ITEM 3: LEGAL PROCEEDINGS
Mystery Bridge Road Environmental Matters
The Company was named as one of four potentially responsible parties ("PRPs") at a U.S. Environmental Protection Agency ("EPA") Superfund site known as the Mystery Bridge Road/U.S. Highway 20 site located
near Casper, Wyoming (the "Brookhurst Subdivision"). The EPA's remedy consists of two parts, "Operating Unit One," which addresses the groundwater cleanup and "Operating Unit Two," which addresses cleanup procedures for the soil and free-phase petroleum product. A Consent Decree between the Company, the EPA and another PRP was entered on October 2, 1991, in the Wyoming Federal District Court. Groundwater cleanup under Operating Units One and Two have been proceeding since 1990 and 1992, respectively, and is expected to proceed through 1996 at a total cost remaining estimated not to exceed $150,000. (United States of America v. Dow Chemical Company, Dowell Schlumberger, Inc., and K N Energy, Inc., Civil Action No. 91CV1042, United States District Court for the District of Wyoming; formerly reported as Administrative Orders for Removal Action on Consent, October 15, 1987, and Amendment to Administrative Order for Removal Order on Consent, October 10, 1989, Docket No. CERCLA VII-88-01, United States Environmental Protection Agency; Judicial Entry of Consent Decree, United States v. Dow Chemical Company, et al. (D. Wyo) USDC-WY-91CV1042B, Superfund Site Number 8T83, Natrona County, Wyoming; EPA Docket Number CERCLA-VIII.)
Other Environmental Matters
An environmental audit performed by the Company revealed that a grease known as Rockwell 860 had been used as a valve sealant at several of the Company's locations in Nebraska and Colorado. Rockwell 860 is a solid clay-like material which does not easily spill into the environment, but contains approximately ten percent PCBs. The PCBs are contained within the pipeline and valves at the subject locations. PCBs are regulated under the Toxic Substances Control Act. On March 31, 1993, the Company filed suit against Rockwell International Corporation, manufacturer of the valve sealant, and two other related defendants, alleging that the defendants were responsible for the Company's environmental expenses and commercial losses resulting from any EPA or state required PCB cleanup or mitigation. The Company settled with Rockwell, et al. in March 1994 which resolved all disputes between the parties. (K N Energy, Inc. and Rocky Mountain Natural Gas Company v. Rockwell International Corp et al., United States District Court for the District of Colorado, Case No. 93-711.)
During February 1994, the Company submitted its Phase I Report and PCBs Work Plan to EPA Region VII (covering Nebraska) and EPA Region VIII (covering Colorado). During March 1994, EPA Region VIII accepted both the Phase I Report and the PCBs Work Plan as administratively complete. EPA Region VIII also granted the Company permission to proceed with implementation of the PCBs management and remediation activities described in its Work Plan to address sites in Colorado. EPA Region VII has not yet formally responded. The Company currently estimates the total cost of remediation to be approximately $1.7 million, a substantial portion of which is recoverable under the Rockwell settlement. The unrecoverable amount will not have a material adverse impact on the Company's financial position or results of operations. The PCBs cleanup program is not expected to interrupt or diminish the Company's operational ability to gather or transport natural gas, and will occur over a period of years.
Certain used pipe reclaimed at the Company's Holdrege, Nebraska pipeyard was wrapped with asphalt-saturated asbestos felt, which was commonly removed in accordance with Company practices. The removed wrap contains friable asbestos fibers above the regulatory standard. The Nebraska Department of Environmental Control, the agency having jurisdiction over this matter, was notified and approved the Company's remediation plan. Remediation was effectively completed in 1994 and the total cost is not expected to exceed $700,000. The asbestos cleanup program did not interrupt or diminish the Company's operational ability to gather or transport natural gas.
In the spring of 1994, the Kansas Department of Health and Environment ("KDHE") notified a number of pipeline companies operating in Kansas, including K N, that residual elemental mercury might be present in the soils adjacent to certain natural gas metering facilities. In July 1994, the Company initiated a mercury sampling program on its systems in central and western portions of Kansas, pursuant to a five year assessment program which has been approved by the KDHE and will require that 20 percent (135) of the 675 sites be tested each year. The sampling for the first year has been completed; however, no determination regarding remediation has been reached at this time. The Company currently cannot estimate the extent of the remediation nor the costs, although the Company believes all or a portion of such costs will be recoverable from insurance carriers. On December 27, 1994, the Company received notice from the KDHE that no active remediation will be required until completion of the five-year assessment program. Such costs are not expected to have any material adverse impact on the Company's financial position or results of operations. The mercury cleanup program is not expected to interrupt or diminish the Company's operational ability to gather or transport natural gas.
In May 1994, the Company discovered that use of a lubricating oil containing PCBs has caused contamination in certain equipment, soils and liquids at the Company's Scott City, Kansas, helium extraction facility. A Site Assessment Report has been submitted to the EPA for its review, and no response has yet been received. The Company's investigation of this situation is ongoing, and a workplan is being developed for EPA review. The Company estimates the total cost for remediation to be approximately $600,000, which is not expected to have a material adverse impact on the Company's financial position or results of operations. The PCBs cleanup program is not expected to interrupt or diminish the Company's operational ability at the helium facility.
Effective April 1, 1992, the Company acquired substantially all of the assets and assumed substantially all of the liabilities of the Maple Gas Corporation ("Maple"). The assets consisted of 10 natural gas processing plants and approximately 1,100 miles of related gas gathering pipelines. The Maple assets contained certain environmental liabilities for which the Company obtained indemnifications from Maple and the Cabot Corporation ("Cabot"). The Company is unable to estimate its potential exposure, if any, for such liabilities at this time, but does not expect them to have any material adverse impact on the company's financial position or results of operation.
In November 1989, the Company acquired gathering and transmission assets from certain subsidiaries of Cabot. These assets contained certain environmental liabilities for which the Company obtained indemnities from Cabot pursuant to an Omnibus Acquisition Agreement. Issues have arisen concerning Cabot's indemnification obligations; however, in conjunction with the merger, the Company and Cabot entered into a standstill agreement pertaining to these and other matters. The Company believes it will be able to reach agreement with Cabot, and is unable to estimate its potential exposure for such liabilities at this time, but does not expect them to have a material adverse impact on the Company's financial position or results of operations.
Grynberg v. K N,et al.
On October 9, 1992, Jack J. Grynberg filed suit in the United States District Court for the District of Colorado against the Company, Rocky Mountain Natural Gas Company and GASCO, Inc. (the "K N Entities") alleging that the K N Entities as well as K N Production Company and K N Gas Gathering, Inc., have violated Federal and state antitrust laws. In essence, Grynberg asserts that the companies have engaged in an illegal
exercise of monopoly power, have illegally denied him economically feasible access to essential facilities to transport and distribute gas produced from fewer than 20 wells located in northwest Colorado, and have illegally attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg also asserts certain causes of action relating to a gas purchase contract. No specific monetary damages have been claimed, although Grynberg has requested that any actual damages awarded be trebled. In addition, Grynberg has requested that the K N Entities be ordered to divest all interests in natural gas exploration, development and production properties, all interests in distribution and marketing operations, and all interests in natural gas storage facilities, separating these interests from the Company's natural gas gathering and transportation system in northwest Colorado. On August 13, 1993, the United States District Court, District of Colorado, stayed this proceeding pending exhaustion of appeals in a related state court action involving the same plaintiff. (Grynberg v. K N, et al., Civil Action No. 92-2000, United States District Court for the District of Colorado.)
Westerman, et al. v. K N Energy, Inc.,et al.
On December 8, 1994, K N and its wholly owned subsidiary K N Gas Supply Services, Inc. were sued by gas producers in northeastern Colorado in District Court, Dallas County, Texas, under claims arising from two gas purchase contracts covering gas purchases from wells in the Niobrara Field, Colorado. The producers assert take-or-pay claims for contract years 1993 and 1994 in the amount of $1,157,000 plus interest, as well as actual and punitive damages in the amount of $156,000,000 for breaches of contractual and fiduciary duties arising out of a January 1977 Farmout Agreement between the producers and K N.
On December 21, 1994, the lawsuit was removed from Texas state court to the United States District Court for the Northern District of Texas (Dallas). (Westerman, et al. v. K N Energy, Inc. and K N Gas Supply Services, Inc., Civil Action No.:3:94-CV-2773-X, United States District Court for the Northern District of Texas, Dallas Division.)
Take-or-Pay Matters
Certain of the companies acquired from Cabot when the Company acquired the Westar System were parties to a number of lawsuits or were subject to asserted claims by natural gas purchase contracts containing take-or-pay provisions, which require the purchaser either to take a minimum amount of gas or to pay for such minimum quantities. All of these lawsuits and most claims have been resolved under terms which the Company considers favorable. Most gas suppliers of the Company have entered into excess gas purchase contracts with one of the Company's gas marketing subsidiaries. These excess gas purchases contracts are generally credited against take-or-pay gas volumes, which minimizes take-or-pay exposure.
