Exhibit 10.1
TRANSATLANTIC PETROLEUM LTD.
RETENTION INCENTIVE AGREEMENT
This Retention Incentive Agreement (“
Agreement
”) is made and entered into as of April [•], 2018 by and between TransAtlantic Petroleum Ltd., a Bermuda exempted company (the “
Company
”), and [•] (“
Employee
”).
RECITALS
WHEREAS, the Company is exploring strategic alternatives, including a possible sale of the Company (the “
Transaction
”); and
WHEREAS, Employee is currently providing services to the Company, and the Company desires to incentivize Employee to continue to provide such services to the Company to the best of Employee’s ability and to cooperate with effecting the Transaction.
NOW, THEREFORE, in consideration of the premises and promises contained in this Agreement, and other good and valuable consideration the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, the Company and Employee agree as follows:
1.
Retention Incentives
. Subject to the terms and conditions set forth in this Agreement, including any reduction in Retention Incentives pursuant to Section 2 hereof, Employee shall receive an amount equal to three months of base salary, as allocated for the time spent working on matters for the Company (the “
Retention Incentives
”). In order to be eligible to receive the Retention Incentives, the Employee must (i) render reasonable cooperation in connection with effecting the Transaction and (ii) provide reasonable best efforts in achieving the Company’s 2018 business plan. The Retention Incentives shall be paid to Employee on the earlier of (i) sixty (60) days following the date of the consummation of the Transaction (the “
Closing Date
”) and (ii) March 31, 2019.
For purposes of this Agreement, “Cause” shall mean Employee’s (i) willful or deliberate failure to perform material duties to the Company or gross negligence in the performance of such material duties; (ii) breach of the Company’s code of ethics; (iii) breach of a duty of loyalty or misconduct that causes or is reasonably likely to cause harm to the Company or any of its affiliates; (iv) dishonesty, willful misconduct or fraud in connection with Employee’s performance of his or her duties or related to the business of the Company or its affiliates; (v) failure to render reasonable cooperation in connection with effecting the Transaction and provide reasonable best efforts in achieving the Company’s 2018 business plan; (vi) conviction of a felony or a crime involving moral turpitude; or (vii) failure to comply with the general terms of their employment offer letter
.
2.
Forfeiture of Retention Incentives
. Employee will not earn or be paid the Retention Incentives or any portion thereof if, prior to the Closing Date, Employee: (i) has voluntarily resigned for any reason; (ii) has been terminated for Cause;
(iii) has died; or (iv) has become disabled, as reasonably determined by the Company.
If Employee has been terminated prior to the Closing Date without Cause, Employee shall be entitled to a portion of the Retention Incentives equal to the Retention Incentives
multiplied by
a fraction the numerator of which is the number of
1
days beginning January 5, 2018 and ending on the date that Employee was terminated and the denominator of which is the number of days beginning January 5, 2018 and ending on the earlier of the Closing Date and
March
31, 201
9
.
Such amount shall be paid at the next period following such termination.
3.
Confidentiality
. As a condition to eligibility for, and payment of, the Retention Incentives, Employee hereby agrees to keep the terms of this Agreement in strict confidence.
4.
Employment Status
. Nothing in this Agreement shall be considered effective to change Employee’s employment status with the Company or to guarantee any continued employment with the Company. Either the Company or Employee may terminate the employment relationship at any time, for any reason or no reason.
5.
Withholding
. Payment of the Retention Incentives, if any, shall be subject to withholding in accordance with applicable tax laws or regulations.
6.
Entire Agreement
. This Agreement embodies the complete agreement and understanding between the parties hereto with respect to the subject matter hereof and supersedes and preempts any prior understandings, agreements or representations by and between the parties, written or oral, which may have related to the subject matter hereof in any way.
7.
Governing Law; Exclusive Jurisdiction
.
The validity, construction, and effect of this Agreement shall be determined in accordance with the laws of the State of Texas
, without regard to the rules relating to conflict of laws. Any legal suit, action or proceeding arising out of or based upon this agreement, the other transaction documents or the transactions contemplated hereby or thereby must be instituted in the state or federal courts located in Dallas County, Texas (and any appellate courts with respect thereto), and each party irrevocably submits to the exclusive jurisdiction of such courts in any such suit, action or proceeding. The parties irrevocably and unconditionally waive any objection to the laying of venue of any suit, action or any proceeding in such courts and irrevocably waive and agree not to plead or claim in any such court that any such suit, action or proceeding brought in any such court has been brought in an inconvenient forum.
8.
Successors and Assigns
. Employee may not assign Employee’s rights or interests under this Agreement. This Agreement shall be binding on and inure to the benefit of the successors and assigns of the Company.
9.
Section 409A
. Notwithstanding anything herein to the contrary, this Agreement is intended to be interpreted and applied so that the payments and benefits set forth herein either shall either be exempt from the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “
Code
”), or shall comply with the requirements of Code Section 409A, and, accordingly, to the maximum extent permitted, this Agreement shall be interpreted to be exempt from or in compliance with Code Section 409A.
