats or firm service interruption upstream due to force majeure. North Shore’s only means of accommodating these events is through storage. (North Shore Ex. H at 17).

Mr. Anderson testified that a decrease in demand does not explain why North Shore did not have net withdrawals from Manlove Field, during a record-cold December, and with record high gas prices. All Illinois gas utilities experience these difficulties—they represent the normal course of business. During such cold weather and high gas prices, North Shore should have had net withdrawals instead of net injections. (Staff Ex. 6.00 at 6).

 

2. Conclusions of Law

 

a. Staff’s Position

Staff proposes a disallowance for imprudent use of gas stored in Manlove Field in the amount of $2,249,249, which represents the difference between the higher-priced gas purchases and the gas in storage that North Shore did not use. Staff points out that one of the chief purposes for storing gas in Manlove Field is to limit the effect of winter gas price spikes on consumers. North Shore’s planned withdrawal problem demonstrates what North Shore expected to withdraw from Manlove. North Shore’s withdrawals from Manlove in December 2000 fell short of its planned withdrawals, which Staff argues is odd given the high prices of natural gas that month. Prudence required North Shore to withdraw from Manlove at least the planned amounts to reduce costs to PGA customers. Staff argues that it was imprudent of North Shore to purchase gas on the open market in November and December of 2000, instead of using the less expensive stored gas at Manlove Field. (Staff Init. Brief at 39-40). Staff further posits that, by injecting gas into Manlove Field, North Shore improperly furthered the interests of parent company, PEC, to use the gas stored at Manlove Field for unregulated third-party transactions. (Id. at 40).

In its Reply Brief, Staff stresses that North Shore failed to explain how its net injection of gas into Manlove in December 2000 was prudent for ratepayers. Staff believes North Shore’s injections in December 2000 were due to its affiliate, PGL’s, third-party transactions involving Manlove.²⁷ (Staff Reply Brief at 34).

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²⁷  The Commission takes judicial notice of the record in Docket 01-0707, where PGL’s Manlove transactions were thoroughly explored.

Staff also takes issue with North Shore’s assertion that Staff failed to account for operational factors in its analysis: that North Shore must schedule and purchase supplies over three-day weekends; whenever weather conditions varied from forecasts, North Shore had to use storage from Manlove; customers change their deliveries; and industrial customers’ demands change. Staff argues that North Shore failed to support these claims with any evidence that these factors existed during the reconciliation period. In addition to North Shore bearing the burden of proof, North Shore also presumably controls any information it could use to support its claims about Manlove field operations. North Shore neither provided instances in which these operational factors occurred nor did it quantify the extent of such instances. Finally, all Illinois gas utilities face these operational issues and do so without experiencing the problems experienced by North Shore. (Staff Reply Brief at 34).

b. North Shore’s Position

North Shore argues that it met some of its “end users’” requirements through withdrawals from Manlove during the 2000-2001 winter. North Shore acknowledges that actual withdrawals were less than planned for December 2000. Operational factors drove withdrawals from Manlove. On some days in December, actual load was less than forecast. North Shore states that since gas volume nominations cannot be changed, any unexpected decrease in demand necessarily led to a reduction in storage withdrawal. (North Shore Init. Brief at 48).

North Shore must also adjust its operations to meet any changes, forecasted or actual, in weather. When actual weather conditions differ from forecasted weather, North Shore uses storage to accommodate these differences. Further, North Shore must deal with “imperfect” knowledge of transportation customer deliveries, which often causes the amounts delivered to North Shore to change. North Shore receives information on these deliveries at the same time it schedules its own gas supplies. Finally, North Shore must also adjust for industrial customers changing their demand, heating customers changing thermostats and the interruption of firm services up on upstream pipelines. (North Shore Init. Brief at 48).

c. The AG’s Position

The AG notes that North Shore anticipated net withdrawals from Manlove in December 2000. Instead, it experienced net injections. Not only did North Shore not follow its withdrawal plan, its injections into storage during the winter represent a deviation from normal practices. Instead of relying on less expensive stored gas to mitigate consumer costs during a time of high gas prices, North Shore purchased more expensive spot gas to replace its stored gas. North Shore did not provide an explanation of its use of Manlove until Staff examined the additional discover and concluded that North Shore’s parent company’s strategic partnership with affiliates must have caused North Shore to cancel the planned withdrawals so that gas could be used for more profitable third-party transactions. After Staff made this accusation, North Shore finally attempted to explain its actions. North Shore stated that operational factors lead to the alteration of its plans for Manlove. The AG argues that North Shore failed to meet its burden of proof on this issue and the Commission should accept Staff’s recommended disallowance for North Shore’s imprudent use of Manlove. (AG Init. Brief at 31-33).

