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TAT > SEC Filings for TAT > Form 10-Q on 30-Nov-2012All Recent SEC Filings

Show all filings for TRANSATLANTIC PETROLEUM LTD.

Form 10-Q for TRANSATLANTIC PETROLEUM LTD.


30-Nov-2012

Quarterly Report


Item 2. Management's 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 are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing and royalty and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Bulgaria and Romania. As of September 30, 2012, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors and chief executive officer.

Financial and Operational Performance Highlights. Highlights of our financial performance and operational performance for the third quarter of 2012 include:

For the three months ended September 30, 2012, we reported $0.5 million of net income from continuing operations. This includes a $6.3 million non-cash loss on the change in fair value of our commodity derivative contracts.

During the quarter ended September 30, 2012, we derived 73.2% of our revenues from the production of oil and 22.8% of our revenues from the production of natural gas.

Total oil and natural gas revenues increased 0.5% to $31.8 million for the quarter ended September 30, 2012 from $31.6 million realized in the same period in 2011. The increase was primarily the result of an increase in our average realized price received, which increased revenues by $5.4 million. This increase was offset by lower production volumes, which decreased revenues by $5.2 million.

Total production was approximately 229 net thousand barrels ("Mbbls") of oil and approximately 928 net million cubic feet ("Mmcf") of natural gas for the third quarter of 2012, as compared to approximately 222 net Mbbls of oil and approximately 1,426 net Mmcf of natural gas for the same period in 2011.

As of September 30, 2012, we produced an aggregate of approximately 2,441 net barrels ("Bbls") of oil per day and approximately 10.1 net Mmcf of natural gas per day.

For the quarter ended September 30, 2012, we incurred $24.5 million in capital expenditures, as compared to capital expenditures of $24.1 million for the quarter ended September 30, 2011.

As of September 30, 2012, we had $32.8 million in outstanding debt and no short-term borrowings, as compared to $158.7 million in outstanding debt and short-term borrowings of $80.7 million as of December 31, 2011, excluding liabilities held for sale.

Recent Developments

Amendment to Amended and Restated Credit Facility. In November 2012, we entered into an amendment to our amended and restated senior secured credit facility (the "Amended and Restated Credit Facility") with Standard Bank Plc ("Standard Bank") and BNP Paribas (Suisse) SA ("BNP Paribas"). The amendment, among other things, reduces the commitment fee rate, extends the first commitment reduction date from September 30, 2012 to December 31, 2013 and provides for a scheduled quarterly reduction of the commitment amount beginning on December 31, 2013, when the commitment amount, which is currently $78.0 million, will be reduced to $67.0 million, and ending on March 31, 2016, when the commitment amount will reach zero.

Appointment of New Director. On June 28, 2012, Charles J. Campise was appointed to our board of directors. Mr. Campise brings more than 20 years of international oil and natural gas financial and accounting expertise to our board, including serving as senior vice president and chief financial officer of Toreador Resources Corporation from May 2006 to March 2010 and as corporate controller for Transmeridian Exploration Incorporated from December 2003 until May 2005.

Closing of Sale of Oilfield Services Business. On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited ("Viking International") and Viking Geophysical Services, Ltd. ("Viking Geophysical"), to a joint venture owned by Dalea Partners, LP, an affiliate of Mr. Mitchell ("Dalea"), and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The transaction was approved by a special committee of our board of directors after the receipt of a fairness opinion solely for the benefit of the special committee, which was subject to certain assumptions and limitations as provided in such opinion. The promissory note is payable five years from the date of issuance or earlier upon the occurrence of certain specified events, including an initial public offering by the joint venture. Upon the consummation of an initial public offering by the joint venture and the prior approval of Dalea, we can elect to convert the outstanding balance of the promissory note, including accrued interest, into the number of shares offered in the initial public offering equal to such outstanding balance divided by the per share purchase price paid by the public in the initial public offering. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling, LLC ("Viking Drilling") and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale to pay down approximately $45.2 million in outstanding indebtedness under our Amended and Restated Credit Facility.


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Entry into Master Services Agreements. On June 13, 2012, we also entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri A.S. ("VOS") and Viking Geophysical in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation, that are needed for our operations in Bulgaria, Romania and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each master services agreement is for a five-year term. Currently, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity.

Entry into Transition Services Agreement. On June 13, 2012, we also entered into a transition services agreement with Viking Services Management, Ltd. ("Viking Management") in connection with the sale of our oilfield services business. Pursuant to the transition services agreement, we agreed to provide certain administrative services, including, but not limited to, continued use of certain of our employees and independent contractors, a guarantee of a lease for flats in Turkey, Turkish tax or legal advice and services, office space in Istanbul, Turkey, information technology support and certain software or licenses to Viking Management. In addition, Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain office space in Tekirdag, Turkey. In the third quarter of 2012, we entered into an addendum to the transition services agreement whereby Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain equipment yards in the Thrace Basin and in southwestern Turkey. The transition services agreement has a two-year term. Viking Management agreed to use commercially reasonable efforts to eliminate its need for such services as soon as practicable following the entry into the agreement.

