Item 1.
|
Financial Statements
|
T
RANS
A
TLANTIC
P
ETROLEUM
L
TD
.
Consolidated Balance Sheets
(in thousands of U.S. dollars, except share data)
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
December 31,
2013
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,161
|
|
|
$
|
12,881
|
|
Accounts receivable
|
|
|
|
|
|
|
|
|
Oil and natural gas sales, net
|
|
|
38,796
|
|
|
|
30,619
|
|
Joint interest and other
|
|
|
5,974
|
|
|
|
15,348
|
|
Related party
|
|
|
192
|
|
|
|
1,004
|
|
Prepaid and other current assets
|
|
|
3,242
|
|
|
|
5,072
|
|
Deferred income taxes
|
|
|
2,666
|
|
|
|
2,239
|
|
Assets held for sale
|
|
|
29
|
|
|
|
536
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
56,060
|
|
|
|
67,699
|
|
|
|
|
|
|
|
|
|
|
Property and equipment:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties (successful efforts method)
|
|
|
|
|
|
|
|
|
Proved
|
|
|
298,369
|
|
|
|
260,857
|
|
Unproved
|
|
|
61,957
|
|
|
|
54,392
|
|
Equipment and other property
|
|
|
41,285
|
|
|
|
39,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
401,611
|
|
|
|
355,165
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(127,761
|
)
|
|
|
(104,193
|
)
|
|
|
|
|
|
|
|
|
|
Property and equipment, net
|
|
|
273,850
|
|
|
|
250,972
|
|
Other long-term assets:
|
|
|
|
|
|
|
|
|
Other assets
|
|
|
9,973
|
|
|
|
8,880
|
|
Note receivable related party
|
|
|
11,500
|
|
|
|
11,500
|
|
Goodwill
|
|
|
7,574
|
|
|
|
7,535
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
29,047
|
|
|
|
27,915
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
358,957
|
|
|
$
|
346,586
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
13,002
|
|
|
$
|
16,712
|
|
Accounts payable - related party
|
|
|
7,697
|
|
|
|
23,090
|
|
Accrued liabilities
|
|
|
16,477
|
|
|
|
20,658
|
|
Derivative liabilities
|
|
|
8,279
|
|
|
|
3,737
|
|
Asset retirement obligations
|
|
|
397
|
|
|
|
610
|
|
Loan payable
|
|
|
28,288
|
|
|
|
43,284
|
|
Liabilities held for sale
|
|
|
7,533
|
|
|
|
7,559
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
81,673
|
|
|
|
115,650
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
10,830
|
|
|
|
10,286
|
|
Accrued liabilities
|
|
|
6,785
|
|
|
|
6,487
|
|
Deferred income taxes
|
|
|
19,018
|
|
|
|
16,134
|
|
Loan payable
|
|
|
59,766
|
|
|
|
26,482
|
|
Derivative liabilities
|
|
|
5,716
|
|
|
|
4,230
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities
|
|
|
102,115
|
|
|
|
63,619
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
183,788
|
|
|
|
179,269
|
|
Commitments and contingencies
|
|
|
|
|
|
|
|
|
Shareholders equity:
|
|
|
|
|
|
|
|
|
Common shares, $0.10 par value, 100,000,000 shares authorized; 37,447,909 shares issued and outstanding as of June 30, 2014 and
37,340,206 shares issued and outstanding as of December 31, 2013
|
|
|
3,745
|
|
|
|
3,734
|
|
Additional paid-in capital
|
|
|
542,725
|
|
|
|
542,091
|
|
Accumulated other comprehensive loss
|
|
|
(63,188
|
)
|
|
|
(64,985
|
)
|
Accumulated deficit
|
|
|
(308,113
|
)
|
|
|
(313,523
|
)
|
|
|
|
|
|
|
|
|
|
Total shareholders equity
|
|
|
175,169
|
|
|
|
167,317
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity
|
|
$
|
358,957
|
|
|
$
|
346,586
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
1
T
RANS
A
TLANTIC
P
ETROLEUM
L
TD
.
Consolidated Statements of Comprehensive Income (Loss)
(Unaudited)
(U.S. dollars and shares in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30,
|
|
|
For the Six Months Ended
June 30,
|
|
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
40,441
|
|
|
$
|
29,455
|
|
|
$
|
73,425
|
|
|
$
|
62,180
|
|
Sales of purchased natural gas
|
|
|
491
|
|
|
|
719
|
|
|
|
1,036
|
|
|
|
1,525
|
|
Other
|
|
|
129
|
|
|
|
342
|
|
|
|
246
|
|
|
|
855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
41,061
|
|
|
|
30,516
|
|
|
|
74,707
|
|
|
|
64,560
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
4,666
|
|
|
|
3,328
|
|
|
|
8,797
|
|
|
|
8,855
|
|
Exploration, abandonment and impairment
|
|
|
3,775
|
|
|
|
11,885
|
|
|
|
7,916
|
|
|
|
15,749
|
|
Cost of purchased natural gas
|
|
|
440
|
|
|
|
619
|
|
|
|
925
|
|
|
|
1,331
|
|
Seismic and other exploration
|
|
|
892
|
|
|
|
1,090
|
|
|
|
4,186
|
|
|
|
1,333
|
|
Revaluation of contingent consideration
|
|
|
|
|
|
|
(5,000
|
)
|
|
|
(2,500
|
)
|
|
|
(5,000
|
)
|
General and administrative
|
|
|
7,460
|
|
|
|
6,893
|
|
|
|
14,012
|
|
|
|
14,416
|
|
Depreciation, depletion and amortization
|
|
|
12,588
|
|
|
|
9,581
|
|
|
|
22,678
|
|
|
|
18,557
|
|
Accretion of asset retirement obligations
|
|
|
106
|
|
|
|
124
|
|
|
|
204
|
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
29,927
|
|
|
|
28,520
|
|
|
|
56,218
|
|
|
|
55,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
11,134
|
|
|
|
1,996
|
|
|
|
18,489
|
|
|
|
9,066
|
|
Other (expense) income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest and other expense
|
|
|
(1,769
|
)
|
|
|
(955
|
)
|
|
|
(2,972
|
)
|
|
|
(1,845
|
)
|
Interest and other income
|
|
|
327
|
|
|
|
307
|
|
|
|
600
|
|
|
|
682
|
|
(Loss) gain on commodity derivative contracts
|
|
|
(9,522
|
)
|
|
|
4,278
|
|
|
|
(8,560
|
)
|
|
|
3,502
|
|
Foreign exchange gain (loss)
|
|
|
2,494
|
|
|
|
(2,543
|
)
|
|
|
1,150
|
|
|
|
(3,030
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other (expense) income
|
|
|
(8,470
|
)
|
|
|
1,087
|
|
|
|
(9,782
|
)
|
|
|
(691
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
2,664
|
|
|
|
3,083
|
|
|
|
8,707
|
|
|
|
8,375
|
|
Current income tax expense
|
|
|
(838
|
)
|
|
|
(528
|
)
|
|
|
(907
|
)
|
|
|
(1,867
|
)
|
Deferred income tax (expense) benefit
|
|
|
(389
|
)
|
|
|
348
|
|
|
|
(2,370
|
)
|
|
|
(573
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
1,437
|
|
|
|
2,903
|
|
|
|
5,430
|
|
|
|
5,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
(93
|
)
|
Net income
|
|
$
|
1,437
|
|
|
$
|
2,903
|
|
|
$
|
5,410
|
|
|
$
|
5,842
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment
|
|
|
5,092
|
|
|
|
(13,543
|
)
|
|
|
1,797
|
|
|
|
(16,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
6,529
|
|
|
$
|
(10,640
|
)
|
|
$
|
7,207
|
|
|
$
|
(10,537
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.04
|
|
|
$
|
0.08
|
|
|
$
|
0.15
|
|
|
$
|
0.16
|
|
Discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
Weighted average common shares outstanding
|
|
|
37,411
|
|
|
|
36,893
|
|
|
|
37,402
|
|
|
|
36,891
|
|
Diluted net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.04
|
|
|
$
|
0.08
|
|
|
$
|
0.15
|
|
|
$
|
0.16
|
|
Discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
Weighted average common and common equivalent shares outstanding
|
|
|
37,411
|
|
|
|
36,893
|
|
|
|
37,402
|
|
|
|
36,891
|
|
The accompanying notes are an integral part of these consolidated financial statements.
2
T
RANS
A
TLANTIC
P
ETROLEUM
L
TD
.