[
Signature page follows
]
2
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.
EMPLOYEE
TRANSATLANTIC PETROLEUM LTD.
__________________________________
Name:
Name:
Title:
Exhibit 99.1
TransAtlantic Petroleum Announces Change in Time of Presentation at IPAA New York Oil and Gas Symposium
Hamilton, Bermuda (April 6, 2018) – TransAtlantic Petroleum Ltd.
(TSX: TNP) (NYSE American: TAT) (the “Company” or “TransAtlantic”) today announced that the time for its management presentation at the IPAA New York Oil and Gas Symposium has been changed from 4:05 pm Eastern Time to 3:35 pm Eastern Time on Monday, April 9, 2018.
A live webcast of the event and slide presentation will be available on the Company’s website at
www.transatlanticpetroleum.com
. To access the webcast, click on “Investors”, select “Events and Presentations”, and click on “Listen to webcast” under the event listing.
About TransAtlantic Petroleum
The Company is an international oil and natural gas company engaged in the acquisition, exploration, development, and production of oil and natural gas. The Company holds interests in developed and undeveloped properties in Turkey and Bulgaria.
(NO STOCK EXCHANGE, SECURITIES COMMISSION, OR OTHER REGULATORY AUTHORITY HAS APPROVED OR DISAPPROVED THE INFORMATION CONTAINED HEREIN.)
Forward-Looking Statements
This news release and the presentations referred to herein contain statements concerning the marketing of the Company, the Company’s drilling program, the Company’s 3D seismic program, the evaluation of the Company’s prospects in the Thrace Basin in Turkey, the Molla Area of Southeast Turkey, and Bulgaria, information on the Company’s reserves, use of future prospective capital in the Company’s business, expectations of future funding and capital sources, drilling, completion, and cost of wells, the production and sale of oil and natural gas, as well as other expectations, plans, goals, objectives, assumptions, and information about future events, conditions, results of operations, and performance that may constitute forward-looking statements
1
Exhibit 99.1
or information under applicable securities legislation. Such forward-looking statements or information are based on a number of assumptions, which may prove to be incorrect.
Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to, access to sufficient capital; market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids, and oil products; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which the Company carries on business, especially economic slowdowns; actions by governmental authorities; receipt of required approvals; increases in taxes; legislative and regulatory initiatives relating to fracture stimulation activities; changes in environmental and other regulations; renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; outcomes of litigation; the negotiation and closing of material contracts; and other risks described in the Company’s filings with the SEC.
The forward-looking statements or information contained in this news release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Contacts:
Chad D. Burkhardt
Vice President, General Counsel and Corporate Secretary
+1 (214) 265-4705
TransAtlantic Petroleum Ltd.
16803 Dallas Parkway
Addison, Texas 75001
http://www.transatlanticpetroleum.com
2
Bahar Production Facility 2018 IPAA New York Bahar Central Production Facility PRESENTATION Exhibit 99.2
disclaimer Outlooks, projections, estimates, targets and business plans in this presentation or any related subsequent discussions are forward-looking statements. Actual future results, including TransAtlantic Petroleum Ltd.’s own production growth and mix; financial results; the amount and mix of capital expenditures; resource additions and recoveries; finding and development costs; project and drilling plans, timing, costs, and capacities; marketing process; access to capital; revenue enhancements and cost efficiencies; industry margins; margin enhancements and integration benefits; and the impact of technology could differ materially due to a number of factors. These include market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities, receipt of required approvals, increases in taxes, legislative and regulatory initiatives relating to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; shortages of drilling rigs, equipment or oilfield services; and other factors discussed here and under the heading “Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2017, which is available on our website at www.transatlanticpetroleum.com and at www.sec.gov. See also TransAtlantic’s audited financial statements and the accompanying management discussion and analysis. Forward-looking statements are based on management’s knowledge and reasonable expectations on the date hereof, and we assume no duty to update these statements contained in our Form 10-K as of any future date, except as required by law. The information set forth in this presentation does not constitute an offer, solicitation or recommendation to sell or an offer to buy any securities of TransAtlantic. The information published herein is provided for informational purposes only. TransAtlantic makes no representation that the information and opinions expressed herein are accurate, complete or current. The information contained herein is current as of the date hereof, but may become outdated or subsequently may change. Nothing contained herein constitutes financial, legal, tax, or other advice. The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We may use the terms “estimated ultimate recovery,” “EUR,” “probable,” “possible,” and “non-proven” reserves, “prospective resources” or “upside” or other descriptions of volumes of resources or reserves potentially recoverable through additional drilling or recovery techniques. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by TransAtlantic. There is no certainty that any portion of estimated prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the estimated prospective resources. This presentation includes 1P, 2P, and 3P reserves based on a reserve report prepared by Degolyer & MacNaughton as of December 31, 2017 using forward strip pricing (“YE2017 D&M Strip-Pricing Reserve Report”) and a reserve report prepared by Degolyer & MacNaughton as of December 31, 2017 using SEC pricing (“YE2017 D&M SEC Reserve Report”). 1P reserves refer to proved reserves. 2P reserves refer to proved reserves plus probable reserves. 3P reserves refer to proved reserves plus probable reserves plus possible reserves. Proved reserves are those quantities of oil and natural 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. Probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of 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. 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. Possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. 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.
