Peoples Energy 8K Entry into a Material Definitive Agreement | SEC 5 Apr 06

On November 7, 2001, the Commission commenced this docket requiring Peoples Gas Light and Coke Company (“PGL”) 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 PGL 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, the Illinois Attorney General, the Cook County State’s Attorney and the City of Chicago. On March 7, 2005, pursuant to a ruling made by the Administrative Law Judge, (the “ALJ”) the parties filed pre-hearing briefs stating their positions as to how 83 Ill. Adm. Code 525.40 applied to the facts at bar. Pursuant to proper notice, hearing in this matter convened before a duly authorized ALJ on April 18, 2005 and continued through April 21, 2005. Subsequently, the record was marked “Heard and Taken.” PGL and Commission Staff filed initial briefs on June 30, 2005. The City of Chicago, (the “City”) the Citizens Utility Board (“CUB”) and the Illinois Attorney General (the “AG”) filed one initial brief collectively on that same day.¹ Reply briefs were filed on August 19, 2005. These three parties filed Briefs on Exception on October 3, 2005 and Reply Briefs on Exceptions on October 11, 2005. PGL requested oral argument, which the Commission granted on December 13, 2005.²The Commission heard oral arguments on December 21, 2005.

____________________

¹ Reference is made herein to positions asserted in joint briefs filed by these three entities as the “GCI,” which is the Governmental and Consumer Intervenors.

² With its Brief on Exceptions, PGL also filed a document entitled “Exhibit 1 to Brief on Exceptions,” which is, essentially, the Administrative Law Judge’s Proposed Order (the “ALJPO”) rewritten. Many of the proposed changes therein were not substantiated by legal or factual argument, as is required by law. (83Ill. Adm. Code 200.830(b)-(e); (Fraley v. City of Elgin, 251 Ill. App. 3d 72, 76, 621 N.E.2d 276 (2^nd Dist. 1993); In re Marriage of Thornquist, 79 Ill. App. 3d 791, 798, 399 N.E.2d 176 (1^st Dist. 1979)). And, many of the proposed changes therein misstate the record. By failing to assert a legal or factual argument in support of changes PGL seeks, PGL has waived its right to have this Commission consider them. (Fraley, 251 Ill. App. 3d at, 76). Except in on instance, we did not consider these contentions. (See, Section III(o) herein).

01-0707

On January 17, 2006, PGL, North Shore Gas Company (“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”).³ 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, and meet other requirements defined in the agreement.

On January 23, 2006, the Peoples 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 of the Reconciliation Dockets, the Commission asked that the Settling Parties meet with Staff and the Cook County State’s Attorney (“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.

____________________

³ The Settlement also addressed three circuit court cases.

01-0707

Testifying on behalf of PGL were: Thomas Zack, Director of Gas Supply Services; David Wear, the Manager of Gas Supply Administration at PGL; William Morrow, the Vice-President of PGL, the Vice-President of Peoples Energy Corporation and the President of Peoples Energy Resource Company; Valerie Grace, PGL’s Director of Rates and Gas Transportation Services; Thomas Puracchio, PGL’s Gas Storage Manager: 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 Dianna Hathhorn, an accountant in the Accounting Department of the Commission’s Financial Analysis Division, Eric Lounsberry, the Supervisor of the Gas Section of the Engineering Department of the Commission’s Energy 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 were Brian Ross, a Principal with CR Planning, Inc. and Jerome Mierzwa. Testifying on behalf of the City was John Herbert. Testifying on behalf of the AG was David Effron a regulatory consultant. Testifying on behalf both the City and CUB was Lindy Decker, an Audit Manager with Grant Thornton LLP.

I. The Settlement Agreement

Outstanding Procedural Matters

On October 7, 2005, PGL filed a Petition for Interlocutory Review of the Ruling on Staff’s Motion to Strike Reply Brief and Deny Other Relief. 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 Petition for Interlocutory Review and 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.

01-0707

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

The Illinois Supreme Court addressed the standard for the Commission’s approval of settlement agreements and for 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 on 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.

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 dockets⁴, which the Commission will deal with in separate orders. For the remaining two dockets, 01-0706 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.

____________________

⁴ 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 a “Party”).

01-0707

Second, the Commission must determine whether the provisions of the proposed Settlement and Addendum 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 evidence and findings of imprudence in the ALJPO 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 adopt 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.

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 areof which are set forth in the Settlement (Exhibit 1) and Addendum (Exhibit 2). The Settlement Agreement 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.

01-0707

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. 01-0706 and the instant docket. Staff recommended approximately $92 million in disallowances in the instant proceeding and approximately $4 million in disallowances in Docket No. 01-0706. Using those numbers as indicators of the level of harm caused to consumers in each service territory, the Commission finds that $96,000,000 of the $100,000,000 shall be refunded to customer accounts in PGL’s service territory.

The Company shall distribute the $96,000,000 refund to customer accounts in PGL's service territory by refunding one hundred dollars ($100.00) to each customer account in Service Classification No. 1 - Small Residential Service ("SC No. 1") that is receiving service from the Company upon the date this Order is entered. The $100 refund shall be provided to all SC No.1 customer accounts—both transportation and sales service.

After $100 dollars is allocated to each SC No. 1 customer account, the remainder of the $96,000,000 shall be allocated to all remaining Service Classifications (“Non-residential Service Classifications) based on each Non-residential Service Classification’s share of the total PGA gas consumed by all Non-residential Service Classifications during the 2001, 2002, 2003, and 2004 reconciliation periods (“Reconciliation Periods”).

Each Non-residential Service Classification’s allocation, with the exception of the allocations to Service Classification No. 3 - Large Volume Service ("SC No. 3") and Service Classification No. 4 - Large Volume Demand Service ("SC No. 4"), shall be divided by the total number of customer accounts (both transportation and sales) 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 Non-residential Service Classifications shall be provided to both sales and transportation customer accounts with the exception of SC No. 3 and SC No. 4 customer 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. Refunds to SC No. 4 customer accounts shall be calculated in the same manner as refunds to SC No. 3 customer accounts.

01-0707

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 days of the date this Order is served to the parties, PGL shall file an informational filing with the Commission's Chief Clerks 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:

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;

the amount to be refunded to each customer account in each service classification;

the number of current and former customers that held customer accounts on Service Classification No. 3 and Service Classification No. 4 during the Reconciliation Periods and consumed PGA gas at any time during the Reconciliation Periods;

the amount of PGA gas consumed during the Reconciliation Periods by each current and former customer that held a Service Classification No. 3 or Service Classification No. 4 account during the Reconciliation Periods;

an indication of whether former SC No. 3 and SC No. 4 customers are still a going concern, the amount to be refunded to customers in each service classification; and,

the amount to be refunded to each current and former customer account that received service under Service Classification No. 3 and Service Classification No. 4 during the Reconciliation Periods.

The refund shall be issued in one installment and shall be considered a credit to each 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.

01-0707

Refunds shall be issued to all customer accounts within thirty 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. The filing will also include the total numbers of customers receiving the refund, and for all Service Classifications except for SC 1, the refund amount for each customer.

2. Accounting Proposals Adopted from the ALJPO

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. Section III.A.2 of the Settlement includes a statement paralleling Finding (13) of the 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 and third party non-tariff 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.

01-0707

The text of those findings from the ALJPO incorporated into the Settlement by the Addendum are:

(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;

01-0707

(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.

(ALJPO at 135-136.)

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.

01-0707

Gas Reconciliation

A reconciliation of Peoples Gas’ 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	$30,466,781.15
2. Factor A Adjustments Amortized to Sch. I at 09/30/00 per 2000 reconciliation (Refund)/Recovery	13,153,581.51
3. Factor O (Refunded)/Recovered during 2000	_______0_______
4. Balance to be (Refunded)/Recovered during 2001 from prior periods	43,620,362.66
5. 2001 PGA Recoverable Costs	883,501,818.75
6. 2001 PGA Actual Recoveries	958,580,973.43
7. Interest	801,015.36
8. Other Adjustments	0
9. Pipeline Refunds	___(614,882.34)__
10. (Over)/Under Recovery for 2001	(74,893,021.66)
11. PGA Reconciliation Balance at 9/30/01 (Over)/Under Collected	(31,272,659.00)
12. Factor A Adjustments unreconciled at 9/30/01 (Refund)/Recovery	(10,342,032.56)
13. Unamortized Balance at 9/30/01 (Refund)/Recovery	($20,930,626.44)
14. Requested Ordered Reconciliation Factor to be (Refunded)/Recovered [Factor O]	0

01-0707

II.

The Procedural History of this Docket

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.⁵ (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, PGL 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 and its 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). In fact, PGL contended that it had no business dealings with enovate. (See, e.g., CUB Motion to Compel, February 3, 2004). enovate is described below. When reopening discovery, the ALJ permitted the movants to seek additional information through discovery from PGL about its relationship with its affiliate, enovate, but ruled that the discovery requests the movants sought to enforce were vague and overbroad. (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)). While ultimately PGL did respond to discovery requests asking for information about its relationship with enovate, those records are not complete. Throughout the course of discovery, PGL maintained that Enron North America, a co-owner of enovate, had that information. (See, e.g., GCI Init. Brief at 30).

____________________

⁵ 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.

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.

01-0707

The Protective Order

Another contested item in this docket was the Protective Order, which was entered after the parties fully briefed this issue.⁷ At that time, PGL maintained that highly confidential information about its gas-buying practices was being tendered in discovery and these documents needed to be kept under seal to protect PGL from unscrupulous use of information in this docket in the marketplace. In response, Staff, CUB, the City and the AG maintained that the information PGL claimed was confidential was “stale;” that is, it was too old to be used against PGL in the marketplace. Except for the obvious lapse of time, these parties did not provide factual support for this factual conclusion.

There is evidence in this proceeding concerning PGL’s and its affiliates business dealings with Enron which, if revealed in a competitive setting could cause harm to PGL or an affiliate.⁸ Therefore, the protective order remains in place. However, the Commission concludes that the information set forth herein discussing certain terms in the business dealings among PGL/PGL affiliates and Enron Midwest/Enron North

America is not protected by the protective order, as it is not information that, if revealed in a competitive setting, would cause harm to PGL or an affiliate. This information does not divulge PGL’s gas buying needs, its buying practices, or like information that could be used against PGL or an affiliate in the marketplace.

The Commission additionally notes that the contracts in question were executed in September of 1999, over six years ago, and they created a highly unique business arrangement. The full consideration (what is given up or taken pursuant to a contract, i.e., money or services) cannot necessarily be ascertained by analyzing any one contract, or even all of the contracts, as some of the contracts were inter-dependent. Also, some of the contracts were verbal. And, some of the consideration provided is not mentioned in the contracts.

Finally, the contractual arrangements amongst PGL/PGL affiliates and Enron North America/Enron Midwest were designed to avoid Commission detection. Thus, consideration for the transactions represents what personnel at the parties thereto were willing to give up in these transactions, while still avoiding Commission scrutiny. In other words, the consideration in these transactions is not representative of any true market value or true purchasing need on the part of PGL or a PGL affiliate.

____________________

⁷ In an Interlocutory Appeal filed on behalf of the People of the State of Illinois, the AG maintained, essentially, that this order was entered without the parties having briefed the issue. (01-0707, Petition of the People of the State of Illinois for Interlocutory Review, August 11, 2004). This simply is not correct. (See, e.g., Comments of City and CUB Regarding Issuing a Protective Order, July 20, 2004).

⁸ The protective order only protected the confidentiality of documents subject to the attorney-client privilege and trade secrets, which is, information that, if revealed in a competitive setting, could cause harm. (See, 01-0707, Protective Order, July 21, 2004).

01-0707

As to information about Manlove Field which could be considered to be proprietary, PGL divulged that information about Manlove Field in the public version of its briefs. That information, therefore, is not subject to the protective order.

C. The Applicable Legal Standards

1. The Duty Imposed on PGL 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 Commission, 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 PGL’s purchased gas adjustment tariff(“PGA”), which allows it to pass its gas costs on directly to consumers.⁹ (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 PGL in supplying gas to consumers. (83 Ill. Adm. Code 525.40(a)). With respect to gas costs, consumers pay PGL whatever price PGL 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 PGL 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, PGL must “refrain” from doing anything that would increase the gas charge. (Id.).

Although PGL’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 PGL 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 PGL’s 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)).

____________________

⁹ The word “consumer” is used here to mean PGL’s rate-paying customers, including both residential customers and businesses.

01-0707

2. The Burden of Proof

The Commission commenced this reconciliation proceeding, as it does every year. However, the burden of proof is on PGL to establish the prudence of its costs of gas purchases and related costs. (220 ILCS 5/9-220(a)). PGL has the burden to prove this by a 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 NE2d 68 (1987)).

III. Entities Involved

A. Findings of Fact

As the record demonstrates, several entities are involved in this rather complicated fact pattern. Of primary importance is PGL, a local distribution company (“LDC”) and the subject of this reconciliation proceeding. It distributes gas to consumers that are within its service territory, chiefly located in the City of Chicago. It must purchase the gas that it distributes to consumers. (Tr. 871, 887). Next, Peoples Energy Corporation (“PEC”), PGL’s parent company, is a player in several scenarios discussed later in this order. Affiliated with PGL and PEC are Peoples Energy Resources Company (“PERC”) and North Shore Gas Company. (PGL Ex. L at 3). Additionally, Enron North America Corp. (“Enron NA”) was wholly-owned by Enron Corp. (Staff Ex. 2.00, Attachments, Guaranty, at 1). The list does not stop here.

PGL furnished Staff and the parties with two letters of intent (“First LOI” and “Second LOI”) between PEC and Enron NA. The First LOI was executed on September 16, 1999 by PEC and Enron NA.¹⁰

The First LOI outlined Enron NA’s and PEC’s intent to pursue a joint venture. In this LOI, Enron NA and PEC stated a desire to enter into Hub and marketing services to the Chicago wholesale marketplace, including: parking, balancing, exchange and title tracking services, risk management services, asset optimization services to PEC and affiliates, wholesale bundled services to PEC in power and gas, and investment in and monetization of capital improvement of PEC’s Chicago infrastructure. (Id. at ST-PG 192)). To effectuate these dealings, PEC and Enron NA were to form a new company in the form of a joint venture.

____________________

¹⁰ The First LOI was executed on the same day as the GPAA. The signatories to this LOI were William Morrow, Vice President of PEC, and David Delainey, Managing Director of Enron NA, the same as the signatories to the GPAA.

01-0707

The Second LOI outlined profit-sharing of hub revenues between PEC and Enron NA, sharing of peaking service between the two parties and sharing of Enron NA’s revenues. Though this document was apparently not executed (signed by the parties), the actual relationship between the parties was very similar to what the First LOI provided. It provided that the terms of a definitive contract between the two were to specify the terms of conditions of the business arrangements and the sharing of profits and losses. (Id. at 192). No written contract was actually ever executed by these parties; instead, they proceeded to do business based on a verbal commitment. (Staff Ex. 9.00, Attachment G).

Enron NA and PERC each formed a subsidiary for the purpose of owning interest in another limited liability company. Enron NA formed Enron Midwest, LLC (“Enron Midwest” or “Enron MW”); PERC formed Peoples Midwest, LLC (“Peoples Midwest”). (Staff Ex. 7.00 at 8). These two entities then formed enovate, LLC¹¹ to facilitate a profit-sharing arrangement that gave PEC/PERC 50% of all of the profits Enron Midwest gleaned through various business dealings with PGL.

1. enovate, LLC

Peoples Midwest and Enron Midwest formally created enovate, LLC (”enovate”) by a Limited Liability Company (“LLC”) Agreement dated April 26, 2000. (PGL Ex. N at 3). According to the agreement, Peoples Midwest and Enron Midwest each invested approximately $100,000 in enovate. In return, each entity received, 50% of the profits from enovate. (PGL Ex. N at 3, Staff Ex. 9.00 at 9, Attachment C; Tr. 800). When Enron Midwest transacted business with PGL during the time period in question, 50% of Enron Midwest’s profits were credited to enovate. Thus PEC/PERC received that 50% of Enron Midwest’s profits. (Staff Ex. 9.00 at 15-16; 7.00 at 11). Enron Midwest was the managing partner of enovate because it possessed the skills, resources and expertise to operate enovate efficiently and profitably. (Tr. 812-13).

enovate had few tangible assets or expenses of its own. enovate owned pipeline transportation rights with Trunkline Gas Company, interruptible services that it purchased from interstate pipelines and local gas distribution companies, as well as physical gas supply agreements with Northern Illinois Gas Company and Northern Indiana Public Service Co. (PGL Ex. N at 4-5). enovate also claimed to have 30 Bcf of storage.¹² (See, City-CUB Ex. 2.00 at 18). The record demonstrates that Enron NA and PERC provided operations and management needs. enovate used office space rented by Enron NA and other facilities, computer systems and training systems provided by Enron NA. The personnel who ran enovate were employed by and paid by PERC. (Tr. 793, 795). enovate had no payroll. (Tr. 794-95). Because PERC and Enron NA each bore the labor costs associated with enovate, there was no need for enovate to have a payroll. (PGL Ex. N at 6). enovate had no administrative costs and no cash on its books. (City-CUB Ex. 1.0 at 65).

____________________

¹¹ enovate, LLC was originally named Midwest Energy Hub, LLC.

¹² A Bcf of gas is one million MMBtus; a MMBtu is one million Btus. (Staff Ex. 2.00, Attachments, GPAA, at 5; Tr. 1004). Also, a decatherm, or a Dth, is one million Btus. (NYMEX.com\glossary). A Btu is a British thermal unit, which is the amount of energy required to raise the temperature of one pound of pure water the one degree from 59 degrees to 60 degrees, Fahrenheit, at sea level pressure. (Staff Ex. 2.00, Attachments, GPAA, at 2).

01-0707

On November 28, 2000, PGL filed an application pursuant to Section 7-101¹³ of the Public Utilities Act (“PUA” or “the Act”) for Commission permission to enter into a contract with an affiliate, enovate, LLC. In that verified application, PGL averred that PGL and enovate entered into a contract, subject to Commission approval, which governed the terms of purchases and sales between PGL and enovate. This contract was for the purpose of “optimizing” the use of PGL’s gas supply and capacity assets. (Application of Peoples Gas Light and Coke Co. for Authority under Section 7-101 of the Ill. Pub. Utilities Act to enter into a Master Natural Gas Agreement with enovate, LLC, Docket No. 00-0760, at 2). On March 21, 2001, PGL filed a motion to dismiss its application, stating that PGL no longer desired to expend the resources necessary for the proceeding. (Motion to Dismiss, March 21, 2001, Docket No. 00-0760). The Commission granted the Motion to Dismiss on May 9, 2001. However, PGL continued to directly transact business with enovate. PGL also transacted business with enovate indirectly, through Enron NA/Enron Midwest. At no time did the Commission approve any affiliate interest agreement between PGL and enovate.

Evidence adduced during this reconciliation proceeding outlines transactions between PGL and enovate. PGL witness Mr. Morrow¹⁴ testified that during the time period in question, enovate purchased “Hub services” from PGL pursuant to an operating statement on file with the Federal Energy Regulatory Commission (“FERC”). (PGL Ex. N at 5). enovate also used PGL’s gas distribution system. Without PGL’s gas distribution system, enovate would not have been able to conduct the transactions set forth herein. enovate also sold gas directly to PGL in the “Trunkline Deal” and Transaction 16/22. These transactions will be discussed below. enovate further conducted other transactions with PGL through Enron Midwest. To reiterate, none of enovate’s transactions with PGL were made with Commission approval of an affiliated interest contract.

According to Mr. Morrow, to keep track of transactions between enovate and Enron, enovate issued a series of daily reports that recorded and valued activity every day, year-to-date, and it valued what might have occurred that day. (Tr. 798). Those reports were distributed among PEC personnel in its risk and credit areas, and to the PERC employees who worked at enovate. (Id.; Tr. 804). enovate also distributed all of the accounting data that was needed to record its income. (Tr. 798). Additionally, if PEC accountants needed details on a daily basis or on a monthly basis, Enron provided this information to those accountants. (Tr. 798-99). These reports were also published and circulated daily; they tracked information from trades and other activity. (Tr. 804).

____________________

¹³ Section 7-101 of the PUA governs transactions between affiliated interests.

¹⁴ In addition to being the Vice President of PEC, Mr. Morrow is also the Vice President of PGL, the President of PERC, member of the Board of Managers for enovate, and Peoples Midwest’s representative on enovate’s Board of Directors.

01-0707

Mr. Morrow testified generally as to the types of transactions enovate engaged in. He testified that as a wholesale gas marketer, enovate entered into physical and financial gas purchases and sales, as well as speculative trading.¹⁵ ( PGL Ex. N at 4). enovate concentrated its business in the Upper Midwest. (Id.). Mr. Morrow also testified as to the nature of enovate’s transactions with Peoples and enovate's sources of revenue. He stated that, although he received daily reports about enovate’s business activities, he did not know what percentage of enovate’s activities were devoted to speculative trading. (Tr. 804-806). He testified that because Enron Midwest was the managing partner of enovate, Enron kept all of the books. (Tr. 806). According to Mr. Morrow, the data provided by Enron to Peoples Energy was not “fine cut” enough to be able to calculate how much of enovate’s activities concerned speculative trading. (Tr. 806). Peoples’ personnel did not feel that it was necessary or required of them to have a sub-split of enovate’s business activities. (Id.). There is no evidence in this record that any of enovate’s revenue came from sources other than the revenue-sharing of Enron Midwest’s profits gleaned from PGL. (See, e.g., PGL Ex. N at 4; Tr. 805).

PEC had an audit performed of enovate to determine that the correct procedures and monitoring practices were in place to protect PEC in its new venture with enovate. (Tr. 808-09)._ This audit was conducted by an internal group and an outside consultant who specialized in derivatives in energy trading. (Id.). In this audit, the auditors expressed concern that revenue-sharing between PEC and Enron “related to the optimization of the PGL Hub” and the activities of Enron Midwest were not formally documented. The auditors noted that Enron Midwest revenues were being transferred quarterly to enovate through an “annuity trade” (quotes in original text) between the two entities, but because nothing was in writing, PEC exposed itself to higher financial risk than it would have if there were written contracts memorializing its profit-sharing agreement with Enron. (Staff Ex. 9.00, Attachment G at 2).

enovate was in existence for only a short period of time when Enron filed for bankruptcy.¹⁶ After Enron’s bankruptcy filing, PEC bought Enron’s share in enovate for approximately $2 million. (Tr. 814, 817). PEC sent a “team” to Houston after that to retrieve any record that was necessary to wind down enovate’s business for that year. (Tr. 815). PEC personnel did not gather all of enovate’s documents. enovate discontinued operating in 2002. (Id.).

The following represents significant financial milestones in enovate’s history: Enron Midwest and PEC each contributed $100,000 paid-in capital to enovate. (See., e.g., City-CUB Ex. 1.0 at 65). On September 30, 2000, which was the end of enovate’s first year of operation, enovate reported revenues of $4,319,083. enovate did not receive capital contributions from PEC/Enron until October of 2000. During the reconciliation period, enovate gained $100 million in revenues and approximately $20 million in profits. (See, e.g., City-CUB Ex. 1.0 at 64-65). During the reconciliation period, PEC garnered $9,052,823 in revenues from enovate. Enron garnered an additional $10,630,817.¹⁷ (Staff Exs. 5.00 at 27; 9.00, Attachments, Scheds. 9.05 and 9.06). City of Chicago/CUB witness Ms. Decker opined that such astronomical earnings are not commonplace in the midstream gas industry. (City-CUB Ex. 1.0 at 65).

____________________

¹⁵ Speculative trading is the act of engaging in buying or selling natural gas at a definite price, where the entity engaged bears the risks and opportunities associated with continual changes in price. (PGL Ex. N at 4).

¹⁶ The Commission takes judicial notice of the fact that Enron Corporation filed for bankruptcy on December 2, 2001.

01-0707

B. Conclusions of Law - Scope of this Proceeding

1. PGL’s Argument

PGL argues that the scope of this proceeding should not include transactions involving enovate because those operations are only relevant if and to the extent that they affected recoverable gas costs. PGL states that because the actions of enovate had no effect on recoverable gas costs, the Commission cannot consider those transactions here. PGL maintains that Business and Professional People for the Public Interest v. Ill. Commerce Comm., 171 Ill. App. 3d 948, 525 N.E.2d 1053, (1^st Dist. 1988), does not apply here because that case concerned a FAC reconciliation and was governed not only by Section 9-220 of the PUA, but also by the federal Public Utilities Regulatory Policies Act of 1978 (“PURPA”). According to PGL, PURPA required the utility in that case, Commonwealth Edison Company (“ComEd”), to insure maximum economies in those operations and purchases that affect the rates to which such clauses apply. Because the transactions in question here are not subject to PURPA, PGL avers that the ruling in Business and Professional People for the Public Interest v. Ill. Commerce Comm., does not apply here. (PGL Reply Brief at 9-11).

2. The Position of the GCI

The GCI contend that the scope of this proceeding is broad, citing Business and Professional People, 171 Ill. App. 3d at 958. The GCI argue that the scope of any reconciliation proceeding encompasses the non-procurement actions of a utility that have both direct and indirect impact on utility charges when those charges are passed on to consumers, which they allege is the case here. The GCI aver that in Business and Professional People, the Appellate Court rejected an argument that a $70 million refund ordered by the Commission due to the poor performance of a nuclear power plant was outside the scope of ComEd’s FAC reconciliation, even though the costs incurred regarding nuclear power plants were in base rates, not in a FAC reconciliation. ComEd incurred this $70 million charge because the nuclear power plant was supposed to operate at 60% capacity, but it only operated at 18% capacity, requiring ComEd to purchase additional power and pass the cost of that power on to consumers in its FAC. (See, GCI Reply Brief at 19).

When rejecting ComEd’s argument that the Commission exceeded the authority conferred on it by the statutory predecessor to Section 9-220, the Appellate court ruled that “To rule otherwise would result in an extremely narrow interpretation of a broad grant of statutory power and would also defy common sense.” The GCI posit that the enovate and hub-related transactions had an effect on what consumers paid. (Id.).

____________________

¹⁷ These amounts do not include profits from the Trunkline Deal and the SOC. (Staff Ex. 9.00, Attachments, Scheds. 9.05, 9.06).

01-0707

The GCI also cite Ill. Commerce Commission, on its own Motion, Revisions of Part 525, 1995 Ill. PUC Lexis 579, in which the Commission ruled that reconciliation proceedings are the proper venue for examining utilities’ design-day planning and the way that utilities have used their system supply and capacity in off-system transactions and in exchanges. In the Part 525 Order, the Commission also concluded that prudent management and gas supply and storage capacity could include economic use of PGA assets or costs, to reduce PGA charges imposed on consumers. The GCI reason that here, under a variety of arrangements between PGL and Enron affiliates, opportunities to realize revenues that could offset PGA costs were either foregone or they were diverted to a PGL affiliate. (GCI Init. Brief at 23).

The GCI maintain that hedging activities are among the Section 9-220 recoverable costs, as those activities are price management costs. Also, 83 Ill. Adm. Code Section 525.40(d) requires that all gas costs recovered by a utility must be offset by the revenues derived therefrom, if any of the associated costs regarding that transaction are recoverable PGA gas costs. (Id.).

3. Commission Analysis and Conclusions

As shall be set forth herein in the section entitled “enovate,” the record evidence establishes that in several instances, PGL’s affiliates used enovate to artificially inflate costs borne by consumers in a manner that unfairly conferred profits on Enron and PGL affiliates. In the face of this evidence, PGL argues that the Commission should not be determining whether those profits artificially inflated costs borne by consumers in its PGA. The Commission disagrees. PGL cites no law that requires us to ignore transactions that raised gas costs, either by passing on unnecessary costs through enovate, or by engaging in transactions with enovate at less than market value, depriving consumers of the true market value of the transactions.

We also note that discovery was reopened in February of 2004 in order to determine what transactions involving enovate affected PGA gas costs. Since at least that time, with regard to enovate transactions, counsel for PGL was on notice that evidence regarding enovate’s business, which impacted PGL’s gas costs, could be an issue at the hearing. The hearing convened over a year later, in April of 2005. Yet, during the hearing, PGL made no attempt to exclude the evidence it now contends is extraneous to this proceeding. PGL, therefore, has waived its right to do so. (See, e.g., Smith v. Department of Professional Regulation, 202 Ill. App. 3d 279, 287, 559 N.E.2d 884 (1^st Dist. 1990), ruling that failure to raise issues such as due process, at hearing, constitutes waiver of that issue.).

PGL’s construction of Business and Professional People, 171 Ill. App. 3d at 958, does not aid it. In Business and Professional People, the Appellate Court concluded that ComEd was subject to the same requirements under the PUA as it was under PURPA. However, it noted that the PUA conferred a broad grant of authority on the Commission to inquire into production management, in order to determine whether ComEd’s fuel purchases were prudently made. (Business and Professional People, 171 Ill. App. 3d at 958). In so ruling, it stated:

01-0707

If in a fuel reconciliation proceeding, the Commission could not examine the reasons that necessitated a fuel purchase, the (statutory) prudence standard would have no effect . . . a utility could generate electricity in any manner it chose, efficiently, or inefficiently.

(Id. at 958). Thus, in Business and Professional People, the Appellate Court did not apply PURPA, as PGL suggests. A FAC reconciliation is subject to the same statutory requirements as a PGA. (See, e.g., Ill. Power v. Ill. Commerce Comm., 245 Ill. App. 3d 365, 612 N.E.2d 925 (3^rd Dist. 1992)). Even if PGL did not waive its right to contest the propriety of this evidence, PGL has failed to establish that evidence regarding enovate transactions is not relevant.

C. Conclusions of Law - Enron Profits

Staff’s Position

Staff recommends that the Commission disallow $19,683,640 for PGL’s involvement with enovate, approximately $9.1 million of which is the profit PEC garnered through enovate during the year in question, and approximately $10.6 million of which is Enron’s profit for the year in question. (Staff Ex. 5.00 at 6-7). Staff posits that since Enron shared profits with PEC through enovate, PGL personnel had an incentive to use Enron/Enron affiliates, as opposed to other entities, for gas supply, irrespective of PGL costs. This profit-sharing agreement provided both PGL/PEC and Enron affiliates with the motive to manipulate the prices PGL paid to Enron/Enron affiliates for gas, so that profits would be allocated to PEC shareholders, instead of consumers through PGL’s PGA. Dr. Rearden opined that without such an intention, it would be difficult to understand why PGL entered into transactions that were so transparently imprudent. (Staff Ex. 12.00 at 2-3).

According to Staff, the “enovate P & L” statement establishes that some, if not all, of enovate’s transactions were recovered through the PGA. Transactions such as the “38 Special” and other 3PSEs were recorded as credits to PGL’s PGA gas charge. Staff also takes issue with PGL’s statement that Staff does not have more concrete evidence regarding enovate’s activities. PGL did not tender documents in discovery regarding enovate, stating that Enron kept these documents. (Staff Reply Brief at 68, 69). Staff additionally contends that a lack of documentation regarding enovate’s business transactions is prohibited by General Instructions Nos. 2, and 14, of Part 505 of the Commission Rules, which require PGL to keep all records needed to develop the history or facts regarding a transaction. (Id. at 75).

Staff points out that both agreements, the GPAA and the LOI, were executed on the same day. According to Staff, it defies logic to maintain that two parties executed two agreements on the same day, without having the parties consider both contracts as part of the same arrangement. (See, e.g., Staff Ex. 7.00 at 8). Staff acknowledges that it does not matter that the entity involved in the profit-sharing was Enron, which, filed for bankruptcy subsequent to the reconciliation period. Rather, what is important to Staff is the nature of the transactions at issue that PGL entered into. (Staff Ex. 12.00 at 2-3).

01-0707

Staff maintains that it presented evidence establishing that enovate could not have done business without using PGL’s PGA assets, such as interstate transportation and leased storage. Staff provided documents, like PGL’s list of “annuities” it paid to Enron Midwest/enovate. Staff concludes that PGL presented no evidence refuting that which Staff presented. (Staff Reply Brief at 70).

GCI’s Position

The GCI concur with Staff. (See, CUB Ex. 1.0 at 8). GCI points to additional transactions that show PGL’s improper dealings with enovate, Enron and PGL’s parent. The GCI contend that when PEC assumed the Citgo Contract and sold gas to PGL through Enron Midwest, PEC structured this transaction to avoid Commission scrutiny under Section 7-101. Also, the Trunkline Deal was not an arm’s-length transaction. According to the GCI, the Trunkline Deal involved Enron Midwest in a manner that conferred no benefit on ratepaying consumers, as Enron Midwest was only involved to avoid the Commission’s scrutiny, in an attempt to conceal an unapproved affiliate transaction. (GCI Init. Brief at 70, 72-73). The record contains various e-mails to William Morrow. The GCI argue that these e-mails establish that PEC deliberately avoided filing for Commission approval of enovate pursuant to Section 7-101 of the PUA. (GCI Init. Brief at 60; City-CUB Exs. 1.32, 1.33, 2.0 at 14).

The GCI point out that PGL never presented evidence that refuted Ms. Hathhorn’s testimony that 100% of Enron Midwest’s activities flowed to enovate, 50% of which was shared with PERC/PEC. They maintain that once evidence establishing a nexus between PGA assets and enovate profits was revealed, PGL had the burden to rebut that evidence. Instead, PGL offered a vague assertion that enovate had a variety of assets. Some amount of enovate’s income came from speculative trading and enovate purchased non-tariff services from Nicor and Northern Indiana Public Service Co. In support, the GCI cite PGL Ex. N at 5. (GCI Reply Brief at 49-51).

The GCI contend that enovate used PGA assets-PGL’s owned and leased storage, its gas supply and system injection and withdrawals. They aver that the only explanation in this record for enovate’s astronomical profits was enovate’s preferential use of PGL assets. (GCI Init. Brief at 59-61).

PGL’s Position

PGL concedes that enovate was its affiliate. Nevertheless, it contends that affiliates can purchase services at the regulated rates and PGL can enter into transactions with affiliates without Commission approval, if those transactions are made in the ordinary course of business, citing 220 ILCS 5/7-101 and 83 Ill. Adm. Code 310. PGL further claims that neither enovate nor any other affiliate bought or sold gas from it, citing PGL Ex. C, 37-38. (See, also, PGL Init. Brief at 86). Allegedly, PGL had no other contact with enovate; enovate did not manage PGL’s Hub and enovate costs and revenues did not flow through PGL’s PGA. Thus, according to PGL, any transaction PGL entered into with enovate was not subject to Section 7-101 of the PUA. Citing no fact of record, PGL further argues that any enovate transaction on PGL’s system, or through association with PGL, has “no bearing on (PGL’s) costs.” (PGL Init. Brief at 87-88). However, PGL admits that enovate purchased hub services from PGL in the reconciliation period. (PGL. Init. Brief at 86, PGL Ex. C at 37-38).

01-0707

PGL further contends that enovate had a variety of assets, even if those assets were not physical things. PGL concludes that Staff has unjustly maintained that enovate’s profits were derived solely from its association with PGL. PGL lists various assets enovate had, such as office space, capital contributions from PEC and Enron Midwest, parent guarantees, and firm pipeline capacity from Trunkline. PGL does not mention one instance in which enovate generated income from using these assets. (PGL Init. Brief at 86-88). PGL believes that its witnesses Zack and Morrow rebutted Staff’s and the GCI’s recommended disallowances. (Id. at 88; PGL Ex. K at 11-13).

PGL concedes that enovate used its gas supply system, but contends that the fact that enovate profited from that use is no basis for a cost disallowance. PGL cites no law or facts in support of this argument. Instead, PGL argues that businesses always intend to “make money.” PGL asserts that Staff and the GCI failed to prove that there was a tie between enovate’s income and the prudence of its recoverable gas costs. Moreover, there is no evidence that the lawful business dealings between PEC and enovate harmed consumers. According to PGL, Staff and the GCI did not present any actual proof that enovate made profits through use of PGL’s system. (PGL Reply Brief at 56-57, 89).

Also, according to PGL, it was unable to quantify the amount of money enovate generated from speculative trading, citing Mr. Morrow’s testimony that the data PEC had regarding enovate was not “fine cut” enough to precisely calculate this amount. (Tr. 805-06). PGL also had no burden to respond to Staff’s and the GCI’s allegation about enovate generating profits from PGL’s ratepaying consumers because those allegations were unsupported. (Id. at 58-59).

Commission Analysis and Conclusions

1) Lack of Evidence Regarding enovate’s Operations

PGL claims that it did not conduct business with enovate. It asserts that enovate had assets through which it gained profits that have nothing to do with PGL. However, at hearing, Mr. Morrow admitted that PGL supplied no proof as to how much, if any, of enovate’s profits were gained from these other sources. (Tr. 805-06). Conspicuously absent from this record is any documentation, on the part of PGL, as to what business enovate, its affiliate, actually conducted. For example, Mr. Morrow, who received daily reports as to enovate’s activities, testified that enovate engaged in speculative trading. He could not say, however, how much of this trading occurred, because Enron had all of the documentation. (Id.). It is noteworthy that both the SOC and the GPAA required Enron North America to provide PGL with documentation, which is some indicia that generally, Enron was contractually required to provide PEC/PGL with appropriate documentation. Yet, often PGL did not have documentation regarding enovate’s operations.

01-0707

On two occasions, PGL successfully retrieved documents from Enron regarding enovate’s business activities. (See, e.g., Tr. 610-611; 617-18; 814-819). Yet, even in the face of outstanding discovery requests, PGL never tendered evidence in discovery or at hearing regarding enovate’s operations.¹⁸ PGL has provided no explanation as to why enovate records were still with Enron after PEC purchased Enron’s half of enovate and continued to wind up enovate’s business. The Commission finds PGL’s lack of documentation regarding its dealings with enovate to be imprudent.

PGL’s failure to produce such documentation has other ramifications. A trier of fact can draw an inference, when a party has failed to produce evidence within its power to produce, that this evidence if produced would be adverse to that party. (Schaffer v. Chicago and Northwestern Co., 129 Ill. 2d 1, 25-26, 541 N.E.2d 643 (1989)). However, this inference may be drawn only when: a.) the evidence was under the party’s control and could have been produced through reasonable diligence; b.) a reasonably prudent person would have offered the evidence, if he believed that it would have been favorable; and c.) no reasonable excuse for failure to produce the evidence has been shown. (Kersey v. Rush Trucking Co., 344 Ill. App. 3d 690, 696, 800 N.E.2d 847 (2^nd Dist. 2003)).

Part 505 of the Commission’s Rules requires PGL to keep documents verifying the reasons for its transactions. The fact that PGL later acquired documents from Enron on more than one occasion, establishes that PGL was able to access those documents. The fact that PGL could obtain these documents establishes that these records were under PGL’s control. (Berlinger’s v. Beef’s Finest, 57 Ill. App. 3d 319, 325, 372 N.E.2d 1043 (1^st Dist. 1978); Fentress v. Triple Mining, 261 Ill. App. 3d 930, 938, 633 N.E.2d. 102 (4^th Dist. 1994)). A reasonable person would offer documentary evidence establishing what transactions enovate entered into, with specificity, if that evidence supported a contention that enovate conducted business that had nothing to do with use of PGL’s PGA assets. This is especially true here, as Staff presented documentary evidence showing enovate’s profits were derived from use of PGL’s PGA assets and those profits unnecessarily raised PGA gas costs. In fact, Ms. Hathhorn testified that her review of various enovate records led her to believe that 100% of enovate’s profits were derived from PGA gas costs. A reasonable person would proffer evidence to rebut or explain this very serious contention.

Also, the fact that Enron still had these documents even after PEC bought Enron’s share of enovate and wound up enovate’s business and even after information was requested in discovery is a flimsy excuse for PGL’s failure to keep track of its own business records. This is especially true, when as Staff points out, Section 505 of the Commission’s rules requires PGL keep records explaining the nature of and need for its transactions.

_____________________

¹⁸ Apparently, however, after Staff’s request for enovate’s general ledger was ruled to be overbroad, Staff did not tender a narrower discover request on this matter. (Tr. 608-10).

01-0707

In Berlinger’s cited above, Mr. Mizaur, the defendant, testified as to what his business sold. He never produced sales slips, but he testified that the proceeds from these sales were used to pay bills. Mr. Mizaur produced no documents to support this testimony. On appeal, Mr. Mizaur argued that the trial judge should not have drawn the inference that these documents, if produced, would be unfavorable to him. He averred that the Internal Revenue Service (the “IRS”) was in possession of these documents; he did not have them. The Appellate Court disagreed, ruling that Mr. Mizaur had the ability to request these documents from the IRS; thus, these documents were under his control. (Berlinger’s, 57 Ill. App. 3d at 325).

The same legal reasoning applies in this case. PGL made no showing that it was unable to acquire pertinent enovate documents. To the contrary, on two occasions, PGL asked for and received enovate documents from Enron. As Staff points out, these documents were required to be in PEC/PGL possession pursuant to the USOA. The Commission can, therefore, draw the inference that if PGL had produced these records, they would have been adverse to PGL. If PGL had produced these documents, they would have established that enovate’s profits were garnered from its relationship with PGL.

2) Section 7-101 and 7-102 of the PUA

An “affiliated interest” is a corporation that owns or holds, directly or indirectly, ten percent or more of the voting capital stock of a public utility. (220 ILCS 5/7-101(a)). The Act provides that:

No management, construction, engineering, supply, financial or similar contract and no contract or arrangement for the purchase, sale, lease or exchange of any property or for the furnishing of any service, property or thing, hereafter made with any affiliated interest, . . . shall be effective unless it has first been filed with and consented to by the Commission or is exempted . . . Every contract or arrangement not consented to or excepted by the Commission as provided for in this Section is void.

