tat-8k_20190326.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported): March 26, 2019

 

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

Bermuda

001-34574

None

(State or other jurisdiction of

(Commission File Number)

(IRS Employer

incorporation)

 

Identification No.)

 

 

 

 

 

16803 Dallas Parkway

Addison, Texas

 

 

 

75001

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (214) 220-4323

 

(Former name or former address, if changed since last report)

 

________________________________

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  

 


 

Item 2.02 Results of Operations and Financial Condition.

On March 26, 2019, TransAtlantic Petroleum Ltd. (the “Company”) issued a press release announcing financial results for the quarter and year ended December 31, 2018 and providing an operations update. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.

The information in Item 2.02 of this Current Report on Form 8-K, including Exhibit 99.1 attached hereto, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing of the Company under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, whether made before or after the date hereof, except as shall be expressly set forth by specific reference to Item 2.02 of this Current Report on Form 8-K in such filing.

Item 7.01 Regulation FD Disclosure.

On March 26, 2019, the Company posted a reserves presentation to its website at www.transatlanticpetroleum.com. A copy of the reserves presentation is attached as Exhibit 99.2 to this Current Report on Form 8-K.

The information in Item 7.02 of this Current Report on Form 8-K, including Exhibit 99.2 attached hereto, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference in any filing of the Company under the Securities Act, or the Exchange Act, whether made before or after the date hereof, except as shall be expressly set forth by specific reference to Item 7.02 of this Current Report on Form 8-K in such filing.

Item 9.01  Financial Statements and Exhibits.

(d) Exhibits.

 

Exhibit No.

Description of Exhibit

99.1

Press release, dated March 26, 2019, issued by TransAtlantic Petroleum Ltd.

99.2

TransAtlantic Petroleum Ltd. Reserves Presentation, dated March 2019

 


2

 


 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

Date:

March 26, 2019

 

 

 

 

 

 

 

 

TRANSATLANTIC PETROLEUM LTD.

 

 

 

 

 

 

By:

/s/ Tabitha T. Bailey

 

 

 

Tabitha T. Bailey

 

 

 

Vice President, General Counsel, and Corporate Secretary

 

 

 

 

 

 

 

3

 

tat-ex991_126.htm

Exhibit 99.1

 

 

TransAtlantic Petroleum Announces Fourth Quarter and Year-End 2018 Financial Results and Provides an Operations Update

 

Hamilton, Bermuda (March 26, 2019) – TransAtlantic Petroleum Ltd. (TSX: TNP) (NYSE American: TAT) (the “Company” or “TransAtlantic”) today announced its financial results for the quarter and year ended December 31, 2018 and provided an operations update. Additional information can be found on the Company’s website at http://www.transatlanticpetroleum.com.

Summary

 

Average daily net sales volumes in the fourth quarter of 2018 were 3,016 barrels of oil equivalent per day (“BOEPD”), up 3% from 2,917 BOEPD in the third quarter of 2018 and up 8% from 2,799 BOEPD in the fourth quarter of 2017. Average daily net sales volumes for 2018 were 2,892 BOEPD, down 8% from 3,144 BOEPD in 2017. The Company’s year-to-date average daily net wellhead production through February 2019 was approximately 3,127 BOEPD, comprised of 3,031 barrels of oil per day (“BOPD”) and 0.6 million cubic feet of natural gas per day (“MMCFPD”).

 

Revenues for 2018 were $70.8 million, up 25% from $56.6 million in 2017. Revenues for the fourth quarter of 2018 were $15.5 million, up 2% from $15.2 million for the fourth quarter of 2017 and down 23% from $20.1 million for the third quarter of 2018. 1

 

Operating income for 2018 was $25.5 million, up 210% from $8.2 million in 2017. Operating income for the fourth quarter of 2018 was $2.8 million, up 47% from $1.9 million for the fourth quarter of 2017 and down 74% from $11.0 million for the third quarter of 2018.

 

Net loss for 2018 was $5.2 million, down 78% from $23.9 million in 2017. Net loss for the fourth quarter of 2018 was $0.7 million, down 82% from $4.0 million for the fourth quarter of 2017 and down 58% from $1.7 million for the third quarter of 2018.

 

Adjusted EBITDAX for 2018 was $37.1 million, up 17% from $31.8 million for 2017. Adjusted EBITDAX for the fourth quarter of 2018 was $6.2 million, down 26% from $8.4 million for the fourth quarter of 2017 and down 55% from $13.9 million for the third quarter of 2018. 2

 

Total debt as of December 31, 2018 was $22.0 million, down 16% from $26.2 million as of September 30, 2018. Net debt as of December 31, 2018 was $12.1 million, down 4% from $12.6 million as of September 30, 2018.3

 

1 

Beginning January 1, 2018, the Company adopted Accounting Standards Update No. 2014-09, Revenue from Contacts with Customers (Topic 606), requiring transportation and processing expenses, which were previously netted from revenue, to be classified as expenses.

2 

Adjusted EBITDAX is a non-GAAP financial measure. See the reconciliation at the end of the press release.

3 

Net debt is a non-GAAP financial measure consisting of total debt as reflected on the Company’s balance sheet minus cash and cash equivalents as reflected on the Company’s balance sheet. For December 31, 2018, total debt was $22.0 million, and cash and cash equivalents was $9.9 million. For September 30, 2018, total debt was $26.2 million, and cash and cash equivalents was $13.6 million.

