Snyder Oil Corp – ‘10-K/A’ for 12/31/93

As of:  Monday, 4/25/94   ·   For:  12/31/93   ·   Accession #:  860713-94-12   ·   File #:  1-10509

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SNYDER OIL CORPORATION        

Annual Report on Form 10-K        
December 31, 1993         

PART I            

ITEM 1.  BUSINESS                                                               

General                                                                         

Snyder Oil Corporation (the "Company") is engaged in the              
development and acquisition of oil and gas properties primarily in              
the Rocky Mountain region of the United States. The Company also                
gathers, transports, processes and markets natural gas generally in             
proximity to its principal producing properties. Over the five year             
period from 1988 to 1993, revenues increased from $14.7 million to              
$229.9 million, net income increased from $5.1 million to $25.7                 
million and net cash provided by operations increased from $8.1                 
million to $68.3 million. At December 31, 1993, the Company's net               
proved reserves totaled 103.6 million barrels of oil equivalent                 
("MMBOE"), having a pretax present value at constant prices of $390.4           
million. Approximately 69% of its proved reserves are natural gas.              

Approximately 90% of the present value of the Company's proved        
reserves is concentrated in five major producing areas located in               
Colorado, Wyoming and Texas. In total, the Company's properties are             
located in 15 states and the Gulf of Mexico and include 5,122 gross             
(2,187 net) producing wells and nine gas transportation and                     
processing facilities. The Company operates more than 2,100 wells               
which account for over 90% of its developed reserves. In addition to            
its domestic operations, the Company is also participating in several           
international exploration and development projects through its wholly           
owned subsidiary, SOCO International, Inc., and through its 36% owned           
affiliate, Command Petroleum Holdings NL. At December 31, 1993, the             
Company held undeveloped acreage totaling 539,000 gross acres                   
(326,000 net) domestically and 4.3 million gross acres (3.3 million             
net) internationally.                                                           

The Company has pursued a balanced strategy of development            
drilling and acquisitions, focusing on operating efficiency and                 
enhanced profitability through the concentration of assets in                   
selected geographic areas or "hubs." Currently, the primary emphasis            
of the Company's growth strategy is development drilling in the                 
Rockies, mainly the Wattenberg Field in the Denver-Julesburg Basin              
("DJ Basin") of Colorado where the Company drilled 323 wells in 1993.           
In implementing this strategy in the Wattenberg Field over the past             
three years, the Company has achieved the following: (i) drilled                
approximately 667 wells, 660 of which are currently producing; (ii)             
increased production more than five times, from an average of 2.6               
MBOE per day in 1991 to an average of 13.3 MBOE per day in 1993;                
(iii) increased proved reserves nearly 50% from 37.9 MMBOE at yearend           
1991 to 55.2 MMBOE at yearend 1993; and (iv) generally reduced                  
drilling and completion costs by  over 30% through a combination of             
aggressive cost cutting, economies of scale and technological                   
improvements. Through a major joint venture with Union Pacific                  
Resources Company, as well as acquisitions and leasing, the Company             
has accumulated a substantial inventory of potential drilling                   
locations, including 1,102 locations that were classified as proved             
undeveloped at December 31, 1993.                                               

In 1993, the Company embarked on a program to apply the               
experience gained in the Wattenberg Field to two other large scale              
gas developments in the Rockies. In the Washakie Basin of southern              
Wyoming (the "East Washakie Project"), the Company currently operates           
128 wells and holds a significant inventory of potential drilling               
locations, including 98 locations that were classified as proved                
undeveloped at December 31, 1993. The Company has also initiated the            
development of a third hub in the Rockies through three purchase                
transactions, as well as farmouts and leasing. As a result, the                 
Company currently holds a significant inventory of potential drilling           
locations in the Piceance and Uinta Basins of Colorado and Utah                 
(collectively, the "Western Slope Project"), including 101 locations            
that were classified as proved undeveloped at December 31, 1993.                

During 1994, the Company intends to continue development in the       
DJ Basin and to increase activity in the East Washakie and Western              
Slope Projects. The Company expects to spend $175 to $200 million for           
development drilling and expansion of gas facilities in 1994,                   
including the drilling of over 650 wells, 500 of which are planned              
for the Wattenberg Field and up to 90 for the East Washakie and                 
Western Slope Projects. As part of this program, the Company will               
emphasize the improvement of well economics through the use of                  
technological improvements and cost saving drilling techniques, as              
well as the capture of downstream margins via the Company's gas                 
facilities. In addition to development drilling in the Rockies, the             
Company intends to pursue acquisitions to strengthen its existing               
asset base and secure a foothold in new geographic areas and to                 
continue progress in bringing its international projects to fruition.           

Development                                                                     

General.  Since 1990, development drilling has become the             
primary focus of the Company's growth strategy. The Company believes            
that its existing properties have extensive development drilling and            
enhancement potential, primarily in the DJ Basin of Colorado, the               
Washakie Basin in southern Wyoming, the Piceance and Uinta Basins in            
western Colorado and Utah and in the Giddings Field in southern                 
Texas. The Company designs its major drilling programs to reduce                
risk, create synergies with its gas management operations and exploit           
the potential for continuous cost improvement. In 1994, the Company             
expects to drill over 650 wells, including approximately 500 wells in           
the Wattenberg Field, where the size of its operations enables it to            
continue to refine the application of new drilling, completion and              
operating techniques, and to apply the experience gained there to               
establish other large scale development projects in the Rockies.                

In its large scale development projects, the Company also             
attempts to acquire and maintain a sizeable inventory of potential              
drilling locations, many of which may not be economic at current cost           
and price levels, but which the Company believes may ultimately prove           
attractive to develop if reservoir assumptions are validated and well           
economics improve over the life of the project through cost                     
reductions or price increases. No assurances can be given that such             
conditions will be satisfied and, accordingly, that such locations              
will be drilled.                                                                

Assuming no material changes in product prices and capital            
availability, the Company estimates that it will expend from $150 to            
$200 million per year for development drilling and gas facilities               
over the next three to five years. Such expenditures totalled $64.8             
million in 1992 and $112.8 million in 1993, primarily in the                    
Wattenberg Field.                                                               

DJ Basin                  

Wattenberg Field.  The Wattenberg Field is the Company's largest      
base of operations, representing over  55% of total proved reserves.            
Between 1991 and 1993, the Company drilled a total of 667 wells in              
Wattenberg, of which 323 were drilled during 1993. At yearend, the              
Company had interests in more than 1,400 producing wells, of which              
the Company operated over 1,100. Through a major joint venture with             
UPRC, complementary acquisitions and an extensive leasing program,              
the Company has accumulated up to 6,000 potential drilling locations            
in the Wattenberg Field. The Company expects that over half of these            
sites will ultimately prove attractive to develop. The Company                  
expects to drill approximately 500 wells per year in the Wattenberg             
Field for at least the next several years.                                      

At yearend 1993, the net proved reserves attributed to the            
Wattenberg properties were 16.9 million barrels of oil and 229.9 Bcf            
of gas. The reserves were attributable to 1,437 producing wells, 51             
wells in progress, 1,102 proved undeveloped locations and                       
approximately 387 proved behind pipe zones. The Company expects                 
proved reserves to be assigned to other locations as drilling                   
progresses.                                                                     

The Company acquired its first properties in Wattenberg during        
1986. In 1990, it substantially increased its acreage position by               
acquiring rights to the Codell and Niobrara formations underlying               
32,985 net acres from Amoco Production Company ("Amoco") for $14.4              
million. Several farm-ins from Amoco in 1992, financed primarily                
through a transfer of Section 29 tax credits, resulted in earning               
additional Codell/Niobrara rights as well as rights to the Sussex, J-           
Sand and Dakota formations in a number of locations. During 1993, a             
series of purchases added nearly 9 MMBOE at a net cost of under $3.50           
per barrel as well as several pipeline and processing facilities that           
complement existing facilities. See "Acquisition Program."                      

In early 1994, the Company finalized an agreement with UPRC           
under which the Company has the right for up to six years to drill              
wells on locations of its choosing on UPRC's previously uncommitted             
undeveloped acreage throughout the Wattenberg area. This transaction            
substantially increased the Company's Wattenberg undeveloped acreage            
inventory. Many of the locations have the potential for improved                
economics through completion in one or more of the Shannon, Sussex,             
J-Sand or Dakota formations, as well as the Codell and Niobrara.                
During the venture's initial three-year term, the Company is required           
to drill a minimum of 120, 120 and 60 wells per year. After the                 
initial period, the Company can, at its option, extend the venture              
annually for up to three additional years by drilling at least 150              
wells per year. There is no limit on the maximum number of wells that           
can be drilled, and wells in excess of the required minimum in any              
year will reduce the number of wells required in the following year             
by up to 50%. If the Company drills less than the minimum number of             
wells, it is required to pay UPRC $20,000 per well for the shortfall.           
On each well that is drilled on UPRC's mineral acreage under the                
venture, UPRC retains a 15% mineral owner royalty and has the option            
either to receive an additional 10% royalty interest after pay-out or           
to participate in the well as a 50% working interest owner. On                  
leasehold acreage, UPRC does not have the right to participate in the           
well but will retain a royalty interest that will result in a total             
royalty burden of 25%. As compensation for committing its acreage               
position to the Company, UPRC was granted warrants to purchase two              
million shares of the Company's Common Stock. See "Management's                 
Discussion and Analysis of Financial Condition and Results of                   
Operations -- Development, Acquisition and Exploration."                        

Drilling.  The Company began drilling operations in Wattenberg        
in early 1991. From 1991 to December 1993, the Company expended                 
$151.1 million to drill 667 wells, of which 323 were drilled in 1993.           
At yearend, 609 of these wells were producing, 51 were in various               
stages of drilling and completion and seven were dry holes.                     

The size of the Wattenberg drilling program has resulted in           
numerous advantages. The Company acts as operator on all its                    
development sites in the Wattenberg Field and much of the acreage is            
held by production. As a result, the Company has significant                    
operational control over the timing of the development program. The             
actual drilling locations and schedule are selected to minimize costs           
associated with rig moves, surface facilities, location preparation             
and gathering system and pipeline connections and to evaluate and               
quantify incremental reserve potential across the acreage position.             

The Company's success in continuing to reduce its costs of            
drilling and operations, as well as applying new technology, will be            
important to the full development of its undeveloped acreage in                 
Wattenberg. The Company has selected procedures for drilling and                
completing wells that it believes maximize recoverable reserves and             
economics. The Company has also been able to reduce its costs of                
drilling, completing and operating wells significantly by negotiating           
favorable prices with suppliers of drilling and completion services             
because of the size of its drilling program. These cost reductions              
often allow the Company to earn an attractive rate of return even on            
lower reserve wells. The reductions have been achieved by several               
methods. One of the most significant is the formation of alliances              
with selected vendors who work with Company personnel to improve                
coordination and reduce both parties' costs. The resultant reductions           
are credited wholly or in large part to the Company while vendors'              
margins are maintained or increased.                                            

In addition to cost reduction, the Company seeks to employ new        
technology or to creatively apply existing technology to reduce costs           
or to produce reserves that would otherwise remain unrecovered. One             
example is the drilling of four or more wells from a single drilling            
pad in residential areas, under reservoirs and on inaccessible                  
acreage.                                                                        

The Codell formation, which is the primary objective of the           
drilling, is a blanket siltstone formation that exists under much of            
the Wattenberg acreage at depths of 6,700 to 7,500 feet. Codell                 
reserves have a high degree of predictability due to uniform                    
deposition and gradual transition from high to low gas/oil ratio                
areas. The Company generally dually completes the Niobrara chalk                
formation, which lies immediately above the Codell, to enhance                  
drilling economics. The Codell/Niobrara wells produce most                      
prolifically in the first six to twelve months, after which                     
production declines to a fraction of initial rates. More than half of           
a typical well's reserves are recovered in the first three years of             
production. As a result, each well contributes significantly more               
production in its first year than in subsequent years. However, the             
declining production of individual wells is expected to be offset by            
continuing development drilling.                                                

During 1992 and 1993, the Company expanded its drilling targets       
to include both deeper and shallower formations. The J sand lies                
approximately 400 feet below the Codell. It is a low permeability               
sandstone generally found to be productive throughout the DJ Basin              
with performance varying proportionately with porosity and thickness.           
The Dakota formation lies approximately 150 feet below the J sand. It           
is a low permeability sand occasionally naturally fractured with less           
predictable commercial accumulations and varied performance results.            
The Sussex formation is at average depths of 4,500 feet. The Sussex             
sands were deposited as bars and exhibit variable reservoir quality             
with a moderate degree of predictability.                                       

Because the Codell, Niobrara and J formations are continuous          
reservoirs over a large portion of the DJ Basin, the Company believes           
that drilling in the Wattenberg Field is relatively low risk. In                
addition, the Company has compiled a comprehensive geologic and                 
production database for approximately 12,000 wells within a 4,350               
square mile area between Denver and the Wyoming border and has had              
considerable success in predicting variations in thickness, porosity,           
gas/oil ratios and productivity. Of the 667 wells drilled between               
1991 and 1993, only seven have been dry holes. Dry holes cost an                
average of only $65,000 per well. The average net cost of a completed           
well approximated $193,000 during 1993 with only 30 days usually                
elapsing between spud date and initial production.                              

