APPENDIX 10

APPENDIX 10

ASSUMPTIONS FOR IMPACT ANALYSIS

GENERAL ASSUMPTIONS FOR 

ALL ALTERNATIVES 

The following assumptions apply to all analyses presented. 

The BLM would comply with applicable laws, regulations, 

and policies in implementation of a resource management 

plan. The effects discussed in the analysis are those that would 

result from management decisions, not those that would result 

from compliance with laws, regulations, and policies. Management actions would be implemented as stated, and funding 

and personnel would be adequate to carry out the actions. 

Standard operating procedures would be followed in plan 

implementation. Some of these procedures are summarized in 

the appendices to this document. 

The assumption and analysis guidelines listed below were 

utilized to assess impacts to all of the alternatives. Generally, 

a 20-year period with the base year as 1998 was used in 

preparing assumptions for each resource. 

Air Quality Assumptions 

The maximum number of wells drilled would be 110; 58 

wells successful (53 percent success rate), and that 3,480 

horsepower of compression (based on 60-hp per producing 

well) would be necessary. 

Over 20 years, 10,000 acres would be treated through 

prescribed burns. 

Oil and gas drilling emission assumptions are based on the 

Jonah II EIS Air Quality cumulative impact analysis, i.e., 

drilling uses 2,500-hp diesel engines and 24-days for rig up, 

drilling, and rig down time (20-day drilling) (USDI 1998a). 

Oil and gas well and compressor emission assumptions are 

based on the Pinedale Anticline Draft Environmental Impact 

Statement Technical Air Quality Analysis (USDI 1999a). 

Cultural and Paleontological 

Assumptions 

The overall density of archeological sites in the planning 

area is approximately 3.2 sites per 640 acres. Of that number, 

about one-third prove to be significant in terms of National 

Register of Historic Places criteria. This density is based on 

less than 5 percent of the planning area inventoried at a Class 

III level intensity. Areas of site density as high as 15 sites per 

section have been found. Estimates of the number of sites that 

could be impacted by various actions is calculated by simply 

multiplying the 3.2 sites per 640 acres by the number of acres 

where surface disturbance would occur. 

The BLM’s preferred method of handling cultural resources in the context of public land development is to avoid 

adversely affecting cultural sites. However, when avoidance 

would be detrimental to other resource values, mitigation 

methods would be considered. Mitigation by data recovery 

may be an acceptable management practice for sites that are 

eligible for the National Register of Historic Places under 

criteria D, because of the scientific data they contain. While 

data recovery may increase the cost or affect timely completion of a specific action, it may be beneficial to the overall 

resource base because it adds to the understanding of prehistory or history and enables BLM to better manage the totality 

of cultural resources in the planning area. Other mitigation 

measures may be appropriate for properties that are eligible 

for the NRHP under criteria A, B, and C. However, mitigation 

of adverse effects to those sites would usually be more 

difficult than sites eligible under criteria D. 

In addition to archaeological sites, which are the most 

common kind of heritage resource in the Jack Morrow Hills 

planning area, several locations have been identified by Native American traditional elders as “respected places.” These 

locations are places with special significance to tribal peoples 

and as such are administered under several mandates including the American Indian Religious Freedom Act (AIRFA), 

and Executive Order 13007, in addition to the National 

Historic Preservation Act. Special accommodations are to be 

made to protect these places and to allow Native Americans to 

use them for religious purposes whenever possible within the 

context of other BLM mandates. Efforts to consult with 

Native American tribal representatives can take considerable 

time. Development activities could be delayed while consultation with tribal representatives takes place. 

Various kinds of cultural resources tend to be affected 

differently by differing kinds of impacts. The BLM’s preferred method of managing cultural resources within the 

context of public land development is to avoid affecting them. 

However, avoidance is not always feasible. This is especially 

the case when health and safety issues are involved, or when 

other resource values may be involved. When avoidance is 

not feasible it is possible that heritage resources could be 

destroyed by surface disturbing activities, or that some of their 

values may be diminished by disruption of the surrounding 

landscape, by the introduction of audible disturbances or by 

other actions. Efforts to mitigate the adverse effects of such 

actions would be common to all alternatives, but would not 

necessarily be sufficient to ameliorate all kinds of effects on 

heritage resources. 

Land sales or exchanges could be adverse or beneficial 

depending upon whether significant cultural resource are 

acquired or leave Federal jurisdiction. In Wyoming there is 

little in the way of state law protecting cultural resources thus 

land exchanges with the State can be adverse to the cultural 

resource base by removing the property from the protection of 

the National Historic Preservation Act and other Federal laws. 

Generally, inventory and evaluation for cultural resources is 

required prior to allowing lands to leave federal jurisdiction 

thus preventing potential adverse effects that could result 

from the loss of federal protection. 

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APPENDIX 10

Significant fossils may be expected throughout the Cretaceous and Tertiary units exposed in the planning area. The 

BLM’s method of handling paleontological resources in the 

context of public land development is to first identify paleontological resource potential at the field office level. The BLM 

field office will conduct a literature search and field review in 

coordination with the regional paleontologist to classify or 

rank the area of consideration according to its potential to 

contain vertebrate fossils, or noteworthy occurrences of invertebrate or plant fossils. Lands will be classified using the 

criteria set forth in BLM Handbook 8270-1-General Procedural Guidance for Paleontological Resource Management. 

The Handbook describes these land classifications or conditions in the following way: 

Condition 1- Areas that are known to contain vertebrate 

fossils or noteworthy occurrences of invertebrate or plant 

fossils. Consideration of paleontological resources will be 

necessary if the Field Office review of available information 

indicates that such fossils are present in the area. 

Condition 2 - Areas with exposures of geological units or 

settings that have high potential to contain vertebrate fossils or 

noteworthy occurrences of invertebrate or plant fossils. The 

presence of geological units from which such fossils have 

been recovered elsewhere may require further assessment of 

these same units where they are exposed in the area of 

consideration. 

Condition 3 - Areas that are very unlikely to produce vertebrate fossils or noteworthy invertebrate or plant fossils based 

on their surficial geology, igneous or metamorphic rocks, 

extremely young alluvium, colluvium, or eolian deposits or 

the presence of deep soils. However, if possible it should be 

noted at what depth bedrock may be expected in order to 

determine if fossiliferous deposits may be uncovered during 

surface disturbing activities. 

Condition 1 or Condition 2 classifications may trigger the 

initiation of a formal analysis by a qualified paleontologist 

prior to authorizing land-use actions involving surface disturbance. The formal analysis will include analysis of existing 

data, followed by a field survey, report of findings, and 

recommendations for mitigation. A Mitigation and Monitoring Plan will then be developed and implemented. Mitigation 

is complete when the mitigation plan is implemented and the 

final report, including any specimen inventory, is accepted by 

the BLM. Condition 3 classification suggests that further 

paleontological consideration is generally unnecessary. 

Fire Assumptions 

Lightning patterns would remain the same and that there 

exists a relationship between lightning fires and current vegetation patterns associated with known lightning belts. Further, it would be assumed that there exists a relationship 

between person-caused fires and density of use and that the 

current annual average of 100 acres (33 occurrences, all 

ignition sources) burned due to wildfire would continue. 

Lands and Realty Assumptions 

The pipelines, road rights-of-way, and permits would be 

located in association with oil and gas production areas. 

Revocation of any withdrawals would open those lands to 

disposal and mineral location, unless those lands are otherwise withdrawn (e.g., a withdrawal to protect resources in an 

ACEC which is also located within the oil shale withdrawal). 

Any final revocation of the land and mineral withdrawals is 

projected to the year 2010. 

Livestock Grazing Assumptions 

Construction of fences, pipelines, water wells, troughs, 

and reservoirs would cause a loss of some soil and vegetation. 

Vegetation would be reestablished along fences and pipelines 

within 3 to 5 years. Sites of water wells, troughs, and 

reservoirs (approximately 1 acre) would remain disturbed for 

the long term (10 to 20 years) and would be revegetated upon 

abandonment. 

Prescribed burns and wildfires would cause a loss of 

vegetation for a period of one to two years and a change in 

vegetation for 15 to 30 years. Burn areas would be rested from 

livestock grazing for the first two growing seasons following 

prescribed burns. This could increase to two full years if 

mountain shrubs or aspen vegetative communities are included within the burn area. Rest from livestock grazing for 

a period of two years could also be required in wildfire areas 

but would be determined on a case-by-case basis. 

Within the Jack Morrow Hills planning area, livestock 

grazing would occur throughout the area. The effects described would be the same for the core area, the connectivity 

area, Areas of Critical Environmental Concern, Wilderness 

Study Areas, etc., and therefore are not discussed separately. 

The impacts within these areas would be the same as in the 

general area. 

The average forage acre factor would be 12.5 acres per 

AUM. 

Mineral Assumptions 

Oil and Gas 

Drilling Assumptions 

Most drilling activity has been concentrated in the south 

central part of the planning area (Nitchie Gulch unit/field) 

with additional exploratory wells scattered across the rest of 

the area. If allowed, most future activity would spread out 

from present areas of production. Exploration activity is also 

expected to be concentrated in areas where exploratory unit 

proposals have been made. Scattered tests will continue to be 

drilled throughout the area with concentrations of wells being 

drilled around new successful wells. Lowest rates of activity 

are expected to be on the north edge of the planning area where 

targets are deep and lie below granites of the Wind River 

Thrust. 

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APPENDIX 10

Drilling targets have been formations of Cretaceous age 

(145 of the 153 wells drilled) (Appendix 13). Only two wells 

have tested formations deeper than the Cretaceous. Six wells 

were shallow Tertiary targets and none were productive. 