In its Reply Brief, the AG argues that North Shore only offers one occurrence that might explain the net injections into Manlove in December 2000—forecasting error. All other explanations center around events that might occur. North Shore failed to provide any sort of analysis to show how any of its explanations actually affected its operations of Manlove. (AG Reply Brief at 27-28).

d. Commission Analysis and Conclusions

The Commission agrees with Staff at the AG that North Shore imprudently operated Manlove Field during December 2000. Instead of using less expensive stored gas to mitigate high gas prices during that month, North Shore experienced net injections. North Shore attempts to explain this by attributing the net injections to load forecasting error. North Shore claims that on certain days it sent out less gas than forecasted, which somehow corresponded to a decrease in withdrawals from storage. If North Shore needed to withdraw less from storage, it makes no sense that North Shore actually injected into storage.

North Shore claims to use storage to counteract the effects of cold weather on demand. However, record cold conditions (and record prices) existed in December 2000. During that time, the record demonstrates that instead of using planned withdrawals to soften the blow to PGA customers, North Shore used expensive spot gas to meet its consumers’ needs.

North Shore also attempts to explain its storage operations with generalizations about transportation customer deliveries, changes in industrial demand, customers changing thermostats and changes in pipeline demand upstream. The Commission agrees with Staff and the AG that these are merely generalizations for which North Shore failed to provide any documentary evidence that any of these situations affected North Shore during the reconciliation period. Even if the Commission were to accept North Shore’s reasoning, all gas utilities deal with these situations. These are things North Shore must deal with as par for the course and plan accordingly. At best, this demonstrates North Shore’s preferential treatment of its non-PGA customers, unfortunately to the detriment of PGA customers.

Commission rules require North Shore to “refrain” from taking actions that unnecessarily increase costs to PGA customers. North Shore ignored this obligation by not using planned storage withdrawals to meet consumers’ needs during a particularly cold winter month and by purchasing extraordinarily expensive spot gas for consumers, which unnecessarily increased costs. The Commission finds North Shore’s operation of its Manlove Field resource to be imprudent. Any disallowance associated with this finding of imprudence is properly included in the Settlement Agreement and Addendum discussed in Section I of this order.

As a final matter, the Commission notes Staff’s theory that North Shore altered its planned Manlove withdrawals in December 2000 to accommodate its parent company and affiliates’ strategic relationship with Enron NA. This rouses the Commission suspicions, which tempts us to draw inferences from the record in 01-0707. However, the record in this docket does not contain sufficient information for the Commission to positively conclude that North Shore’s storage operations rose to the level of that in Docket 01-0707.

 

1. Findings of Fact

 

Hedging is a way to reduce price volatility. Hedging instruments include futures contracts, option contracts, swap contracts, which are also called “derivatives,” and are securities or contracts whose value depends on the value of the underlying asset. (North Shore Ex. F at 8).

North Shore witness Mr. Wear testified that North Shore took “several steps” to address price volatility during the reconciliation year. North Shore used seasonal storage and “followed” two separate price protection programs. North Shore had two different price protection programs that were in effect. North Shore did not use one of its price protection programs, the “Gas Supply Price Protection Financial Trading Strategy,” at all during the time period in question. (North Shore Ex. B at 7).

North Shore’s second hedging program, the “Gas Supply Price Protection Strategy,” became effective in May of 2001. (North Shore Ex. B at 8). As part of this program, North Shore locked in a fixed price with Enron NA for baseload gas. Approximately 23.5% of purchases North Shore made in May through September of 2001 were at that fixed price. (North Shore Ex. C at 20).