Cheyenne.  During 1993, 29 wells were placed on stream in a           
shallow gas producing area on the northeast flank of the DJ Basin.              
This project, known as the Cheyenne Project, began with the                     
acquisition of five shut-in gas wells in 1990 when the Company                  
determined that it could capitalize on new open access rules of the             
Federal Energy Regulatory Commission ("FERC") by constructing a                 
gathering system to transport gas to a nearby interstate pipeline.              
After acquiring almost 50,000 acres of leases in the area and selling           
an approximate 27.5% interest to other parties on a promoted basis,             
the Company has drilled 54 successful wells and six dry holes in the            
area and constructed a gathering system having a capacity of 10 Mmcf            
per day to transport the gas to the interstate pipeline. The Company            
currently operates 61 wells in this area that produce from the                  
Niobrara formation and plans to drill approximately 20 additional               
wells during 1994.                                                              

East Washakie                 

During 1993, the Company initiated a major project to apply the       
cost-cutting and improved drilling and completion techniques learned            
in the Wattenberg Field to develop fluvial Mesaverde sands in the               
eastern Washakie Basin. An eleven well pilot project was completed in           
1993 to test drilling and completion techniques and confirm cost                
estimates. A second drilling program is currently being initiated.              
After final evaluation of the drilling, the Company may initiate a              
large scale drilling program in this area upon completion of a                  
required environmental impact statement. The environmental impact               
statement was filed in October 1993, and clearance is currently                 
expected in the second half of 1994. Depending on the timing of                 
environmental clearance and continued evaluation of drilling results,           
the Company expects to drill up to 60 wells in East Washakie during             
1994.                                                                           

Since the mid-1980's, the Company's properties in the Barrel          
Springs Unit and the Blue Gap Field of southern Wyoming, together               
with its gas gathering and transportation facilities there, have been           
one of its most significant assets. See "Gas Management" and                    
"Properties - Significant Properties."  The Company currently                   
operates 128 wells in this area and holds up to 1,200 potential                 
drilling locations, 98 of which were classified as proved undeveloped           
at yearend 1993. The Company believes that more than half of the                
potential locations may ultimately prove attractive to develop. The             
Company currently holds interests in 95,000 gross (76,000 net)                  
undeveloped acres in the Washakie Basin. This includes 36,000 gross             
(32,000 net) undeveloped acres added during 1993.                               

Western Slope             

During 1993, the Company initiated the Western Slope Project by       
establishing a sizable position in the Piceance Basin on the western            
slope of Colorado and in the Uinta Basin in northeastern Utah. The              
Company formed the 53,000 acre Hunter Mesa Unit in the southeast                
corner of the Piceance Basin. Through purchases and farmouts, the               
Company obtained a majority interest and acts as unit operator.                 
Immediately adjacent to the Hunter Mesa Unit, a 100% working interest           
was purchased in the 26,000 acre Divide Creek Unit for $6.2 million.            
The acquisition of this Unit, which has six wells producing from the            
Mesaverde and Cameo Coal formations, added 17.6 Bcf of proved gas               
reserves as well as an established operating base. Near yearend, the            
Company also purchased interests in 122 producing wells, 29 non-                
producing wells and 69 proved undeveloped locations. In total, this             
purchase included 55,000 net acres in various fields in the Piceance            
and Uinta Basins.                                                               

Through these purchases, farmouts and a leasing program, the          
Company currently holds acreage with up to 1,000 potential drilling             
locations, of which the Company believes 40% could ultimately prove             
to be attractive to develop. Of these locations, 101 were classified            
as proved undeveloped at yearend 1993. The development of the                   
Mesaverde sands in the Piceance Basin began with the spudding of the            
initial test well near the end of 1993. The development will continue           
with a 10 well test program during 1994 to confirm cost estimates and           
improved recovery techniques. If successful, the Company may drill up           
to 30 wells in 1994 and approximately 100 wells per year thereafter.            
The Company's ability to continue to develop the Piceance Basin is in           
part dependent on arranging gathering and transportation at a                   
reasonable cost. The company is exploring options for gathering and             
transporting future gas production, including the possibility of                
constructing Company owned facilities.                                          

Other Development             

At the end of 1992, the Company acquired interests in four large      
producing fields in central Wyoming from a major oil company at a               
cost of $56.1 million. Two of the fields, the Hamilton Dome and                 
Riverton Dome Fields, are operated by the Company. During 1993, the             
Company evaluated opportunities in the fields and instituted programs           
to enhance production in the latter part of the year. In the Hamilton           
Dome Field, improvement of the water injection system and completion            
of two new wells increased daily production 8% above the levels                 
projected at the time of the acquisition. A third well should be                
completed in the second quarter of 1994. In the Riverton Dome Field,            
workovers and recompletions increased daily production over 10% above           
the levels projected at the time of the acquisition. Additional                 
workovers and development drilling are scheduled for both fields                
during 1994. The Company is attempting to work with the major oil               
companies that operate the other two fields purchased, both of which            
are producing slightly below acquisition projections.                           

The Company operates the Adair waterflood property in Gaines          
County, Texas, which it purchased in September 1991. Initial                    
development of the Adair Unit in 1992 cost approximately $1.7 million           
net to the Company. Based on production response from the initial               
phase of development, the Company spent an additional $.4 million in            
1993 to conduct a pilot program which reduced well spacing on a                 
portion of the Unit. This program increased the unit production from            
150 barrels per day to 260 barrels per day. The Company plans to                
spend an additional $1.1 million to implement an infill development             
program throughout the Unit.                                                    

In the Giddings Field in Southeast Texas, the Company has             
undertaken a horizontal drilling program to further exploit existing            
properties in the area. During 1993, the Company spent $2.2 million             
to re-enter or drill 10 wells, of which nine were completed and one             
abandoned. The Company is encouraged by the results to date and plans           
to increase its expenditures in the field during 1994. At yearend, 25           
locations were classified as having proved undeveloped reserves.                

Acquisition Program                                                             

The Company believes that acquisitions continue to be an              
attractive method of increasing its reserve base and cash flow. In              
its acquisition efforts, the Company plans to focus on purchasing               
properties that strengthen its strategic position and complement its            
large-scale gas development projects in the Rockies, as well as                 
provide opportunities to establish meaningful positions in new areas.           
From 1983 through 1993 the Company, on behalf of itself, its                    
affiliates and other investors, purchased oil and gas properties and            
related assets with an aggregate cost of nearly $650 million. The               
Company actively seeks to acquire incremental interests in existing             
properties, acreage with development potential, gas gathering,                  
transportation and processing facilities and related assets,                    
particularly in proximity to existing properties. Purchases of                  
incremental interests or adjacent properties are generally small in             
size but in aggregate represent a sizeable opportunity that is                  
relatively easy to pursue.                                                      

Due to its rate of return requirements and the high cost of           
pursuing potential acquisitions, the Company generally prefers                  
negotiated transactions to auctions. Complex transactions involving             
legal, financial or operational difficulties have frequently                    
permitted purchase of assets at favorable prices. Past acquisitions             
of corporations laid the groundwork for the Wattenberg hub, and may             
in the future provide opportunities to expand in other areas.                   
Acquisitions of incremental interests are being given particular                
emphasis to take advantage of systems and operational knowledge                 
already in place. The Company has extensive experience in completing            
numerous types of acquisitions using varied financing sources in                
addition to internal cash flow.                                                 

During 1993 domestic acquisitions having a total cost of $51.0        
million were completed, primarily to strengthen Wattenberg and                  
establish two new hubs that the Company believes have the potential             
to develop into large scale gas development projects. In Wattenberg             
a series of purchases added nearly 9 million BOE of proved reserves             
at a net cost of under $3.50 per barrel as well as several pipeline             
and processing facilities that complement the Company's existing                
gathering systems. In the largest of these acquisitions, the Company            
paid $19.7 million and, after an exchange of interests with a third             
party, acquired an approximate 80% working interest in 153 producing            
wells and 284 undeveloped locations having total proved reserves                
estimated to exceed 7 million BOE. A portion of the value of the                
transaction lay in the large volume of undedicated gas located in               
close proximity to the Company's gas lines.                                     

In the Washakie Basin, the Company expended over $7.8 million to      
acquire a 25% incremental interest in its Barrel Springs properties             
and interests in 44 producing wells and 7 undeveloped locations, as             
well as a gathering system that expands the existing gathering                  
infrastructure in the area. These acquisitions added approximately              
3.6 million BOE of proved reserves and, together with an active                 
leasing program, formed the basis for the East Washakie Project, the            
Company's second operating hub in the Rockies. See "Development -               
East Washakie."                                                                 

Through three purchase transactions, as well as farmouts and          
leasing, the Company established a substantial position in the                  
Piceance and Uinta Basins during 1993, laying the foundation of the             
Western Slope Project, a third gas development hub in the Rockies. A            
$6.2 million purchase gave the Company a 100% working interest in the           
26,000 acre Divide Creek Unit in the southeast Piceance Basin. The              
Company also formed the adjacent 53,000 acre Hunter Mesa Unit and               
through purchases and farmouts obtained a majority working interest             
position and became unit operator. Near yearend the Company also                
acquired interests in 122 producing wells, 29 non-producing wells and           
69 proved undeveloped locations in various fields in the Uinta and              
Piceance Basins. See "Development - Western Slope."                             

The following table summarizes acquisition activity since 1983:       

                                                                [Download Table]

                                                   Purchase Price                
Year    Major Assets Acquired                           Company Affiliates  Total
                                                                                 
1983 Louisiana gas pipeline                         $     3.5 $      -       $3.5
1984 Various producing properties                        27.8        -       27.8
1985 Utah, Texas and Oklahoma properties                 56.1        -       56.1
1986 Colorado and Wyoming properties                     61.8       15.4     77.2
1987 Mississippi and Colorado properties, Roggen                                 
     gas plant, Wyoming gas facilities                   71.0        -       71.0
1988 Various producing properties                        33.8       18.5     52.3
1989 Various producing properties                        12.3       56.9     69.2
1990 Wattenberg properties, incremental interests       161.2 (a)    -      161.2
1991 Waterflood properties, incremental interests         9.9        -        9.9
1992 Wyoming properties, incremental interests           63.6        -       63.6
1993 Colorado and Wyoming properties,                                            
     incremental interests, acreage                      51.0        -       51.0

     Total                                           $  552.0 $     90.8 $  642.8

        (a)  Includes the acquisition of a publicly traded partnership managed
by the Company.                                   

Gas Management                                                                  

General.  The Company expanded its gas gathering and processing       
capacity during 1993 with the construction of additional gathering              
facilities and expansion of the Roggen plant in Wattenberg, as well             
as the acquisition of additional gas facilities in Wattenberg and in            
Wyoming. By yearend, operated processing capacity had increased to              
more than 80 MMcf per day and gathering system capacity was increased           
to more than 200 MMcf per day, while marketed net volumes reached 100           
MMcf per day. The gas management unit complements the Company's                 
development and acquisition activities by providing additional cash             
flow and enhancing returns. The segment is also increasingly                    
profitable in its own right. During 1993, gross margin increased by             
approximately 23% to $10 million. See "Customers and Marketing."                

Colorado Facilities.  The largest concentration of gas                
facilities is in the Wattenberg area. These facilities include two              
major gathering systems, the Enterprise system and Energy Pipeline,             
the Roggen processing plant, and a number of minor facilities. By               
yearend 1993, the Roggen plant capacity had reached 60 million cubic            
feet ("MMcf") per day. During the fourth quarter of 1993, average               
throughput had reached 54 MMcf per day. The plant is expected to                
process gas from currently undeveloped locations, new third party               
sources and permanently released locations on acreage acquired from             
Amoco, plus additional gas from current suppliers. Gas developed                
through the UPRC joint venture is not dedicated to a processing plant           
and will significantly increase future volumes of gas available to be           
processed in the Company's facilities.                                          

The gas produced from the majority of the new Wattenberg wells        
drilled on acreage acquired from Amoco is dedicated for the life of             
the lease to Amoco's Wattenberg gas processing plant. If Amoco were             
unable to process Company production at its plant for any reason,               
including a shut-down of the plant, it would have a short-term                  
adverse impact on the Company. The Company has expanded its                     
processing facilities in Wattenberg in order to process Company and             
third party gas that is not dedicated to Amoco. The Company intends             
to continue to expand its facilities during 1994 to handle additional           
gas developed through continued drilling activity. These facilities             
will also enable the Company to partially mitigate the effects of               
significant downtime at the Amoco plant.                                        

At the Roggen plant, gas is processed to recover gas liquids,         
primarily propane and a butane/gasoline mix, from gas supplied by the           
Company and third parties. The liquids are then sold separately from            
the residue gas. The liquids are marketed to local and regional                 
distributors and the residue gas is sold to utilities, independent              
marketers and end users through an intrastate system and the Colorado           
Interstate Gas ("CIG") pipeline. A liquids line permits the direct              
sale of Roggen's liquids products through an Amoco line to the major            
interchange at Conway, Kansas. In addition, Phillips Petroleum began            
reactivation of an old interconnect, which should be operational by             
the end of the second quarter of 1994, which will connect the Roggen            
plant to the Phillips Powder River liquids pipeline.                            

The Company's Wattenberg gathering systems include over 600           
miles of pipeline that collect, compress and deliver gas from over              
1,400 wells to the Roggen plant. During 1993, the Company                       
substantially increased the capacity of its gathering systems through           
the expansion of existing facilities and the acquisition of new                 
facilities. The Company also completed the second phase of the                  
Enterprise system during 1993. Enterprise collects a portion of the             
Company's gas produced from acreage acquired from Amoco and delivers            
it to the Amoco Wattenberg plant. Enterprise includes 26 miles of 20"           
diameter trunk and 29 miles of associated lateral gathering lines               
connecting 20 of the Company's existing central delivery points. As             
a result of the completion of the second phase, the Enterprise system           
has the capacity to deliver 75 MMcf per day to the Amoco Wattenberg             
plant.                                                                          

During 1993, the Company also expanded its gathering system by        
constructing a nine mile 16" pipeline loop on the western portion of            
its Energy Pipeline system, which came on line in October 1993. This            
expansion provides pressure relief and additional capacity for                  
further development in the area. In addition, the Company acquired a            
pipeline that expands its gathering capacity to the north of the                
Roggen plant, which may be converted to a residue line allowing for             
the delivery of residue gas from the tailgate of the Roggen plant to            
the Williams Natural Gas System.                                                

The Company has negotiated a transportation arrangement with CIG      
that, in conjunction with the gathering fees to be charged on the               
Enterprise system, allows the delivery of gas to the Amoco Wattenberg           
plant at a favorable rate. In addition to reducing the Company's                
exposure to future escalation in gathering costs applicable to the              
Company's production, Enterprise provides an enhanced degree of                 
operational control. Because the Enterprise system interconnects with           
the Company's other Colorado facilities, the Roggen plant and other             
plants in the area can serve as a backup for processing a portion of            
the Company's gas in the event of any curtailment at the Amoco                  
Wattenberg plant. While shut downs of Amoco's plant reduce the                  
Company's production, diversion of gas to the Roggen plant and, to a            
lesser degree, two other plants in the area, enabled the Company to             
produce significant volumes that would have otherwise been curtailed.           

