Pursuant to your request, we have conducted an independent evaluation, completed on March 6, 2015, to serve as a reserves audit of the extent and value of the proved, probable, and possible oil, natural gas, and condensate reserves, as of December 31, 2014, of certain properties owned by TransAtlantic Petroleum Ltd. (TransAtlantic) in Turkey and Bulgaria. TransAtlantic has represented that these properties account for 58.1 percent, on a net equivalent barrel basis, of TransAtlantic’s net proved, probable, and possible reserves, as of December 31, 2014. 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.

Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by TransAtlantic after deducting interests owned by others. Only net reserves are reported herein.

Gas reserves estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas produced from the reservoir after reduction for shrinkage resulting from field separation, processing, fuel use, and flare available to be delivered into a gas pipeline for sale. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.70 pounds per square inch absolute (psia). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation.

Values of proved, probable, and possible reserves shown herein are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves adjusted for net profits (where applicable). Future net revenue is defined as the future gross revenue less direct operating expenses, capital costs, abandonment costs, and net profits, where applicable. Direct operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate 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 oil, natural gas, and condensate reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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.

Data used in this audit were obtained from reviews with TransAtlantic personnel, from TransAtlantic files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by TransAtlantic with respect to property interests, 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, 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.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance 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 (Revision as of February 19, 2007).” 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.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure 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 adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors. In such case, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

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, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

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

The fields have been grouped into three asset groups based on economic considerations: the Thrace Basin Natural Gas Company (TBNGC) asset group, the core TransAtlantic properties (TAT) asset group, and the Edirne asset group (consisting of Edirne field). All fields are subject to a royalty of 12.5 percent. The TBNGC asset group is subject to an additional 1.0-percent overriding royalty interest, except for the Alibey field which has a 0.5-percent overriding royalty interest. Certain wells in TAT and Edirne

asset groups are also subject to a net profits interest of 5 percent. 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 calculated revenue associated with the net profits payable.

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 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.

(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.

(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 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 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.

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.

The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with proved reserves.

The following economic assumptions were used for estimating existing and future prices and costs:

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. An average reference oil price during this period was Brent at 102.70 United States dollars (U.S.$) per barrel. The oil and condensate prices used to estimate reserves herein were as follows: U.S.$50.97 per barrel in Bulgaria, U.S.$92.70 per barrel in AG field, U.S.$98.20 per barrel in Alibey field, U.S.$94.87 per barrel in Arpatepe field, U.S.$86.69 per barrel in Goksu field, U.S.$74.20 per barrel in Kazanci field, U.S.$94.89 per barrel in the Bahar and Molla fields, and U.S.$95.20 per barrel in the Selmo field. The overall volume‑weighted average oil price in this report was U.S.$94.53. An average reference gas price during this period was the United Kingdom National Balancing Point Index of U.S.$8.35 per million British thermal units. The gas prices used in this report were as follows: U.S.$9.10 per thousand cubic feet (Mcf) for TBNGC asset group, U.S.$8.10 per Mcf for the Edirne asset group, U.S.$4.25 per Mcf for Bulgaria, U.S.$7.62 per Mcf for the Bakuk field, and U.S.$8.10 per Mcf for the remaining fields in TAT asset group. The overall volume-weighted average gas price in this report was U.S.$8.71 per Mcf. These prices were held constant for the lives of the properties.

As represented by TransAtlantic, there is a 5-percent net profits interest burden for certain wells in the AG, Alpullu, CAB, DAK, Edirne, Karapurcek, and REDY fields. Where applicable, the net profits reduced TransAtlantic’s ownership of reserves and revenue values.

Estimates of operating expenses based on current expenses were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions. Future capital expenditures were estimated using current values and were not adjusted for inflation.

Abandonment costs were provided by TransAtlantic. These costs were estimated using current values and were not adjusted for inflation. Abandonment costs herein include well abandonment only. Also, 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.

All fields are subject to a royalty of 12.5 percent. Fields in the TBNGC asset group are subject to an additional 1.0-percent overriding royalty interest, except for the Alibey field, which has an 0.5-percent overriding royalty interest. Certain wells in the Edirne field are subject to a third-party carried net revenue interest of 2.625 percent. 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.

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 oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, oil, condensate, and gas reserves estimated herein.

The estimates of net proved, probable, and possible reserves, as of December 31, 2014, attributable to the interests owned by TransAtlantic in Turkey and Bulgaria, of the properties evaluated herein, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):

	Estimated by DeGolyer and MacNaughton Net Reserves as of December 31, 2014
	Oil (bbl)	Condensate (bbl)	Sales Gas (Mcf)

Proved
Developed	6,857,363	0	9,550,865
Undeveloped	7,548,724	0	6,702,616

Total Proved	14,406,087	0	16,253,481

Probable
Developed	1,400,078	0	3,034,009
Undeveloped	10,031,579	0	20,759,520

Total Probable	11,431,657	0	23,793,529

Possible
Developed	1,456,587	0	3,073,332
Undeveloped	10,571,420	0	73,666,119

Total Possible	12,028,007	0	76,739,451

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

The estimated revenue and expenditures attributable to TransAtlantic’s interests in Turkey and Bulgaria in the proved, probable, and possible net reserves, as of December 31, 2014, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows, expressed in United States dollars (U.S.$):

	Estimated by DeGolyer and MacNaughton as of December 31, 2014
	Proved
	Developed (U.S.$)	Undeveloped (U.S.$)	Total (U.S.$)	Probable (U.S.$)	Possible (U.S.$)

Future Gross Revenue	733,285,294	771,083,916	1,504,369,210	1,283,000,278	1,759,157,222
Production Taxes	0	0	0	0	0
Operating Expenses	165,528,104	139,853,057	305,381,161	145,089,251	188,509,510
Capital Costs	3,869,689	230,805,583	234,675,272	200,494,978	181,979,150
Abandonment Costs	2,777,290	431,964	3,209,254	621,538	762,176
Net Profits	237,706	(700,234)	(937,940)	(879,914)	(20,599,531)
Future Net Revenue	560,872,505	399,293,078	960,165,583	935,914,597	1,367,306,855
Present Worth at 10 Percent	418,513,961	230,019,491	648,533,452	518,031,340	663,182,647

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 tax expenses were not taken into account in the preparation of these estimates.

In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved, probable, and possible reserves, and present worth of estimated future net revenue from proved, probable, and possible reserves of oil, condensate, and sales 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 Financial Accounting Standards Board 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 Securities and Exchange Commission; 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.

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.

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


		/s/ Lloyd W. Cade, P.E.
		Lloyd W. Cade, P.E.
[SEAL]		Senior Vice President
		DeGolyer and MacNaughton


		/s/ Lloyd W. Cade, P.E.
		Lloyd W. Cade, P.E.
[SEAL]		Senior Vice President
		DeGolyer and MacNaughton