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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2014
OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-34574
TRANSATLANTIC PETROLEUM LTD.
(Exact name of registrant as specified in its charter)
Bermuda |
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None |
(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
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16803 Dallas Parkway Addison, Texas |
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75001 |
(Address of principal executive offices) |
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(Zip Code) |
Registrant’s telephone number, including area code: (214) 220-4323
Securities registered pursuant to Section 12(b) of the Act:
Title of each class |
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Name of each exchange on which registered |
Common shares, par value $0.10 |
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NYSE MKT |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer |
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Accelerated filer |
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Non-accelerated filer |
¨ (Do not check if a smaller reporting company) |
Smaller reporting company |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of common shares, par value $0.10 per share, held by non-affiliates of the registrant, based on the last sale price of the common shares on June 30, 2014 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $257.1 million. For purposes of this computation, all officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such officers, directors or 10% beneficial owners are, in fact, affiliates of the registrant.
As of March 6, 2015, there were 40,777,149 common shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2015 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.
TRANSATLANTIC PETROLEUM LTD.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014
INDEX
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Item 1. |
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Item 1A. |
15 |
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Item 1B. |
28 |
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Item 2. |
29 |
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Item 3. |
45 |
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Item 4. |
45 |
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Item 5. |
46 |
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Item 6. |
47 |
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Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
48 |
Item 7A. |
61 |
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Item 8. |
62 |
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Item 9. |
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure |
63 |
Item 9A. |
63 |
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Item 9B. |
64 |
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Item 10. |
65 |
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Item 11. |
65 |
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Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
65 |
Item 13. |
Certain Relationships and Related Transactions, and Director Independence |
65 |
Item 14. |
65 |
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Item 15. |
66 |
Forward-Looking Statements
Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable U.S. and Canadian securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “plans,” “expects,” “estimates,” “budgets,” “intends,” “anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may” or other similar words.
By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements, including the factors discussed under Item 1A. Risk Factors in this Annual Report on Form 10-K. Such factors include, but are not limited to, the following: fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflicts; the negotiation and closing of material contracts; future capital requirements and the availability of financing; estimates and economic assumptions used in connection with our acquisitions; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; our ability to effectively integrate companies and properties that we acquire; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. 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 and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs; drilling of new wells; demand for oil and natural gas 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, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.
Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law.
Glossary of Selected Oil and Natural Gas Terms
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.
2D seismic. Geophysical data that depict the subsurface strata in two dimensions.
3D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic.
Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
i
Bbl/d. Barrels of oil per day.
Bcf. One billion cubic feet of natural gas.
Boe. Barrels of oil equivalent. Boe is not included in the DeGolyer and MacNaughton reserves report and is derived by the Company by converting natural gas to oil in the ratio of six Mcf of natural gas to one Bbl of oil. The conversion factor is the current convention used by many oil and natural gas companies. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Boepd. Barrels of oil equivalent per day.
Commercial well; commercially productive well. An oil and natural gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Directional drilling. The technique of drilling a well while varying the angle of direction of a well and changing the direction of a well to hit a specific target.
Dry hole; dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Exploitation. The continuing development of a known producing formation in a previously discovered field, including efforts to maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well.
Farm-in or farm-out. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location, the completion of other work commitments related to that acreage, or some combination thereof.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Frac; fracture stimulation. A stimulation treatment involving the fracturing of a reservoir and then injecting water, sand and chemicals into the fractures under pressure to stimulate hydrocarbon production in low-permeability reservoirs.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Initial production rate. Generally, the maximum 24-hour production volume from a well.
Mbbl. One thousand stock tank barrels.
Mboe. One thousand barrels of oil equivalent.
Mboepd. One thousand barrels of oil equivalent per day.
Mcf. One thousand cubic feet of natural gas.
ii
Mcf/d. One thousand cubic feet of natural gas per day.
Mmbbl. One million stock tank barrels.
Mmboe. One million barrels of oil equivalent.
Mmcf. One million cubic feet of natural gas.
Mmcf/d. One million cubic feet of natural gas per day.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Overriding royalty interest. An interest in an oil or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.
Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.
Productive well. A productive well is a well that is not a dry well.
Proved developed reserves. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
iii
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Recompletion. An operation within an existing well bore to make the well produce oil or natural gas from a different, separately producible zone other than the zone from which the well had been producing.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Sales volumes. The amount of production of oil or natural gas sold after deducting royalties and working interests owned by third parties.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is one of the most frequently occurring sedimentary rocks.
Standardized measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows for the years ended December 31, 2014, 2013 and 2012 are estimated by applying the simple average spot prices for the trailing twelve month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.
Tcf. One trillion cubic feet of natural gas.
Undeveloped acreage. License or lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Wellhead production. The volume of oil or natural gas produced after deducting royalties and working interests owned by third parties prior to any oil and natural gas lost or used from wellhead to market.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.
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In this Annual Report on Form 10-K, references to “we,” “us,” “our,” or the “Company” refer to TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis. Unless stated otherwise, all sums of money stated in this Annual Report on Form 10-K are expressed in U.S. Dollars.
Our Business
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 an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2014, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of March 1, 2015, approximately 36% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, the chairman of our board of directors and our chief executive officer.
Based on the reserves reports prepared by DeGolyer and MacNaughton (for Turkey) and Deloitte LLP (for Albania), independent petroleum engineers, our estimated proved reserves at December 31, 2014 were approximately 32,749 Mboe, of which 87.5% was oil. Of these estimated proved reserves, 68.2% were proved developed reserves. As of December 31, 2014, the PV-10 and Standardized Measure of our proved reserves were $884.4 million and $672.1 million, respectively. See “Item 2. Properties—Value of Proved Reserves” for a reconciliation of PV-10 to the Standardized Measure.
Recent Developments
Convertible Notes. During the two months ended February 20, 2015, we sold $55.0 million of 13.0% convertible notes due 2017 (the “Initial Notes”) in a non-brokered private placement. Subsequently, we exchanged the Initial Notes for substantially identical notes (the “Exchange Notes”) issued pursuant to an indenture, dated as of February 20, 2015, between ourselves and U.S. Bank National Association, as trustee. The Exchange Notes bear interest at a rate of 13.0% per annum and mature on July 1, 2017, unless earlier redeemed or converted.
Stream Acquisition. On November 18, 2014, we closed an arrangement under British Columbia law (the “Arrangement”) pursuant to an arrangement agreement (the “Arrangement Agreement”) with Stream Oil & Gas Ltd. (“Stream”) whereby we acquired all of the outstanding common shares of Stream in exchange for 3.2 million common shares of the Company issued at closing, and an additional 0.6 million common shares issuable if certain conditions are met. The total transaction value for the acquisition of Stream was approximately $23.9 million ($28.0 million if certain conditions are met) (at a deemed price of $7.41 per common share). Stream owns 100% of the interests in three onshore oil fields and one gas concession, consisting of one onshore gas field and one exploration license, all in Albania. We are now operating in Albania under the name TransAtlantic Albania Ltd.
Our Strengths
We believe that the following strengths provide us with meaningful competitive advantages:
Significant Exploration Acreage in Known Hydrocarbon Basins. As of December 31, 2014, we held approximately 1.8 million net acres in Turkey, Albania and Bulgaria. The majority of this acreage is exploratory, but lies within areas of known hydrocarbon production. We will seek to actively develop our acreage to monetize production, and we will consider joint ventures or farm-out agreements where appropriate.
Operations in Attractive Regions. We have focused our operations in countries that have established, yet underexplored petroleum systems, 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. Our production in Turkey is subject to a 12.5% royalty rate, and the corporate income tax rate is 20%. We sell our oil based on Brent crude pricing, and natural gas prices are generally higher in Turkey than in North America. During 2014, we realized average prices of $83.08 per Bbl for our oil sales volumes and $8.67 per Mcf for our natural gas sales volumes in Turkey. Our production in Albania is subject to a 12% royalty rate (which includes a 10% mineral tax) until we have recovered 100% of our costs.
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Growing Production and Reserves. We invested $134.8 million in exploration, development and acquisitions during 2014. Our investment resulted in a 168% increase in our proved reserves at December 31, 2014 as compared to December 31, 2013. In addition, during 2014, we increased our average daily wellhead production rate by 19.1%, as compared to 2013.
Strong and Experienced Board and Management Team. Our management team, led by our chairman and chief executive officer, Mr. Mitchell, includes executives and managers with significant industry, operational and technical experience, many of whom have an established history of working together in the industry. Mr. Mitchell previously built Riata Energy, Inc. (re-named SandRidge Energy, Inc.) into one of the largest privately-held energy companies in the United States before selling his controlling stake in 2006. In addition, we added Marlan Downey and Gregory Renwick to our board in 2013 and 2014, respectively. Mr. Downey, with over 50 years of experience in the industry, and Mr. Renwick, with over 35 years of experience in the industry, each brings significant geological and management experience to our board. In 2014, we also made significant additions to our management team, with a new president, chief operating officer and vice president of geosciences, providing a depth of exploration, acquisition, reservoir engineering, drilling and geological experience. In addition, in 2013, we added four senior technical employees who have substantial experience in geology, horizontal drilling, unconventional reservoirs and completions, and secondary recovery. On average, our technical management team possesses more than 28 years of industry experience.
Our Strategy
The following are key elements of our strategy:
Operate within Existing Cash Flows and Maintain Core Acreage. With the dramatic decline in oil prices, we are cutting our overhead and capital expenditures in an effort to operate within existing cash flow. Notwithstanding the decline in oil prices, we plan to drill at least five gross obligation wells in 2015 to hold our most promising licenses.
Increase Reserves and Production. Once oil prices stabilize and begin to recover, we plan to resume more robust investing in exploration and development to increase our oil and natural gas reserves and production in Turkey on our Arpatepe, Molla, Selmo and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling, fracture stimulation and enhanced oil recovery techniques. In Albania, we plan to complete the drilling and completion of the D34H1 well (the “D34H1”) and, depending upon the results, re-enter two other gas wells in the Delvina gas field. We also plan to revitalize our oilfields in Albania through well recompletions and reactivations, enlarging and lowering pumps and expanding waterfloods. We may also deepen and core several oil wells to better measure oil saturations and understand the potential of the oilfields.
Utilize New 3D Seismic Data to Improve Well Targeting. For the year ended December 31, 2014, we spent $3.7 million finalizing our 3D seismic survey over areas of Turkey where 3D seismic data did not previously exist. We received the processed data in the third quarter of 2014 and drilled several wells in the fourth quarter of 2014 based on the 3D seismic data, all resulting in successful wells, which are either producing or expected to be productive. 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 2014, we extensively used horizontal drilling techniques on our wells in the Selmo field to more effectively extract hydrocarbons and increase our returns on invested capital. We expect to continue using horizontal drilling techniques in 2015 in in the Selmo and Bahar fields.
Further Optimize Fracture Stimulation Program. In 2013 and 2014, we expanded our use of hydraulic fracturing technology to complete otherwise low porosity and permeability formations in Turkey. The evolution of fracturing fluids and stimulation designs has yielded positive results in southeastern Turkey. During 2015, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.
Pursue Other Growth or Financing Opportunities. In addition to growing our reserves and production through exploration and development of our substantial acreage in Turkey and Albania, we continually evaluate acquisition, joint venture and farm-in/out opportunities. We are focused on both strengthening our positions in Turkey and Albania as well as identifying opportunities in new countries, as we did in 2014 with our acquisition of Stream.
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Our Properties and Operations
Summary of Geographic Areas of Operations
The following table shows net reserves information as of December 31, 2014:
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Proved |
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Proved Developed |
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Undeveloped |
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Total Proved |
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Probable Reserves |
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Possible Reserves |
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Reserves (Mboe) |
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Reserves (Mboe) |
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Reserves (Mboe) |
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(Mboe) |
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(Mboe) |
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Turkey |
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8,449 |
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8,666 |
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17,115 |
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15,398 |
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24,818 |
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Albania |
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13,900 |
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1,734 |
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15,634 |
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13,341 |
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12,405 |
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Turkey
As of December 31, 2014, we held interests in 19 onshore and offshore exploration licenses and 20 onshore production leases covering a total of 1.8 million gross acres (1.1 million net acres) in Turkey. As of December 31, 2014, we had total net proved reserves of 14,406 Mbbl of oil and 16,254 Mmcf of natural gas, net probable reserves of 11,432 Mbbl of oil and 23,795 Mmcf of natural gas and net possible reserves of 12,028 Mbbl of oil and 76,739 Mmcf of natural gas in Turkey. During 2014, our average wellhead production was approximately 5,212 net Boepd of oil and natural gas in Turkey. The following summarizes our core producing properties in Turkey:
Southeastern Turkey. During 2014, substantially all of our oil production was concentrated in southeastern Turkey, primarily in the Arpatepe, Bahar, Goksu and Selmo oil fields. These fields are located southwest of the Turkish portion of the Zagros fold belt. The Zagros fold belt includes prolific oil trends that extend from Iran and Iraq into Turkey.
We hold a 100% working interest in the Selmo production lease, which expires in June 2025. The Selmo oil field is the second largest oil field in Turkey in terms of historical cumulative production and is responsible for the largest portion of our current crude oil production. In 2014, we drilled 12 horizontal developmental wells in the field, which had an average initial production rate of approximately 300 Bbl/d per well. We also initiated waterflood and polymer injection pilot test programs in the Selmo field in 2014. We believe secondary recovery will increase production from the field. For 2014, our net wellhead production of crude oil from the Selmo field was 1,027,639 Bbls at an average rate of approximately 2,815 Bbl/d. Turkiye Petrolleri Anonim Ortakligi (“TPAO”), a Turkish government-owned oil and natural gas company, and Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, purchase all of our crude oil production from the Selmo oil field, which is transported by truck to their neighboring facilities. At December 31, 2014, we had 60 net producing wells in the Selmo oil field.
We hold a 100% working interest in each of our four Molla exploration licenses, which contain the Goksu and Bahar oil fields. In the Goksu field, we are primarily targeting the Mardin formation, and in the Bahar field, we are primarily targeting the Bedinan and Hazro formations. We completed shooting our 800 square kilometer Molla 3D seismic program in April 2014, and the initial phase of processed data was delivered in the third quarter of 2014. In 2014, we completed three vertical wells and one re-entry directional well in the Bahar field. For 2014, our wellhead production of crude oil from the Molla exploration licenses was 213,609 Bbls at an average rate of approximately 585 Bbl/d. At December 31, 2014, we had seven net producing wells on the Molla exploration licenses.
We hold a 50% working interest in our Arpatepe production lease and exploration license. For 2014, our wellhead production of crude oil from the Arpatepe field was 64,857 Bbls at an average rate of approximately 178 Bbl/d. In 2014, we drilled two vertical wells in the Arpatepe field, which had a gross average initial production rate of approximately 370 Bbl/d per well. At December 31, 2014, we had five gross (2.5 net) producing wells on the Arpatepe production lease.
Northwestern Turkey. Substantially all of our natural gas production is concentrated in the Thrace Basin, which is one of Turkey’s most productive onshore natural gas regions. It is located in northwestern Turkey near Istanbul. We have accumulated significant onshore acreage in the Thrace Basin.
Our goal is to monetize proven formations in the Thrace Basin. For 2014, our wellhead production of natural gas in the Thrace Basin was approximately 3,384 Mmcf, or approximately 9.3 Mmcf/d. In 2014, we drilled three horizontal wells and six vertical conventional wells in the Thrace Basin area. As of December 31, 2014, we had 140 gross (66.5 net) producing wells on our Thrace Basin properties, and we plan to focus on prospect and development locations in the Thrace Basin during 2015.
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Bulgaria
As of December 31, 2014, we held interests in one onshore exploration concession and one onshore production concession covering a total of 567,000 acres in Bulgaria. During 2014, our wellhead production was approximately 3.3 Mmcf of natural gas on a limited test basis in Bulgaria. At December 31, 2014, we had no reserves in Bulgaria.
On November 14, 2012, Bulgaria’s Council of Ministers awarded our subsidiary, Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), a 35-year production concession covering the approximately 163,000 gross acre Koynare concession area (the “Koynare Concession Area”). The Koynare Concession Area contains the Deventci-R1 well, where we discovered a natural gas reservoir in the Jurassic-aged Ozirovo formation at a depth of approximately 13,800 feet, which the Bulgarian government has certified as a geologic and commercial discovery. During 2013, our wellhead production was approximately 15.8 Mmcf of natural gas on a limited test basis, which was sold to a compressed natural gas facility adjacent to the Deventci-R1 well.
In August 2013, we entered into a farm-out agreement with Koynare Development Ltd. (“KDL”), a private oil and natural gas investment company, pursuant to which KDL would fund 75% of our initial $40 million work program in Bulgaria in exchange for a 50% interest in our Koynare Concession Area. We will also assign KDL 50% of our interest in our Stefenetz concession area, subject to LNG Energy Ltd’s (now Esrey Energy) (“Esrey”) farm-out interest, in the event that the pending concession application is approved by the Bulgarian government.
In January 2012, the Bulgarian Parliament enacted legislation that banned fracture stimulation in the Republic of Bulgaria. The legislation had the effect of preventing conventional drilling and completion activities. As a result, we temporarily suspended drilling and completion operations in Bulgaria in January 2012. In June 2012, the Bulgarian Parliament amended the legislation to clarify that conventional operations were not intended to be affected by the law. Accordingly, our conventional natural gas exploration, development and production activity in Bulgaria resumed in 2013. The current legislation significantly constrains our unconventional natural gas exploration, development and production activities in Bulgaria.
During the second half of 2013, we resumed drilling the Deventci-R2 directional well on our Koynare Concession Area. In January 2014, we reached target depth of 14,100 feet on the Deventci-R2 well and conducted a long-term pressure build-up test on the well during the second quarter of 2014 to evaluate the well’s connectivity to the reservoir following an initial production test of approximately 2.0 Mmcf/d of natural gas with condensates. In the fourth quarter of 2014, we received approval from the Bulgarian government to acidize the well. We conducted initial stimulation in December 2014 to enhance the well’s productivity and are currently evaluating the results of the stimulation.
In November 2011, we initiated the application process for a production concession covering approximately 395,000 gross acres over the southern portion of our former A-Lovech exploration permit (the “Stefenetz Concession Area”). The Stefenetz Concession Area is estimated to contain over 300,000 prospective acres of Etropole shale at a depth of approximately 12,500 feet, which the Bulgarian government has certified as a geologic discovery. During 2012, we initiated an environmental impact assessment which the Bulgarian government must approve prior to granting the production concession. We applied for a commercial discovery in the fourth quarter of 2011 for the Peshtene R-11 well. The Ministry of Economy and Energy rejected our application in July 2014. We appealed the decision in accordance with Bulgarian law and are awaiting a decision from the Ministry of Economy and Energy. Pursuant to our agreement with Esrey, if we obtain a production concession over the Stefenetz Concession Area, Esrey would fund an additional $12.5 million in exchange for a 50% working interest in the production concession. The remaining 50% working interest in the production concession would be split equally between us and KDL.
Albania
We own 100% of the interests in three onshore oil fields and one gas concession consisting of one onshore gas field and one exploration license in Albania. As of December 31, 2014, we had total net proved reserves of 14,259 Mbbl of oil and 8,249 Mmcf of natural gas, net probable reserves of 10,014 Mbbl of oil and 19,963 Mmcf of natural gas and net possible reserves of 7,152 Mbbl of oil and 31,518 Mmcf of natural gas in Albania. During 2014, we had net production (before mineral taxes) of 842 Bbl/d of oil and no natural gas. The following summarizes our core producing properties in Albania:
Ballsh-Hekal. We have taken over 23 wells (of which 13 are producing) from Albpetrol Sh.A (“Albpetrol”) in the Ballsh-Hekal field. We believe that a significant number of these wells did not penetrate the entire hydrocarbon column. Albpetrol still operates approximately 60 wells in the field. We have the right to take over the remaining wells at our option, which we expect to do in 2015. During 2014, our net production (before mineral taxes) was 86 Bbl/d of oil from the field.
Cakran-Mollaj. We have taken over 70 wells (of which approximately 30 are producing) from Albpetrol in the Cakran-Mollaj field. We believe that a significant number of these wells did not penetrate the entire hydrocarbon column. During 2014, our net
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production (before mineral taxes) was approximately 307 Bbl/d of oil from this field. We are working on improving the reliability of surface equipment in this field prior to reactivating and recompleting additional wells.
Gorisht-Kocul. We have taken over all 295 wells (of which approximately half are producing) in the Gorisht-Kocul field from Albpetrol. We believe that a significant number of these wells did not penetrate the entire hydrocarbon column. During 2014, our net production (before mineral taxes) from this field was 449 Bbl/d of oil. We are in the process of conducting two waterflood projects in this reservoir, which have mitigated the natural pressure and production decline in portions of this field. In addition, we intend to workover and reactivate existing wells with modern rod pumps and progressive cavity pumps.
Delvina Concession. We own the Delvina Concession, which is comprised of the partially-developed Delvina field and the Delvina exploration block.
Delvina Field. The Delvina natural gas field has two previously producing vertical wells, the Delvina D4 and D12 wells. During the workover of the Delvina D12 well in 2013, after successful stimulation and flow tests, Stream encountered an obstruction in the completion string that could not be removed through solvent injection and was planning further workover procedures. We plan to bring the Delvina D4 well back online following workover of the well. In April 2014, Stream spud the D34H1 well in the Delvina field, reaching a depth of approximately 750 meters before temporarily abandoning drilling due to a lack of funds. Drilling operations on the D34H1 well will resume during the first half of 2015. The Delvina natural gas field is connected to potential markets by an existing pipeline, including to a local thermal power plant, but needs additional downstream capacity.
Delvina Block. Under the Delvina License Agreement and Petroleum Agreement, we have the right to develop approximately 60,000 acres adjacent to the Delvina natural gas field, referred to as the Delvina Block. The Delvina Block offers significant exploration potential.
Current Operations
As of March 1, 2015, our net wellhead production in Turkey was an aggregate of approximately 4,164 Bbl/d, primarily from the Selmo production lease, Arpatepe production lease and Molla exploration licenses, and approximately 7.1 Mmcf/d of natural gas, primarily from our various Thrace Basin production leases and exploration licenses. As of March 1, 2015, our net production (before mineral taxes) in Albania was an aggregate of approximately 652 Bbl/d. The following describes our current operations by country:
Turkey. We are not engaging in any new drilling activities in Turkey during the first quarter of 2015.
Bulgaria. In the fourth quarter of 2014, we received approval from the Bulgarian government to acidize the Deventci-R2 well on the Koynare Concession Area. We conducted initial stimulation in December 2014 to enhance the well’s productivity and are currently evaluating the results of the stimulation.
Albania. We plan to resume drilling the D34H1 well during the first half of 2015.
Planned Operations
We expect our net field capital expenditures for 2015 to range between $12.0 and $38.0 million. We expect net field capital expenditures during 2015 include approximately $12.0 million of drilling and completion expense for five gross obligation wells to hold our most promising licenses in Turkey. We expect cash on hand, proceeds from the sale of our convertible notes, and cash flow from operations will be sufficient to fund our 2015 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2015 capital expenditure budget is subject to change.
Exploration, Development and Production. We currently plan to execute the following drilling and exploration activities during 2015:
Turkey. We plan to drill five gross license obligations wells. Depending upon oil pricing, we may resume drilling in our Molla area or the Selmo field. We also plan to complete the Pinar-1 and Ebiyat-2 wells during the first half of 2015.
Bulgaria. We plan to evaluate additional completion activities on the Deventci-R2 well.
Albania. We plan to resume drilling the D34H1 well during the first half of 2015.
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Principal Markets
In accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, Segment Reporting (“ASC 280”), we currently have three reportable geographic segments: Turkey, Albania and Bulgaria. For financial information about our operating segments and geographic areas, refer to “Note 12—Segment information” to our consolidated financial statements.
Customers
Oil. During 2014, 78.6% of our oil production was concentrated in the Selmo field in Turkey. TUPRAS purchases the majority of our oil production from the Selmo field. During 2014, we sold $102.8 million of oil to TUPRAS, representing approximately 73.0% of our total revenues. We sell our oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement. Under the purchase and sale agreement, TUPRAS purchases oil produced by us and delivered to our Boru Hatlari ile Petrol Tasima A.S. (“BOTAŞ”) Batman tanks and to the BOTAŞ Dörtyol plant. The price of the oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. The purchase and sale agreement automatically renews for successive one-year terms unless earlier terminated in writing by either party. No other purchasers of our oil accounted for more than 10% of our total revenues.
Natural Gas. During 2014, no purchasers of our natural gas accounted for 10% or more of our total revenues.
Competition
We operate in the highly competitive areas of oil and natural gas exploration, development, production and acquisition with a substantial number of other companies, including U.S.-based and international companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:
· |
seeking oil and natural gas exploration licenses and production licenses and leases; |
· |
acquiring desirable producing properties or new leases for future exploration; |
· |
marketing oil and natural gas production; |
· |
integrating new technologies; and |
· |
contracting for drilling services and equipment and securing the expertise necessary to develop and operate properties. |
Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for and produce oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
Fracture Stimulation Program
Oil and natural gas may be recovered from our properties through the use of fracture stimulation combined with modern drilling and completion techniques. Fracture stimulation involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We have successfully utilized fracture stimulation in our Thrace Basin, Molla and Selmo licenses and production leases.
For unconventional reservoirs, including the Mezardere formation in the Thrace Basin, a typical fracture stimulation consists of injecting between 20,000 and 100,000 gallons of fluid that contain between 10,000 and 150,000 pounds of sand. Fluids vary depending on formation and treatment objective but, in general, are either slickwater (fresh water with salt and friction reducer) or a gelled fluid containing organic polymers with a 4% potassium chloride solution and required breakers. Fracture stimulations in Selmo and Molla are conducted in a low permeability carbonate reservoir. These stimulations generally consist of injecting between 20,000 and 100,000 gallons of fluid that contain between 10,000 and 100,000 pounds of sand. Fluids are generally a mixture of slickwater and 15% hydrochloric acid, which is typical in carbonate stimulation. The size of fracture stimulation treatments is dependent on net pay thickness and the proximity of the hydrocarbon zones of interest to water bearing zones.
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Although the cost of each well will vary, on average approximately 30% of the total cost of drilling and completing a well in the unconventional Mezardere formation in the Thrace Basin and approximately 15% of the total cost of completing a well at Selmo is associated with fracture stimulation activities. We account for these costs as typical drilling and completion costs and include them in our capital expenditure budget.
We believe that the stacked nature of the sandstone intervals within the Mezardere unconventional formation, which is up to approximately 5,300 feet thick, and the limited number of deep penetrations to date on these structures provides significant opportunities for additional drilling and multi-stage fracs as the program matures.
We diligently review best practices and industry standards in connection with fracture stimulation activities and strive to comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across potable water sources, cementing surface casing from setting depth to surface and second string from setting depth up into the surface casing and, in some cases, to surface, continuously monitoring the fracture stimulation process in real time and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources or at a certified water treatment plant. There have not been any incidents, citations or suits involving environmental concerns related to our fracture stimulation operations on our properties.
In the Thrace Basin, Selmo and Molla, we have access to water resources which we believe will be adequate to execute our fracture stimulation program in 2015. We also employ procedures for environmentally friendly disposal of fluids recovered from fracture stimulation, including recycling approximately 50% of these fluids.
For more information on the risks of fracture stimulation, please read “Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry—Our oil and natural gas operations are subject to extensive and complex laws and government regulation in the jurisdictions in which we operate and compliance with existing and future laws may increase our costs or impair our operations” and “Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry—Legislative and regulatory initiatives and increased public scrutiny relating to fracture stimulation activities could result in increased costs and additional operating restrictions or delays.”
Governmental Regulations
Government Regulation. Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations concerning exploration, development, production, exports, taxes, labor laws and standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. Due to our international operations, we are subject to the following issues and uncertainties that can affect our operations adversely:
· |
the risk of expropriation, nationalization, war, revolution, political instability, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs; |
· |
laws of foreign governments affecting our ability to fracture stimulate oil or natural gas wells, such as the legislation enacted in Bulgaria in January 2012 and the temporary suspension of unconventional exploration and drilling activities imposed in Romania in 2012; |
· |
the risk of not being able to procure residency and work permits for our expatriate personnel; |
· |
taxation policies, including royalty and tax increases and retroactive tax claims; |
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exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations; |
· |
laws and policies of the United States affecting foreign trade, taxation and investment, including anti-bribery and anti-corruption laws; |
· |
the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and |
· |
the possibility of restrictions on repatriation of earnings or capital from foreign countries. |
Permits and Licenses. In order to carry out exploration and development of oil and natural gas interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved.
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Repatriation of Earnings. Currently, there are no restrictions on the repatriation of earnings or capital to foreign entities from Turkey, Albania or Bulgaria. However, there can be no assurance that any such restrictions on repatriation of earnings or capital from the aforementioned countries or any other country where we may invest will not be imposed in the future. We may be liable for the payment of taxes upon repatriation of certain earnings from the aforementioned countries.
Environmental. The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. These regulations can have an impact on the selection of drilling locations and facilities, and potentially result in increased capital expenditures. In addition, environmental legislation may require those wells and production facilities to be abandoned and sites reclaimed to the satisfaction of local authorities. Such regulation has increased the cost of planning, designing, drilling, operating and, in some instances, abandoning wells. We are committed to complying with environmental and operational legislation wherever we operate.
There has been a recent surge in interest among the media, government regulators and private citizens concerning the possible negative environmental and geological effects of fracture stimulation. Some have alleged that fracture stimulation results in the contamination of aquifers and may even contribute to seismic activity. In January 2012, the government of Bulgaria enacted legislation that banned the fracture stimulation of oil and natural gas wells in the Republic of Bulgaria and imposed large monetary penalties on companies that violate that ban. In 2012, the Romanian government temporarily suspended unconventional drilling and exploration of hydrocarbons, including fracture stimulation, pending a government review of unconventional drilling and completion techniques. As a result of the suspension, we relinquished our Sud Craiova license in Romania. There is a risk that Turkey or Albania could at some point impose similar legislation or regulations. Such legislation or regulations could severely impact our ability to drill and complete wells, and could increase the cost of planning, designing, drilling, completing and operating wells. We are committed to complying with legislation and regulations involving fracture stimulation wherever we operate.
Such laws and regulations not only expose us to liability for our own negligence, but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.
Insurance
We currently carry general liability insurance and excess liability insurance, including pollution insurance, with a combined annual limit of $22.0 million per occurrence and $24.0 million in the aggregate. These insurance policies contain maximum policy limits and are subject to customary exclusions and limitations. Our general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if, the general liability insurance per occurrence limit is reached.
We also maintain control of well insurance. Our control of well insurance has a per occurrence and combined single limit of $15.0 million and is subject to deductibles ranging from $150,000 to $500,000 per occurrence.
