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Mitchell Energy & Development Corp – ‘10-K’ for 1/31/94 – EX-13

As of:  Tuesday, 4/26/94   ·   For:  1/31/94   ·   Accession #:  950129-94-319   ·   File #:  1-06959

Previous ‘10-K’:  None   ·   Next:  ‘10-K/A’ on 4/28/94 for 1/31/94   ·   Latest:  ‘10-K/A’ on 7/26/96 for 1/31/96

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 4/26/94  Mitchell Energy & Dev Corp        10-K        1/31/94   11:390K                                   Bowne - Houston/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Mitchell Energy 10-K 1994                             25    138K 
 2: EX-4.A      To Mitchell 10-K                                      12     38K 
 3: EX-10.F     To Mitchell 10-K                                      21     40K 
 4: EX-10.G     To Mitchell 10-K                                      19     39K 
 5: EX-10.J     To Mitchell 10-K                                      26     92K 
 6: EX-12       To Mitchell 10-K                                       2±    10K 
 7: EX-13       To Mitchell 10-K                                      70    350K 
 8: EX-21       To Mitchell 10-K                                       2±     9K 
 9: EX-23       To Mitchell 10-K                                       1      7K 
10: EX-99.A     To Mitchell 10-K                                       1      7K 
11: EX-99.B     To Mitchell 10-K                                       1      7K 


EX-13   —   To Mitchell 10-K
Exhibit Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
4Revenues
5Letter to Shareholders
17Gas gathering and transmission
19Other
20Real Estate Division
"The Woodlands
27Management's Discussion and Analysis of Financial Position and Results of Operations
33Restructuring charges
"Extraordinary item
"Cumulative effect of change in accounting methods
40General and administrative expense
43Other expense
46Notes to Consolidated Financial Statements
55Transmission and Processing
60Report of Independent Public Accountants
61Supplemental Oil and Gas Information
65Historical Summary
67Board of Directors
68Principal Officers
69Corporate Information
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EXHIBIT 13 MITCHELL ENERGY & DEVELOPMENT CORP. FISCAL 1994 ANNUAL REPORT YEAR ENDED JANUARY 31, 1994
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THE COMPANY Mitchell Energy & Development Corp. traces its origins to a small wildcatting firm formed in 1946. Today, the Company is a large independent energy producer. It also is a major real estate developer, primarily in the Houston-Galveston region. At the end of fiscal 1994, the Company had approximately 2,900 full-time employees. Principal energy operations include the exploration for and production of natural gas and oil, production of natural gas liquids and operation of intrastate pipelines. In its most recent fiscal year, the Company produced more than 74 billion cubic feet of natural gas and 20.3 million barrels of liquid hydrocarbons (gas liquids, oil and condensate). At year end, it owned or had interests in more than 3,400 wells, 1.5 million acres of leases, nearly 5,000 miles of pipeline and processing plants capable of producing natural gas liquids at a rate of more than 55,000 barrels per day. The Company's largest land development project is The Woodlands, a 25,000-acre community located 27 miles north of downtown Houston. Overall, its real estate holdings comprise about 55,500 acres, plus a variety of office, retail, industrial and other buildings. [Inside Front Cover]
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CONTENTS [Enlarge/Download Table] Letter to Shareholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Exploration and Production Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Mitchell Adds High-Tech Tools to E&P Arsenal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Transmission and Processing Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Capitalizing on One of Texas' Hottest Plays . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Real Estate Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 The Woodlands Celebrates Its 20th Anniversary . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Management's Discussion and Analysis of Financial Position and Results of Operations . . . . . . . . 29 Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Supplemental Oil and Gas Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Historical Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Board of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Principal Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 Corporate Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 GLOSSARY [Enlarge/Download Table] Btu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . British thermal units MMBtu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . million Btu Mcf . . . . . . . . . . . . . . . . . . . . . . . . . . . thousand cubic feet (measure of natural gas volume) MMcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . million cubic feet Bcf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . billion cubic feet Bbl . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . barrel (measure of liquid hydrocarbon volume) MMBbls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . million barrels NGL or NGLs . . . . . . . . . . . . . . . natural gas liquids (ethane, propane, butanes and natural gasoline) DD&A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . depreciation, depletion and amortization Note: All natural gas volumes in this annual report are stated at the legal pressure base of the area in which the reserves are located and at 60 degrees Fahrenheit. Oil, gas and NGL volume, price and reserve information includes applicable equity partnership interests. 1
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HIGHLIGHTS MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES YEAR ENDED JANUARY 31 (dollars in thousands except per-share data) [Download Table] 1994 1993 ---------- ---------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . . $ 19,687(1) $ 18,487(2) ---------- ---------- EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . $ .39(1) $ .39(2) ---------- ---------- REVENUES Exploration and Production . . . . . . . . . . . . . . $ 266,166 $ 214,681 Transmission and Processing . . . . . . . . . . . . . . 560,537 566,700 Real Estate . . . . . . . . . . . . . . . . . . . . . . 126,106 121,453 ---------- ---------- Total . . . . . . . . . . . . . . . . . . . . . . . $ 952,809 $ 902,834 ========== ========== SEGMENT OPERATING EARNINGS Exploration and Production . . . . . . . . . . . . . . $ 66,583 $ 43,318 Restructuring charges . . . . . . . . . . . . . . . . . -- (20,726) ---------- ---------- 66,583 22,592 Transmission and Processing . . . . . . . . . . . . . . 42,659 88,504 Real Estate . . . . . . . . . . . . . . . . . . . . . . 21,078 22,801 ---------- ---------- Total . . . . . . . . . . . . . . . . . . . . . . . $ 130,320 $ 133,897 ========== ========== CAPITAL ADDITIONS . . . . . . . . . . . . . . . . . . . $ 355,845 $ 237,668 ========== ========== TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . $2,415,476 $2,271,799 ========== ========== ESTIMATED PRESENT VALUE OF FUTURE PRE-TAX NET REVENUES FROM PROVED NATURAL GAS, OIL AND NGL RESERVES (2) . . . . . . . . . . . . . . $1,038,000 $1,220,000 OPERATING STATISTICS (AVERAGE DAILY AMOUNTS) Natural gas sales (Mcf) . . . . . . . . . . . . . . . . 193,800 149,000 Crude oil, condensate sales (Bbls) . . . . . . . . . . 6,000 5,600 Natural gas liquids production (Bbls) . . . . . . . . . 49,800 47,200 Pipeline throughput (Mcf) . . . . . . . . . . . . . . . 549,000 566,000 ------------------- (1) Net of an $11 million (22-cent-per-share) deferred tax charge related to the August 1993 increase in the federal corporate tax rate and an extraordinary debt retirement charge of $5.4 million (10 cents per share). (2) Net of Exploration and Production Division after-tax restructuring charges of $13.7 million (30 cents per share); extraordinary debt retirement charge of $7.3 million (15 cents per share); and a change in accounting methods to implement Statement of Financial Accounting Standards No. 106, which had a cumulative prior-year effect of $10.6 million (23 cents per share). ESTIMATED PROVED RESERVES (GRAPHS) 2
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LETTER TO SHAREHOLDERS It's been a roller-coaster year. Natural gas prices have been up, while oil and natural gas liquids prices were up and down during the past 12 months. No doubt there will be more twists and turns ahead for the industry, but I believe that the Company is well-positioned for whatever the future may hold, having taken a number of steps to strengthen its organization and financial capability. We started fiscal 1994 with an excellent first quarter - double the prior-year period's earnings before unusual and extraordinary charges. The strong results were mainly attributable to a 27 percent increase in natural gas sales volumes and to higher gas prices. Both prices and volumes were up for natural gas liquids as well, but the effects of those gains were largely offset by increased fuel and shrinkage costs due to higher gas prices. By the second quarter, world oil prices had begun to fall as a result of OPEC's failure to hold the line on production and in anticipation of Iraq's eventual return to the market. Natural gas liquids, which compete with petroleum products, also declined in price at a time when margins already were being squeezed by the high cost of gas. Still, we posted a 16 percent earnings gain, thanks largely to those very same high gas prices, which were a boon to Exploration and Production Division operating earnings. In addition, we had further natural gas sales volume increases as a result of the Company's buy-out of its development drilling partnership in May 1993. Funds for that $78.3 million acquisition came from the highly successful public offering of 5.9 million shares of Class B common stock, which netted the Company $123.4 million. We used the remainder of the proceeds to reduce debt and to drill wells that otherwise would have been undertaken by the partnership. Another important benefit of the offering is that it raised the Company's profile throughout the investment community and increased the liquidity of our Class B stock, which in recent months has traded at parity with - or higher than - the Class A stock. Also, Moody's Investors Service upgraded its debt rating for the Company's senior notes in January 1994, so all three of our debt ratings are now investment grade. We took advantage of the improved rating with two new senior note issues that same month: $250 million of 6 3/4 percent, 10-year notes; and $100 million of three-year, 5.1 percent notes. The new issues locked in attractive rates on a sizable portion of our existing debt. 3
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They are the latest in a series of initiatives undertaken over the last two years to enhance the Company's financial capability. Weak natural gas liquids prices and tight margins were more evident in the second half of last year. In the third quarter, our average NGL sales price was down 21 percent from a year earlier. Earnings for the period would have been lower than those of the prior-year quarter, but still in the black, had it not been for a one-time, $11 million non-cash charge related to an increase in deferred taxes resulting from a higher federal corporate tax rate. That caused us to post a $2 million, 4-cent-per-share loss for the quarter. Continued NGL price weakness and a $5.4 million charge for early debt retirement reduced fourth-quarter earnings to $611,000, or 1 cent per share, versus $19.5 million, or 41 cents per share, in the prior-year period. The $5.4 million was money well spent, however, because we will realize $9 million in annual savings as a result of refinancing that debt at a substantially lower interest rate. For all of fiscal 1994, we reported net earnings of $19.7 million, up $1.2 million from the year-earlier amount. Because more shares were outstanding after the Class B stock offering, per-share earnings were flat at 39 cents. Excluding extraordinary and unusual charges in both years, the Company would have earned $36.1 million, or 71 cents per share, in fiscal 1994, versus $50 million, or $1.07 per share, in fiscal 1993. Thus far in the current year, low oil prices continue to depress the price of natural gas liquids. Some relief may be on the horizon in the form of three ethylene plants due to come on line within a year, creating more than 100,000 barrels per day of new NGL demand in the United States and Canada. Conversely, the natural gas side of our business continues to be a bright spot, with prices up and volumes at record levels. Harsh winter weather kept gas prices strong through the fourth quarter and into fiscal 1995. Because of the uncertain price outlook, we are reducing our capital expenditures this year by 21 percent. We typically rethink the budget at various times, so spending could be adjusted upward or downward, depending on what happens to oil, gas and natural gas liquids prices. The record cold tested our new Spindletop natural gas storage facility for the first time, and everything worked extremely well. The first partially completed cavern is being utilized to its full 1.7 Bcf working gas capacity, and we plan to make additional cavern space available to our customers later this year. Two major energy projects are nearing completion. The Company and partners Sun Company and Enterprise Products have nearly completed a world-class MTBE gasoline additive plant at Mont Belvieu, Texas, and the facility is expected to be in production by 4
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summer. Nearby, with partners Trident NGL and Conoco, we are expanding the capacity of our natural gas liquids fractionator by 40,000 barrels per day. The new capacity should be in operation by September. Real estate operating earnings were down slightly from those of the prior year, mainly as a result of slower residential sales in The Woodlands. But prospects for the community are excellent, particularly in the commercial area. The biggest news in our Real Estate Division is the million-square-foot regional mall rapidly taking form in The Woodlands. We own 50 percent of that project and virtually all of the surrounding acreage, where commercial activity is flourishing in anticipation of the mall's grand opening this October. Last November, all of us at the Company were shocked and saddened by the untimely death of Exploration and Production Division President Don Covey. Don joined us in 1976 after 21 years with Shell Oil. He was a talented executive, a gifted leader and a wonderful human being, as anyone who knew Don will attest. In early January, W. D. (Bill) Stevens was named to the new post of president and chief operating officer of the corporation. He also succeeded Don as president of our Exploration and Production Division. Bill has been on our board of directors since his 1992 retirement as president of Exxon Company, U.S.A., after 35 years with that organization. He brings a wealth of experience and a fresh perspective that I expect will have positive effects on the way we do business. I retain the positions of chairman and chief executive officer. With our existing backlog of proven drilling locations, our diversification and synergy of operations, and the major new energy and real estate projects we have on the verge of completion - not to mention our dedicated and talented employees - the Company is in excellent shape to weather the current price environment and profit when the inevitable turnaround comes. George P. Mitchell Chairman and Chief Executive Officer March 31, 1994 5
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EXPLORATION & PRODUCTION DIVISION GAS AND OIL SALES Record natural gas production, combined with improved prices, led to a sharp increase in Exploration and Production Division operating earnings. As compared with prior-year results before restructuring charges, the division's fiscal 1994 operating earnings rose 54 percent and accounted for more than half of the Company's total. At a record-high 193,800 Mcf per day, our marketed production of natural gas in fiscal 1994 was 30 percent more than the 149,000 Mcf per day sold in the preceding year. A major contributor to the increase was production related to the May 1993 buy-out of MEC Development, Ltd., a development drilling partnership in which we had owned an interest since the early 1980s. Greater utilization of our production capacity also contributed to the fiscal 1994 gains. For the past several years, we have curtailed output when the so-called gas "bubble" of excess deliverability drove market-sensitive prices to unacceptably low levels. One important indication of the improved supply-demand balance is FINANCIAL HIGHLIGHTS YEAR ENDED JANUARY 31 (in thousands) [Download Table] 1994 1993 -------- -------- REVENUES Oil and gas . . . . . . . . . . . . . . . . $265,798 $202,692 Other . . . . . . . . . . . . . . . . . . . 368 11,989 -------- -------- $266,166 $214,681 ======== ======== SEGMENT OPERATING EARNINGS Oil and gas . . . . . . . . . . . . . . . . $ 66,948 $ 44,722 Other . . . . . . . . . . . . . . . . . . . (365) (1,404) -------- -------- 66,583 43,318 Restructuring charges . . . . . . . . . . . -- (20,726) -------- -------- $ 66,583 $ 22,592 ======== ======== CAPITAL ADDITIONS Consolidated . . . . . . . . . . . . . . . $238,219 (1) $ 77,703 MEC Development, Ltd. . . . . . . . . . . . 13,154 (2) 51,392 (2) -------- -------- $251,373 $129,095 ======== ======== ------------------ (1) Includes $78,251 for buy-out of MEC Development, Ltd. (2) Total additions of MEC Development, Ltd. 6
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that we made no significant price-related production curtailments last year. Natural gas prices, including the leasehold value of natural gas liquids, averaged $2.86 per Mcf in fiscal 1994, compared with $2.84 in the preceding year. These prices are a blend of realizations from sales under fixed-price contracts and sales at market-sensitive prices. During the most recent year, approximately 52 percent of our production was sold under fixed-price contracts at an average price of $3.52 per Mcf; the remainder was sold on the spot market at an average of $2.14. The price of natural gas sold under our largest gas contract rose to $3.75 per MMBtu on January 1, 1994. This contract extends through December 1997 and provides for annual increases of 25 cents per MMBtu. Crude oil and condensate production averaged 6,000 barrels per day in fiscal 1994, up from 5,600 barrels per day in the prior year. World oil prices slumped in the second half, driving our average realization per barrel down to $13.82 for the fourth quarter and $16.31 for the year. In fiscal 1993, the average was $18.49. EXPLORATION AND DEVELOPMENT In fiscal 1994, we replaced 160 percent of the natural gas reserves we produced. NATURAL GAS SALES (GRAPHS) On January 31, 1994, our proved gas reserves were at an all-time high of 627.5 Bcf, up from 583.7 Bcf a year earlier. It was the sixth consecutive year - and the 17th out of the last 19 years - in which our exploration and development programs more than replaced the natural gas reserves we produced. We did not quite replace our production of crude oil and condensate reserves. At year end, the total was 15.3 MMBbls, down from 15.8 MMBbls at the end of fiscal 1993. Property sales accounted for the difference in these year-end amounts. 9
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Most of the fiscal 1994 reserve additions were achieved by drilling, but we also added reserves through acquisitions, the largest of which was the previously noted buy-out of MEC Development, Ltd. Exploration and Production Division capital additions totaled $173.1 million in fiscal 1994, up from comparable expenditures of $129.1 million in the preceding year. Excluded from this comparison is the $78.3 million MEC Development buy-out. Included is $13.2 million of MEC Development capital expenditures made prior to the acquisi- WELL COMPLETIONS (1) YEAR ENDED JANUARY 31, 1994 [Enlarge/Download Table] Exploratory Development Total -------------------- --------------------- --------------------- Total Oil Gas Dry Oil Gas Dry Oil Gas Dry ----- --- --- --- --- --- --- --- --- --- Texas North Texas . . . . . . . 69 -- -- -- 12 53 4 12 53 4 East Central Texas . . . 12 -- -- -- -- 12 -- -- 12 -- Gulf Coast . . . . . . . 36 -- 3 12 1 18 2 1 21 14 New Mexico . . . . . . . . 24 3 5 3 11 1 1 14 6 4 Colorado . . . . . . . . . 5 -- -- 1 -- 4 -- -- 4 1 Other(2) . . . . . . . . . 8 2 -- 4 -- 2 -- 2 2 4 ----- --- --- ---- ---- ---- --- ---- ---- ---- Gross Wells(3) . . . . . . 154 5 8 20 24 90 7 29 98 27 ===== === === ==== ==== ==== === ==== ==== ==== Net Wells . . . . . . . . . 121.4 4.5 5.8 12.0 17.1 77.1 4.9 21.6 82.9 16.9 ===== === === ==== ==== ==== === ==== ==== ==== ------------------ (1) Excludes service wells. (2) Mississippi, New York, Ohio and Pennsylvania. (3) An additional 50 wells (41.7 net wells) were in the process of drilling or completion on January 31, 1994. LEASEHOLDINGS AT JANUARY 31, 1994 [Download Table] Gross Net Acres Acres --------- --------- Colorado . . . . . . . . . . . . . 26,200 22,400 New Mexico . . . . . . . . . . . . 66,800 59,600 Ohio . . . . . . . . . . . . . . . 110,500 110,000 South Dakota . . . . . . . . . . . 40,600 13,200 Texas . . . . . . . . . . . . . . 200,600 141,100 Utah . . . . . . . . . . . . . . . 58,300 54,100 Wyoming . . . . . . . . . . . . . 21,400 11,300 Other* . . . . . . . . . . . . . . 102,800 85,800 --------- --------- Total undeveloped acreage . . . . 627,200 497,500 Producing acreage . . . . . . . . . 843,000 625,900 --------- --------- Total acreage . . . . . . . . . . 1,470,200 1,123,400 ========= ========= ------------------ * Alabama, Arkansas, California, Kansas, Louisiana, Mississippi, Montana, Nebraska, New York, Oklahoma, Pennsylvania and West Virginia. 10
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tion. In light of current economic conditions in the industry, the fiscal 1995 budget for the division has been set at $129.7 million - a level that is expected to enable the Company to replace this year's gas production. Our finding costs were adversely affected last year by participation in a five-well offshore Texas exploratory drilling program operated by a third party that, after an initial commercial discovery at Brazos Block 552, produced only dry holes. Costs also were driven up by expensive mechanical failures in two deep wells in bay waters of the lower Texas Gulf Coast that subsequently were junked and abandoned. These projects accounted for about 57 cents of our fiscal 1994 finding costs of $7.54 per barrel of oil equivalent, which was up from the prior year's $5.93. These amounts are based on the costs and reserve additions associated with each year's drilling program. Included in the additions are reserves of natural gas (net of gas lost in processing), natural gas liquids (lease and plant share), and oil and condensate. During fiscal 1994, we participated in 154 wells, of which 82 percent were successfully completed. In the prior year, we participated in 152 wells, 85 percent of which were completed as producers. While the totals were about the same for CRUDE OIL AND CONDENSATE (GRAPHS) both years, our working interests were equivalent to 121.4 net wells in fiscal 1994, up substantially from 77.6 net wells in fiscal 1993. As in the past, the Fort Worth Basin of North Texas was a principal focus of fiscal 1994 drilling. Sixty-five well completions were made there out of 69 wells drilled. Historically, our primary targets in the basin have been relatively shallow gas-bearing conglomerate and sand formations. In recent years, however, we have become active in the deeper Barnett shale. This is an extremely 11