Disclaimer (cont.) This presentation also includes prospective resource estimates from the Netherland, Sewell & Associates, Inc. Prospective Resource Report dated as of May 31, 2017 (“May 2017 NSAI Prospective Resource Report”), and the DeGloyer and MacNaughton Prospective Resource Report dated as of December 31, 2017 (“December 2017 D&M Prospective Resource Report”), and the DeGloyer and MacNaughton Prospective Resource Report for the Thrace Basin dated as of December 31, 2017 (“December 2017 D&M Prospective Resource Report – Thrace Basin”). Prospective resources are not the same as reserves or contingent resources. Prospective resources are those quantities of oil and gas estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Risks associated with the estimate of prospective resources contained in this presentation include, but are not limited to: The Thrace Basin Centered Gas Accumulation (“Thrace BCGA”) play is in the early exploration and delineation cycle with limited well control and limited fracture stimulation and testing data. Prospects evaluated in the May 2017 NSAI Prospective Resource Report are developed largely using seismic interpretation. Limited well control data is available to support the prospects. The volumes associated with the May 2017 NSAI Prospective Resource Report are all the unrisked high estimate, meaning there is no more than a 10% probability that the volumes discovered will exceed the estimate. There is no long-term well production performance from the Thrace BCGA or the May 2017 NSAI Prospective Resource Report prospects to establish a production type curve specific to the prospect, thereby requiring use of analogue information to establish development plans and to confirm the chance of commerciality. Recovery efficiencies are uncertain given the absence of site specific long-term well production performance data. The limited deep drilling carried out in the Thrace Basin and Bulgaria provides limited visibility on future costs to drill, frac and complete deep development wells to exploit prospects in those regions and the associated impact on the chance of commerciality. Although oil and gas activity has been underway for many decades in Turkey, as activity levels increase, timelines may increase to achieve government and local landowner approvals. Note on PV10 and PV20: The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future federal income taxes. The PV10 future net revenues have been discounted at an annual rate of 10% and the PV20 future net revenues have been discounted at an annual rate of 20% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties or the oil and natural gas reserves TransAtlantic owns. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. PV10 and PV20 are not measures of financial or operating performance under GAAP. Neither PV10 nor PV20 should be considered as an alternative to the Standardized Measure as defined under GAAP. The Standardized Measure represents the PV10 after giving effect to income taxes. Note on BOE: BOE (barrel of oil equivalent) is derived by converting natural gas to oil in the ratio of six thousand cubic feet (MCF) of natural gas to one barrel (bbl) of oil. BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Important Notice This presentation reflects TransAtlantic’s management’s opinions of a logical and appropriate production, development, and exploration program, which balances the following objectives: Increasing production income by drilling proved undeveloped locations Advancing testing of high-value resource and prospective prospects to a state where continuous development could be commenced in mid-2019 following reservoir testing of wells drilled in 2018 and early 2019 Constructing the necessary and justified production facilities to support the continuous development described in 2) above All activities in 1) and 2) located and timed to conserve and expand TransAtlantic’s production licenses in the greatest realistic manner Making fair estimates of costs and production results based upon prior history and expected practices The drilling and exploration activities discussed in this presentation seek to provide investors with information to better understand the value potential of TransAtlantic’s current properties and opportunities. This presentation depicts an accelerated work-plan that exceeds TransAtlantic’s current cash flow and credit facilities and therefore this presentation should be read as a description of the “potential” of TransAtlantic’s assets rather than as a description of actual intended operations.