The Basket Agreement between the Company and Cabot provides for an equal sharing of up to $40 million (any excess will be borne solely by Cabot) between the Company and Cabot of certain gas contract take-or-pay liabilities of the companies acquired from Cabot for periods prior to the closing date of the acquisition from Cabot and for certain other potential gas contract claims. (See "Items 1 and 2: Business and Properties"). The Company's maximum exposure under this arrangement is $20 million. The Company's estimated liability under the Basket Agreement is approximately $6.0 million, which was recorded in connection with the acquisition of the natural gas pipeline business from Cabot, and as such will not have a material adverse effect on the Company's financial position or results of operation. As of December 31, 1994, the Company had made net payments of approximately $12.4 million.
The Company is also involved in various disputes and litigation arising in the normal course of business including take-or-pay exposure not covered by the matters discussed above, including the Westerman litigation described in this Item 3. The Company believes that it has adequate defenses or insurance coverage relating to such litigation and that the outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on the Company's financial position or results of operations.
The Company believes it has meritorious defenses to all lawsuits and legal proceedings in which it is a defendant and will vigorously defend against them. Based on its evaluation of the above matters, and after consideration of reserves established, the Company believes that the resolution of such matters will not have a material adverse effect on the Company's financial position or results of operations.
ITEM 4:
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
EXECUTIVE OFFICERS OF THE REGISTRANT
(A) Identification and Business Experience of Executive Officers
These officers generally serve until March of each year.
(B) Involvement in Certain Legal Proceedings
None.
PART II
ITEM 5:
ITEM 5: MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed for trading on the New York Stock Exchange under the symbol KNE. Dividends paid and the price range of the Company's common stock by quarters for the last two years, are provided below.
* Pre-merger dividend rate reflects the effect of pooling of interests accounting. AOG did not pay a dividend on common stock.
ITEM 6:
ITEM 6: SELECTED FINANCIAL DATA
FIVE-YEAR REVIEW
Selected Financial Data (In Thousands Except Per Share Amounts)
ITEM 7:
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CONSOLIDATED FINANCIAL RESULTS OF OPERATIONS
In the third quarter of 1994, the Company expensed $25.9 million of non-recurring costs related to the merger of AOG into K N and to the restructuring of the Company's retail natural gas services segment. These costs, primarily professional fees, severance-related expenses and the write-off of certain information systems costs, reduced 1994 net income by $19.3 million, or $0.69 per common share.
Excluding the effect of the merger and restructuring costs, net income was $34.7 million, $30.9 million and $36.3 million for 1994, 1993 and 1992, respectively. After payment of preferred dividends, the respective earnings per common share were $1.21, $1.09 and $1.34.
The improvement in 1994 earnings over 1993 was attributable to rate increases in both retail and interstate system jurisdictions, increased deliveries to irrigation customers and expense reductions resulting from the merger. Net income in 1993 was reduced by a $4.5 million (pre-tax) write-down of an investment in a well servicing company. Operating results were adversely affected by mild fourth quarter 1994 weather (impacting systems throughput as well as margins on nonregulated gas sales) and lower 1994 prices for natural gas liquids ("NGLs").
The decline in 1993 earnings reflected the impact of unfavorable summer weather on gas sales to irrigation customers, a significant decline in prices for NGLs during the second half of 1993, and the investment write-down referred to previously. Incremental earnings from 1993 and 1992 acquisitions of natural gas gathering and processing facilities, favorable resolution of retail rate cases and insurance settlements related to environmental issues partially offset the unfavorable 1993 factors.
RESULTS OF OPERATIONS
Operating results by business segment, excluding the non-recurring merger and restructuring costs, and consolidated other income and (deductions) and income taxes are discussed below. The Company's retail natural gas services segment, which includes its Colorado and Wyoming intrastate operations, and the interstate transportation and storage services segment have been combined to provide meaningful comparisons. The interstate segment became a separate business unit effective with the implementation of Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") on October 1, 1993. Segment operating revenues, gas purchases, operations and maintenance expenses, and volumetric data cited below are before intersegment eliminations (dollars in millions).
The decline in 1994 and 1993 gas sales revenues and volumes and gas purchases primarily reflects the implementation of Order 636, which became effective October 1, 1993. As a result, merchant services to wholesale customers were converted to transportation and storage services. Gas sales volumes to wholesale customers totaled 16.4 trillion Btus and 26.8 trillion Btus in 1993 and 1992, respectively. In addition to Order 636, effective January 1, 1994, the interstate segment's principal gas processing plant and substantially all of its gathering facilities were transferred to a nonjurisdictional subsidiary included in the gathering, processing and marketing services business segment. Accordingly, the above table reflects results of K N's rate-regulated businesses post-Order 636. The increase in 1993 transportation and storage revenues and volumes, compared to 1992, largely resulted from the Order 636-related change in service to wholesale customers. The full year's impact of Order 636 on 1994 transportation and storage revenues was offset by the effect of the transfer of gathering facilities. The decline in this segment's 1994 NGLs and other revenues, NGLs volumes, operations and maintenance expenses, and depreciation, depletion and amortization was primarily due to the transfer of properties. Operations and maintenance expenses were favorably impacted in the second half of 1994 due to merger savings.
Rate activity and weather have significantly influenced the operating results of this business segment. Favorable resolution of retail and interstate system rate cases generated additional annual revenues of $10.7 million during 1994. Retail rate activity in 1993 resulted in additional annual revenues of $4.9 million. The level of sales and transportation volumes delivered to irrigation customers depends on precipitation levels during the summer months. These volumes totaled 10.1 trillion Btus, 4.9 trillion Btus and 8.1 trillion Btus in 1994, 1993 and 1992, respectively. Retail sales volumes related to space heating were approximately the same in 1994 and 1992; however, 1993 sales volumes were approximately 4 trillion Btus higher, or 11 percent higher, than 1994 or 1992 due to colder weather.
Operating results of this business segment, which include the merged AOG assets, were significantly impacted in 1994 by the transfer to this segment of certain properties from the interstate segment, as explained previously. In addition, 1994 revenues, expenses and operating income reflect the full year contribution of gathering and processing asset acquisitions in 1993 and 1992. In April 1992, the Company acquired 10 processing plants and related gathering systems. In October 1992, the Company assumed operations of the Douglas gathering and processing system. The Wattenberg gathering and transmission system was acquired in April 1993, and the Wind River joint-venture gathering facilities were acquired in June 1993.
Operating results in 1994 and 1993 were adversely impacted by declining NGLs prices and lower margins on 1994 gas sales due, primarily, to unfavorable weather. The average NGLs price per gallon for 1994 was approximately $0.04 below 1993 prices; average prices for 1993 were $0.03 per gallon lower than 1992. Earnings from properties transferred from the interstate segment and expense reductions resulting from the merger more than offset the impact on segment operating income of lower 1994 NGLs prices and gas sales margins. The positive contributions of acquisitions (approximately $1.8 million of incremental operating income) to 1993 pre-tax earnings partially offset the effects of lower NGLs prices.
Sustained increases in revenues, expenses and production have resulted from acquisitions of gas and oil reserves and production in February 1994 and July 1992. In October 1994, the Company sold a 50 percent interest in the gas reserves and production acquired earlier in 1994. At December 31, 1994, net proved reserves were approximately 50 Bcf equivalent of natural gas.
Increases in interest expense resulted from the issuance of long-term debt to fund capital expenditures and acquisitions. The impact of higher amounts of long-term borrowings has been partially offset by the refunding of $65 million of higher coupon debt in 1993 and 1992. The Company realized a $1.5 million gain from the sale of a gathering system in the 1994 second quarter, which is included in "Minority Interests and Other, Net".
The 1994 effective tax rate reflects the non-deductibility of certain merger costs. Additionally, the one percent increase in the Federal tax rate, due to enactment of the Revenue Reconciliation Act of 1993, impacted the effective tax rate for both 1994 and 1993. Refer to Note 8 of Notes to Consolidated Financial Statements for a reconciliation of statutory rates to effective rates.
LIQUIDITY AND CAPITAL RESOURCES
The primary sources of cash during 1994 were generated from operations, the issuance of long-term debt, the sale of contract demand receivables and short-term borrowings. Principal non-operating cash outflows included capital expenditures and acquisitions, redemptions of long-term debt and preferred stock, and payments of interest and dividends.
CASH FLOWS FROM OPERATING ACTIVITIES
Excluding the $41 million of proceeds from the sale of contract demand receivables and cash expenditures of $18.1 million related to the merger and restructuring, 1994 net cash flows from operations were $68.3 million, compared with $67.9 million and $51.0 million for 1993 and 1992, respectively. Net operating cash flows for 1994 and 1992 were adversely impacted by higher income tax payments, gas prepayments and litigation and environmental settlements.
CAPITAL EXPENDITURES AND COMMITMENTS
Excluding acquisitions, 1994 capital expenditures totaled $70.6 million compared with expenditures of $100.8 million in 1993 and $74.8 million in 1992. The higher level of spending in 1993 was due to implementation of Order 636 (measurement facilities and systems) and construction of new corporate office facilities.
