ITEM 1. BUSINESS
General The Columbia Gas System, Inc. (the Corporation) organized under the laws of the State of Delaware on September 30, 1926, is a registered holding company under the Public Utility Holding Company Act of 1935, as amended, (1935 Act) and derives substantially all its revenues and earnings from the operating results of its 19 direct subsidiaries. On July 31, 1991, the Corporation and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions for protection under Chapter 11 of the Federal Bankruptcy Code. Both the Corporation and Columbia Transmission are debtors-in-possession under the Bankruptcy Code and continue to operate their businesses in the normal course subject to the jurisdiction of the United States Bankruptcy Court for the District of Delaware. The Corporation owns all of the securities of its subsidiaries except for approximately 10 percent of the stock in Columbia LNG Corporation. The Corporation's subsidiaries are engaged in exploration for and production of oil and natural gas, natural gas transmission, natural gas distribution and other energy operations. In addition, Columbia Gas System Service Corporation provides data processing, financial, accounting, legal and other services for the Corporation and other affiliates. The Corporation and its subsidiaries are sometimes referred to herein as the System.
Oil and Gas Operations The Corporation's oil and gas subsidiaries, Columbia Gas Development Corporation and Columbia Natural Resources, Inc., explore for, develop, produce, and market oil and natural gas in the United States. These companies hold interests in more than two million net acres of gas and oil leases and have proved oil and gas reserves in excess of 750 billion cubic feet of gas equivalent.
Operations are focused in the Appalachian, Arkoma, Michigan, Permian, Powder River and Williston basins; both onshore and offshore in the Gulf Coast areas of Texas and Louisiana, and in Utah and California. Offshore holdings include interests in federal blocks, most of which are located in the West Cameron, Vermilion, Eugene Island, and Ship Shoal areas of the Gulf of Mexico.
Transmission Operations The Corporation's two interstate pipeline transmission companies, Columbia Transmission and Columbia Gulf Transmission Company (Columbia Gulf), operate a 23,700-mile pipeline network that extends from offshore in the Gulf of Mexico to New York State and the eastern seaboard. In addition, Columbia Transmission operates one of the nation's largest underground storage systems.
Historically, Columbia Transmission offered both a wholesale sales service and a transportation service to local distribution companies. However, when a new federally mandated business restructuring of the industry took effect in late 1993, Columbia Transmission expanded its transportation and storage services for local distribution companies and industrial and commercial customers and now provides only a minimal sales service. Columbia Gulf's pipeline system, which extends from offshore Louisiana to West Virginia, carries a major portion of the gas delivered by Columbia Transmission. It also transports gas for third parties within the production areas of the Gulf Coast. Columbia Gulf owns interests in the Overthrust, Ozark and Trailblazer pipelines, which extend into major midcontinent and western gas-producing areas. Combined, Columbia Transmission and Columbia Gulf serve customers in 15 northeastern, middle Atlantic, midwestern, and southern states and the District of Columbia.
Columbia LNG Corporation has announced plans to initiate peaking services from its Cove Point LNG facility by the end of 1995.
Distribution Operations The Corporation's five distribution subsidiaries provide natural gas service to more than 1.9 million residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia, Kentucky, and Maryland. These subsidiaries purchase gas supplies to serve their high-priority customers and transport gas for industrial and commercial customers who purchase gas from other sources. More than 28,000 miles of distribution pipelines serve such major
ITEM 1. BUSINESS (Continued)
markets as Columbus, Lorain, Parma, Springfield, and Toledo in Ohio; Gettysburg, York and a part of Pittsburgh in Pennsylvania; Lynchburg, Staunton, Portsmouth and Richmond suburbs in Virginia; Ashland, Frankfort and Lexington in Kentucky; and Cumberland and Hagerstown in Maryland.
Other Energy Operations The Corporation's TriStar Ventures Corporation participates in natural gas-fueled cogeneration projects that produce both electricity and useful thermal energy.
Two subsidiaries, Columbia Propane Corporation and Commonwealth Propane, Inc., sell propane at wholesale and retail to approximately 68,000 customers in six states.
In the Appalachian area, Columbia Coal Gasification Corporation another subsidiary owns over 500 million tons of coal reserves, much of which contains less than one percent sulfur. Approximately 50 percent of the total reserves are leased to other companies for development.
Columbia Energy Services oversees the System's nonregulated natural gas marketing efforts and provides an array of supply and fuel management services to distribution companies, independent power producers and other large end users both on and off the transmission and distribution subsidiaries' pipeline systems.
Columbia Gas System Service Corporation provides centralized, cost-efficient data processing, financial, accounting, legal, and other services for the Corporation and other operating subsidiaries.
For additional discussion of the System's business segments, including financial information for the last three fiscal years, see Item 7, page 19 through 52 and Note 16 on page 93 of Item 8.
Other Relevant Business Information The System's customer base is broadly diversified, with no single customer accounting for a significant portion of sales or transportation revenues.
The Corporation's operating subsidiaries are subject to competitive pressures from other pipeline systems and producers that sell and/or transport natural gas as well as from competition from alternative fuels, primarily oil and electricity. The oil and gas subsidiaries compete in the marketplace for sales of their oil and gas production through a combination of long-term contracts and spot sales. The transportation subsidiaries compete in the highly competitive northeast and midwest energy markets. The distribution subsidiaries compete with alternative fuels and to a limited extent with other gas companies.
Certain subsidiaries file reports with various federal agencies containing estimates of company-owned oil and gas reserves. These estimates are generally consistent but not always comparable to those reported in the 1993 Annual Report to Shareholders.
At January 31, 1994, the System had 10,114 full-time employees of which 2,089 are subject to collective bargaining agreements.
Information relating to environmental matters is detailed in Item 7 pages 33 through 34, page 41 and page 46 and in Item 8, Note 12H on pages 87 through 91.
For a listing of the subsidiaries of the Corporation and their lines of business refer to Exhibit 22.
Public Utility Holding Company Act of 1935 The Corporation and its subsidiaries are subject, in certain matters, to the jurisdiction of the Securities and Exchange Commission (SEC) under the 1935 Act. In 1944, the SEC held that the major portions of the System complied with the requirements of Section 11 of the 1935 Act relating to a "single integrated public-utility system" and businesses reasonably incidental thereto, but the SEC reserved jurisdiction over the retainability of certain subsidiaries.
ITEM 1. BUSINESS (Continued)
Included were two companies owning pipelines in West Virginia and Northern Virginia extending into Maryland and New York (the reserved pipelines are now part of Columbia Transmission) and Virginia Gas Distribution Corporation (now a part of Commonwealth Gas Services, Inc.). Since that time, the reservation of jurisdiction has been expanded to include the subsequently acquired properties of Blue Ridge Gas Company (a Virginia retail company which is now part of Commonwealth Gas Services, Inc.), Commonwealth Gas Pipeline Corporation (now a part of Columbia Transmission) and a retail subsidiary (Commonwealth Gas Services, Inc.) acquired as a result of the merger of the Corporation with Commonwealth Natural Resources, Inc. and Lynchburg Gas Company, (now a part of Commonwealth Gas Services, Inc.).
The Corporation filed a motion with the SEC in June 1955 requesting the termination of such reserved jurisdiction. After hearings, no further action has been taken and the Corporation is unable to predict whether or when the SEC will finally dispose of the Corporation's 1955 motion and resolve the retainability issue.
The Gas Related Activities Act (GRAA), enacted in 1990, provides that gas transmission is deemed to be reasonably incidental or economically necessary or appropriate to the operation of the gas utility system under Section 11 of the 1935 Act. Since the basis for questioning the retainability of the gas transmission pipelines was compliance with this Section 11 criteria, the passage of the GRAA supports, and should resolve, the retainability of the gas transmission pipelines.
If however, any of these properties were ultimately to be held not retainable, management believes that the SEC would permit the Corporation to adopt a plan for orderly disposition which would permit full realization of their intrinsic values.
ITEM 2.
ITEM 2. PROPERTIES
Information relating to properties of subsidiary companies is detailed on pages 6 through 7 herein and pages 96 through 99 of Item 8 under Note 18. The System also owns coal interests in the Appalachian area. Assets under lien and other guarantees are described on page 86 in Note 12E of Item 8.
Neither the Corporation nor any subsidiary knows of material defects in the title to any real properties of the subsidiaries of the Corporation or of any material adverse claim of any right, title, or interest therein, pending or contemplated except the Official Committee of Unsecured Creditors of Columbia Transmission has filed a complaint which challenges the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. as an alleged fraudulent transfer. Substantially all of Columbia Transmission's property has been pledged to the Corporation as security for First Mortgage Bonds issued by Columbia Transmission to the Corporation which has also been challenged by the Official Committee of Unsecured Creditors of Columbia Transmission.
ITEM 2. PROPERTIES (Continued)
OIL AND GAS DATA
Acreage - At December 31, 1993
Net Wells Completed - 12 Months Ended December 31
Productive and Drilling Wells - At December 31, 1993
(a) Includes 17 net horizontal wells in 1993, 13 net horizontal wells in 1992 and 14 net horizontal wells in 1991. (b) Includes 808 multiple completion gas wells and 8 multiple completion oil wells, all of which are included as single wells in the table. Also includes 46 gross productive horizontal wells.
ITEM 2. PROPERTIES (Continued)
GAS PROPERTIES OF SUBSIDIARIES - AS OF DECEMBER 31, 1993
NOTE: This table excludes minor gas properties and all construction work in progress. The titles to the real properties of the subsidiaries of the Corporation have not been examined for the purpose of this document. Neither the Corporation nor any subsidiary knows of material defects in the title to any of the real properties of the subsidiaries of the Corporation or of any material adverse claim of any right, title, or interest therein, pending or contemplated except the Official Committee of Unsecured Creditors of Columbia Transmission has filed a complaint which challenges the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. as an alleged fraudulent transfer. Substantially all of Columbia Transmission's property has been pledged to the Corporation as security for First Mortgage Bonds issued by Columbia Transmission to the Corporation which has also been challenged by the Official Committee of Unsecured Creditors of Columbia Transmission
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
I. Shareholder Class Actions and Derivative Suits (Unless otherwise noted, all matters are stayed pursuant to Section 362 of the Bankruptcy Code)
Since the June 19, 1991 announcement by the Board of Directors regarding the Corporation's proposed charge to second quarter earnings and suspension of its dividend, seventeen complaints including suits purporting to be class actions, or alleging claims common to the purported class actions, have been filed in the U.S. District Court for the District of Delaware. These actions have been consolidated under the style In re Columbia Gas Securities Litigation, Consol. C.A. No. 91-357. Although an amended and consolidated complaint has yet to be filed, the preconsolidated complaints variously named the Corporation, then current members of its Board of Directors, certain officers, the Corporation's independent public accountants, and the Corporation's underwriters for its 1990 common stock offering as defendants (the Defendants).
These complaints generally allege the Defendants publicly made material misleading statements during the relevant class periods (from February 28, 1990 to June 19, 1991) concerning the Corporation's financial condition, and failed to disclose material facts which rendered other statements misleading, thereby artificially inflating the market price of the Corporation's common stock and publicly traded debt securities, causing the various plaintiffs and other class members to purchase such publicly traded securities at artificially inflated prices. The complaints allege violations of Sections 11, 12(2) and 15 of the Securities Act of 1933, Sections 10(b), 20(a) and Rule 10b-5 of the Securities Exchange Act of 1934, negligent misrepresentations, and common law fraud and deceit.
In addition to the above-referenced class actions, three derivative stockholder actions have been filed in the Court of Chancery of the State of Delaware. These cases have been consolidated under the style In Re Columbia Gas Derivative Litigation. The complaints in these actions name as defendants the Board of Directors and the Corporation (nominal). The complaints generally allege that the members of the Board of Directors breached their fiduciary duties to the Corporation by failing to make required disclosures thereby causing the Corporation to be subjected to federal securities law liabilities.
II. Bankruptcy Matters
A. Matters in the United States Bankruptcy Court for the District of Delaware
1. Columbia Gas Transmission Corporation v. The Columbia Gas System, Inc. and Columbia Natural Resources, Inc., C.A. No. 92-35. (U.S. Bankruptcy Ct. Dist. of Delaware, filed March 18, 1992). The Official Committee of Unsecured Creditors of Columbia Transmission filed a complaint (the Intercompany Complaint) challenging the status of approximately $1.7 billion of debt owed by Columbia Transmission to the Corporation and the transfer of natural resource properties representing 450 billion cubic feet of natural gas reserves and one million barrels of oil reserves to Columbia Natural Resources, Inc. (Columbia Natural Resources) as well as other intercompany transactions.
On May 14, 1992, the Official Committee of Unsecured Creditors of Columbia Transmission filed a motion to withdraw the jurisdictional reference to the U.S. District Court for the District of Delaware and filed a demand for a jury trial. On February 9, 1993, the motion was denied by the U. S. District Court and on August 20, 1993, the Third Circuit denied the appeal by the Official Committee of Unsecured Creditors of Columbia Transmission of the District Court's order allowing resolution of the Intercompany Complaint before the Bankruptcy Court.
On June 11, 1992 the Corporation filed a motion and supporting brief for partial dismissal or, in the alternative partial summary judgment with respect to certain counts of the complaint which was supported by Columbia's Equity Security Holders Committee and Unsecured Creditors Committee. The motion has been fully briefed and a pretrial schedule has been established which, if followed, would result in a trial of the Intercompany
ITEM 3. LEGAL PROCEEDINGS (Continued)
Complaint in the spring of 1994. There has been no indication as to when the Bankruptcy Court might act on Columbia's motion for summary judgment.
2. Motion to Fix Procedures to Establish Columbia Transmission's Liability to Third Party Beneficiary Investor Complaints. On February 17, 1993, movants, who are investors in production companies and claim to be third party beneficiaries of the contracts between Columbia Transmission and the production companies, filed a motion seeking to have their status as third party beneficiaries recognized and seeking to have their claims against Columbia Transmission liquidated separate from the Estimation Procedure established to deal with producer claims. By order dated April 5, 1993, the Bankruptcy Court lifted the stay in order to allow the New Jersey State Court to determine whether plaintiffs enjoyed third party beneficiary status in the pending State Court action. However, the Bankruptcy Court with movants' acquiescence, held that movants' claim (to the extent that they are established) would be governed by the estimation procedure.
3. Bank of Boston, Trustee v. The Columbia Gas System, Inc. On March 2, 1993, the Trustee for the Indenture under which debentures were issued by the Employees Thrift Plan of Columbia Gas System (Plan) filed a complaint against the Corporation alleging tortious interference with contract and breach of duty. The Indenture Trustee alleges that the Corporation is not acting in accordance with the Plan when it directs the Plan Trustee to use sums paid by participating employers to match employee contributions and not to pay debt service on the outstanding debentures. The Corporation's Answer to the complaint alleging tortious interference with contract for failure to pay installments due LESOP debenture holders was filed April 2, 1993. On May 14, 1993, the Corporation filed a motion for summary judgment challenging the Bank's standing to bring the action. Bank of Boston filed its brief in opposition to the Corporation's motion on June 14, 1993 and the Corporation's reply brief was filed on June 29, 1993. Bank of Boston filed an amended adversary complaint on June 30, 1993.
B. Appeals to the United States Court of Appeals for the Third Circuit
1. Enterprise Energy Corporation, et al., v. United States of America, on behalf of its Internal Revenue Service On June 18, 1991, the U.S. District Court for the Southern District of Ohio approved a settlement of this class action suit by Appalachian oil and gas producers. The settlement required Columbia Transmission to make two $15 million payments into escrow, for distribution to class members as formal contract amendments were finalized. The first $15 million was paid into escrow in March 1991.
Columbia Transmission filed an application with the Bankruptcy Court which would permit it to honor the settlement (including authority to make the second $15 million payment into escrow in March 1992) but to reject the amended contracts. On December 12, 1991, the Bankruptcy Court ruled that distribution from escrow of the first $15 million payment could be effected pursuant to the settlement; however, the Bankruptcy Court denied Columbia Transmission's request for approval to make the second $15 million payment scheduled to be made in March 1992. Further, the Bankruptcy Court granted the motion to reject the contracts, as amended, pursuant to the Enterprise settlement.
On October 6, 1992, the District Court affirmed the Bankruptcy Court's order denying Columbia Transmission's motion to assume the executory settlement contract. Enterprise Energy Corp.'s request for rehearing, reargument and reconsideration of the order denying Columbia Transmission's motion to assume the executory settlement contract was denied on April 27, 1993. On May 25, 1993, Enterprise Energy filed a notice of appeal to the United States Court of Appeals for the Third Circuit from the Bankruptcy Court order denying Columbia Transmission's motion to require assumption or rejection of the executory settlement contract. Briefing is complete. Oral argument was held January 18, 1993.
2. In re The Columbia Gas System, Inc. et al.; West Virginia State Department of Taxation v. U.S., Nos. 93-7531 and 93-7532. This is the appeal of the District Court's Memorandum Opinion and Order affirming
ITEM 3. LEGAL PROCEEDINGS (Continued)
the Bankruptcy Court's ruling that the property taxes centrally assessed by West Virginia as public service business taxes for the "1992 tax year" were incurred by Columbia Transmission prepetition and denying Columbia Transmission's motion for authorization to pay the taxes. Briefing has been completed and oral argument was heard on March 2, 1994.
3. The Columbia Gas System, Inc. and Columbia Gas Transmission v. U.S. Trustee, No. 93-7609. On August 30, 1993, the Corporation and Columbia Transmission filed an Appeal of the District Court's order adopting the Magistrate's Report and Recommendation and granting the U.S. Trustee's appeal of the Bankruptcy Court's July 31, 1993 order approving certain investment guidelines and the Bankruptcy Court's order denying the U.S. Trustee's Motion for Reconsideration of the Bankruptcy Court's July 31, 1993 order. On February 10, 1994, the District Court granted a stay pending appeal of the August 19, 1993 order which approved the Magistrate's Report and Recommendation.
III. Purchase and Production Matters (Unless otherwise noted, all matters are stayed pursuant to Section 362 of the Bankruptcy Code)
A. Appalachian Producer Litigation
1. Enterprise Energy Corp. et al. v. Columbia Gas Transmission Corp., C. A. No. C2-85-1209, (U. S. Dist. Ct., S. D. Ohio, filed July 26, 1985). See II B. 1.
2. Phillips Production Co. v. Columbia Gas Transmission Corp., C.A. No. 89-0269, (U.S. Dist. Ct., W.D. Pa. filed February 7, 1989). The complaint as filed contained six separate counts involving ten gas purchase contracts with Columbia Transmission. Plaintiff's principal claims were for additional take-or-pay payments, for retroactive tight sands gas pricing, and a challenge to Columbia Transmission's invocation of cost recovery clauses in the gas purchase contracts. All claims except those relating to Columbia Transmission's invocation of the cost recovery clause were settled and dismissed December 18, 1989, pursuant to agreement of the parties. The cost recovery claim was stayed pending resolution of Enterprise Energy suit (discussed above). Thereafter, Phillips cost recovery claim was stayed by Columbia Transmission's filing.
3. Columbia Gas Transmission Corp. v. Alamco, Inc. et al., C.A. No. 88-C-38-2 (Harrison (W.Va) Cir. Ct. filed January 15, 1988). Under a 1983 release agreement, Columbia Transmission filed suit against Alamco, Inc. (Alamco) contending that Alamco was obligated to sell gas to Columbia Transmission at prices and under terms and conditions being generally offered by Columbia Transmission at the time purchases were resumed as opposed to the conditions of the original contract. Trial of the state court action was interrupted and stayed by Columbia Transmission's petition in Bankruptcy filed July 31, 1991. A parallel suit was filed by Alamco, naming the Corporation, Columbia Transmission, Columbia Gas System Service Corporation and Commonwealth Gas Pipeline Corporation, alleging antitrust violations. In the opinion of counsel, the antitrust claim was barred by the statute of limitations; however on March 13, 1991, Columbia Transmission's and Commonwealth Gas Pipeline's motions to dismiss were denied without prejudice to Columbia Transmission's right to assert, by summary judgment or otherwise, that Alamco's claims are time barred, or that Alamco cannot prove the allegations in its complaint.
In late May 1992, a settlement agreement in principle was reached which was approved by the Bankruptcy Court on July 28, 1992. As a result, after the order becomes final, these actions will be dismissed upon the earlier of confirmation of a Columbia Transmission plan of reorganization or closing of the Columbia Transmission bankruptcy proceeding.
B. Southwest Producer Litigation (Suits naming Columbia Transmission are stayed as to Columbia Transmission; indemnification agreements will be effective if the contract providing indemnification is not rejected)
ITEM 3. LEGAL PROCEEDINGS (Continued)
1. Royalty Owners Litigation: The agreements between Columbia Transmission and certain southwest producers effective in 1985 which reformed gas purchase contracts have resulted in a number of lawsuits against the producers. Under the agreements, Columbia Transmission has a qualified obligation to indemnify the producers in certain instances against claims by their royalty owners.
Certain suits were pending against Amoco Production Company for which it was seeking indemnification from Columbia Transmission as of the commencement of Columbia Transmission's proceeding in bankruptcy. In November 1993, Columbia Transmission and Amoco entered an agreement, subject to Bankruptcy Court approval, terminating the contracts and providing that Amoco shall have an allowed unsecured claim for $4.1 million for all royalty indemnification and excess royalty claims.
New Ulm and Fox v. Mobil Oil Corporation, Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-655 (155th Judicial Dist. Ct. of Austin County, TX). New Ulm alleged Columbia Transmission incorrectly paid for gas on the basis of Columbia Transmission's market-out price rather than the higher price New Ulm claimed was available to it under the contracts.
After the Bankruptcy Court entered an order modifying the automatic stay provisions of the Bankruptcy Code, jury trial began on June 22, 1992, and concluded with a verdict against Columbia Transmission on July 2, 1992, in the amount of approximately $5.6 million, including interest. On July 30, 1992, the Court denied Columbia Transmission's motion for judgment notwithstanding the jury's verdict and entered judgment against Columbia Transmission in such amount for actual damages, prejudgment interest and attorneys' fees. Columbia Transmission's motion for new trial was denied on October 12, 1992. Columbia Transmission has perfected an appeal to the First Court of Appeals at Houston, Texas. Briefing is complete and oral argument was held on December 7, 1993.
2. Wagner & Brown v. Columbia Gas Transmission Corp., C.A. No. 83-15091 (Orleans Parish (La.) Civ. Dist. Ct.). This suit involves Columbia Transmission's alleged breach of a gas purchase and sales agreement. The claims of Wagner & Brown have been settled, and the case was dismissed as to Wagner & Brown on March 6, 1986. The claims of El Paso Exploration Co. (now Meridian Oil Production, Inc. (Meridian)), which intervened as a plaintiff and asserted all the claims and allegations made by Wagner & Brown, including take-or-pay, price differential and specific performance, have not been settled. In September 1990, Meridian served a Second Amended Petition in which it alleges damages in excess of $60 million (and an additional $40 million of interest) as a result of Columbia Transmission's failure to meet its take-or-pay and minimum take obligations. The issue of price differential has been settled. A status conference was held May 28, 1991, and a hearing on the plaintiff's motion for partial summary judgment on Columbia Transmission's legal defenses was held June 14, 1991.
A motion by Meridian for a Bankruptcy Court order lifting the automatic stay so as to permit it to prosecute its claims against Columbia Transmission was denied.
3. Koch Industries Inc. v. Columbia Gas Transmission Corp. C.A. No. 89-2156 (U.S. Dist. Ct., E.D. La., filed May 12, 1989). On January 11, 1991, Columbia Transmission filed an action, Columbia Gas Transmission Corp. v. Koch Industries. Inc., C.A. No. 91-0174, (U.S. Dist. Ct., E.D. La). This lawsuit was related to the settlement of an earlier lawsuit between the parties. Columbia Transmission sought an order declaring that it is under no obligation to increase its purchase nominations under the contracts because of Koch's unasserted right to correct imbalances between it and other working interests owners in the acreage dedicated under the contract. Koch filed a complaint seeking a contrary determination. Koch Industries, Inc. v. Columbia Gas Transmission Corp., C.A. No. 91-0177 (U.S. Dist. Ct. E.D. La). The two cases were consolidated. Judgment in favor of Koch Industries, Inc. and against Columbia Transmission was issued on April 29, 1991. Columbia Transmission's motion to alter or amend the judgment was denied on June 5, 1991. On June 19, 1991, Columbia Transmission filed a Notice of Appeal to the Fifth Circuit. On August 20, 1991, the Clerk of the Court advised
ITEM 3. LEGAL PROCEEDINGS (Continued)
Columbia Transmission that the case was stayed during the Chapter 11 Bankruptcy proceedings.
4. Energy Development Corp. v. Columbia Gas Transmission Corp., C.A. No. CV91-0960, (U.S. Dist. Ct., W. D., La., division Lafayette/Opelousas, filed May 13, 1991). Energy Development Corporation alleges that Columbia Transmission breached the take-or-pay, minimum daily quantity and inequitable withdrawal provisions of the gas purchase contract between Energy Development Corporation and Columbia Transmission.
IV. Corporate Matters
1. The East Lynn Condemnation - United States v. 16.286.08 Acres et al., C.A. No. 77-3324H (U. S. Dist. Ct., S.D. W.Va. filed December 26, 1976). The United States Corps of Engineers condemned certain fee lands in Wayne County, West Virginia. On December 7, 1990, a United States District Judge issued an order which adjudicates the amount of just compensation Columbia Natural Resources was entitled to receive for the minerals taken, including interest on the award through October 31, 1990, at $44,830,148. In October 1991, checks totalling $52,254,883 were issued to Columbia Transmission (holder of letter to the property when the condemnation proceeding commenced), Columbia Natural Resources (current owner) and the attorneys in the condemnation proceeding. To allow immediate deposit, the checks were endorsed to Columbia Transmission. Columbia Natural Resources and Columbia Transmission believe that a constructive trust in favor of Columbia Natural Resources, the real party in interest, was created; however, this view may be subject to challenge in Columbia Transmission's bankruptcy proceeding.
V. Regulatory Matters
A. Take-or-Pay and Contract Reformation Costs Billed by Pipeline Suppliers
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-41, appeals pending sub nom., Baltimore Gas & Electric Co. v. FERC, C.A. No. 88-1779 U.S. Ct. of App., D.C. Cir.) On February 3, 1992, FERC denied requests for rehearing of orders accepting Columbia Transmission's Order No. 528 flowthrough filings, except to the extent that customers may challenge Columbia Transmission's prudence for actions after April 1, 1987, to the extent that it contributed to these upstream pipeline charges. On March 19, 1993 the FERC issued an order denying requests for rehearing and permitting Columbia Transmission to flow through upstream pipeline Order No. 528 costs. On December 30, 1993, the FERC issued an order denying Cincinnati Gas & Electric Company's request for rehearing of the March 19, 1993 order, reaffirmed the February 3, 1992 and March 19, 1993 orders in all respects, and indicated that no further rehearing requests would be entertained. The Court issued a procedural order in the joint appeals, leading to oral argument on May 10, 1994.
2. AGD v. FERC, No. 88-1385 (U.S. Ct. of App., D.C. Cir.). On December 28, 1989, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the deficiency-based direct billing of Order No. 500 costs approved by the FERC in Tennessee Gas Pipeline Co., No. RP86-119, is unlawful retroactive ratemaking and violates the filed rate doctrine. On October 9, 1990, the U.S. Supreme Court denied certiorari in AGD. Accordingly, the FERC issued its order on remand on November 1, 1990 (Order No. 528).