COMMODITIES CYCLES . Commodities are a contrarian opportunity as uptrend of the current cycle begins. Oil and gas are especially attractive since they are less exposed to China demand than industrial metals. 40 Year 1 Year Commodities at Historic Extreme Lows Relative to Overall Stock Market Commodities to Stock Ratio
Favorable oil market fundamentals . Global demand growth has balanced supply, ending the oil glut International Energy Agency, Oil Market Report: 13 February 2018 1.5 billion internal combustion vehicles on roads compared to 2-3 million electric vehicles (Tailpipe to Smokestack shift) 1 billion bbl’s must be found every 10 days. Will move toward 8 days before leveling (and natural gas will be mitigating force) Declining discoveries setting the stage for tightening of Oil and Gas markets Declining Discoveries
Key learnings: oil & gas investing * See slide 22 for further details Insider alignment is key. Find owner-operators with skin in the game. Focus on reserves as key valuation framework, ideally buying at a discount Look for long runway of future growth to current operations TransAtlantic, one of the world’s most undervalued E&P companies, meets all of these investment criteria. TransAtlantic’s Alignment to those Observations Oil and Gas Investing Observations 70%+ owned by 5 entities; CEO & related family members beneficially own greater than 40% of common shares and of Series A preferred shares TAT trades at more than a 60% discount to its proved reserves TransAtlantic acreage builds to more than $10 per share NAV* (>7X current price)
Transatlantic petroleum capital structure . Listed Exchanges and Tickers NYSE AMERICAN: TAT TSX: TNP Share Price as of 30-Mar-2018 $1.29 Common Shares Outstanding 50.4 MM Common Shares to be issued if all Preferred Shares Convert(1) 42.1 MM Market Capitalization $65 MM Fully-Diluted Market Capitalization(1) $119 MM Enterprise Value(1) $130 MM Assumes preferred shares converted to common shares. Cash of ~$19MM and total debt of ~$29MM per Q4’2017 10K filing and term loan announced November 2017. As Of 3-30-18
Balance sheet: debt managed through oil price cycle . (1)This pro forma amount assumes three payments of $1.375mm on our Term Loan for each month Jan, Feb, and March 2018. 2) Adjusted EBITDAX is a non-GAAP financial measure. See the reconciliation on page 28 Total Debt ($ Millions) New Term Loan Net Financial Debt at YE 2017 was $9.7mm Q4 2017 EBITDAX was $8.4mm(2) (1)
. Company Overview: u.s. Technology in high-return international locales A Dallas, TX – based oil and gas company applying proven, North American technology to known international hydrocarbon basins Focused on horizontal drilling, stimulation, and 3D seismic Operate in countries favorable commodity prices, royalty, and tax rates Holds 367,000 net acres in Turkey and 163,000 net acres in Bulgaria Fiscal regimes among the best in the world 8,900 net acres in the highly productive Şelmo Oil Field 121,600 net acres in the oil rich Molla Area ~ 50,000+ net acres in the evolving basin centered gas play in Thrace Basin
Historical Capex and Production Growth Note: 2018 expected capex includes $1.6 to $4.6 million of capital expenditures that are contingent on funding and assumes that TransAtlantic drills each of the wells described in its previously disclosed 2018 drilling schedule. 2019 expected capex is contingent on funding and assumes that TransAtlantic drills each of the wells described in its previously disclosed 2019 drilling schedule and incurs additional pipeline expenses. (1) Thrace Basin Natural Gas Corporation; disposed of in 2016 (2) Assumes exploration success in Bulgaria; includes Thrace, Dadas Sand and Dadas Shale (2) (1) Short-cycle portfolio, highly responsive to capex spend
Production and development: Şelmo Field In Southeast Turkey . 2nd largest oil field in Turkey discovered in 1964 by Mobil 700 MMBO in place and 91+ MMBO produced TransAtlantic 100% WI Focus of 2018-2019 drilling campaign to increase production Şelmo Field ~ 11.9 MMBoe 2P Reserves 2P PV10 $236 MM Brent Forward Strip November 29, 2017 TransAtlantic Petroleum Announces New Drilling Program With receipt of proceeds from the 2017 Term Loan, the Company is launching a new drilling program. The Company plans to begin drilling the Şelmo-81H1 well starting in the first quarter of 2018. Şelmo is a “Cash Cow” SOUTHEAST TURKEY Based on YE2017 D&M Strip-Pricing Reserve Report Pre-tax values based on YE2017 D&M Strip-Pricing Reserve Report Note: PV10 values for all reserves calculated using SEC prices are as follows: 1P: $266 MM and 2P: $464 MM assuming a flat price of $54.89/bbl. Please see slide 29-32 for reconciliation of PV10 values to the most comparable GAAP measure. Steady, solid long-lived field with improved prospects from applying new recovery techniques.