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"tight" formation, but we have made it commercially productive in naturally fractured areas with wells that are stimulated by a completion technique known as massive hydraulic fracturing. The value of our Barnett shale properties has steadily improved, both as a result of drilling success and reserve increases based on well performance. The North Personville Field, located in the Limestone County area of East Central Texas, is the Company's second-largest natural gas property, and our fiscal 1994 drilling there resulted in several successful outsteps which extended the limits of the field's known productive area. In addition, we continued infill drilling on 160-acre spacing of units we previously drilled with 320-acre well spacing. The outstep program yielded some of the best wells in the history of our drilling there, while the infill program should improve recovery of gas trapped in the area's tight rock formations. We also had continued success in the Delaware Basin of southeastern New Mexico, an area that, like North Texas, has multiple producing horizons. Our main strategy there has been to drill to the gas-prospective Morrow sand, at a depth of about 12,000 to 14,000 feet, while we look for shallower oil-bearing formations in the same well. PRINCIPAL PRODUCING AREAS YEAR ENDED JANUARY 31 [Download Table] Average Daily Sales -------------------------- 1994 1993* ------- ------- NATURAL GAS (NET MCF) North Texas . . . . . . . . . . . . . . . . . 98,600 86,900 Limestone County area (East Central Texas) . . 32,900 21,300 Gulf Coast, onshore . . . . . . . . . . . . . 23,400 16,200 Gulf Coast, offshore . . . . . . . . . . . . . 7,800 5,900 Rocky Mountain area . . . . . . . . . . . . . 11,000 5,700 Southeastern New Mexico . . . . . . . . . . . 8,200 6,300 Other . . . . . . . . . . . . . . . . . . . . 11,900 6,700 ------- ------- Total . . . . . . . . . . . . . . . . . . . . 193,800 149,000 ======= ======= CRUDE OIL AND CONDENSATE (NET BBLS) North Texas . . . . . . . . . . . . . . . . . 1,800 2,000 Gulf Coast . . . . . . . . . . . . . . . . . . 1,300 900 Southeastern New Mexico . . . . . . . . . . . 900 700 Other . . . . . . . . . . . . . . . . . . . . 2,000 2,000 ------- ------- Total . . . . . . . . . . . . . . . . . . . . 6,000 5,600 ======= ======= ------------------ * Certain amounts have been reclassified to conform to the fiscal 1994 presentation. 12
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In the Gulf Coast area, we were particularly successful in increasing gas reserves in the Pinehurst Field area of Montgomery County, Texas. We have numerous other prospects along the Gulf Coast, in New Mexico and elsewhere but will not pursue all of them as aggressively as in the past year until energy prices improve. We will, however, continue to drill at a level sufficient to maintain deliverability for our natural gas contract sales in North and East Texas and in the Hell's Hole Field in western Colorado. RESERVE REPLACEMENT TRACK RECORD (GRAPH) At the end of fiscal 1994, the Company had interests in 2,257 gas pro- ducers and 1,156 oil producers - a total of 3,413 wells, of which 86 were productive in two or more zones. The interests were equivalent to 2,662 net wells - 1,960 gas and 702 oil - of which 76 were productive in two or more zones. (MAP) 13
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TRANSMISSION & PROCESSING DIVISION GAS PROCESSING A drop in the price of U.S. natural gas liquids starting last summer, coupled with higher gas costs, cut gas processing operating earnings by nearly two-thirds in fiscal 1994. NGL prices were depressed by lower crude prices worldwide and by excess inventories across the nation. By year end, NGL prices had declined by more than 25 percent, from an average of $13.68 per barrel in March to $10.16 per barrel in December. Our processing business was caught in an unusual profit-margin squeeze last year. At the same time revenues were slipping because of falling NGL prices, our costs were rising because of higher gas prices. While the gas price gains produced excellent earnings growth for the Exploration and Production Division, they had the opposite effect on the Transmission and Processing Division, because roughly one-half of our gas processing contracts require the Company to replace gas consumed in the plant as fuel and through shrinkage when the liquids are extracted. Make-up gas volumes had to be purchased at relatively high spot-market prices. Poor profit margins in the second half forced the Company to shut down some processing plants temporarily and to reduce output at others, cutting total NGL production from a record 54,900 barrels per day in February 1993 to a fiscal-year low of 40,400 barrels in FINANCIAL HIGHLIGHTS YEAR ENDED JANUARY 31 (in thousands) [Download Table] 1994 1993 --------- ---------- REVENUES Gas processing . . . . . . . . . . . . . $ 255,537 $ 309,917 Gas gathering and transmission . . . . . 296,373 248,605 Other . . . . . . . . . . . . . . . . . . 8,627 8,178 --------- --------- $ 560,537 $ 566,700 ========= ========= SEGMENT OPERATING EARNINGS Gas processing . . . . . . . . . . . . . $ 21,932 $ 60,370 Gas gathering and transmission . . . . . 18,742 25,517 Other . . . . . . . . . . . . . . . . . . 1,985 2,617 --------- --------- $ 42,659 $ 88,504 ========= ========= CAPITAL ADDITIONS . . . . . . . . . . . . $ 48,628 $ 70,473 ========= ========= 14
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December. Volumes also were reduced for a period last summer when our largest processing plant, located at Bridgeport in North Texas, was shut down for 13 days while our biggest gas customer performed scheduled pipeline maintenance. Still, overall NGL production was up for the full year, averaging 49,800 barrels per day, compared with 47,200 barrels per day in fiscal 1993. The increase was due to an acquisition we made in August 1992 of Oryx Energy's interests in a dozen processing plants in Texas and Oklahoma. Conoco is our 50 percent partner in that venture, known as C&L Processors. That partnership processes gas primarily under "percent of proceeds" contracts, which do not require the purchase of make-up gas, and C&L was profitable despite the second-half downturn. Mitchell's share of the liquids produced by the partnership averaged 8,100 barrels per day last year. Another partnership in which the Company holds a 45 percent interest, UP Bryan Plant Joint Venture, increased its NGL production from the previous year by almost 20 percent, to more than 20,000 barrels a day in fiscal 1994. The partnership's processing plants, located along the Austin Chalk trend of East Central Texas, returned to full service in May 1993 after being partially off line for nearly a year due to an explosion at an unaffiliated NGL storage site that serves UP Bryan. NATURAL GAS LIQUIDS (GRAPHS) Nationwide, inventory surpluses have been trimmed to more normal levels due to production cutbacks and periods of brisk winter demand, but prices for ethane, propane and other natural gas liquids are likely to remain under downward pressure as long as oil prices are depressed. About three-quarters of the gas liquids we sell compete against crude-based products, primarily naphtha and gas oil, as feedstocks for petrochemi- 17
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cal plants. The other 25 percent competes in the fuel market. Although crude-based products remain plentiful, we are optimistic that NGL prices will begin firming later this year as a result of increased demand from the petrochemical industry. NGL producers saw a 120,000-barrel-per-day increase in liquids demand on the Gulf Coast and a robust price rebound in 1991, when petrochemical manufacturers opened three new plants in Texas and Louisiana to produce ethylene, a building block for a variety of plastics. Three more large ethylene plants now under construction should create a similar increase in NGL demand during the next 12 months. Formosa Plastics is expected to start its new ethylene plant at Point Comfort, Texas, this spring, and Dow Chemical plans to open ethylene facilities at Freeport, Texas, and in Alberta, Canada. Another component of the Company's liquids business, Gulf Coast Fractionators, is being expanded, and the new capacity should be in operation by September. Gulf Coast Fractionators separates mixed gas liquids from the field into pure products at its plant at Mont Belvieu, Texas. The plant, which Mitchell owns in partnership with Trident NGL and Conoco, is expanding its production capacity from 65,000 barrels per day to 105,000 barrels per day. Unlike gas processing, NGL fractionation is a volume-based service business that is much less sensitive to swings in commodity prices. Last year, Conoco bought a 22.5 percent stake in the plant, reducing our previous half interest to 38.75 percent. Through a refinancing of the plant, our Company netted $15.5 million in cash. The Transmission and Processing Division will enter a new business line with the opening of an MTBE gasoline additive plant. The plant is being built in partnership with Sun Company and Enterprise Products. Our Company has a one-third interest in the facility, which has a design capacity of 12,500 barrels per day but is expected to produce at a higher rate. MTBE (methyl tertiary butyl ether) is a key ingredient in "reformulated" gasoline. The plant will open ahead of the final round of clean air regulations requiring use of cleaner-burning gasoline in pollution-prone areas of the country. Start-up is scheduled for this summer - several months ahead of the original schedule. The MTBE facility, also located at Mont Belvieu, is expected to contribute significantly to operating earnings in the second half of the current year. Sun has agreed to buy 100 percent of the plant's 18
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production for the first 10 years. We will supply one-third of the feedstock, providing us with a firm market for more than half of our butane production. Largely as a result of prices that are too low to warrant operation of some of our gas processing plants, natural gas liquids reserves declined to 107.4 MMBbls at the end of fiscal 1994 from 127.4 MMBbls at the same time a year earlier. However, a substantial part of the gas liquids removed from our reserve base because they are not currently economic to process would be added back if prices improve to the point that operation of the out-of-service plants again is justified. GAS GATHERING AND TRANSMISSION Average gas throughput along our intrastate pipeline systems was down slightly in fiscal 1994 to 549,000 Mcf per day from 566,000 Mcf a year earlier, mainly due to a reduction in contract volumes and to natural declines in some of the fields our pipelines serve. However, our Ferguson-Burleson County Gas Gathering System moved record volumes of gas in fiscal 1994, thanks to a 108-mile expansion project that also boosted gas compression on the line. The Company holds a 45 percent interest in partnership with Union Pacific (MAP) 19
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Resources. The system moved a daily average of 256,000 MMBtu during the year, an increase of more than 12 percent over volumes carried in fiscal 1993. Also, on our Winnie Pipeline system, volumes surged from roughly 170,000 Mcf per day in November to as high as 300,000 Mcf in late January, due to a prolonged cold snap in the Northeast and to recent transmission system improvements. In November, we completed a strategic link-up between Winnie and the Texaco Sabine interstate pipeline. That interconnection boosted volumes last winter on the Winnie system by as much as 120,000 Mcf per day because it enabled us for the first time to help our third-party customers get their gas from Southeast Texas to the important Henry Hub gas trading market in South Central Louisiana. Our new Spindletop storage facility at Beaumont, Texas, also attracted new volumes of gas to the Winnie system last year. We are continuing to increase our storage capacity at Spindletop with the development of a second cavern. Using the new cavern, we plan to double the facility's current 1.7 Bcf of working gas capacity by December. The storage project originally was conceived as a means of enhancing Winnie's service to existing customers in the Golden Triangle, a highly industrialized area along the upper Texas Gulf Coast. However, it soon became clear that the facility offered opportunities for attracting off-system customers. In July, the Company signed a 10-year lease agreement with Natural Gas Clearinghouse, the nation's largest independent natural gas marketer, for 1 Bcf of storage capacity--half last year and the remainder in the current year. PIPELINE OPERATIONS (GRAPH) As a result of that contract, Spindletop's first cavern was fully utilized during its first year of operation. Plans call for the storage facility to be expanded to at least 12 Bcf, and possibly to 18 Bcf of working gas capacity by 1997. Because the Transmission and Processing Division's expenditures for several major projects were largely funded earlier, the division's capital spending in 1994 was substantially lower than in the prior year. The division's capital budget for fiscal 1995 has been set 20
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at $29.6 million, down from $48.6 million in fiscal 1994. OTHER Other division operations include Brazos Gas Compressing Co., a service company that increases the pressure of natural gas to move it through gathering or transmission lines. That subsidiary, which works both for us and for third parties, is a consistent contributor to the division's operating earnings. Natural Gas Processing (CHART) 21
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REAL ESTATE DIVISION THE WOODLANDS The Woodlands, our largest real estate project, maintained its number-one ranking in the Houston area in new home sales and starts for the fourth year in a row. It also was named one of the top 10 communities in the United States by American Metro/Study Corporation and was honored as 1993 winner of the world's premier real estate award, the Prix D'Excellence, by the Paris-based International Real Estate Federation. The Woodlands' population increased by about 2,600 during the year, to more than 38,500. Approximately 750 jobs were added, bringing total non-construction employment to about 11,500. But the substantial progress we made during fiscal 1994 was not fully reflected in operating earnings, which were affected by a slowdown in residential lot sales. Commercial activity picked up dramatically, however, with the beginning of construction of The Woodlands Mall, a regional shopping center encompassing a million square feet and featuring four major retailers as anchor tenants. The Woodlands Corporation is building the mall in a 50-50 joint venture with Sears' Homart subsidiary. The partnership will own approximately 345,000 square feet of space not being occupied by the four department stores. The mall is on schedule for an October 1994 grand opening. Construction of the mall has spurred real estate activity in The Woodlands, FINANCIAL HIGHLIGHTS YEAR ENDED JANUARY 31 (in thousands) [Download Table] 1994 1993 -------- -------- REVENUES The Woodlands . . . . . . . . . . . . . . . . $108,218 $ 99,556 Other . . . . . . . . . . . . . . . . . . . 17,888 21,897 -------- -------- $126,106 $121,453 ======== ======== SEGMENT OPERATING EARNINGS The Woodlands . . . . . . . . . . . . . . . $ 24,601 $ 23,466 Other . . . . . . . . . . . . . . . . . . . (3,523) (665) -------- -------- $ 21,078 $ 22,801 ======== ======== CAPITAL ADDITIONS . . . . . . . . . . . . . . $ 65,132 $ 84,954 ======== ======== 22
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including the sale in fiscal 1994 of more than 30 acres of prime commercial land. In addition, institutional clients purchased approximately 113 acres. For the year, our commercial and institutional land sales exceeded $13.3 million, compared with $5.1 million in the prior year. We've made significant progress on the development of Pinecroft Center, a 350,000-square-foot retail facility adjacent to the mall. The first phase opened in 1991 with a 112,000-square-foot Target store. Construction is in progress for several other retailers and restaurants, including Service Merchandise, Marshalls, Toys 'R' Us, Black-Eyed Pea, Chili's, Guadalajara Cafe and Grille, and Jack-in-the-Box. Groundbreaking also took place for a neighborhood shopping center serving the villages of Cochran's Crossing and Alden Bridge. A Kroger "signature" store and an Eckerd Drug store have signed leases as anchors for the 136,000-square-foot center, and prospects are excellent for filling the remaining space. This project, a joint venture with an institutional investor, is scheduled to open this fall. The office occupancy rate in The Woodlands averaged 90 percent for fiscal 1994, its highest level since 1981. At the beginning of the year, Hughes Christensen completed its move into its new world headquarters and manufacturing facility in The Woodlands. Allstate Insurance Co. moved into its 39,000 square feet of space in the new Parkwood II office building in March 1994. At year end, all five of our Ventures Technology buildings in The Woodlands' Research Forest were 100 percent leased. Indicating their potential for growth, five young Research Forest companies completed initial or secondary public stock offerings totaling more than $80 million during the year. THE WOODLANDS RESIDENTIAL (GRAPHS) Construction will commence this year on a 38,000-square-foot, build-to- 25
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suit headquarters and technology facility for GeneMedicine, which will add 65 employees to the community's work force. The pharmaceutical company was formed to transfer to the marketplace technologies developed at Baylor College of Medicine. Service Corporation International, the largest funeral home operator in the world, purchased a 70-acre site in The Woodlands at the end of fiscal year 1994. The property will be used for development of Forest Park-The Woodlands, a cemetery and funeral home. A lack of job growth in the region and a slow start due to unusually wet weather and a reduced inventory of available lots caused residential lot sales to decline 7 percent, from 911 in the prior year to 844 in fiscal 1994. However, the average lot price rose from $38,196 to $39,055, and the price per square foot increased to $3.38 from $3.14. Residential lot sales picked up in the third quarter, carrying into the new fiscal year. Occupancy rates for apartments managed by the Company averaged 90 percent for the year, and demand remains strong. In July, construction of the Forest View Apartments, a 256-unit affordable housing project, was completed. By year end, 95 percent of its units were leased. The Woodlands Executive Conference Center, Resort and Country Club had record earnings and revenues in fiscal 1994. Group bookings at the REAL ESTATE HOLDINGS AT JANUARY 31, 1994 [Enlarge/Download Table] Property Description Company-Owned Acreage -------- ----------- --------------------- The Woodlands Master-planned, 25,000-acre community located 27 miles north of downtown Houston. 16,820 Land held for investment, Principally undeveloped properties development or sale in Galveston, Grimes, Harris, Montgomery, San Jacinto and Waller counties, Texas. 37,750 Resort and other operating Includes Pirates' Beach, Pirates' Cove properties and other developed properties on Galveston Island; Magnolia Country subdivisions northwest of Houston; and Cape Royale on Lake Livingston. 970 ------ 55,540 ====== 26
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conference center increased substantially, and country club membership reached an all-time high. In addition, Shell Oil announced an extension of its sponsorship of the Shell Houston Open PGA golf tournament at The Woodlands for the next three years. The tournament again will receive THE WOODLANDS STATISTICAL HIGHLIGHTS AT JANUARY 31, EXCEPT AS NOTED [Download Table] 1994 1993 ------ ------ Population . . . . . . . . . . . . . . . . . 38,550 35,910 Employment (non-construction) . . . . . . . . 11,500 10,750 Occupancy rates Office-industrial . . . . . . . . . . . . 88% 88% Apartments . . . . . . . . . . . . . . . . 92% 88% Woodlands Executive Conference Center and Resort (average for the year) . . . 62% 58% Managed properties (square feet) Office-industrial . . . . . . . . . . . . 1,725,660 1,686,630 Retail . . . . . . . . . . . . . . . . . . 478,760 453,340 COMMERCIAL ACTIVITY IN THE WOODLANDS MALL AREA (MAP) 27
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national television coverage on the ABC network. Mitchell Mortgage Company continued its successful lending program in fiscal 1994. During the year, this subsidiary originated $67 million in permanent home mortgage loans for both newly purchased and refinanced single-family dwellings. Although the subsidiary sells virtually all of the loans, it retains servicing rights through which it earns loan administration fees. The servicing portfolio at year end amounted to approximately $600 million. At year end, cumulative capital investment in The Woodlands by the Company and third parties totaled approximately $2.9 billion, up from $2.6 billion the year before. The Company's share was 24 percent, about the same as a year earlier. Including the mall, some 1.5 million square feet of private and public construction was under way in The Woodlands at the beginning of fiscal 1995. When completed, these facilities should create 3,000 to 4,000 new jobs. Among the public-sector projects are the 72,000-square-foot Colin Powell Elementary School, a 30,000-square-foot library and a 12,000-square-foot Montgomery County annex building. THE WOODLANDS CONSTRUCTION STARTS YEAR ENDED JANUARY 31 (GRAPH) OTHER The San Luis Hotel in Galveston is now one of the largest resort and conference centers on the Gulf Coast. With its added conference and dining facilities, the hotel has expanded its market and increased off-peak occupancy rates. On Company property adjacent to The San Luis, construction is under way on a 500-seat Landry's Restaurant. Resort property sales on West Galveston Island were soft throughout the year, in large part due to the flat Houston economy. During the year, a partnership in which the Company has an interest acquired several important government permits for the Lake Catamount skiing development near Steamboat Springs, Colorado. These permits should add value to the property and allow the partnership to proceed with a business plan for possible development. 28
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND RESULTS OF OPERATIONS MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES LIQUIDITY AND CAPITAL RESOURCES A principal strategy of the Company has been to acquire well-positioned energy and real estate assets and to enhance their value through long-term development programs. This strategy requires major front-end capital investments, which are recovered over extended periods of time as energy reserves are produced and real estate investments are developed and operated or sold. The Company generally has funded its investment activities using cash provided by operating activities and sales of varying interests in mature real estate assets supplemented to the extent necessary with proceeds from long-term borrowings. In recent years, the primary sources of such borrowed funds have been bank credit agreements of the energy and real estate subsidiaries and senior notes of the parent company. Needed funds initially have been borrowed under the bank credit agreements, and the credit availability under these facilities periodically has been restored by paying down outstanding borrowings using proceeds from public offerings of parent company senior notes. During January 1994, the Company issued $250 million of 6 3/4% Senior Notes Due 2004 and $100 million of 5.10% Senior Notes Due 1997. The proceeds of these borrowings were used to prepay $200 million of 11 1/4% Senior Notes Due 1999 and to pay down outstanding borrowings under the Company's bank credit agreements as discussed above. The 11 1/4% senior notes were redeemed on February 25, 1994 at a price of 103.21% of principal. In addition to lowering the Company's interest costs, these transactions increased the Company's credit availability, extended the maturities of its indebtedness, reduced its exposure to floating interest rates and increased the percentage of the Company's indebtedness that is unsecured, parent company debt. The Company adopted a dual-class common stock structure during fiscal 1993 to facilitate the use of common stock in connection with general financing transactions, acquisitions or corporate restructurings. During May 1993, the Company sold 5.9 million Class B shares, and Mr. Mitchell, the Company's majority shareholder, sold one million of his Class B shares. The Company's $123.4 million net proceeds of this public offering were used in connection with its buy-out of the MEC Development, Ltd., partnership and to fund fiscal 1994 drilling costs that otherwise would have been expenditures of that partnership. The Company's bank revolving credit and commercial paper facilities provide for aggregate borrowings of approximately $558 million. Exclusive of the $206 million which was used in late February to redeem the 11 1/4% senior notes, the Company had unused capacity of $299 million available under these committed credit facilities at January 31, 1994. The terms of the Company's $250 million Energy and $165 million Real Estate bank revolving credit facilities were amended during October 1993. The term-loan feature that previously was part of these agreements was eliminated, and these facilities are now five-year revolvers maturing on July 31, 1998. For their fifth year, which begins on August 1, 1997, the committed amounts for these facilities decrease to 75% of their initial size. Also during October 1993, the maturity of the Company's $125 million commercial paper program was extended through June 1997, and the term of a mortgage subsidiary's $18 million bank credit facility was extended through July 1996. Exclusive of the $200 million debt prepayment discussed above and maturities under its bank credit facilities and commercial paper program, the Company's aggregate five-year debt maturities totaled approximately $136 million at January 31, 1994. Because of its continued development activities and overall economic factors, the Company expects the values of its energy and real estate assets to increase over time. Such value increases should enable the Company to raise capital to fund a portion of its ongoing development costs. Additionally, the Company's business plan includes the use of energy and real estate partnerships and sales of mature real estate properties to provide for some of its funding needs. Because of the cyclical nature of energy 29