Amendment to Ban on Fracture Stimulation in Bulgaria. In January 2012, the Bulgarian Parliament enacted legislation that was intended to ban fracture stimulation in the Republic of Bulgaria. The legislation also prevented conventional drilling and completion activities. The Bulgarian Parliament has since amended the legislation to allow conventional drilling and completion activities. In November 2012, we were awarded a production concession over the Koynare concession area, which covers approximately 160,000 acres. As a result we expect our conventional natural gas exploration, development and production activity in the country to resume. As long as the current legislation remains in effect, our unconventional natural gas exploration, development and production activities in Bulgaria will be significantly constrained.

Third Quarter 2012 Operational Update

During the third quarter of 2012, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey. In addition, we continued to expand our inventory of exploration opportunities with new prospects identified on recently completed 3D seismic surveys.

Production. For the quarter ended September 30, 2012, we produced an average of approximately 2,492 net Bbls of oil per day and approximately 10.1 net Mmcf of natural gas per day.

Turkey-Southeast.

Selmo. We completed four wells and began drilling one additional well during the third quarter of 2012. In September 2012, we completed five of 14 planned fracture stimulations of existing wells at Selmo.

Arpatepe. In the third quarter of 2012, we began completion activity for the Arpatepe-6 well. The well started producing during the fourth quarter of 2012 at an initial gross rate of approximately 200 Bbls of oil per day. The Bati Arpatepe-1 well, which was drilled and funded by Aladdin Middle East, Ltd., the operator of the Arpatepe license, did not find commercial quantities of hydrocarbons and has been plugged and abandoned.

Molla. We conducted completion operations on the Bahar-1 well, which encountered oil and natural gas shows in the Bedinan sands formation as well as in the Mardin, Hazro and Dadas formations. In addition, we completed drilling the Goksu-3H well, which we expect to complete during the fourth quarter of 2012 as our first producing horizontal well in Turkey.

Turkey-Thrace Basin. In the third quarter of 2012, we spud six wells, completed 10 new wells and fracture stimulated five wells. As of September 30, 2012, we had $5.6 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. We have identified at least two more sands within the Mezardere formation that we expect the Pancarkoy-1 well to initially test by conventional means.

Turkey-Central Basins. We completed the initial planned acquisition of the Sivas Basin data, which Shell Upstream Turkey B.V. co-funded. We have extended the seismic data acquisition program in the Sivas Basin and expect to complete this additional data acquisition in the fourth quarter of 2012. We drilled the Alibey-1H well, which is our first horizontal well in Turkey. We are currently evaluating completion techniques for this well, which is located on our Gaziantep exploration licenses. In addition, we resumed drilling the Konak-1 exploration well on our Gurun exploration license.


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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 and Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2012, we are focused on accomplishing the following objectives:

Commence Tekirdag Field Area Development. We expect to begin drilling our infield tight-gas development program in the Tekirdag field area in the Thrace Basin based upon our projected 50-acre drainage wells. Based on the results of fracture stimulations of new and existing wells, we have designed an initial 88-well development program, which we expect to begin during the fourth quarter of 2012. The development program is expected to proceed as a two-rig campaign with continuous drilling and completion activity continuing into 2015.

Explore New Fault Blocks Identified by Recently Acquired Seismic Data. We plan to continue exploration drilling of new fault blocks identified by recently acquired 3D seismic data on our Hayrabolu and Gocerler licenses in the Thrace Basin and by recently acquired 2D seismic data on our Gurun exploration license in southeastern Turkey.

Expand Fracture Stimulation Program. We expect to complete the 14-well fracture stimulation program at Selmo during the fourth quarter of 2012. We also plan to fracture stimulate the Bedinan sand formation in the Bahar-1 well during the fourth quarter of 2012. We plan to resume fracture stimulation activity in the Thrace Basin after the Selmo frac program and the Bahar-1 fracture stimulations are completed.

Develop Southeastern Turkey Licenses. We plan to complete and test the Alibey-1H well and the Goksu-3H well in the fourth quarter of 2012. In addition, we expect to begin the acquisition of approximately 200 kilometers of 2D seismic data over our recently acquired West Molla exploration license. We plan to spud the Durukoy-1 exploration well on our Idil exploration license.

Reduce Exploration Risk Through Partnerships. In an effort to increase the pace of exploration activity, share exploration risk, and reduce our share of the capital commitments necessary to carry forward the exploration of our extensive acreage positions, we are currently seeking joint venture partners for our exploration acreage in Bulgaria, Romania and Turkey and plan to continue this effort during the remainder of 2012.

Capital expenditures for the remainder of 2012 are expected to range between $20 million and $35 million. Approximately 40% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 60% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Selmo, Arpatepe, Molla, Idil and Gurun.