Drilling targets are expected to be dominantly from stratigraphic trapped Cretaceous-aged sediments or Tertiary- or 

Cretaceous-aged coal beds. No more than six wells will test 

rocks older than the Cretaceous. Hydrogen sulfide and carbon 

dioxide may be associated with any hydrocarbons encountered in deeper formations. Any carbon dioxide gas bearing 

formations have no development potential during the life of 

this plan. 

The Nitchie Gulch unit/field area is developed on 160-acre 

spacing while the rest of the planning area is on a 640-spacing. 

Any new fields discovered in the future are expected to be first 

developed on a 640-acre spacing and will quickly be down 

spaced to 160 acres per well. 

Most wells have been drilled by smaller companies and 

independents. This is expected to continue to be the case in the 

future. The size of fully developed fields is expected to be 20 

to 25 wells (Diedrich 1999). 

The deepest well drilled was to 22,947 feet. Most wells in 

the 5,000 to 10,000 range lie in the Nitchie Gulch unit/field 

area because it is the highest structural location on the Rock 

Springs Uplift. Wells must be drilled deeper outside this area 

to reach the same target formations. The deepest wells have 

been drilled on the north part of the planning area. Wells will 

generally be drilled from 5,000 to 10,000 feet in the Nitchie 

Gulch unit/field area. Wells outside this area will generally be 

deeper but less than 15,000 feet. 

Produced water disposal methods are expected to be by 

reinjection, disposal pits (estimated at 0.1 acre each), or by 

discharge (DEQ Water Quality standards would be met). 

Petroleum Reserve Estimates and Well Production 

Rates 

A total of 66 wells have been reported as being completed 

as producers as of April 1998. Some wells produce from two 

different formations. Formations completed for production 

are: 

• Frontier - 50 wells 

• Dakota - 22 wells 

• Muddy - 6 wells 

• Mowry - 1 well 

• Rock Springs - 1 well 

• Mesaverde Group coal beds - 3 wells 

Ultimate gas recovery for all 66 wells is estimated to be 

145.4 billion cubic feet. About 24.3 billion cubic feet of gas 

is left to produce from the wells still producing. Based on 

these wells the average estimated ultimate gas recovery is 

expected to be 2.2 billion cubic feet per well. Decline curve 

analysis indicates that the average well will produce for about 

26 years before declining to an uneconomic rate, which would 

result in abandonment. 

Production of the 2.2 billion cubic feet of gas from each 

well is assumed to be equally spread over a wells 26 year 

producing life, or at a rate of 84.6 million cubic feet of gas per 

year. 

The ratio of oil/condensate production was assumed to 

remain similar to its present ratio. At this ratio an average well 

will produce 117 barrels of oil/condensate each year. 

Oil and gas production rates determined for the Green 

River Resource Management Plan and Final Environmental 

Impact Statement (1996) are 159.6 million cubic feet of gas 

per year and 5,643 barrels of oil or condensate. Gas production rates in the planning area are almost one half of the rates 

for average wells in the entire Rock Springs Field Office and 

oil/condensate rates are only 2 percent. This information 

shows that these producing wells are less economic than wells 

in other productive parts of the region. 

Assuming a productive life of 26 years results in only four 

presently producing wells that could still be active in 2017. 

Surface Disturbance 

These guidelines for access roads, drill pads, and pipelines 

and powerlines would be used to determine acres of surface 

disturbance associated with oil and gas exploration and development drilling activities. 

Access Roads: 

• 40 feet total width disturbance 

• 12 to 14-foot-wide travelway 

• 4.8 acres initial disturbance per linear road mile 

• 4.0 acres initial disturbance per access road (less than 1 

mile disturbed per well) 

• 4.0 acres long-term disturbance per producing well (no 

stabilization or revegetation of barrow ditch) 

• 4.0 acres of access road stabilized per abandoned dry 

well, after three years 

• 4.0 acres of access road stabilized after abandonment of 

each producing well, after three years 

Road standards would be in conformance with guidelines 

issued in BLM Manual 9113 (Roads) and in Surface Operating Standards for Oil and Gas Exploration and Development 

(1989). 

Drill Pads: 

• 3.0 acres initial disturbance per average well pad 

• 0.7 acres long-term disturbance per producing well 

• 2.3 acres stabilized per producing well, after three years 

• 3.0 acres stabilized per abandoned dry well, after three 

years 

• 0.7 acres stabilized after abandonment of each producing well, after three years 

Pipelines and Powerlines: 

• 6.0 acres initial disturbance per producing well 

• 5.5 acres stabilized per producing well, after three years 

• 0.5 acres long-term disturbance per producing well 

• 0.5 acres stabilized after abandonment of each producing well, after three years 

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APPENDIX 10

Coalbed Methane Assumptions 

Coals of the Fort Union, Almond, and Rock Springs 

Formations have been tested. Development has not continued 

due primarily to low gas prices and disappointing test results 

and secondarily due to environmental concern over disposal 

of produced water. 

Future targets will be Cretaceous or Tertiary coals in the 

area mapped as having coalbed methane potential (Map 46). 

The comment letter from Barlow & Haun, Inc. (1998) indicates a potential gas reserve of 50 billion cubic feet. 

The most likely coals to be targeted for exploration and 

development will be those of the Rock Springs formation 

because their thickness, resources, and gas content are favorable. This favorable area is in the eastern lobe of the coalbed 

methane potential area shown on Map 46. 

Fort Union formation coals in the western lobe of the 

potential area are less prospective because their recorded gas 

contents are low. 

Presently coalbed methane is not technically productive 

due to low gas prices and water disposal costs. No wells are 

expected to be drilled until after 2000. During the 1998-2017 

period only 10 coalbed methane tests are projected. They will 

most likely lie on the southeast boundary of the eastern lobe, 

although a few tests could be made in the western lobe. Small 

quantities of gas can be expected to be produced from each 

test. Fifty percent of these wells are expected to be hooked up 

to a pipeline for production. 

In the long term, the two existing wells and five new wells 

will still be producing in 2017. 

Spacing would be at 160 acres per well or less. Produced 

water disposal methods would be by reinjection, disposal 

ponds (estimated two acres each), discharge (DEQ water 

quality standards would be met), or treatment with a portion 

disposed of in ponds and a portion discharged (DEQ water 

quality standards would be met). 

No production rate assumptions were made for coalbed 

methane. No production history is available to make a 

reasonable assessment at this time. Coalbed methane wells 

produce at low rates and the seven projected producing wells 

would not contribute significant production to the much larger 

volumes expected from conventional wells. 

Coalbed Methane Disturbance 

These guidelines for access roads, drill pads, and pipelines 

and powerlines would be used to determine acres of surface 

disturbance associated with coalbed methane exploration and 

development drilling activities. 

Access Roads: 

• 40 feet total width disturbance 

• 12 to 14-foot-wide travelway 

• 4.8 acres initial disturbance per linear road mile 

• 4.8 acres initial disturbance per well drilled 

• 4.0 acres long-term disturbance per producing well (no 

stabilization or revegetation of barrow ditch) 

• 4.0 acres of access road stabilized per abandoned dry 

well, after three years 

• 4.0 acres of access road stabilized after abandonment of 

each producing well, after three years 

Road standards would be in conformance with guidelines 

issued in BLM Manual 9113 (Roads) and in Surface Operating Standards for Oil and Gas Exploration and Development 

(1989). 

Drill Pads: 

• 3.0 acres initial disturbance per average well pad 

• 0.7 acres long-term disturbance per producing well 

• 2.3 acres stabilized per producing well, after three years 

• 3.0 acres stabilized per abandoned dry well, after three 

years 

• 0.7 acres stabilized after abandonment of each producing well, after three years 

Pipelines and Powerlines: 

• 6.0 acres initial disturbance per producing well 

• 5.5 acres stabilized per producing well, after three years 

• 0.5 acres long-term disturbance per producing well 

• 0.5 acres stabilized after abandonment of each producing well, after three years 

Shallow Coalbed Methane Project-Industry recently expressed interest in development of potential shallow coalbed 

methane reserves. On the southeast border of the planning 

area, River Gas has proposed re-entering the two planning 

area shut-in coalbed methane wells and testing other sites 

outside the planning area. These tests would be of Rock 

Springs Formation coals. 

If these wells are successful, industry has proposed testing 

Rock Springs and Almond formation coals at other points in 

the planning area itself. Tests of these coals would be at 

shallower depths than at the River Gas prospect. Drilling, 

testing, completions, facilities, and surface disturbance would 

be different from normal oil and gas wells and from deeper 

coalbed wells. 

Anticipated Activity Level and Project Life. Fifteen wells 

would be drilled over the two-year period beginning in the 

year 2000. Initially, five wells will be drilled in a pod pattern. 

A pod pattern is a central well with wells drilled in adjacent 

spacing units to the north, south, east, and west. The additional 10 wells will be drilled in the following year if the first 

tests look promising. Additional wells will be drilled in two 

pods of five. 

The wells will be located along the crest of the Rock 

Springs Uplift, to the east of the Sand Dunes WSA. The first 

five wells would be outside the core area. If the five wells 

show promise the drilling program will continue, possibly 

extending into the core area. Actual well locations will 

depend on the success of previous drilling, which shows 

where coalbed methane can be produced economically. Economic factors could cause companies to limit activity to less 

than 15 wells. For this EIS we will assume that all wells will 

be drilled. 

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APPENDIX 10

Individual wells will produce for 10 to 20 years, based on 

information from the Powder River Basin. The project life 

thus will be 12 to 22 years. For this EIS we will assume that 

no wells will be abandoned before 2017. 

Production of coal bed methane from shallow coal beds 

would be on a 40-acre well spacing pattern. Exact well 

locations will be determined during the environmental analysis conducted for each well’s application to drill. In addition 

to well sites, other facilities, such as access roads, gas gathering and water disposal pipelines, electrical utilities, and compressors, will be constructed to aid gas production in any well 

field(s) developed. 