(220 ILCS 5/7-101(d)(3)). (Emphasis added). Section 7-102 of the Act, which is entitled “Transactions Requiring Commission Approval” provides that:

No public utility may use, appropriate, or divert any of its moneys, property or other resources in or to any business or enterprise which is not, prior to such use, appropriation or diversion essentially and directly connected with or a proper and necessary department or division of the business of such public utility . . .

01-0707

(220 ILCS 5/7-102(g)). It further provides that:

Every assignment, transfer, lease, mortgage, sale or other disposition or encumbrance . . . of the . . . plant, equipment, business or other property of any public utility, or any merger or consolidation thereof, and every contract, . . . or other transaction referred to in this Section and not exempted . . . made otherwise than in accordance with an order of the Commission authorizing the same . . . shall be void.

(220 ILCS 5/7-102(h)(E)). (Emphasis added). Any contract that confers benefits, whether directly or indirectly, upon affiliates is prohibited by law, unless a utility obtains Commission approval. If a utility enters into a contract with an affiliate without Commission approval, that contract is void, unless it is specifically exempted. PGL claims no such exemption here. (Id.).

On September 16, 1999, the same two persons, David Delainey and William Morrow, executed both the GPAA and a letter of intent to divide profits between PEC and Enron NA, each to receive 50% of the profit from certain business dealings outlined in the letter of intent (the”1999 LOI”). (Group Ex. 1 at ST-PG-194). As PGL has contended, at the time these documents were executed, Enron was a very large and powerful company. There is no evidence that this large, powerful entity had any other need—except one, that would compel it to accept only 50% of the profits it garnered from PEC and its affiliates.

PGL contends, essentially, that enovate’s business transactions were unrelated to PGL. The record clearly shows otherwise. As is evidenced by the 1999 LOI, the intent of parties in that document was to confer profits on Enron, half of which would be shared with PEC through enovate. It defies common sense to contend that Enron would be willing to share half of the profits Enron North America gained through enovate with PEC, unless Enron North America was dependent on PGL/PEC for profits. Otherwise, Enron could simply take its business elsewhere and enter into a contract with another company, whereby Enron would provide services and not be subject to sharing 50% of the profits with an affiliate of that entity.

The credible evidence does not establish that the transactions set forth herein benefited PGL. The only explanation left, based on the credible evidence, for PGL’s willing compliance in deals that did not gain it profit, and indeed, often lost money when compared with what it could have received on the open market, was that PGL acquiesced so that PEC/PERC could benefit through its 50% of enovate’s profits.

The record is replete with evidence that enovate was just a shell company formed to glean profits from PGL’s PGA consumers without conferring any benefits. For example, PGL’s accounting records regarding the “Trunkline Deal” make no mention of Enron Midwest, even though Enron Midwest sold the gas to PGL in that transaction. This is some indicia that PGL personnel did not view Enron Midwest’s role in this transaction as consequential. (Group Ex. 1, ST-PG-75-76). What PGL personnel did find important enough to mention in PGL accounting records was PERC’s 50% profit from this deal--through enovate. (Id.). Also, Ms. Hathhorn testified that 100% of Enron Midwest’s activity flowed first to enovate, for a subsequent 50/50 sharing with PERC/PEC. (Staff ex. 9.00 at 9).

01-0707

Further, the evidence shows a systematic pattern of transactions using PGA assets with Enron Midwest that conferred 50% of Enron Midwest’s profits on PEC/PERC through enovate, at PGA customers' expense. As has been set forth herein, Transactions 16/22; Transaction 103; the “Hub Blowout;” “Manlove Jumpstart,” and other transactions conferred profits on PEC/PERC that were paid for by consumers. There is no evidence that PEC/PERC performed any consideration to earn the profits gleaned through enovate. In addition to reaping profits at consumers’ expense, these transactions brazenly made little, if any, economic sense. For example, “Manlove Jumpstart” was a loan of gas to Enron Midwest, while at the same time, Enron Midwest sold gas back to PGL at a higher price. (Staff Ex. 7.00 at 53-54; Staff Ex. 3.00 at 56). Profits from the sales of gas flowed to PEC/PERC through enovate, not to consumers as required by the PUA and Commission rules.

While typically, in the context of prudence, the fact that a service could have been acquired for less cost does not necessarily make a transaction imprudent, it does here. Enron North America, or Enron Midwest took a profit for its part in the shell game, with an additional profit passed on to PEC/PERC at the expense of PGL, and ultimately at the PGA consumers’ expense. enovate was nothing more than subterfuge for PEC or PERC reaping profits from PGL, which is prohibited by Section 7-101(d) of the PUA.

At a minimum, these transactions were all conducted in such a manner as to confer profit on PGL affiliates at the expense of PGL, the regulated utility. Often, Enron Midwest was the contractual “straw man,” performing nothing in exchange for services or payment rendered, but acting as a third-party so that the PGL/PGL affiliate transactions could evade Commission detection. Sections 7-101 and 7-102 do not provide for an exception for business dealings with affiliated interests that are effectuated through third-parties. (220 ILCS 5/7-101, 7-102). What was accomplished by effectuating the transactions here through Enron North America or Enron Midwest, was escaping Commission detection. Use of a third-party did not make these transactions legal. All enovate contracts involving PGL directly or indirectly are, therefore, void, ab initio.

Further, the Commission finds evidence regarding PGL’s dealings with enovate is properly reviewed in a PGA reconciliation. As the GCI point out, Section 525.40(d) of the Commission’s rules require that revenues derived from non-tariff transactions must be used to offset recoverable gas costs if any of the associated costs are recoverable gas costs. (83 Ill. Adm. Code 525.40(d)). Here, the evidence established that enovate used PGL’s PGA assets such as its PGA gas supply. (See, e.g., City -CUB Ex. 2.5 at 9; City-CUB Ex. 2.0 at 18). Therefore, the profits derived therefrom must offset PGA costs. (Id.). Staff presented evidence establishing that enovate’s profits were solely derived from use of PGA assets. (See, e.g., Staff Ex. 9.00 at 9). PGL’s vague assertion that enovate made an unspecified amount of money that it could not ascertain through means other than use of PGL’s PGA assets does not rebut the evidence presented establishing that enovate made money at the expense of ratepaying consumers.

01-0707

PGL avers that it is improper to “summarily” hold it responsible for what it deems to be lawful arm’s length transactions between PEC, Enron North America and their subsidiaries. PGL points out that its parent has every legal right to structure transactions in any legitimate manner it chooses, even if the effect of that structure avoids Commission jurisdiction. According to PGL, there never was a claim that the transactions between PEC and Enron were unlawful. (PGL BOE at 31).

PGL overlooks the evidence and the arguments presented. By its own admission, PGL’s parent only has a right to structure legitimate, legal transactions in a manner that avoids Commission jurisdiction. It is true that PEC’s unregulated activities do not fall under Commission jurisdiction. However, when PEC structures transactions that involve the use of regulated assets, the Commission has every right and indeed an obligation, to consider the effects of these transactions. PGL’s assertion that no one claimed that transactions between PEC and Enron were unlawful misstates the record. Staff and other parties have established that these transactions violated the law, were not arm’s length transactions, and, they created profits for PEC while increasing consumer gas costs. PGL’s argument is without merit.

PGL also argues that there was no “direct evidence” that the transactions between PEC, Enron North America and their unregulated subsidiaries were structured to avoid Commission scrutiny. Even if this were so, according to PGL, this structure would not be unlawful or in violation of Commission rules. The Commission finds PGL’s argument is baseless. PGL does not state what “direct evidence” is and it cites no law requiring that this Commission only consider it. PGL also cites no law construing Sections 7-101 and 7-102 of the PUA to apply only to transactions that do not involve third-party “straw men” like Enron Midwest. PGL also ignores the fact that it did not present credible evidence rebutting or explaining the evidence presented by Staff establishing that enovate’s transactions with PGL unnecessarily raised gas costs.

PGL further asserts that the findings in the ALJPO do not support piercing the corporate veil. (“Courts are willing to treat parent and subsidiary corporations as ’alter egos’ only where the evidence shows that the parent exercises day-to-day business control over the subsidiary.”). This argument ignores the fact that the law asserted here does not concern piercing a corporate veil pursuant to corporate law. The law asserted here is Sections 7-101 and 7-102 of the PUA.

On Exceptions, PGL avers, citing no fact of record, that when it withdrew its petition for Commission approval of its transactions with enovate, it only continued to conduct transactions with enovate that did not need Commission approval pursuant to Section 7-101 of the PUA. (PGL BOE at 30). Because PGL cites no factual basis for this argument, PGL waived its right to have this Commission consider it. (Fraley, 251 Ill. App. 3d at 77). This argument ignores the evidence presented at hearing establishing that PGL did enter into transactions, directly and indirectly, with enovate.

For all of the above reasons, the Commission finds that PGL acted imprudently when directly or indirectly transacting business with enovate.

01-0707

3) Ordinary Course of Business

PGL correctly asserts that transactions made in the ordinary course of business do not require Commission approval. However, PGL’s direct and indirect transactions with enovate were not conducted in the ordinary course of business. (See, e.g., 83 Ill. Adm. Code 310.10-310.60 defining the ordinary course of business, within the context of what is excluded from Commission approval of affiliated interest transactions, as routine transactions, like routine banking transactions; settling accounts of $5,000 or less with consumers who have financial difficulties; employment contracts; supply contracts and contracts, pursuant to which, the total financial obligation is $500 or less.). For example, PGL paid enovate for gas and pipeline delivery in the “Trunkline Deal.” (Staff Ex. 5.00 at 6). This certainly does not fall within “ordinary course of business” activities outlined above. PGL cites no authority interpreting the phrase “ordinary course of business” to include a purchase or sale of gas made by an LDC.

PGL also ignores its own actions. PGL filed an application seeking Commission approval, pursuant to Section 7-101 of the Act, of its relationship with enovate. PGL’s petition indicated its relationship with enovate would be for the purpose of optimizing “the use of the Company’s gas supply and capacity assets.” (Peoples Gas Light and Coke Co., Application for Authority under Section 7-101 of the Public Utilities Act to Enter into a Master Natural Gas Contract with enovate, LLC, Docket No. 00-0760). The existence of this application is indicia that PGL decision-makers knew that PGL was required by law to petition for Commission approval before it transacted business with its affiliate, enovate. PGL chose to terminate that proceeding because it didn’t want to spend any more resources pursuing Commission approval, not because PGL thought Commission approval was unnecessary. However, after PGL withdrew its application for Commission approval of its relationship with enovate, it continued to transact business with enovate, sometimes directly and sometimes through Enron North America/Enron Midwest. Given all the evidence and other nuances of PGL’s relationship with enovate, the Commission has no choice but to conclude that PGL’s failure to obtain approval of its affiliated interest with enovate was for the purpose of avoiding Commission detection.

For all of the reasons above, the Commission finds PGL acted imprudently by transacting business with enovate. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement fully discussed in Section I .

01-0707

IV. The Gas Purchase Agency Agreement

A. Findings of Fact

1. Background

In October of 1998, PGL filed a petition with the Commission, Docket No. 98-0820, requesting permission to eliminate its PGA and instead impose a fixed gas charge of 31.08 cents per therm. In an Order dated June 7, 1999, the Commission allowed PGL to impose a fixed gas charge, but it authorized PGL to charge a fixed rate of 25.63 cents per therm. In reaching this decision, the Commission concluded that PGL 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 PGL’s proposal improperly normalized day-to-day variations in demand through the spot market, instead of relying on storage. The Commission further concluded that PGL undervalued the credits consumers received for the net revenue from off-system transactions. (See, Peoples Gas Light and Coke Company, Proposal to Eliminate its Purchased Gas Adjustment (PGA) Clause and Include Gas Charges in Base Rates, 1999 Ill. PUC Lexis 414 at *15-21, 24-25).

Pursuant to the effort described above, PGL sent “requests for qualifications” (“RFQs”) to gas marketers and selected Enron NA to be its gas supplier for the fixed gas charge. PGL never implemented a fixed gas charge. PGL 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. (PGL Ex. C at 8-12).

On September 16, 1999, PGL entered into a five-year agreement with Enron NA. Pursuant to this contract, effective October 1, 1999, Enron NA supplied PGL with 66% of its gas supply during the reconciliation year. (See, e.g., Tr. 1011; Staff Ex. 2.00, attachments, GPAA). This contract was called the Gas Purchase Agency Agreement (“GPAA”). (Tr. 907). Before entering into the GPAA, PGL did not seek competitive bids. Rather, it engaged in private negotiations with Enron NA. (PGL Ex. C at 4-5).

The person primarily responsible for entering into the contract with Enron was William Morrow. Mr. Morrow also oversaw the negotiations of the GPAA with Enron North America. (PGL Ex. C at 10). As noted previously, Mr. Morrow and David Delainey, Managing Director of Enron North America, executed the GPAA. (Staff Ex. 2.00, attachments, GPAA, at 36).

Before the GPAA, PGL usually entered into gas contracts with several suppliers for smaller volumes of gas. Those contracts, typically, had terms ranging from four months to five years. (See, e.g., Staff Ex. 2.00 at 8-9).

01-0707

2. 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. (Tr. 1039). The Gas Supply Division includes the Gas Supply Administration Department and it is responsible for entering into and administering contracts for gas supply and for purchasing transportation and storage services. (PGL 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 PGL who actually decided whether to enter into the contract with Enron NA. (Tr. 1046). Previous to the GPAA, PGL’s gas supply contracts provided that PGL would purchase the same quantity for a fixed five-month period (November through March) or for a period of one or two years.

In general, the GPAA had three main provisions through which Enron North America provided PGL with approximately 66% of its total gas supply. (See, e.g., PGL Ex. F, Attachment 10). Those provisions were for Baseload Quantity gas, Summer Incremental Quantity gas (“SIQ”), and Daily Incremental Quantity gas (“DIQ”). (Staff Ex. 2.00, Attachments, GPAA, at 7). The GPAA also required PGL to release pipeline capacity to Enron North America. (Id. at 12). The GPAA was negotiated with a view toward other transactions between the parties. Reference is made therein to several other agreements, gas transportations contracts, the gas supply contracts and the “Master Agreement.” (Id. at 16). These provisions will be further described below.

According to Mr. Wear, when PGL negotiated the GPAA with Enron NA, the following were PGL’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 demand in weather under normal conditions, colder than normal conditions and warmer than normal conditions; and

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

(PGL Ex. C at 11). Later, Mr. Wear asserted that the GPAA also conferred certain non-quantifiable benefits on PGL, like technical support provided by Enron North America and training as to the use of financial hedging instruments, like energy derivatives and options. (PGL Ex. F at 8-9). PGL 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 PGL were concerned that the GPAA could increase the gas costs it passed on to consumers in its PGA.

01-0707

a. Baseload Quantity Gas

This provision refers to the established daily volume of gas PGL was required to purchase from Enron NA by month from October 1999 to October 2004. Daily baseload purchases are ones that PGL made in order to meet its overall supply requirements. (Tr. 1070). 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).

PGL used “normal weather” to establish its baseload needs, although PGL did not provide any study or analysis to support its decision to use “normal weather” as its determinant for baseload quantity gas. (Staff Ex. 2.00). The price of baseload quantity gas purchased pursuant to the GPAA was the price published in Natural Gas Intelligence Chicago citygate¹⁹ First-of-the-Month (“FOM”) price, less a three cent per MMBtu discount.²⁰ (See, e.g., Id., Staff Ex. 3.00 at 8).

b. The SIQ and DIQ Provisions

Two of the GPAA provisions allowed PGL to purchase gas supply to meet its incremental needs. Gas purchased pursuant to the Summer Incremental Quantity (“SIQ”) clause was used to fill PGL’s on-system and purchased gas storage facilities from the months of April through November. SIQ gas was used to create a supply of less expensive summer gas to meet PGL’s needs in the winter, when gas prices would be higher. (Tr. 1209-20). SIQ gas was, in effect, PGL’s “hedging gas.” (See, e.g., PGL Ex. C at 14; Staff Ex. 7.00 at 34).

Pursuant to the GPAA’s SIQ clause, Enron NA agreed to supply gas to PGL at the Natural Gas Intelligence Chicago citygate FOM price, minus three cents per MMBtu.²¹ (Staff Ex. 2.00, Attachments, GPAA, at 2, 9). During the months of April through November, Enron North America was required to provide at least 45,000 MMBtus of gas per day to PGL. (Id. at 6, 9; Tr. 908). Enron NA could, at its sole discretion, deliver an amount up to and including 125,000 MMBtus of gas to PGL. (Id. at 6). Also during this period, whenever Enron MW delivered more than 45,000 MMBtus of gas, PGL was obliged to purchase this gas as long as the gas delivered did not exceed 125,000 MMBtus. (Tr. 909). Thus, Enron NA had the option to, but not the obligation to, deliver up to 80,000 MMBtus of gas to PGL, over and above the contractual minimum of 45,000 MMBtus of gas. (Id. at 2, 9).

______________________

¹⁹ The Chicago citygate is a term that refers to the delivery points on the systems of PGL, North Shore and Nicor Gas. (Tr. 1078).

²⁰ 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).

²¹ Citygate pricing includes the cost of transporting the gas to the Chicago citygate. (See, e.g., Staff Ex. 2.00 at 20).

01-0707

On any given day, PGL had no control over the amount of gas it received pursuant to the SIQ clause. This clause allowed Enron NA to control a portion of PGL’s supply by choosing the amount of SIQ gas delivered to PGL. On 236 of the 244 summer days during the time period in question, Enron forced PGL to purchase maximum SIQ volumes. (Staff Ex. 3.00 at 31). Over 70% of the days when Enron NA delivered the maximum amount of SIQ gas, PGL was forced to sell gas back to Enron NA. (City-CUB Ex. 2.00 at 13; Staff Ex. 2.00 at 29; Tr. 869)

The Daily Incremental Quantity (“DIQ”) clause gave PGL the right to purchase gas at the Gas Daily Chicago citygate Daily Midpoint Price, up to a certain specified level. PGL received DIQ gas with no discount. (Staff Ex. 2.00, Attachments, GPAA, at 3). Pursuant to the DIQ clause, PGL could nominate any portion or no portion of the DIQ. The amount of gas that PGL could purchase on any given day pursuant to the DIQ clause was determined by subtracting the total pipeline capacity that PGL released to Enron North America 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; PGL Initial Brief at 11).

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 PGL.²²(PGL Ex. B at 5). The DIQ clause, however, did not impose this added premium. Mr. Wear calculated the savings incurred by not paying this added premium to be $345,894 for the time period in question. Staff concurs that this provision saved consumers money and it concurs with this calculation.

______________________

²¹ Citygate pricing includes the cost of transporting the gas to the Chicago citygate. (See, e.g., Staff Ex. 2.00 at 20).

²² 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).

01-0707

Staff witness Mr. Anderson opined that the combination of the SIQ provision and the DIQ provision gave Enron NA the incentive to force PGL to pay higher gas prices. The SIQ was priced at lower FOM index prices, minus three cents per MMBtu. The SIQ provision required PGL to take a minimum 45,000 MMBtus per day, although Enron NA could force PGL to take up to 125,000 MMBtus per day. 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 would deliver less SIQ gas and deliver the more expensive DIQ gas instead. When the Daily Midpoint Price rose above the FOM price, Enron had the economic incentive not to sell PGL the full SIQ amount, irrespective of PGL’s needs, forcing PGL to purchase gas at higher prices. (Staff Ex. 2.00 at 24-25).

GCI witness Ms. Decker also averred that the terms of the GPAA allowed Enron NA to force PGL to buy more gas, when doing so was advantageous economically to Enron NA. She opined that allowing Enron NA to determine how much gas PGL received pursuant to the SIQ clause had no practical or prudent purpose. (City-CUB Ex. 1.0 at 11-12). Ms. Decker noted that normally, sellers maximize their profits. Thus, the interest of Enron NA would not translate into the best interest of PGL. Also, normally, LDCs like PGL recover their carrying costs in base rates. Since an LDC cannot increase base rates without filing a rate case, an LDC has the incentive to recover carrying costs by passing on such costs in the form of a gas cost. (Id. at 15). Ms. Decker pointed out that during the reconciliation period, overall, PGL gas prices were 22.28% higher than Chicago citygate prices. She also noted that PGL’s gas prices decreased after Enron filed bankruptcy and concluded that this decrease was caused by the GPAA, as, pursuant to the GPAA, PGL ceded control of price and quantity to Enron NA at the expense of consumers. (Id. at 23-24).

Before entering into the GPAA, PGL performed no analysis of the effect of the DIQ or SIQ provisions on consumers. PGL also did not assess the value that Enron North America received as a result of its ability to manipulate the SIQ clause. (Tr. 911-12). Staff calculated that Enron’s use of the SIQ and DIQ clauses in this manner incurred unnecessary costs that were passed on to consumers in the amount of $4,818,319. (Staff Ex. 3.00 at 35).

c. Provisions that Allowed Enron North America to Increase

the Cost of Gas

According to Staff and GCI, the GPAA contained several provisions that allowed Enron NA to unilaterally increase the cost of PGL’s gas supply. Pursuant to the “Baseload Price Adjustment Clause” (“BLPA”), Enron NA had the option to change the price of a portion of baseload volumes from the FOM price to the Gas Daily and Chicago citygate Daily Price, without notice or limit.²³ (Staff Ex. 2.00, Attachments, GPAA, at 9). The Chicago citygate Daily Price was often higher than the Gas Daily price. However, Enron NA did not invoke this right to change the price during the reconciliation period. (Staff Ex. 3.00 at 18).

______________________

²³ Both the Gas Daily and the Natural Gas Intelligence Weekly are readily-available sources for setting prices in gas contracts. These two publications, however, do not always have the same prices for the same thing. (See, e.g., PGL Ex. C at 18-20). One million MMBtus is approximately equivalent to one Bcf of gas. (Tr. 1004). A MMBtu is one million Btus. (Staff Ex. 2.00, Attachments, GPAA, at 5). A decatherm is also one million Btus. (NYMEX.com\glossary). A Btu is a British thermal unit, which is the amount of energy required to raise the temperature of one pound of pure water the one degree from 59 degrees Fahrenheit to 60 degrees Fahrenheit, at sea level pressure. (Staff Ex. 2.00, Attachments, GPAA, at 2)

01-0707

Notwithstanding any increase imposed by Enron NA made pursuant to the BLPA, 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 PGL. (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 for up to 71,250 MMBtus per day of gas. Pursuant to Article 4.2(b), Enron NA could elect to change the baseload purchase price from the FOM price to the daily midpoint Gas Daily Chicago citygate price. (Staff Ex. 2.00 Attachments, GPAA, at 3, 10). Article 4.2(c) also gave Enron NA the right, during the winter period (December through March), to change the price of baseload gas for up to 71,250 MMBtus per day of gas. Pursuant to Article 4.2(c), Enron North America could elect to change baseload purchases from the Natural Gas Intelligence Chicago citygate FOM prices to the daily midpoint Gas Daily Chicago citygate price. (Staff Ex. 2.00, Attachments, GPAA, at 3, 10).

Ms. Decker opined that Articles 4.2(b) and 4.2(c) gave control over pricing to Enron NA. Under various market conditions, one or the other of the pricing options would be more advantageous to Enron NA and less advantageous to PGL. (City-CUB Ex. 1.0 at 10-11).

d. Released Pipeline Capacity and Foregone Demand Credits

PGL articulated several reasons for its decision to enter into the GPAA. These reasons will be discussed more fully below. Two of PGL’s reasons for executing the GPAA were to prevent the erosion of basis and to eliminate demand charges. As part of PGL’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 PGL to release all of its rights, title and interests to certain pipeline capacity to Enron NA. (Staff Ex. 2.00, Attachments, GPAA, at 12, 13). According to Mr. Wear, Enron NA sold gas to PGL at the citygate to meet PGL’s requirements. To facilitate this, PGL released some of its pipeline capacity to Enron NA (PGL Ex. B at 4; Staff Ex. 2.00, Attachments, GPAA, par. 4.3, Schedule 6.2). PGL released pipeline capacity to Enron NA on the following interstate pipelines: Midwestern Gas Transmission (“MG”) Trunkline, American Natural Resource Company, (“ANR”) and Natural Gas 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 PGL reimbursed Enron NA for all the pipeline transportation costs that it paid. (Staff Ex. 2.00 at 17-19; Attachments, GPAA, Article 4.3). PGL, though, was entitled to all credits, refunds and reimbursements due it from any pipelines for demand or reservation charges. (Id. at 11). PGL also bore the cost of and received the credits from any increase or decrease in variable transportation 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).

Also pursuant to the GPAA, PGL agreed to renew one of its contracts with Natural Gas Pipeline of North America until the term of the GPAA expired on October 31, 2004. (Id. at Art. 6.4). PGL also had recall rights. Enron NA did not have management rights or responsibilities associated with storage. (PGL Ex. C at 22). Enron could, however, use whatever capacity PGL did not need for Enron’s own business purposes without paying PGL anything for the use of those pipelines. (Staff Ex. 2.00 at 19).

01-0707

Mr. Anderson pointed out that PGL traded the use of its pipeline capacity in exchange for citygate prices. These citygate prices included the cost of transporting the gas to Chicago, PGL paid twice for transporting gas to Chicago and passed those costs on to its PGA customers. Furthermore, PGL gave away its excess capacity to Enron NA. (Id. at 20). In Mr. Anderson’s opinion, the GPAA did not protect PGL’s PGA customers from eroding basis. (Id. at 18, 20).

PGL 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 PGL to reimburse Enron NA for all pipeline demand charges incurred. (Staff Ex. 2.00, Attachments, GPAA, Art. 4.3). PGL failed to provide an analysis of the cost components of the GPAA; therefore, there is no evidence to show that PGL isn’t paying demand charges. Mr. Anderson avers that mere statements concluding that the GPAA contains no demand charges are not enough.

In the reconciliation year²⁴ PGL entered into 103 off-system transactions.²⁵ In 1998, PGL entered into 346 such transactions. In 1999, it entered into 358 off-system transactions. In 2000, when PGL operated under the GPAA, PGL entered into only 114 off-system transactions. (PGL Ex. C at 31).

Mr. Wear testified that the number of off-system transactions declined after PGL entered into the GPAA. The reason for the decline, according to Mr. Wear, was the fact that PGL had released some of 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. (PGL Ex. C at 31-32).

Dr. Rearden opined that, during the months when the SIQ was in effect, there was usually plenty of “slack” in the released pipeline capacity for PGL to choose DIQ gas for at least as much volumes as was specified in the DIQ provision. Thus, PGL could force the price of gas upward. (Staff Ex. 7.00 at 35).

e. Flexible Pricing

As more fully articulated below, one of PGL’s reasons for executing the GPAA was that it allowed for flexible pricing options. Article 4.2 of the GPAA allowed the parties to renegotiate the price of 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). PGL did not attempt to arrive at a mutually agreed-upon alternative price to that which was specified in the GPAA until May of 2001. (Tr. 978). There was no reason that PGL personnel could not have procured a lower price before May of 2001. (Tr. 978-79).

______________________

²⁴ PGL’s reconciliation year is also the same as its fiscal year.

²⁵ PGL’s fiscal year is the same as the reconciliation period, October 1, through September 30 of any given year.

01-0707

f. Penalties Paid on Re-sales of Gas to Enron

Article 2.4 gave PGL the right to resell gas to Enron NA. The price for resales was a daily price, minus a penalty. The amount of the penalty was contingent upon how timely PGL was at nominating the resale and the amount of the resale. Also, larger resales incurred larger penalties. The penalties ranged from 1.00 cents to 3.50 cents per MMBtu. (Staff Ex. 2.00, Attachments, GPAA, 9-10; Staff Ex. 3.00 at 28).

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 PGL expected to have an oversupply of gas. (Staff Ex. 3.00 at 29). Resales occurred most often when Enron NA had already forced PGL to purchase the maximum amount of SIQ gas. Only 3.4% of resales during the summer period were made on days in which Enron NA personnel did not choose to deliver the SIQ maximum or an amount near the maximum. On 93.9% of the days when Enron NA forced PGL to buy these large quantities, PGL made resales back to Enron NA. Dr. Rearden opined that if PGL 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).

PGL witness Wear explained why PGL wanted this provision to be included in the GPAA. Mr. Wear stated that when negotiating the GPAA, PGL required a sell-back provision in the contract because a sell-back provision created a firm market that PGL could turn to when it had an oversupply. (PGL Ex. C at 23). A standing firm bid to purchase oversupply, which would likely be executed under excess conditions in the marketplace, is valuable. (Id. at 20-21). He also testified that it was often difficult for PGL to unload large amounts of gas. (Tr. 1071). According to Mr. Wear, it was not advantageous to PGL to be in a position in which it had 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, PGL would receive less money than it would have received otherwise. (Tr. 1071). Mr. Wear testified that most spot transactions are 5,000 to 10,000 MMBtus. The more gas PGL has to unload, the more time it could take to accomplish that goal.

An oversupply can also cause pipeline imbalances. An imbalance can occur when PGL’s no-notice storage contractual rights are exceeded by the amount of gas that is in that storage. Under these circumstances, pursuant to contract, PGL must pay a penalty, which can be substantial. (PGL Ex. C at 26-27). Mr. Wear stated that the resale provision was not placed in the GPAA in anticipation of an oversupply. Rather, PGL personnel recognized that resales might be necessary. (PGL Ex. F at 19-20).

g. 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, at 10).

01-0707

h. Conversion to Performance-Based Rates

Article 4.5 of the GPAA provided that, if during the term of the GPAA, PGL 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 the pricing terms of the GPAA. (Staff Ex. 2.00, Attachments, GPAA, at 12).

i. Books and Records

Article 19.9 of the GPAA required PGL 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).

j. The “Master Contract”

Attached to the GPAA was the “Master Contract.” It was the master agreement, pursuant to which PGL and Enron NA could enter into transactions, like Transaction 19. (Tr. 1085). Pursuant to the GPAA, the terms and conditions of any sales or purchases “shall be set forth in a Transaction Agreement pursuant to the Master Agreement.” (Staff Ex. 2.00, Attachments, GPAA at 7). Thus, Enron North America and PGL were contractually required to document the transactions between them in the form of a formal contract.

Economic Analyses Made of the GPAA Just Before it was Executed

During discovery, Staff and the GCI requested any studies, analysis or like information used by PGL to determine the economic benefits of the GPAA. Initially, PGL denied that any economic analysis of the effect of the GPAA on consumers had ever been performed. (See, e.g., Staff Ex. 2.00 at 5; GCI Init. Brief at 31). In fact, PGL’s chief witness, Mr. Wear, the Manager of Gas Supply Administration at PGL, testified that no economic analysis of the GPAA was performed. (PGL Ex. F at 14; Tr. 1009-10).

01-0707

However, after discovery reopened, a study called the “Aruba Analysis” surfaced. Roy Rodriguez, who was employed in Peoples Energy Corp’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. (Tr. 1294). Using information gathered by PGL personnel²⁶, Mr. Rodriquez analyzed the projected economic value conferred on Enron NA by PEC and the projected effect of the GPAA gas prices on consumers. (Tr. 1294; Staff Ex. 7.00 at 12).

In the Aruba Analysis, Mr. Rodriguez compared the GPAA FOM price, minus the 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.²⁷ (See, e.g., Staff Ex. 7.00 at 13). 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. (Group Ex. 1 at ST-PG-135-161). In both scenarios that Mr. Rodriguez used, the results indicated that the GPAA would increase consumer gas costs. (Group Ex. 1 at ST-PG-135-161). Mr. Rodriguez discussed the findings in his “Aruba Analysis” with Mr. Wear, meaning decision makers at PGL knew or should have known the GPAA would cost PGA customers more than other supply arrangements. (See, e.g., City-CUB Ex. 1.0 at 18).

Mr. Wear also performed an analysis of the economic costs of the GPAA. At hearing, counsel for the City questioned Mr. Wear about a document, Wear Cross Ex. 15, which had been produced by PGL in discovery. This document was taken from Mr. Wear’s computer and it was in a file created by Mr. Wear. (Tr. 1036-46). It simulated what total gas costs would have been pursuant to the GPAA compared to what 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 15). Wear Cross Exhibit 15 indicated that 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.²⁸ (See, Wear Cross Exhibit 15).

During the hearing phase of this docket, Mr. Wear’s behavior called into question his credibility. Mr. Wear testified that he did not recognize Wear Cross Exhibit 15. (Tr. 1011). He did not recall performing any comparisons regarding the price of gas paid to Enron NA. (Tr. 1076; 1010). Mr. Wear professed to have no memory regarding a document that he admitted was on his password-protected computer in a computer folder that he created. (Tr. 1036-46). However, he admitted preparing a similar document, PGL Exhibit 8. (Tr. 1013).

______________________

²⁶ This is the same data contained in PGL Exs. 2 and 3, attached to Mr. Wear’s testimony. (PGL Ex. C, Attachments 2,3).

²⁷ 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).

²⁸ In its Initial Post-trial Brief, PGL avers that Mr. Wear did not recall this document, but, he “may have” nevertheless conducted an analysis of how a supply agreement like the GPAA would have affected consumers. (PGL Init. Post-trial Brief at 60). PGL further asserts that Wear Cross Exhibit 15 established that the GPAA was “increasingly favorable” over the four-year period it analyzed. (Id.). This is not correct. Not surprisingly, PGL cites no actual dollar amounts from that document.

01-0707

Neither of the analyses discussed above took the economic impact of all of the GPAA provisions into consideration. However, according to both analyses, the GPAA would result in higher gas costs being passed on the consumers. (Wear Cross Ex. 15; Group Ex. 1 at ST-PG-135-161;Tr. 911-12).

4. The Reasons Articulated by PGL for Entering into the GPAA

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

a. 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. (Tr. 881). It is, essentially, the cost, as is reflected in the marketplace, of transporting the gas to Chicago citygate. (Tr. 883, 885; PGL Ex. C at 7). 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. (See, e.g., PGL Ex. F at 5). Specifically, Northern Border Pipeline Co. and Alliance Pipeline had projects planned for Chicago that would increase capacity to the Chicago area by almost 2.0 Bcf of gas per day. (PGL Ex. C at 6). The effect of these projects would be to erode the value of PGL’s existing transportation contracts. (Id.). PGL witness Wear testified that one reason PGL entered into the GPAA was to counteract the predicted decline in basis from a field location to Chicago. (Tr. 1067). 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. (Staff Ex. 3.00 at 12).

Before signing the GPAA, PGL purchased a portion of its portfolio at citygate prices. (Tr. 937). According to Mr. Wear, these citygate purchases mitigated some of the effect of a decline in basis. (Tr. 937-38). However, in order for the citygate delivery price to be profitable, the average basis would have to fall below the transportation costs. (PGL Ex. H at 34).

01-0707

Additionally, in the past, PGL was able to “optimize” its transportation assets on days when they were not needed to meet system requirements.²⁹ (PGL. Ex. C at 8). A decrease in basis might also result in a decrease in the amount of demand credits PGL received through “optimization” of its firm transportation contracts through off-system transactions. (See, e.g., Staff Ex. 2.00 at 14 and PGL Ex. C at 6). Mr. Wear estimated that the decrease in optimization credits available resulting from a decline in basis was $400,000. (PGL Ex. C at 9).

Mr. Wear testified that PGL 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. (PGL Ex. B at 6). According to Mr. Wear, declining basis was a reason PGL personnel decided to enter into the GPAA with Enron NA. (Tr. 883). Mr. Wear testified that purchasing gas at the citygate index price would lower the cost of gas. (Tr. 888). Mr. Wear also opined that the three-cent discount offset the financial impact of declining basis on consumers. (Tr. 1079-81). Mr. Wear projected the decline in basis to be slightly more than one cent per MMBtu per year. (PGL Ex. C at 8-9). There is no credible evidence that any of the PGL decision-makers contemplated that basis would decline more than this amount. Mr. Wear sponsored PGL’s basis projections. (Tr. 890).

Staff Witness Dr. Rearden testified that the most important evaluation of the GPAA is a comparison between that which PGL 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 three cents per MMBtu. To acquire a “hedge” against basis, PGL 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 gas costs as a result of the GPAA. (Id. at 23-24).

_____________________

²⁹ 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., Tr. 996-999).

01-0707

Staff Witness Mr. Anderson testified that PGL had other options with which it could have avoided a loss in released capacity revenues and demand credits due to eroding basis. PGL had, at the time period in question, 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 PGL entered into the GPAA, it renegotiated four pipeline contracts. (Staff Ex. 2.00 at 16-17). Mr. Anderson opined that there is no evidence that PGL personnel were unaware that potential basis erosion was on the horizon at that time. To combat a decline in basis, PGL could have negotiated shorter-term contracts, to be re-negotiated as competition reduced pipeline rates. (Id. at 18). Mr. Anderson also opined that load shifting is another way to mitigate the financial effect of declining basis. Load-shifting between competing pipelines is a common practice in the industry. (Tr. 875). PGL conducts business with six pipeline suppliers and has the flexibility to shift load between those suppliers. (Id.). When a gas company puts more load on a pipeline, it can receive discounts from the pipeline at rates below the maximum FERC rate. (Tr. 875). The basis projections that Mr. Wear prepared showed a projected decline in basis of approximately one cent per MMBtu. (Tr. 890).

Staff believes that to properly evaluate the prudence of the GPAA, one must consider the information available to PGL 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 information that Mr. Wear used to prepare PGL Ex. 2, Dr. Rearden compared the citygate price with the field price, plus the cost of delivery from the field to the citygate. He calculated the difference between the two and concluded that the citygate price did not offset any decline in basis. He estimated that the gas purchased through the GPAA, using the GPAA prices, would increase gas prices by approximately $26,205,000 over the five-year life of the GPAA. (Staff Init. Brief at 50). Dr. Rearden used the same data as that used by PGL witness Mr. Wear. However, in Mr. Wear’s calculations, he found the projected decline in basis to be approximately one cent per MMBtu per year. (PGL Ex. C at 8; Staff Ex. 12.00 at 8).

Dr. Rearden testified that, in order to accurately determine basis for delivered gas, one must use both the Chicago-Henry Hub basis and the weighted average basis from Henry Hub to a field zone. This method is how Mr. Rodriguez analyzed basis when preparing the “Aruba Analysis.” (PGL Ex. L at 2). In Dr. Rearden’s opinion, PGL 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).

b. 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. (Tr. 891). Information, such as a report issued by the Cambridge Energy Research Associates, (“CERA”) was available to PGL decision-makers at the time PGL was negotiating the GPAA indicated that basis would decline. The CERA Report, however, contains information about the value of basis declining in some locations that are not pertinent to PGL. (Staff Exs. 12.00 at 17; 7.00 at 25).

01-0707

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. (PGL Ex. L at 45). Mr. Graves admitted that whether the GPAA would “pay off” for PGL was not a certainty. (PGL Ex. L at 47). There is no evidence indicating that decision-makers or anyone else at PGL considered the CERA Report or other industry data indicating the possibility of a steep decline in basis, when deciding to enter into the GPAA.

c. A Liquidity Premium

A liquidity premium is an adjustment made in order to take into account the fact that PGL, 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, PGL must meet consumer needs; it cannot wait until gas prices fall. Mr. Graves opined that, when calculating basis, a liquidity premium must be used. (See, PGL Ex. L at 19). Mr. Rodriguez used a liquidity premium when he prepared the “Aruba Analysis.” Using a 1.5 cent liquidity premium, 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. (PGL Ex L at 19). Mr. Graves never stated why he determined that this 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, PGL 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 PGL, can have a superior ability to buy gas below that which other buyers pay. (Staff Ex. 12.00 at 13).

d. Unquantifiable Benefits

According to PGL, 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 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. (PGL Ex. F at 9). However, there is no evidence that PGL’s employees ever used any of these services. Because PGL traded no 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.

01-0707

B. Conclusions of Law

Proposed Disallowances

Staff proposed a total cost disallowance for the GPAA of $13,304,910. Staff’s proposed disallowances are as follows: $10,755,048 for the increase in prices due to citygate versus delivered gas prices; $847,429 for foregone demand credits; $86,681 for resale penalties; $4,818,319 for increased gas costs due to the SIQ option. Staff also proposed credits of approximately $3.2 million for the provisions that saved consumers money. (See, Staff Ex. 7.05). The GCI’s total recommended disallowance is $37,470,517 for increased gas costs. (City-CUB Ex. 1.0 at 4). As is set forth below, Staff and the GCI raise several issues regarding the prudence of the GPAA, in light of what decision-makers at PGL knew or should have known.

2. Ignoring Internal Unfavorable Economic Analyses

a. Staff’s Position

Two internal economic analyses performed just before PGL entered into the GPAA indicated that the GPAA would raise the price of gas borne by consumers through PGL’s PGA. PGL witness Mr. Wear performed an economic analysis of the financial impact of 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 15). 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-135-161).

According to Staff, there are no economic analyses indicating that the GPAA was prudent. And, the two analyses PGL did perform established that the GPAA would be more costly than PGL’s supply purchasing practices in previous years. Nevertheless, PGL entered into the GPAA. (Staff Init. Brief at 44, 47-48).

Staff posits that PGL presented no evidence that it considered any alternative to the GPAA, which was a dramatic departure from PGL’s gas-buying practice in prior years. Previously, PGL purchased gas in the field and paid for transportation to the Chicago citygate. In contrast, the GPAA represented 66% of PGL’s system supply purchases for the time period in question. Another major difference between the GPAA and PGL’s previous supply contracts was the length of the contract. The GPAA was a five-year contract. Typically, PGL’s gas supply contracts were one or two years in duration. (Id. at 44-45). Thus, Staff argues that a change in purchasing method requires evidence, perhaps in the form of a request for proposal (an “RFP”) or in the form of an economic study, establishing the prudence of PGL’s decision to enter into the GPAA. (Id. at 46). Staff views the lack of any quantitative analysis supporting the GPAA as indicia of imprudence. Staff does not contend that PGL should be required to perform any specific type of analysis. (Staff Reply Brief at 20).