Consolidated Statements of Equity
(Unaudited)
(U.S. dollars and shares in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Shares
|
|
|
Common
Shares ($)
|
|
|
Additional
Paid-in
Capital
|
|
|
Accumulated
Other
Comprehensive
Loss
|
|
|
Accumulated
Deficit
|
|
|
Total
Shareholders
Equity
|
|
Balance at December 31, 2013
|
|
|
37,340
|
|
|
$
|
3,734
|
|
|
$
|
542,091
|
|
|
$
|
(64,985
|
)
|
|
$
|
(313,523
|
)
|
|
$
|
167,317
|
|
Issuance of restricted stock units
|
|
|
108
|
|
|
|
11
|
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
|
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
713
|
|
Tax withholding on restricted stock units
|
|
|
|
|
|
|
|
|
|
|
(68
|
)
|
|
|
|
|
|
|
|
|
|
|
(68
|
)
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,797
|
|
|
|
|
|
|
|
1,797
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,410
|
|
|
|
5,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2014
|
|
|
37,448
|
|
|
$
|
3,745
|
|
|
$
|
542,725
|
|
|
$
|
(63,188
|
)
|
|
$
|
(308,113
|
)
|
|
$
|
175,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
3
T
RANS
A
TLANTIC
P
ETROLEUM
L
TD
.
Consolidated Statements of Cash Flows
(Unaudited)
(in
thousands of U.S. dollars)
|
|
|
|
|
|
|
|
|
|
|
For the Six Months
Ended June 30,
|
|
|
|
2014
|
|
|
2013
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
5,410
|
|
|
$
|
5,842
|
|
Adjustment for net loss from discontinued operations
|
|
|
20
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
5,430
|
|
|
|
5,935
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
713
|
|
|
|
881
|
|
Foreign currency loss
|
|
|
74
|
|
|
|
2,138
|
|
Loss (gain) on commodity derivative contracts
|
|
|
8,560
|
|
|
|
(3,502
|
)
|
Cash settlement on commodity derivative contracts
|
|
|
(2,533
|
)
|
|
|
(1,736
|
)
|
Amortization of loan financing costs
|
|
|
764
|
|
|
|
256
|
|
Deferred income tax expense
|
|
|
2,370
|
|
|
|
573
|
|
Exploration, abandonment and impairment
|
|
|
7,916
|
|
|
|
15,749
|
|
Depreciation, depletion and amortization
|
|
|
22,678
|
|
|
|
18,557
|
|
Accretion of asset retirement obligations
|
|
|
204
|
|
|
|
253
|
|
Revaluation of contingent consideration
|
|
|
(2,500
|
)
|
|
|
(5,000
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
2,215
|
|
|
|
10,432
|
|
Prepaid expenses and other assets
|
|
|
2,056
|
|
|
|
141
|
|
Accounts payable and accrued liabilities
|
|
|
(6,487
|
)
|
|
|
11,045
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities from continuing operations
|
|
|
41,460
|
|
|
|
55,722
|
|
Net cash used in operating activities from discontinued operations
|
|
|
(64
|
)
|
|
|
(1,071
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
41,396
|
|
|
|
54,651
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties
|
|
|
(62,993
|
)
|
|
|
(52,320
|
)
|
Additions to equipment and other properties
|
|
|
(2,589
|
)
|
|
|
(7,925
|
)
|
Restricted cash
|
|
|
|
|
|
|
(206
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities from continuing operations
|
|
|
(65,582
|
)
|
|
|
(60,451
|
)
|
Net cash provided by investing activities from discontinued operations
|
|
|
500
|
|
|
|
1,016
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(65,082
|
)
|
|
|
(59,435
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
Tax withholding on restricted stock units
|
|
|
(68
|
)
|
|
|
|
|
Loan proceeds
|
|
|
26,092
|
|
|
|
22,885
|
|
Loan repayment
|
|
|
(7,804
|
)
|
|
|
(15,885
|
)
|
Loan financing costs
|
|
|
(2,176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities from continuing operations
|
|
|
16,044
|
|
|
|
7,000
|
|
Effect of exchange rate changes on cash
|
|
|
(78
|
)
|
|
|
(1,064
|
)
|
Net (decrease) increase in cash and cash equivalents
|
|
|
(7,720
|
)
|
|
|
1,152
|
|
Cash and cash equivalents, beginning of period
|
|
|
12,881
|
|
|
|
14,768
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
5,161
|
|
|
$
|
15,920
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosures:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
1,212
|
|
|
$
|
1,539
|
|
|
|
|
|
|
|
|
|
|
Cash paid for taxes
|
|
$
|
|
|
|
$
|
1,448
|
|
|
|
|
|
|
|
|
|
|
Supplemental non-cash financing activities:
|
|
|
|
|
|
|
|
|
Repayment of amended and restated credit facility from refinancing
|
|
$
|
49,766
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
4
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements
(Unaudited)
1. General
Nature of operations
TransAtlantic Petroleum Ltd. (together with its subsidiaries, we, us, our, the Company or
TransAtlantic) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, have
stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed
and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of August 1, 2014, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our
board of directors.
Basis of presentation
Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally
accepted in the United States (U.S. GAAP). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and
estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates,
including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may
result in revised estimates and actual results may differ from these estimates.
Certain information and footnote disclosures normally included in the
consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). These
consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2013.
2. Recent accounting pronouncements
In April 2014, the Financial Accounting Standard Board (FASB) issued Accounting Standards Update (ASU) 2014-08,
Reporting Discontinued Operations and Disclosures of Components of an Entity
(ASU 2014-08). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of
an entity that represent strategic shifts that have (or will have) a major effect on an entitys operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the
disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant
component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a
material impact on our consolidated financial statements or results of operations.
In May 2014, the FASB issued ASU 2014-09,
Revenue from
Contracts with Customers
(ASU 2014-09). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to
a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential
impact of ASU 2014-09 on our consolidated financial statements and results of operations.
We have reviewed other recently issued, but not yet adopted,
accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on
current or future earnings or operations.
5
3. Property and equipment
Oil and natural gas properties
The following table sets forth the capitalized costs under the successful efforts method for our oil and natural gas properties as of:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
December 31, 2013
|
|
|
|
(in thousands)
|
|
Oil and natural gas properties, proved:
|
|
|
|
|
|
|
|
|
Turkey
|
|
$
|
297,748
|
|
|
$
|
260,232
|
|
Bulgaria
|
|
|
621
|
|
|
|
625
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties, proved
|
|
|
298,369
|
|
|
|
260,857
|
|
Oil and natural gas properties, unproved:
|
|
|
|
|
|
|
|
|
Turkey
|
|
|
57,502
|
|
|
|
51,273
|
|
Bulgaria
|
|
|
4,455
|
|
|
|
3,119
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas properties, unproved
|
|
|
61,957
|
|
|
|
54,392
|
|
|
|
|
|
|
|
|
|
|
Gross oil and natural gas properties
|
|
|
360,326
|
|
|
|
315,249
|
|
Accumulated depletion
|
|
|
(119,373
|
)
|
|
|
(96,958
|
)
|
|
|
|
|
|
|
|
|
|
Net oil and natural gas properties
|
|
$
|
240,953
|
|
|
$
|
218,291
|
|
|
|
|
|
|
|
|
|
|
At June 30, 2014 and December 31, 2013, we excluded $0.7 million and $1.5 million, respectively, from the depletion
calculation for proved development wells currently in progress and for costs associated with fields currently not in production.
At June 30, 2014,
the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $32.6 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved
reserves, and $146.2 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.
At December 31, 2013, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $35.5 million relating to
acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $126.9 million relating to well costs and additional development costs, which are being depleted by the
unit-of-production method using proved developed reserves.
Impairment and dry hole costs
During the three and six months ended June 30, 2014, we recorded $3.8 million and $7.9 million of impairment and exploratory dry hole costs, respectively.
Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $3.5 million related to impairment on one well in the first quarter of 2014 and $2.8 million related to impairment of the Kazanci-5 well in the second quarter of
2014. Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $1.4 million was cash spent during the period.
Capitalized cost greater than one year
As of
June 30, 2014, we had $1.7 million of exploratory well costs capitalized for the Hayrabolu-10 well, which we spud in February 2013. The Hayrabolu-10 well continues to be evaluated for completion pending more analysis and comparable well
results.
Equipment and other property
The
historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
December 31, 2013
|
|
|
|
(in thousands)
|
|
Other equipment
|
|
$
|
3,944
|
|
|
$
|
2,678
|
|
Inventory
|
|
|
24,811
|
|
|
|
24,318
|
|
Gas gathering system and facilities
|
|
|
4,508
|
|
|
|
4,485
|
|
Vehicles
|
|
|
347
|
|
|
|
321
|
|
Leasehold improvements, office equipment and software
|
|
|
7,675
|
|
|
|
8,114
|
|
|
|
|
|
|
|
|
|
|
Gross equipment and other property
|
|
|
41,285
|
|
|
|
39,916
|
|
Accumulated depreciation
|
|
|
(8,388
|
)
|
|
|
(7,235
|
)
|
|
|
|
|
|
|
|
|
|
Net equipment and other property
|
|
$
|
32,897
|
|
|
$
|
32,681
|
|
|
|
|
|
|
|
|
|
|
6
We classify our materials and supply inventory, including steel tubing and casing, as long-term assets because
such materials will ultimately be classified as long-term assets when the material is used in the drilling of a well.
