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Society of Petroleum Evaluation Engineers

Fair Market Value Example Problems 2017

Introduction and Guidance

These documents are being provided to you for the purpose of soliciting your personal opinion of the fair market value (FMV) of the oil and gas ownership described in 8 example situations (problems). Page 2 is an answer sheet. It is requested that you clearly post your answers in dollars in the spaces provided. Should you care to supplement any of your responses, the method for doing that is included on the answer sheet. We prefer that you respond to all 8 problems. Problem 4 and Problem 8 may require more of your time than the others. The submission procedure is designed to maintain the confidence of your opinions. The fact that you submitted a response will be recorded.

The following definition of fair market value applies:

Fair Market Value is the price a willing buyer will pay and willing seller will accept for a property, when the property is exposed to the market for a reasonable period of time, and neither party has any compulsion to buy or sell, and both being knowledgeable of the pertinent facts.

Each problem is inclusive of reserve report-like economics included on pages following the problem statement with other exhibits in between. Each problem begins with a problem statement and ends with the associated economic presentations. A few of the problems present alternate economic cases to help you form an opinion but regardless of that, a single monetary response is called for on the answer sheet.

Those preparing the problems were directed to use $60 per barrel for the price of oil, $3 per MCF for the price of gas, and to hold cost parameters constant. Any investments (future capital) were directed to be in 2017 dollars. This direction is for the purpose of consistency between the problems and for uniformity in problem preparation. Please accept those conditions as factual in your assessment of FMV. Assume that the production and cash flow projection result from a well prepared study of all available facts and that all pertinent facts have been disclosed in the problem statement.

The designs of the problems have been prepared by multiple evaluation engineers. The resulting problem statements thus vary in format depending on what the designer of the problem felt you needed to know. Don’t read anything into those variations. Some of the problems include associated production graphs, others do not. One includes a map.

A procedure for providing supplemental responses is provided on the Answer Sheet. The primary purpose for requesting supplemental responses is to provide details as to how the FMV estimate was derived. Problem 7, for instance, has PDP and behind pipe reserves. Providing the contribution to FMV for the PDP and behind pipe portions separately in a supplement is desirable. You might feel that the problem statement is not adequate and you can supplement your response to address that issue. In such a case, please post a value on the answer sheet and include any assumption(s)/qualification(s) you needed to make in the supplemental response.



Answer Sheet

Are you a SPEE member? Yes No (circle one) If the answer is “No”, please submit supplemental evidence with your response supporting your qualification to express the solicited opinions.

If you are supplementing a response, please provide a unique identifying mark(s) (examples drlA1, drl5B, spe8B) in the space following the first question mark of the respective problem number and on the supplemental response page you are including with your return. Do not include supplements to multiple problems on the same page. The answer sheet and supplemental responses may be in the format of your choice. Send electronic responses (email with attachments – Answer Sheet and Supplements) to [email protected]. Alternately, hardcopy mail responses may be sent to:

Jeanne Douglas (SPEE FMV Survey) Moyes & Co 8235 Douglas Avenue #1121 Dallas, TX 75225

Supplemental responses are solicited primarily for the purpose of characterizing the math, method, or logic behind the development of your answer but may also be used for qualifying statements. The answers included on this page need to be a specific US dollar amount as opposed to a range.

All responses will be kept confidential. If you are greatly concerned about the confidentiality process, the snail mail option can be used with the omission of a return address.

You are asked to provide your opinion of the fair market value of the hypothetical property ownership in the spaces provided below. Please keep in mind the global guidelines for submitting those opinions include accepting the production forecasts as being competently prepared. Assume that the projected oil and gas prices are reasonably certain (don’t speculate). To keep the problems simple, no adjustments for future conditions related to costs or prices are included in the example problems. Accept that as the anticipated conditions and post your response following the respective problem numbers below:

1. $_____________________. Are you supplementing your response? __________ (ID Mark?)








mailto:[email protected]

SPEE FMV Problems 2017 Example 1 Page 1 of 2



Problem 1 Statement Working Interest in a Waterflood Unit

The unit was formed many years ago for the purpose of conducting a waterflood which was implemented and is in a moderately late stage of depletion. The property is a non-operated 10 percent working interest ownership with a revenue interest of 8.5 percent. Prices in the forecasts are net of state taxes. The taxes shown in the economics are local taxes based on independent appraisals by a local agency.

Oil production decline curves have been projected well by well and summed as a guide to produce a unit production forecast. Gas production is projected as a constant gas-oil ratio. Gas sales are projected to be 60 percent of gas produced. Water production on a per well basis is relatively constant. The cumulative production shown on the economics represents volumes produced since formation of the unit. At the January 1, 2017 effective date 35 producing wells and 30 injection wells are in operation. A recent program to abandon inactive wells has just been completed. Tertiary projects have been discussed, however, none have been considered to be economically viable.

The before federal income tax (BFIT) economics portions of the forecasts include expenses to the 8/8 working interest owners that have been divided into fixed and variable portions. The fixed portion is a monthly expense of $150,000. The variable portion of $3.44 per barrel of oil is intended to mimic the anticipated future cost decline resulting from both a reduction in well count and including the anticipated reduction in water handling costs. The fixed expenses include the operator’s overhead charge. The economic projection includes an anticipated well abandonment and unit cleanup 8/8 cost of $4,000,000 at the end of the economic life of the unit.





Problem 2 Statement Shallow Salt Dome Leases

The leases are located onshore along the Gulf of Mexico coast. There are 22 wells that are producing at year end 2016 from a shallow sand reservoir with a strong water drive on top of a salt dome. The wells have been recently drilled on an unregulated dense spacing and are all produced with the aid of rod pumps. The property is operated by the 100 percent working interest owner that holds all the leases which have 1/8 royalty burdens. Prices in the forecasts are net of state taxes. The taxes shown in the economics are local taxes based on independent appraisals by local agencies. The effective date of the valuation is January 1, 2017.

Reserves have been estimated both volumetrically and by decline curve using oil cut versus cumulative oil trends and are in reasonable agreement. Some of the wells are relatively new and the trends are not well established but all the wells produce substantial amounts of water. The volumetric calculation was made using a recovery factor of 50 percent as indicated by the application of the API Bulletin D14 (A Statistical Study of Recovery Efficiency) equation indicated to represent the “…most probable Recovery Factor”. The oil production forecast has been guided by a summary of the individual well projections. There is no gas sold. The pumping units have electric motors and the only need for lease use gas is for treating oil in preparation for sales. Produced gas is adequate for lease use fuel needs.