The FERC has approved Order No. 528 settlements for some of Columbia Transmission's pipeline suppliers. However, there are remaining unresolved direct upstream pipeline supplier Order No. 528 proceedings.
The Order No. 528 filings and settlements to date have reduced Columbia Transmission's Order No. 528 liability to upstream pipelines significantly. Columbia Transmission's customers continue to challenge its right to recover any of these amounts.
B. Direct Billing of Past Period Production and Production-Related Costs
ITEM 3. LEGAL PROCEEDINGS (Continued)
1. Columbia Gas Transmission Corp. v. FERC., C.A. No. 88-1701 (U.S. Ct. of App., D.C. Circuit). On February 9, 1990, the Court issued its opinion finding that the FERC's orders authorizing five of Columbia Transmission's upstream pipeline suppliers to directly bill past period production related costs (Order Nos. 94 and 473) to customers allocated based upon past period purchases violates the filed rate doctrine and the rule against retroactive ratemaking. Therefore, the Court struck the orders authorizing direct billing and remanded the issue to the FERC for further proceedings. On October 9, 1990, the U.S. Supreme Court denied certiorari.
Columbia Transmission reached settlements with Panhandle, Trunkline, Texas Eastern and Texas Gas, which provided for full refunds of Order No. 94 direct billings with rebillings to Columbia Transmission of lesser amounts. These settlements would reduce Columbia Transmission's Order No. 94 direct billing liability to these pipelines from $29 million to $17 million exclusive of interest. Columbia Transmission's customers have objected to those settlements because they contemplate Columbia Transmission's recovery of these rebilled amounts from its customers. On February 10, 1993, the FERC approved Columbia Transmission's Order 94 settlement with four pipeline suppliers, which settlements authorized Columbia Transmission to recover the rebilled payments to its' customers.
On October 28, 1993, Transco and Columbia Transmission filed a letter with the FERC indicating that the remaining issues have been resolved, and that they agreed on a refund to Columbia Transmission of $1.4 million. The FERC is treating this as a settlement offer.
On January 12, 1994, the FERC issued an order on rehearing in which it reversed its earlier conclusions and rejected the Order No. 94 settlements with Panhandle, Trunkline, Texas Eastern and Texas Gas. FERC now holds that Columbia Transmission's 1985 PGA settlement essentially bars recovery of any of the rejected costs. The January 12, 1994, order required Panhandle, Texas Eastern and Texas Gas to refund all Order No. 94 costs, but absolved them of responsibility for paying interest. On February 14, 1994, Columbia Transmission and the upstream pipelines requested rehearing of the January 12 orders. The pipelines have received an extension of time to make refunds until after the FERC rules on rehearing. Columbia Transmission has asked the FERC to hold the Transco settlement in abeyance until after the FERC rules on rehearing. Transco has opposed this request.
C. WACOG Recovery.
1. Columbia Gas Transmission Corp., FERC Dkt. No. RP91-206. On August 1, 1991, Columbia Transmission filed for a 12- month, 20 cent surcharge to its commodity rate to recover certain pre-April 1, 1985, supplier costs which it is entitled to recover, in accordance with the terms of its 1985 Purchased Gas Adjustment settlement, to the extent that its annual weighted average cost of gas (WACOG) compares favorably with the WACOGs of competing pipelines. On August 30, 1991, FERC rejected such filing, without prejudice, finding that Columbia Transmission's calculation of its WACOG was inconsistent with the 1985 settlement. On May 22, 1992, the FERC denied Columbia Transmission's request for rehearing. Columbia Transmission has filed a petition for review of these orders. The matter has been briefed by the parties and oral argument was held on October 22, 1993. On January 3, 1994, Columbia Transmission filed an offer of settlement in Docket Nos. RP93-161 and RP94-1 (see C.3. below) which provides that, upon final approval of the settlement, Columbia Transmission will dismiss its appeal.
2. Columbia Gas Transmission Corp., FERC Dkt. No. RP92-215. On July 31, 1992, Columbia Transmission proposed an 8 cents per Dekatherm surcharge for the 12 months commencing September 1, 1992. On August 31, 1992, the FERC accepted Columbia Transmission's filing subject to suspension, refund and a technical conference. After such technical conference and statements of position by the parties, the FERC rejected the WACOG filing on January 21, 1993 and ordered Columbia Transmission to refund all WACOG charges which it previously collected. On November 26, 1993, the FERC denied Columbia Transmission's request for rehearing of the January 21, 1993, order. Columbia Transmission has filed a petition for review of these orders with the
ITEM 3. LEGAL PROCEEDINGS (Continued)
United States Court of Appeals for the D.C. Circuit. On January 3, 1994, Columbia filed an offer of settlement in Docket Nos. RP93-161 and RP94-1 (see C.3. below) which provides that, upon final approval of the settlement, Columbia Transmission will dismiss its appeal of the orders.
3. Columbia Gas Transmission Corp., Dkt. Nos. RP93-161 and RP94-1. These filings proposed a WACOG surcharge for the 1993-94 period, the last year Columbia Transmission is eligible to file such surcharge. The filing in RP93-161 proposed to collect a 28 cents per Dth surcharge for sales customers for the months of September and October 1993. The filing in RP94-1 proposed to collect a surcharge of 7.22 cents per Dth for most firm transportation customers from November 1, 1993 when Columbia Transmission implemented Order 636, through October 31, 1994. On January 3, 1994, Columbia Transmission filed a settlement which is unopposed to obtain all WACOG surcharges collected during September-December, 1993 and collect a WACOG surcharge of 3.8c. per Dth during January-October, 1994. If Columbia Transmission's WACOG surcharge revenues exceed $42.8 million, it will refund 90% of the excess to customers and retain the remaining 10%. FERC approved the settlement on February 28, 1994.
VI. Other
A. Canada Southern Petroleum Ltd. v. Columbia Gas Development of Canada Ltd. et al., (C.A. No. 9001-03466, Court of Queen's Bench, Alberta, Canada, filed March 7, 1990). The plaintiff asserts, among other things, that the defendant working interest owners, including Columbia Gas Development of Canada Ltd. (Columbia Canada) and various Amoco affiliates, breached an alleged fiduciary duty to ensure the earliest feasible marketing of gas from the Kotaneelee field (Yukon Territory, Canada). The plaintiff seeks, among other remedies, the return of the defendants' interests in the Kotaneelee field to the plaintiff, a declaration that such interests are held in trust for the plaintiff, and an order requiring the defendants to promptly market Kotaneelee gas or assessing damages.
The judge granted the application of Allied Signal, Inc., Home Oil Company and Kern County Land Company to relieve them of the requirement to participate in the proceedings. An appeal of the order by Amoco is pending.
Examination for discovery is still proceeding in the referenced actions. Columbia Canada has had a second round of discovery of its witnesses and has made undertakings to provide additional information which it is in the process of preparing. Amoco has not yet fulfilled the undertakings from its first round of discoveries. Upon it doing so, it is reasonable to suppose that further discoveries of Amoco will be required by Canada Southern.
None of the defendants has yet conducted any discovery of Canada Southern nor of one another. On the present schedule, it is likely that this discovery process will continue well into 1994.
In early 1993, Canada Southern filed a motion to amend their statement of claim to seek an accounting of the amount of operation costs properly recoverable by the working interest holders including Columbia Canada. Columbia has not consented to the amendment and contends that any amounts accrued since the initial statement of claim in 1988 should be barred and more basically, that litigation is inappropriate prior to an audit.
Note: Columbia Canada was sold to Anderson Exploration Ltd. effective December 31, 1991, and the company name subsequently changed to Anderson Oil & Gas, Inc. Pursuant to an Indemnification Agreement re Kotaneelee Litigation, Columbia agreed to indemnify and hold Anderson harmless from losses due to this litigation. An escrow account in the amount of approximately $30,000,000 (Cdn) was established as partial security for the indemnification obligation. Upon emerging from bankruptcy, an additional deposit to the Escrow Account of $25,000,000 (Cdn) will be required in cash or by letter of credit.
ITEM 3. LEGAL PROCEEDINGS (Continued)
B. Minerals Management Service (MMS) has demanded that Columbia Gas Development Corporation (Columbia Development) pay additional royalties for the period October 1, 1983 to December 31, 1985, claiming the prices received by Columbia Development from its affiliate under non-arm's-length contracts were less than the prices received for like-quality gas under comparable arms-length contracts in the field. A complaint was filed by Columbia Development in U.S. District Court in Dallas on October 23, 1992, (Case No. 3:92-CV2199-T), claiming that the six-year statute of limitation applicable to the claim has expired and a protective administrative appeal was filed with the MMS on October 27, 1992. A decision was rendered August 27, 1993, by the Northern District of Texas District Court in favor of the government on the statute of limitations issue, reasoning that the MMS order to pay is not "an action for money damages" under the language of the statute and further granted the government's motion to dismiss in part on the basis of the doctrine of exhaustion of administrative remedies. Columbia Development has appealed the District Court decision to the Fifth Circuit Court of Appeals. Columbia Development's initial brief was filed on January 10, 1994. In another case, the 10th Circuit Court of Appeals ruled in favor of the government on the statue of limitations issue on the grounds that the six-year statute of limitations is tolled until such time as the government could reasonably have known about all facts material to its right of action.
In addition, the MMS audited Columbia Development for the period January 1, 1986, through December 31, 1990, and has made a similar but unquantified claim. Columbia Development has appealed this claim to the Interior Board of Land Appeals and has obtained the MMS's pricing data and analyzed it using comparable pricing from surrounding OCS blocks to determine probable liability. Meetings with the MMS to eliminate less controversial claims (third party sales and sales at MLP) and to present the comparable pricing analysis have been held. MMS is reviewing the information presented.
VII. Environmental
A. Commonwealth of Kentucky Natural Resources and Environmental Protection Cabinet, Department for Environmental Protection. On January 22, 1992, Columbia Transmission received Notices of Violation (NOV) from the Commonwealth of Kentucky, Natural Resources and Environmental Cabinet, Department of Environmental Protection (KyDEP) with respect to ten compressor station sites in the Commonwealth of Kentucky. These notices generally cite the release or disposal of waste materials or hazardous substances, including but not limited to polychlorinated-biphenyls (PCBs). It appears from a letter dated January 13, 1992, from the Natural Resources Environmental Protection Cabinet, Department of Law, that the violations have been asserted for the purposes of establishing the Cabinet's prepetition claims against Columbia Transmission.
The alleged violations provide for fines and penalties that apply separately for each violation and each day of noncompliance which, in the aggregate, are significant. Columbia Transmission's prior experiences, however, as well as those of other companies in the industry, have demonstrated that such fines and penalties have not been assessed at the maximum rate when the company is cooperating with governmental agencies and authorities in remediation activities. Columbia Transmission intends to continue to work with the KyDEP in negotiating a consent decree approving prior remediation activity and a prospective remediation plan.
B. In the Matter of Columbia Gas Transmission Corp., (Region III). Columbia Transmission was subpoenaed to supply information under the authority of the Toxic Substance Control Act (TSCA), the Resource Conservation Recovery Act and the Comprehensive Environmental Response Compensation and Liability Act of 1980. Documents were accumulated and delivered in June and July and conferences with personnel of the Environmental Protection Agency Region III have been held. Columbia Transmission is continuing to provide documents and information to Environmental Protection Agency Region III and has begun negotiation of a possible consent decree under the TSCA approving prior remediation activity and prospective remediation plans developed by Columbia Transmission. Fines or penalties may also be included.
ITEM 3. LEGAL PROCEEDINGS (Continued)
C. Portsmouth Redevelopment and Housing Authority and Commonwealth Gas Services, Inc. (Commonwealth) v. BMI Apartment Associates, C.A. No. 2:93CV242, (U.S. Dist. Ct. E.D. Va., filed March 25, 1993.) A gas manufacturing plant had been operated in Portsmouth, Virginia by Portsmouth Gas Co on a site that was subsequently sold by Portsmouth Gas Co. to the Portsmouth Redevelopment and Housing Authority, which removed equipment and sold the property to developers of apartment complexes and single-family homes. Portsmouth Gas Co. was later acquired by Commonwealth. On February 10, 1993, without admitting or conceding responsibility for the site, Commonwealth provided notice of site contamination to the United States Environmental Protection Agency. On March 25, 1993, Commonwealth and the Portsmouth Housing and Redevelopment Authority filed a cost recovery action in federal court under the Comprehensive Environmental Response Compensation and Liability Act of 1980 against the current and past owners of a former manufactured gas plant site and sought a court order to obtain access to the site for health risk testing. BMI Apartment Associates (BMI), the owners of apartments on the site objected to the request for access and filed a "citizens' suit" under the Resource Conservation and Recovery Act as a counterclaim and cross-claim. On June 14, 1993, the United States District Court granted Commonwealth and the Portsmouth Redevelopment and Housing Authority access to the site to perform the health risk testing and testing on-site was completed June 24, 1993. On July 28, 1993, the Court dismissed the counterclaims of BMI that were drawn on RCRA and loss of contribution protection under CERCLA. The remaining liabilities, damages and allocations are similar for both defendants and plaintiffs. The Health Risk Assessment Report was provided to all parties on August 27, 1993. It finds "no imminent risk to public health." Further investigation will be conducted without relocating residents. In mid-September, 1993, the judge granted an eight month stay of all legal proceedings to permit Commonwealth to conduct full site investigation and provide the opportunity for the parties to discuss settlement. The workplan was completed and work began on November 1, 1993. Emergency permits for waste handling from the City of Portsmouth were obtained to facilitate the investigation. Residents and nearby homeowners were notified of the work. Commonwealth met with the voluntary Remediation Group of VaDEQ. A draft consent agreement delineating the VaDEQ's supervisory responsibility for site work is being developed. On February 14, 1994, a Magistrate was appointed to facilitate settlement discussions.
D. Commonwealth Gas Services/Virginia Department of Environmental Quality. On February 9, 1993, Commonwealth reported to the Virginia Department of Environmental Quality's (VaDEQ) State Water Control Board that an oily substance was seeping through a retaining wall at a former manufactured gas plant site at Petersburg, Virginia. On April 5, 1993 Commonwealth received a request from the State Water Control Board to investigate the seep and submit a report to the Board. Commonwealth has retained a consultant to investigate the seep and prepare the report. Site assessment was submitted to the VaDEQ on July 20, 1993. That report recommends removal of contents of a tank behind the retaining wall. The report also disclosed an additional seep of materials from the creek upstream of the retaining wall area. On July 27, 1993, VaDEQ accepted Commonwealth's recommendations on the two seeps. Commonwealth is proceeding to implement those recommendations over the next six months. On November 1, 1993, a report on the creek bank seep was sent to VaDEQ. It notes fairly widespread groundwater and soil contamination, as well as identifying the source of the creek bank seep. On December 10, 1993, Commonwealth met with the VaDEQ regarding the recently filed report. Commonwealth consultants are developing a workplan to address the contamination noted in the report. Commonwealth is now dealing with VaDEQ remediation group and is in the process of developing a draft memorandum of understanding delineating the course of action to be taken.
E. In Re Columbia Gas Transmission (Region V). On January 28, 1994, Columbia Transmission received from USEPA Region V an Information Request pursuant to the Resource Conservation and Recovery Act (RCRA). The Agency requests Columbia Transmission to submit information and knowledge relating to its generation and management of natural gas pipeline condensate, used engine oil and similar liquids in the state of Ohio. Transmission is in the process of analyzing the information requested and will be discussing this Information Request with Region V.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable. PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Corporation is traded on the New York Stock Exchange under the ticker symbol CG and abbreviated as either ColumGas or ColGs in trading reports. The number of shareholders of record on February 28, 1994, was approximately 64,271 and the stock closed at $28.375. On June 19, 1991, the Corporation suspended the dividend on its common stock. Management cannot determine at this time when dividends will again be paid.
See Item 7 on page 51 for additional information regarding the Corporation's common stock prices and dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
SELECTED FINANCIAL DATA The Columbia Gas System, Inc. and Subsidiaries
N/M - Not meaningful * Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements. **Prior to its Chapter 11 filing, the Corporation made extensive use of variable rate debt since the associated cost was normally less than senior long-term debt. Inclusion of the short-term debt in years prior to 1991 makes those historical ratios more meaningful.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BANKRUPTCY MATTERS
On July 31, 1991, The Columbia Gas System, Inc. (Corporation) and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. Both the Corporation and Columbia Transmission were granted debtor-in-possession status under the Bankruptcy Code, allowing them to continue normal business operations subject to the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court).
Columbia Transmission's Plan of Reorganization The Corporation's and Columbia Transmission's discussions with the Official Committee of Unsecured Creditors of Columbia Transmission (Columbia Transmission Creditors' Committee) to negotiate a reorganization plan for Columbia Transmission and expedite emergence from Chapter 11 proceedings had been largely unsuccessful. Therefore, on January 18, 1994, Columbia Transmission filed, with the Corporation as cosponsor, a reorganization plan (plan) and a disclosure statement, for consideration by its creditors and other interested parties. The plan, which management believes is fair and equitable, proposes to pay 100 percent for all priority, administrative and secured claims and offers various classes of general unsecured creditors, including producers whose gas contracts were rejected by Columbia Transmission, between 80 and 100 percent of Columbia Transmission's estimates of their allowable claims. The $3.3 billion total distribution proposed in Columbia Transmission's plan is based on an estimated value for Columbia Transmission of $3.1 billion and includes significant financial contributions by the Corporation. The plan is premised on a proposed omnibus settlement whereby the Corporation would settle the Intercompany Complaint and facilitate Columbia Transmission's reorganization by (i) accepting the value of the Corporation's secured claims against Columbia Transmission in the form of secured debt and equity securities of Columbia Transmission, and (ii) ensuring the cash (or at the option of the Corporation cash and $100 million market value of the Corporation's common stock) necessary to bring the aggregate distribution to $3.3 billion. Creditors, other than the Corporation, would share in distributions of over $1.2 billion in cash. In addition, the Corporation would consent to the reorganized Columbia Transmission's assumption of responsibility for public environmental enforcement agency claims so that the recoveries of the other creditors would not, with minor exceptions, be diminished by the environmental liabilities of Columbia Transmission's estate.
The plan provides that Columbia Transmission will remain a wholly-owned subsidiary of the Corporation, will continue to offer an array of competitive transportation and storage services, and will retain ownership of its 18,800-mile pipeline network and related facilities.
Columbia Transmission's proposed business solution will offer to producers, whose gas supply contracts were rejected or who have prepetition claims under those contracts, individual, specific settlements of the producers' claims that are based upon uniform assumptions and principles and which, in the view of Columbia Transmission's management, are fair and reasonable settlement values. These specific settlement proposals are being developed
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
and will be filed as an adjunct to the plan. Columbia Transmission estimates that aggregate distributions to producers under the plan would come to approximately $900 million.
In general, the plan provides for immediate cash payment in full to all priority claims, all secured claims held other than by the Corporation, trust fund claims, administrative expenses and unsecured claims of $50,000 or less. The Corporation's secured claims will be satisfied in full with new secured debt and equity securities to be issued by the reorganized Columbia Transmission. Unsecured claims between $50,000 and $250,000 would receive 95 percent of their allowed claims in cash. All other unsecured claims, including the Corporation's unsecured debt and producer contract rejection claims, would receive between 80 and 100 percent of their allowed claims based on current projections. With respect to some of the classes of creditors, the treatment described above depends on the acceptance of the plan by the relevant class. At this time, no creditors have agreed to any of the proposed plan's provisions, and the ultimate confirmed plan of reorganization could be materially different from this initial filing.
Although Columbia Transmission's plan utilizes June 30, 1994, as an assumed date of emergence from bankruptcy, the actual date of emergence will depend on the time required to complete the bankruptcy process and obtain necessary creditor, judicial and regulatory approvals. As part of its filing with the Bankruptcy Court, Columbia Transmission requested that the court defer scheduling required proceedings on the plan and related disclosure statement in order to permit discussions of the plan, including the settlements proposed therein, with Columbia Transmission's creditors, official committees and other interested parties.
Under bankruptcy procedures, after Columbia Transmission's disclosure statement has been approved by the Bankruptcy Court, the disclosure statement and the reorganization plan will be sent to the company's creditors for voting.
The Corporation intends to file a plan for its reorganization which will be consistent with the financial aspects and structure of Columbia Transmission's proposed plan of reorganization. Both plans will be subject to a lengthy review and approval process, including SEC approval, and obtaining adequate financing.
Implementation of Columbia Transmission's plan, and the levels and timing of distributions to its creditors, are subject to a number of risk factors which could materially impact their outcome. The plan sets forth numerous conditions to its confirmation and consummation. The failure to satisfy these conditions in accordance with the terms of the plan would have a material adverse effect on the outcome of Columbia Transmission's bankruptcy and on the Corporation. These conditions include, among others, the confirmation of a reorganization plan for the Corporation, the receipt of necessary approvals for the implementation of Columbia Transmission's plan and the recovery of regulatory and tax benefits which are fundamental to the plan's viability. Both companies anticipate emerging from bankruptcy at the same time. The provisions of the reorganization plans of either Columbia Transmission or the Corporation that are ultimately implemented could be materially different from this initial filing for Columbia Transmission and have a material adverse effect on the Corporation and its subsidiaries and on the rights of shareholders and holders of debt and other obligations.
Events Leading to Bankruptcy Filings Columbia Transmission's Chapter 11 filing was precipitated by a combination of events that adversely affected its physical operations and financial viability. Most notable were federal legislative and regulatory actions, instituted years after Columbia Transmission's gas purchase contracts were signed, that significantly impacted Columbia Transmission's ability to sell the gas it had contracted to buy and to recover its costs from its customers. These problems were exacerbated by record-setting warm weather in 1990 and 1991, which caused spot market prices for gas to plunge and created excess transportation capacity, thus making an unexpected and persistent oversupply of bargain-priced gas available to Columbia Transmission's customers. As a result, Columbia Transmission's ability to market its gas was severely undercut, substantially reducing both sales volumes and revenues.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
After completing studies, in early June 1991, that revealed the magnitude of Columbia Transmission's gas supply problems, the Corporation announced on June 19, 1991, that: (i) it anticipated that a substantial portion of Columbia Transmission's exposure on above-market priced gas purchase contracts would be charged to income in the second quarter; (ii) Columbia Transmission was launching a comprehensive effort to renegotiate or terminate all of its above-market gas purchase contracts under a program which contemplated offering producers up to $600 million of Columbia Transmission's obligations as compensation for restructuring their contracts; (iii) the Corporation was suspending the dividend on its common stock; and (iv) corporate officers were meeting with bank lenders that day seeking to reestablish the Corporation's credit facilities on revised terms in view of Columbia Transmission's financial difficulties. In addition, Columbia Transmission's financial problems were exacerbated when the West Virginia Supreme Court ordered the posting of a $10 million bond by July 29, 1991, in order to stay the execution of a $29.5 million judgment in a lease dispute which was subsequently reversed.
As of July 31, 1991, the Corporation was in default on $83.5 million of short-term obligations and the negotiations with banks and producers had met with only limited success. As a result, on July 31, 1991, the Corporation and Columbia Transmission filed for protection under Chapter 11 of the Federal Bankruptcy Code in the Bankruptcy Court. A discussion of the proceedings under Chapter 11 protection is included in Note 2 of Notes to Consolidated Financial Statements.
In contrast to the situation of many other Chapter 11 debtors, reorganization of Columbia Transmission has not been hampered by unprofitable or marginal business operations. Rather, in Columbia Transmission's case the achievement of the Chapter 11 objective of reorganization has been impacted by the enormity and complexity of the disputed and contingent claims filed against it by unaffiliated creditors and by attempts on behalf of those creditors to obtain recoveries on such claims from the assets of the Corporation's estate. In addition, Columbia Transmission's status as a regulated gas transmission company under the Natural Gas Act (NGA) and its resulting obligations has brought into the bankruptcy forum creditors' rights issues which are complicated by public law issues arising under the NGA.
Bankruptcy Issues On March 19, 1992, the Columbia Transmission Creditors' Committee filed a complaint (Intercompany Complaint) with the Bankruptcy Court alleging that the $1.7 billion of Columbia Transmission's secured and unsecured debt securities held by the Corporation should be recharacterized as capital contributions (rather than loans) and equitably subordinated to the claims of Columbia Transmission's other creditors. The Intercompany Complaint also challenges interest and dividend payments made by Columbia Transmission to the Corporation of approximately $500 million for the period from 1988 to the petition date and the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an alleged fraudulent transfer. Based on the SEC's standardized measurement procedures, CNR's properties had a reserve value of approximately $387 million as of December 31, 1993, a significant portion of which is attributable to the transfer from Columbia Transmission. In May 1992, Columbia Transmission Creditors' Committee filed with the U.S. District Court a motion for a jury trial and to move the Intercompany Complaint from the Bankruptcy Court to the U.S. District Court. This motion was denied and subsequently appealed to the Third Circuit Court of Appeals (Third Circuit). In June 1992, the Corporation filed a motion with the Bankruptcy Court seeking dismissal of, or summary judgment on, principal portions of the Intercompany Complaint. On August 20, 1993, the Third Circuit denied Columbia Transmission Creditors' Committee's appeal, allowing the Bankruptcy Court to consider the merits of the Intercompany Complaint and act upon the Corporation's June 1992 motion for summary judgment. The Bankruptcy Court has not acted on the Corporation's motion for summary judgment, but tentatively scheduled a trial on the Intercompany Complaint to begin June 13, 1994. Management believes that the Intercompany Complaint is without merit; however, the ultimate outcome of these issues is uncertain at this stage of the proceedings.
Discussions with Columbia Transmission's creditors in an attempt to establish the value of the estate and to resolve
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
the matters raised in the Intercompany Complaint are ongoing. Since the standing and value of the Corporation's debt investment in Columbia Transmission is crucial to the determination of the value of the Corporation's estate, the Corporation's reorganization could be affected by the ultimate outcome of the Intercompany Complaint.
At December 31, 1993, the Corporation's investment in Columbia Transmission is as follows:
The Corporation has claims against Columbia Transmission's estate for money it borrowed which are secured by substantially all of Columbia Transmission's assets, including cash. This indebtedness bears interest at rates significantly higher than those earned by Columbia Transmission on its excess cash because of bankruptcy imposed limitations on Columbia Transmission's temporary investments and the current level of interest rates. As a result, the growth in Columbia Transmission's secured interest obligations has exceeded its interest earnings on its cash available for debt service by an amount projected to exceed $300 million by the end of June 1994.
The Internal Revenue Service (IRS) filed identical claims of $553.7 million against both debtor companies and the consolidated Columbia Gas System for tax deficiencies, interest and penalties for the years 1983-1990. Negotiations with IRS representatives have resulted in a settlement on all of the issues included in the IRS claims. This settlement has been documented in a written closing agreement and filed with the Joint Committee on Taxation of the U.S. Congress for formal approval. The IRS settlement also requires Bankruptcy Court approval. Recording the IRS settlement reduced 1993 net income by $44.3 million.