1


 

Estimated proved reserves as of December 31, 2018 were 10,383 thousand barrels of oil equivalent (“MBOE”), down 33% from 15,476 MBOE as of December 31, 2017. Estimated proved developed reserves as of December 31, 2018 were 5,423 MBOE, up 16% from 4,694 MBOE as of December 31, 2017. Estimated proved undeveloped reserves as of December 31, 2018 were 4,960 MBOE, down 54% from 10,781 MBOE as of December 31, 2017.  

Fourth Quarter 2018 Results of Operations

 

For the Three Months Ended

 

 

December 31, 2018

 

 

September 30, 2018

 

 

December 31, 2017

 

Net Sales:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBBL)

 

270

 

 

 

261

 

 

 

246

 

Natural gas (MMCF)

 

44

 

 

 

45

 

 

 

68

 

Total net sales (MBOE)

 

278

 

 

 

268

 

 

 

258

 

Average net sales (BOEPD)

 

3,016

 

 

 

2,917

 

 

 

2,799

 

Realized Commodity Prices:

 

 

 

 

 

 

 

 

 

 

 

Oil ($/BBL unhedged)

$

56.04

 

 

$

76.32

 

 

$

59.90

 

Oil ($/BBL hedged)

$

54.92

 

 

$

74.36

 

 

$

57.84

 

Natural gas ($/MCF)

$

6.06

 

 

$

4.23

 

 

$

4.41

 

Total revenues were $15.5 million for the three months ended December 31, 2018, as compared to $20.1 million for the three months ended September 30, 2018 and $15.2 million for the three months ended December 31, 2017. The Company had a net loss of $0.7 million, or $0.01 per share (basic and diluted), for the three months ended December 31, 2018, as compared to a net loss of $1.7 million, or $0.03 per share (basic and diluted), for the three months ended September 30, 2018, and $4.0 million, or $0.08 per share (basic and diluted), for the three months ended December 31, 2017. Capital expenditures and seismic and corporate expenditures totaled $6.6 million for the three months ended December 31, 2018, as compared to $6.1 million for the three months ended September 30, 2018 and $3.2 million for the three months ended December 31, 2017.

Adjusted EBITDAX for the three months ended December 31, 2018 was $6.2 million, as compared to $13.9 million for the three months ended September 30, 2018 and $8.4 million for the three months ended December 31, 2017.

2018 Annual Results of Operations

Total revenues were $70.8 million for the twelve months ended December 31, 2018, as compared to $56.6 million for the twelve months December 31, 2017. The Company had a net loss of $5.2 million, or $0.10 per share (basic and diluted), for the twelve months ended December 31, 2018, as compared to a net loss of $23.9 million, or $0.50 per share (basic and diluted), for the twelve months ended December 31, 2017. Capital expenditures and seismic and corporate expenditures totaled $23.8 million for the twelve months

2

 


ended December 31, 2018, as compared to $20.6 million for the twelve months ended December 31, 2017.

Adjusted EBITDAX for the twelve months ended December 31, 2018 was $37.1 million, as compared to $31.8 million for the twelve months ended December 31, 2017.

Impact of Foreign Currency Exchange

The Company’s operations and revenue streams are primarily located in Turkey. Most of the Company’s revenue and capital expenditures are settled in U.S. dollars (“USD”) and most of the Company’s operating expenses are settled in Turkish Lira (“TL”). Under U.S. GAAP reporting standards, the Company converts TL into USD. This currency conversion creates gains and losses that impact the Company’s financial statements.

Income Statement Effect

From December 31, 2017 to December 31, 2018, the TL to the USD declined 39.5%. At December 31, 2018, the exchange rate was 5.2609 TL to 1.00 USD as compared to 3.7719 TL to 1.00 USD at December 31, 2017. This resulted in a foreign exchange loss on the Company’s consolidated statements of comprehensive income (loss) of $10.3 million for the twelve months ended December 31, 2018. Approximately 90.0% of this loss was non-cash.

Balance Sheet Effect

For the twelve months ended December 31, 2018, the devaluation of the TL resulted in a $17.3 million loss recorded to “Accumulated other comprehensive income (loss)”. Oil and gas properties were the most affected asset. For the twelve months ended December 31, 2018, proved and unproved properties had a gross loss of approximately $63.5 million ($218.1 million to $154.6 million as of December 31, 2017 and December 31, 2018, respectively). The decrease on proved properties was partially offset by a reduction in accumulated depletion of $36.0 million ($123.2 million to $87.2 million as of December 31, 2017 and December 31, 2018, respectively). The total accumulated other comprehensive loss as of December 31, 2018 was $142.0 million, all of which was non-cash.

For more information regarding the effects of foreign currency exchange on the Company’s operations and reported financial results, please refer to the Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”), filed with the Securities and Exchange Commission (the “SEC”) on March 26, 2018.

3

 


Liquidity

During 2018, the Company repaid its $30 million term loan (the “2016 Term Loan”) under the Company’s general credit agreement (the “Credit Agreement”) with DenizBank, A.S. (“DenizBank”) in full in accordance with its terms. The Company also entered into a $10.0 million term loan (the “2018 Term Loan”) with DenizBank under the Credit Agreement. The 2018 Term Loan is in addition to the Company’s $20.4 million term loan currently outstanding with Denizbank (the “2017 Term Loan” and together with the 2016 Term Loan and the 2018 Term Loan, the “Term Loans”). Each Term Loan is described in the Company’s periodic reports filed from time to time with the Securities and Exchange Commission.