The 1995 capital expenditures budget totals $73.9 million, excluding acquisitions. On February 16, 1995, the Company acquired natural gas transmission pipeline and storage assets in Texas for approximately $80
million. The Company is negotiating the termination of certain pre-Order 636 gas purchase contracts with producers. This could result in significant expenditures in 1995.
The Company does not believe it has a material exposure related to take-or-pay matters. Generally, all amounts paid by the Company for take-or-pay are either fully recoupable under the terms of the gas purchase contracts, or are recoverable from offsetting gas purchase obligations under certain contractual arrangements. Take-or-pay obligations, including payments of above-market prices incurred with respect to the Company's retail distribution operations, are recoverable through purchased gas adjustment clauses in existing state or local regulations. At December 31, 1994, the cumulative amount of take-or-pay payments was $12.5 million.
CAPITAL RESOURCES
Short-term borrowings were $60.0 million and $47.0 million at year-end 1994 and 1993, respectively. The Company has credit agreements with 10 banks to either borrow or use as commercial paper support up to $225 million. Additionally, $125 million of debt securities are issuable under K N's 1993 shelf registration statement filed with the Securities and Exchange Commission. At December 31, 1994, the Company's long-term debt to capitalization ratio was 45 percent and the weighted-average cost of its long-term debt was 8.9 percent.
Following the March 1994 announcement of the K N-AOG merger, Standard and Poor's and Fitch Investor Service placed the Company under credit watch. Subsequently, the two agencies affirmed their previous ratings and Moody's Investors Services upgraded the rating of the Company's debt securities from A3 to A2.
The Company expects that 1995 cash requirements for debt service, preferred stock redemptions, dividends and capital expenditures will be provided by internal cash flows, short-term borrowings and the issuance of common stock for dividend reinvestment and employee benefit plans. The issuance of long-term debt, if any, will be dependent on market conditions. The February 1995 acquisition of natural gas transmission pipeline and storage assets will be funded by short-term borrowings and an operating lease.
REGULATION
Beginning in 1993 and continuing into 1994, the Company has restructured to take advantage of the opportunities and comply with the requirements of Order 636. The competitive opportunities accompanying the unbundling of natural gas services under Order 636 are challenging the Company to become a more customer-responsive provider of natural gas services. In response to this challenge, the Company is repositioning its workforce to be a more dynamic, agile and accessible provider of services and products demanded by its customers.
In all of its regulatory jurisdictions, rates are currently determined on cost-based regulation. At the present time, the Company does not expect a significant change in the manner in which rates are set by regulators. Additionally, the impact of competition has not yet fully impacted the Company's businesses, and to date has generally resulted in conversion of services from the "bundled" merchant and transportation function to transportation services only. The gas cost component of the bundled service rate recovers only actual costs incurred.
RISK MANAGEMENT
To minimize the risk of price changes in the natural gas and NGLs markets and interest rate fluctuations, the Company uses certain financial instruments for hedging purposes only. These instruments include energy futures traded on the New York Mercantile Exchange and over-the-counter markets, including fixed price and basis swaps, options, and interest rate swaps and caps.
During 1994, K N's Board of Directors approved formal energy price risk management policies and procedures. These policies and procedures include the formation of a price risk management committee, and guidelines for authorizing the types of hedging instruments, contract limits, and approval levels. The policy also states that at no time will the Company enter into speculative trading.
OUTLOOK
MERGER
The merged Company operates along an axis of major gas supply basins stretching from the northern Rocky Mountain region through the Mid-Continent to south Texas. Access to six major, geographically diverse producing basins enables the Company to balance complementary peaking periods with a greater choice of supply alternatives. The Company's gas supply group is continually searching for opportunities to achieve lower gas supply costs, while seeking to take advantage of the Company's broader gas supply access. Additional future opportunities to provide broader gas supply access for the Company will come from its participation in the proposed TransColorado Pipeline Project and from the February 1995 acquisition of pipeline and storage assets. These assets are connected to currently existing assets in West Texas and provide expanded opportunities with new and existing customers.
The ongoing marketing efforts of the merged Company are expected to yield efficiencies in purchasing gas supplies, provide leverage in contracting for those supplies and improve utilization of the systems by increasing sales to customers in non-historical market areas. In addition, the Company plans to increase its emphasis on converting current spot market sales to longer-term premium markets and in developing incremental marketing, transportation, storage and other service opportunities, while retaining the current retail and on-system markets as a base load.
At year-end 1994, the Company had over 46 Bcf of working gas storage capacity in conventional and salt cavern storage fields near major pipeline interconnects in the Rocky Mountain, Mid-Continent and Permian Basin areas. An additional six Bcf of working gas storage capacity, strategically located near Houston, Texas, was acquired in the Company's February 1995 transaction. The combined deliverability from these storage fields is over 750 MMcf of gas per day. The key locations of these storage fields means that the merged Company will be able to provide a broader range of services to its customers, including physical gas movement between market centers, load balancing services and delivery reliability supported by storage.
The Company expects to realize greater leverage in the sales of NGLs in 1995 as a result of the merger and incremental throughput. The consolidated sales volumes of NGLs in 1994 were 385 million gallons.
Incremental throughput volumes on the Company's Texas systems provide additional gas supply volumes that are transported through downstream pipelines and may be purchased and sold to incremental markets.
Continued cost savings will result from consolidation of administrative and operational staff, space requirements and information systems and from eliminating certain outside legal, accounting and other services. Reduction in personnel in 1994 totaled 115 persons at an annual savings of $7.0 million. Cash costs related to the merger and restructuring were $18.1 million in 1994 and are expected to be $5.3 million in 1995.
At December 31, 1994, the Company had equity capital of approximately $401 million and a long-term debt to total capitalization ratio of approximately 45 percent, which provides significant financial flexibility to pursue continued growth opportunities. The performance of the combined Company is expected to increase cash flow from operations and provide for positive earnings momentum.
LITIGATION/ENVIRONMENTAL
The Company has been sued in Dallas County, Texas, by Westerman, et al., for breach of contractual and fiduciary duties, including take-or-pay claims, covering properties in Colorado. The Company denies the allegations. In a separate lawsuit filed in federal court in Colorado, the Company has sued the plaintiffs and others asserting that contractual provisions require payment of refunds for gas purchased at above-market prices and, prospectively, for a reduction in gas prices paid under the contracts to market levels. The actual damages claimed by Westerman, et al., total $1.5 million and the punitive damages claimed total $156 million. Although these substantial claims have been made, the Company believes it has a meritorious position in this matter, and does not expect this lawsuit to have a material adverse impact on the Company's results of operations or financial position.
As discussed in Note 6 of Notes to Consolidated Financial Statements, the Company has reported certain environmental liabilities assumed as a result of the July 13, 1994 merger. Included in these liabilities were certain environmental matters related to the Company's acquisition of various assets from the Cabot Corporation in 1989. While the Cabot Corporation agreed to indemnify the Company against certain of these liabilities, the Company may be responsible for certain costs associated with remediation in the future. The Company is presently unable to determine what, if any, dollar amount is associated with this contingency.
The Company's overall potential environmental cost exposure for 1995 is estimated to be approximately $1 million. A substantial part of the Company's 1995 environmental costs are either recoverable through insurance and indemnification provisions, or have been expensed as part of ongoing business.
Refer to Note 6 of Notes to Consolidated Financial Statements for additional information on the Company's pending litigation and environmental matters. Company management believes it has established adequate reserves such that resolution of pending litigation and environmental matters will not have a material adverse impact on the Company's financial position or results of operations.
SIGNIFICANT OPERATING VARIABLES
Natural gas prices have continued on a steady downward trend during 1994 and early 1995. While the Company cannot know actual future prices of natural gas, continued unusually warm winter weather conditions nationwide could cause the downward trend to continue. The Company, however, is partially insulated from the severe impact of such a continuing downturn because of its diverse array of services offered, which span the natural gas value stream from wellhead to burnertip. Although the Company's earnings and success are not directly tied to natural gas price exposure, if the downturn continues over time and affects the industry to the degree the Company experiences significantly reduced gas flows throughout its pipeline systems, the Company's earnings could be negatively impacted.
As part of the processing business, NGLs are extracted from the raw natural gas stream and sold. The average prices for NGLs declined significantly during the second half of 1993 and showed some additional decline in 1994. Over the past six months, prices have been relatively stable. The Company expects a low likelihood of further material price declines in this market arena in the near future. For purposes of comparison, a one cent change in average NGLs prices impacts the Company's operating income by approximately $2.0 million.
ITEM 8:
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To K N Energy, Inc.:
We have audited the accompanying consolidated balance sheets of K N Energy, Inc. (a Kansas corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company'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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of K N Energy, Inc. and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As explained in Note 12 of Notes to Consolidated Financial Statements, the Company changed its method of accounting for postemployment benefits effective January 1, 1994, and its method of accounting for postretirement benefits other than pensions effective January 1, 1993.