At the current stage of depletion each well is producing with a total liquid rate (oil plus water) in the range of 300 to 500 barrels per day and the average oil cut is on the order of 10 percent. Water disposal represents about 32 percent of the per well operating cost of $9,000 per month but other costs not directly posted as disposal cost are impacted by the need to handle the volumes of water. Records are insufficient to provide an estimate of all the water handling costs. This is the operator’s only oil field operation and except for local taxes (projected as 4 percent of revenue after severance) no distinction is made between lease operation cost and overhead. Each well has its own separation, treating equipment and storage tanks. Salvage value is expected to be greater than the abandonment and cleanup cost but the surplus is not expected to be a material item.

In preparation of the before federal income tax (BFIT) cash flow projections, each well was projected at an average cost per month of $12,000. The well count as a function of time is shown on the production graph and, like the production forecast, is based on the individual well projections. An alternate economic forecast might include a fixed and variable scenario but no such exhibit has been prepared.





Problem 3 Statement Royalty Interest in a Waterflood Unit

This is the same unit as described in Problem 1 except with a 5 percent royalty interest.



Fair Market Value Problems 2017 Problem 4 Statement

Faulted Field Unit Working Interest A new field in South Louisiana that has been producing for a year after being discovered and partially developed with 6 vertical wells. Significant additional drilling potential exists. The operator is in need of a FMV of the unit as of January 1, 2017, as a basis to bring in a 50% partner.

The field has been shot with high quality 3D seismic and the reservoir quality is such that the seismic response provides a direct hydrocarbon indicator (DHI) that fits structure. The anticipated oil-water contact has not been drilled with any of the first 6 wells. The second well in the field was cored and the company completed special core analysis (SCAL) to provide critical information for a reservoir simulation model. The material balance oil in place is between 50 to 55 MMbbl. The reservoir simulation model and history match is complete and the 1P recovery factor is estimated to be 22% and the 2P recovery factor is estimated to be 28.7%. The 2P recovery factor is similar to nearby analogue fields. The lease has a continuous drilling clause and the well spacing is 80 acres. The 3P recovery factor is assumed to be 36%.

There is an adjacent structural closure (Fault Block B) that is fault separated from the discovered field. See the map that follows this problem statement. Fault Block B exhibits similar seismic response and is estimated to contain slightly less than 33.7 MMbbl of P50 OOIP.

The operator owns 100% of the leasehold over the entire area and the NRI is 75%. The map that follows illustrates the operator’s development plan which includes drilling 6 additional wells to fully develop Fault Block A and subsequently testing Fault Block B with a single well followed by 7 development wells if the Fault Block is confirmed to be productive.

A 3rd Party Reserves Report for the field is complete and the pertinent data that went into the analysis is shown below. The summary production forecasts and resulting cash flow projections from the reserve report is included at the end of this problem. All the wells are shown on the one-line cash flow summary. To clarify the ultimate gross oil volumes shown on the economics pages, the following table is offered.

Title of Cash Flow Page (Top Right Corner) Ultimate Oil

Recovery, Mbbl Spreadsheet style formula or comment

FB A Proved Dev Prod 5,570 Round off diff to 5572 FB A Probable Dev Prod {incr} 1,716 14537-7268-5572 FB A Probable Undeveloped 7,252 14520(1) -7268 FB A Possible {incr2} 3,697 18235-14537 FB B Prospective Resource Undeveloped 7,252(2) 9664*75% chance factor

applied to the P50 case

(1) 14520 from following Fault Block A text vs. table value of 14,537 (2) Calculates 7,248 but this is the cash flow indicated ultimate


Field and Reservoir Information Details: • The field consists of two fault blocks. One on production (Fault Block A) and the other

remains undrilled (Fault Block B). • Field is covered with high quality 3D seismic. The pay in the reservoir shows an

amplitude response with an amplitude that fits structure. • Field to be developed as per field rules on 80 acre spacing, there is a continuous drilling

requirement applicable to the 6 wells remaining to be drilled.

Fault Block A • Amplitude turnoff is at 9,575’sub-sea • Well drilled off structure has pressure data in the aquifer. Interpolation of pressures

would place OWC at the amplitude turnoff • The LKO is 8,992’ sub-sea • HKO is 8,526’ sub-sea and is near the crest of the structure • Porosity 28%, Sw 30%, Bo 1.50; OOIP =1,013BO/Ac-ft • Oil Gravity is 40o API, GOR is 975 SCF/BBL and PBP is 3,950 psi • Six wells have been drilled in the field and are all on production. Wells drilled on 80

acre spacing. Area under closure down to LKO is 500 acres • OOIP down to LKO is 25,300 MBO, OOIP to amplitude turnoff is 50,600 Mbbl. • 1P recovery factor 22% • 2P recovery factor 28.7% • Recovery factor uncertainty is related to aquifer support • Total 12 wells in the 1000 acre mapped closure • 6 wells sand thickness ranges from 42 to 60’ with an average of 50’ • Initial reservoir pressure at the top in the highest well was 4,433 psi • Estimated 1P Ultimate recovery is 5,572 Mbbl • Estimated 2P recovery to LKO is 7,268 Mbbl • Estimated 2P recovery in trap is 14,520 Mbbl • The first six wells are flowing 600 BOPD and are expected to stay above line pressure for

between 2-3 years and then go on decline

Fault Block B • Fault Block B is 100 ft downthrown to Fault Block A • Amplitude turnoff is -9,400 sub-sea • The seismic character and amplitude response is very similar in both fault blocks • The chance factor for success of Fault Block B being productive is 75%. (That is the

chance of finding hydrocarbons and if hydrocarbons are found then the P90, P50, P10 is the success distribution of hydrocarbons found)

• Fault Block B is 665 acres in size and has estimated OOIP of 33,670 MO with 2P recovery factor of 28.7%. The un-risked prospective resources are 9,664 Mbbl (7,250 Mbbl adjusted for chance of fault block being productive)

• Will need 8 wells to develop field and hold acreage in Fault Block B


Fault Block A Volumetrics

Units 1P 2P

To LKO 2P

To est. OWC 3P Area Acres 500 500 1,000 1,000 H Ft 50 50 50 50 OOIP Mbbl 25,326 25,326 50,652 50,652 RF % 22% 28.7% 28.7% 36% Ultimate Mbbl 5,572 7,268 14,537 18,235 No Wells # 6 6 12 12 Res/Well Mbbl 929 1,211 1,211 1,520

Fault Block B Volumetrics units P90 P50 P10 Area Acres 320 665 665 H Ft 50 50 50 OOIP Mbbl 16,209 33,673 33,683 RF % 22% 28.7 36% Resources Mbbl 3,566 9,664 12,126 No Wells # 4 8 8 Res/Well Mbbl 891 1,208 1,516

SPEE Problem No 4 NPV Table

Net Present Value as of 1/1/2017, $MM

Line Category** Risk Factor* PV0 PV10 PV15 PV20 1 FB A PDP 100% 153.76 126.07 115.74 107.07 2 FB A Probable Developed 100% 61.78 41.05 34.23 28.92 3 FB A Probable Undeveloped 100% 209.22 127.71 102.29 83.03 4 FB A Possible 100% 134.21 74.15 56.88 44.41 5 FB B Risked Prospective Resource 75% 207.54 117.76 91.09 71.47 6 Total 1P, (1) 153.76 126.07 115.74 107.07 7 Total 2P, (1+2+3) 424.76 294.83 252.26 219.02 8 Total 3P, (1+2+3+4) 558.97 368.98 309.14 263.43 9 Total 1P + Prospective Res, (6+5) 361.30 243.83 206.83 178.54

10 Total 2P + Prospective Res, (7+5) 632.30 412.59 343.35 290.49 11 Total 3P + Prospective Res, (8+5) 766.51 486.74 400.23 334.90 *The risk factors shown in the above table represent the expectation for the existence of recoverable oil in the fault block. They are not intended to represent a reserve certainty measurement.