The Company’s primary sources of liquidity for 2018 were its cash and cash equivalents, cash flow from operations, and borrowings under the 2017 Term Loan and the 2018 Term Loan. At December 31, 2018, the Company had cash and cash equivalents of $9.9 million, no long-term debt, $22.0 million in short-term debt and a working capital surplus of $2.5 million, compared to cash and cash equivalents of $18.9 million, $13.0 million in long-term debt, $15.6 million in short-term debt and a working capital surplus of $12.8 million at December 31, 2017.

As of December 31, 2018, the Company had $22.0 million of debt and $46.1 million of 12% Series A Convertible Redeemable Preferred Shares (the “Series A Preferred Shares”) outstanding.

On February 22, 2019, the Company entered into a $20.0 million term loan (the “2019 Term Loan”) with DenizBank under the Credit Agreement. The 2019 Term Loan is in addition to the 2017 Term Loan and 2018 Term Loan currently outstanding with DenizBank. The 2019 Term Loan will be used for general working capital purposes.

4

 


Reserves Update and Comparison

The following table summarizes net proved, probable, and possible reserves at December 31, 2018 and 2017:

 

2018 Reserves

 

2017 Reserves

 

 

Oil and Condensate

(MBBL)

 

Natural Gas

(MMCF)

 

Total

(MBOE)

 

Oil and Condensate

(MBBL)

 

 

Natural Gas

(MMCF)

 

 

Total

(MBOE)

 

Reserves Category

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved developed

5,047

 

2,256

 

5,423

 

 

4,215

 

 

 

2,877

 

 

 

4,694

 

Proved undeveloped

4,929

 

184

 

4,960

 

 

10,568

 

 

 

1,280

 

 

 

10,781

 

Total proved

9,976

 

2,440

 

10,383

 

 

14,783

 

 

 

4,158

 

 

 

15,476

 

Probable reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Probable developed

901

 

787

 

1,032

 

 

819

 

 

 

788

 

 

 

950

 

Probable undeveloped

4,847

 

30

 

4,852

 

 

11,884

 

 

 

1,177

 

 

 

12,080

 

Total probable

5,748

 

817

 

5,884

 

 

12,702

 

 

 

1,965

 

 

 

13,030

 

Possible reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Possible developed

1,132

 

906

 

1,283

 

 

875

 

 

 

865

 

 

 

1,019

 

Possible undeveloped

5,072

 

32

 

5,077

 

 

11,725

 

 

 

993

 

 

 

11,891

 

Total possible

6,204

 

938

 

6,360

 

 

12,600

 

 

 

1,859

 

 

 

12,910

 

Estimates of reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. For more information regarding estimates of reserves, please refer to the 2018 Form 10-K.

Proved Reserves

At December 31, 2018, estimated proved reserves were 10,383 MBOE, a decrease of 5,093 MBOE, or 33%, compared to 15,476 MBOE at December 31, 2017. This decrease was primarily attributable to revisions of previously estimated recoveries from planned wells in the Selmo field following revisions to the Company’s drilling plans in light of the expiration of the Company’s Selmo production lease in 2025, which resulted in a decrease of 3,680 MBOE, and from planned wells in the Bahar field following the establishment of the oil/water contact for the Bahar field, which resulted in a decrease of 2,618 MBOE. Additionally, proved reserves decreased 1,055 MBOE for volumes sold. This decrease was partially offset by a 2,045 MBOE increase in proved reserves due to the discovery of productive pay in the Yeniev oil field.

5

 


Operational Update

Southeastern Turkey

Molla

Yeniev Field

Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water. In November 2018, the Company spud the East Yeniev-1 appraisal well to further delineate the structure. The well was drilled to a total measured depth of 9,900 feet and encountered hydrocarbon shows in the Mardin and Bedinan formations. Completion operations began in January 2019 and resulted in a discovery in the Mardin formation.

Other

The Company spud the Blackeye-1 well in January 2019. The well was drilled to a total measured depth of 11,105 feet and encountered oil shows in the Hazro, Mardin, and Bedinan formations. Completion operations began in February 2019.

Selmo

The Company completed the initial phase of operations in the Selmo-1 well to re-enter and test the Permian formation, establishing the productivity of the Permian formation. During a short-term flow test of a previously untested interval, the Selmo-1 well tested 45.6 API condensate along with natural gas containing a high carbon dioxide percentage component. While the Selmo-1 well lies in what is interpreted as the gas cap of the structure, the positive test results warrant further testing lower on the structure.

Northwestern Turkey

Thrace Basin BCGA

The Company continues to evaluate its prospects in the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of the recent production test results at the Yamalik-1 exploration well operated by Valeura Energy Inc. (“Valeura”) with its partner Equinor ASA (formerly Statoil ASA) (“Equinor”). The Yamalik-1 exploration well is located on a license directly adjacent to the Company’s 120,000 net acres in the Thrace Basin of which it believes approximately 50,000 net acres (100% working interest, 87.5% net revenue interest) is in the Thrace Basin BCGA and analogous to the Valeura and Equinor acreage.

Subsequent to drilling and testing of the Yamalik-1 well, the joint venture between Valeura and Equinor announced a three-well program. In the first quarter of 2019, Valeura and Equinor announced that they drilled and cased a second well in the Thrace Basin BCGA, the Inanli-1 well. According to Valeura and

6

 


Equinor, the well was drilled to a total depth of 4,885 meters and encountered 1,615 meters of high net-to-gross sandstone, which they interpreted to contain over-pressured gas. Valeura and Equinor announced that they expect to complete the well in the first quarter of 2019. In the first quarter of 2019, Valeura and Equinor announced that they spud the Devepinar-1 appraisal well and drilled it to intermediate casing point at 3,375 meters. According to Valeura and Equinor, the Devepinar-1 appraisal well is designed as a 20-kilometer step-out well to test the lateral extent of the Thrace Basin BCGA.