/s/ Arthur Andersen LLP
Denver, Colorado February 16, 1995.
CONSOLIDATED STATEMENTS OF INCOME K N ENERGY, INC. AND SUBSIDIARIES
The accompanying notes are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS K N ENERGY, INC. AND SUBSIDIARIES
The accompanying notes are an integral part of these balance sheets.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY K N ENERGY, INC. AND SUBSIDIARIES YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS K N ENERGY, INC. AND SUBSIDIARIES
The accompanying notes are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Principles of Consolidation
The consolidated financial statements include the accounts of K N Energy, Inc. ("K N") and its majority-owned subsidiaries (the "Company").
Investments in jointly-owned gas pipeline systems representing 20 to 50 percent ownership of such systems are accounted for under the equity method.
All material intercompany items and transactions have been eliminated.
(B) Accounting for Regulatory Activities
The Company's regulated public utilities are accounted for in accordance with the provisions of Statement of Financial Accounting Standards No. 71, which prescribes the circumstances in which the application of generally accepted accounting principles is effected by the economic effect of regulation.
Regulatory assets and liabilities represent probable future revenue or expense to the Company associated with certain charges and credits which will be recovered from or refunded to customers through the ratemaking process. The following regulatory assets and liabilities were reflected in the accompanying financial statements (in thousands):
As of December 31, 1994, $18.5 million of the Company's regulated assets and $7.7 million of the Company's regulated liabilities were being recovered from or refunded to customers through rates over periods ranging from 1 to 19 years.
(C) Earnings Per Share
Primary earnings per share are computed based on the monthly weighted average number of common shares outstanding during the periods and the assumed exercise of dilutive common stock equivalents (stock options and warrants) using the treasury stock method.
On August 10, 1993, K N's Board of Directors declared a three-for-two common stock split. The number of common shares used in computing earnings per share and per share amounts in the accompanying financial statements have been restated to reflect the stock split and the tax-free exchange of 0.47 of a share of K N common stock for each outstanding share of American Oil and Gas Corporation ("AOG") common stock (see Note 2). The number of common shares used in computing earnings per share was 28,044,000 in 1994, 27,424,000 in 1993 and 24,828,000 in 1992.
(D) Gas in Underground Storage
K N's regulated interstate retail distribution business and Northern Gas Company account for gas in underground storage using the last-in, first-out ("LIFO") method. K N Gas Supply Services, Inc., K N Gas Marketing, Inc. and Anthem Energy Company, L.P., nonjurisdictional subsidiaries, value gas in underground storage at average cost. Rocky Mountain Natural Gas Company and Westar Transmission Company use the first-in, first-out ("FIFO") method.
The Company also maintains gas in its underground storage facilities on behalf of certain third parties. The Company receives a fee for its storage services but does not reflect the value of third party gas in the accompanying financial statements.
(E) Prepaid Gas
Prepaid gas represents payments made in lieu of taking delivery of (and purchasing) natural gas under the take-or-pay provisions of the Company's gas purchase contracts, net of any subsequent recoupments in kind from producers. Funds paid by the Company for take-or-pay are fully recoupable from future production, and are recorded as an asset (Prepaid Gas). When recoupment is made in kind in a subsequent contract year, natural gas purchase expense is recorded and the asset is reduced.
(F) Property, Plant and Equipment
Property, plant and equipment is stated at cost, which for constructed plant includes indirect costs such as payroll taxes, fringe benefits, and administrative and general costs. Expenditures which increase capacities or extend useful lives are capitalized. Routine maintenance, repairs and renewal costs are expensed as incurred.
The cost of depreciable utility property, plant and equipment retired, plus the cost of removal less salvage, is deducted from accumulated depreciation with no effect on current period earnings. Gains or losses are recognized upon retirement of nonutility property, plant and equipment.
(G) Exploration and Development Costs
K N's gas and oil subsidiaries follow the "successful efforts" method of accounting. Under this method, acquisition costs, successful exploration costs and development costs are capitalized and unsuccessful exploration costs, lease rentals and evaluation costs are expensed.
(H) Depreciation, Depletion and Amortization
Depreciation is computed based on the straight-line method over the estimated useful life for most gas service property, plant and equipment. The unit-of-production method is used for computing depreciation, depletion and amortization for gas and oil properties.
(I) Deferred Revenues
In conjunction with the Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") restructuring activities, the Company negotiated new gas sales agreements with its former wholesale customers. As a result, the Company is now responsible for performance under, or to otherwise dispose of, certain pre-Order 636 gas purchase contracts. The gas sales agreements provide for such customers to pay fixed demand charges over the agreement term, and to purchase gas from a subsidiary of the Company at negotiated commodity rates. The demand portion of the gas sales agreements was recorded as deferred revenues in 1993. Commodity charges are recorded as deferred revenues as gas is delivered under these agreements. Gas purchase, gathering, transportation, and contract administration costs are recorded as a reduction to the related revenues. In addition, losses on sales of excess gas supplies to a marketing affiliate at market clearing rates are recorded in deferred revenues. Subsequent margins earned on these sales by the marketing affiliate are recognized as income when the gas is delivered. Company management believes that the revenues being collected and deferred under these agreements will be sufficient to offset future costs associated with the gas purchase contracts.
In January 1994, contract demand receivables with a face amount of $41 million were sold to a financial institution. No gain or loss was recorded on the sale.
(J) Reclassification of Prior Year Amounts
Certain prior year amounts have been reclassified to conform with the 1994 presentation.
(K) Cash Flow Information
The Company considers all highly-liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Changes in Other Working Capital Items Summary, Supplemental Disclosures of Cash Flow Information and Supplemental Schedule of Noncash Investing and Financing Activities are as follows (in thousands):
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
On December 31, 1992, AOG acquired a partner's 25 percent interest in Red River Pipeline partnership ("Red River") by assuming that partner's share of Red River's liabilities. In January 1993, AOG acquired an additional 25 percent interest in Red River for cash and the assumption of liabilities. In April 1992, AOG acquired the assets of The Maple Gas Corporation ("Maple") for $5.5 million cash, a $5.5 million note payable and the assumption of certain of Maple's liabilities. In 1992, K N purchased all of the capital stock of two corporations, each of which owned gas distribution systems, for $5.2 million. The liabilities assumed in conjunction with these acquisitions are as follows (in thousands):
2. MERGER
On July 13, 1994, pursuant to the Agreement of Merger dated March 24, 1994, AOG was merged into the Company. As a result of the merger, each outstanding share of common stock of AOG was converted into 0.47 of a share of common stock of K N and the right to receive in cash the value of any fractional share of K N. In connection with the merger, all the outstanding shares of AOG common stock were converted into approximately 12.2 million shares of K N stock, and the authorized number of shares of K N common stock was increased to 50 million shares. On July 13, 1994, the stockholders of K N approved the issuance of stock in connection with the merger, as well as certain other matters, and the shareholders of AOG approved the merger.
The merger was accounted for as a pooling of interests and, accordingly, the historical consolidated financial statements for periods prior to consummation of the merger have been restated as though the companies had been combined for all periods reported herein.
The following table provides a reconciliation of revenues and earnings reported by K N to the combined amounts presented (in thousands):
* Represents revenues and earnings of AOG prior to the July 13, 1994 merger. ** Includes merger and restructuring costs totaling $19.3 million after taxes.
3. MERGER AND RESTRUCTURING COSTS
The Company recorded merger and restructuring costs totaling $25.9 million in the third quarter of 1994. Total expected cash expenditures relating to these charges are $23.4 million, of which $5.3 million had not yet been paid as of December 31, 1994.
Merger expenses include $12.4 million in investment bankers' and other professional fees, $7.7 million for severance and employee benefit costs for approximately 230 employees who have been or will be terminated through consolidation of administrative and operational staff, and $4.6 million in costs to eliminate duplicative space requirements and equipment, and to write-off the cost of information systems not required subsequent to the merger.
Costs related to the formal restructuring plan of the Company's retail distribution operations total $1.2 million, representing severance and employee benefit costs for terminating approximately 90 retail distribution employees as a result of the restructuring and centralization of customer service functions. The restructuring is expected to be completed in the third quarter of 1995.
4. ACQUISITIONS
(A) Transmission and Storage Systems
On February 16, 1995, K N's gas transmission affiliate, AOG Gas Transmission Company, L.P., acquired natural gas transmission pipeline and storage assets in Texas.
The assets include two West Texas pipeline systems, comprised of 347 miles of pipeline and related facilities, which are currently connected to AOG's core pipeline system. In addition, surface facilities, lease rights and approximately 10.8 Bcf of natural gas in storage in a leased, Gulf Coast storage field will be acquired. AOG
also acquired the remaining 50 percent interest it did not previously own in a 90-mile joint venture pipeline near Midland, Texas.
The total price was $80.1 million, subject to closing adjustments. K N utilized an operating lease and short-term debt financing arrangements to fund the acquisition.