Mr. Wear testified that North Shore’s price protection programs insulated consumers from price volatility. Another way for North Shore to protect consumers was to make physical purchases at forward prices that produced a ”dampening effect” on price spikes. Mr. Wear further testified that the purchases North Shore made mitigated price volatility for its customers, “not only for gas consumed during (the) May through September period, in which the deliveries were made, but also for the re-injection of gas withdrawn to satisfy customer requirements during the preceding winter months.” (North Shore Ex. B. at 8).

a. North Shore Expert Witness Mr. Graves’ Testimony

All opinions contained in this section of the order are those of Mr. Graves unless otherwise noted. Frank Graves, Audit Manager with Grant Thorton LLP, testified that exposure to price risk is the uncertain realization of what a cost of revenue is as the result of a purchase or sale. That exposure is affected by the quantity involved in the purchase. He opined that utilities should have some coherent plan to lessen the effect of price risk. Mr. Graves also acknowledged that hedging by utilities can be very useful, when it achieves specific risk reduction goals that benefit consumers, as well as the benefits the financial health of a utility. (North Shore Ex. F at 8).

North Shore’s decision not use financial hedging instruments during the 2001 reconciliation year, “in light of the Commission’s lack of guidance” regarding financial hedging instruments was prudent. The Commission has clearly stated that hedging is not required. Regulated utilities cannot, without clear direction from regulators, internalize their own successes and failures. (North Shore Ex. F at 6). The Commission has never required, or even encouraged, utilities to use financial hedging instruments. This is in contrast to other state commissions, like the New York Public Service Commission cited by Mr. Ross, which requires the use of financial hedging instruments. Without a clear statement from the Commission supporting the use of financial hedging instruments, a utility could easily be found to be imprudent if it chose to embark on a financial hedging program. (Id. at 16-17, 21).

It is only feasible to have such a program when there are specific hedging guidelines enunciated by regulators, determining when and why mitigating price volatility is worthwhile. It is “inappropriate” to impose disallowances after market price spikes have occurred, when a utility did not have a “clear signal” from a regulatory commission as to how it should hedge. (Id. at 8-9).

Comparing North Shore to unregulated companies, like its parent, PEC, is not “useful,” because such companies hedge only to reduce their financial risk, not to manage consumer prices. These companies do not have to worry about what a regulatory body will determine with regard to their hedging purchases. North Shore’s shareholders do not benefit from gains produced by hedging, as, pursuant to the PGA, all of the costs and benefits are passed on to consumers, not the shareholders. (Id. at 23-24). The appropriate level of hedging is not obvious, it is best determined by a Commission-generated inquiry and the gradual process of controlled customer exposure, as, the appropriate level of hedging depends on a consumer comfort with the idea. Some consumers may prefer to be at fixed prices, which provides stability, but may foreclose the opportunity of lower prices. Others may be averse to fixed prices. Still other, larger consumers may be able to obtain their own hedges. (Id. at 29).

Financial hedging instruments do not necessarily lower gas costs. A hedging program should only be expected to reduce volatility. A hedging program also increases gas costs and there is no way of knowing beforehand whether a hedging program will increase or decrease gas costs. Spot gas prices are always different than past forward (financial hedging instrument) prices, because unexpected market conditions often arise after a hedging instrument is bought or sold. (North Shore Ex. F at 9). Additionally, financial hedging instruments have no effect on average prices paid in the primary gas supply market. Financial hedging instruments only reflect the risk tradeoffs between purchases at different times or at different places. Therefore, financial hedging instruments do not gain control over average wholesale prices and there can be no expected savings when expected cost savings are fairly priced. (Id.).

Volatility exposure, on the other hand, can be transferred from one party to another. Financial hedging instruments are traded on markets with “sophisticated parties” on either side of a transaction. Thus, the prices at which hedges are available reflect a consensus view of the most likely outcome. Hedging is a risk management function; it is not a least-cost function. (Id. at 10, 12). Price spikes in previous years (the winters of 1995 and 1996 through 1997) were indicia that the Commission chose not to implement price hedging programs after those two price spikes occurred. (Id. at 25).

Gas price volatility started in May of 2000. It approached 65-70% in June and July of 2000. However, that level of volatility was not unusual, given the volatility that existed in the fall and winter of 1999-2000. The volatility increase in the summer of 2000 did not provide a strong signal that a hedging program should be initiated. Volatility in the winter of 2000 through 2001 was much higher than the volatility in the summer of 2000, but, this was only known “after the fact. The extreme run-up in gas prices during the winter of 2000-2001 was unprecedented and unpredictable, and so was the rapid decline in gas prices shortly thereafter. Mr. Ross uses “hindsight information” when advancing their proposed disallowances. (Id. at 16-17).

