(excerpt of full report)


Table of Contents


1. Introduction 3 
2. Gas Production Forecasts 5 
3. Economics 8 
4. Reserves 11 
Bibliography 12 
Glossary 13 
APPENDIX A: Petroleum Resources Management System  

APPENDIX B: Individual and Reserve Category Decline Curves, Type Wells, and Cash Flow Summaries



Table of Figures


Figure 1: Foothills Acreage Map and Well Locations 4 
Figure 2: Point of Rocks Type Well 6 
Figure 3: Total Gas Production History and Forecast 8 


Table of Tables


Table 1: Workover Schedule for Foothills Wells 7 
Table 2: Bridger Coal Mine Monthly Gas Deliveries 9 
Table 3: Foothills Blended Gas Prices 10 
Table 4: Foothills Oneline Summary 11 


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1. Introduction


Estimated herein are net natural gas reserves for Foothills Exploration interests in the Point of Rocks, South Black Rock, and Deadman Wash gas fields, all located in Sweetwater County, Wyoming (Figure 1). The 22 producing wells and 3 recompletions considered here target various intervals of the Second Frontier Formation with the exception of one well. The South Black Rock 43-15 is completed in the Frontier, Muddy, and Dakota intervals. 18 of the 22 producing wells are located in the Point of Rocks field, 3 are in the South Black Rock field, and 1 well is in the Deadman Wash field. First reported production among the 22 wells, from the Shiprock Federal 34-1R in the Point of Rocks field, was in 2002, followed by first reported production from the majority of the wells in 2006, 2007, and 2008. As of May 2019, the most recent date for which public data are available, 18 of the 22 wells are on production with average rates of 97 mcfd of gas and 1 bpd of water. Cumulative gas recovery through May 2019 is 11.256 bcf.


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Figure 1: Foothills Acreage Map and Well Locations


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The subject wells all produce a dry gas with a median historical gas-water ratio (GWR) of 259 mcf/stb. The Shiprock Federal 34-1R produces small, infrequent amounts of associated hydrocarbon liquids at rates too low to be considered here. To increase well productivity, Foothills plans to install plunger lift on the 18 producing wells in the Point of Rocks (PoR) field and to acidize 4 low rate producers. Foothills intends to recomplete 3 wells in the Point of Rocks (PoR) field after the current completions deplete.


Reserves estimated herein are compliant with the current SEC reserves definitions and have an effective date of August 1, 2019. The SEC Henry Hub natural gas price for this date is $2.973/mmbtu. Foothills receives Kern River (Platts) gas price with the exception of gas sold in the first six months of a year to a local coal mine at a premium price. This work utilized a blended price calculated from the constant SEC price, the differential between Kern River and Henry Hub, and the Bridger coal mine gas price premium of $3/mmbtu over Kern River price. All costs and expenses were held constant.


This one volume report consists of a narrative letter with figures and tables, a oneline summary of the properties, and appendices containing individual entity decline curve forecasts or performance predictions and reserve category and individual entity annualized cash flow summaries.


2. Gas Production Forecasts


Decline curves were used to forecast future performance of Foothills producing wells, all of which exhibited exponential declines. Decline rates ranged from 4 to 36%/yr with a median decline rate of 10.5%/yr. Technically recoverable resources were calculated based on an abandonment rate of 50 mcf/month. Decline curves for all producing wells are included in Appendix B.


To increase well productivity, Foothills plans to install plunger lift on the 18 producing wells in the PoR field and anticipates a 33% uplift in gas rate. Plunger installation increases the gas production rate but leaves the technically recoverable gas volume unchanged. For each producer, a new, steeper exponential decline rate was calculated from the assumed 33% uplift in rate, the unchanged technically recoverable gas volume, and the same 50 mcf/month abandonment rate. Foothills plans to install the plungers at the rate of one well per month beginning in September of this year, finishing in February of 2021. In addition, Foothills plans to acidize four low rate PoR producers to increase productivity when the wells are down for plunger installation. Based on acid jobs in similar wells, Foothills anticpates a doubling of the gas rate.


