![]() 4Q12 Preliminary Financial and Operations Review March 19, 2013 Exhibit 99.2 |
![]() Forward Looking Statements 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; 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, 2011 and our Quarterly Report on Form 10-Q for the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012 available at our website at www.transatlanticpetroleum.com and www.sec.gov. See also TransAtlantic’s 2011 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 as of any future date. 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 the Company. The information published herein is provided for informational purposes only. The Company 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 has generally permitted oil and gas companies, in their filings with the SEC, to disclose only 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 that the SEC’s guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. 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. BOE 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. 2 |
![]() Company Overview TransAtlantic Petroleum Ltd. is an international energy company engaged in the acquisition, development, exploration, and production of crude oil and natural gas in Turkey, Bulgaria and Romania. 3 NYSE-AMEX: Toronto: TAT TNP Share Price (1) : $1.01 Market Cap (1) : $372.6 million Enterprise Value (1) : $390.6 million Proved Reserves (2) : 11.6 MMboe SEC PV10 (3) : $511.0 million (1) Priced as of market close on 3/15/2013. (2) Reflects DeGoyler and MacNaughton (“D&M”) reserve report, effective 12/31/2012 based on $108.30/barrel and $8.94/Mcf. (3) Please see slide 25 for a reconciliation of our PV10 to our standardized measure. Executive Management Chairman & CEO: N. Malone Mitchell, 3rd President: Ian J. Delahunty VP, CFO: Wil F. Saqueton VP, Legal: Jeffrey S. Mecom $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 |
![]() Asset Characteristics 4 (1) Reflects DeGolyer and MacNaughton (“D&M”) reserve report, effective 12/31/2012 based on $108.30/barrel and $8.94/Mcf. BOE conversions are calculated by the Company. Natural Gas 18% Oil 82% Undeveloped 44% Developed 56% Oil 65% Natural Gas 35% Selmo 59% Thrace 35% Other 7% Growth Profile 5,000 Reserve Profile 4Q12 Production Profile (1) 0 10 20 30 40 50 60 70 Possible Probable Proved 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 (1) 80 |
![]() Delayed 10-K 5 As announced in our Press Release yesterday, TransAtlantic needs additional time to file our 2012 Form 10-K, and we have filed Form 12b-25 which provides an additional 15 days to file our Form 10-K • Time extension is due to prior period errors that relate to the allocation of well costs to our depletion schedule during the years 2009 through 2011, which result in the understatement of depletion expense recorded on the Company’s financials for the years 2009 through 2012. Note that depletion expense is a non-cash item. • We are working with our independent registered public accounting firm to evaluate the impact of these prior period errors on both the current and prior period financial statements. • Management and the Board of Directors have already initiated a process to hire a third party accounting consultant to assist and supplement the in-house accounting staff with a thorough review of all prior period accounting and documentation. |
![]() Preliminary 4Q12 Financials 6 • Until we file the 10-K, we can only provide limited financial information • We expect fourth quarter Net Loss from Continuing Operations to be between $20 to $25 million • The fourth quarter included exploration, abandonment and impairment charges of approximately $24 million largely driven by dry holes on several high risk exploration wells including Konak-1 ($9.5mm) and Durukoy-1 ($6.3mm) and impairment of value on several of our unproved property licenses ($7.7mm) • We expect fourth quarter Adjusted EBITDAX from Continuing Operations to be between $22 to $24 million • As of December 31, 2012 • Cash balance of $14.8 million • Long-term debt of $32.8 million • No short-term debt • Credit facility availability of $26.9 million |
![]() 2013 CapEx and Operating Plan 7 $131 Million Capital Budget • Within current cash flow, cash on hand, and credit availability. • Accelerate with consummation of a joint venture Southeast Turkey • Drill horizontal wells to increase productivity. • Expand 2012 discoveries (Goksu, Bahar, and Alibey). • Drill off-structure to evaluate resource play prospectivity. • 3D seismic of Molla blocks (Bahar, Goksu, and Ambar). Northwest Turkey – Thrace Basin • Tekirdag development project – low risk gas production growth – normal pressure gradient. • Hayrabolu – Eight exploration and delineation wells – overpressured below 1,500 meters. • Final exploitation of Edirne blocks (NW Thrace). • Limited development within TPAO joint blocks as they "learn" unconventional potential. • 3D on structure near Thrace area “kitchen.” Other • Sivas Basin – First half of 2013. • Bulgaria – Resume activity summer 2013. |