Given the continued expansion of the Company's drilling program       
in 1994 and beyond and the potential for third party connections, the           
Company is continuing to explore opportunities to expand its                    
Wattenberg gas facilities. Subsequent to yearend, the decision was              
made to double the Company's processing capacity through the                    
construction of a new plant on the west side of the field. The new              
plant is scheduled to be operational in late 1994.                              

Wyoming Facilities.  The Company operates two pipeline systems        
in Wyoming that enhance its ability to market gas produced from its             
properties in the Washakie Basin. Wyoming Gathering and Production              
Company ("WYGAP") gathers gas produced from 53 operated wells in the            
Barrel Springs Unit. The system has a capacity of 26 MMcf per day.              
Throughput averaged 10 MMcf and 14 MMcf per day during 1992 and 1993,           
respectively. WYGAP delivers gas to Western Transmission Corporation            
("Westrans"), a Company-owned interstate pipeline system which                  
operates under FERC jurisdiction. At the beginning of 1993, the                 
Company assumed operations of CIG's Carbon County Blue Gap gathering            
system pursuant to a lease. The Company has exercised an option to              
acquire the system subject to regulatory approval. The Company also             
purchased Blue Gap gathering facilities formerly owned by Williams              
Field Services. Both systems extend the Company's transportation                
capabilities to the south.                                                      

The Westrans system consists of a 26-mile main pipeline, a            
smaller 9.2-mile line and related gathering facilities. The system              
gathers and transports gas under open access transportation service             
agreements on an interruptible basis. The main line extends from the            
Washakie Basin area of Carbon County, Wyoming to connections with               
Williams' and CIG's interstate pipelines in Sweetwater County,                  
Wyoming. Gas transported on Westrans also has access to California              
markets through the Kern River Pipeline which was completed in                  
February 1992 via interconnects with CIG and Williams. Westrans is              
located near several other interstate pipelines, providing the                  
potential for additional interconnects that offer alternative                   
transportation routes to end markets. In addition to the gas from               
WYGAP, which accounts for over 90% of its volumes, Westrans                     
transports volumes from other operated wells and third parties. The             
capacity of Westrans is 65 MMcf per day. Throughput volumes generally           
vary from 13 to 20 MMcf per day. Daily throughput averaged 15 MMcf              
during 1992 and 1993. If the planned acceleration of drilling in East           
Washakie occurs, volumes of gas on the Company's gas pipeline in the            
area may be substantially increased. As the East Washakie Project               
progresses, the Company expects to further expand its gathering                 
network in the area.                                                            

Other Facilities.  The Company expanded its gathering system in       
southern Nebraska during 1993 to gather gas produced from newly                 
developed Cheyenne County properties for delivery to various markets            
accessible through an interstate pipeline. The Cheyenne system                  
includes 9.5 miles of 4" to 6" trunkline and 6 miles of 3" lateral              
gathering lines. During the fourth quarter of 1993, throughput                  
averaged 3 MMcf per day of gas from 60 producing wells. Included in             
the December 1992 acquisition of Wyoming properties was a gas                   
processing plant in Fremont County, Wyoming. The plant has a 20 MMcf            
per day capacity with current throughput of 8 MMcf per day from the             
28 producing wells in the Riverton Dome Field.                                  

In conjunction with the growing level of acquisition and              
development activity in the Western Slope Project, the Company is               
actively exploring alternatives to gather and transport future gas              
production, including the possible construction of a Company-owned              
gathering and transportation line. Traditionally, the lack of                   
sufficient pipeline capacity has been a major deterrent to                      
development in the Piceance Basin.                                              

International Activities                                                        

The Company's strategy internationally is to develop projects         
that have the potential for a major impact in the future. The Company           
attempts to structure the projects to limit its financial exposure              
and mitigate political risk by minimizing financial commitments in              
the early phases of a project and seeking industry partners and                 
investors to fund the majority of the equity capital. A wholly owned            
subsidiary of the Company, SOCO International, Inc., is the holding             
company for all the Company's international operations. During 1993,            
the Company purchased from Edward T. Story, President of SOCO                   
International, the 10% of SOCO International held by him and canceled           
Mr. Story's option to purchase an additional 20% of the company. In             
connection with the purchase, the Company granted Mr. Story an option           
to purchase 10% of the currently outstanding shares of SOCO                     
International, which is financed primarily by Company loans, through            
April 1998 for $600,000. The option price is subject to adjustment in           
certain circumstances.                                                          

Russian Joint Venture.  In early 1993, the Company formed             
Permtex, a joint drilling venture with Permneft, a Russian oil and              
gas company, to develop four major proven oil fields located in the             
Volga-Urals Basin of the Perm Region of Russia, approximately 800               
miles east of Moscow. During 1993, Permtex was registered by the                
Russian authorities, representing governmental approval of the terms            
of the joint venture and authorization for Permtex to commence                  
business. In early 1994, the Company executed a finance and insurance           
protocol with OPIC, an agency of the United States government that              
provides financing and political risk insurance for American                    
investment in developing countries, related to the financing of                 
Permtex.                                                                        

Permtex holds exploration and development rights to over 300,000      
acres in the Volga-Urals Basin. The contract area contains four major           
fields and four minor fields as well as a number of prospects. The              
Company estimates that the four major fields could ultimately produce           
115 million barrels of oil. The major fields have been delineated               
through 45 previously drilled wells, none of which had been placed on           
production as of yearend 1993. It is anticipated that 25 of the                 
existing wells will be placed on production, of which four should go            
on stream in the first half of 1994, and that 400 additional                    
development wells will be drilled over the next five to ten years.              
The joint venture will primarily utilize Russian personnel and                  
equipment and Western technology under joint Russian/American                   
management.                                                                     

As of March 1, 1994, the Company holds a 28.1% interest in            
Permtex, after giving effect to the purchases by each of Command, the           
Company's Australian affiliate, and Holland Sea Search NV ("HSSH"),             
a Dutch affiliate of Command, of 6.25% interests in Permtex.                    
Recently, a major Japanese trading company has also committed to                
purchase a 10 to 20% interest in Permtex, which would reduce the                
Company's interest to 20.6% if the full amount is purchased.                    

Command Petroleum Holdings NL.  In May 1993, the Company              
purchased 42.8% of the outstanding shares of Command for                        
approximately $18.2 million. At the time of the purchase, Thomas J.             
Edelman, President of the Company, Edward T. Story, President of SOCO           
International, and two other designees were elected to Command's                
eight-person board of directors. Command is an exploration and                  
production company based in Sydney, Australia and listed on the                 
Australian Stock Exchange. Following a private placement of equity              
securities in early 1994, Command had working capital of $35 million            
and no debt. Its current market capitalization approximates US$150              
million. Command currently holds interests in more than 20                      
exploration permits and production licenses primarily in the                    
Southwestern Pacific Rim including Australia and Papua New Guinea.              
Until recently, Command held a 28.7% interest in HSSH, a publicly               
traded Dutch exploration and production company whose primary asset             
is an interest in the North Sea's Markham gas field. After yearend              
1993, Command increased its position in HSSH to nearly 48%. Recently,           
Command purchased a 6.25% interest in Permtex, acquired an interest             
in an offshore Tunisian permit operated by Marathon Oil Company and             
acquired an 11.4% interest in the East Shabwa Contract Area in Yemen.           
Command funded the expenditures with a portion of a $16.4 million               
privately placed equity offering which reduced the Company's                    
ownership to 35.7%. If as expected, all of Command's warrants                   
expiring in November 1994 are exercised, the Company's ownership                
would be decreased to 29.6%.                                                    

The Company believes that Command's exploration expertise,            
experienced technical staff and inventory of prospects complement the           
Company's acquisition and development expertise and position the                
Company to play a larger role in overseas development of oil and gas            
reserves. In addition, Command and HSSH provide access to                       
international capital markets which could provide additional sources            
of financing for international projects.                                        

Mongolia.  The Company further expanded its international             
efforts by entering into a production sharing agreement with Mongol             
Petroleum Company, the national oil company of Mongolia. The Company            
believes this agreement is the first such contract ever awarded by              
Mongolia. The agreement covers 11,400 square kilometers, or                     
approximately 2.8 million gross acres, in the Tamstag Basin of                  
northeastern Mongolia. In addition, the Company received a right of             
first refusal from Mongol Petroleum for the adjacent block which                
covers 11,130 square kilometers. As a consequence, the Company                  
controls over 5 million acres in this basin which, although                     
previously unexplored and remote from existing markets, is highly               
prospective. These concessions offset the Hailar Basin of China, a              
portion of which is included in the China National Petroleum                    
Corporation's round of invitations for bidding in 1994. During 1993,            
the Company initiated seismic work to broadly define the subsurface             
and this work is expected to continue into 1995.                                

Tunisia.  During 1993 the Company completed its 400 kilometer         
seismic acquisition program in the Fejaj Permit area of central                 
Tunisia. The permit area encompasses approximately 1.2 million gross            
acres and is predominately onshore, with a small portion extending              
into the Gulf of Gabes. After the Company integrates the newly                  
acquired seismic work with over 1,400 kilometers of reprocessed data            
and extensive geological field information, the Company will seek               
industry partners for a 1995 exploratory well.                                  

Production, Revenue and Price History                                           

The following table sets forth information regarding net              
production of crude oil and liquids and natural gas, revenues and               
expenses attributable to such production and to natural gas                     
transportation, processing and marketing and certain price and cost             
information for the five years ended December 31, 1993.                         

                                                        [Enlarge/Download Table]


                                                    December 31,                      
                               1989         1990       1991           1992      1993  

                                                                                      
Production                                                                            
Oil (MBbl)                        277        1,049      1,487          1,776     3,451
 Gas (MMcf)                     4,027       12,769     18,382         23,090    35,080
 MBOE (c)                         948        3,497      4,937          5,989     9,297

Revenues                                                                              
 Oil production              $  5,069     $ 24,806   $ 30,667       $ 33,512  $ 53,174
 Gas production (a)             7,410       24,997     34,677         43,851    71,467
      Subtotal                 12,479       49,803     65,344         77,363   124,641
 Transportation, processing                                                           
      and marketing            10,885       29,442     21,459         38,611    94,839
 Interest and other             3,179        2,928      5,698          4,198    10,405
      Total                  $ 26,543     $ 82,173   $ 92,501       $120,172  $229,885

Operating expenses                                                                    
 Production                  $  4,930     $ 18,088   $ 24,882       $ 28,057  $ 44,901
 Transportation, processing                                                           
      and marketing             9,168       24,103     14,202         30,469    84,840
                             $ 14,098     $ 42,191   $ 39,084       $ 58,526  $129,741

Gross margin                 $ 12,445     $ 39,982   $ 53,417       $ 61,646  $100,144

Production data                                                                       
 Average sales price (b)                                                              
      Oil (Bbl)             $   18.30     $  23.65   $  20.62       $  18.87  $  15.41
      Gas (Mcf) (a) (c)          1.65         1.69       1.68           1.74      1.94
      BOE (c)                   12.97        14.18      13.24          12.92     13.41
 Average operating expense/BOE$    5.20  $    5.17  $    5.04     $    4.68   $   4.83


(a) Gas production is converted to oil equivalents at the rate of 6             
Mcf per barrel, except for Thomasville Field gas which through 1992             
was converted based on its price equivalency to the Company's other             
gas.  Average gas prices exclude Thomasville production.  See                   
"Management's Discussion and Analysis of Financial Condition and                
Results of Operations."                                                         
(b) Sales of natural gas liquids are included in gas revenues.  Gas             
revenues for the year ended December 31, 1989 and 1990 include                  
nonrecurring receipts of $183,000 and $219,000, respectively, in                
settlement of contract claims, which have been excluded from average            
sales price computations.                                                       
(c) The Company estimates that its composite net wellhead prices at             
December 31, 1993 were approximately $2.11 per Mcf of gas and $11.49            
per barrel of oil.                                                              

Drilling Results                                                                

The following table sets forth information with respect to wells              
drilled during the past three years.  The information should not be             
considered indicative of future performance, nor should it be assumed           
that there is necessarily any correlation between the number of                 
productive wells drilled, quantities of reserves found or economic              
value.  Productive wells are those that produce commercial quantities           
of hydrocarbons whether or not they produce a reasonable rate of                
return.                                                                         

                                                                [Download Table]


                                              1991          1992           1993 
                                                                                
                Development wells                                               
                  Productive                                                    
                   Gross                      143.0         241.0          382.0
                   Net                        117.2         207.5          316.0
                  Dry                                                           
                   Gross                        3.0           6.0           10.0
                   Net                          2.8           2.7            5.5

                Exploratory wells                                               
                  Productive                                                    
                   Gross                        5.0           -              2.0
                   Net                          1.8           -              2.0
                  Dry                                                           
                   Gross                        5.0           -              6.0
                   Net                          1.5           -              3.3
(                                                                               

As of December 31, 1993, the Company had 61 gross (50.9 net)                  
development wells in progress.  Between yearend and February 28,                
1994, the Company spudded 118 wells.  At that date 135 gross (116.7             
net) wells, including wells in progress at yearend, had been                    
completed, two wells (1.5 net) had been abandoned and 42 gross (36.3            
net) development wells were in progress.                                        