We require our third-party service providers to sign master service agreements with us pursuant to which they agree to indemnify us for the personal injury and death of the service provider’s employees as well as subcontractors that are hired by the service provider. Similarly, we generally agree to indemnify our third-party service providers against similar claims regarding our employees and our other contractors.
We also require our third-party service providers that perform fracture stimulation operations for us to sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to fracture stimulation operations. We believe that our general liability, excess liability and pollution insurance policies would cover third-party claims related to fracture stimulation operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policies may not cover fines, penalties or costs and expenses related to government-mandated environmental clean-up responsibilities.
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Bermuda Tax Exemption
As a Bermuda exempted company and under current Bermuda law, we are not subject to tax on profits, income or dividends, nor is there any capital gains tax applicable to us in Bermuda. Profits can be accumulated, and it is not obligatory for us to pay dividends.
Furthermore, we have received an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966, as amended, that in the event that Bermuda enacts any legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, we and any of our operations or our shares, debentures or other obligations shall be exempt from the imposition of such tax until March 31, 2035, provided that such exemption shall not prevent the application of any tax payable in accordance with the provisions of the Land Tax Act, 1967 or otherwise payable in relation to land in Bermuda leased to us.
We are required to pay an annual government fee (the “AGF”), which is determined on a sliding scale by reference to our authorized share capital and share premium account, with a minimum fee of $1,995 Bermuda Dollars and a maximum fee of $31,120 Bermuda Dollars. The Bermuda Dollar is treated at par with the U.S. Dollar. The AGF is payable each year on or before the end of January and is based on the authorized share capital and share premium account on August 31 of the preceding year.
In Bermuda, stamp duty is not chargeable in respect of the incorporation, registration, licensing of an exempted company or, subject to certain minor exceptions, on their transactions.
Employees
As of December 31, 2014, we employed 719 people. Approximately 40 of our employees at one of our subsidiaries operating in Turkey were represented by collective bargaining agreements with the Petroleum, Chemical and Rubber Workers Union of Turkey (“PETROL-IS”). Approximately 35 of our employees at another of our subsidiaries operating in Turkey were represented by a separate collective bargaining agreement with PETROL-IS. We consider our employee relations to be satisfactory.
Formation
We were incorporated under the laws of British Columbia, Canada on October 1, 1985 under the name Profco Resources Ltd. and continued to the jurisdiction of Alberta, Canada under the Business Corporations Act (Alberta) on June 10, 1997. Effective December 2, 1998, we changed our name to TransAtlantic Petroleum Corp. Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Bermuda Companies Act 1981 under the name TransAtlantic Petroleum Ltd.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.transatlanticpetroleum.com as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.
Executive Officers of the Registrant
The following table and text sets forth certain information with respect to our executive officers as of March 1, 2015:
Name |
|
Age |
|
Positions |
N. Malone Mitchell 3rd |
|
53 |
|
Chairman and Chief Executive Officer |
Todd C. Dutton |
|
61 |
|
President |
James R. Huling |
|
52 |
|
Chief Operating Officer |
Wil F. Saqueton |
|
45 |
|
Vice President and Chief Financial Officer |
Matthew W. McCann |
|
46 |
|
General Counsel and Corporate Secretary |
Harold “Lee” Muncy |
|
62 |
|
Vice President of Geosciences |
N. Malone Mitchell 3rd has served as our chief executive officer since May 2011, as a director since April 2008 and as our chairman since May 2008. Since 2005, Mr. Mitchell has served as the president of Riata Corporate Group, LLC, a Dallas-based private oil and natural gas exploration and production company. From June to December 2006, Mr. Mitchell served as president and chief operating officer of SandRidge Energy, Inc. (formerly Riata Energy, Inc.), an independent oil and natural gas company concentrating in exploration, development and production activities. Until he sold his controlling interest in Riata Energy, Inc. in June 2006, Mr. Mitchell also served as president, chief executive officer and chairman of Riata Energy, Inc., which Mr. Mitchell founded in 1985 and built into one of the largest privately held energy companies in the United States.
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Todd C. Dutton has served as our president since May 2014. Mr. Dutton has served as president of Longfellow Energy, LP ("Longfellow"), a Dallas, Texas-based independent oil and natural gas exploration and production company owned by the Company's chairman and chief executive officer, N. Malone Mitchell 3rd and his family, since January 2007, where his primary responsibility is to originate and develop oil and natural gas projects. He brings 37 years of experience in the oil and natural gas industry, focusing on exploration, acquisitions and property evaluation. He has served in various supervisory and management roles at Texas Pacific Oil Company, Coquina Oil Corporation, BEREXCO INC. and Riata Energy, Inc. Mr. Dutton earned a B.B.A. in Petroleum Land Management from the University of Oklahoma.
James R. Huling has served as the Company’s chief operating officer since May 2014. He has also served as chief operating officer of Longfellow since May 2012. From 2007 until May 2012, Mr. Huling served as president of Kiamichi Energy Corporation, a Fort Worth, Texas-based consulting and production company that he founded. He brings nearly 30 years of experience in reservoir engineering, drilling, and completion operations and production optimization. Mr. Huling began his career with Kerr-McGee Corporation and subsequently held engineering and operational roles with Encore Acquisition Company, Riata Energy, Inc. and Ovation Energy Partners before founding Kiamichi Energy Corporation.
Wil F. Saqueton has served as the Company’s vice president and chief financial officer since August 2011. Mr. Saqueton previously served as the Company’s corporate controller from May 2011 until August 2011 and as a consultant to the Company from February 2011 until May 2011. Prior to joining the Company, Mr. Saqueton served as the vice president and chief financial officer of BCSW, LLC, the owner of Just Brakes in Dallas, Texas, from July 2006 to December 2010. From July 1995 until July 2006, he held a variety of positions at Intel Corporation, including strategic controller at the Chipset Group, operations controller at the Americas Sales and Marketing Organization Division, finance manager at the Intel Online Services, Inc. Division and senior financial analyst at the Chipset Group. Prior to 1995, Mr. Saqueton was a senior associate at Price Waterhouse, LP.
Matthew W. McCann has served as the Company’s general counsel and corporate secretary since August 6, 2014. Mr. McCann also has served as counsel for Riata Corporate Group, LLC and business development specialist for Longfellow since 2011 and from 2007 to 2009. From 2009 to 2011, Mr. McCann served as chief executive officer of the Company. Prior to joining Riata Corporate Group and Longfellow, he served as senior vice president, legal and corporate secretary for SandRidge Energy, Inc. Mr. McCann began his legal career at Sprouse Shrader Smith PLLC in Amarillo, Texas.
Harold “Lee” Muncy has served as the Company’s vice president of geosciences since June 2014. Mr. Muncy previously served as vice president, exploration for the Bass Companies, a group of Fort Worth, Texas-based independent oil and natural gas exploration and production companies, where he worked from 2000 to 2012. He brings more than 35 years of geological experience in the oil and natural gas industry, where he has focused on exploration, exploitation and worldwide transactions. He began his career as a geologist with Mobil Oil Corporation and served as exploration manager for Fina Oil & Chemical Company and vice president of exploration and land for TransTexas Gas Corp. Mr. Muncy earned a B.S. and an M.S. in Geology & Mineralogy from The Ohio State University.
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Risks Related to Our Business
A decline in oil and natural gas prices may adversely affect our results of operations, financial condition or ability to meet our capital expenditure obligations and financial commitments.
Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Oil prices have declined substantially in recent months and may remain at or below current levels in the near future. The market price of Brent crude oil has decreased approximately 50% since June 2014 as a result of market uncertainties over the supply and demand of oil due to increased production in certain regions, decisions made by OPEC, the current state of the global economy and concerns over future global oil demand. Lower oil and natural gas prices, such as the recent substantial decline in oil prices, may reduce the amount of oil and natural gas that we can produce economically, make some wells uneconomical to drill or operate, reduce our ability to develop our properties, reduce our ability to offset the natural decline in production from producing wells through new development and result in lower reserves. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future.
A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. The recent substantial decline in oil prices may adversely impact the ultimate development of the quantity of reserves that we reported at December 31, 2014. If oil or natural gas prices continue to decline in the future, we might not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:
· |
market expectations regarding supply and demand for oil and natural gas; |
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decreased demand due to weak global economic growth; |
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levels of production and other activities of the Organization of Petroleum Exporting Countries and other oil and natural gas producing nations; |
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market expectations about future prices; |
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the level of global oil and natural gas exploration, production activity and inventories; |
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political conditions, including embargoes, in or affecting oil and natural gas production activities; |
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increased production due to new extraction developments and improved extraction and production methods; and |
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the price and availability of alternative fuels. |
Our businesses, results of operations, future rate of growth and quantities of reserves that are commercially recoverable depend heavily on the prices we receive for oil sales. Oil prices also affect our cash flows available for capital expenditure obligations and financial commitments. No assurance can be given that future oil prices will be at levels which enable us to do business profitably or at levels that make it economically viable to produce from certain wells. A decline in oil or natural gas prices may have a material adverse effect on our business, financial condition and results of operations.
We may be required to write down the carrying values of our oil and natural gas properties.
Oil prices have declined substantially in recent months and may remain at or below current levels in the near future. There is a risk that due to the recent decline in oil prices or future declines in oil prices, we could be required to write down the carrying value of our oil and natural gas properties, which would reduce our earnings and shareholders’ equity. We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, the costs of productive wells, developmental dry holes and productive leases are capitalized. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be non-productive. The capitalized costs of our oil and natural gas properties may not exceed their estimated fair market value. When evaluating our proved properties, we are required to test for potential write-downs at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets, which is typically on a field-by-field basis. If capitalized costs exceed future cash flows, we write down the costs of proved properties to our estimate of fair market value, which is generally estimated using a discounted cash flow approach. When evaluating our unproved properties, we write down the capitalized costs of the unproved properties if it is determined that the costs are
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not likely to be recoverable. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity.
We have a history of losses and may not achieve consistent profitability in the future.
We have incurred substantial losses in prior years. During 2014, we generated net income from continuing operations of $29.1 million. We will need to generate and sustain increased revenue levels in future periods in order to become consistently profitable, and even if we do, we may not be able to maintain or increase our level of profitability. We may incur losses in the future for a number of reasons, including risks described herein, unforeseen expenses, difficulties, complications and delays, and other unknown risks.
Our exploration, development and production activities may not be profitable or achieve our expected returns.
The future performance of our business will depend upon our ability to identify, acquire and develop additional oil and natural gas reserves that are economically recoverable. Success will depend upon our ability to acquire working and revenue interests in properties upon which oil and natural gas reserves are ultimately discovered in commercial quantities, and the ability to develop prospects that contain additional proven oil and natural gas reserves to the point of production. Without successful acquisition and exploration activities, we will not be able to develop additional oil and natural gas reserves or generate additional revenues. There are no assurances that additional oil and natural gas reserves will be identified or acquired on acceptable terms, or that oil and natural gas reserves will be discovered in sufficient quantities to enable us to recover our exploration and development costs or sustain our business.
The successful acquisition and development of oil and natural gas properties requires an assessment of recoverable reserves, future oil and natural gas prices and operating costs, potential environmental and other liabilities, and other factors. Such assessments are inherently uncertain. In addition, no assurance can be given that our exploration and development activities will result in the discovery of additional reserves. Operations may be curtailed, delayed or canceled as a result of lack of adequate capital and other factors, such as lack of availability of rigs and other equipment, title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties, or unusual or unexpected formations, pressures and/or work interruptions. In addition, the costs of exploration and development may materially exceed our internal estimates.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future success depends on the success of our exploration, development and production activities in each of our prospects. These activities are subject to numerous risks beyond our control, including the risk that we will be unable to economically produce our reserves or be able to find commercially productive oil or natural gas reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project unprofitable. Further, many factors may curtail, delay or prevent drilling operations, including:
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unexpected drilling conditions; |
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pressure or irregularities in geological formations; |
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equipment failures or accidents; |
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pipeline and processing interruptions or unavailability; |
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title problems; |
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adverse weather conditions; |
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lack of market demand for oil and natural gas; |
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delays imposed by, or resulting from, compliance with environmental laws and other regulatory requirements; |
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declines in oil and natural gas prices; and |
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shortages or delays in the availability of drilling rigs, equipment and qualified personnel. |
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Our future drilling activities might not be successful, and drilling success rates overall or within a particular area could decline. We could incur losses by drilling unproductive wells. Shut-in wells, curtailed production and other production interruptions may materially adversely affect our business, financial condition and results of operations.
Shortages of drilling rigs, equipment, oilfield services and qualified personnel could delay our exploration and development activities and increase the prices we pay to obtain such drilling rigs, equipment, oilfield services and personnel.
Our industry is cyclical and, from time to time, there may be a shortage of drilling rigs, equipment, oilfield services and qualified personnel in the countries in which we operate. Shortages of drilling and workover rigs, pipe and other equipment may occur as demand for drilling rigs and equipment increases, along with increases in the number of wells being drilled. These factors can also cause significant increases in costs for equipment, oilfield services and qualified personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly increase our net loss, decrease our cash provided by operating activities, or restrict our ability to conduct the exploration and development activities we currently have planned and budgeted or which we may plan in the future. In addition, the availability of drilling rigs can vary significantly from region to region at any particular time. An undersupply of rigs in any of the regions where we operate may result in drilling delays and higher drilling costs for the rigs that are available in that region.
We depend on the services of our chairman and chief executive officer.
We depend on the performance of Mr. Mitchell, our chairman and chief executive officer. The loss of Mr. Mitchell could negatively impact our ability to execute our strategy. We do not maintain a key person life insurance policy on Mr. Mitchell.
The majority of our oil is sold to one customer, and the loss of this customer could have a material adverse impact on our results of operations.
TUPRAS purchases all of our oil production from Turkey, representing 72.0% of our total revenues in 2014. If TUPRAS reduces its oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TUPRAS may be subject to its own operating risks that could increase the risk that it could default on its obligations to us. Under Turkish law, TUPRAS is obligated to purchase all of our oil production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer. Pursuant to a purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. Changes to Turkish law could adversely affect our business and results of operations.
A significant failure of our computer systems may increase our operating costs or otherwise adversely affect our business.
We depend upon our computer systems to perform accounting and administrative functions as well as manage other aspects of our operations. Our computer systems and networks are subject to risks that may cause interruptions in service, including, but not limited to, security breaches, physical damage, power loss, software defects, hacking attempts, computer viruses and malware, lost data and programming and/or human errors. Significant interruptions in service, security breaches or lost data may have a material adverse effect on our business, financial condition or results of operations.
We could lose permits or licenses on certain of our properties in Turkey unless the permits or licenses are extended or we commence production and convert the permits or licenses to production leases or concessions.
At December 31, 2014, of our total net undeveloped acreage, 24.0% and 22.6% will expire during 2015 and 2016, respectively, unless we are able to extend the permits or licenses covering this acreage or commence production on this acreage and convert the permits or licenses into production leases or concessions. If our permits or licenses expire, we will lose our right to explore and develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
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We could lose permits or licenses on certain of our properties in Albania unless we address non-compliance with the terms of such permits or licenses.
We are currently not in compliance with certain terms of certain of our permits or licenses in Albania. We are working with the Albanian government to resolve the payment of amounts due to Albpetrol and compliance with the terms of certain of our licenses in Albania. If we are unsuccessful in resolving these issues, Albpetrol could take steps to terminate some or all of the licenses.
Virtually all of our operations are conducted in Turkey, Bulgaria and Albania, and we are subject to political, economic and other risks and uncertainties in these countries.
Virtually all of our international operations are performed in the emerging markets of Turkey, Bulgaria and Albania, which may expose us to greater risks than those associated with more developed markets. Due to our foreign operations, we are subject to the following issues and uncertainties that can adversely affect our operations:
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the risk of, and disruptions due to, expropriation, nationalization, war, revolution, election outcomes, economic instability, political instability, or border disputes; |
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the uncertainty of local contractual terms, renegotiation or modification of existing contracts and enforcement of contractual terms in disputes before local courts; |
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the risk of import, export and transportation regulations and tariffs, including boycotts and embargoes; |
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the risk of not being able to procure residency and work permits for our expatriate personnel; |
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the requirements or regulations imposed by local governments upon local suppliers or subcontractors, or being imposed in an unexpected and rapid manner; |
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taxation and revenue policies, including royalty and tax increases, retroactive tax claims and the imposition of unexpected taxes or other payments on revenues; |
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exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over foreign operations; |
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laws and policies of the United States, including the U.S. Foreign Corrupt Practices Act, (“FCPA”) and of the other countries in which we operate affecting foreign trade, taxation and investment, including anti-bribery and anti-corruption laws; |
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our internal control policies may not protect us from reckless and criminal acts committed by our employees or agents, including violations or alleged violations of the FCPA; |
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the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and |
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the possibility of restrictions on repatriation of earnings or capital from foreign countries. |
To manage these risks, we sometimes form joint ventures and/or strategic partnerships with local private and/or governmental entities. Local partners provide us with local market knowledge. However, there can be no assurance that changes in conditions or regulations in the future will not affect our profitability or ability to operate in such markets.
Acts of violence, terrorist attacks or civil unrest in southeastern Turkey and nearby countries could adversely affect our business.
During 2014, we derived 78.6% of our oil production from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social, security and economic problems, terrorist attacks, insurgencies, war and civil unrest. Since December 2010, political instability has increased markedly in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, hundreds of thousands of Syrian refugees have fled to Turkey and more can be expected to cross the border as the conflict continues. Moreover, tensions between Turkey and Syria have escalated.
The current conflict with the terrorist group Islamic State in Iraq and Syria (“ISIS”), as well as tension in and involving the Kurdish regions of northern Iraq, which are contiguous to the region where our southeast Turkey licenses are located, may have political, social or security implications in Turkey or otherwise have a negative impact on the Turkish economy. Stability and security in Iraq deteriorated significantly in 2014 due to the conflict with ISIS.
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Turkey has also experienced problems with domestic terrorist and ethnic separatist groups. For example, Turkey has been in conflict for many years with the People’s Congress of Kurdistan (formerly known as the PKK), an organization that is listed as a terrorist organization by states and organizations, including Turkey, the European Union and the United States.
The potential impact on our business from such events, conditions and conflicts in these countries is uncertain. We may be unable to access the locations where we conduct operations or transport oil to our offtakers in a reliable manner. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.
The Stream acquisition involves risks associated with acquisitions and integrating acquired businesses, including the potential exposure to significant liabilities, and the intended benefits of the Stream acquisition may not be realized.
The Stream acquisition involves risks associated with acquisitions and integrating acquired businesses into existing operations, including:
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the risks of entering into markets in which we have no prior experience; |
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our estimates regarding reserves and production resulting from the Stream acquisition may prove to be incorrect; |
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our senior management's attention may be diverted from the management of daily operations to the integration of Stream; |
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we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage; |
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difficulties in assimilating and integrating the internal controls, technologies and personnel acquired; |
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the properties acquired in the Stream acquisition may not perform as well as we anticipate; and |
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unexpected costs, delays and challenges may arise in integrating Stream. |
Even if we successfully integrate Stream into our operations, it may not be possible to realize the full benefits we anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Stream acquisition, our business, results of operations and financial condition may be adversely affected.
Our failure to successfully integrate Stream’s business could negatively impact our future business and financial results
Our failure to successfully integrate Stream’s business could negatively impact our future business and financial results. Our acquisition of Stream represents an expansion of our operations into a new geographic area in an international market, with operating conditions and a regulatory environment that may not be as familiar to us as our existing core operating areas. Our success in operating in Albania will depend, in part, on our ability to realize benefits from integrating Stream’s business with our existing businesses. The integration process may be complex, costly and time-consuming. To realize such benefits, we must successfully combine the businesses in an efficient and effective manner. If we are not able to achieve these objectives within the anticipated time frame, or at all, any benefits related to our acquisition of Stream may not be realized fully, or at all, or may take longer to realize than expected.
Successful integration will require, among other things, combining the companies’:
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accounting; |
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information technology; |
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internal control over financial reporting; |
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disclosure controls; |
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key personnel; |
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geographically separate facilities; and |
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businesses and executive cultures. |
We may not accomplish this integration successfully and may not realize the benefits contemplated by combining the operations of the Company and Stream.
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Our senior credit facility and term loan facility contain various restrictive covenants that limit our management’s discretion in the operation of our business and could lead to an event of default that may adversely affect our business, financial condition and results of operations.
The operating and financial restrictions and covenants in our senior credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”), and in our term loan facility (the “Term Loan Facility”) with Raiffeisen Bank Sh.A (“Raiffeisen”), may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.
Our Senior Credit Facility contains various covenants that restrict our ability to, among other things:
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incur additional debt; |
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create liens; |
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enter into any hedge agreement for speculative purposes; |
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engage in business other than as an oil and natural gas exploration and production company; |
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enter into sale and leaseback transactions; |
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enter into any merger, consolidation or amalgamation; |
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declare or provide for any dividends or other payments or distributions; |
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redeem or purchase any shares; or |
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guarantee the obligations of any other person. |
In addition, the Senior Credit Facility requires us to maintain specified financial ratios and tests. Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial tests and ratios required by the Senior Credit Facility and could result in an event of default under the Senior Credit Facility.
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 TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Amity Oil International Pty. Ltd. (“Amity”), Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”), and DMLP, Ltd. (“DMLP,” and together with TEMI, Talon Exploration, TransAtlantic Turkey, Amity and Petrogas, the “Borrowers”) or either of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide; (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.
In the event of a default and acceleration of indebtedness under the Senior Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.
Pursuant to the terms of the Term Loan Facility, until amounts under the Term Loan Facility are repaid, Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”), may not, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of Stream Sub to create any liens, (iii) enter into any amalgamation, demerger, merger, or corporate reconstruction or any joint venture or partnership agreement, (iv) incorporate any company as a subsidiary, (v) dispose of any asset, (vi) declare or pay any dividends to shareholders, (vii) enter into a sale and leaseback arrangement, (viii) make any substantial change to the general nature or scope of its business from that carried on at the date of the Term Loan Facility, (ix) use, deposit, handle, store produce, release or dispose of dangerous materials, (x) make any loans or grant any credit, and (xi) cancel, terminate amend or waive any default under any export contract or allow any buyer to do the same.
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In addition, the Term Loan Facility contains financial covenants that require Stream Sub to maintain as of the end of each fiscal year: (i) earnings before interest, taxes, depreciation and amortization (“EBITDA”) of not less than $10.0 million; (ii) an outstanding loan principal of no more than twice its EBITDA; and (iii) EBITDA of at least ten times greater than its accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments.
An event of default under the Term Loan 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, upon the occurrence of a change of control of Stream Sub, Stream Sub is required to notify Raiffeisen, and Raiffeisen would have the option to cancel loan commitments and accelerate all outstanding loans and other amounts payable. A change of control is defined under the Term Loan Facility as Stream ceasing to hold more than 75% of the shares in the issued share capital of Stream Sub carrying the right to vote. Our acquisition of Stream did not constitute a change of control under the Term Loan Facility.
Stream must, upon the request of Raiffeisen when Stream Sub’s predicted expenditures exceed its predicted revenues for any period, inject cash into Stream by means of equity loan or other method acceptable to Raiffeisen to the extent necessary to remedy the cashflow shortfall or repay the total amount outstanding under the Term Loan Facility.
We could experience labor disputes that could disrupt our business in the future.
As of December 31, 2014, approximately 40 of our employees at one of our subsidiaries operating in Turkey were represented by collective bargaining agreements with PETROL-IS. We are currently negotiating a collective bargaining agreement with PETROL-IS covering approximately 35 employees at another of our subsidiaries operating in Turkey. Potential work disruptions from labor disputes with these employees could disrupt our business and adversely affect our financial condition and results of operations.
We could be assessed for Canadian federal tax as a result of our 2009 continuance under the Bermuda Companies Act 1981.
For Canadian tax purposes, we were deemed, immediately before the completion of our 2009 continuance under the Bermuda Companies Act 1981, to have disposed of each property owned by us for proceeds equal to the fair market value of that property, and will be subject to tax on any resulting net income. In addition, we were required to pay a special “branch tax” equal to 25% of any excess of the fair market value of our property over the “paid-up capital” (as defined in the Income Tax Act (Canada)) of our outstanding common shares and our liabilities. However, management, together with its professional advisors, has determined that the paid-up capital of our common shares and our liabilities exceeded the fair market value of our property, resulting in no “branch tax” being payable. The Canada Revenue Agency (“CRA”) may not accept our determination of the fair market value of our property. In the event that CRA’s determination of fair market value is significantly higher than our valuation and such determination is final, we may be subject to material amounts of tax resulting from the deemed disposition.
Risks Related to the Oil and Natural Gas Industry
Reserves estimates depend on many assumptions that may turn out to be inaccurate.
Any material inaccuracies in our reserves estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves that we may report. In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves that we may report. In addition, we may adjust estimates of proved, probable and possible reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable and possible reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves.
Investors should not assume that the pre-tax net present value of our proved, probable and possible reserves is the current market value of our estimated oil and natural gas reserves. We base the pre-tax net present value of future net cash flows from our proved,
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probable and possible reserves on prices and costs on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.
We may not correctly evaluate reserves data or the exploitation potential of properties as we engage in our acquisition, development, and exploitation activities.
Our future success will depend on the success of our acquisition, development, and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates regarding reserves and production resulting from the acquisitions of TEMI, Talon Exploration, Amity, Petrogas, Direct Bulgaria, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) and Stream, and our exploration and development activities may prove to be incorrect, which could significantly reduce our income and our ability to generate cash needed to fund our capital program and other working capital requirements in the longer term.
We may be unable to acquire or develop additional reserves, which would reduce our cash flow and income.
In general, production from oil and natural gas properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploration and development activities or in acquiring properties containing reserves, our reserves will generally decline as reserves are produced. Our oil and natural gas production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.
To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for oil and natural gas or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional reserves, and we might not be able to drill productive wells at acceptable costs.
A substantial or extended decline in oil and natural gas prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments, including debt service.
Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future.
A decrease in the price of oil and natural gas may mean that we are not able to generate sufficient cash flow to meet our debt service payments, which could lead to a default under these agreements.
A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. If oil or natural gas prices decline significantly for extended periods of time in the future, we might not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:
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market expectations regarding supply and demand for oil and natural gas; |
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levels of production and other activities of the Organization of Petroleum Exporting Countries and other oil and natural gas producing nations; |
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market expectations about future prices; |
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the level of global oil and natural gas exploration, production activity and inventories; |
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political conditions, including embargoes, in or affecting oil and natural gas production activities; and |
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the price and availability of alternative fuels. |
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices may have a material adverse effect on our business, financial condition and results of operations.
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If oil and natural gas prices decline, we may be required to write down the carrying values of our oil and natural gas properties.
There is a risk that we could be required to write down the carrying value of our oil and natural gas properties, which would reduce our earnings and shareholders’ equity. We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, the costs of productive wells, developmental dry holes and productive leases are capitalized. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties. Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be non-productive. The capitalized costs of our oil and natural gas properties may not exceed their estimated fair market value. When evaluating our proved properties, we are required to test for potential write-downs at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets, which is typically on a field-by-field basis. If capitalized costs exceed future cash flows, we write down the costs of proved properties to our estimate of fair market value, which is generally estimated using a discounted cash flow approach. When evaluating our unproved properties, we write down the capitalized costs of the unproved properties if it is determined that the costs are not likely to be recoverable. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity.
The development of proved undeveloped reserves is uncertain. In addition, there are no assurances that our probable and possible reserves will be converted to proved reserves.
At December 31, 2014, approximately 31.8% of our total estimated net proved reserves were proved undeveloped reserves. Undeveloped reserves, by their nature, are significantly less certain than developed reserves. At December 31, 2014, we also had a significant amount of unproved reserves, which consist of probable and possible reserves. There is significant uncertainty attached to unproved reserves estimates. The discovery, determination and exploitation of undeveloped or unproved reserves requires significant capital expenditures and successful drilling and exploration programs. We may not be able to raise the additional capital that we need to develop these reserves. There is no certainty that we will be able to convert undeveloped reserves to developed reserves or unproved reserves into proved reserves or that our undeveloped or unproved reserves will be economically viable or technically feasible to produce.
Part of our strategy involves drilling in new or emerging unconventional formations using fracture stimulation and horizontal drilling and completion techniques. The results of our drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production.
The results of our drilling in new or emerging unconventional formations, such as the Mezardere formation, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to use past drilling results in those areas to help predict our future drilling results. Further, part of our drilling strategy to maximize recoveries from our properties in Turkey, particularly in southeastern Turkey, involves the drilling of horizontal wells. Our experience with horizontal drilling in southeastern Turkey, as well as the industry’s drilling and production history, while growing, is limited. The ultimate success of these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. Further, the utilization of these techniques requires substantially greater capital expenditures, as compared to the drilling of a traditional vertical well. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, and/or natural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Legislative and regulatory initiatives and increased public scrutiny relating to fracture simulation activities could result in increased costs and additional operating restrictions or delays.
Fracture stimulation is an important and commonly used process for the completion of oil and natural gas wells and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. Recently, there has been increased public concern regarding the potential environmental impact of fracture stimulation activities. Most of these concerns have raised questions regarding the drilling fluids used in the fracturing process, their effect on drinking water supplies, the use of water in connection with completion operations, and the potential for impact to surface water, groundwater and the environment generally.
The increased attention regarding fracture stimulation could lead to greater opposition, including litigation, to oil and natural gas production activities using fracture stimulation techniques. Increased public scrutiny may also lead to additional levels of regulation in the countries in which we operate that could cause operational restrictions or delays, make it more difficult to perform fracture stimulation or could increase our costs of compliance and doing business. Additional legislation or regulation, such as a requirement to disclose the chemicals used in fracture stimulation, could make it easier for third parties opposing fracture stimulation to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. A
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substantial portion of our operations rely on fracture stimulation, and the adoption of legislation in Bulgaria have placed restrictions on our fracture stimulation activities, causing us to suspend our fracture stimulation activities in Bulgaria. The adoption of legislative or regulatory initiatives in Turkey restricting fracture stimulation could impose operational delays, increased operations costs and additional related burdens on our exploration and production activities which could suspend or make it more difficult to perform fracture stimulation, cause a material decrease in the drilling of new wells and related completion activities and increase our costs of compliance and doing business, which could materially impact our business and profitability.
We are subject to operating hazards.
The oil and natural gas exploration and production business involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, stuck tools, uncontrollable flows of oil or natural gas, abnormally pressured formations and environmental hazards such as oil spills, surface cratering, natural gas leaks, pipeline ruptures, discharges of toxic gases, underground migration, surface spills, mishandling of fracture stimulation fluids, including chemical additives, and natural disasters. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, loss of or damage to well bores and/or drilling or production equipment, costs of overcoming downhole problems, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Gathering systems and processing facilities are subject to many of the same hazards and any significant problems related to those facilities could adversely affect our ability to market our production.