![]() Management Transition 8 Success of horizontal, unconventional plays drive increased need for drilling and completions team managed and staffed with team leaders with heavy experience in horizontal drilling, multi-stage fracture design, and North American activity pace. Key New Hires/Promotions: Ian Delahunty, President – Completions engineer, US & international experience with Schlumberger, Oxy and TransAtlantic. Mitch Whatley, VP-Drilling – Drilling engineer, extensive horizontal experience with Pioneer (Eagle Ford), Encana (Haynesville and Deep Bossier), and additional industry experience with Marathon and Sidewinder Drilling. Justin Davis, VP-Engineering – Completions engineer, extensive, multi-basin, unconventional experience with Riata, SandRidge, TransAtlantic and Viking. Darcy Dorscher, VP-Production & Facilities – Engineer, extensive international experience in Canada, India, Kazakhstan, Madagascar, Qatar, and Turkey. Geological & Geophysical – Relocated senior personnel to Dallas. |
![]() 1P Reserves Roll-forward 9 YE2011 Production Revisions Discoveries YE2012 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 |
![]() Year-end 3P Reserves Profile and Comparison 10 *Hatched area represents increased 2P/3P independent reserves evaluation disclosed by Valeura Energy, which benefitted from three additional weeks of study/review. 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 2011 Gas 2012 Gas* 2011 Oil 2012 Oil 1P 2P 3P |
![]() Turkey: Activity Overview 11 Thrace Basin Region Summary: Conventional and tight natural gas production with upside potential from deep intervals and technological application. Proved Reserves: 11.1 Bcf (1) 4Q12 Production: 9.2 MMcf/d Thrace Basin Southeast Central Southeast Region Summary: Conventional oil production provides low decline base. Conventional and unconventional upside opportunities. Proved Reserves: 9.7 MMboe (1) 4Q12 Production: 2.9 Mboe/d Central Region Summary: Frontier basins offer under-explored, high potential, oil and gas opportunities Proved Reserves: 0.0 MMboe 4Q12 Production: 0.0 Mboe/d Overview Region Summary: Over 4 million acres in an under-explored region with attractive fiscal terms. Extension of prolific Syrian and Iraqi oil fields in the southeast and established natural gas play in the northwest. Proved Reserves: 11.6 MMboe (1) 4Q12 Production: 4.4 Mboe/d (1) Reflects DeGolyer and MacNaughton (“D&M”) reserve report, effective 12/31/2012 based on $108.30/barrel and $8.94/Mcf. BOE conversions are calculated by the Company. |
![]() Molla: Demonstrating Stacked Pay Potential 12 Demonstrated horizontal success with Goksu 3H over 300 BOPD after ~5 months of production. Vertical discovery (Bahar-1) IP after frac at ~600 BOPD. Horizontal currently drilling. Tested 150 BOPD (Bahar-1). Two cores taken. |
![]() Molla-area Gravity Map 13 * DeGolyer & McNaughton as of 12/31/2012 Goksu: 2P Reserves: 2.9 MMbbls* Field discoveries align well with gravity data. Meaningful running room whether structural or stratigraphic. Kastel Field: EUR 15 MMbbls Bahar: 2P Reserves: 2.5 MMbbls* |
![]() Molla: Mardin Potential and Goksu Discovery 14 * DeGolyer & McNaughton as of 12/31/2012. Molla: Mardin Overview Mardin Formation Fractured Cretaceous carbonate present across the region. Initial vertical discoveries bolstered by recent application of horizontal drilling processes. Total 1P reserves of 0.6 MMbbls*. Total 2P reserves of 2.9 MMbbls*. Goksu-3H Flowing over 300 BOPD after almost 5 months of production. TransAtlantic’s first horizontal completion, 1,600 foot lateral. Drilled and completed for approximately $3.5 million. Goksu-2 Cumulative production nearing 60,000 Bbls. Initial flow rates were 400-500 BOPD in February 2012. Put on 16/64” choke. Stable FTP of 240 psi. |
![]() Molla: Mardin Reserves 15 * DeGolyer & McNaughton as of 12/31/2012. |
![]() Molla: Mardin Horizontal – Ambar Structure 16 |
![]() Molla: Bedinan and Hazro Discovery 17 * DeGolyer & McNaughton as of 12/31/2012. Molla: Bedinan & Hazro Overview Conventional targets immediately above and below Dadas with prospectivity demonstrated via recent discovery well. Bedinan Formation Hazro Formation Shut-in while Hazro tested (150 bopd) Analog Hazro well 27 km north of Bahar-1 with EUR of 1.4 mmbo and 14 bcf. Bahar-1 (TAT operated discovery well) - Hazro tested 150 BOPD. Sandstone directly above the Dada Shale. Horizontal offset currently drilling designed for multi- stage frac completion. Bedinan produced ~600 BOPD (+ high BTU gas) after frac. TAT operated vertical discovery well with 50’ of net pay Normal pressure gradient in southern (shallower) part of the basin at Arpatepe field (25 kms south). Arpatepe Field EUR’s of 200mbo – 400mbo with acid stimulation. Overpressured in central and northern parts of basin. Sandstone immediately below the Dada Shale. Total 2P reserves of 2.5 MMbbls* including 2.1 MMbbls from the Bedinan and 400 Mbbls from the Hazro. Total 1P Reserves of 1.4 MMbbls* including 1.0 MMbbls from the Bedinan and 400 Mbbls from the Hazro. Bahar-1 |