There is no coalbed methane production in the region. 

Without this production to compare to, estimated coalbed 

methane production rates could not be determined for this 

project. 

The 15 proposed wells would result in increased rates of 

development, add new coalbed methane production, increase 

the area of disturbance, and may increase surface water 

discharge if water quality is fresh. 

Produced Water-Gathering System and Discharge Facilities. Expected water production rates per well are unknown. 

We expect produced water at shallower depths to be fresh. 

Water that is fresh may be discharged from individual wells or 

collected and discharged at a central location. All produced 

water will be discharged only at NPDES permitted points. 

As wells get deeper off the crest of the Rock Springs Uplift, 

water quality will deteriorate and concentrations of dissolved 

solids would be greater. Discharge of poor quality water at the 

surface could probably not be allowed. This water would 

probably be injected into one or more open well bores located 

in the Nitchie Gulch Field. Most producing wells in this area 

are at the end of their productive life and could be converted 

for water injection use. 

Shallow Coalbed Methane Project Disturbance 

Access Roads. The BLM has a general policy that requires 

access roads to oil and gas wells to be crowned, ditched, and, 

in most cases, graveled or otherwise surfaced. This policy is 

based on the typical requirements for multicomponent rigs 

(rigs with two or more parts) and facilities. Rigs and facilities 

for these shallow wells will be simple in comparison. Thus, 

access needs will be reduced. 

Operations are expected to be as described in “Wyodak 

Coal Bed Methane Project Draft Environmental Impact Statement” (1999). A water well type drilling rig would be used for 

both drilling and completion activities. This type of drill rig 

and well servicing equipment is modest in size, when compared with multicomponent drill rigs and equipment used to 

drill deeper conventional oil and gas wells. Each well will be 

drilled within one to three days. Well completion also would 

occur within one to three days. Typically, wellpads would not 

be leveled unless steep terrain could not be avoided. For this 

type of producing well, service visits would be expected to 

occur once a month. As a result, two-track unimproved roads 

or trails would be used for access to most of these wells. 

In some cases, roads may need to be upgraded to BLM’s 

minimum standards due to special conditions such as rough 

topography or stream drainage areas. Use of cut and fill 

construction techniques for well access roads may disturb up 

to 1.8 acres per well located in difficult terrain. This disturbance is expected to occur on no more than 20 percent of the 

wells drilled. This disturbance would be considered as longterm disturbance. Additionally, travel on two-track roads will 

be rescheduled or postponed during infrequent periods of wet 

weather when vehicular traffic use could cause rutting. 

Drilling Operations. These shallow wells would be no deeper 

than about 1,200 feet and would have steel casing cemented in 

the hole. Typically, drilling operations will be confined 

within 100 foot by 100 foot well sites that are not leveled and 

are not cleared of vegetation. Cut and fill construction 

techniques to level work areas will be limited to areas where 

the land surface is too steep to allow the drill rig to set up. Use 

of cut and fill construction techniques for well sites may be 

necessary an estimated 10 percent of the time and may disturb 

up to 0.25 acres per well. Total disturbance for all well pads 

would be 0.4 acres. Areas disturbed, but not needed for 

production, will be reclaimed after drilling ends. 

Typically, a truck-mounted water well drilling rig will be 

driven to the well site and erected. Additional equipment, 

materials, and water will be trucked to the site. About 8,000 

gallons of water per well for cement preparation, well stimulation, dust control, and possibly drilling mud will be needed. 

Drilling mud is usually native mud and bentonite. 

A temporary mud pit about six feet deep, 10 feet wide, and 

up to 30 feet long, will be dug within each well site, used 

during drilling and completion operations, and then reclaimed. 

Total disturbance from 15 pits would be 0.1 acre. 

The drilling and completion operation for this type of well 

normally requires about seven to 25 people, including personnel for logging and cementing activities. Each well will be 

drilled within a period of one to three days. In preparation for 

production of gas from a drilled, cased, and cemented wellbore, 

a well completion program may be initiated to stimulate 

production of gas and to determine gas and water production 

characteristics. A mobile completion rig similar to the drill rig 

may be transported to the well site, erected, and used to 

complete a well. Completion operations are expected to 

average one to three days per well. Methane gas may be 

vented and water temporarily discharged for a short period 

during testing to determine whether wells will be produced. 

Once determined to be productive, wells would be shut-in 

until pipelines and other production facilities are constructed. 

Well Production Facilities. If wells are productive, about 

five or six square feet of surface will be leveled to install 

wellhead facilities. A weatherproof covering will be placed 

over the wellhead facilities. No additional structure will be 

constructed at the well site for gas-water separation facilities. 

A downhole pump will be used to produce water from the 

producing interval(s). Methane gas will flow to the surface 

using the space between the production casing and the water 

tubing. No pumpjacks will be put at the wellheads. The longterm surface disturbance at each productive well location 

667
APPENDIX 10

where no cut and fill construction techniques are utilized is 

likely to encompass a negligible area, much less than 0.1 acre. 

Well site production facilities typically will not be fenced or 

otherwise removed from existing uses. 

Pipeline trenches for well gathering lines are expected to 

disturb portions of 40-foot wide corridors temporarily and be 

reclaimed after construction is completed. Trenches will be 

constructed along the two-track well access roads wherever 

possible. Separate gathering lines, averaging one quarter to 

one-half mile long each, will be buried in the trenches and will 

transport methane gas to production facilities and produced 

water to discharge points. Disturbance would be 6 acres per 

well and 5.5 acres would be stabilized per producing well, 

after three years. 

Typically, gas production from each well will be individually measured and mechanically or electronically recorded at 

a central collection point or pod facility. Gas gathering lines 

for each five to 10 wells will be tied together at the pod facility. 

Here gas is commingled into the gas gathering system, which 

will transport it to a compressor station. An improved road, 

averaging one-half mile in length, will be constructed to each 

pod and will disturb an area no wider than 50 feet. Each pod 

facility will disturb about 0.25 acres. 

Additional Disturbance Assumptions. Shallow coalbed methane project activity is expected to center near the crest of the 

Rock Springs Uplift, in the south center part of the planning 

area. Where potential methane bearing coal beds lie below 

1,200 feet, conventional coalbed methane exploration and 

development procedures will be required. Activity related to 

conventional coalbed would be as described above under 

“Coalbed Methane Exploration and Development”. 

Table A10-1 shows a projection of the shallow coalbed 

methane drilling activity expected to occur over the 20-year 

period being studied. In the short term and long term, 15 new 

wells will be drilled. None are assumed to be abandoned. 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance to the planning 

area (Table A10-1). Long-term disturbance from the 15 wells 

would only be 14.4 acres. 

Assumptions by Alternative. For the No Action Alternative, 

all 15 wells would be drilled south of the core area. For all 

other alternatives, the first five wells would be drilled south of 

the core area and the others could extend into the core area. 

Coal, Oil Shale, Sodium (Brine), and Potash 

No oil shale development is expected during the planning 

period. There is low potential for coal and brine development. 

Existing coal mines and known coal reserves south of the 

planning area are expected to meet the demand for coal (USDI 

1996) but limited amounts of exploration may occur within 

the planning area to evaluate future coal development potential. If coal exploration occurs at all, it would likely occur in 

the last five to ten years of the planning period. The most 

probable location for exploration would be within the Rock 

Springs Known Recoverable Coal Resource Area and be 

limited to the areas open to exploration south and east of the 

Steamboat Mountain ACEC and south of the Eastern Portion 

of the Greater Sand Dunes ACEC. Access would largely be 

along existing roads and trails and overland. The amount of 

disturbance is expected to be between 10 and 15 acres and 

occur in a single season. It is expected that disturbed sites 

would be fully reclaimed within three years of disturbance. 

Brine (containing soda ash, oil, and gas) development 

potential is also low, because existing soda ash and oil and gas 

development is expected to meet the demand for these products during the planning period. Any development of brine 

within the brine potential area would occur slowly and in 

phases and likely occur in the last five to ten years of the 

planning period. Only a small portion of the planning area (in 

T. 23 and 24 N., R. 106 W.) is included within the brine 

potential area. Based on a past proposal by BWAB Incorporated, only about five wells would be expected in the planning 

area. Each well would disturb about 0.5 acres. Drilling would 

likely occur during the snow-free season, then be visited at 

least once per day during production. Access would be along 

existing roads and trails with a minimal amount of new road 

construction. Total disturbance within the planning area 

would be about five acres in the first year of development; 

then, due to interim reclamation, decrease to about three acres 

for the life of wells. Until drilling and testing of the brine 

producing zones are completed, it is not known how long the 

wells would produce. 

The Leucite Hills, including Boars Tusk and Steamboat 

Mountain, are known to contain potash. Chemical analyses of 

the rocks from Steamboat Mountain and Boars Tusk indicate 

a potash content of 12.66 and 9.81 percent, respectively 

(Hausel, Sutherland, and Gregory 1995). Hausel, et al., 

reports Steamboat Mountain had the highest potash content of 

any of the 24 samples collected from the Leucite Hills volcanic field. Schultz and Cross (1912) estimated 20,618,180 tons 

of potash occur within an estimated 206,181,800 tons of rock 

at Steamboat Mountain. Boars Tusk was estimated to contain 

2,899,438 tons of potash. Potash was mined during the first 

world war by the Liberty Potash Company on Zirkel Mesa, 

located south of the planning area. Potassium chloride was 

processed in a plant in Green River for fertilizer (Hausel, 

Sutherland, and Gregory 1995). Though Steamboat Mountain and Boars Tusk contain considerable amount of potash, 

development of this resource in these areas is unlikely during 

the planning period given the existing surface use constraints 

and the amount of potash contained elsewhere in the Leucite 

Hills. 