Note: DeGolyer & McNaughton oil type curve has an 24-hour IP of 185 bbl/d and is based off assumptions that result in a curve below TAT’s observed well performance in the area. Economic results are shown on a pre-tax basis. Rate – Time Production Plot Economic Summary Best Fit Curve - Each well drilled makes $4.6mm profit (average) Şelmo wells deliver 49-128% returns Bahar Bedinan 1P type curve per DeGolyer & McNaughton Reserve Report Şelmo - Great economics and actual averages outperform 1P reserves
Production and development: Molla Area Fields In Southeast Turkey Additional focus of 2018 drilling campaign Key source of unbooked potential reserve upside Molla Area Fields ~ 15.6 MMBoe 2P Reserves 2P PV10 $321 MM Bahar Field: (~7MMBoe 1P reserves, 11MMBoe 2P) produces from the Bedinan Sandstone, Dadas Sand, Hazro F-3 Sand and Hazro F-4 Dolomite formations, Mardin shows untested Liquids rich gas and secondary recovery upside SOUTHEAST TURKEY Mardin Based on YE2017 D&M Strip-Pricing Reserve Report Pre-tax values based on YE2017 D&M Strip-Pricing Reserve Report Note: PV10 values for all reserves calculated using SEC prices are as follows: 1P: $266 MM and 2P: $464 MM assuming a flat price of $54.89/bbl. Please see slide 29-32 for reconciliation of PV10 values to the most comparable GAAP measure. A Highly productive, stacked pay oil field (Anadarko Basin Analog)
. Molla Area: bahar Field - Great economics Rate – Time Production Plot Economic Summary DeGolyer & McNaughton Curve - Each well makes $10.4mm profit (average) Bahar Bedinan 1P type curve per DeGolyer & McNaughton Reserve Report Bahar wells deliver returns > 300%
Primary basins: Southeast Turkey Basin – Anadarko Basin Analog . Over > 85 mmboe (1) of net conventional and 600 mmboe (2) of net unconventional prospective resources have been identified in the Molla Area of Southeast Turkey Multiple targets and stacked plays. Five pay zones Drill depths are < 4,000m, with the shallowest pay zones starting at 1,500m Wells are expected to cost ~$2-4 MM to drill and complete vertically Discoveries can be rapidly monetized, given proximity to existing infrastructure Prospectivity Overview Molla Area Prospecitivity Overview Pinar Discovery Yeniev 1 Drilling Now Cavuslu Discovery Based on May 2017 NSAI Prospective Resource Report Based on internal estimates
Primary basins: Thrace Basin – Jonah field analog TransAtlantic has a 100%(1) interest in the Temrez leases, covering an area of 120,000 acres in the Thrace basin. Valeura (Statoil JV) just announced results from a well validating significant Basin Centered Gas Play in the basin. 4 Tcf of prospective resource on TransAtlantic’s Temrez license(2). Subject to funding, TransAtlantic intends to commence a 3-well delineation program in Q4 2018. TransAtlantic acquired its Thrace Basin leases from Zorlu Enerji, which has the option to either a 5% NPI or participate with a 25% WI on all future wells drilled on the Temerez Blocks. December 2017 D&M Prospective Resources Report Basin Centered Gas Accumulations (BCGA) are very valuable assets Source: Unconventional Oil & Gas Handbook, Y. Zee Ma, Stephen Holdtch. BCGAs with 4 Tcf of recoverable gas translates to gross revenues of $20 billion with gas prices of $5 per MCF in Turkey. Valeura’s potential BCGA discovery has excited markets VLE stock price up 5x since announcement TransAtlantic controls acreage immediately adjacent to Valeura. TAT’s Thrace Assets Result in Favorable Comparisons Comparison VLE TAT Wells on license ü ü Sand present ü ü 500+ meters net pay ü ü Over-pressure confirmed ü ü Gas and oil tests ü ü Slickwater well completion ü û BCGA Net acres ~65 – 75K ~50K Pipeline ü ü Operations û ü Value $310 MM(1) Based on Valeura Energy’s February 2018 equity offering price of $5.70 per common share
Potential of tat’s THRACE acreage in THE temrez area TransAtlantic’s Acreage Bulgaria Northwest Turkey TAT Exploration acreage TAT Production acreage BCGA Boundary Yamalik-1: Aggregate test rates of 2.9 mmcfd with condensate of 20-70 bbls/mmcf from four test intervals (eight fracs) in the Keşan Formation at ~0.7 psi/ft Structural Depth in the Thrace Basin Source: December 2017 D&M Prospective Resources Report – Thrace Basin Total represents the statistical aggregate Total represents the arithmetic summation Mean Case 23,016 acres productive area 47% of the 49,134 acres within the pressured area 1,117 feet of net pay 56% net to gross ratio 7.6% porosity 50% gas saturation 54% recovery efficiency High Case 31,937 acres productive area 65% of the 49,134 acres within the pressured area 1,972 feet of net pay 76% net to gross ratio 10.1% porosity 63% gas saturation 69% recovery efficiency 1TCF = ± $5B Gross Sales The 4 Tcf resource estimate could turn out to be conservative