01-0707

b. GCI’s Position

The GCI, as well, argue that entering into the GPAA in the face of two analyses indicating that the GPAA would raise gas costs is imprudent. (GCI Initial Brief at 36-38). The GCI point out that the credibility of PGL’s chief witness on this issue, Mr. Wear, was impeached through the existence of Wear Cross Ex. 15. Despite Mr. Wear’s testimony that no economic analysis was performed of the GPAA by any PGL personnel, an economic analysis of the GPAA Mr. Wear performed, and it was unfavorable. The GCI point out that Wear Cross Ex. 15 is also a party-admission, as it contradicts PGL’s assertion that no economic analysis of the GPAA was performed by PGL personnel. (GCI Init. Brief at 31-35).

The GCI aver that Wear Cross Ex. 15 and the “Aruba Analysis” establish that entering into the GPAA would increase the cost of gas borne by consumers. PGL 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 GCI contend that, because contemporaneous analyses were performed demonstrating the imprudence of the GPAA, PGL’s justifications of its failure to conduct a favorable economic analysis are no longer relevant, except to demonstrate PGL’s lack of credibility. (GCI Init. Brief at 35-37).

c. PGL’s Position

PGL 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 PGL, Mr. Wear’s analysis (Wear Cross Ex. 15) showed that the characteristics of the GPAA were, in fact, increasingly favorable over the four-year period Mr. Wear analyzed. PGL argues that this exhibit showed directionally improving results, when comparing the last year of historical data 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, PGL asserts that its expectations with regard to the effect of declining basis were correct.³⁰ (PGL Reply Brief at 29). PGL also asserts that its Ex. 8, which was prepared by Mr. Wear, establishes that the GPAA would be beneficial to consumers. (PGL Init. Brief at 60-61).

PGL further claims that the Commission should not consider the “Aruba Analysis” because PGL decision-makers did not consider it when deciding to enter into the GPAA. Also, the “Aruba Analysis” is not consistent with conclusions drawn by PGL’s expert witness Mr. Graves after the GPAA was executed. (PGL Init. Brief at 61). PGL maintains that Staff and the GCI have placed far too much emphasis on the “Aruba Analysis” and Wear Cross Ex. 15, as there is no evidence that PGL decision-makers were privy to these analyses. Further, even though PGL did not object to admission of the “Aruba Analysis” into evidence at hearing, Staff could have, but did not, subpoena Mr. Rodriguez to testify. (Id.).

Both Staff witnesses Dr. Rearden and Mr. Anderson criticized PGL for not implementing an RFP bidding process and not relying on a written quantitative analysis when electing to execute the GPAA. According to PGL, in so doing, Staff has required PGL to have these tasks performed for the first time. In the past, PGL did not conduct formal bidding or conduct economic analysis of its supply contracts. (See, PGL Init. Brief at 56-59; PGL Ex. L at 12).

_____________________

³⁰Declining basis is discussed in Section (b)(2) herein.

01-0707

On Exceptions, PGL argues that the Commission is altering the applicable standard when requiring it to justify its decisions based on information that could have been available to decision-makers at the time the relevant decisions were made. PGL argues that this Commission should not require utilities to use information that decision-makers knew or should have known at the time they made a decision. (PGL BOE at 57).

d. Commission Analysis and Conclusions

After the ALJ reopened discovery in this matter, two economic analyses of the GPAA, performed by employees of PGL/PEC, magically emerged. These analyses are the Wear Cross Ex. 15 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.³¹

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

The Commission notes that PGL’s error is not in failing to perform a certain type of study or in failing to solicit a certain type of bid. Rather, PGL’s error is its lack of evidence indicating consideration by PGL personnel of the economic impact of the GPAA on consumers prior to executing it. Additionally, we agree with the GCI that the importance of PGL’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 available.

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, PGL 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 PGL’s supply for a period of five years. PGL had an obligation, pursuant to statute, to mitigate rising gas costs. (220 ILCS 5/9-220). Yet, here, PGL 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.).

_____________________

³¹The “Aruba Analysis” included transportations costs and basis. Wear Cross Ex. 15 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. 15; Staff Group Ex. 1 at ST-PG-135-161).

01-0707

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

PGL’s assertion that Wear Cross Ex. 15 establishes that its expectations with regard to the effect of declining basis were correct is without merit. PGL overlooks the fact that, in Wear Cross Exhibit 15, Mr. Wear did not analyze basis. He merely compared PGL’s historical purchases of gas with four years of previous gas purchases PGL made (from October, 1995 to September, 1999) using GPAA purchases prices, like FOM minus three cents per MMBtu. (Wear Cross Ex. 15). Mr. Wear’s analysis proves nothing with regard to the impact of basis and the GPAA.

Mr. Wear projected an approximate loss of $50 million over the four-year period he analyzed. Mr. Wear also projected a gain in the fourth year (1999) of $10,920,308. (Id.). PGL does not explain how incurring a loss of $50 million over four years is offset by approximately $11 million in the last 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. (See, e.g., Tr. 1072, where Mr. Wear stated that he previously testified that PGL did not renegotiate with Citgo because the Citgo gas PGL received previously was inferior, but, admitted that, after PEC assumed the Citgo contract, PGL continued to receive this same inferior gas (through Enron Midwest)). 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 15 impeached Mr. Wear’s credibility, as the record is replete with statements he made that no economic analysis was performed. (See, e.g., Tr. 1009-10). However, Wear Cross Ex. 15 established, at a minimum, that Mr. Wear created a document on his computer approximately one week before PGL executives signed the GPAA. (Wear Cross Ex. 15; Staff Ex. 2.00, GPAA). Any statement made by Mr. Wear that he did not recall Wear Cross Ex. 15, or that he did not recall with whom he spoke regarding this document is not credible.

The Commission concludes that PGL 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 does not absolve PGL from its obligation to incur only those costs that are prudently incurred. (220 ILCS 5/9-220). And, any objection PGL 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)).

01-0707

It is unfathomable to the Commission that PGL 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 PGL to “refrain” from actions that lead to an increase in costs for consumers. The fact that PGL’s decision-makers did not consider them actually shows that PGL 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. PGL’s decision was, therefore, imprudent. (Illinois Power, 245 Ill. App. 3d at 371). Disallowances based on the specific increases in costs caused by PGL’s imprudent decision will be discussed in detail below.

On Exceptions, PGL ignores the law in arguing that the Commission should only require it to justify its decisions based on information that could have been available to decision-makers at the time the relevant decisions were made. The Commission is required to determine whether a decision is prudent based on what decision-makers knew or should have known. (See, e.g., Ill. Power, 245 Ill. App. 3d at 371). Moreover, we decline to allow utilities to justify decisions based on information that decision-makers might have known, unless, as is the case with the “Aruba Analysis and Wear Cross Ex. 15, those documents were prepared for the purpose of making the decision in question. In such a case, the decision-makers should have known the contents of those documents.

Enron’s Ability to Change the Price of Gas: the Baseload Price Adjustment Clause and Articles 4.2(b) and 4.2(c) of the GPAA

a. Staff’s Position

Staff contends that, pursuant to the BLPA, Enron NA could increase the price of baseload gas. Also, Articles 4.2(b) and 4.2(c) of the GPAA allowed Enron to increase the price of baseload gas in wintertime, notwithstanding any increases Enron North America imposed pursuant to the BLPA. Staff acknowledges that no harm actually resulted from these three clauses, as Enron never actually changed the price of gas pursuant to these three clauses during the reconciliation period. Staff avers that it was unreasonable for PGL 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 PGL needed to meet customer demands. (Staff Init. Brief at 41; 50-51). Because consumers suffered no economic harm from these provisions, Staff seeks no disallowance. (Id. at 56).

b. GCI’s Position

The GCI also contend that the BLPA and Articles 4.2(b) and 4.2(c) of the GPAA allowed Enron NA to unilaterally increase the price of baseload gas in wintertime, which was imprudent. (GCI Init. Brief at 45, 47).

01-0707

c. PGL’s Position

PGL acknowledges that the BLPA clause 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. According to Mr. Wear, PGL agreed to include the BLPA clause in order to secure the three-cent per MMBtu discount on baseload gas and SIQ gas. (Id. at 21). PGL argues that the emphasis on the existence of these clauses is misplaced because Enron NA never invoked these clauses. And, Articles 4.2(b) and 4.2(c) expired, unexercised, before the commencement of the reconciliation year. (PGL Reply Brief at 30).

d. Commission Analysis and Conclusions

The Commission agrees with Staff and the GCI that facts were known to PGL decision-makers at the time the GPAA was negotiated which established that these clauses could have resulted in harm to ratepaying consumers. A simple review of these three clauses in the GPAA would have revealed that Enron NA could have imposed unnecessary costs on consumers. Baseload gas is critical for PGL to meet the demands of its customers. Because PGL 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 PGL. (220 ILCS 5/9-220). Yet, conspicuously absent from this record is evidence that anyone at PGL was concerned that Enron could increase the price of gas, if Enron decided to do so.

The Commission finds that PGL acted imprudently by entering into a contract with three provisions that potentially allowed Enron NA to increase the price of baseload gas, which is the quantity PGL 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 PGL 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.

4. Baseload, SIQ and DIQ Gas

Staff’s Position

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

PGL indicated that it established baseload requirements through negotiations with Enron NA and did not necessarily reflect demand. PGL stated that baseload quantities included in the GPAA were similar to baseload purchases prior to the existence of the GPAA. Finally, PGL 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 PGL’s explanations justify the contracted amount of baseload included in the GPAA. (Staff Init. Brief at 41).

01-0707

Baseload requirements represent the portion of customer demand that a gas utility can take on its system. If a gas utility purchases 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 PGL would provide some sort of study or analysis to support its decision to use normal weather conditions to establish baseload requirements. PGL did not do that here. Staff believes PGL to be unreasonable in committing to purchase baseload requirements without first analyzing the needs of its customers. (Staff Ex. 2.00 at 21-22).

Pursuant to the SIQ provision, Enron NA chose the amount of gas it delivered to PGL during the summer period defined in the GPAA. Enron NA sold SIQ gas to PGL at the FOM price, less a three-cent per MMBtu discount. However, the GPAA enabled Enron NA to force PGL to purchase maximum SIQ volumes of gas when the Gas Daily price was less than the FOM price. (See, Staff Ex. 3.00 at 31). According to Staff, the SIQ provision forced PGL to buy gas it did not need. Enron NA could, and did, deliver large amounts of SIQ gas to PGL when the FOM price was higher than the daily price, which forced PGL to buy gas it did not need at a higher price than what was available in the marketplace at the daily price. Staff argues that it was imprudent for PGL to allow Enron NA to determine how much gas PGL would receive. (Staff Ex. 12.00 at 24; Staff Init. Brief at 49).

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 PGL 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 80,000 MMBtus of SIQ gas to PGL, and if PGL needed that amount of gas, PGL would be required to purchase gas at a higher cost. (Staff Ex. 12.00 at 24). PGL submitted evidence establishing that on only 20% of the days on which Enron NA made such a decision, PGL did not purchase DIQ volumes from Enron NA at the daily price. (PGL Ex. L at 11; Staff Init. Brief at 43). Staff determined that the SIQ increased consumer costs during the year in question in the amount of $4,818,319, which represents the difference between the daily price index and the FOM index price, times incremental SIQ gas volumes. (Staff Init. Brief at 56).

b. GCI’s Position

The GCI argue that the SIQ clause virtually guaranteed that Enron would benefit, at the expense of consumers. Citing Mr. Wear’s testimony on this issue, they conclude that PGL should not have been “indifferent to when the volumes of gas showed up.” (GCI Init. Brief at 47-48)

c. PGL’s Position

PGL contends that the SIQ provision was prudent because relinquishing control over how much SIQ gas was delivered to it was done in exchange for a three-cent discount. (See, e.g., PGL Init. Brief at 18). According to Mr. Wear, the three-cent per MMBtu discount in both the baseload clause and the SIQ clause saved consumers $2.7 million. (PGL Ex. C at 16).

01-0707

PGL argues that Staff and the GCI exaggerate the effect of the SIQ provision, which PGL acknowledges “allowed Enron some control over the timing and amount of gas sold to Peoples Gas under the GPAA.” (PGL Reply Brief at 35). PGL points out that Enron NA had no control over the amounts of PGL’s higher-priced purchases from Enron North America pursuant to the DIQ clause. Also, citing Staff’s Initial Brief and Mr. Anderson’s testimony, PGL argues that Enron NA never forced PGL to buy DIQ gas when Enron NA selected the minimum amount of SIQ gas. (PGL Reply Brief at 36).

d. Commission Analysis and Conclusions

As an initial matter, the Commission agrees with Staff that PGL should have performed some sort of analysis to determine its baseload requirements 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 PGL 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; City/CUB Ex. 1.0 at 9). Mr. Wear testified that having an oversupply could produce undesirable consequences for PGL. Yet, the SIQ provision relinquished PGL’s control over the amount of gas PGL would receive on any given day to Enron NA.

It defies logic for PGL 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 PGL’s control. Without control over the amount of gas Enron NA delivered to PGL on any given day, it is difficult to imagine how PGL could effectively plan how to meet its responsibilities. Too little gas, also, brought about undesirable consequences, as it required PGL to buy gas at the higher DIQ price from Enron NA, or elsewhere, at a daily price. (See, e.g., PGL Ex. B at 6). The SIQ clause allowed Enron NA to force PGL 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 PGL’s claim that this provision would be offset by the three-cent discount.

PGL’s reference to Staff witness Mr. Anderson’s testimony in support of its claim that Enron NA never forced PGL to take maximum SIQ gas is taken out of context. (See, Tr. 869). So is its reference to Staff’s Initial Brief in support of its contention that Enron NA never forced PGL to take the maximum amount of SIQ gas. In fact, Staff argued on page 43 of this Brief that when Enron NA delivered only the minimum SIQ gas, PGL was required to find volumes to replace SIQ gas. Staff averred that Enron NA forced PGL to take minimum volumes approximately 80% of the time when doing so was economically advantageous for Enron NA. (Staff Init. Brief at 43). There is other evidence, however, that Enron also forced PGL, on 236 of the 244 summer days, to purchase maximum SIQ volumes. (Staff Ex. 3.00 at 31). PGL’s argument ignores the evidence.

01-0707

Essentially, the SIQ gas was injected to create a supply of less expensive summer gas to meet PGL’s winter load requirements, which includes gas for ratepaying consumers. PGL had an obligation, pursuant to Section 9-220 of the PUA, to procure that gas in a manner that did not unnecessarily increase consumer gas costs. The SIQ provision caused PGL to fail in this obligation. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum fully discussed in Section I .

The Commission notes that Section 4.5 of the GPAA allowed PGL to renegotiate the price of gas, if PGL were to discontinue use of a PGA rider and therefore would no longer be directly passing the price of gas 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, PGL would not find those prices to be satisfactory. If PGL had to pay for this gas and account to its shareholders for those costs, the prices would be re-negotiated. This is further evidence that PGL did not have its customer’s best interests in mind when negotiating the GPAA.

5. Foregone Demand Credits

a. Staff’s Position

Staff contends that, by releasing pipeline capacity pursuant to the GPAA, PGL surrendered its ability to engage in demand-credit transactions. Before the GPAA, PGL obtained revenues that were flowed through its PGA, offsetting costs that were passed on to consumers. These revenues were obtained in two ways. Either PGL released pipeline capacity, earning a fee, or it engaged in demand credit transactions where 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 55).

b. PGL’s Position

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

Commission Analysis and Conclusions

Even assuming that PGL is correct in its contention that it is not possible to determine the amount of foregone demand credits with certainty, PGL 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 PGL ceded to Enron NA pursuant to the GPAA generated income before the GPAA was executed. (PGL Ex. C at 31; Staff Ex. 3.00 at 34). After the GPAA was executed, this pipeline capacity generated no income. It should have been obvious to PGL that this capacity could generate no income. (Staff Ex. 2.00, Attachments, GPAA, Art. 4.3)

01-0707

While PGL has contended, essentially, that Dr. Rearden’s calculation of foregone demand credits is inaccurate, PGL proffers no evidence as to what would be accurate. There is nothing patently inaccurate about Dr. Rearden’s use of the profits PGL gleaned during a previous fiscal year to determine what PGL would have earned. The Commission agrees with Staff that PGL’s release of pipeline capacity increased consumer costs with no benefit for consumers resulting from this release. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as approved in Section I.

6. Penalties for Resales of Gas

Staff’s Position

Dr. Rearden estimated that penalties on resales of gas pursuant to the GPAA raised consumer costs by $86,681. (Staff Ex. 3.00 at 34). Dr. Rearden opined that the existence of this provision is indicia that PGL expected to have an oversupply. (Id. at 29).

PGL’s Position

PGL argues that the resale provision, even with its penalties, was beneficial. An oversupply creates significant issues, as it is difficult for PGL personnel to unload large amounts of gas, and, an oversupply can create an overpressure situation. (PGL Init. Brief at 23). PGL argues that Staff continues, wrongfully, to characterize the financial onus imposed by the GPAA on consumers whenever resales occurred as a “penalty.” According to PGL, Staff has ignored the dynamics of the marketplace. Also, Dr. Rearden acknowledged that a sale at less than the daily midpoint price does not necessarily reflect a penalty. (Tr. 1292, PGL Reply Brief at 31).

Referring to Mr. Wear’s testimony, PGL maintains that the sell-back provision is not an uncommon one. Mr. Wear testified that once, in a contract that spanned from 1996 through 1998, PGL had a similar arrangement with an unnamed supplier. (See, PGL Ex. C at 32). Also, the sell-back provision compared favorably with alternatives, like purchasing “Park and Loan” services from an interstate pipeline. Further, if PGL had too much gas, it could incur substantial pipeline overrun charges. (PGL Reply Brief at 32-33).

01-0707

Commission Analysis and Conclusions

PGL asserts that unloading excess gas can be a very difficult task. (See, e.g., PGL Ex. C at 23). 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 a rare occurrence. If PGL 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 PGL received on a daily basis. Instead, PGL chose to enter into a supply contract where Enron NA could decide to deliver, at Enron NA’s sole discretion, the maximum SIQ. Enron NA exercised its option under the SIQ provision on 236 out of 244 summer days during the reconciliation period. On an astonishing 70% of those days, PGL was forced to resell the Enron NA-caused oversupply back to Enron NA and incur penalties. It is unclear to the Commission how allowing another entity to control the delivered SIQ gas, the same entity to which PGL must ‘conveniently’ resell any artificially created oversupply at a loss, could be considered prudent. Compounding that with the profit sharing arrangement between PGL’s parent and Enron NA, the Commission finds the reselling of gas to Enron NA to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as approved in Section I.

PGL’s citation to Dr. Rearden’s testimony overlooks the fact that penalties were imposed by the GPAA every time a resale was made, irrespective of the daily midpoint price. PGL’s argument concerning Dr. Rearden’s testimony does not aid it.

Mr. Wear’s testimony regarding one single two-year contract with an unnamed supplier for an unspecified amount of gas does not aid PGL. 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 PGL to accept excess gas supply from Enron NA. Finally, there is no evidence that this unnamed contract involved the supply of 66% of PGL’s total intake of gas, which is the situation here.

7. Released Pipeline Capacity

Staff’s Position

Staff argues that, when PGL released pipeline capacity to Enron NA, it surrendered an item for which consumers paid for through the PGA. The value of that pipeline capacity is $3,377,303, over the five-year life of the contract. (See, Staff Init. Brief at 51).

PGL’s Position

PGL contends that it did not release pipeline capacity. It cites FERC rules, which provide 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 PGL whatever PGL was required to pay the pipelines. (See, 18. C. F. R. 284.8(f); PGL Init. Brief at 20).

01-0707

Commission Analysis and Conclusions

The regulation cited by PGL 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 PGL to reimburse Enron NA for those charges, PGL 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.

PGL bears the burden of proof here, which it failed to meet. It did not provide evidence establishing that the pipeline capacity it released was not paid for by consumers pursuant to the terms in the GPAA. (See, generally, PGL Init. Brief). Enron NA had use of that pipeline capacity for its own business purposes above and beyond facilitating supply to PGL. Enron 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. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as approved in Section I.

8. Eroding Basis

PGL’s Position

The cost of transporting gas to Chicago is passed on to consumers in PGL’s PGA. (83 Ill. Adm. Code 525.40(a)). Based on Mr. Wear’s and Mr. Graves’ testimony about a concern in the industry regarding an impending decline in pipeline transportation value, PGL contends that it entered into the GPAA to protect itself, and therefore consumers, from a decline in the value of PGL’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 pipeline capacity 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. (PGL Initial Brief at 29-30; See also, PGL Ex. H at 42; PGL Ex. E. at 6). Also, as basis declined, so would PGL’s revenues from “optimizing” transportation assets. (PGL Ex. C at 9). According to Mr. Wear, purchasing gas at the citygate price, as well as the three-cent discount on baseload and SIQ gas, offset the impact of a decline in basis. Citing this testimony, PGL argues that the three-cent discount “guaranteed” value for its transportation assets and offset the expected decline in basis. (See, e.g., Tr. 883, 1079-81; PGL Init. Brief at 48-50). Also, the expected basis decline was not an event that would occur immediately. (PGL Reply Brief at 27).

01-0707

PGL argues that Staff unjustly accuses it of failing to just shift loads amongst pipelines in order to obtain better pipeline prices. PGL points out that, even Mr. Anderson acknowledged that price is not the only factor when selecting pipeline capacity. Also, operational considerations limit the extent to which PGL personnel can shift a load. Further, Natural Gas Pipeline is the only interstate pipeline directly connected to PGL’s distribution system. Natural Gas Pipeline uses “pressure control” operations instead of “flow control”. Pipelines that use pressure control operations provide “true” no-notice service. As consumption on PGL’s system changes, the pressure changes, causing PGL to take more or less gas as pipeline pressure dictates. With pipelines that operate under flow control, changes in pipeline pressure do not affect the flow of gas upstream on PGL’s system. PGL contends that therefore, only Natural Gas Pipeline by way of its pressure control operations, can assist it in real time balancing. (PGL Reply Brief at 29-30).

Staff’s Position

Staff maintains that buying gas at the citygate price, as opposed to buying it in the field and delivering it, unnecessarily increased the price of gas in the amount of $10,755,048. (Staff Init. Brief at 55). Staff argues that PGL did not demonstrate that the GPAA preserved the value of pre-existing transportation assets against a falling basis. Staff points out that PGL negotiated four new pipeline contracts in 1998 and another in 1999, just before PGL executed the GPAA, which occurred in September of 1999. If PGL 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 36-37).

Staff points out that PGL 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, Staff maintains, PGL has used this practice in the past. However, PGL presented no evidence that it considered this alternative before it executed the GPAA. (Staff Init. Brief at 35-36). Staff states that it is not requiring PGL to investigate these two alternatives. Instead, the evidence indicates that PGL did not even consider alternatives available to it when negotiating the GPAA. Staff points to the profit-sharing partnership PEC formed with Enron North America/Midwest and contends, in essence, that the real reason PGL entered into the GPAA was that arrangement. (Id. at 37).

Staff also argues that the GPAA did not offset any decline in basis because the GPAA caused PGL 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.).

01-0707

Staff avers that there is no evidence that PGL decision-makers actually contemplated a steep decline in basis when the GPAA was signed. Staff contends that PGL failed to present evidence that before signing the GPAA, PGL conducted an evaluation of the probability of a steep decline in basis. (Staff Reply Brief at 36). Staff further contends that the three-cent discount must be compared to the field price, plus the variable cost of transportation versus the citygate price. Staff argues that the economic impact of other provisions of the GPAA must also be examined, such as Enron NA’s re-pricing options, the resale penalty, lost demand credits due to the GPAA, and, the financial impact of Enron’s manipulations of the SIQ provision. ³² (Staff Init. Brief at 48-49).

Given PGL’s projections of basis made at the time the GPAA was executed, Staff contends that the GPAA’s discounts were not enough to offset the projected basis decline. (Id. at 37-38). Staff avers that correct manner to determine the field price and delivery costs, versus the citygate price, is to do the same analysis PGL performed when it valued the transportation it released to Enron North America pursuant to the GPAA. For each delivery point in the transportation contracts PGL released to Enron, PGL projected a basis from the Henry Hub to that point, and, to Chicago, using NYMEX futures contract prices to determine the amount of these prices. PGL also used NYMEX futures prices to determine the price of gas in the field. Similarly, PGL calculated the citygate price as the Henry Hub price, plus basis. PGL determined variable transportation costs by viewing the applicable tariffs. (Id.).

Staff does not dispute that the three-cent per MMBtu discount conferred a benefit on ratepaying consumers. Using the amounts just previously described, Staff estimated that the value of the three-cent discount, over the life of the GPAA, was $13,176,693, and the extra cost imposed on consumers by use of the citygate price was $26,205,000, over the life the GPAA.³³ (Staff Ex. 3.00 at 17-18; Staff Init. Brief at 50; FCG-ARG-3). Staff avers that this differential, coupled with other harmful clauses in the GPAA, make it imprudent. (Id. at 49-52).

Commission Analysis and Conclusions

PGL professes that its decision-makers were 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, PGL relinquished pipeline capacity to Enron NA to “facilitate the citygate supply relationship.” (PGL Ex. B at 4). Consumers also paid the citygate price of gas, which includes the cost of transportation to Chicago. PGL 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 three-cent discount, did not offset the decline in basis.

_____________________

³²These other provisions of the GPAA shall be discussed herein, in other sections of this Order.

³³Staff’s figures here were proffered for purposes of price comparison, not as a disallowance. (See, Staff Ex. 7.02).

01-0707

Further, the evidence did not establish that the citygate prices and the three-cent discount on baseload and SIQ gas actually protected PGL, and thus consumers, from declining basis. This is true because, as previously set forth herein, PGL 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 three-cent discount included in PGL’s citygate purchases to the point of non-existence. Given the amount of extra costs that the GPAA imposed, it makes no sense to focus on basis as a measure of the prudence of the GPAA without looking at the substantial increases in costs that the GPAA imposed.

PGL contends that it did not consider any other economic aspect of the GPAA, such as the BLPA or the interplay between the SIQ and DIQ provisions. (See, e.g., PGL Ex. C at 11). In so arguing, PGL 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, essentially PGL admits that it entered into the GPAA imprudently. (Id.).

PGL cites no authority, and indeed there is none, that allows utilities to enter into 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 PGL decision-makers claim to have considered when executing the GPAA. (Illinois Power, 245 Ill. App. 3d at 371).

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

PGL 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 PGL to explore alternatives to the GPAA, the fact that PGL 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 PGL’s failure to fully evaluate its options to combat eroding basis, if indeed this was a reason to execute the GPAA, to be imprudent. Ample 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 in the field. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as discussed in Section 1.

01-0707

The CERA Report and Other Reasons for Possibly Higher Basis

PGL’s Position

PGL’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. (PGL Ex. H at 45-46; Attachments, FCG-6 and FCG-7; PGL Ex. C 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.³⁴ (See, e.g., PGL Ex. 2, Spring 1999 CERA Report). Based on information that existed at the time PGL executed the GPAA, PGL argued that when comparing basis with actual transportation costs, Dr. Rearden improperly determined that an average decline in basis was $0.01 per MMBtu per year.³⁵ However, PGL admits that there is no evidence establishing that the PIRA and CERA Reports were considered by PGL decision-makers when entering into the GPAA. It argues that Mr. Graves’ estimates are still valid. (PGL Reply Brief at 39-40).

PGL also argues that the 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 PGL 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. PGL argues that illiquidity is a phenomenon that it experiences in the field. Dr. Rearden used field prices in his basis calculations, which according to PGL, underestimated the actual field prices because field areas are not as liquid as trading hubs. (PGL Reply Brief at 37-39). PGL also argues that Mr. Graves “followed Dr. Rearden’s lead” when only calculating basis from Ventura and Henry Hub to the Chicago citygate. Mr. Graves did not study the effect of the CERA scenarios on basis from the field to the citygate. (Id. at 39-40).

_____________________

³⁴ At trial, none of the parties objected to the admission of this testimony and documents into evidence.

³⁵PGL stated in its Initial Brief that its review of projections for the GPAA showed that basis “likely would decline,” implying that PGL personnel analyzed basis when the GPAA was negotiated and projected a steep decline in basis. (See, PGL Init. Brief at 48). 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, PGL Ex. C. at 78, where Mr. Wear stated that the CERA Reports existed at the time when PGL negotiated the GPAA. He never stated that anyone at PGL actually read that report. (See, e.g., Tr. 944-45, where Mr. Wear admitted that “scenarios” illustrating a dramatic decline in basis were not part of the record.)).

01-0707

Staff’s Position

Staff maintains that there is no evidence in this record that any PGL decision-maker considered steep basis projections, like those found in the CERA Study, before entering into the GPAA. Also, locations in the CERA Study are not the same as the pertinent PGL delivery points. Therefore, Staff concludes that the CERA Study is not relevant because the information therein is not comparable to the facts here. And, Mr. Graves’ projections are not accurate because he only used the CERA scenarios to examine changes in basis from the Henry Hub to the Chicago citygate. An accurate depiction of the basis at issue would account for the effects of basis changes at other field locations in each scenario, and would therefore, examine any effect from altering the field zone prices, as well as the Chicago citygate price. (Staff Ex. 12.00 at 15-17).

Staff also points out that the CERA report only contained information regarding regional markets, not delivery points. 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 27-28).

Commission Analysis and Conclusions

The portion of Mr. Graves’ testimony that PGL 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 of increased gas costs. Even if the Commission were to accept PGL’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. A steep decline in basis does not excuse PGL personnel from entering into a contract that contained clauses, like the BLPA, with an obvious potential to cause economic harm to consumers.

The Commission finds PGL’s reliance on the “Aruba Analysis” as evidence of the effects of the decline in basis rather curious, if not disingenuous. First, PGL wants us to ignore it since PGL decision-makers did when executing the PGAA. Now, PGL wants the Commission to consider the “Aruba Analysis” as evidence that PGL’s efforts to combat eroding basis were legitimate. Interestingly, PGL’s request does nothing to strengthen its case. In the “Aruba Analysis,” Mr. Rodriguez used a high and low SIQ volume to examine the effects of the projected basis on consumer gas costs. Both sets of projections indicated that the GPAA would increase consumer costs. (Group. Ex. 1.00 at ST-PG 50-74). Even including a liquidity premium, 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.

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 liquidity premium he used. Therefore, the Commission agrees with Staff that use of Mr. Graves’ liquidity premium is not substantiated.

01-0707

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 capacity PGL released to Enron NA to “facilitate the citygate supply relationship.” Enron NA paid nothing to PGL for the privilege of using this capacity for its own business purposes, although Enron NA only used this capacity when PGL did not use this capacity. (See, e.g., Staff Ex. 2.00, Attachments, GPAA, pars. 6.1, 6.4, PGL Ex. B at 4). Thus, the GPAA did not offset the effect of any decline in preexisting transportation costs.

PGL 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, PGL ignores the fact that we are required, by law, to consider only what decision-makers considered, or should have 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 PGL 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 PGL 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. PGL’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 PGL’s assertion that Mr. Graves “followed Dr. Rearden’s lead” and calculated basis from the Henry Hub or Ventura to the Chicago citygate, PGL’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. (See, PGL Reply Brief at 38).

9. Differing Economic Theories

PGL’s Position

Various witnesses recommended different dollar amounts as to the recommended disallowances for the GPAA. These different opinions as to how much the GPAA was imprudent, according to PGL, illustrate that how the GPAA should be quantified is subjective, making it unreasonable to view the GPAA as imprudent. (PGL Init. Brief at 57).

PGL points to the GCI testimony on the GPAA and states that the differences amongst the experts as to the dollar values of the harm it caused for consumers demonstrates that it is not possible to determine the GPAA’s economic impact. PGL concludes that therefore, neither Staff nor the GCI provided a basis for finding the GPAA imprudent. PGL points out that honest differences of opinion are not necessarily evidence of imprudence. (PGL Init. Brief at 56-57).

01-0707

Staff’s Position

Staff posits that the GPAA was a complex contract and, for the most part, the experts only differ in terms of mathematical approaches, not in their opinions as to why PGL personnel acted imprudently. Additionally, the existence of a variety of approaches of experts is often the case in litigation. In support, Staff cites Hall v. National Freight, Inc., 264 Ill. App. 3d 412, 422-23, 636 N.E.2d 791 (1^st Dist. 1994)). Staff concludes that PGL’s argument confuses the reasonableness in the amount of the adjustment proposed as a result of imprudence with a determination as to prudence. (Staff Reply Brief at 31-33).

GCI’s Position

The GCI aver that all of the experts PGL cites agreed that the GPAA was imprudent. Their differing estimations only have to do with the amount of damage conferred on consumers, which does not mean that the GPAA was prudent. The GCI posit that PGL’s contention is disingenuous, as it ignores the fact that some experts only addressed specific provisions of the GPAA, while others examined the entire contract. (GCI Reply Brief at 30).

Commission Analysis and Conclusions

PGL overlooks the fact that all of the Staff witnesses, as well as Mr. Mierzwa, Mr. Effron and Ms. Decker, concluded that the GPAA was imprudent. There is, in fact, no disagreement amongst Dr. Rearden, Mr. Mierzwa, Mr. Effron, Ms. Hathhorn, Mr. Knepler, Mr. Anderson, Ms. Decker and other witnesses that the GPAA was imprudent. Some of these witnesses testified only as to different aspects of the GPAA. Others examined the total contract. Different issues were raised by different experts.

As Staff points out, there is nothing unusual about experts espousing different opinions as to the economic harm of a person’s actions. The same rules as to weight and credibility apply to experts as to other witnesses; it is up to the trier of fact to assess the credibility of an expert, as the trier of fact is in the best position to do so. (Hall, 264 Ill. App. 3d at 422-23). PGL’s argument on this issue is without merit.

10. Staff Witness Dr. Rearden’s Dollar Values

PGL’s Position

PGL contends that Dr. Rearden’s extensive calculations as to the economic value of the harm to consumers resulting from the GPAA are but “mathematical exercises.” PGL avers that these calculations are erroneous because they are based on a single set of assumptions and inputs, rather than considering a “range of realistic scenarios.” According to PGL, Dr. Rearden’s calculation of basis was too precise to be meaningful. (PGL Init. Brief at 59).

01-0707

Commission Analysis and Conclusions

While PGL contends Dr. Rearden improperly treated prudence as a “mathematical exercise” in fact, the measure of economic harm to consumers resulting from increased costs is mathematical. Dr. Rearden’s determination as to what harm consumers incurred is something that PGL decision-makers could, and should, have contemplated, but did not, prior to executing the GPAA.

It should also be pointed out that many provisions in the GPAA had the obvious potential to increase costs, with no offsetting benefit to consumers from those additional costs. Calculating a “range of scenarios” of potential disasters is not helpful, or even meaningful, when PGL personnel could have simply read the GPAA and determined that harmful terms existed, like the BLPA, or the fact that Enron North America could have forced unnecessary costs on consumers.

The Commission concludes that PGL overlooks the fact that it had the burden to prove that the GPAA was prudent. Merely stating generalities as to possible ways in which Dr. Rearden’s calculations might be erroneous is not the same as presenting evidence explaining why Dr. Rearden is in error. PGL’s argument is without merit.

11.

PGL’s Previous Reconciliation

PGL’s Position

PGL points to its previous PGA reconciliation, Docket 00-0720, which concerned its gas purchases from October 1, 1999, through September 30, 2000, and therefore concerned PGL’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 PGL. (See, Ill. Commerce Commission, on its own Motion, v. Peoples Gas Light and Coke Co., 2002 Ill. PUC Lexis 170). PGL reasons that finding the GPAA imprudent here, after having found it prudent in PGL’s previous reconciliation, is unreasonable. Such a conclusion would “stand the Commission’s prudence standard on its head.” PGL 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). (PGL Init. Brief at 53). PGL 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. (PGL Reply Brief at 7-9).

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). Staff maintains that new evidence, such as the “Aruba Analysis” and Wear Cross Ex. 15, came to light for the first time in this docket, even though this evidence was under PGL’s control. (Staff Init. Brief at 33-34).

01-0707

GCI’s Position

The GCI posit that the reason previous Commission decisions do not bind it is because this 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 GCI additionally maintain that reconciliation proceedings like this one are single-year proceedings. This Commission’s determination in each reconciliation proceeding is confined to relevant evidence presented regarding the costs incurred in that 12-month period.

The GCI additionally assert that the GPAA was not thoroughly reviewed in PGL’s previous reconciliation, as PGL initially concealed information. (GCI Reply Brief at 14-16). The GCI distinguish Ill. Power Co. v. Ill. Commerce Commission, 339 Ill. App. 3d 425, 790 N.E.2d 377 (1^st Dist. 2003), because here, Staff and the GCI argue that PGL’s failure to heed the results of two internal analyses was imprudent. In contrast, in Ill. Power, Staff required Ill. Power to conduct a specific type of analysis that it had never required of it before. (GCI Reply Brief at 38-40).

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 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 operational 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. PGL correctly points out that in the previous reconciliation, Commission Staff did not voice a concern with PGL/PGL 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 NA, or the existence of the “Aruba Analysis” until February of 2004, when discovery was reopened.

01-0707

PGL is required by law to petition the Commission for approval of affiliated-interest transactions. PGL did not divulge pertinent information to Staff in this proceeding before discovery was reopened, and it did not acquire Commission approval of its relationship with enovate. (See, 220 ILCS 5/7-101; 102). Documents such as the “Aruba Analysis” and Wear Cross Exhibit 15, which both establish that PGL/PEC 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, PGL’s failure to disclose pertinent facts distinguishes this case from PGL’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 of pertinent 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, this Commission is not imposing a new standard. Rather, it is imposing the standard it would have imposed, if pertinent information had been disclosed properly by PGL.

The Commission reiterates that Section 9-220 of the Public Utilities Act puts the burden of proof of prudence on PGL. Section 9-220 does not give PGL 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.

12. Proxy for Historical Gas Purchase Practices

PGL’s Position

PGL avers that the GPAA was a good proxy for its historical purchases, when compared to PGL’s past practices. (PGL Init. Brief at 44). 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. at 52). PGL asserts that its Exhibit 8 establishes that the GPAA was a reasonable proxy for its actual monthly gas costs for the two fiscal years prior to the GPAA, 1998 and 1999. According to PGL, this exhibit establishes that its total average gas price it previously paid was $0.0327 per MMBtu more than the Chicago citygate prices it incurred pursuant to the GPAA. (PGL Init. Brief at 53).

01-0707

PGL Ex. 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. (See, PGL Ex. C at 28). Mr. Wear testified that PGL 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. (Id.).

PGL also cites its Ex. 9, which is attached to Mr. Wear’s Rebuttal testimony, PGL Ex F. It contends that the increases in costs associated with GPAA were less than 0.25% of the total GPAA costs passed on to consumers. Finally, PGL cites its Ex. 10, which is also attached to PGL Ex. F. It is a comparison between its GPAA gas purchases and its non-GPAA purchases. PGL’s GPAA purchases, which comprised approximately 66% of the total in Ex. 10, were approximately 14% less expensive than its non-GPAA gas purchases. (PGL Ex. F, Attachment 10; PGL Initial Brief at 53).

Staff’s Position

Staff points out that, in the past, PGL 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 Initial Brief at 40; Staff Ex. 2.00 at 27). Staff maintains that, according to the basis projections PGL 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 PGL did in previous years. (Staff Ex. 3.00 at 22-24; Staff Ex. 7.00 at 20-21).

GCI’s Position

The GCI aver that PGL Ex. 10 does not aid PGL, as the GPAA covered a very large portion of PGL’s gas-buying needs. Non-GPAA purchases were, therefore almost by definition, unplanned and spot purchases made under unfavorable market conditions. The GCI conclude that absent anomalous market behavior, it is predictable that non-GPAA costs would be higher than the planned gas cost purchases PGL made pursuant to the GPAA. Also, PGL did not address the significantly different risk profile of the GPAA due to having only one contract with a single supplier for approximately two-thirds of its supply. The GCI maintain that PGL’s argument overlooks the harms to consumers caused by the GPAA, which ceded control over price and the amount of gas delivered. The GCI argue that there is no evidence that PGL personnel considered any of these large deficiencies when entering into this contract. (GCI Reply Brief at 23-25).

01-0707

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 unilaterally change the price of baseload gas. PGL 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 PGL to buy gas on the spot market on some occasions and left PGL with gas to unload on other occasions. When PGL unloaded the excess gas by selling it back to Enron NA, PGL paid a penalty every time it made a resale. PGL made no showing that its previous gas purchase contracts contained such provisions. The GPAA was not a prudent proxy for PGL’s previous gas contracts.

Moreover, PGL’s Exhibit 8 does not establish that the GPAA was prudent. While PGL 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 prices in previous years, does not establish that the costs imposed by the GPAA were reasonable. This is especially true here, when the credible evidence established that profits from this contract were gleaned by PGL affiliates/Enron North America/Enron Midwest, often for performing no real service or for performing very little service.³⁶ PGL Ex. 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.

PGL 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. PGL 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, PGL did not perform an analysis like Exhibit 8 before executing the GPAA. (PGL Ex. C at 28).

Finally, as the GCI point out, PGL presented no evidence at hearing indicating that its purchases in addition to those made pursuant to the GPAA were made under circumstances like those made pursuant to the GPAA. The fact that the GPAA was a contract to supply two-thirds of PGL’s gas supply is some indication that purchases made outside the GPAA were made on more of an emergency basis. Therefore, PGL Ex. 10 does not aid PGL.

_____________________

³⁶ See, the analysis herein regarding third-party transactions.

01-0707

13. Market-Based Pricing with No Demand or Reservation Charges

PGL’s Position

PGL 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. PGL has used market-based contracts in the past. (PGL Init. Brief at 47-48; Ex. L at 13). Market-based pricing results in gas costs that track market conditions. (PGL Ex. L at 13-14).