Our oil and natural gas operations are subject to extensive and complex laws and government regulation in the jurisdictions in which we operate and compliance with existing and future laws may increase our costs or impair our operations.
Our oil and natural gas operations are subject to numerous federal, state, local, foreign and provincial laws and regulations, including those related to the environment, employment, immigration, labor, oil and natural gas exploration and development, payments to local, foreign and provincial officials, taxes and the repatriation of foreign earnings. If we fail to adhere to any applicable federal, state, local, foreign and provincial laws or regulations, or if such laws or regulations restrict exploration or production, or negatively affect the sale, of oil and natural gas, our business, prospects, results of operations, financial condition or cash flows may be impaired. We may be subject to governmental sanctions, such as fines or penalties, as well as potential liability for personal injury, property or natural resource damage and might be required to make significant capital expenditures to comply with federal, state or international laws or regulations. In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations could adversely affect our business or operations, or substantially increase our costs and associated liabilities.
In addition, exploration for, and exploitation, production and sale of, oil and natural gas in each country in which we operate is subject to extensive national and local laws and regulations requiring various licenses, permits and approvals from various governmental agencies. If these licenses or permits are not issued or unfavorable restrictions or conditions are imposed on our exploration or drilling activities, we might not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any licenses or permits, might result in the suspension or termination of operations and subject us to penalties. Our costs to comply with these numerous laws, regulations, licenses and permits are significant.
Specifically, our oil and natural gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and/or criminal penalties, incurring investigatory or remedial obligations and the imposition of injunctive relief.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to comply in all material respects with applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability. We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.
Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly
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increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.
In addition, many countries have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of oil and natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for some of our services or products in the future.
We do not plan to insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and natural gas operations.
We do not intend to insure against all risks. Our oil and natural gas exploration and production activities are subject to numerous hazards and risks associated with drilling for, producing and transporting oil and natural gas, and storing, transporting and using explosive materials, and any of the following risks can cause substantial losses:
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environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination, underground migration and surface spills or mishandling of fracture stimulation fluids, including chemical additives; |
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abnormally pressured formations; |
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leaks of oil, natural gas and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, including fracture stimulation activities, or from the gathering and transportation of oil, natural gas and other hydrocarbons, malfunctions of pipelines, processing or other facilities in our operations or at delivery points to third parties; |
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spillage or mishandling of oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third-party service providers; |
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse; |
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fires and explosions; |
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personal injuries and death; |
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regulatory investigations and penalties; and |
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natural disasters. |
As is customary in the oil and natural gas industry, we maintain insurance against some, but not all, of our operating risks. Our insurance may not be adequate to cover potential losses or liabilities and insurance coverage may not continue to be available at commercially acceptable premium levels or at all. We might not elect to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our business, financial condition or results of operations.
We might not be able to identify liabilities associated with properties or obtain protection from sellers against them, which could cause us to incur losses.
Our review and evaluation of prospects and future acquisitions might not necessarily reveal all existing or potential problems. For example, inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, may not be readily identified even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with acquired properties.
Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.
We operate in the highly competitive areas of oil and natural gas exploration, development, production and acquisition with a substantial number of other companies, including U.S.-based and foreign companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in each of the following areas:
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seeking oil and natural gas exploration licenses and production licenses; |
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acquiring desirable producing properties or new leases for future exploration; |
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marketing oil and natural gas production; |
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integrating new technologies; and |
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contracting for drilling services and equipment and securing the expertise necessary to develop and operate properties. |
Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for exploratory prospects and productive oil and natural gas properties than we can. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for and produce oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
We might not be able to obtain necessary permits, approvals or agreements from one or more government agencies, surface owners, or other third parties, which could hamper our exploration, development or production activities.
There are numerous permits, approvals, and agreements with third parties, which will be necessary in order to enable us to proceed with our exploration, development or production activities and otherwise accomplish our objectives. The government agencies in each country in which we operate have discretion in interpreting various laws, regulations, and policies governing operations under the licenses. Further, we may be required to enter into agreements with private surface owners to obtain access to, and agreements for, the location of surface facilities. In addition, because many of the laws governing oil and natural gas operations in the international countries in which we operate have been enacted relatively recently, there is only a relatively short history of the government agencies handling and interpreting those laws, including the various regulations and policies relating to those laws. This short history does not provide extensive precedents or the level of certainty that allows us to predict whether such agencies will act favorably toward us. The governments have broad discretion to interpret requirements for the issuance of drilling permits. Our inability to meet any such requirements could have a material adverse effect on our exploration, development or production activities.
Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
Risks Related to Our Common Shares
The interests of our controlling shareholder may not coincide with yours and such controlling shareholder may make decisions with which you may disagree.
As of March 1, 2015, Mr. Mitchell beneficially owned approximately 36% of our outstanding common shares. As a result, Mr. Mitchell could control substantially all matters requiring shareholder approval, including the election of directors and approval of significant corporate transactions. In addition, this concentration of ownership may delay or prevent a change in control of our company and make some future transactions more difficult or impossible without the support of Mr. Mitchell. The interests of Mr. Mitchell may not coincide with our interests or the interests of our other shareholders.
The value of our common shares may be affected by matters not related to our own operating performance.
The value of our common shares may be affected by matters that are not related to our operating performance and which are outside of our control. These matters include the following:
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general economic conditions in the United States, Turkey, Albania, Bulgaria and globally; |
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industry conditions, including fluctuations in the price of oil and natural gas; |
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governmental regulation of the oil and natural gas industry, including environmental regulation and regulation of fracture stimulation activities; |
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fluctuation in foreign exchange or interest rates; |
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liabilities inherent in oil and natural gas operations; |
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geological, technical, drilling and processing problems; |
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unanticipated operating events which can reduce production or cause production to be shut in or delayed; |
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failure to obtain industry partner and other third-party consents and approvals, when required; |
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stock market volatility and market valuations; |
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competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel; |
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the need to obtain required approvals from regulatory authorities; |
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worldwide supplies and prices of, and demand for, oil and natural gas; |
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political conditions and developments in each of the countries in which we operate; |
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political conditions in oil and natural gas producing regions; |
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revenue and operating results failing to meet expectations in any particular period; |
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investor perception of the oil and natural gas industry; |
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limited trading volume of our common shares; |
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announcements relating to our business or the business of our competitors; |
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the sale of assets; |
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our liquidity; and |
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our ability to raise additional funds. |
In the past, companies that have experienced volatility in the trading price of their common shares have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have a material adverse effect on our business, financial condition and results of operation.
U.S. shareholders who hold common shares during a period when we are classified as a passive foreign investment company may be subject to certain adverse U.S. federal income tax consequences.
Management believes that we are not currently a passive foreign investment company. However, we may have been a passive foreign investment company during one or more of our prior taxable years and could become a passive foreign investment company in the future. In general, classification of our company as a passive foreign investment company during a period when a U.S. shareholder holds common shares could result in certain adverse U.S. federal income tax consequences to such shareholder.
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Certain U.S. shareholders who hold common shares during a period when we are classified as a controlled foreign corporation may be subject to certain adverse U.S. federal income tax rules.
Management believes that we currently are a controlled foreign corporation for U.S. federal income tax purposes and that we will continue to be so treated. Consequently, a U.S. shareholder that owns 10% or more of the total combined voting power of all classes of our shares entitled to vote on the last day of our taxable year may be subject to certain adverse U.S. federal income tax rules with respect to the shareholder’s investment in us.
Risks Related to Our Indebtedness
Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our debt service and other obligations.
We have a significant amount of indebtedness. Our substantial indebtedness could have significant effects on our business. For example, it could:
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make it more difficult for us to satisfy our financial obligations, including with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing our indebtedness; |
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increase our vulnerability to general adverse economic, industry and competitive conditions, especially declines in oil and natural gas prices; |
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limit our ability to borrow additional funds, and |
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limit our financial flexibility |
Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to our indebtedness and to satisfy any other debt obligations will depend on our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting our company and industry, many of which are beyond our control.
Item 1B. Unresolved Staff Comments
Not applicable.
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Turkey
General. As of December 31, 2014, we held interests in 19 onshore and offshore exploration licenses and 20 onshore production leases covering a total of approximately 1.8 million gross acres (approximately 1.1 million net acres) in Turkey. We acquired our interests in Turkey through acquisitions, as well as through farm-in agreements with existing third-party license holders and through applications submitted to the Turkish General Directorate for Petroleum Affairs (the “GDPA”), the agency responsible for the regulation of oil and natural gas activities under the Ministry of Energy and Natural Resources in Turkey.
The following map shows our interests in Turkey:
Reserves. As of December 31, 2014, we had total net proved reserves of 14,406 Mbbl of oil and 16,254 Mmcf of natural gas, net probable reserves of 11,432 Mbbl of oil and 23,794 Mmcf of natural gas and net possible reserves of 12,028 Mbbl of oil and 76,739 Mmcf of natural gas in Turkey.
Equipment Yards. As of December 31, 2014, we leased equipment yards in Muratli, Diyarbakir and Tekirdag and owned equipment yards at Selmo and Edirne.
Commercial Terms. Turkey’s fiscal regime for oil and natural gas licenses is presently comprised of royalties and income tax. The royalty rate is 12.5% and the corporate income tax rate is 20%. Our revenue from the Selmo oil field is subject to an additional 10% royalty, which is offset by the amount of exploration expense that TEMI and DMLP, the owners of our interest in the Selmo oil field, incur in Turkey. If those exploration expenses do not equal or exceed the amount of this additional 10% royalty, we would owe the difference. Dividends repatriated from Turkey would be subject to a withholding tax rate of 15% unless reduced by a tax treaty. There is also an 18% value added tax. However, for exploration licenses, no value added tax is assessed on drilling, completion, workover, seismic and geologic activities.
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Licensing Regime. The licensing process in Turkey for oil and natural gas concessions occurs in three stages: permit, license and lease. Under a permit, the government grants the non-exclusive right to conduct a geological investigation over an area. The size of the area and the term of the permit are subject to the discretion of the GDPA. A new petroleum law was passed by the Turkish government in May 2013, amending some of the processes related to licensing and operations in Turkey. The regulations concerning implementation were passed by the Turkish government in January 2014. The existing licenses and future licensing processes are currently in a transition phase from the old petroleum law to the new petroleum law. The new law provides that operators have the option to maintain their licenses under the old petroleum law for the duration of the existing terms of a license or to convert their licenses to the new petroleum law prior to the expiration of the license. Further details regarding the timing for conversion are awaiting confirmation from the GDPA.
The GDPA awards a license after it approves the applicant’s work program, which may include obligations such as geological and geophysical work, seismic reprocessing and interpretation and contingent shooting of seismic and drilling of wells. A license grants exclusive rights over an area for the exploration for and production of petroleum.
Licensing Under the Old Petroleum Law. A license has a term of four years and requires drilling activities by the third year, but this obligation may be deferred into the fourth year by posting a bond. A license is eligible for two separate two-year extensions by fulfilling prior work commitments and subscribing to additional work commitments. A final three-year term may be granted as an appraisal period for any oil or natural gas discovery registered in the previous terms. No single company may own more than an aggregate of 100% of eight licenses within a district. Rentals are due annually based on the size of the license.
Once a discovery is made, the license holder may apply to convert the area, not to exceed 25,000 hectares (approximately 62,000 acres), to a lease. Under a lease, the lessee may produce oil and natural gas. The term of a lease is for 20 years and may be extended for two further terms of 10 years each. Annual rentals are due based on the size of the lease. The production lease holder is typically able to apply for a new exploration license covering the area of the original exploration license, minus the area of the newly-granted production lease.
Licensing Under the New Petroleum Law. A license has a term of five years and requires the license holder to post a bond equal to 2% of the cost of the work commitments to secure the fulfillment of the work commitments. Licenses shall be based on map sections of scale equal to 1/50,000 (approximately 148,000 acres) or 1/25,000 (approximately 37,000 acres). A license is eligible for two separate two-year extensions by fulfilling prior work commitments and subscribing to additional work commitments, including the drilling of at least one well in each separate extension period, and providing a bond to secure fulfillment of the additional work commitments. A final two-year term may be granted to appraise a petroleum discovery made during the prior terms. An additional six-month extension may be granted during any of the foregoing terms in order to complete the drilling or testing of a well.
Once a discovery is made, the license holder may apply to convert part of the license area, covering the prospective petroleum field, to a production lease. Under a lease, the lessee may produce oil and natural gas. The term of a lease is for 20 years and may be extended for two further terms of 10 years each. The production lease holder is typically able to apply for a new exploration license covering the area of the original exploration license, minus the area of the newly-granted production lease.
The expiration dates reported on our exploration licenses and production leases below are subject to various extensions available under the old petroleum law and the new petroleum law. Those portions of exploration licenses with production are available during any term for conversion to a production lease with a term of 20 years plus two further 10 year extensions if production is maintained. We have applied to the GDPA to convert some of our qualifying acreage into the new petroleum law regulations. This will be a gradual process, but we anticipate that conversion into the new petroleum law will provide for the renewal of the exploration license terms for qualifying acreage.
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Northwestern Turkey. The following map shows our interests in northwestern Turkey at December 31, 2014:
Adatepe (Production Lease 4959 and License 5016). We own a 50% working interest in Production Lease 4959 and License 5016, which cover approximately 3,086 gross acres and 117,000 gross acres, respectively. As of December 31, 2014, we had seven gross (3.5 net) producing wells on the Adatepe production lease. In 2015, we plan to drill one well on License 5016 or License 4288 to satisfy the work program for License 5016, and we plan to maintain production to satisfy our obligation on Production Lease 4959. We are the operator of Production Lease 4959 and License 5016. The current terms of Production Lease 4959 and License 5016 expire in September 2031 and January 2016, respectively, with extensions available under the old and new petroleum laws.
Alpullu (Production Lease 4794) and Temrez (License 4861). We own a 100% working interest in Production Lease 4794 and License 4861, which cover approximately 3,158 acres and 117,000 acres, respectively. As of December 31, 2014, we had six gross and net producing wells on the Alpullu production lease. One well on License 4861 is currently awaiting completion. We plan to maintain production to satisfy our obligation on Production Lease 4794. We are the operator of Production Lease 4794 and License 4861, which expire in September 2028 and December 2014, respectively, with extensions available under the old and new petroleum laws. We applied to convert License 4861 to the new petroleum law for a new five-year term in the second quarter of 2014, and are awaiting GDPA approval.
Atakoy (Production Lease 5122). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Lease 5122, which covers approximately 440 gross acres. As of December 31, 2014, we had ten gross (4.15 net) producing wells on the Atakoy production lease. We plan to maintain production to satisfy our obligation on Production Lease 5122. We are the operator of Production Lease 5122, which expires in November 2032, with extensions available under the old and new petroleum laws.
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Banarli (Production Lease 5059). We own a 50% working interest in Production Lease 5059, which covers approximately 4,608 gross acres. As of December 31, 2014, we had one gross (0.5 net) producing well on the Banarli production lease. We plan to maintain production to satisfy our obligation on Production Lease 5059. We are the operator of Production Lease 5059, which expires in February 2032, with extensions available under the old and new petroleum laws.
Bekirler (License 4126). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in License 4126, which covers approximately 124,000 gross acres. We are the operator of License 4126, which expires in December 2015.
Dogu Adatepe (Production Lease F19-b4-1). We own a 50% working interest in the Dogu Adatepe Production Lease, which covers part of our former Cayirdere license. The lease covers approximately 4,000 gross acres and expires in October 2017, subject to an additional 28 years of extensions under the new petroleum law available with the maintenance of production on the production lease.
Edirne (Production Leases) and Habiller (License 4037). We own a 55% working interest in three Edirne Production Leases and a 100% working interest in License 4037, which cover an aggregate of approximately 239,000 gross acres. In April 2010, we commenced natural gas sales from the Edirne natural gas field. As of December 31, 2014, we had 11 gross (6.1 net) producing wells on the Edirne and Habiller licenses. We are the operator of the Edirne Production Leases and License 4037, which expire in 2034 and March 2016, respectively, with extensions available under the old and new petroleum laws.
Gelindere (Production Lease 3659). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Lease 3659, which covers approximately 709 gross acres. As of December 31, 2014, we had one gross (0.4 net) producing well on the Gelindere lease. We plan to maintain production to satisfy our obligation on Production Lease 3659. We are the operator of Production Lease 3659, which expires in June 2017, with extensions available under the old and new petroleum laws.
Gocerler (Production Lease 4200 and License 4288). We own a 50% working interest in Production Lease 4200 and License 4288, which cover approximately 3,363 gross acres and 119,000 gross acres, respectively. As of December 31, 2014, we had four producing wells on the Gocerler production lease and nine gross (4.5 net) producing wells on License 4288. We plan to drill one well in 2015 on License 4288 or License 5016 to satisfy the work program for License 4288 and we plan to maintain production to satisfy our obligations on Production Lease 4200. We are the operator of Production Lease 4200 and License 4288, which expire in May 2023 and August 2015, respectively, with extensions available under the old and new petroleum laws.
Hayrabolu (Production Lease 2926). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Lease 2926, which covers approximately 12,400 gross acres. As of December 31, 2014, we had four gross (1.7 net) producing wells on the Hayrabolu production lease. We plan to maintain production to satisfy our obligation on Production Lease 2926. We are the operator of Production Lease 2926, which expires in February 2020, with one ten-year extension available under the old and new petroleum laws.
Karaevli (License 3934 and Karaevli Production Lease). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in License 3934 and the Karaevli Production Lease, which cover approximately 122,000 gross acres. As of December 31, 2014, we had three gross (1.3 net) producing wells on the Karaevli license. We are the operator of License 3934 and the Karaevli Production Lease, which expire in November 2015 and April 2019, respectively, with extensions available under the old and new petroleum laws.
Karanfiltepe (License 5151). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in License 5151, which covers approximately 121,000 gross acres. As of December 31, 2014, we had two gross (0.8 net) producing wells on the Karanfiltepe license. We are the operator of the Karanfiltepe license, which expires in June 2017, with extensions available under the old and new petroleum laws. We applied for conversion of this license to the new petroleum law in the second quarter of 2014, and are awaiting GDPA approval.
Malkara (License 4532). We own a 100% working interest in License 4532, which covers approximately 122,000 acres. We are the operator of License 4532, which expires in January 2015, with extensions available under the old and new petroleum laws. We applied for conversion of this license to the new petroleum law in the second quarter of 2014, and are awaiting GDPA approval.
Osmanli (License 3931 and Osmanli Production Leases). We own 41.5%, subject to a 0.415% overriding royalty interest, in License 3931 and the three Osmanli Production Leases, which cover approximately 118,000 gross acres. As of December 31, 2014, we had 53 gross (22.0 net) producing wells on the Osmanli license and Osmanli Production Leases. License 3931 and Production Lease 3860 were the focus of our 2014 horizontal drilling campaign in the Thrace Basin. We are the operator of License 3931 and the Osmanli Production Leases, which expire in November 2015 and April 2024, respectively, with extension available under the old and new petroleum laws.
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Senova (License 3858). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in License 3858, which covers approximately 122,000 gross acres. Depending on the recompletion results of the Senova-1 well and Akcahalil-1 well, we plan to apply for a production lease on the southern portion of License 3858. We are the operator of License 3858, which expires in May 2015, with extensions available under the old and new petroleum laws. We applied for the conversion of the northern portion of this license to the new petroleum law in the second quarter of 2014 and are currently awaiting GDPA approval.
Tekirdag (Production Lease 3860) and Gazioglu (Production Lease 3861). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Leases 3860 and 3861, which cover an aggregate of approximately 4,300 gross acres. As of December 31, 2014, we had 26 gross (10.8 net) producing wells on the Tekirdag and Gazioglu production leases. Production Lease 3860 and License 3931 were the focus of our 2014 horizontal drilling campaign in the Thrace Basin. We plan to maintain production to satisfy our obligation on Production Leases 3860 and 3861. We are the operator of Production Leases 3860 and 3861, which expire in December 2023 and December 2021, respectively, with extensions available under the old and new petroleum laws.
Southeastern Turkey. The following map shows our interests in southeastern Turkey at December 31, 2014:
Arpatepe (Production Lease 5003 and License 5025). We own a 50% working interest in Production Lease 5003 and License 5025, which cover approximately 11,200 and 84,800 gross acres, respectively. For 2014, our wellhead production of oil from the Arpatepe field was approximately 64,875 Bbls of oil, at an average rate of approximately 178 Bbl/d. As of December 31, 2014, we had five producing wells on the Arpatepe production lease. We plan to drill the South Goksu-1 exploration well on License 5025 in 2015. Aladdin Middle East, Ltd. is the operator of Production Lease 5003 and License 5025, which expire in November 2028 and February 2016, respectively, with extensions available under the old and new petroleum laws.
33
Bakuk (License 5064 and Production Lease 5043). We own a 50% working interest in License 5064 and Production Lease 5043. The exploration license covers approximately 61,000 gross acres, and the production lease covers approximately 34,400 gross acres. Production continues from the Bakuk-101 well, and we are evaluating additional offset well locations. Tiway Turkey, Ltd. (“Tiway”) is the operator of License 5064 and Production Lease 5043, which expire in June 2016 and January 2032, respectively, with extensions available under the old and new petroleum laws.
Bismil (License 4239). License 4239 was acquired from ARAR during the second quarter of 2013. We own a 100% working interest in the Bismil license, which covers approximately 4,800 gross acres. License 4239 was part of our large Molla 3D acquisition program, and we drilled the Bati Yasince-1 discovery well in the fourth quarter of 2014, which was producing oil as of December 31, 2014. We are the operator of the license, which expires in June 2015. We continue to monitor production and plan to apply for a production lease covering the majority of this acreage in 2015.
Gaziantep (Gazientep License and Alibey License). We own a 62.5% working interest in the Gazientep and Alibey Licenses, subject to a 0.313% overriding royalty interest, which cover the former License 4607 and an aggregate of 123,000 gross acres. We are the operator of the Gazientep and Alibey Licenses, which expire in October 2019. We are currently evaluating additional prospects on the Gaziantep and Alibey Licenses, including an offset to the Alibey-1H discovery well.
Idil (License 4642). We own a 50% working interest in License 4642, which covers approximately 123,000 gross acres. In February 2014, we entered into a farm-out agreement with Onshore Petroleum Company AS (“Onshore”), whereby Onshore will fund the costs, up to $3.5 million, to drill and complete a well targeting the Mardin formation. We began drilling this well in the fourth quarter of 2014 and plan to complete the well during the first half of 2015. We are the operator of License 4642, which expires in October 2016.
Molla (Licenses 4174 and 4845) and West Molla (License 5046). We own a 100% working interest in Licenses 4174, 4845 and 5046, which cover an aggregate of approximately 112,000 gross acres. As of December 31, 2014, we had six gross and net wells producing on the Molla licenses. We continue to interpret the 800 sq. km. 3D seismic data to delineate prospects on the Molla licenses. We are the operator of Licenses 4174, 4845 and 5046, which expire in June 2016, March 2015 and June 2016, respectively, with extensions available under the old and new petroleum laws. We applied for a two-year extension on License 4845 in the fourth quarter of 2014 and are currently awaiting GDPA approval.
Selmo (Production Lease 829). We own a 100% working interest in Production Lease 829, which covers 8,886 acres and includes the Selmo oil field. As of December 31, 2014, there were 60 gross and net producing wells on the Selmo production lease. For 2014, our wellhead production of oil in the Selmo field was approximately 1,027,639 Bbls of oil, at an average rate of approximately 2,815 Bbl/d. The Selmo lease was the focus of a horizontal drilling campaign in 2014, and we initiated a waterflood pilot test program in the first quarter of 2014, in which two Selmo wells were converted to injection wells. We are the operator of Production Lease 829, which expires in June 2025.
Hazro License Application. We have applied with the GDPA to acquire two new license quadrants, L45-c1 and L45-c2, which we believe to be prospective for the Bedinan, Mardin and Hazro formations. There are five competing bids for the acreage, and we are currently awaiting the GDPA’s response.
34
Bulgaria
General. As of December 31, 2014, we held interests in one onshore exploration permit and one onshore production concession in Bulgaria. We acquired all of our Bulgarian interests through the purchase of Direct Bulgaria in February 2011. In January 2012, the Bulgarian Parliament enacted legislation that banned the fracture stimulation of oil and natural gas wells in the Republic of Bulgaria. The legislation also had the effect of preventing conventional drilling and completion activities. In June 2012, the Bulgarian Parliament amended the legislation to clarify that conventional drilling and completion activities were not intended to be affected by the law. As long as this legislation remains in effect, our unconventional natural gas exploration, development and production activities in Bulgaria will be significantly constrained. The following map shows our interests in Bulgaria at December 31, 2014:
Reserves. As of December 31, 2014, there were no economic reserves associated with our properties in Bulgaria.
Commercial Terms. Bulgaria’s petroleum laws provide a framework for investment and operation that allows foreign investors to retain the proceeds from the sale of petroleum production. The fiscal regime is comprised of royalties and income tax.
The royalty ranges from 2.5% to 30%, based on an “R factor” which is particular to each production concession agreement, but is typically calculated by dividing the total cumulative revenues from a production concession by the total cumulative costs incurred for that production concession.
The production concession holder pays Bulgarian corporate income tax, which is assessed at a rate of 10%. All costs incurred in connection with exploration, development and production operations are deductible for corporate income tax purposes.
Resident companies which remit dividends outside of Bulgaria are subject to a dividend withholding tax between 10% to 15%, depending on the proportion of the capital owned by the recipient. No customs duty is payable on the export of petroleum, nor is customs duty payable on the import of material necessary to conduct petroleum operations. There is also a 20% value added tax. Oil is priced at market while natural gas is tied to a bundle pricing based in part on the import price and in part on the domestic price.
35
Licensing Regime. The licensing process in Bulgaria for oil and natural gas concessions occurs in two stages: exploration permit and then production concession.
Under an exploration permit, the government grants exploration rights for a term of up to five years to conduct seismic and other exploratory activities, including drilling. The recipient of an exploration permit commits to a work program and posts a bank guarantee in the amount of the estimated cost for the program. The area covered by an onshore exploration permit may be as large as 5,000 square kilometers. The exploration permit may be extended for up to two additional two-year terms, subject to fulfillment of minimum work programs, and may be extended for an additional one-year term in order to appraise potential geologic discoveries. Interests under an exploration permit are transferable, subject to government approval. The permit holder is required to pay an annual area fee equal to 40 Bulgarian Lev (approximately $25 at December 31, 2014) per square kilometer, or 40 Bulgarian Lev (approximately $25 at December 31, 2014) per square kilometer in the event the permit term is extended.
Upon the registration of a commercial discovery, an exploration permit holder may apply for a production concession. The production concession size corresponds to the area of the commercial discovery. The duration of a production concession is 35 years and may be extended by a further 15 years subject to the terms and conditions of the production concession agreement. Interests under a production concession are transferable, subject to government approval. No bonus is paid to the government by the company upon conversion to a production concession.
Koynare. We own a 100% working interest, subject to a 3.02% overriding royalty interest and KDL’s 50% farm-in interest, in the Koynare production concession covering approximately 163,000 acres. The Koynare Concession Area contains the Deventci-R1 well, where we discovered a reservoir in the Jurassic-aged Ozirovo formation at a depth of approximately 13,800 feet, which the Bulgarian government has certified as a geologic and commercial discovery. In November 2011, we commenced drilling the Deventci-R2 appraisal well on the Koynare Concession Area, which we suspended following the enactment of the Bulgarian government’s January 2012 legislation. During the second half of 2013, we resumed drilling the Deventci-R2 directional well on our Koynare Concession Area. In January 2014, we reached target depth of 14,100 feet on the Deventci-R2 well, and conducted a long-term test on the well during the second quarter of 2014 with an initial production test of approximately 2.0 Mmcf/d of natural gas with condensates. In the fourth quarter of 2014, we received approval from the Bulgarian government to acidize the well. We conducted initial stimulation in December 2014 to enhance its productivity and are currently evaluating the results of the stimulation.
Stefenetz. In November 2011, we initiated the application process for a production concession covering approximately 395,000 acres over the southern portion of our former A-Lovech exploration permit. The Stefenetz Concession Area is estimated to contain over 300,000 prospective acres for Etropole shale at a depth of approximately 12,500 feet, which the Bulgarian government has certified as a geologic discovery. During 2012, we initiated an environmental impact assessment, which the Bulgarian government must approve prior to granting the production concession.
In September 2011, we entered into an agreement with Esrey pursuant to which Esrey funded the drilling of an exploration well on the Stefenetz Concession Area to core and test the Etropole shale formation. This well, the Peshtene-R11, reached total depth in late November 2011, from which we collected more than 900 feet of core. We suspended drilling and completion of the Peshtene-R11 well following enactment of the Bulgarian government’s January 2012 legislation. We and Esrey are evaluating the core data and developing a conventional completion program for the Peshtene-R11 well. If we obtain a production concession over the Stefenetz Concession Area, Esrey would fund up to an additional $12.5 million in exchange for a 50% working interest in the production concession. The remaining 50% working interest in the production concession would be split equally between us and KDL.
Aglen. We have applied to relinquish the Aglen exploration permit, which covers approximately 1,700 acres within the boundaries of the former A-Lovech exploration permit and lies within the boundary of the Stefenetz Concession Area. Due to the Bulgarian government’s January 2012 legislation, a force majeure event was recognized by the government. As of March 1, 2015, we were still negotiating the relinquishment of this license.
36
Albania
General. We own 100% of the interests in three onshore oil fields and one gas concession consisting of one onshore gas field and one exploration license, all in Albania. Stream commenced operations in Albania in November 2007, taking over the operation of wells, associated equipment and facilities from Albpetrol, the state owned oil company in Albania. Subsequent to the acquisition of Stream, we have been operating in Albania under the name TransAtlantic Albania Ltd. The following map shows our interests in Albania at December 31, 2014:
Reserves. As of December 31, 2014, we had total net proved reserves of 14,259 Mbbl of oil and 8,249 Mmcf of natural gas, net probable reserves of 10,014 Mbbl of oil and 19,963 Mmcf of natural gas and net possible reserves of 7,152 Mbbl of oil and 31,518 Mmcf of natural gas in Albania.
Commercial Terms. In August 2007, Stream entered into Instruments of Transfer to join four License Agreements between Agjencia Kombëtare e Burimeve Natyrore, the Albanian National Agency of Natural Resources (“AKBN”), and Albpetrol and entered into four Petroleum Agreements with Albpetrol, which together give us the right to access and develop three onshore oil fields and one onshore gas field. The four License Agreements each have a 25-year term, with unlimited five-year renewal options. These fields contain approximately 600 existing wells, of which approximately 250 are producing, with the remainder shut-in predominantly due to failures of production equipment as a result of insufficient capital investment by Albpetrol.