Primary basins: bulgaria (1) Based on May 2017 NSAI Prospective Resource Report 35-year Koynare Production Concession through 2048 covers 163,000 acres Koynare #1 drilled by Direct Petroleum utilizing old 2D seismic crossed a major fault and encountered the target zone at deeper depth. Completed for gas – condensate discovery from shallower zone. 3D seismic shot by TransAtlantic identified the fault location and target located northeast. Estimated 25 MMbbl recoverable (Primary).(1) Contingent on funding, Q3 18 plan to whipstock and drill #1 well to 3D target and delineate more shallow pay Multiple additional leads create running room Highest per well return potential in portfolio ± 8-1 BULGARIA Conventional high margin potential to be exploited with 3D insights North Koynare Prospect
Tat marketing process – timelines Week of Mar 5 Week of Mar 19 Week of Mar 12 Week of Mar 26 Week of April 02 Week of Apr 09 Week of Apr 16 Week of Apr 23 Week of Apr 30 Week of May 07 Week of May 14 Week of May 21 Week of May 28 Week of Jun 04 Week of Jun 11 Week of Jun 18 Company Marketing Process and Key Events Investor Outreach Campaign Week of Feb 19 Week of Feb 26 Reserve Report Released Investor Presentation Released London TPH kickoff Data Room Open, Management Presentation to Prospective Buyers Negotiations Bids (Week of May 15) Annual Meeting (June 19) IPAA/OGIS in NYC April 9th 3:35 p.m. EST Email & Phone Campaign Q4 TAT Earnings Conference Call Fireside Chat (April 3rd 2 p.m. EST) Contact Lytham Partners for Participation Robert Blum (phone: 602-889-9700) Q1 Earnings Call (Week of May 7) The above schedule and events are subject to change as the process evolves. Hosted by Lytham Partners TransAtlantic Petroleum Presentation IPAA/OGIS in NYC Investor 1-on-1 Meetings April 10th-11th Contact Lytham Partners for Participation Joe Diaz (phone: 602-889-9700);
TransAtlantic Market valuation – regional peers . TransAtlantic offers exposure to high margin barrels at an attractive valuation Current EV/2P Reserves versus Full-Year 2017 Netback ($/boe) $0 - $10 Current EV / 2017 2P Reserves ($/boe) YE 2017 Netback(1) ($/boe) Profitability Public Market Value $10 - $20+ $0 - $20 $20 - $40 TransAtlantic EV / YE 2017 2P of $5.06/boe and YE 2017 netback of $38.40/boe Source: Company filings, FactSet as of 27-Mar-2018. Note: Reserves and financial values as of YE 2017, except Tethys Energy and JKX which reflect pro rata Q3 2017 netback and reserve values as the companies’ 2017 annual results have not yet been posted. Netback defined as revenue less operational expenses per net boe of production; pre-tax
Transatlantic petroleum is significantly undervalued Update before IPAA Pre-tax values based on YE 2017 D&M Strip-Pricing Reserve Report. Note: PV10 values calculated using SEC prices are as follows: 1P - $244 MM and 2P - $464 MM assuming a flat price of $54.89/bbl. PV20 values calculated using SEC prices are as follows: 3P $124 MM assuming a flat price of $54.89/bbl. Please see slides 29-32 reconciliation of PV10 and PV20 values to most comparable GAAP measure. Based on TransAtlantic’s 50,000 net acre position in the BCGA at $6,200/acre, calculated based on Valeura Energy’s market value using Valeura Energy’s February 2018 equity offering price of $5.70 per common share. Bulgaria, Dadas Sand and Molla conventional exploration resource values per May 2017 NSAI Prospective Resource Report. Dadas Shale and Şelmo Deep potential excluded from analysis. Note: Assumes 92.5 mm shares fully diluted Enterprise value of $130 MM is just 39% of 1P resources PV10 and just 23% of 2P PV10 $1.29 share price as of 03/30/18 TAT Stock Price $10 $8 $6 $4 $2 Catalysts: Dadas frac of Cavuslu Yeniev well Q2 2018 in the Molla area Koynare re-entry Q3 2018 in Bulgaria Bulgaria ~26 net mmboe Molla Conventional ~85 net mmboe Dadas Sand ~122 net mmboe Conventional and Unconventional Exploration Upside
Transatlantic Recap December 2017 D&M Prospective Resource Report May 2017 NSAI Prospective Resource Report and internal estimates STRATEGY SIGNIFICANT ASSETS LUCRATIVE LOCALE GROWTH AHEAD MASSIVE VALUE Established North American drilling & completion techniques can deliver value across portfolio of onshore Europe Material positions in the Thrace Basin Centred Gas Accumulation play in Northwest Turkey with 4 - 8 Tcf and 100 - 200 mmbbls of independently certified (net) prospective gas and condensate resources(1) and the SE Anatolian Basin with ~685 mmbbls of prospective oil resources(2) Active operations in Turkey, with a supportive regulatory environment, attractive fiscal framework and high energy demand On-going drilling campaign underway expected to grow production in 2018 and the potential to more than double overall production by end of 2019, contingent on funding Attempting to unlock value through TPH marketing process
Transatlantic petroleum operating environment . Bahar Field Bahar Central Production Facility Oil Storage Şelmo Şelmo