(B) Natural Gas Processing Business
Effective April 1, 1992, AOG acquired substantially all of the assets and assumed substantially all of the liabilities of Maple. The assets consisted of 10 natural gas processing plants and approximately 1,056 miles of related gas gathering pipelines. The purchase price was approximately $86 million, consisting of $5.5 million cash, a $5.5 million note payable and the assumption of substantially all of Maple's liabilities. The acquisition was accounted for as a purchase.
The results of operations of the acquired business are included in the accompanying financial statements from the date of the acquisition.
(C) Gathering and Transmission System
On April 1, 1993, the Company completed the $48 million acquisition of the Wattenberg natural gas gathering and transmission system. The system has both regulated and nonregulated components. The regulated transmission segment, approximately $18 million of the acquisition, was financed with corporate funds, and the balance of the system was financed through an operating lease. The system gathers and transports gas from approximately 1,800 receipt points in northeastern Colorado.
(D) Gas and Oil Reserve Acquisition
On February 1, 1994, the Company's gas and oil development subsidiaries, K N Production Company and GASCO, Inc., acquired gas reserves and production properties located near existing K N operations in western Colorado and in the Moxa Arch region of southwestern Wyoming for a total purchase price of approximately $30 million. The acquired properties have total net reserves of approximately 50 Bcf equivalent of natural gas. In October 1994, the Company sold a 50 percent undivided interest in substantially all the acquired properties to a third party with whom they will jointly develop the properties.
5. REGULATORY MATTERS
(A) Restructuring and Reorganization
On April 8, 1992, FERC issued Order 636 which requires a fundamental restructuring of interstate natural gas pipelines. K N implemented Order 636 restructured services on October 1, 1993. As a part of its action on K N's restructuring proposal, FERC approved implementation of K N's gas supply realignment ("GSR") crediting mechanism.
K N requested FERC approval, as a result of Order 636, to transfer all of its interstate transmission and storage facilities to K N Interstate Gas Transmission Co. ("KNI"), a wholly-owned jurisdictional subsidiary of K N, and substantially all of its gathering and processing facilities to K N Gas Gathering, Inc. ("KNGG"), a nonjurisdictional wholly-owned subsidiary of K N. FERC approved the transfer of K N's interstate gas
transmission and storage facilities to KNI effective October 1, 1993. FERC authorized the transfer of certain gathering and processing facilities from KNI to KNGG effective January 1, 1994. KNI's only remaining gathering system was transferred to KNGG in early 1995. AOG's assets and facilities were not a part of this reorganization.
Order 636 required pipelines to unbundle sales and transportation services. KNI has complied with FERC's directive to mitigate its GSR costs caused by this restructuring. KNI's GSR process allows for the assignment of its above-market contracts. Under KNI's tariff, every shipper has a right to take assignment of these above-market contracts. Shippers may either take assignment of these above-market contracts or enter into a negotiated exit fee. This eliminated the need to make any GSR cost recovery filing with FERC.
In January 1995, as a result of a settlement reached with its customers, the Company filed an application with FERC to transfer certain storage assets held by KNI to a newly created nonjurisdictional subsidiary, K N Natural Gas, Inc. If this transfer is approved, KNI will own only the Huntsman, Nebraska storage facilities.
(B) Rate Matters
On December 30, 1993, KNI made a rate filing with FERC requesting a $12.0 million annual increase in revenues. The new rates became effective July 1, 1994, subject to refund. KNI submitted a Stipulation and Agreement ("S&A") to FERC in November 1994. On January 20, 1995, FERC approved the S&A, which provides for an $8.7 million annual increase in revenues. As part of the settlement, test year depreciation expense was reduced $0.7 million as a result of lower depreciation rates on FERC jurisdictional facilities. Revenues collected above the settlement rates will be refunded to customers in early 1995.
K N's retail natural gas services business segment received rate increases from a number of jurisdictions during 1994, 1993 and 1992, as summarized below:
*Rocky Mountain Natural Gas Division of K N Energy, Inc.
Additionally, in connection with a 1990 Nebraska rate case, $1.6 million of previously deferred revenues were recorded as revenue in 1993.
6. LEGAL MATTERS
The Company was named as one of four potentially responsible parties ("PRPs") at a U.S. Environmental Protection Agency ("EPA") Superfund site known as the Mystery Bridge Road/U.S. Highway 20 site located near Casper, Wyoming (the "Brookhurst Subdivision"). The EPA's remedy consists of two parts, "Operating Unit One," which addresses the groundwater cleanup, and "Operating Unit Two," which addresses cleanup procedures for the soil and free-phase petroleum product. A Consent Decree between the Company, the EPA and another
PRP was entered on October 2, 1991, in the Wyoming Federal District Court. Groundwater cleanup under Operating Unit One and Two have been proceeding since 1990 and 1992, respectively, and is expected to continue through 1996 at a total remaining estimated cost not to exceed $150,000.
An environmental audit performed by the Company revealed that a grease known as Rockwell 860 had been used as a valve sealant at several of the Company's locations in Nebraska and Colorado. Rockwell 860 is a solid clay-like material which does not easily spill into the environment, but contains approximately 10 percent polychlorinated biphenyls ("PCBs"). The PCBs are contained within the pipeline and valves at the subject locations. PCBs are regulated under the Toxic Substances Control Act. On March 31, 1993, the Company filed suit against Rockwell International Corporation, manufacturer of the valve sealant, and two other related defendants, alleging that the defendants were responsible for the Company's environmental expenses and commercial losses resulting from any EPA or state required PCBs cleanup or mitigation. The Company settled with Rockwell, et al. in March 1994 which resolved all disputes between the parties.
During February 1994, the Company submitted its Phase I Report and PCBs Work Plan to EPA Region VII (covering Nebraska) and EPA Region VIII (covering Colorado). During March 1994, EPA Region VIII accepted both the Phase I Report and the PCBs Work Plan as administratively complete. EPA Region VIII also granted the Company permission to proceed with implementation of the PCBs management and remediation activities described in its Work Plan to address sites in Colorado. EPA Region VII has not yet formally responded. The Company currently estimates the total cost of remediation to be approximately $1.7 million, a substantial portion of which is recoverable under the Rockwell settlement. The unrecoverable amount will not have a material adverse impact on the Company's financial position or results of operations. The PCBs cleanup program is not expected to interrupt or diminish the Company's operational ability to gather or transport natural gas, and will occur over a period of years.
Certain used pipe reclaimed at the Company's Holdrege, Nebraska, pipeyard was wrapped with asphalt-saturated asbestos felt, which was commonly removed in accordance with Company practices. The removed wrap contains friable asbestos fibers above the regulatory standard. The Nebraska Department of Environmental Control, the agency having jurisdiction over this matter, was notified and approved the Company's remediation plan. Remediation was effectively completed in 1994 and the total cost is not expected to exceed $700,000. The asbestos cleanup program did not interrupt or diminish the Company's operational ability to gather or transport natural gas.
In the spring of 1994, the Kansas Department of Health and Environment ("KDHE") notified a number of pipeline companies operating in Kansas, including K N, that residual elemental mercury might be present in the soils adjacent to certain natural gas metering facilities. In July 1994, the Company initiated a mercury sampling program on its systems in central and western portions of Kansas, pursuant to a five-year assessment program which has been approved by the KDHE and will require that 20 percent (135) of the 675 sites be tested each year. The sampling for the first year has been completed; however, no determination regarding remediation has been reached at this time. The Company currently cannot estimate the extent of the remediation nor the costs, although the Company believes all or a portion of such costs will be recoverable from insurance carriers. On December 27, 1994, the Company received notice from the KDHE that no active remediation will be required until completion of the five-year assessment program. Such costs are not expected to have any material adverse impact on the Company's financial position or results of operations. The mercury cleanup program is not expected to interrupt or diminish the Company's operational ability to gather or transport natural gas.
In May 1994, the Company discovered that use of a lubricating oil containing PCBs has caused contamination in certain equipment, soils and liquids at the Company's Scott City, Kansas, helium extraction facility. A Site Assessment Report has been submitted to the EPA for its review, and no response has yet been received. The Company's investigation of this situation is ongoing, and a workplan is being developed for EPA review. The Company estimates the total cost for remediation to be approximately $600,000, which is not expected to have a material adverse impact on the Company's financial position or results of operations. The PCBs cleanup program is not expected to interrupt or diminish the Company's operational ability at the helium facility.
Effective April 1, 1992, the Company acquired substantially all of the assets and assumed substantially all of the liabilities of Maple. The assets consisted of 10 natural gas processing plants and approximately 1,056 miles of related gas gathering pipelines. The Maple assets contained certain environmental liabilities for which the Company obtained indemnifications from Maple and Cabot Corporation ("Cabot"). The Company is unable to estimate its potential exposure for such liabilities at this time, but does not expect them to have any material adverse impact on the Company's financial position or results of operations.