At June 30, 2014, we excluded
$24.8 million of inventory and $1.2 million of software from depreciation as the inventory and software had not been placed into service. At December 31, 2013, we excluded $24.3 million of inventory and $0.7 million of software from
depreciation as the inventory and software had not been placed into service.
4. Asset retirement obligations
The following table summarizes the changes in our asset retirement obligations (ARO) for the six months ended June 30,
2014 and for the year ended December 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
December 31, 2013
|
|
|
|
(in thousands)
|
|
Asset retirement obligations at beginning of period
|
|
$
|
10,896
|
|
|
$
|
11,958
|
|
Change in estimates
|
|
|
|
|
|
|
(7
|
)
|
Liabilities settled
|
|
|
(212
|
)
|
|
|
(296
|
)
|
Foreign exchange change effect
|
|
|
53
|
|
|
|
(2,258
|
)
|
Additions
|
|
|
286
|
|
|
|
991
|
|
Accretion expense
|
|
|
204
|
|
|
|
508
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at end of period
|
|
|
11,227
|
|
|
|
10,896
|
|
Less: current portion
|
|
|
397
|
|
|
|
610
|
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
10,830
|
|
|
$
|
10,286
|
|
|
|
|
|
|
|
|
|
|
Our ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement
include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.
5. Commodity derivative instruments
We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of a
portion of our future oil production. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.
To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance
sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the
caption (Loss) gain on commodity derivative contracts. Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption Cash settlement on commodity derivative
contracts. We are required under our senior secured credit facility (the Senior Credit Facility) with BNP Paribas (Suisse) SA (BNP Paribas) and the International Finance Corporation (IFC) to hedge at least
30% of our anticipated oil production volumes in Turkey.
In May 2014, we novated our existing commodity derivative contracts with Standard Bank Plc
(Standard Bank) and BNP Paribas and entered into new commodity derivative contracts with BNP Paribas. During the three months ended June 30, 2014, we recognized a $0.7 million realized loss on the unwinding of these commodity
derivative contracts, which is included in our consolidated statement of comprehensive income (loss) under the caption (Loss) gain on commodity derivative contracts.
7
During the three months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative
contracts of $9.5 million and a net gain of $4.3 million, respectively. During the six months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative contracts of $8.6 million and a net gain of $3.5 million, respectively.
At June 30, 2014 and December 31, 2013, we had outstanding contracts with respect to our future crude oil production as set forth in the tables
below:
Fair Value of Derivative Instruments as of June 30, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
Period
|
|
|
Quantity
(Bbl/day)
|
|
|
Weighted
Average
Minimum
Price (per Bbl)
|
|
|
Weighted
Average
Maximum Price
(per Bbl)
|
|
|
Estimated Fair
Value of Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Collar
|
|
|
July 1, 2014December 31, 2014
|
|
|
|
1,770
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
$
|
(4,758
|
)
|
Collar
|
|
|
January1, 2015December 31, 2015
|
|
|
|
1,410
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
|
(6,027
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(10,785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
Additional Call
|
|
|
|
|
Type
|
|
Period
|
|
|
Quantity
(Bbl/day)
|
|
|
Weighted
Average
Minimum
Price
(per Bbl)
|
|
|
Weighted
Average
Maximum
Price
(per Bbl)
|
|
|
Weighted
Average
Maximum
Price
(per Bbl)
|
|
|
Estimated Fair
Value of
Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Three-way collar contract
|
|
|
January 1, 2016December 31, 2016
|
|
|
|
1,066
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
$
|
114.25
|
|
|
$
|
(2,057
|
)
|
Three-way collar contract
|
|
|
January 1, 2017December 31, 2017
|
|
|
|
888
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
$
|
114.25
|
|
|
|
(851
|
)
|
Three-way collar contract
|
|
|
January 1, 2018December 31, 2018
|
|
|
|
726
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
$
|
114.25
|
|
|
|
(282
|
)
|
Three-way collar contract
|
|
|
January 1, 2019March 31, 2019
|
|
|
|
663
|
|
|
$
|
85.00
|
|
|
$
|
97.25
|
|
|
$
|
114.25
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(3,210
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Instruments as of December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Type
|
|
Period
|
|
|
Quantity
(Bbl/day)
|
|
|
Weighted
Average
Minimum
Price (per Bbl)
|
|
|
Weighted
Average
Maximum Price
(per Bbl)
|
|
|
Estimated Fair
Value of Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Collar
|
|
|
January 1, 2014December 31, 2014
|
|
|
|
622
|
|
|
$
|
80.83
|
|
|
$
|
118.07
|
|
|
$
|
(387
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(387
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars
|
|
|
Additional Call
|
|
|
|
|
Type
|
|
Period
|
|
|
Quantity
(Bbl/day)
|
|
|
Weighted
Average
Minimum
Price
(per Bbl)
|
|
|
Weighted
Average
Maximum
Price
(per Bbl)
|
|
|
Weighted
Average
Maximum
Price
(per Bbl)
|
|
|
Estimated Fair
Value of
Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Three-way collar contract
|
|
|
January 1, 2014December 31, 2014
|
|
|
|
726
|
|
|
$
|
85.00
|
|
|
$
|
97.13
|
|
|
$
|
162.13
|
|
|
$
|
(3,350
|
)
|
Three-way collar contract
|
|
|
January 1, 2015December 31, 2015
|
|
|
|
1,016
|
|
|
$
|
85.00
|
|
|
$
|
91.88
|
|
|
$
|
151.88
|
|
|
|
(4,230
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(7,580
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet presentation
The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even
when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at June 30, 2014 and December 31, 2013, and (ii) the net recorded fair value as
reflected on our consolidated balance sheets at June 30, 2014 and December 31, 2013.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2014
|
|
Underlying commodity
|
|
Location on Balance Sheet
|
|
|
Gross
Amount of
Recognized
Liabilities
|
|
|
Gross
Amount
Offset in the
Consolidated
Balance
Sheet
|
|
|
Net Amount of
Liabilities
Presented in the
Consolidated
Balance Sheet
|
|
|
|
|
|
|
(in thousands)
|
|
Crude oil
|
|
|
Current liabilities
|
|
|
$
|
8,279
|
|
|
$
|
|
|
|
$
|
8,279
|
|
Crude oil
|
|
|
Long-term liabilities
|
|
|
$
|
5,716
|
|
|
$
|
|
|
|
$
|
5,716
|
|
|
|
|
|
|
|
|
|
As of December 31, 2013
|
|
Underlying commodity
|
|
Location on Balance Sheet
|
|
|
Gross
Amount of
Recognized
Liabilities
|
|
|
Gross
Amount
Offset in the
Consolidated
Balance
Sheet
|
|
|
Net Amount of
Liabilities
Presented in the
Consolidated
Balance Sheet
|
|
|
|
|
|
|
(in thousands)
|
|
Crude oil
|
|
|
Current liabilities
|
|
|
$
|
3,737
|
|
|
$
|
|
|
|
$
|
3,737
|
|
Crude oil
|
|
|
Long-term liabilities
|
|
|
$
|
4,230
|
|
|
$
|
|
|
|
$
|
4,230
|
|
9
6. Loan payable
As of the dates indicated, our third-party debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
|
December 31,
2013
|
|
Floating Rate Debt
|
|
(in thousands)
|
|
Amended and Restated Credit Facility
|
|
$
|
|
|
|
$
|
49,766
|
|
Senior Credit Facility
|
|
|
59,766
|
|
|
|
|
|
TBNG credit facility
|
|
|
26,700
|
|
|
|
20,000
|
|
Unsecured lines of credit
|
|
|
1,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loan payable
|
|
|
88,054
|
|
|
|
69,766
|
|
Less: current portion
|
|
|
28,288
|
|
|
|
43,284
|
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
59,766
|
|
|
$
|
26,482
|
|
|
|
|
|
|
|
|
|
|
Amended and Restated Credit Facility
On May 18, 2011, DMLP, Ltd. (DMLP), TransAtlantic Exploration Mediterranean International Pty Ltd (TEMI), Talon Exploration, Ltd.
(Talon Exploration), TransAtlantic Turkey, Ltd. (TransAtlantic Turkey) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (Petrogas) (collectively, and together with
Amity Oil International Pty Ltd (Amity), the Borrowers) entered into an amended and restated credit facility (the Amended and Restated Credit Facility) with Standard Bank and BNP Paribas. Each of the Borrowers is
our wholly owned subsidiary. In July 2011, Amity executed a joinder agreement and became a borrower under the Amended and Restated Credit Facility. The Amended and Restated Credit Facility was guaranteed by us and each of TransAtlantic Petroleum
(USA) Corp. and TransAtlantic Worldwide, Ltd. (TransAtlantic Worldwide). On May 6, 2014, we entered into the new Senior Credit Facility and, on May 15, 2014, we repaid the Amended and Restated Credit Facility in full and it was
terminated.
Senior Credit Facility
On
May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp.
and TransAtlantic Worldwide (each, a Guarantor).
The amount drawn under the Senior Credit Facility may not exceed the lesser of
(i) $150.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate
amount of such lenders individual commitment. The lenders have an initial aggregate commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of
$150.0 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1,
2016.
