Attached files

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EX-32.2 - EX-32.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex322_7.htm
EX-32.1 - EX-32.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex321_13.htm
EX-31.2 - EX-31.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex312_14.htm
EX-31.1 - EX-31.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex311_8.htm
EX-23.2 - EX-23.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex232_10.htm
EX-23.1 - EX-23.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex231_11.htm
EX-21.1 - EX-21.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex211_339.htm
EX-10.27 - EX-10.27 - TRANSATLANTIC PETROLEUM LTD.tat-ex1027_241.htm
EX-10.26 - EX-10.26 - TRANSATLANTIC PETROLEUM LTD.tat-ex1026_242.htm
EX-10.25 - EX-10.25 - TRANSATLANTIC PETROLEUM LTD.tat-ex1025_92.htm
EX-4.3 - EX-4.3 - TRANSATLANTIC PETROLEUM LTD.tat-ex43_340.htm
10-K - 10-K - TRANSATLANTIC PETROLEUM LTD.tat-10k_20191231.htm

Exhibit 99.1

 

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244

 

March 3, 2020

TransAtlantic Petroleum Ltd.

16803 Dallas Parkway, Suite 200

Addison, Texas 75001

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2019, of the extent and value of the estimated proved, probable, and possible oil, condensate, and sales gas reserves of certain properties in Turkey and Bulgaria in which TransAtlantic Petroleum Ltd. (TransAtlantic) has represented it holds an interest. This evaluation was completed on March 3, 2020. TransAtlantic has represented that these properties account for 100 percent on a net equivalent barrel basis of TransAtlantic’s net proved, probable, and possible reserves as of December 31, 2019. The net proved, probable, and possible reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by TransAtlantic.

 

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests held by TransAtlantic after deducting all interests held by others.

 

Values for proved, probable, and possible reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves before reduction

 


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for net profits (where applicable). Future net revenue is calculated by deducting operating expenses, capital costs, abandonment costs, and net profits, where

 


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applicable, from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and the capitalized portion of field maintenance costs. Abandonment costs are represented by TransAtlantic to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of TransAtlantic, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a nominal discount rate of 10 percent compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

 

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

 

Information used in the preparation of this report was obtained from TransAtlantic. In the preparation of this report we have relied, without independent verification, upon information furnished by TransAtlantic with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, estimation of taxes, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating

 


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conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

 

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

 


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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the

 


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proved area if these areas are in communication with the proved reservoir.

 

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

 

Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the

 


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reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

(vi) Pursuant to paragraph (iii) of the proved oil and gas reserves definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

 


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Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

 

Based on the current stage of field development, production performance, the development plans provided by TransAtlantic, and analyses of areas offsetting

 


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existing wells with test or production data, reserves were classified as proved, probable, or possible. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by TransAtlantic.

 

TransAtlantic has represented that its senior management is committed to the development plan provided by TransAtlantic and that TransAtlantic has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

 

When applicable, the volumetric method was used to estimate the original gas in place (OGIP) and the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

 

When appropriate, estimates of ultimate recovery were obtained after applying recovery factors to OGIP or OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the fluids and rock properties, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves and reserves forecasts, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report or to a license limit, including extensions if applicable, whichever comes first.

 

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

 

Data provided by TransAtlantic from wells drilled through December 31, 2019, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October 31, 2019. Estimated

 


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cumulative production, as of December 31, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

 

Oil and condensate reserves estimated herein are to be recovered by normal field separation and are expressed in barrels (bbl). In these estimates, 1 barrel equals 42 United States gallons. For the fields evaluated herein, condensate reserves were estimated to be zero.

 

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities estimated herein are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in thousands of cubic feet (103ft3).

 

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

 

Proved developed producing reserves were estimated based on performance trends. Proved undeveloped reserves were estimated for drilling and sidetracks based on statistical analysis of the performance of existing wells and recent drilling results, as well as volumetric analysis where sufficient data were available. Probable and possible reserves were based on better well performance than projected for the proved reserves plus incremental volumetric recovery relating to the drilling and recompletion estimates.