Columbia Transmission has recorded liabilities of approximately $1.2 billion to reflect the estimated effects of its above- market producer contracts and estimated supplier obligations associated with pricing disputes and take-or-pay obligations for historical periods. With Bankruptcy Court approval, Columbia Transmission rejected more than 4,800 above-market gas purchase contracts with producers. The producers whose gas purchase contracts were rejected filed claims for damages that, after being adjusted for duplicative and other erroneous claims, are in excess of $13 billion. The Bankruptcy Court approved the appointment of a claims mediator in 1992 to implement a claims estimation procedure related to the rejected above-market producer contracts and other producer claims. The mediator held hearings on generic issues and various estimation methodologies and discovery matters during 1993. Columbia Transmission anticipates that the mediator may issue recommended determinations during the second quarter of 1994 which, under the Bankruptcy Court-approved estimation procedure, are expected to provide the basis for a recalculation of producer contract rejection claims. In Columbia Transmission's judgment, the positions taken by all producers before the claims mediator and the evidence presented demonstrate that the total level of allowable contract rejection claims, generically determined, will not exceed 1/10th of the $13 billion asserted in the claims as filed and is likely to be between $600 million and $950 million. The acceptance of certain positions advanced by Columbia Transmission on the evidence of record, as well as Columbia Transmission's as yet unheard defenses, could decrease substantially this range of possible aggregate outcomes. Resolution of the contract-specific issues
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
not yet presented could increase or decrease individual claims materially but should not significantly alter the range of possible aggregate outcomes.
The resolution of these issues can significantly influence future reported financial results. Accounting standards require that as claim amounts are allowed by the Bankruptcy Court, the full amount of the allowed claim must be recorded. This could result in liabilities being recorded which bear little relationship to the amounts ultimately required to be paid in settlement of those claims and could conceivably exceed the Corporation's total investment in Columbia Transmission. Any such distortion would not be corrected until final plans of reorganization are approved for the Corporation and Columbia Transmission.
At a hearing on February 23, 1994, the Bankruptcy Court granted the Columbia Transmission Creditors' Committee's motion for the establishment of a data room that will make business information on Columbia Transmission available to third parties who may be interested in the company. In granting the motion, the Bankruptcy Court instructed the parties to jointly develop proposed data room procedures which should provide for a substantial entrance fee, exclude Columbia Transmission's future business plans and projections and establish strong confidentiality protections. The Bankruptcy Court also instructed that such procedures should be filed with the Bankruptcy Court by March 11, 1994, for a hearing on March 15, 1994. Columbia Transmission is working toward the expeditious development and conclusion of the data room process in order to minimize any potential delays to its reorganization efforts. The Corporation has stated that its Columbia Transmission subsidiary is not for sale but that if a credible, bona fide third party offer is made for that company, it would be given appropriate consideration.
Other Related Issues
Corporation's Objection to Claims In 1993, the Bankruptcy Court granted the Corporation's request to expunge over 7,100 proofs of claim filed against the Corporation. As a result, less than 500 filed claims against the Corporation currently remain to be resolved.
Leveraged Employee Stock Ownership Plan On May 31, 1992, the debt service payment on debentures issued under the Leveraged Employee Stock Ownership Plan (LESOP) portion of the Columbia's Employees' Thrift Plan (Thrift Plan) was not made and no further debt service payments are likely to be made until the Corporation emerges from bankruptcy. Under the terms of the Corporation's guarantee of the debentures, the LESOP debenture holders will become creditors of the Corporation, subordinated to holders of the debentures and medium-term notes issued by the Corporation. Management has concluded that it is more equitable and may be economically preferable to pay all creditors at the same time in accordance with consummation of the Corporation's plan of reorganization.
The Trustee for the Indenture under which the debentures were issued by the Thrift Plan filed a complaint against the Corporation on March 2, 1993, alleging tortious interference with contract for failure to pay installments due LESOP debenture holders. On April 2, 1993, the Corporation filed an answer to the complaint and, on May 14, 1993, filed a motion in the Bankruptcy Court for summary judgment to dismiss this action which is still pending.
Security Holder Litigation After the announcement on June 19, 1991, regarding the Corporation's probable charge to second quarter earnings and the suspension of its dividend, 17 complaints including purported class actions were filed against the Corporation and its directors and certain officers of the debtor companies in the U.S. District Court of Delaware. The actions, which generally allege violations of certain antifraud provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934, have been consolidated. In addition, three derivative actions were filed in the Court of Chancery in and for New Castle County (Delaware) alleging that directors breached their fiduciary duties.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
These suits have been stayed by either the Bankruptcy Court filing or by stipulation of the parties. While the Corporation believes that it has meritorious defenses to these actions, the outcome is uncertain at this time.
Customer Refunds In July 1993, the U.S. Court of Appeals for the Third Circuit overturned most of a U.S. District Court ruling and affirmed an earlier Bankruptcy Court decision that refunds Columbia Transmission received from upstream pipelines, as well as the Gas Research Institute (GRI) surcharge payments it collected from customers, are held in trust, by Columbia Transmission, for those customers and the GRI and are not part of Columbia Transmission's estate. In August 1993, the Third Circuit denied the Columbia Transmission Creditors' Committee's request for a rehearing. In February 1994, the Supreme Court denied petitions for review of the Third Circuit decision.
Under the Third Circuit ruling, approximately $173 million in refunds that Columbia Transmission has received, or expects to receive postpetition from upstream pipelines and GRI surcharges collected should be passed through to the customers and to the GRI. In addition, the Third Circuit determined that $35 million in upstream pipeline refunds and GRI surcharges, which Columbia Transmission collected prior to filing Chapter 11 while received in trust, were subject to the "lowest intermediate cash balance test" (the amount remaining in trust at the time of bankruptcy) and should be distributed on a pro rata basis to the customers and to the GRI to the extent of Columbia Transmission's $3.3 million cash balance on July 31, 1991. The Third Circuit affirmed another part of the U. S. District Court's decision and held that approximately $16 million that Columbia Transmission owes upstream suppliers, for gas purchased and transportation services received prior to its bankruptcy filing, is ordinary unsecured debt which must be discharged in the bankruptcy process.
On February 10, 1994, the District Court issued an order for the Bankruptcy Court to pursue further proceedings in accordance with the Third Circuit's refund decision directing the pass-through of these refunds. At a hearing on December 29, 1993, the Bankruptcy Court observed that the Federal Energy Regulatory Commission (FERC) should determine whether customers are entitled to the actual interest earned on refunds being held by Columbia Transmission or the higher FERC-prescribed interest rate. On February 18, 1994, Columbia Transmission filed a motion with the FERC for determination of this interest issue. Columbia Transmission will ask the Bankruptcy Court for implementation of the mandate. Columbia Transmission will also have to file with the FERC to reimplement its flow-through of Order Nos. 500/528 refunds from its pipeline suppliers, which represent the majority of the refunds at issue. It is anticipated that Columbia Transmission will recommence the flow-through of the upstream pipeline refunds in 1994.
Total customer claims in Columbia Transmission's bankruptcy proceedings relating to, or arising from, Columbia Transmission's contracts with its customers for sales, transportation, gas storage and similar services and other miscellaneous claims represent about 450 claims for a total of approximately $550 million as filed, plus a potentially substantial sum filed in undetermined amounts. Columbia Transmission successfully resolved a significant portion of these customer claims. Not resolved are customer claims that total approximately $113 million at December 31, 1993, that seek to protect rights associated with any prepetition revenues collected subject to refund in general rate filings and purchased gas adjustment filings, including matters subject to court appeals. In addition, the claims filed in undetermined amounts, which potentially could be significant, still remain to be resolved. In October 1993, approximately $160 million was refunded to customers by Columbia Transmission reflecting the terms of a settlement of a 1991 rate case approved by the Bankruptcy Court in July 1993. Bankruptcy Court approval for a 1990 rate case settlement for rates in effect from November 1, 1990 through November 30, 1991 was deferred pending the decision by the Third Circuit regarding the flow-through of certain refunds. Appropriate reserves for rate refund liabilities have been recorded for these matters to reflect management's judgment of the ultimate outcome of the proceedings.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Customer Recoupment Rights During the fourth quarter of 1993, various customers of Columbia Transmission filed motions with the Bankruptcy Court seeking authority to exercise alleged recoupment and setoff rights, whereby they would be permitted to reduce amounts owed to Columbia Transmission against refunds owed to the customers by Columbia Transmission, including amounts which were not otherwise payable in full under the above-mentioned July 1993 Third Circuit decision, all customer refunds under the 1990 rate case settlement and miscellaneous refunds not otherwise payable in full to them. Customers are alleging that they have recoupment and setoff rights of approximately $83 million at December 31, 1993.
On October 20, 1993, the Bankruptcy Court approved an interim settlement under which customers continued to pay Columbia Transmission for FERC-authorized services at authorized rates, and Columbia Transmission has agreed to grant these customers a priority claim to the extent the Bankruptcy Court finds them entitled to recoupment rights. In January 1994, the Bankruptcy Court issued a procedural order whereby other customers would be permitted to file recoupment and setoff motions by February 18, 1994, with a trial on all such motions scheduled for June 1994.
Interest Expense Interest expense of the Corporation is not being accrued during bankruptcy but a calculation of interest is included in a footnote on the Statements of Consolidated Income and Consolidated Balance Sheets. Such interest has been calculated based on management's interpretation of the contractual arrangements which govern the various debt instruments the Corporation has outstanding exclusive of any redemption premiums. The Official Committee of Unsecured Creditors of the Corporation (Committee) has asserted claims for interest which exceed disclosed amounts by approximately $40 million at December 31, 1993. There are several factors to be considered in making these calculations that are subject to uncertainty as to their ultimate outcome in the bankruptcy proceeding, including the interest rates and method of calculation to be applied to overdue payments of principal and interest. In addition, the Committee has asserted that approximately $110 million of redemption premiums should be paid on high cost debt instruments.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
OIL AND GAS OPERATIONS
Market Conditions Natural gas markets showed renewed strength in 1993, responding to seasonal weather conditions and uncertainty regarding the availability of supplies in the new operating environment brought about by FERC Order No. 636 (Order 636). Overall for 1993, natural gas prices averaged $2.28 per Mcf compared to $2.02 in 1992. Oil prices continued their decline from a 1992 level of $18.20 per barrel to $16.17 per barrel for 1993.
Capital Expenditures The 1993 capital expenditure program increased to $95 million from the $71 million level in 1992. The 1993 program provided for increased development drilling and a modest exploration program in the southwest.
In the southwest, Columbia Gas Development Corporation (Columbia Development) experienced an increase in both gas and oil production in 1993, reflecting the continuing success of its drilling program, especially its horizontal drilling program in the Austin Chalk Trend in Texas. During the fourth quarter of 1993, Columbia Development drilled and completed its 100th horizontal well in that area. Major reconditioning work in early 1993 also contributed to the increase in production.
During 1993, 87 gross (46 net) wells were drilled with a 69 percent success rate. Of these, 47 were drilled in the Austin Chalk, 94 percent of which were successful. Productivity was enhanced by an increased emphasis on dual lateral wells (multiple lateral wells drilled from a single vertical well). The 44 successful wells drilled included 70 laterals. This substantially increased production while reducing overall cost per well, since the costs of the vertical portion of each well were shared by more than one lateral and the combined laterals accessed a larger area. In 1992, 30 wells with 38 laterals were drilled.
Horizontal wells drilled in the Austin Chalk formation during 1993 tested at average daily rates ranging from 250 to 1,040 barrels of oil and 550,000 to 3.1 million cubic feet of gas. Columbia Development holds varying interests in these wells. Development drilling continues in the South Harmony Church area in southern Louisiana. In 1993, three successful wells in this area, 100 percent owned by Columbia Development, tested at combined rates of seven million cubic feet of gas and 925 barrels of oil per day.
In the Appalachian area, CNR's 1993 development well program totaled 120 gross (75 net) wells, with a success rate of 89 percent. One of the most promising areas under development is a formation underlying existing production in Ohio, known as Rose Run. CNR has been producing in this formation in recent years with excellent results. Favorable reservoir characteristics allow Rose Run prospects to quickly generate a return on invested capital. CNR's 1994 development program will continue to target several prospects in this area.
The oil and gas segment's total 1994 exploration and development program of $91 million will continue to focus primarily on development drilling while maintaining the modest level of the 1993 exploration program. Because of weak oil prices the Corporation has adopted more conservative guidelines for economic evaluations to reduce risk.
Reserves Net proved natural gas reserves at the end of 1993 totalled 697 Bcf, compared to 779.5 Bcf at the end of 1992. Proved oil, condensate and natural gas liquids decreased from 14.7 million barrels at the end of 1992 to 12.8 million barrels at the end of 1993. The year end drop in oil prices accounted for approximately 0.6 million barrels of the decline by rendering some properties uneconomical. Increased oil prices would result in recovery of those reserves.
As a result of a year end decline from 1992 to 1993 in gas prices together with an increase in lifting costs, the
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
recoverable gas reserves for CNR were revised downward 65.9 Bcf (11 percent). Without this reduction, newly discovered reserves and extensions approximately equaled production. In addition, Columbia Development's Huntington Beach oil recovery waterflood project has shown disappointing production during 1993, resulting in revised reserve estimates of 1.1 million barrels, down 1.6 million barrels from 1992. Geological and engineering analysis of the project is continuing.
Current pricing has enhanced the profitability of gas prospects, and these prospects are the focus of the 1994 capital program.
Royalty Dispute Columbia Development is involved in a $14 million royalty dispute with the U.S. Minerals Management Service (MMS) regarding royalty valuation issues in connection with prior sales to an affiliate. As a result of an unfavorable lower-court decision regarding the statute of limitations, a pre-tax reserve of $5.4 million has been established by Columbia Development. Based on information currently available, management believes this reserve to be adequate; however, the contested matters are under review, and management is currently negotiating a settlement with the MMS.
Proposed Rulemaking for Offshore Drilling Financial Responsibility The MMS has issued an advance notice of proposed rulemaking for oil spill financial responsibility that would establish financial responsibility at $150 million for all operators of offshore facilities and facilities in, on, or under the navigable waters of the United States.
Regulations currently require operators to demonstrate financial responsibility of up to $35 million in liability coverage. Both Columbia Development and CNR operate in navigable waterways covered under the proposed regulations. The insurance industry has indicated an unwillingness to meet the proposed financial responsibility due to certain proposed provisions contained in the rulemaking. Many comments have been received by the MMS critical of this rulemaking and its new financial responsibility requirement as well as other provisions. Since final rules may be at least two years away, it is impossible to determine the implications for the Corporation's oil and gas operations.
Volumes Gas production totalled 71.5 Bcf in 1993, an increase of 3 percent over 1992. The increase includes new Southwest offshore production and new onshore production in Texas, south Louisiana and New Mexico. This improvement was tempered by a small decrease in production due to construction and maintenance activities on pipelines and compressors serving Columbia's Appalachian production area. After adjusting for the 1991 sale of the Canadian operations, gas production for 1992 was essentially unchanged from the previous year.
Oil and liquids production in 1993 of 3,603,000 barrels reflected an increase of nearly 18 percent compared to 1992 due largely to the success of the Southwest program. Production for 1992, after adjusting for the sale of the Canadian operations, increased 228,000 barrels over 1991.
Operating Revenues Higher gas prices together with increases in oil and gas production led to operating revenues of $222.2 million in 1993, an increase of 12 percent over 1992. Dampening these improvements was the lower average price for oil and liquids and the $5.4 million reserve for the royalty dispute discussed above.
The sale of the Canadian subsidiary was the primary reason for 1992 operating revenues to decrease $16.1 million from 1991, or 7 percent. The decline was somewhat offset as the average gas price in 1992 was $2.02 per Mcf, 7 percent higher than 1991, after adjusting for the 1991 sale of the Canadian operations. The average price for oil
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
and liquids in 1992 of $18.20 per barrel represented a decline of 18 percent from the price for domestic production the previous year.
Operating Income (Loss) Operating income of $53.6 million in 1993 compares to an operating loss of $101.2 million in the prior year which was due largely to recording a writedown in the carrying value of oil and gas properties of $126.4 million due to depressed energy prices. The current period improvement in operating income also reflected higher operating revenues and lower depletion expense. These improvements were partially offset by higher operation and maintenance expense for costs related to new wells and additional reconditioning work on older wells.
The $96.7 million additional operating loss in 1992 compared to 1991 resulted from the effect of the writedown mentioned above together with higher operating expenses. These declines were mitigated by writedowns incurred in 1991 for the Canadian properties.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM OIL AND GAS OPERATIONS (UNAUDITED)
* Includes results from Canadian operations that were sold effective December 31, 1991.
OIL AND GAS OPERATING HIGHLIGHTS*
* Years 1991 through 1989 include results from Canadian operations that were sold effective December 31, 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATIONS
Operations The transportation and storage rates of Columbia Transmission and the transportation rates of Columbia Gulf Transmission Company (Columbia Gulf) are currently among the most competitive serving the companies' general market areas. The companies are committed to maintaining their competitive position on an ongoing basis through a combination of efficient and effective maintenance of existing facilities, economical new market development and a commitment to the highest level of overall customer satisfaction.
Columbia Transmission recently received an order from the FERC for the construction of the Rutledge Compressor Station in Harford County, Maryland. This station will allow Columbia Transmission to transport 53,400 Mcf per day to the Eagle Point Cogeneration Plant in New Jersey and over 58,000 Mcf per day to New England Power. It is anticipated that the Rutledge Compressor Station will be in service by December 1994.
Columbia Transmission will provide approximately 52,000 Mcf per day of interruptible transportation service to Gordonsville Energy Limited Partnership, an independent power producer in Louisa County, Virginia, in late summer of 1994.
Rate Cases Columbia Transmission's and Columbia Gulf's rates are subject to the jurisdiction of the FERC. These transmission companies (Transmission) make periodic filings for rate changes to recover costs associated with new facilities, operating and capital costs, and to reflect changes in throughput, cost allocation or rate design. Settlements of issues related to these filings are subject to approval by the FERC, and with respect to Columbia Transmission during its bankruptcy, the Bankruptcy Court.
During 1993, Columbia Transmission and Columbia Gulf sought approval of two rate settlements. As previously reported, a 1990 rate filing by both companies covering the period November 1, 1990 through November 30, 1991, received FERC approval in 1992; however, Bankruptcy Court approval for Columbia Transmission to make refunds has been delayed pending resolution of certain motions filed by various creditors.
Columbia Transmission and Columbia Gulf received FERC and Bankruptcy Court approvals for a settlement of a general rate case that went into effect on December 1, 1991. Two parties continue to contest certain aspects of the settlement. Columbia Transmission and Columbia Gulf have made refunds and implemented rates prescribed to all parties consenting to this settlement. The nonconsenting parties, for whom separate proceedings are expected to be scheduled soon, have challenged the FERC's order and have filed a court appeal. In management's opinion, the outcome of the legal proceedings with the nonconsenting parties, including the above mentioned court appeal, will not have a material adverse impact on the Corporation.
WACOG Surcharge Under the terms of a 1985 settlement with its customers, Columbia Transmission is entitled to impose a sales commodity surcharge when its weighted average cost of gas (WACOG) met certain conditions. These conditions were met in 1992, and Columbia Transmission was authorized to include the surcharge in its rates for the period September 1, 1993 through August 31, 1994. Under Order 636, which became effective November 1, 1993, Columbia Transmission essentially eliminated its merchant function and proposed an alternative method of recovering these costs which the FERC conditionally accepted.
In January 1994, Columbia Transmission filed a settlement with the FERC resolving all issues relating to this unrecovered surcharge. The settlement permits Columbia Transmission to continue collecting a surcharge on transportation volumes through October 1994, that would result in the opportunity to collect approximately $42.8 million in additional revenues.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Order No. 636 During 1993, Columbia Transmission and Columbia Gulf implemented the restructured services mandated by the FERC's Order 636. Columbia Transmission has virtually eliminated its merchant function and now offers a variety of unbundled storage and transportation services. In order to implement this restructuring, the companies made a series of filings with the FERC reflecting changes in rates and the terms and conditions under which services would be offered.
On October 22, 1993, Columbia Transmission and Columbia Gulf made their final compliance filing before implementing restructured services, under Order 636, on November 1, 1993. In this filing, the companies complied with previous FERC orders and made various revisions to the terms and conditions applicable to their restructured transportation and storage services. In December 1993, the FERC issued an order on rehearing that permitted Columbia Transmission to retain in its rates, costs which the FERC had previously determined were associated with its merchant function, and approved the level of costs that Columbia Transmission proposed to be allocated to interruptible transportation service.
In the series of orders issued in Columbia Transmission's Order 636 proceeding, the FERC addressed issues related to Columbia Transmission's ability to recover transition costs. The FERC determined that costs incurred by Columbia Transmission as a result of rejecting producer gas supply contracts, in its bankruptcy proceeding in 1991, were not eligible for recovery as Gas Supply Realignment (GSR) costs under Order 636. In addition, recovery of these costs pursuant to Orders 500 and 528 was prohibited by the terms of a 1989 customer settlement. The FERC determined that Columbia Transmission could recover certain contract rejection costs through its existing Gas Inventory Charge (GIC), but only to the extent such costs were not incurred during the 1991 contract year, a period in which Columbia Transmission did not meet the qualifying competitive test under the GIC. If upheld, the FERC rulings, which are subject to pending court review, effectively preclude Columbia Transmission from recovering a significant portion of the producer contract rejection costs from its customers.
The FERC has generally acknowledged Columbia Transmission's right to seek recovery of other types of transition costs. The FERC approved Columbia Transmission's proposal to recover certain purchased gas costs that were incurred prior to Order 636 restructuring. It also agreed to waive a nine-month time limit on Columbia Transmission's ability to seek recovery of unrecovered purchased gas costs to the extent the costs resulted from contracts that are currently in litigation, including bankruptcy litigation. Approximately $60 million in unrecovered purchased gas costs were outstanding at December 31, 1993, in addition to approximately $140 million of prepetition unrecovered purchased gas costs that have not been paid due to the bankruptcy filing.
The FERC also addressed Columbia Transmission's ability to recover costs associated with upstream pipeline contracts. Columbia Transmission currently holds firm transportation agreements with certain pipeline companies that historically have been used to deliver gas to Columbia Transmission. These contracts have remaining terms of various lengths and require the payment of monthly reservation fees whether or not the capacity is utilized. Under Order 636, downstream pipelines such as Columbia Transmission are required to offer to assign most of their firm upstream capacity to their customers. Columbia Transmission's annual demand charge commitments on these upstream non-affiliated pipelines was approximately $108 million; however, assignments of certain of these contracts by Columbia Transmission to its customers in conjunction with service restructuring under Order 636 have reduced this amount to less than $74 million. The total commitment for demand charges after November 1, 1993, is approximately $421 million on an undiscounted basis, excluding any mitigating effect of the pipelines marketing the capacity to others.
Subject to review in connection with periodic rate filings, the FERC approved Columbia Transmission's proposal to continue to recover costs associated with retained upstream pipeline contracts through its demand rates. Recovery of such costs would be subject to review and approval in semiannual limited rate filings. Columbia Transmission
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
has reached settlements that will eliminate approximately half of the annual cost of these contracts and is continuing its efforts to negotiate a mutually agreeable termination of the remainder of the contracts.
Columbia Transmission's strategy has been to assume all upstream pipeline contracts that can be directly assigned to its customers or need to be retained by Columbia Transmission for operational reasons and negotiate exit fees for other upstream contracts. The FERC ruling in the Order 636 proceedings permits recovery of these exit fees through rates, provided that Columbia Transmission can show that they are prudently incurred. Columbia Transmission retains the option of rejecting such contracts in its bankruptcy proceedings, if appropriate exit fees cannot be negotiated. The financial statements reflect a $130 million liability and offsetting receivable for the exit fee issue; however, the ultimate cost could vary depending on the outcome of ongoing discussions with the affected pipelines.
Several settlements with upstream pipelines have been concluded. In 1993, the Bankruptcy Court approved settlements between Columbia Transmission and Texas Eastern Transmission Corporation, Panhandle Eastern Pipe Line Company and Texas Gas Transmission Corporation which provide for assumption of certain contracts and termination of others. None of these settlements required Columbia Transmission to pay an exit fee to the upstream pipeline.
In November 1993, the Bankruptcy Court approved a settlement between Columbia Transmission and Tennessee Gas Pipe Line Company (Tennessee). This settlement provides for Columbia Transmission's assumption of certain contracts, the termination of certain other contracts that are no longer necessary for Columbia Transmission's operations and payment to Tennessee of approximately $42 million in consideration for Tennessee's substantial reduction of its major transportation contracts with Columbia Transmission. On January 11, 1994, Columbia Transmission and Tennessee made a filing at the FERC to approve the settlement. Columbia Transmission expects to ultimately recover the costs and fees associated with the assumption and termination of these contracts under Order 636. The Tennessee settlement agreement is conditioned upon this recoverability.
The FERC affirmed that Columbia Transmission could continue its existing rate structure to recover costs associated with its gathering facilities through its gathering and other transportation rates until it files a general rate case. Management continues to evaluate the long-term plans for Columbia Transmission's gathering facilities which have a net book value of approximately $63 million at December 31, 1993. The regulatory treatment of gathering facilities is currently the subject of a generic FERC proceeding. While the ultimate outcome of issues related to realization of its investment in gathering facilities is uncertain at this time and future charges to income may be required, management believes that substantially all of these costs will be recovered through rates or sale of the facilities.
As part of its September 29, 1993 order on Columbia Transmission's and Columbia Gulf's Order 636 compliance filings, the FERC initiated a proceeding concerning Columbia Gulf's transportation service to Columbia Transmission. Columbia Gulf was directed to show cause as to why it has not filed for FERC abandonment authorization to reduce capacity and service to Columbia Transmission as required under the Natural Gas Act. Columbia Gulf responded to the show cause order on December 22, 1993. Management does not believe an abandonment filing was necessary and does not expect the resolution of this issue to have a material adverse effect on the Corporation's financial position.
One type of transition cost which the FERC acknowledged would be eligible for recovery consideration is "stranded costs", which are the costs of a pipeline's assets previously used to provide bundled sales service in the pre-Order 636 era and are unsubscribed in the Order 636 environment. Columbia Gulf has several pipelines and related facilities that are not fully subscribed to under Order 636. Certain facilities south of Rayne, Louisiana (primarily in the offshore Gulf of Mexico area), are being evaluated; however, management has not identified any stranded facilities at this time and the outcome of these evaluations is uncertain. Dependent upon the results of such evaluation, charges to income could be required. The net book value of the facilities under study was approximately $40 million at December 31, 1993. It is management's view that any costs associated with these facilities will be fully recoverable through rates.
Order 94 Settlements On January 12, 1994, the FERC granted requests for rehearing of prior orders approving settlements between
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Columbia Transmission and four of its upstream pipeline suppliers relating to those suppliers' direct billings to Columbia Transmission of the FERC's Order 94 (Order 94) costs in the mid-1980s. The rehearing orders found that the settlements must be rejected because they are expressly contingent upon Columbia Transmission's recovery of the Order 94 settlement payments from its customers and Columbia Transmission's 1985 PGA Settlement essentially bars such recovery. The orders also hold that these pipelines are not entitled to bill any Order 94 charges to Columbia Transmission. The FERC ordered these upstream pipelines to refund the principal amounts of all Order 94 collections from Columbia Transmission, but waived any requirement that these pipelines pay interest on the refunds. Since Columbia Transmission has been reflecting the interest income on these refunds since 1990, these orders led to a $19.5 million reduction to interest income in 1993. Columbia Transmission has sought rehearing and, if necessary, will seek court review of these orders. It is expected that pipeline suppliers will also request rehearing arguing their rights to re-bill such charges to Columbia Transmission. The ultimate outcome of this issue is uncertain at this time and could impact future operating results depending upon the results of these additional regulatory and court reviews.