The Company expects to spud a shallow exploration well on its license in the Thrace Basin in the second quarter of 2019.

Bulgaria

The Company commenced the side-track and re-drilling of the Deventci R-1 well in December 2018, targeting the Ozirovu and Dolmi Dabnik formations. The well was drilled to a total depth of 16,450 feet. Although the Company encountered the targeted formations, tests did not indicate commercial quantities of reservoir quality rock. The Company is currently evaluating future activity in Bulgaria.

Conference Call

The Company will host a live webcast and conference call on Wednesday, March 27, 2019 at 7:30 a.m. Central time (8:30 a.m. Eastern time) to discuss 2018 annual and fourth quarter financial results and provide an operations update. Investors who would like to participate in the conference call should call (877) 878-2762 or (678) 809-1005 approximately ten minutes prior to the scheduled start time and ask for the TransAtlantic conference call. The conference ID is 3986583.

A live webcast of the conference call and replay will be available through the Company’s website at www.transatlanticpetroleum.com. To access the webcast and replay, click on “Investors,” select “Events and Presentations,” and click on “Listen to webcast” under the event list. The webcast requires IOS, Microsoft Windows Media Player, or RealOne Player.

A telephonic replay of the call will be available through March 29, 2019 and may be accessed by dialing (855) 859 -2056 or (404) 537-3406. The conference ID is 3986583.


7

 


TransAtlantic Petroleum Ltd.

Consolidated Statements of Comprehensive Income (Loss)

(U.S. Dollars and shares in thousands, except per share amounts)

 

 

For the Three Months Ended

 

 

For the Twelve Months Ended

 

 

December 31,

 

 

December 31,

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

$

15,409

 

 

$

15,048

 

 

$

70,268

 

 

$

55,523

 

Sales of purchased natural gas

 

 

 

 

 

 

 

 

 

 

654

 

Other

 

116

 

 

 

139

 

 

 

521

 

 

 

462

 

Total revenues

 

15,525

 

 

 

15,187

 

 

 

70,789

 

 

 

56,639

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production

 

2,789

 

 

 

3,451

 

 

 

10,769

 

 

 

12,249

 

Transportation costs

 

1,280

 

 

 

 

 

 

4,665

 

 

 

 

Exploration, abandonment and impairment

 

8

 

 

 

685

 

 

 

401

 

 

 

934

 

Cost of purchased natural gas

 

 

 

 

 

 

 

 

 

 

568

 

Seismic and other exploration

 

149

 

 

 

1,677

 

 

 

489

 

 

 

4,723

 

General and administrative

 

5,057

 

 

 

3,514

 

 

 

14,719

 

 

 

12,817

 

Depreciation, depletion and amortization

 

3,386

 

 

 

3,901

 

 

 

14,059

 

 

 

16,925

 

Accretion of asset retirement obligations

 

50

 

 

 

46

 

 

 

174

 

 

 

190

 

Total costs and expenses

 

12,719

 

 

 

13,274

 

 

 

45,276

 

 

 

48,406

 

Operating income

 

2,806

 

 

 

1,913

 

 

 

25,513

 

 

 

8,233

 

Other (expense) income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss on sale of TBNG

 

 

 

 

 

 

 

 

 

 

(15,226

)

Interest and other expense

 

(2,399

)

 

 

(1,857

)

 

 

(10,048

)

 

 

(8,838

)

Interest and other income

 

240

 

 

 

435

 

 

 

1,082

 

 

 

1,098

 

Gain (loss) on commodity derivative contracts

 

3,359

 

 

 

(2,151

)

 

 

(1,797

)

 

 

(1,852

)

Foreign exchange loss

 

(3,305

)

 

 

(806

)

 

 

(10,292

)

 

 

(1,861

)

Total other expense

 

(2,105

)

 

 

(4,379

)

 

 

(21,055

)

 

 

(26,679

)

Income (loss) before income taxes

 

701

 

 

 

(2,466

)

 

 

4,458

 

 

 

(18,446

)

Current income tax expense

 

(139

)

 

 

(997

)

 

 

(2,820

)

 

 

(2,073

)

Deferred income tax expense

 

(1,277

)

 

 

(576

)

 

 

(6,854

)

 

 

(3,356

)

Net loss

 

(715

)

 

 

(4,039

)

 

 

(5,216

)

 

 

(23,875

)

Other comprehensive income (loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Foreign currency translation adjustment

 

5,962

 

 

 

(6,278

)

 

 

(17,255

)

 

 

15,550

 

Comprehensive income (loss)

$

5,247

 

 

$

(10,317

)

 

$

(22,471

)

 

$

(8,325

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss per common share:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Basic net loss per common share

$

(0.01

)

 

$

(0.08

)

 

$

(0.10

)

 

$

(0.50

)

Weighted average common shares outstanding

 

50,625

 

 

 

50,319

 

 

 

50,505

 

 

 

48,196

 

Diluted net loss per common share

$

(0.01

)

 

$

(0.08

)

 

$

(0.10

)

 

$

(0.50

)

Weighted average common and common equivalent shares outstanding

 

50,625

 

 

 

50,319

 

 

 

50,505

 

 

 

48,196

 

8

 


TransAtlantic Petroleum Ltd.