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prices and the real estate business, value increases will not occur evenly, and it is possible that value declines periodically will occur. However, the Company expects that its activities will continue to increase shareholder value over the longer term. The Company believes its asset values and cash flows will be sufficient to allow it to provide for both its short-term and long-term liquidity needs. Such short-term needs can be met by supplementing operating cash flows with borrowings under committed bank credit facilities. Public debt and equity markets will be accessed periodically to provide for the Company's longer-term needs. At January 31, 1994, the Company's long-term debt totaled $988.3 million, up $40.6 million from the balance at the beginning of the year. Primarily because of the Class B stock sale, however, the debt/equity ratio declined to 1.31 from 1.50. Since the Company's short-term liquidity needs can be completely satisfied using its committed bank revolving credit facilities, it has chosen not to maintain the large excess cash balances that would be necessary for positive working capital to be reported. Because of this and since its principal sources of operating cash flows (the following year's production of energy reserves and sales of real estate) cannot be reported as working capital, the Company had a working capital deficit of $28.2 million at January 31, 1994. Cash flows from gas processing operations historically have constituted a significant portion of the Company's overall cash flows. NGL margins and cash flows were adversely affected during the second half of fiscal 1994 by low sales prices - which were largely the result of low world oil prices - and by relatively high costs for replacement gas under keep-whole processing agreements. For the most part, this trend persisted throughout a relatively cold winter. As the end of the winter heating season approaches, the outlook for future NGL prices is unclear. Domestic NGL inventories have declined substantially in recent months because of price-related production cutbacks, and while this is expected to positively affect future NGL prices, it is not clear what, if anything, OPEC will do to firm world oil prices and thereby reduce the downward pressure that such prices have exerted on NGL realizations. In the recent pricing environment, margins for the Company's keep-whole processing plants generally have not been sufficient to cover operating costs, and consequently many of these smaller facilities have been temporarily shut down. The Company's NGL production volumes averaged 42,000 barrels per day in fiscal 1994's fourth quarter, 22% below the first-half average. Production continued at a reduced level early in fiscal 1995. The poor pricing scenario for NGLs and oil also had a negative impact on the estimated quantities and present values of the Company's reserves. The estimated present value of pretax future net revenues of the Company's energy reserves, calculated in accordance with Securities and Exchange Commission regulations, totaled $1.038 billion at January 31, 1994 - $842 million for natural gas and oil and $196 million for plant NGLs. At January 31, 1993, these amounts totaled $1.22 billion - $880 million for natural gas and oil and $340 million for plant NGLs. Principally because uneconomic quantities are excluded from the reported amounts, the Company's plant NGL reserves declined by 16% during fiscal 1994. However, the presently uneconomic quantities remain committed to the Company's processing plants and would be restored to the reported reserves with improved gas processing economics. The depressed oil and NGL prices also negatively impact the Company's full cost ceiling limitation calculations, and the "cushion" between this ceiling and the financial statement carrying value of the Company's oil and gas properties eroded substantially during fiscal 1994. Additional erosion could necessitate additions to the Company's future DD&A expense provisions. As discussed in the following section, the low prices for oil and NGLs also caused the Company to reduce its fiscal 1995 capital budget. Furthermore, the Company is seeking other means of improving 30
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its fiscal 1995 earnings and cash flows. Although specific measures have not yet been determined, such actions could include the disposition of assets and other steps that would result in both operating and overhead cost reductions. CAPITAL SPENDING The following table compares the fiscal 1995 capital budget with the actual capital additions for fiscal 1994 and 1993 (dollars in millions): [Enlarge/Download Table] 1995 Budget 1994 1993 --------------- ----------------- ---------------- Amount % Amount % Amount % ------ ----- ------ ----- ------ ----- Exploration and Production . . . . $129.7 56.2 $159.9 44.9 $77.7 32.7 MEC Development, Ltd. buy-out . . -- -- 78.3 22.0 -- -- Transmission and Processing . . . . 29.6 12.8 48.6 13.7 70.5 29.7 Real Estate . . . . . . . . . . . . 65.5 28.4 65.1 18.3 85.0 35.7 Corporate . . . . . . . . . . . . . 6.0 2.6 3.9 1.1 4.5 1.9 ------ ----- ------ ----- ------ ----- $230.8 100.0 $355.8 100.0 $237.7 100.0 ====== ===== ====== ===== ====== ===== The consolidated budget for fiscal 1994 capital spending, initially set at $226.6 million, was later revised to $372.7 million. Most of the revisions were related to the buy-out of MEC Development, Ltd., effective May 1, 1993, including increases in the consolidated budget to cover drilling costs that otherwise would have been expenditures of the partnership. Including the $78.3 million for the partnership buy-out, fiscal 1994 capital additions ultimately totaled $355.8 million, 4.5% below the revised budget. Largely because of low crude oil prices and their adverse impact on NGL prices and margins, the Company chose to scale back its fiscal 1995 capital spending plans to better balance its cash inflows and outflows. This level of spending is believed adequate to allow the Company to replace the gas and oil reserves that will be produced in fiscal 1995, to fund its ongoing Transmission and Processing projects and to provide for the ongoing development of The Woodlands. The Company monitors its cash flows on an ongoing basis, and the fiscal 1995 capital budget may be adjusted - either upward or downward - in response to changed circumstances. Because of continued low margins for NGLs and the timing of annual Texas ad valorem tax payments, semiannual senior note interest payments and the previously mentioned debt prepayment premium, the Company's long-term debt may rise during the early part of fiscal 1995 by an amount approximating fiscal 1994's $40 million increase. With some expected improvements in energy prices and margins and receipts from sales of mature real estate properties later in the year, debt subsequently is projected to decline. However, such reductions may not be sufficient to entirely erase the earlier increase. Even after excluding the effect of fiscal 1994's buy-out of MEC Development, Ltd., the capital budget calls for lower Exploration and Production Division capital spending, the bulk of which will consist of reduced drilling expenditures. The division will continue to emphasize the development of known reserves and expects to replace production even at the lower spending level by concentrating its efforts on the best available prospects. Also, it is anticipated that the Company's fiscal 1995 average production volumes for natural gas and oil will rise both because of the carryover effect of fiscal 1994's drilling activity and the full-year's impact of the partnership buy-out. The $19.0 million planned reduction in capital additions for Transmission and Processing in fiscal 1995 is principally attributable to lower expenditures for pipeline projects and reduced capital contributions to an unconsolidated partnership which is completing the construction of an MTBE plant. Construction will continue in fiscal 1995 on the wholly owned Spindletop natural gas storage facility, where initial operations commenced late in the third quarter of fiscal 1993. However, since the capital expenditures for Spindletop's infrastructure have already been made, storage capacity can be added at a relatively low cost. 31
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The fiscal 1995 capital budget calls for Real Estate Division spending to remain essentially unchanged from the prior-year level. Capitalized costs should decline somewhat because of an expected reduction in the Company's effective interest rate due to the prepayment of the 11 1/4% senior notes while "hard" costs will increase if build-to-suit facilities are constructed, as planned, for companies that are considering relocating to The Woodlands. In addition to its fiscal 1995 consolidated capital budget, the Company will be participating through partnerships in several significant construction projects. These projects, which are funded principally using proceeds of loan agreements of the partnerships, include the previously noted MTBE plant, expansion of a fractionation facility and construction of a regional mall in The Woodlands. A partnership in which the Company has a one-third interest is constructing an MTBE plant at Mont Belvieu, Texas with a design capacity of 12,500 barrels per day. MTBE (methyl tertiary butyl ether) is an oxygenate used in the production of environmentally cleaner gasoline. This plant, with an estimated construction cost of $220 million, is expected to begin production during the summer of 1994. Each of the three partners in this venture is to provide one-third of the plant's isobutane feedstock, and one of the partners, Sun Company, Inc., has agreed to purchase all of the MTBE production for a period of ten years. Plant construction costs are funded through the partnership's $176 million loan agreement and capital contributions from the partners. The Company's capital contributions to the partnership, which are expected to decline to $1 million in fiscal 1995 from the prior year's $9 million, are included in the consolidated capital budget. Conversely, expenditures funded by partnership borrowings are not included in the consolidated budget. Through its 38.75% ownership in Gulf Coast Fractionators (GCF), the Company is participating in a 40,000 barrel-per-day expansion of an NGL fractionation plant at Mont Belvieu, Texas. The expanded facility is expected to begin operating in September 1994. In connection with the $40 million expansion project and the entrance of Conoco, Inc. into the partnership, GCF arranged an $85 million term loan in June 1993. Of the loan proceeds, $40 million was distributed to the partners in fiscal 1994, the Company's share of which was $15.5 million. The expansion costs are being funded by borrowings under the partnership's loan agreement. Accordingly, such expenditures are not included in the Company's consolidated capital budget. Each of the partners has executed long-term contracts with GCF for the fractionation of production from certain of their gas processing plants. The Woodlands Mall, a one million-square-foot regional mall, is the largest project in which the Real Estate Division will participate in fiscal 1995. The mall, which is being developed by a partnership equally owned by the Company and Homart Development Co., a subsidiary of Sears, Roebuck and Co., is expected to open in October 1994. Costs of the 345,000-square-foot gross leasable area being constructed by the partnership, together with site development and other general costs, are being funded using proceeds of the partnership's $65 million loan agreement. Because of this, the Company's consolidated capital budget does not include these costs. ENVIRONMENTAL AND OTHER MATTERS Concern for the environment has been part of the Company's operating philosophy for many years. In the ordinary course of conducting its business, the Company incurs costs, both expensed and capitalized, to preserve and protect the environment. As public concern for the environment has grown in recent years, new environmental regulations and laws have been enacted, and the enforcement of existing laws has been strengthened. Among other things, these regulations - some of which affect the Company's energy and real estate activities - involve significant financial responsibilities and impose constraints on the manner in which operations may be conducted. The Company considers compliance with environmental protection regulations and laws, and the related costs, to be a necessary and manageable part of its business. To date, the Company has not been faced with major clean-up obligations and has been able to conform with environmental regulations without materially altering its operating strategies. 32
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The Company's real estate development activities are subject to certain wetlands preservation regulations. The timely performance of environmental impact assessments, together with flexibilities available because of the Company's large landholdings and its practice of designing and constructing projects in harmony with the natural environment, have enabled the Company to comply with these and other resource preservation regulations. While it is not possible to fully anticipate the financial obligations or operating constraints that might ultimately result from increasingly stringent environmental regulations and enforcement programs, management believes the Company is well-positioned within the industries in which it competes to deal with environmental protection requirements. Furthermore, clean-burning natural gas, the cornerstone of the Company's energy operations, is likely to benefit from increasing environmental awareness. Real estate development activities also are affected by regulations, policies and actions of various governmental agencies and other entities relating to essential public services, including utilities, telephone service and schools. To date, these public services have been obtained in a manner that has enhanced the Company's development activities, and management expects that this will continue to be the case for the foreseeable future. As previously reported, litigation had been brought by a pipeline purchaser related to three natural gas sales contracts which extended until 2000 and provided for above-market minimum prices. This litigation was settled in January 1994 when new gas sales contracts were executed. While near-term revenues under the new contracts will likely be lower, the Company estimates that total revenues over the terms of these contracts will at least equal those which would have been received under the previous agreements. OPERATING STATISTICS Certain operating statistics (including, where applicable, proportional interests in equity partnerships) for fiscal 1994, 1993 and 1992 follow: [Download Table] 1994 1993 1992 -------- -------- -------- AVERAGE DAILY VOLUMES Natural gas sales (Mcf) . . . . . . . . . . . . 193,800 149,000 157,800 Crude oil and condensate sales (Bbls) . . . . . 6,000 5,600 5,400 Natural gas liquids produced (Bbls) . . . . . . 49,800 47,200 44,000 Pipeline throughput (Mcf) . . . . . . . . . . . 549,000 566,000 581,000 AVERAGE SALES PRICES Natural gas (per Mcf) . . . . . . . . . . . . . $ 2.86 $ 2.84 $ 2.74 Crude oil and condensate (per Bbl) . . . . . . 16.31 18.49 18.95 Natural gas liquids produced (per Bbl) . . . . 12.18 13.41 13.41 RESIDENTIAL LOT SALES - THE WOODLANDS Lots sold . . . . . . . . . . . . . . . . . . . 844 911 910 Average price . . . . . . . . . . . . . . . . . $ 39,055 $ 38,196 $ 36,400 RESULTS OF OPERATIONS - FISCAL 1994 COMPARED WITH FISCAL 1993 The Company's results for fiscal 1994 and 1993 - both before and after unusual items which affected each year's earnings - are shown on the table on the following page. Exclusive of the unusual items, the Company earned $36.1 million in fiscal 1994, compared with $50.0 million in the prior year. After considering the unusual items, net earnings were $19.7 million ($.39 per share on 51,004,000 shares) in fiscal 1994 and $18.5 million ($.39 per share on 46,858,000 shares) in fiscal 1993. The average number of outstanding shares rose primarily because of the May 1993 sale of 5.9 million Class B shares. 33
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Exploration and Production earnings rose substantially in fiscal 1994 due to sharply higher natural gas volumes and prices, including the impact of the previously mentioned buy-out of MEC Development, Ltd., effective May 1, 1993. More than offsetting these gains, however, were sharply lower earnings for Transmission and Processing operations, particularly in the second half of the year. Gas processing margins were adversely affected by declining NGL sales prices and rising market-sensitive natural gas feedstock costs under keep-whole processing agreements. The following table and discussion identify and explain the major increases (decreases) in earnings (in millions): [Enlarge/Download Table] Segment Operating Earnings -------------------------------- Trans- Exploration mission and and Real Pretax Net Production Processing Estate Other* Earnings Earnings ---------- ---------- ------ ------ -------- -------- FISCAL 1993 AMOUNTS . . . . . . . . . . . . . $22.6 $ 88.5 $22.8 $(86.6) $ 47.3 $ 18.5 ADD BACK FISCAL 1993 UNUSUAL ITEMS Restructuring charges . . . . . . . . . . . . 20.7 -- -- .5 21.2 13.7 Extraordinary item . . . . . . . . . . . . . -- -- -- -- -- 7.3 Cumulative effect of change in accounting methods . . . . . . . . . . . -- -- -- -- -- 10.5 ----- ------ ----- ------ ------ ------ FISCAL 1993 AMOUNTS BEFORE UNUSUAL ITEMS . . . . . . . . . . . 43.3 88.5 22.8 (86.1) 68.5 50.0 ----- ------ ----- ------ ------ ------ MAJOR INCREASES (DECREASES) Natural gas Sales under fixed-price contracts . . . . . 9.6 -- -- -- 9.6 6.2 Market-sensitive sales . . . . . . . . . . 16.1 -- -- -- 16.1 10.5 Oil and condensate sales . . . . . . . . . . (3.2) -- -- -- (3.2) (2.1) Oil and gas DD&A rate increase . . . . . . . (8.3) -- -- -- (8.3) (5.4) Gas processing NGL price . . . . . . . . . . . . . . . . . -- (16.4) -- -- (16.4) (10.7) Marketing activities . . . . . . . . . . . -- (6.9) -- -- (6.9) (4.5) Increased cost of sales . . . . . . . . . . -- (10.6) -- -- (10.6) (6.9) Full year's ownership of C&L Processors' (C&L) plants . . . . . . . . -- 3.0 -- -- 3.0 2.0 Production volumes (excluding impact of C&L plant acquisitions) . . . . -- (1.9) -- -- (1.9) (1.2) Gas gathering and transmission . . . . . . . -- (6.6) -- -- (6.6) (4.3) Real estate . . . . . . . . . . . . . . . . . -- -- (1.1) -- (1.1) (.7) Interest expense incurred . . . . . . . . . . -- -- -- 1.2 1.2 .8 Other Recognition of previously deferred natural gas revenues . . . . . . 3.9 -- -- -- 3.9 2.5 Excise tax refunds . . . . . . . . . . . . 1.0 -- -- 1.9 2.9 1.9 Contingent liability reversal . . . . . . . 1.9 -- -- -- 1.9 1.2 SAR/Bonus unit expense accruals . . . . . . (1.0) (.4) (.6) (1.1) (3.1) (2.0) Miscellaneous . . . . . . . . . . . . . . . 3.3 (6.1) -- 1.3 (1.5) (1.2) ----- ------ ----- ------ ------ ------ 23.3 (45.9) (1.7) 3.3 (21.0) (13.9) ----- ------ ----- ------ ------ ------ FISCAL 1994 AMOUNTS BEFORE UNUSUAL ITEMS . . . . . . . . . . . 66.6 42.6 21.1 (82.8) 47.5 36.1 FISCAL 1994 UNUSUAL ITEMS Deferred income tax charge due to increased statutory tax rate . . . . . . -- -- -- -- -- (11.0) Extraordinary item . . . . . . . . . . . . . -- -- -- -- -- (5.4) ----- ------ ----- ------ ------ ------ FISCAL 1994 AMOUNTS AFTER UNUSUAL ITEMS . . . . . . . . . . . . $66.6 $ 42.6 $21.1 $(82.8) $ 47.5 $ 19.7 ===== ====== ===== ====== ====== ====== ------------------------- * Includes general and administrative expense and other expense. 34
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FISCAL 1993 UNUSUAL ITEMS Restructuring charges. Pretax restructuring charges of approximately $21.2 million ($8.0 million of cash costs and $13.2 million of additional DD&A and asset write-downs) were recorded in the first quarter of fiscal 1993, all but $0.5 million of which were related to a reorganization of oil and gas exploration and production activities. See Note 9 of Notes to Consolidated Financial Statements for additional information. Extraordinary item. On April 13, 1992, the Company completed the early retirement of its $250 million of 11 1/4% Senior Notes Due 1997. The redemption price was 103.21% of principal, and the premium and related unamortized debt issuance costs were expensed, resulting in an extraordinary loss of $7.3 million (after tax benefit of $3.7 million). Cumulative effect of change in accounting methods. Effective February 1, 1992, the Company adopted SFAS No. 106 concerning postretirement medical benefits by recording, as the cumulative effect of a change in accounting methods, prior-service cost of $15.9 million. After a tax benefit of $5.4 million, this reduced fiscal 1993's net earnings by $10.5 million. EXPLORATION AND PRODUCTION OVERVIEW Excluding the effect of the prior year's restructuring charges, Exploration and Production Division operating earnings rose by $23.3 million in fiscal 1994, to $66.6 million. Because of improved natural gas market conditions and acquisitions of all remaining interests in MEC Development, Ltd., properties, average daily natural gas sales volumes totaled 193,800 Mcf, up from 149,000 in fiscal 1993. For the fourth quarter, such sales averaged 217,400 Mcf per day, up 36% from the prior-year period's 159,400. Natural Gas - Sales under fixed-price contracts ($9.6 million increase). Production under fixed-price contracts averaged 101,700 Mcf per day at a price of $3.52 per Mcf during fiscal 1994; such amounts were 85,300 and $3.54, respectively, during the prior year. The volume increase was largely the result of the acquisition in December 1992 of additional interests in producing properties that had been owned by MEC Development, Ltd., and the buy-out of the limited partner's remaining interests in May 1993. The average sales price received for contract natural gas was virtually the same as last year's average. This was because the positive impact of a $.25 per MMBtu annual increase under the sales contract with Natural Gas Pipeline Company of America ("NGPL") covering most of the Company's North Texas production was essentially offset by lower realizations for leasehold natural gas liquids and reduced amortization of deferred restructuring proceeds associated with the NGPL contract. Natural Gas - Market-sensitive sales ($16.1 million increase). The average sales price received by the Company for market-sensitive gas during fiscal 1994 was $2.14 per Mcf, up 13% from the previous year's $1.90. Production volumes rose 45% to 92,100 Mcf per day. The previously discussed acquisitions of partnership interests contributed to the higher volumes. Also, because of the improved pricing for market-sensitive gas, most of the Company's properties were at full production during fiscal 1994; production had been curtailed during the first half of fiscal 1993 in response to depressed prices. Oil and condensate sales ($3.2 million decrease). Fiscal 1994's average sales price for oil and condensate of $16.31 per barrel was down 12% from the $18.49 of the prior year, reducing operating earnings by $4.6 million. Oil prices declined substantially during the last half of fiscal 1994 as world oil prices fell, and the Company's average price for the fourth quarter of $13.82 was substantially below the full-year average. Partially offsetting the effect of the lower prices was a 400 barrel-per-day increase in production volumes, which added $1.4 million to operating earnings. Oil and gas DD&A rate increase ($8.3 million decrease). The Company's overall DD&A rate rose during fiscal 1994 primarily because of the buy-out of MEC Development, Ltd. 35