Field Operations                                                                

In its capacity as operator, the Company supervises day-to-day field          
activities, generally employing a combination of its personnel and              
contract pumpers.  The Company maintains eight district field offices           
and one division office.                                                        

As operator, the Company charges overhead fees to all working               
interest owners according to the applicable operating agreements.  As           
of the end of 1991, 1992 and 1993, respectively, the Company operated           
1,442, 1,745 and 2,176 wells.  The Company received overhead                    
reimbursements for operations and drilling of $10.1 million,                    
$12.9 million and $15.5 million during 1991, 1992 and 1993,                     
respectively (including reimbursements attributable to the Company's            
interest).  The increase in reimbursements is attributable to the               
increase in operated drilling and producing wells and contractual               
escalations.   Based on the time allocated to operations, these                 
reimbursements in aggregate generally have exceeded the costs of such           
activities.                                                                     

Customers and Marketing                                                         

The Company's oil and gas production is principally sold to refiners          
and others having pipeline facilities near its properties. Where                
there is no access to gathering systems, crude oil is trucked to                
storage facilities. In 1992 and 1993, Amoco accounted for                       
approximately 27% and 12% of revenues, respectively, as the result of           
the contractual dedication, which terminated at the end of 1993, of             
a portion of the Company's natural gas and natural gas liquids                  
produced from certain of its Wattenberg acreage. Historically, this             
arrangement provided for average prices in excess of spot due to                
participation in certain fixed price contracts, many of which are               
expected to expire over the next two years. The Company exercised its           
option to release its natural gas and natural gas liquids and began             
marketing its production beginning January 1, 1994. The Company                 
believes, however, that it can obtain pricing comparable to that                
which would have been obtainable through Amoco. The marketing of oil            
and gas by the Company can be affected by a number of factors that              
are beyond its control and whose future effect cannot be accurately             
predicted. The Company does not believe, however, that the loss of              
any of its customers would have a material adverse effect on its                
operations.                                                                     

In addition to marketing a significant portion of its own gas, in             
1992 the Company initiated an effort to supplement its cash flow                
through the purchase and resale of gas owned by third parties. Gross            
margins during 1992 and 1993 from third party marketing activities              
was $.6 million and $1.2 million, respectively, as average third                
party volumes increased from 58.7 to 89.9 MMcf per day. The Company             
expects to continue increasing its role in third party gas marketing.           

In June 1991, the Company entered into a contract to supply gas to            
a cogeneration facility through August 2004. The contract calls for             
the Company to supply 10,000 MMBtu per day. This plant, which                   
requires up to 24,500 MMBtu per day of gas, began operations in 1989            
and is located at a manufacturing facility in Oklahoma City. The                
facility has firm fifteen-year sales agreements with a utility                  
company for electricity and with a tire manufacturer for steam. The             
effect of this contract depends on market prices for gas and its                
choice of alternative sources of gas (including the spot market) to             
meet its supply commitments. Gross margin generated from the contract           
was approximately $1.5 million for both 1991 and 1992. A contractual            
limitation of the contract sales price and rising gas purchase costs            
resulted in a net loss of $267,000 on the contract during 1993. At              
present gas price levels, the Company foresees continued negative or            
breakeven margins for this contract through July 1994. At that time,            
a change in the pricing formula should result in improved margins.              

Competition                                                                     

The oil and gas industry is highly competitive in all its phases.             
Competition is particularly intense with respect to the acquisition             
of producing properties.  There is also competition for the                     
acquisition of oil and gas leases, in the hiring of experienced                 
personnel and from other industries in supplying alternative sources            
of energy.                                                                      

Competitors in acquisitions, exploration, development and production          
include the major oil companies in addition to numerous independent             
oil companies, individual proprietors, drilling and acquisition                 
programs and others.  Many of these competitors possess financial and           
personnel resources substantially in excess of those available to the           
Company.  Such competitors may be able to pay more for desirable                
leases and to evaluate, bid for and purchase a greater number of                
properties than the financial or personnel resources of the Company             
permit.  The ability of the Company to increase reserves in the                 
future will be dependent on its ability to select and acquire                   
suitable producing properties and prospects for future exploration              
and development.                                                                

Title to Properties                                                             

Title to the properties is subject to royalty, overriding royalty,            
carried and other similar interests and contractual arrangements                
customary in the oil and gas industry, to liens incident to operating           
agreements and for current taxes not yet due and other comparatively            
minor encumbrances.  The majority of the value of the Company's                 
properties is mortgaged to secure borrowings under the bank credit              
agreement.                                                                      

As is customary in the oil and gas industry, only a perfunctory               
investigation as to ownership is conducted at the time undeveloped              
properties believed to be suitable for drilling are acquired.  Prior            
to the commencement of drilling on a tract, a detailed title                    
examination is conducted and curative work is performed with respect            
to known significant defects.                                                   

Regulation                                                                      

The Company's operations are affected by political developments and           
federal and state laws and regulations.  Oil and gas industry                   
legislation and administrative regulations are periodically changed             
for a variety of political, economic and other reasons.  Numerous               
departments and agencies, federal, state, local and Indian, issue               
rules and regulations binding on the oil and gas industry, some of              
which carry substantial penalties for failure to comply.   The                  
regulatory burden on the oil and gas industry increases the Company's           
cost of doing business, decreases flexibility in the timing of                  
operations and may adversely affect the economics of capital                    
projects.                                                                       

In the past, the federal government has regulated the prices at               
which oil and gas could be sold.  Prices of oil and gas sold by the             
Company are not currently regulated.  There can be no assurance,                
however, that sales of the Company's production will not be subject             
to federal regulation in the future.                                            

The following discussion of various statutes, rules, regulations or           
governmental orders to which the Company's operations may be subject            
is necessarily brief and is not intended to be a complete discussion            
thereof.                                                                        

Federal Regulation of Natural Gas.  Historically, the sale and                
transportation of natural gas in interstate commerce have been                  
regulated under various federal and state laws including, but not               
limited to, the Natural Gas Act of 1938, as amended ("NGA") and the             
Natural Gas Policy Act of 1978 ("NGPA"), both of which are                      
administered by FERC.  However, regulation of first sales, including            
the certificate and abandonment requirements and price regulation,              
was phased out during the late 1980's and all remaining wellhead                
price ceilings terminated on January 1, 1993.                                   

FERC continues to have jurisdiction over transportation and sales             
other than first sales. Commencing in the mid-1980's, FERC                      
promulgated several orders designed to correct perceived market                 
distortions resulting from the traditional role of major interstate             
pipeline companies as wholesalers of gas and to make gas markets more           
competitive by removing transportation and other barriers to market             
access.  These orders have had and will continue to have a                      
significant influence on natural gas markets in the United States and           
have, among other things, allowed non-pipeline companies, including             
the Company, to market gas and fostered the development of a large              
spot market for gas.  These orders have gone through various                    
permutations, due in significant part to FERC's response to court               
review of these orders.  Parts of these orders remain subject to                
judicial review, and the Company is unable to predict the impact on             
its natural gas production and marketing operations of judicial                 
review of these orders.                                                         

In April 1992, FERC issued Order 636, a rule designed to restructure          
the interstate natural gas transportation and marketing system to               
remove various barriers and practices that have historically limited            
non-pipeline gas sellers, including producers, from effectively                 
competing with pipelines.  The restructuring process will be                    
implemented on a pipeline-by-pipeline basis through negotiations in             
individual pipeline proceedings. Although Order 636 does not regulate           
any of the Company's material gas operations, FERC has stated that              
Order 636 is intended to foster increased competition in all phases             
of the natural gas industry.  Industry commentators have predicted              
profound effects (which vary from commentator to commentator) on                
various segments of the industry as a result of this competition.               
Order 636 is being implemented on a pipeline-by-pipeline basis                  
through negotiated settlements in independent pipeline service                  
restructuring proceedings designed specifically to "unbundle" the               
pipelines' services (e.g., transportation, sales and storage) so that           
producers, marketers and end-users of natural gas may secure services           
from the most economical source.                                                

The restructuring proceedings continued throughout 1993, with the             
majority of pipelines having received FERC orders approving their               
compliance filings, subject to conditions, so that the 1993-1994                
winter heating season is the first period during which FERC Order 636           
procedures have been operative.  To date, management of the Company             
believes the Order 636 procedures have not had any significant effect           
on the Company.  Because the restructuring involved wholesale changes           
in the operating procedures of pipelines, however, the Company is not           
able to predict the long term effect of the new procedures. Also, the           
Order and many of the pipeline procedures adopted in response                   
thereto, will be subject to lengthy administrative and judicial                 
review, which may result in procedures that are significantly                   
different from those currently in effect.                                       

When it issued Order 636, FERC recognized that in an effort to                
enable non-pipeline gas sellers to compete more effectively with                
pipelines, it should not allow pipelines to be penalized as                     
competitors by any of their existing contracts which required the               
pipelines to pay above-market prices for natural gas.  FERC                     
recognized that it did not have authority to nullify these contracts,           
and instead encouraged pipelines and producers to negotiate in good             
faith to terminate or amend these contracts to align them with market           
conditions. During 1993, the Company renegotiated its contract with             
Southern Natural Gas Company ("SONAT") under which SONAT had                    
purchased the Company's gas from the Thomasville Field at prices                
substantially above market value. As a result of the renegotiation,             
the Company received a $14 million payment and beginning January 1,             
1994 the Company will receive a price that, while somewhat above                
current prices, will be substantially lower that the average 1993               
contract price of $12.16 per Mcf.                                               

State Regulation of Transportation of Natural Gas.  Some states have          
adopted open-access transportation rules or policies requiring                  
intrastate pipelines or local distribution companies to transport               
natural gas to the extent of available capacity.  These rules or                
policies, like federal rules, are designed to increase competition in           
natural gas markets.  The economic impact on the Company and gas                
producers generally of these rules and policies is uncertain.                   

State Regulation of Drilling and Production.  State regulatory                
authorities have established rules and regulations requiring permits            
for drilling, reclamation and plugging bonds and reports concerning             
operations, among other matters.  Most states in which the Company              
operates also have statutes and regulations governing a number of               
environmental and conservation matters, including the unitization or            
pooling of oil and gas properties and establishment of maximum rates            
of production from oil and gas wells.  Some states also restrict                
production to the market demand for oil and gas. Such statutes and              
regulations may limit the rate at which oil and gas could otherwise             
be produced from the Company's properties.  Some states have enacted            
statutes prescribing ceiling prices for gas sold within the state.              

During the current session of the Colorado legislature, the Colorado          
Department of Natural Resources has prepared a bill ("SB 177"), which           
gives additional authority to the Colorado Oil and Gas Conservation             
Commission ("COGCC") in their regulation of the oil and gas industry.           
The bill has currently passed the Senate Agricultural Committee and             
will be presented to the full legislature in March.  This bill is               
very similar to legislation proposed during the 1993 legislature                
session.  Legislation of this type could increase the cost of the               
Company's operations and erode the traditional rights of the oil and            
gas industry in Colorado to make reasonable use of the surface to               
conduct drilling and development activities.  In addition, a                    
coalition of oil and gas industry and agriculture are working on a              
Surface Damage Compensation bill.  The group will try to have the               
bill sponsored and passed in this session of the legislature.  This             
bill, if enacted, would also increase the Company's cost of doing               
business.                                                                       

Also at the statewide level, the surface owner groups have indicated          
that they may seek a statewide ballot initiative to overturn the                
traditional real property concept of the dominance of the mineral               
estate and put the surface estate as the dominate estate.  These same           
groups are also active at the local level, and there have been a                
number of city and county governments who have either enacted new               
regulations or are considering doing so.  The incidence of such local           
regulation has increased following a recent decision of the Colorado            
Supreme Court which held that local governments could not prohibit              
the conduct of drilling activities which were the subject of permits            
issued by the COGCC, but that they could limit those activities under           
their land use authority.  Under these decisions, local                         
municipalities and counties may take the position that they have the            
authority to impose restrictions or conditions on the conduct of such           
operations which could materially increase the cost of such                     
operations or even render them entirely uneconomic.  The Company is             
not able to predict which jurisdictions may adopt such regulations,             
what form they may take, or the ultimate effects of such enactments             
on its operations.  In general, however, these ordinances are aimed             
at increasing the involvement of local governments in the permitting            
of oil and gas operations, requiring additional restrictions or                 
conditions on the conduct of operations, to reduce the impact on the            
surrounding community and increasing financial assurance                        
requirements.  Accordingly, the ordinances have the potential to                
delay and increase the cost, or in some cases, to prohibit entirely             
the conduct of drilling operations.                                             

In response to the concerns of surface owners, during 1993 the COGCC          
adopted, regulations for the DJ Basin governing notice to and                   
consultation with surface owners prior to the conduct of drilling               
operations, imposing specific reclamation requirements on operators             
upon the conclusion of operations and containing bonding requirements           
for the protection of surface owners and enhanced financial assurance           
requirements.  Although numerous changes are expected in light of the           
recently adopted and pending regulatory initiatives, management is              
not able to predict the final form of these initiatives or their                
impact on the Company.                                                          

In December 1992, COGCC instituted a review of "slimhole"                     
completions (i.e., completions using pipe having a diameter of less             
than 4-1/2") and expressed concerns that slimhole completions could             
result in the loss of reserves, cause environmental damage and result           
in increased abandonment costs to the State.  Hearings on the matter            
were scheduled for February 1994.  Following meetings of                        
representatives of the Company and other major Wattenberg operators             
with the COGCC at which the operators discussed slimhole techniques,            
the hearings were postponed until May.  Although the Company believes           
that slimhole completion is a safe and economically viable completion           
method, the Company is unable to predict what, if any regulations               
might be adopted by the COGCC or their effect on the Company.                   
Regulations that imposed significant restrictions on slimhole                   
completions, however, could increase the cost of the Company's                  
drilling operations and could cause certain locations to become                 
uneconomic.                                                                     