Locatables 

Existing levels of mining activity from the gold placers 

near Oregon Gulch are expected to remain through the planning period. Mining activity generally disturbs between one 

and five acres at any one time and includes small scale 

exploration by trenching with a backhoe or pick and shovel 

work. One exception to the backhoe, pick and shovel, is a 

trommel operation, which is run by operators in their free 

time. Such activity is limited to the snow-free months, 

typically May through mid-November. 

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APPENDIX 10

Gold has been worked from the placers east of Dickie 

Springs near Oregon Gulch since the late 1800s. No large 

scale mining has ever occurred in the area despite exploration 

by several well known mining companies and the price of gold 

reaching $850.00 per ounce in 1980. The potential for 

development of a gold mine in this area is low. It is impossible 

to predict the amount of disturbance that would occur with 

development of a mine since no proposals have been submitted and limited information is available regarding the occurrence of gold. However, a hypothetical gold mine has been 

developed for planning purposes only. A hypothetical mine 

could process as much as 320,000 tons per year of ore and 

disturb about 53 acres over an 11-year life (see Table A10-2). 

Besides gold occurrences in the northeastern portion of the 

planning area, there is the potential for diamonds to occur in 

association with the Quaternary volcanic rocks (lamproites) 

that make up Boars Tusk and Steamboat Mountain, located in 

the southern portion of the planning area (Hausel, et al. 1995). 

Though no diamonds have ever been recovered from these 

lamproites, they exhibit characteristics similar to diamondiferous lamproites found in Arkansas, Western Australia, and 

India. In general, diamonds are primarily restricted to the vent 

facies rock, which is represented at two, and possibly three, 

volcanic vents on top of Steamboat Mountain. Additional 

vents occur in other areas of the Leucite Hills volcanic field to 

the south of the planning area. 

Additional exploration is needed to further define these 

structures and to search for diamonds. Either detailed petrographic and geochemical analyses or larger sample volumes 

will be necessary to make this determination. It is anticipated 

that such exploration may occur during the planning period. 

Access to the top of Steamboat Mountain is limited; therefore, 

exploration may consist of helicoptering a drill rig to the top 

of Steamboat Mountain to gather the required information. 

Additional drilling may occur near Boars Tusk as well. About 

2 acres of disturbance is anticipated from these activities. 

Salables 

Quality construction materials are lacking on the lands that 

remain open to development of salable minerals, with the 

exception of Steamboat Mountain, which is capped by volcanic lava. However, under the No Action Alternative, Steamboat Mountain ACEC is closed to mineral material activities. 

Alternatives to the No Action Alternative will consider opening the lava capped upland to development of mineral materials. 

Demand for material in the planning area is expected to 

increase during the planning period, commensurate with the 

increase in oil and gas development and the needs of the 

Wyoming Highway Department (WYDOT) for reconstruction of U.S. Highway 191 and State Highway 28. Currently, 

sand and gravel for oil and gas development come from 

outside the planning area. Other construction materials, such 

as that used for constructing road base, are located during 

selection of the road alignment. Reconstruction of U.S. 

Highway 191 and Wyoming Highway 28 would require about 

25 acres of disturbance in addition to the 4 acres of existing 

disturbance associated with WYDOT’s pit along Wyoming 

Highway 28. WYDOT has a need for a 10-acre site along the 

east side of U.S. Highway 191 and within the planning area for 

a hot batch plant by the year 2001. The other 15 acres of 

disturbance would be associated with mineral material sites 

located elsewhere along U.S. Highway 191 and Wyoming 

Highway 28. Development of the mineral material sites is 

expected within the last 10 years of the planning period. 

The Lance Formation, Lewis Shale, and Mesaverde Group 

stratigraphic units could contain clays and shales usable in 

structural clay products (Construction Materials Survey 1965). 

Structural clay products include brick tile, sewer pipe and 

many other manufactured clay products used in construction. 

Little testing of these clays and shales has been conducted. 

The stratigraphic units containing the potentially usable clays 

occur in the southern portion of the planning area. With the 

surface use constraints that exist in this area and the abundance of clay products available in the United States and 

around the world, no development of this resource is expected 

within the planning area during the planning period. 

Off-Road Vehicle Assumptions 

Sales of all-terrain vehicles (ATVs) are anticipated to 

increase 300 percent to 400 percent in the next three to five 

years and their use on public lands will increase significantly. 

Public land agencies will increase land ethic programs such as 

“Leave No Trace” and “Tread Lightly” to gain voluntary 

compliance for visitor behavior. 

Recreation Assumptions 

As the population increases in the Intermountain West and 

as National Parks and Forests reach carrying capacity, visitor 

use in the planning area could increase from 1 percent to 2 

percent per year for the 20-year life of the plan. 

Local chambers of commerce and the travel and tourism 

industry are expected to continue and/or increase efforts to 

attract tourists to the area and to extend travelers’ visits to the 

area for longer periods of time which could increase usage. 

Most visitor use in the planning area occurs from late May 

to late October based on weather. Visitor use in winter months 

could increase if roads leading into the area are made “all 

weather” or are plowed. 

Non-consumptive recreation such as back country byways, watchable wildlife, wild horse viewing, mountain biking, etc., will continue to increase in popularity on public 

lands. 

Hunting pressure will fluctuate with the big game populations, i.e., if the elk population drops then fewer permits would 

be issued by Wyoming Game and Fish Department. Changes 

in Wyoming Game and Fish Department population objectives would also affect hunting opportunity. 

As open spaces decrease with development, pressure on 

existing open spaces will increase. 

Because of “flat” federal budgets, new recreation developments such as campgrounds are not anticipated. However, 

upgrades to the parking lot and restrooms at the Greater Sand 

Dunes ORV area could occur. 

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APPENDIX 10

Socioeconomic Assumptions 

The basic assumptions used in determining socioeconomic 

impacts and depicting their impact is the use of a 20-year 

planning horizon for the period 1991-2010. During this 

period, for planning purposes, it assumed that prices will 

remain constant for all commodities, thereby allowing a 

consistent basis for comparison. All dollar figures used for 

evaluating impacts in the socioeconomic analysis are in current dollars. There was no attempt to discount out-year 

dollars. 

The contribution of the mineral industry is measured in the 

quantity of each product produced, related to the value of that 

product, the direct income, and the indirect components of 

those income streams, and the purchases (expenditures on) of 

services and input products. In addition, the payment of direct 

taxes such as severance taxes to the state and the payment of 

ad valorem taxes to the county, cities and towns and the school 

systems along with the refunds of that share of the royalties 

collected on Federal lands, half of which are returned to the 

county of production, are major contributors of revenue to this 

area. 

Soils Assumptions 

Realty actions such as rights-of-way for linear actions such 

as pipelines and roads can adversely affect soils especially in 

areas of vegetated sand dunes which could be impacted by 

wind erosion when the vegetation is removed. Uncontrolled 

runoff from roads can create gullying in adjacent drainages. 

Impacts to soils from grazing are caused by over-utilization of the riparian areas where soil compaction and vegetative removal can create bank instability. This leads to loss of 

channel stability and results in higher sediment load. 

Impacts from oil and gas development include sedimentation, salt and phosphate loading, groundwater contamination, 

bank and channel instability, loss of aquifers, retort leachate 

production, augmented flows, and water disposal. Soil contamination from spills of drilling fluids and accompanying 

chemicals for production drilling threaten area soils. Unlined 

reserve pits offer no protection from contamination to surrounding soils. 

Off-road vehicle use impacts soil as a result of compaction 

of travel surfaces, disruption of vegetative cover, and disruption of soil surfaces by deep treaded tires. 

Designation of areas suitable for rallies and cross-country 

races would have local adverse impacts on soil conditions 

through compaction and disturbance of the surface layers. 

Proper monitoring and rehabilitation should restrict the extent 

of soil damage. Any such designated areas must be closely 

examined before approval is given. None are anticipated in 

this plan. 

Vegetation manipulation to enhance wildlife habitat would 

cause localized short-term impacts to physical and chemical 

characteristics of soils, increasing erosion susceptibility 

through the loss of both ground cover and litter accumulation. 

Over the long term, vegetation should increase over pretreatment production levels which would decrease the erosion 

hazard. 

Vegetation Assumptions 

Two precipitation zones cover 98 percent of the planning 

area. In the 7- to 9-inch zone of annual precipitation, stabilizing vegetative ground cover would occur in 2 to 3 years. Brush 

establishment/invasion in surface disturbed areas creating a 

vegetative landscape similar to the adjacent lands would occur 

in 15 to 20 years. In the 10- to 14-inch zone of annual 

precipitation, stabilizing vegetative ground cover would be 

established within 2 years. Brush invasion in surface disturbed areas creating a vegetative landscape similar to adjacent lands would occur within 13 to 15 years. 

Adequate forage is available for current wildlife objective 

numbers. 

Visual Resources Management 

Assumptions 

Visual resource management designations would be incorporated into all project planning. Designations would be 

managed with mitigation or by avoidance when affected by 

projects or activity impacts. Visual resources would continue 

to be given special consideration in the Greater Sand Dunes, 

Oregon Buttes, and Steamboat Mountain ACECs; White 

Mountain Petroglyphs; Red Desert Watershed Area; South 

Pass Historic Landscape; National Scenic Trail; and National 

Historic Trails. More emphasis will be placed on mitigating 

effects to the visual resources. 