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TRANSMISSION AND PROCESSING OVERVIEW Transmission and Processing operating earnings declined $45.9 million (52%) in fiscal 1994 principally because of sharply lower gas processing margins and reduced earnings from gas gathering and transmission operations. NGL production volumes averaged 49,800 Bbls per day, up from 47,200 during fiscal 1993 because of the previously reported acquisition by a 50% owned partnership of interests in 13 plants effective August 1, 1992, which more than offset volume declines at other plants. Gas Processing - NGL price ($16.4 million decrease). The average price for NGLs produced during fiscal 1994 declined $1.23 per Bbl to $12.18, reducing operating earnings by $16.4 million. As previously discussed, NGL prices fell particularly in the last half of fiscal 1994, and the average price for the fourth quarter of $10.59 per barrel was substantially below the average for the full year. Gas Processing - Marketing activities ($6.9 million decrease). Because of a time lag between the production of unfractionated NGLs and the sale of the fractionated products (propane, ethane, etc.), the Company's marketing activities generally benefit from a rising trend in NGL prices and absorb losses when such prices decline. Principally because NGL prices declined during much of fiscal 1994 after increasing during most of the previous year, a $6.9 million unfavorable year-to-year operating earnings variance for marketing activities was reported. Gas Processing - Increased cost of sales ($10.6 million decrease). Gas processing cost of sales consists principally of amounts paid to owners of processed natural gas. Such amounts are based either on the value of natural gas consumed in processing under keep-whole agreements or on a percentage of the value of NGLs produced under percent-of-proceeds agreements. Costs under keep-whole contracts rose substantially during fiscal 1994 because of the previously mentioned increase in market-sensitive natural gas prices. Also contributing to the year-to-year rise in costs was the fact that in fiscal 1993 the Company successfully used futures-market transactions to fix the price on a portion of its natural gas feedstock requirements, reducing its fiscal 1993 costs by $3.5 million; there were no such transactions in fiscal 1994. Gas Processing - Full year's ownership of C&L Processors' plants ($3.0 million increase). The acquisition by C&L Processors, a 50% owned partnership, of interests in 13 gas processing plants effective August 1, 1992 added $3.0 million to the Company's gas processing operating earnings during the first half of fiscal 1994 (the period for which its results were not included in the prior year). Since the partnership is accounted for on an equity basis, these earnings are after all expenses, including interest charges, which were substantial since the acquisition was funded entirely by partnership borrowings. Gas Processing - Production volumes, excluding impact of C&L plant acquisitions ($1.9 million decrease). For plants other than those owned by C&L Processors, the Company's average daily production volumes during fiscal 1994 totaled 41,700 barrels per day - 1,100 barrels per day below their prior-year level. The reduced fiscal 1994 production of these plants, which lowered operating earnings by $1.9 million, was principally the result of lesser throughput for certain plants because of normal production declines for natural gas wells in their service areas and the temporary shut-down of other plants beginning in the fourth quarter because of inadequate processing margins. Gas Gathering and Transmission ($6.6 million decrease). Excluding the effect of increased SAR/Bonus unit expense accruals, fiscal 1994 operating earnings from gas gathering and transmission activities were $6.6 million below those of the prior year. The principal causes of this decline were lower margins for the wholly owned Winnie Pipeline system and for two 45% owned partnerships with Union Pacific Resources Company (UPRC). Winnie's margins were lower primarily because of the required renegotiation of certain contracts in the first quarter of calendar 1993 (when market-sensitive natural gas prices rose to a level exceeding the equivalent price for fuel oil) and because of volume declines caused by certain contract terminations which occurred late in fiscal 1993. The margin decline for the pipeline partnerships was largely the result of changes in certain contracts (see page 33 for additional information). Partially offsetting the effect of reduced pipeline margins were increased fiscal 1994 earnings from the marketing of "off-system" natural gas. 36
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REAL ESTATE AND OTHER Real estate ($1.1 million decrease). Excluding the effect of increased SAR/Bonus unit expense accruals, Real Estate Division operating earnings during fiscal 1994 were $1.1 million below those of the prior year. The absence in fiscal 1994 of a commercial property transaction similar to last year's sale of a half interest in the Panther Creek Retail Center, sharply lower sales of resort lots and a 7% decline in residential lot sales in The Woodlands contributed to the lower earnings. Largely offsetting the negative impact of these items were increased profits from sales of commercial and institutional land in The Woodlands. Largely because of the flat Houston economy, fiscal 1994 resort lot sales declined sharply from the prior-year level. While The Woodlands continued to lead the Houston area in home sales, the Company sold 844 residential lots to builders in fiscal 1994, down from 911 during the prior year. This decline occurred both because of softness in the Houston-area market (due to reduced growth in jobs and fewer corporate relocations) and as a result of slowed lot development in The Woodlands, which caused shortages in certain categories of lot inventories during the first half of the year. Lot sales improved during the second half of fiscal 1994 due, in part, to low interest rates and to the offering by home builders of a broader range of housing products. Operating earnings from sales of commercial and institutional acreage in The Woodlands rose substantially in fiscal 1994 when the Company sold 144 acres of such land (versus 58 acres in the previous year). Revenues from such transactions rose by $8.2 million, to $13.3 million, both as a result of the increased volume and because the average sales price was higher since a larger portion of the activity involved prime retail sites. Interest expense incurred. Interest expense incurred, excluding amounts reported as cost of sales for finance operations, totaled $74.1 million during fiscal 1994, down $1.2 million from the prior-year amount. This reduction was caused by a decline in the Company's average effective interest rate to 7.7% from 8.1%. Contributing to the rate decline were the refunding at 9 1/4% in April 1992 of $250 million of 11 1/4% fixed-rate notes and lower market rates for short-term obligations. The beneficial impact of the lower interest rates was partially offset by an increase in the Company's average debt balance and a decrease in the percentage of lower-priced, floating-rate debt because of the sale of $100 million of 8% Senior Notes in July 1992. Other - Recognition of previously deferred natural gas revenues ($3.9 million increase). During the second quarter of fiscal 1994, the Company recognized certain natural gas revenues which previously had been deferred because of future obligations for which the Company is no longer expected to be liable. Other - Excise tax refunds ($2.9 million increase). During the fourth quarter of fiscal 1994, the Company recognized excise tax refunds applicable to prior years, of which $1.0 million was for taxes previously charged to oil and gas operating earnings and $1.9 million was for accrued interest on such tax overpayments. Other - Contingent liability reversal ($1.9 million increase). During the first quarter of fiscal 1994, a contingent liability related to contractual matters was reversed when it was determined that this liability - which had been recorded several years ago - was no longer needed. Other - SAR/Bonus unit expense accruals ($3.1 million decrease). Expense accruals for SARs/Bonus units were substantially higher in fiscal 1994 because of larger year-to-year per share rises in the Company's common stock prices ($4.38 for Class A shares and $5.63 for Class B shares versus $2.13 and $1.25 in the prior year). Also contributing to this expense increase were exercises at higher mid-year prices of options and bonus units, many of which had January 1994 expiration dates. 37
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FISCAL 1994 UNUSUAL ITEMS Deferred tax charge due to increased Federal income tax rate. Deferred Federal income tax expense for the third quarter of fiscal 1994 included $11 million attributable to an increase enacted in August 1993 in the corporate statutory Federal income tax rate from 34% to 35%. Because of the rate change, it was necessary to increase the Company's deferred tax liability by an amount equal to 1% of the aggregate cumulative difference between the book and tax bases of its assets and liabilities. Extraordinary item. In January 1994, the Company called for redemption its $200 million of 11 1/4% Senior Notes Due 1999. The redemption price was 103.21% of principal, and the premium and related unamortized debt issuance costs were expensed, resulting in an extraordinary loss on the early retirement of debt of $5.4 million (after tax benefits of $2.9 million). QUARTERLY FINANCIAL DATA (UNAUDITED) MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES (in thousands except per share data) [Enlarge/Download Table] First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- FISCAL 1994 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $230,846 $243,652 $247,418 $230,893 Segment operating earnings . . . . . . . . . . . . . . . . 36,389 37,679 30,467 25,785 Earnings (loss) before extraordinary item . . . . . . . . . 10,289 10,751 (1,964)(a) 6,037 Extraordinary item (early retirement of $200 million of senior notes) . . . . . . . . . . . . -- -- -- (5,426) Net earnings (loss) . . . . . . . . . . . . . . . . . . . . 10,289 10,751 (1,964)(a) 611 Earnings per share Before extraordinary item . . . . . . . . . . . . . . . . .22 .21 (.04)(a) .11 Net earnings (loss) . . . . . . . . . . . . . . . . . . . .22 .21 (.04)(a) .01 FISCAL 1993 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $186,321 $214,911 $250,712 $250,890 Segment operating earnings . . . . . . . . . . . . . . . . 9,118(b) 35,815 45,121 43,843 Earnings (loss) before extraordinary item and cumulative effect of change in accounting methods . . . . . . . . . . . . . . (8,602)(b) 9,295 16,138 19,458 Extraordinary item (early retirement of $250 million of senior notes) . . . . . . . . . . . . (7,251) -- -- -- Cumulative effect of change in accounting methods (for post-retirement medical benefits) . . . . . (10,551) -- -- -- Net earnings (loss) . . . . . . . . . . . . . . . . . . . . (26,404) 9,295 16,138 19,458 Earnings per share Before extraordinary item and cumulative effect of change in accounting methods . . . . . . . . (.18) .20 .34 .41 Net earnings (loss) . . . . . . . . . . . . . . . . . . . (.56) .20 .34 .41 ------------------------- (a) During the third quarter of fiscal 1994, the Company recorded a deferred tax provision of $11 million as the result of an August 1993 increase in the corporate statutory Federal income tax rate from 34% to 35%. (b) During the first quarter of fiscal 1993, the Company recorded restructuring charges which reduced segment operating earnings by $20,726 and net earnings before extraordinary item and cumulative effect of change in accounting methods by $13,706. 38
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RESULTS OF OPERATIONS - FISCAL 1993 COMPARED WITH FISCAL 1992 The Company reported net earnings of $18.5 million ($.39 per share) for fiscal 1993. Absent the effect of the unusual items set forth below, net earnings for the period would have been $50 million ($1.07 per share). This compares with the $44.3 million ($.95 per share) earned during the prior year. The following table and discussion identify and explain the major increases (decreases) in earnings (in millions): [Enlarge/Download Table] Segment Operating Earnings -------------------------------- Trans- Exploration mission and and Real Pretax Net Production Processing Estate Other* Earnings Earnings ---------- ---------- ------ ------ -------- -------- FISCAL 1992 AMOUNTS . . . . . . . $ 41.3 $ 89.8 $ 22.7 $(85.5) $ 68.3 $ 44.3 ------ ------ ------ ------ ------ ------ MAJOR INCREASES (DECREASES) Natural gas Sales under fixed-price contracts . . . .3 -- -- -- .3 .2 Market-sensitive sales . . . . . . . . . 5.9 -- -- -- 5.9 3.9 Oil and gas DD&A rate increase . . . . . . (2.8) -- -- -- (2.8) (1.8) Gas processing Increased cost of sales . . . . . . . . -- (7.3) -- -- (7.3) (4.8) C&L Processors acquisition . . . . . . . -- 4.4 -- -- 4.4 2.9 Production volumes and operating expenses . . . . . . . . . . -- (3.5) -- -- (3.5) (2.3) Marketing activities . . . . . . . . . . -- 1.9 -- -- 1.9 1.2 Gas gathering and transmission . . . . . . -- 2.3 -- -- 2.3 1.5 Real estate . . . . . . . . . . . . . . . . -- -- .1 -- .1 .1 Interest expense incurred . . . . . . . . . -- -- -- 5.9 5.9 3.9 Interest capitalized . . . . . . . . . . . -- -- -- (3.2) (3.2) (2.1) General and administrative expense . . . . -- -- -- (3.2) (3.2) (2.1) Lower effective income tax rate . . . . . . -- -- -- -- -- 5.5 Other . . . . . . . . . . . . . . . . . . . (1.4) .9 -- (.1) (.6) (.4) ------ ------ ------ ------ ------ ------ 2.0 (1.3) .1 (.6) .2 5.7 ------ ------ ------ ------ ------ ------ FISCAL 1993 AMOUNTS BEFORE UNUSUAL ITEMS . . . . . . . . . . 43.3 88.5 22.8 (86.1) 68.5 50.0 ------ ------ ------ ------ ------ ------ UNUSUAL ITEMS (see page 35) Restructuring charges . . . . . . . . . . . (20.7) -- -- (.5) (21.2) (13.7) Extraordinary charge . . . . . . . . . . . -- -- -- -- -- (7.3) Cumulative effect of change in accounting methods . . . . . . . . . -- -- -- -- -- (10.5) ------ ------ ------ ------ ------ ------ (20.7) -- -- (.5) (21.2) (31.5) ------ ------ ------ ------ ------ ------ FISCAL 1993 AMOUNTS AFTER UNUSUAL ITEMS . . . . . . . . . . $ 22.6 $ 88.5 $ 22.8 $(86.6) $ 47.3 $ 18.5 ====== ====== ====== ====== ====== ====== ------------------------- * Includes general and administrative expense and other expense. EXPLORATION AND PRODUCTION OVERVIEW Exclusive of the restructuring charges, Exploration and Production Division operating earnings rose by $2.0 million in fiscal 1993, to $43.3 million. The Company's average daily natural gas sales volumes totaled 149,000 Mcf in fiscal 1993, down from 157,800 in the previous year, while the average sales price rose to $2.84 per Mcf from $2.74. Natural Gas - Sales under fixed-price contracts ($0.3 million increase). Because of offsetting year-to-year volume and price variances, the Company's operating earnings from natural gas sales under fixed-price contracts rose $0.3 million in fiscal 1993. An average of 85,300 Mcf per day of natural gas was produced by the Company under fixed-price contracts during fiscal 1993 at an average price of $3.54 per Mcf; such amounts were 96,100 and $3.43, respectively, in the prior year. The production decline, which reduced operating earnings 39
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by $5.3 million, resulted primarily from reduced quantities of North Texas production sold to NGPL and from lower contract sales in the Limestone County area. The higher average sales price, which was caused by the $.25 per MMBtu annual rate escalation for residue gas sales under the NGPL contract, increased operating earnings by $2.6 million. The production decline, of which 8,100 Mcf per day was in North Texas, resulted principally from the Company's decision to meet a larger portion of the NGPL contract volumes using natural gas purchased in that area, rather than production from the Company's wells. During fiscal 1993, such purchases and resales averaged 10,400 Mcf per day, roughly double the prior-year amount, and operating profits from such transactions rose by $3.0 million. Natural Gas - Market-sensitive sales ($5.9 million increase). During fiscal 1993, the Company's market-sensitive natural gas production volumes averaged 63,700 Mcf per day at an average price of $1.90 per Mcf, up from 61,700 and $1.65 in the prior year, increasing operating earnings by $5.9 million. After declining to as low as $1.00 per MMBtu at times during the first quarter, market-sensitive prices rose sharply over the remainder of the fiscal year as the market perceived that natural gas demand had, or soon would, come into balance with production capabilities. Because of the unacceptably low prices for market-sensitive production early in fiscal 1993, the Company limited such production to 45,700 Mcf per day in the first quarter. In response to subsequent price improvements, market-sensitive production volumes were increased, and for the fourth quarter such production averaged 74,400 Mcf per day. Oil and gas DD&A rate increase ($2.8 million decrease). The Company's DD&A rate per dollar of oil and gas revenue rose during fiscal 1993, reducing operating earnings by $2.8 million. TRANSMISSION AND PROCESSING OVERVIEW On an overall basis, Transmission and Processing Division operating earnings fell by $1.3 million, to $88.5 million, as a $4.5 million decline in gas processing earnings more than offset increases in earnings from gas gathering and transmission ($2.3 million) and other activities ($0.9 million). The Company produced an average of 47,200 barrels of NGLs per day during fiscal 1993 at an average price of $13.41 per barrel. In the prior year, these amounts were 44,000 barrels per day and $13.41 per barrel. Contributing to the increased production of NGLs in fiscal 1993 was the previously mentioned acquisition of interests in 13 plants by C&L Processors, which added 8,700 barrels to the Company's average daily production during the last half of fiscal 1993 (or 4,300 barrels per day to the full year's average). An increase from 30% to 45% in the Company's interest in the U. P. Bryan partnership effective November 1, 1991 also contributed to the higher production. The impact of this ownership increase would have been substantially greater, however, had this partnership's operations not been adversely affected by liquids pipeline curtailments - which continued through the fourth quarter - associated with an April 1992 explosion at an unaffiliated NGL storage facility. This had the effect of reducing production volumes since ethane, which constitutes approximately one-third of the NGL product stream, had to be "rejected" and sold as part of the natural gas stream. The annual volume gains attributable to these two partnerships were partially offset, however, by a production decline of 2,300 barrels per day for the Company's consolidated plants. These declines were principally the result of reduced plant inlet volumes caused by field declines, producer curtailments early in fiscal 1993 associated with depressed natural gas prices and the previously discussed lower North Texas natural gas production volumes. Gas Processing - Increased cost of sales ($7.3 million decrease). Gas processing cost of sales consists principally of amounts paid to the owners of processed natural gas. Such payments are based either on the value of the natural gas consumed in processing under keep-whole agreements or on a percentage of the value of NGLs produced under percent-of-proceeds agreements. Such costs rose $7.3 million during fiscal 1993, both because of sharply higher prices for market-sensitive natural gas beginning in the second quarter and higher transportation costs for plants that were affected during much of fiscal 1993 by liquids pipeline curtailments, requiring production to be trucked, rather than moved through product pipelines. 40
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Gas Processing - C&L Processors acquisition ($4.4 million increase). The acquisition by C&L Processors, a newly formed 50%-owned entity, of interests in 13 gas processing plants effective August 1, 1992 added $4.4 million to fiscal 1993's gas processing operating earnings. Since the partnership is accounted for on an equity basis, this $4.4 million is after all expenses, including interest charges. Such charges were substantial since the acquisition was funded entirely using proceeds from partnership borrowings. Gas Processing - Production volumes and operating expenses ($3.5 million decrease). Operating earnings attributable to the production of gas processing plants other than those owned by C&L Processors fell by $3.5 million in fiscal 1993 due to the previously discussed declines in production volumes and to higher operating expenses, which were largely attributable to the Company's increased ownership interest in certain partnership plants. Gas Processing - Marketing activities ($1.9 million increase). Earnings attributable to NGL marketing activities increased by $1.9 million in fiscal 1993. Because of a time lag between the production of unfractionated NGLs - which are transferred to the Company's marketing department at market values during the period produced - and the sale of the fractionated products (propane, ethane, etc.), marketing activities generally benefit from a rising trend in NGL prices and absorb losses when such prices decline. Largely because of rising NGL prices during much of the year, fiscal 1993 marketing profits were $4.3 million above those of the prior year. Partially offsetting these added profits, however, was an unfavorable $2.4 million year-to-year variance in deferred profits. For financial statement purposes, profits applicable to NGL production inventoried by the marketing department must be deferred since it has not yet been sold to third parties. As a result, earnings are reduced in periods when inventories rise. Alternatively, when such volumes decrease, previously deferred profits are recognized, thereby increasing earnings. NGL inventories rose during fiscal 1993 after declining during the previous year. Because of this, profits of $0.7 million were deferred in the current year. Conversely, $1.7 million of previously deferred profits were recognized in fiscal 1992, resulting in the $2.4 million year-to-year operating earnings variance. Gas Gathering and Transmission ($2.3 million increase). Operating earnings from gas gathering and transmission activities totaled $25.5 million in fiscal 1993, $2.3 million above the prior-year amount. This improvement was attributable to a $5.8 million increase in the Company's equity in the earnings of the Ferguson-Burleson partnership, which resulted both from an increase in the Company's ownership percentage and from an expansion of the partnership's operations. Effective November 1, 1991, the Company increased its ownership interest from 30% to 45% by contributing certain pipeline assets to the partnership. The Ferguson-Burleson system serves an area in which the Company's partner, UPRC, has an active drilling program. Throughput of this system increased substantially because many wells were connected to it during fiscal 1993 and 1992. Partially offsetting the higher earnings of this partnership was a $3.5 million decline in the Company's earnings from its other pipeline systems, which occurred largely because of volume declines. The lower volumes occurred because of field declines, producer curtailments early in fiscal 1993 associated with depressed natural gas prices and a "loss" of volumes that resulted from the contribution to the Ferguson-Burleson partnership of assets that had been 100% owned. REAL ESTATE AND OTHER Real estate ($0.1 million increase). Real Estate Division fiscal 1993 operating earnings totaled $22.8 million, or $0.1 million more than those of the prior year. Operating earnings rose $2.1 million due to increased earnings from residential activities ($1.3 million) and Commercial and Investment Properties ("C&I") ($0.8 million). These increases were essentially offset, however, by a decrease in operating earnings of $2.0 million attributable to the lack of a transaction in the current year comparable to the sale of 565 acres of undeveloped property in Colorado, which contributed $1.7 million to fiscal 1992's operating earnings, and to a decline of $0.3 million in earnings from other activities. 41