Environmental Matters Columbia Transmission and Columbia Gulf are subject to extensive federal, state and local laws and regulations relating to environmental matters. These laws and regulations, which are constantly changing, require expenditures for corrective action at various operating facilities and waste disposal sites for conditions resulting from past practices that subsequently were determined to be environmentally unsound.
The transmission subsidiaries have received notice from the United States Environmental Protection Agency (EPA) that they are among several parties responsible under federal law for placing wastes at Superfund sites and may be required to share in the cost of remediation of these sites. However, considering known facts, existing laws and possible insurance and rate recoveries, management does not believe the identified Superfund matters will have a material adverse effect on future income or on the Corporation's financial position.
The transmission subsidiaries are continuing their comprehensive review of compliance with existing environmental standards, including review of past operational activities and identification of potential site problems, through site reviews and formulation of remediation programs where necessary. The transmission subsidiaries have made progress in these ongoing self- assessment programs. However, because of the thousands of miles of pipeline which they operate, the exceptionally large number of sites at which they conduct or have conducted operations, and the long period over which operations have been conducted, completion of site screenings, characterizations and site-specific remediations will require approximately 10 to 12 years. All environmental agencies have been declared exempt from the Bar Date established by the Bankruptcy Court for claims by creditors.
A study for Columbia Transmission to quantify the scope of remediation activities which will be undertaken in future years to address the issues identified was recently concluded. This study, site investigations and characterization efforts performed throughout 1993, resulted in total accruals for the year of approximately $60 million for Columbia Transmission. These and other minor adjustments bring Columbia Transmission's recorded net liability to $143.6 million at December 31, 1993. This represents the lower end of the range of reasonable outcomes with the upper end estimated to total approximately $280 million based on information currently available.
As characterization and site-specific activities by Columbia Transmission determine the nature and extent of contamination at its facilities and as remediation plans are developed, additional charges to earnings could occur. To the extent such plans require approval of federal and/or state authorities, estimates are subject to revision. Based on the limited data now available and various assumptions as to characterization and remediation, management believes that annual future expenditures for Columbia Transmission's site investigations, characterization and remediation activities could be up to $20 million per year over a 10- to 12- year time frame. Since the transmission companies do not account for their operations under SFAS No. 71, earnings will continue to be charged as costs become probable and reasonably estimable, regardless of when expenditures are made.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
As a result of site characterization studies at various locations during 1993, Columbia Gulf recorded an additional accrual of $6.7 million for environmental remediation. This accrual is for polychlorinated biphenyl (PCB) cleanup and hydrocarbon spills at certain compressor station sites and screenings for possible exposure at other locations. Columbia Gulf anticipates completion of cleanup during 1994. At that time, costs of remediation, if any, will be quantified, and an additional accrual may become necessary.
In 1992, Columbia Transmission received a subpoena and information request (Request) from the EPA Region III regarding three major environmental statutes: The Toxic Substance Control Act (TSCA), the Resource Conservation and Recovery Act (RCRA), and the Comprehensive Environmental Response Compensation and Liability Act (CERCLA). The Request relates to Columbia Transmission's past and current environmental practices. Since receipt of the Request, Columbia Transmission has provided the EPA with substantial materials regarding the Request. Columbia Transmission continues to meet with the EPA to attempt to resolve the subpoena issues, including related fines and penalties, which it believes will be resolved in the near future.
Columbia Transmission on January 28, 1994 received from EPA Region V an Information Request pursuant to RCRA. The agency requested Columbia Transmission to submit information and knowledge relating to its generation and management of natural gas pipeline condensate, used engine oil and similar liquids in the state of Ohio. Columbia Transmission is in the process of analyzing the information requested and will be discussing this Information Request with EPA Region V.
It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred by Columbia Transmission and Columbia Gulf.
The eventual total cost of full future environmental compliance for Columbia Transmission and Columbia Gulf is difficult to estimate due to, among other things: (1) the possibility of as yet unknown contamination; (2) the possible effect of future legislation and new environmental agency rules; (3) the possibility of future litigation; (4) the possibility of future designations as a potentially responsible party by the EPA and the difficulty of determining liability, if any, in proportion to other responsible parties; (5) possible insurance and rate recoveries; and (6) the effect of possible technological changes relating to future remediation.
Management expects most environmental assessment and remediation costs to be recoverable through rates or insurance. Although significant charges to earnings could be required prior to rate recovery, management does not believe that environmental expenditures will have a material adverse effect on the Corporation's financial position based on known facts, existing laws and regulations and the period over which expenditures are required.
Clean Air Act Amendments of 1990 Columbia Transmission and Columbia Gulf have completed preliminary studies to determine the impact of the Clean Air Act Amendments of 1990 (CAA-90). The studies focused on various compressor facilities for both companies. The facilities are among those affected by the new nitrogen oxide emission standards under CAA-90. It is estimated that capital expenditures necessary to comply with these new standards could be in excess of $30 million over the next few years. However, due to the preliminary nature of the studies, the uncertainty of individual state regulations and other variables, the actual amount of future expenditures related to CAA-90 is difficult to estimate. Management anticipates that all capital expenditures made in compliance with CAA-90 will be recoverable through the rate-making process. Operation and maintenance expenses, including monitoring of emissions and permit fees, could approximate $5 million to $10 million per year for the transmission companies.
Partnership Issues Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark pipeline partnerships. Since these partnerships are nonrecourse project-financed pipelines, the partnerships' firm shipper contracts were assigned to various banks (or in the case of Ozark, to the Indenture Trustee) as collateral for loans.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Columbia Transmission and other shippers are attempting to negotiate exit fees under Order 636 with the partnerships. As a result of these negotiations and the current depressed demand for capacity in certain of the partnerships, the realizability of these investments is uncertain, and a valuation reserve of $5.4 million was established in 1993. It is not expected that these issues will be resolved until late 1994. At December 31, 1993, Columbia Gulf's investment in the partnerships amounted to $35.4 million, net of the valuation reserve and before related deferred taxes.
Cove Point LNG Terminal As previously reported, Columbia LNG Corporation (Columbia LNG) has developed a new business plan to reactivate the Cove Point facility. Originally this plan anticipated a new peaking and storage service by the end of 1994, as well as a terminalling service for liquefied natural gas (LNG) received by tanker. However, that plan has been modified to where now only a peaking service will be offered initially. As a consequence, Columbia LNG recorded a writedown in the carrying value of its investment in the Cove Point facility in the second quarter 1993 that reduced the Corporation's income by $37.9 million after-tax. This amount included estimated dismantling costs for the offshore facilities of approximately $12 million after-tax. Until transferred to the new partnership, as discussed below, Columbia LNG plans to maintain the offshore facilities for possible future imports and at the present time has no plans to abandon or dismantle them.
A partnership between Columbia LNG and a wholly-owned subsidiary of Potomac Electric Power Company was formed in October 1993. The partnership, which is pursuing Columbia LNG's business plan filed an application with the FERC on November 3, 1993, seeking authorization to acquire all of the existing plant and pipeline facilities owned by Columbia LNG and for authorization to recommission the plant and construct new facilities in order to provide peaking services beginning in 1995. In addition to the FERC, this transaction will require other governmental approvals. Bankruptcy Court approval was received in January 1994.
The realization of the Corporation's remaining investment in Columbia LNG of $10.1 million will be dependent upon successful implementation of the partnership and the related business plan.
Volumes Throughput for Transmission includes tariff sales and transportation service to local distribution companies (LDCs) and other customers in Columbia Transmission's market area, Columbia Gulf's main line transportation service from Louisiana to West Virginia and Columbia Gulf's short-haul transportation service primarily from the Gulf of Mexico to Rayne, Louisiana. Transmission's throughput in 1993 was 1,355.9 Bcf, a decrease of 18.4 Bcf from 1992. In 1992, throughput increased 144.8 Bcf over 1991 to 1,374.3 Bcf.
A decrease of 13.1 Bcf in market area transportation between 1993 and 1992 was due primarily to the one-time arrangement in 1992 in which customers used market area transportation to repay certain gas delivered to them during the 1990 - 1991 winter season by Columbia Transmission. Throughput losses not associated with prior period activity also occurred primarily due to competition from other pipelines that began operating under Order 636 (or a modified version thereof) earlier this year. As expected, this load loss began to reverse following Columbia Transmission's implementation of Order 636 in November 1993, when its transportation rates became more competitive. This effect was partially offset by a throughput improvement resulting from customers using firm transportation services for delivering gas withdrawn from storage during 1993. In 1992, customers' increased use of Columbia Transmission's firm storage service (FSS) led to an increase of 59.1 Bcf in market area transportation from the year before.
Columbia Gulf's 1993 mainline transportation service increased 5.6 Bcf from 1992 and between 1992 and 1991 increased by 38.9 Bcf. These increases primarily reflect additional transportation services for customers to move gas to Columbia Transmission's storage under its FSS agreement and to meet their supply requirements. Prior to the implementation of Order 636, a portion of Columbia Gulf's mainline capacity was reserved for Columbia Transmission's use for deliveries to LDCs and other markets. Beginning on November 1, 1993, however, Columbia Gulf's capacity was assigned to LDCs and end users.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Short-haul transportation has been increasing in recent years, reflecting additional arrangements made by marketers and customers for delivery of lower-priced spot market gas. In 1993, short-haul transportation was essentially unchanged from last year and reflected an increase of 60.3 Bcf between 1992 and 1991.
Sales volumes for 1993 decreased 12.3 Bcf from 1992 due primarily to the implementation of Order 636. This decrease was partially offset by colder weather in the current period and the timing of prepaid gas sales. Comparing 1992 to 1991, sales increased 83.4 Bcf reflecting 10 percent colder weather, timing changes for prepaid gas sales and Columbia Transmission's competitive market-sensitive commodity rate, that resulted from the rejection in Bankruptcy Court of noncompetitive above-market gas purchase contracts.
Net Revenues Transmission's 1993 net revenues of $841.5 million increased $80.1 million over 1992. Included in 1993's net revenues are $20.3 million associated with the recovery through Columbia Transmission's WACOG surcharge, as discussed previously, and GIC revenues of $20.8 million. 1992 GIC revenues were $20.9 million. The GIC mechanism allowed Columbia Transmission to charge a fee to customers whose purchases fell below a pre-determined level provided Columbia Transmission's cost of gas meets a comparability test with competing pipelines. Also improving 1993 net revenue was an adjustment to rate refund reserves and the favorable effect of normal weather. These effects combined with the benefit of the full year effect of Columbia Transmission's new rate design where a greater portion of its fixed costs are recovered through a monthly demand charge more than offset the recording of a loss on the sale of storage inventory.
Net revenues for 1992 increased to $761.4 million, up $126.9 million over 1991 principally reflecting improved rate design together with higher throughput and GIC revenues.
Operating Income (Loss) Operating income for 1993 of $178.7 million, increased $48.8 million over 1992. Higher net revenues together with a 1992 provision for gas supply costs combined to more than offset the effect of recording a second quarter 1993 writedown of $57.5 million for the investment in the Cove Point LNG facility (See Note 12F in Notes to Consolidated Financial Statements for more information). Additional reserves for environmental costs of $66.8 million and $65.3 million were recorded in 1993 and 1992, respectively. After adjusting for these and other unusual items, operating income would have increased $37.8 million. These improvements more than offset higher operating expenses, including increased labor and benefits costs due in part to employee severance costs. These costs resulted from reengineering Transmission's operations to improve the segment's efficiency and effectiveness in the increasingly competitive natural gas industry.
Transmission's 1992 operating income of $129.9 million compares to a loss of $1,192.2 million for 1991. The principal reason for the increase was the 1991 provision for gas supply charges of $1,319.2 million. After adjusting for bankruptcy and other unusual items, Transmission's operating income would have improved $62.1 million in 1992 over 1991, due to increased throughput and rate design changes.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM TRANSMISSION OPERATIONS (UNAUDITED)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
TRANSMISSION OPERATING HIGHLIGHTS
* Includes 116 billion cubic feet applicable to the sale of storage inventory gas.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATIONS
Market Conditions For the first time in four years, weather in the market area served by the distribution companies (Distribution) was colder than normal. Weather was only 1 percent colder than normal but 3 percent colder than last year, and resulted in a 7.7 Bcf improvement in Distribution's weather sensitive deliveries. In addition, relatively strong economic conditions throughout Distribution's service territory, low interest rates, strong new housing starts in several key market areas, and moderate unemployment, enabled Distribution to add about 28,000 net residential and commercial customers during the year, a 1.5 percent growth rate that tracks last year's growth and compares favorably with the national average. Transportation deliveries in 1993 increased 13.8 Bcf, 6.8 percent over 1992, reflecting strong electric power generation demand and increasing industrial activity.
Distribution's electric competitors continue to pursue well-organized, heavily funded strategic initiatives targeting markets such as space and water heating. Electric companies in Distribution's markets are using a variety of aggressive measures such as equipment leasing programs, rebates and promotional incentives to make marketing inroads. These marketing efforts have resulted in a reduction of approximately 0.6 percent in Distribution's space heating load as a result of electric add-on heat pump penetration and a 1.4 percent reduction in gas water heating saturation since 1987. As a result, Distribution has been countering with its own strategic programs such as equipment leasing, targeted advertising and promotional activity that is designed to bolster Distribution's core marketing and counter these negative competitive impacts.
Distribution's marketing strategy is to augment ongoing development of its core residential, commercial, and industrial markets by pursuing opportunities to develop new markets for natural gas in the areas of natural gas vehicles (NGV), electric power generation and gas cooling.
Distribution is a leading participant in the gas industry's efforts to promote NGVs as alternatives to conventionally fueled fleet and mass transit vehicles. In March 1993, Columbia Gas of Ohio, Inc. (COH) opened the nation's largest publicly accessible NGV fueling station in Columbus, Ohio. Distribution operates five other publicly accessible stations and is initiating a five-year program to establish approximately 100 additional publicly accessible fueling sites throughout its service territory. Distribution is also committed to maximizing the number of NGVs in its own fleet over the next several years to approximately 2,500, and continues to work with commercial and industrial prospects to assist them in evaluating NGVs for fleet applications.
Distribution's concentration on public sector initiatives is also yielding results. Recently, Virginia enacted laws to provide tax credits and reduced fuel taxes for alternative fuel vehicles (AFV) as well as require federal Clean Fuel Fleet programs in two areas beyond requirements of federal law. Pennsylvania established a $3.5 million fund to provide up to a 60 percent grant for purchases of AFVs and AFV filling equipment. Pending are initiatives in Kentucky to exempt NGVs from motor fuel testing and a proposal in Ohio to provide partial sales and use tax exemptions for the purchase of AFVs and filling equipment.
Distribution continues to actively pursue the developing power generating market. Distribution currently serves 15 power generation and cogeneration facilities which consume about 30 Bcf of natural gas each year. CAA-90 offers significant new opportunities to promote the use of natural gas for electric power generation. Commonwealth Gas Services, Inc. (COS) reached agreement with Gordonsville Energy Limited Partnership to transport gas for a new combined cycle generating plant which will produce electric power for a Virginia utility beginning in mid-1994 which is expected to use approximately 3.0 Bcf of gas annually. Distribution is currently working with five additional prospects, both existing and new electric power generating plants, that may want to use natural gas in order to comply with the CAA-90 by the year 2000.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Distribution's customers operate commercial and industrial cooling and refrigeration systems with a capacity of approximately four million refrigerant tons. Less than one percent of this cooling and refrigeration load, roughly 0.2 Bcf, is currently served by gas cooling equipment. Distribution is aggressively pursuing this market. With improved gas cooling equipment, rising peak electric costs and concerns about the environmental effects of chlorofluorocarbon refrigerants, Distribution has an opportunity to add significant load in the summer months when demand for gas is relatively low. The GRI estimates that 30-50 percent of this market could be served economically with gas cooling systems. Sales of gas cooling equipment in Distribution's service territory increased tenfold in 1993 to 3,096 refrigerant tons, or about 1.5 percent of total new and replacement equipment sales and 6 percent of large tonnage chiller sales.
Rate Cases During 1993, Distribution filed two rate cases. COS filed an expedited rate case for a $3.5 million annual revenue increase, seeking recovery of increased operating expenses and a return on additional plant investments since COS' 1992 general rate case. A final order in this expedited proceeding is expected by June 1994.
The Virginia State Corporation Commission (VSCC) in October 1993, issued an order resolving COS' 1992 general rate case. While the VSCC provided a favorable increase in annual revenues of $5.6 million, a 4.5 percent increase, it did not adopt an array of regulatory reform proposals advanced by COS that included establishing rates based on a fully projected test year and a weather normalization clause.
In October 1993, the Maryland Public Service Commission approved a rate settlement for Columbia Gas of Maryland, Inc. (CMD) that provided for a two-step increase in annual revenues of $2.2 million beginning October 1993, implementation of a weather normalization adjustment effective with the winter season which began November 1993, as well as full recovery of postretirement medical benefit costs.
In contrast to 1993, Distribution's rate activity for 1994 is expected to accelerate and may involve up to four general rate cases to recover increasing costs. Columbia Gas of Pennsylvania, Inc. (CPA) filed a rate case in early 1994 and filings are tentatively scheduled in Ohio for the first quarter and in Virginia and Kentucky on or about May 1. Distribution's total revenue request could range between $90 and $100 million or roughly 5 percent of its total revenue. Even though these filings are scheduled early in the year, new rates will not be effective until the fourth quarter of 1994 or later. All filings will incorporate the regulatory initiatives currently being pursued by Distribution and addressed below.
Strategic Regulatory Issues Distribution continues to actively pursue an array of regulatory reform initiatives designed to overcome regulatory barriers in the increasingly competitive Order 636 era. It is advocating a comprehensive package of new services, increased revenue levels and incentive rate mechanisms. Specific elements include the use of enhanced projected ratemaking and cost deferral mechanisms to mitigate adverse timing lags, cost containment and enhanced customer service and supply initiatives, and revenue stabilization mechanisms to mitigate the effects of unusual weather conditions and take into account typical increases in operation and maintenance expenses and capital expenditures without resorting to time consuming and costly general rate case proceedings.
While no state commission has yet adopted Distribution's comprehensive reform package, Distribution has made notable strides in some of its jurisdictions, including the innovative settlement in Maryland mentioned above reflecting many elements of its comprehensive initiative. In Ohio, COH has been involved in proposed legislation that provides utilities the option of filing rate cases on a fully projected test year basis. In Pennsylvania, CPA is supporting a number of the Public Utility Commission's (PUC) recently announced initiatives aimed at providing more regulatory responsiveness and flexibility, specifically, recognizing in rates construction work in progress for certain investments placed in service after the ratemaking test year.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
FERC Order 636 Distribution successfully began the transition into the new environment created by Order 636. All of the requirements mandated by the Order have been implemented by Distribution's interstate pipeline suppliers and thus far operations have been running smoothly despite the much colder than normal weather experienced in early 1994. Over the next several years, additional pipeline filings and related FERC orders, addressing the recovery of pipeline transition costs stemming from Order 636, are expected. However, based on current estimates of these transition costs and indications from state commissions, management does not expect the transition costs to have a significant adverse impact on Distribution's earnings or customer rates.
Gas Supply Distribution has developed supply arrangements and operating plans and has aggregated gas supplies to meet market needs in a flexible, cost- effective manner. Distribution entered the 1993-94 winter heating season with storage inventory near maximum levels and with a short-term purchasing/operating plan designed to fully satisfy firm retail and standby service obligations during periods that are up to ten percent colder than normal. Early operating experience during the extreme cold weather conditions of mid-January 1994, when peak design conditions were met or exceeded over the course of two consecutive days, thoroughly tested Distribution's capabilities. Throughout this extraordinary period of record-setting peak demands, Distribution's facilities maintained deliveries and adequate gas supplies were available. Beyond a few isolated operating problems and certain brief limitations on customers who elected to contract for interruptible service, reliable customer service was maintained.
Environmental Matters Distribution has initiated a comprehensive environmental program designed to ensure complete and prompt compliance with all state and federal environmental requirements. As part of this program, Distribution is continuing the process of conducting an environmental assessment of its sites and evaluating procedures. The assessment and evaluation process will continue over the next three to five years.
Distribution's primary environmental issues relate to former manufactured gas plant sites. Currently, Distribution has identified twelve former gas plant sites that it either owned or acquired through facility purchases. Environmental investigations are being conducted at five of these sites and remedial action may be required. Investigations will be conducted at a number of the other sites in the near future. Manufactured gas plant sites currently being investigated include areas in York and Bellefonte, Pennsylvania, and Portsmouth, Petersburg and Lynchburg, Virginia. (See Note 12H of Notes to Consolidated Financial Statements for additional information regarding these sites.)
To the extent site investigations have been completed, remediation plans developed and any Distribution responsibility for remedial action established, the appropriate liability has been recorded. As additional investigations are completed and remediation costs become probable, the appropriate liability will be recorded. As of December 31, 1993, the distribution subsidiaries recorded net liabilities of $5.9 million for environmental matters. Management anticipates recovery of remediation costs through normal rate proceedings.
SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions (OPEB) Management anticipates that full rate recovery of its accrued OPEB costs in all states is likely, based on the state commissions' awareness of this issue and favorable generic policy decisions in a number of jurisdictions coupled with Distribution's cost management efforts and plans to fully fund all postretirement benefits allowed in rates in irrevocable trust arrangements.
The present value of the postretirement benefit obligation to be paid to current and retired employees for all the distribution subsidiaries amounts to approximately $143.2 million as of December 31, 1993. Of this amount, $138.1 million has been deferred as a regulatory asset pending anticipated recovery through rates in various jurisdictions.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board issued guidelines establishing criteria for recording such a regulatory asset, including a requirement for collection of accrual basis expense in rates and recovery of the transition obligation within approximately 20 years. These criteria are not necessarily being adopted by the public utility commissions regulating the distribution subsidiaries. Differences in requirements between the accounting rules and the ratemaking decisions ultimately adopted can result in a writedown of some or all of this regulatory asset. The distribution subsidiaries have implemented cost containment measures designed to reduce their OPEB obligations. In addition to other measures, employees will be required to share a portion of their postretirement health benefit costs and guidelines have been established redefining years of service requirements before an employee is eligible for retiree health benefits. Other cost-saving plans are being reviewed for consideration in an ongoing effort to effectively manage OPEB costs.
Integrated Resource Planning Integrated Resource Planning (IRP) combines the concepts of supply side and demand side management (DSM). The DSM component of IRP generally deals with programs to reduce customer demand, particularly during peak demand periods, and thereby reduce the need to construct or acquire additional supply capacity. The supply side component of IRP generally involves the evaluation of supply options, including the acquisition of supply from alternative sources or supply arrangements.
IRP was first implemented for electric utilities by state utility commissions because of the major investments required to add new electric generating capacity and the resultant impact of these investments on customer rates. However, state commissions in Distribution's market area are now actively considering the adoption of natural gas IRP programs. Distribution generally regards this as a positive development since it provides a more balanced competitive situation between gas and electric utilities. Distribution has significant concerns that electric DSM programs, if not properly controlled by state regulators, could result in ratepayer-financed marketing programs and incentives that would inappropriately influence long-term purchases committing customers to electric use.
The proper development of gas IRP programs should enable Distribution to continue to compete for new load and replacement appliances and equipment to improve system load factors and operating economics. However, certain significant competitive concerns remain because electric utilities can generally support higher incentives for customers to purchase certain electric appliances because it is far more expensive to expand electric generating capacity than to expand gas distribution capacity to deliver the same quantity of useful energy. Also, most commissions have been reluctant to deal with the relative environmental impacts of using natural gas versus coal, oil or nuclear generated electric power for residential and commercial end uses, which would result in reduced overall emissions and provide higher incentives for gas usage.
Distribution's IRP efforts are designed to encourage state regulators to deal with utility IRP programs on a comprehensive basis. Distribution believes that under such an approach, commissions are more likely to recognize the many significant advantages of using natural gas rather than electricity for most residential and commercial and many industrial end uses or at a minimum, work to maintain more competitive parity between gas and electric rates. Distribution is working aggressively to communicate the many advantages of a comprehensive approach to IRP.
Volumes Throughput for 1993 totaled 509.8 Bcf, a 23.1 Bcf increase over 1992. Higher transportation deliveries of 13.8 Bcf were due mainly to increased usage by power generating facilities in Virginia and Pennsylvania. The 9.3 Bcf increase in tariff sales volumes reflects higher customer usage due primarily to 3 percent colder weather and the net addition of approximately 28,000 customers.
Distribution's throughput for 1992 increased 30.3 Bcf over 1991 after adjusting for the 1991 sale of a New York subsidiary. Despite 1992 being 2 percent warmer than normal, it was still 10 percent colder than the prior year.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
This colder weather and the net addition of 28,000 new customers led to higher sales volumes. Transportation volumes also increased in 1992 due largely to increased deliveries to power-generating facilities as well as other customers using this service to meet their supply requirements.
Net Revenues For the year ended December 31, 1993, net revenues of $726 million reflected an increase of $29.5 million over the same period last year. Increased throughput generated $18.7 million of this improvement. Additionally, new rates in effect during 1993 in Virginia and Maryland and the full year impact of rates placed in effect in 1992 combined to generate $7.6 million with revenues for fixed charges from new customers accounting for most of the remaining $3.2 million increase.
Colder weather was the principal reason for 1992's net revenues increasing to $696.5 million. After adjusting for the sale of the New York subsidiary in 1991, the net revenues in 1992 represented an increase of $62 million over 1991. The full year effect of favorable rate settlements in all of Distribution's operating areas also contributed to the higher net revenues.
Operating Income Operating income improved $8.7 million over the previous year. Higher net revenues of $29.5 million were partially offset by increased operating expenses of $20.8 million. An $8.8 million increase in operation and maintenance expense reflecting wage increases, additional personnel requirements associated with the implementation of Order 636, as well as the filling of certain vacancies that had been deferred and higher lease costs for the Columbus, Ohio headquarters building were the primary reasons for the increase. Additionally, costs for the streamlining of corporate service functions and studies underway to enhance customer service also contributed to the increase. These increases were partially offset by a $4.2 million charge recorded in 1992 for COS OPEB costs. Depreciation expense increased $4.7 million primarily reflecting plant additions, while increased gross receipts taxes and property taxes of $7.3 million were attributable to higher taxable revenues and plant additions.