**Because all the volumes produced from FB A are from a common source of supply, it is difficult to precisely differentiate between developed (producing) and undeveloped categories. For a more precise understanding of the category, see the third column in the table on page 1 and the FB A Volumetrics table above.


23,707.34 0.00

4,381.33 3,286.00 0.00 56,814.19

1,673.37 1,255.02 0.00 19,218.73

7,023.89 5,267.92 0.00 92,435.51

1,170.65 877.99 0.00 15,407.091,170.65 877.99 0.00 15,407.091,170.65 877.99 0.00 15,404.521,170.65 877.99 0.00 15,403.111,170.65 877.99 0.00 15,407.091,170.65 877.99 0.00 15,406.62

3,604.87 2,703.65 0.00 40,283.87

7,023.89 5,267.92 0.00 92,433.09

877.99 658.49 0.00 11,553.39877.99 658.49 0.00 11,555.52877.99 658.49 0.00 11,555.32877.99 658.49 0.00 11,554.97877.99 658.49 0.00 11,553.19877.99 658.49 0.00 11,552.87877.99 658.49 0.00 11,552.33877.99 658.49 0.00 11,555.52

5,062.505,062.505,062.505,062.505,062.50

TRC Eco One Liner 3.rpt 1 of 6

Risked (Applies to Prospective Resources Only)

17,780.51 1,098,534.79 301,185.40 84,187.50

40,500.00

42,187.50

6,750.00

26,154.90 14,273.44FB B Prospective 8 P50 906.54 679.90 40,794.26 1,975.47 26,151.71 14,043.16FB B Prospective 7 P50 906.54 679.90 40,794.26 1,975.47

26,154.03679.90 40,794.26 1,975.47

34,869.68

14,735.02FB BProspective 6 P50 906.54 679.90 40,794.26 1,975.47 26,154.36 14,502.36FB B Prospective 5 P50 906.54

5,062.50

26,151.91 15,202.43FB B Prospective 4 P50 906.54 679.90 40,794.26 1,975.47 26,152.26 14,962.39FB B Prospective 3 P50 906.54 679.90 40,794.26 1,975.47

24,466.33679.90 40,794.26 1,975.475,062.50

14,600.05FB B Prospective 2 P50 906.54 679.90 40,794.26 1,975.47 26,151.71 15,446.37FB B Prospective 1 P50 906.54

74,145.16

Prospective Undeveloped Resources

7,252.31 5,439.23 326,354.05 15,803.75 207,537.21 117,765.22

19,949.85

Possible Undeveloped Reserves

FB A Possible {inc2} 3,697.31 2,772.99 166,379.11 8,110.95 0.00 134,206.18

FB A Prob 6 1,208.72 906.54 54,392.34 2,633.96 6,750.00

34,873.201,208.72 906.54 54,392.34 2,633.96 20,932.87FB A Prob 5 1,208.72 906.54 54,392.34 2,633.96 6,750.00 34,869.21 20,434.84FB A Prob 4 6,750.00

34,869.21 22,476.72FB A Prob 3 1,208.72 906.54 54,392.34 2,633.96 6,750.00 34,871.78 21,435.33FB A Prob 2 1,208.72 906.54 54,392.34 2,633.96 6,750.00

209,222.29 127,706.33

FB A Prob 1 1,208.72 906.54 54,392.34 2,633.96 6,750.00 34,869.21 22,476.72

Probable Undeveloped Reserves

7,252.31 5,439.23 326,354.05 15,803.75

126,067.90

Probable Producing Reserves

FB A Probable Dev Prod{incr} 1,716.28 1,287.21 77,232.38 3,765.07 0.00 61,778.72 41,047.54

766,503.41 486,732.15

1,500.00 153,759.00Proved Producing Reserves

FB A Proved Dev Prod 4,493.67 3,370.25 202,215.20 9,858.00

Grand Total24,411.88 18,308.91 53,341.52

Gas(MMcf)

Oil(Mbbl)

Other (M$)

Ownership Group All Cases

Invest.(M$)

Non-Disc.(M$)

Disc. CF(M$)Risked / UnRisked

Cash FlowGross Reserves Net Reserves Net Revenue Expense

& Tax(M$)

Lease Name Oil(Mbbl)

Gas(MMcf)

Oil(M$)

Gas (M$)

Economic One-Liners4/11/2017 1:42:56 PMProject Name : SPEE FMV Problems 2017 Example 4 As of Date: 1/1/2017

1,076.24 1,049.74

0.00

Est. Cum Oil (Mbbl) : Est. Cum Gas (MMcf) : Est. Cum Water (Mbbl) :

Case : Type : Field :

Operator : Reservoir : Co., State :

API No. :

South LA Onshore LongCo

Jefferson, LA

LEASE CASE Date: 04/11/2017 1:59:42PM Partner : Retrieval Code : Reserve Cat. : Location : Archive Set :

Custom Selection SPEE FMV Problems 2017 Example 4

Discount Rate : 10.00 As of : 01/01/2017

All Cases

Proved Producing

default

ECONOMIC PROJECTION FB A Proved Dev Prod

Misc. Rev. Net

(M$) Year

Oil Gross

(Mbbl)

Gas Gross

(MMcf)

Oil Net

(Mbbl)

Gas Net

(MMcf)

Oil Price

($/bbl)

Gas Price

($/Mcf)

Oil & Gas Rev. Net

(M$)

Taxes Net

(M$)

Costs Net

(M$)

Invest. Net

(M$)

NonDisc. CF Annual

(M$)

Cum Disc. CF

(M$)

2017 1,161.60 1,132.56 60.00 3.00 54,820.11 0.00 5,938.11 6,762.48 0.00 42,119.53 40,142.23 871.20 849.42 2018 1,113.70 1,085.86 60.00 3.00 52,559.76 0.00 5,826.86 6,483.64 0.00 40,249.25 75,087.44 835.28 814.40 2019 811.13 790.85 60.00 3.00 38,280.18 0.00 4,830.64 4,722.15 0.00 28,727.39 97,807.98 608.35 593.14 2020 553.33 539.49 60.00 3.00 26,113.50 0.00 3,981.82 3,221.30 0.00 18,910.38 111,405.43 414.99 404.62 2021 375.38 365.99 60.00 3.00 17,715.37 0.00 3,395.92 2,185.33 0.00 12,134.12 119,338.01 281.53 274.49

2022 255.50 249.11 60.00 3.00 12,057.78 0.00 3,001.22 1,487.42 0.00 7,569.14 123,838.08 191.62 186.83 2023 173.90 169.55 60.00 3.00 8,207.00 0.00 2,732.57 1,012.40 0.00 4,462.04 126,251.22 130.43 127.16 2024 49.15 47.92 60.00 3.00 2,319.49 0.00 946.22 286.13 1,500.00 -412.85 126,067.90 36.86 35.94

Rem. Total 7.4

Ult.