Summary of Consolidated Statements of Cash Flows

(in thousands of U.S. Dollars)

 

 

For the Twelve Months Ended December 31,

 

 

2018

 

 

2017

 

Net cash provided by operating activities

$

28,695

 

 

$

17,880

 

Net cash (used in) provided by investing activities

 

(26,532

)

 

 

1,935

 

Net cash used in financing activities

 

(6,636

)

 

 

(13,411

)

Effect of exchange rate changes on cash

 

(5,931

)

 

 

(1,044

)

Net (decrease) increase in cash, cash equivalents, and restricted cash

$

(10,404

)

 

$

5,360

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9

 


TransAtlantic Petroleum Ltd.

Summary Consolidated Balance Sheets

(in thousands of U.S. Dollars, except share data)

 

 

December 31, 2018

 

 

December 31, 2017

 

ASSETS

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

Cash and cash equivalents

$

9,892

 

 

$

18,926

 

Accounts receivable, net

 

 

 

 

 

 

 

Oil and natural gas sales

 

12,912

 

 

 

15,808

 

Joint interest and other

 

982

 

 

 

1,576

 

Related party

 

878

 

 

 

1,023

 

Prepaid and other current assets

 

8,696

 

 

 

3,866

 

Note receivable - related party

 

5,828

 

 

 

 

Inventory

 

5,167

 

 

 

7,494

 

Total current assets

 

44,355

 

 

 

48,693

 

Property and equipment:

 

 

 

 

 

 

 

Oil and natural gas properties (successful efforts method)

 

 

 

 

 

 

 

Proved

 

163,006

 

 

 

193,647

 

Unproved

 

15,695

 

 

 

24,445

 

Equipment and other property

 

14,408

 

 

 

14,075

 

 

 

193,109

 

 

 

232,167

 

Less accumulated depreciation, depletion and amortization

 

(105,850

)

 

 

(129,183

)

Property and equipment, net

 

87,259

 

 

 

102,984

 

Other long-term assets:

 

 

 

 

 

 

 

Other assets

 

986

 

 

 

2,247

 

Note receivable - related party

 

 

 

 

6,726

 

Total other assets

 

986

 

 

 

8,973

 

Total assets

$

132,600

 

 

$

160,650

 

 

 

 

 

 

 

 

 

LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

Accounts payable

$

3,896

 

 

$

4,853

 

Accounts payable - related party

 

2,922

 

 

 

3,141

 

Accrued liabilities

 

13,073

 

 

 

10,014

 

Derivative liability

 

 

 

 

2,215

 

Loans payable

 

22,000

 

 

 

15,625

 

Total current liabilities

 

41,891

 

 

 

35,848

 

Long-term liabilities:

 

 

 

 

 

 

 

Asset retirement obligations

 

4,667

 

 

 

4,727

 

Accrued liabilities

 

7,259

 

 

 

8,810

 

Deferred income taxes

 

20,314

 

 

 

19,611

 

Loans payable

 

 

 

 

13,000

 

Total long-term liabilities

 

32,240

 

 

 

46,148

 

Total liabilities

 

74,131

 

 

 

81,996

 

Commitments and contingencies

 

 

 

 

 

 

 

Series A preferred shares, $0.01 par value, 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2018

 

21,300

 

 

 

21,300

 

Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2018

 

24,750

 

 

 

24,750

 

Shareholders’ equity:

 

 

 

 

 

 

 

Common shares, $0.10 par value, 200,000,000 shares authorized; 52,413,588 shares and 50,319,156 shares issued and outstanding as of December 31, 2018 and 2017, respectively

 

5,241

 

 

 

5,032

 

Treasury shares

 

(970

)

 

 

(970

)

Additional paid-in-capital

 

577,488

 

 

 

575,411

 

Accumulated other comprehensive loss

 

(142,021

)

 

 

(124,766

)

Accumulated deficit

 

(427,319

)

 

 

(422,103

)

Total shareholders’ equity

 

12,419

 

 

 

32,604

 

Total liabilities, Series A preferred shares and shareholders’ equity

$

132,600

 

 

$

160,650

 

10

 


Reconciliation of Net Loss to Adjusted EBITDAX (Unaudited)

(in thousands of U.S. Dollars)

 

For the Three Months Ended

 

 

For the Twelve Months Ended

 

 

December 31, 2018

 

 

September 30, 2018

 

 

December 31, 2017

 

 

December 31, 2018

 

 

December 31, 2017

 

Net loss

$

(715

)

 

$

(1,720

)

 

$

(4,039

)

 

$

(5,216

)

 

$

(23,875

)

Adjustments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest and other, net

 

2,159

 

 

 

2,565

 

 

 

1,422

 

 

 

8,966

 

 

 

7,740

 

Income tax expense

 

1,416

 

 

 

5,857

 

 

 

1,573

 

 

 

9,674

 

 

 

5,429

 

Exploration, abandonment, and impairment

 

8

 

 

 

162

 

 

 

685

 

 

 

401

 

 

 

934

 

Seismic and other exploration expense

 

149

 

 

 

122

 

 

 

1,677

 

 

 

489

 

 

 

4,723

 

Foreign exchange loss

 

3,305

 

 

 

2,991

 

 

 

806

 

 

 

10,292

 

 

 

1,861

 

Share-based compensation expense

 

115

 

 

 

122

 

 

 

136

 

 

 

455

 

 

 

692

 

(Gain) loss on derivative contracts

 

(3,359

)

 

 

1,290

 

 

 

2,151

 

 

 

1,797

 

 

 

1,852

 

Cash settlements on commodity derivative contracts

 

(302

)

 

 

(511

)

 

 

-

 

 

 

(4,012

)

 

 

32

 

Accretion of asset retirement obligation

 

50

 

 

 

35

 

 

 

46

 

 

 

174

 

 

 

190

 

Depreciation, depletion, and amortization

 

3,386

 

 

 

2,938

 

 

 

3,901

 

 

 

14,059

 

 

 

16,925

 

Loss on sale of TBNG

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

15,256

 

Adjusted EBITDAX

$

6,212

 

 

$

13,851

 

 

$

8,358

 

 

$

37,079

 

 

$

31,759

 

 

Adjusted EBITDAX (“Adjusted EBITDAX”) is a non-GAAP financial measure that represents net loss plus interest and other income, net, income tax expense, exploration, abandonment, and impairment, seismic and other exploration expense, foreign exchange loss, share-based compensation expense, (gain) loss on derivative contracts, cash settlements on commodity derivative contracts, accretion of asset retirement obligation, depreciation, depletion, and amortization, loss on sale of TBNG, and net other items.