Environmental Regulations.  Operations of the Company are subject to          
numerous laws and regulations governing the discharge of materials              
into the environment or otherwise relating to environmental                     
protection. These laws and regulations may require the acquisition of           
a permit before drilling commences, prohibit drilling activities on             
certain lands lying within wilderness and other protected areas and             
impose substantial liabilities for pollution resulting from drilling            
operations.  Such laws and regulations also restrict air or other               
pollution and disposal of wastes resulting from the operation of gas            
processing plants, pipeline systems and other facilities owned                  
directly or indirectly by the Company.                                          

In connection with its most significant acquisitions, the Company             
has performed environmental assessments and found no material                   
environmental noncompliance or clean-up liabilities requiring action            
in the near or intermediate future, although some matters identified            
in the environmental assessments are subject to ongoing review.  The            
Company has assumed responsibility for some of the matters                      
identified.  Some of the Company's properties, particularly larger              
units that have been in operation for several decades, may require              
significant costs for reclamation and restoration when operations               
eventually cease.  Environmental assessments have not been performed            
on all of the Company's properties.  To date, expenditures for                  
environmental control facilities and for remediation have not been              
significant to the Company.  The Company believes, however, that it             
is reasonably likely that the trend toward stricter standards in                
environmental legislation and regulations will continue.  For                   
instance, efforts have been made in Congress to amend the Resource              
Conservation and Recovery Act to reclassify oil and gas production              
wastes as "hazardous waste," the effect of which would be to further            
regulate the handling, transportation and disposal of such waste.  If           
such legislation were to pass, it could have a significant adverse              
impact on the Company's operating costs, as well as the oil and gas             
industry in general.                                                            

New initiatives regulating the disposal of oil and gas waste are              
also pending in certain states, including states in which the Company           
conducts operations, and these various initiatives could have a                 
similar impact on the Company.  The COGCC has enacted rules regarding           
the regulation of disposal of oil field waste.  These rules establish           
significant new permitting, record-keeping and compliance procedures            
relating to the operation of pits, the disposal of produced water,              
and the disposal and/or treatment of oil field waste, including waste           
currently exempt from federal regulation.  These rules may require              
the addition of technical personnel to perform the necessary record-            
keeping and compliance and may require the termination of production            
from some of the Company's marginal wells, for which the cost of                
compliance would exceed the value of remaining production.  In                  
addition, as indicated above, the COGCC has enacted regulations                 
imposing specific reclamation requirements on operators upon the                
conclusion of their operations.  Management believes that compliance            
with current applicable laws and regulations will not have a material           
adverse impact on the Company.                                                  

A number of states have recently established more stringent                   
environmental regulations to ensure compliance with federal                     
regulations, and have either proposed or are considering regulations            
to implement the Federal Clean Air Act.  These new regulations are              
not expected to have a significant impact on the Company or its                 
operation.  In the longer term, regulations under the Federal Clean             
Air Act may increase the number and type of Company facilities that             
require permits, which could increase the Company's cost of                     
operations and restrict its activities in certain areas.                        

Federal Leases.  The Company conducts operations under federal oil            
and gas leases.  These operations must be conducted in accordance               
with permits issued by the Bureau of Land Management and are subject            
to a number of other regulatory restrictions.  Multi-well drilling              
projects on federal leases may require preparation of an                        
environmental assessment or environmental impact statement before               
drilling may commence. Moreover, on certain federal leases, prior               
approval of drill site locations must be obtained from the                      
Environmental Protection Agency.                                                

Officers                                                                        

In early 1993, the Company restructured its organization, dividing            
operations into four separate business units and decentralized a                
number of staff functions.  Each business unit has bottom line                  
responsibility in order to reduce administrative costs, increase                
efficiency and increase focus on enhancing asset value.  The flatter            
organization structure should also assist the Company in capitalizing           
on opportunities that may result in significant growth, including               
acquisitions and additional enhancement projects.                               

Listed below are the officers and a summary of their recent business          
experience.                                                                     

Name                       Position                                             

John C. Snyder             Chairman and Director                                
Thomas J. Edelman          President and Director                               
John A. Fanning            Executive Vice President and Director                
Charles A. Brown           Vice President - Emerging Assets                     
Steven M. Burr             Vice President - Planning and Engineering            
Robert J. Clark            Vice President - Gas Management;                     
        President, SOCO Gas Systems Inc.
Gary R. Haefele            Vice President - DJ Basin                            
Peter E. Lorenzen          Vice President - General Counsel and                 
Secretary               
James H. Shonsey, Jr.      Vice President - Corporate Services and              
Controller              
Edward T. Story            Vice President - International; President,           
SOCO International, Inc.
Diana K. Ten Eyck          Vice President - Investor Relations                  
Rodney L. Waller           Vice President - Special Projects                    
Richard A. Wollin          Vice President - Asset Rationalization               

John C. Snyder (52), a director and Chairman, founded the Company's           
predecessor in 1978.  From 1973 to 1977, Mr. Snyder was an                      
independent oil operator in Texas and Oklahoma.  Previously, he was             
a director and the Executive Vice President of May Petroleum Inc.               
where he served from 1971 to 1973.  Mr. Snyder was the first                    
president of Canadian-American Resources Fund, Inc., which he founded           
in 1969.  From 1964 to 1966, Mr. Snyder was employed by Humble Oil              
and Refining Company (currently Exxon Co., USA) as a petroleum                  
engineer. Mr. Snyder received his Bachelor of Science Degree in                 
Petroleum Engineering from the University of Oklahoma and his Masters           
Degree in Business Administration from the Harvard University                   
Graduate School of Business Administration.  Mr. Snyder is a director           
of the Fort Worth Country Day School.                                           

Thomas J. Edelman (43), a director and President, co-founded the              
Company.  Prior to joining the Company in 1981, he was a Vice                   
President of The First Boston Corporation.  From 1975 through 1980,             
Mr. Edelman was with Lehman Brothers Kuhn Loeb Incorporated.  Mr.               
Edelman received his Bachelor of Arts Degree from Princeton                     
University and his Masters Degree in Finance from the Harvard                   
University Graduate School of Business Administration.  Mr. Edelman             
is a director of Command Petroleum Holdings NL, an affiliate of the             
Company.  In addition, Mr. Edelman serves as chairman of the board of           
Lomak Petroleum, Inc. and as a director of Petroleum Heat & Power               
Co., Inc., Wolverine Exploration Company and Total Energy Services              
Corporation.                                                                    

John A. Fanning (54), a director and Executive Vice President,                
joined the Company in 1987 and has been a director since 1982.                  
Between 1985 and 1987, Mr. Fanning was a private investor.  He was a            
director, President and Chief Executive Officer of The Western                  
Company of North America, which provides drilling and technical                 
services to the oil industry, until 1985. Mr. Fanning joined The                
Western Company in 1968 and served in various capacities including              
Director of Planning, Division Manager, President of Western                    
Petroleum Services and Executive Vice President.  From 1965 through             
1968, he was a Planning and Financial Analyst with The Cabot                    
Corporation.  Mr. Fanning received his Bachelor of Science Degree in            
Physics from Holy Cross College and his Masters Degree in Industrial            
Management from Massachusetts Institute of Technology.  Mr. Fanning             
is a director of TNP Enterprises Inc, a public utility holding                  
company.                                                                        

Charles A. Brown (47), Vice President - Emerging Assets, joined the           
Company in 1987.  He was a petroleum engineering consultant from 1986           
to 1987.  He served as President of CBW Services, Inc., a petroleum             
engineering consulting firm, from 1979 to 1986 and was employed by KN           
from 1971 to 1979 and Amerada Hess Corporation from 1969 to 1971.               
Mr. Brown received his Bachelor of Science Degree in Petroleum                  
Engineering from the Colorado School of Mines.                                  

Steven M. Burr (37), Vice President - Planning and Engineering,               
joined the Company in 1987.  From 1982 to 1987, he was a Vice                   
President with the petroleum engineering consulting firm of                     
Netherland, Sewell & Associates, Inc. ("NSAI").  From 1978 to 1982,             
Mr. Burr was employed by Exxon Company, U.S.A. in the Production                
Department.  Mr. Burr received his Bachelor of Science Degree in                
Civil Engineering from Tulane University.                                       

Robert J. Clark (49), President of SOCO Gas Systems Inc. and Vice             
President - Gas Management of the Company, joined the Company in                
1988.  From 1985 to 1988, Mr. Clark was Vice President - Natural Gas            
for Ladd Petroleum Corporation, a subsidiary of General Electric                
Company.  From 1967 to 1985, Mr. Clark served in various management             
capacities with Northern Illinois Gas Company, NICOR Exploration                
Company and Reliance Pipeline Company, all of which were subsidiaries           
of NICOR, Inc.  Mr. Clark received his Bachelor of Science Degree in            
Accounting from Bradley University and his Masters Degree in Business           
Administration from Northern Illinois University.                               

Gary R. Haefele (51), Vice President - DJ Basin, rejoined the                 
Company in 1993.  Mr. Haefele was a consultant to the Company in                
1992.  From 1981 to 1991, Mr. Haefele worked for the Company as                 
Senior Vice President, Production.  Mr. Haefele served as Vice                  
President, Engineering and International Operations for Hamilton                
Brothers from 1979 to 1981.  Mr. Haefele held various production and            
reservoir engineering positions for Chevron from 1965 to 1979.  Mr.             
Haefele has a Bachelor of Science Degree in Petroleum Engineering               
from the University of Wyoming.                                                 

Peter E. Lorenzen (44), Vice President - General Counsel and                  
Secretary, joined the Company in 1991.  From 1983 through 1991, he              
was a shareholder in the Dallas law firm of Johnson & Gibbs, P.C.               
Prior to that, Mr. Lorenzen was an associate with Cravath, Swaine &             
Moore.  Mr. Lorenzen received his law degree from New York University           
School of Law and his Bachelor of Arts Degree from Johns Hopkins                
University.                                                                     

James H. Shonsey (42), Vice President - Controller, joined the                
Company in 1991.  From 1987 to 1991, Mr. Shonsey served in various              
capacities including Director of Operations Accounting for Apache               
Corporation.  From 1976 to 1987 he held various positions with                  
Deloitte & Touche, Quantum Resources Corporation, Flare Energy                  
Corporation and Mizel Petro Resources, Inc.  Mr. Shonsey received his           
CPA certificate from the state of Colorado, his Bachelor of Science             
Degree in Accounting from Regis University and his Master of Science            
Degree in Accounting from the University of Denver.                             

Edward T. Story (50), President of SOCO International, Inc. and Vice          
President - International of the Company, joined the Company in 1991.           
From 1990 to 1991, Mr. Story was Chairman of the Board of a jointly-            
owned Thai/US company, Thaitex Petroleum Company.  Mr. Story was co-            
founder, Vice Chairman of the Board and Chief Financial Officer of              
Conquest Exploration Company from 1981 to 1990.  He served as Vice              
President Finance and Chief Financial Officer of Superior Oil Company           
from 1979 to 1981.  Mr. Story held the positions of Exploration and             
Production Controller and Refining Controller with Exxon U.S.A. from            
1975 to 1979.  He held various positions in Esso Standard's                     
international companies from 1966 to 1975. Mr. Story received a                 
Bachelor of Science Degree in Accounting from Trinity University, San           
Antonio, Texas and a Masters of Business Administration from The                
University of Texas in Austin, Texas. Mr. Story is a director of                
Command Petroleum Holdings NL, an affiliate of the Company.  In                 
addition, Mr. Story serves as a director of Bank Texas, Inc., a bank            
holding company and Hi/Lo Automotive, Inc., a distributor of                    
automobile parts.                                                               

Diana K. Ten Eyck (47), Vice President - Investor Relations, joined           
the Company in 1993.  From 1990 to 1993, Ms. Ten Eyck held various              
positions with Gerrity Oil & Gas Corporation, including Director,               
Senior Vice President, Chief Operating Officer, Chief Financial                 
Officer, Chief Administrative Officer and Corporate Secretary.  From            
1988 to 1990, Ms. Ten Eyck held various positions with The Robert               
Gerrity Company including Director, Senior Vice President, Chief                
Operating, Chief Financial Officer and Corporate Secretary.  Ms. Ten            
Eyck received a Bachelor of Arts Degree in Mathematics from the                 
University of Colorado at Boulder and a Ph.D. in Mineral Economics              
from the Colorado School of Mines.                                              

Rodney L. Waller (44), Vice President - Special Projects, joined the          
Company in 1977.  Previously, Mr. Waller was employed by Arthur                 
Andersen & Co.  Mr. Waller received his Bachelor of Arts Degree from            
Harding University.  Mr. Waller serves as a director of Wolverine               
Exploration Company.                                                            

Richard A. Wollin (41), Vice President - Asset Rationalization,               
joined the Company in 1990.  From 1983 to 1989, Mr. Wollin served in            
various management capacities including Executive Vice President of             
Quinoco Petroleum, Inc. with primary responsibility for acquisition,            
divestiture and corporate finance activities.  From 1976 to 1983, he            
was employed in various capacities for The St. Paul Companies, Inc.,            
including Senior Vice President of St. Paul Oil & Gas Corp.  Mr.                
Wollin received his Bachelor of Science Degree from St. Olaf College            
and his law degree from the University of Minnesota Law School.  Mr.            
Wollin is a director of Oxford Consolidated, Inc., a public oil and             
gas company, and a member of the Minnesota Bar Association.                     