The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The
current borrowing base is $74.6 million. The borrowing base amount equals, for any calculation date, the lowest of:
|
|
|
the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00; and
|
|
|
|
the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00.
|
The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that
immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of
hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of
up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such
lenders individual commitment.
10
Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum
(5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the aggregate
commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount
under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and
(iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit
issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.
The Senior Credit Facility is secured by a
pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower and (iv) substantially all of the
present and future assets of the Borrowers.
The Borrowers are required to comply with certain financial and non-financial covenants under the Senior
Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:
|
|
|
ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;
|
|
|
|
ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Senior Credit Facility of not less than 1.50 to 1.00;
|
|
|
|
ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and
|
|
|
|
ratio of total debt to EBITDAX of less than 2.50 to 1.00.
|
The Senior Credit Facility defines EBITDAX as net
income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated intercompany
debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary,
unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and
geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in calculating net
income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.
Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall
cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens,
(iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of
investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as
necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change
its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon
licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the
territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans
as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.
An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain
covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is
an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly,
day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated
in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases
11
for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of
our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares
entitled to vote for members of our board of directors on a fully-diluted basis; provided, that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an
event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.
As of
July 1, 2014, we had outstanding borrowings of $59.8 million under the Senior Credit Facility and availability of $14.8 million.
TBNG credit
facility
On June 18, 2013, our wholly owned subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (TBNG), entered into a
78.8 million New Turkish Lira (TRY) (approximately $37.1 million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available
in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate is established at the time of each borrowing. We have made three borrowings under this
credit facility, on October 9, 2013, November 5, 2013 and January 22, 2014, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at
then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility.
Unsecured lines of credit
Our wholly owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At
June 30, 2014, we had outstanding borrowings of $1.6 million under these lines of credit.
7. Contingencies relating to production leases and exploration permits
Selmo
We are involved in
litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate the
potential additional operating costs we would incur in the event the purported surface owners claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.
Morocco
In the second quarter of 2012, we were
notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee
that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our
Tselfat exploration permit during 2012 for this contingency.
Aglen
In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under
our Aglen exploration permit work program. Due to the Bulgarian governments January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by the government.
Although we invoked force majeure, we recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during 2012 for this contractual obligation.
Direct Petroleum
In July 2013, we entered into a
second amendment (the Amendment) to the purchase agreement (the Purchase Agreement) with Direct Petroleum Exploration, LLC (Direct). The Amendment set forth a new obligation to drill and test the Deventci-R2 well
by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our
consolidated statements of comprehensive income (loss) under the caption Revaluation of contingent consideration during the six months ended June 30, 2014.
In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the
Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2014, we had not recorded a contingent liability for this contingent
consideration. Any adjustment will be recorded when it becomes probable and estimable.
Additionally, the Amendment provides that if the Bulgarian
government issues a production concession over the stefenetz concession area (the Stefenetz Concession Area), Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is
less than 200,000 acres. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be
recorded when it becomes probable and estimable.
12
8. Shareholders equity
Reverse stock split
On
March 4, 2014, our shareholders approved a 1-for-10 reverse stock split, which became effective March 6, 2014. Pursuant to the reverse stock split, all shareholders of record received one common share for each ten common shares owned
(subject to minor adjustments as a result of fractional shares). The reverse stock split reduced the issued and outstanding common shares as of March 4, 2014 from 374,026,984 to 37,402,698. U.S. GAAP requires that the reverse stock split be
applied retrospectively to all periods presented. As a result, all common share amounts and transactions herein have been adjusted to reflect the 1-for-10 reverse stock split.
Restricted stock units
Share-based compensation
expense of approximately $0.3 million and $0.7 million with respect to awards of restricted stock units (RSUs) was recorded for the three and six months ended June 30, 2014, respectively. We recorded share-based compensation expense
of $0.5 million and $0.9 million for the three and six months ended June 30, 2013, respectively.
As of June 30, 2014, we had approximately $1.4
million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.
Earnings per share
We account for earnings per
share in accordance with Accounting Standards Codification (ASC) Subtopic 260-10,
Earnings Per Share
(ASC 260-10). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted.
Basic earnings per common share for the three and six months ended June 30, 2014 and 2013 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted
average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and six months ended June 30, 2014 and 2013 are computed in the same manner as basic earnings per common share after assuming the
issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs. For the three and six months ended June 30, 2014 and 2013, there were no dilutive securities included in the calculation of diluted earnings
per share.
The following table presents the basic and diluted earnings per common share computations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
|
Six Months Ended
June 30,
|
|
(in thousands, except per share amounts)
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
Net income from continuing operations
|
|
$
|
1,437
|
|
|
$
|
2,903
|
|
|
$
|
5,430
|
|
|
$
|
5,935
|
|
Net loss from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(20
|
)
|
|
$
|
(93
|
)
|
Basic net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding
|
|
|
37,411
|
|
|
|
36,893
|
|
|
|
37,402
|
|
|
|
36,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.04
|
|
|
$
|
0.08
|
|
|
$
|
0.15
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common and common equivalent shares outstanding
|
|
|
37,411
|
|
|
|
36,893
|
|
|
|
37,402
|
|
|
|
36,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
$
|
0.04
|
|
|
$
|
0.08
|
|
|
$
|
0.15
|
|
|
$
|
0.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discontinued operations
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
$
|
0.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
9. Segment information
In accordance with ASC 280,
Segment Reporting
(ASC 280), we have two reportable geographic segments: Turkey and Bulgaria.
Summarized financial information from continuing operations concerning our geographic segments is shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
Turkey
|
|
|
Bulgaria
|
|
|
Total
|
|
|
|
(in thousands)
|
|
For the three months ended June 30, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
41,051
|
|
|
$
|
10
|
|
|
$
|
41,061
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(3,082
|
)
|
|
|
5,819
|
|
|
|
(73
|
)
|
|
|
2,664
|
|
Capital expenditures
|
|
$
|
64
|
|
|
$
|
27,540
|
|
|
$
|
334
|
|
|
$
|
27,938
|
|
For the three months ended June 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
2
|
|
|
$
|
30,486
|
|
|
$
|
28
|
|
|
$
|
30,516
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(3,154
|
)
|
|
|
1,525
|
|
|
|
4,712
|
|
|
|
3,083
|
|
Capital expenditures
|
|
$
|
|
|
|
$
|
27,147
|
|
|
$
|
|
|
|
$
|
27,147
|
|
For the six months ended June 30, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
74,690
|
|
|
$
|
17
|
|
|
$
|
74,707
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(6,902
|
)
|
|
|
13,319
|
|
|
|
2,290
|
|
|
|
8,707
|
|
Capital expenditures
|
|
$
|
233
|
|
|
$
|
49,321
|
|
|
$
|
1,375
|
|
|
$
|
50,929
|
|
For the six months ended June 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
2
|
|
|
$
|
64,462
|
|
|
$
|
96
|
|
|
$
|
64,560
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(6,134
|
)
|
|
|
9,897
|
|
|
|
4,612
|
|
|
|
8,375
|
|
Capital expenditures
|
|
$
|
|
|
|
$
|
45,846
|
|
|
$
|
|
|
|
$
|
45,846
|
|
Segment assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
$
|
13,464
|
|
|
$
|
338,754
|
|
|
$
|
6,710
|
|
|
$
|
358,928
|
(1)
|
December 31, 2013
|
|
$
|
14,070
|
|
|
$
|
321,749
|
|
|
$
|
10,231
|
|
|
$
|
346,050
|
(1)
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
$
|
|
|
|
$
|
7,574
|
|
|
$
|
|
|
|
$
|
7,574
|
|
December 31, 2013
|
|
$
|
|
|
|
$
|
7,535
|
|
|
$
|
|
|
|
$
|
7,535
|
|
(1)
|
Excludes assets held for sale from our discontinued Moroccan operations of $29,000 and $536,000 at June 30, 2014 and December 31, 2013, respectively.
|
10. Financial instruments
Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loan payable were each
estimated to have a fair value approximating the carrying amount at June 30, 2014 and December 31, 2013, due to the short maturity of those instruments.
Interest rate risk
We are exposed to interest
rate risk as a result of our variable rate short-term cash holdings and borrowings under the Senior Credit Facility.
Foreign currency risk
We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar,
Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the
U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At June 30, 2014, we had 8.2 million TRY (approximately $3.9 million) in cash and cash equivalents, which
exposes us to exchange rate risk based on fluctuations in the value of the TRY.
Commodity price risk
We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to,
supply and demand. At June 30, 2014 and December 31, 2013, we were a party to commodity derivative contracts.
Concentration of credit
risk
The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government
agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our
oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.