After adjusting for the sale of the New York subsidiary, operating income in 1992 of $137.7 million increased $27 million over 1991 as higher net revenues were partially offset by increased operating expenses. Increased operating expenses of $558.8 million resulted primarily from higher labor and benefit costs and the effect of regulatory lag that resulted in only a portion of increased costs being recovered through rates.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF OPERATING INCOME FROM DISTRIBUTION OPERATIONS (UNAUDITED)
* Includes Columbia Gas of New York, Inc. through March 31, 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
DISTRIBUTION OPERATING HIGHLIGHTS*
* Includes Columbia Gas of New York, Inc. through March 31, 1991. ** Reflects volumes under purchase contracts of less than one year.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
OTHER ENERGY OPERATIONS
Cogeneration Independent power production continues to be a growth area for natural gas. The Corporation is involved in several cogeneration projects through TriStar Ventures Corporation (TriStar), a wholly-owned subsidiary. Projects in operation or under construction total nearly 300 megawatts in which TriStar holds various interests. Three cogeneration facilities are now operating; a 117-megawatt facility in Pedricktown, New Jersey, a 50-megawatt plant in Binghamton, New York and an 85-megawatt plant in Rumford, Maine. Natural gas is delivered to the Binghamton and Pedricktown facilities by Columbia Transmission. These three projects generated $5.8 million and $4.5 million of income before interest and income taxes in 1993 and 1992, respectively. A 47-megawatt plant near Vineland, New Jersey is scheduled to begin operations in mid-1994. TriStar and its partners also have other projects in various stages of development. Value is also generated from the projects for the transmission subsidiaries of the Corporation who benefit from increased throughput while the oil and gas segment has increased sales opportunities.
TriStar was participating in the development of a 56-megawatt plant in Washington, D.C. on which construction had been delayed pending regulatory review and approval. On October 13, 1993, processing of the building permit was suspended indefinitely by the District of Columbia. This action combined with numerous regulatory delays, caused the project to become financially nonviable. Accordingly, TriStar and its partner halted efforts to build the project and TriStar wrote off its net investment in the project of $3.1 million after-tax. On November 1, 1993, the partnership filed an $80 million lawsuit in federal court against the District of Columbia and certain District officials.
Propane During 1993, propane sales by Columbia Propane Corporation and Commonwealth Propane, Inc., totaled 58.1 million gallons, a decrease of 8 percent from the previous year. The propane companies serve approximately 68,000 customers in parts of Maryland, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. The companies are focusing their sales efforts on the higher-margin residential segment.
Coal Operations The Corporation has in excess of 500 million tons of coal reserves. Approximately 50 percent of the reserves, much of which contain less than one percent sulfur, are leased to other parties for development.
Environmental Matters The Columbia Gas System Service Corporation (Service Corporation) received a "General Notice of Potential Liability and CERCLA Section 104(2) Request for Information" concerning a process site to which the Service Corporation sent certain solvents. This notice was sent to in excess of 100 parties requesting information about any involvement with the owner of the site or the site itself. Management has furnished the information requested and does not believe this Superfund matter will have a material adverse effect on future income or on the Corporation's financial position.
Net Revenues Propane sales to wholesale and industrial customers have been decreasing over the past few years due to unacceptable margins while, to a lesser extent, sales to higher-margin residential customers have been increasing. As a result of this strategy, total sales volumes have decreased, but net sales revenues have been rising. This change led to net sales revenues of $29.8 million in 1993, an increase of $2.5 million, and in 1992 an increase of $700,000 compared to the year earlier. Increases in revenues resulting from gas marketing activities were largely offset by increased products purchased expense.
Revenues in 1993 from services provided to affiliates and coal royalties resulted in an increase in other revenues of $3.1 million, to $73.4 million, from the prior year. Other revenues in 1992 of $70.3 million, were $5.2 million
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
lower than the year earlier primarily because a decrease in revenues from affiliate companies more than offset higher coal royalty revenues.
Operating Income The net revenue increase of $5.6 million was more than offset by $10.7 million higher operating expenses primarily reflecting increased labor and benefits costs that included employee severance costs recorded in 1993. The 1992 net revenue decline of $4.5 million compared to 1991 was more than offset by reduced operating expenses of $6.4 million, resulting from lower labor and benefits costs in 1992 due to a reduction in the number of employees and a charge in 1991 for employee severance costs.
STATEMENTS OF OPERATING INCOME FROM OTHER ENERGY OPERATIONS (UNAUDITED)
OTHER ENERGY OPERATING HIGHLIGHTS
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
CONSOLIDATED REVIEW
Net Income The Corporation reported net income for 1993 of $152.2 million, or $3.01 per share, compared to $51.2 million, or $1.01 per share in 1992. After adjusting for the unusual and bankruptcy related items detailed below, 1993 net income of $155.1 million was up $56.4 million over the prior year. The oil and gas, transmission and distribution segments all experienced improved results in 1993. These improvements resulted from increased throughput, the full year effect of a new rate design implemented by the transmission companies as well as lower depletion expense, higher prices for gas production and increased oil and gas production for the oil and gas segment. The distribution segment's results improved because the weather was 3 percent colder than 1992 and because of higher transportation volumes.
Unusual and Bankruptcy Related Items After-tax Effect on Net Income
* Reflects charges that are allowed to be collected by Columbia Transmission to recover costs when it meets certain competitive tests for its commodity sales rate or cost of gas.
Operating Income by Segment The oil and gas segment had operating income of $53.6 million in 1993, compared to an operating loss of $101.2 million in 1992. The prior period loss was mainly due to a writedown of $126.4 million in the carrying value of oil and gas assets due to low energy prices. Lower depletion expense, higher gas prices and increased oil and gas production also contributed to the current period increase and were only partially offset by lower oil and liquids prices and the recording of a reserve for a royalty dispute with the MMS. The average gas price in 1993 was $2.28 per Mcf, up $0.26 per Mcf over last year, whereas the average price for oil and liquids decreased to $16.17 per barrel, down $2.03 per barrel from 1992. Oil and gas production for 1993 of 3,603,000 barrels and 71.5 Bcf, increased 542,000 barrels and 2.3 Bcf, respectively, over last year.
The transmission segment's 1993 operating income of $178.7 million, up $48.8 million, reflected a significant improvement over the 1992 level. After adjusting for the pre-tax effect of the unusual items, operating income increased $37.8 million over 1992. Included in these unusual items are increased revenues from GIC and WACOG
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
revenues Columbia Transmission is permitted to recover from its customers when it met certain competitive tests with other pipelines. These sources of revenue were unique to Columbia Transmission's merchant function which was essentially eliminated under Order 636. After adjusting 1992 throughput for a customer exchange arrangement, throughput improved resulting in higher revenues. This effect together with the full year effect in 1993 of Columbia Transmission's new rate design were the principal reasons for the $37.8 million improvement. Under this new rate design, a greater portion of fixed costs are collected through a monthly demand charge rather than the commodity charge where they are susceptible to weather fluctuations. Gas costs continue to be recovered through commodity charges. Also contributing to the 1993 improvement over 1992 was approximately $15 million of additional expense recorded in the prior period for settlements with a supplier.
Weather in the distribution segment's service areas was 3 percent colder than 1992. The colder weather helped raise 1993 operating income to $146.4 million, an increase of $8.7 million over 1992. Improved recovery of costs through higher rates in effect in Virginia and Maryland contributed to the increase. Mitigating these improvements were higher operating expenses that included increases in labor and benefits expense and costs associated with streamlining corporate service functions and studies underway to enhance customer service.
Other energy operations had operating income of $1.7 million, a decrease of $5.1 million compared to 1992. The reduction primarily reflects recording $6.3 million for costs associated with the Service Corporation's reengineering program.
Revenues Operating revenues for 1993 of $3,391.2 million, increased more than 16 percent from the year earlier largely due to the full year effect of Columbia Transmission's new rate design, pipeline exit fees of $130 million for Columbia Transmission, higher retail sales resulting from colder weather during 1993 and higher distribution rates. In addition, Columbia Transmission's WACOG revenues, sale of storage to customers, higher gas prices and increased oil and gas production also contributed to the improvement. Revenues associated with pipeline exit fees were offset in products purchased expense and had no effect on income.
Operating revenues for 1992 increased $345.2 million over 1991 to $2,922 million due to a combination of higher sales volumes as a result of colder weather, the full year effect of higher distribution rates and Columbia Transmission's new rate design and more competitive sales rate.
Expenses Over the last three years, higher sales necessitated an increase in volumes of gas purchased resulting in an increase in products purchased expense of $337.6 million in 1993, compared to 1992, and $180.4 million for 1992 over 1991. In addition, higher average rates for gas purchased, particularly spot market purchases, also contributed to the increase in 1993. Higher expense for pipeline exit fees were offset in revenues as mentioned above.
In 1992, Columbia Transmission anticipated only a minimal merchant function would be offered when Order 636 was implemented in November 1993; therefore, a provision for gas supply charges of $38.6 million was recorded to reflect a writedown of certain capitalized gas costs in excess of amounts to be amortized in 1993.
Higher labor and benefits expense in 1993, which included $14.8 million for severance costs associated with reengineering many of the System functions to gain efficiencies and improve competitiveness, together with rising operating costs led to higher operation and maintenance expense of $26.5 million. Partially offsetting these increases was higher expense in 1992 for certain supplier settlements by Columbia Transmission. Raising expense in both 1993 and 1992 were environmental costs of $66.8 million and $65.3 million, respectively.
The higher environmental costs recorded in 1992 and increased labor and benefits expense of Columbia Transmission
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
were the primary reasons for the $111.3 million increase in operation and maintenance expense over 1991. Additional expenses in 1992 associated with certain producer settlements also contributed to the increase.
Due to depressed energy prices in early 1992, a writedown was recorded of $126.4 million in the carrying value of oil and gas properties. This was the principal reason for the $128.3 million decrease in 1993 in depreciation and depletion expense. The significant increase in depreciation and depletion expense of $83.1 million in 1992 over 1991 was also the result of this writedown, which was partially offset by writedowns for the Canadian oil and gas properties in 1991.
Income Taxes As detailed in Note 5 of Notes to Consolidated Financial Statements, income taxes in 1993 increased $65.4 million over last year reflecting increased income, adjustments due to the IRS settlement and the increased tax rate. In 1992, income taxes increased $481.5 million as the Corporation had pre-tax book income in 1992 compared to a loss in 1991.
Other Income (Deductions)
Other Income (Deductions) reduced income in 1993 and 1992 by $85.3 million and $1.5 million, respectively. In 1993, interest expense increased $87.8 million due largely to recording interest on prior years' taxes of $74.5 million primarily as a result of the IRS settlement. Interest income and other, net decreased $13.2 million primarily reflecting $19.5 million for a FERC order eliminating interest payments from certain upstream pipeline suppliers and a reserve for pipeline partnership investments partially offset by increased interest income on prior years' taxes and other issues. Income was improved in 1993 and 1992 by approximately $212.4 million and $224.9 million, respectively, from not accruing interest expense for prepetition obligations. (Since the July 31, 1991 bankruptcy filing, the estimated effect of not accruing interest expense on these prepetition obligations totals approximately $523 million. However, the actual interest that will ultimately be paid pursuant to the final plans of reorganization could differ significantly and cannot be determined at this time.) Reorganization items, net reflects bankruptcy issues that improved income $8.9 million in 1993 compared to an income decrease of $8.3 million last year. Included in these amounts is $39.9 million of interest earned on accumulated cash, up $13 million over 1992, and $31 million for 1993 professional fees and related expenses together with other miscellaneous reorganization items, a decrease of $4.2 million from last year.
In 1992 Other Income (Deductions), net reduced income $1.5 million versus $119.4 million in 1991. Income was improved in both 1992 and 1991 by not accruing interest expense on prepetition obligations by approximately $224.9 million and $85.6 million, respectively. The decrease of $11.9 million in Interest Income and Other, net was due to several items including a $17.9 million gain in 1991 on the sale of the New York distribution subsidiary and a $2.9 million gain on the 1991 sale of the Canadian oil and gas properties. These items were partially offset by a $14.5 million writedown for certain cogeneration projects. The change between 1992 and 1991 for bankruptcy issues increased income $6.1 million. Professional fees and related expenses, combined with other miscellaneous reorganization items, were $35.2 million and $18.9 million in 1992 and 1991, respectively, while interest earned on accumulated cash was $26.9 million in 1992 and $4.5 million in the prior year.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
STATEMENTS OF COMMON STOCK PRICES AND DIVIDENDS
LIQUIDITY AND CAPITAL RESOURCES
Cash from Operations The full year effect of Transmission's new rate design, higher rates for Distribution and colder weather during 1993 compared to last year, together with certain refunds received from suppliers, resulted in net cash from operations of $850.4 million, an increase of $85 million for 1993. Higher oil and gas production and increased gas prices also contributed to this improvement. Cash received from customers increased $412 million in 1993, primarily reflecting increased volumes due to colder weather earlier in the year together with higher rates. The receipt of rate refunds by certain subsidiaries led to the $79.4 million rise in other operating cash receipts. An increase in the spot market price for gas and additional gas volumes purchased to meet customer requirements resulted in $302.2 million more cash being paid to suppliers partially offsetting the above cash improvements. In addition, a refund payment by Columbia Transmission led to a $102 million rise in other operating cash payments in 1993.
Colder weather in 1992 compared to the prior year and the suspension of interest payments on August 1, 1991, due to the bankruptcy filing raised net cash from operations $233.8 million to $765.4 million in 1992 over 1991. Higher 1992 throughput from colder weather, increased receipts due to implementing a new rate design for Columbia Transmission and higher distribution rates were the primary reasons for the $300.5 million increase in cash received from customers. The suspension of interest payments on prepetition debt obligations led to the $100.4 million decrease in interest paid. Partially offsetting these improvements was the 1991 receipt of a settlement payment on a property dispute which caused other operating cash receipts to decline $48 million. Also, higher income taxes due to timing differences between periods and increased property tax assessments caused income taxes paid and other tax payments to increase $40.6 million and $31.5 million, respectively.
The Corporation maintains a debtor-in-possession facility (DIP Facility) for up to $100 million, including the availability of letters of credit of up to $50 million. The DIP Facility is available for use in conjunction with internally generated funds for general corporate purposes and to provide financing for subsidiaries not involved in the bankruptcy proceedings. As of January 31, 1994, $12.7 million of letters of credit were outstanding under the
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND ESULTS OF OPERATIONS (Continued)
DIP Facility. The DIP Facility expires December 31, 1994, although a request to extend it will be made, if necessary. During 1993, there were no borrowings under the DIP Facility. Absent unusual circumstances, the Corporation expects to remain in a cash surplus position during all of 1994. As of January 31, 1994, the Corporation and its subsidiaries, excluding Columbia Transmission, had excess cash of $148 million, which was invested in money market instruments.
The liquidity needs of Columbia Transmission are being satisfied by internally generated funds. As of January 31, 1994, Columbia Transmission had $1,250.9 million invested in money market instruments through a wholly-owned subsidiary, Columbia Transmission Investment Corporation. Columbia Transmission also maintains a DIP Facility solely for the issuance of letters of credit for up to $25 million. As of January 31, 1994, the balance of outstanding letters of credit under Columbia Transmission's DIP Facility was $1.8 million. In December 1993, Columbia Transmission extended its DIP Facility through December 31, 1995.
The Corporation's subsidiaries (other than Columbia Transmission during bankruptcy) must receive SEC approval under the Public Utility Holding Company Act of 1935 for all financing. As part of the approval process, the Corporation files the financing requirements of each of its subsidiaries with the SEC along with other material supporting management's opinion that the amounts requested are in the best interest of the Corporation's investors. In connection with recent filings, the Corporation has been requested to provide greater detail in support of the financing of subsidiaries which have, from time to time, experienced losses. These companies include: Columbia LNG, TriStar, TriStar Capital Corporation, Columbia Coal Gasification Corporation and Columbia Development. The need to provide information requested by the SEC to satisfy these concerns has made the receipt of timely approval more difficult and future delays could be experienced. However, management continues to believe it will receive approval of its financing requests.
CAPITAL EXPENDITURES
Capital expenditures for 1993 were $361 million, an increase of $61 million over 1992. The increase reflects expenditures on some projects that had been deferred in previous years. In 1992 and 1991, the Corporation's subsidiaries reduced capital expenditures to the extent possible consistent with the need to maintain safe and efficient operating facilities, the need to meet new service and tariff obligations, drilling commitments and the need to preserve going concern values.
Some of the Corporation's subsidiaries will be initiating projects that can no longer be deferred which will increase the 1994 program $107 million, to $468 million.
In 1994, Distribution will make investments of approximately $18 million to improve the efficiency of support services where expenditures had previously been deferred. Also included in Distribution's 1994 capital expenditure program are expenditures to provide deliveries to gas powered electric generating plants in its market areas and third-party natural gas vehicle public refueling stations. The majority of the transmission companies' expenditures will be for maintaining their extensive pipeline and storage system. In addition, $26 million is included for a project to provide gas to a New England electric generating facility which has been deferred since 1990 pending regulatory approval. Expenditures in 1994 for the oil and gas segment will remain essentially at 1993 levels. The current weakness in oil prices has resulted in a reduction in planned 1994 expenditures for exploratory drilling. The majority of the segment's expenditures will be for less risky development drilling.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
COMPARATIVE GAS OPERATIONS DATA The Columbia Gas System, Inc. and Subsidiaries
* Certain amounts in prior periods have been reclassified to conform with the current presentation.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of The Columbia Gas System, Inc.:
We have audited the accompanying consolidated balance sheets of The Columbia Gas System, Inc. (a Delaware corporation, the "Corporation") and subsidiaries as of December 31, 1993 and 1992, and the related statements of consolidated income, cash flows and common stock equity for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Corporation and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
On July 31, 1991, the Corporation and Columbia Gas Transmission Corporation ("Columbia Transmission"), a wholly-owned subsidiary, filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. Note 2 discusses, among other matters, uncertainties associated with the Chapter 11 proceedings, including the status of the Corporation's loans to Columbia Transmission, certain prepetition intercompany asset transfers and the measurement of certain liabilities. This note also discusses purported class action and other complaints which have been filed against the Corporation generally alleging violations of certain securities laws. The accompanying financial statements do not reflect any liability associated with these complaints as the Corporation believes it has meritorious defenses to these actions; however, the ultimate outcome is uncertain. As a result of these matters, the Corporation may take, or be required to take, actions which may cause assets to be realized or liabilities to be liquidated for amounts other than those reflected in the financial statements. These factors create substantial doubt about the Corporation's ability to continue as a going concern. The accompanying financial statements have been prepared assuming that the Corporation and Columbia Transmission will continue as going concerns which contemplates the realization of assets and payment of liabilities in the ordinary course of business. The appropriateness of the Corporation continuing to present financial statements on a going concern basis is dependent upon, among other items, the terms of the ultimate plan of reorganization and the ability to generate sufficient cash from operations and financing sources to meet obligations.
As discussed in Note 4, effective January 1, 1991, the Corporation changed its method of accounting for income taxes and postretirement benefits other than pensions pursuant to standards promulgated by the Financial Accounting Standards Board.
The schedules listed in the Index to Item 8, Financial Statements and Supplementary Data, are the responsibility of the Corporation's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
New York, New York February 10, 1994
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED INCOME The Columbia Gas System, Inc. and Subsidiaries
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements. **Due to the bankruptcy filings, interest expense of approximately $212 million, $225 million and $86 million has not been recorded for 1993, 1992 and 1991, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
CONSOLIDATED BALANCE SHEETS The Columbia Gas System, Inc. and Subsidiaries
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements. **The Corporation has 10,000,000 shares of preferred stock, $50 par value, authorized but unissued. ***Due to the bankruptcy filings, accrued interest of approximately $523 million and $311 million has not been recorded as of December 31, 1993 and December 31, 1992, respectively. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED CASH FLOWS The Columbia Gas System, Inc. and Subsidiaries
*Reference is made to Notes 1A and 2 of Notes to Consolidated Financial Statements. **Includes amounts transferred from interest paid, cash paid to employees and for other employee benefits and other operating cash payments. ***The Corporation considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY The Columbia Gas System, Inc. and Subsidiaries
*100 million shares authorized at December 31, 1993, 1992 and 1991 - $10 par value. **The Corporation's only foreign subsidiary, Columbia Gas Development of Canada Ltd., was sold during 1991. The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. PRINCIPLES OF CONSOLIDATION. The Consolidated Financial Statements include the accounts of the Corporation and all subsidiaries. All intercompany accounts and transactions have been eliminated, except for the Corporation's investment in Columbia LNG Corporation (see Note 12F).
On July 31, 1991, the Corporation and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), filed separate petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code. The debtor companies are operating their businesses as debtors-in-possession (DIP) under the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). As such, the debtor companies cannot engage in transactions considered to be outside the ordinary course of business without obtaining Bankruptcy Court approval (see Note 2).
The accompanying financial statements reflect all adjustments necessary in the opinion of management to present fairly the results of operations in accordance with generally accepted accounting principles applicable to a going concern. Such presentation contemplates the realization of assets and payment of liabilities in the ordinary course of business. As a result of the reorganization proceedings under Chapter 11, the debtor companies may take, or be required to take, actions which may cause assets to be realized, or liabilities to be liquidated, for amounts other than those reflected in the financial statements. The appropriateness of continuing to present consolidated financial statements on a going concern basis is dependent upon, among other things, the terms of the ultimate plan of reorganization, future profitable operations, the ability to comply with DIP and other financing agreements and the ability to generate sufficient cash from operations and financing sources to meet obligations. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or the amounts and classification of liabilities that might be necessary as a result of the outcome of the uncertainties discussed herein.
Certain reclassifications have been made to the 1992 and 1991 financial statements to conform to the 1993 presentation.
B. BASIS OF ACCOUNTING FOR RATE-REGULATED SUBSIDIARIES. Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," provides that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it reasonable to assume that such rates can be charged and collected. The Corporation's interstate transmission companies did not meet these criteria, and consequently are not applying the provisions of SFAS No. 71. In 1992, management concluded that it was no longer appropriate for Columbia LNG Corporation (Columbia LNG) to continue application of SFAS No. 71 (see Note 12F). The Corporation's gas distribution subsidiaries follow the accounting and reporting requirements of SFAS No. 71.
C. GAS UTILITY AND OTHER PLANT AND RELATED DEPRECIATION. Property, plant and equipment (principally utility plant) are stated at original cost. The cost of gas utility and other plant of the distribution companies includes an allowance for funds used during construction (AFUDC).
In addition, Columbia Gas of Ohio, Inc. is permitted to include in its plant investment post-in-service carrying charges on those eligible plant investments which are placed in service between December 31, 1990, and December 31, 1994. Subject to commission approval, the carrying charges are also authorized
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
to be included in base rates in subsequent rate filings. These carrying charges are subject to a net income limitation, as determined by the commission. Property, plant and equipment of other subsidiaries includes interest during construction (IDC).
The 1993, 1992 and 1991 before-tax rates for AFUDC and IDC were 8.0 percent and 9.6 percent, respectively. They represent the rates in effect prior to Chapter 11 filings. The portion of interest capitalized by subsidiaries during the period the Corporation is in bankruptcy is eliminated in the Consolidated Financial Statements.
Improvements and replacements of retirement units are capitalized at cost. When units of property are retired, the accumulated provision for depreciation is charged with the cost of the units and the cost of removal, net of salvage. Maintenance, repairs and minor replacements of property are charged to expense. The Corporation's subsidiaries provide for annual depreciation on a composite straight-line basis.
The average annual depreciation rate for Transmission property was 2.6 percent in 1993, 1992 and 1991. The average annual depreciation rate for Distribution property was 3.3 percent in 1993 and 1992, and 3.6 percent in 1991.
D. OIL AND GAS PRODUCING PROPERTIES. The Corporation's subsidiaries engaged in exploring for and developing oil and gas reserves follow the full cost method of accounting. Under this method of accounting, all productive and nonproductive costs directly identified with acquisition, exploration and development activities are capitalized in a countrywide cost center. If costs exceed the sum of the estimated present value of the cost center's net future oil and gas revenues and the lower of cost or estimated value of unproved properties, an amount equivalent to the excess is charged to current depletion expense. Gains or losses on the sale or other disposition of oil and gas properties are normally recorded as adjustments to capitalized costs.
Depletion for domestic subsidiaries is based upon the ratio of current-year revenues to expected total revenues, utilizing current prices, over the life of production. Depletion for the Canadian subsidiary, which was sold as of December 31, 1991, was based upon the ratio of volumes produced to total reserves.
E. COMMODITY HEDGING. Commodity futures, options on futures, and commodity price swaps are used from time to time to hedge prices of crude oil, natural gas production, propane inventories and commitments for natural gas purchases and sales, in order to minimize the risk of market fluctuations. Under internal guidelines, hedging positions for oil and gas production can be taken for up to 80 percent of the expected uncommitted monthly production. Gains and losses on the hedging transactions are recognized when the hedged commodity is sold or purchased.
F. GAS INVENTORY. Gas inventory is carried at cost on a last-in, first-out (LIFO) basis. The estimated replacement cost of gas inventory in excess of carrying amounts at December 31, 1993, was approximately $85 million for the distribution companies. Liquidation of LIFO layers related to gas delivered by the distribu- tion companies does not affect income since the effect is passed through to customers as part of purchased gas adjustment tariffs. As a result of implementing Federal Energy Regulatory Commission (FERC) Order No. 636 (Order 636), Columbia Transmission substantially eliminated its merchant function and, therefore, no longer carries a gas inventory. Amounts previously recorded as "Gas Inventory - Noncurrent" have been reclassified to Property, Plant and Equipment which represents the volume of gas required to maintain pressure levels for storage service.
G. INCOME TAXES AND INVESTMENT TAX CREDITS. The Corporation and its subsidiaries record income taxes to recognize full interperiod tax allocations. Under the liability method, deferred income taxes are
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.
Previously recorded investment tax credits of the gas distribution subsidiaries were deferred and are being amortized over the life of the related properties to conform with regulatory policy.
H. ESTIMATED RATE REFUNDS. Certain rate-regulated subsidiaries collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management's current judgment of the ultimate outcome of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.
I. DEFERRED GAS PURCHASE COSTS. The Corporation's gas distribution subsidiaries defer differences between gas purchase costs and the recovery of such costs in revenues, and adjust future billings for such deferrals on a basis consistent with applicable tariff provisions.
J. REVENUE RECOGNITION. The Corporation's rate-regulated subsidiaries bill customers on a monthly cycle billing basis. Revenues are recorded on the accrual basis including an estimate for gas delivered but unbilled at the end of each accounting period. Columbia Transmission also records the impact on revenues of the future recovery or refund of differences between current gas and transportation costs and amounts currently included in the billed rates. In addition, Columbia Transmission and Columbia Gulf record the effect on revenues to reflect the recovery or refund of differences between current fuel usage and amounts retained.
2. REORGANIZATION PROCEEDINGS UNDER CHAPTER 11 OF THE BANKRUPTCY CODE
A. GENERAL. Under the Bankruptcy Code, actions by creditors to collect prepetition indebtedness are stayed and other contractual obligations may not be enforced against either the Corporation or Columbia Transmission. As debtors-in-possession, both the Corporation and Columbia Transmission have the right, subject to Bankruptcy Court approval and certain other limitations, to assume or reject executory contracts and unexpired leases. In this context, "rejection" means that the debtor companies are relieved from their obligations to perform further under the contract or lease but are subject to a claim for damages for the breach thereof. Any claims for damages resulting from rejection are treated as general unsecured claims in the reorganization. The parties affected by these rejections may file claims with the Bankruptcy Court in accordance with bankruptcy procedures. Prepetition claims which were contingent or unliquidated at the commencement of the Chapter 11 proceeding are generally allowable against the debtor-in-possession in amounts fixed by the Bankruptcy Court. Substantially all liabilities as of the petition date are subject to resolution under plans of reorganization to be approved by the Bankruptcy Court after submission to any required vote by affected parties. The Corporation's reorganization plan also requires approval by the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935.