Major Phase : Initial Rate : Abandonment : Initial Decline : Initial Ratio : Abandon Ratio : Abandon Day :

Eco. Indicators

Return on Investment (disc) : Return on Investment (undisc) :

Years to Payout : Internal Rate of Return (%) :

173.251 103.506

0.05 >1000

Working Interest : Revenue Interest : Rev. Date :

Initial 1st Rev. 2nd Rev.

1.00000000 0.75000000

Present Worth Profile (M$) 5.00% : 8.00% :

10.00% :

PW PW PW PW PW

PW 138,518.74 130,760.70 126,067.90

12.00% : 15.00% :

20.00% : 30.00% : 40.00% : 50.00% : 60.00% :

PW PW PW PW

121,713.68 115,745.80

107,076.10 93,382.88 83,106.53 75,139.81 68,796.67

Oil

0.975 0.975

3.873

bbl/month bbl/month

b = 0.00 Mcf/bbl Mcf/bbl

%/year

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4,493.67 4,381.33

5,569.91 5,431.07

60.00 3.00 212,073.19 0.00 30,653.36 26,160.83 1,500.00 153,759.00 0.00

126,067.90

100,960.79 10,313.70

05/13/2024 0.00000000 0.00000000 0.00000000 0.00000000

0.00 3,370.25

0.00 3,286.00

2 of 6 TRC Standard Eco.rpt

0.00 0.00 0.00




API No. :


Jefferson, LA

INCREMENTAL CASE Date: 04/11/2017 1:59:42PM Partner : Retrieval Code : Reserve Cat. : Location : Archive Set :



All Cases

Probable Producing

default

ECONOMIC PROJECTION FB A Probable Dev Prod{incr}

Misc. Rev. Net

(M$) Year

Oil Gross

(Mbbl)

Gas Gross

(MMcf)

Oil Net

(Mbbl)

Gas Net

(MMcf)

Oil Price

($/bbl)

Gas Price

($/Mcf)

Oil & Gas Rev. Net

(M$)

Taxes Net

(M$)

Costs Net

(M$)

Invest. Net

(M$)

NonDisc. CF Annual

(M$)

Cum Disc. CF

(M$)

2017 8.43 8.22 60.00 3.00 397.70 0.00 16.13 49.06 0.00 332.51 302.08 6.32 6.16 2018 57.70 56.26 60.00 3.00 2,723.03 0.00 189.97 335.91 0.00 2,197.15 2,171.14 43.27 42.19 2019 329.31 321.07 60.00 3.00 15,541.16 0.00 1,084.24 1,917.12 0.00 12,539.80 11,990.19 246.98 240.80 2020 398.23 388.28 60.00 3.00 18,794.09 0.00 1,311.18 2,318.39 0.00 15,164.52 22,888.16 298.67 291.21 2021 277.79 270.85 60.00 3.00 13,110.17 0.00 914.64 1,617.24 0.00 10,578.29 29,798.68 208.35 203.14

2022 194.33 189.47 60.00 3.00 9,171.03 0.00 639.82 1,131.32 0.00 7,399.89 34,193.67 145.75 142.10 2023 135.88 132.48 60.00 3.00 6,412.77 0.00 447.39 791.06 0.00 5,174.32 36,987.64 101.91 99.36 2024 164.67 160.56 60.00 3.00 7,771.54 0.00 1,917.79 958.68 -1,500.00 6,395.07 40,110.70 123.50 120.42 2025 146.77 143.10 60.00 3.00 6,926.70 0.00 2,643.25 854.46 0.00 3,429.00 41,643.50 110.08 107.33 2026 3.16 3.08 60.00 3.00 149.25 0.00 62.67 18.41 1,500.00 -1,431.83 41,047.54 2.37 2.31

Rem. Total 9.0

Ult.


Eco. Indicators



65.522 0.000

0.54 >1000



1.00000000 0.75000000


10.00% :

PW PW PW PW PW

PW 49,940.07 44,314.43 41,047.54

12.00% : 15.00% :

20.00% : 30.00% : 40.00% : 50.00% : 60.00% :

PW PW PW PW

38,110.17 34,234.00

28,919.97 21,324.61 16,299.83 12,824.43 10,331.17

Oil

0.975 0.975

2.663

bbl/month bbl/month


%/year

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1,716.28 1,673.37

1,716.28 1,673.37

60.00 3.00 80,997.46 0.00 9,227.08 9,991.65 0.00 61,778.72 0.00

41,047.54

101,638.88 10,000.00

01/09/2026 0.00000000 0.00000000 0.00000000 0.00000000

0.00 1,287.21

0.00 1,255.02


0.00 0.00 0.00


Date : 04/11/2017 1:59:42PM Partner :



All Cases ECONOMIC SUMMARY PROJECTION

Probable Undeveloped Reserves

Misc. Rev. Net

(M$) Year

Oil Gross

(Mbbl)

Gas Gross

(MMcf)

Oil Net

(Mbbl)

Gas Net

(MMcf)

Oil Price

($/bbl)

Gas Price

($/Mcf)

Oil & Gas Rev. Net

(M$)

Taxes Net

(M$)

Costs Net

(M$)

Invest. Net

(M$)

NonDisc. CF Annual

(M$)

Cum Disc. CF

(M$)

2017 96.32 93.88 60.00 3.00 4,545.43 0.00 497.11 560.72 13,000.00 -9,512.39 -9,066.17 72.24 70.41 2018 665.41 648.02 60.00 3.00 31,401.45 0.00 3,450.63 3,873.66 26,000.00 -1,922.85 -10,959.83 499.06 486.02 2019 1,125.13 1,094.34 60.00 3.00 53,092.94 0.00 5,863.68 6,549.62 0.00 40,679.64 21,114.37 843.84 820.75 2020 1,108.08 1,075.54 60.00 3.00 52,283.62 0.00 5,806.91 6,449.95 0.00 40,026.77 49,802.83 831.06 806.66 2021 1,081.41 1,047.54 60.00 3.00 51,020.44 0.00 5,718.49 6,294.28 0.00 39,007.67 75,221.61 811.06 785.65