Also, the GPAA had no reservation or demand charges with respect to DIQ gas. Demand charges are typical for swing services, and the DIQ clause, essentially, provided a swing service. In the past, however, PGL has paid demand charges for swing services. PGL points out that not paying demand charges for swing gas saved consumers money. (PGL Init. Brief at 48)).

PGL avers that reference by Staff and the GCI to pipeline demand charges is disingenuous, as PGL personnel were not concerned with the costs consumers would pay in the way of pipeline demand charges when entering into the GPAA. Rather, PGL personnel were only concerned with commodity demand charges. (PGL Reply Brief at 35).

Staff’s Position

Staff points out that, pursuant to the GPAA, PGL continued to pay pipeline demand charges. (Staff Init. Brief at 38-39; Staff Ex. 2.00 at 20). However, Staff acknowledges that the DIQ clause did not have demand charges, which lowered gas costs for consumers. Staff estimated that the amount of gas demand charges saved pursuant to the DIQ clause was $1,750,000, over the life of the GPAA. (Staff Ex. 7.02; Staff Init. Brief at 51-52). Staff recommends offsetting its proposed disallowances for the time period in question in the amount of $350,000 (Staff Ex. 7.02).

GCI’s Position

The GCI point out that there were, in fact, pipeline demand charges embedded in the GPAA. The GCI concur with Staff that market-based pricing, with no demand charges for DIQ gas, does not justify entering into the GPAA. (GCI Init. Brief at 43).

The GCI posit that there is nothing per se prudent about market-based pricing. Mr. Graves, PGL’s expert, acknowledged that in circumstances like those involved in the Citgo contract, PGL is obligated to take advantage of a reasonable opportunity to acquire gas at less than the market price.³⁷ (GCI Reply Brief at 20).

_____________________

^{37 The Citgo contract is discussed herein under the heading “the Citgo Contract.”}

01-0707

Commission Analysis and Conclusions

The GPAA eliminated the demand charges that would have been incurred for swing gas. While Staff has provided evidence that PGL 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). However, for the year in question, the undisputed amount of saved gas demand charges is $350,000. (See, e.g., PGL Ex. C at 15). Based on the evidence provided, it appears that the GPAA provided this benefit to consumers.

PGL’s argument that the GCI and Staff disingenuously raise the issue of pipeline demand charges is a party-admission. PGL 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 PGL’s assertion that it did not consider these charges when entering into the GPAA is an admission that it acted imprudently.

Finally, as the GCI point out, PGL’s assertion that market-based pricing was beneficial ignores the situations it created regarding the market in the reconciliation year. As shall be set forth herein, situations like the Citgo contract could be considered to be market-based pricing, even though PEC/Enron Midwest artificially inflated the prices consumers paid for the gas procured pursuant to that contract. As the GCI point out, there is nothing per se prudent about market-based pricing. PGL’s assertion that market-based pricing in the GPAA is evidence of prudence is without merit.

14. Flexible Pricing

PGL’s Position

PGL 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. It could, for example, lock in prices other than the applicable index price. (PGL Init. Brief at 48). PGL argues that the GPAA’s flexible pricing provision (Article 4.2(a)) provided a benefit for consumers. Beginning in May, 2001, PGL locked-in the price of certain baseload quantities under the GPAA. PGL personnel did this pursuant to its “Gas Price Protection Strategy,” which was in place during the reconciliation period. (Id. at 51).

aa.

Staff’s Position

Staff posits that the flexible pricing provision only had value because the GPAA was a five-year contract. It maintains that PGL could have gained pricing flexibility by merely doing what it did in the past-entering into contracts of shorter duration. Staff argues that the flexible pricing provision merely restores the flexibility PGL would have had if it had not committed itself to a five-year contract with Enron NA. And, according to Staff, other parts of Article 4.2 decreased PGL’s pricing flexibility, while enhancing Enron NA’s flexibility. (Staff Ex. 2.00 at 26).

01-0707

Further, Article 4.2(a) did not allow PGL to unilaterally change the GPAA prices. Instead, pursuant to this provision, both PGL and Enron NA were required to agree to a price change. Presumably, Staff contends, Enron NA would only agree to a price change if it benefited from that change. Additionally, almost any contract can be changed by mutual assent. Thus, Staff concludes that flexible pricing does not compensate consumers for a pricing provision that does not provide gas at the least cost. (Staff Ex. 3.00 at 30).

bb.

GCI’s Position

The GCI contend that the GPAA’s flexibility in pricing was one-sided. The BLPA clause in the GPAA allowed Enron NA to increase the price of up to 71,250 MMBtus of gas, per day, in the winter period. The GCI aver that the amount of the change was from the FOM price to the daily price. Thus, Enron North America had the flexibility to raise gas prices through the BLPA clause.

PGL, on the other hand, could change the price of gas only if Enron NA agreed to that change. The GCI aver that flexible pricing was only an issue because the GPAA was such an extensive contract. It covered 66% of PGL’s gas supply and it lasted five years; thus, granting this substantial power to Enron NA was not prudent. (GCI Init. Brief at 43).

cc.

Commission Analysis and Conclusions

PGL’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 PGL 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.

Anything in the GPAA allowing PGL to renegotiate prices with Enron NA must be viewed in the context of the whole contract. The BLPA clause allowed Enron NA to change the price of baseload gas, if it so desired. (Staff Ex. 2.00, Attachments, GPAA, at 9). And, Articles 4.2(b) and 4.2(c) of the GPAA gave Enron NA the right, above and beyond the BLPA, to change the price of gas to the Gas Daily Midpoint Price for up to 71,250 MMBtu for any day in the contractually-defined winter period. Thus, anything modified mutually, could be unilaterally modified again by Enron NA. (Staff Ex. 2.00, Attachments, GPAA, at 9). The Commission concludes that the flexible pricing provision conferred no benefit on consumers.

01-0707

15. Load Flexibility

dd.

PGL’s Position

PGL argues that the GPAA also provided it with flexibility. PGL 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 PGL the flexibility to address these fluctuations. (PGL Exs. C at 14; Ex. L at 15-16).

Also, the GPAA gave PGL the right to resell gas to Enron NA. According to PGL, this right substantially eliminated the uncertainty associated with finding a market for gas, often on short notice. PGL contends that the need to sell gas is substantially influenced by variables, such as weather, customer usage and transportation customers’ deliveries, over which PGL has little or no control. PGL points out that an oversupply can cause a pipeline imbalance, which can result in penalties that it must pay. (PGL Init. Brief at 49-50).

PGL maintains that the penalties it incurs when selling gas back to Enron NA are not really penalties. This is true because the sell-backs in the GPAA are based on daily prices. (See, Staff Ex. 2.00, Attachments, GPAA, at 9-10). However, according to PGL, 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. (PGL Init. Brief at 50-51).

ee.

Staff’s Position

Staff contends that PGL presented no evidence establishing that the GPAA was equal to, or superior to, PGL’s contracts in previous years. And, 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 39; Staff Ex. 2.00 at 26). Staff points out that PGL had no control over the amount of gas Enron NA delivered to it pursuant to the SIQ provision. As a result, PGL had too much gas on its hands. Without the GPAA, PGL’s need to unload excess gas would have been occasional and in small quantities. (Staff Ex. 7.00 at 33).

ff.

GCI’s Position

PGL ceded control over the amount of gas that the GPAA required PGL to purchase. Enron North America’s decisions regarding how much SIQ gas it delivered to PGL led, repeatedly, to oversupply situations that required PGL to sell gas back to Enron NA. The GCI argue that on 93% of the occasions when the sell-back provision was used, Enron NA had delivered maximum SIQ volumes, citing Staff Ex. 2.00 at 20. (GCI Init. Reply Brief at 22-23).

01-0707

gg.

Commission Analysis and Conclusions

While the arrangement in the GPAA (the mix of baseload, SIQ and DIQ gas) provided PGL 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 PGL 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 PGL or on consumers. When weighed against the harm that the provisions PGL cites in support of its contention that it had load flexibility, PGL has not sustained its burden to establish that the beneficial aspects its cites outweigh the harmful aspects of these provisions.

16. Unquantifiable Benefits

hh.

PGL’s Position

PGL contends that the GPAA conferred benefits on it that are not easily quantified. A large contract with a single supplier allowed PGL to conduct its daily purchases while remaining hidden from the larger market. Citing Mr. Wear, PGL avers that without direct knowledge of PGL’s purchase plans in that marketplace, “daily prices might tend to rise less dramatically than if (PGL) were out in the open market soliciting offers from dozens of counterparts.” (PLG Ex. F at 8; PGL Init. Brief at 56).

PGL 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 NA had a presence in the Chicago market. Also, according to PGL, Enron provided other benefits, benefits it would not have received with a portfolio of smaller contracts. (PGL Init. Brief at 55). Enron NA further supplied PGL with technical support to facilitate operations, including a secure webpage that allowed PGL and Enron NA to exchange information about daily activity. Enron NA additionally created a database for PGL’s gas controllers. This database retrieved historical system send-outs based on weather outputs. Enron NA also provided training to PGL employees as to how to use financial hedging instruments, like energy derivatives and options. (See, PGL Ex. F at 9).

ii.

Staff’s Position

Staff contends that PGL offered no facts or concrete examples to demonstrate the value of those benefits. Instead, according to Staff, PGL asserted only vague generalizations. And, these benefits did not provide direct results for consumers. (Staff Init. Brief at 53).

01-0707

jj.

GCI’s Position

The GCI argue that none of the unquantifiable benefits cited by PGL supports its claim that the GPAA was prudent. They contend that PGL presented no evidence establishing that its daily price activity was large enough to have an impact on the prices in the larger market. Also, PGL presented no evidence establishing that the GPAA actually made prices less dramatic in the larger market. Rather, Mr. Wear merely stated that such a situation might occur. (GCI Reply Brief at 25-26). Additionally, PGL presented no evidence that Enron North America’s size and market dominance, at the time the GPAA was executed, were elements of the GPAA. Finally, the GCI posit that, while Mr. Wear testified that certain aspects of the GPAA benefited operations and employee education, Mr. Wear did not testify that anyone at PGL considered these benefits when deciding whether to enter into the GPAA. (Id. at 26-27).

kk.

Commission Analysis and Conclusions

Mr. Wear’s statement, quoted above, is too vague to be given any evidentiary weight. He also offers no examples, and the phrase “might tend to rise,” is speculative. Mr. Wear does not explain what PGL would be doing in the open marketplace soliciting bids, or why. And, Mr. Wear points to no information establishing that previously, PGL’s baseload gas was purchased on a daily basis in the open marketplace.

There also is no evidence establishing that training PGL employees on futures and financial derivatives provided any benefit to consumers or that such training ever occurred; PGL conducted no such transactions during the time period in question. Additionally, while PGL argues that Enron NA was a premier supplier, it proffered no evidence indicating that Enron NA’s reputation was an asset to PGL consumers. Therefore, there is no evidence that Enron NA being a premier supplier, at the time the GPAA was entered into, is of any benefit. And, as the GCI point out, there is no evidence that PGL decision-makers considered these benefits, or even knew of these benefits at the time the GPAA was executed. The Commission concludes that PGL failed to present evidence establishing that the “unquantifiable benefits” it cites conferred any meaningful benefit on consumers.

17. Conclusions Regarding the GPAA, in Total

ll.

PGL’s Position

Citing Mr. Graves’ testimony, PGL asks the Commission, if it feels that CERA and PIRA basis data should be considered, to consider what Mr. Graves estimated as a disallowance. Since the actual credit for baseload and SIQ purchases was three cents, the disallowance should only be for the gap between the required credit to show prudence taking the three-cent discount on baseload and SIQ purchases into account. PGL reasons that the amount of increased costs per MMBtu should be multiplied by the FOM volumes taken during the reconciliation period to calculate a disallowance. Using

01-0707

this approach, Mr. Graves estimated that harm to consumers was in the range between $2.9 and $8 million. PGL avers that Dr. Rearden’s calculations treat all of the unspecified “anomalous results” of the 2000-2001 winter period as attributable to the GPAA. (See, PGL Reply Brief at 40-41).

On Exceptions, PGL argues that the ALJPO’s proposed disallowance of $13,304,910 is only 2.3% of the total gas costs paid to Enron North America pursuant to the GPAA during the reconciliation period. It reasons that therefore, 97.7% of the GPAA gas costs were prudent. According to PGL, based on this result, finding its decision to be imprudent “seemingly runs afoul” of the principle that a finding of imprudence requires more than a mere difference of opinion. (PGL BOE at 33-34).

Commission Analysis and Conclusions

Certain obvious harms exist in the GPAA that, even without some sort of economic analysis, are apparent upon a reading of this contract. A diligent reading of the BLPA, Articles 4.2(b) and 4.2(c) and the SIQ provision would place a reasonable person on notice that executing the GPAA would relinquish control to Enron North America over price and amount, essential contractual terms. There are other, less obvious harms to the GPAA, such as paying twice for the same delivery of gas, decreasing the amount of demand credits available due to release of pipeline capacity, and paying penalties on resales, when resales were necessitated by the SIQ provision.

PGL correctly maintains that the GPAA conferred some benefits. For example, it imposed no demand fees on swing gas. When the benefits of the GPAA are weighed, however, against the harms it caused, it is overwhelmingly clear that the GPAA was indeed a harmful contract.

PGL accepted the GPAA, in the face of two economic analyses indicating that this contract would increase consumer costs, and PGL decision-makers, nevertheless, executed this contract. There is ample evidence of disregard for the negative effects of the GPAA on consumers—executing the GPAA, despite two economic analyses establishing its harm on consumers—and the obvious harms in that contract, mentioned above, that should become apparent to any PGL personnel—exercising a stand of care that a reasonable person would use—upon reading this contract.

There is no credible evidence that PGL personnel were concerned about the increased costs resulting from the GPAA. Based on this record, the Commission cannot draw the conclusion that entering into the GPAA was an inadvertently bad decision. Nor can we conclude, based on this record, that it was a good decision that simply went awry. Rather, the Commission concludes that entering into a relationship with Enron NA—conferring profits to its parent company, PEC with no offsetting benefit derived by PGA consumers from those profits—is astonishingly imprudent. PGL decision-makers willingly entered into a contract that created oversupplies, as is evidenced by the fact that 93.9% of the time when Enron North America sold the

01-0707

maximum amount of SIQ gas, PGL had to sell gas back to Enron NA, and had to pay a penalty every time it made a sell-back.

Additionally, we cannot view the GPAA in a vacuum. On the same day Mr. Morrow signed the GPAA, he also signed an LOI on behalf of PEC, PGL’s parent company, agreeing to share profits with the same company that provided PGL with gas pursuant to the GPAA. As shall be set forth herein, there is credible evidence in this record, establishing that the GPAA was negotiated with an eye toward profit-sharing from PGL’s relationship with Enron NA.

The Commission finds PGL’s use of the GPAA to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for the GPAA is properly included in the Settlement Agreement and Addendum as discussed in Section I.

V. Manlove Field

A. Findings of Fact

1. Background

Gas utilities typically employ some means of storage to meet supply needs. PGL’s Manlove Field (“Manlove”) is one such facility. Manlove is an aquifer, which is a water-bearing porous geologic structrure with properties that lend to conversion to a natural gas storage facility. (Staff Ex 2.00 at 42). Manlove is dome-shaped, with a cover of impermeable rock that prevents the upward migration of natural gas. Porous, water-filled rock exists underneath the layer of impermeable rock. PGL injects natural gas into the pores of the water-filled rock, displacing the water. The displaced water then contains the natural gas by forming a seal at the bottom of the aquifer (also known as a reservoir). (Id.).

Three basic components of natural gas exist in storage reservoirs: top or working gas (“working”); recoverable base gas and non-recoverable base gas. Gas utilities cycle working gas during the course of normal operations during the injection/withdrawal seasons. Recoverable base gas is not cycled, but provides the necessary pressure to cycle the working gas. Recoverable gas represents a non-depreciating capital plant while in operation. This gas can only be removed from the reservoir upon abandonment. Non-recoverable gas is trapped in the reservoir and cannot be recovered, even at abandonment. This gas is capitalized and depreciated over the life of the reservoir. (Staff Ex. 2.00 at 42-43).

01-0707

PGL typically injects gas into storage during the summer when natural gas prices are lower. During the winter, PGL relies on stored gas to meet its customers’ heating needs, supplementing with spot purchases as needed. PGL also provides storage services for third parties, including North Shore Gas. PGL also uses storage to accommodate for weather that was not forecasted, a force majeure, and situations, in which, gas suppliers provide a different amount of gas other than that which was agreed upon.³⁸ (PGL Ex. D at 17). PGL stores 27 Bcf of natural gas for PGA customers and 8 Bcf for non-tariffed services at Manlove. (See, e.g., PGL Initial Brief at 9). Mahomet pipeline connects Manlove to PGL’s Chicago distribution system. (Tr. 1301).

The injection season for Manlove Field usually commences the first or second week of March and it ends in the first or second week of December. (PGL Ex. I at 6). Once withdrawal season begins, PGL personnel continues to withdraw gas for the remainder of the season. (Id. at 7). At the start of each injection season, a working gas target for that season is established. Then, an injection schedule is made, whereby certain injection volumes are targeted, as well as average daily rates for each month. (PGL Ex. I at 5). PGL personnel monitor monthly totals of injections and the seasonal cumulative totals. If a particular month is long or short compared to the schedule, or if the working gas target is revised, the rest of the injection season is adjusted. (Id.). When PGL shifts to the withdrawal season, withdrawals from Manlove should not fall below a certain level. (PGL Ex. L at 50). Once withdrawals begin, they cannot be stopped. (Id.). PGL personnel are not able to change from injections to withdrawals and back again. (Tr. 1066). Therefore, if PGL is in its injection phase, Manlove can be unavailable for withdrawals during the months of October, November, March and April. (Id.).

During the winter of 2000-2001, PGL personnel planned to keep enough gas in Manlove to carry it through the third week in January, in order to meet peak winter conditions. (Staff Ex. 6.00 at 40-41). In November of 2000, PGL stored gas for its ratepaying customers, North Shore Gas and third-party customers. PGL considers this to be “Hub services,” or “non-tariff” services. Withdrawals from Manlove commenced on November 21, 2001, two weeks earlier than usual. At the time PGL began withdrawing gas from Manlove, third-party customers had already injected approximately 7.1 Bcf of gas. (Staff Ex. 7.00 at 46).

Certain events happened that caused PGL to alter its storage withdrawal plans for Manlove. Record cold conditions existed in Chicago in the months of November and December of 2000. (See, e.g., Tr. 1066-67). 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. Also, natural gas prices increased dramatically in November. In December, gas prices peaked at over $10 per MMBtu and remained above $5 per MMBtu almost through April. (Staff Ex. 3.00 at 50).

_____________________

³⁸A 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)).

01-0707

PGL witness Mr. Wear testified that the reason PGL personnel decided to withdraw gas from Manlove earlier than usual was because the weather at that time was colder than normal and gas prices at that time were at an unprecedented high. PGL decided to begin withdrawals earlier than planned because November 2000 gas prices were higher than December 2000 and January 2001 forward prices and it was possible that the colder than normal weather would subside. (PGL Ex. F at 35). Because of this decision, Mr. Wear stated that PGL needed to buy less gas to balance the system. Also as a result of this decision, PGL had less storage gas to use going into December, which necessitated modifying PGL’s withdrawal plan. (PGL Ex. F at 35-36).

As mentioned above, PGL used Manlove to provide storage for its PGA customers and to provide services to third parties. Some of PGL’s third party transactions involved Enron. In November of 2000, PGL allocated only half of Manlove’s storage capacity for consumers. The other half of this gas went to third-parties. As discussed in more detail below, “Manlove Jumpstart” was one such third party transaction. In December of 2000, 52% of the gas withdrawn from Manlove went to consumers. In January of 2001, 78.4% of Manlove gas withdrawals were for consumer use. (See, Staff Ex. 3.00 at 50). None of the revenues from third-party transactions were used to offset gas costs passed on to consumers pursuant to PGL’s PGA. (Staff Ex. 7.00 at 54).

To facilitate the non-tariffed³⁹ third-party transactions, PGL increased the amount of working gas in Manlove by 8 Bcf, representing a significant increase of approximately 30%. (See, e.g., Staff Ex. 2.00 at 29, 45). According to Staff witness Mr. Anderson, an increase in working gas must be supported with an increase in recoverable and non-recoverable base gas. Ideally, PGL should perform reservoir engineering studies to determine the appropriate amounts of recoverable and non-recoverable gas needed to support an increase in working gas. PGL provided no data in this proceeding demonstrating that PGL increased recoverable and non-recoverable gas when it increased working gas at Manlove. Essentially, PGL failed to show how it increased non-tariffed working gas in Manlove without increasing recoverable gas and non-recoverable gas. This failure lead to PGA customers improperly paying for the necessary recoverable and non-recoverable gas. PGL improperly passed costs for non-tariffed services on to PGA customers. (Staff Ex. 2.00 at 46).

_____________________

³⁹ Non-tariffed services are not subject to rates on file with the ICC. Rather, these transactions are performed either pursuant to a FERC operating statement or through third party storage agreements. For third party storage arrangements, PGL leverages its system assets. (Staff Ex. 2.00 at 30).

01-0707

Staff provided an analysis of third party transactions during the winter of the reconciliation period at Manlove. On January 5, 2001, PGL’s non-tariff, third-party inventory balance turned negative; meaning third-parties removed more gas from Manlove than they had injected into it. On February 28, 2001, PGL’s maximum negative third-party inventory occurred at -4,903,211 Dth. This third-party inventory remained negative for almost five months, until May 3, 2001. (Staff Exs. 2.00 at 37; 3.00 at 59). During this five-month period, it was not possible for PGL to meet third-party obligations without using the gas it stored for consumer use—the PGA gas. (Staff Ex. 2.00 at 37). PGL did not use a total of 25.5 Bcf of gas stored in Manlove, which PGL claims is reserved for consumers use during the winter months. PGL withdrew a total of 12 Bcf of gas over the 2000-2001 winter heating season (November through March) for third-parties. Seven Bcf of that gas was injected by third-parties during that season. (Staff Ex. 7.00 at 46). An additional five Bcf of gas used for third-parties, however, was the less expensive gas purchased for consumer use in the winter. (See, e.g., Staff Ex. 3.00 at 44; 7.00 at 47-49; City-CUB Ex. 4.0 at 45).

Staff witness Dr. Rearden explained the significance of the negative third party balances. According to Dr. Rearden, a negative third-party balance shows PGL gave preference to third party transactions at the expense of PGA customers. PGL measured the gas flows into and out of Manlove and then allocated those volumes between various entities. In doing this, PGL must ensure it meets its obligations to PGA customers, as well as third parties. In December 2000 and January 2001, PGL over-allocated resources to third party customers and under-allocated resources to PGA customers. During this period of particularly high gas prices, PGL denied its PGA customers the benefit of lower priced storage withdrawals. (Staff Ex. 12.00 at 30-31). Further, these negative balances also evince that third-party transactions do not have a benign impact on consumers. When PGL over-allocated gas for third-parties, this over-allocation interfered with withdrawal plans for consumers. (Id. at 31). CUB witness Ms. Decker additionally opined that the gas used in third-party transactions was not limited to just an oversupply of gas. (City-CUB Ex. 1.0 at 47).

PGL used all of its supply assets to meet its system load requirements for any given day. Thus, on any given day, the PGL consumer requirements and PGL’s third-party requirements were fulfilled by whatever gas PGL had on hand. (Staff Ex. 2.00 at 38). Third-party services also altered the timing and use of PGA purchases and injections, as well as the timing and use of withdrawals from leased storage and withdrawals from Manlove, especially during periods of high demand. (Staff Ex. 2.00 at 38-39).

The gas stored at Manlove for use in the 2000-2001 winter was purchased in the summer of 2000. Because PGL over-allocated resources to third parties during Manlove’s withdrawal season, it then needed to purchase replacement gas for PGA customers. PGL acquired this replacement (or swing) gas by purchasing expensive winter gas and passing the cost of that gas on to consumers. Two of PGL’s major suppliers for this replacement gas were Enron NA and Enron Midwest. In some instances, PGL delivered gas from Manlove to Enron Midwest and then purchased expensive spot winter gas to replace that gas. (See, e.g., Staff Ex. 3.00 at 59). Enron Midwest and Enron NA, combined, accounted for 28% of PGL’s swing purchases for the month of November 2000. In December, 2000, these two entities provided 36.8% of PGL’s swing gas. In January, 2001, these two entities supplied 23.3% of PGL’s swing gas. (Staff Ex. 7.00 at 55). Dr. Rearden opined that PGL’s primary use of Manlove during the winter season was to benefit third-party Hub transactions. (Staff Ex. 7.00 at 38).

01-0707

According to CUB-City witness Mr. Mierzwa, the average price of gas during the Manlove summer injection season of 2000 was $4.12 per Dth. The average cost of gas purchased to replace this gas was $10.76 per Dth. Mr. Mierzwa determined that the economic loss suffered by consumers as a result of PGL’s giving preference to third party transactions over PGA customer needs was $51.2 million. (City-CUB Ex. 4.02 at 18).

Staff witness Mr. Anderson concluded that, in addition to using Manlove Field to provide non-tariff services, PGL also used leased storage services, the cost of which consumers paid for through the PGA. (Staff Ex. 2.00 at 39). In his opinion, PGL would not be able to perform non-tariff services without all of its supply resources, including, the gas it bought for consumers and leased storage, without using that which was designated for consumers in third-party transactions. (Id. at 39). Mr. Anderson further testified that PGL had an inappropriate incentive to use PGA assets to provide non-tariff services. PGL recovers the costs of serving consumers through the PGA. However, PGL engages in non-tariff transaction, subject to competitive market conditions. PGA costs are an automatic pass through, whereas PGL must compete to win non-tariff business. The pressure to generate revenue in the competitive market likely caused PGL to favor its non-tariff services customers at the expense of PGA customers. (Id. at 40). The costs PGL avoided by using storage gas designated for consumers in third party transactions increased the net revenues received by PGL/PGL affiliates from those transactions. (Staff Ex. 2.00 at 39). Ms. Decker, also, opined that, when accomplishing third-party transactions, PGL used its storage and transportation assets. (City-CUB Ex. 1.0 at 44).

PGL responded to Staff’s and CUB-City’s concerns. According to Mr. Wear, even if PGL had not used Manlove Field for third-parties, the same amount of gas would have been available for consumer use and the consumers would be unaffected, both in terms of the withdrawal season and Manlove’s peak day activity. Mr. Wear testified that PGL usually plans to have only 25.5 Bcf of gas storage available for consumers. That is all PGL would have had for consumer use, even if PGL personnel had not decided to withdraw gas from Manlove early, (in November, as opposed to December) in the time period in question. (PGL Ex. F at 38). One of the reasons for this is that PGL attempts to fully cycle the working inventory of its storage fields to maintain overall performance and the lifespan of the fields. Experience with the Manlove aquifer showed that storing 25.5 Bcf for consumers fit PGL’s load profile. (Id.).

Further, under warmer-than-normal weather conditions, Mr. Wear continued, PGL would not be able to withdraw more than 25.5 Bcf of gas. Under other weather scenarios, PGL would use the extra gas injected into Manlove Field, but such use would reduce or replace the need for baseload purchases. Mr. Wear stated that reducing baseload purchases would be economically unwise because baseload purchases are necessary to achieve a mix of FOM prices and daily prices. Mr. Wear reasoned that, without baseload purchases, PGL could be required to buy gas on the daily market, subjecting it to daily price volatility. Also, PGL would not be able to reduce much of its other storage services. Those services perform unique functions to meet PGL’s load requirements. (PGL Ex. F at 39). Also, according to Mr. Wear, the peak day capacity of Manlove would not change. The amount of gas stored in Manlove has no impact on peak day capacity. Rather, that capability is determined by Manlove’s geological characteristics. (Id.).

01-0707

Mr. Wear further testified that PGL could not have interrupted deliveries to third party customers and instead used that gas for PGA customers. If PGL had interrupted third-party services, it would have been in breach of its contractual commitments and its tariff obligations to those third-parties. Gas delivered by third parties to Manlove either must be returned to those parties at some point. Mr. Wear did not specifically state what those contractual commitments or tariff obligations were. (PGL Ex. F at 40).

2. The Decline Point for Manlove

When determining whether and when to withdraw gas from Manlove, PGL personnel consider Manlove’s geological factors. (Tr. 873-4). PGL witness Mr. Puracchio, who is responsible for operating Manlove, testified that gas storage in an aquifer, such as Manlove, is less efficient than other types of storage. This is because injecting gas into, and withdrawing gas from, an aquifer results in large proportions of gas being trapped in the pores of the rocks by the water.⁴⁰ Along with the gas in the aquifer, large amounts of water are also produced. (PGL Ex. I at 3). The water must be displaced by injecting gas at a pressure that is higher than the pressure of the water. (PGL Ex. I at 3).

Because a certain pressure must be maintained to withdraw gas from an aquifer, after a certain point in time in the withdrawal season, Manlove can no longer meet its rated maximum capacity. This is called its “decline point.” (Tr. 679). At that point, usually in February, Manlove cannot be counted on as a source of supply for peak delivery. (Tr. 677). During the reconciliation period, PGL personnel projected that Manlove Field would reach its decline point on February 4, 2001. Manlove Field actually reached its decline point on February 2, 2001. (PGL Ex. M at 5).

Mr. Puracchio testified that PGL cycled more than 27 Bcf of gas per season at Manlove. Injecting more gas extends the field decline point, which extends how long Manlove is useful for storage. When more gas is injected, less gas becomes trapped. (Id. at 7; Tr. 681). During the time period in question, PGL personnel successfully extended the decline point of Manlove, which increased Manlove Field’s storage capability. (Tr. 681). PGL presented no evidence establishing that this increased capacity was used to benefit consumers directly, through use of this extra capacity, or indirectly, through profits from the use of this extra capacity.

_____________________

⁴⁰ Use of the term “trapped gas” in Mr. Puracchio’s testimony does not refer to any accounting terminology. (See, e.g., PGL Ex I. at 27). Instead, it speaks to the term “trapped” as it is used in common parlance. (Id.).

01-0707

3. Maintenance Gas or “Cushion Gas”

Maintenance gas is gas that is used to keep a certain, necessary level of pressure in a natural gas utility’s system. Because this pressure must be maintained, maintenance gas cannot be withdrawn under normal operating conditions. (Staff Ex. 1.00 at 13). Historically, until the reconciliation year in question, PGL designated this gas as “maintenance gas;” which is recoverable in base rates, not in a PGA. For the time period in question, however, PGL recorded this gas as gas that was lost and unaccounted for (“GLU”). Staff maintains that $4,628,267 represents the amount of gas that was improperly recorded as GLU. PGL does not contest this proposed disallowance. (PGL Init. Brief at 104).

Before 1999, PGL personnel allocated 6.5% to 7.5% of the gas it injected into Manlove to cushion gas. (Staff Ex. 2.00 at 58; PGL Ex. I at 13). PGL hired consultants, who performed the Roxar Study to determine what effect, if any, adding this gas to Manlove would have on Manlove. Both the Roxar study and the Smedivg Study, cited by Mr. Anderson, recommended allocating 5%-6% to cushion gas. (PGL Ex. M at 5).

In 1999, PGL personnel began allocating only 2% of the total injected gas at Manlove to cushion gas, including the gas injected for third-parties. (See, e.g., PGL Ex. M at 4). However, third-parties received 100% of the gas injected for them during the time period in question. Staff witness Mr. Knepler concluded that consumers subsidized third-parties by paying for the third-parties’ share of the maintenance gas. (Staff Ex. 1.00 at 13). PGL also injected gas into Manlove for use by North Shore. However, PGL did not charge North Shore for maintenance gas. Mr. Knepler concluded that PGL customers also subsidized North Shore. (Staff Ex. 1.00 at 27). Further, according to Staff witness Mr. Anderson before PGL used Manlove for third-party services, PGL should have considered the results of the studies PGL conducted, recommending an increase in the volume of recoverable and non-recoverable base gas. (Staff Ex. 2.00 at 58).

Mr. Puracchio testified that performance at Manlove was adequate with a 2% allocation to cushion gas. As a result of allocating only 2% of gas to “cushion gas,” field performance at Manlove has not declined. This, he stated, was “clear evidence” that a 6.5-7.5 % allocation of gas to cushion gas is not needed. (PGL Ex. I at 13; PGL Ex. M at 5).

Mr. Anderson testified that when PGL personnel increased the amount of gas injected by eight Bcf, the amount of gas lost increased by 0.52 to 0.60 Bcf of gas, which cost consumers $3.2 million to $3.7 million. (Staff Ex. 2.00 at 13). In Mr. Anderson’s opinion, it was imprudent of PGL to increase the amount of gas it put into Manlove, even after having studies performed which determined that substantial additional costs to consumers would be necessary to support those services. (Staff Ex. 2.00 at 30).

01-0707

4. Displacement

Staff witness Mr. Anderson testified that PGL could not have been able to supply non-tariff, third-party services without using assets that are included in PGL’s PGA. Mr. Anderson opined that PGL used displacement to perform these services with its PGA gas. (Staff Ex. 2.00 at 31-32). Mr. Anderson explained that displacement is the process by which gas moves through a pipeline transportation system, without the physical delivery of the same molecules of gas. Displacement concerns accounting entries instead of the physical movement of gas. If, for example, PGL injected 1,000 units of gas into Manlove during a 24-hour period and withdrew 10 units of non-tariff gas from Manlove, PGL personnel would execute an accounting entry with ten units of PGA gas that it could have, but did not, inject into Manlove. Instead, these 10 units were supplied to the third-party. In this example, physically, PGL only injected 990 units of gas and another ten units was used for the third-party transaction. (Id. at 32). Displacement permits the movement of gas through a pipeline without actually delivering the same molecules of gas. (Staff Ex. 2.00 at 32).

Thus, gas is a fungible commodity; it is not possible to physically distinguish whether gas stored in Manlove was purchased for consumers, or whether it was injected for third-party use. What separates various injections and withdrawals is only accounting entries, which include the gas volume and price paid for it, where applicable. (Staff Ex. 2.00 at 32).

Mr. Anderson analyzed the injections and withdrawals during the months of October, 2000 through September of 2001. He concluded that PGL used displacement to accomplish many non-tariff services. The data showed PGL physically operated Manlove in a manner consistent with practices at other aquifers in Illinois. Like other aquifers, PGL injected gas into Manlove from April through October and withdrew gas from December through February. PGL treated May and November as swing months, where both injections and withdrawals may take place. However, Mr. Anderson noticed PGL recorded injections during the winter months and withdrawals during the summer months. He opined that because injections were recorded during winter months when, normally, no physical injections take place and withdrawals occurred during summer months, when no physical withdrawals take place, PGL used displacement to accomplish its third-party services. (Id. at 34-35).

Mr. Anderson concluded that approximately 8,506 Dths of gas did not physically move. (Staff Ex. 2.00 at 36-37). He averred that PGL’s records established that approximately 9,237,000 Dths more gas was withdrawn from Manlove than actual metering records at Manlove stated. (Id. at 37). This discrepancy shows that PGL used displacement to perform non-tariff services. Additionally, use of displacement allowed PGL to arrange third-party transactions without incurring the cost of physically transporting that gas. (Id. at 38).

Displacement uses recoverable gas costs for the performance of non-tariff services. Mr. Anderson concluded that, if non-tariff revenues do not flow through PGL’s

01-0707

PGA, personnel at PGL will have the inappropriate incentive to use gas costs passed on to consumers to provide third-party, non-tariff services. (Id. at 40). He stated that, in his opinion, there is nothing wrong with displacement per se. Rather, Staff objects to PGL’s use of displacement of gas while still contending that only its rate-based assets (Manlove and its transmission system) are used to perform non-tariff services. (Id. at 39).

Large Withdrawals from Manlove for Third-Parties at the Onset of Winter

During the time period in question, PGL provided services to third-parties that were not pursuant to its Commission-jurisdictional tariff. In general, it provided transportation, storage and “park and loan” services.⁴¹ PGL also provided 3PSes, which were exchanges of gas with third-parties. (PGL Ex. C at 29-31).

Also during the time period in question, PGL entered into what is referred to herein as 3PSE exchanges with Enron Midwest, three of which PGL personnel colorfully entitled; “38 Millennium Special;” “Manlove Jumpstart;” and “Hub Blowout.” Collectively, these three contracts called for PGL to supply 3.5 Bcf of gas to Enron Midwest during November, 2000 and continuing through February of 2001. The three exchange agreements provided that Enron Midwest would return this gas to PGL beginning in April of 2001 through October of 2001. PGL derived minimal payments from these three contracts.

In the course of discovery, PGL provided Staff with three different explanations as to how it was compensated for entering into these exchange contracts. At first, PGL maintained that two of these contracts were priced at “the cost of carry” which means that a value was assigned to the gas loaned, as well as the gas delivered, with the difference between the two treated as a loan. (See, Staff Ex. 3.00 at 52). PGL provided no explanation at that time with regard to the third contract, the “38 Millennium Special” . (Id.). Next, PGL claimed that it determined the values attached to the loan and repayment of gas in these contracts by examining the pricing differentials using NYMEX forward prices (for futures contracts). (See, Staff Ex. 3.00 at 52). Later, it averred that two of the three contracts were paid for in conjunction with FERC Operating Statement firm transportation services it provided to Enron Midwest, Meaning PGL bundled two services together and received one payment for both (Id.).

The “Hub Blowout” exchange provided for a loan to Enron MW of .5 Bcf of gas in November of 2000 and PGL was to receive an equal amount of gas back again in August and September of 2001. The articulated “cost of carry” for this transaction was $145,000, payable to PEC, PGL’s parent company. (See, Staff Ex. 3.00 at 54). While PGL delivered the loan as planned, Enron MW actually repaid the loan from June through August 2001. Actual compensation to PEC was $368,125. PGL asserted that the reason the change occurred was due to “additional value that was created after the original transaction was entered into.” (sic). (Id.).

_____________________

⁴¹ A “park and loan” transaction is one, in which, a shipper delivers gas to PGL on an agreed-upon schedule, subject to interruption, (a ”park”) and PGL would then be obliged to return a like quantity of gas to that shipper, on an agreed-upon schedule, also subject to PGL interruption (the “loan”). A loan, however, can occur before a park. PGL does not use any of its pipeline transportation for these transactions. (PGL Ex. C at 33).

01-0707

“Manlove Jumpstart” consisted of a loan of gas, occurring on November 21, 2000 through November 30, 2000, of one million MMBtus of gas to Enron Midwest at the Chicago citygate Daily Price, the same price as DIQ gas. PGL received $265,000 compensation for this transaction. “Manlove Jumpstart” commenced at the same time PGL began withdrawing gas for PGA customers from Manlove Field. PGL stopped purchasing DIQ gas from Enron NA during this time period. Instead, on almost every day that PGL withdrew gas and sold it to Enron MW pursuant to “Manlove Jumpstart,” it also purchased the same amount of gas at the higher Gas Daily Chicago citygate Daily Price. PGL received funds for the exchange, but did not pass them through to consumers. (See, Staff Ex. 7.00 at 53-54; Staff Ex. 3.00 at 56).

At that time, the applicable NYMEX futures price differential was 85.5 cents per MMBtu. In fact, the spot price for gas at this point in time was at a record high. (See Staff Ex. 3.00 at 53-54). PGL’s compensation from Enron MW, however, was 10.8 cents per MMBtu, less than one-eighth of the value of that gas. This gas loan was not repaid until April through October of 2001. (Id. at 56).

The “38 Millennium Special” was an attempt to expand Manlove’s storage capacity by using two summer storage cycles, instead of only one. (City-CUB Ex. 1.0 at 54). It consisted of a loan of 2 Bcf of gas to Enron MW in February of 2001, which was repaid in March and April of 2001. The compensation Enron MW paid to PGL was $124,022. This compensation was part of a non-tariff service contract. At that time, the smallest price differential between pertinent futures contracts in Natural Gas Intelligence was 107 cents per MMBtu. PGL’s compensation for entering into the “38 Millennium Special,” however, was at 6.2 cents per MMBtu. (Staff Ex. 3.00 at 56-57).

Using Manlove Field, PGL also offered “Park and Loan” storage services to Enron and others during the time period in question. (Staff. Ex. 5.00 at 5). These services were interruptible, thus, PGL had the right to refuse service or discontinue providing service, if supplying such service would impair its ability to draw on this resource to meet the needs of consumers. (Tr. 928-29).

A. Conclusions of Law

1. Staff’s Position

Staff argues that PGL acted imprudently with respect to several decisions involving Manlove Field and proposes two disallowances for this imprudence. The first is $10,268,171, which is the value of the gas loaned to third-parties, minus the value of the gas those third-parties returned to Manlove at the time when the gas was returned. (Staff Init. Brief at 57, 62). Staff also proposes to disallow $25,920,181, which is the cost of gas PGL purchased to initially replace that gas, for a total proposed gross disallowance of $36,188,352. From this amount, Staff deducts $6,628,631; $4,378,466 of which represents the amount of profit gained from FERC operations, and $2,250,165 of which represents profits from PGL storage exchange transactions. The latter amount concerns third-party transactions and will be discussed in the Section here discussing third-party transactions. Thus, Staff’s net disallowance for imprudent use of Manlove Field is $29,559,721. (See, attached Schedule, Staff Init. Brief at 57, 62).

01-0707

Staff notes that in November of 2000, PGL allocated only half of Manlove’s storage capacity for consumers. The other half was used to deliver gas to third parties. PGL did not offset gas costs passed on to consumers with these revenues as Commission rules require. (Staff Ex. 7.00 at 54-55). Staff maintains that PGL over-allocated Manlove to third-parties in a manner that raised gas costs that were borne by consumers. Staff argues that PGL also over-allocated usage of Manlove at a time when the prices were high. According to Staff, PGL’s over-allocation of gas to third-parties additionally required it to purchase gas on the spot market to support Manlove’s peak delivery. Staff avers that PGL could have interrupted its third-party services to prevent the need for spot purchases for PGA customers, but it did not. PGL had an option through which it could have averted buying gas on an exceptionally high market in a colder-than-normal winter, but PGL did not avail itself of this option. (Id. at 58).