In November 1989, the Company acquired gathering and transmission assets from certain subsidiaries of Cabot. These assets contained certain environmental liabilities for which the Company obtained indemnities from Cabot pursuant to an Omnibus Acquisition Agreement. Issues have arisen concerning Cabot's indemnification obligations; however, in conjunction with the merger, the Company and Cabot entered into a standstill agreement pertaining to these and other matters. The Company believes it will be able to reach agreement with Cabot, and is unable to estimate its potential exposure for such liabilities at this time, but does not expect them to have a material adverse impact on the Company's financial position or results of operations.
On October 9, 1992, Jack J. Grynberg filed suit in the United States District Court for the District of Colorado against the Company, Rocky Mountain Natural Gas Company and GASCO, Inc. (the "K N Entities") alleging that the K N Entities as well as K N Production Company and K N Gas Gathering, Inc., have violated federal and state antitrust laws. In essence, Grynberg asserts that the companies have engaged in an illegal exercise of monopoly power, have illegally denied him economically feasible access to essential facilities to transport and distribute gas produced from fewer than 20 wells located in northwest Colorado, and illegally have attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg also asserts certain causes of action relating to a gas purchase contract. No specific monetary damages have been claimed, although Grynberg has requested that any actual damages awarded be trebled. In addition, Grynberg has requested that the K N Entities be ordered to divest all interests in natural gas exploration, development and production properties, all interests in distribution and marketing operations, and all interests in natural gas storage facilities, separating these interests from the Company's natural gas gathering and transportation system in northwest Colorado. On August 13, 1993, the United States District Court, District of Colorado, stayed this proceeding pending exhaustion of appeals in a related state court action involving the same plaintiff.
On December 8, 1994, K N and its wholly-owned subsidiary K N Gas Supply Services, Inc. ("KNGSS") were sued by gas producers in northeastern Colorado in District Court, Dallas County, Texas under claims arising from two gas purchase contracts covering gas purchases from wells in the Niobrara Field, Colorado. The producers assert actual take-or-pay claims for contract years 1993 and 1994 in the amount of $1,157,000 plus interest, as well as punitive damages in the amount of $156,000,000 for alleged breaches of contractual and fiduciary duties arising out of a January 1977 Farmout Agreement between the producers and K N. On
December 21, 1994, the lawsuit was removed from Texas state court to the United States District Court for the Northern District of Texas (Dallas). On January 12, 1995, K N and KNGSS filed a motion to dismiss for lack of personal jurisdiction or, if jurisdiction is found to exist, a motion to transfer the cause of action to federal court in Colorado. That motion is pending. Additional litigation was initiated on January 31, 1995, by KNGSS against the plaintiffs and others in federal court in Colorado. In this lawsuit, KNGSS asserts that contractual provisions require payment of refunds for gas purchased at above-market prices and, prospectively, for a reduction in gas prices paid under the contracts to market levels. The Company believes it has a meritorious position in these matters, and does not expect these lawsuits to have a material adverse effect on the Company's financial position or results of operations.
The Company believes it has meritorious defenses to all lawsuits and legal proceedings in which it is a defendant and will vigorously defend against them. Based on its evaluation of the above matters, and after consideration of reserves established, the Company believes that the resolution of such matters will not have a material adverse effect on the Company's financial position or results of operations.
7. PROPERTY, PLANT AND EQUIPMENT
Investment in property, plant and equipment, at cost, and accumulated depreciation, depletion and amortization ("Accumulated DD&A"), detailed by business segment, are as follows (in thousands):
8. INCOME TAXES
Deferred income tax assets and liabilities are recognized based on enacted tax laws for all temporary differences between financial reporting and tax bases of assets and liabilities. Deferred tax assets are reduced by a valuation allowance for the amount of any tax benefit that is not expected to be realized. .
Components of the income tax provision applicable to federal and state income taxes are as follows (in thousands):
The difference between the statutory federal income tax rate and the Company's effective income tax rate is summarized as follows:
The Company has recorded deferred regulatory assets of $1.3 million and $2.0 million, and deferred regulatory liabilities of $5.2 million and $4.9 million at December 31, 1994 and 1993, respectively, which are expected to result in cost-of-service adjustments. These amounts reflect the "gross of tax" presentation required under Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes". The deferred tax assets and liabilities and deferred regulatory assets and liabilities for rate-regulated entities computed according to SFAS 109 result from the following (in thousands):
As of December 31, 1994, the Company had for tax purposes: (i) estimated NOL carryforwards of $5.4 million and (ii) capital loss carryforwards of $1.0 million. The NOL carryforwards will expire in 2003 through 2008. The capital loss carryforwards, which are available to reduce future capital gains, expire in 1996. The Company also has AMT credits of approximately $15.4 million available to reduce its regular future tax liability in excess of the AMT otherwise due in any year.
9. FINANCING
(A) Notes Payable
On December 1, 1994, K N entered into a credit agreement with eight banks to borrow for general corporate purposes, including commercial paper support, up to a total of $200 million. Depending on the type of borrowing made under the credit agreement, borrowings may bear interest at or above prime, or at margins above certificate of deposit rates bid by New York certificate of deposit dealers, or at margins above rates offered by certain designated banks in the London Interbank market, or at money market rates quoted by the banks under the agreement. The term of borrowing may range from one day to no more than 360 days. Under the credit agreement, K N agrees to pay a facility fee based on the total commitment, at rates which vary based on the financial rating of K N's long-term debt. The credit agreement expires December 1, 1999. K N also has credit agreements with two banks to either borrow or use for commercial paper support up to a total of $25 million. Borrowings are made at rates negotiated on the borrowing date and for a term of not more than one year. Under these agreements, K N pays a commitment fee on the unused commitment. At December 31, 1994, no amounts were outstanding under these credit agreements. At December 31, 1993, $10 million was outstanding under credit agreement arrangements in effect at that time.
Commercial paper issued by K N represents unsecured short-term notes with maturities not to exceed 270 days from the date of issue. During 1994, all commercial paper issued was redeemed within 50 days, with interest rates ranging from 3.12 percent to 6.30 percent. At December 31, 1994 and 1993, $60.0 million and $37.0 million of commercial paper, respectively, were outstanding at rates ranging from 5.87 percent to 6.30 percent and from 3.45 percent to 3.58 percent, respectively.
The weighted average interest rates on short-term borrowings outstanding were 6.09 percent and 3.45 percent as of December 31, 1994 and 1993, respectively.
(B) Long-Term Debt
Maturities of long-term debt for the five years ending December 31, 1999, are as follows (in thousands):
In October 1994, K N sold publicly $75 million of 30-year, 8.75% debentures at an all-in cost to the Company of 8.91 percent. This debt was issued from the Company's $200 million shelf registration statement which the Securities and Exchange Commission declared effective in November 1993. Proceeds from this financing were used to fund capital expenditures and to reduce short-term borrowing incurred in July 1994 to retire the Senior Revolving Credit and Term Note Facility of AOG.
In September 1993, K N sold $50 million of 6.5% debentures at an all-in cost to K N of 6.61 percent. Proceeds from the debt financing were used to redeem K N's 10 3/4% sinking fund debentures and to fund capital expenditures.
As discussed more fully in Note 11, in 1993, AOG entered into two interest-rate swap agreements and, in 1994, the Company entered into four interest rate cap agreements covering $35 million of notional principal.
At December 31, 1994 and 1993, the carrying amount of the Company's long-term debt was $366.2 million and $362.1 million, respectively, and the estimated fair value was $355.2 million and $384.0 million, respectively. The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturation.
10. PREFERRED STOCK
(A) K N Class A $8.50 Preferred Stock
The remaining 5,000 shares of K N Class A $8.50 Preferred Stock subject to mandatory redemption were redeemed by the Company in 1994. In each of the years 1993 and 1992, the Company redeemed 10,000 shares subject to mandatory redemption.
(B) K N Class B $8.30 Preferred Stock
The K N Class B $8.30 Preferred Stock is subject to mandatory redemption through a sinking fund (at $100 per share, plus accrued and unpaid dividends) of $571,400 annually in 1996 and 1997 and $572,000 in 1998. At the option of the Company, this stock is redeemable, in whole or in part, at $101.31 per share prior to January 2, 1996; such redemption price is reduced annually thereafter until January 2, 1998, when it becomes $100 per share. Also, at the option of the Company, 5,714 shares of this stock may be redeemed in each of the years 1995 through 1997, inclusive, at $100 per share. In each of the years 1994, 1993 and 1992, the Company redeemed 5,714 shares subject to mandatory redemption, and an additional 5,714 shares at $100 per share.
(C) K N Class A $5.00 Preferred Stock
The K N Class A $5.00 Preferred Stock is redeemable, in whole or in part, at the option of the Company at any time on 30 days' notice at $105 per share plus accrued dividends. This series has no sinking fund requirements.
(D) AOG 9% Cumulative Convertible Preferred Stock
In November 1992, AOG called all outstanding shares of its 9% cumulative convertible preferred stock for redemption. Prior to the redemption date, all holders elected to convert their shares into AOG's common stock. Effective January 20, 1993, AOG issued 2,429,265 of its common shares (equivalent to 1,141,755 shares of K N common stock) in connection with the conversion.
(E) Rights of Preferred Shareholders
All outstanding series of preferred stock have voting rights.