The increase in gas costs North Shore passed on to consumers in the winter of 2000-2001, were unprecedented and unexpected. The peak daily price was more than six standard deviations over the average price.²⁸ This was an incredibly rare event, which occurred due to the surge in wholesale gas prices due to a decline in well-production, OPEC price-tightening, and the fact that gas prices remained high over the preceding summer, which resulted in many buyers filling their seasonal storage late, hoping for a price decline that never occurred. Also, in California, power markets experienced shortages in hydro-electric power, and at the same time, experienced an unusually hot summer. The “California crisis” may have contributed to a general anxiety about future energy prices,” which increased willingness to pay high gas prices. Further, futures prices for gas were at very high levels for two to three years forward. Finally, electric companies began using gas to generate electricity. (Id. at 27-29).

b. CUB Expert Witness Mr. Ross’ Testimony

The opinions contained in this section of the order reflect those of Mr. Ross unless otherwise noted. Mr. Ross, Principal with CRP Planning Inc., considered North Shore’s management decisions regarding price volatility and he evaluated whether North Shore personnel took reasonable steps in the face of known risks and market conditions. He noted that North Shore has faced price volatility in the past. Previously, during the winter of 1996-97, North Shore faced extreme price volatility in the gas markets. That winter revealed both the magnitude of the price risk from volatility that North Shore could face, and the extent to which North Shore’s PGA customers are exposed to the volatility and price risk of the wholesale market. (CUB Ex 1.00 at 1- 3).

Hedging is commonly used to mitigate price risk. Large gas consumers who procure their own gas supply frequently hedge some portion of their gas supply to limit price risk, either through participation in the futures market or through the use of fixed price contracts and ceiling prices. North Shore considered managing price risk in a study conducted in 1998, but ultimately, it declined to adopt that hedging strategy. (CUB Ex 1.00 at 6, 7).

 

North Shore routinely manages weather risk in its annual, monthly, and daily supply planning. It can also limit customers’ exposure to volatility by using risk management tools, or by “hedging.” Hedging, for gas buyers, is akin to insurance against unexpected price increases. Hedging techniques can include financial hedges and fixed price hedging. Other forms of hedging include storing gas. (Id. at 4-5,10-11). In the past, North Shore affiliates have hedged against price risk. North Shore’s parent company, PEC, invested in gas and oil fields by using swaps and options. (Id. at 4-5,10-11).

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²⁸  The standard deviation Mr. Graves used is $1.26 per MMBtu and it is for a 10-year period. It is based on data that includes a high-price period. (North Shore Ex. F at 26).

North Shore’s customers bore a substantial price increase during the reconciliation year because North Shore personnel chose to link nearly all of its gas supply contracts to market indices, which followed the rapidly escalating market clearing price. The market price escalations created substantial hardship for North Shore’s PGA customers. (CUB Ex. 1.00 at 12, 13). Because North Shore faced little price risk when acquiring its gas supply, North Shore does not have a strong incentive to mitigate this risk. Consumers, however, face a considerable price risk because this cost is passed on to consumers.

Also, North Shore personnel did not care to protect consumers from price risk, as North Shore personnel were not required to adhere to any explicit hedging standards enunciated by the Commission. The Commission has not required companies to engage in any mitigation strategy, nor has it restricted utilities from using hedging strategies. Rather, the Commission has left whether a prudent strategy would include financial hedges up to utilities to decide. (CUB Ex. 1.00 at 9-10, 12, 13). He concluded that North Shore failed to exercise a standard of care that a reasonable person would have used, in light of known conditions and risks before, and during the reconciliation period. (Id. at 1-2, 9,14)

North Shore could have managed its price risk by making greater use of stored gas when spot market prices were high, using financial hedging mechanisms, including fixed-price forward and ceiling prices in its supply contracts. North Shore made no attempt to use fixed price contracts or hedge against the risk of price volatility. North Shore also chose not to use hedging tools to mitigate the price risk of its contracted gas supply, and it did not engage any of its suppliers to hedge as part of providing supply. For the 2000-2001 heating season, North Shore’s gas purchasing strategy was dependent on contracts indexed to daily and monthly market rates. (CUB Ex 1.00 at 9, 10-11).