Staff points out that, by January 5, 2001, PGL’s third-party customers had drained all of the gas injected into Manlove for these third-parties’ benefit. Staff maintains that PGL allowed third-party customers to continue to remove gas after January 5, 2001 through March of 2001. (Staff Reply Brief at 55). Since third-parties had withdrawn their gas from Manlove as of January 5, 2001, PGL used the gas it stored for its ratepaying customers, and those of North Shore, to satisfy its third-party customers’ demands. (Id. at 57-58). PGA customers suffered increased costs as a result.

Also, since PGL loaned gas to third-parties, Staff asserts that there was less volume in Manlove Field. A certain volume is necessary in order to keep the pressure at peak deliverability. (Staff Ex. 3.00 at 59). PGL bought gas for storage in Manlove to maintain sufficient pressure to keep Manlove at peak deliverability. The price of this new gas was borne by consumers instead of the third-parties. (Id. at 58; Staff Ex. 7.00 at 46). Staff contends that PGL acted imprudently when loaning gas stored for winter use by consumers to third-parties, rather than using it for ratepaying consumers. (Id. at 58).

Staff argues that when PGL made these withdrawals at the expense of consumers and replaced that gas, it did so in a manner that conferred benefit on its parent, PEC. PGL’s major suppliers for spot gas were Enron NA and Enron MW. Staff avers that the partnership between PEC and Enron was established to earn profits for both partners, thus, Hub services with third-party customers allowed PEC to enjoy those profits. (Staff Init. Brief at 58-59).

Staff opines that PGL acted imprudently by not interrupting these third-party transactions, as PGL’s failure to interrupt them left PGL with far less capacity to deliver the inexpensive summer gas that was purchased for consumers. (Staff Ex. 3.00 at 47). Staff acknowledges that there could be instances where the amount of money paid by a third party could overcome the added costs incurred by contracting for non-interruptible services. That was not the case here, however. PGL did not use the revenues from third-party services to offset consumer gas costs. Therefore, Staff concludes that consumers received no benefit from these transactions, instead consumers were harmed.

Staff posits that PGL limited its withdrawals from Manlove during a time when consumers needed it most---in December of 2000. Staff avers that if PGL personnel really intended to meet PGL’s articulated goal of maintaining peak delivery from Manlove until late January of 2001, PGL personnel would have interrupted service to its third-party consumers. (Staff Reply Brief at 41; Staff Ex. 7.00 at 50).

01-0707

Staff states, essentially, that PGL ignores the record when relying on Mr. Wear’s statement that the amount of Manlove Field storage capacity used for consumers was established independently from its decisions to store gas for third-party services. Staff points to the evidence provided by Dr. Rearden, which Staff contends, established that PGL put third-party customers’ needs before those of consumers. (Staff Reply Brief at 42-43).

Staff disagrees with PGL’s assertion that displacing storage services for withdrawing additional gas from Manlove is not feasible. Staff points out that it has never asserted that PGL’s use of its leased storage was improper. Therefore, PGL’s argument on this issue is irrelevant. (Staff Init. Brief at 49).

Also, Staff states that while it may be true, for planning purposes that storage services are not substitutable, in operational terms, this is less true. According to Staff, when planning, PGL cannot consider all storage as the same, but in operations, PGL can alter the use of leased storage in conjunction with Manlove Field. Since PGL used displacement to perform third-party services, leased storage and storage at Manlove had an impact on each other. (Staff Reply Brief at 44; Staff Ex. 2.-00 at 31-41). Staff posits that PGL proffered no evidence of specific instances in which these operational factors occurred and to what extent they occurred during the reconciliation period. (Staff Reply Brief at 45-46). Also, according to PGL’s Initial Brief, PGL had no-notice services, which enabled PGL to withdraw or inject gas with little or no “lead time.” According to PGL, the no-notice services allowed it to serve load variations quickly, when unforeseen circumstances occurred. Staff concludes that PGL’s Brief establishes that it had service options with which it could have accommodated third-party obligations instead of allowing third parties to withdraw gas from Manlove allocated for PGA customer use. (Staff Reply Brief at 47, citing PGL Initial Brief at 67).

Staff takes issue with PGL’s assertion that Staff’s use of the LIFO rate required PGL to have knowledge of information (PGL’s annual LIFO rate) that was not available to PGL personnel at the time the withdrawals from Manlove took place. Staff argues that it used LIFO to calculate the harm done to consumers as a result of PGL’s imprudent actions; Staff did not determine that PGL should use LIFO on a daily basis. (Staff Reply Brief at 50-51; 53-54).

Staff finds PGL’s contention that it made almost no “incremental” purchases beyond baseload purchases to be misleading, citing PGL’s Initial Brief at 68-69. Staff points out that PGL purchased additional gas for PGA customers due to its third-party transactions. According to Staff, it does not matter whether those purchases are baseload purchases or other purchases. (Staff Reply Brief at 55).

On Exceptions, Staff argues that in fact, PGL personnel should have been able to determine the cost of gas from one transaction relative to another at any given time. This is true, Staff continues, because the Public Utilities Act requires PGL to manage its gas costs in a manner that allows PGL to prove the prudence of transactions affecting the PGA. In support, Staff cites 220 ILCS 5/9-220. Staff points out that PGL’s alternative to Dr. Rearden’s determination as to the cost of replacement gas is based on the LIFO value of gas. The LIFO value, however, overstates the value of gas and therefore it understates the adverse impact of the third-party transactions. (PGL Reply Brief on Exceptions at 10-11).

01-0707

2. PGL’s Position

Without any record citation, PGL argues that it did nothing wrong in failing to use gas stored at Manlove “in excess of the 25.5 Bcf of gas it bought and injected in Manlove.” PGL claims that if it had not used this gas for third-parties, it would have been in breach of contractual commitments and/or violating unspecified laws by “stealing gas that belonged to third parties.” (PGL Init. Brief at 68). PGL further maintains that none of its customers have a right to demand services from Manlove Field or any other specific resource. It points out that during its withdrawal period within the reconciliation period, Manlove never had a negative balance. Also, PGL avers that its accounting regarding what customer gets what gas has no operational relevance. (Id. at 70). According to Mr. Wear, consumers should not have “unfettered use” of a storage field. (PGL Ex. H at 30).

PGL admits that it bought gas to replace that which it loaned to third-parties. It argues that it did not purchase as much replacement gas as Staff states. And, the loaned gas was replaced by third parties. PGL asserts that while Staff’s proposed disallowance is based on 4,914,182 Dth of “loan activity,” at most PGL only bought 352,342 Dth of replacement gas. PGL claims that no one was harmed by these purchases. (PGL Init. Brief at 70-71; PGL Ex. 14, 15).

Citing Mr. Wear’s testimony, PGL argues that no damage was done to consumers due to third-party transactions because, even if PGL did not engage in such transactions, the same amount of storage at Manlove would have been used for consumers. No additional volume of gas would have been in PGL’s storage inventory for consumer use. Mr. Wear stated, in essence, that injecting more gas into Manlove would have been financially unwise because then PGL would not have been purchasing gas at FOM prices, which is less expensive than gas purchased on the daily market. (PGL Init. Brief at 65; PGL Ex. F at 38-39).

PGL asserts that Staff and the GCI failed to consider the purpose of its purchased storage. PGL does not state that it used purchased storage for consumer use; instead, it states that total withdrawals from purchased storage for the five winter months (November through March) were greater than those it made in the previous year. (PGL Reply Brief at 43).

PGL argues that displacing purchased storage service with additional gas from Manlove Field is not possible because only a marginal amount of “tweaking” can be done between these two types of storage. Its services from Natural Gas Pipeline are used to correct weather forecast errors. Also, PGL has firm storage from ANR Pipeline for swing loads in the fringe months of October, November, March and April, when Manlove is not available for withdrawals. PGL acknowledges that it had no-notice services from ANR, but, it contends that Manlove does not have a no-notice feature to it. Citing Mr. Wear’s testimony, PGL concludes that, in addition to the difficulty in cycling additional Manlove inventories during warmer than normal conditions and its effect on baseload purchases, PGL must maintain diversity for operational and reliability concerns. (PGL Init. Brief at 67-68).

01-0707

PGL maintains that providing service to third-parties has also produced operational benefits for Manlove Field, as less gas becomes trapped and the field decline point is extended when more gas is stored at Manlove. PGL avers that increasing the amount of gas injected into Manlove Field by eight Bcf extended the decline point (from approximately 18 Bcf to approximately 27 Bcf), resulting in an increase of one Bcf of cumulative withdrawal. (PGL Initial Brief at 71).

Citing no portion of the record, PGL states that it did not need to use Manlove Field for consumers in December of 2000 because purchased gas nominations could not be changed. PGL also contends that it did not use more of the gas stored in Manlove for consumers in January and February of 2001 because it did not need to do so. PGL points out that January and February are the coldest months of the year in Chicago. Usually, there are about nine days in January and February in Chicago where the temperature is below 10 degrees Fahrenheit. In January and February of 2001, however, there was only one day in which the weather dipped below 10 degrees Fahrenheit. PGL personnel could not know in advance that the storage would not be needed for anticipated cold days. (PGL Init. Brief at 77-79).

PGL avers that Dr. Rearden’s calculations as to the harm from its withdrawals for third-party use are improper because he used NYMEX futures prices to determine the price of gas at certain times. NYMEX data for January through March of 2001 would not establish that prices during that time would be lower than December 2000 prices. And, according to PGL, NYMEX futures prices are a very poor indicator as to the actual price. (PGL Init. Brief at 80-81).

PGL further argues that Dr. Rearden’s calculations as to the harm caused by its use of PGA gas for third-party use is improper because Dr. Rearden based his calculations on PGL’s LIFO price. PGL’s LIFO price, however, is unknown until the end of its fiscal year. PGL contends that therefore, it could not be used to make daily withdrawal decisions. (PGL Init. Brief at 81). Also, Staff’s recommended disallowance did not take PGL’s operational considerations, like peak day protection, its balancing needs and the possibility that summer prices could exceed winter prices, into account. PGL concludes that it must be flexible and use storage to accommodate discrepancies between planned and actual conditions. (Id. at 81-82).

PGL agrees with Mr. Anderson that it used displacement to accomplish the third-party transactions. PGL maintains that it cannot color-code the molecules of gas it injects into Manlove. There is no guarantee that the same gas that was injected for a particular purpose, such as for consumers, will be withdrawn for that purpose. And, gas is a fungible commodity; it really does not matter what gas a person or entity receives. PGL concludes that it impossible, from an operational perspective, to state that a transaction did or did not have any recoverable gas costs associated with it. (Id.).

PGL further asserts that Commission Staff should not be allowed to contest its use of Manlove Field because Commission Staff participated in PGL’s FERC proceeding in which PGL was certificated by the FERC to provide such services. (PGL Reply Brief at 49).

01-0707

In its Brief on Exceptions, PGL contends that Dr. Rearden’s calculation of damages with regard to the purchases of replacement gas is too high because Dr. Rearden used the actual, but highest, withdrawals from Manlove Field, minus the LIFO price, to determine the avoided costs, or how much consumers were harmed. PGL reasons that CUB Witness Mr. Mierzwa’s estimated analysis is more accurate. However, according to PGL, given that both Staff and the GCI based their disallowances on factors that improperly exaggerate their calculations, an unspecified adjustment is necessary to reduce the disallowance to $12,960,090.50. PGL asserts that when making a determination as to the harm resulting from replacement gas purchases, Dr. Rearden improperly assumed that PGL could know what purchases had the highest price. (PGL BOE at 17-18).

3. GCI’s Position

GCI witness Mr. Mierzwa testified that PGL used 12 Dths of gas to support third-party transactions conducted during the winter of 2000-2001. He recommended a disallowance of $51.2 million due to PGL’s imprudent use of Manlove Field. (CUB Ex. 2.00 at 7). The GCI argue that the actual amount of gas withdrawn from Manlove was 12 Dth of gas. This is the amount of gas that PGL could have used for consumers, but did not, resulting in PGL personnel having to purchase gas at prices more than double the average cost of the gas in storage. (GCI Init. Brief at 57-58).

The GCI contend that gas stored in Manlove and the costs of operating and maintaining Manlove are encompassed by the PGA. They argue that therefore, those facilities should be used first for consumers, or exclusively for consumers. The GCI concede that there is nothing wrong with using storage facilities to generate revenues from third-party transactions. Rather, the GCI maintain, PGL was unreasonable in engaging in such activities in a manner that increased consumer costs. (GCI Init. Brief at 56-57).

The GCI take issue with PGL’s assertion that it could not have used more than 25.5 Bcf of gas for consumers during the time period in question. The GCI point to Mr. Mierzwa’s testimony that PGL could have used its computerized gas planning model to determine how much stored gas should be used for system supply, rather than giving third-party transactions priority over consumers. In fact, PGL did not even prepare a gas supply plan for the winter of 2000 through 2001 regarding warmer than normal weather conditions. Since PGL planned to make no daily-priced purchases if the winter of 2000 through 2001 was normal (not colder or warmer than normal), the GCI maintain that under warmer than normal conditions, it would be unlikely that PGL would purchase significant amounts of gas at the daily price. (GCI Reply Brief at 45-48).

The GCI additionally point out that while PGL argues that adding more gas to Manlove Field extended Manlove’s decline point, which increased the amount of gas that could be stored at Manlove, PGL witness Mr. Puracchio was unable to identify any economic benefit to consumers associated with the extension of Manlove’s decline point. (GCI Init. Brief. at 53; Tr. 681-82).

01-0707

The GCI further posit that PGL entered into the third-party transactions in the summer of 2000, at the same time when it would also be planning to store enough gas to serve customers under extreme winter conditions. The GCI conclude that because PGL failed to maintain sufficient flexibility to meet consumer needs in the winter of 2000 through 2001, PGL cannot now complain that it could not meet those needs due to contracts that PGL imprudently entered into. (Id. at 48).

4. Commission Analysis and Conclusions

The PUA requires PGL to do what is reasonable and necessary to prudently incur gas costs. (220 ILCS 5/9-220). PGL failed to provide evidence establishing that its withdrawal practices from Manlove Field during the winter of the reconciliation period complied with the prudence requirement in the PUA. Not only did PGL fail to meet its burden of proof with respect to its withdrawal practices, but other parties provided ample evidence showing PGL acted imprudently.

As an initial matter, what the Commission finds particularly appalling is PGL’s third party transactions with Enron that increased consumers PGA costs without giving consumers the benefits of any profits gained from these transactions. As discussed elsewhere in this order, the Commission can think of no other explanation for the creation of the corporate consanguinity here than to divert revenues from PGL to an unregulated entity. Parties to Manlove Jumpstart and 38 Special clearly intended to use PGL’s PGA assets for the unregulated entities’ shareholder gain, to the detriment of consumers. This lends considerable support to the Commission’s finding that many of PGL’s third party transactions involving gas stored at Manlove were imprudent.

PGL contends that stored gas cannot be labeled for a particular customer’s use. From a purely operational perspective, this is true. However, proper accounting should allow PGL to track gas stored in Manlove for PGA customer use and gas stored for third party use. The record demonstrates that PGL knew of at least three accounting options for managing third party withdrawals from Manlove Field. PGL could have used the lower-priced summer gas for third-parties and allowed consumers to benefit from the profits from those transactions. It also could have used the lower-priced summer gas for consumer benefit and charged third-parties for the cost of higher-priced winter gas. The third of PGL’s options, charging consumers for higher-priced gas and loaning the less expensive summer gas to third parties, with none of the profits benefiting consumers, is what PGL chose to do. This flies in the face of the requirement that PGL offset any costs of using PGA assets with any profits gleaned from such transactions.

Further, PGL’s contention that no customer has the right to use Manlove overlooks the evidence, which concerns what gas was used for third-parties and for consumers, in terms of the accounting treatment it received. No party has asserted that any customer of PGL, consumer or otherwise, has a right to use a particular facility. Rather, various parties in this proceeding have consistently maintained that PGL had a duty, conferred upon it by Section 9-220 of the PUA, not to engage in transactions in a manner that increase consumer gas costs.

It is noteworthy that PGL contends that its use of storage provides a “hedge” for consumers. Yet, as Staff established, during the winter of 2000-2001, Manlove Field was not providing much of a “hedge” for consumers.

01-0707

PGL’s factually unsupported conclusion that it should not be required to “use gas in excess of the 25.5 Bcf it bought and injected into Manlove” to provide consumers with gas lacks validity for many reasons. (See, PGL Init. Brief at 68). This conclusion of fact is asserted with no factual basis cited. 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)). Additionally, PGL’s conclusion is erroneous. During much of the time when PGL was withdrawing gas for third-parties from Manlove, its inventory for third-party gas was at a negative balance. Consumers did not even have full access to the 25.5 Bcf of gas allocated for their use.

PGL claims its third-party services were not interruptible without providing any evidence to support this assertion. In fact, the record demonstrates PGL could interrupt third party services. The Commission finds it difficult to believe that PGL could not have interrupted its third-party contractual obligations to honor its obligations to consumers, had it so chosen. PGL’s decisions to position third-party requests before the needs of consumers placed PGL in the undesirable position of being required to buy large quantities of replacement gas at higher prices. In turn, PGL passed these imprudently incurred costs on to PGA customers.

Further, PGL’s assertion that not using stored gas third-party contractual commitments and unspecified laws would be “stealing” that gas from third-parties contradicts Mr. Wear’s testimony that third-party services could be interrupted. (Tr. 929-35). It also contradicts PGL’s statement on page 25 of its Initial Brief that its park and loan services were interruptible. (PGL Init. Brief at 25). PGL cannot have it both ways. It would seem to the Commission that prudent storage management would not place the needs of third parties above the needs of PGA customers. This PGL did not do.

Mr. Wear’s testimony that PGL could not have used its purchased storage to accomplish third-party transactions does not aid PGL. The propriety of PGL’s use of its purchased storage has never been an issue. Therefore, this testimony is irrelevant. Even if this testimony was relevant, it is vague. Mr. Wear cites no examples as to why PGL had no alternatives to use of Manlove for third-parties, or even why PGL decision-makers entered into third- party storage contracts knowing that use of Manlove Field was its only option. Staff offered evidence to sufficiently contradict Mr. Wear’s testimony on this issue. As Staff points out, the existence of no-notice contracts is some indicia that PGL had alternatives to use of Manlove Field.

PGL believes the Commission should compare PGL’s storage withdrawals during the reconciliation period to PGL’s withdrawals during the previous winter. This does not aid PGL because there is no evidence here as to the circumstances in the winter of 1999-2000. For example, PGL could have been using Manlove in the previous year for third-party storage in the same manner in which it did here. There is no evidence here establishing what was done in the previous year. Certainly, there is evidence here establishing that the GPAA was in effect during the previous year, but beyond that, there is no evidence establishing what occurred during the winter of 1999 through 2000.

01-0707

PGL’s argument that it used baseload gas, instead of swing gas, to replace the stored summer gas misses the point. The issue here is not where the replacement gas came from. Rather it is what consumers were required to pay as a result of PGL’s decision to use its consumer“hedge” for third-parties. PGL’s Exs. 14 and 15 indicate that great amounts of gas stored for consumer use were withdrawn from Manlove and used for third-parties. PGL Ex. 15 compares its swing purchases in the month of March to the value of the loan paybacks that occurred in that month. However, it does not mention the value of the gas when it was loaned to third-parties. (See, PGL Exs. 14, 15). These Exhibits do not establish that that PGL acted prudently.

PGL’s contention that the loaned gas was paid back, therefore no harm was done, is also without merit. Dr. Rearden calculated the value of gas bought, less the value of the gas returned by third-parties. (See, e.g., Staff Init. Brief at 57). Because third-party gas was not returned until March through September of 2001, that gas was not available to consumers during the winter, meaning PGL had to purchase any supply shortfalls elsewhere, typically at increased costs. And, the gas was worth less when it was paid back by third-parties.

Mr. Puracchio, who is PGL’s Gas Storage Manager, testified that injecting more gas into Manlove makes it more useful because this use extends the decline point of Manlove, which is the point, at which, a given daily withdrawal rate can no longer be met. (PGL Ex. M at 8). The problem with this assertion is that there is no credible evidence in this record that the additional gas injected could not have been used to confer a benefit on ratepaying consumers, either directly or indirectly, by passing the profits on from third-party use of Manlove to consumers. At a minimum, PGL should have managed the extra storage space at Manlove in a way that did not increase the costs passed on to consumers. The record shows that PGL’s management of Manlove withdrawals increased consumers costs either indirectly, through increased costs caused by but not borne by third-parties and directly, through PGL’s practice of “dipping into” the gas purchased for consumers and using that gas for third-parties, requiring PGL to purchase more expense replacement gas. This only leads to a conclusion of imprudence.

PGL’s assertion that it did not use Manlove in December as much as has been forecast is factually unsupported. We need not consider it. (Fraley v. City of Elgin, 251 Ill. App. 3d 72, 76, 621 N.E.2d 276 (2^nd Dist. 1993); In re Marriage of Thornquist, 79 Ill. App. 3d 791, 798, 399 N.E.2d 176 (1^st Dist. 1979)).

PGL’s assertion that it did not need to use the gas stored in Manlove Field because the weather was warm in the winter of 2001 is equally without merit. PGL, the party that had the burden of proof, could have provided evidence establishing the weather conditions in January and February of 2001. It did not. Merely stating that there was only one day in that two-month period in which the weather dipped below 10 degrees Fahrenheit does not establish that the weather was not cold during this period. PGL provided no evidence as to what the weather was like or how the weather affected consumer demand. Furthermore, the Commission finds it difficult to follow PGL’s logic here when it actually started withdrawals from Manlove earlier than planned due to colder than normal weather in December 2000. PGL has not established that it did not need to use gas stored in Manlove Field during January and February 2001 because of warmer than usual weather conditions.

01-0707

PGL’s contention that NYMEX futures prices are not the same as actual prices also ignores the fact that it had the burden of proof. PGL could have presented evidence establishing what it determined was the actual relevant prices to be. It did not. The only evidence as to what gas was worth at the pertinent times on this issue was Dr. Rearden’s assessment of NYMEX futures prices. Dr. Rearden did not proffer NYMEX futures prices to suggest that PGL should have purchased futures in December, which is what PGL suggests in its argument. Rather, he proffered those prices to determine the value of gas on the open market.

Mr. Wear’s testimony that the additional working capacity would not have been deemed to be useful for use by ratepaying consumers is also not credible. Mr. Wear stated that, to place more gas in Manlove would be financially unwise because PGL would then be using stored gas, in part, instead of purchasing baseload gas. This, he averred, is bad because baseload gas was the less expensive FOM Gas, as opposed to gas purchases on the daily market. (PGL Ex. F at 38-39). There is nothing in this record, however, indicating that using gas already in storage would be more expensive than buying FOM gas. While it is true that FOM gas is generally less expensive than gas purchased on a daily market, there is no evidence that using more of Manlove’s storage for consumers would raise the cost of gas passed on to consumers. And, as the GCI point out, under warmer than normal conditions, it is unlikely that PGL would need to purchase much gas at a daily price. Mr. Wear again misstated facts, casting further doubts as to his credibility.

Record evidence indicates that PGL loaned gas to third-parties that was originally purchased to meet some of consumers’ supply needs during the winter months. Commission regulations bar a utility from engaging in any transaction that raises the costs that are passed on to consumers. These regulations provide that utilities “shall refrain from entering into any such transaction” that would raise such charges. (83 Ill. Adm. Code 525.40(d)). (emphasis added). Were the Commission to accept PGL’s position, we would only encourage utilities to use assets meant for consumers as a means to cull corporate profit that is not passed on to consumers. We would also be encouraging utilities not to actively participate in gas price reduction on behalf of consumers. This scenario was not the intent of this Commission when it promulgated Section 525.40. (Ill. Commerce Comm., on its own Motion: Revision of 83 Ill. Adm. Code 525, 1995 Ill. PUC Lexis 592 at *17). Section 525.40(d) was meant to deter utilities from subsidizing off-system transactions with assets used for consumers and thus subject to a PGA. This is not to suggest that the Commission disapproves of all third-party transactions on the part of utilities. Rather, when third-party transactions involve use of PGA assets, use of those assets, especially gas supply, must be prudent.

The Commission finds PGL acted imprudently with regard to many aspects of its operation of Manlove Field. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as discussed in.

01-0707

VI. Unaccounted for Gas- “GLU”

A. Findings of Fact

According to Staff witness Mr. Anderson, Unaccounted-for Gas (“GLU”) is defined as the difference between gas available from all sources and gas sales accounted for by the utility as sales, net interchange and company use. This difference, or “lost” gas can occur in a variety of ways, such as leakage, theft, meter inaccuracies, or temperature or pressure changes. (Staff Ex. 2.00 at 50). GLU is an accounting term for gas that has become lost or is otherwise unaccounted for. It is the difference between the amount of gas sent out and that which has been sold. (Tr. 702). GLU is recovered by PGL in its PGA. (Staff Ex. 2.00 at 50).

Evidence adduced during the hearings shows PGL’s GLU levels for several years. In fiscal year 1998, PGL reported GLU at 1.10 %. (Tr. 714). In fiscal 1999, it was 1.09%. In fiscal 2000, it was at 0.84 %. In 2002, PGL’s GLU was 2.89%. (Id.). However, during the reconciliation period, PGL’s GLU level was approximately 3.76%, which is an increase from the previous year of almost 400%. (Tr. 699). Management at PGL was aware that its GLU increased dramatically during the time period in question. (Tr. 694).

PGL witness Mr. Zack concluded that the level of GLU recorded during the reconciliation period was not excessive. Also, he did not believe that increasing GLU from 1999 to 2002 represented a trend. Mr. Zack testified that it is not uncommon for GLU to be 6.0%. He bases his conclusions on his experience with GLU, not his experience at PGL. Mr. Zack is in charge of gas supply planning, gas supply administration, gas control and gas storage for both PGL and North Shore. (Tr. 735). Mr. Zack was not in PGL’s gas supply administration department during the reconciliation period. (Tr. 736).

City-CUB witness Ms. Decker testified that during the reconciliation period, PGL consumers paid for a significantly larger amount of gas than was actually delivered during the reconciliation period. (City-CUB Ex. 1.0 at 28; 2.0 at 25). Because PGL personnel did not correct this increase in GLU, she opined that PGL was imprudent. (Id. at 33-34). While GLU may be a relatively low in terms of a percentage, here, it represents a very large amount of gas. (Id. at 41). Ms. Decker pointed out that PGL initiated an investigation to determine why GLU increased so much. (City-CUB Ex. 1.0 at 34-35).

Ms. Decker averred that gas shippers acknowledge that a small percentage of gas in their pipeline, or “throughput,” is taken or consumed along the way to run compressors as the gas travels through shipping pipelines and storage devices. (City-CUB Ex. 1.0 at 29). She also stated that a significant amount of PGL’s total gas is customer-owned gas. Ms Decker recommended a disallowance in the amount of $38,102,680, which represents excess costs PGL recovered from consumers. (Id. at 34).

01-0707

B. Conclusions of Law

1. Staff’s Position

Staff took no position on the issue of excess GLU. As has been previously discussed herein, Staff recommended a disallowance in the amount of $4,628,267, which represents the amount of maintenance gas that was improperly accounted for as GLU and recovered through the PGA. PGL does not contest Staff’s proposed disallowance. (See, e.g., PGL Init. Brief at 104).

2. GCI’s Position

City-CUB witness Ms. Decker testified that during the reconciliation period, PGL consumers paid for a significantly larger amount of gas than was actually delivered during that period. (City-CUB Ex. 2.0 at 25). During the time period in question, PGL’s GLU increased by approximately 400%. (Id. at 33-34). According to GCI, PGL executives were alarmed at the GLU levels. The GCI argue that PGL personnel did not attempt to correct this problem, therefore, PGL was imprudent. (Id. at 33-34; GCI Initial Brief at 74-77). Ms. Decker opined that the Commission should disallow $38,102,680, which represents excess costs PGL recovered from consumers due to PGL’s excessive GLU. (Id. at 34). The GCI assert that this unexplained increase in GLU, which resulted in increased costs to consumers, was imprudent. (See, e.g., GCI Initial Brief at 14, 74-76).

Furthermore, PGL’s claim that its GLU was within the range of PGL’s Illinois peers is hindsight, as this could not have been known at the time in question. The GCI conclude that therefore, consideration of other Illinois gas companies’ GLU is not permitted. (GCI Reply Brief at 78).

4. PGL’s Position

PGL argues that Ms. Decker’s benchmark of 1% GLU was based solely on PGL’s GLU from two prior years. This, PGL contends, is an arbitrary benchmark. Also, Ms. Decker did not include maintenance gas in her total figure when determining the percentage of GLU. If she had done this, GLU would have been reduced from 3.76% to 3.44%. (Id. at 91). PGL presented statistics as to its Illinois peers as to their GLU during the time period in question. Based on these statistics, PGL concludes that the amount of its GLU was not imprudent. (PGL Init. Brief at 90).

01-0707

On Exceptions, PGL maintains that GLU rises and falls by its very nature. It concluded that given the fluctuating nature of GLU, a comparison of multiple-year averages is a better indicator of PGL’s performance, as opposed to a single year. (PGL Reply BOE at 6-7). According to PGL, what appears to be a large increase in GLU in terms of percentage, can be quite large in actual quantity, even when the percentage changes from one small percentage to another small percentage. (Id. at 7).

5. Commission Analysis and Conclusions

The Commission agrees with the GCI that PGL should have exercised more care with respect to GLU. We also agree with the GCI that evidence of the GLU levels of PGL’s peers during the time period in question could not have been known to PGL personnel at that time. It is, therefore, impermissible hindsight and we will not consider it.

The Commission cannot state, based on this record, that PGL’s conduct rose to the level of imprudence. PGL personnel did note that there was a problem. However, there is simply no evidence that, if PGL personnel had undertaken any course of action, its GLU would have been reduced. We also note that Ms. Decker did not take into account that maintenance gas, which, when properly recorded, will increase the total amount of gas, and reduces her GLU percentage, albeit slightly.

The evidence established that GLU can occur in a variety of ways, such as meter inaccuracies, leakage, or temperature changes. (See, e.g., Staff Ex. 2.00 at 50). The source of the problem can be difficult to detect. There is no evidence that PGL personnel knew or should have known what was causing a sharp increase in its GLU during the time period in question. Ms. Decker’s testimony on GLU speaks to what is acceptable for pipelines, not LDCs. (See, City-CUB Ex. 1.0 at 29). There is no evidence that LDCs like PGL would have the same factual considerations as those of pipelines. Finally, we agree with PGL that a benchmark based on two previous years is not reasonable, as, generally, benchmarks are based on a wider time-frame in order to ensure that anomalies do not occur. Therefore, the Commission declines to accept the GCI’s recommended disallowance on this issue.

The GCI’s point is well-taken regarding Ms. Decker’s testimony as to how PGL corrected its level of GLU. The PGL investigation she referred to did not occur in the reconciliation period. However, there is no evidence that in this proceeding if PGL personnel had undertaken an investigation in the reconciliation period, they would have been able to determine the cause of the GLU and correct the problem.

Finally, the GCI blame PGL for the fact that Ms. Decker’s benchmark for GLU was only two years in duration, as the GCI assert that this was all the information that PGL gave them in discovery. However, the remedy for an incomplete discovery response is another discovery request or a motion to compel. We note that there is no indicia that this situation is like the one regarding enovate’s activities, where the evidence was allegedly with Enron and PGL claimed that therefore, it did not have that evidence.

01-0707

VII. Off-System Transactions in General

A. Findings of Fact

According to PGL, off-system transactions (i.e., sales for resale) are a routine part of the management of its system. PGL used Manlove Field and Mahomet Pipeline to provide third-party services. (See, e.g., Staff Ex. 3.00 at 45). PGL also used leased storage and PGA gas to provide third-party services. PGL did not offset PGA costs passed on to consumers with profits earned from these. (Id.).

Mr. Wear averred that all off-system transactions must accomplish one or more of the following criteria: a.) provide a positive commodity or demand credit; b.) meet operational needs; or c.) test the logistics or feasibility of future transactions that would meet operational needs or provide demand/commodity credits. (PGL Ex. C at 29). According to Mr. Wear, off-system transactions can reduce the gas costs PGL passed on to consumers in its PGA. When an off-system transaction uses an asset, the costs of which PGL recovers through its PGA, the revenues from that transaction flow through that PGA gas charge as well. Mr. Wear acknowledged that the reason such revenues offset gas charges is that the law requires PGL to use those revenues to offset the gas charges PGL passes on to consumers in its PGA. (PGL Ex. C at 30). PGL classified its system transactions in two categories, Hub and PGA. Mr. Wear testified that the third-party transactions that used only base rate assets were considered to be Hub transactions. Those transactions that used gas charge assets were considered to be PGA transactions. (Tr. 993).

GCI witness Mr. Mierzwa testified as to how a gas utility should determine how much storage should be used to serve its load. He opined that a major gas utility such as PGL should have utilized its Gas Dispatch Model to determine how much gas storage should be used for system supply. However, PGL personnel chose not to use the model during the winter of 2000/2001. (CUB Ex. 4.0, at 25-28). Mr. Mierzwa also testified that, based on the gas supply plan prepared by PGL, an additional 12 Bcf of storage could have been used. PGL could have reduced the amount of baseload purchases it made during warmer than normal weather by merely reducing baseload purchases up to 13.5 Bcf during the months of December, 2000 through February of 2001. (Id.). Mr. Mierzwa proposed a disallowance for PGL’s storage and exchange activities that do not involve loans of gas in the amount of $27.1 million. He used the average cost of gas that was used to displace higher gas costs. In Mr. Mierzwa’s opinion, the amount of gas used for third-parties was actually 12 Bcf of gas. (Id. at 10). Mr. Mierzwa further opined that Staff’s use of PGL’s LIFO rate understated the adverse impact on sales customers of the PGL storage and exchange activities. Under PGL’s LIFO rate, storage injections and withdrawals are based on the average cost of gas for the fiscal year. Gas injected by third-parties in the summer of 2000 would not have been included in the LIFO rate. (Id. at 12-15).

100

01-0707

B. Conclusions of Law

1. Staff’s Position

Staff’s total proposed cost disallowance for off-system loans of gas, or what Staff has referred to as non-tariff services, is $6,628,631. Staff’s recommended disallowance contains two components: $4,378,466 for revenues from PGL’s FERC operations and $2,250,165 for its storage exchange transactions. Staff argues that the revenues from PGL’s off-system transactions should be included in PGL’s PGA, as opposed to its base rates. Including these revenues in PGL’s PGA would offset the gas costs that are borne directly by consumers through the PGA. Staff contends that to accomplish the off-system transactions, PGL used all of its assets, including gas, leased storage and the Mahomet Pipeline and Manlove Storage Field. Pursuant to this Commission’s PGA regulations, the costs associated with these items, (i.e., leased storage and flowing gas) as well as the profits therefrom, should be passed on to consumers through PGL’s PGA. (See, e.g., Staff Ex. 12.00 at 31; Staff Init. Brief at 63-64).

PGL’s use of the term “above the line” in its Initial Brief is incorrect, according to Staff; it refers to an incomparable situation to the one here-revenues and expenses that are included in a utility’s operating income for purposes of determining rates. Staff argues that an expense recorded “above the line” can be flowed through a PGA. (Staff Reply Brief at 63).

Staff contends that if the Commission were to allow PGL to recover the profits from use of these assets in base rates, the Commission would provide PGL with the incentive to unnecessarily increase the cost of gas passed on to consumers. Indeed, according to Staff, here, PGL did raise gas costs borne directly by consumers in order to support its off-system transactions. (See, e. g., Staff Ex. 3.00 at 5).

Staff argues that any third-party transaction used at least three assets, Mahomet Pipeline, Manlove Field and displaced gas. Staff points out that displaced gas is a recoverable gas cost, citing 83 Ill. Adm. Code 525.40(a)(1). Staff contends that Section 525.40 of the Commission’s rules does not address whether an asset is recorded through base rates. Rather, this Rule speaks to whether any associated cost necessary to complete a transaction is a recoverable cost, as is defined in Section 525.40(a). (Staff Reply Brief at 58).

Staff maintains that PGL is required by law to refrain from actions that raise gas costs. When, as is the case here, non-tariff services alter the delivery of gas to ratepayers from least cost values, these non-tariff services raise the amount of gas costs passed on to consumers. Also, when PGL does not use the profits gleaned from third-party loans to offset gas costs borne by consumers, it does not have the incentive to limit non-tariff services in a manner that considers the needs of consumers. (Staff Ex. 10.00 at 9).

101

01-0707

Staff contends that use of displaced gas allowed PGL to enter into transactions that used facilities without the physical delivery of the same molecules of gas. Thus, displaced gas molecules injected into PGL’s system substituted for gas molecules that are presently in PGL’s system. (Staff Initial Brief at 65-66). Citing PGL’s Section 525.40 Brief at 12, Staff posits that PGL admitted that the transfer of gas may occur at different points in time and at different locations. And, under PGL’s FERC operating statement, PGL entered into transactions that first required it to loan gas to third-parties, which was repaid in-kind at a later date. Staff contends that it was impossible for PGL to accomplish such a transaction without using displacement of gas in its system. Because the cost of natural gas is defined as a recoverable gas cost by Section 525.40(a)(1) of the Commission rules, Staff avers that PGL is required by Section 525.40(d) to include the revenues from use of that gas in its determination of what costs are recoverable here. (Staff Init. Brief at 66-67).

2. PGL’s Position

PGL disagrees with Staff and the GCI that the revenues in question are derived from transactions that are subject to gas charges. This is true, PGL continues, because the costs involved for all of the assets involved in these transactions, such as PGL’s transmission pipelines and Manlove Field, are included in PGL’s base rates, not passed through its gas charge. (PGL Init. Brief at 72-73). Mr. Wear stated that “none of the costs supporting PGL’s Hub transactions are recovered through the gas charge.” (PGL Ex. C at 33).

PGL contends that the expenses it incurs in connection with Manlove Field and the Mahomet Pipeline are included in its base rates. It reasons that therefore, the profits from use of those assets should be in base rates, not passed on directly to consumers in its PGA to offset the cost of gas. PGL also asserts that because its Hub services are available only because of base rate assets that it owns, Section 525.40(d) does not require PGL to flow the revenues from these transactions through its PGA. (PGL BOE at 23).

PGL also argues that this Commission has consistently ruled that third-party revenues are not to be included in PGAs, citing 83 Ill. Adm. Code 525.40(d). (PGL Reply Brief at 72-73). PGL points to Northern Ill. Gas Co., Application for an Order Approving its Accounting Treatment Related to Certain Market Area Hub Activities, 1996 Ill. PUC lexis 151, *11), and contends that the Commission allegedly required Nicor to account for its revenues by including them in its next rate case. (Id. at 74-75). Also, in Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 956, and Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 201, the Commission again found Nicor’s above-the-line treatment of its third-party revenues to be acceptable. (PGL Init. Brief at 74-75).

PGL further posits that Staff is wrong in asserting that the two Nicor/North Shore pipeline contract dockets were exempt from PGA consideration because they were pursuant to tariffs. These contracts were filed pursuant to Section 7-102 of the PUA. According to PGL, there is no tariff under which Nicor provided service to North Shore. (PGL Reply Brief at 48).

102

01-0707

PGL further maintains that until this Commission issued a final Order in Nicor’s recent rate case, docket 04-0779, this Commission had a longstanding practice of allowing Nicor to account for its Hub revenue through base rates. PGL maintains that fairness dictates that the appropriate forum for deciding the treatment for PGL’s hub revenue is in its next rate case. (PGL BOE at 22).

Also, according to PGL, Staff’s assertion that only system supply gas can be used for third-party transactions elevates form over substance. There are many sources of gas, such as recoverable cushion gas and gas that is supplied to transportation and delivery customers, which do not touch the gas charge. Mr. Anderson knew that PGL had transportation programs, but he could not testify if gas was purchased from PGL or others. (Tr. 871-72). However, 40% of PGL’s annual throughput is gas supplied by third-parties who buy their gas from non-utility sources. Citing Section 525.40 generally, PGL argues that gas in storage affects its gas charge only when it is delivered to end users. Citing Mr. Wear’s testimony, PGL contends that merely because a transaction involves displacement does not mean that PGL has purchased gas for which the costs are recovered through its PGA. (PGL Reply Brief at 45-47).

PGL also cites Mr. Anderson’s testimony and asserts that it is impossible to know if the molecules placed in the system are the same as those later delivered to an entity. Also, according to PGL, third-party services can be supported without using gas charge assets. Interstate pipelines with no merchant functions provide services like park and loan services. PGL points to a service provided by Natural Gas Pipeline, but does not state that it ever contracted for this service. (PGL Reply Brief at 47-48).

3. GCI’s Position

The GCI, also, cite 83 Ill. Adm. Code Section 525.50(d) and contend that revenues from use of PGL’s PGA assets, such as leased pipeline and gas, must offset consumer gas costs through the PGA. The GCI point out that this regulation requires that such revenues must offset PGA gas costs if any of the costs associated with the transaction in question is a “recoverable gas cost,” as is defined in Section 525.40(a). (emphasis added). Because PGL used displacement of gas to accomplish these transactions, PGL could move the gas without incurring the cost of physically transporting gas to the customer, or having that customer arrange for transportation. The costs PGL avoided by using gas injected into storage to serve consumers on the operations of PGL’s system increased the revenues involved. However, consumers paid the entire cost of storage and for pipeline use without receiving any corresponding benefit. (GCI Init. Brief at 51-52).