We are required to submit annual work programs and budgets to Albpetrol each year, including the nature and amount of capital expenditures, which is required to be consistent with the plans of development (“PODs”) for the fields approved by AKBN. Significant deviations from the PODs are subject to the approval of AKBN and Albpetrol.
37
Pursuant to the terms of the Petroleum Agreements, we pay a 2% to 7.2% gross over-riding royalty to Albpetrol, which may be paid in kind or cash. In addition, we are required to pay a royalty to Albpetrol based on the amount of pre-existing production (“PEP”) from the wells taken over by Stream. The PEP royalty is calculated on a well by well basis and is initially equal to 65% to 70% of the PEP preceding the takeover of the well by Stream. The PEP royalty declines at a rate of 10% per year for the oil fields and 5% per year for Delvina.
In 2008, a new 10% mineral tax was enacted by the Albanian Ministry of Finance. The new mineral tax is equal to 10% of gross sales after deducting any PEP royalties paid. Under the Petroleum Agreements, any new financial burdens (including new mineral taxes) are to be neutralized by amendments to the Petroleum Agreements. We are working with officials from Albpetrol and AKBN to finalize amendments to the Petroleum Agreements to neutralize the 10% mineral tax. As of December 31, 2014, we had $10.9 million of tax payments awaiting neutralization.
Ballsh-Hekal. The Ballsh-Hekal field was discovered in 1966 and produces oil from fractured carbonates of Cretaceous-Paleocene age. The oil contains sulphur. The field is developed with an average well spacing of approximately 4 hectares/well (10 acres/well). We believe that a significant number of these wells did not penetrate the entire hydrocarbon column.
We have taken over 23 wells (of which 13 are producing) from Albpetrol in the Ballsh-Hekal field. We believe that a significant number of these wells did not penetrate the entire hydrocarbon column. Albpetrol still operates approximately 60 wells in the field. We have the right to take over the remaining wells at our option. During 2014, our net production, before mineral taxes, was 86 Bbl/d of oil from the field.
Cakran-Mollaj. The Cakran-Mollaj field was discovered in 1977 and is currently producing from fractured carbonates of Cretaceous-Paleocene age. This is the deepest of our fields in Albania at 2,650 to 3,700 meters. The field is developed with an average well spacing of approximately 16 hectares/well (40 acres/well). We took over 70 wells (of which approximately 30 are producing) from Albpetrol. We believe that a significant number of these wells did not penetrate the entire hydrocarbon column.
During 2014, our net production, before mineral taxes, was approximately 307 Bbl/d of oil from this field. We are working on improving the reliability of surface equipment in this field prior to reactivating and recompleting additional wells.
Gorisht-Kocul. Discovered in 1965, the Gorisht-Kocul field is a heavy oil field that produces from fractured carbonates of Cretaceous-Paleocene age. Well depths range from 400 to 1,250 meters, and the oil contains sulphur. The field is fully developed with an average well spacing of approximately 2 hectares/well (5 acres/well). We believe that a significant number of these wells did not penetrate the entire hydrocarbon column.
We took over all 295 wells (of which approximately half are producing) in the Gorisht-Kocul field from Albpetrol. From During 2014, our net production from this field, before mineral taxes, was 449 Bbl/d of oil. We are in the process of conducting two waterflood projects in this reservoir, which have mitigated the natural pressure and production decline in portions of this field. We intend to workover and reactivate existing wells in 2015 with modern rod pumps and progressive cavity pumps.
Delvina Concession. We own the Delvina Concession, which is comprised of the partially developed Delvina field and the Delvina exploration block.
Delvina Field. The Delvina natural gas field was discovered in 1987 and produces natural gas and natural gas liquids from reservoirs at a depth of 2,800 to 3,500 meters from fractured carbonates of Cretaceous- Paleocene age. The Delvina natural gas field is connected to potential markets by an existing pipeline, but needs additional downstream capacity.
The field has two previously producing vertical wells, the Delvina D4 and D12 wells. During the workover of the Delvina D12 well in 2013, after successful stimulation and flow tests, Stream encountered an obstruction in the completion string that could not be removed through solvent injection and is planning workover procedures. We plan to bring the Delvina D4 well back online following workover of the Delvina D12 well. In April 2014, Stream spud the D34H1 well in the Delvina field, reaching a depth of approximately 750 meters before temporarily abandoning drilling due to a lack of funds. Drilling operations on the D34H1 well are expected to resume during the first half of 2015.
Delvina Block. Under the Delvina License Agreement and Petroleum Agreement, we have the right to develop approximately 60,000 acres adjacent to the Delvina natural gas field, referred to as the Delvina Block. The Delvina Block offers significant growth potential.
38
Summary of Oil and Natural Gas Reserves
The following table summarizes our net proved, probable and possible reserves at December 31, 2014 and 2013.
|
Reserves |
|
|||||||||
|
Oil and Condensate (Mbbl) |
|
|
Natural Gas (Mmcf) |
|
|
Total (Mboe) |
|
|||
Reserves Category |
|
|
|
|
|
|
|
|
|
|
|
December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
Turkey |
|
|
|
|
|
|
|
|
|
|
|
Proved reserves |
|
|
|
|
|
|
|
|
|
|
|
Proved developed |
|
6,857 |
|
|
|
9,551 |
|
|
|
8,449 |
|
Proved undeveloped |
|
7,549 |
|
|
|
6,703 |
|
|
|
8,666 |
|
Total proved |
|
14,406 |
|
|
|
16,254 |
|
|
|
17,115 |
|
Probable reserves |
|
|
|
|
|
|
|
|
|
|
|
Probable developed |
|
1,400 |
|
|
|
3,035 |
|
|
|
1,906 |
|
Probable undeveloped |
|
10,032 |
|
|
|
20,760 |
|
|
|
13,492 |
|
Total probable |
|
11,432 |
|
|
|
23,795 |
|
|
|
15,398 |
|
Possible reserves |
|
|
|
|
|
|
|
|
|
|
|
Possible developed |
|
1,457 |
|
|
|
3,073 |
|
|
|
1,969 |
|
Possible undeveloped |
|
10,571 |
|
|
|
73,666 |
|
|
|
22,849 |
|
Total possible |
|
12,028 |
|
|
|
76,739 |
|
|
|
24,818 |
|
Albania |
|
|
|
|
|
|
|
|
|
|
|
Proved reserves |
|
|
|
|
|
|
|
|
|
|
|
Proved developed |
|
13,900 |
|
|
|
- |
|
|
|
13,900 |
|
Proved undeveloped |
|
359 |
|
|
|
8,249 |
|
|
|
1,734 |
|
Total proved |
|
14,259 |
|
|
|
8,249 |
|
|
|
15,634 |
|
Probable reserves |
|
|
|
|
|
|
|
|
|
|
|
Probable developed |
|
- |
|
|
|
- |
|
|
|
- |
|
Probable undeveloped |
|
10,014 |
|
|
|
19,963 |
|
|
|
13,341 |
|
Total probable |
|
10,014 |
|
|
|
19,963 |
|
|
|
13,341 |
|
Possible reserves |
|
|
|
|
|
|
|
|
|
|
|
Possible developed |
|
- |
|
|
|
- |
|
|
|
- |
|
Possible undeveloped |
|
7,152 |
|
|
|
31,518 |
|
|
|
12,405 |
|
Total possible |
|
7,152 |
|
|
|
31,518 |
|
|
|
12,405 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
Proved reserves |
|
|
|
|
|
|
|
|
|
|
|
Proved developed |
|
20,757 |
|
|
|
9,551 |
|
|
|
22,349 |
|
Proved undeveloped |
|
7,908 |
|
|
|
14,952 |
|
|
|
10,400 |
|
Total proved |
|
28,665 |
|
|
|
24,503 |
|
|
|
32,749 |
|
Probable reserves |
|
- |
|
|
|
- |
|
|
|
- |
|
Probable developed |
|
1,400 |
|
|
|
3,035 |
|
|
|
1,906 |
|
Probable undeveloped |
|
20,046 |
|
|
|
40,723 |
|
|
|
26,833 |
|
Total probable |
|
21,446 |
|
|
|
43,758 |
|
|
|
28,739 |
|
Possible reserves |
|
|
|
|
|
|
|
|
|
|
|
Possible developed |
|
1,457 |
|
|
|
3,073 |
|
|
|
1,969 |
|
Possible undeveloped |
|
17,723 |
|
|
|
105,184 |
|
|
|
35,254 |
|
Total possible |
|
19,180 |
|
|
|
108,257 |
|
|
|
37,223 |
|
December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
Turkey |
|
|
|
|
|
|
|
|
|
|
|
Proved reserves |
|
|
|
|
|
|
|
|
|
|
|
Proved developed |
|
4,875 |
|
|
|
10,450 |
|
|
|
6,617 |
|
Proved undeveloped |
|
4,839 |
|
|
|
4,589 |
|
|
|
5,604 |
|
Total proved |
|
9,714 |
|
|
|
15,039 |
|
|
|
12,221 |
|
Probable reserves |
|
|
|
|
|
|
|
|
|
|
|
Probable developed |
|
1,057 |
|
|
|
3,378 |
|
|
|
1,620 |
|
Probable undeveloped |
|
7,063 |
|
|
|
19,652 |
|
|
|
10,338 |
|
Total probable |
|
8,120 |
|
|
|
23,030 |
|
|
|
11,958 |
|
Possible reserves |
|
|
|
|
|
|
|
|
|
|
|
Possible developed |
|
1,218 |
|
|
|
3,307 |
|
|
|
1,769 |
|
Possible undeveloped |
|
15,659 |
|
|
|
74,898 |
|
|
|
28,142 |
|
Total possible |
|
16,877 |
|
|
|
78,205 |
|
|
|
29,911 |
|
39
Value of Proved Reserves
The following table shows our estimated future net revenue, PV-10 and Standardized Measure as of December 31, 2014:
(in thousands) |
|
|
|
|
|
Future net revenue |
|
$ |
1,519,169 |
|
|
Total PV-10 (1) |
|
$ |
884,387 |
|
|
Total Standardized Measure |
|
$ |
672,082 |
|
(1) |
The PV-10 value of the estimated future net revenue is not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV-10, while not a financial measure in accordance with U.S. GAAP, provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under U.S. GAAP. PV-10 should not be considered as an alternative to the Standardized Measure as defined under U.S. GAAP. The Standardized Measure represents the PV-10 after giving effect to income taxes. The following table provides a reconciliation of our PV-10 to our Standardized Measure: |
(in thousands) |
|
|
|
|
|
Total PV-10 (1) |
|
$ |
884,387 |
|
|
Future income taxes |
|
|
(392,211 |
) |
|
Discount of future income taxes at 10% per annum |
|
|
179,906 |
|
|
Standardized Measure |
|
$ |
672,082 |
|
Proved Reserves
Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Natural Gas Reserves under U.S. Law.”
At December 31, 2014, our estimated proved reserves were 32,749 Mboe, an increase of 20,528 Mboe, or 168.0%, compared to 12,221 Mboe at December 31, 2013. This increase was primarily attributable to the acquisition of Stream, the continued success of our horizontal drilling campaigns in the Selmo oil field and the Thrace Basin and the successful appraisal of the Bahar oil field. The Albanian assets of Stream constituted 15,634 Mboe or 76.2% of the increase. Of these proved reserves, 88.9% are in the proved developed category and are part of the producing oil assets in Albania. The increase in proved reserves was partially offset by sales volumes of 1,883 Mboe in 2014, consisting of 1,339 Mbbls of oil and 3,262 Mmcf of natural gas.
At December 31, 2014, we recorded an increase in proved reserves of 5,208 Mboe through extensions and discoveries. These increases were due to the following factors: (i) horizontal drilling in Selmo, which resulted in the conversion of 2,234 Mboe from probable or possible reserves to proved reserves due to successful wells in the previously under-drilled southeast portion of the field and confirming that oil still remains at, or below, the current oil-water contact; (ii) the addition of 467 Mboe in the Thrace Basin as a result of the Gurgen discovery and successful Sogucak test in the Kuzey Emirali-1 well; (iii) the addition of 2,243 Mboe due to successful appraisal wells on the Bahar structure and (iv) the addition of 264 Mbbls in the Arpatepe oil field as a result of the Arpatepe-7 appraisal well success which extended the field to the southeast.
At December 31, 2014, we recorded an increase in proved reserves due to technical revisions of 1,254 Mbbl and 1,668 Mmcf (1,532 Mboe total). The revision in oil of 1,254 Mbbls was an increase from December 31, 2013, in which we recorded a loss of 436 Mbbls, and was mostly attributable to well performance in Selmo. Prior to initiating the horizontal well campaign in Selmo in 2013, drilling had been halted due to poor vertical well performance. This resulted in negative revisions to estimates for 2013. By contrast, the horizontal wells drilled in late 2013 and throughout 2014 have performed better than original estimates and thus resulted in positive technical revisions. The revision in gas of 1,668 Mmcf was a decrease from December 31, 2013, in which we recorded 3,436 Mmcf in technical revisions and was mostly attributable to a decrease in activity in the Thrace Basin, where we did not introduce any new technology to the gas fields. In 2013, we successfully fracture stimulated the Mezardere formation for the first time. This led to an aggressive recompletion program as we fine-tuned our stimulation methodology which, in turn, greatly increased many behind pipe reserves. The performance of these fracture stimulated wells versus the unstimulated type curves allowed for positive reserve revisions. The estimated undiscounted capital costs associated with our proved reserves is $357.8 million.
40
Proved Undeveloped Reserves
At December 31, 2014, our estimated proved undeveloped reserves were 10,400 Mboe, an increase of 4,796 Mboe, or 85.6%, compared to 5,604 Mboe at December 31, 2013. Of this increase in proved undeveloped reserves, 1,734 Mboe was from the acquisition of Stream, 1,834 Mboe was from extensions and discoveries from horizontal drilling in Selmo and 1,228 Mboe was from extensions and discoveries in the Molla field and the Thrace Basin in Turkey. All of our proved undeveloped reserves as of December 31, 2014 will be developed within five years of the date the reserve was first disclosed as a proved undeveloped reserve. The estimated undiscounted capital costs associated with our proved undeveloped reserves is $266.6 million.
Probable Reserves
Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Natural Gas Reserves under U.S. Law.”
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
Possible Reserves
Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Natural Gas Reserves under U.S. Law.”
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
41
Internal Controls
Management has established, and is responsible for, a number of internal controls designed to provide reasonable assurance that the estimates of proved, probable and possible reserves are computed and reported in accordance with rules and regulations provided by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls consist of documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. We also retain outside independent engineering firms to prepare estimates of our proved, probable and possible reserves. We work closely with this firm, and management is responsible for providing accurate operating and technical data to it. Management has tested the processes and controls regarding our reserves estimates for 2014. Senior management reviews and approves our reserves estimates, whether prepared internally or by third parties. In addition, our audit committee serves as our reserves committee and is composed of three outside directors, all of whom have experience in the review of energy company reserves evaluations. The audit committee reviews the final reserves estimate and also meets with representatives from the outside engineering firm to discuss their process and findings.
Oil and Natural Gas Reserves under U.S. Law
In the United States, we are required to disclose proved reserves, and we are permitted to disclose probable and possible reserves, using the standards contained in Rule 4-10(a) of the SEC’s Regulation S-X. The estimates of proved, probable and possible reserves in Turkey presented as of December 31, 2014 have been prepared by DeGolyer and MacNaughton, our external engineers for Turkey. The technical person at DeGolyer and MacNaughton that is primarily responsible for overseeing the preparation of our reserves estimates in Turkey is a Registered Professional Engineer in the State of Texas and has a Bachelor of Science degree in Mechanical Engineering from Kansas State University. He has over 32 years of experience in oil and natural gas reservoir studies and evaluations and is a member of the Society of Petroleum Engineers.
The estimates of proved, probable and possible reserves in Albania presented as of December 31, 2014 have been prepared by Deloitte LLP, our external engineers for Albania. The technical person at Deloitte LLP that is primarily responsible for overseeing our reserves estimates in Albania has a Bachelor of Science degree in Chemical Engineering from the University of Calgary. He has over 20 years of experience in oil and gas reservoir engineering and reserves determination.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with DeGolyer and MacNaughton and Deloitte LLP to ensure the integrity, accuracy and timeliness of data furnished to them for the preparation of their reserves estimates. Our chief reservoir engineer has over 42 years of experience in oil and natural gas reservoir studies and evaluations. He has a Bachelor of Science degree in Petroleum Engineering from Colorado School of Mines and a Masters of Business Administration degree from the University of Phoenix. He is a Registered Professional Engineer in the state of Colorado, and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
Estimates of oil and natural gas reserves are projections based on a process involving an independent third-party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped, probable and possible reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See “Supplemental Information —Supplemental oil and natural gas reserves information (unaudited)” to our consolidated financial statements for additional information regarding our oil and natural gas reserves.
The technologies and economic data used in the estimation of our proved, probable and possible reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.
The estimates of proved, probable and possible reserves prepared by DeGolyer and MacNaughton for the year ended December 31, 2014 included a detailed evaluation of our Selmo, Arpatepe, Bakuk, Molla and Thrace Basin properties in Turkey and our West Koynare field in Bulgaria. DeGolyer and MacNaughton determined that their estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about whether proved reserves are economically producible from a given date forward, under existing economic conditions, operating methods and government regulations, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.
42
The estimates of proved, probable and possible reserves prepared by Deloitte LLP for the year ended December 31, 2014 included a detailed evaluation of our Ballsh-Hekal, Cakran-Mollaj, Gorisht-Kocul and Delvina properties in Albania. Deloitte LLP determined that their estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about whether proved reserves are economically producible from a given date forward, under existing economic conditions, operating methods and government regulations, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.
Oil and Natural Gas Reserves under Canadian Law
As a reporting issuer under Alberta, British Columbia and Ontario securities laws, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. DeGolyer and MacNaughton and Deloitte LLP evaluated the Company’s reserves as of December 31, 2014, in accordance with the reserves definitions of NI 51-101 and the Canadian Oil and Gas Evaluators Handbook (“COGEH”). Our annual oil and natural gas reserves disclosures prepared in accordance with NI 51-101 and COGEH and filed in Canada are available at www.sedar.com.
Oil and Natural Gas Sales Volumes
The following table sets forth our sales volumes of oil and natural gas (including by field for any field that contained 15% or more of our total proved reserves at December 31, 2014) for 2014, 2013 and 2012:
|
Sales Volumes |
|
|||||||||
|
Oil (1) |
|
|
Natural Gas |
|
|
Total |
|
|||
Year |
(Bbls) |
|
|
(Mcf) |
|
|
(Boe) |
|
|||
2014 |
|
|
|
|
|
|
|
|
|
|
|
Total Turkey |
|
1,302,439 |
|
|
|
3,258,537 |
|
|
|
1,845,529 |
|
Selmo field |
|
1,023,877 |
|
|
|
– |
|
|
|
1,023,877 |
|
Total Albania |
|
36,200 |
|
|
|
– |
|
|
|
36,200 |
|
Gorisht-Kocul field |
|
19,306 |
|
|
|
– |
|
|
|
19,306 |
|
2013 |
|
|
|
|
|
|
|
|
|
|
|
Total Turkey |
|
932,463 |
|
|
|
3,495,698 |
|
|
|
1,515,079 |
|
Selmo field |
|
665,025 |
|
|
|
– |
|
|
|
665,025 |
|
2012 |
|
|
|
|
|
|
|
|
|
|
|
Total Turkey |
|
947,998 |
|
|
|
4,204,629 |
|
|
|
1,648,720 |
|
Selmo field |
|
813,222 |
|
|
|
– |
|
|
|
813,222 |
|
(1) |
“Oil” volumes include condensate (light oil) and medium crude oil. |
Average Sales Price and Production Costs
The following table sets forth the average sales price per Bbl of oil and Mcf of natural gas and the average production cost, not including ad valorem and severance taxes, per unit of production for each of 2014, 2013 and 2012:
|
2014 |
|
|
2013 |
|
|
2012 (1) |
|
|||
Turkey: |
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price Oil ($/Bbl) |
$ |
82.92 |
|
|
$ |
101.05 |
|
|
$ |
102.60 |
|
Natural Gas ($/Mcf) |
$ |
8.67 |
|
|
$ |
9.43 |
|
|
$ |
8.72 |
|
Unit Costs Production ($/Boe) |
$ |
8.56 |
|
|
$ |
10.62 |
|
|
$ |
9.20 |
|
Albania: |
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price Oil ($/Bbl) |
$ |
52.43 |
|
|
$ |
– |
|
|
$ |
– |
|
Natural Gas ($/Mcf) |
$ |
– |
|
|
$ |
– |
|
|
$ |
– |
|
Unit Costs Production ($/Boe) |
$ |
31.15 |
|
|
$ |
– |
|
|
$ |
– |
|
(1) |
We have recalculated the oil and natural gas costs per Boe for the year ended December 31, 2012 based on working interest volumes before royalty deductions to conform to current year presentation. |
43
Drilling Activity
The following table sets forth the number of net productive and dry exploratory wells and net productive and dry development wells we drilled in 2014, 2013 and 2012:
|
Development Wells |
|
|
Exploratory Wells |
|
||||||||||
|
Productive |
|
|
Dry |
|
|
Productive |
|
|
Dry |
|
||||
Turkey: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
14.7 |
|
|
|
2.0 |
|
|
|
4.6 |
|
|
|
0.4 |
|
2013 |
|
10.5 |
|
|
|
0.5 |
|
|
|
3.5 |
|
|
|
4.4 |
|
2012 |
|
14.5 |
|
|
|
1.4 |
|
|
|
4.0 |
|
|
|
7.9 |
|
Bulgaria: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
2013 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
2012 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Albania: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
2013 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
2012 |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Oil and Natural Gas Properties, Wells, Operations and Acreage
Productive Wells. The following table sets forth the number of productive wells (wells that were producing oil or natural gas or were capable of production) in which we held a working interest as of December 31, 2014:
|
Oil |
|
|
Natural Gas |
|
||||||||||
|
Gross (1) |
|
|
Net (2) |
|
|
Gross (1) |
|
|
Net (2) |
|
||||
Turkey |
|
73.0 |
|
|
|
70.0 |
|
|
|
141.0 |
|
|
|
67.0 |
|
Bulgaria |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Albania |
|
202.0 |
|
|
|
202.0 |
|
|
|
– |
|
|
|
– |
|
(1) |
“Gross wells” means the wells in which we held a working interest (operating or non-operating). |
(2) |
“Net wells” means the sum of the fractional working interests owned in gross wells. |
Developed Acreage. The following table sets forth our total gross and net developed acreage as of December 31, 2014:
|
Developed Acres |
|
|||||
|
Gross (1) |
|
|
Net (2) |
|
||
Turkey |
|
210,711 |
|
|
|
106,373 |
|
Albania |
|
19,993 |
|
|
|
19,993 |
|
Total |
|
230,704 |
|
|
|
126,366 |
|
(1) |
“Gross” means the total number of acres in which we had a working interest. |
(2) |
“Net” means the sum of the fractional working interests owned in gross acres. |
Undeveloped Acreage. The following table sets forth our undeveloped land position as of December 31, 2014:
|
Undeveloped Acres |
|
|||||
|
Gross (1) |
|
|
Net (2) |
|
||
Turkey |
|
1,690,406 |
|
|
|
1,034,854 |
|
Bulgaria |
|
567,106 |
|
|
|
567,106 |
|
Albania |
|
55,635 |
|
|
|
55,635 |
|
Total |
|
2,313,147 |
|
|
|
1,657,595 |
|
(1) |
“Gross” means the total number of acres in which we had a working interest. |
(2) |
“Net” means the sum of the fractional working interests owned in gross acres. |
44
Undeveloped Acreage Expirations. The following table summarizes by year our undeveloped acreage scheduled to expire in the next five years:
|
Undeveloped Acres (1) |
|
|
% of Total Undeveloped Acres |
|
||||||
|
Gross (2) |
|
|
Net (3) |
|
|
Net (3) |
|
|||
2015 |
|
731,916 |
|
|
|
397,568 |
|
|
|
24.0 |
|
2016 |
|
568,466 |
|
|
|
374,928 |
|
|
|
22.6 |
|
2017 |
|
120,726 |
|
|
|
50,101 |
|
|
|
3.0 |
|
2018 |
|
– |
|
|
|
– |
|
|
|
– |
|
2019 |
|
152,107 |
|
|
|
95,067 |
|
|
|
5.7 |
|
(1) |
Excludes the Stefenetz Concession Area for which we have applied for a production concession. |
(2) |
“Gross” means the total number of acres in which we had a working interest. |
(3) |
“Net” means the sum of the fractional working interests owned in gross acres. |
We anticipate that we will be able to extend the license terms for substantially all of our undeveloped acreage in Turkey scheduled to expire in 2015 through the execution of our current work commitments.
TEMI has been involved in a number of lawsuits with a group of villagers living around the Selmo oil field who claim ownership of a portion of the surface at Selmo. These cases are being vigorously defended by TEMI and Turkish government authorities. We do not have enough information to estimate the potential additional operating costs we could incur in the event the purported surface owners’ claims are ultimately successful. The following is a summary of these cases.
In 2003, the villagers applied to the Kozluk Civil Court of First Instance in Turkey with seven title survey certificates dating back to Ottoman times. These villagers were granted title registration certificates, and in 2005, these villagers applied to the Kozluk Civil Court of First Instance to enlarge the areas covered by the certificates to approximately 20 square kilometers. Neither we nor, to our knowledge, any ministry in the Turkish government received notice of this court proceeding. Almost all of our production wells at the Selmo oil field lie within this enlarged area. In 2009, the Supreme Court overruled the Kozluk Civil Court of First Instance and directed it to re-examine the case (the “Surface Litigation”).
In 2006, the Turkish Forestry Authority filed a claim in the Kozluk Cadastre Court against the villagers for attempting to register land that is registered with the Turkish government as forest. TEMI joined the Turkish government as a plaintiff in that case. In February 2011, the Kozluk Cadastre Court decided to suspend the case until there is a resolution of the Surface Litigation.
In addition, TEMI is a defendant in two nuisance cases filed in the Kozluk Cadastre Court and one claim for damages filed in the Kozluk Civil Court of First Instance. The plaintiffs in each of these cases are the same villagers in the Surface Litigation. The Turkish Treasury Department and the Turkish Forestry Authority have joined TEMI as defendants in each of these cases. The Kozluk Cadastre Court has decided to suspend each of these nuisance cases until there is a resolution of the Surface Litigation. On December 27, 2012, the Kozluk Civil Court of First Instance dismissed the damages case, and the plaintiffs appealed that decision.
On June 27, 2012, the Kozluk Civil Court of First Instance dismissed the Surface Litigation. The court issued its formal decision on August 8, 2012, and the plaintiffs filed an appeal with the Court of Appeal. The file was reversed by the Court of Appeal and sent back to the Kozluk Civil Court of First Instance in August 2014. The Court of Appeals ruled that the Kozluck Civil Court of First Instance investigate the merits of the dispute to determine the ownership position of the parties, that TPAO should be added as a party to the litigation, and that the cadastral map sheet depicting the real properties at issue must be investigated. The parties then appealed to the Court of Appeals for correction of judgment.
We continue to operate on the surface at Selmo, and have paid surface damages for locations at Selmo from the time we began operating the Selmo lease to present.
Item 4. Mine Safety Disclosures
Not applicable.
45
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Canada
Our common shares are traded in Canada on the Toronto Stock Exchange (the “TSX”) under the trading symbol “TNP”. The following table sets forth the quarterly high and low sales prices per common share in Canadian dollars on the TSX for the periods indicated. The high and low sales prices per common share for each quarterly period within the two most recent fiscal years indicated below have been adjusted to reflect our 1-for-10 reverse stock split effected March 6, 2014.
|
High |
|
|
Low |
|
||
2014: |
|
|
|
|
|
|
|
Fourth Quarter |
$ |
9.85 |
|
|
$ |
6.00 |
|
Third Quarter |
$ |
13.29 |
|
|
$ |
10.10 |
|
Second Quarter |
$ |
12.04 |
|
|
$ |
8.62 |
|
First Quarter |
$ |
9.80 |
|
|
$ |
7.80 |
|
2013: |
|
|
|
|
|
|
|
Fourth Quarter |
$ |
10.00 |
|
|
$ |
7.70 |
|
Third Quarter |
$ |
10.10 |
|
|
$ |
6.10 |
|
Second Quarter |
$ |
9.40 |
|
|
$ |
7.10 |
|
First Quarter |
$ |
10.70 |
|
|
$ |
8.50 |
|
United States
Our common shares are traded in the United States on the NYSE MKT exchange under the trading symbol “TAT”. The following table sets forth the high and low sales price per common share in U.S. Dollars on the NYSE MKT for the periods indicated. The high and low sales prices per common share for each quarterly period within the two most recent fiscal years indicated below have been adjusted to reflect our 1-for-10 reverse stock split effected March 6, 2014.
|
High |
|
|
Low |
|
||
2014: |
|
|
|
|
|
|
|
Fourth Quarter |
$ |
8.65 |
|
|
$ |
5.15 |
|
Third Quarter |
$ |
12.48 |
|
|
$ |
8.99 |
|
Second Quarter |
$ |
11.39 |
|
|
$ |
7.89 |
|
First Quarter |
$ |
8.84 |
|
|
$ |
7.00 |
|
2013: |
|
|
|
|
|
|
|
Fourth Quarter |
$ |
11.00 |
|
|
$ |
7.30 |
|
Third Quarter |
$ |
9.70 |
|
|
$ |
7.10 |
|
Second Quarter |
$ |
9.10 |
|
|
$ |
6.90 |
|
First Quarter |
$ |
10.40 |
|
|
$ |
8.80 |
|
Common Shares and Dividends
As of March 6, 2015, we had 40,777,149 common shares issued and outstanding and held by 79 record holders, including nominee holders such as banks and brokerage firms who hold shares for beneficial owners.
We have not declared any dividends to date on our common shares. We have no present intention of paying any cash dividends on our common shares in the foreseeable future, as we intend to use cash flow from operations to invest in our business.
Foreign Exchange Control Regulations
We have been designated as a non-resident for Bermuda exchange control purposes by the Bermuda Monetary Authority. Because of this designation, there are no restrictions on our ability to transfer funds in and out of Bermuda.
The transfer of shares between persons regarded as residents outside Bermuda for exchange control purposes and the sale of our common shares to or by such persons may take place without specific consent under the Exchange Control Act 1972. Issuances and
46
transfers of shares involving any person regarded as a resident in Bermuda for exchange control purposes require specific approval under the Exchange Control Act 1972.