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Residential lot sales in The Woodlands totaled 911 in fiscal 1993, substantially unchanged from fiscal 1992's level. Profits from such sales rose $1.3 million, however, largely because of a 5% increase in the average sales price. The improvement in C&I operating earnings of $0.8 million was principally due to increased earnings from hospitality operations (primarily The Woodlands Executive Conference Center and Resort), office buildings and retail properties. Gains from sales of commercial properties contributed approximately $2.0 million to real estate operating earnings in each of fiscal 1993 and 1992. Interest expense incurred. Interest expense, excluding amounts reported as cost of sales for finance operations, totaled $75.3 million during fiscal 1993, down $5.9 million from the prior-year amount due to lower effective interest rates ($13.3 million) offset by an increase in the average debt balance ($7.4 million). Contributing to the decline in the Company's average effective interest rate (from 9.5% to 8.1%) were substantially lower market rates for short-term obligations in fiscal 1993 as well as the refunding during April 1992--at a 2% lower rate--of $250 million of 11 1/4% Senior Notes. Partially offsetting the beneficial impact of the lower interest rates was an increase in the Company's average debt balance, which raised interest expense by $7.4 million. Although the Company's long-term debt balance at January 31, 1993 was below the level at the beginning of the year, the average balance of debt outstanding during fiscal 1993 was substantially above the prior year's average. This occurred largely because of the timing of the closing of certain major transactions. In fiscal 1993, several major transactions were completed during the fourth quarter; whereas in the prior year such transactions were spread fairly evenly over the year. Interest capitalized. Because of the Company's lower effective interest rate, interest capitalized declined by $3.2 million in fiscal 1993, even after increases in the average balances of energy and real estate assets subject to capitalization. General and administrative expense. General and administrative expense increased in fiscal 1993 principally as the result of inflationary increases in payroll and other costs. Also contributing to the higher costs were increased charges for incentive compensation and for increased SAR/Bonus unit expense accruals because of a rise in the Company's stock price during fiscal 1993. Lower effective income tax rate. The Company's effective tax rate in fiscal 1993 of 23.3% was down sharply from the 35.1% rate of the prior year for several reasons, the largest of which was the reversal of certain prior-year Texas franchise tax accruals that reduced income taxes by $3.5 million. See Note 5 of Notes to Consolidated Financial Statements for reconciliations between the statutory rate and the Company's effective tax rate for these periods and for additional information concerning the major items which contributed to the year-to-year reduction in the Company's effective tax rate. 42
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QUARTERLY STOCK DATA MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES (dollars per share) [Enlarge/Download Table] First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- ------- FISCAL 1994 Class A--Market price High . . . . . . . . . . . . . . . . . . . . . $ 25 1/2 $ 27 1/8 $ 29 5/8 $ 24 1/2 Low . . . . . . . . . . . . . . . . . . . . . 17 21 24 1/4 17 3/4 Cash dividends . . . . . . . . . . . . . . . . . .12 .12 .12 .12 Class B--Market price High . . . . . . . . . . . . . . . . . . . . . 23 27 3/8 27 1/4 22 Low . . . . . . . . . . . . . . . . . . . . . 16 1/8 20 3/8 21 1/8 16 1/8 Cash dividends . . . . . . . . . . . . . . . . . .1325 .1325 .1325 .1325 FISCAL 1993 Prior to Reclassification Market price High . . . . . . . . . . . . . . . . . . . . . $ 16 7/8 $ 17 1/2 Low . . . . . . . . . . . . . . . . . . . . . 14 1/4 14 3/4 Cash dividends . . . . . . . . . . . . . . . . . .10 .10 Class A--Market price High . . . . . . . . . . . . . . . . . . . . . 17 1/2 $ 19 5/8 $ 19 1/4 Low . . . . . . . . . . . . . . . . . . . . . 13 5/8 16 3/4 16 Cash dividends . . . . . . . . . . . . . . . . . -- .10 .12 Class B--Market price High . . . . . . . . . . . . . . . . . . . . . 17 1/8 18 5/8 17 5/8 Low . . . . . . . . . . . . . . . . . . . . . 13 16 1/4 14 1/8 Cash dividends . . . . . . . . . . . . . . . . . -- .1050 .1325 43
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CONSOLIDATED BALANCE SHEETS MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES JANUARY 31, 1994 AND 1993 (dollar amounts in thousands) [Enlarge/Download Table] 1994 1993 ---- ---- ASSETS CURRENT ASSETS Cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,832 $ 28,097 Trade receivables, net of allowance for doubtful accounts of $2,720 and $2,004 . . . . . . . . . . . . . . . . . . . . 134,570 143,080 Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,400 19,672 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,123 10,795 ---------- ---------- Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188,925 201,644 ---------- ---------- PROPERTY, PLANT AND EQUIPMENT, AT COST Oil and gas properties, full cost method of accounting Costs being amortized . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,907,799 1,736,926 Costs not being amortized . . . . . . . . . . . . . . . . . . . . . . . . . . 50,389 40,957 Transmission and processing facilities . . . . . . . . . . . . . . . . . . . . . 561,605 540,984 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175,825 180,713 ---------- ---------- 2,695,618 2,499,580 Less - accumulated depreciation, depletion and amortization . . . . . . . . . . 1,390,729 1,315,800 ---------- ---------- 1,304,889 1,183,780 ---------- ---------- REAL ESTATE (Note 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 896,652 864,351 ---------- ---------- OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,010 22,024 ---------- ---------- $2,415,476 $2,271,799 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,955 $ 10,635 Oil and gas proceeds payable . . . . . . . . . . . . . . . . . . . . . . . . . . 64,110 69,163 Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92,895 94,303 Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,156 45,960 ---------- ---------- Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 217,116 220,061 ---------- ---------- LONG-TERM DEBT (Note 4) Energy operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 486,066 448,883 Real estate operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 502,252 498,840 ---------- ---------- 988,318 947,723 ---------- ---------- DEFERRED CREDITS AND OTHER LIABILITIES Deferred income taxes (Note 5) . . . . . . . . . . . . . . . . . . . . . . . . . 339,456 330,763 Natural gas contract restructuring proceeds . . . . . . . . . . . . . . . . . . 51,527 69,908 Deferred income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,731 34,871 Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36,374 36,421 ---------- ---------- 458,088 471,963 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 3 and 6) STOCKHOLDERS' EQUITY (Notes 7 and 10) Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued) Common stock, $.10 par value (authorized 100,000,000 Class A and 100,000,000 Class B shares) . . . . . . . 5,386 4,796 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . 143,440 20,347 Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 617,214 623,469 Treasury stock, at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . (14,086) (16,560) ---------- ---------- 751,954 632,052 ---------- ---------- $2,415,476 $2,271,799 ========== ========== ------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements. 44
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CONSOLIDATED STATEMENTS OF EARNINGS MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES FOR THE YEARS ENDED JANUARY 31, 1994, 1993 AND 1992 (in thousands except per share amounts) [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- REVENUES Exploration and production . . . . . . . . . . . . . . . . . . . . . . $266,166 $214,681 $231,073 Transmission and processing . . . . . . . . . . . . . . . . . . . . . 560,537 566,700 511,979 Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126,106 121,453 131,318 -------- -------- -------- 952,809 902,834 874,370 -------- -------- -------- OPERATING COSTS AND EXPENSES (including DD&A) (Note 9) Exploration and production (including restructuring charges of $20,726 in 1993). . . . . . . . . . . . . . 199,583 192,089 189,809 Transmission and processing . . . . . . . . . . . . . . . . . . . . . 517,878 478,196 422,122 Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105,028 98,652 108,594 -------- -------- -------- 822,489 768,937 720,525 -------- -------- -------- SEGMENT OPERATING EARNINGS (Note 9). . . . . . . . . . . . . . . . . . 130,320 133,897 153,845 General and administrative expense . . . . . . . . . . . . . . . . . . 43,222 41,398 38,184 -------- -------- -------- TOTAL OPERATING EARNINGS . . . . . . . . . . . . . . . . . . . . . . . 87,098 92,499 115,661 -------- -------- -------- OTHER EXPENSE Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . 74,057 75,284 81,169 Capitalized interest . . . . . . . . . . . . . . . . . . . . . . . . . (35,721) (36,205) (39,426) Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,224 6,096 5,618 -------- -------- -------- 39,560 45,175 47,361 -------- -------- -------- EARNINGS BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . . . . . 47,538 47,324 68,300 INCOME TAXES (including deferred tax charge of $11,000 in 1994 due to increase in corporate tax rate) (Note 5) . . . . . . 22,425 11,035 23,954 -------- -------- -------- EARNINGS BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . . . . . . . . . . . . . 25,113 36,289 44,346 EXTRAORDINARY ITEM - LOSS FROM EARLY RETIREMENT OF DEBT (net of tax benefit of $2,921 and $3,736) (Note 4) . . . . . (5,426) (7,251) -- CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS (net of tax benefit of $5,435) (Note 11) . . . . . . . . . . -- (10,551) -- -------- -------- -------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 19,687 $ 18,487 $ 44,346 ======== ======== ======== EARNINGS PER SHARE Earnings before extraordinary item and cumu- lative effect of change in accounting methods . . . . . . . . . . . $ .49 $ .77 $ .95 Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . . . . (.10) (.15) -- Cumulative effect of change in accounting methods . . . . . . . . . . -- (.23) -- -------- -------- -------- Net earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ .39 $ .39 $ .95 ======== ======== ======== AVERAGE COMMON SHARES OUTSTANDING (including both Class A and Class B shares effective with the reclassi- fication of the common stock in June 1992) (Note 7) . . . . . . . . 51,004 46,858 46,849 ======== ======== ======== ------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements. 45
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CONSOLIDATED STATEMENTS OF CASH FLOWS MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES FOR THE YEARS ENDED JANUARY 31, 1994, 1993 AND 1992 (in thousands) [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- OPERATING ACTIVITIES Earnings before extraordinary item and cumu- lative effect of change in accounting methods . . . . . . . . . . . $ 25,113 $ 36,289 $ 44,346 Adjustments to reconcile earnings before extraordinary item and cumulative effect of change in accounting methods to cash provided by operating activities Depreciation, depletion and amortization . . . . . . . . . . . . 153,245 133,029 128,084 Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . 10,432 3,698 10,976 Cost of land sold . . . . . . . . . . . . . . . . . . . . . . . . 33,367 28,424 36,446 Residential land development costs, net of reimbursements . . . . . . . . . . . . . . . . . (14,303) (17,333) (19,292) Partnership distributions in excess of (less than) earnings . . . 13,849 (16,832) (12,268) Amortization of deferred natural gas contract restructuring proceeds . . . . . . . . . . . . . . . . (18,723) (20,360) (26,698) Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,972) 5,887 383 --------- --------- --------- 198,008 152,802 161,977 Changes in operating assets and liabilities Trade receivables . . . . . . . . . . . . . . . . . . . . . . . 4,071 (3,089) (3,843) Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . (1,728) 2,754 (2,329) Payables . . . . . . . . . . . . . . . . . . . . . . . . . . . (29,075) 17,895 (12,404) Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . -- (3,308) (10,961) Accrued liabilities and other . . . . . . . . . . . . . . . . . (1,469) 3,629 (4,118) --------- --------- --------- Cash provided by operating activities . . . . . . . . . . . . . . 169,807 170,683 128,322 --------- --------- --------- INVESTING ACTIVITIES Capital additions Total on accrual basis . . . . . . . . . . . . . . . . . . . . . . . (355,845) (237,668) (223,612) Residential land development costs deducted above . . . . . . . . . 14,303 17,333 19,292 Adjustment to cash basis . . . . . . . . . . . . . . . . . . . . . . 21,125 (206) (1,100) --------- --------- --------- (320,417) (220,541) (205,420) Proceeds from sales of commercial properties . . . . . . . . . . . . . -- 27,129 13,428 Proceeds from sale of notes receivable . . . . . . . . . . . . . . . . -- 20,095 -- Proceeds from dispositions of property, plant and equipment . . . . . 8,625 5,855 1,191 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (286) 6,119 1,186 --------- --------- --------- Cash used for investing activities. . . . . . . . . . . . . . . . (312,078) (161,343) (189,615) --------- --------- --------- FINANCING ACTIVITIES Proceeds from issuance of debt . . . . . . . . . . . . . . . . . . . . 351,728 385,274 148,694 Debt repayments . . . . . . . . . . . . . . . . . . . . . . . . . . . (311,813) (381,243) (94,979) Net proceeds from issuance of common stock (Note 7) . . . . . . . . . 123,429 -- -- Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . (25,942) (20,097) (18,739) Debt prepayment premium . . . . . . . . . . . . . . . . . . . . . . . -- (8,025) -- Treasury stock purchases . . . . . . . . . . . . . . . . . . . . . . . -- (4,347) -- Senior note issuance costs . . . . . . . . . . . . . . . . . . . . . . (2,431) (4,249) -- Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,035 57 2,585 --------- --------- --------- Cash provided by (used for) financing activities. . . . . . . . . 136,006 (32,630) 37,561 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . (6,265) (23,290) (23,732) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR . . . . . . . . . . . . . 28,097 51,387 75,119 --------- --------- --------- CASH AND CASH EQUIVALENTS, END OF YEAR . . . . . . . . . . . . . . . . $ 21,832 $ 28,097 $ 51,387 ========= ========= ========= ------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements. 46
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES FOR THE YEARS ENDED JANUARY 31, 1994, 1993 AND 1992 (dollar amounts in thousands) [Enlarge/Download Table] Additional Common Paid-in Retained Treasury Stock Capital Earnings Stock Total ------ ---------- -------- -------- ----- DOLLAR AMOUNTS BALANCE, JANUARY 31, 1991. . . . . . . . . . . . . $4,796 $ 20,344 $599,472 $(13,667) $610,945 Net earnings . . . . . . . . . . . . . . . . . . . -- -- 44,346 -- 44,346 Cash dividends (40 cents per share). . . . . . . . -- -- (18,739) -- (18,739) Exercises of stock options . . . . . . . . . . . . -- (53) -- 870 817 ------ -------- -------- -------- -------- BALANCE, JANUARY 31, 1992. . . . . . . . . . . . . 4,796 20,291 625,079 (12,797) 637,369 Net earnings . . . . . . . . . . . . . . . . . . . -- -- 18,487 -- 18,487 Cash dividends (20 cents per share prior to reclassification; 22 cents per share on Class A and 23.75 cents per share on Class B). . . . . . -- -- (20,097) -- (20,097) Purchase and cancellation of fractional shares . . -- (8) -- -- (8) Treasury stock purchases . . . . . . . . . . . . . -- -- -- (4,347) (4,347) Exercises of stock options . . . . . . . . . . . . -- 64 -- 584 648 ------ -------- -------- -------- -------- BALANCE, JANUARY 31, 1993 . . . . . . . . . . . . 4,796 20,347 623,469 (16,560) 632,052 Issuance of common stock (Note 7). . . . . . . . . 590 122,839 -- -- 123,429 Net earnings . . . . . . . . . . . . . . . . . . . -- -- 19,687 -- 19,687 Cash dividends (48 cents per share on Class A and 53 cents per share on Class B) . . . -- -- (25,942) -- (25,942) Exercises of stock options . . . . . . . . . . . . -- 254 -- 2,474 2,728 ------ -------- -------- -------- -------- BALANCE, JANUARY 31, 1994 . . . . . . . . . . . . $5,386 $143,440 $617,214 $(14,086) $751,954 ====== ======== ======== ======== ======== [Enlarge/Download Table] Common Stock Issued Treasury Stock --------------------------------------- ------------------------------------ Prior to Prior to Reclassi- Reclassi- fication Class A Class B fication Class A Class B --------- ------- ------- --------- ------- ------- SHARE AMOUNTS BALANCE, JANUARY 31, 1991. . . . . . 47,956,869 1,131,684 Exercises of stock options . . . . . -- (74,147) ---------- --------- BALANCE, JANUARY 31, 1992. . . . . . 47,956,869 1,057,537 Exercises of stock options . . . . . -- (23,600) Reclassification of stock. . . . . . (47,956,292) 23,978,146 23,978,146 (1,033,936) 516,968 516,968 Cancellation of fractional shares. . . . . . . . . (577) -- -- (1) Exercises of stock options . . . . . -- -- -- -- (13,000) (11,200) Treasury stock purchases . . . . . . -- -- -- -- 15,000 281,600 ----------- ---------- ---------- ---------- ------- ------- BALANCE, JANUARY 31, 1993. . . . . . -- 23,978,146 23,978,146 -- 518,968 787,368 =========== ========== Issuance of common stock . . . . . . -- 5,900,000 -- -- Exercises of stock options . . . . . -- -- (101,138) (94,887) Other . . . . . . . . . . . . . . . (29) (29) (353) (353) ---------- ---------- ------- ------- BALANCE, JANUARY 31, 1994. . . . . . 23,978,117 29,878,117 417,477 692,128 ========== ========== ======= ======= ------------------------------------------------------------------------------- The accompanying notes are an integral part of these financial statements 47
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Notes to Consolidated Financial Statements Mitchell Energy & Development Corp. and Subsidiaries January 31, 1994, 1993 and 1992 (1) Summary of Significant Accounting Policies Principles of consolidation. The consolidated financial statements include the accounts of Mitchell Energy & Development Corp. and its majority-owned subsidiaries (the "Company"). All significant intercompany accounts and transactions are eliminated in consolidation. The Company follows the equity method of accounting for investments in 20% to 50% owned entities. The Company's net investment in each of these entities is included in the applicable segment's asset caption of the consolidated balance sheets, and its equity in the pretax earnings or losses of each entity is included in the applicable caption of revenues or operating costs and expenses of the consolidated statements of earnings. Property, plant and equipment. The Company follows the full cost method of accounting for oil and gas properties. All costs associated with the acquisition, exploration and development of oil and gas properties, including nonproductive costs, are capitalized. Properties are considered to be unevaluated until a determination of the quantity of proved reserves attributable to the property can be made. Unless impairment has occurred, the cost of unevaluated properties is excluded from the amortization base. Amortization is provided on the unit-of-production method based on future gross revenues. Volumes of oil and gas are converted to common units on the basis of future gross revenues computed using current market prices except where otherwise specified by contractual agreement. Amortization per dollar of oil and gas revenue was $.48 in fiscal 1994, 1993 and 1992. An analysis of the capitalized costs of unevaluated properties excluded from the full cost amortization base at January 31, 1994 follows (in thousands): [Enlarge/Download Table] Fiscal Year During Which Incurred Total ---------------------------------------- Costs 1994 1993 1992 Prior ----- ---- ---- ---- ----- Lease acquisitions . . . . . . . . . $16,221 $ 6,333 $4,130 $3,568 $2,190 Exploration . . . . . . . . . . . . . 30,113 22,488 2,978 3,091 1,556 Capitalized interest . . . . . . . . 4,055 2,014 1,186 683 172 ------- ------- ------ ------ ------ $50,389 $30,835 $8,294 $7,342 $3,918 ======= ======= ====== ====== ====== The Company expects that the majority of these costs will be added to the amortization base over the next four years as reserve determinations are made or impairment occurs. Depreciation of natural gas processing plants, gas transmission facilities and other property is generally provided on the straight-line method over estimated service lives of 12 to 24; 5 to 25 and 3 to 25 years, respectively. Real estate operations. Costs associated with the acquisition and development of real estate, including holding costs, are capitalized as incurred. Capitalization of holding costs, principally interest and ad valorem taxes, is limited to properties for which active development continues. Where practicable, capitalized costs are specifically assigned to individual assets; otherwise, such costs are allocated based on estimated values of the affected assets. Depreciable real estate assets are depreciated on the straight-line method over estimated useful lives ranging from three to fifty years. Real estate is carried at the lower of historical cost or estimated net realizable value. The impact of changes in economic conditions and other factors on the realizable values of real estate are regularly monitored and evaluated. The effect of any significant changes which adversely impact real estate carrying values are reported in earnings in the period such effect can be reasonably estimated. Earnings from sales of real estate are recognized when a buyer has made an adequate cash down payment and has attained the attributes of ownership. Notes received in connection with land sales are discounted when the stated purchase prices are significantly different from those which would have resulted from similar cash transactions. 48
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The cost of land sold is generally determined as a specific percentage of the sales revenues recognized for each land development project. These percentages are based on estimated development costs and sales revenues to completion for each project. The specific identification method is used to determine the cost of land sold for certain land parcels located outside The Woodlands. Because they represent the principal revenues and costs for these activities, interest income and interest expense of the Company's finance operations are reported, respectively, as revenues and costs and expenses in the consolidated statements of earnings. Deferred natural gas contract restructuring proceeds. The Company has deferred earnings recognition for certain natural gas contract restructuring proceeds. These deferred amounts are being amortized to earnings over the periods to which the consideration relates. Such amortization totaled $18,723,000; $20,360,000 and $26,698,000 in fiscal 1994, 1993 and 1992. Earnings per common share. Earnings per common share have been computed by dividing net earnings by the weighted average number of common shares outstanding during each period, which for periods subsequent to June 24, 1992 includes both Class A and Class B shares. After giving effect to the differing cash dividends paid on these shares, fiscal 1994 earnings per share before extraordinary item for the Class A and Class B shares were $.46 and $.52 (versus $.49 on a combined basis) while net earnings per share for each class were $.36 and $.40 (versus $.39 on a combined basis). The effect of the differing dividend payments was not significant to earnings per common share in fiscal 1993. The dilutive effect of outstanding stock options, which is less than 3%, has not been included in the earnings per share computations. Statements of Cash Flows. Short-term investments with maturities of three months or less are considered to be cash equivalents. Commercial paper and bank revolving credit agreement borrowings with terms of three months or less are excluded from the amounts reported as debt proceeds and repayments. Inter-est paid--excluding amounts capitalized, but including amounts reported as cost of sales for finance oper-ations--totaled $38,052,000; $40,556,000 and $45,143,000 during fiscal 1994, 1993 and 1992. Income taxes paid during these periods totaled $12,840,000; $6,619,000 and $11,248,000. There were no significant non-cash investing or financing activities during the three-year period ended January 31, 1994. (2) REAL ESTATE In accordance with industry accounting practice, real estate assets are reported as long-term assets in the consolidated balance sheets. Such assets consisted of the following at January 31, 1994 and 1993 (in thousands): [Download Table] 1994 1993 ---- ---- The Woodlands Land and improvements . . . . . . . . . . . . . . . . . $479,461 $463,461 Commercial properties, net of accumulated depreciation of $47,135 and $42,110 . . . . . . . . . 148,301 135,517 -------- -------- 627,762 598,978 Land held for investment, development or sale . . . . . . 159,949 159,712 Resort and other operating properties, net of accumulated depreciation of $7,648 and $6,807 . . . . . 65,956 65,574 Notes and contracts receivable, at cost, net of allowance for doubtfu accounts of $507 and $678 . . . . 42,985 40,087 -------- -------- $896,652 $864,351 ======== ======== The Company's real estate activities are concentrated in the area surrounding Houston, Texas. Consequently, these operations and the associated credit risks may be affected, either positively or negatively, by changes in economic conditions in this geographical area. The Company's principal real estate property is a master-planned community located north of Houston known as "The Woodlands," which is being developed on approximately 25,000 acres. Activities associated with this development 49