 

The fields evaluated herein are subject to a royalty of 12.5 percent. Certain wells are also subject to a net profits interest burden of 5 percent.

 

The net reserves quantities reported herein reflect the appropriate quantity reductions for royalty interests and overriding royalty interests, as well as the quantity reduction yielded from the estimated revenue associated with the net profits payable, where applicable.

 


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Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by TransAtlantic in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil, Condensate, and Gas Prices

TransAtlantic has represented that the oil, condensate, and gas prices used in this evaluation were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The average Brent Oil price during this period was U.S.$62.74 per barrel. The oil, condensate, and gas prices used to estimate reserves herein are presented in the following table, expressed in United States dollars per barrel (U.S.$/bbl) and United States dollars per thousand cubic feet (U.S.$/103ft3):

 

Country

Field

 

Oil and

Condensate

Price

(U.S.$/bbl)

 

Gas Price

(U.S.$/103ft3)

 

 

 

 

 

Turkey

 

 

 

 

AG

 

NA

 

6.09

Arpatepe

 

58.07

 

NA

Bahar

 

58.86

 

NA

Bakuk

 

NA

 

3.18

Edirne

 

NA

 

6.09

Goksu

 

55.06

 

NA

Molla

 

58.86

 

NA

Selmo

 

58.65

 

NA

Yeniev

 

58.86

 

NA

Other TAT fields

 

NA

 

6.09

Bulgaria

 

 

 

 

West Koynare

 

NA

 

NA

 

 

 

 

 

Note: Fields with no sellable quantities of oil, condensate, or gas have been denoted as NA (not applicable).

 

The overall volume-weighted average oil and condensate prices used in this report were U.S.$58.79 per barrel, U.S.$58.65 per barrel, and U.S.$58.78 per barrel for proved, probable, and possible reserves, respectively. The average reference gas price during this period was the Botas Gas exchange price of

 


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U.S.$7.17 per thousand cubic feet (103ft3). The overall volumeweighted average gas prices in this report were U.S.$5.29 per 103ft3, U.S.$4.94 per 103ft3, and U.S.$5.16 per 103ft3 for proved, probable, and possible reserves, respectively. These prices were held constant for the lives of the properties.

Operating Expenses and Capital Costs

Estimates of operating expenses and capital costs were based on historical, current, and budgeted expenses and costs provided by TransAtlantic. In certain cases, future operating expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Future capital expenditures were estimated using current values and were not adjusted for inflation.

Abandonment Costs

Abandonment costs were provided by TransAtlantic. These costs were estimated using current values and were not adjusted for inflation. Abandonment costs are represented by TransAtlantic to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration (if any) associated with the abandonment. In some instances, abandonment costs were assigned to certain completion projections to ensure that well abandonment costs were included on a per-well basis and not duplicated for multiple recompletions in a single wellbore. TransAtlantic has represented that it will relinquish operation of the Selmo field to the Turkish Government at the end of June 2025, and therefore will not be responsible for abandonment costs pertaining to wells in the Selmo field that produce beyond June 2025.

Net Profits Interest

As represented by TransAtlantic, there is a 5-percent net profits interest burden for certain wells in the Alpullu, Edirne, Karapurcek, and REDY fields in Turkey. Where applicable, the

 


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net profits reduced TransAtlantic’s ownership of reserves and revenue.

Royalty

All fields are subject to a royalty of 12.5 percent. Certain wells in the Edirne field are subject to a third-party carried net revenue interest of 2.625 percent.

Taxes

TransAtlantic has represented that there are no production taxes to be paid in Turkey or Bulgaria. No other taxes, including income taxes for Turkey, Bulgaria, or the United States, were considered in this evaluation.