B. COLUMBIA TRANSMISSION'S PLAN OF REORGANIZATION. The Corporation's and Columbia Transmission's discussions with the Official Committee of Unsecured Creditors of Columbia Transmission (Columbia Transmission Creditors' Committee) to negotiate a reorganization plan for Columbia Transmission and expedite emergence from Chapter 11 proceedings had been largely unsuccessful. Therefore, on January 18, 1994, Columbia Transmission filed, with the Corporation as cosponsor, a reorganization plan (plan) and a disclosure statement, for consideration by its creditors and other interested parties. The plan, which management believes is fair and equitable, proposes to pay 100 percent for all priority, administrative and secured claims and offers various classes of general unsecured creditors, including producers whose gas
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
contracts were rejected by Columbia Transmission, between 80 and 100 percent of Columbia Transmission's estimates of their allowable claims. The $3.3 billion total distribution proposed in Columbia Transmission's plan is based on an estimated value for Columbia Transmission of $3.1 billion and includes significant financial contributions by the Corporation. The plan is premised on a proposed omnibus settlement whereby the Corporation would settle the Intercompany Complaint (see page 65, C. Prepetition Obligations) and facilitate Columbia Transmission's reorganization by (i) accepting the value of the Corporation's secured claims against Columbia Transmission in the form of secured debt and equity securities of Columbia Transmission, and (ii) ensuring the cash (or at the option of the Corporation cash and $100 million market value of the Corporation's common stock) necessary to bring the aggregate distribution to $3.3 billion. Creditors, other than the Corporation, would share in distributions of over $1.2 billion in cash. In addition, the Corporation would consent to the reorganized Columbia Transmission's assumption of responsibility for public environmental enforcement agency claims so that the recoveries of the other creditors would not, with minor exceptions, be diminished by the environmental liabilities of Columbia Transmission's estate.
The plan provides that Columbia Transmission will remain a wholly-owned subsidiary of the Corporation, will continue to offer an array of competitive transportation and storage services, and will retain ownership of its 18,800-mile pipeline network and related facilities.
Columbia Transmission's proposed business solution will offer to producers, whose gas supply contracts were rejected or who have prepetition claims under those contracts, individual, specific settlements of the producers' claims that are based upon uniform assumptions and principles and which, in the view of Columbia Transmission's management, are fair and reasonable settlement values. These specific settlement proposals are being developed and will be filed as an adjunct to the plan. Columbia Transmission estimates that aggregate distributions to producers under the plan would come to approximately $900 million.
In general, the plan provides for immediate cash payment in full to all priority claims, all secured claims held other than by the Corporation, trust fund claims, administrative expenses and unsecured claims of $50,000 or less. The Corporation's secured claims will be satisfied in full with new secured debt and equity securities to be issued by the reorganized Columbia Transmission. Unsecured claims between $50,000 and $250,000 would receive 95 percent of their allowed claims in cash. All other unsecured claims, including the Corporation's unsecured debt and producer contract rejection claims, would receive between 80 and 100 percent of their allowed claims based on current projections. With respect to some of the classes of creditors, the treatment described above depends on the acceptance of the plan by the relevant class. At this time, no creditors have agreed to any of the proposed plan's provisions, and the ultimate confirmed plan of reorganization could be materially different from this initial filing.
Although Columbia Transmission's plan utilizes June 30, 1994, as an assumed date of emergence from bankruptcy, the actual date of emergence will depend on the time required to complete the bankruptcy process and obtain necessary creditor, judicial and regulatory approvals. As part of its filing with the Bankruptcy Court, Columbia Transmission requested that the court defer scheduling required proceedings on the plan and related disclosure statement in order to permit discussions of the plan, including the settlements proposed therein, with Columbia Transmission's creditors, official committees and other interested parties.
Under bankruptcy procedures, after Columbia Transmission's disclosure statement has been approved by the Bankruptcy Court, the disclosure statement and the reorganization plan will be sent to the company's creditors for voting.
The Corporation intends to file a plan for its reorganization which will be consistent with the financial aspects and structure of Columbia Transmission's proposed plan of reorganization. Both plans will be
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
subject to a lengthy review and approval process, including SEC approval, and obtaining adequate financing.
Implementation of Columbia Transmission's plan, and the levels and timing of distributions to its creditors, are subject to a number of risk factors which could materially impact their outcome. The plan sets forth numerous conditions to its confirmation and consummation. The failure to satisfy these conditions in accordance with the terms of the plan would have a material adverse effect on the outcome of Columbia Transmission's bankruptcy and on the Corporation. These conditions include, among others, the confirmation of a reorganization plan for the Corporation, the receipt of necessary approvals for the implementation of Columbia Transmission's plan and the recovery of regulatory and tax benefits which are fundamental to the plan's viability. Both companies anticipate emerging from bankruptcy at the same time. The provisions of the reorganization plans of either Columbia Transmission or the Corporation that are ultimately implemented could be materially different from this initial filing for Columbia Transmission and have a material adverse effect on the Corporation and its subsidiaries and on the rights of shareholders and holders of debt and other obligations.
C. PREPETITION OBLIGATIONS. Columbia Transmission's prepetition obligations include secured and unsecured debt payable to the Corporation, estimated supplier obligations, estimated rate refunds, accrued taxes and other trade payables and liabilities. Prepetition obligations of the Corporation primarily represent debentures, bank loans and commercial paper outstanding on the filing date together with accrued interest to that date. A substantial amount of Columbia Transmission's liabilities subject to Chapter 11 proceedings relate to amounts owed to the Corporation. Columbia Transmission's borrowings have been funded by the Corporation on a secured basis since June 1985 and are secured by mortgages and a cash collateral order approved by the Bankruptcy Court. On the petition date, the principal amount of the First Mortgage Bonds outstanding was $930.4 million. Prepetition and postpetition interest on secured debt owed by Columbia Transmission to the Corporation is $346.4 million at December 31, 1993. In addition to these secured claims, the Corporation has an unsecured claim against Columbia Transmission of $351 million in installment notes issued prior to 1985 and accrued interest to the petition date.
On March 19, 1992, the Columbia Transmission Creditors' Committee filed a complaint (Intercompany Complaint) with the Bankruptcy Court alleging that the $1.7 billion of Columbia Transmission's secured and unsecured debt securities held by the Corporation should be recharacterized as capital contributions (rather than loans) and equitably subordinated to the claims of Columbia Transmission's other creditors. The Intercompany Complaint also challenges interest and dividend payments made by Columbia Transmission to the Corporation of approximately $500 million for the period from 1988 to the petition date and the 1990 property transfer from Columbia Transmission to Columbia Natural Resources, Inc. (CNR) as an alleged fraudulent transfer. Based on the SEC standardized measurement procedures, CNR's properties had a reserve value of approximately $387 million as of December 31, 1993, a significant portion of which is attributable to the transfer from Columbia Transmission. In May 1992, Columbia Transmission Creditors' Committee filed with the U.S. District Court a motion for a jury trial and to move the Intercompany Complaint from the Bankruptcy Court to the U. S. District Court. This motion was denied and subsequently appealed to the Third Circuit Court of Appeals (Third Circuit). In June 1992, the Corporation filed a motion with the Bankruptcy Court seeking dismissal of, or summary judgment on, principal portions of the Intercompany Complaint. On August 20, 1993, the Third Circuit denied Columbia Transmission Creditors' Committee's appeal, allowing the Bankruptcy Court to consider the merits of the Intercompany Complaint and act upon the Corporation's June 1992 motion for summary judgment. The Bankruptcy Court has not acted on the Corporation's motion for summary judgment, but tentatively scheduled a trial on the Intercompany Complaint to begin June 13, 1994. Management believes that the Intercompany Complaint is without merit; however, the ultimate outcome of these issues is uncertain at this stage of the proceedings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Discussions with Columbia Transmission's creditors in an attempt to establish the value of the estate and to resolve the matters raised in the Intercompany Complaint are ongoing. Since the standing and value of the Corporation's debt investment in Columbia Transmission is crucial to the determination of the value of the Corporation's estate, the Corporation's reorganization could be affected by the ultimate outcome of the Intercompany Complaint.
The Internal Revenue Service (IRS) filed identical claims of $553.7 million against both debtor companies and the consolidated Columbia Gas System for tax deficiencies, interest and penalties for the years 1983-1990. Negotiations with IRS representatives have resulted in a settlement on all of the issues included in the IRS claims. This settlement has been documented in a written closing agreement and filed with the Joint Committee on Taxation of the U.S. Congress for formal approval. The IRS settlement also requires Bankruptcy Court approval. Recording the IRS settlement reduced 1993 net income by $44.3 million.
Columbia Transmission has recorded liabilities of approximately $1.2 billion to reflect the estimated effects of its above-market producer contracts and estimated supplier obligations associated with pricing disputes and take-or-pay obligations for historical periods. With Bankruptcy Court approval, Columbia Transmission rejected more than 4,800 above-market gas purchase contracts with producers. The producers whose gas purchase contracts were rejected filed claims for damages that, after being adjusted for duplicative and other erroneous claims, are in excess of $13 billion. The Bankruptcy Court approved the appointment of a claims mediator in 1992 to implement a claims estimation procedure related to the rejected above-market producer contracts and other producer claims. The mediator held hearings on generic issues and various estimation methodologies and discovery matters during 1993. Columbia Transmission anticipates that the mediator may issue recommended determinations during the second quarter of 1994 which, under the Bankruptcy Court-approved estimation procedure, are expected to provide the basis for a recalculation of producer contract rejection claims. In Columbia Transmission's judgment, the positions taken by all producers before the claims mediator and the evidence presented demonstrate that the total level of allowable contract rejection claims, generically determined, will not exceed 1/10th of the $13 billion asserted in the claims as filed and is likely to be between $600 million and $950 million. The acceptance of certain positions advanced by Columbia Transmission on the evidence of record, as well as Columbia Transmission's as yet unheard defenses, could decrease substantially this range of possible aggregate outcomes. Resolution of the contract-specific issues not yet presented could increase or decrease individual claims materially but should not significantly alter the range of possible aggregate outcomes.
The resolution of these issues can significantly influence future reported financial results. Accounting standards require that as claim amounts are allowed by the Bankruptcy Court, the full amount of the allowed claim must be recorded. This could result in liabilities being recorded which bear little relationship to the amounts ultimately required to be paid in settlement of those claims and could conceivably exceed the Corporation's total investment in Columbia Transmission. Any such distortion would not be corrected until final plans of reorganization are approved for the Corporation and Columbia Transmission.
Regarding claims made by pipeline suppliers, on September 13, 1993, the Bankruptcy Court approved an agreement between Columbia Transmission and Texas Eastern Corporation (Texas Eastern) and the settlement of related claims. Under the terms of this agreement, Columbia Transmission will collect $30 million in refunds from Texas Eastern and all claims filed by Texas Eastern against Columbia Transmission, totalling $672 million, will be withdrawn. In November 1993, the Bankruptcy Court approved a settlement between Columbia Transmission and Tennessee Gas Pipe Line Company (Tennessee). This agreement provides for Columbia Transmission's assumption of certain contracts, the termination of certain other contracts that are no longer necessary for Columbia Transmission's operations, and payment to Tennessee of approximately $42 million in consideration for Tennessee's substantial reduction of its major transportation contracts with Columbia Transmission. On January 11, 1994, Columbia Transmission and Tennessee made a filing with the FERC to approve the settlement. Columbia Transmission expects to ultimately recover the costs and fees associated with the assumption and termination of these contracts under
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Order 636. The Tennessee settlement agreement is conditioned upon this recoverability. These settlements resolve a significant portion of the pipeline supplier claims against Columbia Transmission.
The Pension Benefit Guaranty Corporation (PBGC) filed claims of $150 million against both the Corporation and Columbia Transmission alleging that if the retirement plan had been terminated by March 31, 1992, it would have been underfunded. Management believes that the claims made by the PBGC are inappropriate and in error since the Bankruptcy Court has approved continued operation of the retirement plan, required annual contributions are being made, there is no intention to terminate the plan and the plan is not underfunded. Management further believes that the PBGC's claim can be resolved without any financial consequences to the Corporation or Columbia Transmission. On January 29, 1993, the PBGC confirmed that while it remains confident that issues regarding its claims can be resolved by mutual agreement, the PBGC has decided not to proceed further with settlement negotiations regarding withdrawal of its claims at the present time due to the uncertainties associated with the bankruptcy proceedings. At December 31, 1993, the date of the latest actuarial valuation, plan assets exceeded the accumulated benefit obligations by $166.5 million.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
The accompanying Consolidated Balance Sheets include approximately $4 billion of liabilities subject to the Chapter 11 proceedings of the Corporation and Columbia Transmission as follows:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
D. PAYMENT OF DIVIDENDS AND DEBT SERVICE. The Corporation's Board of Directors suspended the payment of dividends on the Corporation's common stock on June 19, 1991. The Corporation also discontinued payments related to debt service. Columbia Transmission suspended dividend, interest and debt payments to the Corporation. The Corporation and Columbia Transmission have also suspended the payment of most other prepetition obligations. Management cannot predict at this time when or whether any financial restructuring plans will be approved or what provisions, if any, such plans would contain as related to the resumption of dividends, debt service and other payments.
E. INTEREST EXPENSE. Interest expense of the Corporation is not being accrued during bankruptcy, but a calculation of interest is included in a footnote on the Statements of Consolidated Income and Consolidated Balance Sheets. Such interest has been calculated based on management's interpretation of the contractual arrangements which govern the various debt instruments the Corporation has outstanding exclusive of any redemption premiums. The Official Committee of Unsecured Creditors of the Corporation has asserted claims for interest which exceed disclosed amounts by approximately $40 million at December 31, 1993. There are several factors to be considered in making these calculations that are subject to uncertainty as to their ultimate outcome in the bankruptcy proceeding, including the interest rates and method of calculation to be applied to overdue payments of principal and interest. In addition, the committee has asserted that approximately $110 million of redemption premiums should be paid on high cost debt instruments.
F. SECURITY HOLDER LITIGATION. After the announcement on June 19, 1991, regarding the Corporation's probable charge to second quarter earnings and the suspension of its dividend, 17 complaints including purported class actions were filed against the Corporation and its directors and certain officers of the debtor companies in the U.S. District Court of Delaware. The actions, which generally allege violations of certain anti-fraud provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934, have been consolidated. In addition, three derivative actions were filed in the Court of Chancery in and for New Castle County (Delaware) alleging that directors breached their fiduciary duties. These suits have been stayed by either the Bankruptcy Court filing or by stipulation of the parties. While the Corporation believes that it has meritorious defenses to these actions, the outcome is uncertain at this time.
G. CUSTOMER RECOUPMENT RIGHTS. During the fourth quarter of 1993, various customers of Columbia Transmission filed motions with the Bankruptcy Court seeking authority to exercise alleged recoupment and setoff rights, whereby they would be permitted to reduce amounts owed to Columbia Transmission against refunds owed to the customers by Columbia Transmission, including amounts which were not otherwise payable in full under the July 1993 Third Circuit decision discussed below, all customer refunds under the 1990 rate case settlement and miscellaneous refunds not otherwise payable in full to them. Customers are alleging that they have recoupment and setoff rights of approximately $83 million at December 31, 1993.
On October 20, 1993, the Bankruptcy Court approved an interim settlement under which customers continued to pay Columbia Transmission for FERC-authorized services at authorized rates, and Columbia Transmission has agreed to grant these customers a priority claim to the extent the Bankruptcy Court finds them entitled to recoupment rights. In January 1994, the Bankruptcy Court issued a procedural order whereby other customers would be permitted to file recoupment and setoff motions by February 18, 1994, with a trial on all such motions scheduled for June 1994.
H. CUSTOMER REFUNDS. In July 1993, the Third Circuit overturned most of a U.S. District Court ruling and affirmed an earlier Bankruptcy Court decision that refunds Columbia Transmission received from upstream pipelines, as well as the Gas Research Institute (GRI) surcharge payments it collected from customers, are held in trust, by Columbia Transmission, for those customers and the GRI and are not part of Columbia Transmission's estate. In August 1993, the Third Circuit denied the Columbia Transmission Creditors' Committee's request for a rehearing. In February 1994, the Supreme Court denied petitions for review of the Third Circuit decision.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Under the Third Circuit ruling, approximately $173 million in refunds that Columbia Transmission has received, or expects to receive postpetition from upstream pipelines and GRI surcharges collected, should be passed through to the customers and to the GRI. In addition, the Third Circuit determined that $35 million in upstream pipeline refunds and GRI surcharges, which Columbia Transmission collected prior to filing Chapter 11 while received in trust, were subject to the "lowest intermediate cash balance test" (the amount remaining in trust at the time of bankruptcy) and should be distributed on a pro rata basis to the customers and to the GRI to the extent of Columbia Transmission's $3.3 million cash balance on July 31, 1991. The Third Circuit affirmed another part of the U.S. District Court's decision and held that approximately $16 million that Columbia Transmission owes upstream suppliers, for gas purchased and transportation services received prior to its bankruptcy filing, is ordinary unsecured debt which must be discharged in the bankruptcy process.
On February 10, 1994, the U.S. District Court issued an order for the Bankruptcy Court to pursue further proceedings in accordance with the Third Circuit's refund decision directing the pass-through of these refunds. At a hearing on December 29, 1993, the Bankruptcy Court observed that the FERC should determine whether customers are entitled to the actual interest earned on refunds being held by Columbia Transmission or the higher FERC-prescribed interest rate. On February 18, 1994, Columbia Transmission filed a motion with the FERC for determination of the interest issue. Columbia Transmission will ask the Bankruptcy Court for implementation of the mandate. Columbia Transmission will also have to file with the FERC to reimplement its flow-through of Order Nos. 500/528 refunds from its pipeline suppliers, which represent the majority of the refunds at issue. It is anticipated that Columbia Transmission will recommence the flow-through of the upstream pipeline refunds in 1994.
Total customer claims in Columbia Transmission's bankruptcy proceedings relating to, or arising from, Columbia Transmission's contracts with its customers for sales, transportation, gas storage and similar services and other miscellaneous claims represent about 450 claims for a total of approximately $550 million as filed, plus a potentially substantial sum filed in undetermined amounts. Columbia Transmission successfully resolved a significant portion of these customers claims. Not resolved are customer claims that total approximately $113 million at December 31, 1993, that seek to protect rights associated with any prepetition revenues collected subject to refund in general rate filings and purchased gas adjustment filings, including matters subject to court appeals. In addition, the claims filed in undetermined amounts, which potentially could be significant, still remain to be resolved. In October 1993, approximately $160 million was refunded to customers by Columbia Transmission reflecting the terms of a settlement of a 1991 rate case approved by the Bankruptcy Court in July 1993. Bankruptcy Court approval for a 1990 rate case settlement for rates in effect from November 1, 1990 through November 30, 1991 was deferred pending the decision by the Third Circuit regarding the flow- through of certain refunds. Appropriate reserves for rate refund liabilities have been recorded for these matters to reflect management's judgment of the ultimate outcome of the proceedings.
I. REORGANIZATION ITEMS. During 1993, 1992 and 1991 the Corporation and Columbia Transmission have earned interest income on cash accumulated from the suspension of payments related to prepetition liabilities and incurred expenses associated with professional fees and other related services, as detailed below:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
J. FINANCIAL INFORMATION FOR THE DEBTOR COMPANIES. Condensed financial information for the Corporation and Columbia Transmission as of, and for, periods ended December 31, are as follows:
3. REGULATORY MATTERS
A. Columbia Transmission has collected revenues from its customers associated with the pass-through of upstream pipeline supplier take- or-pay and contract reformation costs under FERC Order Nos. 500 and 528. Certain customers have challenged recovery of such costs which totals $160 million, (excluding interest) net of amounts to be refunded, on the basis that a 1985 rate settlement precludes collection. The FERC has consistently denied the customers' assertions and appeals have been filed with the U.S. Court of Appeals, D.C. Circuit. Management continues to believe these challenges are without merit and the FERC orders, which support collection of these costs, will ultimately be upheld.
B. In April 1992, the FERC issued Order 636, its final rule on Pipeline Service Obligations and Equality of Transportation Services by Pipelines. This order fundamentally changes the role of pipelines from providing a merchant function to one in which they perform principally as transporters of gas that distribution companies and end users purchase directly from producers and other suppliers.
While Order 636 provided that pipelines may recover all prudently incurred costs resulting from the transition to Order 636, the FERC stated that filings to recover such costs should not be made until a pipeline's service restructuring proposal, that identifies various transition costs, has been approved. With respect to gas supply realignment costs, costs associated with reforming or terminating above-market price supply contracts, Columbia Transmission noted in its filing that the majority of such costs on its system will be determined in the context of the bankruptcy proceedings regarding the treatment of producer
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
contract rejection costs. The company stated that the ultimate level of such costs is uncertain and that recovery would be pursued in future filings with the FERC.
In 1993, the FERC issued a series of orders on the restructuring proposals and on September 29, 1993, the FERC issued an order which allowed Columbia Transmission and Columbia Gulf to implement restructured services on November 1, 1993. While confirming its initial ruling regarding the ineligibility for recovery of producer contract rejection costs as gas supply realignment or Order Nos. 500/528 costs, the FERC did rule that Columbia Transmission could seek to recover a small portion of the contract rejection costs that had earlier been ruled to be unrecoverable. The FERC also agreed to waive a nine-month time limit on Columbia Transmission's ability to seek recovery of unrecovered purchased gas costs to the extent the costs resulted from contracts that are currently in litigation, including bankruptcy litigation. Approximately $60 million in unrecovered purchased gas costs were outstanding at December 31, 1993, in addition to approximately $140 million of prepetition unrecovered purchased gas costs that have not been paid due to the bankruptcy filing.
The FERC affirmed that Columbia Transmission could maintain recovery of gathering costs through its gathering and other transportation rates at least until the filing of a general rate case and approved a separate charge applicable to product extraction activities. Management continues to evaluate long-term plans for these gathering facilities ($63.3 million at December 31, 1993).
Subject to review in connection with periodic rate filings, the FERC approved Columbia Transmission's proposal to continue to recover costs associated with retained upstream pipeline contracts through its demand rates. Recovery of such costs would be subject to review and approval in semiannual limited rate filings. Columbia Transmission has reached settlements that will eliminate approximately half of the annual cost of these contracts and is continuing its efforts to negotiate a mutually agreeable termination of the remainder of the contracts.
The FERC also addressed Columbia Transmission's ability to recover costs associated with upstream pipeline contracts. Columbia Transmission currently holds firm transportation agreements with certain pipeline companies that historically have been used to deliver gas to Columbia Transmission. These contracts have remaining terms of various lengths and require the payment of monthly reservation fees whether or not the capacity is utilized. Under Order 636, downstream pipelines such as Columbia Transmission are required to offer to assign most of their firm upstream capacity to their customers. Columbia Transmission's annual demand charge commitments on these upstream nonaffiliated pipelines was approximately $108 million; however, assignments of certain of these contracts by Columbia Transmission to its customers in conjunction with service restructuring under Order 636 have reduced this amount to less than $74 million. The total commitment for demand charges after November 1, 1993, is approximately $421 million on an undiscounted basis, excluding any mitigating effect of the pipelines marketing the capacity to others.
Columbia Transmission's strategy has been to assume all upstream pipeline contracts that can be directly assigned to its customers or need to be retained by Columbia Transmission for operational reasons and negotiate exit fees for other upstream contracts. The FERC ruling in the Order 636 proceedings permits recovery of these exit fees through rates, provided that Columbia Transmission can show that they are prudently incurred. Columbia Transmission retains the option of rejecting such contracts in its bankruptcy proceedings, if appropriate exit fees cannot be negotiated. The financial statements reflect a $130 million liability and offsetting receivable for the exit fee issue; however, the ultimate cost could vary depending on the outcome of ongoing discussions with the affected pipelines.
Several settlements with upstream pipelines have been concluded. In 1993, the Bankruptcy Court approved
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
settlements between Columbia Transmission and Texas Eastern Transmission Corporation, Panhandle Eastern Pipe Line Company and Texas Gas Transmission Corporation which provide for assumption of certain contracts and termination of others. None of these settlements required Columbia Transmission to pay an exit fee to the upstream pipeline.
One type of transition cost which the FERC acknowledged would be eligible for recovery consideration is "stranded costs", which are the costs of a pipeline's assets previously used to provide bundled sales service in the pre-Order 636 era, that are unsubscribed in the Order 636 environment. Columbia Gulf has several pipelines and related facilities that are not fully subscribed to under Order 636. Certain facilities south of Rayne, Louisiana, (primarily in the offshore Gulf of Mexico area) are being evaluated; however, management has not identified any stranded facilities at this time and the outcome of these evaluations is uncertain. Dependent upon the results of such evaluation, charges to income could be required. The net book value of the facilities under study was approximately $40 million at December 31, 1993. It is management's view that any costs associated with these facilities will be fully recoverable through rates.
As part of its September 29, 1993 order on Columbia Transmission's and Columbia Gulf's Order 636 compliance filings, the FERC initiated a proceeding concerning Columbia Gulf's transportation service to Columbia Transmission. Columbia Gulf was directed to show cause as to why it has not filed for abandonment to reduce capacity and service to Columbia Transmission under the required FERC authorization under Section 7(b) of the Natural Gas Act. Columbia Gulf responded to the show cause order on December 22, 1993. Management does not believe an abandonment filing was necessary and does not expect the resolution of this issue to have a material adverse effect on the Corporation's financial position.
C. On January 12, 1994, the FERC granted requests for rehearing of prior orders approving settlements between Columbia Transmission and four of its upstream pipeline suppliers relating to those suppliers' direct billings to Columbia Transmission in the mid-1980s of production-related FERC Order No. 94 (Order 94) costs. The rehearing orders find that the settlements must be rejected because they are expressly contingent upon Columbia Transmission's recovery of the Order 94 settlement payments from its customers, and that Columbia Transmission's 1985 PGA Settlement essentially bars such recovery. However, the orders also hold that these pipelines are not entitled to bill any Order 94 charges to Columbia Transmission, and ordered these upstream pipelines to refund the principal portion of all Order 94 collections from Columbia Transmission, but waived any requirements that these pipelines pay interest on the refunds. Since Columbia Transmission has been reflecting the interest income on these refunds since 1990, the effect of these orders led to a $19.5 million reduction in interest income in 1993. Columbia Transmission has sought rehearing and, if necessary, will seek court review of these orders. It is expected that pipeline suppliers will also request a rehearing arguing their rights to re-bill such charges to Columbia Transmission. The ultimate outcome of this issue is uncertain at this time and could impact future operating results depending upon the results of these regulatory and court reviews.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
4. ACCOUNTING CHANGES
A. In the fourth quarter of 1991, the Corporation adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (OPEB), retroactive to January 1, 1991. This method of accounting for postretirement benefits accrues the actuarially determined costs for life insurance and medical benefits ratably from the date an employee becomes eligible for such benefits. The Corporation's subsidiaries previously expensed these costs as cash payments were made. As permitted under SFAS No. 106, the subsidiaries elected to record the full amount of their estimated accumulated postretirement benefits obligation other than pensions of $223.8 million. These obligations represent the actuarial present value of the postretirement benefits to be paid to current employees and retirees based on services rendered.