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Foothills plans to recomplete three PoR wells (Figure 1) in behind pipe zones when the current completions are depleted. The Point of Rocks 44-21 and Point of Rocks 28-2 wells, both currently completed in the lower, fluvial portion of the Second Frontier formation, are scheduled to be recompleted in the upper, marine portion of the Second Frontier as the lower zones deplete. Under the economic assumptions discussed below, both of these wells are currently uneconomic so for this evaluation both were scheduled for recompletion in October of this year. The Shiprock Federal 34-1R is currently producing from the marine section of the Second Frontier and will be recompleted in the stratigraphically lower fluvial zones upon depletion of the marine section. Under the assumptions discussed below, this completion has an 18 year life and was scheduled for recompletion in May 2037.


A type well was constructed to forecast gas recovery from the recompletions using production histories of the existing 10 PoR PDP wells (Figure 2). The type well initial rate was 5,045 mcf/month (166 mcfd), the decline rate was 9.04%/yr (0.0948 yr-1 exponential decline), and the resulting 50 year cumulative production was 633 mcf. Performance of the three recompletions, categorized here as PBP reserves, was estimated by adjusting the type well initial rate by the ratio of new completion thickness divided by total net thickness of the local Second Frontier formation. The PDP effective decline rate was left unchanged at 9.04%/yr for the PBP type wells.



Figure 2: Point of Rocks Type Well


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Dates for plunger installations, acid stimulations and recompletions for the PoR field are summarized in Table 1 below.


Table 1: Workover Schedule for Foothills Wells


API  LEASE  WELL_ID  plunger install  acidize  drill date  recomplete
49037271060000  POINT OF ROCKS  23-1  9/1/19         
49037267720000  SHIPROCK  3-1  10/1/19         
49037256800000  SHIPROCK  34-4  11/1/19         
49037244420000  SHIPROCK FEDERAL  4-4  12/1/19  x      
49037271050000  SHIPROCK  33-9  1/1/20         
49037240560000  SHIPROCK FEDERAL  20-10  2/1/20         
49037271840000  POINT OF ROCKS  44-21  3/1/20  x     10/1/19
49037269090000  POINT OF ROCKS  26-2  4/1/20  x      
49037273890000  POINT OF ROCKS  44-27  5/1/20  x      
49037270160000  POINT OF ROCKS  28-2  6/1/20        10/1/19
49037270150000  SHIPROCK FEDERAL  28-1  7/1/20         
49037269010000  SHIPROCK  29-1  8/1/20         
49037256840000  SHIPROCK FEDERAL  32-40  9/1/20         
49037275170000  SHIPROCK  32-33  10/1/20         
49037265400000  SHIPROCK  33-1  11/1/20         
49037268160000  SHIPROCK  33-2  12/1/20         
49037275030000  SHIPROCK  33-33  1/1/21         
49037211630001  SHIPROCK FEDERAL  34-1R  2/1/21        5/1/37


Fieldwide gas production is first forecasted to drop below the Bridger contracted volumes in January of 2036. The monthly decrease in Bridger gas demand is more rapid than the steady field decline causing field deliverability to rise above the Bridger volumes until the winter of 2037 when a 3 month shortfall occurs. Recompletion of the 34-1R lifts the field gas rate above Bridger volumes until a 3 month shortfall in winter 2040. The shortfall increases to 4 months in 2044 and 5 months in 2045. This five month shortfall in the winter months persists for the remainder of the field life considered here.


Gas production from all wells considered here (Figure 3) peaked at 130,000 mcf/month in 2008 and has since declined to 54,000 mcf/month as of May 2019. The forecast curve exhibits upticks in gas rate due to plunger installations in the near future and recompletion of the 34-1R in 2037. Cumulative gas recovery through May 2019 is 11.336 bcf and remaining reserves are estimated to be 4.901 bcf, giving an estimated ultimate recovery from all wells of 16.237 bcf.


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Figure 3: Total Gas Production History and Forecast


3. Economics


Economics were run using the gas production forecasts developed above combined with the following parameters. Plunger installation capital costs were $15,000 per well, acid stimulations were $4,686 per well, and recompletions were $250,000 per well. A two-month delay between a workover and first production was assumed.


Fixed operating expenses were $2,144 per well per month, increasing by $200 per well per month after plunger installation. Variable OPEX was a gas gathering charge of $0.242/mcf.


Individual well interests varied with an average PDP working interest of 88.5%. Before and after payout net revenue interests averaged 71.3% and 69.5%, respectively.


The gas BTU factor was 1.035 and shrink was 10.3%.


Severance and ad valorem tax rates were 5.6% and 6.2%, respectively.