2022 960.17 928.41 60.00 3.00 45,296.47 0.00 5,319.03 5,588.25 0.00 34,389.20 95,623.62 720.13 696.31 2023 712.06 687.45 60.00 3.00 33,589.52 0.00 4,502.42 4,144.04 0.00 24,943.07 109,094.98 534.05 515.59 2024 499.70 481.87 60.00 3.00 23,570.76 0.00 3,803.67 2,908.04 0.00 16,859.06 117,373.05 374.78 361.41 2025 348.74 336.03 60.00 3.00 16,449.34 0.00 3,307.03 2,029.45 0.00 11,112.86 122,334.02 261.55 252.02 2026 244.18 235.14 60.00 3.00 11,517.05 0.00 2,963.07 1,420.94 0.00 7,133.04 125,229.85 183.13 176.36

2027 170.97 164.57 60.00 3.00 8,063.76 0.00 2,722.27 994.89 0.00 4,346.60 126,834.94 128.22 123.43 2028 119.98 115.46 60.00 3.00 5,658.81 0.00 2,554.57 698.17 0.00 2,406.06 127,643.54 89.98 86.60 2029 82.91 79.77 60.00 3.00 3,910.45 0.00 2,401.70 482.46 0.00 1,026.29 127,958.02 62.18 59.83 2030 35.23 33.89 60.00 3.00 1,661.42 0.00 1,232.85 204.98 0.00 223.59 128,020.84 26.42 25.42 2031 2.04 1.97 60.00 3.00 96.34 0.00 80.77 11.89 0.00 3.69 128,021.81 1.53 1.47

Rem. Total 14.2

Ult. Eco. Indicators



4.629 6.166

2.32 147.99


10.00% :

PW PW PW PW PW

PW 161,966.33 140,157.83 127,706.33

12.00% : 15.00% :

20.00% : 30.00% : 40.00% : 50.00% : 60.00% :

PW PW PW PW

116,653.37 102,287.21

83,030.81 56,509.15 39,735.48 28,581.39 20,860.38

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1,500.00 -1,500.00 7,252.31 7,023.89

7,252.31 7,023.89

60.00 3.00 342,157.80 0.00 50,224.19 42,211.33 40,500.00 209,222.29 -315.48

127,706.33 0.00

5,439.23 0.00

5,267.92


0.00 0.00 0.00




API No. :


Jefferson, LA

INCREMENTAL CASE Date: 04/11/2017 1:59:42PM Partner : Retrieval Code : Reserve Cat. : Location : Archive Set :



All Cases

Possible Undeveloped

default

ECONOMIC PROJECTION FB A Possible {inc2}

Misc. Rev. Net

(M$) Year

Oil Gross

(Mbbl)

Gas Gross

(MMcf)

Oil Net

(Mbbl)

Gas Net

(MMcf)

Oil Price

($/bbl)

Gas Price

($/Mcf)

Oil & Gas Rev. Net

(M$)

Taxes Net

(M$)

Costs Net

(M$)

Invest. Net

(M$)

NonDisc. CF Annual

(M$)

Cum Disc. CF

(M$)

2017 -33.68 -32.84 0.00 0.00 -1,589.47 0.00 -203.79 -196.07 0.00 -1,189.61 -1,224.99 -25.26 -24.63 2018 52.80 51.48 60.00 3.00 2,491.67 0.00 173.83 307.37 0.00 2,010.47 509.93 39.60 38.61 2019 84.49 82.38 60.00 3.00 3,987.39 0.00 278.18 491.88 0.00 3,217.33 3,039.13 63.37 61.78 2020 277.45 270.51 60.00 3.00 13,093.96 0.00 913.51 1,615.24 0.00 10,565.21 10,533.73 208.09 202.89 2021 573.21 558.88 60.00 3.00 27,051.89 0.00 1,887.29 3,337.06 0.00 21,827.54 24,705.44 429.91 419.16

2022 748.04 729.34 60.00 3.00 35,303.01 0.00 2,462.94 4,354.89 0.00 28,485.18 41,570.68 561.03 547.01 2023 587.80 573.10 60.00 3.00 27,740.57 0.00 1,935.34 3,422.01 0.00 22,383.22 53,655.54 440.85 429.83 2024 417.96 407.51 60.00 3.00 19,725.29 0.00 1,376.15 2,433.26 0.00 15,915.88 61,466.99 313.47 305.63 2025 295.47 288.09 60.00 3.00 13,944.51 0.00 972.85 1,720.16 0.00 11,251.50 66,486.83 221.61 216.06 2026 307.41 299.73 60.00 3.00 14,507.98 0.00 3,119.90 1,789.67 -1,500.00 11,098.41 71,006.25 230.56 224.79

2027 218.11 212.65 60.00 3.00 10,293.34 0.00 2,878.12 1,269.76 0.00 6,145.46 73,274.69 163.58 159.49 2028 153.52 149.68 60.00 3.00 7,245.21 0.00 2,665.47 893.75 0.00 3,685.99 74,512.35 115.14 112.26 2029 14.72 14.35 60.00 3.00 694.70 0.00 299.43 85.70 1,500.00 -1,190.42 74,145.16 11.04 10.76

Rem. Total 12.1

Ult.


Eco. Indicators



159.016 0.000

1.66 170.84



1.00000000 0.75000000


10.00% :

PW PW PW PW PW

PW 98,612.11 82,891.26 74,145.16

12.00% : 15.00% :

20.00% : 30.00% : 40.00% : 50.00% : 60.00% :

PW PW PW PW

66,534.87 56,878.79

44,405.16 28,286.69 18,894.84 13,090.44

9,324.39

Oil

0.975 0.975

-0.059

bbl/month bbl/month


%/year

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3,697.31 3,604.87

3,697.31 3,604.87

60.00 3.00 174,490.06 0.00 18,759.20 21,524.67 0.00 134,206.18 0.00

74,145.16

101,999.85 10,204.29

02/12/2029 0.00000000 0.00000000 0.00000000 0.00000000

0.00 2,772.99

0.00 2,703.65


0.00 0.00 0.00


Date : 04/11/2017 1:59:42PM Partner :



All Cases ECONOMIC SUMMARY PROJECTION

Risked @ 75%

FB B Prospective Resource Undeveloped

Misc. Rev. Net

(M$) Year

Oil Gross

(Mbbl)

Gas Gross

(MMcf)

Oil Net

(Mbbl)

Gas Net

(MMcf)

Oil Price

($/bbl)

Gas Price

($/Mcf)

Oil & Gas Rev. Net

(M$)