14
Fair value measurements
The following table summarizes the valuation of our financial assets and liabilities as of June 30, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Classification
|
|
|
|
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
(Level 1)
|
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
|
Significant
Unobservable Inputs
(Level 3)
|
|
|
Total
|
|
|
|
(in thousands)
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (commodity)
|
|
$
|
|
|
|
$
|
(13,995
|
)
|
|
$
|
|
|
|
$
|
(13,995
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
(13,995
|
)
|
|
$
|
|
|
|
$
|
(13,995
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Classification
|
|
|
|
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
(Level 1)
|
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
|
Significant
Unobservable Inputs
(Level 3)
|
|
|
Total
|
|
|
|
(in thousands)
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments (commodity)
|
|
$
|
|
|
|
$
|
(7,967
|
)
|
|
$
|
|
|
|
$
|
(7,967
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
(7,967
|
)
|
|
$
|
|
|
|
$
|
(7,967
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. All other financial
instruments are recorded at carrying value. The carrying value of these other financial instruments approximates fair value, as they are subject to short-term floating interest rates that approximate the rates available to us.
11. Related party transactions
The following table summarizes related party accounts receivable and accounts payable as of the dates indicated:
|
|
|
|
|
|
|
|
|
|
|
June 30,
2014
|
|
|
December 31,
2013
|
|
|
|
(in thousands)
|
|
Related party accounts receivable:
|
|
|
|
|
|
|
|
|
Viking International master services agreement
|
|
$
|
171
|
|
|
$
|
939
|
|
Riata Management service agreement
|
|
|
21
|
|
|
|
65
|
|
|
|
|
|
|
|
|
|
|
Total related party accounts receivable
|
|
$
|
192
|
|
|
$
|
1,004
|
|
|
|
|
|
|
|
|
|
|
Related party accounts payable:
|
|
|
|
|
|
|
|
|
Viking International master services agreement
|
|
$
|
7,258
|
|
|
$
|
15,956
|
|
Viking Geophysical master services agreement
|
|
|
18
|
|
|
|
6,800
|
|
Riata Management service agreement
|
|
|
421
|
|
|
|
334
|
|
|
|
|
|
|
|
|
|
|
Total related party accounts payable
|
|
$
|
7,697
|
|
|
$
|
23,090
|
|
|
|
|
|
|
|
|
|
|
For the three and six months ended June 30, 2014 and 2013, we incurred expenditures of $31.6 million and $50.6 million,
and $17.5 million and $37.7 million, respectively, related to our various related party agreements.
12. Discontinued operations
Discontinued operations in Morocco
On June 27, 2011, we decided to discontinue our operations in Morocco. We have transferred our oilfield services equipment from Morocco to Turkey and have
substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.
15
The assets and liabilities held for sale are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2014
|
|
|
December 31, 2013
|
|
|
|
(in thousands)
|
|
Cash
|
|
$
|
16
|
|
|
$
|
23
|
|
Other assets
|
|
|
13
|
|
|
|
513
|
|
|
|
|
|
|
|
|
|
|
Total assets held for sale
|
|
$
|
29
|
|
|
$
|
536
|
|
|
|
|
|
|
|
|
|
|
Accrued expenses and other liabilities
|
|
$
|
7,533
|
|
|
$
|
7,559
|
|
|
|
|
|
|
|
|
|
|
Total liabilities held for sale
|
|
$
|
7,533
|
|
|
$
|
7,559
|
|
|
|
|
|
|
|
|
|
|
Our operating results from discontinued operations for the three and six months ended June 30, 2014 and 2013 are
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended
June 30,
|
|
|
For the Six Months Ended
June 30,
|
|
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
|
|
(in thousands)
|
|
Total revenues
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Total costs and expenses
|
|
|
|
|
|
|
(52
|
)
|
|
|
(20
|
)
|
|
|
(138
|
)
|
Total other income (expense)
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations before income taxes
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
(93
|
)
|
Income tax provision
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(20
|
)
|
|
$
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
Item 2.
|
Managements Discussion and Analysis of Financial Condition and Results of Operations
|
In this Quarterly Report on Form 10-Q, references to we, our, us or the Company, refer to
TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis unless the context requires otherwise. Unless stated otherwise, all sums of money stated in this Quarterly Report on Form 10-Q are expressed in U.S. Dollars.
Executive Overview
We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our
operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to
exploration and production companies. As of June 30, 2014, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of August 1, 2014,
approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.
Financial and Operational Performance Highlights
. Highlights of our financial and operational performance for the second quarter of
2014 include:
|
|
|
We reported $1.4 million of net income from continuing operations for the three months ended June 30, 2014, as compared to $2.9 million for the same period in 2013.
|
|
|
|
We derived 81.0% of our revenues from the production of oil, 17.5% of our revenues from the production of natural gas and 1.5% of our revenues from other sources during the three months ended June 30, 2014.
|
|
|
|
Total oil and natural gas sales revenues increased 37% to $40.4 million for the quarter ended June 30, 2014, from $29.5 million in the same period in 2013. The increase was primarily the result of an increase in
sales volumes of 89 thousand barrels of oil equivalent (Mboe) and an increase in the average sales price of $8.40 per barrel of oil equivalent (Boe).
|
|
|
|
Wellhead production was 319 thousand barrels (Mbbls) of oil and 890 million cubic feet (Mmcf) of natural gas for the quarter ended June 30, 2014, as compared to 231 Mbbls of oil
and 926 Mmcf of natural gas for the same period in 2013.
|
|
|
|
For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $28.1 million for the
quarter ended June 30, 2013.
|
|
|
|
As of June 30, 2014, we had $59.8 million in long-term debt and $28.3 million in short-term debt, as compared to $26.5 million in long-term debt and $43.3 million in short-term debt as of December 31, 2013.
|
Recent Developments
Senior Credit Facility
. On May 6, 2014, DMLP, Ltd. (DMLP), TransAtlantic Exploration Mediterranean International Pty
Ltd (TEMI), Talon Exploration, Ltd. (Talon Exploration), TransAtlantic Turkey Ltd., Amity Oil International Pty Ltd (Amity) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret
A.Ş. (Petrogas)(collectively, the Borrowers) entered into a senior secured credit facility (the Senior Credit Facility) with BNP Paribas (Suisse) SA (BNP Paribas) and the International Finance
Corporation (IFC). Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (TransAtlantic
Worldwide) (each, a Guarantor). We used the proceeds from the Senior Credit Facility to pay off in full our prior senior secured credit facility on May 15, 2014, and to fund our oil and natural gas development and exploration
activities in Turkey.
Changes in Management
. On May 27, 2014, our board of directors appointed Todd C. Dutton as president
and James R. Huling as chief operating officer of the Company. On June 16, 2014, we announced that our board of directors appointed Harold Lee Muncy as vice president of geosciences. In addition, our board of directors accepted the
resignation of vice president, legal and corporate secretary Jeffrey S. Mecom and appointed Matthew W. McCann as general counsel and corporate secretary effective as of August 6, 2014. Mr. Mecom plans to remain at the Company in an
advisory capacity through September 8, 2014.
Second Quarter 2014 Operational Update
During the second quarter of 2014, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in
northwestern Turkey, and tested the Deventci-R2 well in Bulgaria.
Turkey-Southeast
Molla
. We completed shooting our Molla 3D seismic program of approximately 800 km
2
in April 2014. The final phase of processed data is projected to be delivered in the third quarter of 2014. We recently drilled the Bahar-2ST and Bahar-3 wells, both of which are being completed. We also commenced drilling the Bahar-4 and Bahar-6,
vertical wells, which we expect will yield additional confirmation of the Bahar structure. For the remainder of 2014, we expect to spud at least two additional vertical Bahar wells. We also plan to drill one Mardin horizontal well based on our new
Molla 3D seismic data.
17
Selmo
. We drilled three MSD horizontal wells, the Selmo-84H, Selmo-54H and Selmo-85H in
the second quarter of 2014, and completed two of these wells. We are currently drilling the Selmo-68H3 well. During the first half of 2014, we spudded a total of five MSD horizontal wells, and we expect to spud four additional horizontal wells in
the Selmo field during the remainder of 2014.
We initiated a waterflood pilot test program in the Selmo field in which two Selmo wells
were converted to injector wells. To date, we have injected more than 250,000 barrels of water into the Selmo field. We believe secondary recovery will increase production from the field, and we intend to convert at least two additional Selmo wells
to injector wells in 2014.
Based on the successful results of our five-well polymer injection program in the first quarter of 2014, which
added approximately 250 barrels of oil per day (bbl/d), we plan to commence a second phase of polymer injections in the third quarter of 2014.
Arpatepe
. We completed the Arpatepe-7, a Bedinan appraisal well in the second quarter of 2014. We plan to drill one additional
appraisal well and initiate a waterflood pilot test in the Arpatepe field during the remainder of 2014.
Idil
. We expect to drill a
vertical exploration well on our Idil license in the second half of 2014. Our joint venture partner, Onshore Petroleum Company AS (Onshore), will be assigned a 50% interest in the Idil license and will fund 100% of TransAtlantics
expected share of the cost of this well.
Turkey-Thrace Basin, Northwest
During the second quarter of 2014, we processed the remaining 25% of our Osmanli 3D seismic program. We recently spudded the TDR-5H well.