103

01-0707

The GCI further contend that Northern Ill. Gas Co., Application for an Order Approving its Accounting Treatment Related to Certain Market Area Hub Activities, 1996 Ill. PUC Lexis 151, does not concern Section 525.40. In that docket, this Commission simply rejected Nicor’s contention that third-party revenues should be split between its shareholders and ratepayers and concluded that the ratepayers are entitled to the full amount of such revenues. It was in the context of rejecting Nicor’s proposal to share revenues, whose above-the-line treatment was not challenged, that the Commission determined that revenues should be treated above-the-line. (GCI Reply Brief at 43-44). And, in the two other Commission decisions cited by PGL, Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 956, and Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 201, no party argued that third-party revenues should flow through a PGA. (Id. at 44).

The GCI point out that PGL did not dispute that the transactions in question were accomplished through displacement. The GCI assert that the unrefuted evidence of record establishes that displacement is not possible without use of PGA gas. Also, leased pipeline and leased storage was used in displacement. These costs are recoverable gas costs under Section 525.40(a)(2) and the associated revenues must be used to offset gas charges. (GCI Initial Brief at 42-43).

4. Commission Analysis and Conclusions

PGL’s contention that this Commission has consistently construed Section 525.40 of its rules in a manner that allows revenues from non-PGA assets to be accounted for in base rates is without a basis in fact. None of the cases PGL cites even mention Section 525.40. Moreover, the language in this regulation is unambiguous. This Commission cannot look to extrinsic sources to ascertain the meaning of a law that is unambiguous. (People v. Hari, 355 Ill. App. 3d 449, 456-57, 822 N.E.2d 889 (4^th Dist. 2005)). Finally, as Staff points out, the term “above the line” refers to what is included in a determination of utility operating income when setting base rates, as opposed to what costs utility shareholders bear. This proceeding does not involve setting base rate revenues or determining what costs are recovered through base rates. It is not applicable to the situation here, where the Commission is determining what costs are borne directly by consumers through a PGA.

The cost of system supply gas and any other gas “purchased for injection into the gas stream” is an expense that is passed directly on to consumers through a PGA. (83 Ill. Adm. Code 525.40(a)(1)). The cost of leased pipeline and leased storage is also a PGA expense. (83 Ill. Adm. Code 525.40(a)(2) and (3)). All revenues from any transactions that use these assets must offset the costs imposed on consumers by a PGA, as the regulations further provide that recoverable gas costs “shall be offset by the revenues derived from transactions at rates that are not subject to the Gas Charge(s) if any of the associated costs are recoverable gas costs.” (83 Ill. Adm. Code 525.40(d)). (Emphasis added). Therefore, even when a third-party transaction only uses some PGA assets (in other words, when a third-party transaction only involves one recoverable associated cost), the revenues from those transactions offset the costs imposed by a utility in its PGA. (Id.).

104

01-0707

PGL ignores the issues raised by the parties by contending that it is impossible from an operational standpoint to state that a transaction did not have any recoverable gas costs associated with it. Section 525.40 is an accounting regulation. It does not concern operational matters. And, this regulation requires PGL to offset gas costs with the revenues from a transaction if any of its PGA assets are used for the benefit of third-parties. (83 Ill. Adm. Code 525.40(d)).

As Staff and the GCI point out, the two Nicor cases PGL cites approving transportation contracts, Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 956, and Northern Ill. Gas Co., Petition for Approval of a Firm Transportation Agreement, 2003 Ill. PUC Lexis 201, are not applicable in this situation. Section 525.40(d) creates an exception in terms of what gas costs must be recovered through a PGA. It provides that “[T]his subsection shall not apply to transactions subject to rates contained in tariffs filed with the Commission, or in contracts entered into pursuant to such tariffs . . .” (83 Ill. Adm. Code 525.40(d)). The two Nicor transportation contracts in the dockets cited above were contracts entered into pursuant to tariffs filed at the Commission. (Nicor, 2003 Ill. PUC Lexis 956 at *3-4; Nicor, 2003 Ill. PUC Lexis 201 at *4-5). What was at issue in those transportation contract cases is not the situation here.

PGL contends that these two transportation contract dockets are not exempt from Section 525.40 because there was no tariff, under which, Nicor provided transportation service to North Shore. (See, PGL Reply Brief at 48). This argument ignores the language in this regulation. Section 525.40(d) specifically exempts contracts entered into “pursuant to tariffs on file with the Commission.” (83 Ill. Adm. Code Section 525.40(d)). (Emphasis added.). These transportation contracts were pursuant to tariffs on file with the Commission. (See, e.g., Nicor, 2003 Ill. PUC Lexis 956 at *3, where the Commission ruled that it was proper for North Shore to treat the charges for the service as recoverable gas costs that are accounted for in its PGA; Nicor, 2003 Ill. PUC Lexis 201 at *2, where the Commission commented that the maximum quantity that Nicor Gas would transport represented 1.4% of Nicor Gas' historical peak day sendout). The transportation contract provided services to consumers. Services to consumers are pursuant to tariffs on file with the Commission. Pursuant to Section 525.40(d), such contracts are exempt from the accounting treatment that Section 525.40 would otherwise impose.

PGL’s assertion that it is possible to accomplish third-party services without using gas charge assets also does not aid it. The issue here is what happened, not what services are possibly available to PGL. Stating that some interstate pipelines offer services that make it possible to transact third-party services is not the same as establishing what happened here.

PGL’s assertion that gas in storage affects its gas charge only when it is delivered to end users ignores the language in Section 525.40. There is no provision in this regulation that requires delineation of gas costs at the time of delivery. Moreover, essentially, in so arguing, PGL states that when a transaction is completed through displacement instead of delivery, none of the costs associated with the displacement transaction flows through its PGA. There is no such language supporting such an argument in Section 525.40. The Commission agrees with Staff and the GCI that Section 525.40(d) requires PGL to offset the PGA costs passed on to consumers with the revenues gleaned from, at a minimum, PGA gas, as well as other assets, during the reconciliation period.

105

01-0707

Finally, PGL has not established that the revenues from these services should be handled in PGL’s next rate case. The final Order amending the applicable regulation, Section 525.40(d), issued on October 3, 1995. (Ill. Commerce Comm. on its own Motion, Revision of 83 Ill. Adm. Code 525, 1995 Ill. PUC Lexis 640). The final Order issued in Nicor’s previous rate case on April 3, 1996 (Northern Ill. Gas Co., Proposed General Increase in Rates for Gas Services, 1996 Ill. PUC Lexis 204). This Order issued pursuant to a petition filed approximately 11 months prior to April 3, 1996. It appears, therefore, that there was an overlap in time between the two dockets and Section 525.40(d) was not incorporated in Nicor’s previous rate case.

However, here, according to PGL, use of Manlove Field for park and loan and exchange services did not commence until 1998, well-after the time in which Section 525.40(d) was promulgated. (Ill. Commerce Comm., on its own Motion, Revision of 83 Ill. Adm. Code 525, 1995 Ill. PUC Lexis 640; PGL Initial Brief at 23-25). We also note that PGL participated in the rulemaking proceeding that added Section 505.40(d)). (Id.). Further, during some of the time between Nicor rate cases, Nicor did not even have a PGA, it had a performance-based regulatory program. (See, e.g., Illinois Commerce Commission, on its own Motion, v. Northern Illinois Gas Co., 2002 Ill. PUC Lexis 1164). Further, we note that PGL has not presented facts indicating that its situation is similar to that of Nicor.

In conclusion, the Commission finds that PGL improperly passed off-system transaction costs to consumers through the PGA without any corresponding offset in revenues. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as discussed in Section I. As a final note on this issue, the Commission recognizes PGL’s commitment in the Settlement Agreement and Addendum to include revenues from its off-system transactions, or its non-tariff services, in PGL’s PGA as opposed to its base rates.

106

01-0707

VIII. Specific Off-System Transactions

A. Transactions 16/22

1. Findings

During discovery, PGL advised Commission Staff that transactions 16/22 were as follows: Enron MW had the right to call on up to 20,000 Dths of gas per day, up to a total of 200,000 Dth of gas, during November and December of 2000. The price for the gas was set at the Natural Gas Intelligence Chicago citygate FOM. PGL characterized this transaction as a call option with a “demand credit” to PGL in the amount of $241,600.00.⁴² However, PGL did not receive payment from Enron Midwest. Instead, it received payment for this transaction from enovate, three months after the gas was delivered. (Staff Ex. 1.00 at 28-30).

PGL needed to purchase gas in order to make up for the gas it sold to Enron Midwest pursuant to this transaction. The amount of money needed to make up this difference in gas was $535,554, which is Staff’s proposed disallowance. PGL does not contest this recommended disallowance. (PGL Initial Brief at 103-5).

PGL personnel professed not to know the nature of this transaction until Staff served discovery on PGL asking for an explanation. PGL personnel then consulted with Enron Midwest to determine the nature of the transaction it entered into. (Staff Ex. 3.00 at 39-40). In Mr. Knepler’s opinion, the lack of documentation evincing the nature of this transaction establishes a breakdown in internal controls at PGL. Mr. Knepler recommended requiring PGL to conduct internal audits for five years.⁴³ (Staff Ex. 1.00 at 29).

The Commission makes note of the agreed to disallowance and also notes that any disallowances are included in the Settlement Agreement and Addendeum as discusssed in Section I. The Commission further notes that the discussion of Staff’s recommendation to require PGL to conduct internal audits for five years will be discussed in another section of this order.

_____________________

⁴² A call option is a trading terms for the right to buy a contract at a specific price at a certain time. (NYMEX.com/Media/energyhedge).

⁴³ At the time this deal came into existence, enovate was called “Midwest Energy Hub.” (Staff Ex. 9.00 at 18).

107

01-0707

B. The Trunkline Deal

1. Findings of Fact

The Trunkline Deal was a series of transactions between PGL, Enron Midwest and enovate. When it was effectuated, enovate already had leased Trunkline pipeline capacity from the South Texas field zone to the Chicago citygate. It obtained baseload gas supplies from PERC and Reliant to fill the leased pipeline capacity. (Staff Ex. 7.00 at 50; Staff Ex. 9.00 at 18). enovate then sold this gas to Enron Midwest with delivery at the Chicago citygate. (Staff Exs. 7.00 at 50, 68; Staff Ex. 9.00 at 18) enovate delivered the gas to Enron Midwest in the form of a call option. (See, Group. Ex. 1 at ST-PG-262-65).

Enron Midwest then sold this gas and pipeline service to PGL with delivery at the Chicago citygate at the same price at which Enron Midwest purchased from enovate. (Staff. Ex. 7.00 at 50, Staff Ex. 9.00 at 19). PGL then paid enovate, enovate, in turn, paid Trunkline. From these payments, PERC PGL’s affiliate, received 50% of the revenues enovate accrued. (Group Ex. 1 at ST-PG 76-77). This entire series of transactions was effectuated on the same day. (Id. at 68-69). The total profit garnered by PERC/Enron Midwest for these transactions was $372,000. (Staff Ex. 5.00 at 6; Staff Ex. 9.00, Attachment F).

PGL’s accounting records regarding the “Trunkline Deal” show the following columns: “PGL paying enovate” “enovate paying Trunkline” “net” and “PERC’s 50%.” No mention is made therein of Enron Midwest. (Staff Ex. 9.00, Attachment F). The “Trunkline Deal” was recorded in this manner because PGL and PERC were affiliates and PERC received one-half of enovate’s income. In such an instance, PGL would not recognize income coming from an affiliate in its accounting documents. (Group Ex. 1, ST-PG-75-76).

Staff witnesses Dr. Rearden and Ms. Hathhorn opined that this series of transactions was not done at arms-length. (Staff Ex. 7.00 at 51; Staff Ex. 9.00 at 19; Staff Ex. 12.00 at 38). Enron Midwest provided no service. Enron Midwest did, however, serve as a “buffer” between PGL/PGL affiliates, which avoided Commission detection. (See, e.g., Staff Ex. 9.00 at 19; Staff Ex. 12.00 at 38; Staff Ex. 13.00 at 19).

2. Conclusions of Law

Staff’s Position

Staff points out that PGL’s accounting treatment of the Trunkline Deal made no mention of Enron Midwest. According to Staff, this accounting treatment evinces that Enron Midwest performed no service. Staff maintains that Enron Midwest’s function in this transaction was to act as an intermediary in order to shield the Trunkline Deal from Commission scrutiny pursuant to Section 7-101 of the PUA. Staff recommends a disallowance in the amount of $372,000, which is the total profit garnered from this transaction by PEC and Enron Midwest. (Staff Init. Brief at 82-84; Staff Ex. 9.00, Attachment F).

108

01-0707

Dr. Rearden testified that, in his opinion, this was not an arm’s length transaction. Enron Midwest passed enovate’s costs through to PGL without any markup. PGL could have obtained gas at the same price at which enovate acquired it, but it chose to create a “daisy chain” to indirectly link itself to its affiliate enovate. (Staff Ex. 12.00 at 39). In his opinion, enovate earned profits due to its relationship with PGL, as all of enovate’s profits depended on PGL’s participation in this deal. (Staff Ex. 7.00 at 69-72). Without PGL to ensure the existence of a buyer, enovate may not have been able to assemble this transaction. (Id.). Staff points out that, because the Trunkline Deal was sponsored by enovate, the profits from this deal accrued to Enron Midwest and PEC. Because this was an affiliate transaction, the profits should have been flowed through the PGA. However, PGL’s consumers received no credit or other benefit from this transaction. (Id. at 70; Staff Ex. 12.00 at 39).

Staff contends that the $372,000 PGL paid to enovate should be disallowed. Staff maintains that the Trunkline deal was nothing but a ruse for PGL to transact business with enovate, using Enron Midwest as a “straw man” to escape the Commission’s scrutiny regarding affiliated interest transactions. It posits that finding this deal to be imprudent will discourage utilities from attempting to “end-run the PUA.” (Staff Initial Brief at 84-85).

Staff maintains that by redirecting funds from PGL to enovate, PGL furthered the strategic partnership between PEC and Enron whose purpose was to use PGL assets and gas to increase PEC/Enron profits. Staff avers that its adjustment is not an attempt to undo the entire deal. Rather, Staff’s recommended disallowance recuperates the profits made at the expense of consumers. (Staff Reply Brief at 84-86).

In its Brief on Exceptions, Staff argues there should be a finding that the Trunkline Deal was imprudent because there was no written contract between the parties. (Staff BOE at 18).

PGL’s Position

PGL maintains that it acted prudently because it purchased, pursuant to this transaction, firm rights to purchase supplies year-round on a swing basis.⁴⁴ It avers that, pursuant to the Trunkline Deal, PGL customers received market-priced gas. PGL contends that the Trunkline Deal was just an ordinary gas purchase transaction, in that the pricing structure was not atypical. According to Mr. Wear, the reservation charge in that transaction was in consideration for the firm rights for swing delivery and for the implied cost of transportation from the field zone to the citygate. (PGL Init. Brief at 97-8).

_____________________

⁴⁴Swing contracts permit a utility to take gas on any given day, subject only to timely notice to the seller and the pipeline.

109

01-0707

Mr. Wear testified that this contract provided the potential for PGL to alter its deliveries by 92,500 MMBtus from one day to the next in the winter, which provided PGL with supply flexibility and the ability to balance its load. The pricing formula in this transaction provided PGL with the opportunity to benefit from field prices, which at that point in time, lagged behind the citygate prices. PGL concludes that this transaction provided it with a significant amount of supply flexibility, as it allowed PGL to purchase up to 50,000 MMBtus of gas. PGL acknowledges that the Trunkline Deal was not part of its peak day supply portfolio, but maintains that nevertheless, swing gas pursuant to the Trunkline Deal could be used in the winter. (PGL Ex. L at 42-43; PGL Init. Brief at 96-98).

Commission Analysis and Conclusions

The Commission finds PGL acted imprudently by engaging in the Trunkline Deal. Any disallowance associated with the Commission’s finding of imprudence for this transaction is properly included in the Settlement Agreement and Addendum as discussed in Section I . The record indicates that PGL attempted to disguise an affiliate transaction by using Enron Midwest as a straw man. PGL directly paid enovate for the gas and pipeline capacity that Enron Midwest actually supplied to PGL. Thus, PGL did in fact, directly transact business with its affiliate, enovate. If this transaction were truly an arm’s length transaction, PGL would have paid the entity that was supposed to be its supplier, Enron Midwest, for gas and transportation. PGL did not. Further, the Commission notes that PEC gained 50% of the profits of this transaction by virtue of its relationship with enovate. Additionally, there is no evidence in this record establishing that Enron Midwest actually performed a service, other than acting as a conduit to remove the transaction from Commission detection.

PGL’s assertion that the value it received was really in the pipeline transportation (from the field to the citygate and the ability to divert gas away from the citygate) only demonstrates that this was really an affiliated interest transaction accomplished through Enron Midwest. enovate, the affiliated interest, held the Trunkline contract and enovate supplied pipeline transportation pursuant to this contract. As shall be discussed in the portion of this Order discussing enovate, since this was an affiliated interest contract that was not approved by this Commission, it is void, ab initio. (220 ILCS 7-101(d)(3); 7-102(g)). Additionally, the Commission agrees with Staff that the profits from this transaction should have been flowed through the PGA.

Staff also argues that the Trunkline Deal should be found to be imprudent because there was no written contract. We agree that the Trunkline Deal was imprudent, but it was imprudent because it passed on unnecessary costs to consumers. We agree with Staff that the Trunkline Deal should have been memorialized in some fashion. However, the Commission declines to require utilities to enter into written contracts for every purchase of gas. Rather, we stress that all transactions should be supported with adequate documentation, in whatever form, memorializing the terms of the transaction and otherwise complying with the USOA. PGL should be savvy enough to know that prudently incurred gas costs are easier to substantiate with written agreements than oral agreements. PGL alleges it memorialized the Trunkline Deal in writing. However, the contract which PGL claims memorialized the transaction here appears to concern Transaction 19 or a similar type of arrangement. (Group Ex. 1 at ST-PG-254-57).

110

01-0707

C. Transaction 103

1. Findings of Fact

On May 7, 2000, PGL contracted with Enron Midwest to deliver gas to Enron Midwest in December of 2000 at the October FOM price. In exchange, Enron Midwest agreed to pay a pipeline penalty to Natural Gas Pipeline. The value of that pipeline penalty was $0.10 per MMBtu. (See, e.g., Staff Ex. 7.00 at 41).

At the time this transaction was agreed upon, the NYMEX futures price for December 2000 delivery was $3.30 per MMBtu. The NYMEX futures price for October 2000 delivery was $3.094 per MMBTU. Enron Midwest gained a profit of $0.206 per MMBtu, resulting in a financial gain in the amount of $1,411,031. (Staff Ex. 7.00 at 42).

2. Conclusions of Law

Staff’s Position

Staff’s proposed disallowance for this transaction is $1,411,031. (Staff Ex. 7.00 at 17, 41). Staff states that Transaction 103 is imprudent because this transaction did not equal the projected difference in futures gas prices between October and December of 2000 at the time this transaction was consummated. The terms of this contract were “struck” in April of 2000 and it involved delivery of gas to Enron Midwest in December of 2000 at October, 2000 prices in exchange for Enron Midwest paying a pipeline penalty that PGL had incurred. (Staff Reply Brief at 82-83). Staff avers that this transaction was imprudent because the dollar amount of the penalty Enron Midwest paid was less than the projected difference in the price of gas between October and December. PGL and Enron Midwest knew this since they had information about the October and December 2000 prices (i.e., NYMEX futures) in April of 2000. Staff further contends that Transaction 103 was imprudent because basis usually increases in winter. Essentially, PGL decision-makers knew, when entering into this transaction, that payment of the penalty would not adequately compensate consumers. (Staff Init. Brief at 81).

Staff points out that there is nothing uniquely beneficial about paying a penalty. To be prudent, the benefit conferred on Enron MW by this arrangement should equal what PGL gave up in exchange for the payment of this penalty. (Id.). Staff posits that here, the increased costs to consumers resulting from Transaction 103 is the additional cost of gas that PGL purchased to replace the gas it sold to Enron Midwest pursuant to this transaction. (Id.).

111

01-0707

Staff opines that the spread between the October and December futures and forward gas markets provide a means by which one can determine whether Transaction 103 is prudent. This is true because this contract was entered into in April or May of 2000, when the actual contract price was not known. What was known at that time, were futures and forward prices. (Staff Ex. 7.00 at 41). Using NYMEX data, Dr. Rearden computed the value conferred on Enron at $0.206 per MMBtu. He then subtracted $0.10, which is the value of the pipeline penalty Enron Midwest paid. The results indicated that PGL received about half of what the gas was worth. Dr. Rearden opined that the value of obtaining gas in December 2000 at October 2000 prices far exceed the value to PGL of Enron Midwest paying the penalty. He concluded that PGL imprudently gave up too much in Transaction 103. (Staff Ex. 12.00 at 40). Dr. Rearden pointed out that his use of the NYMEX spread was to determine what was known to the parties when they entered into Transaction 103, not to require PGL to perform hedges. (Id.).

Staff posits that because this transaction was entered into in advance, the only valuation available to the decision-makers at the time the transaction was entered into was NYMEX futures prices. When determining the value of this transaction, to use any other type of information would entail using information that PGL personnel would not have known at the time the transaction was entered into. (Staff Reply Brief at 81-82).

PGL’s Position

PGL contends that Transaction 103 was a reasonable business decision designed to avoid paying a pipeline penalty. Because of PGL’s Rate Schedule DSS (Delivered Storage Service) that PGL purchases from Natural, PGL was faced with either reduced injection rights in the upcoming injection season or pay a cycling charge t the pipeline. PGL could have paid the pipeline charge to preserve its injection rights. However, Enron MW offered an alternative—Enron MW would pay the entire charge in exchange for Transaction 103. PGL argues this arrangement allowed it balancing flexibility in the 2000 injection season and provided the opportunity to receive gas commodity charge credits through off-system transactions. PGL used these injection rights 69 times. (PGL Initial Brief at 95-96).

PGL also argues that Dr. Rearden’s calculations are wrong because Dr. Rearden based his calculations on a theory that this transaction was purely a financial spread transaction that PGL could have undertaken. PGL avers that the injections to support the sale to Enron MW, which took place from May through October, were expected on a no-notice basis. Therefore, according to PGL, there could not be a baseload hedge on this gas. Also, the October, 2000 prices, which occurred at the time the transaction was entered into, were higher than NYMEX prices from May through October. Even with a hedge, PGL could not have achieved the economic result that Dr. Rearden asserted was possible. (PGL Initial Brief at 97).

PGL characterizes Staff’s analysis of this transaction as a “purely theoretical economical analysis.” It argues that it could not have both paid the pipeline charge and also hedge the October/December spread because the benefit it received from payment of the pipeline penalty was a no-notice service that could not be hedged. (Id.).

112

01-0707

Commission Analysis and Conclusions

PGL does not explain why it could not simply have paid this penalty. Also, Staff does not contend that that the penalty should not have been paid. While paying the penalty may have preserved PGL’s injection rights, there is no evidence here that who paid the penalty made a difference. Therefore, PGL could have paid the penalty. Nor does PGL explain why Enron Midwest could not have tendered fair market value (i.e., the applicable futures price) in exchange for the payment of this penalty. What PGL should have considered before agreeing to this transaction was whether it would increase costs to PGA customers. PGL provided no evidence that it even considered the effects on PGA customers.

PGL’s averments regarding Dr. Rearden’s disallowance calculations overlook his actual testimony, which does not speak of NYMEX futures or options in terms of imposing a duty to purchase hedges through the use of futures. Rather, Dr. Rearden’s testimony speaks of the NYMEX futures in terms of what gas prices were known to the parties about the value of the gas conferred on Enron Midwest pursuant to Transaction 103 when they entered into it. (Staff Ex. 7.00 at 41).

PGL’s statement that the transaction was entered into in October is incorrect. The transaction was entered into in April or May of 2000. The events that took place pursuant to this agreement occurred in December of 2000. The only discernable connection in this record to the month of October, 2000 is that the gas price was the October price. (Staff Ex. 7.00 at 41). Therefore, the applicable NYMEX futures prices would be those that existed in April or May of 2000. PGL’s assertion that October futures prices were promising is based on prices that existed in October of 2000, not the October futures prices that existed when the transaction was entered into. Finally, Mr. Wear’s testimony that Dr. Rearden’s calculations as to NYMEX futures prices is incorrect is not credible. The Commission agrees with Staff that this transaction is imprudent. Any disallowance associated with the Commission’s finding of imprudence for this transaction is properly included in the Settlement Agreement and Addenduem as discussed in Section I.

D. Transaction 19

1. Findings of Fact

Transaction 19 was an agreement where PGL resold baseload gas to Enron NA in the amount of 50,000 Dths of gas per day, for each day in the month of December, 2000, at the Natural Gas Intelligence Chicago citygate FOM price. (Tr. 917). Enron Midwest sold this gas back to PGL at high winter daily spot prices. (See, e.g., Staff Ex. 12.00 at 24). PGL executed this agreement in November 2000, around the time it decided to begin early withdrawals from Manlove. (PG Ex. F at 49-50). The replacement gas cost consumers $5,661,703. (AG Ex. 1.1 at 11-20). Dr. Rearden opined that the reason PGL personnel entered into this transaction was the desire for unregulated profits from this transaction. (Staff Ex. 7.00 at 28-29).

The total value of this transaction was approximately $9.5 million. (Tr. 918). PGL entered into this contract based on one e-mail. (Tr. 1295).

113

01-0707

According to Mr. Wear, the gas sold to Enron NA was just “excess gas.” Mr. Wear testified that PGL entered into this agreement based on several factors: The November 2000 gas prices were higher than the forward prices for December 2000 and January 2001 and PGL believed the colder than normal weather that existed at the time would subside, leading to PGL’s early withdrawals from Manlove. (PGL Ex. F at 35). Mr. Wear testified that this decision reduced the amount of purchased gas PGL needed to balance its system. At the time, the purchase price of gas was at unprecedented high levels. (PGL Ex. F at 35-36).

Also, PGL personnel were concerned with the possibility of having an oversupply of gas. At the same time, however, they were concerned with the possibility that PGL would have an undersupply of gas. (Id.). Transaction 19 and weather conditions in Chicago caused PGL to fall short in December of 2000, in terms of what gas it needed to serve its customers. Thus, PGL had to replace the 50,000 MMBtus of gas that it sold to Enron NA per day. It did so by buying an approximately equal amount of gas, at the higher daily price. (See, e.g., AG Ex. 1.1 at 11-12).

2. Conclusions of Law

Staff’s Position

Staff’s proposed disallowance for this transaction is $5,661,703, which represents the cost of replacement gas. (Staff Brief at 78). Dr. Rearden opined that this gas was sold before PGL personnel could determine what the weather in the beginning of winter would be like. (Tr. 1296). Staff points out that much of the gas withdrawn for third-parties in November was done to loan gas to Enron MW in the form of “Manlove Jumpstart.” Staff opines that PGL personnel needed to ensure that a sufficient amount of stored gas would be available, in case this gas was needed later on in the winter. Also, PGL’s explanation that it was planning for warmer than normal conditions in November was implausible.

Staff is of the opinion that Transaction 19 imprudently decreased PGL’s ability to respond to any weather other than a warmer than normal winter in Chicago. The risk PGL identified, facing oversupply due to warmer than normal winter, is a situation that PGL faces every year. Staff argues that PGL personnel traded the risk that it might suffer losses on the excess supply due to the winter weather for the risk of being short during an already cold winter.

114

01-0707

PGL’s Position

PGL argues that Transaction 19 was a reaction to an oversupply. PGL sold the gas involved because it had too much gas. PGL argues that if it had reduced its baseload purchases, it would still risk being exposed to daily price increases.⁴⁵ (PGL Init Brief at 93). Citing Mr. Wear’s testimony, PGL avers that at the time it entered into Transaction 19, it had purchased quantities of spot gas to fill Manlove Field and to meet a higher than normal demand. These gas purchases were at an unprecedented high level. Because gas prices were so high, an early onset of gas withdrawal would reduce gas purchases by nearly $3 million per day, but it would also mean that PGL would enter the heating season with less stored gas than what was planned, as well as the “increased likelihood of a weather-related oversupply.” (Id. at 94).

PGL disagrees with Mr. Effron’s assessment of Transaction 19. PGL argues that Mr. Effron purported to compare qualified “costs” with quantified “benefits” to produce a recommended disallowance of $8.1 million. (See, AG Ex. 1.0 at 15, 18). This analysis was based on Mr. Effron surmising that Transaction 19 was a surrogate for the BLPA clause in the GPAA. According to PGL, the only apparent purpose of Mr. Effron‘s statement was “to make his GPAA cost/benefit analysis produce a larger result than can be attributed to the GPAA.” PGL avers that both the GPAA and Transaction 19 are prudent. It contends that Mr. Effron presented no evidence of a tie between the BLPA, which Enron North America never exercised, and Transaction 19. In support, PGL cites PGL Ex. F at 53-54. (PGL Init. Brief at 63-64).

Likewise, PGL argues that Staff’s proposed disallowance is too high. PGL seeks to reduce Staff’s disallowance to $5,057,982. PGL contends that Dr. Rearden should not have used PGL’s highest-priced purchases of replacement gas to determine what Transaction 19 cost consumers, as no particular gas purchase it made was allocated to any particular customer. PGL contends that the proper way to determine the value of the replacement gas necessitated by Transaction 19 is to use a weighted average of the pertinent gas purchases. (PGL Init. Brief at 95-96). Also, Dr. Rearden used 50,000 Dth of gas, for every day Transaction 19 was replaced. However, there were days, in which, PGL did not buy 50,000 Dth of replacement gas. Correcting these errors, and allowing for a previous computational error made by Dr. Rearden, reduces Staff’s proposed disallowance by $1,299,706. (Id. at 96).

PGL asserts that Staff disregards the consequences of its decision to begin withdrawing gas two weeks early from Manlove Field. Because PGL had to withdraw 350,000 MMBtus daily, PGL personnel were required to create a tendency at Manlove for gas and water to move toward the center of this reservoir. (PGL Reply Brief at 53-54). Also, by selling gas to Enron NA outside the GPAA resale provision, Transaction 19 preserved the three-cent per MMBtu credit. PGL concludes that therefore, this transaction was beneficial to consumers. (Id. at 54-55).

_____________________

⁴⁵In this context, it appears that PGL is referring to baseload purchases as DIQ gas, not baseload gas. Baseload gas was not sold at daily prices; instead, it was sold at FOM price, with a three-cent per MMBtu discount. (Staff Ex. 2.00, Attachments, GPAA).

115

01-0707

PGL further asserts that its decision to enter into Transaction 19 only can be criticized based upon an after the fact review. PGL personnel had to decide whether to engage in the transaction before it could know what the weather in December of 2000 would be. According to PGL, under different weather and price conditions, Transaction 19 would have been unfavorable to Enron NA. PGL does not state what those different weather and price conditions are. (PGL BOE at 26).

GCI’s Position

The GCI’s recommended disallowance for this transaction is $5,472,000. Mr. Effron opined that, while Enron NA never actually acted upon the BLPA, Transaction 19 was a substitute for increasing consumer gas costs pursuant to the BLPA. While PGL averred that Transaction 19 was meant to address an oversupply, Mr. Effron was of the opinion that PGL’s planning document regarding Transaction 19 showed the opposite, that PGL risked undersupply in December of 2000. (AG Ex. 1.1 at 11-16). The GCI point out that the spot gas PGL bought to replace the 50,000 MMBtus to Enron NA was higher than the average daily price in December of 2000. (GCI Init. Brief at 46).

The GCI posit that there was no clear oversupply situation in Chicago in November of 2000 that merited this extraordinary situation. The planning documents that PGL offered to support this decision actually demonstrated the opposite. (AG Ex. 1.0 at 12; GCI Reply Brief at 33). This planning document established that there were as many days projected by PGL personnel that would be in excess of its available supply (short), as would be long. However, the largest daily short position would be greater than any long position projected. The GCI maintain the PGL disregarded the possible problems from being in a short position because PGL could have bought expensive spot gas to correct a short situation. (GCI Reply Brief at 33-34).

Also, the sellback provision had a maximum of 150,000 MMBtus, which was three times the amount of the transaction here. PGL could have exercised the sellback provision on individual days for a specific price, instead of doing what it did here, committing to a month-long obligation to sell gas. (Id.).

Commission Analysis and Conclusions

This is yet another in a long line of imprudent decisions PGL made during the reconciliation year in question. PGL bases its argument on the prudence of Transaction 19 on Mr. Wear’s testimony, which the Commission previously determined to be not credible. Mr. Wear testified, essentially, that PGL personnel made the decision to unload excess gas because they were concerned about both an undersupply and an oversupply, which makes no sense. (PGL ex. F at 35-36). Mr. Wear offered no explanation as to why PGL personnel would be concerned with having too much gas in November, the beginning of the winter heating season. In fact, at that point in time, record cold conditions existed. (Staff Ex. 3.00 at 50).

116

01-0707

Even if the Commission were to accept Mr. Wear’s version of the events as true, it was imprudent for PGL to place itself in a position where its personnel feared having an oversupply of gas at the onset of winter. In fact, PGL’s subsequent purchases of gas to replace this gas is some evidence that a fear of having an oversupply was not the case. Moreover, PGL presented conflicting reasons for engaging in Transaction 19. To contend that early withdrawals from Manlove were necessary to protect PGA customers from high gas prices during the colder than expected November 2000 and to also contend PGL faced an oversupply simply flummoxes us. PGL’s imprudent behavior unnecessarily increased costs for PGA customers. The Commission finds Transaction 19 to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for this transaction is properly included in the Settlement Agreement and Addendum as discussed in Section 1.

PGL disagrees with Dr. Reardon’s assessment of the proposed disallowance. PGL did not establish that Dr. Rearden improperly used only high spot gas prices, as PGL did not present credible evidence establishing that these prices do not depict its actual purchases. If Dr. Rearden’s amounts were not correct, PGL could have, but did not, produce evidence documenting the correct gas prices. However, there is insufficient evidentiary support to conclude that Transaction 19 was a substitute for the BLPA. We cannot adopt this assumption without evidence that Transaction 19 was a substitute for the BLPA. We conclude, therefore, that Staff’s recommended disallowance better reflects the economic loss incurred by consumers as a result of this transaction.

Finally, the Commission notes that PGL transacted here with Enron MW, meaning one-half of the profits from any subsequent sales of gas garnered from this transaction were conferred upon PEC/PERC through enovate. The profits from this transaction flowed to enovate instead of through the PGA as required by Commission rules, lending further support to the Commission’s finding of imprudence on Transaction 19.

E. The Storage Optimization Contract (“SOC”)

1. Findings of Fact

During the time period in question, PGL had contracts with six pipeline suppliers. (Tr. 875). These contracts allowed PGL to purchase gas in the field and transport gas to the Chicago citygate at less than citygate prices, when the basis differentials for a given transportation contract was wider than the cost. (Tr. 905). There were times, however, when PGL did not used these transportation rights. (See, e.g., Tr. 901). For a fee, PGL loaned its unused transportation rights to third-parties. (Id.). According to Mr. Wear, the purpose of making such loans is to generate income to be used as a credit that offset customer gas charges. (Tr. 901-02).

117

01-0707

PGL had two contracts, called the NSS Contracts, with Natural Gas Pipeline Company (“Natural”) for storage service. (Tr. 996-98). These contracts were for tariffed services that had rigid rules. (Tr. 997). Under Rate Schedule NSS (“NSS”), Natural provided PGL with 75-day storage service. PGL coupled the NSS with the “no-notice balancing” under Natural’s Rate Schedule Firm Transportation Service (“FTS”). The NSS tariff required PGL to keep the gas stored at a certain level. (Tr. 999). PGL generally needed a 10 or 20 day of period of storage service which it used only on the coldest days in winter, both NSS contracts required PGL to purchase 75 days of capacity. (Tr. 997). The maximum storage volume for the two NSS Contracts, combined, was 19,218,750 MMBtus. (Tr. 1009).

On January 21, 2000, PEC received an offer from the entity that had previously “optimized” the NSS contracts with Natural Gas Pipeline. This offer suggested three alternatives:

-the entity would market “seasonal gross margins” for 17% of the profits therefrom and market “unencumbered capacity” at 30% of the profits; and it would market “encumbered capacity for 10% of the profits. However, PEC would pay the carrying costs for “encumbered capacity.”

-a “Fixed Price Proposal,” in which the entity would pay PEC a fixed amount per month, in return for managing the NSS contract. PEC again would pay the carrying costs.

-the entity proposed managing just one Bcf of the storage service in return for a fixed payment to PEC.

(Staff Ex. 7.00 at 63-64). PEC personnel chose not to explore any of these options with this company. Instead, they chose to execute the Storage Optimization Contract(“SOC”) with Enron MW. Under the SOC, Enron MW would “optimize” the excess leased storage capacity of PGL. PGL chose this because it wanted more “no notice” rights in its portfolio, but did not need the 75 days of peaking capacity. PGL stated that by entering into the SOC, it was able to convert its two 75 day NSS contracts into a 10-day storage contract and a 20 day storage contract.⁴⁶ The costs and revenues associated with the SOC flowed through PGL’s gas charge and were paid by consumers. (Tr. 996). PGL received a total of $334,344 in credits from the SOC during the time period in question, which it flowed through the PGA. (Staff Ex. 9.02).

Article 4, par. 2, of the SOC obliged Enron MW to purchase gas for injection into the Natural Gas Pipeline on behalf of PGL. (See, e.g., Tr. 1006). This was done so that PGL’s inventory never fell below the amount required by Natural Gas Pipeline in its tariffs. (Tr. 1007). When Enron MW caused gas to be injected into PGL’s NSS storage, PGL was obligated to compensate Enron MW for that gas. (Tr. 1007). PGL did so by transferring title to Enron MW of a quantity of gas equal to that which Enron Midwest injected into PGL’s NSS storage. (Tr. 1008). When Enron MW withdrew gas from the unrestricted NSS capacity, Enron MW would return title of the equivalent value of gas to Manlove. (Tr. 1008).

_____________________

⁴⁶ The 10-day storage contract was for 90,000 MMBtus. The 20-day storage contract was for 85,000 MMBtus for a total of 1,700,000 MMBtus.

118

01-0707

PGL paid Enron Midwest $20,000 per month as a management fee. (See, e.g., Staff Ex. 7.00 at 64). This contract also provided that Enron MW took a percentage of the profits for providing optimization services. This percentage increased as the gross margin increased. (Staff Ex. 2.00, Attachments, SOC Contract). Not only did Enron MW profit from this arrangement, but so did PEC/PERC per the profit sharing arrangement with Enron NA. PEC/PERC received half of these fees paid for the year in question, or $120,000. ($20,000 x 12 divided by 2). (Staff Ex. 9.00 at 15, Sched. 9.02).

PGL paid other fees to Enron MW pursuant to the SOC as well. The total fees PGL paid to Enron Midwest pursuant to the SOC were $503,000. (Staff Ex. 15-16; Schedule 9.02). Pursuant to the profit-sharing arrangement between Enron Midwest and PEC, PEC was entitled to 50% of the profits gained by EMW from the SOC. After PERC’s/PEC’s share was apportioned, Enron Midwest gleaned $717,455 from the SOC. (Staff Ex. 7.00 at 49).

The SOC required Enron MW to file reports with PGL setting forth what Enron MW was doing in the field. (Tr. 1324). Those reports would show what Enron MW did to earn the revenues it took. (Staff Ex. 3.00 at 64). Enron Midwest, however, did not file these reports with PGL. (Tr. 1324). There is no evidence to indicate that Enron Midwest actually earned any of the revenues it took pursuant to the SOC.

The GCI contend that because the NSS contracts were used only during peak times, PGL only needed 15 days of capacity. However, the two NSS contracts each provided 75 days of capacity. (City-CUB Ex. 1.0 at 53). The cost in procuring this extra capacity and other related costs were borne by consumers. Ms. Decker opined that the SOC allowed Enron Midwest to gain control over Manlove Field because it required PGL to inject a substantial amount of gas into its NSS accounts. (City-CUB Ex. 1.0 at 53).

2. Conclusions of Law

a. Staff’s Position

Staff recommends a total disallowance for the SOC in the amount of $1,340,455, which Staff breaks down into two parts. Staff recommends a $717,455 disallowance for PGL’s failure to establish that the SOC was a prudent choice and which represents the amount Enron MW received from for “optimizing” the NSS contracts. Staff also recommends a disallowance of $623,000, which is PERC’s share of Enron MW’s management fees that were funneled through enovate, and its share of the revenues that Enron Midwest generated by “optimizing” the NSS capacity, but were also funneled to PEC/PERC through enovate. (Staff Init. Brief at 88-89; Staff Ex. 5.00 at 6).

119

01-0707

Staff articulated several other reasons PGL’s participation in the SOC was imprudent. Staff maintains that PGL’s failure to document what Enron MW was doing to earn the revenues it took pursuant to the SOC was imprudent. Staff posits that PGL never explained why it needed Enron Midwest to optimize its leased storage. And, PGL had an alternative to Enron Midwest, another company that was interested in optimizing this storage, at more favorable terms to consumers. Staff contends that PGL chose EMW over this other vendor due to the profit-sharing arrangement Enron Midwest had with PEC. Staff argues that therefore, PGL’s choice of Enron Midwest as its storage optimizer was imprudent. (Staff Init. Brief at 87-88, Staff Ex. 7.00 at 49).

Staff also argues that PEC gleaned profits pursuant to SOC from PGL. Enron MW paid PERC/PEC one-half of the management fees it collected which amounted to $240,000. Staff argues that this arrangement is blatant cross-subsidization, as it served no purpose other than to move money from PGL to its parent, just to increase PEC/PERC’s revenues. According to Staff, PGL has proffered no explanation for entering into a contract that conferred benefits on its corporate parent, which also denied consumers the full benefits of storage optimization. (Id. at 88-89).