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include residential and commercial land sales; the construction and operation of office and industrial buildings, apartments, retail shopping centers, golf courses and a conference center and the mortgage banking operations of a wholly owned subsidiary, Mitchell Mortgage Company. Other real estate assets include large landholdings northwest of Houston and certain resort properties. (3) EQUITY INVESTMENTS Entities accounted for on the equity method include approximately 30 partnerships engaged in energy or real estate activities. The principal partnership interests included the following at January 31, 1994: [Enlarge/Download Table] Ownership Percentage Nature of Operations ---------- -------------------- ENERGY OPERATIONS Austin Chalk Natural Gas Marketing Services 45 Natural gas marketing Belvieu Environmental Fuels 33.33 Production of MTBE C&L Processors Partnership 50 Natural gas processing Ferguson-Burleson County Gas Gathering System 45 Gas gathering and transmission Gulf Coast Fractionators 38.75 Fractionation of natural gas liquids U. P. Bryan 45 Natural gas processing REAL ESTATE OPERATIONS The Fort Crockett Hotel Limited 50 Resort hotel in Galveston, Texas Lake Catamount Joint Venture 50 Land held for development The Woodlands Mall Associates 50 Regional mall in The Woodlands Other real estate partnerships own a cable television system located in The Woodlands and various commercial properties, most of which are located in The Woodlands. Summarized balance sheet information at January 31, 1994 and 1993 for all entities accounted for on the equity method follows (in thousands): [Enlarge/Download Table] 1994 1993 ---- ---- Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 83,764 $ 94,778 Net noncurrent assets Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 483,583 392,724 Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157,016 133,363 Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72,281 88,024 Debt (including current maturities of $25,514 and $32,367) Company's proportionate share Recourse to the Company . . . . . . . . . . . . . . . . . . . . . . . . . 118,705 53,553 Nonrecourse to the Company . . . . . . . . . . . . . . . . . . . . . . . 59,010 87,194 Other parties' proportionate share ($17,855 of which was guaranteed by the Company at January 31, 1994) . . . . . . . . . . . 245,797 166,449 -------- -------- 423,512 307,196 Notes payable to the Company . . . . . . . . . . . . . . . . . . . . . . . . 9,751 8,945 Deferred credits and other . . . . . . . . . . . . . . . . . . . . . . . . . 737 2,543 Owners' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218,082 214,157 Summarized earnings information for the years ended January 31, 1994, 1993 and 1992 for all entities accounted for on the equity method follows (in thousands): [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . $505,374 $494,297 $308,270 Operating earnings . . . . . . . . . . . . . . . . . . . . . . 71,271 106,630 85,917 Pretax earnings* . . . . . . . . . . . . . . . . . . . . . . . 56,837 93,586 75,337 Proportionate share of pretax earnings included in the Company's reported operating earnings . . . . . . . . 23,249 43,813 30,002 ------------------------- * Before interest expense for those entities whose activities are funded by capital contributions of the owners. 50
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Using a portion of the proceeds of a common stock offering (see Note 7), the Company purchased, effective May 1, 1993, the limited partner's interest in MEC Development, Ltd. for $52,585,000, from which the partner repaid its proportionate share of partnership debt. The Company also repaid its share of the partnership's debt of $25,666,000, and the partnership was liquidated. All reserves and other assets previously owned by the partnership are now held by the Company. Since this partnership was a significant contributor to the earnings reported in the above table, its removal from these results effective May 1, 1993 caused a significant portion of the fiscal 1994 earnings declines for these entities. The operations of many of these partnerships have been funded using term loans secured by their assets and in some cases by contractual commitments or guaranties of the partners. A summary of the outstanding indebtedness of these entities (excluding notes payable to the Company) at January 31, 1994 and 1993 follows (in thousands): [Enlarge/Download Table] The Company's Proportionate Share in 1994 Entity Total --------------------------- ------------------------- Recourse Nonrecourse 1994 1993 -------- ----------- -------- -------- ENERGY OPERATIONS Belvieu Environmental Fuels, $176 million . . . . $ 45,333 $ -- $136,000 $ 25,000 C&L Processors Partnership . . . . . . . . . . . 31,514 26,846 116,719 130,000 Gulf Coast Fractionators, $85 million . . . . . 24,897 -- 64,250 -- MEC Development, Ltd. . . . . . . . . . . . . . . -- -- -- 62,425 -------- ------- -------- -------- 101,744 26,846 316,969 217,425 -------- ------- -------- -------- REAL ESTATE OPERATIONS The Fort Crockett Hotel Limited . . . . . . . . . 4,168 2,030 12,397 13,172 The Woodlands Mall Associates, $65 million . . . 9,345 -- 18,689 -- Apartment partnerships . . . . . . . . . . . . . 1,178 14,610 37,728 32,363 Others . . . . . . . . . . . . . . . . . . . . . 2,270 15,524 37,729 44,236 -------- ------- -------- -------- 16,961 32,164 106,543 89,771 -------- ------- -------- -------- $118,705 $59,010 $423,512 $307,196 ======== ======= ======== ======== Belvieu Environmental Fuels is constructing a plant at Mont Belvieu, Texas, which is designed to produce 12,500 barrels per day of MTBE, a gasoline additive that reduces carbon monoxide emissions. The plant, which has an estimated cost of $220,000,000, is expected to begin production during the summer of 1994. Plant construction costs are being funded using proceeds of the partnership's loan agreement and equal capital contributions of the partners. The partnership's debt is nonrecourse to the partners except during the construction period when each partner has guaranteed its one-third share of the debt. The partnership has entered into agreements which require each of the three partners to provide one-third of the plant's isobutane feedstock and one of the partners, Sun Company, Inc., to purchase all of its production for a period of ten years. The Company and its partner, Conoco, Inc., have each agreed to make aggregate future cash contributions to C&L Processors Partnership of up to 27% of the partnership's loan balance should its operating cash flows not be sufficient to cover scheduled principal and interest payments. No such contributions were required through January 31, 1994. Gulf Coast Fractionators (GCF) executed an $85,000,000 bank term loan agreement in June 1993. The primary uses of the loan proceeds were to fund a $40,000,000 expansion of GCF's fractionator and $40,000,000 in cash distributions to the partners, of which the Company's share was $15,500,000. In connection with the 40,000-barrel-per-day expansion, Conoco, Inc. became a 22.5% owner of GCF, and the Company's ownership was reduced from 50% to 38.75%. Each of the three partners has guaranteed its pro rata share of the $40,000,000 expansion financing (until the plant is satisfactorily completed) and any shortfall in a $10,000,000 reserve fund until a specified financial ratio is met. After these requirements are satisfied, the debt will be nonrecourse to the partners. Each partner also has executed long-term contracts with GCF for the fractionation of production from certain of its gas processing plants. 51
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In connection with its guarantee of certain indebtedness of The Fort Crockett Hotel Limited partnership, the Company has agreed to make cash advances to fund the partnership's cash flow deficiencies until certain debt coverage tests are met. Such advances, which included funds for operations, debt retirement and capital improvements, aggregated $2,972,000; $4,747,000 and $2,943,000 during fiscal 1994, 1993 and 1992. The fiscal 1994 and 1993 advances included $469,000 and $2,884,000 to cover the costs of an expansion of the partnership's facilities. The principal loan agreements of this partnership include call provisions which could require these loans to be repaid at any time after December 1994. Based on preliminary discussions with the lenders, the Company expects these loans can be extended beyond their call dates. The Woodlands Mall Associates is a partnership owned equally by the Company and Homart Development Co., a wholly owned subsidiary of Sears, Roebuck and Co. It was formed to develop a one million square foot, regional shopping mall in The Woodlands. Construction began in June 1992, and it is anticipated that the mall will open in October 1994. On January 31, 1994, the partnership entered into a $65,000,000 five-year term loan, which is secured by the property and the joint and several guaranties of the partners. (4) LONG-TERM DEBT The Company's outstanding debt includes parent company borrowings, the proceeds of which have been advanced to the operating subsidiaries, as well as direct borrowings by certain subsidiaries. Allocation of the parent company advances among the subsidiaries changes in response to the specific financing needs of the subsidiaries and the parent company. A summary of outstanding long-term debt at January 31, 1994 and 1993 follows (in thousands): [Enlarge/Download Table] 1994 -------------------------------------- Real Energy Estate 1993 Operations Operations Total Total ---------- ---------- -------- -------- PARENT COMPANY SENIOR NOTES, UNSECURED 11 1/4% (redeemed in February 1994) . . . . . $200,000 $200,000 5.10%, due February 15, 1997 . . . . . . . . 100,000 -- 8%, due July 15, 1999 . . . . . . . . . . . 100,000 100,000 9 1/4%, due January 15, 2002 . . . . . . . . 250,000 250,000 6 3/4 %, due February 15, 2004 . . . . . . . 250,000 -- -------- -------- $446,386* $453,614* 900,000 550,000 SUBSIDIARY BORROWINGS Bank revolving credit agreements, unsecured Energy, $250 million . . . . . . . . . . . -- -- -- 76,000 Real estate, $165 million . . . . . . . . -- 19,000 19,000 113,000 Mitchell Mortgage Company, $18 million, at floating interest rates . . . . . . . -- 11,300 11,300 12,000 Commercial paper, at floating interest rates . . . . . . . . . . . . . . 9,680 12,320 22,000 124,763 Uncommitted money market facilities, at floating interest rates . . -- -- -- 35,000 Unsecured term loan, 7.98%, due in May 1997 . . . . . . . . . . . . . 30,000 -- 30,000 30,000 Mortgages, 10.4% average rate . . . . . . . -- 15,973 15,973 17,595 -------- -------- -------- -------- 486,066 512,207 998,273 958,358 Less - Amounts reported as short-term debt . . . . . . . . . . . . . . -- 9,955 9,955 10,635 -------- -------- -------- -------- $486,066 $502,252 $988,318 $947,723 ======== ======== ======== ======== ------------ *Intercompany loans from parent company. During January 1994, the parent company called for redemption its $200,000,000 of 11 1/4% Senior Notes Due 1999. This early redemption was completed on February 25, 1994 at a price of 103.21% of principal. The expensing of this premium and related unamortized debt issuance costs resulted in an extraordinary charge of $5,426,000 (after tax benefit of $2,921,000), which was recorded when the debt was called in January 1994. 52
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During January 1994, the parent company issued $250,000,000 of 6 3/4% Senior Notes Due 2004 and $100,000,000 of 5.10% Senior Notes Due 1997. Initially, the loan proceeds were advanced to the operating subsidiaries, which used them to pay down borrowings under their commercial paper and bank revolving credit agreements. In February 1994, the subsidiaries reborrowed a portion of the amounts temporarily paid down and advanced such funds to the parent company, which used them to fund the February 1994 debt redemption. On April 13, 1992, the parent company redeemed its $250,000,000 of 11 1/4% Senior Notes Due 1997 using the proceeds of a March 1992 offering of $250,000,000 of 9 1/4% Senior Notes Due 2002. This early redemption was completed at a price of 103.21% of principal, and the expensing of this premium and related unamortized debt issuance costs resulted in an extraordinary charge of $7,251,000 (after tax benefit of $3,736,000). Except for the notes which were redeemed in February 1994, the Company's senior notes have no sinking fund requirements and are not redeemable prior to their respective maturity dates. The terms of the Company's Energy and Real Estate bank revolving credit facilities were amended during October 1993. The term-loan feature that previously was part of these agreements was eliminated, and these facilities are now five-year revolvers maturing on July 31, 1998. For their fifth year--which begins on August 1, 1997--the committed amounts for these facilities are to be reduced to 75% of their initial size. Interest rates on these floating-rate borrowings are based on the London Interbank Offered Rate, the prevailing certificate of deposit rate or prime. Also during October 1993, the maturity of the Company's commercial paper program was extended through June 1997, and the term of Mitchell Mortgage Company's bank credit facility was extended through July 1996. The debt agreements contain certain restrictions which, among other things, require consolidated stockholders' equity to equal at least $400,000,000 and require the maintenance of specified financial and oil and gas reserve and/or asset value-to-debt ratios. The agreements also limit additional borrowings, restrict the sale or lease of certain assets and limit the right of the parent company and certain subsidiaries to merge with other companies. Retained earnings available for the payment of cash dividends totaled $351,954,000 at January 31, 1994. The loan agreements also limit cash advances and dividend payments to the parent company by the subsidiaries. At January 31, 1994, transfers to the parent of approximately $1,240,000,000 were allowable under these agreements. Maturities of long-term debt for the five fiscal years subsequent to January 31, 1994 are as follows (in thousands): [Enlarge/Download Table] 1995 1996 1997 1998 1999 -------- ------ ------- -------- ------ Senior notes . . . . . . . . . . . . . . $200,000 $ -- $ -- $100,000 $ -- Bank revolving credit agreements . . . . -- -- 11,300 -- 9,045 Commercial paper . . . . . . . . . . . . -- -- -- 22,000 -- Unsecured term loan . . . . . . . . . . -- -- -- 30,000 -- Mortgages . . . . . . . . . . . . . . . 598 3,697 503 464 494 -------- ------ ------- -------- ------ $200,598 $3,697 $11,803 $152,464 $9,539 ======== ====== ======= ======== ====== Bank revolving credit agreement maturities are based on present conversion dates, which may be extended. The fiscal 1995 debt maturities shown above are included in noncurrent liabilities in the accompanying balance sheet since the Company repaid these obligations by borrowing under existing commercial paper and bank revolving credit agreements having no fiscal 1995 maturities. At January 31, 1994, additional borrowings of approximately $505,000,000 were available under existing commercial paper and bank revolving credit agreements. The Company compensates the banks for these facilities by paying commitment and other fees and maintaining minimum unrestricted cash deposits of $3,125,000. 53
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(5) Income Taxes The Company follows Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." This statement requires deferred tax assets and liabilities to be determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements. Exclusive of the tax benefits attributable to the extraordinary charges discussed in Note 4 and the cumulative effect of a change in accounting methods discussed in Note 11, income taxes for the years ended January 31, 1994, 1993 and 1992 consist of the following (in thousands): [Download Table] 1994 1993 1992 ------- ------- ------- CURRENT Federal . . . . . . . . . . . . . . . . . . . . . . $ 8,805 $ 9,515 $ 9,633 State . . . . . . . . . . . . . . . . . . . . . . . 3,188 (2,178) 3,345 ------- ------- ------- 11,993 7,337 12,978 ------- ------- ------- DEFERRED Federal (including charge of $11,000 in 1994 due to increase in corporate tax rate) . . . 11,958 3,665 3,371 State . . . . . . . . . . . . . . . . . . . . . . . (1,526) 33 7,605 ------- ------- ------- 10,432 3,698 10,976 ------- ------- ------- $22,425 $11,035 $23,954 ======= ======= ======= The Omnibus Budget Reconciliation Act of 1993 was signed into law during August 1993, increasing the corporate statutory Federal income tax rate from 34% to 35%. The principal impact of this rate change on the Company's financial statements was a fiscal 1994 deferred tax provision of $11,000,000 to increase the liability for deferred Federal income taxes by an amount equal to 1% of the aggregate cumulative difference between the book and tax bases of its assets and liabilities. Of the aggregate fiscal 1992 provisions for current and deferred state income taxes, approximately $10,500,000 was attributable to the August 1991 enactment of an income-based franchise tax by the State of Texas. After the resultant Federal income tax benefit, this increased the Company's net provision for income taxes by approximately $6,900,000. As enacted, the legislation provided for retroactive taxation of the income of certain prior periods, including for the Company all of fiscal 1992 and most of fiscal 1991. Furthermore, under the liability method of accounting for income taxes, it was necessary to apply the revised Texas franchise tax rules to a portion of the Company's cumulative temporary differences, which resulted in a substantial deferred tax provision. During November 1992, the Texas franchise tax rules were revised in a manner that eliminated a substantial portion of the Company's liability for taxes attributable to periods prior to the enactment of the legislation. Because of this, the Company's current and deferred state income tax provisions for fiscal 1993 were reduced by $2,775,000 and $2,539,000, respectively. After the resultant Federal income tax charge, this lowered the Company's net provision for income taxes by $3,507,000. Reconciliations from the applicable statutory Federal income tax rates to the Company's effective income tax rates (exclusive of tax benefits attributable to extraordinary charges and the cumulative effect of a change in accounting methods) for the fiscal years 1994, 1993 and 1992 follow: [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- Statutory Federal income tax rate . . . . . . . . . . . . . . . . 35.0% 34.0% 34.0% State income taxes, net of Federal income tax benefit . . . . . . 2.3 (3.0) 10.6 Federal tax credits . . . . . . . . . . . . . . . . . . . . . . . (10.8) (7.9) (2.5) Utilization of tax carryforwards . . . . . . . . . . . . . . . . (2.3) -- (6.6) Increase in corporate statutory Federal income tax rate . . . . . 23.1 -- -- Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . (.1) .2 (.4) ---- ---- ---- 47.2% 23.3% 35.1% ==== ==== ==== 54
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Federal tax credits consist principally of amounts available under Section 29 of the Internal Revenue Code for natural gas produced from certain wells. The provisions for deferred Federal income taxes for fiscal 1994 and 1992 were reduced by $1,054,000 and $4,503,000, respectively, when certain tax carryforwards were estimated to be utilizable that previously had been expected to expire. The principal components of the Company's deferred income tax liability include the following at January 31, 1994 and 1993 (in thousands): [Enlarge/Download Table] 1994 1993 ---------- --------- Oil and gas acquisition, exploration and development costs deducted for tax purposes in excess of financial statement DD&A . . . . . . . . . . . . . $ 197,511 $ 206,607 Real estate holding costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179,790 168,241 Depreciation of other energy assets . . . . . . . . . . . . . . . . . . . . . . . . 69,727 65,521 Business tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . (34,254) (36,499) Unused alternative minimum tax credits . . . . . . . . . . . . . . . . . . . . . . (25,396) (25,569) Natural gas contract restructuring proceeds . . . . . . . . . . . . . . . . . . . . (18,034) (23,769) Employee benefits expense not currently deductible for tax purposes . . . . . . . . (14,249) (13,284) Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (15,639) (10,485) ---------- --------- $ 339,456 $ 330,763 ========== ========= At January 31, 1994, the Company had business tax credit carryforwards (consisting principally of investment tax credits) of approximately $34,254,000 substantially all of which expire during the fiscal years 1996 through 2001 and approximately $25,396,000 of unused alternative minimum tax credits that can be carried forward indefinitely. These carryforwards have been recognized in the calculation of financial statement tax provisions. Accordingly, their future utilization will only reduce the amount of taxes currently payable, not the financial statement provision for income taxes. (6) COMMITMENTS AND CONTINGENCIES Environmental regulations. The Company is considered by the United States Environmental Protection Agency to be a potentially responsible party with respect to four Superfund waste disposal sites. The only site involving more than minimal potential exposure to the Company is the Operating Industries, Inc. site located in Monterey Park, California, where small amounts of drilling fluids from Company-operated oil and gas wells were deposited. Although the Company contends that it should be exempt from liability with respect to this site, to date it has paid and expensed approximately $290,000 of clean-up costs. Additional exposure exists for future clean-up and closure costs of this site. While the Company believes that it is in substantial compliance with the many federal, state and local laws and regulations relating to the protection of the environment and public health, such laws and regulations affect the Company's operations, expenses and costs; and changes and potential changes in such regulations are continually monitored by the Company. In particular, Congress is currently considering reauthorization of the Comprehensive Environmental Response, Compensation and Liability Act (the Superfund legislation) and amendments to the Clean Water Act dealing with wetlands. However, management expects that none of the matters discussed in this or the preceding paragraph, when ultimately resolved, will have a material adverse effect upon the Company's financial position or results of operations. Litigation and other. The Company is party to various claims and other legal actions arising in the ordinary course of business and to recurring examinations performed by the Internal Revenue Service and other regulatory agencies. Management expects that none of these matters, when ultimately resolved, will have a material adverse effect upon the Company's financial position or results of operations. Mortgage activities. Mitchell Mortgage Company (MMC) administers approximately $202,000,000 of securities, backed by Federal Housing Administration (FHA) and Department of Veterans Affairs (VA) mortgages, on which it has guaranteed payments of principal and interest to the security holders. 55