management team Strong management team and insider alignment Management Team Name Malone Mitchell III Todd Dutton Fabian Anda Chad Burkhardt Selami Uras Lee Muncy David Mitchell Title Chairman & CEO President VP, Finance VP, GC & CS VP, Land VP, Geosciences VP, Engineering Experience 33 years 37 years 18 years 18 years 30 years 38 years 10 years Biography Founded Riata Energy in 1985; saw it through numerous deals and operational evolutions Purchased National Energy Group in 2006 and with Riata renamed it to SandRidge Energy Oklahoma State University BS President of Longfellow Energy since 2007 Held various positions at Texas Pacific Oil Co., Coquina Oil Corp., BEREXCO and Riata Energy University of Oklahoma BBA (Petroleum Land Management) Certified Professional Landman Management roles in a variety of multicultural roles Began his career at ConocoPhillips in operational and financial positions University of Saint Thomas at Houston (Finance and Business Administration; International Finance) Joined TAT from Baker Botts where he served as Partner in the Corporate division Duke University School of Law, JD Texas A&M BA (Anthropology and English) Serves as the TAT representative in Turkey, since 2006 Previously was the Resident Rep. and General Manager for ARCO O&G Started his career at Geophysical Services in Turkey Faculty of Economical & Commercial Sciences Financial Advisor Certificate and Certified CPA Oversees TAT’s geological and geophysical efforts Previously served as VP of Exploration at Bass Companies Began his career as a geologist with Mobil Oil Corp. Ohio State University BS, MS (Geology & Mineralogy) Joined TAT in 2013 and has served in several operations and engineering roles Began his career at Talisman Energy as an engineer in a variety of positions University of British Columbia BASC (Engineering) Registered Professional Engineer (Alberta) Beneficially owns approximately 47% of Common Shares and, with his children, 45% of Series A Preferred Shares
Selmo Production Facility Şelmo Thank You
Appendix
reconciliation for ebitdax For the Three Months Ended For the Twelve Months Ended TBNG Excluding TBNG U.S. Dollars in thousands Dec 31, 2017 Sept 30, 2017 Dec 31, 2016 Dec 31, 2017 Dec 31, 2016 Two Months Ended Feb 28, 2017 (1) Twelve Months Ended Dec 13, 2016 Twelve Months Ended Dec 31, 2017 Twelve Months Ended Dec 31, 2016 Net loss from continuing operations $ (4,039) $ (4,353) $ (5,699) $ (23,875) $ (22,445) $ (15,242) $ 6,002 $ (8,633) $ (28,447) Adjustments: $ - $ - Interest and other, net 1,422 2,140 1,600 7,740 9,295 (130) (1,906) 7,870 11,201 Current and deferred income tax expense 1,573 518 226 5,429 6,046 - 1,005 5,429 5,041 Exploration, abandonment, and impairment 685 141 2,999 934 5,963 6 349 928 5,614 Seismic expense 1,677 2,966 20 4,723 104 4,723 104 Foreign exchange loss (gain) 806 48 3,212 1,861 3,871 196 (3,370) 1,665 7,241 Share-based compensation 136 142 133 692 629 692 629 Loss (gain) on commodity derivative contracts 2,151 1,365 838 1,852 3,257 1,852 3,257 Cash settlements on commodity derivative contracts - - - 32 4,188 32 4,188 Accretion of asset retirement obligation 46 49 88 190 373 - 124 190 249 Depreciation, depletion, and amortization 3,901 4,272 5,972 16,925 29,025 (43) 2,567 16,968 26,458 Commodity derivative unwind gain - - - - - - - Net other items (Including loss on sale of TBNG) - - - 15,256 582 15,615 (359) 582 Adjusted EBITDAX from continuing operations (2) (3) (4) $ 8,358 $ 7,288 $ 9,389 $ 31,759 $ 40,888 $ 402 $ 4,771 $ 31,357 $ 36,117 TransAtlantic sold TBNG on February 28, 2017 Adjusted EBITDAX from continuing operations ("Adjusted EBITDAX") is a non-GAAP financial measure that represents net (loss) income from continuing operations plus interest and other net, current and deferred income tax expense, exploration, abandonment and impairment, seismic and other exploration expense, foreign exchange (gain) loss, share-based compensation expense, loss (gain) on commodity derivative contracts, cash settlements on commodity derivative contacts, accretion of asset retirement obligation, depreciation, depletion, and amortization, loss on sale of TBNG, and net other items. TransAtlantic believes Adjusted EBITDAX assists management and investors in comparing TransAtlantic's performance on a consistent basis without regard to depreciation, depletion, and amortization and impairment of oil and natural gas properties and exploration expenses, among other items, which can vary significantly from period to period. In addition, management uses Adjusted EBITDAX as a financial measure to evaluate TransAtlantic's operating performance. Adjusted EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income or income from continuing operations prepared in accordance with GAAP. Net income or income from continuing operations may vary materially from Adjusted EBITDAX. Investors should carefully consider the specific items included in the computation of Adjusted EBITDAX.