Taxes Net

(M$)

Costs Net

(M$)

Invest. Net

(M$)

NonDisc. CF Annual

(M$)

Cum Disc. CF

(M$)

2017 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2018 179.30 174.72 60.00 3.00 8,461.82 0.00 927.83 1,043.84 24,875.00 -18,384.84 -15,896.65 134.48 131.04 2019 901.41 877.72 60.00 3.00 42,538.49 0.00 4,677.56 5,247.53 15,750.00 16,863.40 -2,958.69 676.06 658.29 2020 1,122.48 1,091.13 60.00 3.00 52,966.74 0.00 5,854.78 6,534.10 0.00 40,577.86 26,124.75 841.86 818.34 2021 1,099.44 1,066.54 60.00 3.00 51,874.72 0.00 5,778.30 6,399.55 0.00 39,696.88 51,988.59 824.58 799.91

2022 1,064.57 1,030.67 60.00 3.00 50,224.69 0.00 5,662.91 6,196.15 0.00 38,365.63 74,723.19 798.43 773.00 2023 900.90 870.68 60.00 3.00 42,499.32 0.00 5,123.89 5,243.20 0.00 32,132.23 92,066.36 675.67 653.01 2024 644.09 621.58 60.00 3.00 30,382.39 0.00 4,278.73 3,748.38 0.00 22,355.28 103,042.23 483.06 466.19 2025 449.50 433.35 60.00 3.00 21,202.76 0.00 3,638.52 2,615.89 0.00 14,948.35 109,714.56 337.13 325.01 2026 314.73 303.20 60.00 3.00 14,845.06 0.00 3,195.15 1,831.53 0.00 9,818.38 113,699.71 236.05 227.40

2027 220.37 212.18 60.00 3.00 10,393.84 0.00 2,884.75 1,282.36 0.00 6,226.72 115,998.20 165.27 159.14 2028 154.64 148.85 60.00 3.00 7,293.93 0.00 2,668.59 899.91 0.00 3,725.43 117,249.13 115.98 111.64 2029 107.93 103.86 60.00 3.00 5,090.35 0.00 2,514.94 628.04 0.00 1,947.38 117,844.31 80.94 77.89 2030 71.18 68.48 60.00 3.00 3,357.24 0.00 2,211.64 414.21 0.00 731.39 118,048.40 53.39 51.36 2031 21.76 20.94 60.00 3.00 1,026.46 0.00 804.18 126.64 0.00 95.63 118,073.02 16.32 15.70

Rem. Total 14.9

Ult. Eco. Indicators



4.430 5.919

3.07 133.46


10.00% :

PW PW PW PW PW

PW 154,817.06 131,099.56 117,765.22

12.00% : 15.00% :

20.00% : 30.00% : 40.00% : 50.00% : 60.00% :

PW PW PW PW

106,070.19 91,091.61

71,470.81 45,537.44 30,030.85 20,269.78 13,868.92

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1,562.50 -1,562.50 7,252.31 7,023.89

7,252.31 7,023.89

60.00 3.00 342,157.80 0.00 50,221.77 42,211.33 42,187.50 207,537.21 -307.80

117,765.22 0.00

5,439.23 0.00

5,267.92




Fair Market Value Example Problems 2017 Problem 5 Statement

Midcontinent Oil Shale Lease – Unconventional Reservoir

This example problem is not an actual case. It is designed to be fairly realistic and illustrate certain points. Simplifying assumptions were used in the interest of time and clarity.

This is a midcontinent property which includes 25 contiguous square mile sections (i.e., 16,000 acres). Interests owned are consistent for all 25 sections. The interests only include the subject oil shale formation and exclude other formations. The formation depth is approximately 5,000 feet and fairly consistent across the property. The formation thickness is also relatively consistent at 100 feet. There are no water aquifers near the target formation that could cause problems. The formation is relatively un‐faulted and therefore didn’t interfere with a straightforward drilling program. This lease position was put together during 2011.

The operator drilled and completed four wells per section, a total of 100 wells, during 2012 and 2013. This represents a drainage area of 160 acres per well and lateral spacing of 1,320 feet (5,280 feet per 4 wells). All wells were drilled horizontally with nominal lateral lengths of slightly less than one mile (the length of the sections). All wells were multistage fracture stimulated with a fracture technique known to be successful in this oil shale play.

All necessary facilities (flowlines, pipelines, etc.) were installed during the 2012 and 2013 drilling timeframe. All the wells were brought online 1/1/2014 and have now been producing for three years. Appropriately sized pumps have already been installed on all of the wells.

All‐inclusive operating costs for the last two years have been consistent at $8,000 per well per month. Estimated abandonment costs net of salvage of $10,000 per well are included in the forecasts. Both oil and gas meet pipeline specifications. The gas is not processed prior to sale — therefore no plant product sales. There are no transportation charges for either product.

The wells’ production histories have hyperbolic decline trends. They have an average hyperbolic exponent of 1.45 as seen on many of the wells in this play. Although the wells are behaving as expected, the terminal exponential decline is not yet well understood in this play. The current (1/1/2017) average instantaneous decline for the wells is 20%. Two forecast cases have been run for consideration. Case A uses a 15% terminal decline (sometimes labeled Dmin). Case B uses a 6% terminal decline.

Key Parameters (Consider these to be factual information)

1. The effective date of purchase and sale is January 1, 2017. 2. Although this is a solution gas drive reservoir and the GOR will normally be expected to

increase over time, the simplifying assumption that it will be constant has been made. 3. Pumps have already been installed on all of the wells. 4. All gas compressors needed are already installed. 5. Gas fuel and shrinkage to run the compressors is 10%. 6. Oil and gas prices are $60 per barrel and $3.00 per MCF. 7. There is a good market for both the oil and gas.


8. There is no price escalation in the projections. 9. There is no cost escalation in the projections. 10. Production/severance tax is projected as 4.6% on oil and 7.5% on gas. 11. Ad valorem tax is projected as 2.5% based on historical rates. 12. Working interest is 100%. Net revenue interest is 75%. There are no interest reversions. 13. The cash flow projections represent a before federal income tax analysis (BFIT).

Case A – You are reasonably certain that the average minimum (terminal) exponential decline will be 15%. This is intended to be treated as the proved case. Case B – You believe the average minimum (terminal) exponential decline will probably be 6% based on your experience with other shale plays and tight formations. This is intended to be treated as your 2P case.