The Company believes Adjusted EBITDAX assists management and investors in comparing the Company’s performance on a consistent basis without regard to depreciation, depletion, and amortization, impairment of oil and natural gas properties, exploration expenses, and foreign exchange gains and losses among other items, which can vary significantly from period to period. In addition, management uses Adjusted EBITDAX as a financial measure to evaluate the Company’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 prepared in accordance with GAAP. Net income or income may vary materially from Adjusted EBITDAX. Investors should carefully consider the specific items included in the computation of Adjusted EBITDAX.

11

 


About TransAtlantic

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 contains statements concerning the Company’s drilling program, the evaluation of the Company’s prospects in southeastern Turkey, the Thrace Basin in northwestern Turkey, and Bulgaria, the drilling, completion, and cost of wells, the production and sale of oil and natural gas, and the holding of an earnings conference call, as well as other expectations, plans, goals, objectives, assumptions, and information about future events, conditions, exploration, production, results of operations, and performance that may constitute forward-looking statements 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.

12

 


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.

Note on BOE

Barrels of oil equivalent, or BOE, are derived by the Company by converting natural gas to oil in the ratio of six thousand cubic feet of natural gas (“MCF”) to one stock tank barrel, or 42 U.S. gallons liquid volume (“BBL”), of oil. A BOE conversion ratio of six MCF to one 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. BOE may be misleading, particularly if used in isolation.

Contacts:

Tabitha T. Bailey

Vice President, General Counsel and Corporate Secretary

(214) 265-4708

 

TransAtlantic Petroleum Ltd.

16803 Dallas Parkway

Addison, Texas 75001

http://www.transatlanticpetroleum.com

 

 

13

 

tat-ex992_9.pptx.htm

Slide 1

March 2019 Year end 2018 reserves presentation Exhibit 99.2

Slide 2

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 TransAtlantic 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, 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, 2018, 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 TransAtlantic assumes 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. This presentation 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, 2018 using forward strip pricing (“YE2018 D&M Strip-Pricing Reserve Report”) and a reserve report prepared by Degolyer & MacNaughton as of December 31, 2018 using SEC pricing (“YE2018 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. 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. TransAtlantic believes 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. Disclaimer 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; 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 TransAtlantic 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, 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, 2018, 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 TransAtlantic assumes 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 offerto 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 otheradvice. 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. This presentation 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 orrecovery 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, 2018 using forward strip pricing (“YE2018 D&M Strip-Pricing Reserve Report”) and a reserve report prepared by Degolyer & MacNaughton as of December 31, 2018 using SEC pricing (“YE2018 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 evidenceindicates 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. Whenprobabilistic 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.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. TransAtlantic believes 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) ofnatural 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 theburner tip and does not represent a value equivalency at the wellhead. 2 | NYSE AMERICAN: TAT TSX: TNP

Slide 3

Oil priceS Year SEC BRENT FWD STRIP   ($/Bbl) ($/Bbl) 2017 YE $54.05 $54.89 2018 YE $72.08 $67.14 2019 $72.08 $55.83 2020 $72.08 $56.77 2021 $72.08 $57.89 2022 $72.08 $58.80 2023 $72.08 $59.99 OIL PRICES SEC VS. FORWARD STRIP PRICES $30.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 $70.00 $45.00 YE2016 YE2017 YE2018 SEC Price Fwd Strip Gas (6-1 Boe) 2017 YE $54.05 $54.89 2018 YE$72.08 $67.14 2019$72.08 $55.83 2020$72.08 $56.77 2021$72.08 $57.89 2022$72.08 $58.80 2023$72.08 $59.99 Year SEC BRENT FWD STRIP ($/Bbl) ($/Bbl) 2016, 2017 vs. 2018 Forward Strip Prices YE2016 FWD STRIP YE2017 FWD STRIP YE2018 FWD STRIP $80.00 $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 2018 2019 2020 2021 2022 2023 2024 2025 3 | NYSE AMERICAN: TAT TSX: TNP

Slide 4

2018 year-end Reserves continuity (SEC) Development plan aligns future capital with growth potential in molla area Based on YE2018 D&M SEC Reserve Report 2018 YEAR-END RESERVES CONTINUITY (SEC) DEVELOPMENT PLAN ALIGNS FUTURE CAPITAL WITH GROWTH POTENTIAL IN MOLLA AREA PROVED RESERVES COMPARISON (SEC) 18.0 16.0 14.0 12.0 10.0 8.0 6.04.02.00.0 MMBOE 15.5 -1.1 -3.7 -2.6 -0.4 8.1 0.2 2.0 10.4 YE2017 Production selmo write-downs bahar write-downs technical revisions 2018 continuity price revisions yeniev reserve adds ye2018 Based on ye2018 D&M SEC Reserve report 4 | NYSE AMERICAN: TAT TSX: TNP