Watershed Health and Water Quality 

Assumptions 

This portion of the analysis is based upon the ability of the 

proposed alternatives to achieve the stated objectives of: 1) 

stabilizing and conserving soils; 2) increasing vegetative 

production; 3) maintaining or improving surface and groundwater quality; and 4) protecting, maintaining, or improving, 

wetlands, floodplains, and riparian areas. All of which are 

related through erosion and water infiltration. If the selected 

alternative meets these conditions, it should also be in compliance with federal state and local laws and regulations regarding water quality. These include: The Clean Water Act as 

amended by the Water Quality Act of 1987 (Public Law 100-

4), and the State of Wyoming Department of Environmental 

Quality, Water Quality Rules and Regulations (Wyoming 

State Law 9-4-101 through 9-4-115, 35-11-12(a)(I), and 35-

11-302). 

Watershed health incorporates both upland and riparian 

conditions and is related to vegetation, soil, and run off. The 

better the condition of the watershed, the better the quality of 

the water. 

As human activity in the area increases, the potential for 

degradation of watershed health and water quality will increase. This creates a need to heal existing disturbances and 

buffer the effects of future activity. 

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APPENDIX 10

Any disturbance to the soil surface or changes in vegetative 

cover may have an effect on watershed health and water 

quality. Such disturbances can include but are not limited to 

roads, well pads, pipelines, livestock and wildlife grazing 

impacts, and off-road recreation. The degree of impact any 

one or series of disturbances has is influenced by a multitude 

of factors that includes location within the watershed, time 

and degree of disturbance, existing vegetation, and average 

precipitation. Therefore, watershed health and water quality 

can be related to other portions of this document that include 

grazing, soils, and mineral development. 

A 1982 sediment study and recent Proper Functioning 

Condition (PFC) surveys indicate that Jack Morrow Creek 

and Pacific Creek provide a disproportionate amount of the 

sediment in relation to the amount of water produced. This 

indicates that there are existing conditions that prompt concern. Some degree of sediment would continue to be generated from natural occurrences and human-caused actions. 

Roads, pads, and the associated runoff are major concerns 

for surface hydrology. The compaction of the road base and 

the smoothing of the road surface reduce infiltration and 

increase runoff. The creation of drainage ditches and the 

installation of culverts channelizes runoff. These structures 

would reduce the overall erosion associated with surface 

disturbance but could increase the rate of erosion where they 

concentrate overland flow. Proper installation would reduce 

this effect. Well pads have the same effect, although normally 

not as extensive as a road system. It is assumed that even with 

good engineering and maintenance to reduce these effects, 

they would not totally be eliminated. 

Nonpoint (general runoff) pollution is the primary concern 

in the planning area; thus, water quality and land condition are 

closely tied. For the purposes of this analysis it is assumed that 

the greater the level of human activity (oil and gas field 

development, livestock grazing, road building, recreation, 

etc.), the greater the potential for a degradation of land 

condition through erosion and the introduction of hazardous 

materials. Point pollution is less of a concern as potential 

sources are normally limited in volume and generally located 

on active drill or construction sites where it is more easily 

monitored and controlled. 

The increase in the rate of recreational and field development activity and resulting pressure on land and water resources will vary depending on the chosen alternative. It is 

assumed that there will not be a reduction in overall activity 

from the present situation under any alternative. Alternative 

B shows a decrease in field development activity over time, 

but recreation use would most likely still increase. 

Grazing activities will also have varied impacts under the 

different alternatives. However, it is assumed that the implementation of the Standards and Guides for Healthy Rangeland 

(S&Gs) (43 CFR 4180.1) will have a moderating effect on the 

impacts between the alternatives but will not completely 

eliminate them. 

Cumulative impact estimates for the planning area watersheds were calculated in the following way. 

1. Watershed boundaries were delineated using topographic 

relief. Because steeper slopes are more vulnerable to 

erosion, smaller watersheds were drawn in areas of high 

topographic relief. Larger watersheds were drawn in 

areas of low topographic relief because of the reduced 

erosive potential and difficulties in locating hydrologic 

boundaries in relatively flat country. Watershed size 

averages around 1,750 acres with a wide distribution. In 

several cases, the planning area boundary cuts across 

watersheds creating very small areas. 

2. The area, length of roads, and number of well pads for 

each watershed were obtained from the GIS system. 

3. It is assumed for this analysis that all roads were 40 feet 

wide for their entire length. Using this assumption, road 

lengths were then translated into estimated acres of road 

per watershed. 

4. Each well pad was assumed to create a disturbance of one 

acre. 

5. The percentage of disturbance for each watershed was 

determined by adding the road and well pad related 

disturbances and dividing by watershed area. 

6. The watersheds were then ranked as to their percentage of 

disturbance and the calculated disturbance was rounded 

to the nearest full percentage. 

Table A10-3 reflects a brief analysis of the planning area 

based on the above procedure. This method of analysis is 

sensitive to the size of the watershed chosen. The smaller a 

watershed is, the greater the percentage of disturbance will 

occur for any given amount of disturbance. Ideally, all the 

watersheds should be close to the same size but this is not the 

case. Watershed sizes ranges from over 11,000 acres to less 

than 2. Additional analysis will be needed to address site 

specific effects. 

Because of the sensitivity of this method to watershed size 

and the wide range of sizes resulting from the delineation 

process, an additional tool of analysis is to group watersheds 

of similar size prior to comparison. For example, smaller 

watersheds with a high percentage of disturbance were separated out because they indicate a high potential for localized 

erosion and suggest areas to focus on with initial monitoring 

efforts. Larger watersheds were grouped and ranked as well 

but, because of their larger sizes, the percentages of disturbance were lower than the smaller watersheds. 

As mentioned before, watershed size within the planning 

area is a function of topographic relief and where the planning 

area boundary happened to cross a larger watershed. The top 

three watersheds with the greatest percentage disturbance 

easily fall into this category as they encompass less than two 

acres each. These watersheds and several of the other smaller 

watersheds were originally part of larger watersheds but were 

truncated in the computer analysis by the planning area 

boundary. For the purposes of this analysis, they will be 

considered separately. 

Tables A10-4 through A10-8 reflect the analysis of the 

watersheds. Under this type and scale of analysis, watersheds 

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APPENDIX 10

of less than 100 acres are still considered relatively small. 

However, given the greater than 10 percent disturbance, they 

indicate an area of concern. As watershed size increases, it 

takes a larger total area of disturbance to register as a significant change in the percentage of disturbance. Therefore, the 

level of disturbance being considered is lower. Just as the 

smaller watersheds require special consideration, so do the 

larger watersheds. Watershed size and the percentage disturbance for a given amount of disturbance are inversely proportional. Therefore a larger watershed with a lower percentage 

of disturbance may rate a higher level of concern than is first 

evident. 

This analysis is limited in scope as it only considers 

concentration of disturbance in relatively large areas within 

the boundary of the planning area, not the actual conditions on 

the ground. It can be easily influenced by the size of the 

selected watersheds and does not take into account slope, 

disturbance location, localized flow conditions, or soil characteristics. An example of this can be found in the Nitch Creek 

Watershed (J2NC1, J2NC2, . . .) The sub watersheds are 

comparatively large and flat. While this indicates a lower 

potential for high energy overland flows than might occur in 

watersheds with steeper topography, it does not reflect that 

much of this area consists of stabilized sand dunes that are 

highly sensitive to disturbance. This method also does not 

allow direct comparisons between all watersheds. An example can be found in the partial watersheds listed in Table 

A10-4 and Table A10-5. These partial watersheds with high 

percentages of disturbance indicate areas of concentrated 

activity and may be good places to consider monitoring. 

However, they do not reflect cumulative impacts within the 

entire watershed as portions are outside the planning area 

boundary and can not be accurately compared to watersheds 

that are of considerably larger size. Given these constraints, 

a low ranking does not mean that erosion within such a 

watershed is not a concern. 

While this analysis does not indicate specific locations and 

disturbances, it does indicate watersheds that have a greater 

concentration of activity than those in the immediate vicinity, 

and thus poses a higher potential erosion. In short, this is the 

first cut and should not be used exclusively to determine 

cumulative impacts. More information can be gained by 

looking at other aspects of the land such as soil type, riparian 

and stream conditions, and the conditions of existing surface 

disturbances. 

Wild Horse Assumptions 

There would be a 20 percent annual increase in horse 

numbers and gathering would occur about every 2 years. 

Gathering would be directed at maintaining the wild horse 

population within appropriate management level range of 415 

to 600 animals. 

About 1 acre would be disturbed and vegetation and forage 

removed from setting up and use of wild horse traps. 

Wilderness Study Area Assumptions 

All seven Wilderness Study Areas found within the planning area will continue to be managed under the “Interim 

Management Policy and Guidelines for Lands Under Wilderness Review” (USDI 1995). It is not anticipated that Wilderness designation or unsuitability determinations will occur 

during the planning period. 

Wildlife Assumptions 

The planning area is primarily pristine in nature and a wide 

array of wildlife species are known to inhabit the area; 

however, there is also a lack of information for many species. 

Big game are regularly monitored by the Wyoming Game and 

Fish Department but little is known about neotropical birds, 

amphibians, reptiles, etc. There is also a lack of information 

in regards to Threatened, Endangered, or Sensitive species. It 

is assumed that some level of development and recreational 

activity would occur and that as development and recreational 

activities increase more fragmentation of habitats will occur 

making movement for many species difficult. More information on wildlife will continue to be gathered as development 

occurs but more species will also become species of concern. 

The Steamboat elk herd is very susceptible to displacement 

by human activities or harassment because of the lack of 

hiding and escape cover. Elk are the least tolerant to human 

disturbance or intrusion of any of the big game species that 

inhabit the planning area. Increased activity and a continuous 

human presence across the planning area would make 

sustainability of this herd very unlikely (pg 361 GRRMP 

FEIS, USDI 1996). Elk will be displaced from areas where 

development occurs, and depending on the extent of development may be lost in that area for the life of the development. 