Problem 6 Statement Large Abandonment Costs

These offshore fields and platforms are in US Federal waters in the Gulf of Mexico and are being offered for sale by their operator who owns an 85 percent working interest. The wells are in their latter stages of depletion. All wells and facilities are mechanically sound. There are no environmental concerns. There are 3 platforms (B, C, and D) with one remaining producing well on each. There are a few shut-in wells. The investments shown in the economics are all for plugging and abandonment costs – wells, platforms and facilities. The operator has had considerable experience in offshore operations inclusive of abandonment operations and has provided the cost estimates. Those estimates have been closely reviewed and are believed to be accurate estimates subsequence to a few adjustments made during the review process. Production from platforms B, C and D are expected to be suspended at mid-year 2019, 2022 and 2024 respectively with each platform being abandoned thereafter. The first following petroleum economics projection presents the expected case for the combination of all three platforms.

The second following petroleum economics projection is a copy of the first projection except the plugging and abandonment investments have been removed. That extra “No Abandonment Cost” projection is provided to give the valuator the opportunity, using a bit of math, to calculate the discounted value of the abandonment costs at multiple discount rates should the valuator wish to know that.





Problem 7 Statement Old Field with Behind Pipe Zones

FIELD HISTORICAL

A major oil company identified the "Pepper" salt dome circa 1910, with the first commercial well completed some ten years later with production at about 5,000 feet. Within the next three years, production jumped to eight million barrels of oil a year. It tapered off thereafter, although another major field in the area was discovered in 1935. In mid-1980's, although the boom days had long since ended, the Pepper Field continued to yield more than 630,000 barrels of oil a year and sizable quantities of casinghead gas. Much of the increase in production during these years was due to the extensive engineering work carried out in the area. Cumulative production as of year-end 2016 had exceeded some 200 million barrels of oil.

THE DELONG LEASE

The "Delong" lease in the Pepper Field has been producing since at least the mid-1930's with Texas Railroad Commission (TRC) records available since 1941 (see the historical production graph, Attachment 1). Through 2014, due to steady drilling and re-completion operations, production has been relatively flat since the mid-1980's. However, due to the drop in oil prices there was no new drilling on the lease in 2016 and thus far none planned for 2017. For TRC reporting purposes all zones under the Delong lease are commingled. Currently production emanates primarily from Frio, Yegua and Miocene zones above 4,500 feet.

At year-end 2016 there were 41 active oil producers on the Delong lease. Based on individual well projections, a composite PDP projection was developed (see the graph of Attachment 1). Oil, water and gas volumes were projected by individual well. As the production emanates from various zones that are under both depletion and active waterdrive, the individual well production profiles can vary considerably (see the example wells Attachment 2-A and 2-B). These individual well plots include all the historical zones that at various times have been produced by the wells (i.e., there have been multiple recompletions in the two wells that are all lumped together during the presented production histories).

The economic projections for the Delong lease include a multiple well PDP production forecast and 21 forecasts in the 11 economic cases for identified behind pipe zones. The PDP forecast represents a summary of the projection of 41 wells using decline curves. Oil volumes for Proved Behind Pipe zones were individually forecasted based on volumetric calculations and reservoir analogs. Based on the 10 percent discounted present worth of the cash flow projections the behind pipe value is about 56 percent of the total value (the PDP plus behind pipe value).

With respect to potential drainage from the behind pipe zones, the reservoir engineer consultant and the operator's in-house geologist meet once or twice a year (even if there was no drilling program the previous year) to review individual well and reservoir performance and any changes in reservoir geological interpretations that might impact the behind pipe reserves.


OPERATING COSTS AND INVESTMENTS (CAPITAL COSTS)

The recompletion costs required to produce the behind pipe zones are estimated at $50,000 each based on the average recompletion cost during the last two years. For PDP wells with behind pipe recompletion, a minimum lag time of 90 days is scheduled before the next zone is placed on production. Recompletion costs are assumed to be concurrent with the first production date of each zone. Estimated abandonment costs are $20,000 per well based on recent AFE estimates and abandonment costs were assumed to be incurred one year after the date of last production.

Operating costs were based on the following: • For the PDP wells a fixed monthly well cost of $1,850 and lifting cost of $0.75 per barrel

of oil and water produced. • The operating costs for the behind pipe recompletions are based on an estimated fixed

monthly cost of $2,400 per well. Water was not forecast for recompletions but the higher fixed monthly cost was adjusted upward to account for the lack of the lifting cost component.

No casinghead gas sales were projected for the behind pipe recompletions (gas revenue for the PDP projections is less than 1 percent of the total revenue). No escalation for investments or operating costs were applied (consistent with problem construction guidance).

PRICE DECK AND ESCALATION

The assumed effective date of the report is January 1, 2017. The price deck used for the evaluation is $60 per barrel of oil and $3.00 per Mcf of gas. The FMV opinion is to be based on these prices to eliminate variability of FMV due to price assumptions.







Problem 8 Statement An International Production Sharing Agreement

Scenario Orsova Energy, the license operator, is offering for sale a 50% interest in the EPL064 license in Menovia containing the Solaris oil field development at the end of 2016, with an effective date for the transaction of 1st January 2017. Production profile and cost cases at the P90, P50 and P10 levels of confidence have been commissioned from an independent Expert. The Expert was instructed that the oil price to be used is $60 per barrel and that no cost or price escalation and no inflation is to be included in the development of the cash flow projections. The parties agree that the only asset of value on the EPL064 license is the Solaris field development. Field Description Solaris is an onshore oil field development, discovered in 2012 in the Mazrek basin in Menovia. Three further exploration wells have confirmed the existence of an anticlinal trap with fair reservoir properties (average porosity 18.5% and average permeability 36.4 mD) and good quality 42 degree API oil with a very low gas/oil ratio. There is additionally a small gas cap. The field will have two further appraisal delineation wells before the development plan is to be implemented, one to confirm the oil-water contact due to the long transition zone seen in wells to date and the second to delineate the western extent of the field. There is however sufficient confidence to proceed with the development plan which has obtained both Government and Orsova Board approval. The field is estimated to have oil reserves of 543.5 MMbbl at the P50 reserve level. After the two appraisal delineation wells in 2017 and 2018, development will commence from 2019, with first oil planned for 2022. All produced gas will be re-injected. A dedicated plant for processing and fluids treatment will be constructed, after which the oil will be exported via a pipeline tie-in to the Menovian export network to a coastal port for shipping. Oil production during a peak year is forecast at 192 Mbbl/d. All costs are in 2017 US dollar monetary terms. Past exploratory costs of $US 187.6 million have been agreed by the Government as recoverable under the terms of the license agreement and as a corporate income tax allowance. The purchaser of the offered position will have no income tax liability as the National Oil Company will pay those taxes on behalf of the purchaser. Production Sharing Contract: EPSA The EPL064 license is governed by an Exploration and Production Sharing Agreement (“EPSA”) which has been signed between the National Oil Corporation (“NOC”), “The


First Party” and the Contractor, “The Second Party” (the position from which the 50% interest is carved), for the exploration and development activities in Block Z1, which contains the Solaris field. The effective date of the EPSA is 1st January 2010. The key elements for economic modelling are as follows:

1. Allocation of Petroleum

The EPSA allocates 72% of petroleum production (crude oil, liquid hydrocarbon by-products and natural gas) to the First Party (First Party Petroleum Production Allocation). The Second Party receives up to the remaining 28% of petroleum production according to the cost recovery and profit share mechanisms described below. The allocation is on a calendar year basis.