Reserves Reconciliation (1/4) DeGolyer and MacNaughton did not estimate the Standardized Measure. PV10 and PV20 values of the estimated future net revenue is not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV10 and PV20, while not a financial measure in accordance with U.S. GAAP, provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV10 and PV20 are not measures of financial or operating performance under U.S. GAAP. PV10 and PV20 should not be considered as an alternative to the Standardized Measure as defined under U.S. GAAP. The following table provides a reconciliation of our 1P-PV10 at SEC pricing to our Standardized Measure: Value of Proved Reserves The following table shows our estimated future net revenue of 1P Reserves at SEC Pricing, Standardized Measure, 1P-PV10 at SEC Pricing, 1P-PV10 at forward strip pricing, 2P-PV10 at forward strip pricing, 3P-PV10 at forward strip pricing, and Incremental 3P-PV20 at forward strip pricing as of December 31, 2017: Turkey Total (in thousands) Future net revenue of 1P at SEC pricing $ 411,920 $ 411,920 Total Standardized Measure (1) $ 229,050 $ 229,050 Total 1P-PV10 at SEC pricing (2) $ 266,358 $ 266,358 Total 1P-PV10 at strip pricing (2) $ 336,471 $ 336,471 Total 2P-PV10 at strip pricing (2) $ 569,729 $ 569,729 Total 3P-PV10 at strip pricing (2) $ 815,292 $ 815,292 Incremental 3P-PV20 at strip pricing (2) $ 140,566 $ 140,566 DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure. Turkey Total (in thousands) Total 1P-PV10 $ 266,358 $ 266,358 Future income taxes (1) (51,334 ) (51,334 ) Discount of future income taxes at 10% per annum (1) 14,026 14,026 Standardized Measure (1) $ 229,050 $ 229,050
Reserves Reconciliation (2/4) Prepared Strip Prices to SEC PV10 and SMOG (1) DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure Note: The PV10 value of the estimated future net revenue is not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV10, while not a financial measure in accordance with U.S. GAAP, provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV10 is not a measure of financial or operating performance under U.S. GAAP. PV10 should not be considered as an alternative to the Standardized Measure as defined under U.S. GAAP. The Standardized Measure represents the PV10 after giving effect to income taxes. Proved (1P) (in thousands) Total PV10 at Strip Pricing $ 336,471 Adjustments Relating to Strip Pricing and Terminal Volumes $ (70,112) Total PV10 at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 Proved + Probable (2P) (in thousands) Total 2P PV10 at Strip Pricing $ 569,729 Adjustments Relating to Incremental Probable Volumes $ (233,258) Total Proved (1P) PV10 at Strip Pricing $ 336,471 Adjustments Relating to Strip Pricing and Terminal Volumes $ (70,112) Total PV10 for Proved (1P) at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 Proved + Probable + Possible (3P) (in thousands) PV20 of Incremental Possible at Strip Pricing $ 140,566 Adjustment Relating to Change in Discount Rate from 20% to 10% $ 104,997 PV10 of Incremental Possible at Strip Pricing $ 245,564 Total 2P PV10 at Strip Pricing $ 569,729 Total 3P PV10 at Strip Pricing $ 815,292 Adjustments Relating to Strip Pricing and Terminal Volumes $ (133,770) Total 3P PV10 at SEC Pricing $ 681,522 Adjustments Relating to Incremental Probable and Possible Volumes $ (345,051) Total Proved (1P) PV10 at Strip Pricing $ 336,471 Adjustments Relating to Pricing and Terminal Volumes $ (70,112) Total PV10 for Proved (1P) at SEC Pricing $ 266,358 Future Income Tax Discounted at 10% per annum(1) $ (37,308) Standardized Measure(1) $ 229,050 The following table provides a reconciliation of our 1P-PV10 at forward strip pricing to our Standardized Measure: The following table provides a reconciliation of our 2P-PV10 at forward strip pricing to our Standardized Measure: The following table provides a reconciliation of our 3P-PV20 at forward strip pricing to our Standardized Measure:
Reserves Reconciliation (3/4) Overview – SEC Pricing vs. Forward Strip YE2017 SEC Reserves YE2017 Forward Strip Reserves Liquids Gas Total PV10 PV20 (mmbbls) (Bcf) (mmboe) ($mm) ($mm) Total Proved 14.8 4.2 15.5 266.4 182.0 Total Probable 12.7 2.0 13.0 197.4 114.8 Total Possible 12.6 1.9 12.9 217.8 124.0 Total 1P 14.8 4.2 15.5 266.4 182.0 Total 2P 27.5 6.1 28.5 463.8 296.8 Total 3P 40.1 8.0 41.4 681.5 420.8 Liquids Gas Total PV10 PV20 (mmbbls) (Bcf) (mmboe) ($mm) ($mm) Total Proved 14.9 4.2 15.6 336.5 236.9 Total Probable 12.7 2.0 13.1 233.3 138.0 Total Possible 12.6 1.9 12.9 245.6 140.6 Total 1P 14.9 4.2 15.6 336.5 236.9 Total 2P 27.6 6.1 28.6 569.7 374.9 Total 3P 40.2 8.0 41.6 815.3 515.5
Reserves Reconciliation (4/4) Pricing Data Forward Strip Prices ($) Oil 2018 $67.14 2019 $62.92 2020 $60.14 2021 $58.70 2022 $58.24 2023 $58.14 2024 $58.30 SEC Prices ($) Oil 2016 YE $44.42 2017 YE $58.89