ITEM 2.  PROPERTIES                                                             

General                                                                         

The Company's reserves are concentrated in several major producing            
areas.  These include the Wattenberg Field in Colorado, central and             
southern Wyoming, the Piceance and Uinta Basins in the Western Slope            
of Colorado and Utah, the Giddings area in South Texas, the Spraberry           
Trend in West Texas, waterflood units in Texas, and the Appalachian             
Basin in eastern Ohio and Pennsylvania.                                         

At December 31, 1993, the Company had interests in 5,122 gross      
(2,187 net) producing oil and gas wells located in 15 states and in             
the Gulf of Mexico.  As of December 31, 1993, estimated proved                  
reserves totalled 31.9 million barrels of oil and 430.1 Bcf of gas.             
In addition to its oil and gas reserves, the Company holds interests            
in nine gas transportation and processing facilities.  See "Business            
- Gas Management."                                                              

Proved Reserves                                                                 

The following table sets forth estimated yearend proved reserves for          
the three years ended December 31, 1993.                                        

</TABLE>                                                                        
                                                                [Download Table]
                                          December 31,      
                                   1991      1992      1993 
                                                            

Crude oil and liquids (MBbl)                                
     Developed                    9,094     21,116    18,032
     Undeveloped                 10,584     11,086    13,898
       Total                     19,678     32,202    31,930

   Natural gas (MMcf)                                       
     Developed                  136,229    194,621   268,349
     Undeveloped                110,940     93,037   161,740
       Total                    247,169    287,658   430,089

   Total MBOE (a)                66,641     84,393   103,612

(a)  Natural gas reserves are converted to oil equivalents at the               
rate of 6 Mcf per barrel, except Thomasville Field gas reserves prior           
to 1993. See "Management's Discussion and Analysis of Financial                 
Condition and Results of Operations."                                           

The following table sets forth pretax future net revenues from the            
production of proved reserves and the Pretax PW10% Value of such                
revenues.                                                                       

                                                                [Download Table]



(In thousands)                         December 31, 1993             
                             Developed  Undeveloped(a)   Total       
                                                                     
1994                        $ 81,401      $(24,109)     $ 57,292     
1995                          59,421         1,220        60,641     
1996                          47,148         8,472        55,620     
Remainder                    286,510       228,209       514,719     
Total                       $474,480      $213,792      $688,272     

Pretax PW10% Value          $297,638      $ 92,771      $390,409  (b)

(a) Net of estimated capital costs, including estimated costs of                
$68.9 during 1994.                                                              
(b) The after tax PW10% value of proved reserves totalled $340.5                
million at yearend 1993.                                                        

The quantities and values in the preceding tables are based on        
prices in effect at December 31, 1993, averaging $11.49 per barrel of           
oil and $2.11 per Mcf of gas. Price reductions decrease reserve                 
values by lowering the future net revenues attributable to the                  
reserves and will reduce the quantities of reserves that are                    
recoverable on an economic basis. Price increases have the opposite             
effect. Any significant decline in prices of oil or gas could have a            
material adverse effect on the Company's financial condition and                
results of operations.                                                          

Proved developed reserves are proved reserves that are expected       
to be recovered from existing wells with existing equipment and                 
operating methods. Proved undeveloped reserves are proved reserves              
that are expected to be recovered from new wells drilled to known               
reservoirs on undrilled acreage for which the existence and                     
recoverability of such reserves can be estimated with reasonable                
certainty, or from existing wells where a relatively major                      
expenditure is required to establish production.                                

Future prices received for production and future production           
costs may vary, perhaps significantly, from the prices and costs                
assumed for purposes of these estimates. There can be no assurance              
that the proved reserves will be developed within the periods                   
indicated or that prices and costs will remain constant. With                   

respect to certain properties that historically have experienced                
seasonal curtailment, the reserve estimates assume that the seasonal            
pattern of such curtailment will continue in the future. There can be           
no assurance that actual production will equal the estimated amounts            
used in the preparation of reserve projections.                                 

The present values shown should not be construed as the current       
market value of the reserves. The 10% discount factor used to                   
calculate present value, which is specified by the Securities and               
Exchange Commission ("SEC"), is not necessarily the most appropriate            
discount rate, and present value, no matter what discount rate is               
used, is materially affected by assumptions as to timing of future              
production, which may prove to be inaccurate. For properties operated           
by the Company, expenses exclude the Company's share of overhead                
charges. In addition, the calculation of estimated future net                   
revenues does not take into account the effect of various cash                  
outlays, including, among other things, general and administrative              
costs and interest expense.                                                     

There are numerous uncertainties inherent in estimating               
quantities of proved reserves and in projecting future rates of                 
production and timing of development expenditures. The data in the              
above tables represent estimates only. Oil and gas reserve                      
engineering must be recognized as a subjective process of estimating            
underground accumulations of oil and gas that cannot be measured in             
an exact way, and estimates of other engineers might differ                     
materially from those shown above. The accuracy of any reserve                  
estimate is a function of the quality of available data and                     
engineering and geological interpretation and judgment. Results of              
drilling, testing and production after the date of the estimate may             
justify revisions. Accordingly, reserve estimates are often                     
materially different from the quantities of oil and gas that are                
ultimately recovered.                                                           

Netherland, Sewell & Associates, Inc. ("NSAI"), independent           
petroleum consultants, prepared estimates of or audited the Company's           
proved reserves which collectively represent more than 80% of Pretax            
PW10% Value as of December 31, 1993. Approximately 38% of the yearend           
Pretax PW10% Value was estimated internally by the Company and 62%              
was estimated independently by NSAI. No estimates of the Company's              
reserves comparable to those included herein have been included in              
reports to any federal agency other than the SEC.                               

Producing Wells                                                                 

The following table sets forth certain information at December        
31, 1993 relating to the producing wells in which the Company owned             
a working interest.  The Company also held royalty interests in 240             
producing wells.  Wells are classified as oil or gas wells according            
to their predominant production stream.                                         

                                                                [Download Table]


                                                           Average
 Principle                      Gross           Net        Working
 Product Stream                 Wells          Wells      Interest
                                                                  
Crude oil and liquids          3,026          1,297         43%   
Natural gas                    2,096            890         42%   
          Total                5,122          2,187         43%   

Acreage                                                                         

The following table sets forth certain information at December 31,            
1993 relating to acreage held by the Company.  Undeveloped acreage is           
all a acreage held under lease, permit, contract, or option that is             
not in a spacing unit for a producing well, including leasehold                 
interests identified for development or exploratory drilling.                   

                                                                [Download Table]


                                          Gross               Net
                                                                 
          Developed (a)                520,000            191,000
          Undeveloped                                            
          Domestic                     539,000            326,000
          International                                          
           Russia                      306,000             86,000
           Tunisia                   1,200,000          1,140,000
           Mongolia                  2,800,000          2,100,000
            Total undeveloped        4,845,000          3,652,000
          Total                      5,365,000          3,843,000

                                      Gross               Net    

Developed (a)                          520,000            191,000
Undeveloped                                                      
          Domestic                     539,000            326,000
          International                                          
           Russia                      306,000             86,000
           Tunisia                   1,200,000          1,140,000
           Mongolia                  2,800,000          2,100,000
            Total undeveloped        4,845,000          3,652,000
Total                                5,365,000          3,843,000

(a)  Developed acreage is acreage assigned to producing wells.                  

Significant Properties                                                          

Although the Company's properties are widely dispersed                        
geographically, emphasis has been placed on establishing hubs in                
certain producing basins.  Interests in five producing areas                    
accounted for approximately 90% of Pretax PW10% Value at December 31,           
1993.  This concentration of assets results in economic efficiencies            
in the management of assets and permits identification of                       
complementary acquisition candidates.  Summary information regarding            
reserve concentrations and more detailed information regarding the              
four most significant properties are set forth below.                           

                                                        [Enlarge/Download Table]

                                       Proved Reserve Quantities                     
                            Producing    Crude Oil     Natural  Pretax PW 10% Value  
                              Wells      & Liquids       Gas        Amount    Percent
                                          (MMBbl)      (MMcf)       (000)            
                                                                                     
DJ Basin (CO, NE)            1,336       16,984      242,155     $245,617     62.9%  
East Washakie (WYO)            135        1,334       72,871       41,903   10.7     
Central Wyoming (WYO)        1,042        7,207       28,913       30,905    7.9     
Western Slope (CO & UT)        148          439       41,070       22,113    5.7     
Giddings Field (TX)             96          752        7,987       10,960    2.8     
 Subtotal                    2,757       26,716      392,996      351,498   90.0     
Other                        2,365        5,214       37,093       38,911   10.0     
 Total                       5,122       31,930      430,089     $390,409    100.0%  
</table                                                                              

 D J Basin.  Interests in the Wattenberg Field account for most of                   
the Company's interest in the D J Basin and include 1,437 producing                  
wells (including 161 wells in which the Company owns royalty                         
interests) located principally in Weld County in northern Colorado,                  
of which 1,124 wells are operated by the Company.  Major producing                   
zones are the Codell Sandstone and Niobrara Carbonates, although the                 
Company has expanded drilling targets to include the "J" Sandstone                   
and the Sussex Sandstone and, to a lesser degree, other formations.                  
The producing zones vary in depth from 4,500 to 7,500 feet and                       
include solution gas drive oil reservoirs, gas-condensate or volatile                
oil reservoirs and retrograde condensate gas reservoirs.  The                        
reserves are considered to be medium to long-term, with gas reserves                 
representing the majority of the Pretax PW10% Value at December 31,                  
1993.  The properties contain approximately 387 proved developed                     
nonproducing (behind pipe) recompletions and 1,102 proved undeveloped                
locations at yearend 1993.  Development of these nonproducing and                    
undeveloped reserves will continue through the late 1990's.  Much of                 
the gas from Company wells is delivered to the Company's pipeline and                
processing facilities in the area.  This provides a high degree of                   
control over the transportation, processing and marketing of the DJ                  
Basin production.  See "Business - Development - D J Basin" and                      
"Business - Gas Management."                                                         

 East Washakie.  The Company operates 50 wells in the Barrel Springs                 
Unit and 78 wells in the Blue Gap Field.  The Company also owns and                  
operates Mexican Flats Service Company, Inc., which owns a disposal                  
site for water produced from the Company's and other parties' wells.                 
The major producing reservoir of both the Barrel Springs Unit and                    
Blue Gap Field is the Mesaverde, which ranges in depth from 8,000 to                 
10,000 feet.                                                                         

 Gas production accounts for approximately 95% of the 12.3 million                   
BOE of reserves for the Carbon County wells, with condensate                         
accounting for the remaining 5%.  The economic life of these wells is                
generally projected to be 30 to 40 years.  The Company holds 95,000                  
gross (76,000 net) undeveloped acres in the area, including                          
approximately 1,200 potential locations.  See "Business - Development                
- East Washakie Project."                                                            

 A subsidiary of the Company, is the major gas purchaser for the                     
Carbon County, Wyoming properties, and Total Petroleum Inc., an                      
unrelated party, purchases the condensate.  In the past, the Barrel                  
Springs Unit was shut-in or severely curtailed due to lack of a                      
market for its gas.  The Blue Gap Field has historically been                        
curtailed in the summer due to the lack of an acceptable gas price.                  
Curtailment did not occur to any significant degree in either field                  
during 1993.                                                                         

 Central Wyoming.  In December 1992, the Company acquired four large                 
producing fields and several smaller fields from Atlantic Richfield                  
Company.  The Pitchfork and Hamilton Dome fields produce sour crude                  
oil primarily from the Tensleep, Madison and Phosphoria formations at                
depths of 2,500 to 4,000 feet.  The Salt Creek field produces sweet                  
crude oil from the Wall Creek formation at depths of 2,000 to 2,900                  
feet.  The Riverton Dome field produces primarily gas from the                       
Frontier and Dakota tight sands formations at 8,000 to 10,000 feet                   
with some sour crude oil production from the Tensleep and Phosphoria.                

 The production from the Riverton Dome field is processed by a plant                 
included in the 1992 purchase by the Company.  The Company operates                  
the Hamilton Dome and Riverton Dome fields.  Approximately 86% of the                
12.0 million BOE of reserves are classified as proved producing.  Oil                
accounts for almost 60% of the reserves.   There are 10 Hamilton Dome                
and Riverton Dome drilling locations to which proved undeveloped                     
reserves have been attributed.  These reserves are planned for                       
development over the next year.  If successful, additional locations                 
could be booked as proved.  See "Business - Development - Other."                    

 Western Slope.   The Company has an interest in 148 producing wells,                
of which 58 wells are operated by the Company, in the Piceance and                   
Uinta Basins.  Major producing zones include the Uinta, Green River,                 
Wasatch, Mesaverde, Dakota, Morrison, Cozzette and Corcoran                          
formations.  Producing zones vary in depth from 3,000 to 9,000 feet.                 
Gas reserves represent the majority of the Pretax PW 10% value at                    
December 31, 1993.  The Properties contain approximately 20 proved                   
nonproducing (behind pipe) recompletions and 101 proved undeveloped                  
locations at yearend 1993.  In total, the Company holds over 1,000                   
potential drilling locations in these areas. See "Business -                         
Development - Western Slope Project."                                                

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                               PART II                                               

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION                  
AND RESULTS OF OPERATIONS                                                            

Results of Operations (a)                                                            

 Comparison of 1993 results to 1992.  Total revenues rose 91% in 1993                
to $229.9 million. Net income before taxes and extraordinary items                   
more than doubled to reach $34.9 million in 1993. The increase was                   
led by a rapid rise in production and assisted by an increase in gas                 
processing and transportation margins. Before the effect of a                        
favorable $3.8 million income tax accounting change in 1992 and a                    
$1.9 million 1993 extraordinary charge on early retirement of debt,                  
earnings per common share were $.80 in 1993 compared to $.53 in 1992,                
a 51% increase.                                                                      

 The gross margin from production operations for 1993 increased 62%                  
to $79.7 million, which was primarily related to a 65% growth in oil                 
and gas production. The price received per equivalent barrel                         
decreased by 3% to $13.41. Total operating expenses including                        
production taxes increased 60% during 1993 although operating cost                   
per BOE decreased to $4.83 from $4.99 in 1992. Expense reductions                    
gained from wells added in the DJ Basin, where operating costs                       
averaged $2.76 per BOE, were partially offset by the late 1992                       
acquisition of Wyoming wells from a major oil company where 1993                     
operating costs averaged $7.45 per BOE.                                              

 For the year ended December 31, 1993, average daily production was                  
25,472 BOE, a 65% increase from 1992. Average daily production in the                
fourth quarter of 1993 climbed to 10,314 Bbls and 105.6 MMcf (27,917                 
BOE). The production increases resulted primarily from acquisitions                  
and continuing development drilling in the DJ Basin. Domestically,                   
$51.0 million in properties were acquired in 1993, primarily in and                  
around existing hubs in Colorado and Wyoming. The acquisitions                       
included a significant number of development locations and should                    
continue to add to production in 1994. In 1993, 311 wells were placed                
on production in the DJ Basin, with 51 wells in various stages of                    
drilling and completion at yearend. Because the majority of the wells                
were added in the latter part of the year, production will not be                    
fully impacted until 1994. Additionally, significant downtime was                    
experienced in the fourth quarter at the major processing plant in                   
the DJ Basin, which increased line pressures and hampered production.                
To a lesser extent, this situation continued into early 1994.                        