During the remainder of 2014, we expect to drill five conventional shallow wells and one additional horizontal well targeting the Teslimkoy formation in the Thrace Basin.
Bulgaria
In the second
quarter of 2014, we conducted a long-term pressure build-up test on the Deventci-R2 well to evaluate its connectivity to the reservoir following an initial production test of approximately 2.0 million cubic feet per day (Mmcf/d) of
natural gas with condensates. On June 26, 2014, we submitted a request to the Bulgarian government to acidize the well. Upon receipt of approval, we plan to stimulate the well to enhance its productivity.
Planned Operations
We continue to actively explore and develop our existing oil and natural gas properties in Turkey and evaluate opportunities for further
activities in Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and bringing these discoveries into production. For the remainder of 2014, we are focused on accomplishing the following
objectives:
|
|
|
Increase Reserves and Production
. In the second quarter of 2014, we increased our average net sales volumes per day by 8% from the first quarter of 2014, and by 24% from the second quarter of 2013. We plan to
continue to grow our oil and natural gas reserves and production in Turkey through exploration and development on our Selmo, Molla and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal
drilling and fracture stimulation techniques. During the remainder of 2014, we plan to drill, or participate in the drilling of, approximately nine new gross wells in southeastern Turkey and approximately six new gross wells in northwestern Turkey.
|
|
|
|
Utilize New 3D Seismic Data to Improve Well Targeting
. During the year ended December 31, 2013, we spent $12.8 million shooting 3D seismic over areas of Turkey where 3D seismic data did not previously exist.
We expect this new data will improve our ability to target well locations, drill wells and ultimately delineate hydrocarbon reservoirs.
|
|
|
|
Expand the Use of Horizontal Drilling
. During 2013, we expanded our use of horizontal drilling, employing it on 13 of 35 wells drilled, with successful results in the Selmo, Molla and Thrace Basin areas. During
the remainder of 2014, we anticipate that extensive use of horizontal drilling techniques on our wells in southeastern and northwestern Turkey will more effectively extract hydrocarbons and increase our returns on invested capital.
|
|
|
|
Further Expand Fracture Stimulation Program
. In 2013, we expanded our use of hydraulic fracturing technology to complete otherwise low productive formations in Turkey. The evolution of fracturing fluid and
stimulation design has yielded positive results in both northwestern and southeastern Turkey. For the remainder of 2014, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics
.
|
18
|
|
|
Pursue Other Growth Opportunities.
In addition to growing our reserves and production through the exploration and development of our substantial acreage in Turkey and Bulgaria, we continually evaluate
acquisition, joint venture and farm-in/out opportunities. We are focused on both strengthening our positions in Turkey and Bulgaria and identifying opportunities in new countries.
|
We expect net field capital expenditures for the remainder of 2014 to range between $45.0 million and $55.0 million for the drilling and
completion of approximately 15 gross wells, the recompletion of approximately 15 existing gross wells, the processing of remaining seismic data, infrastructure improvements and other capital investments. Of these expenditures, we expect to spend
approximately 75% in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey,
devoted to developing conventional and unconventional natural gas production and building infrastructure. We expect cash on hand, borrowings from our credit facilities and cash flow from operations will be sufficient to fund the remainder of our
2014 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2014 capital expenditure budget is subject to change. We currently plan to execute the following
drilling and exploration activities during the third and fourth quarters of 2014:
Turkey.
We plan to drill approximately 15 gross
wells, six of which are expected to be drilled horizontally and approximately 75% of which will be fracture stimulated. We also plan to continue our waterflood pilot test and polymer injection programs.
Bulgaria
. We plan to perform additional completion activities on the Deventci-R2 well pending approval from the Bulgarian government to
acidize the well.
Discontinued Operations in Morocco
In June 2011, we discontinued our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco.
We have presented the Moroccan segment operating results as discontinued operations for the three and six months ended June 30, 2014 and June 30, 2013.
Significant Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which
have been prepared in accordance with generally accepted accounting principles in the United States (U.S. GAAP). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect
the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in Note 2. Significant accounting policies to our audited consolidated financial statements
included in our Annual Report on Form 10-K for the year ended December 31, 2013 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by
management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making
judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. There have been no changes to the significant
accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.
Recent Accounting
Pronouncements
In April 2014, the Financial Accounting Standard Board (FASB) issued Accounting Standards Update
(ASU) 2014-08,
Reporting Discontinued Operations and Disclosures of Components of an Entity
(ASU 2014-08). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to
disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entitys operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued
operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an
individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU
2014-08 to have a material impact on our consolidated financial statements or results of operations.
In May 2014, the FASB issued ASU
2014-09,
Revenue from Contracts with Customers
(ASU 2014-09). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the
transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are
currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.
19
We have reviewed other recently issued, but not yet adopted, accounting standards in order to
determine their effects, if any, on our results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on our current or future earnings or operations.
Results of OperationsThree Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013
Our results of operations for the three months ended June 30, 2014 and 2013 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
Change
|
|
|
|
2014
|
|
|
2013
|
|
|
2014-2013
|
|
|
|
(in thousands of U.S. dollars, except per unit amounts and volumes)
|
|
Welhead Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl)
|
|
|
319
|
|
|
|
231
|
|
|
|
88
|
|
Natural gas (Mmcf)
|
|
|
890
|
|
|
|
926
|
|
|
|
(36
|
)
|
Total production (Mboe)
|
|
|
467
|
|
|
|
385
|
|
|
|
82
|
|
Average daily wellhead production (Boepd)
|
|
|
5,132
|
|
|
|
4,231
|
|
|
|
901
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl)
|
|
|
318
|
|
|
|
230
|
|
|
|
88
|
|
Natural gas (Mmcf)
|
|
|
821
|
|
|
|
816
|
|
|
|
5
|
|
Total production (Mboe)
|
|
|
455
|
|
|
|
366
|
|
|
|
89
|
|
Average daily sales volumes (Boepd)
|
|
|
5,000
|
|
|
|
4,022
|
|
|
|
978
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
104.53
|
|
|
$
|
94.13
|
|
|
$
|
10.40
|
|
Natural gas (per Mcf)
|
|
$
|
8.77
|
|
|
$
|
9.57
|
|
|
$
|
(0.80
|
)
|
Oil equivalent (per Boe)
|
|
$
|
88.88
|
|
|
$
|
80.48
|
|
|
$
|
8.40
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
40,441
|
|
|
$
|
29,455
|
|
|
$
|
10,986
|
|
Sales of purchased natural gas
|
|
|
491
|
|
|
|
719
|
|
|
|
(228
|
)
|
Other
|
|
|
129
|
|
|
|
342
|
|
|
|
(213
|
)
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
4,666
|
|
|
$
|
3,328
|
|
|
$
|
1,338
|
|
Exploration, abandonment and impairment
|
|
|
3,775
|
|
|
|
11,885
|
|
|
|
(8,110
|
)
|
Cost of purchased natural gas
|
|
|
440
|
|
|
|
619
|
|
|
|
(179
|
)
|
Seismic and other exploration
|
|
|
892
|
|
|
|
1,090
|
|
|
|
(198
|
)
|
Revaluation of contingent consideration
|
|
|
|
|
|
|
(5,000
|
)
|
|
|
5,000
|
|
General and administrative
|
|
|
7,460
|
|
|
|
6,893
|
|
|
|
567
|
|
Depletion
|
|
|
12,022
|
|
|
|
8,976
|
|
|
|
3,046
|
|
Depreciation and amortization
|
|
|
566
|
|
|
|
605
|
|
|
|
(39
|
)
|
Interest and other expense
|
|
|
1,769
|
|
|
|
955
|
|
|
|
814
|
|
Foreign exchange (gain) loss
|
|
|
(2,494
|
)
|
|
|
2,543
|
|
|
|
(5,037
|
)
|
(Loss) gain on commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlements on commodity derivative contracts
|
|
$
|
(1,781
|
)
|
|
$
|
(484
|
)
|
|
$
|
(1,297
|
)
|
Change in fair value on commodity derivative contracts
|
|
|
(7,741
|
)
|
|
|
4,762
|
|
|
|
(12,503
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (loss) gain on commodity derivative contracts
|
|
$
|
(9,522
|
)
|
|
$
|
4,278
|
|
|
$
|
(13,800
|
)
|
Oil and natural gas costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
8.98
|
|
|
$
|
7.96
|
|
|
$
|
1.02
|
|
Depletion
|
|
$
|
23.14
|
|
|
$
|
21.46
|
|
|
$
|
1.68
|
|
Oil and Natural Gas Sales.
Total oil and natural gas sales revenues increased $10.9 million to $40.4
million for the three months ended June 30, 2014, from $29.5 million realized in the same period in 2013. Of this increase, $7.2 million was due to an
20
increase in sales volumes of 89 Mboe. Additionally, we realized a higher average price per Boe, which resulted in higher revenues of $3.8 million. Our average price received increased $8.40 per
Boe to $88.88 per Boe for the three months ended June 30, 2014, from $80.48 per Boe for the same period in 2013.