When determining what North Shore should have hedged, Mr. Ross used a futures market hedging strategy, as futures are the most common and simplest financial hedges, assuming purchases of six-month natural gas futures (based on the monthly average of the daily midpoint futures prices at the Henry Hub) for May through September.²⁹ Mr. Ross focused on North Shore’s firm supply gas, because it is the gas purchased by North Shore through pre-negotiated gas supply contracts for which a gas supplier guarantees delivery. Most of North Shore’s winter firm supply is composed of North Shore’s baseload contracts, which it cannot change, in terms of volume or pricing. In the winter, firm supply is used to meet demand; it is not usually put in storage. (Id. at 6, 17).

 

 

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²⁹  A six-month futures contract is held six months in advance. Thus, a six-month May futures contract would be purchased in December, payable over the life of that contract. This differs from a forward contract, where payment is due at the time of, or following, delivery. (NYMEX.com\glossary)). 

During the reconciliation year, North Shore personnel knew that gas price volatility was affecting consumers, North Shore personnel had developed familiarity with price risk hedging, had designed a hedging strategy, and were actively mitigating price risk for its shareholders. North Shore personnel knew that price risk was a real risk deserving of mitigation, since it took proactive steps to protect shareholders from price risk in the reconciliation year. It researched the available tools and implemented a strategy to hedge price risk; it simply chose not to do so for consumers. (Id. at 16-18). North Shore personnel deliberately chose not to mitigate price risk for customers. The Commission’s prior decisions on hedging do not create a regulatory ‘safe harbor,’ which is an action or set of actions that North Shore can take for which the Commission will not question the prudence of the actions. North Shore personnel should rely on the Commission’s past decisions because this particular situation is different from the situations in those cases. (Id. at 9).

Mr. Ross recommends a disallowance of $9,782,479, which is based on a comparison of actual gas costs with those incurred under his recommended hedging program.

 

2. Conclusions of Law

 

a. North Shore’s Position

North Shore argues that its decision not to use financial hedging during the 2001 reconciliation was not imprudent. The Commission has consistently ruled that utilities use financial hedging to demonstrate the prudence of gas purchases. North Shore finds fault with CUB witness Ross’ testimony for several reasons. Staff witness Rearden did not consider North Shore’s level of hedging to be imprudently low. Further, Commission rulings on the prudence of other gas utilities’ gas purchases for the same reconciliation period did not find that pricing conditions required financial hedging. (North Shore Init. Brief at 20).

North Shore criticizes CUB’s analysis as being impermissible hindsight review. Hedging should work to reduce volatility and does not always mean lowest cost. CUB’s analysis would only have benefited PGA customers through hindsight since that is how it would have been possible to lower gas costs through hedging. Mr. Ross’ analysis provides no idea of how much volatility should be hedged. (North Shore Init. Brief at 25).

b. Staff’s Position

Dr. Rearden proposed no disallowance for North Shore’s lack of financial hedging in the 2001 reconciliation year. He believes North Shore’s level of hedging to not be imprudently low. (Staff Ex. 7.00 at 54-55).

c. CUB’s Position

CUB argues that North Shore’s lack of financial hedging for the 2001 reconciliation year was imprudent. North Shore bears the burden of proving that costs recovered through the PGA were reasonable, prudently incurred an accounted for as prescribed by the PUA and Commission rules. (CUB Init. Brief at 8).

CUB notes that while the Commission has not previously required utilities to engage in hedging, the Commission has also not forbidden it. North Shore’s arguments regarding prior Commission decisions on hedging hold little, if any, weight. Further, prior Commission decisions do not afford North Shore a “regulatory safe harbor,” where North Shore is protected from even the threat of a disallowance because the Commission has not affirmatively required hedging. (CUB Init. Brief at 10).

d. The AG’s Position

In its Reply Brief, the AG avers that North Shore failed to properly consider or implement a hedging strategy for the 2001 reconciliation year. The AG states that North Shore improperly relies on prior Commission decision to justify the non-existence of its hedging strategies. (AG Reply Brief at 28-29).

e. Commission Analysis and Conclusions

In addition to procuring a good price for gas, there generally are two ways that a utility like North Shore can mitigate the effect of higher prices in the marketplace on its PGA customers. North Shore can protect against volatility in the marketplace and it can protect against the effect of higher winter gas costs. When prices will be volatile is not necessarily predictable. How volatile a market will be, and for how long, is not a known quantity. That prices will be volatile on occasion is known, as gas prices have been volatile in the past.