If, for any class of preferred stock, the Company (i) is in arrears on dividends, (ii) has failed to pay or set aside any amounts required to be paid or set aside for all sinking funds, or (iii) is in default on any of its redemption obligations, then no dividends shall be paid or declared on any junior stock nor shall any junior stock be purchased or redeemed by the Company. Also, if dividends on any class of preferred stock are sufficiently in arrears, the holders of that stock may elect one-third of the Company's Board of Directors.
(F) Fair Value
At December 31, 1994, the carrying amounts and the estimated fair value of the Company's outstanding preferred stock subject to mandatory redemption were $1.7 million and $1.6 million, respectively. The comparable amounts at December 31, 1993, were both $3.4 million. The fair value of the Company's preferred stock is estimated based on an evaluation made by an independent security analyst.
11. RISK MANAGEMENT
The Company uses two types of risk management instruments - energy futures and interest rate swaps - which are discussed below. The Company is exposed to credit-related losses in the event of nonperformance by counterparties to these financial instruments, but does not expect any counterparties to fail to meet their obligations given their existing credit ratings.
The fair value of these risk management instruments reflects the estimated amounts that the Company would receive or pay to terminate the contracts at the reporting date, thereby taking into account the current unrealized gains or losses on open contracts. Market quotes are available for significantly all instruments used by the Company.
(A) Energy Futures
The Company engages in energy futures trading activities to minimize its risk of price changes in the spot and fixed price natural gas, crude oil, and natural gas liquids markets. Energy futures trading activities include the use of crude oil and natural gas commodity contracts and options, fixed price swaps, and basis swaps and options. Pursuant to its Board of Directors' approved guidelines, the Company engages in these activities only as a hedging mechanism against pre-existing physical gas sale, purchase, system use, and storage contracts in order to protect profit margins, and does not engage in speculative trading. These energy futures, swaps, and options are recorded at fair value. Gains and losses on hedging positions are deferred and recognized as operating expenses in the period the underlying physical transactions take place. As the Company engages in no speculative trading activities, all 1994 transactions are recorded as hedges.
As of December 31, 1994, the Company had deferred $13.4 million, representing the difference between the current market value and the original physical contracts' value, associated with its hedging activities, of which $5.3 million relates to commodity contracts and $8.1 million relates to over-the-counter swaps and options. The deferrals will be offset by the corresponding underlying physical transactions and are reflected as deferred charges in the accompanying financial statements. At December 31, 1994, the Company held notional long volumetric positions of 69.4 Bcf of gas, of which 34.1 Bcf were held in gas commodity positions and 35.3 Bcf were held in over-the-counter swaps and options. Of the 69.4 Bcf notional total, associated physical transactions of 51.9 Bcf are expected to occur in 1995, 8.7 Bcf in 1996, and 8.8 Bcf in 1997 and beyond. A change of plus or minus 10 percent of the fair market prices of the above financial instruments would have the approximate effect of reducing or increasing the above deferrals by $13.4 million, which would be offset by corresponding increases or decreases in the value of the underlying physical transactions.
(B) Interest Rate Swaps
The Company has entered into various interest rate swap and cap agreements for the purpose of managing interest rate exposure. Settlement amounts payable or receivable under these agreements are recorded as interest expense or income in the accounting period they are incurred.
In February 1993, AOG entered into a three-year interest rate swap agreement covering $25 million of notional principal whereby it pays LIBOR, which is reset every six months in arrears, in exchange for a fixed rate of 5.07 percent. This agreement terminates March 1996.
In September 1993, AOG entered into a second three-year interest rate swap agreement covering $10 million of notional principal at LIBOR rates, which are reset every 12 months in arrears, in exchange for a fixed rate of 5.27 percent. In August 1994, the counterparty to this second agreement exercised its rights to extend this agreement by one additional year, with the agreement now terminating in September 1997.
In 1994, the Company entered into four interest rate cap agreements which effectively cap the LIBOR rate to be paid by the Company under these swap agreements at 7.5 percent for the terms of the original swap agreements.
12. EMPLOYEE BENEFITS
(A) Retirement Plans
The Company has defined benefit pension plans covering substantially all full-time K N employees. The Merger Agreement provides that, beginning January 1, 1995, K N will provide to employees who were employed by AOG at the effective time of the merger and are currently with the Company, benefit plans, policies and programs that are no less favorable than those provided to K N's similarly situated employees. These plans provide pension benefits that are based on the employees' compensation during the period of employment. These plans are tax qualified subject to the minimum funding requirements of ERISA. The Company's funding policy is to contribute annually the recommended contribution using the actuarial cost method and assumptions used for determining annual funding requirements. Plan assets consist primarily of pooled fixed income, equity, bond and money market funds.
Net pension cost includes the following components (in thousands):
The following table sets forth the plans' funded status and amounts recognized in the Company's financial statements at December 31, 1994 and 1993 (in thousands):
The rate of increase in future compensation and the expected long-term rate of return on assets were 4.5 and 8.5 percent, respectively, for 1994, 4.5 and 9.25 percent, respectively, for 1993 and 5.0 and 9.25 percent, respectively, for 1992. The weighted average discount rate used in determining the actuarial present value of the projected benefit obligation was 8.25 percent for 1994 and 7.5 percent for the 1993 and 1992 periods.
The Company also contributes the lesser of 10 percent of K N's net income or 10 percent of normal K N employee compensation to the Employees Retirement Fund Trust Profit Sharing Plan (a defined contribution plan). Contributions by the Company were $2.3 million, $2.6 million and $2.1 million for 1994, 1993 and 1992, respectively.
(B) Other Postretirement Employee Benefits
The Company has a defined benefit postretirement plan providing medical care benefits upon retirement for all eligible K N employees with at least five years of credited service as of January 1, 1993, and their eligible dependents. Retired K N employees are required to contribute monthly amounts which depend upon the retired employee's age, years of service upon retirement and date of retirement.
This plan also provides life insurance benefits upon retirement for all K N employees with at least 10 years of credited service who are age 55 or older when they retire. The Company pays for a portion of the life insurance benefit; K N employees may, at their option, increase the benefit by making contributions from age 55 until age 65 or retirement, whichever is earlier. In 1993, the Company began funding the future expected postretirement benefit costs under the plan by making payments to Voluntary Employee Benefit Association trusts. The Company's funding policy is to contribute amounts within the deductible limits imposed on Internal Revenue Code Sec. 501(c)(9) trusts. Plan assets consist primarily of pooled fixed income funds.
Effective January 1, 1993, the Company prospectively adopted Statement of Financial Accounting Standards No. 106 ("SFAS 106") which requires the accrual of the expected costs of postretirement benefits other than pensions during the years that employees render service. The Accumulated Postretirement Benefit Obligation ("APBO") of the plan at January 1, 1993, was approximately $18.8 million. The Company has elected to amortize this transition obligation to expense over a 20-year period.
Net postretirement benefit cost includes the following components (in thousands):
Prior to 1993, the cost of providing medical care benefits to retired K N employees was recognized as expense as claims were paid, and the cost of life insurance benefits for retirees was not accrued. Instead, life insurance claims were paid from a trust fund resulting from termination of third-party coverage. The Company's net cost of medical care claims for retirees was approximately $1.2 million in 1992.
The following table sets forth the plan's funded status and the amounts recognized in the Company's financial statements as follows (in thousands):
The weighted average discount rate used in determining the actuarial present value of the APBO was 7.5 percent for both periods. The assumed health care cost trend rate was nine percent for 1994 and seven percent for 1995 and beyond. A one-percentage-point increase in the assumed health care cost trend rate for each future year would have increased the aggregate of the service and interest cost components of the 1994 net periodic postretirement benefit cost by approximately $17,000 and would have increased the APBO as of December 31, 1994, by approximately $215,000.
K N's interstate retail distribution business, in connection with rate filings described in Note 5(B) for Kansas, Nebraska and Wyoming, has received regulatory approval to include in the cost-of-service component of its rates the cost of postretirement benefits as measured by application of SFAS 106. In addition, KNI has received approval from FERC for similar regulatory treatment in connection with its rate filing, also described in Note 5(B). At December 31, 1994, no SFAS 106 costs were deferred as regulatory assets.
(C) Other Postemployment Benefits
In November 1992, FASB issued SFAS 112, which establishes standards of financial accounting and reporting for the estimated cost of benefits provided by an employer to former or inactive employees after employment but before retirement. The Company adopted SFAS 112 on January 1, 1994. Implementation of SFAS 112 had no material effect on the Company's financial position or results of operations. At December 31, 1994, $0.8 million of SFAS 112 costs were deferred as regulatory assets.
13. COMMON STOCK OPTION AND PURCHASE PLANS
K N has incentive stock option plans for key employees and nonqualified stock option plans for its nonemployee directors and employees. In 1994, the Company's shareholders approved an expanded stock-based awards plan for key employees which allows for the granting of both nonqualified and incentive options, restricted stock awards, stock appreciation rights and other stock-based awards. Outstanding stock options granted under
an AOG stock plan have been converted to stock options for K N common stock using the exchange ratio of 0.47. Under all plans, except the 1994 plan and the AOG plan, options are granted at not less than 100 percent of the market value of the stock at the date of grant. Under the 1994 plan, options may be granted at less than 100 percent of the market value of the stock at the date of grant. Options granted under these plans vest immediately or up to five years and expire no later than 10 years after date of grant.