The present value of the postretirement benefit obligation to be paid to current and retired employees for all the distribution subsidiaries amounts to approximately $143 million as of December 31, 1993. Of this amount, $138.1 million has been deferred as a regulatory asset pending anticipated recovery through rates in various jurisdictions. The Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board issued guidelines establishing criteria for recording such a regulatory asset, including a requirement for collection of accrual basis expense in rates and recovery of the transition obligation within approximately 20 years. These criteria are not necessarily being adopted by the public utility commissions regulating the distribution subsidiaries. Differences in requirements between the accounting rules and the rate making decisions ultimately adopted can result in a writedown of some of this regulatory asset.
The distribution subsidiaries, as well as the Corporation's other operating companies, have implemented cost-management measures designed to reduce their OPEB obligations. In addition to other measures, employees will be required to share a portion of their postretirement health benefit costs and guidelines have been established redefining years of service requirements before an employee is eligible for retiree health benefits. Other cost-saving plans are being reviewed for consideration in an ongoing effort to effectively manage OPEB costs.
The regulatory commission in Ohio issued a final order in February, 1993 in a generic rate investigation regarding recovery of postretirement benefit costs. The commission's order provides utilities the opportunity to fully recover prudently incurred postretirement costs on an accrual basis. Amounts in excess of pay-as-you-go costs may continue to be deferred until rate recovery begins. The amount of the Columbia Gas of Ohio regulatory asset in the accompanying balance sheet was $85.6 million as of December 31, 1993.
In March 1993, the Pennsylvania PUC stated in a proposed policy statement that any utility in its jurisdiction meeting certain conditions may seek formal PUC approval to record a regulatory asset equal to the difference between its current rate recognition of postretirement benefit costs and its accrued liability for such expenses. The amounts recorded will be subject to recovery in future rate proceedings to the extent that such costs are prudently incurred and certain conditions are met, such as dedicated funding of postretirement costs in excess of the pay-as-you-go level. Columbia Gas of Pennsylvania's (CPA) petition to maintain the postretirement benefit deferred regulatory asset until rate recovery begins was granted in December, 1993. This order gave CPA the permission to recover transition costs over 20 years. At December 31, 1993, the carrying value of CPA's regulatory asset was approximately $33.1 million.
The Kentucky state commission has indicated that the rate treatment of accrued postretirement benefits will be addressed on a company- by-company basis. Management believes Columbia Gas of Kentucky (CKY) will ultimately obtain recovery authorization based on a recent commission rate order for another utility, holding that recovery of these costs on an accrual basis better reflects the true cost of providing service to current customers. CKY will continue to defer its postretirement benefit costs in excess of the pay-as-you-go amount, pending the filing of its next general rate case which is currently scheduled for mid-1994. At December 31, 1993, the carrying value of CKY's regulatory asset was approximately $9.8 million.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Commonwealth Gas Services (COS) placed interim rates into effect June 1, 1993, subject to refund, which included recovery of accrued OPEB costs. Indications from the Virginia State Corporation Commission (VSCC) are that the costs will be deemed prudent and recoverable according to the commission's 1992 generic order addressing postretirement costs. As a result of the recovery of transition costs over a period of 40 years, the EITF guidelines required COS to expense $4.2 million in 1992.
Columbia Gas of Maryland's (CMD) general rate case settlement, effective October 1993, allows CMD to include in rates the full amount of accrued postretirement benefit costs as well as the recovery of the transition obligation over 20 years.
Although proceedings in certain state jurisdictions have yet to be finalized, based on currently available information, management believes rate recovery mechanisms will be adopted that permit continued regulatory asset treatment in accordance with recent EITF guidelines.
B. In February 1992, the Financial Accounting Standards Board issued SFAS No. 109, "Accounting for Income Taxes." The Corporation adopted SFAS No. 109 in the fourth quarter of 1992, retroactive to January 1, 1992. This Statement supersedes SFAS No. 96, "Accounting for Income Taxes," which was adopted by the Corporation in 1991 and improved earnings by $170 million. SFAS No. 109 changes the criteria for recognition and measurement of deferred tax assets and reduces complexity. The adoption of SFAS No. 109 had no impact on the Corporation's financial statements.
C. In November 1992, the Financial Accounting Standards Board issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits." This Statement requires employers to recognize any obligation which exists to provide benefits to former or inactive employees after employment, but before retirement. Such benefits include, but are not limited to, salary continuation, supplemental unemployment, severance, disability (including workers' compensation), job training, counseling, and continuation of benefits such as health care and life insurance coverage.
This Statement will be effective for fiscal years beginning after December 15, 1993, and the Corporation plans to adopt the Statement on January 1, 1994. Based on the facts and circumstances known today, the total obligation to the Corporation and its subsidiaries will be approximately $8.8 million. Of this amount, approximately $5.4 million will be expensed upon adoption. The remaining $3.4 million will be deferred by certain of the distribution subsidiaries as a regulatory asset pending rate recovery from the various state commissions.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
5. INCOME TAXES
The components of income tax expense are as follows:
Total income taxes are different than the amount which would be computed by applying the statutory Federal income tax rate to book income before income tax. The major reasons for this difference are as follows:
*Includes losses from foreign operations of $41.5 million for 1991.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Deferred tax balances are as follows:
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The source of these differences and tax effect of each is as follows:
6. SALE OF SUBSIDIARIES
A. The sale of Columbia Gas of New York, Inc. to New York State Electric & Gas Corporation was completed on April 5, 1991, and provided an increase to net income of $9.2 million. The total price was $57.5 million including $39.2 million for the 328,000 outstanding shares of common stock and $18.3 million for the outstanding debt.
B. The sale of Columbia Gas Development of Canada Ltd. (Columbia Canada), a wholly-owned Canadian oil and gas exploration and production subsidiary, to Anderson Exploration, Ltd. was effective as of December 31, 1991.
The sales price for Columbia Canada was $94.8 million. Of this amount, $27.7 million was placed in escrow as security for certain post-closing obligations of the Corporation including indemnification for potential losses arising from litigation involving Columbia Canada. The Corporation expects to receive all or substantially all of the escrow account when the litigation is concluded. Upon emergence from bankruptcy, the Corporation is obligated to deposit into an escrow account an additional $25 million (Canadian). If after emergence from bankruptcy, the Corporation maintains an investment grade bond rating for a six-month period, the additional deposit would be
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
returned. Also, the Corporation has the right to provide a letter of credit in place of the cash deposit. As of December 31, 1993, $25.4 million, including accrued interest, remains in escrow for potential losses arising from litigation.
7. PENSION AND OTHER POSTRETIREMENT BENEFITS
The Corporation has a trusteed, noncontributory pension plan which covers all regular employees, 21 years of age and older. The plan provides defined benefits based on the highest three-year average annual compensation in the final five years of service and years of credited service. It is the Corporation's funding policy to contribute to the plan based on a percentage of payroll, subject to the statutory minimum and maximum limits.
The following table provides 1993-1991 pension cost components for the plan, along with additional relevant data:
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Pension plan assets consist principally of common stock equities and fixed income securities. The following table reconciles plan assets and liabilities to the funded status of the plan:
As of December 31, 1993 the assumptions for the discount rate and the average compensation growth rate have been revised downward to 7.0% and 5.5%, respectively. The net effect of these changes was to increase the accumulated benefit obligation and the projected benefit obligation by $42.2 and $38.2 million, respectively.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
In addition to providing pension benefits, the Corporation's subsidiaries provide other postretirement benefits, including medical care and life insurance, which cover substantially all active employees upon their retirement. The following table provides the total postretirement benefit cost components recognized during 1993 and 1992 along with additional relevant data:
*One of the several established medical trusts is subject to taxation which results in an after-tax asset earnings rate that is less than 9.0%.
* Includes $138.1 million and $127.2 million capitalized by the distribution subsidiaries as a regulatory asset in 1993 and 1992, respectively.
As of December 31, 1993, the assumptions for the discount rate and the average compensation growth rate have been revised downward to 7.0 percent and 5.5 percent, respectively. The net effect of these changes was an $11.0 million increase in the accumulated postretirement benefit obligation.
The healthcare cost trend rate assumption significantly affects the amounts reported. For example, a 1 percent increase in this rate would increase the accumulated postretirement benefit obligation by $19.0 million at December 31, 1993, and increase other postretirement costs by $3.7 million for the year. The accumulated
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
postretirement benefit obligations for 1993 and 1992 were calculated assuming healthcare cost trend rates starting at 12 percent and 16 percent and decreasing to 5.5 percent and 6.5 percent, respectively, after approximately 25 years.
The postretirement medical plans of the majority of the Corporation's subsidiaries are currently funded on a pay-as-you-go basis. However, several subsidiaries have begun advanced funding as this benefit obligation is granted rate recovery. A total of $16.9 million and $13.0 million were contributed to the various medical trusts in 1993 and 1992, respectively.
All of the Corporation's subsidiaries participate in funding for postretirement life insurance benefits utilizing a voluntary employee beneficiary association trust. The Corporation's funding policy is to make annual contributions to this trust, subject to the statutory maximum tax-deductible limit. Employee contributions are not required.
8. LONG-TERM INCENTIVE PLAN
The Corporation has a Long-Term Incentive Plan (Plan) which provides for the granting of nonqualified stock options, stock appreciation rights and contingent stock awards as determined by the Compensation Committee of the Board of Directors. That committee also has the right to modify any outstanding award. A total of 1,500,000 shares of the Corporation's authorized common stock was initially reserved for issuance under the Plan's provisions. There were 363,415 shares remaining available for awards at December 31, 1993.
Stock appreciation rights, which are granted in connection with certain nonqualified stock options, entitle the holders to receive stock, cash or a combination thereof equal to the excess market value over the grant price.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Transactions for the three years ended December 31, 1993, are as follows:
In addition to the options, a contingent stock award of 4,110 shares was granted to a key executive in 1991 which remains outstanding at December 31, 1993.
9. DEFINED CONTRIBUTION (THRIFT) PLAN
Eligible employees may participate in the Thrift Plan by contributing up to 16 percent of their monthly basic earnings to any one or more of several funds. The Corporation's participating subsidiaries make matching contributions of 50 percent to 100 percent of deposits made by each of its participating employees up to 6 percent of basic earnings based upon the months of participation in the plan by each employee. All employer matching contributions for participants under age 55 are invested in the fund holding common stock of the Corporation. Participants age 55 and older may invest employer contributions in any one or more of the several funds. Employees are eligible for participation in the Thrift Plan after completing one year of service.
In 1990, the Corporation established a Leveraged Employee Stock Ownership Plan (LESOP). The LESOP was designed to pre-fund a portion of the matching obligation under the terms of the Thrift Plan and to utilize tax
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
advantages afforded by the Internal Revenue Code.
In October 1991, the Board of Directors of the Corporation authorized the termination of the LESOP subject to the approval of the Bankruptcy Court. It is anticipated that the termination will be part of the Corporation's plan of reorganization. Upon termination, any shares of common stock of the Corporation remaining in the LESOP Trust account would be sold and the proceeds paid to the holders of debentures issued under the LESOP. Any unpaid balance due would become subject to the subordinate guarantee of the Corporation and become a claim to be resolved as part of the reorganization plan. Based on recently issued guidance from the American Institute of Certified Public Accountants, it is anticipated the ultimate termination will not result in any charges to earnings, but will result in a reduction to capital of approximately $34.1 million based on a closing stock price of $25 3/8 on January 31, 1994. As of December 31, 1993, the LESOP suspense account held 1,416,155 shares.
The participating subsidiaries ceased making contributions to the LESOP for debt service payments but continue to contribute to the Thrift Plan those amounts necessary to fulfill the matching obligations to participants. Matching contributions to the Thrift Plan were $11.0 million, $13.2 million and $8.6 million in 1993, 1992, and 1991, respectively. Thrift Plan expenses were $11.0 million, $13.2 million and $17.9 million for 1993, 1992 and 1991, respectively. The difference between matching contributions and expense for 1991 was attributable to the additional expenses required under the now suspended LESOP.
10. DEBT OBLIGATIONS
The Corporation's filing for protection under the Bankruptcy Code constituted an event of default under substantially all of its debt agreements. Because payment of debt which existed at the filing date is suspended by the Bankruptcy Code, substantially all of the Corporation's debt, including short-term debt, has been classified as Liabilities Subject to Chapter 11 Proceedings. In addition, payment of interest on prepetition debt is suspended, and no interest expense on such debt has been recorded since commencement of the bankruptcy proceedings.
Following the Chapter 11 filing, the Corporation received approval from the Bankruptcy Court and the SEC, under the Public Utility Holding Company Act of 1935, for debtor-in-possession financing (the DIP Facility). The DIP Facility is for up to $100 million and includes the availability of letters of credit of up to $50 million. The DIP Facility was reduced by the Corporation from $275 million to $200 million on July 10, 1992 and was reduced to the current level effective June 17, 1993. The Corporation has extended the DIP Facility to December 31, 1994.
Two borrowing options are available to the Corporation under the DIP Facility. The Corporation may borrow at the agent's alternative reference rate plus 1 percent or the Eurodollar rate plus 2 1/4 percent (for either 1, 2 or 3 months). In addition to a commitment fee of 1/2 of 1 percent per annum on the average daily unused amount of the facility, other fees have been paid to the lenders under the DIP Facility.
Columbia Transmission also maintains a DIP Facility solely for the issuance of letters of credit for up to $25 million. Columbia Transmission has extended its DIP Facility to December 31, 1995, to allow for letters of credit with terms for the full calendar year of 1995.
11. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The Corporation, effective December 31, 1992, adopted SFAS No. 107, "Disclosures about Fair Value of Financial Instruments." The Statement extends existing fair value disclosure practices by requiring all entities to disclose the fair value of financial instruments, both assets and liabilities, recognized and not recognized in
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
the Consolidated Balance Sheets, for which it is practicable to estimate fair value. For purposes of this disclosure, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale. Fair value may be based on quoted market prices for the same or similar financial instruments, or on valuation techniques such as the present value of estimated future cash flows using a discount rate commensurate with the risks involved.
The uncertainties related to the outcome of the Corporation's Chapter 11 proceedings and the resulting effect upon the ultimate value of the Corporation's financial assets and liabilities add significantly to the uncertain nature of any estimate of fair value. The estimates of fair value required under SFAS No. 107 require the application of broad assumptions and estimates. Accordingly, any actual exchange of such financial instruments could occur at values significantly different from the amounts disclosed.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
As cash and temporary cash investments, current receivables, current payables, and certain other short-term financial instruments are all short-term in nature, their carrying amount approximates fair value. The estimated fair values of the Corporation's other financial instruments are reflected in the accompanying table.
Long-term investments Long-term investments include escrowed proceeds from the sale of the Canadian subsidiary (see Note 6B), which consist of hedged Canadian Treasury bills ($25.4 million and $25.1 million for 1993 and 1992, respectively). The Canadian Treasury bills are hedged with short-term foreign currency contracts, so that the combined carrying amount of the asset and related hedging instrument approximates fair value. Long-term investments also include an income tax refund receivable with associated interest at IRS rates ($31.2 million for 1993) whose carrying amount approximates fair value. Also included are loans receivable ($12.8 million and $15.6 million for 1993 and 1992, respectively) whose estimated fair values are based on the present value of estimated future cash flows using an estimated rate for similar loans extended currently. It is not practicable to estimate the fair value of long-term receivables ($144.4 million and $154.2 million for 1993 and 1992, respectively) for the expected recovery by Columbia Transmission of certain gas purchase liabilities for which the timing and amount of payments to be received will be dependent on the outcome of the Chapter 11 proceedings. As discussed in Note 2, the uncertainties related to these proceedings could significantly influence the fair value of this financial instrument. The financial instruments included in long-term investments are primarily reflected in Investments and Other Assets in the Consolidated Balance Sheets.
Liabilities subject to Chapter 11 proceedings The estimated fair value of the Corporation's debentures and medium-term notes is based on quoted market prices for those issues that are traded on an exchange, and estimates provided by brokers for other issues. However, quoted market prices and broker estimates inherently include judgments concerning the outcome of the Corporation's and Columbia Transmission's Chapter 11 proceedings.
Note 2 discusses the uncertainties related to these proceedings which could significantly influence the fair value of these financial instruments. It was not practicable to estimate the fair value of the remaining long-term debt, which includes the Subordinated Guarantee of the LESOP debt ($87.0 million) and miscellaneous debt of Columbia Transmission ($1.4 million for 1993 and 1992), because no reliable measurement methodology exists. Prior to filing its petition for protection under Chapter 11 of the Bankruptcy Code, the Corporation regularly issued commercial paper, bank notes and other short-term debt instruments. The carrying amount of such securities ($892.6 million) is included in Liabilities Subject to Chapter 11 Proceedings. Payment of these obligations and any related interest is subject to approval by the Bankruptcy Court. Although investors from time to time may buy and sell these debt obligations, the terms of any such transactions are private and not
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
disclosed to the Corporation. Because there can be no assurance as to the ultimate timing and amount of principal and interest repayments of these obligations, it is not practicable to determine their fair values.
The carrying amount of other Liabilities Subject to Chapter 11 Proceedings ($1,556.0 million and $1,595.4 million for 1993 and 1992, respectively) primarily represents accounts payable, accrued liabilities and other liabilities. As discussed in Note 2, these liabilities are subject to adjustment at the direction of the Bankruptcy Court. In addition, the timing of the ultimate payment of these liabilities, as well as interest, if any, is also subject to determination by the Bankruptcy Court. Accordingly, it is not practicable to determine the fair value of these liabilities.
12. OTHER COMMITMENTS AND CONTINGENCIES
A. CAPITAL EXPENDITURES. Capital expenditures for 1994 are currently estimated at $468 million. Of this amount, $91 million is for oil and gas operations, $201 million for transmission operations, $152 million for distribution operations and $24 million for other energy operations.
B. PRODUCER CONTRACT MATTERS. Columbia Transmission has rejected more than 4,800 natural gas purchase contracts which collectively made the company's gas sales rate noncompetitive. Under Order 636, Columbia Transmission will have a minimal merchant function, i.e., less than one percent of total throughput. Customers' requirements will be met with gas purchased under remaining and new contracts including 30- day spot contracts as may be required. Rejection of additional contracts could result in liabilities that could require future charges against earnings.
C. PARTNERSHIP PROJECTS. Columbia Gulf is a general partner in the Trailblazer, Overthrust and Ozark partnerships. Since these partnerships are nonrecourse, project-financed pipelines, firm shipper contracts were assigned to banks (or in the case of Ozark to the Indenture Trustee) as collateral for loans. Columbia Transmission and other shippers are attempting to negotiate exit fees under Order 636 with the partnerships. As a result of these negotiations and the current depressed demand for the capacity on several of these pipelines, the realizability of these investments is uncertain. Accordingly, a reserve of $5.4 million was established in 1993. At December 31, 1993, Columbia Gulf's investment in the partnerships amounted to $35.4 million, net of the valuation reserve and before related deferred taxes.
D. OTHER LEGAL PROCEEDINGS. The Corporation and its subsidiaries have been named as defendants in various legal
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material adverse impact on the Corporation's consolidated financial position or results of operations.
E. ASSETS UNDER LIEN. The loans under the debtor-in-possession financing arrangement for the Corporation are given superpriority claim status pursuant to Section 364(c) (1) of the Bankruptcy Code. Loans to the Corporation are secured by either a first or second priority perfected lien on, and security interest in, all property of the Corporation including intercompany loans, other than the voting securities of the Corporation's distribution subsidiaries and Columbia LNG. Columbia Transmission's letter of credit facility is secured by either a first or second priority perfected lien on, and security interest in, all property of Columbia Transmission.
Substantially all of Columbia Transmission's properties have been pledged to the Corporation as security for debt owed by Columbia Transmission to the Corporation.
F. COVE POINT LNG TERMINAL. In 1991, the Corporation entered into a conditional agreement for the sale of its remaining interest in Columbia LNG to Shell LNG Company (Shell LNG), a subsidiary of Shell Oil Company. On July 16, 1992, the Corporation was notified by Shell LNG that it would not proceed with the interim purchase of 40.8 percent of the stock of Columbia LNG. Shell LNG's notification terminated the agreements between the Corporation and Shell LNG for the purchase of the remaining Columbia LNG stock. Shell LNG currently owns 9.2 percent of Columbia LNG's outstanding stock.
As previously reported, Columbia LNG has developed a new business plan to reactivate the Cove Point facility. This plan anticipated a new peaking and storage service by the end of 1994, as well as a terminalling service for liquefied natural gas (LNG) received by tanker. An application with the FERC to charge customers based upon individually negotiated market rates was filed in February 1993. In accordance with the business plan and in anticipation of the FERC filing, management concluded, in 1992, that it was no longer appropriate for Columbia LNG to continue application of SFAS No. 71 and regulatory assets were removed from Columbia LNG's balance sheet resulting in an extraordinary charge of $60.1 million pre-tax ($39.7 million after-tax) recorded in the third quarter of 1992.
An open season, allowing potential customers to bid on the capacity of all of the offered services, was held March 31, 1993 through April 14, 1993. Based on the results of the bids, which were not sufficient to proceed with the project as it was originally proposed, Columbia LNG restructured the offered services to more adequately address the service needs of the potential customers. A second open season, offering additional services, was held May 24, 1993 through June 2, 1993. This open season resulted in sufficient bids to proceed with the peaking and transportation services. The one bid received during the second open season for baseload terminalling service was subsequently withdrawn. As a result, Columbia LNG does not currently anticipate a baseload terminalling service in the near future. As a consequence, Columbia LNG recorded a writedown in the carrying value of its investment in the Cove Point facility in the second quarter 1993 that reduced the Corporation's income $37.9 million after-tax. This amount included estimated dismantling costs for the offshore facilities of approximately $12 million after-tax. However, until such time as the offshore facilities are transferred to the new partnership, as discussed below, Columbia LNG plans to maintain the facilities for possible future imports and, at the present time, has no plans to abandon or dismantle them. Besides the writedown discussed above and the extraordinary charge discussed in the preceding paragraph, Columbia LNG has incurred operating losses during the prior three years which are not significant to the consolidated financial results of the Corporation.
On October 28, 1993, as amended on January 27, 1994, PEPCO Enterprises, Inc. (PEPCO), which is a wholly-owned subsidiary of Potomac Electric Power Company, entered into an agreement to form a limited partnership.
The February 1993 filing with the FERC was withdrawn by Columbia LNG and the Partnership, Cove Point LNG Limited Partnership (Cove Point LNG) that will pursue the business plan discussed above, filed an
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
application with the FERC on November 3, 1993, seeking authorization to acquire all of the existing plant and pipeline facilities owned by Columbia LNG and for authorization to recommission the plant and construct new facilities in order to provide peaking services beginning in 1995. On the same day, Columbia LNG filed with the FERC for authorization to abandon its facilities by transfer to Cove Point LNG and to withdraw its February 26, 1993 filing. In addition to the FERC, this transaction will require other governmental approvals. Bankruptcy Court approval was received in January 1994.
After the receipt of necessary regulatory approvals, the PEPCO affiliates will contribute up to $25 million in equity and loans for their half interest in the partnership. At the same time, Columbia LNG will transfer title to its existing plant and pipeline facilities to the partnership and assign to the partnership the precedent agreements for the services to be offered. Any cash requirements of the partnership prior to the in-service date of the project which are in excess of $25 million will be provided by Columbia LNG up to a maximum of $7 million. The cost of recommissioning the Cove Point facility and installing the necessary liquefaction equipment is estimated to be approximately $27 million. Columbia LNG or an affiliate will operate the plant and pipeline facilities for the partnership.
A number of intervenors filed with the FERC in regard to Columbia LNG's plan for the Cove Point facility. While generally supportive of the plan to reopen the facility, some of the intervenors questioned the use of the individually negotiated market rates and requested the pass-through of certain benefits from prior collections from Columbia Transmission.
The realization of the Corporation's remaining investment in Columbia LNG of $10.1 million will be dependent upon successful implementation of the partnership and related business plan.
G. OPERATING LEASES. Payments made in connection with operating leases are charged to operation and maintenance expense as incurred. Such amounts were $55.5 million in 1993, $57.9 million in 1992 and $57.9 million in 1991. Future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year are:
H. ENVIRONMENTAL MATTERS. The Corporation's subsidiaries are subject to extensive federal, state and local laws and regulations relating to environmental matters. These laws and regulations, which are constantly changing, require expenditures for corrective action at various operating facilities, waste disposal sites and former gas manufacturing sites for conditions resulting from past practices that subsequently were determined to be environmentally unsound.
Certain subsidiaries have received notice from the United States Environmental Protection Agency (EPA) that
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
they are among several parties responsible under federal law for placing wastes at Superfund sites and may be required to share in the cost of remediation for these sites. However, considering known facts, existing laws and possible insurance and rate recoveries, management does not believe the identified Superfund matters will have a material adverse effect on future annual income or on the Corporation's financial position.
The transmission subsidiaries are continuing their comprehensive review of compliance with existing environmental standards, including review of past operational activities and identification of potential site problems, through site reviews and formulation of remediation programs where necessary. While the Corporation's transmission subsidiaries have made progress in these ongoing self-assessment programs, because of the thousands of miles of pipeline which they operate, the exceptionally large number of sites at which they conduct or have conducted operations, and the long period over which operations have been conducted, completion of site screenings, characterizations and site-specific remediations will cover a time frame of approximately 10 to 12 years.
A study for Columbia Transmission to quantify the scope of remediation activities which will be undertaken in future years to address the issues identified was recently concluded. The study, site investigations and characterization efforts performed throughout 1993 resulted in total accruals for the year of approximately $60 million for Columbia Transmission. These and other minor adjustments bring Columbia Transmission's recorded net liability to approximately $143.6 million at December 31, 1993. This represents the lower end of the range of reasonable outcomes with the upper end estimated to total approximately $280 million based on information currently available.
As characterization and site-specific activities by Columbia Transmission determine the nature and extent of contamination, if any, at its operating facilities and as remediation plans are developed, additional charges to earnings could occur. To the extent such plans require approval of federal and/or state authorities, estimates are subject to revision. Based on the limited data now available and various assumptions as to characterization, management believes that annual future expenditures for Columbia Transmission's site investigations, characterization and remediation activities could be up to $20 million per year over an approximate 10 to 12 year time frame. Earnings will continue to be charged appropriately in advance of required expenditures.
As a result of site characterization studies at various locations, during 1993, Columbia Gulf recorded an additional accrual of $6.7 million for environmental remediation. This accrual is for polychlorinated biphenyl (PCB) and petroleum hydrocarbon cleanup at certain compressor station sites and screenings for possible exposure at other locations. Columbia Gulf anticipates completion of cleanup during 1994. At that time, costs of remediation, if any, will be quantified and an additional accrual may become necessary.
In 1992, Columbia Transmission received a subpoena and information request (Request) from the EPA Region III regarding three major environmental statutes: The Toxic Substances Control Act (TSCA), the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response Compensation and Liability Act (CERCLA). The Request relates to Columbia Transmission's past and current environmental practices. Since receipt of the Request, Columbia Transmission has provided the EPA with various materials pursuant to the Request. Columbia Transmission has continued to meet with the EPA to attempt to resolve the subpoena issues and continues to work cooperatively with environmental officials in the various states in which it operates. All environmental agencies have been declared exempt from the Bar Date established by the Bankruptcy Court for claims by creditors.