Slide 5

2018 year-end Reserves continuity PROVEN COMPANY RESERVE VALUE STAYS RELATIVELY FLAT IN VOLATILE PRICE ENVIRONMENT Based on YE2018 D&M SEC Reserve Report and YE2018 D&M Strip-Pricing Reserve Report 2018 YEAR-END RESERVES CONTINUITY PROVEN COMPANY RESERVE VALUE STAYS RELATIVELY FLAT IN VOLATILE PRICE ENVIRONMENT PROVED RESERVES VALUE COMPARISON (PV10) 350.0 300.0 250.0 200.0 150.0 100.0 50.0 0.0 MM$ $266.4 -$25.5 -$66.2 -$0.7 $173.9 $86.7 $60.0 $320.6 -$90.4 $230.2 YE2017 SEC selmo write-downs bahar write-downs technical revisions 2018 continuity price revisions yeniev reserve adds ye2018 sec sec to brent fwd revision ye 2018 brent fwd Based on year2018 D&M sec reserve report and ye2018 D&M strip-pricing reserve report 5 | NYSE AMERICAN: TAT TSX: TNP

Slide 6

Overview – sec vs. brent forward strip Reserves (MMBoe) Proved (1P) 1P + Probable (2P) 1P + 2P + Possible (3P) YE2017 15.5 28.5 41.4 Production -1.1 -1.1 -1.1 Adds/Revisions -4.0 -11.2 -17.7 YE2018 10.4 16.3 22.6 Y/Y Change -33% -43% -45% Reserves/Production 9.8 15.3 21.3 Reserves (MMBoe) Proved (1P) 1P + Probable (2P) 1P + 2P + Possible (3P) YE2017 15.5 28.5 41.4 Production -1.1 -1.1 -1.1 Adds/Revisions -4.2 -11.4 -17.9 YE2018 10.2 16.1 22.4 Y/Y Change -34% -44% -46% Reserves/Production 9.6 15.1 21.1 BRENT SEC Reserves snapshot BRENT FORWARD Reserves snapshot Based on YE2018 D&M SEC Reserve Report and YE2018 D&M Strip-Pricing Reserve Report OVERVIEW –SEC VS. BRENT FORWARD STRIP BRENT SEC RESERVES SNAPSHOT Reserves(MMBOE) Proved(1P) 1P + Probable(2P) 1P + 2P + Possible(3P) YE2017 15.5 28.5 41.4 Production -1.1 -1.1 -1.1 Adds/Revisions -4.0 -11.2 -17.7 YE2018 10.4 16.3 22.6 Y/Y Change -33% -43% -45% Reserves/Production 9.8 15.3 21.3 BRENT FORWARD RESERVES SNAPSHOT Reserves (MMBOE) Proved(1P) 1P + Probable(2P) 1P + 2P + Possible(3P) YE2017 15.5 28.5 41.4 Production -1.1-1.1-1.1 Adds/Revisions -4.2-11.4-17.9 YE2018 10.2 16.1 22.4 Y/Y Change-34% -44% -46% Reserves/Production 9.6 15.1 21.1 45.0 40.0 35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 MMBOE 15.5 10.4 28.5 16.3 41.4 22.6 proved (1P) 1P + probable (2P) 1P + 2P + possible (3P) MMBOE 45.0 40.0 35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 15.5 10.2 28.5 16.1 41.4 22.4 Proved (1P) 1P + Probable (2P) 1P + 2P + Possible (3P) Based on ye2018 D&M sec reserve report and ye 2018 D&M strip-pricing reserve report 6 | NYSE AMERICAN: TAT TSX: TNP