As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermuda residents, but as an exempted company, we may not participate in certain business transactions, including: (1) the acquisition or holding of land in Bermuda (except that required for our business and held by way of lease or tenancy for terms of not more than 50 years) without the express authorization of the Bermuda legislature, (2) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Finance, (3) the acquisition of any bonds or debentures secured by any land in Bermuda, other than certain types of Bermuda government securities or (4) the carrying on of business of any kind in Bermuda, except in furtherance of our business carried on outside Bermuda.
Item 6. Selected Financial Data
The following table summarizes selected consolidated financial information from continuing operations for each of the five years in the period ended December 31, 2014. All periods presented have been adjusted to reflect our oilfield services business segment and Moroccan segment as discontinued operations. You should read the information set forth below in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.
|
Year Ended December 31, |
|
|||||||||||||||||
|
2014 (1) |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
|||||
|
(amounts in thousands, except per share amounts) |
|
|||||||||||||||||
Total revenues |
$ |
140,728 |
|
|
$ |
130,827 |
|
|
$ |
143,908 |
|
|
$ |
128,905 |
|
|
$ |
70,854 |
|
Seismic and other exploration |
|
4,285 |
|
|
|
14,009 |
|
|
|
5,040 |
|
|
|
11,542 |
|
|
|
16,883 |
|
Net income (loss) from continuing operations |
|
29,096 |
|
|
|
(13,271 |
) |
|
|
(6,373 |
) |
|
|
(77,574 |
) |
|
|
(29,545 |
) |
Comprehensive income (loss) income |
|
14,751 |
|
|
|
(50,686 |
) |
|
|
38,470 |
|
|
|
(173,012 |
) |
|
|
(77,514 |
) |
Basic net income (loss) per common share from continuing operations |
|
0.77 |
|
|
|
(0.36 |
) |
|
|
(0.17 |
) |
|
|
(2.18 |
) |
|
|
(0.95 |
) |
Basic weighted average number of shares outstanding |
|
37,829 |
|
|
|
37,069 |
|
|
|
36,742 |
|
|
|
35,597 |
|
|
|
31,249 |
|
|
As of December 31, |
|
|||||||||||||||||
|
2014 (1) |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
|
|||||
|
(amounts in thousands) |
|
|||||||||||||||||
Total assets |
$ |
546,403 |
|
|
$ |
346,586 |
|
|
$ |
358,258 |
|
|
$ |
448,802 |
|
|
$ |
473,968 |
|
Long-term liabilities |
|
183,811 |
|
|
|
63,619 |
|
|
|
72,819 |
|
|
|
112,904 |
|
|
|
62,486 |
|
Shareholders' equity |
|
211,464 |
|
|
|
167,317 |
|
|
|
213,827 |
|
|
|
171,273 |
|
|
|
276,057 |
|
Capital expenditures, including acquisitions (2) |
|
141,810 |
|
|
|
99,951 |
|
|
|
81,824 |
|
|
|
152,440 |
|
|
|
170,317 |
|
_______________
(1) |
Includes the results of operations of Stream since November 18, 2014. |
(2) |
Excludes seismic and other exploration expenditures. |
47
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2014, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of March 1, 2015, approximately 36% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, the chairman of our board of directors and our chief executive officer.
Recent Decline in Oil Prices
As a result of the recent decline in prices for Brent crude, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses. These initiatives include the negotiation of exploration and development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.
Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices.
2014 Financial and Operational Performance
· |
We reported $29.1 million of net income from continuing operations. This includes a $37.5 million gain on our commodity derivative contracts and a $6.0 million foreign exchange loss. |
· |
We derived 78.1% of our revenues from the production of oil, 20.1% of our revenues from the production of natural gas and 1.8% of our revenues from other sources during the year ended December 31, 2014. |
· |
Total oil and natural gas sales revenues increased 8.6% to $138.2 million for the year ended December 31, 2014, from $127.3 million in 2013. The increase was primarily the result of an increase in sales volumes of 365 Mboe, which was partially offset by a decrease in the average sales price of $10.44 per Boe. |
· |
Wellhead production was 1,345 Mbbls of oil and 3,567 Mmcf of natural gas for the year ended December 31, 2014, as compared to 942 Mbbls of oil and 3,932 Mmcf of natural gas for 2013. |
· |
In 2014, we incurred $146.1 million in total capital expenditures, including license acquisition and seismic expenditures, from continuing operations, as compared to $114.0 million in 2013. |
· |
As of December 31, 2014, we had $106.0 million in long-term debt and $52.6 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
For information on our recent developments, see “Item 1. Business—Recent Developments.”
2014 Operations
During 2014, we implemented a three-part strategy to increase production and cash flow in Turkey: (i) the Molla vertical program, (ii) the Selmo field redevelopment program, which included horizontal drilling, and (iii) the Thrace Basin development program, which included a combination of vertical and horizontal drilling. We also began operations in Albania with the acquisition of Stream. For additional information on our current operations, see “Item 1. Business—Current Operations.”
48
Planned Operations
We plan to satisfy license earning obligations for our core properties in Turkey and to drill the D34H1 well in Albania. For more information on our planned 2015 operations, see “Item 1. Business—Planned Operations.”
Critical Accounting Policies
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 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 consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which 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.
We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties. In accordance with the successful efforts method of accounting for oil and natural gas properties, costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. Acquisition costs of proved properties are amortized using the unit-of-production method based on total proved reserves, and exploration well costs and additional development costs are amortized using the unit-of-production method based on proved developed reserves. Proceeds from the sale of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be non-productive. The determination of an exploratory well’s ability to produce generally must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Impairment of Long-Lived Assets. We follow the provisions of Accounting Standards Codification (“ASC”) 360, Property, Plant and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by field for potential impairment. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of a field are less than its carrying value. If an impairment occurs, the carrying value of the impaired field is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert, (ii) the Company’s history in exploring the area, (iii) the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Business Combinations. We follow ASC 805, Business Combinations (“ASC 805”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”). ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations will be accounted for by applying the acquisition method.
Foreign Currency Translation and Remeasurement. We follow ASC 830, Foreign Currency Matters (“ASC 830”) which requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. The functional currency for each of our subsidiaries in Turkey and Bulgaria is the local currency and is the U.S.
49
Dollars in Albania. For certain entities, translation adjustments result from the process of translating the functional currency of the foreign operation’s financial statements into our U.S. Dollar reporting currency, which is a non-cash transaction. These translation adjustments are reported separately and accumulated in the consolidated balance sheets as a component of accumulated other comprehensive loss.
ASC 830 requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Exchange gains or losses from re-measuring transactions and monetary accounts in a currency other than the functional currency are included in earnings.
Goodwill. In accordance with ASC 350, Intangibles-Goodwill and Other (“ASC 350”), goodwill is not amortized, but is tested for impairment on an annual basis at December 31, or more frequently as impairment indicators arise. ASC 350 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. We assessed the qualitative factors at December 31, 2014 and, based upon the results of the qualitative assessment, we determined that it was not necessary to perform the two-step goodwill impairment test and that our goodwill was not impaired. All of our goodwill is attributable to our Turkey operating segment.
Oil and Gas Reserves. The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged DeGolyer and MacNaughton and Deloitte LLP, our independent reserve engineers, to independently evaluate our properties that result in estimates for all of our estimated proved reserves at December 31, 2014.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Income Taxes. We follow the asset and liability method prescribed by ASC 740, Income Taxes (“ASC 740”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under ASC 740, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in earnings in the period that includes the enactment date.
Other Recent Accounting Pronouncements and Reporting Rules
In April 2014, the 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 entity’s 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.
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), an amendment to FASB Accounting Standards Codification ("ASC") Topic 205, Presentation of Financial Statements. This update provides guidance on management's responsibility in evaluating whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not
50
expect the adoption of ASU 2014-15 to have a material impact on our consolidated financial statements or results of operations. If events occur in future periods that could affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.
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 recent pronouncements will have a significant effect on our current or future earnings or operations.
Results of Operations—Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
|
Year Ended December 31, |
|
|
Change |
|
||||||
|
2014 |
|
|
2013 |
|
|
2014-2013 |
|
|||
|
(in thousands of U.S. Dollars, except per unit amounts and production volumes) |
|
|||||||||
Sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
1,339 |
|
|
|
933 |
|
|
|
406 |
|
Natural gas (Mmcf) |
|
3,262 |
|
|
|
3,512 |
|
|
|
(250 |
) |
Total production (Mboe) |
|
1,883 |
|
|
|
1,518 |
|
|
|
365 |
|
Average daily sales volumes (Boepd) |
|
5,157 |
|
|
|
4,159 |
|
|
|
998 |
|
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
82.10 |
|
|
$ |
101.02 |
|
|
$ |
(18.92 |
) |
Natural gas (per Mcf) |
$ |
8.66 |
|
|
$ |
9.40 |
|
|
$ |
(0.74 |
) |
Oil equivalent (per Boe) |
$ |
73.40 |
|
|
$ |
83.84 |
|
|
$ |
(10.44 |
) |
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
$ |
138,174 |
|
|
$ |
127,270 |
|
|
$ |
10,904 |
|
Sales of purchased natural gas |
|
2,127 |
|
|
|
2,581 |
|
|
|
(454 |
) |
Other |
|
427 |
|
|
|
976 |
|
|
|
(549 |
) |
Total revenues |
|
140,728 |
|
|
|
130,827 |
|
|
|
9,901 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
19,999 |
|
|
|
18,602 |
|
|
|
1,397 |
|
Exploration, abandonment and impairment |
|
19,864 |
|
|
|
27,333 |
|
|
|
(7,469 |
) |
Cost of purchased natural gas |
|
2,055 |
|
|
|
2,247 |
|
|
|
(192 |
) |
Seismic and other exploration |
|
4,285 |
|
|
|
14,009 |
|
|
|
(9,724 |
) |
Revaluation of contingent consideration |
|
(2,500 |
) |
|
|
(5,000 |
) |
|
|
2,500 |
|
General and administrative |
|
31,625 |
|
|
|
29,020 |
|
|
|
2,605 |
|
Depletion |
|
46,812 |
|
|
|
38,996 |
|
|
|
7,816 |
|
Depreciation and amortization |
|
2,115 |
|
|
|
2,326 |
|
|
|
(211 |
) |
Interest and other expense |
|
6,213 |
|
|
|
3,929 |
|
|
|
2,284 |
|
Foreign exchange loss |
|
5,998 |
|
|
|
9,663 |
|
|
|
(3,665 |
) |
Deferred income tax expense |
|
11,263 |
|
|
|
979 |
|
|
|
10,284 |
|
Gain (Loss) on commodity derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
Cash settlements on commodity derivative contracts |
|
(2,100 |
) |
|
|
(3,521 |
) |
|
|
1,421 |
|
Change in fair value on commodity derivative contracts |
|
39,554 |
|
|
|
823 |
|
|
|
38,731 |
|
Total gain (loss) on commodity derivative contracts |
|
37,454 |
|
|
|
(2,698 |
) |
|
|
40,152 |
|
Oil and natural gas costs per Boe: |
|
|
|
|
|
|
|
|
|
|
|
Production |
$ |
9.23 |
|
|
$ |
10.72 |
|
|
$ |
(1.49 |
) |
Depletion |
$ |
21.59 |
|
|
$ |
22.48 |
|
|
$ |
(0.89 |
) |
Oil and Natural Gas Sales. Excluding sales of purchased natural gas, total oil and natural gas sales increased to $138.2 million in 2014, from $127.3 million in 2013. Of this increase, $30.5 million resulted from an increase in sales volumes of 365 Mboe. Sales volumes increased (i) primarily on our southeast Turkey oil wells due to our successful horizontal drilling program in 2014 and (ii) due to the acquisition of Stream. This increase was partially offset by a decrease of $19.4 million, attributable to a lower average realized prices per Boe in 2014. Our average price received decreased $10.44 to $73.40 per Boe in 2014, compared to $83.84 per Boe in 2013.
Production. Production expenses for 2014 increased to $20.0 million from $18.6 million in 2013. The increase was primarily attributable to the acquisition of Stream in 2014. However, production expense per Boe decreased by $1.49 to $9.23 per Boe in 2014,
51
compared to $10.72 per Boe in 2013. This decrease was primarily attributable to an increase in our production volumes during 2014 compared to 2013.
Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs decreased to $19.9 million in 2014, compared to $27.3 million for 2013. The decrease was primarily due to a $15.5 million decrease in exploratory dry hole expense offset by $6.5 million increase in impairment and abandonment. The majority of our impairment and abandonment charges of $17.5 million in 2014 related to three exploratory wells in Turkey.
Seismic and Other Exploration. Seismic and other exploration costs decreased to $4.3 million for 2014, compared to $14.0 million for 2013. The decrease was primarily due to seismic acquisition activities conducted on our West Molla license during 2013.
Revaluation of Contingent Consideration. As a result of the amendment to the purchase agreement with Direct Petroleum LLC (“Direct”), during 2014, we recognized the reversal of a $2.5 million contingent liability that was originally recorded in 2011.
General and Administrative. General and administrative expense increased $2.6 million to $31.6 million for 2014, compared to $29.0 million for 2013. The increase was primarily due to a $1.5 million charge to bad debt expense for an uncollectible receivable and $1.2 million of acquisition expenses related to the acquisition of Stream. This was partially offset by a decrease in office rent expense of $0.3 million during 2014.
Depletion. Depletion expense increased to $46.8 million or $21.59 per Boe for 2014, compared to $39.0 million or $22.48 per Boe for 2013. The increase was due primarily to additions to proved properties on our Selmo and Bahar fields and an increase in production volumes during 2014.
Interest and Other Expense. Interest and other expense increased to $6.2 million in 2014, compared to $3.9 million in 2013. The increase was primarily due to an increase in our average level of debt outstanding during 2014 compared to 2013. Excluding debt assumed in the Stream acquisition, at December 31, 2014, we had $135.7 million of total debt outstanding, compared to $69.8 million at December 31, 2013. Also contributing to the increase was a $0.5 million write-off of loan financing costs related to our prior amended and restated credit facility, which was repaid in May 2014.
Foreign Exchange Loss. We recorded a foreign exchange loss of $6.0 million in 2014, compared to a loss of $9.7 million in 2013. The change in foreign exchange is primarily unrealized (non-cash) in nature and results 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 decrease in foreign exchange loss in 2014 was due to a 8.6% devaluation of the TRY compared to the U.S. Dollar in 2014, compared to a 19.7% devaluation during 2013.
Deferred Income Tax Expense. Deferred income tax expense increased to $11.3 million for the year ended December 31, 2014, compared to $1.0 million for 2013. The increase was primarily due to changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.
Gain (Loss) on Commodity Derivative Contracts. During 2014, we recorded a net gain on commodity derivative contracts of $37.5 million, compared to a net loss of $2.7 million for 2013. In 2014, we recorded a $39.6 million gain to mark our commodity derivative contracts to their fair value and a $2.1 million loss on settled contracts. In 2013, we recorded a $0.8 million gain to mark our commodity derivative contracts to their fair value and a $3.5 million loss on settled contracts. We are required under our Senior Credit Facility to hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey.
52
Results of Operations—Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
|
Year Ended December 31, |
|
|
Change |
|
||||||
|
2013 |
|
|
2012 |
|
|
2013-2012 |
|
|||
|
(in thousands of U.S. Dollars, except per unit amounts and production volumes) |
|
|||||||||
Sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
933 |
|
|
|
949 |
|
|
|
(16 |
) |
Natural gas (Mmcf) |
|
3,512 |
|
|
|
4,238 |
|
|
|
(726 |
) |
Total production (Mboe) |
|
1,518 |
|
|
|
1,655 |
|
|
|
(137 |
) |
Average daily sales volumes (Boepd) |
|
4,159 |
|
|
|
4,522 |
|
|
|
(363 |
) |
Average prices: |
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
$ |
101.02 |
|
|
$ |
102.55 |
|
|
$ |
(1.53 |
) |
Natural gas (per Mcf) |
$ |
9.40 |
|
|
$ |
8.68 |
|
|
$ |
0.72 |
|
Oil equivalent (per Boe) |
$ |
83.84 |
|
|
$ |
81.04 |
|
|
$ |
2.80 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
$ |
127,270 |
|
|
$ |
134,113 |
|
|
$ |
(6,843 |
) |
Sales of purchased natural gas |
|
2,581 |
|
|
|
7,882 |
|
|
|
(5,301 |
) |
Other |
|
976 |
|
|
|
1,913 |
|
|
|
(937 |
) |
Total revenues |
|
130,827 |
|
|
|
143,908 |
|
|
|
(13,081 |
) |
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
18,602 |
|
|
|
17,804 |
|
|
|
798 |
|
Exploration, abandonment and impairment |
|
27,333 |
|
|
|
39,993 |
|
|
|
(12,660 |
) |
Cost of purchased natural gas |
|
2,247 |
|
|
|
7,694 |
|
|
|
(5,447 |
) |
Seismic and other exploration |
|
14,009 |
|
|
|
5,040 |
|
|
|
8,969 |
|
Revaluation of contingent consideration |
|
(5,000 |
) |
|
|
- |
|
|
|
(5,000 |
) |
General and administrative |
|
29,020 |
|
|
|
33,947 |
|
|
|
(4,927 |
) |
Depletion |
|
38,996 |
|
|
|
26,024 |
|
|
|
12,972 |
|
Depreciation and amortization |
|
2,326 |
|
|
|
2,191 |
|
|
|
135 |
|
Interest and other expense |
|
3,929 |
|
|
|
8,340 |
|
|
|
(4,411 |
) |
Foreign exchange loss |
|
9,663 |
|
|
|
(1,083 |
) |
|
|
10,746 |
|
Deferred income tax expense |
|
979 |
|
|
|
1,817 |
|
|
|
(838 |
) |
Loss on commodity derivative contracts: |
|
|
|
|
|
|
|
|
|
|
|
Cash settlements on commodity derivative contracts |
|
(3,521 |
) |
|
|
(3,829 |
) |
|
|
308 |
|
Change in fair value on commodity derivative contracts |
|
823 |
|
|
|
(1,719 |
) |
|
|
2,542 |
|
Total loss on commodity derivative contracts |
|
(2,698 |
) |
|
|
(5,548 |
) |
|
|
2,850 |
|
Oil and natural gas costs per Boe: |
|
|
|
|
|
|
|
|
|
|
|
Production |
$ |
10.72 |
|
|
$ |
9.42 |
|
|
$ |
1.30 |
|
Depletion |
$ |
22.48 |
|
|
$ |
13.77 |
|
|
$ |
8.71 |
|
Oil and Natural Gas Sales. Excluding sales of purchased natural gas, total oil and natural gas sales decreased to $127.3 million in 2013, from $134.1 million in 2012. Of this decrease, $11.1 million resulted from a decrease in sales volumes of 137 Mboe. Sales volumes decreased primarily on our Thrace Basin wells due to high decline rates. This decrease was partially offset by an increase of $4.3 million, attributable to higher average realized prices per Boe resulting from the production of a higher percentage of oil and the realization of higher natural gas prices. Our average price received increased $2.80 to $83.84 per Boe in 2013, compared to $81.04 per Boe in 2012.
Production. Production expenses for 2013 increased to $18.6 million from $17.8 million in 2012. The increase was primarily attributable to the sale of our oilfield services business in June 2012. Certain expenses that were classified as inter-company and eliminated upon consolidation prior to the sale are now classified as third party. Production expense per Boe increased $1.30 to $10.72 per Boe in 2013, compared to $9.42 per Boe in 2012. This increase is primarily attributable to a decrease in our production volumes during 2013 as compared to 2012, combined with a higher percentage of oil production, which has a higher production cost per Boe compared to natural gas.
53
Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs decreased to $27.3 million in 2013, compared to $40.0 million for 2012. The decrease was primarily due to an $8.7 million decrease in exploratory dry hole expense and a $4.0 million decrease in impairment and abandonment. The majority of our impairment and abandonment charges of $11.3 million in 2013 related to our exploration licenses in Turkey. In 2012, impairment was taken on a portion of our proved properties in Turkey for $6.7 million and on our exploration licenses in Turkey for $8.4 million. Additionally, in 2013, nine wells were written off to exploration, abandonment and impairment for $16.0 million, compared to 16 wells which were written off in 2012 for $24.7 million.
Seismic and Other Exploration. Seismic and other exploration costs increased to $14.0 million for 2013, compared to $5.0 million for 2012. The increase was primarily due to seismic acquisition activities conducted on our West Molla license during 2013.
Revaluation of Contingent Consideration. As a result of the amendment to the purchase agreement with Direct, during 2013, we recognized the reversal of a $5.0 million contingent liability that was originally recorded in 2011.
General and Administrative. General and administrative expense decreased $4.9 million to $29.0 million for 2013, compared to $33.9 million for 2012. The decrease was primarily due to a decrease in employee-related costs of $2.1 million and a decrease in legal, accounting and consultancy expense of $0.5 million. Employee-related costs decreased due to a reduction in head count in 2013, and legal, accounting and consultancy expenses decreased primarily due to the timely filing of our quarterly reports on Form 10-Q for the quarters ended June 30, 2013 and September 30, 2013. Also contributing to the decrease was a $2.0 million accrual for a contingency related to our Aglen exploration permit in Bulgaria, which was recognized during 2012. The remaining decrease of $0.3 million was attributable to our overall cost reduction efforts.
Depletion. Depletion expense increased to $39.0 million for 2013, compared to $26.0 million in 2012. The increase was due primarily to capital additions in the Selmo, Tekirdag, Goksu and Molla fields and to downward reserves revisions, which increased the depletion rates for certain fields.
Interest and Other Expense. Interest and other expense decreased to $3.9 million for 2013, compared to $8.3 million for 2012. The decrease was primarily due to a decrease in our average debt levels from 2013 to 2012. In June 2012, we repaid $129.2 million of debt with proceeds from the sale of our oilfield services business.
Foreign Exchange Loss (Gain). We recorded a foreign exchange loss of $9.7 million in 2013, compared to a gain of $1.1 million in 2012. The change in foreign exchange is primarily unrealized (non-cash) in nature and results 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 increased foreign exchange loss in 2013 is due to a 19.7% decrease in value of the TRY compared to the U.S. Dollar in 2013.
Deferred Income Tax Expense. Deferred income tax expense decreased to $1.0 million for the year ended December 31, 2013, compared to $1.8 million for 2012. The decrease was primarily due to changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.
Loss on Commodity Derivative Contracts. During 2013, we recorded a net loss on commodity derivative contracts of $2.7 million, compared to a net loss of $5.5 million for 2012. In 2013, we recorded a $0.8 million gain to mark our commodity derivative contracts to their fair value and a $3.5 million loss on settled contracts. In 2012, we recorded a $1.7 million loss to mark our commodity derivative contracts to their fair value and a $3.8 million loss on settled contracts. We were required under our prior amended and restated credit facility to hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey.
54
Discontinued Operations. All revenues and expenses associated with our Moroccan operations and oilfield services business for 2013 and 2012 have been included in discontinued operations. The results of operations for our Moroccan operations and oilfield services business were as follows:
|
Year Ended December 31, |
|
|||||
|
2013 |
|
|
2012 |
|
||
|
(in thousands) |
|
|||||
Revenues: |
|
|
|
|
|
|
|
Oil and gas sales |
$ |
– |
|
|
$ |
68 |
|
Oilfield services |
|
– |
|
|
|
19,888 |
|
Total revenues |
|
– |
|
|
|
19,956 |
|
Costs and expenses: |
|
|
|
|
|
|
|
Production |
|
178 |
|
|
|
789 |
|
Oilfield services costs |
|
25 |
|
|
|
12,955 |
|
General and administrative |
|
302 |
|
|
|
10,938 |
|
Total costs and expenses |
|
505 |
|
|
|
24,682 |
|
Operating loss |
|
(505 |
) |
|
|
(4,726 |
) |
Other income (expense): |
|
|
|
|
|
|
|
Interest and other expense |
|
(8 |
) |
|
|
(156 |
) |
Interest and other income |
|
71 |
|
|
|
562 |
|
Foreign exchange loss |
|
– |
|
|
|
(763 |
) |
Total other income (expense) |
|
63 |
|
|
|
(357 |
) |
Loss before income taxes from discontinued operations |
|
(442 |
) |
|
|
(5,083 |
) |
Gain on sale of discontinued operations |
|
– |
|
|
|
35,999 |
|
Income tax provision |
|
– |
|
|
|
(8,297 |
) |
Net (loss) income from discontinued operations |
$ |
(442 |
) |
|
$ |
22,619 |
|
Capital Expenditures
For 2014, we incurred $146.1 million in total capital expenditures, including license acquisition, seismic and corporate expenditures, compared to $114.0 million for 2013. The increase in capital expenditures was primarily due to the acquisition of Stream.
We expect our net field capital expenditures for 2015 to range between $12.0 and $38.0 million. We expect net field capital expenditures during 2015 to include approximately $12.0 million of drilling and completion expense for five gross obligation wells to hold our most promising licenses in Turkey. We expect cash on hand, proceeds from the private placement of convertible notes, and cash flow from operations will be sufficient to fund our 2015 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2015 capital expenditure budget is subject to change.
Liquidity and Capital Resources
Our primary sources of liquidity for 2014 were our cash and cash equivalents, cash flow from operations, proceeds from the issuance of our convertible notes and borrowings under our Senior Credit Facility. At December 31, 2014, we had cash and cash equivalents of $35.1 million, $106.0 million in long-term debt, $52.6 million in short-term debt and a working capital deficit of $45.9 million (excluding assets and liabilities held for sale, deferred income taxes and derivative assets), compared to cash and cash equivalents of $12.9 million, $26.5 million in long-term debt, $43.3 million in short-term debt and working capital deficit of $39.4 million at December 31, 2013 (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities). Cash provided by operating activities from continuing operations during 2014 was $78.1 million, compared to cash provided by operating activities from continuing operations of $68.8 million in 2013, due primarily to an increase in oil revenues.
Cash used in investing activities from continuing operations during 2014 increased to $117.2 million, compared to cash used in investing activities from continuing operations of $105.1 million in 2013, due primarily to an increase in drilling operations on our Bahar oil field. Additionally, cash provided by financing activities from continuing operations was $61.6 million in 2014, compared to cash provided in financing activities from continuing operations of $37.0 million in 2013, due primarily to an increase in our borrowings.
55
As a result of the recent decline in prices for Brent crude, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses. These initiatives include the negotiation of exploration and development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.
We believe that our cash flows from operations and existing cash on hand are sufficient to conduct our planned operations through 2015 and meet our contractual requirements, including license obligations. Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.
Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices.
As of December 31, 2014, the outstanding principal amount of our debt was $158.6 million. In addition to cash, cash equivalents and cash flow from operations, at December 31, 2014, we had a Senior Credit Facility, a credit facility with a Turkish bank, convertible notes, a term loan facility, a prepayment agreement, a note with Viking International Limited (“Viking International”) and a shareholder loan, all of which are discussed below.
Senior Credit Facility. On May 6, 2014, DMLP, TEMI, Talon Exploration, TransAtlantic Turkey Ltd., Amity and Petrogas (collectively the “Borrowers”) entered into the Senior Credit Facility with BNP Paribas and the 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 lender’s 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 borrowing base was $71.5 million as of December 31, 2014. 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 lender’s individual commitment.
Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.26% at December 31, 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.
56
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) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized under the “full cost” accounting method), (vii) 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), and (viii) 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 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.
57
Pursuant to the Senior Credit Facility, at least one of the Borrowers is required to maintain commodity derivative contracts with BNP Paribas that hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey. TEMI has entered into three-way collar contracts with BNP Paribas, which hedge the price of oil through March 2019.
At December 31, 2014, we had borrowings of $68.3 million under the Senior Credit Facility and $3.2 million of available borrowing capacity. At December 31, 2014, we were not in compliance with Section 8.16(a) of our Senior Credit Facility, which requires the Borrowers to maintain a current ratio of not less than 1.10:1.0. The lenders have granted the Borrowers a waiver on the current ratio requirement through March 31, 2015. At March 15, 2015, we had no availability under the Senior Credit Facility.
TBNG Credit Facility. TBNG has a fully drawn credit facility with a Turkish bank. The facility bears interest at a rate of 6.6% per annum and is due in monthly principal installments of $2.3 million each, ending September 30, 2015. The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell. At December 31, 2014, TBNG had balance of $20.0 million under the credit facility and no availability.
Convertible Notes. As of December 31, 2014, we sold $47.4 million of convertible notes in a non-brokered private placement (the “Notes”). The Notes bore interest at a rate of 13.0% per annum and would have matured on July 1, 2017. The Notes were convertible, at the election of a holder, any time after July 1, 2015, into our common shares (the “Common Shares”) at a conversion price of $6.80 per share. Subsequent to December 31, 2014, we sold an additional $7.6 million of Notes. On February 20, 2015, the Company exchanged the Notes for substantially identical notes issued pursuant to an indenture (the “Exchange Notes”).
Exchange Notes. On February 20, 2015, we issued $55.0 million of Exchange Notes in exchange for all outstanding Notes. The Exchange Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association, as trustee (the “Trustee”).
The Exchange Notes bear interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year, commencing on July 1, 2015. The Exchange Notes will mature on July 1, 2017, unless earlier redeemed or converted.
Holders may, at any time after July 1, 2015 and from time to time at such holder’s option, convert, subject to certain terms and conditions, any or all of the principal of any Exchange Note into fully paid and nonassessable Common Shares at the conversion price. The initial conversion price is $6.80 per Common Share, subject to adjustment as described in the Indenture. Prior to or contemporaneously with the conversion of any of the principal of an Exchange Note, all accrued but unpaid interest on the principal amount being converted will be paid in cash. The Exchange Notes may not be converted into Common Shares on the maturity date or the redemption date.
At any time on or after July 1, 2015, we may redeem all or part of the Exchange Notes at the redemption prices specified below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid interest to the redemption date.
Period Beginning |
Redemption Price |
July 1, 2015 |
107.5% |
January 1, 2016 |
105.0% |
July 1, 2016 |
102.5% |
January 1, 2017 |
100.0% |
If we experience a fundamental change (as defined in the Indenture), we will be required to make an offer to repurchase the Exchange Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase. Additionally, if we sell certain assets in exchange for $50.0 million or more in cash consideration, in certain circumstances, we will be required to use a portion of the net cash proceeds of such sale to make an offer to repurchase Exchange Notes at a price equal to the price we would be required to pay for an optional redemption at such time, plus accrued and unpaid interest, if any, up to but excluding the date of repurchase. The Indenture provides for customary events of default. The Indenture contains limited covenants.
Term Loan Facility. On September 17, 2014, Stream Sub and Raiffeisen entered into the Term Loan Facility, which amended and restated a facility agreement, dated December 15, 2011, as amended (the “Facility Agreement”). The loan matures on December 31, 2016 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to pay 1/16th of the total commitment each quarter on the last business day of each of March, June, September and December each year. The loan is
58
guaranteed by Stream Sub’s parent company, Stream. Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs. The Term Loan Facility is secured by substantially all of the assets of Stream Sub.