 The gross margin from gas processing, transportation and marketing                  
activities for 1993 increased 23% to $10.0 million from $8.1 million                 
in 1992. The increase was primarily attributable to a $3.0 million                   
(33%) rise in transportation and processing margins as a result of                   
additional DJ Basin production and the recent expansion                              

(a)  Prior to 1993, production from the Thomasville Field, which was                 
sold at prices that were significantly above market, was converted to                
equivalent barrels based on its price relative to the Company's other                
gas production. Beginning in 1993, Thomasville production was                        
converted to oil equivalents at the rate of 6 Mcf per barrel. In                     
order to provide comparability between periods, equivalent barrel                    
information, other than depletion rates, for 1992 and 1991 has been                  
restated in this section to reflect Thomasville production at the                    
conversion rate of 6 Mcf per barrel. All equivalent barrel                           
information presented elsewhere in this Prospectus reflects the                      
historical method of conversion of Thomasville production used by the                
Company in the applicable year.                                                      
</page>                                                                              

of the related facilities. Gas marketing margins for 1993 decreased                  
by $1.1 million due to reduced margins on the Company's Oklahoma                     
cogeneration supply contract, which declined as a result of an                       
imposed limitation of the contract sales price and rising gas                        
purchase costs. In 1993 the net contract margin was a loss of                        
$267,000, which was $1.8 million less than 1992. At present gas price                
levels, the Company foresees continued negative or breakeven margins                 
for the cogeneration contract through July 1994. At that time, a                     
change in the pricing formula should result in improved margins. The                 
cogeneration margin reduction was partially offset by a $667,000                     
(126%) rise in other gas marketing margins in 1993 resulting from                    
increased third party marketing.                                                     

 Other income was $10.4 million during 1993, compared to $4.2 million                
in 1992. The $6.2 million increase resulted from a $3.5 million gas                  
contract settlement received in April 1993, collection of a $1.7                     
million litigation judgment and greater gains on the sales of                        
securities.                                                                          

 General and administrative expenses, net of reimbursements, for 1993                
represented 3% of revenues compared to 5.6% in 1992 as expenses were                 
held essentially flat while revenues grew 91%. Interest and other                    
expenses increased 28% primarily as a result of a rise in outstanding                
debt balances. Senior debt was substantially reduced in April 1993                   
with proceeds from a preferred offering, but increased through                       
yearend as a result of development expenditures, acquisitions, the                   
investment in Command Petroleum Holdings NL and the retirement of                    
$25.0 million in subordinated debt.                                                  

 Depletion, depreciation and amortization during 1993 increased 60%                  
from the prior year. The increase was the direct result of the 65%                   
rise in equivalent production between years. The producing depletion                 
rate per BOE for 1993 was reduced to $4.75 from $4.79 in 1992. The                   
rate was reduced by an ongoing drilling cost reduction program,                      
partially offset by an increase from the discontinuation of                          
converting Thomasville production to equivalent quantities based on                  
relative gas prices.                                                                 

 The Company adopted FASB Statement No. 109, "Accounting for Income                  
Taxes," effective January 1, 1992. Net income for 1992 was increased                 
by $3.8 million for the cumulative effect of the change in method of                 
accounting for income taxes. In 1992 the income tax provision was                    
reduced from the statutory rate of 34% by $5.5 million due to the                    
elimination of deferred taxes as a result of tax basis in excess of                  
financial basis. In 1993 the income tax provision was reduced from                   
the newly enacted rate of 35% to an effective rate of approximately                  
20% as a result of full realization of the excess basis benefit. The                 
Company anticipates deferred taxes will be provided in 1994 and                      
beyond based on the full statutory rate and accordingly will increase                
substantially.                                                                       

 Comparison of 1992 results to 1991.  Revenues rose 30% in 1992 to                   
$120.2 million, compared to $92.5 million in 1991. Net income for                    
1992 was $20.6 million, a 134% increase from the $8.8 million in                     
1991. The increases resulted from greater oil and gas production                     
volumes, lower interest expense, reduced general and administrative                  
expenses and a $3.8 million reversal of the cumulative effect of                     
prior year deferred taxes with the adoption of a change in the method                
of accounting for income taxes.                                                      

 Average daily production for 1992 rose 24% to 15,408 BOE due mostly                 
to development drilling in the DJ Basin of Colorado as 189 wells were                
placed on production there. As a result, the gross margin from                       
production increased 22% to $49.3 million in 1992. The price per BOE                 
decreased 4% during 1992.                                                            

 The gross margin from gas processing, transportation and marketing                  
activities for 1992 increased 12% to $8.1 million from $7.3 million                  
in 1991. The growth was primarily the result of increased marketing                  
of third party gas in New Mexico, Colorado and Wyoming. Gas                          
processing and transportation margins increased moderately as volumes                
were increased late in the year by expansions of pipeline and plant                  
facilities to take advantage of increasing DJ Basin production. Other                
income for 1992 decreased 26% to $4.2 million from a reduction in                    
gains on sales of securities and lower interest on notes receivable.                 

 Direct operating expenses including production taxes increased only                 
13% during 1992 as the operating cost per BOE decreased to $4.99 from                
$5.47 in 1991, due to increased DJ Basin production where operating                  
costs have been significantly lower than average. General and                        
administrative expenses, net of reimbursements, for 1992 represented                 
less than 6% of revenues compared to 8% in 1991, as revenues rose                    
30%. Interest and other expenses dropped 39% in 1992 due to lower                    
average outstanding senior debt after the application of proceeds                    
from a preferred stock offering in late 1991.                                        

Development, Acquisition and Exploration                                             

 During 1993 the Company expended $93.1 million for oil and gas                      
property development and exploration, $51.0 million for acquisitions                 
and $22.6 million for gas facility expansion and other assets, for a                 
total of $166.7 million in property and equipment expenditures.                      
Additionally, the Company made an $18.2 million investment in an                     
Australian based exploration and production company.                                 

 The Company has concentrated a significant portion of its                           
development activities in the DJ Basin. Capital expenditures for DJ                  
Basin development totalled $75.4 million during 1993. A total of 311                 
newly drilled wells were placed on production there in 1993 and 51                   
were in progress at yearend. Additionally, 42 recompletions were                     
performed in 1993, with seven in process at yearend. In December                     
1993, 16 drilling rigs were in operation in the DJ Basin. The Company                
anticipates putting 500 or more wells per year on production in the                  
DJ Basin for the next few years. With additional leasing activity and                
through drilling cost reductions that add proved undeveloped                         
locations as they become economic, the Company has increased the                     
inventory of available drillsites. In December 1993, the Company                     
entered into a letter of intent with Union Pacific Resources Company                 
("UPRC") whereby the Company will gain the right to drill wells on                   
UPRC's previously uncommitted acreage throughout the Wattenberg area.                
This transaction significantly increased the Company's undeveloped                   
Wattenberg inventory. UPRC will retain a royalty and the right to                    
participate as a 50% working interest owner in each well, and                        
received warrants to purchase two million shares of Company stock. Of                
the warrants, one million expire three years from the date of grant,                 
and are exercisable at $25 per share, while the other one million                    
expire in four years and are exercisable at $27 per share. On                        
February 8, 1995, the exercise prices may be reduced to 120% of the                  
average closing price of the Company stock for the preceding 20                      
consecutive trading days, but not below $21.60 per share. The                        
expiration date of the warrants will be extended one year if the                     
average closing price over such 20 day trading period is less than                   
$16.50 per share.                                                                    

 The Company expended $14.8 million for other development and                        
recompletion projects and $2.9 million for exploration during 1993.                  
In Nebraska, 29 wells were added to production in 1993 as an                         
extension of a drilling program initiated in 1992. An additional 20                  
wells are planned in Nebraska for 1994. In southern Wyoming, 11 wells                
in the East Washakie Basin development program were successfully                     
drilled and completed during the last half of 1993 with three in                     
process at yearend. In this program, significant cost-cutting                        
measures were applied based on the experience gained in the DJ Basin.                
In central Wyoming on the properties acquired from a major oil                       
company in late 1992, efforts have been focused on increasing                        
operating efficiency with limited development drilling and workover                  
activity. In 1993, three successful wells were drilled in the fourth                 
quarter and selected development and recompletion activity is                        
scheduled for 1994. In the Piceance Basin of western Colorado, a                     
three well test program was started in December of 1993 on acreage                   
acquired there during the year, with one well undergoing completion,                 
the second in progress and a third scheduled for early 1994. Current                 
plans include a minimum of 25 wells in the basin during 1994. In                     
South Texas, a combined operated and non-operated program was                        
initiated, with nine wells completed in 1993 and one well abandoned.                 
A total of 25 additional horizontal locations have been identified                   
and drilling should continue with as many as 15 wells planned in                     
1994. In its domestic exploration efforts, the Company initiated a                   
seismic program in Louisiana and began drilling early in the fourth                  
quarter. Advanced seismic techniques are being used to identify                      
further prospects in Louisiana and expectations are to drill up to 20                
wells in 1994.                                                                       

 A total of $51.0 million in domestic acquisitions were completed in                 
1993. In May 1993, the Company purchased an interest in 121 producing                
wells and over 70 drilling locations in the DJ Basin area for $3.3                   
million. In July, an incremental 25% interest in the Company's Barrel                
Springs and Duck Lake Fields in Wyoming was purchased for $6.1                       
million. The properties are 90% gas and include 44 producing wells                   
and 46 undeveloped locations. In August, the Company acquired                        
interests in 225 producing wells and 272 proved undeveloped locations                
in the DJ Basin for $19.7 million. The proved reserves are 70% gas                   
with more than two-thirds requiring future development to produce.                   
Late in the year, two acquisitions were completed in the Piceance and                
Uinta Basins of Western Colorado for a total of $12.5 million. The                   
majority of the value was in undeveloped locations as only 128 wells                 
were currently producing. Numerous other producing and undeveloped                   
acquisitions totalling $9.4 million were completed, mostly in or                     
close to the Company's principal operating areas.                                    

 The Company's gas gathering and processing facilities have been                     
undergoing significant transformation since late 1992. In 1993, the                  
Company expended $20.1 million to develop further its gas related                    
assets. The Company spent $9.4 million toward the second phase of its                
DJ Basin gathering expansion to construct a high pressure line to                    
deliver gas directly to the major gas processing plant in the area                   
and expand its gathering network for the increased drilling activity.                
An additional $2.6 million was expended to expand the Roggen Plant                   
for the production increases. A total of $5.6 million in additional                  
transportation and gathering facilities were constructed in the DJ                   
Basin including a nine mile 16" interconnect line completed in                       
October to relieve high line pressures, a 20" western gathering                      
extension and numerous other extensions and connections. A gathering                 
system that delivers third party gas to the Roggen Plant was                         
purchased for $703,000. The Company expended $1.4 million to complete                
construction of a system to gather gas from its Nebraska drilling                    
project. These projects are intended to take advantage of the                        
significant increase in drilling activity in these areas.                            

 In May 1993, the Company acquired 42.8% (currently 35.7%) of the                    
outstanding shares of Command Petroleum Holdings NL ("Command"), a                   
Sydney based Australian exploration and production company listed on                 
the Australian Stock Exchange, for $18.2 million. Command holds                      
interests in more than 20 exploration permits and licenses and a                     
28.7% interest in a Netherlands exploration and production company                   
whose assets are located primarily in the North Sea. Permtex, the                    
Company's Russian joint venture, received central government approval                
in August and the Company executed a finance and insurance protocol                  
with the Overseas Private Investment Corporation ("OPIC"), a United                  
States government agency. Current plans call for 25 of the existing                  
45 shut-in wells to be placed on production in 1994, and that 400                    
development wells will be drilled over the next ten years. Extensive                 
seismic work began in the fourth quarter of 1993 for 400 kilometers                  
of data in Tunisia and 500 kilometers in Mongolia.                                   