Production.
Production expenses for the three months ended June 30, 2014 increased to $4.7 million or $8.98 per Boe, from $3.3 million or $7.96 per Boe for the same period in 2013. The increase was primarily attributable to $1.1 million of operating
expenses, which we billed back to our Thrace Basin Natural Gas (Turkiye) Corporation (TBNG) joint venture partners during the three months ended June 30, 2013, following a redetermination of operating costs.
Exploration, Abandonment and Impairment.
Exploration, abandonment and impairment costs for the three months ended June 30, 2014
decreased approximately $8.1 million to $3.8 million, from $11.9 million for the same period in 2013. During the three months ended June 30, 2014, we recorded impairment charges of $2.8 million primarily related to the Kazanci-5 well, compared
to the three months ended June 30, 2013, when we incurred license impairment charges of $4.6 million. Additionally, three wells were written off for $6.1 million during three months ended June 30, 2013.
General and Administrative.
General and administrative expense was $7.5 million for the three months ended June 30, 2014, as
compared to $6.9 million for the same period in 2013. The increase was primarily due to an increase in employee-related costs of $0.9 million and an increase in travel expenses of $0.1 million, which was partially offset by a decrease in accounting
and consulting expenses of $0.4 million. Employee-related costs increased primarily due to severance payments made to former employees. Accounting and consulting expenses were higher during the three months ended June 30, 2013 primarily due to
the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013.
Depletion.
Depletion increased to $12.0 million or $23.14 per Boe for the three months ended June 30, 2014, compared to $9.0
million or $21.46 per Boe for the same period of 2013. The increase was primarily due to additions to proved properties during the three months ended June 30, 2014.
Interest and Other Expense.
Interest and other expense increased to $1.8 million for the three months ended June 30, 2014, as
compared to $1.0 million for the same period in 2013. The increase was primarily due to a $0.5 million write-off of loan financing costs related to the amended and restated credit facility, which was repaid in May 2014. Also contributing to the
increase was an increase in our average level of debt outstanding during the three months ended June 30, 2014 compared to the same period in 2013. At June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million
at June 30, 2013.
Foreign Exchange (Gain) Loss.
We recorded a foreign exchange gain of $2.5 million during the three months
ended June 30, 2014, compared to a loss of $2.5 million for the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts
in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (TRY) amount if it has not been settled previously. The
increase in foreign exchange gain during the three months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the
three months ended June 30, 2013.
(Loss) Gain on Commodity Derivative Contracts.
During the three months ended June 30,
2014, we recorded a net loss on commodity derivative contracts of approximately $9.5 million, as compared to a net gain of $4.3 million for the same period in 2013. During the three months ended June 30, 2014, we recorded a $7.7 million loss to
mark our commodity derivatives to their fair value and a $1.8 million loss on settled contracts. During the same period in 2013, we recorded a $4.8 million gain to mark our commodity derivatives to their fair value and a $0.5 million loss on settled
contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.
Discontinued Operations.
All revenues and expenses associated with our Moroccan operations for the three months ended June 30,
2014 and 2013 have been included in discontinued operations.
21
The results of operations for our Moroccan operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
|
|
2014
|
|
|
2013
|
|
|
|
(in thousands)
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
|
|
|
$
|
41
|
|
General and administrative
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
Operating loss
|
|
|
|
|
|
|
(52
|
)
|
Other income (expense):
|
|
|
|
|
|
|
|
|
Interest and other expense
|
|
|
|
|
|
|
(6
|
)
|
Interest and other income
|
|
|
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
|
|
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
Net income from discontinued operations
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Results of OperationsSix Months Ended June 30, 2014 Compared to Six Months Ended
June 30, 2013
Our results of operations for the six months ended June 30, 2014 and 2013 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
Change
|
|
|
|
2014
|
|
|
2013
|
|
|
2014-2013
|
|
|
|
(in thousands of U.S. dollars, except per unit amounts and volumes)
|
|
Wellhead production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl)
|
|
|
580
|
|
|
|
476
|
|
|
|
104
|
|
Natural gas (Mmcf)
|
|
|
1,950
|
|
|
|
1,782
|
|
|
|
168
|
|
Total production (Mboe)
|
|
|
905
|
|
|
|
773
|
|
|
|
132
|
|
Average daily wellhead production (Boepd)
|
|
|
5,000
|
|
|
|
4,271
|
|
|
|
729
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl)
|
|
|
578
|
|
|
|
470
|
|
|
|
108
|
|
Natural gas (Mmcf)
|
|
|
1,755
|
|
|
|
1,616
|
|
|
|
139
|
|
Total production (Mboe)
|
|
|
871
|
|
|
|
739
|
|
|
|
132
|
|
Average daily sales volumes (Boepd)
|
|
|
4,812
|
|
|
|
4,083
|
|
|
|
729
|
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
101.06
|
|
|
$
|
98.44
|
|
|
$
|
2.62
|
|
Natural gas (per Mcf)
|
|
$
|
8.52
|
|
|
$
|
9.85
|
|
|
$
|
(1.33
|
)
|
Oil equivalent (per Boe)
|
|
$
|
84.30
|
|
|
$
|
84.14
|
|
|
$
|
0.16
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
73,425
|
|
|
$
|
62,180
|
|
|
$
|
11,245
|
|
Sales of purchased natural gas
|
|
|
1,036
|
|
|
|
1,525
|
|
|
|
(489
|
)
|
Other
|
|
|
246
|
|
|
|
855
|
|
|
|
(609
|
)
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
8,797
|
|
|
$
|
8,855
|
|
|
$
|
(58
|
)
|
Exploration, abandonment and impairment
|
|
|
7,916
|
|
|
|
15,749
|
|
|
|
(7,833
|
)
|
Cost of purchased natural gas
|
|
|
925
|
|
|
|
1,331
|
|
|
|
(406
|
)
|
Seismic and other exploration
|
|
|
4,186
|
|
|
|
1,333
|
|
|
|
2,853
|
|
Revaluation of contingent consideration
|
|
|
(2,500
|
)
|
|
|
(5,000
|
)
|
|
|
2,500
|
|
General and administrative
|
|
|
14,012
|
|
|
|
14,416
|
|
|
|
(404
|
)
|
Depletion
|
|
|
21,581
|
|
|
|
17,362
|
|
|
|
4,219
|
|
Depreciation and amortization
|
|
|
1,097
|
|
|
|
1,195
|
|
|
|
(98
|
)
|
Interest and other expense
|
|
|
2,972
|
|
|
|
1,845
|
|
|
|
1,127
|
|
Foreign exchange (gain) loss
|
|
|
(1,150
|
)
|
|
|
3,030
|
|
|
|
(4,180
|
)
|
(Loss) gain on commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlements on commodity derivative contracts
|
|
$
|
(2,533
|
)
|
|
$
|
(1,736
|
)
|
|
$
|
(797
|
)
|
Change in fair value on commodity derivative contracts
|
|
|
(6,027
|
)
|
|
|
5,238
|
|
|
|
(11,265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (loss) gain on commodity derivative contracts
|
|
$
|
(8,560
|
)
|
|
$
|
3,502
|
|
|
$
|
(12,062
|
)
|
Oil and natural gas costs per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
8.85
|
|
|
$
|
10.49
|
|
|
$
|
(1.64
|
)
|
Depletion
|
|
$
|
21.71
|
|
|
$
|
20.56
|
|
|
$
|
1.15
|
|
22
Oil and Natural Gas Sales.
Total oil and natural gas sales revenues increased $11.2
million to $73.4 million for the six months ended June 30, 2014, from $62.2 million realized in the same period in 2013. Of this increase, $11.1 million was due to an increase in sales volumes of 132 Mboe. Additionally, we realized a slightly
higher average price per Boe, which resulted in an additional $0.1 million of revenue. Our average price received increased $0.16 per Boe to $84.30 per Boe for the six months ended June 30, 2014, from $84.14 per Boe for the same period in
2013.
Production.
Production expenses for the six months ended June 30, 2014 decreased to $8.8 million or $8.85 per Boe, from
$8.9 million or $10.49 per Boe for the same period in 2013. The decrease of $1.64 per Boe was primarily attributable to an increase in our working interest production volumes during the six months ended June 30, 2014 compared to the same period
in 2013.
Exploration, Abandonment and Impairment.
Exploration, abandonment and impairment costs for the six months ended
June 30, 2014 decreased approximately $7.8 million to $7.9 million, from $15.7 million for the same period in 2013. During the six months ended June 30, 2014, we impaired two wells for $6.3 million. During the six months ended
June 30, 2013, we wrote off four wells for $10.0 million and incurred license impairment charges of $4.6 million.
Seismic and
Other Exploration.
Seismic and other exploration costs increased to $4.2 million for the six months ended June 30, 2014, as compared to $1.3 million for the same period in 2013. The increase was primarily due to seismic acquisition activity
conducted on our West Molla and Osmanli licenses during the six months ended June 30, 2014.