![]() Molla: Bedinan Horizontal – Cataksu-1H 18 Bahar-2H Drilling Curve Now Cataksu-1H Next well in program. Lateral trajectory TBD. |
![]() Selmo Remapping 19 Selmo Overview • Extensive work has been done to remap and model Selmo to identify bypassed oil due to the extremely fractured nature of the field. • New dynamic model incorporates updated substructure mapping with production and pressure histories to determine the areas of the field that will most benefit from a horizontal drilling campaign. • We believe horizontal wellbores will allow pressure drawdown that is more uniform across the length of the wellbore and prevent water coning or premature breakthrough of water. • 2013 budget provides for 4 horizontal wells in the Middle Sinan Dolomite (MSD) and 1 horizontal well in the Lower Sinan Dolomite (LSD). Example Selmo Horizontals |
![]() New License Applications 20 Acquired or applied for seven new licenses totaling over 550k acres. |
![]() Thrace Basin – Mezardere Formation 21 New basin-wide map provides better understanding of source, kitchen, trap, and pressure dynamics. TEKIRDAG |
![]() Thrace Basin Frac: Tekirdag Development Program 22 Development Program Characteristics: • Initial 88-well development program covering approximately 5,000 acres of the Tekirdag Field Area. • Plan 17 wells in Tekirdag area and 8 wells in Hayrabolu during 2013. • Two rig drilling program carries activity into 2015. • Gross well costs expected to range between $2.0 million and $3.0 million, depending upon total depth and completion design. • Gross expected ultimate recovery expected to exceed 70 Bcf (1) . (1) Internal estimate prepared 10/1/12 Tekirdag Hayrabolu |
![]() Thrace Basin Frac: Tekirdag Development Program 23 DTD-19 5-stage frac, flowing back with early choked gas rate > 1 MMcf/d BTD-5 4-stage frac, flowing back with early choked gas rate ~ 1 MMcf/d |
![]() Thrace Basin Frac: Hayrabolu Trend 24 11,000 prospective acres Yildirim-1 2-stage frac, drilling out plugs. Pre-frac instantaneous flow rate of 1.8MMcf/d Kazanci-5 Deepest zone unsuccessful Hayrabolu-10 Drilling Kazanci-5 |
![]() EBITDAX Reconciliation 25 For the three months ended (in millions) Dec 31, 2012 Adjusted EBITDAX from continuing operations $22.0 – $24.0 Subtract: Interest and other, net $1.2 Income tax expense 2.6 Depreciation, depletion, and amortization 11.3-14.3 Accretion of asset retirement obligation 0.1 Exploration, abandonment, and impairment 24.4 Seismic and other exploration 2.4 Other items 2.2 Net loss from continuing operations ($25.2) – ($20.2) * Totals may not sum due to independent rounding This presentation references estimated EBITDAX, which is a non-GAAP financial measure that represents earnings from continuing operations before income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense. The Company believes EBITDAX assists management and investors in comparing the Company’s performance and ability to fund capital expenditures and working capital requirements on a consistent basis without regard to depreciation, depletion and amortization, impairment of natural gas and oil properties and exploration expenses, which can vary significantly from period to period. In addition, management uses EBITDAX as a financial measure to evaluate the Company’s operating performance. EBITDAX is also widely used by investors and rating agencies. EBITDAX is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Information regarding income taxes, interest, depreciation, depletion, amortization, impairment, abandonment and exploration expense is unavailable on a forward looking basis. Net income, income from operations, or cash flow provided by operating activities may vary materially from EBITDAX. Investors should carefully consider the specific items included in the computation of EBITDAX. The Company has disclosed EBITDAX to permit a comparative analysis of its operating performance and debt servicing ability relative to other companies. |
![]() Hedge Profile 26 As of 12/31/2012 775 622 0 831 726 1,016 $100.25 $99.63 $88.44 $0 $25 $50 $75 $100 $125 $150 0 250 500 750 1,000 1,250 1,500 2013 2014 2015 way Collars Collars Floor/Ceiling Mid- point 3- |
![]() PV10 Reconciliation 27 The PV-10 value of the estimated future net revenue are not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV-10, 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. PV-10 is not a measure of financial or operating performance under U.S. GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under U.S. GAAP. US $ thousands Total PV 10: $511,075 Future income taxes: (106,411) Discount of future income taxes at 10% per annum: 31,213 Standardized measure: $435,880 The following table provides a reconciliation of our PV10 to our standardized measure: |
![]() Investor Contact Information Chad W. Potter, CFA VP – Finance / Investor Relations (214) 265-4746 chad.potter@tapcor.com Wil F. Saqueton VP – Chief Financial Officer (214) 265-4743 wil.saqueton@tapcor.com Ian Delahunty President (214) 265-4780 Ian.delahunty@tapcor.com 16803 Dallas Parkway P.O. Box 246 Addison, TX 75001-0246 28 |