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These mortgages are supported by government-sponsored insurance and are collateralized by real estate. In the event of default by a mortgagor, MMC may incur a loss if uncollected principal and interest, together with foreclosure and other costs, exceed established FHA or VA reimbursement limitations. Management does not expect that losses, if any, incurred in connection with defaults by borrowers under FHA and VA mortgages serviced by MMC will have a significant adverse effect on the Company's financial position or results of operations. Leases and contingent liabilities. The Company has various noncancellable equipment and facility operating lease agreements which provide for aggregate future payments of approximately $92,900,000. Minimum rentals for each of the five years subsequent to January 31, 1994 total #approximately $9,400,000; $9,200,000; $8,800,000; $8,900,000 and $8,200,000. Rental expense for all operating leases was approximately $9,900,000; $9,300,000 and $8,800,000 in fiscal 1994, 1993 and 1992. Exclusive of obligations described elsewhere in these notes, the Company had contingent liabilities at January 31, 1994 totaling approximately $14,700,000, including $5,700,000 of debt guarantees (principally for nonprofit institutions located in The Woodlands). (7) COMMON STOCK In May 1993, the Company sold 5,900,000 shares of its nonvoting Class B common stock at $21.875 per share. After deducting offering costs, the net proceeds from the sale totaled approximately $123,400,000. Of the net proceeds, $78,251,000 was used in connection with the buy-out of MEC Development, Ltd. (see Note 3). The remaining proceeds initially were used to pay down borrowings under certain Energy Division credit facilities. Such amounts subsequently were reborrowed to fund drilling costs that otherwise would have been expenditures of the partnership. On June 24, 1992, the stockholders approved an amendment to the Articles of Incorporation which authorized the reclassification of the Company's common stock into two classes of common stock designated Class A and Class B. Each share of the Company's prior common stock was converted into one-half share of Class A common stock and one-half share of Class B common stock, with any resulting fractional amounts redeemed for cash. Both the Class A and Class B common shares are freely transferable and are listed on the New York Stock Exchange; neither is convertible into the other class of common stock or any other security of the Company at the option of the holder. The Class A shares have full voting rights, whereas the Class B shares have no voting rights except as provided by law. The amended Articles of Incorporation allow cash dividends on Class B shares to be greater, but not less, than those paid on Class A shares and also contain certain Class B protection provisions. (8) TRANSACTIONS WITH RELATED PARTIES As a result of transactions occurring prior to fiscal 1973, when the Company became publicly owned, certain individuals, principally George P. Mitchell, Chairman of the Board and majority stockholder, hold real estate adjacent to that owned by the Company and interests in oil and gas properties in which the Company also owns interests, from which the related parties could realize substantial personal benefits as a result of the Company's activities. 56
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(9) SEGMENT INFORMATION Industry segment data for the fiscal years ended January 31, 1994, 1993 and 1992 are as follows (in thousands): [Enlarge/Download Table] Inter- Segment Identi- Outside segment Operating Capital fiable Revenues Revenues Earnings DD&A Additions Assets -------- -------- -------- ---- --------- ------ FISCAL 1994 EXPLORATION AND PRODUCTION Oil and gas . . . . . . . . . . . . . $ 265,798 $ -- $ 66,948 $ 121,178 $ 237,876 $ 1,011,802 Other . . . . . . . . . . . . . . . . 368 5,779 (365) 415 343 7,630 ---------- ------------ --------- ----------- --------- ----------- 266,166 5,779 66,583 121,593 238,219 1,019,432 ---------- ------------ --------- ----------- --------- ----------- TRANSMISSION AND PROCESSING Gas processing . . . . . . . . . . . 255,537 18,819 21,932 9,705 5,641 147,937 Gas gathering and transmission . . . 296,373 88,744 18,742 9,352 30,668 244,932 Other . . . . . . . . . . . . . . . . 8,627 12,766 1,985 2,651 12,319 34,576 ---------- ------------ --------- ----------- --------- ----------- 560,537 120,329 42,659 21,708 48,628 427,445 ---------- ------------ --------- ----------- --------- ----------- REAL ESTATE . . . . . . . . . . . . . 126,106 6,620 21,078 7,282 65,132 930,535 ---------- ------------ --------- ----------- --------- ----------- CORPORATE . . . . . . . . . . . . . . -- -- -- 2,662 3,866 38,064 ---------- ------------ --------- ----------- --------- ----------- $ 952,809 $ 132,728 $ 130,320 $ 153,245 $ 355,845 $ 2,415,476 ========== ============ ========= =========== ========= =========== FISCAL 1993 EXPLORATION AND PRODUCTION Oil and gas . . . . . . . . . . . . . $ 202,692 $ -- $ 44,722 $ 89,731 $ 77,397 $ 890,631 Restructuring charges . . . . . . . . -- -- (4,990) -- -- -- Other . . . . . . . . . . . . . . . . 11,989 9,017 (1,404) 962 306 13,071 Restructuring charges . . . . . . . . -- -- (15,736) 8,713 -- -- ---------- ------------ --------- ----------- --------- ----------- 214,681 9,017 22,592 99,406 77,703 903,702 ---------- ------------ --------- ----------- --------- ----------- TRANSMISSION AND PROCESSING Gas processing . . . . . . . . . . . 309,917 18,485 60,370 10,464 8,326 177,399 Gas gathering and transmission . . . 248,605 60,596 25,517 10,144 57,325 229,356 Other . . . . . . . . . . . . . . . . 8,178 15,035 2,617 3,118 4,822 25,203 ---------- ------------ --------- ----------- --------- ----------- 566,700 94,116 88,504 23,726 70,473 431,958 ---------- ------------ --------- ----------- --------- ----------- REAL ESTATE . . . . . . . . . . . . . 121,453 5,456 22,801 7,143 84,954 893,001 ---------- ------------ --------- ----------- --------- ----------- CORPORATE . . . . . . . . . . . . . . -- -- -- 2,754 4,538 43,138 ---------- ------------ --------- ----------- --------- ----------- $ 902,834 $ 108,589 $ 133,897 $ 133,029 $ 237,668 $ 2,271,799 ========== ============ ========= =========== ========= =========== FISCAL 1992 EXPLORATION AND PRODUCTION Oil and gas . . . . . . . . . . . . . $ 205,035 $ -- $ 43,365 $ 93,280 $ 83,265 $ 894,729 Other . . . . . . . . . . . . . . . . 26,038 11,887 (2,101) 2,053 863 35,037 ---------- ------------ --------- ----------- --------- ----------- 231,073 11,887 41,264 95,333 84,128 929,766 ---------- ------------ --------- ----------- --------- ----------- TRANSMISSION AND PROCESSING Gas processing . . . . . . . . . . . 271,497 22,430 64,900 9,755 15,214 164,917 Gas gathering and transmission . . . 231,068 65,400 23,212 11,241 31,824 176,344 Other . . . . . . . . . . . . . . . . 9,414 15,202 1,745 2,123 3,711 20,023 ---------- ------------ --------- ----------- --------- ----------- 511,979 103,032 89,857 23,119 50,749 361,284 ---------- ------------ --------- ----------- --------- ----------- REAL ESTATE . . . . . . . . . . . . . 131,318 6,220 22,724 7,050 82,881 892,558 ---------- ------------ --------- ----------- --------- ----------- CORPORATE . . . . . . . . . . . . . . -- -- -- 2,582 5,854 68,716 ---------- ------------ --------- ----------- --------- ----------- $ 874,370 $ 121,139 $ 153,845 $ 128,084 $ 223,612 $ 2,252,324 ========== ============ ========= =========== ========= =========== 57
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The Company's gas gathering and transmission revenues historically have consisted principally of amounts attributable to the purchase and resale by its pipelines of natural gas flowing through their systems. However, beginning in fiscal 1993, transactions involving buying and reselling of "off-system" natural gas have constituted an increasing percentage of gas gathering and transmission revenues. Since such activities do not use the Company's pipeline systems, they can be economic even though the margins are relatively small. As these low-margined activities have expanded, they have caused the ratio of operating earnings to revenues for the gas gathering and transmission segment to decline. During the first quarter of fiscal 1993, the Company recorded pretax restructuring charges totaling $21,191,000 in connection with a reorganization of its Exploration and Production Division. The major charges were related to oil and gas and other operations; the remaining $465,000 was charged to other expense. The charges consisted principally of costs attributable to an early retirement program and other personnel reductions, additional depreciation expense on drilling rigs and asset write-downs (principally inventories) resulting from the Company's decision to substantially reduce the scope of its contract drilling and oil field supply operations. Because of their magnitude and unusual nature, and in accordance with Accounting Principles Board Opinion No. 30, these restructuring charges have been reported as separate components of segment operating earnings. Intersegment revenues are recorded at prevailing market prices and are eliminated in consolidation. Substantially all of the Company's operations are conducted in the United States. The Company's energy revenues are derived principally from uncollateralized sales to customers in the electrical generation, gas distribution, petrochemical and oil and gas industries. These industry concentrations have the potential to impact the Company's exposure to credit risk, either positively or negatively, because customers may be similarly affected by changes in economic or other conditions. The creditworthiness of this customer base is strong, and the Company has not experienced significant credit losses on such receivables. Oil and gas segment sales to Natural Gas Pipeline Company of America constituted approximately 13%, 12% and 11% of consolidated revenues, respectively, during fiscal 1994, 1993 and 1992. (10) STOCK OPTIONS AND BONUS UNITS The Company's stock option plans authorize the granting of incentive options and nonqualified options to purchase common stock at prices not less than the market value on the date of grant. The options have maximum terms of ten years and become exercisable over a five-year period. Certain of the option grants have associated stock appreciation rights (SARs) which entitle the optionee to receive a cash payment equal to the difference between the market value and the option price for the number of options being exercised. Summarized stock option information follows: [Enlarge/Download Table] Exercisable Options ------------------- Shares Options Average Reserved for Outstanding Number Price Future Grant ----------- ------ ----- ------------ AT JANUARY 31, 1991 . . . . . . . . . . . . . . . . 554,950 517,775 $ 8.76 479,000 Granted . . . . . . . . . . . . . . . . . . . . . . 41,500 Exercised (at average price of $8.76 per share) . . (105,975) --------- AT JANUARY 31, 1992 . . . . . . . . . . . . . . . . 490,475 422,875 $ 8.83 437,500 Exercised (at average price of $8.78 per share) . . (65,000) Cancelled . . . . . . . . . . . . . . . . . . . . . (21,400) --------- AT JANUARY 31, 1993 . . . . . . . . . . . . . . . . 404,075 344,375 $ 8.96 437,500 Granted . . . . . . . . . . . . . . . . . . . . . . 120,000 Exercised (at average price of $8.82 per share) . . (218,375) Cancelled . . . . . . . . . . . . . . . . . . . . . (4,400) --------- AT JANUARY 31, 1994 . . . . . . . . . . . . . . . . 301,300 142,100 $ 9.99 321,900 ========= 58
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The Company also uses phantom-stock awards, which it calls "bonus units", as a long-term incentive. Upon the redemption of such awards, grantees receive gross compensation in amounts equal to the difference between the market price of the Company's common stock and a floor price (the market price of the stock when the units were awarded). The Company's 1991 Bonus Unit Plan authorized the issuance of up to 700,000 units, substantially all of which have been granted. These units generally vest in equal annual installments over a five-year period. At January 31, 1994, grants covering 553,050 units with an average floor price of $15.90 were outstanding (188,850 of which were exercisable). The Company recognizes compensation expense over the applicable vesting terms of the SARs and bonus units. Such expense aggregated $3,875,000; $757,000 and $941,000 in fiscal 1994, 1993 and 1992. (11) RETIREMENT BENEFITS Qualified retirement plan. Substantially all employees, except hospitality industry employees, who meet age and service requirements are covered by a defined benefit retirement plan which is maintained without cost to the employees. Pension benefits are based on years of service and average earnings for the three highest consecutive years during the ten years immediately preceding retirement. The Company's funding policy is to make contributions to the plan of at least the minimum amounts required by applicable Federal laws and regulations. Such contributions to the plan were none in fiscal 1994 and 1993 and $1,400,000 in fiscal 1992. The projected unit credit actuarial method is used in determining the Company's required annual contributions to the retirement plan and in computing financial statement pension expense. The assumptions used in the computations include an expected long-term rate of return on plan assets of 9%, annual increases in salary levels of 5% in fiscal 1994 (6% in prior years) and discount rates for the projected benefit obligation of 7.25%; 8.5% and 7.75% for fiscal 1994, 1993 and 1992, respectively. Plan assets consist primarily of marketable equity securities and long-term U. S. Treasury notes. Components of financial statement pension expense for the years ended January 31, 1994, 1993 and 1992 were (in thousands): [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- Service cost - benefits accrued during the year . . . . $ 4,097 $ 4,554 $ 3,993 Interest accrued on projected benefit obligation . . . 7,188 6,559 5,895 Early-retirement benefits accrued . . . . . . . . . . . -- 1,586 -- Return on plan assets . . . . . . . . . . . . . . . . . (8,581) (7,995) (6,964) Amortization of unrecognized gains . . . . . . . . . . (1,853) (1,149) (1,149) -------- -------- -------- Financial statement pension expense . . . . . . . . . . $ 851 $ 3,555 $ 1,775 ======== ======== ======== The following table summarizes the plan's funded status for financial statement purposes and the related amounts included in the Company's balance sheets at January 31, 1994 and 1993 (in thousands): [Download Table] 1994 1993 ---- ---- ACTUARIAL PRESENT VALUE OF PENSION BENEFIT OBLIGATION Vested benefits . . . . . . . . . . . . . . . . . . . . . $ 77,289 $ 59,086 Nonvested benefits . . . . . . . . . . . . . . . . . . . 3,809 6,106 --------- --------- Accumulated benefit obligation . . . . . . . . . . . . . 81,098 65,192 Provision for future salary increases . . . . . . . . . . 24,637 21,228 --------- --------- Projected benefit obligation . . . . . . . . . . . . . . $ 105,735 $ 86,420 ========= ========= AMOUNTS AVAILABLE TO SATISFY PENSION BENEFIT OBLIGATION Plan assets, at market value . . . . . . . . . . . . . . $ 110,600 $ 97,191 Unrecognized actuarial gains . . . . . . . . . . . . . . (16,509) (21,564) Balance sheet accrual for pension expense . . . . . . . . 11,644 10,793 --------- --------- $ 105,735 $ 86,420 ========= ========= 59
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Nonqualified retirement plans. Internal Revenue Service regulations limit the benefits that may be paid to certain "highly-compensated" employees under the Company's qualified retirement plan. Nonqualified plans are maintained to make the basis on which those individuals' retirement benefits are determined the same as is used for other employees. The Company's liability to make these payments is a general obligation for which a trust fund has not been established. Approximately $819,000; $2,108,000 (including $1,656,000 attributable to early retirement benefits provided in connection with the Exploration and Production Division restructuring) and $310,000 was expensed in fiscal 1994, 1993 and 1992 related to these plans. At January 31, 1994, the aggregate balance sheet liability attributable to these plans totaled $3,587,000. Postretirement medical benefits. Retirees who reach retirement age while working for the Company and meet certain other eligibility requirements may elect coverage under the Company's medical plan. The Company has the right to amend or terminate medical benefits for active employees and retirees or to change the required level of participant contributions. Prior to fiscal 1993, the cost of providing these postretirement health care benefits, which is reduced by available Medicare coverage and retiree contributions, was expensed as claims were paid. The Company's net cost for this coverage was approximately $695,000 in fiscal 1992. The Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," effective February 1, 1992. Accordingly, a charge for postretirement medical benefits of $10,551,000 ($15,986,000 before tax) was recorded as the cumulative effect of the change in accounting methods for periods prior to fiscal 1993. Components of financial statement expense for postretirement medical benefits for the years ended January 31, 1994 and 1993 were (in thousands): [Download Table] 1994 1993 ---- ---- Service cost - benefits accrued during the year . . . . . . $ 554 $ 720 Interest accrued on projected benefit obligation . . . . . 1,046 1,323 Amortization of unrecognized gains . . . . . . . . . . . . (291) -- --------- -------- $ 1,309 $ 2,043 ========= ======== The plan is unfunded, and benefits are paid as costs are incurred. Such benefits payments totaled approximately $1,200,000 and $900,000 in fiscal 1994 and 1993. The following table summarizes the plan's status for financial statement purposes and the related amounts included in the Company's balance sheets at January 31, 1994 and 1993 (in thousands): [Download Table] 1994 1993 ---- ---- ACTUARIAL PRESENT VALUE OF POSTRETIREMENT BENEFIT OBLIGATION Retirees . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,463 $ 8,784 Fully eligible, active plan participants . . . . . . . . . 2,913 2,659 Other active plan participants . . . . . . . . . . . . . . 5,921 5,736 Unrecognized actuarial gains (losses) . . . . . . . . . . . (1,059) (50) --------- -------- Balance sheet accrual for postretirement benefits . . . . . $ 17,238 $ 17,129 ========= ======== Effective February 1, 1993, the Company amended its medical plan to incorporate a scheduled-reimbursements methodology under which the Company and providers agree to specified rates for individual services. In connection with this change, the assumed medical cost trend rate was also revised. In fiscal 1994, the Company's medical cost trend rate was assumed to start at 7% and decline gradually to 5.5% in 2002 and remain at that level thereafter; for fiscal 1993, these amounts were 12% and 6%, respectively. The medical cost trend rate assumption has a significant effect on the amount 60
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of the obligation and the periodic cost reported. An increase of 1% in the assumed trend rate for each year would have increased the actuarial present value of the postretirement benefit obligation at January 31, 1994 by $2,737,000 and the aggregate service and interest components of the fiscal 1994 cost by a total of $268,000. Discount rates of 7.25% and 8.5% were used in determining the present value of the postretirement benefit obligation at January 31, 1994 and 1993, respectively. (12) Financial Instruments The following table summarizes the carrying amounts and estimated fair values of the Company's financial instruments for which it is practicable to estimate that value as of January 31, 1994 (in thousands): [Download Table] Carrying Estimated Amounts Fair Values -------- ----------- BALANCE SHEET FINANCIAL INSTRUMENTS Cash and cash equivalents . . . . . . . . . . . . . . . . . $ 21,832 $ 21,832 Notes and contracts receivable . . . . . . . . . . . . . . 42,985 38,208 Short-term debt . . . . . . . . . . . . . . . . . . . . . . 9,955 9,955 Long-term debt . . . . . . . . . . . . . . . . . . . . . . 988,318 1,049,803 OFF-BALANCE-SHEET FINANCIAL INSTRUMENTS Financial guarantees and commitments . . . . . . . . . . . -- 3,875 The estimated fair values for cash and cash equivalents are assumed to equal their carrying amounts because of the short maturities of these instruments. The estimated fair values of notes and contracts receivable are determined by discounting future cash flows using interest rates at which similar loans currently could be made for similar maturities to borrowers with comparable credit ratings. Estimated fair values of fixed-rate, long-term debt are based on quoted market prices or, where such prices are not available, on current interest rates offered to the Company for debt with similar remaining maturities. For other long-term and all short-term debt obligations, which bear interest at floating rates, carrying amounts and fair values are assumed to be equal because of the nature of these obligations. Estimated fair values of financial guarantees and commitments are based on the estimated costs of obtaining letters of credit to relieve the Company of its obligations under such agreements. (13) SUBSEQUENT EVENTS On April 7, 1994, the Company sold 16 land drilling rigs for $9,000,000 in cash and warrants to acquire common stock of the purchaser under which an additional $1,000,000 could be realized during the next two years. This sale effectively completes the Company's withdrawal from the contract drilling business. A pretax gain on this sale of approximately $3,800,000 will be included in the results of fiscal 1995's first quarter. On April 18, 1994, the Company signed a letter of understanding which could lead to the sale of its Winnie Pipeline and Spindletop storage facilities, together with a related gas processing plant. The Company would receive approximately $120,000,000 in cash and would realize a gain, based on the terms of the letter of understanding. Closing of this transaction is subject to completion of due diligence, execution of definitive agreements, receipt of regulatory approvals and other conditions, and no assurance can be given that this will be accomplished. If consummated, it is expected that this sale would close during the second quarter of fiscal 1995. 61
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS Mitchell Energy & Development Corp.: We have audited the accompanying consolidated balance sheets of Mitchell Energy & Development Corp. (a Texas corporation) and subsidiaries as of January 31, 1994 and 1993, and the related consolidated statements of earnings, stockholders' equity and cash flows for each of the three years in the period ended January 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 financial statements referred to above present fairly, in all material respects, the financial position of Mitchell Energy & Development Corp. and subsidiaries as of January 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended January 31, 1994, in conformity with generally accepted accounting principles. As discussed in Note 11 to the consolidated financial statements, effective February 1, 1992, the Company changed its method of accounting for postretirement benefits other than pensions. ARTHUR ANDERSEN & CO. Houston, Texas April 18, 1994 62
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SUPPLEMENTAL OIL AND GAS INFORMATION MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES (UNAUDITED) Reserve quantities. The following tables summarize changes in total proved reserve quantities for the fiscal years ended January 31, 1994, 1993 and 1992 and the proved developed reserve quantities at the dates indicated: [Enlarge/Download Table] Total Proved Reserves ---------------------------------------------------------------------------------------------- 1994 1993 1992 ------------------------------ ------------------------------ ---------------------------- Equity Equity Equity Consol- Partner- Consol- Partner- Consol- Partner- Total idated ships Total idated ships Total idated ships ----- ------ ----- ----- ------ ----- ----- ------ ----- NATURAL GAS (BCF) Beginning balance . . . . . . . . . 583.7 511.7 72.0 581.7 503.6 78.1 576.6 529.0 47.6 Extensions and discoveries . . . . 94.5 84.0 10.5 56.6 12.1 44.5 51.5 22.3 29.2 Production marketed . . . . . . . . (70.7) (69.0) (1.7) (54.6) (47.6) (7.0) (57.6) (52.2) (5.4) Production consumed in operations . (3.7) (3.6) (.1) (3.0) (2.7) (.3) (2.9) (2.7) (.2) Purchases of minerals in-place . . 34.6 34.6 -- 15.0 15.0 -- 6.7 6.7 -- Transfers of undeveloped reserves to partnerships . . . . (.3) (1.4) 1.1 -- (.1) .1 (.9) (4.6) 3.7 Purchases of partnership interests -- 79.0 (79.0) -- 42.5 (42.5) -- -- -- Revisions of previous estimates . . (9.4) (6.7) (2.7) (2.3) (1.4) (.9) 9.2 6.0 3.2 Sales of minerals in-place . . . . (1.2) (1.1) (.1) (9.7) (9.7) -- (.9) (.9) -- ----- ----- ------ ----- ----- ----- ----- ----- ----- Ending balance . . . . . . . . . . 627.5 627.5 -- 583.7 511.7 72.0 581.7 503.6 78.1 ===== ===== ====== ===== ===== ===== ===== ===== ===== OIL AND CONDENSATE (MMBBLS) Beginning balance . . . . . . . . . 15.8 14.0 1.8 15.6 14.1 1.5 15.4 14.6 .8 Extensions and discoveries . . . . 1.7 1.6 .1 1.5 .4 1.1 1.6 .8 .8 Production . . . . . . . . . . . . (2.2) (2.1) (.1) (2.1) (1.9) (.2) (2.0) (1.8) (.2) Purchases of minerals in-place . . .8 .8 -- 1.1 1.1 -- .8 .8 -- Sales of minerals in-place . . . . (.5) (.4) (.1) (.4) (.4) -- -- -- -- Revisions of previous estimates . . (.7) (.7) -- (.4) (.5) .1 (.4) (.5) .1 Improved recovery . . . . . . . . . .5 .5 -- .4 .4 -- .3 .3 -- Transfers and other . . . . . . . . (.1) 1.6 (1.7) .1 .8 (.7) (.1) (.1) -- ----- ----- ------ ----- ----- ----- ----- ----- ----- Ending balance . . . . . . . . . . 15.3 15.3 -- 15.8 14.0 1.8 15.6 14.1 1.5 ===== ===== ====== ===== ===== ===== ===== ===== ===== PLANT NGLS (MMBBLS) Beginning balance . . . . . . . . . 127.4 79.1 48.3 101.6 84.3 17.3 104.8 94.6 10.2 Additions . . . . . . . . . . . . . 10.7 7.1 3.6 17.2 6.1 11.1 15.2 6.2 9.0 Production . . . . . . . . . . . . (18.1) (11.3) (6.8) (17.1) (12.4) (4.7) (16.1) (13.7) (2.4) Purchase of interests in C&L Processors' plants . . . . . . -- -- -- 30.2 -- 30.2 -- -- -- Revisions of previous estimates . . (12.6) (7.6) (5.0) (4.5) 1.1 (5.6) (2.3) (2.8) .5 ----- ----- ------ ----- ----- ----- ----- ----- ----- Ending balance . . . . . . . . . . 107.4 67.3 40.1 127.4 79.1 48.3 101.6 84.3 17.3 ===== ===== ====== ===== ===== ===== ===== ===== ===== [Download Table] Proved Developed Reserves at January 31, ---------------------------------------- 1994 1993 1992 1991 ---- ---- ---- ---- NATURAL GAS (BCF) Consolidated . . . . . . . . . . . . 558.5 437.7 419.9 447.6 Equity partnerships . . . . . . . . . -- 72.0 78.1 47.6 ----- ----- ----- ----- 558.5 509.7 498.0 495.2 ===== ===== ===== ===== OIL AND CONDENSATE (MMBBLS) Consolidated . . . . . . . . . . . . 13.8 12.3 11.9 11.9 Equity partnerships . . . . . . . . . -- 1.8 1.5 .8 ----- ----- ----- ----- 13.8 14.1 13.4 12.7 ===== ===== ===== ===== PLANT NGLS (MMBBLS) Consolidated . . . . . . . . . . . . 59.2 70.8 77.4 87.4 Equity partnerships . . . . . . . . . 37.2 43.1 17.3 10.2 ----- ----- ----- ----- 96.4 113.9 94.7 97.6 ===== ===== ===== ===== 63