General and Administrative.
General and administrative expense was $14.0 million for the six months ended June 30, 2014, compared to $14.4 million for the same period in 2013. The decrease was primarily due to a decrease of $0.6 million in accounting and consulting
expenses and a $0.2 million decrease in office expenses and rent, which was partially offset by a $0.4 million increase in employee-related costs. Accounting and consulting expenses were higher during the six months ended June 30, 2013
primarily due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013. Employee-related costs increased during the six months
ended June 30, 2014 primarily due to severance payments made to former employees.
Depletion.
Depletion increased to $21.6 million
or $21.71 per Boe for the six months ended June 30, 2014, compared to $17.4 million or $20.56 per Boe for the six months ended June 30, 2013. The increase was primarily due to additions to proved properties during the six months ended
June 30, 2014.
Interest and Other Expense.
Interest and other expense increased to $3.0 million for the six months ended
June 30, 2014, compared to $1.8 million for the same period in 2013. The increase was primarily due to an increase in our average level of debt outstanding during the six months ended June 30, 2014 compared to the same period in 2013. At
June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million at June 30, 2013. Also contributing to the increase was a $0.5 million write-off of loan financing costs related to the amended and restated credit
facility, which was repaid in May 2014.
Foreign Exchange (Gain) Loss.
We recorded a foreign exchange gain of $1.2 million during
the six months ended June 30, 2014, compared to a loss of $3.0 million in the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and
monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. The increase in foreign
exchange gain during the six months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the six months ended
June 30, 2013.
(Loss) Gain on Commodity Derivative Contracts.
During the six months ended June 30, 2014, we recorded a
net loss on commodity derivative contracts of approximately $8.6 million, compared to a net gain of $3.5 million for the same period in 2013. During the six months ended June 30, 2014, we recorded a $6.0 million loss to mark our commodity
derivatives to their fair value and
23
a $2.5 million loss on settled contracts. During the same period in 2013, we recorded a $5.2 million gain to mark our commodity derivatives to their fair value and a $1.7 million loss on settled
contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.
Discontinued Operations.
All revenues and expenses associated with our Moroccan operations for the six months ended June 30, 2014
and 2013 have been included in discontinued operations.
The results of operations for our Moroccan operations were as follows:
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|
|
|
|
|
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Six Months Ended June 30,
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|
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2014
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|
2013
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|
|
|
(in thousands)
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|
Costs and expenses:
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|
|
|
|
|
|
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|
Production
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|
$
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|
|
|
$
|
110
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|
General and administrative
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|
|
20
|
|
|
|
28
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|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
20
|
|
|
|
138
|
|
|
|
|
|
|
|
|
|
|
Operating loss
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|
|
(20
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)
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|
|
(138
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)
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Other income (expense):
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|
|
|
|
|
|
|
|
Interest and other expense
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|
|
|
|
|
|
(8
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)
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Interest and other income
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|
|
|
|
|
|
53
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|
|
|
|
|
|
|
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Total other income
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|
|
|
|
|
|
45
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|
|
|
|
|
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|
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Net loss from discontinued operations
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|
$
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(20
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)
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|
$
|
(93
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)
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Capital Expenditures
For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic
expenditures from continuing operations, as compared to $28.1 million for the quarter ended June 30, 2013.
Capital expenditures,
including seismic expenditures, for the third and fourth quarters of 2014 are expected to range between $45.0 million and $55.0 million. We expect to spend approximately 75% of these anticipated expenditures in southeastern Turkey, devoted to
drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey, devoted to developing conventional and
unconventional natural gas production and building infrastructure. Our projected 2014 capital budget is subject to change, and if cash on hand, borrowings from our credit facilities, and cash flow from operations are not sufficient to fund our
capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.
Liquidity and
Capital Resources
Our primary sources of liquidity for the second quarter of 2014 were our cash and cash equivalents, cash flow
from operations and net borrowings under our Senior Credit Facility. At June 30, 2014, we had cash and cash equivalents of $5.2 million, $28.3 million in short-term debt, $59.8 million in long-term debt, and a working capital deficit of $12.5
million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $12.9 million, $43.3 million in short-term debt, $26.5 million in long-term debt, and a working
capital deficit of $39.4 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities) at December 31, 2013. Net cash provided by operating activities from continuing operations for the six months
ended June 30, 2014 decreased to $41.5 million, as compared to net cash provided by operating activities from continuing operations of $55.7 million for the six months ended June 30, 2013. This decrease was primarily a result of a decrease
in our accounts payable during the six months ended June 30, 2014, compared to an increase in our accounts payable during the same period in 2013.
As of June 30, 2014, the outstanding principal amount of our debt was $88.1 million. In addition to cash, cash equivalents and cash flow
from operations, at June 30, 2014, we had a Senior Credit Facility and a credit facility with a Turkish bank, which are discussed below.
Senior Credit Facility.
On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. The
Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.
The amount drawn
under the Senior Credit Facility may not exceed the lesser of (i) $150.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an
individual lender to the extent it exceeds the aggregate amount of such lenders individual commitment. The lenders have an initial aggregate
24
commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of $150.0 million by March 31,
2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.
The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015.
The current borrowing base is $74.6 million. The borrowing base amount equals, for any calculation date, the lowest of:
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the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00; and
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the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00.
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The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation
period that immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount
of hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits
of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such
lenders individual commitment.
Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus
5.00% per annum (5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the
aggregate commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available
amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit
and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of
credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.
The Senior Credit
Facility is secured by a pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower and
(iv) substantially all of the present and future assets of the Borrowers.
The Borrowers are required to comply with certain
financial and non-financial covenants under the Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:
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ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;
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ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Senior Credit Facility of not less than 1.50 to 1.00;
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ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and
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ratio of total debt to EBITDAX of less than 2.50 to 1.00.
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The Senior Credit Facility defines
EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated
intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any
extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion,
geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in
calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.
Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall
not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to
create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make
certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume
25
any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on
business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal
quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit,
securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate
cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or
(xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.
An event of default under the Senior Credit
Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios
and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and
beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or
indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors
at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall
become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided, that, if Mr. Mitchell
ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the
occurrence of such event.
At July 1, 2014, we had borrowings of $59.8 million under the Senior Credit Facility and availability of
$14.8 million.
TBNG Credit Facility.
On June 18, 2013, TBNG entered into a 78.8 million TRY (approximately $37.1
million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available in the form of non-cash bank guarantees and letters of credit for TBNG and
several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing. We have made three borrowings under this credit facility, each of which has a one-year term at a fixed interest
rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility with no remaining
availability.
Contingencies Relating to Production Leases and Exploration Permits
Selmo
We are
involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to
estimate the potential additional operating costs we would incur in the event the purported surface owners claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.
Morocco
In
the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew
down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in
accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.
Aglen
In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual
obligations under our Aglen exploration permit work program. Due to the Bulgarian governments January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by
the government. Although we invoked force majeure, we recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during 2012 for this contractual obligation.
26
Direct Petroleum
In July 2013, we entered into a second amendment (the Amendment) to the purchase agreement (the Purchase Agreement)
with Direct Petroleum Exploration, LLC (Direct). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during
April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption Revaluation of contingent
consideration during the six months ended June 30, 2014.
In addition, the Amendment provides that we will issue $7.5 million
in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of
June 30, 2014, we had not recorded a contingent liability for this contingent consideration.
Additionally, the Amendment provides
that if the Bulgarian government issues a production concession over the stefenetz concession area (the Stefenetz Concession Area), Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the
production concession is less than 200,000 acres. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession
Area. Any adjustment will be recorded when it becomes probable and estimable.
Contractual Obligations
There were no material changes to our contractual obligations set forth in our Annual Report on Form 10-K for the year ended December 31,
2013.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements at June 30, 2014.
Forward-Looking Statements
Certain statements contained in this Quarterly Report on Form 10-Q are forward-looking statements and are prospective.
Forward-looking statements are typically identified by words such as anticipate, believe, expect, plan, intend, may, project, forecast,
estimate, continue, would, could or similar words suggesting future outcomes or statements regarding an outlook. Such forward-looking statements are subject to risks, uncertainties and other factors
which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.
The
following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements: 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 the other factors
discussed in other documents that we file with or furnish to the Securities and Exchange Commission (SEC). The impact of any one factor on a particular forward-looking statement is not determinable with certainty, as such factors are
interdependent upon other factors. In that regard, any statements as to future natural gas or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our
capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development
costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; changes in
any of the foregoing and other statements using forward-looking terminology are forward-looking statements.
Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and
unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other things contemplated by the forward-looking statements will not occur.
Forward-looking statements in this Quarterly Report on Form 10-Q are based on managements beliefs and opinions at the time the
statements are made. The forward-looking statements contained in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. The forward-looking statements included in this Quarterly Report on Form 10-Q
are made as of the date of this Quarterly Report on Form 10-Q and we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information, future events or otherwise, except as required by applicable
securities laws.
27