Staff takes issue with PGL’s statement that the SOC did not increase gas costs. The SOC caused PGL to spend more money for this service than it otherwise would have paid. The previous offer for “optimization services” would have resulted in PGL sharing approximately 19% of the profits with the offering company. The SOC, however, required PGL to pay Enron Midwest an amount between 20% to 40% of the profits from the optimized storage. (Staff Reply Brief at 71-74).

Staff points out that PEC received 50% of Enron MW’s profits from the SOC through enovate. The fact that PEC, PGL’s parent company, received a percentage of profits gleaned from PGL calls into question whether the SOC was an arm’s length transaction. Also, the fact that Section 525.40(a)(4) of the Commission’s Rules allows for recovery of supply management contracts does not, by itself, make such a contract prudent. (Id.).

On Exceptions, Staff seeks a finding that the other optimization contract offer was a better choice for PGL. In effect, Staff seeks a finding that PGL was imprudent for failing to enter into the alternative optimization arrangement. (Staff Reply Brief on Exceptions at 12-14).

b. GCI’s Position

The GCI point out that both of the NSS contracts underlying the SOC provided 75 days of (no-notice) service. In fact, PGL only needed one of the NSS contracts to get the 15 days or so of the no-notice service PGL needed. (City-CUB Ex. 1.0 at 52; City-CUB Ex. 1.25). Also, Article IV(2) of the SOC obliged Enron MW to inject gas into PGL’s NSS storage. Article V(1) of the SOC provided that, when Enron MW caused gas to be injected into PGL’s NSS storage inventory, title to the same amount of PGL gas in Manlove Field was transferred to Enron MW pursuant to Article XI(1) of the SOC. (Staff Ex. 2.00, Attachments, SOC Contract, Tr. 1007-8; City-CUB Ex. 1.0 at 51).

120

01-0707

Thus, by having a second (and unnecessary) NSS contract, a much greater volume of gas in Manlove Field could be transferred to Enron MW. The amount of gas in Manlove that was made available was substantial. The GCI contend that through the SOC, PGL gave Enron MW more than 65% of the volume of gas in Manlove Field that was reserved for its customers, free of the restrictions attached to the NSS contracts. The GCI recommend no disallowance, however, as the harm to ratepaying consumers was not quantifiable. The GCI aver that PGL never produced information that would have allowed them to determine that harm. (GCI Initial Brief at 66-69).

c. PGL’s Position

According to PGL, the SOC did not increase gas costs. PGL points out that the NSS contracts in question provide no-notice, 75-day storage. For each MMBtu of peak withdrawal capability that a shipper wants, that shipper must also acquire 75 times that amount in capacity. PGL desired to acquire no-notice capacity rights, but it did not need 75 days of peaking capability. PGL entered into these two NSS contracts, and what was not needed was “optimized,” or used to support revenue-generating transactions pursuant to the SOC. Under the SOC, Enron Midwest was responsible for acquiring the supplies and coordinating with PGL to dispatch those supplies in order to optimize the storage PGL did not need. (PGL Init. Brief at 26-27, 81).

PGL contends that Section 525.40(a)(4) was promulgated so that third-parties could be paid through the PGA to manage excess capacity. According to PGL, it did not relinquish control over the gas it transferred to Enron Midwest. PGL acknowledges that it transferred title to this gas, but it claims that it only did so because federal policy necessitated the transfer in title. (PGL Init. Brief at 83; PGL Reply Brief at 83).

PGL states that it did not accept the other offer made for storage optimization services because, at that time, the offering company had just been acquired by another company. PGL personnel were concerned about entrusting the NSS contracts to a company with an uncertain future. Also, PGL had two NSS contracts because one contract was an extension of an existing arrangement; the other contract replaced a 30-day storage service that was not renewed. (PGL Reply Brief at 66-67).

d. Commission Analysis and Conclusions

The Commission finds PGL acted imprudently by entering into the SOC. Prior to executing the SOC, PGL received an offer from another company that presented terms more favorable to consumers than the SOC, yet PGL chose Enron Midwest to optimize storage. On its face, this might not look like a bad choice. But, when we consider the arrangement between PEC and Enron NA to funnel profits from their dealings from PGL up to the corporate parents, this smacks of imprudence. PEC gleaned not only 50% of the SOC profits, but PEC gleaned 50% of Enron MW’s management fees pursuant to this contract through enovate.

121

01-0707

PGL proffers no evidence establishing that Enron MW in fact, performed a legitimate service. Also, while Enron Midwest collected its profit, above and beyond its monthly charges, PGL has not proffered evidence, such as what space it “optimized,” to whom, or when, establishing what Enron Midwest did to earn those profits. PGL cites no law that requires this Commission to deem a contract to be prudent when a utility is unable to explain what the provider did to earn monthly fees and contractually-established profits from that contract. Indeed, there is none.

While Commission regulations permit recovery of supply management costs, PGL is still subject to the statutory requirement that all costs must be prudently incurred. (220 ILCS 5/9-220). Therefore, PGL was required to account to the Commission for what Enron MW did to earn its monthly fees and commissions. Additionally, the record here is devoid of any evidence that PEC/PERC performed any service. Yet, it garnered $623,000 in fees collected from consumers. The fact that PEC garnered profits from this transaction casts doubt on any claim that it was an arm’s length transaction.

Citing no law or fact, PGL argues that the conclusions above are mere conjecture and speculation. PGL has waived its right to assert this argument. (Fraley, 251 Ill. App. 3d at 77). PGL had the burden to prove the prudence of this contract. PGL cites no law or fact indicating that these conclusions were anything more than reasonable inferences drawn from the evidence by the trier of fact.

The other optimization offer is evidence that PGL could have optimized the NSS contracts without Enron. This other offer is also some indicia that PGL personnel, when entering into the SOC contract, were motivated by a desire to confer profit on PEC, irrespective of whether the SOC was in the best interests of PGL. However, we decline to find, as Staff suggests, that PGL was imprudent for failing to enter into the other contract. To do so would be managing PGL’s day-to-day affairs.

The Commission finds the SOC to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as discussed in Section I.

F. The Citgo Contract

1. Findings of Fact

Before the reconciliation period, PGL had a gas purchase agreement to buy refinery fuel gas from a Citgo subsidiary, also known as Uno-Ven, or PDVMR, at 75% of the Chicago citygate price. This gas was in the form of a peaking service.⁴⁷ (Group Ex. 1 at ST-PG-184). The Citgo contract was in effect from October 1, 1995 through September 30, 1999. However, PGL continued purchasing pursuant to this contract after it expired, until October 1, 2000. William Morrow, Vice-President of PGL, executed this contract on behalf of PGL. After October 1, 2000, PERC assumed this contract. By way of a letter dated March 13, 2002, William Morrow terminated this contract on behalf of PERC, effective April 30, 2002. (Group Ex. 1 at ST-PG-188).

_____________________

⁴⁷ The peak winter period is December through February. (Tr. 872).

122

01-0707

After PERC assumed PGL’s contract with Citgo, PERC purchased gas at 75% of the citygate price with the same terms and conditions as PGL had done before. PERC then sold gas to Enron MW for 92.5% of the citygate price. Enron MW then sold gas to PGL for 95% of the citygate price. Enron Midwest was the intermediary between PERC and PGL. (Staff Ex. 9.00 at 12; Attachment B; Staff Ex. 13.00 at 1-2). Enron Midwest’s 2.5% profit was transferred to enovate to be split between PEC and Enron North America. (Staff Ex. 9.00 at 9, 14). Also, PERC enjoyed a 17.5% profit from selling this gas to Enron Midwest. (Staff Ex. 9.00, Attachment B). The amount of profit gleaned from this arrangement by PERC and Enron Midwest $2,232,490. (Staff Ex. 9.00, Sched. 9.01).

According to Mr. Wear, the refinery gas PGL previously received pursuant to its contract with Citgo was not of good quality. (Tr. 1072). However, Citgo sold gas to PERC. PERC sold gas to Enron Midwest, who sold gas to PGL. (Tr. 1072-73). Mr. Wear admitted that there was no way of knowing whether PGL was, in fact, receiving the same “inferior” gas from Citgo though PERC/Enron Midwest. (Tr. 1072). Mr. Wear stated that in his opinion, “[a]ny disallowance (regarding the Citgo contract) whatsoever is penalizing (PGL) for buying discounted gas for its customers.” (PGL Ex. L at 47).

2. Conclusions of Law

a. Staff’s Position

Staff proposes a cost disallowance for the Citgo Contract of approximately $2.2 million. Staff maintains that this transaction added unnecessary costs to consumer gas costs. After PERC assumed PGL’s Citgo contract, the price of gas PERC paid did not increase, but, the price paid by consumers increased, from receiving a 25% discount to a 5% discount on the citygate price. Of the 20% difference in discounts, PERC received 17.5%, and Enron MW received 2.5%. Staff argues that Enron MW’s role in this transaction was to aid in the avoidance of Commission scrutiny. (Staff Init. Brief at 85-87).

According to Staff, PGL has never offered evidence indicating that Enron MW performed a service in consideration for the markup it received on this gas. Staff’s recommended disallowance of approximately $2.2 million does not include any profit PERC/PEC earned through its profit-sharing arrangement with Enron North America/Enron Midwest, enovate. Staff never received the documentation that would enable it to determine whether PEC received half of Enron Midwest’s markup. (Id., Staff Ex. 13.00 at 14).

b. PGL’s Position

PGL acknowledges that it purchased refinery gas from Enron MW, instead of Citgo, at 95% pf the index price, instead of at 75%, which is what it previously had with Citgo. PGL avers that the Citgo contract terminated in 2001 and the arrangement through PERC/Enron Midwest actually saved consumers money because consumers paid 5% less than the full price. (PGL Init. brief at 99-100).

On Exceptions, PGL explicitly waived its right to contest this disallowance. (PGL BOE at 37).

123

01-0707

c. GCI’s Position

Pursuant to an unwritten agreement, PERC assumed PGL’s contract with Citgo. By inserting PERC in PGL’s position, according to the GCI, PGL paid 20% more for gas. Also, this arrangement was designed to avoid Section 7-101 of the PUA. Further, according to the GCI, this deal was imprudent because PGL personnel did not keep the contract with Citgo and they accepted the unnecessary mark-ups on the gas. The GCI posit that because PERC/PEC enjoyed 50% of Enron MW’s profits, it is likely that PEC/PERC received an amount of money in additional to its mark-up on the Citgo gas. (GCI Init. Brief at 69-71). According to the GCI, this transaction was imprudent because PGL accepted Enron MW’s markup. (Id. at 69-71).

d. Commission Analysis and Conclusions

The Citgo contract was in effect from October 1, 1995 through September 30, 1999. PGL continued purchasing pursuant to this contract after it expired, until October 1, 2000. After that, PERC assumed this contract. PERC purchased refinery gas under the same terms, including paying 75% of the citygate price, then sold this to Enron MW at a markup. Coming full circle, Enron MW then sold this gas to PGL at an additional markup. The record is empty of evidence that the “middlemen,” PERC and Enron MW, served any legitimate purpose. There is no evidence that this arrangement, through PERC/Enron Midwest was anything but imprudent.

PGL’s contention that the Citgo contract “saved” consumers money after PGL transferred it to PERC is ridiculous . Consumers received the same gas through the PERC/Enron Midwest arrangement as they did from Citgo, but at a 5% discount instead of a 25% discount. By the Commission’s math, this was actually a 20% increase in costs to consumers. PGL provided no evidence that any benefit was conferred on consumers as a result of the 20% increase in gas costs.

PGL’s argument that consumers benefited from this arrangement is just wrong. In fact, the arrangement here was nothing more than an affiliated interest contract whereby PERC garnered profits from consumers through via another scheme with Enron MW. The contract is therefore, void ab initio. For all of these reasons, the Commission finds PGL’s behavior under the Citgo contract to be imprudent. Any disallowance associated with the Commission’s finding of imprudence for this provision is properly included in the Settlement Agreement and Addendum as discussed in Section I.

124

01-0707

G. Hedging

1. Findings of Fact

a. Background

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. (PGL Ex. H at 9).

Mr. Wear testified that PGL took “several steps” to address price volatility during the reconciliation year. It used seasonal storage, and “followed” two separate price protection programs. During the reconciliation period, PGL had two different price protection programs that were in effect. PGL did not use one of its price protection programs at all during the time period in question. (Tr. 969-70).

PGL provided descriptions of both of its price protection programs. Gas prices would have to drop below $2.30 per MMBtu before PGL personnel could purchase gas pursuant to the “Gas Supply Price Protection Financial Trading Strategy.” (Tr. 968). PGL personnel could not lock in any price above $2.30 per MMBtu without the prior approval of its Gas Supply Administration Department. (Tr. 968). In the period up to and including the year in question, gas prices were, on occasion, below $2.30 per MMBtu. (Tr. 968, 969). However, PGL personnel did not purchase any hedges pursuant to this plan. (Tr. 969-70).

PGL’s second hedging program, the “Gas Supply Price Protection Strategy,” became effective in April of 2001. (Tr. 974). The second strategy allowed PGL personnel to lock into prices based on the forward market. (Tr. 975). Pursuant to the second hedging program, the recommended hedging amount was 44%, approximately 53,120,000 MMBtus of gas, of its total purchase volumes from April through October of 2001. (Tr. 976). In November of 2001 through March of 2002, PGL hedged as much as 60% of its purchase volumes. (Tr. 977). PGL personnel used financial hedging instruments during its fiscal year 1999. PGL personnel did not use financial instruments during the instant reconciliation year. (Tr. 972-73).

Mr. Wear testified that PGL’s price protection programs insulated consumers from price volatility. Making physical purchases at forward prices produced a ”dampening effect” on gas price movement. Mr. Wear further testified that the purchases PGL 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.” (PGL Ex. B. at 8).

125

01-0707

b. PGL 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. (Tr. 1160). That exposure is affected by the quantity involved in the purchase. (Id.). He opined that utilities should have some coherent plan to lessen the effect of price risk. (Tr. 1163). 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 benefiting the financial health of a utility. (PGL Ex. H at 8).

PGL’s decision not to use financial hedging instruments “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. (PGL Ex. H 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 PGL 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. PGL’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). In 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, such as the City of Chicago, may be able to obtain their own hedges. (Id. at 29). Exposure to volatility is controllable, to a large degree, when there is an understanding of the costs and benefits of so doing. (Id. at 16-17).

126

01-0707

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. (PGL Ex. H 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. Mr. Graves reasoned that 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).

Mr. Graves noted that 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. In Mr. Graves’ view, both Mr. Herbert and Mr. Ross use “hindsight information” when advancing their proposed disallowances. (Id. at 16-17).

The increase in gas costs PGL passed on to consumers in the winter of 2000-2001 was unprecedented and unexpected. The peak daily price was more than six standard deviations over the average price.⁴⁸ This was an incredibly rare event, which occurred due a variety of facts, such as the surge in wholesale gas prices due to a decline in well production of gas, 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. In Mr. Graves’ opinion, the “California crisis” may have contributed to a general anxiety about future energy prices, which increased a willingness in the marketplace to pay high gas prices. Further, futures prices for gas were at very high levels for two to three years forward. Finally, at that time, electric companies began to use gas to generate electricity. (Id. at 27-29).

_____________________

⁴⁸ The standard deviation Mr. Graves used is $1.26 per MMBtu and it is for a 10year period. It is based on data that includes a high-price period. (PGL Ex. H at 26).

127

01-0707

PGL has “significant storage resources,” which provided a hedge-like benefit to consumers. Any exposure consumers faced was not due to negligence on the part of PGL. Rather, it was due to the Commission’s decision not to require financial hedging and the lack of any process identifying when hedging might be desired. (Id. at 22-23).

Mr. Graves critiqued City and CUB witnesses Mssrs. Herbert and Ross’ proposed disallowance for PGL’s hedging practices during the reconciliation year. Hedging gas purchases made in the summer months would reduce summer volatility. There was good reason to believe that summer prices in 2001 would be high and volatile, due to the “California crisis.” Thus, Mr. Graves reasoned that, by excluding summer hedging, both Mr. Herbert and Mr. Ross created after-the-fact programs tailored to construct their disallowances. (PGL Ex. L at 30). If Mr. Herbert and Mr. Ross had included summer hedges in their recommended disallowances, their proposals would have been dramatically lower. (Id.).

c. CUB Expert Witness Mr. Ross’ Testimony

The opinions contained in this section of the order reflect those of Mr. Ross unless otherwise noted. CUB witness Mr. Ross, Principal with CRP Planning Inc., considered PGL’s management decisions regarding price volatility and he evaluated whether PGL personnel took reasonable steps in the face of known risks and market conditions. He noted that PGL has faced price volatility in the past. Previously, during the winter of 1996-97, PGL faced extreme price volatility in the gas markets. That winter revealed both the magnitude of the price risk from volatility that PGL could face, and the extent to which PGL’s PGA customers are exposed to the volatility and price risk on 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. PGL considered managing price risk in a study conducted in 1998, but ultimately declined to adopt that hedging strategy. (CUB Ex 1.00 at 6, 7).

PGL 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 hedging instruments and the use of fixed-prices. Other forms of hedging include storing gas. (Id. at 4-5,10-11). In the past, PGL affiliates have hedged against price risk. PGL’s parent company, PEC, invested in gas and oil fields by using swaps and options. (Id. at 4-5,10-11).

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

128

01-0707

Also, PGL personnel did not care to protect consumers from price risk, as PGL 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 PGL 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)

PGL 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. PGL made no attempt to use fixed price contracts or to hedge against the risk of price volatility. PGL 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, PGL’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 PGL 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 the months of May through September.⁴⁹ Mr. Ross focused on PGL’s firm supply gas, because it is the gas purchased by PGL through pre-negotiated gas supply contracts for which a gas supplier guarantees delivery. Most of PGL’s winter firm supply is composed of PGL’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).

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

PGL personnel had sufficient knowledge, understanding, and experience with price risk, and had a demonstrated capability to address price risk, yet its personnel chose only to protect shareholders, not customers, from price volatility. (CUB Ex 3.00 at 10, 12).

_____________________

⁴⁹ 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).

129

01-0707

PGL’s witnesses Zack and Graves completely ignored their own research and hedging design. Prior to the reconciliation year, PGL identified both hedging standards and a hedging program designed to mitigate some gas supply price risk pursuant to its Gas Price Protection Plan. In the reconciliation year PGL’s parent implemented a set of price risk management standards to protect shareholders. PGL, however, chose to disregard its research and standards when considering price risk for customers. (Id. at 19).

Twenty percent of PGL’s winter volume is a minimum standard that the Commission should consider, given PGL’s decision to hedge nothing on behalf of consumers during the time period in question. Twenty percent of winter gas purchases were also a reasonable hedging standard at that time for a utility beginning to address price risk. (Id. at 20-21). Mr. Ross stated that he did not need to consider the summer months because PGL had an active price risk hedging program at that time. (CUB Ex 3.00 at 22). Mr. Ross’ strategy focused on the volatility of firm gas supply and a minimum level of hedging, while Mr. Herbert did not determine a minimum standard. (CUB Ex. 3.00 at 23-26).

The Commission is not responsible for the fact that PGL’s customers did not receive the benefit of a reasonable standard of care. The Commission has repeatedly stated that prudence is defined by the reasonable standard of care, and that PGL has the responsibility for understanding and applying a reasonable standard of care. PGL personnel had sufficient information and understanding of hedging strategies, yet they deliberately chose not to do so for PGL’s customers. Simultaneously, however, PGL personnel protected its shareholders from price risk. (CUB Ex 3.00 at 26-27).

Mr. Ross calculated how futures purchase could have mitigated price volatility and price risk for two levels of gas purchases. The first is based on gas supply purchased under firm contracts for the winter heating months (November through March). The second is based on all gas purchases (firm and spot market purchases). The results for the total winter purchase scenario were $85,602,220 hedging total purchases and $53,166,127 hedging 20% of PGL’s winter purchases. The greatest level he used was 14,144,512 MMBtus, using only winter months. In his opinion, this is the minimum prudent volume that PGL should have used to hedge. Based on 20% of PGL’s total supply, he concluded that consumers overpaid $53,166,127 during the reconciliation year, due to PGL’s failure to mitigate higher prices. (Id. at 17, 21).

d. City Expert Witness Mr. Herbert’s Testimony

The opinions contained in this section of the order are those of City witness Mr. Herbert unless otherwise noted. Mr. Herbert evaluated PGL’s supply and risk management practices during the reconciliation period. He considered PGL’s risk management knowledge and capabilities, price volatility, and the information relied upon by PGL personnel during this period. He reviewed PGL’s gas supply management practices focusing on the following: the market conditions during the 2000-2001 winter heating season; how great the natural gas price risk was to ratepayers during this period; the safeguards that were available to PGL to reduce the price risk; the exposure for its regulated customers; PGL personnel’s awareness of the gas commodity price risk; what PGL did to address this risk; and whether it was possible to reduce the price risk exposure during the 2000-2001 winter heating season. (City Ex. 1.0 at 4-5).

130

01-0707

Mr. Herbert concluded that during the winter of 2000-2001, there were obvious indicators that prices were high and volatile and that storage quantities were low. Based on the available information at the time it was evident that, without some action to protect consumers, the PGA would place consumers at a risk of paying higher prices. PGL failed to take any action, based on the market conditions, to protect consumers from exposure to price risk. In fact, PGL personnel did nothing to fix or cap the price of gas for even the minimum amount of gas that its customers would pay. Consumers were harmed as a result of PGL’s decision not to hedge, as they would have benefited had PGL initiated a conservative price risk management program. Based on what PGL personnel should have known, consumers would have saved approximately $230 million. Consumers should not be compelled to pay for the cost consequences of PGL’s lack of prudent risk management. Mr. Herbert recommended that the Commission adjust PGL’s allowed costs to exclude $230 million of the more than $600 million in increased operating revenues PGL received when gas prices spiked in the reconciliation period. (City Ex. 1.0 at 6-7).

PGL had ample notice that these price risks could occur. In the natural gas market, risks surfaced in the 1980’s when daily and monthly market prices of gas were less than the price of gas in many long-term, take-or-pay contracts. Since short-term contracts provided more flexibility and options, gas companies became more dependent and a greater dependency meant more price volatility for utilities. By 1990, the risk was so great that NYMEX developed a natural gas futures contract market. In 2000, NYMEX gas futures became one of the largest regulated commodity markets in the world. Commodity future contracts allow buyers to moderate their exposure to price risk, so they can focus on other parts of their businesses. This allows companies to fix prices themselves for their customers for some period of time in the future. (Id. at 9-12).

However, a futures contract is only one method of managing exposure to price risk. As the use of forward contract markets have matured, more sophisticated methods for managing price risks developed. Markets have since developed for paper contracts, including futures, swaps and option contracts, which are increasingly used. Paper contracts are used as temporary substitutes for the actual commodity. Paper contracts manage price risk where delivery of the commodity is expected. By doing this, a company can fix the price for a portion of its purchases or sales of the commodity, no matter how the physical market prices change. (Id. at 11-13).

This process can break down or fail to fix prices for two reasons. A mismatch can occur between the physical and financial market volumes. If a utility over-projects the need for the commodity, there is a mismatch between utilities’ need and futures contract. The second reason for a hedge to fail is when there is a difference between the financial market and the cash market price at the point of delivery, or basis. If a change in the spot price where a utility purchases its gas is not highly correlated with the futures price in the financials market, exposure to price risk may not be completely eliminated. (Id. at 13-15).

131

01-0707

The difference between a futures and an option is that while a futures contract allows a utility to fix the price of gas for a future time period, an option allows the utility company to put a cap on a price. The futures market requires a futures buyer to put a down payment on the futures position and to increase the size of that down payment, if price declines. An option contract purchases for a fixed price, with no down payment. (Id. at 15-16).The event here would be a rise in the market price to a level that exceeds the price established by the option, or the “strike price.” If the price in the market exceeds the strike price, the option-holder could execute the contract and receive the gas at the strike price; or, the option-holder could sell the option and apply the gains from the sale to the cost of gas purchased at the market price. (Id. at 17-19).

In liquid markets, as the gas futures and options markets usually are, these price and risk management arrangements can usually be made at little cost to the participants. There are administrative and transactional costs and costs associated with maintaining the margin for futures contracts or for selling an option contract. For PGL, that had a service contract with Enron, the cost of fixing the price would be an ordinary business expense. Hedging is not a guarantee of lower prices. But, the cost of assuring that customer costs are less volatile over time is insignificant, compared with the potential size of the price rises, from which, consumers will have been insulated. When the weather is cold, sometimes prices rise dramatically. (Id. at 22-23).

Price volatility is quantitative measure of price risk. It is an indication of the likelihood of price changes of a certain magnitude over a period of time. It is the standard deviation concept. The greater the risk, the more important it is that a utility take action to mitigate the price risk exposure to its customers. Price volatility measures are very important because they allow us to understand what to expect in terms of potential price changes in future prices. These measures also determine the value or cost of hedging instruments in financial derivatives markets. (Id.).

The precise magnitude of the price increases in the 2000-2001 winter heating season may have been a surprise but because actual volatility was high, it should have been obvious to PGL personnel that the prices changed significantly. Given the information available at the time, Mr. Herbert concluded that it was prudent to moderate the possible impact of such volatility on customer bills for the heating season. During the reconciliation period, an estimate of price volatility could be obtained from “Gas Daily” or daily and monthly spot prices can be used to estimate price volatility. The price risk that is associated with natural gas is greater than with other commodities, often 45% or greater, in the winter heating season. Because the volatility of the gas prices makes customers’ bills volatile, it is critical to use price risk management tools. Also, almost 80% of a customer’s bill is based on the cost of the commodity. (Id. at 22-25).

Supply managers must be aware of the price risks on PGL’s largest input purchases, irrespective of whether PGL is able to pass-through the cost. This is true because customers have very a limited ability to protect themselves against price risk or price volatility. (Id.).

132

01-0707

PGL personnel were very familiar with concepts such as commodity futures and option markets, as well as hedging strategies. In 1998, PGL proposed the elimination of its PGA, recommending fixing prices for consumers through hedging. When PGL initiated its RFQ for this endeavor, PGL stated therein that it was interested in finding a company that was especially knowledgeable about price risk management to aid it in supply management. Despite the understanding of PGL personnel of futures market and risk management as a safeguard for regulated service customers, PGL left those customers completely exposed. Mr. Herbert noted that hedges were used to reduce price risks for PGL’s unregulated affiliates. (City Ex. 1.0 at 40).

At the same time as PGL’s decision not to cap prices for its ratepayers, PGL’s parent company was proactive in protecting company revenues by purchasing weather derivatives, resulting in caps on possible revenue loss to the utility due to weather-related declines in heating fuel. This protected shareholders, but not ratepaying consumers. (Id.).

There was a blatant disparity of interest between the risks taken between shareholders and ratepaying consumers. Additionally, other regulated utilities used fixed-price forward contracts during the winter heating season of 2000-2001, as this is a common practice. Mr. Herbert added that most analysts were aware that market conditions were tentative in the winter of 2000-2001. Prices were on the incline, supply was limited, and prices were inelastic, in addition to record high gas prices. (City Ex. 1.0 at 28).

Mr. Herbert additionally averred that what PGL did in its previous reconciliation period has no relevance here because the situation here is different from the year before. Even if price volatility had stayed the same, the price of gas was higher in this reconciliation period. (City Ex. 1.0 at 33).

He testified to what prudent risk management strategies were that a gas utility should provide for the benefit of its regulated customer. This includes a minimum assured level of demand to reduce exposure to price risk. Gas can be effectively hedged, because utility personnel know the minimum amount of gas that will be needed each month. When there is a significant price risk, it is imprudent not to hedge. The minimum requirement level must be established by reviewing all weather conditions. (Id. at 35-37). Customers could suffer an opportunity cost, if prices go down, even if hedging is prudent. However, such a loss would be relatively insignificant. Additionally, over time, the opportunity costs would be less than the savings from hedging. (Id. at 41-42).

A prudent utility company would include in its risk management program reviews of hedges for gas purchases at the Chicago and Gulf markets, regular estimates of price volatility in market analysis, storage, financial hedges to manage price risk, and a way to monitor customer feedback. Mr. Herbert advocated for the need to match physical volumes to be purchased with volumes covered by the hedge and testified that PGL personnel were aware that this was necessary for a hedge to be effective. (Id. at 44).

133

01-0707

Additionally PGL could have used stored gas as a hedge for its regulated customers. Despite the fact that PGL claimed to use its stored gas to hedge for its regulated customers the evidence points to the contrary. There is no portion of stored gas set aside for PGL’s regulated service customers. Also, PGL relied on gas in storage and index-priced gas for its regulated customers, which is very unpredictable. Further, there is nothing to suggest that regulated customers received any price risk mitigation for gas in storage. Had PGL used the gas in storage as a hedge, the weighted average cost of gas would have been less than the index cost of gas during the heating season for consumers. The result is that, had PGL purchased all of its gas requirements at the index price, which is generally higher, regulated customers would have been better off. (Id. at 44-46).

Also, there are ways to quantify the extent to which PGL’s failure to act harmed its regulated customers. Mr. Herbert suggested calculating the difference between PGL’s actual costs and the costs, had PGL hedged. There is a significant differential between actual costs and hedged costs, which resulted in the increase of consumer costs during that 2000-2001 winter heating season. (Id. at 47-49). Mr. Herbert cited PGL’s “Gas Supply Protection Strategy,” which predicted a gas shortage in 2000 and outlined the appropriate gas quantity to be hedged. (City Ex. 2.0 at 8-9). He also cited PGL witnesses who stated that Commission pre-approval is not required for hedging. Mr. Herbert clarified that his position is that PGL was imprudent for doing absolutely nothing at all, despite the market predictors and conditions. (Id. at 11-12).

Mr. Herbert also testified as to how he calculated the harm done to PGL’s customers. Based on information provided by PGL, he calculated an appropriate objective hedging response. Damages themselves work retrospectively, as they are an attempt to cure harm already done to customers. (City Ex. 2.0 at 17-18).

Hedging is not necessarily about minimizing the cost of the commodity over time. Rather, hedging is about reducing the bills of regulated customers. This affords customers the ability to pay their gas bills and pay for food, medicine, and like items. (Id. at 22).

He also took issue with Mr. Graves’ assertion that the year prior to one at issue was not significantly volatile; therefore, there was no reason to hedge. A utility company must constantly look at all of the market indicators. Solid hedging decisions must be based on a “combination of overall patterns.” A company should not “cherry-pick” time periods and must look at extremes of both price and volume volatility.

(Id. at 32-33).

Mr. Herbert disagreed with Mr. Graves’ opinion that all hedging positions start in April. Mr. Herbert recommended that hedging be done at random intervals, in the time period from April through October, as that is the time period when injections and plans for the heating season are made. (City Ex. 2.0 at 26). The heating season must be of primary focus to an LDC like PGL. This is due to the likelihood of price spikes during the heating season because of increased demand. Mr. Herbert could think of no natural gas utility company which used its gas in storage as a hedge for requirements of regulated customers during the summer months. (Id. at 27-28).

134

01-0707

The objective of hedging is not to speculate on future price levels. Based on Mr. Graves’ own exhibits, Mr. Herbert concluded that PGL personnel were aware that price curves were generally moving upward, sometimes, significantly. This should have triggered some sort of price risk management action. Even if PGL personnel were solely looking at price levels, as PGL contends, the skewed distribution of gas prices should have prompted caution and alerted them to the need for hedging. (Id. at 32-33).

Mr. Herbert took issue with Mr. Graves’ contention that his testimony is speculative about what could have or should have been done. Mr. Herbert averred his recommendation to match hedged volumes with the expected minimum requirements of regulated customers is supported by his professional experience. Mr. Herbert stated that he took storage into account, but PGL did not designate a portion of its gas storage for consumer use. Also, due to PGL’s method for calculating LIFO pricing, the price of withdrawn gas changed constantly during the winter of 2000-2001. PGL’s use of storage during this time period did not provide any hedging benefit for consumers. PGL’s use of storage for services like “park and loans” reduced PGL’s capability to use storage as a hedge for consumers. Also, consumers paid approximately $10 million more than they would have if PGL had simply bought gas on the higher-priced daily spot market. (City Ex. 2.0 at 36-37). Mr. Wear’s $130 million estimate of savings through storage is simply the estimated nets of the costs of withdrawal and injection volumes. It ignores the effects of PGL’s LIFO pricing on consumers. (Id. at 38-40).

2. Conclusions of Law

PGL’s Position

PGL argues that because the Commission has never required a utility to use financial hedging instruments, it cannot find its level of hedging imprudent here. Also, PGL points out that Dr. Rearden testified that PGL’s level of hedging for the reconciliation period was not imprudently low. And, Dr. Rearden never stated that PGL’s level of hedging from October through March of the reconciliation period was imprudent. (PGL Init. Brief at 32-33; PGL Reply Brief at 63).

PGL also argues that because PEC is not regulated, whether PEC uses financial hedging instruments is not germane here. PGL points out that, if the Commission were to determine that a program using financial hedging instruments was imprudent, cost recovery could be disallowed, which is not the case for PEC. PGL maintains that during the time period in question, 20 out of 49 U.S. LDCs did not use financial hedging instruments.

PGL asserts that the extreme run-up on gas prices that occurred during the winter of 2000-2001 was unprecedented and unpredictable. It reasons that it could not have known whether hedging would produce desirable results. PGL could not, therefore, have known whether it would win or lose using financial hedging instruments. (PGL. Init. Brief at 39-42). PGL also avers that how much volatility is unacceptable to consumers must be determined in advance. Thus, PGL contends that it could not have known how much of its gas purchases it should hedge. (Id. at 39).

135

01-0707

PGL maintains that futures contracts would not have aided it because, in most months before February of 2001, futures prices were expected to drop. This is true because futures prices are generally lower in the months that are further forward. (PGL Init. Brief at 40-41). PGL states that it withdrew more gas in total in the five winter months than it did the year before. PGL does not state how much of these withdrawals were actually used for consumers. (PGL Init. Brief at 43).

PGL avers that, when asserting that it should have a hedging program, the GCI witnesses did not take PGL’s use of storage into account, as its use of storage saved $130 million for consumers in the winter of the reconciliation period. And, after the winter, PGL saved consumers money through its price risk program. (PGL Reply Brief at 61). Also, the GCI do not understand how storage is reflected in the gas charge through the LIFO rate. If summer replacement prices are lower than winter withdrawal prices, storage provides an effective hedge because consumers only pay the actual gas costs. (Id. at 63).

On Exceptions, PGL argues that because the Commission issued orders in its 1997 reconciliation case, Docket No. 97-0024, only a few months before it had to decide whether to use and begin purchasing financial hedges for the 2000-2001 winter, it had no obligation or responsibility to use financial tools to mitigate price volatility. (PGL BOE at 7-8).

GCI’s Position

The GCI assert that PGL was imprudent in failing to have in place an effective hedging program and in choosing to hedge none of its assured minimum purchases. Mr. Ross’ recommended minimum disallowance is in the amount of $53,166,177, which represents a 20% hedge of winter gas purchases. Mr. Herbert recommended a disallowance of $229,984,352, which is 100% of the minimum amount of gas PGL would need in the winter, irrespective of weather or market conditions. Mr. Herbert’s recommendation was based on his computation of the difference, on a monthly basis, between unhedged prices PGL paid for gas and the price PGL would have paid using Mr. Herbert’s hedging strategy. (GCI Init. Brief at 93).

Both Mr. Herbert and Mr. Ross examined the circumstances at pertinent times, what options were available to PGL and its capabilities. Both experts concluded that because almost 95% of the gas charges PGL collected were attributable to commodity costs, consumers’ bills were almost as volatile as gas prices were in the winter of 2000-2001. Also, there was a 13% rise in gas price volatility over the previous year.

Additionally, at the beginning of the winter heating season, the amount of gas PGL had in storage was very low. Because the supply of gas was tight at that time, PGL left consumers fully exposed to market risks. Both experts concluded that PGL failed to have in place any effective price risk management plan. The GCI maintain that, while PGL manages price risk when PGL itself is exposed to this risk, it merely passes this risk on to consumers in the PGA. (Id. at 83-85). The GCI assert that the only difference between the opinions of these two experts is in the calculation of harm to consumers. (GCI Reply Brief at 69-71).

136

01-0707

The GCI point out that in the Order commencing this docket, the Commission expressly required PGL to describe the measures it took to insulate the PGA from volatility, including any hedging strategies. The GCI opine that prudence requires PGL to have and follow a well-defined price risk management program. Price risk was significant during the time period in question. However, according to the GCI, during the reconciliation period, PGL did not have a functioning price risk management plan during the winter of the reconciliation period. (GCI Init. Brief at 77-79).

The GCI aver that PGL had two price risk management programs in effect during the reconciliation period. The first plan was never used and the second plan did not become effective until April of 2001, after the winter heating season. The GCI reason that therefore, consumers had no protection from price volatility in the winter, when they needed it most. (Id. at 81-82).

The GCI further contend that it is not disputed that PGL personnel had the knowledge and ability to hedge the price risk exposure. Price volatility can be quantified and managed. Yet, PGL declined every option available to it, from fixed priced contracts for future delivery to standardized paper contracts and financial derivatives.

The GCI further contend that, during the time period in question, PGL’s use of storage did not provide consumers with a price hedge. If PGL had merely purchased gas on the spot market, instead of making the gas purchases it made, consumers would have paid about $10 million less for gas. (PGL Reply Brief at 71).

The GCI assert that PGL’s pricing mechanism for gas withdrawn from storage precludes any hedging potential from storage. PGL does not set the price consumers will pay for the gas it injects gas into storage; it sets the consumer price when the gas is withdrawn form storage. PGL uses a LIFO-based pricing mechanism that incorporates year-to-date actual costs and estimated prices for purchases throughout the remainder of the year; thus, prices for customers are never fixed in advance. They aver that any potential price benefit from stored gas purchased at a low price in the preceding injection season is excluded from a LIFO calculation, which uses actual and estimated reconciliation period purchase costs starting over on the first of October every year. (GCI Init. Brief at 85). According to the GCI, Mr. Wear’s calculation of $130 million saved due to storage is nothing of the sort, as it is netted monthly injections and withdrawal volumes and costs using PGL’s average market prices. (PGL Ex. F at 58; Tr. 986-97).

PGL averred that it did not use financial hedging instruments due to a lack of Commission guidance on the subject. The GCI maintain that the evidence indicates otherwise. Before the reconciliation period, (PGL’s 1999 fiscal year) PGL hedged using financial instruments and it did not seek Commission approval before doing so. Also, the Commission did not disallow any portion of this hedged gas supply. (GCI Init. Brief at 87-88),

The GCI disagree with Staff’s contention that PGL’s hedging efforts for the reconciliation period were not imprudent. Because the winter months are the period of maximum price exposure, initiating a hedging program after those months, here in April of 2001, could not outweigh the actual exposure of the high demand portion of the reconciliation period. (Id. at 90-91).

137

01-0707

The GCI point out that Staff admitted that PGL’s level of hedging for October of 2000 through March of 2001 was imprudent. (Id. at 90-92, citing Tr. 1310-12). According to the GCI, Dr. Rearden’s statement cited by PGL, that PGL’s level of hedging was not imprudently low, lacks context. Dr. Rearden looked at the entire reconciliation year, including the spring of 2001, when PGL initiated a hedging program. PGL, however, did not hedge until this time, as its personnel did not utilize PGL’s previous hedging program. In the preceding winter, when consumers would have needed a hedging program the most, there was nothing. And, Dr. Rearden did not view PGL’s level of hedging for the winter of the reconciliation period as prudent. (GCI Reply Brief at 62-63).

The GCI aver that PGL cannot rely on past Commission decisions to support its claim that what it did in the reconciliation period was prudent because the facts in this case are unique. The facts in previous Commission cases are different from those in other Commission cases. In PGL’s previous reconciliation, Ill. Commerce Commission, on its own Motion, v. Peoples Gas Light and Coke Co., Reconciliation of Revenues Collected under Fuel and Gas Adjustment Charges with Actual Costs, 203 Ill. P.U.C Lexis 822, the Commission concluded that it would not create an unconditional obligation to use financial hedging instruments. The GCI point out that, in the previous reconciliation, the Commission neither encouraged nor discouraged financial hedging, as doing so is micro-managing utility operations by dictating what form price risk management must take. (GCI Reply Brief at 67).

With regard to determining consumer tolerance for risk, the GCI assert that it was PGL’s responsibility to make this assessment. According to the GCI, during the winter of the time period in question, PGL decided that no hedging was necessary, which in effect, was a determination that consumers had an unlimited tolerance for price risk. The GCI further take issue with PGL’s assertion that unregulated companies like PEC are not comparable to regulated utilities. They assert that, in fact, regulated companies lack the economic incentive to control PGA costs. (Id. at 71-74).

c. Staff’s Position

Staff witness Dr. Rearden opined that PGL’s level of use of financial hedging instruments, for the entire reconciliation year, was not imprudently low. Hedging does not always lower prices. He reasoned that hedging can only be evaluated with respect to the appetite for risk that consumers have. In his opinion, consumers’ well-being may not be optimized by hedging programs, even when those programs produce lower costs. (Staff Ex. 7.00 at 74). Dr. Rearden pointed out that, for the reconciliation period in question, PGL lost when it did not hedge with financial instruments. In another year, however, PGL might not lose. If prices or volatility was predictable, futures prices would reflect that predictability and hedging would hold few benefits. (Id. at 75). However, in Dr. Rearden’s opinion, PGL’s level of hedging for the winter of 2000-2001 was imprudently low. (Tr. 1312-13).

138

01-0707

d. Commission Analysis and Conclusions

In addition to procuring a good price for gas, there generally are two ways that a utility like PGL can mitigate the effect of higher prices in the marketplace on its PGA customers. PGL 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.