 The Company from time to time acquires securities of publicly traded                
and private oil and gas companies. In addition to its investment in                  
Command, the Company owns, among other investments, more than 5% of                  
the common stock of Lomak Petroleum, Inc. and, as the result of                      
purchases beginning in the third quarter of 1993, American                           
Exploration Company. The Company is currently evaluating a range of                  
possible alternatives with respect to its investment in American                     
Exploration Company, including the possibility of actions to enhance                 
the value of its common stock.                                                       

Financial Condition and Capital Resources                                            

 At December 31, 1993, the Company had total assets of $480 million                  
and working capital of $1.3 million. Total capitalization was $412                   
million, of which 28% was represented by senior debt and the                         
remainder by stockholders' equity. During 1993, the Company fully                    
retired its $25 million of 13.5% subordinated notes and the related                  
cumulative participating interests. During 1993, cash provided by                    
operations was $68.3 million, an increase of 43% over 1992. As of                    
December 31, 1993, commitments for capital expenditures totalled $7.5                
million, primarily for DJ Basin drilling. The Company anticipates                    
that it will expend $175 to $200 million for development drilling and                
expansion of gas facilities in 1994. The level of these and other                    
future expenditures is largely discretionary, and the amount of funds                
devoted to any particular activity may increase or decrease                          
significantly, depending on available opportunities and market                       
conditions. The Company plans to finance its ongoing development,                    
acquisition and exploration expenditures using internally generated                  
cash flow, proceeds from property dispositions and existing credit                   
facilities. In addition, joint ventures or future public and private                 
offerings of securities may be utilized.                                             

 In 1992, an institutional investor agreed to contribute $7 million                  
to a partnership formed to monetize Section 29 tax credits to be                     
realized from the Company's properties, mainly in the DJ Basin. The                  
initial $3 million was contributed in October 1992, and at first                     
payout in June 1993 the second contribution of $1.5 million was                      
received. An additional $1.5 million was received in October 1993.                   
This transaction should increase the Company's cash flow and net                     
income through 1994. A revenue increase of more than $.40 per Mcf is                 
realized on production generated from qualified Section 29 properties                
in this partnership. The Company recognized $3.8 million of this                     
revenue during 1993. Discussions are in progress to expand the scope                 
of this transaction so that the benefits would be continued through                  
at least 1996.                                                                       

 In April 1993, the Company sold 4.1 million depositary shares (each                 
representing a one quarter interest in one share of $100 liquidation                 
value stock) of convertible preferred stock through an underwritten                  
offering for $103.5 million. A portion of the net proceeds of $99.3                  
million was used to retire the entire outstanding balance under the                  
revolving credit facility at that time. The preferred stock pays a 6%                
dividend and is convertible into common stock at $21.00 per share. At                
the Company's option, the preferred stock is exchangeable into 6%                    
convertible debentures on any dividend payment date on or after March                
31, 1994. The preferred stock is redeemable at the option of the                     
Company on or after March 31, 1996.                                                  

 Effective July 1, 1993, the Company renegotiated its bank credit                    
facility and increased it from $150 million to $300 million. The new                 
facility is divided into a $50 million short-term portion and a $250                 
million long-term portion that expires on December 31, 1997. However,                
management's policy is to request renewal of the facility annually.                  
Credit availability is adjusted semiannually to reflect changes in                   
reserves and asset values. At December 31, 1993, the elected                         
borrowing base was $150 million. The majority of the borrowings                      
currently bear interest at LIBOR plus 1.25% with the remainder at                    
prime. The Company also has the option to select the CD rate plus                    
1.375%. Financial covenants limit debt, require maintenance of                       
minimum working capital and restrict certain payments, including                     
stock repurchases, dividends and contributions or advances to                        
unrestricted subsidiaries. Based on such limitations, $86.5 million                  
would have been available for the payment of dividends and other                     
restricted payments as of December 31, 1993. The Company does not                    
currently plan to make, and is not committed to make, any advances or                
contributions to unrestricted subsidiaries that would materially                     
affect its ability to pay dividends under this limitation.                           

 The Company maintains a program to divest marginal properties and                   
assets that do not fit its long range plans. For 1992 and 1993,                      
proceeds from these sales were $3.0 million and $5.5 million,                        
respectively. Included in the 1993 proceeds were $4.0 million of cash                
receipts previously accrued for late 1992 sales. The Company intends                 
to continue to evaluate and dispose of nonstrategic assets.                          

 The Company believes that its capital resources are more than                       
adequate to meet the requirements of its business. However, future                   
cash flows are subject to a number of variables including the level                  
of production and oil and gas prices, and there can be no assurance                  
that operations and other capital resources will provide cash in                     
sufficient amounts to satisfy debt service requirements and to                       
maintain planned levels of capital expenditures or that increased                    
capital expenditures will not be undertaken.                                         

Inflation and Changes in Prices                                                      

 While certain of its costs are affected by the general level of                     
inflation, factors unique to the petroleum industry result in                        
independent price fluctuations.  Over the past five years,                           
significant fluctuations have occurred in oil and gas prices.                        
Although it is particularly difficult to estimate future prices of                   
oil and gas, price fluctuations have had, and will continue to have,                 
a material effect on the Company.                                                    

 The following table indicates the average oil and gas prices                        
received over the last five years and highlights the price                           
fluctuations by quarter for 1992 and 1993.  Average gas prices                       
exclude the Thomasville gas production.  During 1993, the Company                    
renegotiated its Thomasville gas contract and beginning in January                   
1994, the Company will receive a somewhat higher than market price                   
for its Thomasville gas sales, significantly below its 1993 average                  
price of $12.16 per Mcf.  Average price computations exclude contract                
settlements and other nonrecurring items to provide comparability.                   
Average prices per equivalent barrel indicate the composite impact of                
changes in oil and gas prices.  Natural gas production is converted                  
to oil equivalents at the rate of 6 Mcf per barrel.  Equivalent                      
prices prior to 1993 have been restated to reflect elimination of the                
conversion of Thomasville gas volumes based on its price relative to                 
the Company's other gas production.                                                  

                                                                [Download Table]



                          Average Prices              
                   Crude Oil                Per       
                      and      Natural      Equivalent
                    Liquids      Gas        Barrel    
                   (Per Bbl)  (Per Mcf)               
                                                      
 Annual                                               

     1989            $  18.30   $  1.65   $  12.84    
     1990               23.65      1.69      15.61    
     1991               20.62      1.68      14.36    
     1992               18.87      1.74      13.76    
     1993               15.41      1.94      13.41    

 Quarterly                                            

   1992                                               
   First             $  17.80   $  1.56  $   12.66    
   Second               19.72      1.53      13.28    
   Third                20.18      1.70      13.94    
   Fourth               17.98      2.13      14.96    

    1993                                              
   First             $  16.62   $  2.05   $  14.25    
   Second               16.76      1.87      13.65    
   Third                14.78      1.85      12.73    
   Fourth               13.80      2.02      13.12    

In December 1993, the Company was receiving an average of $12.54      
per barrel and $2.27 per Mcf (excluding the Thomasville contract) for           
its production.  Beginning in December 1992, the average oil price              
was effectively reduced by the oil production added from the Wyoming            
acquisition, which sells at a significant discount to West Texas                
Intermediate posting due to the presence of low gravity sour crude in           
two of the fields.                                                              

PART IV             

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM           
8-K.                                                                            

(a)  1. Reference is made to Item 8 on page 34.                                 

2. Schedules otherwise required by Item 8 have been omitted as        
not required or not applicable.                                 

3. Exhibits                                                           

4.1.1   Certificate of Incorporation of Registrant - incorporated by            
reference from Exhibit 3.1 to the Registrant's Registration     
Statement on Form S-4 (Registration No. 33-33455).              

4.1.2   Certificate of Amendment to Certificate of Incorporation of             
Registrant filed February 9, 1990 - incorporated by reference   
from Exhibit 3.1.1 to the Registrant's Registration Statement   
on Form S-4 (Registration No. 33-33455).                        

4.1.3   Certificate of Amendment to Certificate of Incorporation of             
Registrant filed May 22, 1991 - incorporated by reference       
from Exhibit 3.1.2 to the Registrant's Registration Statement   
on Form S-1 (Registration No. 33-43106).                        

4.1.4   Certificate of Amendment to Certificate of Incorporation of             
Registrant filed May 24, 1993 - incorporated by reference       
from Exhibit 3.1.5 to the Registrant's Form 10-Q for the        
quarter ended June 30, 1993 (File No. 1-10509)                  

4.1.5   Certificate of Designations, Powers, Preferences and Rights             
of the Registrant's $4.00 Convertible Exchangeable Preferred    
Stock - incorporated by reference from Exhibit 3.1.3 to the     
Registrant's Annual Report on Form 10-K for the year ended      
December 31, 1991 (File No. 1-10509).                           

4.1.6   Certificate of Designations of the Registrant's $6.00                   
Convertible Exchangeable Preferred Stock - incorporated by      
reference from Exhibit 3.1.5 to the Registrant's Form 10-Q      
for the quarter ended June 30, 1993 (File No. 1-10509)          

10.1    Snyder Oil Corporation 1990 Stock Option Plan for Non-                  
Employee Directors - incorporated by reference from Exhibit     
10.4 to the Registrant's Registration Statement on Form S-4     
(Registration No. 33-33455).                                    

10.1.1  Amendment dated May 20, 1992 to the Registrant's 1990 Stock             
Plan for Non-Employee Directors - incorporated by reference     
to the Registrant's Quarterly Report on Form 10-Q for the       
quarter ended June 30, 1993 (File No. 1-10509).                 

10.2    Registrant's Restated 1989 Stock Option Plan - incorporated             
by reference to the Registrant's Quarterly Report on Form 10-   
Q for the quarter ended June 30, 1992 (File No. 1-10509).       

10.3    SOCO Holdings Inc. 1984 Stock Option Plan - incorporated by             
reference from Exhibit 10.6 to the Registrant's Registration    
Statement on Form S-4 (Registration No. 33-33455).              

10.3.1  Amendment to SOCO Holdings Inc. 1984 Stock Option Plan dated            
July 18, 1985 - incorporated by reference from Exhibit 10.6.1   
to the Registrant's Registration Statement on Form S-4          
(Registration No. 33-33455).                                    

10.3.2  Amendment to SOCO Holdings Inc. 1984 Stock Option Plan dated            
May 24, 1988 - incorporated by reference from Exhibit 10.6.2    
to the Registrant's Registration Statement on Form S-4          
(Registration No. 33-33455).                                    

10.4    Registrant's Profit Sharing & Savings Plan and Trust as                 
amended and restated effective October 1, 1993 - incorporated   
by reference to the Registrant's Quarterly Report on Form 10-   
Q for the quarter ended September 30, 1993 (File No. 1-         
10509).                                                         

10.5    Form of Indemnification Agreement - incorporated by reference           
from Exhibit 10.15 to the Registrant's Registration Statement   
on Form S-4 (Registration No. 33-33455).                        

10.6    Form of Change in Control Protection Agreement - incorporated           
by reference from Exhibit 10.11 to the Registrant's             
Registration Statement on Form S-1 (Registration No.            
33-43106).                                                      

10.7    Long-term Retention and Incentive Plan and Agreement between            
the Registrant and Charles A. Brown - incorporated by           
reference to the Registrant's Quarterly Report on Form 10-Q     
for the quarter ended June 30, 1993 (File No. 1-10509)          

10.8    Agreement dated as of April 30, 1993 between the Registrant             
and Edward T. Story.*                                           

10.9    Purchase and Sale Agreement dated December 11, 1992 between             
Atlantic Richfield Company and Registrant - incorporated by     
reference to Report on 8-K dated December 11, 1992 (File No.    
1-10509).                                                       

10.10   Warrant dated February 8, 1994 issued by Registrant to Union            
Pacific Resource Company.*                                      

10.11   Fourth Restated Credit Agreement dated as of July 1, 1993               
amoung the Registrant and the banks party thereto -             
incorporated by reference from Exhibit 4.1.4 to the             
Registrant's Quarterly Report on Form 10-Q for the quarter      
ended June 30, 1993 (File No. 1-10509).                         

11.1    Computation of Per Share Earnings.*                                     

22.1    Subsidiaries of the Registrant - incorporated by reference              
from Exhibit 22.1 to the Registrant's Annual Report on Form     
10-K for the year ended December 31, 1991 (File No. 1-10509).   

23.1    Consent of Arthur Andersen & Co.*                                       

23.2    Consent of Netherland, Sewell & Associates, Inc.*                       

99.1    Report of Netherland, Sewell & Associates, Inc. dated                   
February 10, 1994 relating to certain of the Registrant's       
property interests.*                                            

99.2    Report of Netherland, Sewell & Associates, Inc. dated                   
February 11, 1994 relating to their audit of reserve            
estimates.*                                                     

(b)    No reports on Form 8-K in the fourth quarter of 1993                   

* Filed as part of Registrant's original Form 10K.                            

SIGNATURE                           

The undersigned registrant hereby amends the following items,                 
financial statements, exhibits or other portions of its Annual Report           
on Form 10-K as set forth in the pages attached hereto:                         

Cover Page                                                            
Item 1.  Business                                                     
Item 2   Properties                                                   
Item 7.  Management's Discussion and Analysis of Financial            
Condition and Results of Operations                                             

Part IV                                                               
Item 14.       Exhibits, Financial Statement Schedules and            
Reports on Form 8-K.                                                            

Pursuant to the requirements of the Securities Exchange Act of        
1934, the registrant has duly caused this amendment to be signed on             
its behalf by the undersigned, thereto duly authorized.                         

            SNYDER OIL CORPORATION

                By:  /s/ Peter E. Lorenzen

       Peter E. Lorenzen
                      Vice President - General Counsel

Date:  April  22, 1994                                                          

Dates Referenced Herein   and   Documents Incorporated by Reference

				Referenced-On Page
This ‘10-K/A’ Filing		Date		First		Last			Other Filings
		12/31/97		2					10-K,  11-K
		3/31/96		2					10-Q
		2/8/95		2
Filed on:		4/25/94
		4/22/94		2
		3/31/94		2					10-Q
		3/1/94		1
		2/28/94		1
		2/11/94		2
		2/10/94		2
		2/8/94		2
		1/1/94		1
For Period End:		12/31/93		1		2			10-K,  11-K
		10/1/93		2
		9/30/93		2
		7/1/93		2
		6/30/93		2
		5/24/93		2
		4/30/93		2
		1/1/93		1
		12/11/92		2
		6/30/92		2
		5/20/92		2
		1/1/92		2
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