Under the Term Loan Facility, Stream Sub may not declare or pay any dividends on any of Stream Sub’s common shares without the consent of the lender, except, provided that no default has occurred and is continuing under the Term Loan Facility, Stream Sub may make payments to Stream from excess cash flow to cover the administrative overhead of Stream, including the salary and related employment costs of any employee, officer or director of Stream, up to a total limit in any three-month period of $500,000.
Pursuant to the terms of the Term Loan Facility, until amounts under the Term Loan Facility are repaid, Stream Sub may not, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of Stream Sub to create any liens, (iii) enter into any amalgamation, demerger, merger, or corporate reconstruction or any joint venture or partnership agreement, (iv) incorporate any company as a subsidiary, (v) dispose of any asset, (vi) declare or pay any dividends to shareholders, (vii) enter into a sale and leaseback arrangement, (viii) make any substantial change to the general nature or scope of its business from that carried on at the date of the Term Loan Facility, (ix) use, deposit, handle, store produce, release or dispose of dangerous materials, (x) make any loans or grant any credit, and (xi) cancel, terminate amend or waive any default under any export contract or allow any buyer to do the same.
In addition, the Term Loan Facility contains financial covenants that require Stream Sub to maintain as of the end of each fiscal year: (i) earnings before interest, taxes, depreciation and amortization (“EBITDA”) of not less than $10.0 million; (ii) an outstanding loan principal of no more than twice its EBITDA; and (iii) EBITDA of at least ten times greater than its accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments.
An event of default under the Term Loan 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, upon the occurrence of a change of control of Stream Sub, Stream Sub is required to notify Raiffeisen, and Raiffeisen would have the option to cancel loan commitments and accelerate all outstanding loans and other amounts payable. A change of control is defined under the Term Loan Facility as Stream ceasing to hold more than 75% of the shares in the issued share capital of Stream Sub carrying the right to vote. Our acquisition of Stream did not constitute a change of control under the Term Loan Facility.
Stream must, upon the request of Raiffeisen when Stream Sub’s predicted expenditures exceed its predicted revenues for any period, inject cash into Stream by means of equity loan or other method acceptable to Raiffeisen to the extent necessary to remedy the cashflow shortfall or repay the total amount outstanding under the Term Loan Facility.
On September 17, 2014, Stream Sub, Stream and Raiffeisen entered into an amendment and restatement agreement pursuant to which Raiffeisen granted a deferral of the June 2014 principal payment due under the Facility Agreement until December 2016. In addition, Raiffeisen waived its rights under the Facility Agreement with respect to events of default resulting from (i) Stream Sub’s non-payment of the June 2014 principal payment; and (ii) Stream Sub’s breach of the financial covenants for the fiscal year ended November 30, 2013. Pursuant to the amendment and restatement agreement, (i) Stream Sub paid all fees, costs and expenses due and (ii) Stream Sub and Albpetrol entered into an agreement to postpone certain capital expenditures that were required under Stream’s work program on its properties.
As of December 31, 2014, we had $10.5 million outstanding under the Term Loan Facility and no availability.
At December 31, 2014, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol and ourselves concerning postponement of capital expenditures. Raiffeisen has granted us a waiver on this requirement until May 5, 2015.
Prepayment Agreement. In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6% (6.17% at December 31, 2014). Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015.
Each of Stream and Stream Sub is required to comply with certain financial and non-financial covenants under the Prepayment Agreement, including financial covenants that Stream must maintain, unless Trafigura agrees otherwise:
(i) |
EBITDA of not less than $10.0 million; |
59
(ii) |
outstanding indebtedness of not more than twice its EBITDA; and |
(iii) |
EBITDA of at least ten times greater than its accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments. |
In addition, Stream must ensure that its coverage ratio is not less than 150% at all times. The coverage ratio is the ratio of the estimated aggregate valuation of the volume of crude oil to be delivered under the oil sales contract between Stream and Trafigura to the outstanding amount of the prepayment plus any applicable funding costs and fees.
Pursuant to the terms of the Prepayment Agreement, until amounts under the Prepayment Agreement are repaid, Stream Sub may not, in each case subject to certain exceptions, (i) create any liens over the Prepayment Agreement, or if such lien would have a material adverse effect, over any other assets or undertakings, (ii) enter into any amalgamation, demerger, merger, or corporate reconstruction, (iii) pay, repay or prepay any principal, interest or other amount on or in respect of or redeem, purchase or cancel any indebtedness owed actually or contingently to any shareholder of Stream Sub or an affiliate of any shareholder of Stream Sub, or (iv) reduce, return, purchase, repay, cancel or redeem any of its share capital.
Trafigura has termination and acceleration rights under the Prepayment Agreement upon the occurrence of certain events, including, 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 triggers termination and acceleration rights. A change of control is defined under the Prepayment Agreement as any person or group of persons acting in concert gaining ownership or control of Stream Sub. Control is defined as the power to direct or cause the direction of the management or policies of another person. Trafigura waived the change of control provision under the Prepayment Agreement in connection with our acquisition of Stream.
At December 31, 2014, we had $3.0 million outstanding under the Prepayment Agreement and no availability.
Viking International Note. On September 16, 2014, Stream issued to Viking International Limited (“Viking International”) a note in the principal amount of $6.8 million. The note was amended monthly to evidence additional advances. At December 31, 2014, we had $6.8 million outstanding under the Viking International note. At March 12, 2015, we had repaid the note.
Shareholder Loan. In March 2014, Stream borrowed CAD $3.0 million from a shareholder of Stream. The loan bore interest at a fixed rate of 10.0% per annum, calculated and compounded monthly. On January 6, 2015, we repaid the shareholder loan in full with the net proceeds from our private placement of Notes.
Contractual Obligations
The following table presents a summary of our contractual obligations at December 31, 2014:
|
|
Payments Due By Year |
|
|||||||||||||||||||||||||
|
|
(in thousands) |
|
|||||||||||||||||||||||||
|
|
Total |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt |
|
$ |
158,598 |
|
|
$ |
52,606 |
|
|
$ |
73,278 |
|
|
$ |
16,150 |
|
|
$ |
11,764 |
|
|
$ |
4,800 |
|
|
$ |
- |
|
Interest |
|
|
26,288 |
|
|
|
11,077 |
|
|
|
9,598 |
|
|
|
4,977 |
|
|
|
595 |
|
|
|
41 |
|
|
|
- |
|
Leases |
|
|
7,097 |
|
|
|
2,826 |
|
|
|
346 |
|
|
|
195 |
|
|
|
33 |
|
|
|
- |
|
|
|
3,697 |
|
Total |
|
$ |
191,983 |
|
|
$ |
66,509 |
|
|
$ |
83,222 |
|
|
$ |
21,322 |
|
|
$ |
12,392 |
|
|
$ |
4,841 |
|
|
$ |
3,697 |
|
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements at December 31, 2014.
60
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risk from changes in interest rates, foreign currency exchange and hedging contracts. A discussion of the market risk exposures follows. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.
Interest Rate Risk
At December 31, 2014, our exposure to interest rate changes related primarily to floating rate borrowings under our Senior Credit Facility. At December 31, 2014, we had $68.3 million in outstanding borrowings under the Senior Credit Facility. The interest we pay on borrowings under the Senior Credit Facility is equal to three-month LIBOR plus 5.00% per annum (5.26% at December 31, 2014). A hypothetical 10% change in the interest rates we pay on the Senior Credit Facility as of December 31, 2014 would result in an increase or decrease in our interest costs of approximately $0.4 million per year.
Foreign Currency Risk
We are subject to changes in foreign currency exchange rates as a result of our operations in foreign countries. The assets, liabilities and results of operations of our foreign operations are measured using the functional currency of such foreign operation. The functional currency for each of our subsidiaries in Turkey and Bulgaria is the local currency. As a result, translation adjustments will result from the process of translating the functional currency of our foreign operation’s financial statements into the U.S. Dollar reporting currency, which is a non-cash transaction. Such non-cash translation adjustments accumulate on our consolidated balance sheets as a component of accumulated other comprehensive loss and are recorded in our consolidated statements of comprehensive income (loss).
The functional currency of our operations in Turkey and Bulgaria is the TRY and the Bulgarian Lev, respectively. The exchange rates used to translate the financial position of our Turkish and Bulgarian operations at December 31, 2014, 2013 and 2012 are shown below:
|
Year Ended December 31, |
|
|||||||||
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
New Turkish Lira per $1.00 U.S Dollar |
|
2.3189 |
|
|
|
2.1343 |
|
|
|
1.7826 |
|
Bulgarian Lev per $1.00 U.S. Dollar |
|
1.6084 |
|
|
|
1.4216 |
|
|
|
1.4827 |
|
We are also subject to foreign currency exposures as a result of our operations in the other foreign countries in which we operate. We record foreign exchange (gain) loss on our consolidated statements of comprehensive income (loss) as a component of other (expense) income for gains and losses which result from re-measuring transactions and monetary accounts into our functional currency in earnings. The change in foreign exchange (gain) loss is primarily unrealized (non-cash) in nature and results 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. For 2014 and 2013, we recorded a foreign exchange loss of $6.0 million and a foreign exchange loss of $9.7 million, respectively. We estimate that a 10% change in the exchange rates would impact our cash balances and our net loss by approximately $0.5 million. We have not used foreign currency forward contracts to manage exchange rate fluctuations.
Commodity Price Risk
Our revenues are derived from the sale of oil and natural gas. The prices for oil and natural gas are extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions.
Pursuant to our Senior Credit Facility, at least one of the Borrowers is required to maintain commodity derivative contracts with BNP Paribas. As a result, TEMI has entered into costless collar and three-way collar derivative contracts with BNP Paribas to hedge the price of oil. Pursuant to our Senior Credit Facility, we cannot enter into hedge agreements that, when aggregated with any other hydrocarbon hedge agreement then in effect, covers notional volumes in excess of 75% of the reasonably projected production volumes attributable to our proved developed reserves. The derivative contracts economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. While the use of the hedging arrangements will limit the downside risk of adverse price movements, it may also limit future gains from favorable movements.
61
The costless collars provide us with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price we will receive for the hedged volumes while the ceiling price represents the highest price we will receive for the hedged volumes. The costless collars are settled monthly. These contracts may or may not involve payment or receipt of cash at inception, depending on the ceiling and floor pricing.
The three-way collar contracts consist of a purchased put, a sold call and a purchased call. The purchased put establishes a lower limit “floor” price, the sold call establishes an upper limit “ceiling” price and the purchased call establishes a “second floor” price on the hedged volumes. The three-way collar contracts require our counterparty to pay us if the settlement price for any settlement period is below the floor price. We are required to pay our counterparty if the settlement price for any settlement period is above the ceiling price but below the second floor price, and our counterparty is required to pay us if the settlement price for any settlement period is above the second floor price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price. The three-way collar contracts are settled monthly.
We have elected not to designate our derivative financial instruments as hedges for accounting purposes, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur. We recognize gains and losses related to these contracts on a mark-to-market basis in our consolidated statements of comprehensive income (loss) under the caption “Loss on commodity derivative contracts.” Cash settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows. All of our oil derivative contracts are settled based upon Brent crude oil pricing. If commodity prices decrease, this commodity price change could have a positive impact to our earnings. Conversely, if commodity prices increase, this commodity price change could have a negative effect on our earnings. Each derivative contract is evaluated separately to determine its own fair value. During 2014, we recorded a net gain on commodity derivative contracts of $37.5 million and a net loss of $2.7 million in 2013.
The following tables summarize our outstanding commodity derivatives contracts with respect to our future oil production as of December 31, 2014:
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
||
|
|
|
|
Quantity |
|
|
Minimum |
|
|
Maximum Price |
|
|
Estimated Fair |
|
||||
Type |
|
Period |
|
(Bbl/day) |
|
|
Price (per Bbl) |
|
|
(per Bbl) |
|
|
Value of Asset |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Collar |
|
January 1, 2015—December 31, 2015 |
|
|
1,410 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
12,518 |
|
|
|
|
|
Collars |
|
|
Additional Call |
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
Average |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Minimum |
|
|
Maximum |
|
|
Maximum |
|
|
Estimated Fair |
|
||||
|
|
|
|
Quantity |
|
|
Price |
|
|
Price |
|
|
Price |
|
|
Value of |
|
|||||
Type |
|
Period |
|
(Bbl/day) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
Asset |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Three-way collar contract |
|
January 1, 2016—December 31, 2016 |
|
|
1,066 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
$ |
7,609 |
|
Three-way collar contract |
|
January 1, 2017—December 31, 2017 |
|
|
888 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
5,748 |
|
Three-way collar contract |
|
January 1, 2018—December 31, 2018 |
|
|
726 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
4,659 |
|
Three-way collar contract |
|
January 1, 2019—March 31, 2019 |
|
|
663 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
1,053 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,069 |
|
Item 8. Financial Statements and Supplementary Data
See Index to Financial Statements on page F-1.
62
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Acquisition of Stream
On November 18, 2014, we acquired Stream. For purposes of determining the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2014, and any change in our internal control over financial reporting for the fourth quarter of 2014, management has excluded the internal control over financial reporting of Stream from its evaluation of these matters. Stream represented approximately $126.6 million or 23.2% of our consolidated total assets at December 31, 2014 and approximately $1.9 million or 1.3% of our consolidated revenue for the year ended December 31, 2014. Any material change to our internal control over financial reporting due to the acquisition of Stream will be disclosed in our Annual Report on Form 10-K for the year ending December 31, 2015 in which our assessment that encompasses Stream will be included.
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and our chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2014, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures. Based upon the evaluation, our chief executive officer and chief financial officer concluded that, as of December 31, 2014, our disclosure controls and procedures were effective.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, is a process designed by, or under the supervision of, the chief executive officer and chief financial officer, or persons performing similar functions, and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP and includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, (iii) provide reasonable assurance that receipts and expenditures are being made only in accordance with appropriate authorizations of management and the board of directors, and (iv) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
On November 18, 2014, we acquired Stream. For purposes of determining the effectiveness of our internal control over financial reporting as of December 31, 2014, management has excluded the internal control over financial reporting of Stream from its evaluation of these matters. Stream represented approximately $126.6 million or 23.2% of our consolidated total assets at December 31, 2014 and approximately $1.9 million or 1.3% of our consolidated revenue for the year ended December 31, 2014.
Our management, under the supervision and with the participation of our chief executive officer and chief financial officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.
The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements, as stated in their reports on pages F-2 and F-3 of this Form 10-K.
63
Changes in Internal Control Over Financial Reporting
As of December 31, 2014, management has sufficient evidence to conclude that remediation has been completed for the two material weaknesses which were reported as of December 31, 2013.
There were no additional changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
64
Item 10. Directors, Executive Officers and Corporate Governance
Certain information required in response to this Item 10 is contained under the heading “Executive Officers of the Registrant” in Part I of this Annual Report on Form 10-K. Other information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Code of Business Conduct
We have adopted a code of ethics that applies to all our officers, directors and employees, including our principal executive officer, principal financial officer, principal accounting officer and controller. The full text of our Code of Conduct is published on our website at www.transatlanticpetroleum.com, on the Corporate Governance page under the About tab. We intend to disclose future amendments to certain provisions of the Code of Conduct, or waivers of such provisions granted to executive officers and directors, on our website within four business days following the date of such amendment or waiver.
Item 11. Executive Compensation
The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
Item 14. Principal Accountant Fees and Services
The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.
65
Item 15. Exhibits and Financial Statement Schedules
(a) |
Documents filed as part of the Report. |
1. |
Reports of Independent Registered Public Accounting Firm |
|
Consolidated Balance Sheets as of December 31, 2014 and 2013 |
|
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2014, 2013 and 2012 |
|
Consolidated Statements of Equity for the years ended December 31, 2014, 2013 and 2012 |
|
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012 |
|
Notes to Consolidated Financial Statements |
2. |
Exhibits required to be filed by Item 601 of Regulation S-K |
The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report.
66
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
March 16, 2015
TRANSATLANTIC PETROLEUM LTD. |
|
/S/ N. MALONE MITCHELL 3rd |
N. Malone Mitchell 3rd Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature |
|
Capacity |
|
Date |
|
|
|
|
|
/S/ N. MALONE MITCHELL 3rd |
|
Chairman and Chief Executive Officer |
|
March 16, 2015 |
N. Malone Mitchell 3rd |
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
/S/ WIL F. SAQUETON |
|
Chief Financial Officer |
|
March 16, 2015 |
Wil F. Saqueton |
|
(Principal Financial Officer and Principal Accounting Officer/Controller) |
|
|
|
|
|
|
|
/S/ BOB G. ALEXANDER |
|
Director |
|
March 16, 2015 |
Bob G. Alexander |
|
|
|
|
|
|
|
|
|
/S/ BRIAN E. BAYLEY |
|
Director |
|
March 16, 2015 |
Brian Bayley |
|
|
|
|
|
|
|
|
|
/S/ CHARLES J. CAMPISE |
|
Director |
|
March 16, 2015 |
Charles J. Campise |
|
|
|
|
|
|
|
|
|
/S/ MARLAN W. DOWNEY |
|
Director |
|
March 16, 2015 |
Marlan W. Downey |
|
|
|
|
|
|
|
|
|
/S/ GREGORY K. RENWICK |
|
Director |
|
March 16, 2015 |
Gregory K. Renwick |
|
|
|
|
|
|
|
|
|
/S/ MEL G. RIGGS |
|
Director |
|
March 16, 2015 |
Mel G. Riggs |
|
|
|
|
67
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-1
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
TransAtlantic Petroleum Ltd.:
We have audited the accompanying consolidated balance sheets of TransAtlantic Petroleum Ltd. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of comprehensive income (loss), equity, and cash flows for each of the years in the three‑year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TransAtlantic Petroleum Ltd. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TransAtlantic Petroleum Ltd.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 16, 2015
F-2
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
TransAtlantic Petroleum Ltd.:
We have audited TransAtlantic Petroleum Ltd.’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransAtlantic Petroleum Ltd.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, TransAtlantic Petroleum Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
TransAtlantic Petroleum Ltd. acquired Stream Oil & Gas Ltd. during 2014, and management excluded from its assessment of the effectiveness of TransAtlantic Petroleum Ltd.’s internal control over financial reporting as of December 31, 2014, Stream Oil & Gas Ltd.’s internal control over financial reporting associated with total assets of $126.6 million and total revenues of $1.9 million included in the consolidated financial statements of TransAtlantic Petroleum Ltd. and subsidiaries as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of TransAtlantic Petroleum Ltd. also excluded an evaluation of the internal control over financial reporting of Stream Oil & Gas Ltd.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransAtlantic Petroleum Ltd. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated March 16, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 16, 2015
F-3
TRANSATLANTIC PETROLEUM LTD.
As of December 31, 2014 and 2013
(in thousands of U.S. Dollars, except share data)
|
2014 |
|
|
2013 |
|
||
ASSETS |
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
Cash and cash equivalents |
$ |
35,132 |
|
|
$ |
12,881 |
|
Accounts receivable, net |
|
|
|
|
|
|
|
Oil and natural gas sales |
|
29,673 |
|
|
|
30,619 |
|
Joint interest and other |
|
19,918 |
|
|
|
15,348 |
|
Related party |
|
602 |
|
|
|
1,004 |
|
Prepaid and other current assets |
|
8,930 |
|
|
|
5,072 |
|
Deferred income taxes |
|
329 |
|
|
|
2,239 |
|
Derivative asset |
|
12,518 |
|
|
|
– |
|
Restricted cash |
|
1,917 |
|
|
|
– |
|
Assets held for sale |
|
28 |
|
|
|
536 |
|
Total current assets |
|
109,047 |
|
|
|
67,699 |
|
Property and equipment |
|
|
|
|
|
|
|
Oil and natural gas properties (successful efforts methods) |
|
|
|
|
|
|
|
Proved |
|
424,031 |
|
|
|
260,857 |
|
Unproved |
|
65,438 |
|
|
|
54,392 |
|
Equipment and other property |
|
42,343 |
|
|
|
39,916 |
|
|
|
531,812 |
|
|
|
355,165 |
|
Less accumulated depreciation, depletion and amortization |
|
(141,977 |
) |
|
|
(104,193 |
) |
Property and equipment, net |
|
389,835 |
|
|
|
250,972 |
|
Other long-term assets: |
|
|
|
|
|
|
|
Other assets |
|
8,836 |
|
|
|
7,977 |
|
Note receivable - related party |
|
11,500 |
|
|
|
11,500 |
|
Derivative asset |
|
19,069 |
|
|
|
– |
|
Deferred income taxes |
|
1,181 |
|
|
|
903 |
|
Goodwill |
|
6,935 |
|
|
|
7,535 |
|
Total other assets |
|
47,521 |
|
|
|
27,915 |
|
Total assets |
$ |
546,403 |
|
|
$ |
346,586 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
Accounts payable |
$ |
39,407 |
|
|
$ |
16,712 |
|
Accounts payable - related party |
|
18,488 |
|
|
|
23,090 |
|
Accrued liabilities |
|
31,238 |
|
|
|
20,658 |
|
Deferred income taxes |
|
2,138 |
|
|
|
– |
|
Derivative liabilities |
|
– |
|
|
|
3,737 |
|
Asset retirement obligations |
|
323 |
|
|
|
610 |
|
Loans payable |
|
45,806 |
|
|
|
43,284 |
|
Loan payable - related party |
|
6,800 |
|
|
|
– |
|
Liabilities held for sale |
|
6,928 |
|
|
|
7,559 |
|
Total current liabilities |
|
151,128 |
|
|
|
115,650 |
|
Long-term liabilities: |
|
|
|
|
|
|
|
Asset retirement obligations |
|
11,053 |
|
|
|
10,286 |
|
Accrued liabilities |
|
12,336 |
|
|
|
6,487 |
|
Deferred income taxes |
|
54,430 |
|
|
|
16,134 |
|
Loans payable |
|
85,192 |
|
|
|
26,482 |
|
Loan payable - related party |
|
20,800 |
|
|
|
– |
|
Derivative liabilities |
|
– |
|
|
|
4,230 |
|
Total long-term liabilities |
|
183,811 |
|
|
|
63,619 |
|
Total liabilities |
|
334,939 |
|
|
|
179,269 |
|
Commitments and contingencies |
|
|
|
|
|
|
|
Shareholders' equity: |
|
|
|
|
|
|
|
Common shares, $0.10 par value, 100,000,000 shares authorized; 40,708,120 shares and 37,340,206 shares issued and outstanding as of December 31, 2014 and December 31, 2013, respectively |
|
4,071 |
|
|
|
3,734 |
|
Additional paid-in-capital |
|
571,150 |
|
|
|
542,091 |
|
Accumulated other comprehensive loss |
|
(79,310 |
) |
|
|
(64,985 |
) |
Accumulated deficit |
|
(284,447 |
) |
|
|
(313,523 |
) |
Total shareholders' equity |
|
211,464 |
|
|
|
167,317 |
|
Total liabilities and shareholders' equity |
$ |
546,403 |
|
|
$ |
346,586 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
TRANSATLANTIC PETROLEUM LTD.
Consolidated Statements of Comprehensive Income (Loss)
For the years ended December 31, 2014, 2013 and 2012
(U.S. Dollars and shares in thousands, except per share amounts)
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
$ |
138,174 |
|
|
$ |
127,270 |
|
|
$ |
134,113 |
|
Sales of purchased natural gas |
|
2,127 |
|
|
|
2,581 |
|
|
|
7,882 |
|
Other |
|
427 |
|
|
|
976 |
|
|
|
1,913 |
|
Total revenues |
|
140,728 |
|
|
|
130,827 |
|
|
|
143,908 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
19,999 |
|
|
|
18,602 |
|
|
|
17,804 |
|
Transportation costs |
|
284 |
|
|
|
– |
|
|
|
– |
|
Exploration, abandonment and impairment |
|
19,864 |
|
|
|
27,333 |
|
|
|
39,993 |
|
Cost of purchased natural gas |
|
2,055 |
|
|
|
2,247 |
|
|
|
7,694 |
|
Seismic and other exploration |
|
4,285 |
|
|
|
14,009 |
|
|
|
5,040 |
|
Revaluation of contingent consideration |
|
(2,500 |
) |
|
|
(5,000 |
) |
|
|
– |
|
General and administrative |
|
31,625 |
|
|
|
29,020 |
|
|
|
33,947 |
|
Depreciation, depletion and amortization |
|
48,927 |
|
|
|
41,322 |
|
|
|
28,215 |
|
Accretion of asset retirement obligations |
|
413 |
|
|
|
508 |
|
|
|
710 |
|
Total costs and expenses |
|
124,952 |
|
|
|
128,041 |
|
|
|
133,403 |
|
Operating income |
|
15,776 |
|
|
|
2,786 |
|
|
|
10,505 |
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
Interest and other expense |
|
(6,213 |
) |
|
|
(3,929 |
) |
|
|
(8,340 |
) |
Interest and other income |
|
1,124 |
|
|
|
1,340 |
|
|
|
2,418 |
|
Gain (loss) on commodity derivative contracts |
|
37,454 |
|
|
|
(2,698 |
) |
|
|
(5,548 |
) |
Foreign exchange (loss) gain |
|
(5,998 |
) |
|
|
(9,663 |
) |
|
|
1,083 |
|
Total other income (expense) |
|
26,367 |
|
|
|
(14,950 |
) |
|
|
(10,387 |
) |
Income (loss) from continuing operations before income taxes |
|
42,143 |
|
|
|
(12,164 |
) |
|
|
118 |
|
Current income tax expense |
|
(1,784 |
) |
|
|
(128 |
) |
|
|
(4,674 |
) |
Deferred income tax expense |
|
(11,263 |
) |
|
|
(979 |
) |
|
|
(1,817 |
) |
Net income (loss) from continuing operations |
|
29,096 |
|
|
|
(13,271 |
) |
|
|
(6,373 |
) |
Loss from discontinued operations before income taxes |
|
(20 |
) |
|
|
(442 |
) |
|
|
(5,083 |
) |
Gain on disposal of discontinued operations |
|
– |
|
|
|
– |
|
|
|
35,999 |
|
Income tax provision |
|
– |
|
|
|
– |
|
|
|
(8,297 |
) |
Net (loss) income from discontinued operations |
|
(20 |
) |
|
|
(442 |
) |
|
|
22,619 |
|
Net income (loss) |
|
29,076 |
|
|
|
(13,713 |
) |
|
|
16,246 |
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
(14,325 |
) |
|
|
(36,973 |
) |
|
|
22,224 |
|
Comprehensive income (loss) |
$ |
14,751 |
|
|
$ |
(50,686 |
) |
|
$ |
38,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
Basic net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
$ |
0.77 |
|
|
$ |
(0.36 |
) |
|
$ |
(0.17 |
) |
Discontinued operations |
$ |
– |
|
|
$ |
(0.01 |
) |
|
$ |
0.62 |
|
Weighted average common shares outstanding |
|
37,829 |
|
|
|
37,069 |
|
|
|
36,742 |
|
Diluted net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
$ |
0.77 |
|
|
$ |
(0.36 |
) |
|
$ |
(0.17 |
) |
Discontinued operations |
$ |
– |
|
|
$ |
(0.01 |
) |
|
$ |
0.62 |
|
Weighted average common and common equivalent shares outstanding |
|
38,031 |
|
|
|
37,069 |
|
|
|
36,742 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
TRANSATLANTIC PETROLEUM LTD.
Consolidated Statements of Equity
For the years ended December 31, 2014, 2013 and 2012
(U.S. Dollars and shares in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
Other |
|
|
|
|
|
|
Total |
|
|||
|
Common |
|
|
|
|
|
|
Common |
|
|
Paid-in |
|
|
Comprehensive |
|
|
Accumulated |
|
|
Shareholders' |
|
||||||
|
Shares |
|
|
Warrants |
|
|
Shares (at par) |
|
|
Capital |
|
|
Income (Loss) |
|
|
Deficit |
|
|
Equity |
|
|||||||
Balances at December 31, 2011 |
|
36,579 |
|
|
|
– |
|
|
$ |
3,658 |
|
|
$ |
533,907 |
|
|
$ |
(50,236 |
) |
|
$ |
(316,056 |
) |
|
$ |
171,273 |
|
Exercise of share options |
|
81 |
|
|
|
– |
|
|
|
8 |
|
|
|
656 |
|
|
|
– |
|
|
|
– |
|
|
|
664 |
|
Issuance of restricted stock units |
|
215 |
|
|
|
– |
|
|
|
21 |
|
|
|
(21 |
) |
|
|
– |
|
|
|
– |
|
|
|
– |
|
Tax withholding on restricted stock units |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(147 |
) |
|
|
– |
|
|
|
– |
|
|
|
(147 |
) |
Share-based compensation |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
3,567 |
|
|
|
– |
|
|
|
– |
|
|
|
3,567 |
|
Foreign currency translation adjustment |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
22,224 |
|
|
|
– |
|
|
|
22,224 |
|
Net income |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
16,246 |
|
|
|
16,246 |
|
Balances at December 31, 2012 |
|
36,875 |
|
|
|
– |
|
|
|
3,687 |
|
|
|
537,962 |
|
|
|
(28,012 |
) |
|
|
(299,810 |
) |
|
|
213,827 |
|
Issuance of common shares |
|
351 |
|
|
|
– |
|
|
|
35 |
|
|
|
2,465 |
|
|
|
– |
|
|
|
– |
|
|
|
2,500 |
|
Issuance of restricted stock units |
|
114 |
|
|
|
– |
|
|
|
12 |
|
|
|
(12 |
) |
|
|
– |
|
|
|
– |
|
|
|
– |
|
Tax withholding on restricted stock units |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(40 |
) |
|
|
– |
|
|
|
– |
|
|
|
(40 |
) |
Share-based compensation |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
1,716 |
|
|
|
– |
|
|
|
– |
|
|
|
1,716 |
|
Foreign currency translation adjustment |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(36,973 |
) |
|
|
– |
|
|
|
(36,973 |
) |
Net loss |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(13,713 |
) |
|
|
(13,713 |
) |
Balances at December 31, 2013 |
|
37,340 |
|
|
|
– |
|
|
|
3,734 |
|
|
|
542,091 |
|
|
|
(64,985 |
) |
|
|
(313,523 |
) |
|
|
167,317 |
|
Issuance of common shares |
|
3,219 |
|
|
|
– |
|
|
|
322 |
|
|
|
23,528 |
|
|
|
– |
|
|
|
– |
|
|
|
23,850 |
|
Contingent payment event |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
4,188 |
|
|
|
– |
|
|
|
– |
|
|
|
4,188 |
|
Issuance of warrants |
|
– |
|
|
|
233 |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Issuance of restricted stock units |
|
149 |
|
|
|
– |
|
|
|
15 |
|
|
|
(15 |
) |
|
|
– |
|
|
|
– |
|
|
|
– |
|
Tax withholding on restricted stock units |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(76 |
) |
|
|
– |
|
|
|
– |
|
|
|
(76 |
) |
Share-based compensation |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
1,434 |
|
|
|
– |
|
|
|
– |
|
|
|
1,434 |
|
Foreign currency translation adjustment |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(14,325 |
) |
|
|
– |
|
|
|
(14,325 |
) |
Net income |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
29,076 |
|
|
|
29,076 |
|
Balances at December 31, 2014 |
|
40,708 |
|
|
|
233 |
|
|
$ |
4,071 |
|
|
$ |
571,150 |
|
|
$ |
(79,310 |
) |
|
$ |
(284,447 |
) |
|
$ |
211,464 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
TRANSATLANTIC PETROLEUM LTD.