Columbia Transmission on January 28, 1994, received from EPA Region V an Information Request pursuant to the RCRA. The agency requested Columbia Transmission to submit information and knowledge relating to its generation and management of natural gas pipeline condensate, used engine oil and similar liquids in the state of Ohio. Columbia Transmission is in the process of analyzing the information requested and will be discussing this Information Request with EPA Region V.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
At least one distribution subsidiary and some of the predecessor companies of the distribution subsidiaries were, or may have been, involved with the ownership and/or the operation of manufactured gas plants. At the present time management is aware of twelve such sites. The distribution subsidiaries are conducting investigations at five sites that date back to the mid-1800s. These plants heated coal tar in a low-oxygen atmosphere to manufacture low-cost gas for areas where natural gas was not generally available. The process created residues such as coal tar which were typically stored on site prior to being sold for commercial use. However, when the plants stopped operation the remaining residue material was in some cases simply buried on the plant sites. As time passed, other uses were made of the plant sites and in some cases their identity as a manufactured gas plant was lost. To the extent site investigations have been completed, remediation plans developed, and any responsibility for remedial action established, the appropriate liability has been recorded. The environmental assessment and evaluation process will continue over the next three to five years. Environmental investigations indicate that remedial action may be required. Investigations will be conducted at a number of the other sites in the near future. The following discusses the status of certain sites:
In 1985, CPA was cited by the Pennsylvania Department of Environmental Resources for coal tar residues on the bottom of a creek bed in York, Pennsylvania. The area was adjacent to the site of a manufactured gas plant operated from 1885 to the early 1950s by a predecessor company, the York County Gas Company, which was purchased in 1968. The site has been under investigation by CPA's consultants to determine the extent of any underground contamination and to propose various remedial measures that can be used to eliminate the release to the creek or remediate the premises. The current costs of the investigation are being recovered in rates. Site remediation costs have been estimated at $4.2 million, which has been recorded as a liability and a corresponding regulatory asset. CPA expects to continue to recover these costs in rates based upon orders received in previous rate cases. However, the ability to recover these costs is subject to (1) the results of each future rate case during the expenditure period or (2) the outcome of a settlement proposal to treat these expenditures as a cost of removal by charging them to the reserve for depreciation and recover them over a five-year period. Remediation work is expected to start in 1994.
Penn Fuel Gas, Inc. (Penn Fuel) advised CPA that a site in Bellefonte, Pennsylvania, sold to Penn Fuel by Central Pennsylvania Gas Company in 1960 was the location of a manufactured gas plant until the mid-1950s. The plant's equipment was disassembled at the time Penn Fuel acquired the property. The old processing building is still used as a warehouse by Penn Fuel. In 1966, CPA acquired substantially all of Central Pennsylvania Gas Company's assets and liabilities.
CPA has agreed to share with Penn Fuel, the costs of investigating the site for environmental contamination and up to $300,000 of the investigation costs. A regulatory asset and offsetting liability was recorded by CPA in March 1993. There is no agreement, nor is there any admission by either CPA or Penn Fuel, regarding liability, if any, for abatement and/or remediation of the site. It is expected that the positions and potential responsibility of each party will become clearer as the investigation proceeds.
In January 1993, the owners of the Patio Plaza Apartments, BMI Apartment Associates (a partnership), contacted COS about possible soil contamination of a site in Portsmouth, Virginia, on which the Portsmouth Gas Company operated a manufactured gas plant from 1854 to 1951. The Portsmouth Gas Company sold this site to the Portsmouth Redevelopment and Housing Authority in 1960. The Portsmouth Gas Company was acquired by Commonwealth Natural Resources, Inc. and subsequently merged into COS in 1981. The Redevelopment Authority subsequently razed the plant and sold the vacant land. Apartments and houses were built on the property and the current owners of some of the apartments reported possible soil contamination to the Virginia Water Quality Control Board. COS notified the EPA regarding the engineering reports provided to it by the owners.
On March 25, 1993, COS and the Portsmouth Redevelopment and Housing Authority jointly filed suit in U.S. District Court, Eastern District of Virginia at Norfolk, Virginia, against the current and former owners of the apartments. The suit sought a declaration that those other parties are liable for the site and requested access to the property for testing which had been denied by the current owners. On June 14, 1993, the Court ordered
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
that COS be permitted access to perform necessary testing of soil and air that resulted in a determination that there was no imminent danger to the residents. Subsequently, the Court granted a stay of all legal proceedings until May 16, 1994 to permit COS to conduct further site testing to determine the extent of any contamination and to recommend corrective measures. Most of that testing was completed in November and December 1993, and the results are anticipated in early 1994. On February 14, 1994, the judge appointed a magistrate to oversee settlement of the suit.
COS incurred legal and engineering consultant expenses that reached approximately $400,000 in 1993. Additional costs are currently anticipated to reach $400,000 in 1994 and accordingly a regulatory asset has been established for $800,000 and the appropriate liability recorded. Other work at this site is anticipated but it is not possible at this time to estimate the costs. Permission was granted by the VSCC to defer the costs of this project as a regulatory asset, subject to recovery in the next rate case.
In February 1993, COS reported to the Virginia Department of Environmental Quality (VaDEQ) a potential soil contamination below a retaining wall at the Petersburg, Virginia Service Center . The VaDEQ has ordered COS to prepare a preliminary site assessment related to the report. In early June 1993, COS contractors performed testing and prepared the preliminary site assessment which was submitted to VaDEQ in July 1993. Additional testing on another area of leakage was conducted in September 1993 with results reported to the VaDEQ in late October 1993. COS is currently completing the removal of contaminated material from an old underground tank on the property which was contributing to the leakage problem. Additional corrective work may be performed in 1994 as a result of further testing that will be conducted.
COS has incurred legal and engineering consultant expenses that reached approximately $170,000 by the end of 1993. At this time, it is not possible to estimate the costs of corrective action or of further work the VaDEQ might require. However, additional consultant costs are estimated to be $280,000 in 1994. Accordingly, a regulatory asset of $450,000 has been established and the liability recorded. Permission was granted by the VSCC to defer the costs of this project as a regulatory asset subject to recovery in the next rate case.
A former manufactured gas plant site in Lynchburg, Virginia was included with the assets of the Lynchburg Gas Company when it was merged into COS in 1989. A liability of $600,000 has been recorded for the removal of certain remaining structures from the manufactured gas plant and clean up of debris at the site. The VSCC has granted COS permission to defer the costs associated with this work and any other remediation related to the site for review and potential recovery in rates at a later time.
A former manufactured gas plant site in Hagerstown, Maryland was included with other assets of the Hagerstown Gas Company acquired by CMD in 1969. This plant operated between 1891 and 1949. The site, at the location of the CMD service center in Hagerstown was reported to the EPA by the state and has been assigned medium priority status by the EPA for future investigation. No investigations have been conducted by the state of Maryland or the EPA at this site and, therefore, it is not possible at this time to estimate the cost of remediation activities, if any.
To the extent the above-mentioned site investigations have been completed, remediation plans developed, and any Distribution responsibility for remedial action established, the appropriate liability has been recorded. As additional investigations are completed and remediation costs become probable, the appropriate liability will be recorded. As of December 31, 1993, the distribution subsidiaries recorded net liabilities of $5.9 million. Management anticipates recovery of remediation costs through normal rate proceedings.
The eventual total cost of full future environmental compliance for the Columbia Gas System is difficult to estimate due to, among other things: (1) the possibility of as yet unknown contamination, (2) the possible effect of future legislation and new environmental agency rules, (3) the possibility of future litigation, (4) the possibility of future designations as a potential responsible party by the EPA and the difficulty of determining liability, if any, in proportion to other responsible parties, (5) possible insurance and rate recoveries, and (6) the effect of possible technological changes relating to future remediation. However, reserves have been
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
established based on information currently available which resulted in a total recorded net liability of $156.1 million for the Columbia Gas System at December 31, 1993, which includes the low end of a range for certain expenditures for the transmission segment previously discussed. As new issues are identified, appropriate additional liabilities may have to be recorded.
It is management's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred.
Management expects most environmental assessment and remediation costs to be recoverable through rates. Although significant charges to earnings could be required prior to rate recovery, management does not believe that environmental expenditures will have a material adverse effect on the Corporation's financial position, based on known facts, existing laws and regulations and the period over which expenditures are required.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
13. INTEREST INCOME AND OTHER, NET
14. INTEREST EXPENSE AND RELATED CHARGES
15. CHANGES IN COMPONENTS OF WORKING CAPITAL
(excludes cash and temporary cash investments, short-term debt and current maturities of long-term debt)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
16. BUSINESS SEGMENT INFORMATION
The following tables provide information concerning the Corporation's major business segments. Revenues include intersegment sales to affiliated subsidiaries, which are eliminated when consolidated. Affiliated sales are recognized on the basis of prevailing market or regulated prices. Operating income is derived from revenues and expenses directly associated with each segment. Identifiable assets include only those attributable to the operations of each segment.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
17. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarterly financial data does not always reveal the trend of the System's business operations due to bankruptcy matters, nonrecurring items and seasonal weather patterns which affect earnings and related components of operating revenues and expenses.
(a) Includes an increase in net income of $13.2 million for the reversal of rate reserves to reflect the outcome of rate cases related to the transmission segment. The effect of not recording interest expense on prepetition debt improved net income $38.2 million.
(b) Includes a decrease in net income of $37.9 million to record a writedown in the investment in the Cove Point LNG facility and a decrease in net income of $7.4 million to record the estimated loss on the sale of storage inventory. The effect of not recording interest expense on prepetition debt improved net income $36.0 million.
(c) Includes a decrease in net income of $40.4 million to record the effect of a preliminary settlement with the IRS, a decrease in net income of $13.0 million to record a liability for future environmental remediation costs, a decrease in net income of $9.8 million to reflect the effect of the higher federal corporate tax rate and a decrease in net income of $9.8 million for several smaller unusual items. The effect of not recording interest expense on prepetition debt improved net income $33.8 million.
(d) Includes an increase in net income of $13.5 million for gas inventory charges collected from customers and an increase in net income of $12.8 million for the WACOG surcharge collected from customers, partially offset by a decrease in net income of $12.6 million for an adjustment to interest income for pipeline direct billings. The effect of not recording interest expense on prepetition debt improved net income $30.1 million.
(e) Includes a decrease in net income of $83.4 million to record a writedown in the carrying value of U.S. oil and gas properties. The effect of not recording interest expense on prepetition debt improved net income $36.8 million.
(f) The effect of not recording interest expense on prepetition debt improved net income $36.0 million.
(g) Includes a decrease in net income of $39.2 million to record a liability for future environmental remediation costs and a decrease in net income of $24.2 million to record a provision for gas supply charges. The effect of not recording interest expense on prepetition debt improved net income $36.6 million.
(h) Includes an increase in net income of $13.1 million for gas inventory charges collected from customers. The effect of not recording interest expense on prepetition debt improved net income $39.1 million.
18. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
INTRODUCTION. Reserve information contained in the following tables for the U.S. properties is management's estimate, which was reviewed by the independent consulting firm of Ryder Scott Company Petroleum Engineers. Reserves are reported as net working interest. Gross revenues are reported after deduction of royalty interest payments.
The Corporation sold its Canadian subsidiary to Anderson Exploration Ltd. of Calgary effective December 31, 1991. In 1991 the oil and gas operations of the Canadian subsidiary resulted in a $24.4 million loss. Accordingly, the reserve and other information for the Canadian properties are not included in the tables for 1991, 1992 and 1993.
(a) Represents expenditures associated with properties on which evaluations have not been completed.
Results of operations for producing activities exclude administrative and general costs, corporate overhead and interest expense.
Income tax expense is expressed at statutory rates less Section 29 credits.
(a) Includes writedown of the carrying value of $126.4 million for 1992.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
Future cash inflows are computed by applying year-end prices to estimated future production of proved oil and gas reserves. Future expenditures (based on year-end costs) represent those costs to be incurred in developing and producing the reserves. Discounted future net cash flows are derived by applying a 10% discount rate, as required by the Financial Accounting Standards Board, to the future net cash flows. This data is not intended to reflect the actual economic value of the Corporation's oil and gas producing properties or the true present value of estimated future cash flows since many arbitrary assumptions are used. The data does provide a means of comparison among companies through the use of standardized measurement techniques.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
A reconciliation of the components resulting in changes in the standardized measure of discounted cash flows attributable to proved oil and gas reserves for the three years ending December 31, 1993, follows:
The estimated discounted future net cash flows decreased during 1993 primarily due to net changes in prices and production costs and revisions to the economic feasibility of producing certain wells. The standardized measure of the Corporation's oil and gas properties can be influenced by affiliated and unaffiliated pipeline transportation rate design (which continues to be evaluated by the FERC).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule I ---------- Page 1 of 2
MARKETABLE SECURITIES - OTHER INVESTMENTS The Columbia Gas System, Inc. and Subsidiaries December 31, 1993 ($ in Millions)
* The short-term investment portfolio consists of numerous securities with similar market characteristics such as credit quality, maturity and marketability. These include bills, notes and bonds issued by the U.S. Government or its agencies (either purchased directly for the System or through repurchase agreements) and money market instruments issued by foreign and domestic corporations. Such instruments include commercial paper and bank certificates of deposit.
** As these securities are short-term in nature, their carrying amount approximates market value.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule I ---------- Page 2 of 2
MARKETABLE SECURITIES - OTHER INVESTMENTS The Columbia Gas System, Inc. and Subsidiaries December 31, 1992 ($ in Millions)
* The short-term investment portfolio consists of numerous securities with similar market characteristics such as credit quality, maturity and marketability. These include bills, notes and bonds issued by the U.S. Government or its agencies (either purchased directly for the System or through repurchase agreements) and money market instruments issued by foreign and domestic corporations. Such instruments include commercial paper and bank certificates of deposit.
** As these securities are short-term in nature, their carrying amount approximates market value.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V The Columbia Gas System, Inc. and Subsidiaries ---------- Year Ended December 31, 1993 Page 1 of 3 ($ in Millions)
(a) Primarily reflects well sales by Columbia Natural Resources, Inc. ($5.5 million).
(b) Primarily reflects Columbia Transmission's transfer of 1.3 Bcf from current gas inventory.
(c) Excludes capital expenditures related to "Investments and Other Assets" ($6.8 million).
NOTE:Construction work in progress for Gas Utility Plant was $56.7 million as of December 31, 1993.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V The Columbia Gas System, Inc. and Subsidiaries ---------- Year Ended December 31, 1992 Page 2 of 3 ($ in Millions)
(a) Primarily reflects the net transfer of assets from Inland Gas Company (Oil and Gas - $5.5 million) to Columbia Gas of Kentucky, Inc. (Distribution $5.5 million), and sales of assets by Columbia Natural Resources, Inc. (Oil and Gas - $4.9 million).
(b) Excludes capital expenditures related to "Investments and Other Assets" ($6.1 million).
(c) Primarily reflects Columbia Transmission's transfer of 9.7 Bcf of gas to current gas inventory.
NOTE:Construction work in progress for Gas Utility Plant was $55.9 million as of December 31, 1992.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
PROPERTY, PLANT AND EQUIPMENT Schedule V The Columbia Gas System, Inc. and Subsidiaries ---------- Year Ended December 31, 1991 Page 3 of 3 ($ in Millions)
(a) Reflects sales of assets by Columbia Natural Resources, Inc.
(b) Includes foreign currency translation adjustment applicable to Canadian property ($1.1 million).
(c) Includes the sale of Columbia Gas Development of Canada Ltd. in a transaction completed in January 1992, effective December 31, 1991. (Canadian Cost Center - $276.5 million and Other General Plant - $1.8 million).
(d) Includes reclassification of certain Inland Gas Company assets from Distribution properties (Distribution - $7.7 million and Other - $7.0 million) to Oil and Gas properties (Other General Plant $14.7 million).
(e) Reflects the deconsolidation of Columbia LNG Corporation, now recorded as "Investment in Columbia LNG Corporation".
(f) Includes the sale of Columbia Gas of New York, Inc. in a transaction completed in April 1991 (Distribution - $55.4 million and Other - $5.6 million).
(g) Excludes capital expenditures related to "Investments and Other Assets" ($5.1 million).
NOTE:Construction work in progress for Gas Utility Plant was $52.1 million as of December 31, 1991.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY, PLANT AND EQUIPMENT Schedule VI The Columbia Gas System, Inc. and Subsidiaries ----------- Year Ended December 31, 1993 Page 1 of 3 ($ in Millions)
NOTE:"Other Changes" generally includes reductions for property sold and the cost of retiring property, offset by salvage on property retired and miscellaneous items.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY, PLANT AND EQUIPMENT Schedule VI The Columbia Gas System, Inc. and Subsidiaries ----------- Year Ended December 31, 1992 Page 2 of 3 ($ in Millions)
NOTE:"Other Changes" generally includes reductions for property sold and the cost of retiring property, offset by salvage on property retired, and miscellaneous items. Significant items are noted below.
(a) Includes a writedown in the carrying value of the United States Cost Center ($126.4 million).
(b) Primarily reflects the net transfer of assets from Inland Gas Company (Oil and Gas - $3.4 million) to Columbia Gas of Kentucky, Inc. and sales of assets by Columbia Natural Resources, Inc. (Oil and Gas - $5.5 million).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
ACCUMULATED DEPRECIATION AND DEPLETION OF PROPERTY, PLANT AND EQUIPMENT Schedule VI The Columbia Gas System, Inc. and Subsidiaries ----------- Year Ended December 31, 1991 Page 3 of 3 ($ in Millions)
Note:"Other Changes" generally includes reductions for property sold and the cost of retiring property, offset by salvage on property retired, and miscellaneous items. Significant items are noted below.
(a) Includes writedowns to reduce the carrying value of the Canadian Cost Center ($61.6 million). A portion of the writedown was recorded in "Cumulative Effect of Change in Accounting for Income Taxes" ($25.2 million) in connection with the adoption of SFAS No. 96.
(b) Includes the sale of Columbia Gas Development of Canada Ltd. in a transaction completed in January 1992, effective December 31, 1991. (Canadian Cost Center - $191.1 million and Other General Plant - $1.1 million).
(c) Includes reclassification of certain Inland Gas Company assets from Distribution properties (Distribution - $5.1 million and Other - $5.4 million) to Oil and Gas properties (Other General Plant $11.3 million).
(d) Reflects the deconsolidation of Columbia LNG Corporation, now recorded as "Investment in Columbia LNG Corporation".
(e) Includes the sale of Columbia Gas of New York, Inc. in a transaction completed in April 1991 (Distribution - $14.6 million and Other - $3.0 million).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule VIII ------------- VALUATION AND QUALIFYING ACCOUNTS The Columbia Gas System, Inc. and Subsidiaries Year Ended December 31, ($ in Millions)
(a) Reflects reclassification to a regulatory asset of the uncollectible accounts related to the Percent of Income Plan (PIP) of Columbia Gas of Ohio, Inc.
(b) Principally reflects amounts charged off as uncollectible less amounts recovered.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
SHORT-TERM BORROWINGS (A) Schedule IX The Columbia Gas System, Inc. and Subsidiaries ----------- ($ in Millions) Page 1 of 2
(a) Prior to June 19, 1991, certain working capital requirements of the Corporation and its subsidiaries were met through the sale of commercial paper, through notes sold directly to commercial banks and/or through borrowings under bank lines of credit. The commercial paper was sold through dealers with maturities ranging from one day to nine months. The Corporation maintained a $500 million revolving short-term committed line of credit, for which participating banks were paid fees of 1/8% per annum on the total facility and 1/16% per annum on the unused portion of the facility. In addition, a $750 million revolving
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
SHORT-TERM BORROWINGS (A) Schedule IX The Columbia Gas System, Inc. and Subsidiaries ----------- ($ in Millions) Page 2 of 2
subordinated committed line of credit was maintained, for which participating banks were paid 3/8% per annum on the unused portion of the facility. Loans under the lines of credit bore interest according to rate options based on prime, bank certificates of deposit or the London InterBank Offered Rate. Since its Chapter 11 filing, the Corporation has had $266.5 million of commercial paper and $621 million of bank loans in default under these facilities.
For periods subsequent to the Chapter 11 filings, Debtor-In-Possession (DIP) Financing facilities were established by the Corporation and Columbia Transmission. The Corporation has available up to $100 million, reduced from $200 million on June 18, 1993, under its DIP Financing facility. Borrowings are at the agent's per annum alternate reference rate plus 1% or the Eurodollar Rate plus 2-1/4% (for either 1, 2 or 3 months). Also, the Corporation is subject to a commitment fee of one-half of 1% per annum on the average daily unused amount of the facility. Additionally, Columbia Transmission's separate DIP facility initially of up to $80 million was reduced to $25 million, on November 29, 1991, which is only available for the issuances of Letters of Credit. Borrowings were at the agent's per annum alternate reference rate plus 1-1/2% or the Eurodollar Rate plus 2-3/4% (for either 1, 2 or 3 months). Columbia Transmission is also subject to a commitment fee of one-half of 1% per annum on the average daily unused amount of the facility.
For additional information regarding these DIP facilities, reference is made to pages 51 and 52 of Management's Discussion and Analysis in Item 7 and Note 10 in Item 8 on page 83. Reference is also made to the DIP Financing Exhibits 10-BR, 10-CB, 10-CC, 10-CD, 10-CF, 10- CG, 10-CH, 10-CK and 10-CL included or incorporated by reference, in this filing.
(b) Based on actual interest expense divided by the average daily borrowings outstanding during the period.
(c) The Corporation did not have any amounts outstanding under its DIP facility during 1993. However, the Corporation's facility was used during the periods January 1, 1992 through December 31, 1992 and August 20, 1991 through December 31, 1991. Columbia Transmission did not have any amounts outstanding under its DIP facility during 1993 and 1992. However, the facility was used during the period of August 6, 1991 through August 21, 1991. Both the Corporation's and Columbia Transmission's DIP facilities include the availability of letters of credit of up to $50 million and $25 million, respectively. As of December 31, 1993, $12.8 million and $1.8 million of letters of credit were outstanding under the Corporation's and Columbia Transmission's DIP facilities, respectively.
(d) The period used in calculating the amounts for short-term financing was from January 1, 1991 through June 18, 1991. This period represents the time during which the Corporation was not in default of its loan agreements.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
Schedule X ----------
SUPPLEMENTARY INCOME STATEMENT INFORMATION The Columbia Gas System, Inc. and Subsidiaries ($ Millions)
Depreciation and amortization of intangible assets, pre-operating costs and similar deferrals, royalties and advertising costs have been omitted inasmuch as the amounts are not in excess of one percent of total revenues as reported in the Statements of Consolidated Income.
ITEM 9.
ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There has not been a change of accountants nor any disagreements concerning accounting and financial disclosure within the past two years.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by this item is contained in the Corporation's Proxy Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
Information regarding the System's executive officers, who are elected annually by the directors, is as follows:
The Columbia Gas System, Inc.
JOHN H. CROOM, 61, Chairman of the Board, President and Chief Executive Officer of the Corporation since August 1984.
DANIEL L. BELL, JR., 64, Senior Vice President and Chief Legal Officer of the Corporation since January 1989, Corporate Secretary since January 1988. Senior Vice President of Columbia's Service Corporation since September 1979.
LOGAN W. WALLINGFORD, 61, Senior Vice President of Columbia Gas System Service Corporation since March 1989. Senior Vice President of Planning and Storage for Columbia Transmission from July 1988 to February 1989, Senior Vice President, Gas Acquisition from July 1987 to June 1988, Vice President of Planning from March 1985 to June 1987.
RICHARD E. LOWE, 53, Vice President of the Corporation and Columbia Gas System Service Corporation since September 1988. Vice President and General Auditor of Columbia Gas System Service Corporation from April 1987 to August 1988. Treasurer of Columbia Gas Development Corporation from April 1979 to March 1987.
JAMES P. HOLLAND, 45, Chairman and Chief Executive Officer of Columbia Transmission and Columbia Gulf Transmission Company since September 1990. President of Columbia Transmission from May 1988 to August 1990. President of Columbia Gulf Transmission Company from October 1989 to August 1990. Senior Vice President of Marketing of Columbia Transmission from July 1987 to April 1988, Senior Vice President of Gas Procurement from January 1986 to June 1987.
C. RONALD TILLEY, 56, Chairman and Chief Executive Officer of Columbia Distribution Companies since January 1987.
MICHAEL W. O'DONNELL, 49, Senior Vice President and Chief Financial Officer of the Corporation since October 1993. Senior Vice President and Assistant Chief Financial Officer of the Columbia Gas System Service Corporation since 1989.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is contained in the Corporation's Proxy Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is contained in the Corporation's Proxy Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is contained in the Corporation's Proxy Statement related to the 1993 Annual Meeting of Stockholders, filed pursuant to Section 14 of the Securities Exchange Act of 1934 and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Exhibits Reference is made to pages 116 through 120 for the list of exhibits filed as a part of this Annual Report on Form 10-K.
Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of the Corporation or its subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of the Corporation and its subsidiaries on a consolidated basis. The Corporation agrees to furnish a copy of any such instrument to the SEC upon request.
Financial Statement Schedules All of the financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8.
Reports on Form 8-K A report on Form 8-K was filed on November 18, 1993, discussing the retirement of Mr. John D. Daly, executive vice president of The Columbia Gas System, Inc. and Columbia Gas System Service Corporation effective December 1, 1993.
A report on Form 8-K was filed on January 3, 1994, discussing the Bankruptcy Court's approval of the extension to March 22, 1994, that Columbia Transmission and the Corporation have the exclusive right to file Chapter 11 plans of reorganization.
A report on Form 8-K was filed on January 19, 1994, discussing Columbia Transmission's filing of its Chapter 11 Reorganization Plan with the Bankruptcy Court.
A report on Form 8-K was filed on February 14, 1994, containing a Press Release published on February 10, 1994, regarding the financial and operating results for the year ended December 31, 1993.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
Undertaking made in Connection with 1933 Act Compliance on Form S-8 For purposes of complying with the amendments to the rules governing Form S-8 under the Securities Act of 1933, the Corporation undertakes the following, which is incorporated by reference into the registration statements on Form S-8, Nos. 33-10004 (filed November 26, 1986) and 33- 42776 (filed September 13, 1991):
Insofar as indemnification for liabilities arising under the Securities Act of 1933 (Act) may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the questions whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
SIGNATURES ----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE COLUMBIA GAS SYSTEM, INC. ----------------------------- (Registrant)
Dated: March 11, 1994
By: /s/ M. W. O'Donnell ---------------------------------------- (M. W. O'Donnell) Senior Vice President and Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
EXHIBIT INDEX -------------
Reference is made in the two right-hand columns below to those exhibits which have heretofore been filed with the Commission. Exhibits so referred to are incorporated herein by reference.
EXHIBIT INDEX (Continued)
- --------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
*Filed herewith
EXHIBIT INDEX (Continued)
- --------------------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K.
EXHIBIT INDEX (Continued)
- --------------------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. *Filed herewith.
EXHIBIT INDEX (Continued)
- -------------------------- (a) Executive Compensation arrangements filed pursuant to Item 14 of Form 10-K. *Filed herewith.