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Foothills receives Kern River (Platts) gas prices with the exception of the gas volumes delivered to the Bridger coal mine (Table 2) which receives Kern River (Platts) price plus a $3/mmbtu premium. Based on the Henry Hub and Kern River monthly gas index prices, the price differential for the first six months of 2019 was +$0.127/mmbtu as the Kern River price was substantially above the Henry Hub price in the colder months. The July 2019 SEC price was $2.973/mmbtu, making the base Foothills price $3.100/mmbtu and the price of gas flowing to the Bridger coal mine $6.100/mmbtu. Blended gas prices by year are listed in Table 3.


Table 2: Bridger Coal Mine Monthly Gas Deliveries

(BTU = 1.035)


  Gas,   Gas, 
Month  Mmbtu   Mcf 
January   11,000    10,628 
February   10,500    10,145 
March   10,500    10,145 
April   8,000    7,729 
May   6,000    5,797 
June   1,000    966 


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Table 3: Foothills Blended Gas Prices


Year  $/Mmbtu   $/Mcf 
2019   3.100    3.209 
2020   3.358    3.475 
2021   3.333    3.450 
2022   3.383    3.501 
2023   3.443    3.564 
2024   3.514    3.637 
2025   3.594    3.720 
2026   3.686    3.815 
2027   3.791    3.924 
2028   3.910    4.047 
2029   4.044    4.185 
1930   4.194    4.341 
1931   4.262    4.411 
1932   4.322    4.474 
1933   4.355    4.507 
1934   4.391    4.544 
1935   4.398    4.552 
1936   4.404    4.558 
1937   4.324    4.475 
1938   4.349    4.502 
1939   4.378    4.531 
1940   4.394    4.548 
1941   4.399    4.553 
1942   4.405    4.559 
1943   4.411    4.565 
1944   4.417    4.572 
1945   4.424    4.579 
1946   4.432    4.587 
1947   4.440    4.596 
1948   4.449    4.605 
1949   4.460    4.616 
1950   4.471    4.627 
1951   4.482    4.639 
1952   4.495    4.653 
1953   4.520    4.678 
1954   4.536    4.695 
1955   4.554    4.713 
1956   4.573    4.733 
1957   4.593    4.754 
1958+   4.600    4.761 


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4. Reserves


Proved Reserves were estimated using the gas profiles, gas prices, and other economic parameters discussed above. Category level Reserves, shown in Table 1 above, total 2,012 mmcf of net gas with a PV10 value of $1,834.7 M$. An oneline summary of Proved Reserves organized by field and then by reserve category is shown in Table 4.


Table 4: Foothills Oneline Summary



Gas production increases and the associated economics due to plunger installation and the acid stimulations were included as part of the PDP reserves and not considered explicitly here as Foothills has retained the current operator who has extensive experience in Greater Green River Basin gas production operations.


Annualized cash flows at the project, field, and entity level are in Appendix B along with the decline curves and type wells discussed above. The field is economic for the 50 year reserves lifetime as specified by the SEC.


Original gas in place (OGIP) for a Second Frontier well on 160 acre well spacing, calculated volumetrically using average public domain porosity and water saturation values of 12.4% and 53%, respectively (SPE 21879, SPE 38379), and a net thickness of 39 feet, was 3.165 bcf. Average recovery for a PoR well, 0.751 bcf, corresponds to a recovery factor of 24% of OGIP. For perspective, industry average recovery for volumetric dry gas wells such as these is typically 50%.


This study did not consider identification and development of any PUD locations.


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Harrison, et al, “Reservoir Characterization of the Frontier Tight Gas Sand, Green River Basin, Wyoming”, SPE 21879, 1991.


Cluff, et al, “Petrophysical Analysis of the Frontier Formation (Cretaceous), Whiskey Buttes Field, Lincoln County, Wyoming”, SPE 38379, 1997.


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%/yr Percent (decline) per year
Bcf Billion Cubic Feet
bpd Barrels per day
BTU British Thermal Unit
GWR Gas Water Ratio
Mcf/month Thousands cubic feet (gas) per month
Mcf/stb Thousands cubic feet (gas) per stock tank barrels
Mmbtu Millions of british thermal units
Mscfd Thousand’s standard cubic feet per day
OGIP Original Gas in Place
PBP Proved Behind Pipe
PDP Proved Developed Producing
PoR Point of Rocks
PUD Proved Undeveloped
PV10 Present Value at 10% discount rate
SEC Securities Exchange Commission
SPE-PRMS Society of Petroleum Engineers- Petroleum Resources Management System


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