As more activity occurs, increased fragmentation of crucial 

habitats in the planning area will also occur, causing loss of the 

biological integrity of the area. Maintaining connectivity 

between crucial habitat areas, and unique or limited vegetative communities would mitigate some of the adverse impacts 

development has on wildlife. It is assumed that some adaptation to activity would occur, but most of the elk herd would not 

adjust. 

Mule deer populations in the planning area are well below 

objective at this time. Increasing development, potential loss 

of parturition areas in the Oregon Buttes area, increased 

fragmentation of crucial habitats, increased recreation use, 

and competition with elk will result in objective numbers for 

mule deer not being met over the life of this plan. It is assumed 

that habitat is not the limiting factor. 

Special Management Area Assumptions 

Visitor health and safe issues and oil and gas development 

conflicts will remain high in portions of the Greater Sand 

Dunes ORV area (currently 17 producing wells in the area). 

The ACEC designation (relevance and importance criteria) in the Greater Sand Dunes could be jeopardized with 

additional oil and gas well development. 

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APPENDIX 10

PREFERRED ALTERNATIVE 

ASSUMPTIONS 

Livestock Grazing 

Eleven livestock grazing water developments would be 

constructed. 

Minerals 

Oil and Gas Exploration and Development 

Activity expected under the Preferred Alternative will be 

approximately the same when compared to the No Action 

Alternative. Instead of the entire Core Area being closed to 

leasing, a staged leasing procedure will close some areas to 

leasing and allow others to be leased within the Core Area and 

Migration Corridor areas. Under this proposal some areas 

would be withheld until others have been developed. 

Producing wells in the planning area have a long well life 

(26-year average production life). The period needed to 

explore, develop, and abandon an area will be longer than the 

life of this plan. It is anticipated that most lands withheld from 

leasing as part of this Preferred Alternative will not become 

available for lease until after 2017. 

With staged leasing, additional areas of no surface occupancy restrictions, and additional surface use restrictions a 

drilling level of 65 wells is expected. This will allow for 

development of one or two fields of 20 to 25 wells somewhere 

in the planning area and other scattered activity. The complicated nature of the staged leasing proposal will reduce industry leasing, exploration, and development interest in those 

parts of the planning area where it is proposed. 

Units 

Twenty of the potential 83 exploratory unit proposals are 

expected to actually be proposed under the No Action Alternative. These projected proposals include proposals already 

made in 1998. This level is reduced by eight over the No 

Action Alternative. Having large parts of the Core Area and 

Migratory Corridor areas involved in a staged leasing scenario 

will make it more difficult for industry to put together a 

complete prospect for unitization. Development in these 

areas would more likely be on an individual lease basis. 

Wells 

Future activity, if exploration and development activity 

were allowed in the entire planning area, was projected (192 

wells). Exploration and development drilling will continue at 

a rate allowing for 65 new wells. Thirty-five of the 65 wells 

could be drilled in the Core and Migratory Corridor areas 

where existing leases are present and new leasing is allowed. 

Any new field developed in these areas may not be fully 

developed due to restrictions that have been proposed. Of the 

other 30 wells that could be drilled in the rest of the planning 

area, a small field could be developed with other wells 

scattered across the area. 

Table A10-9 shows a projection of the drilling activity 

expected to occur over the 20-year period being studied 

(projected coalbed methane development activity is not included). Forty-six wells are currently producing. In the short 

term (1998-2007), 31 new wells will be drilled. Sixteen wells 

will produce and 15 wells will be drilled and abandoned. An 

additional seven older wells will be abandoned, leaving 55 

total wells in production, or nine more wells producing than at 

the beginning of 1998. 

In the long term, more producing wells will be abandoned 

than new producing wells will be drilled. By the end of 2017 

only 38 wells will still be producing, or eight fewer producing 

wells than at the beginning of 1998. As few as four of the 

presently producing wells and the 34 new producing wells 

will still be producing at the end of 2017. 

Production 

A table of projected annual production rates of oil and gas 

through 2017 was prepared for the planning area (Table A10-

10). 

Surface Disturbance 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-9. 

Coalbed Methane Exploration and Development 

Coalbed methane exploration and development activity is 

expected to occur in only parts of the area having potential, 

due to leasing and activity restrictions. Less than one-third of 

the eastern lobe will be available for development activity and 

less than one half of the western lobe will be available. Staged 

leasing restrictions would make it more difficult to develop 

any coalbed methane resource present. Coalbed methane 

needs to be developed completely in an area, because of the 

need to deplete associated water. Large areas of no leasing and 

no surface occupancy will restrict industries ability to explore 

and produce coalbed methane. Under this alternative, number 

of coal bed methane wells that can be drilled will decrease to 

only five wells or less. 

Table A10-11 shows a projection of the coal bed methane 

drilling activity expected to occur over the 20 year period 

being studied. In the short term (1998-2007), 5 new wells will 

be drilled. Three new wells are expected to produce and three 

wells will be drilled and abandoned. Combined with the two 

existing temporarily abandoned coalbed methane wells, five 

wells are expected to be producing in 2007. Over the long 

term, the five wells are expected to continue to produce. 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-11). 

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APPENDIX 10

Recreation 

Same as No Action Alternative. 

NO ACTION ALTERNATIVE 

ASSUMPTIONS 

Livestock Grazing 

No new range improvements would be constructed. 

Minerals 

Oil and Gas Exploration and Development 

Actual activity expected under the No Action Alternative 

is expected to be only one-third of potential activity and is 

assumed for all activity projections made below. Activity 

levels will be lower because about two-thirds of the planning 

area will be unavailable for exploration and development 

activity under the No Action Alternative. The large amount of 

land not available for lease or with restrictions on surface 

disturbing activities reduces industry interest in the entire 

area. 

Units 

Twenty-eight (one-third) of the potential 83 exploratory 

unit proposals are expected to actually be proposed under the 

No Action Alternative. These projected proposals include 

proposals already made in 1998. 

Wells 

Future activity, if exploration and development activity 

were allowed in the entire planning area, was projected (192 

wells). A reduction of potential wells by two-thirds leaves 

only 64 wells that could be drilled under the No Action 

Alternative. 

Table A10-12 shows a projection of the drilling activity 

expected to occur over the 20-year period being studied 

(projected coalbed methane development activity is not included). Forty-six wells are currently producing. In the short 

term (1998-2007), 32 new wells will be drilled. Seventeen 

wells will produce and 15 wells will be drilled and abandoned. 

An additional seven older wells will be abandoned, leaving 56 

total wells in production, or ten more wells producing than at 

the beginning of 1998. Fourteen new exploratory unit 

proposals are anticipated. 

In the long term, more producing wells will be abandoned 

than new producing wells will be drilled. By the end of 2017 

only 38 wells will still be producing, or eight fewer producing 

wells than at the beginning of 1998. As few as four of the 

presently producing wells and the 34 new producing wells 

will still be producing at the end of 2017. Twenty-eight new 

exploratory unit proposals; 64 new wells; 34 new producing 

wells; 30 drilled and abandoned wells; and 42 abandoned 

producing wells are anticipated. At the end of 2017 there will 

be 38 producing wells in the planning area. This will be a 

decrease of eight wells over the December 1997 total of 46 

wells. 

Production

 A table of projected annual production rates of oil and gas 

through 2017 was prepared for the planning area (Table A10-

13). 

Surface Disturbance 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-12). 

Coalbed Methane Exploration and Development 

Coalbed methane exploration and development activity is 

expected to occur in only parts of the area having potential, 

due to leasing and activity restrictions. Approximately one 

third of the eastern lobe is available for development activity 

while about one half of the western lobe is available. 

Table A10-14 shows a projection of the coal bed methane 

drilling activity expected to occur over the 20 year period 

being studied. In the short term (1998-2007), 10 new wells 

will be drilled. Five new wells are expected to produce and 

five wells will be drilled and abandoned. Combined with the 

two existing temporarily abandoned coalbed methane wells, 

seven wells are expected to be producing in 2007. Over the 

long term, the seven wells are expected to continue to produce. 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-14). 

In the short term (1998-2007), 10 new wells will be drilled. 

Five new wells are expected to produce and five wells will be 

drilled and abandoned. Combined with the two existing 

temporarily abandoned coalbed methane wells, seven wells 

are expected to be producing in 2007. Over the long term, the 

seven wells are expected to continue to produce. 

Recreation 

Recreation visitor days increase at the rate of 2 percent per 

year for the planning period. Recreation on public lands is 

continuing to increase. The 2 percent per year rate of growth 

is the same as used for the Green River RMP (see 

Socioeconomics). 

ALTERNATIVE A 

ASSUMPTIONS 

Livestock Grazing 

Twenty-five livestock water developments would be constructed, disturbing 25 acres. 

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APPENDIX 10

Oil and Gas 

Due to incomplete information on the actual number and 

location of these wells the following assumptions were made: 

- There would be activity on the 8,800 acres of crucial 

habitat at the base of Steamboat Mountain, adjacent to 

(and partially in) the Greater Sand Dunes ACEC. 

- Activity would occur in the canyons and on the ridges on 

the back side of Steamboat Mountain. 

- Activity would occur in the connectivity area in conjunction with adjacent activity in the core. 

- Assume activity would occur in calving areas in T. 27, R. 

100. 

- Assume activity would occur with the Yates (T. 25, R. 

104) and Barlow and Haun proposals. 

Minerals 

Oil and Gas Exploration and Development 

Activity expected under Alternative A will increase in 

comparison to the No Action Alternative. With the core area 

open an additional 28 wells are expected to be drilled in that 

area. This will allow for development of a field of 20 to 25 

wells and other scattered activity. With slightly relaxed 

restrictions in the planning area as a whole, an additional eight 

wells are expected to be drilled. Industry interest in some parts 

of the planning area will still be reduced due to remaining 

restrictions that still apply. 

Units 

As many as 46 new exploratory unit proposals are expected 

to actually be proposed under Alternative A. These projected 

proposals include proposals already made in 1998. 