Slide 7

TransAtlantic Corporate reserves summary Ye2018 – degolyer & mcnaughton SEC OIL GAS MBOE PV10   BRENT FWD OIL GAS MBOE PV10   (MBO) (MMCF) (MBOE) (M$)     (MBO) (MMCF) (MBOE) (M$) 1P 9,976 2,441 10,383 $320,625   1P 9,822 2,441 10,229 $230,206 2P 15,724 3,258 16,267 $476,481   2P 15,525 3,258 16,068 $348,015 3P 21,928 4,196 22,628 $648,955   3P 21,705 4,196 22,404 $484,416                       SEC OIL GAS MBOE PV10   BRENT FWD OIL GAS MBOE PV10   (MBO) (MMCF) (MBOE) (M$)     (MBO) (MMCF) (MBOE) (M$) PDP 4,575 424 4,645 $168,223   PDP 4,490 424 4,561 $122,816 PDNP 472 1,833 777 $18,882   PDNP 454 1,833 760 $15,354 PUD 4,929 184 4,960 $133,520   PUD 4,877 184 4,908 $92,036 Total Proved 9,976 2,441 10,383 $320,625   Total Proved 9,822 2,441 10,229 $230,206 P2D 901 788 1,033 $33,389   P2D 896 788 1,027 $26,347 P2U 4,847 30 4,852 $122,467   P2U 4,807 30 4,812 $91,461 Total Prob 5,749 817 5,885 $155,856   Total Prob 5,703 817 5,839 $117,809 P3D 1,132 906 1,283 $39,882   P3D 1,129 906 1,280 $31,676 P3U 5,072 32 5,078 $132,592   P3U 5,051 32 5,057 $104,725 Total Poss 6,204 938 6,360 $172,474   Total Poss 6,180 938 6,336 $136,401 Total Developed 7,080 3,950 7,738 $260,377   Total Developed 6,969 3,950 7,627 $196,193 Based on YE2018 D&M SEC Reserve Report and YE2018 D&M Strip-Pricing Reserve Report TRANSATLANTIC CORPORATE RESERVES SUMMARY YE2018 –DEGOLYER & MCNAUGHTON SEC.OIL.GAS.MBOE.PV10.BRENT FWD.OIL.GAS.MBOE.PV10 (MBO).(MMCF).(MBOE).(M$).(MBO).(MMCF).(MBOE).(M$) 1P.9,976.2,441.10,383.$320,625.1P.9,822.2,441.10,229.$230,206 2P.15,724.3,258.16,267.$476,481.2P.15,525.3,258.16,068.$348,015 3P.21,928.4,196.22,628.$648,955.3P.21,705.4,196.22,404.$484,416 SEC.OIL.GAS.MBOE.PV10.BRENT FWD.OIL.GAS.MBOE.PV10 (MBO).(MMCF).(MBOE).(M$).(MBO).(MMCF).(MBOE).(M$) PDP.4,575.424.4,645.$168,223.PDP.4,490.424.4,561.$122,816 PDNP.472.1,833.777.$18,882.PDNP.454.1,833.760.$15,354 PUD.4,929.184.4,960.$133,520.PUD.4,877.184.4,908.$92,036 Total Proved.9,976.2,441.10,383.$320,625.Total Proved.9,822.2,441.10,229.$230,206 P2D.901.788.1,033.$33,389.P2D.896.788.1,027.$26,347 P2U.4,847.30.4,852.$122,467.P2U.4,807.30.4,812.$91,461 Total Prob.5,749.817.5,885.$155,856.Total Prob.5,703.817.5,839.$117,809 P3D.1,132.906.1,283.$39,882.P3D.1,129.906.1,280.$31,676 P3U.5,072.32.5,078.$132,592.P3U.5,051.32.5,057.$104,725 Total Poss.6,204.938.6,360.$172,474.Total Poss.6,180.938.6,336.$136,401 Total Developed.7,080.3,950.7,738.$260,377.Total Developed.6,969.3,950.7,627.$196,193 Based on YE2018 D&M SEC Reserve Report and YE2018 D&M Strip-Pricing Reserve Report 7 | NYSE AMERICAN: TAT TSX: TNP

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Reserves Reconciliation 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 TransAtlantic owns. 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, 2018: DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure. RESERVES RECONCILIATION 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, 2018: forward strip pricing as of (1)DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure. Total (in thousands) Future net revenue of 1P at SEC pricing $ 479,775 Total Standardized Measure (1) $ 266,157 Total 1P-PV10 at SEC pricing (2) $ 320,625 Total 1P-PV10 at strip pricing (2) $ 230,206 Total 2P-PV10 at strip pricing (2) $ 348,015 Total 3P-PV10 at strip pricing (2) $ 484,416 Incremental 3P-PV20 at strip pricing (2) $ 140,566 (1)DeGolyer and MacNaughton did not estimate the Standardized Measure. (2)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 TransAtlanticowns. 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 investorsinevaluating 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: Total (in thousands) Total 1P-PV10 $ 320,625 Future income taxes (1) $ (77,533) Discount of future income taxes at 10% per annum (1) $ 23,065 Standardized Measure $ 266,157 (1)DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum or the Standardized Measure. 8 | NYSE AMERICAN: TAT TSX: TNP

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Reserves Reconciliation (cont.) 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 TransAtlantic owns. 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. 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 (CONT.) PREPARED STRIP PRICES TO SEC PV10 AND SMOG (1) The following table provides a reconciliation of our 1P-PV10 at forward strip pricing to our Standardized Measure: Proved (1P) (in thousands) Total PV10 at strip pricing $ 230,206 Adjustments relating to strip pricing and terminal volumes $ 90,419 Total PV10 at SEC pricing $ 320,625 Future income taxes discounted at 10% per annum $ (54,468) Standardized Measure (1) $ 266,157 The following table provides a reconciliation of our 2P-PV10 at forward strip pricing to our Standardized Measure: Proved + Probable (2P) (in thousands) Total 2P-PV10 at strip pricing $ 348,015 Adjustments relating to strip pricing and terminal volumes $ (117,809) Total 1P-PV10 at strip pricing $ 230,206 Adjustments relating to strip pricing and terminal volumes $ 90,419 Total 1P-PV10 at SEC pricing $ 320,625 Future income taxes discounted at 10% per annum $ (54,468) Standardized Measure (1) $ 266,157 The following table provides a reconciliation of our 3P-PV20 at forward strip pricing to our Standardized Measure: Proved + Probable + Possible (3P) (in thousands) PV20 of incremental possible at strip pricing $ 79,171 Adjustments relating to change in discount rate from 20% to 10% $ 57,230 PV10 of incremental possible at strip pricing $ 136,401 Total 2P-PV10 at strip pricing $ 348,015 Total 3P-PV10 at strip pricing $ 484,416 Adjustments relating to strip pricing and terminal volumes $ 164,539 Total 3P-PV10 at SEC pricing $ 648,955 Adjustments relating to incremental probable and possible volumes $ (418,749) Total 1P-PV10 at strip pricing $ 230,206 Adjustments relating to pricing and terminal volumes $ 90,419 Total 1P-PV10 at SEC pricing $ 320,625 Future income taxes discounted at 10% per annum $ (54,468) Standardized Measure (1) $ 266,157 (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 TransAtlantic owns. Management believes that the presentation of PV10, while not a financial measure in accordance with U.S. GAAP, providesuseful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because manyfactors 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. 9 | NYSE AMERICAN: TAT TSX: TNP

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