The Commission agrees with Staff’s position and concludes that North Shore’s use of financial hedging instruments, for the entire year, was not imprudently low.

 

VII. Audits

 

A. Staff’s Position

 

Staff recommends that the Commission require North Shore to engage an independent consultant to conduct a management audit of North Shore. Staff also recommends that North Shore be required to perform internal audits of its gas purchasing practices. Staff further recommends that North Shore update its operating agreements with PGL. (Staff Init. Brief at 41-44).

 

 

 

B. North Shore’s Position

 

North Shore believes Staff’s proposed audits are unnecessary. (North Shore Init. Brief at 9).

 

C. Commission Analysis and Conclusions

 

In light of the Settlement and Addendum incorporating these management audit requirements, the Commission accepts the proposals in these documents.

VIII. Finding and Ordering Paragraphs

 

(1)

North Shore Gas Company is a corporation engaged in the distribution of natural gas service to the public in Illinois, and, as such, it is a “public utility” within the meaning of the Public Utilities Act;

(2)

the Commission has jurisdiction over North Shore Gas Company and of the subject-matter of this proceeding;

(3)

the statements of fact set forth in the prefatory portion of this Order are supported by the evidence of record and are hereby adopted as findings of fact;

(4)

as is set forth in this Order, North Shore Gas Company acted imprudently, or otherwise acted contrary to law in its purchasing and storage of gas during the reconciliation period;

(5)

the Settlement Agreement (Exhibit 1) as revised by the Addendum (Exhibit 2) is adopted and their terms incorporated herein as a settlement of allegations that, during the reconciliation period, North Shore had not acted reasonably and prudently in its purchases of natural gas and other activities that affected the amounts collected through Gas Charnges in its fiscal year 2001;

(6)

the unamortized balances at the end of North Shore’s 2001 reconciliation year show a recoverable balance for the Commodity Gas Charge of $7,981,620.48; a recoverable balance of $1,899,343.69 for the Non-Commodity Gas Charge and the Demand Gas Charge; and a recoverable balance of $9,245.22 for the Transition Surcharge, for the total refundable balance of $6,073,031.57, the Factor O refund is zero;

(7)

the reconciliations submitted by North Shore Gas Company of the costs actually incurred for the purchase of natural gas with revenues received for such gas for the reconciliation period beginning October 1, 2000, through September 30, 2001, may properly be approved;

(8)

pursuant to the Settlement Agreement and Addendum, a refund of $100 million is to be distributed in the manner set forth above as part of the consideration paid in global settlement of this docket, as well as I.C.C. Docket Nos. 01-0707, 02-0726, 02-0727, 03-0704, 03-0705, 04-0682 and 04-0683;

(9)

North Shore Gas Company should follow the accounting procedures recited above, where applicable to it, the directive contained in the incorporated parts of the settlement agreement and the addendum thereto in all future gas adjustment charge reconciliation dockets;

(10)

North Shore Gas Company shall file quarterly reports with the Chief Clerk’s office detailing the progress of the Hardship Reconnection program.

IT IS THEREFORE ORDERED that the reconciliation of revenues collected under North Shore Gas Company’s PGA tariff with the actual cost of gas prudently purchased for the time period beginning October 1, 2000, through September 30, 2001, as is set forth herein.

IT IS FURTHER ORDERED that North Shore Gas Company shall comply with all of the Findings of this Order;

IT IS FURTHER ORDERED that any motions, objections, or petitions in this proceeding that have not been specifically ruled on should be disposed of in a manner consistent with the findings and conclusions herein.

IT IS FURTHER ORDERED that the Settlement Agreement (Exhibit 1) and Addendum (Exhibit 2) are hereby incorporated into and made a part of this Order.

IT IS FURTHER ORDERED that North Shore Gas Company shall comply with the directives in Finding (8) above.

IT IS FURTHER ORDERED that, subject to the provisions of Section 10-113 of the Public Utilities Act and 83 Ill. Adm. Code 200.880, this Order is final; it is not subject to the Administrative Review Law.

By Order of the Commission this 28th day of March, 2006.

(SIGNED) CHARLES E. BOX

Chairman