 

In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation
S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

 

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2019, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are

 


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summarized as follows, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (103ft3):

 

 

 

Estimated by DeGolyer and MacNaughton

Net Reserves as of December 31, 2019

 

 

Oil

(bbl)

 

Condensate

(bbl)

 

Sales Gas

(103ft3)

 

 

 

 

 

 

 

Proved Developed

 

5,623,938

 

0

 

2,281,610

Proved Undeveloped

 

4,634,768

 

0

 

185,216

 

 

 

 

 

 

 

Total Proved

 

10,258,706

 

0

 

2,466,826

 

 

 

 

 

 

 

Probable Developed

 

920,128

 

0

 

815,131

Probable Undeveloped

 

6,291,611

 

0

 

29,814

 

 

 

 

 

 

 

Total Probable

 

7,211,739

 

0

 

844,945

 

 

 

 

 

 

 

Possible Developed

 

1,062,299

 

0

 

950,845

Possible Undeveloped

 

5,679,655

 

0

 

32,562

 

 

 

 

 

 

 

Total Possible

 

6,741,954

 

0

 

983,407

 

 

 

 

 

 

 

Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

 

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2019, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in United States dollars (U.S.$):

 

 

 

Estimated by DeGolyer and MacNaughton as of December 31, 2019

 

 

Future Gross

Revenue

(U.S.$)

 

Operating

Expenses

(U.S.$)

 

Capital

Costs

(U.S.$)

 

Abandonment

Costs

(U.S.$)

 

Net Profits

Reduction

(U.S.$)

 

Future Net

Revenue

(U.S.$)

 

Present Worth

at 10 Percent

(U.S.$)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed

 

342,406,436

 

83,016,997

 

1,312,500

 

927,837

 

84,983

 

257,064,119

 

178,977,330

Proved Undeveloped

 

273,852,221

 

42,504,764

 

54,855,000

 

376,350

 

49,523

 

176,066,584

 

109,532,996

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Proved

 

616,258,657

 

125,521,761

 

56,167,500

 

1,304,187

 

134,506

 

433,130,703

 

288,510,326

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Probable Developed

 

58,081,485

 

9,051,023

 

0

 

0

 

27,336

 

49,003,126

 

28,738,143

Probable Undeveloped

 

369,089,576

 

58,799,153

 

41,451,750

 

300,000

 

7,969

 

268,530,704

 

142,348,963

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Probable

 

427,171,061

 

67,850,176

 

41,451,750

 

300,000

 

35,305

 

317,533,830

 

171,087,106

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Possible Developed

 

67,331,424

 

10,574,299

 

0

 

0

 

37,232

 

56,719,893

 

31,268,069

Possible Undeveloped

 

334,092,731

 

31,770,276

 

7,200,000

 

80,000

 

8,708

 

295,033,747

 

147,950,974

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Possible

 

401,424,155

 

42,344,575

 

7,200,000

 

80,000

 

45,940

 

351,753,640

 

179,219,043

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Notes:

1. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves.

2. Future income taxes were not taken into account in the preparation of these estimates.

3. Net reserves and future net revenue reflect reductions for net profits, where applicable.

 

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2019, reserves estimated herein.

 

 


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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in TransAtlantic. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of TransAtlantic. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

 

 

/s/ Regnald A. Boles

Regnald A. Boles, P.E.

[Seal]Senior Vice President

DeGolyer and MacNaughton


 

 

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Regnald A. Boles, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

 

 

1.

That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to TransAtlantic Petroleum Ltd. dated March 3, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

 

 

2.

That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 36 years of experience in oil and gas reservoir studies and evaluations.

 

 

3.

That DeGolyer and MacNaughton or its officers have no direct or indirect interest, nor do they expect to receive any direct or indirect interest in any properties or securities of TransAtlantic Petroleum Ltd. or affiliate thereof.

 

SIGNED: March 3, 2020

 

/s/ Regnald A. Boles

Regnald A. Boles, P.E.

[Seal]Senior Vice President

DeGolyer and MacNaughton