Consolidated Statements of Cash Flows
For the years ended December 31, 2014, 2013 and 2012
(in thousands of U.S. Dollars)
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
29,076 |
|
|
$ |
(13,713 |
) |
|
$ |
16,246 |
|
Adjustment for net loss (income) from discontinued operations |
|
20 |
|
|
|
442 |
|
|
|
(22,619 |
) |
Net income (loss) from continuing operations |
|
29,096 |
|
|
|
(13,271 |
) |
|
|
(6,373 |
) |
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation |
|
1,434 |
|
|
|
1,716 |
|
|
|
2,559 |
|
Foreign currency loss |
|
6,785 |
|
|
|
8,620 |
|
|
|
3,843 |
|
(Gain) loss on commodity derivative contracts |
|
(37,454 |
) |
|
|
2,698 |
|
|
|
5,548 |
|
Cash settlement on commodity derivative contracts |
|
(2,100 |
) |
|
|
(3,521 |
) |
|
|
(3,829 |
) |
Amortization on loan financing costs |
|
1,025 |
|
|
|
510 |
|
|
|
1,991 |
|
Bad debt expense |
|
1,487 |
|
|
|
– |
|
|
|
– |
|
Deferred income tax expense |
|
11,263 |
|
|
|
979 |
|
|
|
1,817 |
|
Inventory write down |
|
– |
|
|
|
– |
|
|
|
1,390 |
|
Exploration, abandonment and impairment |
|
19,864 |
|
|
|
27,333 |
|
|
|
39,993 |
|
Depreciation, depletion and amortization |
|
48,927 |
|
|
|
41,322 |
|
|
|
28,215 |
|
Accretion of asset retirement obligations |
|
413 |
|
|
|
508 |
|
|
|
710 |
|
Revaluation of contingency consideration |
|
(2,500 |
) |
|
|
(5,000 |
) |
|
|
– |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
(3,690 |
) |
|
|
(2,353 |
) |
|
|
(6,872 |
) |
Prepaid expenses and other assets |
|
(1,718 |
) |
|
|
(34 |
) |
|
|
(1,149 |
) |
Accounts payable and accrued liabilities |
|
5,282 |
|
|
|
9,269 |
|
|
|
1,503 |
|
Net cash provided by operating activities of continuing operations |
|
78,114 |
|
|
|
68,776 |
|
|
|
69,346 |
|
Net cash used in operating activities of discontinued operations |
|
(62 |
) |
|
|
(1,426 |
) |
|
|
(25,769 |
) |
Net cash provided by operating activities |
|
78,052 |
|
|
|
67,350 |
|
|
|
43,577 |
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
Acquisitions, net of cash |
|
66 |
|
|
|
– |
|
|
|
– |
|
Additions to oil and natural gas properties |
|
(109,027 |
) |
|
|
(94,266 |
) |
|
|
(70,189 |
) |
Additions to equipment and other properties |
|
(6,318 |
) |
|
|
(10,653 |
) |
|
|
(668 |
) |
Restricted cash |
|
(1,917 |
) |
|
|
(190 |
) |
|
|
949 |
|
Net cash used in investing activities of continuing operations |
|
(117,196 |
) |
|
|
(105,109 |
) |
|
|
(69,908 |
) |
Net cash provided by investing activities of discontinued operations |
|
500 |
|
|
|
1,016 |
|
|
|
156,149 |
|
Net cash (used in) provided by investing activities |
|
(116,696 |
) |
|
|
(104,093 |
) |
|
|
86,241 |
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options |
|
– |
|
|
|
– |
|
|
|
664 |
|
Tax withholding on restricted share units |
|
(76 |
) |
|
|
(40 |
) |
|
|
(147 |
) |
Loan proceeds |
|
73,237 |
|
|
|
66,785 |
|
|
|
25,967 |
|
Loan proceeds - related party |
|
20,800 |
|
|
|
– |
|
|
|
11,000 |
|
Loan repayment |
|
(29,770 |
) |
|
|
(29,785 |
) |
|
|
(78,931 |
) |
Loan repayment - related party |
- |
|
|
|
– |
|
|
|
(84,000 |
) |
|
Loan financing costs |
|
(2,630 |
) |
|
|
– |
|
|
|
(250 |
) |
Net cash provided by (used in) financing activities from continuing operations |
|
61,561 |
|
|
|
36,960 |
|
|
|
(125,697 |
) |
Net cash used in financing activities from discontinued operations |
|
– |
|
|
|
– |
|
|
|
(5,049 |
) |
Net cash provided by (used in) financing activities |
|
61,561 |
|
|
|
36,960 |
|
|
|
(130,746 |
) |
Effect of exchange rate on cash flows and cash equivalents |
|
(666 |
) |
|
|
(2,104 |
) |
|
|
580 |
|
Net increase (decrease) in cash and cash equivalents |
|
22,251 |
|
|
|
(1,887 |
) |
|
|
(348 |
) |
Cash and cash equivalents, beginning of year |
|
12,881 |
|
|
|
14,768 |
|
|
|
15,116 |
|
Cash and cash equivalents, end of year |
$ |
35,132 |
|
|
$ |
12,881 |
|
|
$ |
14,768 |
|
Supplemental disclosures: |
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest |
$ |
3,490 |
|
|
$ |
3,091 |
|
|
$ |
6,946 |
|
Cash paid for taxes |
$ |
– |
|
|
$ |
2,387 |
|
|
$ |
5,596 |
|
Supplemental non-cash financing activities: |
|
|
|
|
|
|
|
|
|
|
|
Issuance of common shares for acquisition |
$ |
23,850 |
|
|
$ |
– |
|
|
$ |
– |
|
Contingent payment event |
$ |
4,188 |
|
|
$ |
– |
|
|
$ |
– |
|
Note receivable - related party from sale of oilfield services business |
$ |
– |
|
|
$ |
– |
|
|
$ |
11,500 |
|
Issuance of common shares - amendment to purchase agreement |
$ |
– |
|
|
$ |
2,500 |
|
|
$ |
– |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-7
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements
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, 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. As of December 31, 2014, we held interests in developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of March 1, 2015, approximately 36% 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.
Oil Price Decline
As a result of the recent decline in prices for Brent crude, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses. These initiatives include the negotiation of exploration and development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.
We believe that our cash flows from operations and existing cash on hand are sufficient to conduct our planned operations through 2015 and meet our contractual requirements, including license obligations. Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.
Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices.
2. Significant accounting policies
Basis of preparation
Our reporting standard for the presentation of our consolidated financial statements is U.S. GAAP. The consolidated financial statements include the accounts of the Company and all majority owned, controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. During the year ended December 31, 2014, we reclassified certain balance sheet amounts previously reported on our consolidated balance sheet at December 31, 2013 to conform to current year presentation.
F-8
Reverse stock split
On March 4, 2014, the Company’s 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 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 transactions described herein have been adjusted to reflect the 1-for-10 reverse stock split.
Cash and cash equivalents
Cash and cash equivalents include term deposits and investments with original maturities of three months or less at the date of acquisition. We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. We determine the appropriate classification of our investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluate such designation at each balance sheet date.
Commodity derivative instruments
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”), requires derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the change in a derivative contract’s fair value currently in earnings as a component of other income (expense).
Fair value measurements
We follow ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements, but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards.
ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value measurement hierarchy are as follows:
Level 1: |
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. |
Level 2: |
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. |
Level 3: |
Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity). |
As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values takes into account the market for our financial assets and liabilities, the associated credit risk and other factors as required by ASC 820. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Foreign currency remeasurement and translation
The functional currency of our subsidiaries in Turkey, Bulgaria, Romania, Morocco, and Albania is the New Turkish Lira (“TRY”), the Bulgarian Lev, the Romanian New Leu, the Moroccan Dirham, and the U.S. Dollar (“USD”) respectively. We follow ASC 830, Foreign Currency Matters (“ASC 830”). ASC 830 requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Exchange gains or losses from remeasuring transactions and monetary accounts in a currency other than the functional currency are included in earnings.
For certain subsidiaries, translation adjustments result from the process of translating the functional currency of subsidiary financial statements into the U.S. Dollar reporting currency. These translation adjustments are reported separately and accumulated in the consolidated balance sheets as a component of accumulated other comprehensive loss.
F-9
Oil and natural gas properties
In accordance with the successful efforts method of accounting for oil and natural gas properties, costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. Acquisition costs of proved properties are amortized using the unit-of-production method based on total proved reserves, and exploration well costs and additional development costs are amortized using the unit-of-production method based on proved developed reserves. Proceeds from the sale of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be non-productive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Equipment and other property
Equipment and other property are stated at cost, and inventory is stated at weighted average cost which does not exceed replacement cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 7 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of equipment sold, or otherwise disposed of, and the related accumulated depreciation, are removed from the accounts and any gain or loss is reflected in current earnings.
Impairment of long-lived assets
We follow the provisions of ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by field for potential impairment. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of a field are less than its carrying value. If an impairment occurs, the carrying value of the impaired field is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert, (ii) the Company’s history in exploring the area, (iii) the Company’s future drilling plans per its capital drilling program prepared by the Company’s reservoir engineers and operations management and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Goodwill
In accordance with ASC 350, Intangibles-Goodwill and Other (“ASC 350”), goodwill is not amortized, but is tested for impairment on an annual basis at December 31, or more frequently as impairment indicators arise. ASC 350 permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. We assessed the qualitative factors at December 31, 2014 and, based upon the results of the qualitative assessment, we determined that it was not necessary to perform the two-step goodwill impairment test and that our goodwill was not impaired. All of our goodwill is attributable to our Turkey operating segment.
Joint interest activities
Certain of our exploration, development and production activities are conducted jointly with other entities and, accordingly, the consolidated financial statements reflect only our proportionate interest in such activities.
F-10
Asset retirement obligations
We recognize a liability for the fair value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the abandonment obligation is included in the computation of depreciation, depletion and amortization. The liability accretes until we settle the obligation. We use a credit-adjusted risk-free interest rate in our calculation of asset retirement obligations.
Revenue recognition
Revenue from the sale of crude oil and natural gas is recognized upon delivery to the purchaser when title passes. During the years ended December 31, 2014, 2013 and 2012, we sold $102.8 million, $87.2 million and $91.8 million, respectively, of oil to Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately owned oil refinery in Turkey, which represented approximately 73.0%, 66.7% and 63.8% of our total revenues, respectively.
Share-based compensation
We follow ASC 718, Compensation—Stock Compensation (“ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, based on estimated grant date fair values. Restricted stock units are valued using the market price of our common shares on the date of grant. We record compensation expense, net of estimated forfeitures, over the requisite service period.
Income taxes
We follow the asset and liability method prescribed by ASC 740, Income Taxes (“ASC 740”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under ASC 740, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in earnings in the period that includes the enactment date.
In connection with our acquisition Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) in August 2010, at December 31, 2012, we recognized a liability due to an uncertain tax position related to the transfer of Petrogas shares to Amity prior to the acquisition (see Note 11). We do not believe there will be any material changes in our unrecognized tax positions over the next twelve months. Our policy is that we recognize interest and penalties accrued on any unrecognized tax positions as a component of income tax expense.
We are a Bermuda exempted company, and under current Bermuda law, we are not subject to tax on profits, income or dividends, nor is there any capital gains tax applicable to us in Bermuda.
Comprehensive income
ASC 220, Comprehensive Income, establishes standards for reporting and displaying comprehensive income and its components (revenue, expenses, gains and losses) in a full set of general-purpose financial statements.
Business combinations
We follow ASC 805, Business Combinations (“ASC 805”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”). ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations are accounted for by applying the acquisition method. See Note 4.
Per share information
Basic per share amounts are calculated using the weighted average common shares outstanding during the year, excluding unvested restricted stock units. We use the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted earnings per share. Diluted calculations reflect the weighted average incremental common shares that would be issued upon exercise of dilutive options assuming the proceeds would be used to repurchase shares at average market prices for the period.
F-11
3. New 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 entity’s 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.
In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), an amendment to FASB Accounting Standards Codification ("ASC") Topic 205, Presentation of Financial Statements. This update provides guidance on management's responsibility in evaluating whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of ASU 2014-15 to have a material impact on our consolidated financial statements or results of operations. If events occur in future periods that affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.
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.
F-12
4. Acquisitions
Stream
On November 18, 2014, we acquired Stream Oil & Gas Ltd. (“Stream”) in exchange for (i) 3.2 million of our common shares of the Company issued at closing, and (ii) an additional 0.6 million of our common shares issuable if certain conditions are met (at a deemed price of $7.41 per common share). We engaged independent valuation experts to assist in the determination of the fair value of the assets and liabilities acquired in the acquisition. We are still assessing the assets acquired and liabilities assumed, thus the final determination of the value of assets acquired and liabilities assumed may result in adjustments to the values presented below. The following tables summarize the consideration paid in the acquisition and the preliminary amounts of assets acquired and liabilities assumed that have been recognized at the acquisition date:
|
(in thousands) |
|
|
Consideration: |
|
|
|
Issuance of 3,218,641 common shares |
$ |
23,850 |
|
Contingent payment event |
|
4,188 |
|
Fair value of total consideration |
$ |
28,038 |
|
Acquisition-Related Costs: |
|
|
|
Included in general and administrative expenses on our consolidated statements of comprehensive income (loss) for the year ended December 31, 2014 |
$ |
1,129 |
|
|
|
|
|
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition: |
|
|
|
Assets: |
|
|
|
Cash |
$ |
66 |
|
Accounts receivable |
|
6,672 |
|
Other current assets |
|
347 |
|
Total current assets |
|
7,085 |
|
Oil and natural gas properties: |
|
|
|
Proved properties |
|
99,927 |
|
Unproved properties |
|
16,140 |
|
Equipment and other property |
|
964 |
|
Total oil and natural gas properties and other equipment |
|
117,031 |
|
Total assets |
|
124,116 |
|
Liabilities: |
|
|
|
Accounts payable |
|
20,673 |
|
Accounts payable - related party |
|
2,820 |
|
Other current liabilities |
|
10,000 |
|
Viking International note - related party |
|
6,800 |
|
Loans payable - current |
|
11,732 |
|
Other non-current liabilities |
|
5,036 |
|
Loans payable - non-current |
|
6,123 |
|
Asset retirement obligations |
|
827 |
|
Deferred income taxes |
|
32,067 |
|
Total liabilities |
|
96,078 |
|
Total identifiable net assets |
$ |
28,038 |
|
The results of operations of Stream are included in our consolidated statement of comprehensive income (loss) beginning November 18, 2014. The revenues and expenses of Stream included in our consolidated statement of comprehensive income (loss) for the year ended December 31, 2014 were:
|
Revenue |
|
|
Loss |
|
||
|
(in thousands) |
|
|||||
Actual from November 18, 2014 through December 31, 2014 |
$ |
1,898 |
|
|
$ |
(118 |
) |
F-13
Pro forma results of operations
The following table presents the unaudited pro forma results of operations for the year ended December 31, 2014 and 2013 as though the acquisition of Stream had occurred at January 1, 2013 (in thousands, except per share amounts):
|
2014 |
|
|
2013 |
|
||
Total revenues |
$ |
160,021 |
|
|
$ |
153,794 |
|
Income (loss) from continuing operations before income taxes |
|
45,166 |
|
|
|
(15,118 |
) |
Income (loss) from continuing operations |
|
32,467 |
|
|
|
(19,435 |
) |
Loss from discontinued operations |
|
(20 |
) |
|
|
(442 |
) |
Net income (loss) |
|
32,447 |
|
|
|
(19,877 |
) |
Net loss per common share from continuing operations |
|
|
|
|
|
|
|
Basic and diluted |
$ |
0.80 |
|
|
$ |
(0.48 |
) |
Net loss per common share from discontinued operations |
|
|
|
|
|
|
|
Basic and diluted |
$ |
- |
|
|
$ |
(0.01 |
) |
5. Goodwill
Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. We have goodwill on acquisitions where we anticipated access to potential exploration and producing opportunities. All of our goodwill is attributable to our Turkey operating segment. Goodwill was as follows at December 31, 2014 and 2013:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Goodwill at January 1, |
$ |
7,535 |
|
|
$ |
9,021 |
|
Foreign exchange effect |
|
(600 |
) |
|
|
(1,486 |
) |
Goodwill at December 31 |
$ |
6,935 |
|
|
$ |
7,535 |
|
6. Property and equipment
Oil and natural gas properties
The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Oil and natural gas properties, proved: |
|
|
|
|
|
|
|
Turkey |
$ |
323,442 |
|
|
$ |
260,232 |
|
Albania |
|
100,037 |
|
|
|
– |
|
Bulgaria |
|
552 |
|
|
|
625 |
|
Total oil and natural gas properties, proved |
|
424,031 |
|
|
|
260,857 |
|
Oil and natural gas properties, unproved: |
|
|
|
|
|
|
|
Turkey |
|
43,090 |
|
|
|
51,273 |
|
Albania |
|
18,301 |
|
|
|
– |
|
Bulgaria |
|
4,047 |
|
|
|
3,119 |
|
Total oil and natural gas properties, unproved |
|
65,438 |
|
|
|
54,392 |
|
Gross oil and natural gas properties |
|
489,469 |
|
|
|
315,249 |
|
Accumulated depletion |
|
(133,304 |
) |
|
|
(96,958 |
) |
Net oil and natural gas properties |
$ |
356,165 |
|
|
$ |
218,291 |
|
At December 31, 2014 and 2013, we excluded $0.9million and $1.5 million of costs, respectively, from the depletion calculation for development wells in progress and for costs on fields currently not in production.
At December 31, 2014, the capitalized costs of our oil and natural gas properties included $129.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $160.8 million relating to well costs, and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.
F-14
At December 31, 2013, the capitalized costs of our oil and natural gas properties included $35.5 million relating to acquisition costs of proved properties, which are being amortized 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 amortized by the unit-of-production method using proved developed reserves.
Dry hole costs
During the years ended December 31, 2014, 2013 and 2012, we recorded $0.5 million, $16.0 million, and $24.7 million of exploratory dry hole costs, respectively. Of the $0.5 million of dry hole costs incurred during the year ended December 31, 2014, approximately $0.3 million was related to cash spent during 2014.
Impairment and abandonment
Unproved oil and natural gas properties that are individually significant are periodically assessed for impairment, and a loss is recognized at the time of impairment. Capitalized costs related to proved oil and natural gas properties, including wells and related equipment and facilities, are evaluated for impairment based on our analysis of undiscounted future net cash flows. If undiscounted future net cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income equal to the difference between the carrying value and the estimated fair value of the properties. We categorize the measurement of fair value of these assets as Level 3 inputs. Estimated fair values are determined using discounted cash flow models. The discounted cash flow models include management’s estimates of future oil and natural gas production, operating and development costs, and discount rates.
During the year ended December 31, 2014, we recorded $19.4 million in impairment and abandonment charges on our proved and unproved properties. Of the $19.4 million, approximately $13.8 million relates to unproved exploratory well impairment on the following wells: $3.5 million related to impairment on the Catak-1 well, $2.8 million related to the Kazanci-5 well, and $7.5 million related to the Bahar-2 side track well.
During the year ended December 31, 2013, we recorded $11.3 million in impairment and abandonment charges on our proved and unproved properties, primarily related to our Senova and Malkara licenses.
During the year ended December 31, 2012, we recorded $6.7 million in impairment charges on our proved properties, of which $2.7 million was due to downward revisions in natural gas reserves in our Alpullu field. We recorded a $8.4 million impairment on our unproved oil and natural gas properties during the year ended December 31, 2012. Of this amount, $5.2 million was attributable to exploration license acquisition costs for the Banarli license.
Capitalized cost greater than one year
As of December 31, 2014, we had $1.6 million of exploratory well costs capitalized for the Hayrabolu-10 well in Turkey, which we spud in February 2013. The Hayrabolu-10 well continues to be evaluated for completion pending more analysis and comparable well results. Additionally, we have $4.0 million of exploratory well costs for the Deventci-R2 well in Bulgaria, which we spud in October 2013, and we are currently still evaluating the results of an acid stimulation.
Equipment and other property
The historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as follows:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Other equipment |
$ |
3,035 |
|
|
$ |
2,678 |
|
Inventory |
|
24,309 |
|
|
|
24,318 |
|
Gas gathering system and facilities |
|
4,128 |
|
|
|
4,485 |
|
Vehicles |
|
536 |
|
|
|
321 |
|
Leasehold improvements, office equipment and software |
|
10,335 |
|
|
|
8,114 |
|
Gross equipment and other property |
|
42,343 |
|
|
|
39,916 |
|
Accumulated depreciation |
|
(8,673 |
) |
|
|
(7,235 |
) |
Net equipment and other property |
$ |
33,670 |
|
|
$ |
32,681 |
|
F-15
We classify our materials and supply inventory, including steel tubing and casing, as a long-term asset because such materials will ultimately be classified as a long-term asset when the material is used in the drilling of a well.
At December 31, 2014, we excluded $24.3 million of inventory and $3.0 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 had not been placed into service.
7. 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 “Gain (loss) 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 credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”), to hedge between 30% and 75% of our anticipated production volumes in Turkey.
During the years ended December 31, 2014, 2013 and 2012, we recorded a net gain on commodity derivative contracts of $37.5 million, a net loss of $2.7 million and $5.5 million, respectively.
At December 31, 2014, we had outstanding commodity derivative contracts with respect to our future crude oil production as set forth in the tables below:
Fair Value of Derivative Instruments as of December 31, 2014
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
||
|
|
|
|
Quantity |
|
|
Minimum |
|
|
Maximum Price |
|
|
Estimated Fair |
|
||||
Type |
|
Period |
|
(Bbl/day) |
|
|
Price (per Bbl) |
|
|
(per Bbl) |
|
|
Value of Asset |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Collar |
|
January 1, 2015—December 31, 2015 |
|
|
1,410 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
12,518 |
|
|
|
|
|
Collars |
|
|
Additional Call |
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
Average |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Minimum |
|
|
Maximum |
|
|
Maximum |
|
|
Estimated Fair |
|
||||
|
|
|
|
Quantity |
|
|
Price |
|
|
Price |
|
|
Price |
|
|
Value of |
|
|||||
Type |
|
Period |
|
(Bbl/day) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
Asset |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Three-way collar contract |
|
January 1, 2016—December 31, 2016 |
|
|
1,066 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
$ |
7,609 |
|
Three-way collar contract |
|
January 1, 2017—December 31, 2017 |
|
|
888 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
5,748 |
|
Three-way collar contract |
|
January 1, 2018—December 31, 2018 |
|
|
726 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
4,659 |
|
Three-way collar contract |
|
January 1, 2019—March 31, 2019 |
|
|
663 |
|
|
$ |
85.00 |
|
|
$ |
97.25 |
|
|
$ |
114.25 |
|
|
|
1,053 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,069 |
|
F-16
At December 31, 2013, we had outstanding commodity derivative contracts with respect to our future crude oil production as set forth in the tables below:
Fair Value of Derivative Instruments as of December 31, 2013
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
|
|
|
||
|
|
|
|
Quantity |
|
|
Minimum |
|
|
Maximum Price |
|
|
Estimated Fair |
|
||||
Type |
|
Period |
|
(Bbl/day) |
|
|
Price (per Bbl) |
|
|
(per Bbl) |
|
|
Value of Liability |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Collar |
|
January 1, 2014—December 31, 2014 |
|
|
622 |
|
|
$ |
80.83 |
|
|
$ |
118.07 |
|
|
$ |
(387 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(387 |
) |
|
|
|
|
Collars |
|
|
Additional Call |
|
|
|
|
|
||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Average |
|
|
Average |
|
|
Average |
|
|
|
|
|
|||
|
|
|
|
|
|
|
|
Minimum |
|
|
Maximum |
|
|
Maximum |
|
|
Estimated Fair |
|
||||
|
|
|
|
Quantity |
|
|
Price |
|
|
Price |
|
|
Price |
|
|
Value of |
|
|||||
Type |
|
Period |
|
(Bbl/day) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
(per Bbl) |
|
|
Liability |
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands) |
|
|
Three-way collar contract |
|
January 1, 2014—December 31, 2014 |
|
|
726 |
|
|
$ |
85.00 |
|
|
$ |
97.13 |
|
|
$ |
162.13 |
|
|
$ |
(3,350 |
) |
Three-way collar contract |
|
January 1, 2015—December 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 December 31, 2014 and December 31, 2013, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at December 31, 2014 and December 31, 2013.
|
|
|
|
As of December 31, 2014 |
|
|||||||||
|
|
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
Net Amount of |
|
||
|
|
|
|
Gross |
|
|
Offset in the |
|
|
Assets |
|
|||
|
|
|
|
Amount of |
|
|
Consolidated |
|
|
Presented in the |
|
|||
|
|
|
|
Recognized |
|
|
Balance |
|
|
Consolidated |
|
|||
Underlying Commodity |
|
Location on Balance Sheet |
|
Assets |
|
|
Sheet |
|
|
Balance Sheet |
|
|||
|
|
|
|
(in thousands) |
|
|||||||||
Crude oil |
|
Current Assets |
|
$ |
12,518 |
|
|
$ |
– |
|
|
$ |
12,518 |
|
Crude oil |
|
Long-term Assets |
|
|
19,069 |
|
|
|
– |
|
|
|
19,069 |
|
|
|
|
|
As of December 31, 2013 |
|
|||||||||
|
|
|
|
|
|
|
|
Gross |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
Net Amount of |
|
||
|
|
|
|
Gross |
|
|
Offset in the |
|
|
Liabilities |
|
|||
|
|
|
|
Amount of |
|
|
Consolidated |
|
|
Presented in the |
|
|||
|
|
|
|
Recognized |
|
|
Balance |
|
|
Consolidated |
|
|||
Underlying Commodity |
|
Location on Balance Sheet |
|
Liabilities |
|
|
Sheet |
|
|
Balance Sheet |
|
|||
|
|
|
|
(in thousands) |
|
|||||||||
Crude oil |
|
Current liabilities |
|
$ |
3,737 |
|
|
$ |
– |
|
|
$ |
3,737 |
|
Crude oil |
|
Long-term liabilities |
|
|
4,230 |
|
|
|
– |
|
|
|
4,230 |
|
F-17
8. Asset Retirement obligations
As part of our development of oil and natural gas properties, we incur asset retirement obligations (“ARO”). Our ARO results from our responsibility to abandon and reclaim our net share of all working interest properties and facilities. At December 31, 2014, the net present value of our total ARO was estimated to be $11.4 million, with the undiscounted value being $29.8 million. Total ARO at December 31, 2014 shown in the table below consists of amounts for future plugging and abandonment liabilities on our wellbores and facilities based on third-party estimates of such costs, adjusted for inflation at a rate of approximately 6.6% per annum for Turkey, 1.4% for Bulgaria, and 1.6% for Albania. These values are discounted to present value using our credit-adjusted risk-free rate for Turkey of 5.3%, Albania of 7.0% and Bulgaria of 5.3% per annum for the years ended December 31, 2014 and 2013. The following table summarizes the changes in our ARO for the years ended December 31, 2014 and 2013:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Asset retirement obligations at beginning of period |
$ |
10,896 |
|
|
$ |
11,958 |
|
Change in estimates |
|
– |
|
|
|
(7 |
) |
Liabilities settled |
|
(373 |
) |
|
|
(296 |
) |
Foreign exchange change effect |
|
(900 |
) |
|
|
(2,258 |
) |
Additions |
|
513 |
|
|
|
991 |
|
Accretion expense |
|
413 |
|
|
|
508 |
|
Acquisitions |
|
827 |
|
|
|
– |
|
Asset retirement obligations at end of period |
|
11,376 |
|
|
|
10,896 |
|
Less: current portion |
|
323 |
|
|
|
610 |
|
Long-term portion |
$ |
11,053 |
|
|
$ |
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.
9. Loans payable
As of the dates indicated, our third-party debt consisted of the following:
|
2014 |
|
|
2013 |
|
||
Fixed and floating rate loans |
(in thousands) |
|
|||||
Senior Credit Facility |
$ |
68,298 |
|
|
$ |
– |
|
Amended and Restated Credit Facility |
|
– |
|
|
|
49,766 |
|
Convertible notes |
|
26,600 |
|
|
|
– |
|
Convertible notes - related party |
|
20,800 |
|
|
|
– |
|
TBNG credit facility |
|
20,025 |
|
|
|
20,000 |
|
Term Loan Facility |
|
10,452 |
|
|
|
– |
|
Viking International note - related party |
|
6,800 |
|
|
|
– |
|
Prepayment Agreement |
|
3,043 |
|
|
|
– |
|
Shareholder loan |
|
2,580 |
|
|
|
– |
|
Loans payable |
|
158,598 |
|
|
|
69,766 |
|
Less: current portion |
|
52,606 |
|
|
|
43,284 |
|
Long-term portion |
$ |
105,992 |
|
|
$ |
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 (collectively, and together with Amity, the “Borrowers”) entered into an amended and restated credit facility (the “Amended and Restated Credit Facility”) with Standard Bank Plc 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.
F-18
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 lender’s 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 borrowing base was $71.5 million as of December 31, 2014. 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 lender’s individual commitment.
Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.26% at December 31, 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) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized under the “full cost” accounting method), (vii) expenses incurred in connection with oil and
F-19
gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), and (viii) 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 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.
Pursuant to the Senior Credit Facility, at least one of the Borrowers is required to maintain commodity derivative contracts with BNP Paribas that hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey. TEMI has entered into three-way collar contracts with BNP Paribas, which hedge the price of oil through March 2019. As of December 31, 2014, we had outstanding borrowings of $68.3 million and $3.2 million of remaining availability under the Senior Credit Facility.
At December 31, 2014, we were not in compliance with Section 8.16(a) of our Senior Credit Facility, which requires the Borrowers to maintain a current ratio of not less than 1.10:1.0. The lenders have granted the Borrowers a waiver on the current ratio requirement through March 31, 2015.