During 1993, AOG issued to its chief executive officer 50,000 shares of restricted AOG common stock (23,500 shares of K N common stock) which vest 50 percent per year. AOG also sold 150,000 shares of AOG common stock (70,500 shares of K N common stock) to its president and chief operating officer for $0.04 per share of AOG common stock ($0.0851 per share of K N common stock). One-half of these shares was fully vested and nonforfeitable upon issuance, and the remainder became fully vested upon consummation of the merger described in Note 2. The market value of these AOG shares issued was approximately $2.3 million based on the average market price per share of AOG common stock on the date of issuance. The market value of the restricted shares was reflected as deferred compensation and is being amortized over the vesting period. The Company recorded compensation expense totaling $1.3 million and $1.2 million for 1994 and 1993, respectively, relating to restricted stock grants awarded under the plans.
At December 31, 1994, 114 employees, officers and directors of the Company held options under the plans. The changes in stock options outstanding during 1994, 1993 and 1992 are as follows, restated to reflect the three-for-two common stock split described in Note 1(C) and the merger described in Note 2:
Unexercised options outstanding at December 31, 1994, expire at various dates between 1995 and 2004.
Effective April 1, 1990, and for each succeeding year, K N established an Employee Stock Purchase Plan under which eligible employees may purchase K N's common stock through voluntary payroll deductions at a 15 percent discount from the market value of the common stock, as defined in the plan.
Under K N's Stock Option, Dividend Reinvestment, Employee Stock Purchase and Employee Benefit Plans, 4,853,498 shares were reserved for issuance at December 31, 1994.
14. COMMON STOCK WARRANTS
At December 31, 1994, warrants to purchase 1,187,432 shares of the Company's common stock were outstanding. The warrants are exercisable at $17.55 per warrant and expire on September 30, 1999.
15. COMMITMENTS AND CONTINGENT LIABILITIES
(A) Leases
On February 16, 1995, AOG Gas Transmission Company, L.P. acquired natural gas transmission pipeline and storage assets in Texas. (See Note 4(A)). A portion of these assets has been funded through 10-year operating leases and payment amounts have been included in the future minimum commitments shown below.
In 1993, K N Front Range Gathering Company began to lease gas gathering equipment and facilities under a 10-year operating lease. In 1992, KNGG began to lease gas gathering facilities and processing equipment under a seven-year operating lease. These operating leases contain purchase options at the end of their lease terms. The Company also leases certain office space, properties and equipment under operating leases.
Payments made under operating leases were $9.6 million in 1994, $8.3 million in 1993 and $5.1 million in 1992.
Future minimum commitments under major operating leases are as follows (in thousands):
(B) Basket Agreement
Under terms of an agreement (the "Basket Agreement") entered into with Cabot Corporation ("Cabot"), the Company's largest stockholder, as part of AOG's acquisition of Cabot's natural gas pipeline business, AOG and Cabot equally share net payments made in settlement of certain liabilities related to operations of the acquired business prior to the acquisition date. During 1995, the Company expects to settle all significant matters covered by the Basket Agreement. The Company's estimated liability is approximately $6.0 million, which was recorded in connection with the acquisition of the natural gas pipeline business from Cabot. As of December 31, 1994, the Company had made net payments of approximately $12.4 million. The difference between net payments made by the Company and its estimated liability is reflected in current assets and consists of (i) the present value of Cabot's share of net payments and (ii) future recoveries from customers.
(C) Capital Expenditure Budget
The consolidated capital expenditure budget for 1995 is approximately $73.9 million, excluding acquisitions.
16. MAJOR CUSTOMER
Energas Company and affiliates comprised 11 percent of consolidated revenues in 1994 and 12 percent of consolidated revenues in both 1993 and 1992.
17. BUSINESS SEGMENT INFORMATION
The Company is a natural gas energy products and services provider engaged in the following activities: (1) selling natural gas at retail (Retail Natural Gas Services), (2) interstate storing and transporting natural gas (Interstate Transportation and Storage Services), (3) gathering, processing, marketing, storing and transporting natural gas (Gathering, Processing and Marketing Services), and (4) developing and producing natural gas and crude oil (Gas and Oil Production).
BUSINESS SEGMENT INFORMATION
* Principally cash and investments
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) QUARTERLY OPERATING RESULTS FOR 1994 AND 1993
(In Thousands Except Per Share Amounts)
*Includes merger and restructuring costs totaling $19.3 million after taxes, or $0.69 per common share.
ITEM 9:
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no such matters during 1994.
PART III
ITEM 10:
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(A) Identification of Directors
For information regarding the Directors, see pages 3-6 of the 1995 Proxy Statement.
(B) Identification of Executive Officers
See Executive Officers of the Registrant under Part I.
(C) Identification of Certain Significant Employees
None.
(D) Family Relationships
See "Relationship Between Certain Directors and the Company" on page 8 of the 1995 Proxy Statement.
(E) Business Experience
See Executive Officers of the Registrant under Part I.
(F) Involvement in Certain Legal Proceedings
See Executive Officers of the Registrant under Part I.
(G) Promoters and Control Persons
None.
ITEM 11:
ITEM 11: EXECUTIVE COMPENSATION
See "Executive Compensation", "Stock Options", "Pension Benefits" and "Director Compensation" on pages 9-18 of the 1995 Proxy Statement.
ITEM 12:
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
See the following pages of the 1995 Proxy Statement: (i) Pages 3-6 relating to common stock owned by directors; (ii) pages 16-17, "Executive Stock Ownership"; and (iii) pages 19-20, "Principal Shareholders".
ITEM 13:
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
(A) Transactions with Management and Others
See "Certain Transactions" on pages 7-8 of the 1995 Proxy Statement and "Relationship Between Certain Directors and the Company" on page 8 of the 1995 Proxy Statement.
(B) Certain Business Relationships
See "Relationship Between Certain Directors and the Company" on page 8 of the 1995 Proxy Statement.
(C) Indebtedness of Management
None.
(D) Transactions with Promoters
Not applicable.
PART IV
ITEM 14:
ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) See the index for a listing and page numbers of financial statements and exhibits included herein or incorporated by reference.
Executive Compensation Plans and Arrangements
Form of Key Employee Severance Agreement (Exhibit 10.2, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1982 Stock Option Plan for Nonemployee Directors of the Company with Form of Grant Certificate (Exhibit 10.3, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1982 Incentive Stock Option Plan for key employees of the Company (Exhibit 10.4, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1986 Incentive Stock Option Plan for key employees of the Company (Exhibit 10.5, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1988 Incentive Stock Option Plan for key employees of the Company (Exhibit 10.6, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
Form of Grant Certificate for Employee Stock Option Plans (Exhibit 10.7, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
Directors' Deferred Compensation Plan Agreement (Exhibit 10.8, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1987 Directors' Deferred Fee Plan and Form of Participation Agreement regarding the Plan (Exhibit 10.9, Amendment No. 1 on Form 8 dated September 2, 1988 to the Annual Report on Form 10-K for the year ended December 31, 1987)*
1992 Stock Option Plan for Nonemployee Directors of the Company with Form of Grant Certificate (Exhibit 4.1, File No. 33-46999)*
K N Energy, Inc. 1994 Executive Incentive Plan (Exhibit 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993)*
K N Energy, Inc. 1995 Executive Incentive Plan (attached hereto as Exhibit 10(l))**
K N Energy, Inc. Nonqualified Deferred Compensation Plan (attached hereto as Exhibit 10(m)**
(b) Reports on Form 8-K
On October 18, 1994, a Current Report on form 8-K was filed to report that on October 19, 1994, K N sold $75 million of its 8.75% Debentures due October 15, 2024, pursuant to an underwritten public offering.*
On January 11, 1995, a Current Report on Form 8-K was filed to report that on January 6, 1995, an affiliate of K N announced its proposed acquisition of certain gas gathering and gas storage assets located in Texas from affiliates of Meridian Oil Inc.*
On February 16, 1995, a Current Report on Form 8-K was filed to report that on February 16, 1995, an affiliate of K N closed its previously announced acquisition of certain gas gathering and gas storage assets located in Texas from affiliates of Meridian Oil Inc.*
* Incorporated herein by reference. ** Included in SEC and NYSE copies only.
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.
K N ENERGY, INC. (Registrant)
March 8, 1995 By /s/ E. Wayne Lundhagen ------------------------------- E. Wayne Lundhagen Vice President, Finance and Accounting
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.
* Incorporated herein by reference. ** Included in SEC and NYSE copies only. *** Such report is being furnished for the information of the Securities and Exchange Commission only and is not to be deemed filed as a part of this annual report on Form 10-K **** Included in SEC copy only.