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Future net cash flows. The following table sets forth estimates of the standardized measure of discounted future net cash flows from total proved reserves at January 31, 1994, 1993 and 1992 (in millions): [Enlarge/Download Table] 1994 1993 1992 ------------------------------ ---------------------------- ---------------------------- Equity Equity Equity Consol- Partner- Consol- Partner- Consol- Partner- Total idated ships Total idated ships Total idated ships ----- ------ ----- ----- ------ ----- ----- ------ ----- Oil and Gas Future cash inflows . . . . . . $ 1,881 $ 1,881 $ -- $ 1,938 $ 1,718 $ 220 $1,855 $1,645 $ 210 Future production and development costs . . . . . . (620) (620) -- (643) (584) (59) (658) (597) (61) Discount -- 10% annually . . . (419) (419) -- (415) (362) (53) (384) (335) (49) ------- ------- ------- ------- ------- ------ ------ ------ ------ Present value of future net revenues . . . . . 842 842 -- 880 772 108 813 713 100 Future income taxes, discounted at 10% annually . . . . . . . (135) (135) -- (194) (164) (30) (184) (164) (20) ------- ------- ------- ------- ------- ------ ------ ------ ------ $ 707 $ 707 $ -- $ 686 $ 608 $ 78 $ 629 $ 549 $ 80 ======= ======= ======= ======= ======= ====== ====== ====== ====== PLANT NGLS Future cash inflows . . . . . . $ 1,188 $ 762 $ 426 $ 1,741 $ 1,086 $ 655 $1,167 $ 971 $ 196 Future production costs . . . . (859) (533) (326) (1,201) (727) (474) (815) (672) (143) Discount -- 10% annually . . . (133) (90) (43) (200) (132) (68) (124) (112) (12) ------- ------- ------- ------- ------- ------ ------ ------ ------ Present value of future net revenues . . . . . 196 139 57 340 227 113 228 187 41 Future income taxes, discounted at 10% annually . . (50) (30) (20) (94) (59) (35) (53) (42) (11) ------- ------- ------- ------- ------- ------ ------ ------ ------ $ 146 $ 109 $ 37 $ 246 $ 168 $ 78 $ 175 $ 145 $ 30 ======= ======= ======= ======= ======= ====== ====== ====== ====== Proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under economic and operating conditions at each year end. Proved developed reserves are expected to be recovered via existing wells using existing equipment and operating methods. Consolidated reserves represent the Company's net interest in oil and gas properties or in reserves committed to Company-owned gas processing plants. Equity partnership reserves represent the Company's proportional interest in the reserves of partnerships that are accounted for using the equity method. The partnerships engaged in oil and gas activities in which the Company previously held an interest were liquidated during fiscal 1994--see Note 3 for additional information concerning the buy-out of MEC Development, Ltd. During fiscal 1993, the Company purchased the remaining interests in Phase 6 of that partnership. The natural gas reserve quantities reported as oil and gas reserves represent wet gas volumes, and include gas quantities that will be converted by processing to NGLs (both leasehold and plant ownership). The oil and gas future net cash flows, however, include only the Company's leasehold reimbursement for natural gas liquids extracted during processing. As discussed below, the remainder of the cash flows associated with the Company's ownership of NGL reserves extracted from its wet gas volumes, is included in plant NGL future net cash flows since those cash flows accrue to the Company because of its ownership of gas processing plants. The quantities reported herein for plant NGLs include all liquids that will be extracted from gas streams contractually committed to Company-owned gas processing plants since the Company, as plant owner, generally has beneficial ownership of all the NGLs so produced. Accordingly, the plant NGL reserves and future net cash flows include amounts attributable to Company-owned NGL reserves and to NGLs extracted from gas streams owned by third parties. The Company reimburses the owners of the natural gas streams based either on a percentage of the value of the liquids produced or on the value of the natural gas consumed in processing under keep-whole agreements. Such reimbursements, including amounts attributable to the Company's oil and gas leasehold interests (included in oil and gas future net cash flows), are deducted as production costs in determining future net cash flows from plant NGLs. Of the total remaining natural gas reserves at January 31, 1994, 267.4 Bcf will be processed at Company plants, including 35.5 Bcf of fiscal 1994's natural gas reserve additions from extensions and discoveries. It is esti- 64
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mated that 65.7 Bcf of such reserves and 8.7 Bcf of such reserve additions will be converted by processing into 37.2 MMBbls and 4.9 MMBbls, respectively, of plant NGL reserves and plant NGL reserve additions. Except where otherwise specified by contractual agreement, future cash inflows are estimated using year-end prices. The future cash inflows shown for fiscal 1994, 1993 and 1992 include deferred contract restructuring proceeds of $51,527,000, $69,908,000 and $90,268,000. Future production and development cost estimates are based on economic conditions at the respective year ends. Future income taxes are computed by applying applicable statutory tax rates to the difference between the present value of estimated future net revenues and the tax basis of proved oil and gas properties after considering applicable tax credit carryforwards, estimated future percentage depletion deductions and energy tax credits. The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended January 31, 1994, 1993 and 1992 (in millions): [Enlarge/Download Table] 1994 1993 1992 -------------------------- --------------------------- --------------------------- Equity Equity Equity Consol- Partner- Consol- Partner- Consol- Partner- Total idated ships Total idated ships Total idated ships ----- ------ -------- ----- ------- -------- ----- ------- -------- OIL AND GAS Extensions and discoveries, net of related costs . . . . . . $ 108 $ 92 $ 16 $ 88 $ 10 $ 78 $ 50 $ 12 $ 38 Sales, net of production costs . . (197) (192) (5) (152) (133) (19) (156) (141) (15) Net changes in prices and production costs . . . . . . (28) (25) (3) 66 57 9 (89) (87) (2) Accretion of discount . . . . . . . 68 64 4 65 55 10 70 64 6 Transfers of undeveloped reserves to partnerships . . . . -- (2) 2 (1) (2) 1 (1) (5) 4 Purchase of partner- ship interests . . . . . . . . . -- 110 (110) -- 60 (60) -- -- -- Production rate changes and other . . . . . . . (28) (21) (7) (26) (16) (10) (9) (15) 6 Development costs incurred . . . . 13 13 -- 13 13 -- 22 22 -- Purchases of minerals in-place . . 47 47 -- 27 27 -- 18 18 -- Sales of minerals in-place . . . . (4) (4) -- (6) (6) -- (1) (1) -- Revisions of previous quantity estimates . . . . . . . (17) (12) (5) (7) (6) (1) 6 2 4 ----- ----- ----- ----- ----- ---- ----- ----- ---- Change in present value of future net revenues . . . . . (38) 70 (108) 67 59 8 (90) (131) 41 Net change in present value of future income taxes . . . . . 59 29 30 (10) -- (10) 35 39 (4) ----- ----- ----- ----- ----- ---- ----- ----- ---- $ 21 $ 99 $ (78) $ 57 $ 59 $ (2) $ (55) $ (92) $ 37 ===== ===== ===== ===== ===== ==== ===== ===== ==== PLANT NGLS Additions, net of related costs . . $ 17 $ 15 $ 2 $ 47 $ 20 $ 27 $ 40 $ 16 $ 24 Sales, net of production costs . . (30) (16) (14) (52) (34) (18) (58) (48) (10) Net changes in prices and costs . . . . . . . . (144) (97) (47) 17 18 (1) (222) (201) (21) Purchase of interests in C&L Processors' plants . . . . . -- -- -- 72 -- 72 -- -- -- Accretion of discount . . . . . . . 34 23 11 23 19 4 42 38 4 Revisions of previous quantity estimates . . . . . . . (17) (8) (9) -- 14 (14) 2 1 1 Other . . . . . . . . . . . . . . . (4) (5) 1 5 3 2 1 2 (1) ----- ----- ----- ----- ----- ---- ----- ----- ---- Change in present value of future net revenues . . . . . (144) (88) (56) 112 40 72 (195) (192) (3) Net change in present value of future income taxes . . . . . 44 29 15 (41) (17) (24) 69 67 2 ----- ----- ----- ----- ----- ---- ----- ----- ---- $(100) $ (59) $ (41) $ 71 $ 23 $ 48 $(126) $(125) $ (1) ===== ===== ===== ===== ===== ==== ===== ===== ==== 65
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Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates, by their nature, are generally less precise than other financial statement disclosures. Discounted future cash flow estimates such as those shown above are not intended to represent estimates of the fair market value of oil and gas properties. Estimates of fair market value also should consider probable reserves, anticipated future oil and gas prices and interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair market value is necessarily subjective and imprecise. Oil and gas related costs and operating results. The following tables set forth capitalized costs at January 31, 1994, 1993 and 1992 and capitalized costs incurred and operating results for oil and gas producing activities for the years then ended (in thousands): [Enlarge/Download Table] 1994 1993 1992 ---- ---- ---- CAPITALIZED COSTS Oil and gas properties Consolidated . . . . . . . . . . . . . . . . . . . . . . . . . . $1,958,188 $1,766,616 $1,717,396 Equity partnership investments (principally undistributed earnings) . . . . . . . . . . . . . -- 11,267 15,847 ---------- ---------- ---------- 1,958,188 1,777,883 1,733,243 Support equipment and facilities . . . . . . . . . . . . . . . . 67,675 66,524 63,513 Accumulated depreciation, depletion and amortization . . . . . . (1,065,993) (1,000,397) (953,369) ---------- ---------- ---------- Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . $ 959,870 $ 844,010 $ 843,387 ========== ========== ========== Proportional interest in net capitalized costs of equity partnerships . . . . . . . . . . . . . . . . . $ -- $ 38,772 $ 39,867 ========== ========== ========== CAPITALIZED COSTS INCURRED Unevaluated lease acquisition . . . . . . . . . . . . . . . . . . $ 9,222 $ 8,650 $ 11,124 Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . 36,192 19,676 20,545 Development . . . . . . . . . . . . . . . . . . . . . . . . . . . 98,326 27,489 33,066 Producing property acquisition . . . . . . . . . . . . . . . . . 89,972 18,934 15,390 ---------- --------- ---------- Capitalized costs incurred . . . . . . . . . . . . . . . . . . . 233,712 74,749 80,125 Equity partnership investments . . . . . . . . . . . . . . . . . . 314 27 507 Support equipment and facilities . . . . . . . . . . . . . . . . . 3,850 2,621 2,633 ---------- --------- ---------- Capital additions . . . . . . . . . . . . . . . . . . . . . . . . $ 237,876 $ 77,397 $ 83,265 ========== ========= ========== Proportional interest in capitalized costs incurred by equity partnerships . . . . . . . . . . . . . $ 5,470 $ 20,039 $ 21,328 ========== ========= ========== OPERATING RESULTS (excluding general and administrative and interest expense) Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 262,163 $ 188,683 $ 195,072 Less - Production costs . . . . . . . . . . . . . . . . . . . . . 61,082 55,523 53,812 Other operating costs . . . . . . . . . . . . . . . . . . . 16,590 12,716 14,578 Depreciation, depletion and amortization . . . . . . . . . 121,178 89,731 93,280 Restructuring charges . . . . . . . . . . . . . . . . . . . -- 4,990 -- ---------- --------- ---------- 63,313 25,723 33,402 Equity in earnings of partnerships . . . . . . . . . . . . . . . . 3,635 14,009 9,963 ---------- --------- ---------- Oil and gas segment operating earnings . . . . . . . . . . . . . . 66,948 39,732 43,365 Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 19,279 9,776 14,649 ---------- --------- ---------- $ 47,669 $ 29,956 $ 28,716 ========== ========= ========== 66
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HISTORICAL SUMMARY MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES YEAR ENDED JANUARY 31, (DOLLAR AMOUNTS IN THOUSANDS) [Enlarge/Download Table] 1994 1993 1992 1991 1990 ---------- ---------- ---------- ---------- ---------- FINANCIAL POSITION AT YEAR END Oil and gas properties . . . . . . . . . . . . . . $ 933,402 $ 818,400 $ 817,977 $ 818,987 $ 793,037 Transmission and processing facilities . . . . . . 318,141 313,178 270,651 243,524 235,773 Other . . . . . . . . . . . . . . . . . . . . . . . 53,346 52,202 59,016 57,672 56,030 ---------- ---------- ---------- ---------- ---------- Net property, plant and equipment . . . . . . . $1,304,889 $1,183,780 $1,147,644 $1,120,183 $1,084,840 ========== ========== ========== ========== ========== Real estate . . . . . . . . . . . . . . . . . . . . $ 896,652 $ 864,351 $ 873,326 $ 842,180 $ 795,199 Total assets . . . . . . . . . . . . . . . . . . . 2,415,476 2,271,799 2,252,324 2,216,235 2,099,360 Capital employed Long-term debt . . . . . . . . . . . . . . . . $988,318 $947,723 $954,327 $904,997 $844,745 Deferred income taxes . . . . . . . . . . . . . 339,456 330,763 329,526 319,681 304,423 Deferred credits and other liabilities . . . . 118,632 141,200 133,488 154,439 172,131 Stockholders' equity . . . . . . . . . . . . . 751,954 632,052 637,369 610,945 582,258 ---------- ---------- ---------- ---------- ---------- $2,198,360 $2,051,738 $2,054,710 $1,990,062 $1,903,557 ========== ========== ========== ========== ========== CAPITAL ADDITIONS (accrual basis) Exploration and Production . . . . . . . . . . . . $ 159,968 $ 77,703 $ 84,128 $ 99,290 $ 80,075 MEC Development, Ltd. buy-out . . . . . . . . . . 78,251 -- -- -- -- Transmission and Processing . . . . . . . . . . . . 48,628 70,473 50,749 29,662 29,236 Real Estate . . . . . . . . . . . . . . . . . . . . 65,132 84,954 82,881 94,084 82,696 Corporate . . . . . . . . . . . . . . . . . . . . . 3,866 4,538 5,854 6,217 3,643 ---------- ---------- ---------- ---------- ---------- $ 355,845 $ 237,668 $ 223,612 $ 229,253 $ 195,650 ========== ========== ========== ========== ========== ENERGY OPERATING STATISTICS Average daily volumes Natural gas sales (Mcf) . . . . . . . . . . . . 193,800 149,000 157,800 150,600 147,300 Crude oil and condensate sales (Bbls) . . . . . 6,000 5,600 5,400 5,200 4,900 Natural gas liquids produced (Bbls) . . . . . . 49,800 47,200 44,000 37,600 33,600 Pipeline throughput (Mcf) . . . . . . . . . . . 549,000 566,000 581,000 458,000 421,000 Average annual sales price (dollars) Natural gas (per Mcf) . . . . . . . . . . . . . $ 2.86 $ 2.84 $ 2.74 $ 2.88 $ 2.79 Crude oil and condensate (per Bbl) . . . . . . 16.31 18.49 18.95 22.89 18.36 Natural gas liquids produced (per Bbl) . . . . 12.18 13.41 13.41 14.36 10.50 Drilling program (gross wells) Wells drilled . . . . . . . . . . . . . . . . . 154 152 163 156 133 Wells completed . . . . . . . . . . . . . . . . 127 129 134 133 122 Well count at year end (gross wells) . . . . . . . 3,413 3,532 3,666 3,613 3,124 REAL ESTATE OPERATING STATISTICS The Woodlands Residential lots sold . . . . . . . . . . . . . . 844 911 910 907 882 Average price per lot (dollars) . . . . . . . . 39,055 38,196 36,400 32,431 26,822 Average price per square foot (dollars) . . . . 3.38 3.14 2.95 2.59 2.37 Commercial and institutional acreage sold . . . . 144 58 171 16 27 Office, industrial and retail space managed (thousands of square feet) . . . . . . . 2,204 2,140 1,798 1,786 1,711 Apartment units managed . . . . . . . . . . . . . . 1,883 2,055 2,055 1,915 1,279 Bulk acreage sold . . . . . . . . . . . . . . . . . 250 -- 565 -- 74 STOCKHOLDERS' EQUITY (per share at year end) . . . $ 14.26 $ 13.55 $ 13.59 $ 13.05 $ 12.41 RATIO OF EARNINGS TO FIXED CHARGES . . . . . . . . 1.30x 1.18x 1.45x 1.30x 1.05x 67
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Historical Summary MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES YEAR ENDED JANUARY 31 (IN THOUSANDS EXCEPT PER SHARE DATA) [Enlarge/Download Table] 1994 1993(a) 1992 1991 1990 -------- -------- -------- -------- -------- REVENUES Exploration and Production . . . . . . . . . . . . . . $266,166 $214,681 $231,073 $237,301 $230,861 -------- -------- -------- -------- -------- Transmission and Processing Gas processing . . . . . . . . . . . . . . . . . . 255,537 309,917 271,497 241,073 164,275 Gas gathering and transmission . . . . . . . . . . 296,373 248,605 231,068 203,709 169,313 Other . . . . . . . . . . . . . . . . . . . . . . . 8,627 8,178 9,414 10,391 5,504 -------- -------- -------- -------- -------- 560,537 566,700 511,979 455,173 339,092 -------- -------- -------- -------- -------- Real Estate . . . . . . . . . . . . . . . . . . . . . . 126,106 121,453 131,318 98,803 88,079 -------- -------- -------- -------- -------- Total revenues . . . . . . . . . . . . . . . . . . $952,809 $902,834 $874,370 $791,277 $658,032 ======== ======== ======== ======== ======== SEGMENT OPERATING EARNINGS Exploration and Production Operations . . . . . . . . . . . . . . . . . . . . $66,583 $43,318 $41,264 $56,062 $62,549 Restructuring charges . . . . . . . . . . . . . . . -- (20,726) -- -- -- -------- -------- -------- -------- -------- 66,583 22,592 41,264 56,062 62,549 -------- -------- -------- -------- -------- Transmission and Processing Gas processing . . . . . . . . . . . . . . . . . . 21,932 60,370 64,900 74,282 35,795 Gas gathering and transmission . . . . . . . . . . 18,742 25,517 23,212 20,866 10,001 Other . . . . . . . . . . . . . . . . . . . . . . . 1,985 2,617 1,745 2,897 2,828 -------- -------- -------- -------- -------- 42,659 88,504 89,857 98,045 48,624 -------- -------- -------- -------- -------- Real Estate . . . . . . . . . . . . . . . . . . . . . . 21,078 22,801 22,724 4,313(b) 15,120 -------- -------- -------- -------- -------- Total segment operating earnings . . . . . . . . 130,320 133,897 153,845 158,420 126,293 General and administrative expense . . . . . . . . . . 43,222 41,398 38,184 37,638 36,962 Interest expense . . . . . . . . . . . . . . . . . . . 74,057 75,284 81,169 88,387 90,239 Capitalized interest . . . . . . . . . . . . . . . . . (35,721) (36,205) (39,426) (45,427) (46,993) Other expense . . . . . . . . . . . . . . . . . . . . . 1,224 6,096 5,618 6,224 (50) -------- -------- -------- -------- -------- EARNINGS BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . . . . . . . . . 47,538 47,324 68,300 71,598 46,135 Income taxes . . . . . . . . . . . . . . . . . . . . . 22,425(c) 11,035 23,954 24,343 15,686 -------- -------- -------- -------- -------- EARNINGS BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . . . . . . . . . . . . . . 25,113 36,289 44,346 47,255 30,449 Extraordinary item . . . . . . . . . . . . . . . . . . (5,426) (7,251) -- -- -- Cumulative effect of change in accounting methods . . . . . . . . . . . . . . . . -- (10,551) -- -- -- -------- -------- -------- -------- -------- NET EARNINGS . . . . . . . . . . . . . . . . . . . . . $ 19,687 $ 18,487 $ 44,346 $ 47,255 $ 30,449 ======== ======== ======== ======== ======== PER COMMON SHARE AMOUNTS Earnings before extraordinary item and cumulative effect of change in accounting methods . . . . . . . . . . . . . . . . $ .49 $ .77 $ .95 $ 1.01 $ .65 Extraordinary item . . . . . . . . . . . . . . . . . . (.10) (.15) -- -- -- Cumulative effect of change in accounting methods . . . -- (.23) -- -- -- -------- -------- -------- -------- -------- Net earnings . . . . . . . . . . . . . . . . . . . . . $ .39 $ .39 $ .95 $ 1.01 $ .65 ======== ======== ======== ======== ======== CASH DIVIDENDS (cents per share) Prior to stock reclassification . . . . . . . . . . . . 20.00 40.00 34.00 36.00 Class A . . . . . . . . . . . . . . . . . . . . . . . . 48.00 22.00 Class B . . . . . . . . . . . . . . . . . . . . . . . . 53.00 23.75 AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . 51,004 46,858 46,849 46,935 46,868 (a) Where applicable, amounts are after pretax restructuring charges which reduced Exploration and Production segment operating earnings by $20.7 million; an additional $.5 million was charged to other expense. (b) After asset write-downs of $11.6 million. (c) Includes $11 million deferred provision related to an increase from 34% to 35% in the corporate statutory Federal income tax rate. 68
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BOARD OF DIRECTORS [Enlarge/Download Table] GEORGE P. MITCHELL SHAKER A. KHAYATT (1) MICHAEL B. MORRIS (1) Chairman and President and Petroleum Consultant; Chief Executive Officer, Chief Executive Officer, retired President of Mitchell Energy & Khayatt and Company, Inc. Petroleum Operations, Development Corp. (investment banking), Conoco, Inc., New York City Houston BERNARD F. CLARK Vice Chairman, BEN F. LOVE (2)(3) RAYMOND L. WATSON (2) Mitchell Energy & Consultant; Chairman, Development Corp. retired Chairman and Executive Committee Chief Executive Officer, of the Board of Directors, W. D. STEVENS (3) Texas Commerce Bancshares, The Walt Disney Company, President and Houston Burbank, California; Chief Operating Officer, Vice Chairman, President-Exploration and WALTER A. LUBANKO (2) The Irvine Company, Production Division, Chairman and President, Newport Beach, California Mitchell Energy & W.A. Lubanko & Co., Inc. Development Corp. (investment banking), BENJAMIN N. WOODSON (2) Brookville, New York Independent Insurance ROBERT W. BALDWIN (1) Consultant; Partner, Consultant M. KENT MITCHELL (1)(3) FIF Management, Ltd. (energy/management); President and (investment management); retired President, Chief Executive Officer, retired Chairman and Gulf Refining and Marketing Bald Head Island Chief Executive Officer, Company (a division of Management, Inc. American General Corporation, Gulf Oil Corp.), (real estate development), Houston Houston Bald Head Island, North Carolina (1) Compensation Committee WILLIAM D. EBERLE (1)(3) (2) Audit Committee Chairman, J. TODD MITCHELL (3) (3) Executive Committee EBCO, Inc. (hotel, real estate President, and service business); The Discovery Bay Company President, Manchester (seismic software) and Associates, Ltd. (international Dolomite Resources, Inc. business consulting), (exploration and investments), Boston and Washington, D.C. Houston 69
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PRINCIPAL OFFICERS [Enlarge/Download Table] (PICTURE) GEORGE P. MITCHELL Chairman and Chief Executive Officer BERNARD F. CLARK (PICTURE) (PICTURE) W. D. STEVENS Vice Chairman President and Chief Operating Officer, President-Exploration and Production Division ROGER L. GALATAS (PICTURE) (PICTURE) PHILIP S. SMITH Corporate Senior Corporate Senior Vice President, Vice President, President-Real Estate Chief Financial Officer and Division President-Administration and Financial Division ALLEN J. TARBUTTON, JR. (PICTURE) (PICTURE) THOMAS P. BATTLE Corporate Senior Corporate Senior Vice President, Vice President, President-Transmission General Counsel and Processing Division and Secretary 70
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CORPORATE INFORMATION [Enlarge/Download Table] STOCK LISTINGS FORM 10-K New York Stock Exchange Copies of the Company's The Pacific Stock Exchange Form 10-K are available upon Ticker Symbols: MND A and MND B written request to: Options Trading: The Pacific Stock Vice President-Public Affairs Exchange Mitchell Energy & Development Corp. P.O. Box 4000 TRANSFER AGENT AND REGISTRAR The Woodlands, Texas 77387-4000 Chemical Shareholder Services Group, Inc. Phone: 713-377-5650 c/o Chemical Bank 450 West 33rd St. New York, New York 10001 Phone: 1-800-635-9270 ANNUAL MEETING 10 a.m. CDT Wednesday, June 29, 1994 The Woodlands Executive Conference Center and Resort 2301 North Millbend The Woodlands, Texas 77380 Design: Gluth, Weaver Design Artwork: Mike Benny Photography: Robb Kendrick, Robert Mihovil, Cliff Roe, Gaylon Wampler, Ted Washington Printing: Champagne Fine Printing 71
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[Download Table] MITCHELL ENERGY & DEVELOPMENT CORP. Bulk Rate U.S. Postage P.O. BOX 4000 PAID 2001 TIMBERLOCH PLACE Spring, Texas THE WOODLANDS, TEXAS 77387-4000 Permit No. 67 (713) 377-5500 AN EQUAL OPPORTUNITY EMPLOYER

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