We currently plan to execute the following drilling and exploration activities during the remainder of 2012:

Turkey. We plan to drill approximately 10 gross wells, five of which we expect to fracture stimulate. In addition, we plan to perform up-hole recompletions in 14 wells in the Thrace Basin and fracture stimulate nine existing wells at our Selmo oilfield. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. In November 2012, we received a production concession on our Koynare concession area, and we expect to resume conventional operating activity on the concession in the first quarter of 2013.

Romania. We plan to seek approval from the Romanian government to suspend our exploration activities as a result of recent legislation prohibiting unconventional drilling and completion operations. In the alternative, we have made preparations to participate in a 200-kilometer 2D seismic survey on the Sud Craiova license.

Discontinued Operations in Morocco

On June 27, 2011, we decided to discontinue 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 all periods presented, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International and Viking Geophysical. We have presented the oilfield services segment operating results as discontinued operations for the nine months ended September 30, 2012 and the three and nine months ended September 30, 2011.


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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 3. Significant accounting policies" to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011 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, 2011.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs ("ASU 2011-04"). ASU 2011-04 amends Accounting Standards Codification ("ASC") 820 Fair Value Measurements and Disclosures ("ASC 820"), providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurement and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 became effective for interim and annual periods beginning after December 15, 2011. We adopted ASU 2011-04 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In June 2011, FASB issued ASU 2011-05, Presentation of Comprehensive Income ("ASU 2011-05"). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. In December 2011, FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 ("ASU 2011-12"). ASU 2011-12 deferred the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. The amendments became effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted ASU 2011-05 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In September 2011, FASB issued ASU 2011-08, Testing Goodwill for Impairment ("ASU 2011-08"). ASU 2011-08 allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity would no longer be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 became effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted ASU 2011-08 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In December 2011, FASB issued ASU 2011-11, Balance Sheet (Topic 210):
Disclosures about Offsetting Assets and Liabilities("ASU 2011-11"). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.


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In July 2012, FASB issued ASU 2012-02, Intangibles-Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment ("ASU 2012-12"). The update provides an entity with the option first to assess qualitative factors in determining whether it is more likely than not that the indefinite-lived intangible asset is impaired. After assessing the qualitative factors, if an entity determines that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. If an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption was permitted. We did not early adopt the provisions of this ASU. We do not expect the impact of adopting this ASU to be material to the Company's financial position, results of operations or cash flows.

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 Operations-Three Months Ended September 30, 2012 Compared to Three
Months Ended September 30, 2011

Our results of operations for the three months ended September 30, 2012 and 2011
were as follows:



                                                                  Three Months Ended September 30,                                             Change
                                                        2012                                            2011                                  2012-2011
                                                                                              (See Note 1)
                                                        (in thousands of U.S. dollars, except per unit prices and costs and  production volumes)
Production:
Oil (Mbbl)                                                            229                                             222                                   7
Natural gas (Mmcf)                                                    928                                           1,426                                (498 )
Total production (Mboe)                                               384                                             460                                 (76 )
Average prices:
Oil (per Bbl)                               $                      105.81                   $                      104.43               $                1.38
Natural gas (per Mcf)                       $                        8.14                   $                        6.53               $                1.61
Oil equivalent (per Boe)                    $                       82.78                   $                       68.74               $               14.04
Revenues:
Oil and natural gas sales                   $                      31,786                   $                      31,621               $                 165
Costs and expenses:
Production                                                          4,542                                           3,329                               1,213
Exploration, abandonment and
impairment                                                          2,104                                           3,944                              (1,840 )
Seismic and other exploration                                       1,725                                           3,174                              (1,449 )
General and administrative                                          6,744                                           8,949                              (2,205 )
Depletion                                                           7,794                                          10,347                              (2,553 )
Depreciation and amortization                                         353                                           1,021                                (668 )
Interest and other expense                                          1,086                                           3,314                              (2,228 )
Gain (loss) on commodity derivative
contracts:
Cash settlements on commodity
derivative contracts                                                 (853 )                                        (1,304 )                               451
Non-cash change in fair value on
commodity derivative contracts                                     (6,293 )                                         7,764                             (14,057 )

Total gain (loss) on commodity
derivative contracts                                               (7,146 )                                         6,460                             (13,606 )
Oil and gas costs per Boe:
Production                                  $                       11.83                   $                        7.24               $                4.59
Depletion                                   $                       20.30                   $                       22.49               $               (2.19 )

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $0.2 million to $31.8 million for the three months ended September 30, 2012, from $31.6 million realized in the same period in 2011. Of the increase, $5.4 million resulted from an increase in our average price received for production, offset by a decrease of $5.2 million due to lower production volumes. Our average price received for production increased $14.04 per Boe to $82.78 per Boe for the three months ended September 30, 2012, from $68.74 per Boe for the same period in . . .

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