2. Cost Recovery Exploration, development, production and other costs incurred by the Second Party can be recovered from 28% of petroleum production. Any costs not recovered in the accounting period (calendar year) are carried forward for recovery in subsequent year(s). Any production remaining from the Second Party allocation after the cost recovery described above is called “Excess Petroleum” and is effectively placed in a profit pool to be shared by the First and Second Party as described below. Costs incurred by the Second Party that are recoverable are as follows: a) Exploration & Appraisal costs (including decommissioning) – 100% as incurred; b) Development costs – 100% as incurred; c) Operating costs – 100% as incurred; d) Decommissioning costs - unit of production basis; e) Training fees – 100% as incurred, as part of Operating costs. It should be noted that the signature and production bonuses within the EPSA are not cost-recoverable. Other than the abandonment costs, all other costs in a single field analysis are recovered at the later of first production and when they are incurred subject to the limitations of the cost recovery limit (i.e. the Second Party allocation). 3. Profit Share

Once the cost recovery process has been completed in each Calendar Year, the remaining petroleum production from the Second Party allocation (effectively the profit pool) is allocated between the First Party and the Second Party under a sliding scale of percentage share versus petroleum production level (the “Production Tranche” method) and the ratio of cumulative petroleum production revenue to cumulative Petroleum Operations expenditure (the “R-Factor” method).

3.1 Second Party Profit Sharing

The Second Party (SP) allocation of Excess Petroleum is defined as:

SP Excess Petroleum = “Base Factor” * “A-Factor” * Excess Petroleum


3.1.1 The Base Factor

The Base Factor for petroleum liquids is determined on a sliding scale incremental basis against average daily production levels of crude oil and liquid hydrocarbon by-products over the calendar year.

Increments of Average Daily Total Petroleum Liquids Production from all Fields in EPSA

Base Factor

From (bbl/d) To (bbl/d)

1 20,000 1.00

20,001 40,000 0.90

40,001 50,000 0.70

50,001 70,000 0.45

70,000 + 0.20

3.1.2 The A Factor

The A Factor is dependent on a Ratio (R-Factor) as follows, determined from the Second Party (SP) Production Revenue and Petroleum Operations Expenditures respectively:

Ratio = SP Cumulative Value of Production / SP Cumulative Expenditures

The R-Factor Ratio applied to each calendar year shall be the Ratio calculated at 31st December of the previous calendar year.

The A Factor is determined on a step basis from the following sliding scale:

Ratio (R-Factor) A Factor

R > R < or =

1.5 0.95

1.5 2.0 0.75

2.0 3.0 0.50

3.0 + 0.25


4. Costs and Expenses

All costs, expenses and liabilities incurred for Exploration and Appraisal activities (including the abandonment thereof) are borne by the Second Party. Capital expenditures are shared by the First Party (20%) and the Second Party (80%). The Second Party share of operating costs is equal to its production allocation percentage for cost recovery, i.e. 28%. 5. Signature and Production Bonuses

A Signature Bonus of $10 million was payable by the Second Party to the First Party within thirty days of the Effective Date of the EPSA in 2010. The Signature Bonus is not cost recoverable. Production Bonuses are payable by the Second Party to the First Party against defined cumulative production thresholds (in oil equivalence barrels) of each commercial discovery within thirty days of achieving the threshold. The Production Bonuses are not cost recoverable.

Cumulative Production (MMboe) EPSA Production Bonuses ($US)

0.1 10,000,000

100 15,000,000

Every additional 30 above 100 5,000,000

6. Abandonment Costs

All abandonment costs, expenses and liabilities incurred on Exploration and Appraisal operations are treated as Exploration and Appraisal Expenditures within the EPSA and are borne by the Second Party. All abandonment costs, expenses and liabilities incurred on development and exploitation operations are shared by the First Party (20%) and the Second Party (80%). Annual Abandonment Provisions are determined on the unit of production method.

7. Training Fees

The Operator is obligated to submit to the Management Committee an annual training programme to train Menovian Nationals. The EPSA requires that the Second Party pays 50% of the budget, namely $250,000 per year for its training programme from the effective date of the contract to the end of the project. 8. Government Royalty Within the terms of the EPSA and Petroleum Law the Second Party is liable to a Royalty on production, however the First Party pays this to the Government from their share of production.


The Royalty is paid on a financial year annual basis and is 16.67% of the value of petroleum won and saved from the Concession Area.

9. Menovia Corporate Income Tax

Within the terms of the EPSA and Petroleum Law the Second Party is liable to a Corporate Income Tax on production, however the First Party pays this to the Government from their share of production. The Corporate Income Tax Rate is 65% but there is no direct relevance of that to the ownership position being offered. The Second Party’s taxable profits are calculated as income under the EPSA less exploration costs less operating costs less depreciation of all physical assets at 10% per year. Operating costs will include the abandonment provisions, training fees and the bonuses. The field should be treated on a standalone basis for Corporate Income Tax purposes: losses incurred prior to production are to be rolled forward until there is sufficient income to offset the losses.

10. Net Cash Flow Calculation

Estimates of the future nominal net cash flow of the oil or gas field for the First Party, Second Party and the Government are determined by calculation of the future revenues and deducting the future costs and taxes. The net cash flows are defined by the following formulae.

10.1 First Party (FP) Net Cash Flow

Net Cash Flow = FP Petroleum Production Allocation + FP Share of Excess Petroleum (Profit Share) + Signature Bonus + Production Bonuses – Development Capital Costs – Operating Costs - Abandonment Costs – SP Royalty – SP Corporate Income Tax

10.2 Second Party Net Cash Flow (50% of this position is being offered for sale)

Net Cash Flow = SP Petroleum Production Allocation (Cost Recovery) + SP Share of Excess Petroleum (Profit Share) - Signature Bonus - Exploration & Appraisal Costs - Capital Costs - Operating Costs - Production Bonuses – Training Fees - Annual Abandonment Provisions

10.3 Government Net Cash Flow

Net Cash Flow = SP Royalty + SP Corporate Income Tax

11. Valuation The valuation is to be at 1st January 2017. For discounting purposes, annual discount factors calculated at mid-year are to be applied to the cash flow forecasts.


Data Source Disclaimer The Menovia EPSA information is based upon a real world EPSA and has been sourced fully from public domain data and general industry knowledge. The Solaris field data is generated by a consultancy as a generic field case to model the Menovia EPSA terms and does not represent any specific field. This example has been constructed without breach of any confidentiality undertakings.


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