We agree with Staff’s position and conclude that PGL’s use of financial hedging instruments, for the entire year, was not imprudently low. While Dr. Rearden testified that PGL’s level of hedging for the winter of 2000-2001 was imprudent, we are unable to accurately quantify a disallowance that would reflect the difference in costs to consumers had PGL used more aggressive hedging instruments.

IX. Further Observations on PGL’s Conduct

The Commission believes PGL’s actions during this reconciliation period move beyond mere imprudence to being egregious. PGL entangled itself in a clever corporate web with its parent company, its affiliates and Enron designed to use PGA assets, assets designated to serve PGL’s ratepayers, solely for the gain of the entities involved. At the center of this web lay enovate, a shell of a company that existed only as a rest stop for profits on their way to PEC/PERC and Enron’s coffers. PGL’s attempts to explain its involvement not only failed, but actually worked against it. PGL flouted the law and Commission rules, completely disregarded its duty to its PGA customers and jeopardized its credibility. Over the next few years, the Commission intends to closely scrutinize PGL through the audits agreed to in the Settlement Agreement and Addendum (discussed below) in hopes that its conduct during this reconciliation is an aberration.

The Commission notes that over four years have passed since this reconciliation proceeding commenced on November 7, 2001, for the October 1, 2000 through September 30, 2001, period in question. While the Commission believes that a proceeding’s duration must be congruent to due process assurance, we believe that PGL’s conduct, in exercising its due process rights, unnecessarily lengthened this proceeding.

Moreover, at various times, PGL was not completely responsive to intervener requests. Particularly stunning is that PGL, throughout initial discovery, denied the existence of vital information about its alleged affiliate business dealings and about the GPAA contract that later was revealed more fully in re-opened discovery. Were it not for the fact that a FERC database contained pertinent information about Enron’s relationship with PGL and PGL’s affiliates and that information —mined by Staff and the GCI from an avalanche of subsequently tendered paper and electronic documents—provided important details on those relationships, this Commission may never have fully ascertained the basis for and the extent of these agreements and transactions that conferred profits to PGL’s corporate parent, PEC, and to Enron NA at ratepayer’s expense.

139

01-0707

Further, PGL engaged in certain agreements and transactions with enovate and Enron MW that were designed to evade Commission detection. That PGL proceeded in these affiliate interest agreements and transactions without prior Commission approval is an astonishing disregard for and circumvention of the Public Utilities Act and Commission rules.

When viewing the record in its totality, the Commission finds that PGL’s conduct is not only imprudent, but it also is egregious. People’s Energy and Enron developed a strategic partnership that diverted revenues from the regulated utility PGL to its unregulated parent company, PEC, and its unregulated subsidiaries, along with Enron NA, with no corresponding benefit to PGA customers that PGL serves. This strategic partnership used PGL’s PGA assets—including gas, contract storage, and Manlove Field operations—and PGL performed transactions and engaged in activities with either enovate, Enron MW, or Enron NA that increased customer gas costs while increasing profits for PGL’s parent company, PEC. In sum and substance, revenues were diverted from ratepayers to Peoples Energy and the unregulated affiliates and to Enron. Those revenues should have gone to ratepayers as an offset to the gas costs that they were actually charged.

The Commission’s conclusion of PGL’s imprudent and egregious conduct is borne out by substantial evidence in seven areas as follows: One, Letters of Intent to create enovate, LLC, the vehicle by which PEC garnered profits from using PGL’s assets, and to enter into the GPAA, a five-year, no-bid contract for 66 percent of PGL’s gas supply; two, the GPAA’s contract provisions that ceded control over gas price and quantity (SIQ and DIQ) to Enron NA, forced customers to pay twice the pipeline transportation of gas to the Chicago citygate, and released pipeline capacity to Enron NA that increased consumer gas costs; three, the enovate, Enron MW, and HUB transaction profit sharing arrangements that were designed to increase revenues flowing to unregulated utility affiliates derived from PGA assets; four, Manlove Field operations use that gave third-parties preferential access to Manlove Field, loans of stored gas meant for consumers, certain off-system loans and exchanges, which required PGL to purchase replacement gas at much higher prices all at ratepayers’ expense; five, the Trunkline Deal, an affiliated interest contract with enovate that used Enron MW as a buffer to avoid Commission detection and that unnecessarily raised PGA gas costs; six, Transaction 19, PGL’s sale of baseload gas to Enron NA and equal buy-back from Enron MW at high winter daily spot prices, that unnecessarily raised PGA gas costs, and seven, Transaction 103, the PGL agreement for delivery of a large amount of gas to Enron MW at the October first of month price in exchange for Enron MW paying a penalty PGL owed to the Pipeline, which unnecessarily raised PGA costs with no benefits conferred on consumers and allowed PEC to enjoy 50% of the profits because the applicable futures price was nearly double the pipeline penalty.

The Commission’s finding of imprudence is not the only result of PGL’s imprudent and egregious conduct during this reconciliation period. The Commission’s confidence in PGL’s management to be forthright and fair in serving ratepayer interests and in dealing with this Commission is shaken. The Commission believes that its regulatory compact with PGL, its presumption of good faith on the part of PGL’s management, and PGL’s overall integrity as a corporate citizen is severely damaged by the instant case.

140

01-0707

X. Other Issues

A. Audits

1. Staff’s Position

Staff believes an audit should be conducted of PGL’s management practices for several reasons. Staff points out that the internal audit of enovate stated that PEC gave enovate control over gas supply and storage functions. (Staff Ex. 9.00 Ex. E). PGL entered into oral contracts to govern certain transactions discussed in prior sections of this order, instead of written contracts. Additionally, PGL failed to keep proper business records. Staff argues that Transaction 16/22 is an example of the problem PGL had in failing to keep basic records. Transaction 16/22 was not recorded in PGL’s Gas Management System, where PGL must record and categorize all of its gas dealings. Transaction 16/22, according to Staff, demonstrates a lack of oversight and internal controls at PGL. Staff points to other examples of lack of internal controls. The evidence provided by PGL to Staff did not establish that many contracts generated full value for the services PGL provided. Additionally, PGL allowed third-parties to make withdrawals from Manlove, even after those parties no longer had gas in storage at Manlove.

Staff maintains that PGL has failed to maintain adequate documentation regarding many of its transactions, including the 3PSEs and Transaction 16/22. Further, PGL’s extensive use of Manlove for third-party transactions demonstrates a lack of management controls, as, when engaging in these contracts, PGL personnel locked up significant capacity at Manlove during peak periods, without regard to the impact those transactions had on consumers’ gas costs. Finally, Staff argues that PGL’s extensive dealings with Enron NA, Enron MW, and its affiliate, enovate, call into question the ability on the part of PGL personnel to separate the interest of PGL from that of its affiliates.

Staff concludes that a management audit of PGL’s gas purchasing practices, gas storage operations and storage activities should be performed by a Commission-approved, independent party. Staff also opines that the Commission should order PGL to conduct internal audits of its gas purchasing practices and report those results to the Manager of the Commission’s Accounting Department. (Staff Ex. 5.00 at 13-14).

Staff acknowledges that the new Sarbanes-Oxley Act requires companies to perform some sort of internal audit. However, if compliance with this Act would truly duplicate the internal audit that Staff seeks to impose, the only effort required by PGL would be to duplicate a Sarbanes-Oxley report and file it at the Commission. (Staff Ex. 5.00 at 14-15).

141

01-0707

Staff posits that an external management audit would be a forward-looking evaluation of the internal controls needed to ensure that ratepaying consumers are protected when PGL personnel make purchasing and storage decisions, like entering into gas supply contracts, allocating company-owned storage, leasing storage capacity and making decisions regarding injections and withdrawals to or from storage. An annual internal audit, on the other hand, would be a historical evaluation of transactions and compliance with internal controls established by the management audit. Staff concludes that annual internal audits are a necessary follow-up to a management audit. (See, Staff Ex. 10.00 at 2-3). Staff also posits that by requiring internal audits, the cost of investigating issues would be borne by PGL, as opposed to publicly-funded agencies, like the City, CUB and Commission Staff.

2. The Position of the GCI

The GCI concur with Staff. (GCI Initial Brief at 95-97).

3. PGL’s Position

PGL claims that since the time period in question, it has taken steps to improve its internal controls and therefore, no management audit is necessary. (PGL Ex. K at 14-15 and PGL Init. Brief at 101-02). PGL also concludes that compliance with recently-enacted Sarbanes-Oxley Act requires it to document and test the process it uses to create its financial statements. PGL cites no portion of this Act in support. It reasons that therefore, a second audit would be duplicative and costly. (PGL Init. Brief at 101-102).

PGL proposes to provide Staff information about its current gas supply and capacity procurement process and, if Staff wishes to initiate a proceeding, it can make the appropriate recommendations to the Commission. (PGL Ex. K at 14).

4. Commission Analysis and Conclusions

The Commission notes that the Peoples Companies agreed to include certain findings from the ALJPO in the Settlement Agreement and Addenduem that require a variety of audits similar to those proposed by Staff. PGL agreed to undertake these audits, therefore the Commission need not rule on this issue.

142

01-0707

B. Other Non-Monetary Issues

1. Compliance with the USOA

a. Staff’s Position

Staff argues that PGL should be required to issue a report as to how it intends to comply with the Uniform System of Accounts (the “USOA”). Staff points out that Commission Regulations require PGL to keep documentation supporting its decisions. PGL is also required by law to keep accurate accounts and records of all transactions with associated companies. (See, 83 Ill. Adm. Code 505.10; 18 CFR 201). However, during discovery, when Staff asked PGL for contracts, workpapers or calculations with respect to various transactions under the SOC and with enovate, such as “Rolling Thunder;” “Tidal Wave;” the “38 Millennium Special” Staff was advised that PGL had none. Staff posits that enovate’s actions are not outside the scope of this proceeding; enovate had a financial relationship with PGL that had an impact on PGL’s PGA costs and revenues. Yet, the records tendered regarding enovate were not complete.

Ms. Hathhorn opines that PGL merely took the word of personnel at Enron North America with regard to many transactions, which demonstrates a lack of controls in the accounting of gas and other transactions affecting the PGA. She recommends that this Commission order PGL to report as to how it intends to comply with the USOA. This report should be filed with the Commission’s Chief Clerk, with a copy to the Manager of the Commission’s Accounting Department within 60 days after the date of a final Order in this Docket. (See, Staff Ex. 9.00 at 24-27).

b. PGL’s Position

PGL does not agree with Staff’s contention on this issue, but it does not oppose the recommendation to file an explanation of steps it took to ensure compliance. (PGL Reply Brief at 71).

c. Commission Analysis and Conclusions

As Staff has pointed out, Commission regulations require PGL to have proof establishing the nature of its transactions. As has been set forth herein, this often was not accomplished here. Staff’s recommendation with regard to the USOA is merely requiring PGL to supply proof that its accounting is in compliance with the law. It is therefore adopted.

143

01-0707

2. Uncontested non-Monetary Issues

The following recommendations made by Staff are not contested by PGL:

Staff recommends that the Commission order PGL to update its operating agreement, which was last approved by the Commission in docket No. 55071. (Staff Ex. 5.00 at 20-22). On Exceptions, Staff points out that it recommended that PGL should be required to file this updated agreement within six months of the final order in this proceeding, and PGL did not object to this requirement. Also, since an operating agreement determines how costs and revenues should be allocated between the utility and its affiliates, an updated operating agreement should be on file before PGL files any new rate case. Therefore, Staff contends that PGL should be required to update its operating agreement within sixty days of the entry of a final order in this docket, or before it files its next rate case, whichever comes first. (Staff Init. BOE at 19)

Staff’s point is well-taken. PGL shall file its update to its operating agreement within sixty days of entry of the final order in this docket, or before it files its next rate case, whichever comes first.

Staff also recommends requiring PGL to account for all gas that is physically injected into the Manlove Storage 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). Staff further recommends that the Commission require PGL to account for the portion of gas injected into the Manlove Storage Field in order to maintain pressure (i.e., maintenance gas) as credits from Account 164.1, Gas Stored Underground, and as charges to Account 117, Gas Stored Underground (for the recoverable portion of cushion gas) or to Account 101, Gas Plant (for the non-recoverable portion of cushion gas). Staff additionally recommends that the Commission order PGL to 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. Finally, Staff recommends that the Commission order PGL to 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 a final order is entered in this proceeding. (Staff Ex. 10.00 at 7-9). The GCI share these recommendations. (GCI Init. Brief at 94).

These recommendations are reasonable and in the public interest and they are approved.

X. Finding and Ordering Paragraphs

(1)

The Peoples Gas Light and Coke 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 The Peoples Gas Light and Coke Company and of the subject-matter of this proceeding;

144

01-0707

(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)

the Settlement Agreement (Exhibit 1) as revised by the Addendum (Exhibit 2) is adopted and their terms incorporated herein as a resolution on the merits, finding that, during the reconciliation period, Peoples Gas Light and Coke Company had not acted reasonably and prudently in its purchases of natural gas and other activities that affected that amounts collected through Gas Charges in its fiscal year 2001;

(5)

the unamortized balances at the end of Peoples Gas Light and Coke Company’s 2001 reconciliation year show a refundable balance for the Commodity Gas Charge of $23,876,327.25; a recoverable balance of $2,969,282.01 for the Non-Commodity Gas Charge and the Demand Gas Charge; and a refundable balance of $23, 580.60 for the Transition Surcharge, for a total refundable balance of $20,930,626.44; the Factor O Refund is zero;

(6)

the reconciliations submitted by The Peoples Gas Light and Coke 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;

(7)

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. 01-0706, 02-0726, 02-0727, 03-0704, 03-0705, 04-0682, 04-0683;

(8)

The Peoples Gas Light and Coke Company should follow the accounting procedures recited above the directives contained in the incorporated parts of the Settlement Agreement and the Addendum in all future gas adjustment charge reconciliation dockets.

(9)

The Peoples Gas Light and Coke Company shall file quarterly reports with the Chief Clerk’s office detailing the progress of the Hardship Reconnection program.

IT IS HEREBY ORDERED that the reconciliation of revenues collected under the Peoples Gas Light and Coke 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 Peoples Gas Light and Coke Company shall comply with all of the Findings of this Order;

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.

145

01-0707

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

(SIGNED) CHARLES E. BOX

Chairman

EXHIBIT 1

SETTLEMENT AGREEMENT AND RELEASE

This Settlement Agreement and Release (“Agreement”) is entered into this 17 day of January, 2006, between and among the PEOPLE OF THE STATE OF ILLINOIS, through LISA MADIGAN, ILLINOIS ATTORNEY GENERAL (the “Illinois Attorney General”) and the CITY OF CHICAGO (the “City of Chicago”), PEOPLES ENERGY CORPORATION, an Illinois Corporation, THE PEOPLES GAS, LIGHT AND COKE COMPANY, an Illinois Corporation (“Peoples Gas”), PEOPLES MW, LLC., a Delaware Limited Liability Company, PEOPLES ENERGY RESOURCES COMPANY, LLC., an Illinois Limited Liability Company, and NORTH SHORE GAS COMPANY, an Illinois Corporation (“North Shore Gas”) (Peoples Energy Corporation, Peoples Gas, Peoples MW LLC, Peoples Energy Resources LLC and North Shore Gas are collectively hereinafter referred to as the “Peoples Companies,” unless otherwise designated individually).

WHEREAS, the Illinois Attorney General commenced an action against the Peoples Companies in the Circuit Court of Cook County, Illinois, County Division, Chancery Department, styled The People of the State of Illinois v. Peoples Energy Corp., et al., No. 05 CH 5124, and the City of Chicago commenced an action against the Peoples Companies in the Circuit Court of Cook County, Illinois, County Division, Chancery Department, styled City of Chicago v. The Peoples Gas Light & Coke Company, et al., No. 05 CH 5107, which two actions were consolidated (the “Litigation”);

WHEREAS, the Illinois Attorney General and the City of Chicago alleged that: (a) from 1999 to 2002, the Peoples Companies and Enron North America carried out a scheme to illegally divert assets from the regulated natural gas utility, Peoples Gas, to Peoples Energy Corporation and to inflate Peoples Gas’s and North Shore Gas’s natural gas costs and pass those inflated costs on to Illinois consumers; and (b) the Peoples Companies carried out this scheme through a series of fraudulent natural gas transactions, sham companies, illegal agreements, and misrepresentations to consumers. The Illinois Attorney General alleged that the Peoples Companies’ actions resulted in increased natural gas costs for Illinois consumers and violated the Illinois Consumer Fraud and Deceptive Business Practices Act (“Consumer Fraud Act”). (815 ILCS 505/1 et seq.). The City of Chicago alleged that the Peoples Companies’ actions resulted in increased natural gas costs for Chicago consumers and violated Municipal Code of Chicago Sections 4-276-470, 2-24-060 and 1-20-020. The Peoples Companies denied these allegations;

WHEREAS, in the Litigation (a) the Illinois Attorney General seeks equitable relief against the Peoples Companies, penalties against Peoples Gas and North Shore Gas, and disgorgement of profits from and penalties against Peoples Energy Corporation, Peoples Energy Resources Company, LLC and Peoples MW, LLC for the alleged violations of the Consumer Fraud Act, (b) the City of Chicago seeks equitable and compensatory relief and penalties from Peoples Gas, Peoples Energy Corporation, Peoples Energy Resources Company, LLC and Peoples MW, LLC for the alleged violations of Municipal Code of Chicago Sections 4-276-470, 2-24-060 and 1-20-020, and (c) the Peoples Companies deny that the Illinois Attorney General or the City of Chicago is entitled to any of the relief requested;

WHEREAS, there is also currently pending before the Illinois Commerce Commission (the “ICC”) statutory reconciliation proceedings for the years 2000 through 2004 involving Peoples Gas (ICC Docket Nos. 00-0720, 01-0707, 02-0727, 03-0705, 04-0683) and North Shore Gas (ICC Docket Nos. 00-0719, 01-0706, 02-0726, 03-0704, 04-0682) (the “Reconciliation Cases”);

WHEREAS, the City of Chicago and the Illinois Attorney General either have appeared or intervened in the Reconciliation Cases and alleged that Peoples Gas and North Shore Gas acted imprudently in purchasing natural gas and passed on imprudent gas costs resulting in unnecessarily increased gas charges to consumers in violation of Section 9-220(a) of the Illinois Public Utilities Act, 220 ILCS 5/9-22(a) and various ICC rules, and Peoples Gas and North Shore Gas have denied these allegations;

WHEREAS, the Peoples Companies, the Illinois Attorney General and the City of Chicago wish to fully adjust, compromise and settle all rights and claims they may have against each other by reason of the Litigation and the Reconciliation Cases; and

WHEREAS, this Agreement does not constitute an admission by or finding against the Peoples Companies that any of the conduct alleged in the Litigation and the Reconciliation Cases was wrongful, unlawful or in violation of any law, regulation or rule.

NOW THEREFORE, the Peoples Companies, the Illinois Attorney General and the City of Chicago agree as follows:

I.	CUSTOMER REFUND

A. Refund to Customers. Peoples Gas and North Shore Gas jointly agree to refund the total sum of $100 million to Peoples Gas’ and North Shore Gas’ customers in a manner consistent with the terms of this Agreement.

B. ICC Approval of Refund. The final settlement of the Reconciliation Cases is subject to approval by the ICC, which, as provided herein, other than the obligations contained in Sections III(B), IV and V, is a condition precedent to the terms of this Agreement.

C. Payment of Customer Refund. The Customer Refund shall be paid as follows:

By crediting, on a per capita basis, the bills of all North Shore Gas’ and Peoples Gas’ customers as follows: (a) a payment in the amount of $50 million that shall begin within 30 days following ICC approval of this Agreement (“First Payment”); and (b) a payment in the amount of $50 million that shall begin 12 months after the First Payment.

The refund amounts shall be clearly and conspicuously identified on all customers’ bills as a credit against current charges, in a manner acceptable to the Illinois Attorney General and the City of Chicago.

In the event that the ICC does not approve a per capita refund, the Customer Refund shall be paid by a method that is acceptable to the ICC, provided, however, that the Customer Refund is $100 million and is paid in two $50 million payments.

D. Parties Cooperation to Obtain ICC Approval. All parties to this Agreement shall take all necessary and commercially reasonable actions to obtain ICC approval of the settlement of the Reconciliation Cases including, within five business days of all parties’ execution of this Agreement, the filing of a motion before the ICC requesting expedited review and disposition and approval of the settlement of the Reconciliation Cases as described in this Agreement. Nothing in this Agreement is intended to limit in any way the ICC’s authority to review and determine whether to approve the settlement of the Reconciliation Cases.

E. ICC Approval. If the ICC fails to approve the settlement of all Reconciliation Cases, this Agreement (and all obligations and agreements contained herein) shall be null and void with the exception of those described in Sections III(B), IV and V of this Agreement. The Parties agree that in the event the ICC does not approve the $100 million refund amount or conditions contained in Sections I(C) of this Agreement, the Illinois Attorney General, the City of Chicago and the Peoples Companies are in no way limited or prevented from pursuing the Litigation or the Reconciliation Cases or from participating, reinstating or asserting any legal rights, allegations, defenses, counterclaims, cross claims, appeals or any other right or assertion allowed by law, statute or regulation and that the Litigation and the Reconciliation Cases continue status quo ante.

II. CONSERVATION AND WEATHERIZATION PROGRAM PAYMENTS

As described more fully below, Peoples Energy Corporation shall pay to the City of Chicago and the Illinois Attorney General, jointly, up to $5 million per year for six years totaling up to $30 million. All payments shall be made payable to the Illinois Attorney General and the City of Chicago, jointly, unless they mutually designate, in writing, payment in another way or to another party or parties. The payments shall be made as follows:

The first installment of up to $5 million (“First Installment”) shall be made within 15 business days after the ICC approves the settlement of the Reconciliation Cases. From the First Installment, the Peoples Companies shall receive a credit in the amount of $675,000 towards the settlement of the case styled The Peoples Gas Light and Coke Company v. City of Chicago (No. 03 L 2212 Cir. Ct. Cook County). The City of Chicago and Illinois Attorney General, jointly and in their discretion, shall determine the use and expenditure of the First Installment. The Illinois Attorney General shall use any payments that she controls for purposes specified under Section 7(e) of the Consumer Fraud Act, 815 ILCS 505/7(e).

Peoples Energy Corporation shall pay the five subsequent payments of up to $5 million, which amounts shall be prepaid, on each anniversary of the First Installment (the “Subsequent Payments”). The Subsequent Payments shall be based upon the amount of the cost for the design, implementation and administration of programs, as estimated in the sole discretion of the Illinois Attorney General and the City of Chicago (the “Estimated Amount”). The Estimated Amount shall be submitted by the Illinois Attorney General and the City of Chicago to Peoples Energy Corporation by written statements. The programs shall be for the following purposes:

To fund a program of conservation and weatherization for low and moderate-income residential dwellings (the “Program”). The Program shall be jointly administered by City of Chicago on behalf of the City of Chicago and Illinois Attorney General on behalf of the State of Illinois or by any other agency, entity or representative to which the Illinois Attorney General and City of Chicago, in writing, mutually agree. The Program shall have the purpose of providing energy and natural gas conservation programs, whether residential improvements or educational or otherwise, for residents within Peoples Gas’ or North Shore Gas’ service areas and shall have the goal of reducing those residents’ energy usage and costs.

Failure to use or expend $5 million in any year after the payment of the First Installment shall in no way affect the Illinois Attorney General’s or the City of Chicago’s ability to request and receive funding up to the maximum amount of $5 million in any subsequent year or, subject to the requirement of this Section II(B), in any way relieve the Peoples Energy Corporation of its obligations to make any of the Subsequent Payments.

III.

ADOPTION OF MANAGEMENT PROPOSALS

Peoples Gas and North Shore Gas will adopt the forward-looking “Management” proposals requested in the Joint Initial Briefs of the City of Chicago, the Illinois Attorney General and the Citizens Utility Board in ICC Docket Nos. 01-0706 and 01-0707.

A. These forward-looking “Management” proposals, the implementation of which is contingent upon ICC approval of the settlement of the Reconciliation Cases, are:

1.	Peoples Gas and North Shore Gas each shall update its operating agreement, which were approved by the ICC in Docket No. 55071.

2.	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.

Peoples Gas and North Shore Gas each 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 audit shall be independent of Peoples Gas, North Shore Gas and their affiliates, ICC Staff, the City of Chicago, the Illinois Attorney General and the Citizens Utility Board and shall be approved by the ICC. Peoples Gas and North Shore Gas shall submit monthly reports on the progress of the management audit to the Chief of the ICC’s Public Utilities Bureau, with a copy to the Manager of the ICC’s Accounting Department, until the management audit report has been submitted. Upon completion of the management audit, copies of the management audit report would be submitted to the Chief of the ICC’s Public Utilities Bureau and the Manager of the ICC’s Accounting Department.

Nothing in this Agreement shall require the Peoples Companies to conduct any management or financial audit of gas purchases or transactions for their 1999-2004 fiscal years. Peoples Energy Corporation acknowledges that it is its Board of Directors’ responsibility to set and implement policy. Peoples Energy Corporation further acknowledges that its Chief Executive Officer reports to its Board of Directors through its Lead Director. The acknowledgments contained in this Section III(B) do not require ICC approval of the settlement of the Reconciliation Cases.

IV.

RECONNECTION AND DEBT FORGIVENESS OF DISCONNECTED CUSTOMERS

A. Disconnected Customers. The Peoples Companies acknowledge that approximately 12,000 past customers of Peoples Gas and North Shore Gas are presently not receiving gas from the Peoples Companies (“Disconnected Customers”). Approximately $14 million of past due accounts are attributable to Disconnected Customers. Peoples Gas and North Shore Gas acknowledge that certain Disconnected Customers, involving customer-occupied residential premises, are hardship cases (the “Hardship Cases”). The Peoples Companies shall cooperate with the Illinois Attorney General and the City of Chicago and any other entity or agency designated by the Illinois Attorney General and the City of Chicago to identify the Hardship Cases.

B. Reconnection of Hardship Cases. Within three days following identification, Peoples Gas and North Shore Gas shall reconnect the Hardship Cases without charge. The Peoples Companies shall cooperate with the Illinois Attorney General and the City of Chicago and any other entity or agency designated by the Illinois Attorney General and the City of Chicago to identify the Hardship Cases. Peoples Gas and North Shore Gas shall relieve and forgive all outstanding debt of the Hardship Cases. The Hardship Cases may be identified by either the Peoples Companies or the Illinois Attorney General and the City of Chicago. Upon determination by and notice from the Illinois Attorney General or the City of Chicago, Peoples Gas and North Shore Gas will advise credit-reporting agencies to remove adverse credit information from the credit reports of the customers who are the Hardship Cases.

No Illinois Commerce Commission Approval. Upon execution of this Agreement by all of the parties, the Peoples Companies agree to fulfill the obligations described in this Section IV notwithstanding lack of ICC approval of the settlement of the Reconciliation Cases.

PROJECTED BAD DEBT

In addition to the obligations above, the Peoples Companies project absorbing, recording and, ultimately, writing off, approximately $52.3 million in bad debt resulting from accounts that its customers, for a variety of reasons, are unable to pay. If the Peoples Companies fail to absorb and record approximately $52.3 million in bad debt for the fiscal year ending September 30, 2006 (“FY2006”), the Peoples Companies agree to absorb and record at least the difference between $52.3 million and the amount actually absorbed and recorded in FY2006 during the fiscal year ending September 30, 2007 or in any subsequent fiscal year. To the extent that this bad debt relates to the Hardship Cases, Peoples Gas and North Shore Gas agree not to pursue collection of those past accounts, but without prejudice to the collection of further amounts incurred. The Hardship Cases may be identified by either the Peoples Companies or the Illinois Attorney General and the City of Chicago. Upon determination by and notice from the Illinois Attorney General or the City of Chicago, Peoples Gas and North Shore Gas will advise credit-reporting agencies to remove adverse credit information from the credit reports of the customers who are the Hardship Cases.

VI. MISCELLANEOUS

A. Effective Upon Execution. This Agreement shall be effective upon execution by all of the parties to the Agreement and may be executed in one or more counterparts.

Circuit Court Approval and Order Entered and Recorded. The Peoples Companies, the Illinois Attorney General and the City of Chicago shall seek judicial approval of this Agreement and the entry of an Agreed Order staying all proceedings in the Litigation until the ICC enters an order regarding the settlement of the Reconciliation Cases. This Agreement shall be included as an exhibit to any such Agreed Order. The parties to this Agreement shall take all necessary and commercially reasonable actions to obtain judicial approval of this Agreement. Failure to obtain such judicial approval shall make this Agreement null and void. In the event of failure to obtain judicial approval, the Peoples Companies, the Illinois Attorney General and the City of Chicago in no way are limited or prevented from pursuing the Litigation or the Reconciliation Cases or from participating, reinstating or asserting any legal rights, allegations defenses, counterclaims, cross claims, appeals or any other right or assertion allowed them by law, statute or regulation and that the Litigation and the Reconciliation Cases continue status quo ante. Upon entry of an order by the ICC approving the settlement of the Reconciliation Cases, the parties shall seek entry of a consent decree pursuant to 735 ILCS 5/2-1009 dismissing the Litigation with prejudice.

C. Jurisdiction. Notwithstanding the dismissal of the Litigation with prejudice, the Peoples Companies, the Illinois Attorney General and the City of Chicago agree that the Circuit Court of Cook County, Chancery Division, shall retain jurisdiction to interpret and enforce the terms of this Agreement.

Binding Agreement. This Agreement shall be binding upon, and its benefits shall inure to the Peoples Companies and their respective heirs, representatives, successors and assigns, as well as the respective representatives, successors and assigns of the Illinois Attorney General and the City of Chicago.

E. Mutual Release. In accordance with and completion of the terms herein, this Agreement is: (1) intended to release and discharge any and all claims that the Illinois Attorney General or the City of Chicago ever had, now have or claim or might have or claim against the Peoples Companies based upon, arising out of or relating to, in whole or in part, through the effective date of this Agreement, the Litigation, the Reconciliation Cases, and the subpoena served upon Peoples Energy Corporation by the Illinois Attorney General, dated August 25, 2005, and (2) is intended to release and discharge any and all claims that the Peoples Companies ever had, now have or claim or might have or claim against the Illinois Attorney General or the City of Chicago based upon, arising out of, or relating to, in whole or in part, through the effective date of this Agreement, the Litigation, the Reconciliation Cases and the subpoena served upon Peoples Energy Corporation by the Illinois Attorney General, dated August 25, 2005.

F. Entire Agreement. All understandings and agreements heretofore made between the parties are superseded by and merged into this Agreement, which alone fully and completely expresses the agreement between the parties relating to its subject matter, and the same is entered into with no party relying upon any statement or representation not embodied in this Agreement. Any modification of this Agreement may be made only by an instrument in writing signed by or on behalf of the party to be bound by such modification.

G. Severability. If any portion, clause, phrase or term of this Agreement is later determined by a court of law to be invalid or unenforceable, for whatever reason, the remaining provisions of this Agreement will remain valid and in effect as to the parties, and will be unaffected by said determination other than those portions which are agreed herein to be a condition precedent.

H. Authority to Enter Into the Agreement. The signatories below, except for the City of Chicago, acknowledge that they have the lawful authority to bind the parties for whom they are signing to the terms of this Agreement.

I. No Admission of Liability. Nothing in this Agreement, or any acts performed or documents executed in furtherance of this Agreement, shall constitute or may be used as an admission that any party to this Agreement is liable to any other party or of the validity of any allegation or claim or defense contained in the Litigation or the Reconciliation Cases.

J. Recitals. The recitals at the beginning of this Agreement are, and shall be construed to be, an integral part of this Agreement.

K. Headings and Interchangeability. The headings of sections contained in this Agreement are merely for convenience of reference and shall not affect the interpretation of any of the provisions of this Agreement. Whenever the context so requires, the singular shall include the plural and vice versa. All words and phrases shall be construed as masculine, feminine, or gender neutral, according to the context. This Agreement is deemed to have been drafted jointly by the parties and any uncertainty or ambiguity shall not be construed for or against any party as an attribution of drafting to such party.

L. Governing Law. This Agreement shall be governed by, construed and enforced in accordance with the laws of the State of Illinois without regard to the choice of law principles thereof.

IN WITNESS WHEREOF, the parties hereto have executed this Settlement Agreement and Release as of day and year above first written.

THE PEOPLE OF THE STATE OF ILLINOIS /s/ Paul J. Gaynor By: The Office of Illinois Attorney General	THE CITY OF CHICAGO By: /s/ Mara S. Georges Title: Corporation Counsel
THE PEOPLES COMPANIES (as defined in this Agreement) By: /s/ Theodore R. Tetzlaff Title: _____________________

SETTLEMENT AGREEMENT AND RELEASE

IN WITNESS WHEREOF, the CITIZENS UTILITY BOARD, by authorized signature herein, executes the Settlement Agreement entered into on January 17, 2006 between and among the PEOPLE OF THE STATE OF ILLINOIS, through LISA MADIGAN, ILLINOIS ATTORNEY GENERAL (the "Illinois Attorney General") and the CITY OF CHICAGO (the "City of Chicago"), PEOPLES ENERGY CORPORATION, an Illinois Corporation, THE PEOPLES GAS, LIGHT AND COKE COMPANY, an Illinois Corporation ("Peoples Gas"), PEOPLES MW, LLC., a Delaware Limited Liability Company, PEOPLES ENERGY RESOURCES COMPANY, LLC., an Illinois Limited Liability Company, and NORTH SHORE GAS COMPANY, an Illinois Corporation ("North Shore Gas") and agrees to be bound by all terms therein. A copy of said Settlement Agreement is attached hereto.

THE CITIZENS UTILITY BOARD

By: /s/ David Kolata

Title: Executive Director

Date: February 27, 2006

EXHIBIT 2

Settlement Agreement Amendment and Addendum

Page 1 of 7

Amendment and Addendum to January 17, 2006 Settlement

Agreement among and between Peoples Energy Corporation,

Peoples Gas Light and Coke Company, Peoples MW, LLC, Peoples

Energy Resources Company, LLC, North Shore Gas Company, the

City of Chicago, the State of Illinois and the Citizen’s Utility Board.

Pursuant to Section VI, F of the Settlement Agreement (“Settlement Agreement”) entered into on January 17, 2006 between and among the PEOPLE OF THE STATE OF ILLINOIS, through LISA MADIGAN, ILLINOIS ATTORNEY GENERAL (the “Illinois Attorney General”) and the CITY OF CHICAGO (the “City of Chicago”), PEOPLES ENERGY CORPORATION, an Illinois Corporation, THE PEOPLES GAS, LIGHT AND COKE COMPANY, an Illinois Corporation (“Peoples Gas”), PEOPLES MW, LLC., a Delaware Limited Liability Company, PEOPLES ENERGY RESOURCES COMPANY, LLC., an Illinois Limited Liability Company, and NORTH SHORE GAS COMPANY, an Illinois Corporation (“North Shore Gas”) (Peoples Energy Corporation, Peoples Gas, Peoples MW LLC, Peoples Energy Resources LLC and North Shore Gas are collectively hereinafter referred to as the “Peoples Companies,” unless otherwise designated individually), and entered into on February 27, 2006 by the CITIZEN’S UTILITY BOARD (“CUB”), This Amendment and Addendum is intended as an Agreement to Amend the Settlement Agreement as follows:.

This Amendment and Addendum is intended to comply with the requirements of the Settlement Agreement, Section VI, F, requiring all modifications to the Settlement Agreement to be in writing.

Other than as specifically stated below, this letter is not intended to modify or amend any terms of the January 17, 2006 Settlement Agreement.

In addition to, or where otherwise noted below in modification of, the terms of the January 17, 2006 Settlement Agreement, it is hereby agreed to by the Illinois Attorney General, the City of Chicago, CUB, and the Peoples Companies as follows:

Amendment Section A:

Peoples Gas and North Shore Gas’ future HUB Revenues:

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

Settlement Agreement Amendment and Addendum

Page 2 of 7

used in the 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 5/1-101 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 cases and rate cases filed by Peoples Gas and North Shore Gas.

Amendment Section B:

Peoples Gas and North Shore Gas’ HUB Revenues addressed in dockets 05-0748 and 05-0749 and in any fiscal year 2006 reconciliation cases regarding Peoples Gas’ and North Shore Gas’ Purchased Gas for the 2005/2006 Heating Season:

Peoples Gas and North Shore Gas and all Peoples Companies agree that they will not oppose an adjustment for the reconciliation years 2005 and 2006 based on HUB revenues that have not, to date, been used to offset consumer gas charges in those years.

Peoples Gas and North Shore Gas and all Peoples Companies will account for all 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) for fiscal year 2005 as offsets to the Gas Charge in accordance with 83 Ill. Admin. Code 525.40(d) and have agreed not to oppose any offset of PGA costs addressed in Dockets 05-0748 and 05-0749. Peoples Gas and North Shore Gas and all Peoples Companies also agree not to oppose any HUB revenue offset of PGA costs to be addressed in any purchased gas reconciliation case regarding Peoples Gas and North Shore Gas that address periods after fiscal year 2005 and prior to the effective date of new rates approved by the Illinois Commerce Commission in the rate cases that the utilities have announced they will file. For Dockets 05-0748 and 05-0749 Peoples Gas and North Shore Gas agree to re-file and amend any testimony filed in those dockets that is not consistent with this Amendment and Addendum.

Amendment Section C:

Peoples Companies’ Agreement to Findings 7, 8, 9, 11, 12, 14 and 15 of the ALJ Proposed Order Dated September 20, 2005:

Peoples Companies hereby agree to implement prospectively findings 7, 8, 9, 11, 12, and 14 of the Administrative Law Judge’s Proposed Order in Docket 01-0707, entered on September 20, 2005 (“ALJ’s Proposed Order”).

Settlement Agreement Amendment and Addendum

Page 3 of 7

Peoples Companies also agree to comply with finding 15 of the ALJ’s Proposed Order for the purpose of allowing the ICC to be able to consider fiscal years 1999-2004 in making prospective behavioral and other recommendations, but not to suggest any further monetary adjustments beyond the refunds included in the January 17, 2006 Settlement Agreement.

The relevant findings of the ALJ’s Proposed Order are attached as Exhibit A to this filing.

Amendment Section D:

Refund To Be Paid In Manner Ordered By the Illinois Commerce Commission:

As already provided in Section I, C, 3 of the January 17, 2006 Settlement Agreement, the Parties agree that the $100 million refund shall be paid by any method that is acceptable to the ICC.

Amendment Section E:

Interest To Be Paid On Refund Amounts:

Peoples Companies hereby agree to calculate interest on all refund payments made at the interest rate provided for in 83 Ill. Admin. Code Part 280.70(e)(1). Interest paid on refunds will be calculated prospectively from the date of the Illinois Commerce Commission order approving the Settlement Agreement until the refunds are paid.

Amendment Section F:

Peoples Companies agree to forgive all outstanding bad debt for Fiscal Years 2000 through 2005.

Peoples Companies agree to forgive all outstanding bad debt from fiscal years 2000-2005 existing at the time of the execution of this addendum. Bad debt shall be defined as those accounts which have been disconnected and on which no payment has been made for six months. Peoples Companies represent that this amount totals approximately $207 million and comprises over 250,000 customer accounts. Peoples Companies also represent that these amounts are currently in, or subject to, collection.

Settlement Agreement Amendment and Addendum

Page 4 of 7

For both the Hardship cases within the projected $52.3 million debt for fiscal year 2006 identified in the January 17,2006 Settlement Agreement Section V and the $207 million identified above, the Peoples Companies agree that they will not pursue, directly or indirectly, collection of these amounts from customers or use any forgiven amounts as a reason to deny gas service to any customer, and that they will communicate with the credit reporting agencies for each of these customers to remove the adverse credit effects of any reporting of these past due amounts and expunge this debt from consumers’ account records, relieving said consumers from the debt forever and always.

Amendment Section G:

Peoples Companies Not To Seek Recovery of Debt Write-Off or Forgiveness In Any Future Rate or Reconciliation Cases.

Peoples Companies hereby agree that they will not seek recovery in any future rate or reconciliation cases of any amounts of debt written-off or relieved under Sections IV and V of the January 17, 2006 Settlement Agreement. Peoples Companies hereby agree that they will not seek recovery in any future rate or reconciliation cases of any amounts of debt written-off or relieved under Section F of this Amendment and Addendum. This agreement does not affect the ability of Peoples Companies to recover any future bad debt as specifically authorized by the ICC now or in the future. Peoples Companies hereby agree that they will not seek recovery in any future rate or reconciliation cases of any amounts associated with the Conservation and Weatherization Program described in Section II of the January 17, 2006 Settlement Agreement.

Amendment Section H:

Peoples Companies agree to permanently enact the hardship reconnection program described in Section IV of the January 17, 2006 Settlement Agreement.

Settlement Agreement Amendment and Addendum

Page 5 of 7

IN WITNESS WHEREOF, the parties hereto have executed this Amendment to the Settlement Agreement and Release on March 6, 2006.

THE PEOPLE OF THE STATE OF ILLINOIS

/s/ David Adams, Assistant Attorney General

By: The Office of Illinois Attorney General

THE CITY OF CHICAGO

By: /s/ Mara S. Georges

Title: Corporation Counsel

THE CITIZEN’S UTILITY BOARD

By: /s/ David Kolata

Title: Executive Director

THE PEOPLES COMPANIES (as defined in this letter above)

By: /s/ Theodore R. Tetzlaff

Title: General Counsel

Settlement Agreement Amendment and Addendum

Page 6 of 7

Exhibit A to Settlement Agreement Amendment and Addendum

(7)

Peoples Gas Light and Coke Company shall update its operating agreement, which was approved by this Commission in Docket No. 55071;

(8)

(9)

* * *

(11)

(12)

* * *

(14)

(15)

Settlement Agreement Amendment and Addendum

Page 7 of 7

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;

ALJ Proposed Order at 135-136.

Peoples Energy Inactive 8-KEntry into a Material Definitive Agreement