Wells 

Future activity, if exploration and development activity 

were allowed in the entire the planning area, was projected 

(192 wells). Reduced restrictions will allow exploration and 

development to increase to 100 wells. 

Table A10-15 shows a projection of the drilling activity 

expected to occur over the 20-year period being studied 

(projected coalbed methane development activity is not included). Forty-six wells are currently producing. In the short 

term (1998-2007), 48 new wells will be drilled. Twenty-five 

wells will produce and 23 wells will be drilled and abandoned. 

An additional seven older wells will be abandoned, leaving 64 

total wells in production, or 18 more wells producing than at 

the beginning of 1998. 

In the long term, more new producing wells will be drilled 

than old producing wells will be abandoned. Fifty-seven 

wells will be producing by the end of 2017, or 11 more than 

at the beginning of 1998. 

Production 

A table of projected annual production rates of oil and gas 

through 2017 was prepared for the planning area (Table A10-

16). 

Surface Disturbance. Statistics on drilling activity and the 

above surface disturbance assumptions were used to project 

acres of disturbance, stabilization, and net long-term disturbance for the planning area (Table A10-15). 

Coalbed Methane Exploration and Development 

Coalbed methane exploration and development activity is 

expected to occur in only parts of the area having potential, 

due to leasing and activity restrictions. Table A10-14 shows 

a projection of the coal bed methane drilling activity expected 

to occur over the 20 year period being studied. In the short 

term (1998-2007), 10 new wells will be drilled. Five new 

wells are expected to produce and five wells will be drilled and 

abandoned. Combined with the two existing temporarily 

abandoned coalbed methane wells, seven wells are expected 

to be producing in 2007. Over the long term, the seven wells 

are expected to continue to produce. 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-14). 

Recreation 

Recreation visitor days will grow at the rate of 1 percent per 

year. The rate of increase is lower than the other alternatives 

based on potential impacts to big game hunting, wildlife 

numbers, and increasing development which will impact the 

“wide open spaces” and opportunities for solitude (see 

Socioeconomics). 

ALTERNATIVE B 

ASSUMPTIONS 

Livestock Grazing 

Eleven livestock grazing water developments would be 

constructed. 

Minerals 

Oil and Gas Exploration and Development 

Activity expected under Alternative B will decrease in 

comparison to the No Action Alternative. With the additional 

areas closed to leasing, more no surface occupancy restrictions, and additional surface use restrictions drilling activity is 

expected to be reduced to only 45 wells. This will allow for 

development of a field of 20 to 25 wells somewhere in the 

planning area and other scattered activity. The additional land 

not available for lease or with restrictions on surface disturbing activities will further reduce industry leasing, exploration, 

and development interest in the entire area. 

675
APPENDIX 10

Units. As many as 19 new exploratory unit proposals are 

expected to actually be proposed under Alternative a. These 

projected proposals include proposals already made in 1998. 

Wells. Future activity, if exploration and development 

activity were allowed in the entire the planning area, was 

projected (192 wells). Increased restrictions means even 

fewer wells will be drilled than under the No Action Alternative. Only 45 wells are expected to be drilled within the entire 

the planning area. Twenty of the 45 wells could be drilled in 

the core and corridor areas were existing leases are present. 

Any new field developed in these areas probably could not be 

fully developed due to additional restrictions that have been 

proposed. Of the other 25 wells that could be drilled in the rest 

of the planning area, a small field could be developed with 

other wells scattered across the area. 

Table A10-17 shows a projection of the drilling activity 

expected to occur over the 20-year period being studied 

(projected coalbed methane development activity is not included). Forty-six wells are currently producing. In the short 

term (1998-2007), 22 new wells will be drilled. Twelve wells 

will produce and ten wells will be drilled and abandoned. An 

additional seven older wells will be abandoned, leaving 51 

total wells in production, or five more wells producing than at 

the beginning of 1998. 

In the long term, more producing wells will be abandoned 

than new producing wells will be drilled. By the end of 2017 

only 28 wells will still be producing, or 18 fewer producing 

wells than at the beginning of 1998. 

Production. A table of projected annual production rates of 

oil and gas through 2017 was prepared for the planning area 

(Table A10-18). 

Surface Disturbance. Statistics on drilling activity and the 

above surface disturbance assumptions were used to project 

acres of disturbance, stabilization, and net long-term disturbance for the planning area (Table A10-17). 

Coalbed Methane Exploration and Development 

Coalbed methane exploration and development activity is 

expected to occur in only parts of the area having potential, 

due to leasing and activity restrictions. Less than one third of 

the eastern lobe will be available for development activity and 

less than one half of the western lobe will be available. 

Restrictions in addition to those of the No Action Alternative 

are expected to decrease the number of coal bed methane wells 

that can be drilled to only five wells. 

Table A10-11 shows a projection of the coal bed methane 

drilling activity expected to occur over the 20-year period 

being studied. In the short term (1998-2007), five new wells 

will be drilled. Three new wells are expected to produce and 

two wells will be drilled and abandoned. Combined with the 

two existing temporarily abandoned coalbed methane wells, 

five wells are expected to be producing in 2007. Over the long 

term, the five wells are expected to continue to produce. 

Statistics on drilling activity and the above surface disturbance assumptions were used to project acres of disturbance, 

stabilization, and net long-term disturbance for the planning 

area (Table A10-11). 

Recreation 

Same as No Action Alternative. 

676
APPENDIX 10

677 
TABLE A10-2

 HYPOTHETICAL GOLD MINE

(0.10 oz/ton)

(320,000-ton mine; 11-year life)

Year 

Production 

(000) 

(tons) 

Disturbance 

(acres) 

Reclaimed 

(acres) 

Total 

Disturbance 

(acres) 

Total 

Reclaimed 

(acres) 

Total 

Remaining 

Disturbance 

(acres) 

1999 150 10 - 10 - 10 

2000 200 4 - 14 - 14 

2001 275 4 2 18 2 16 

2002 320 6 4 24 6 18 

2003 320 5 2 29 8 21 

2004 320 5 5 34 13 21 

2005 320 8 6 42 19 23 

2006 320 4 7 46 26 20 

2007 320 2 7 48 33 15 

2008 250 4 10 52 43 9 

2009 175 1 5 53 48 5 

2010 0 - 5 53 53 0 

TABLE A10-3

WATERSHEDS AND PERCENTAGE DISTURBANCE

Number of 

Watersheds Percentage of Disturbance 

66 <0.5 

168 1.0 

74 2.0 

20 3.0

 5 4.0

 3 5.0

 1 6.0

 1 8.0

 1 12.0

 1 14.0

 2 16.0

 1 27.0

 1 39.0

 1 42.0 

678
TABLE A10-4 

WATERSHEDS WITH THE GREATEST PERCENTAGE DISTURBANCE 

Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J4BRC20 0.70 0.06 0 0.29 42% Part, Low, WSA 

J4AB12 1.97 0.16 0 0.78 39% Part, High 

J4AB17 0.18 0.01 0 0.05 27% Part, High 

Abbreviations used in the Comments column: 

Part = Watershed has been truncated by the planning area boundary. The entire watershed is not being analyzed. 

High = Watershed is entirely or partially within an area with high oil and gas potential. 

Med. = Watershed is entirely or partially within an area with medium oil and gas potential. 

Low = Watershed is entirely or partially within an area with low oil and gas potential. 

Core = Watershed is entirely or partly within the core area. 

WSA = Watershed is entirely or partially within a Wilderness Study Area. 

Elk = Watershed is entirely or partially within the elk calving areas or connecting corridor. 

TABLE A10-5 

WATERSHEDS BETWEEN 10 AND 100 ACRES 

(with an = or > 10% disturbance) 

Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J1PC26 13.11 0.43 0 2.08 16% Part, Low 

J4AB6 15.29 0.38 0 1.84 12% Part, High 

J4BUC7 32.29 0.27 4 5.31 29% Part, High 

J2DC2 58.06 0.86 4 8.17 12% Part, High 

Abbreviations used in the Comments column: 

Part = Watershed has been truncated by the planning area boundary. The entire watershed is not being analyzed. 

High = Watershed is entirely or partially within an area with high oil and gas potential. 

Med. = Watershed is entirely or partially within an area with medium oil and gas potential. 

Low = Watershed is entirely or partially within an area with low oil and gas potential. 

Core = Watershed is entirely or partly within the core area. 

WSA = Watershed is entirely or partially within a Wilderness Study Area. 

Elk = Watershed is entirely or partially within the elk calving areas or connecting corridor. 

TABLE A10-6 

WATERSHEDS BETWEEN 100 AND 1,000 ACRES 

(with an = or > 3% disturbance) 

Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J1NPS3 734.65 3.80 0 18.42 3% Med 

J4RC7 683.21 3.66 2 19.75 3% Part, Low 

J5OS2 671.23 3.71 0 17.99 3% Low, Elk 

J1SM4 654.40 3.58 0 17.36 3% Part, Med. 

J1PC20 594.35 5.64 0 27.35 5% Part, Low 

J1PC21 570.69 3.10 2 17.03 3% Part, Low 

J2NC4 546.22 3.08 2 16.93 3% Part, High, Core 

J5SW3 498.86 4.11 0 19.93 4% Part, Low 

J1PC36 467.49 2.63 0 12.75 3% Part, Med 

J1JM25 415.83 2.37 0 11.49 3% High, Core, Elk 

679
Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J5SW8 292.98 1.71 0 8.29 3% Part, Low 

J5PC6 286.74 1.89 0 9.16 3% Part, Low 

J2DC1 247.65 1.72 0 8.34 3% Part, High 

J4GW2 228.45 2.38 6 17.54 10% Part, High 

J1PC19 223.17 1.79 0 8.68 4% Part, Low 

J1PC24 192.39 1.96 0 9.50 5% Part, Low 

J5HS6 170.53 1.05 0 5.09 3% Part, Low 

J4AB1 158.34 0.78 2 5.78 5% Part, High, WSA 

J2NC4 133.93 0.72 0 3.49 3% Part, High 

Abbreviations used in the Comments column: 

Part = Watershed has been truncated by the planning area boundary. The entire watershed is not being analyzed. 

High = Watershed is entirely or partially within an area with high oil and gas potential. 

Med. = Watershed is entirely or partially within an area with medium oil and gas potential. 

Low = Watershed is entirely or partially within an area with low oil and gas potential. 

Core = Watershed is entirely or partly within the core area. 

WSA = Watershed is entirely or partially within a Wilderness Study Area. 

Elk = Watershed is entirely or partially within the elk calving areas or connecting corridor. 

TABLE A10-7 

WATERSHEDS BETWEEN 1,000 AND 2,000 ACRES 

(with an = or > 3% disturbance) 

Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J1PC12 1882.86 13.74 2 68.62 4% Mod, Low 

J1SD4 1841.16 9.62 0 46.64 3% Mod, Elk 

J1JM24 1635.50 8.54 4 45.41 3% High, Elk 

J1PC22 1518.79 8.36 0 40.53 3% Part, Low 

J1PC32 1165.95 6.09 0 29.53 3% Low, Elk 

Abbreviations used in the Comments column: 

Part = Watershed has been truncated by the planning area boundary. The entire watershed is not being analyzed. 

High = Watershed is entirely or partially within an area with high oil and gas potential. 

Med. = Watershed is entirely or partially within an area with medium oil and gas potential. 

Low = Watershed is entirely or partially within an area with low oil and gas potential. 

Core = Watershed is entirely or partly within the core area. 

WSA = Watershed is entirely or partially within a Wilderness Study Area. 

Elk = Watershed is entirely or partially within the elk calving areas or connecting corridor. 

680
TABLE A10-8 

WATERSHEDS EQUAL TO OR GREATER THAN 2,000 ACRES 

(and equal to or greater than 2% disturbance) 

Name Acres Road 

Miles Wells Acres of Disturbance 

% 

Disturbance Comments 

J5OS3 5526.85 18.87 0 91.49 2% Low 

J2NC2 5385.55 16.64 9 89.68 2% High, ACEC, Core 

J5OG1 4544.50 15.34 6 80.38 2% Low, Elk 

J1PC4 4503.68 29.02 0 140.70 3% Mod, 

J1PC11 3255.52 10.34 0 50.13 2% Mod, 

J1WD25 3077.11 11.10 0 53.82 2% High, Mod, ACEC, 

WSA 

J1WD24 2915.79 12.93 0 62.69 2% High, Mod, WSA 

J3AC3 2875.83 10.69 0 51.83 2% Mod, Elk 

J1SM3 2806.92 12.09 0 58.62 2% Mod, Elk 

J1JM22 2778.09 9.65 8 54.79 2% High, ACEC, Core 

J1JM17 2718.95 10.74 0 52.07 2% High, Elk 

J5DKS6 2714.41 9.82 0 47.61 2% Low, Elk 

J1NPS1 2608.89 9.07 6 49.98 2% High, Med, Low, Elk 

J1PC31 2541.16 7.58 4 40.75 2% Low, Elk 

J1WD23 2538.70 8.73 0 42.33 2% High, Med, WSA, Elk 

J4AD1 2520.18 8.82 6 48.76 2% High, Core, Elk 

J5SW4 2496.08 13.84 2 69.10 3% Low 

J5MDC3 2484.88 9.22 0 44.70 2% Low 

J4AD2 2274.66 7.21 0 34.96 2% High, Elk 

J1JM30 2255.74 8.73 4 46.33 2% High, Elk 

J2NC8 2195.87 7.23 4 39.05 2% High, Core, ACEC 

J1BXC1 2144.72 9.07 4 47.98 2% High, Core, ACEC 

J1JM16 2137.39 6.95 4 37.70 2% High, Elk 

J1SD1 2071.01 10.53 2 53.05 3% Med, Elk 

Abbreviations used in the Comments column: 

Part = Watershed has been truncated by the planning area boundary. The entire watershed is not being analyzed. 

High = Watershed is entirely or partially within an area with high oil and gas potential. 

Med. = Watershed is entirely or partially within an area with medium oil and gas potential. 

Low = Watershed is entirely or partially within an area with low oil and gas potential. 

Core = Watershed is entirely or partly within the core area. 

WSA = Watershed is entirely or partially within a Wilderness Study Area. 

Elk = Watershed is entirely or partially within the elk calving areas or connecting corridor. 

681
APPENDIX 10

682 
TABLE A10-10 

OIL AND GAS PROJECTED PRODUCTION RATES 

1998-2017 

PREFERRED ALTERNATIVE 

Year Oil Production 

(BBLs)1 

Gas Production 

(MMCF)2 

1998 5,499 3,976.2 

1999 5,616 4,060.8 

2000 5,850 4,230.0 

2001 5,967 4,314.6 

2002 6,084 4,399.2 

2003 6,318 4,568.4 

2004 6,318 4,568.4 

2005 6,552 4,737.6 

2006 6,669 4,822.2 

2007 6,435 4,653.0 

2008 6,201 4,483.8 

2009 6,210 4,483.8 

2010 5,733 4,145.4 

2011 5,850 4,230.0 

2012 5,850 4,230.0 

2013 5,733 4,145.4 

2014 5,148 3,722.4 

2015 4,680 3,384.0 

2016 4,563 3,299.4 

2017 4,446 3,214.8 

1

 Annual production per well = 117 barrels (BBLs) of oil or condensate. 

2

 Annual production per well = 84.6 million cubic feet (MMCF) of gas. 

Assumptions: 

46 wells producing as of 12/1997. 

Oil and gas production ratio will remain the same. 

Each well begins producing the year it is completed. 

683
APPENDIX 10

684 
APPENDIX 10

685 
TABLE A10-13 

OIL AND GAS PROJECTED PRODUCTION RATES 

1998-2017 

NO ACTION ALTERNATIVE 

Year Oil Production 

(BBLs)1 

Gas Production 

(MMCF)2 

1998 5,616 4,060.8 

1999 5,733 4,145.4 

2000 5,967 4,314.6 

2001 6,084 4,399.2 

2002 6,201 4,483.8 

2003 6,318 4,568.4 

2004 6,435 4,653.0 

2005 6,669 4,822.2 

2006 6,669 4,822.2 

2007 6,552 4,737.6 

2008 6,201 4,483.8 

2009 6,201 4,483.8 

2010 5,733 4,145.4 

2011 5,850 4,230.0 

2012 5,850 4,230.0 

2013 5,616 4,060.8 

2014 5,148 3,722.4 

2015 4,680 3,384.0 

2016 4,446 3,214.8 

2017 4,446 3,214.8 

1

 Annual production per well = 117 barrels (BBLs) of oil or condensate. 

2

 Annual production per well = 84.6 million cubic feet (MMCF) of gas. 

Assumptions: 

46 wells producing as of 12/1997. 

Oil and gas production ratio will remain the same. 

Each well begins producing the year it is completed. 

686
APPENDIX 10

687 
APPENDIX 10

688 
TABLE A10-16 

OIL AND GAS PROJECTED PRODUCTION RATES 

1998-2017 

Alternative A 

YEAR OIL PRODUCTION 

(BBLs)1 

GAS PRODUCTION 

(MMCF)2 

1998 5,499 3,976.2 

1999 5,733 4,145.4 

2000 6,084 4,399.2 

2001 6,318 4,568.4 

2002 6,669 4,822.2 

2003 6,786 4,906.8 

2004 7,020 5,076.0 

2005 7,371 5,329.8 

2006 7,605 5,499.0 

2007 7,488 5,414.4 

2008 7,254 5,245.2 

2009 7,488 5,414.4 

2010 7,137 5,160.6 

2011 7,371 5,329.8 

2012 7,488 5,414.4 

2013 7,371 5,329.8 

2014 7,020 5,076.0 

2015 6,669 4,822.2 

2016 6,552 4,737.6 

2017 6,669 4,822.2 

1

 Annual production per well = 117 barrels (BBLs) of oil or condensate. 

2

 Annual production per well = 84.6 million cubic feet (MMCF) of gas. 

Assumptions: 

46 wells producing as of 12/1997. 

Oil and gas production ratio will remain the same. 

Each well begins producing the year it is completed. 

689
APPENDIX 10

690 
TABLE A10-18 

OIL AND GAS PROJECTED PRODUCTION RATES 

1998-2017 

ALTERNATIVE B 

Year Oil Production 

(BBLs)1 

Gas Production 

(MMCF)2 

1998 5,499 3,976.2 

1999 5,616 4,060.8 

2000 5,733 4,145.4 

2001 5,733 4,145.4 

2002 5,850 4,230.0 

2003 5,967 4,314.6 

2004 5,967 4,314.6 

2005 6,201 4,483.8 

2006 6,201 4,483.8 

2007 5,967 4,314.6 

2008 5,499 3,967.2 

2009 5,499 3,976.2 

2010 4,914 3,553.2 

2011 5,031 3,637.8 

2012 5,031 3,637.8 

2013 4,797 3,468.6 

2014 4,212 3,045.6 

2015 3,627 2,622.6 

2016 3,393 2,622.6 

2017 3,393 2,453.4 

1

 Annual production per well = 117 barrels (BBLs) of oil or condensate. 

2

 Annual production per well = 84.6 million cubic feet (MMCF) of gas. 

Assumptions: 

46 wells producing as of 12/1997. 

Oil and gas production ratio will remain the same. 

Each well begins producing the year it is completed. 

691