Convertible notes
As of December 31, 2014, we sold $47.4 million of convertible notes in a non-brokered private placement (the “Notes”). The Notes bore interest at a rate of 13.0% per annum and would have matured on July 1, 2017. The Notes were convertible, at the election of a holder, any time after July 1, 2015, into our common shares (the “Common Shares”) at a conversion price of $6.80 per share. Subsequent to December 31, 2014, we sold an additional $7.6 million of Notes. On February 20, 2015, we exchanged the Notes for substantially identical notes issued pursuant to an indenture (the “Exchange Notes”). See Note 16 – Subsequent Events.
F-20
TBNG credit facility
Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) has a fully drawn credit facility with a Turkish bank. The facility bears interest at a rate of 6.6% per annum and is due in monthly principal installments of $2.3 million each, ending September 30, 2015. The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell and his children. At December 31, 2014, TBNG had a balance of $20.0 million under the credit facility and no availability.
Term Loan Facility
On September 17, 2014, Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”) and Raiffeisen Bank Sh.A (“Raiffeisen”) entered into the term loan facility (the “Term Loan Facility”), which amended and restated a facility agreement, dated December 15, 2011, as amended (the “Facility Agreement”). The loan matures on December 31, 2016 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to pay 1/16th of the total commitment each quarter on the last business day of each of March, June, September and December each year. The loan is guaranteed by Stream Sub’s parent company, Stream. Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs. The Term Loan Facility is secured by substantially all of the assets of Stream Sub.
Under the Term Loan Facility, Stream Sub may not declare or pay any dividends on any of Stream Sub’s common shares without the consent of the lender, except, provided that no default has occurred and is continuing under the Term Loan Facility, Stream Sub may make payments to Stream from excess cash flow to cover the administrative overhead of Stream, including the salary and related employment costs of any employee, officer or director of Stream, up to a total limit in any three-month period of $500,000.
Pursuant to the terms of the Term Loan Facility, until amounts under the Term Loan Facility are repaid, Stream Sub may not, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of Stream Sub to create any liens, (iii) enter into any amalgamation, demerger, merger, or corporate reconstruction or any joint venture or partnership agreement, (iv) incorporate any company as a subsidiary, (v) dispose of any asset, (vi) declare or pay any dividends to shareholders, (vii) enter into a sale and leaseback arrangement, (viii) make any substantial change to the general nature or scope of its business from that carried on at the date of the Term Loan Facility, (ix) use, deposit, handle, store produce, release or dispose of dangerous materials, (x) make any loans or grant any credit, and (xi) cancel, terminate amend or waive any default under any export contract or allow any buyer to do the same.
In addition, the Term Loan Facility contains financial covenants that require Stream Sub to maintain as of the end of each fiscal year: (i) earnings before interest, taxes, depreciation and amortization (“EBITDA”) of not less than $10.0 million; (ii) an outstanding loan principal of no more than twice its EBITDA; and (iii) EBITDA of at least ten times greater than its accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments.
An event of default under the Term Loan 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, upon the occurrence of a change of control of Stream Sub, Stream Sub is required to notify Raiffeisen, and Raiffeisen would have the option to cancel loan commitments and accelerate all outstanding loans and other amounts payable. A change of control is defined under the Term Loan Facility as Stream ceasing to hold more than 75% of the shares in the issued share capital of Stream Sub carrying the right to vote. Our acquisition of Stream did not constitute a change of control under the Term Loan Facility.
Stream must, upon the request of Raiffeisen when Stream Sub’s predicted expenditures exceed its predicted revenues for any period, inject cash into Stream by means of equity loan or other method acceptable to Raiffeisen to the extent necessary to remedy the cashflow shortfall or repay the total amount outstanding under the Term Loan Facility.
On September 17, 2014, Stream Sub, Stream and Raiffeisen entered into an amendment and restatement agreement pursuant to which Raiffeisen granted a deferral of the June 2014 principal payment due under the Facility Agreement until December 2016. In addition, Raiffeisen waived its rights under the Facility Agreement with respect to events of default resulting from (i) Stream Sub’s non-payment of the June 2014 principal payment; and (ii) Stream Sub’s breach of the financial covenants for the fiscal year ended November 30, 2013. Pursuant to the amendment and restatement agreement, (i) Stream Sub paid all fees, costs and expenses due and (ii) Stream Sub and Albpetrol Sh. A (“Albpetrol”) entered into an agreement to postpone certain capital expenditures that were required under Stream’s work program on its properties.
As of December 31, 2014, we had $10.5 million outstanding under the Term Loan Facility and no availability.
F-21
At December 31, 2014, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol and ourselves concerning postponement of capital expenditures. Raiffeisen has granted us a waiver on this requirement until May 5, 2015.
Prepayment Agreement
In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6% (6.17% at December 31, 2014). Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015.
Each of Stream and Stream Sub is required to comply with certain financial and non-financial covenants under the Prepayment Agreement, including financial covenants that Stream must maintain, unless Trafigura agrees otherwise:
(i) EBITDA of not less than $10.0 million;
(ii) outstanding indebtedness of not more than twice its EBITDA; and
(iii) EBITDA of at least ten times greater than its accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments.
In addition, Stream must ensure that its coverage ratio is not less than 150% at all times. The coverage ratio is the ratio of the estimated aggregate valuation of the volume of crude oil to be delivered under the oil sales contract between Stream and Trafigura to the outstanding amount of the prepayment plus any applicable funding costs and fees.
Pursuant to the terms of the Prepayment Agreement, until amounts under the Prepayment Agreement are repaid, Stream Sub may not, in each case subject to certain exceptions, (i) create any liens over the Prepayment Agreement, or if such lien would have a material adverse effect, over any other assets or undertakings, (ii) enter into any amalgamation, demerger, merger, or corporate reconstruction, (iii) pay, repay or prepay any principal, interest or other amount on or in respect of or redeem, purchase or cancel any indebtedness owed actually or contingently to any shareholder of Stream Sub or an affiliate of any shareholder of Stream Sub, or (iv) reduce, return, purchase, repay, cancel or redeem any of its share capital.
Trafigura has termination and acceleration rights under the Prepayment Agreement upon the occurrence of certain events, including, 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 triggers termination and acceleration rights. A change of control is defined under the Prepayment Agreement as any person or group of persons acting in concert gaining ownership or control of Stream Sub. Control is defined as the power to direct or cause the direction of the management or policies of another person. Trafigura waived the change of control provision under the Prepayment Agreement in connection with our acquisition of Stream.
At December 31, 2014, Stream had $3.0 million outstanding under the Prepayment Agreement and no availability.
Viking International note
On September 16, 2014, Stream issued to Viking International Limited (“Viking International”) a note in the principal amount of $6.8 million. The note was amended monthly to evidence additional advances. At December 31, 2014, we had $6.8 million outstanding under the Viking International note. At March 12, 2015, we had repaid the note.
Shareholder loan
In March 2014, Stream borrowed CAD $3.0 million from a shareholder of Stream. The loan bore interest at a fixed rate of 10.0% per annum, calculated and compounded monthly. At December 31, 2014, Stream had $2.6 million outstanding under the shareholder loan. On January 6, 2015, we repaid the shareholder loan in full with the net proceeds from our private placement of Notes.
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 December 31, 2014, we had no outstanding borrowings under these lines of credit.
F-22
Loan financing costs
We capitalize certain costs in connection with obtaining our borrowings, such as lender’s fees and related attorney’s fees. These costs are amortized on a straight line basis, which approximates the effective interest method over the term of the loan as a component of interest expense. Loan financing costs, which are included in other assets, totaled approximately $2.7 million and $1.2 million as of December 31, 2014 and 2013, respectively. Amortization of loan financing costs totaled approximately $1.0 million, $0.5 million and $2.0 million during 2014, 2013 and 2012, respectively.
10. Shareholders’ equity
November 2014 share issuance
In November 2014, we issued 3,218,641 common shares at a deemed price of $7.41 per common share for the acquisition of Stream (see Note 4).
July 2013 share issuance
In July 2013, we issued 351,074 common shares at a deemed price of $7.12 per common share to Direct Petroleum Inc. (“Direct”) (see Note 15).
Restricted stock units
Under our 2009 Long-Term Incentive Plan (the “Incentive Plan”), we award restricted stock units (“RSUs”) and other share-based compensation to certain of our directors, officers, employees and consultants. Each RSU is equal in value to one of our common shares on the grant date. Upon vesting, an award recipient is entitled to a number of common shares equal to the number of vested RSUs. The RSU awards can only be settled in common shares. As a result, RSUs are classified as equity. At the grant date, we make an estimate of the forfeitures expected to occur during the vesting period and record compensation cost, net of the estimated forfeitures, over the requisite service period. The current forfeiture rate is estimated to be 12.5%.
Under the Incentive Plan, RSUs vest over specified periods of time ranging from immediately to four years. RSUs are deemed full value awards and their value is equal to the market price of our common shares on the grant date. ASC 718 requires that the Incentive Plan be approved in order to establish a grant date. Under ASC 718, the approval date for the Incentive Plan was February 9, 2009, the date our board of directors approved the Incentive Plan.
Share-based compensation of approximately $1.4 million and $1.7 million with respect to awards of RSUs was recorded for the years ended December 31, 2014 and 2013, respectively. As of December 31, 2014, we had approximately $0.7 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.3 years. The following table sets forth RSU activity for the year ended December 31, 2014:
|
|
Number of RSUs (in thousands) |
|
|
Weighted Average Grant Date Fair Value Per RSU |
|
||
Unvested RSUs outstanding at December 31, 2013 |
|
|
296 |
|
|
$ |
8.91 |
|
Granted |
|
|
179 |
|
|
|
8.57 |
|
Forfeited |
|
|
(103 |
) |
|
|
8.17 |
|
Vested |
|
|
(149 |
) |
|
|
10.06 |
|
Unvested RSUs outstanding at December 31, 2014 |
|
|
223 |
|
|
$ |
8.21 |
|
Stock option plan
Our Amended and Restated Stock Option Plan (2006) (the “Option Plan”) terminated on June 16, 2009. All outstanding awards issued under the Option Plan remained in full force and effect. As of December 31, 2014 and 2013, there were no options outstanding under the Option Plan. All options previously outstanding under the Option Plan had a five-year term.
The fair value of stock options was determined using the Black-Scholes Model and was recognized over the service period of the stock option. All stock options are fully vested; therefore, no share-based compensation expense for stock option awards was recorded for the years ended December 31, 2014, 2013 and 2012. We did not grant any stock options during the years ended December 31, 2014, 2013 and 2012.
F-23
Details of stock option activity for the years ended December 31, 2014, 2013 and 2012 are presented below.
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||||||||||||||
|
Number of Options (in thousands) |
|
|
Weighted Average Exercise Price Per share |
|
|
Number of Options (in thousands) |
|
|
Weighted Average Exercise Price Per share |
|
|
Number of Options (in thousands) |
|
|
Weighted Average Exercise Price Per share |
|
||||||
Outstanding at beginning of year |
|
– |
|
|
$ |
– |
|
|
|
16 |
|
|
$ |
12.30 |
|
|
|
114 |
|
|
$ |
9.07 |
|
Granted |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
Expired |
|
– |
|
|
|
– |
|
|
|
(16 |
) |
|
|
12.30 |
|
|
|
(17 |
) |
|
|
10.00 |
|
Exercised |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
(81 |
) |
|
|
8.24 |
|
Outstanding at end of year |
|
– |
|
|
$ |
– |
|
|
|
– |
|
|
$ |
– |
|
|
|
16 |
|
|
$ |
12.30 |
|
Exercisable at end of year |
|
– |
|
|
$ |
– |
|
|
|
– |
|
|
$ |
– |
|
|
|
16 |
|
|
$ |
12.30 |
|
Earnings per share
We account for earnings per share in accordance with 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 years ended December 31, 2014, 2013 and 2012 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 years ended December 31, 2014, 2013 and 2012 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 stock options, RSUs and warrants, whether exercisable or not. The computation of diluted earnings per common share excluded 758,586 and 959,438 antidilutive common share equivalents from the years ended December 31, 2013 and 2012, respectively.
The following table presents the basic and diluted earnings per common share computations:
(in thousands, except per share amounts) |
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
Net income (loss) from continuing operations |
|
$ |
29,096 |
|
|
$ |
(13,271 |
) |
|
$ |
(6,373 |
) |
Net (loss) income from discontinued operations |
|
$ |
(20 |
) |
|
$ |
(442 |
) |
|
$ |
22,619 |
|
Basic net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
37,829 |
|
|
|
37,069 |
|
|
|
36,742 |
|
Basic net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
0.77 |
|
|
$ |
(0.36 |
) |
|
$ |
(0.17 |
) |
Discontinued operations |
|
$ |
– |
|
|
$ |
(0.01 |
) |
|
$ |
0.62 |
|
Diluted net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Shares: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding |
|
|
37,829 |
|
|
|
37,069 |
|
|
|
36,742 |
|
Dilutive effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Restricted share units |
|
|
152 |
|
|
|
– |
|
|
|
– |
|
Convertible notes |
|
|
50 |
|
|
|
– |
|
|
|
– |
|
Weighted average common and common equivalent shares outstanding |
|
|
38,031 |
|
|
|
37,069 |
|
|
|
36,742 |
|
Diluted net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
0.77 |
|
|
$ |
(0.36 |
) |
|
$ |
(0.17 |
) |
Discontinued operations |
|
$ |
– |
|
|
$ |
(0.01 |
) |
|
$ |
0.62 |
|
Additionally, we had a contingent liability at December 31, 2014 of approximately $4.2 million that is payable in our common shares (see Note 4). At the December 31, 2014 closing price of our common shares, this liability represented 0.6 million common shares that could be potentially dilutive to future earnings per share calculations.
F-24
Warrants
On December 31, 2014, we issued 233,334 warrants for the pledge of Gundem’s Turkish resort (see Note 9). The common share purchase warrants have an exercise price of $5.99 per share and expire on June 30, 2016.
11. Income taxes
The income tax provision differs from the amount that would be obtained by applying the Bermuda statutory income tax rate of 0% for 2014, 2013 and 2012 to income (loss) for the year as follows:
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
(in thousands except rates) |
|
|||||||||
Statutory rate |
|
0.00 |
% |
|
|
0.00 |
% |
|
|
0.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations before income taxes |
$ |
42,143 |
|
|
$ |
(12,164 |
) |
|
$ |
118 |
|
Increase (decrease) resulting from: |
|
|
|
|
. |
|
|
|
|
|
|
Foreign tax rate differentials |
|
8,897 |
|
|
|
(1,443 |
) |
|
|
8,607 |
|
Change in valuation allowance |
|
228 |
|
|
|
982 |
|
|
|
(2,026 |
) |
Expiration of non-capital tax loss carryovers |
|
1,841 |
|
|
|
1,367 |
|
|
|
1,601 |
|
Other |
|
2,081 |
|
|
|
201 |
|
|
|
(1,691 |
) |
Total |
$ |
13,047 |
|
|
$ |
1,107 |
|
|
$ |
6,491 |
|
The components of the net deferred income tax liability at December 31, 2014 and 2013 were as follows:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Deferred tax assets |
|
|
|
|
|
|
|
Unrealized derivative losses |
$ |
– |
|
|
$ |
1,594 |
|
Timing of accruals |
|
692 |
|
|
|
1,043 |
|
Property and equipment |
|
9,761 |
|
|
|
– |
|
Non-capital loss carryovers |
|
28,155 |
|
|
|
25,868 |
|
Valuation allowance |
|
(37,153 |
) |
|
|
(28,404 |
) |
Total deferred tax assets |
|
1,455 |
|
|
|
101 |
|
Deferred tax liabilities |
|
|
|
|
|
|
|
Unrealized derivative gain |
|
(6,317 |
) |
|
|
– |
|
Property and equipment |
|
(50,196 |
) |
|
|
(13,093 |
) |
Total deferred tax liabilities |
|
(56,513 |
) |
|
|
(13,093 |
) |
Net deferred tax liabilities |
$ |
(55,058 |
) |
|
$ |
(12,992 |
) |
Components of net deferred tax liabilities |
|
|
|
|
|
|
|
Current assets |
$ |
329 |
|
|
$ |
2,239 |
|
Non-current assets |
|
1,181 |
|
|
|
903 |
|
Current liabilities |
|
(2,138 |
) |
|
|
– |
|
Non-current liabilities |
|
(54,430 |
) |
|
|
(16,134 |
) |
Net deferred tax liabilities |
$ |
(55,058 |
) |
|
$ |
(12,992 |
) |
We have accumulated losses or resource-related deductions available for income tax purposes in Turkey, Romania, Bulgaria and the United States. As of December 31, 2014, we had non-capital tax losses in Turkey of approximately 151.5 million TRY (approximately $65.3 million), which will begin expiring in 2018; non-capital tax losses in Romania of approximately 7.8 million Romanian New Leu (approximately $2.1 million), which will begin expiring in 2015; non-capital losses in Bulgaria of approximately 8.3 million Bulgarian Lev (approximately $5.1 million), which will begin expiring in 2015; and non-capital tax losses in the United States of approximately $40.7 million, which will begin expiring in 2018.
Effective October 1, 2009, we continued to the jurisdiction of Bermuda. We have determined that no taxes were payable upon the continuance. However, our tax filing positions are still subject to review by taxation authorities who may successfully challenge our interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by us.
F-25
We file income tax returns in the United States, Turkey, Romania, Bulgaria, Morocco and Cyprus, with Turkey being the only jurisdiction with significant amounts of taxes due. Income tax returns filed in Turkey for years before 2009 are no longer subject to examination. The Turkish Ministry of Finance is currently conducting tax audits on two of our Turkish subsidiaries, Amity and TBNG, for the years ended December 31, 2010 and 2012, respectively. The Turkish Ministry of Finance recently began audits of our Turkish subsidiaries, TEMI and DMLP, for the year ended December 31, 2010.
In connection with our acquisition of Amity and Petrogas in August 2010, at December 31, 2012, we recognized a liability due to an uncertain tax position related to the transfer of Petrogas shares to Amity prior to the acquisition. Pursuant to the Amity share purchase agreement, we are indemnified from any tax liability arising in Turkey or Australia as a result of the transfer of the Petrogas shares for a period of up to six years from the sale date at an amount up to 50% of the purchase price of $96.3 million and, therefore, have recorded a corresponding receivable in other long-term assets.
As of December 31, 2014 the liability and receivable consisted of taxes of $3.0 million, penalties of $0.6 million and interest of $2.2 million. During the years ended December 31, 2014 and 2013, the Company recorded interest of $0.5 million and $0.5 million, respectively.
As of December 31, 2014, there were no material uncertain tax positions for which the total amounts of unrecognized tax benefits will significantly increase or decrease within the next 12 months.
F-26
12. Segment information
In accordance with ASC 280, Segment Reporting (“ASC 280”), we have three reportable geographic segments: Turkey, Bulgaria and Albania. Summarized financial information from continuing operations concerning our geographic segments is shown in the following tables:
|
Corporate |
|
|
Turkey |
|
|
Bulgaria |
|
|
Albania |
|
|
Total |
|
|
|||||
|
(in thousands) |
|
|
|||||||||||||||||
For the year ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
$ |
– |
|
|
$ |
138,807 |
|
|
$ |
23 |
|
|
$ |
1,898 |
|
|
$ |
140,728 |
|
|
Production |
|
– |
|
|
|
18,059 |
|
|
|
134 |
|
|
|
1,806 |
|
|
|
19,999 |
|
|
Transportation costs |
|
– |
|
|
|
– |
|
|
|
– |
|
|
|
284 |
|
|
|
284 |
|
|
Exploration, abandonment, and impairment |
|
– |
|
|
|
19,820 |
|
|
|
44 |
|
|
|
– |
|
|
|
19,864 |
|
|
Cost of purchased gas |
|
– |
|
|
|
2,055 |
|
|
|
– |
|
|
|
– |
|
|
|
2,055 |
|
|
Seismic and other exploration |
|
178 |
|
|
|
4,106 |
|
|
|
1 |
|
|
|
– |
|
|
|
4,285 |
|
|
Revaluation of contingent consideration |
|
– |
|
|
|
– |
|
|
|
(2,500 |
) |
|
|
– |
|
|
|
(2,500 |
) |
|
General and administrative |
|
14,418 |
|
|
|
14,984 |
|
|
|
1,669 |
|
|
|
554 |
|
|
|
31,625 |
|
|
Depreciation, depletion and amortization |
|
124 |
|
|
|
48,452 |
|
|
|
18 |
|
|
|
333 |
|
|
|
48,927 |
|
|
Accretion of asset retirement obligations |
|
– |
|
|
|
387 |
|
|
|
19 |
|
|
|
7 |
|
|
|
413 |
|
|
Total costs and expenses |
|
14,720 |
|
|
|
107,863 |
|
|
|
(615 |
) |
|
|
2,984 |
|
|
|
124,952 |
|
|
Operating (loss) income |
|
(14,720 |
) |
|
|
30,944 |
|
|
|
638 |
|
|
|
(1,086 |
) |
|
|
15,776 |
|
|
Interest and other expense |
|
(36 |
) |
|
|
(6,007 |
) |
|
|
(1 |
) |
|
|
(169 |
) |
|
|
(6,213 |
) |
|
Interest income |
|
350 |
|
|
|
770 |
|
|
|
4 |
|
|
|
– |
|
|
|
1,124 |
|
|
Gain on commodity derivative contracts |
|
– |
|
|
|
37,454 |
|
|
|
– |
|
|
|
– |
|
|
|
37,454 |
|
|
Foreign exchange (loss) gain |
|
(4 |
) |
|
|
(6,497 |
) |
|
|
(22 |
) |
|
|
525 |
|
|
|
(5,998 |
) |
|
(Loss) income from continuing operations before income taxes |
|
(14,410 |
) |
|
|
56,664 |
|
|
|
619 |
|
|
|
(730 |
) |
|
|
42,143 |
|
|
Income tax provision |
|
– |
|
|
|
(13,659 |
) |
|
|
– |
|
|
|
612 |
|
|
|
(13,047 |
) |
|
Net (loss) income from continuing operations |
$ |
(14,410 |
) |
|
$ |
43,005 |
|
|
$ |
619 |
|
|
$ |
(118 |
) |
|
$ |
29,096 |
|
|
Total assets at December 31, 2014 |
$ |
51,919 |
|
|
$ |
363,162 |
|
|
$ |
4,675 |
|
|
$ |
126,619 |
|
|
$ |
546,375 |
|
(1) |
Goodwill at December 31, 2014 |
$ |
– |
|
|
$ |
6,935 |
|
|
$ |
– |
|
|
$ |
– |
|
|
$ |
6,935 |
|
|
Capital expenditures for the year ended December 31, 2014 |
$ |
545 |
|
|
$ |
109,563 |
|
|
$ |
1,393 |
|
|
$ |
2,271 |
|
|
$ |
113,772 |
|
|
For the year ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
$ |
– |
|
|
$ |
130,701 |
|
|
$ |
126 |
|
|
$ |
– |
|
|
$ |
130,827 |
|
|
Production |
|
5 |
|
|
|
18,384 |
|
|
|
213 |
|
|
|
– |
|
|
|
18,602 |
|
|
Exploration, abandonment, and impairment |
|
– |
|
|
|
27,116 |
|
|
|
217 |
|
|
|
– |
|
|
|
27,333 |
|
|
Cost of purchased gas |
|
– |
|
|
|
2,247 |
|
|
|
– |
|
|
|
– |
|
|
|
2,247 |
|
|
Seismic and other exploration |
|
100 |
|
|
|
13,909 |
|
|
|
– |
|
|
|
– |
|
|
|
14,009 |
|
|
Revaluation of contingent consideration |
|
– |
|
|
|
– |
|
|
|
(5,000 |
) |
|
|
– |
|
|
|
(5,000 |
) |
|
General and administrative |
|
12,685 |
|
|
|
16,068 |
|
|
|
267 |
|
|
|
– |
|
|
|
29,020 |
|
|
Depreciation, depletion and amortization |
|
69 |
|
|
|
41,196 |
|
|
|
57 |
|
|
|
– |
|
|
|
41,322 |
|
|
Accretion of asset retirement obligations |
|
– |
|
|
|
475 |
|
|
|
33 |
|
|
|
– |
|
|
|
508 |
|
|
Total costs and expenses |
|
12,859 |
|
|
|
119,395 |
|
|
|
(4,213 |
) |
|
|
– |
|
|
|
128,041 |
|
|
Operating (loss) income |
|
(12,859 |
) |
|
|
11,306 |
|
|
|
4,339 |
|
|
|
– |
|
|
|
2,786 |
|
|
Interest and other expense |
|
– |
|
|
|
(3,929 |
) |
|
|
– |
|
|
|
– |
|
|
|
(3,929 |
) |
|
Interest income |
|
284 |
|
|
|
1,056 |
|
|
|
– |
|
|
|
– |
|
|
|
1,340 |
|
|
Loss on commodity derivative contracts |
|
– |
|
|
|
(2,698 |
) |
|
|
– |
|
|
|
– |
|
|
|
(2,698 |
) |
|
Foreign exchange (loss) gain |
|
(9 |
) |
|
|
(9,664 |
) |
|
|
10 |
|
|
|
– |
|
|
|
(9,663 |
) |
|
(Loss) income loss from continuing operations before income taxes |
|
(12,584 |
) |
|
|
(3,929 |
) |
|
|
4,349 |
|
|
|
– |
|
|
|
(12,164 |
) |
|
Income tax provision |
|
– |
|
|
|
(1,107 |
) |
|
|
– |
|
|
|
– |
|
|
|
(1,107 |
) |
|
Net (loss) income from continuing operations |
$ |
(12,584 |
) |
|
$ |
(5,036 |
) |
|
$ |
4,349 |
|
|
$ |
– |
|
|
$ |
(13,271 |
) |
|
Total assets at December 31, 2013 |
$ |
14,070 |
|
|
$ |
321,749 |
|
|
$ |
10,231 |
|
|
$ |
– |
|
|
$ |
346,050 |
|
(1) |
Goodwill at December 31, 2013 |
$ |
– |
|
|
$ |
7,535 |
|
|
$ |
– |
|
|
$ |
– |
|
|
$ |
7,535 |
|
|
F-27
Capital expenditures for the year ended December 31, 2013 |
$ |
1,003 |
|
|
$ |
96,206 |
|
|
$ |
2,742 |
|
|
$ |
– |
|
|
$ |
99,951 |
|
|
For the year ended December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
$ |
– |
|
|
$ |
143,650 |
|
|
$ |
258 |
|
|
$ |
– |
|
|
$ |
143,908 |
|
|
Production |
|
169 |
|
|
|
17,328 |
|
|
|
307 |
|
|
|
– |
|
|
|
17,804 |
|
|
Exploration, abandonment, and impairment |
|
285 |
|
|
|
39,708 |
|
|
|
– |
|
|
|
– |
|
|
|
39,993 |
|
|
Cost of purchased gas |
|
– |
|
|
|
7,694 |
|
|
|
– |
|
|
|
– |
|
|
|
7,694 |
|
|
Seismic and other exploration |
|
304 |
|
|
|
4,726 |
|
|
|
10 |
|
|
|
– |
|
|
|
5,040 |
|
|
General and administrative |
|
10,982 |
|
|
|
20,603 |
|
|
|
2,362 |
|
|
|
– |
|
|
|
33,947 |
|
|
Depreciation, depletion and amortization |
|
30 |
|
|
|
28,092 |
|
|
|
93 |
|
|
|
– |
|
|
|
28,215 |
|
|
Accretion of asset retirement obligations |
|
– |
|
|
|
679 |
|
|
|
31 |
|
|
|
– |
|
|
|
710 |
|
|
Total costs and expenses |
|
11,770 |
|
|
|
118,830 |
|
|
|
2,803 |
|
|
|
– |
|
|
|
133,403 |
|
|
Operating (loss) income |
|
(11,770 |
) |
|
|
24,820 |
|
|
|
(2,545 |
) |
|
|
– |
|
|
|
10,505 |
|
|
Interest and other expense |
|
(1,890 |
) |
|
|
(6,450 |
) |
|
|
– |
|
|
|
– |
|
|
|
(8,340 |
) |
|
Interest income |
|
308 |
|
|
|
2,110 |
|
|
|
– |
|
|
|
– |
|
|
|
2,418 |
|
|
Loss on commodity derivative contracts |
|
– |
|
|
|
(5,548 |
) |
|
|
– |
|
|
|
– |
|
|
|
(5,548 |
) |
|
Foreign exchange gain (loss) |
|
79 |
|
|
|
1,054 |
|
|
|
(50 |
) |
|
|
– |
|
|
|
1,083 |
|
|
(Loss) income from continuing operations before income taxes |
|
(13,273 |
) |
|
|
15,986 |
|
|
|
(2,595 |
) |
|
|
– |
|
|
|
118 |
|
|
Income tax provision |
|
– |
|
|
|
(6,491 |
) |
|
|
– |
|
|
|
– |
|
|
|
(6,491 |
) |
|
Net (loss) income from continuing operations |
$ |
(13,273 |
) |
|
$ |
9,495 |
|
|
$ |
(2,595 |
) |
|
$ |
– |
|
|
$ |
(6,373 |
) |
|
Total assets at December 31, 2012 |
$ |
14,930 |
|
|
$ |
339,752 |
|
|
$ |
1,957 |
|
|
$ |
– |
|
|
$ |
356,639 |
|
(1) |
Goodwill at December 31, 2012 |
$ |
– |
|
|
$ |
9,021 |
|
|
$ |
– |
|
|
$ |
– |
|
|
$ |
9,021 |
|
|
Capital expenditures for the year ended December 31, 2012 |
$ |
– |
|
|
$ |
80,957 |
|
|
$ |
867 |
|
|
$ |
– |
|
|
$ |
81,824 |
|
|
(1) |
Excludes assets from our discontinued Moroccan operations of $28,000, $0.5 million, and $1.6 million at December 31, 2014, 2013 and 2012, respectively. |
13. Financial 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 Bulgarian Lev, European Union Euro, Albanian Lek, and TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At December 31, 2014, we had 12.5 million TRY (approximately $5.4 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 December 31, 2014 and 2013, we were a party to commodity derivative contracts.
F-28
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 (“TPAO”), the national oil company of Turkey, Zorlu Dogal Gaz Ithalat Ihracat ve Toptan Ticaret A.S. (“Zorlu”), a privately owned natural gas distributor in Turkey, and TUPRAS, which purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.
Fair value measurements
Cash and cash equivalents, receivables, notes receivable, accounts payable, accrued liabilities, the TBNG credit facility, the Term Loan Facility, the Prepayment Agreement, the Viking International note, and the shareholder loan were each estimated to have a fair value approximating the carrying amount at December 31, 2014 and 2013 due to the short maturity of those instruments. Indebtedness under the Senior Credit Facility was estimated to have a fair value approximating the carrying amount at December 31, 2014 and 2013 since the interest rate is generally market sensitive.
The financial assets and liabilities measured on a recurring basis at December 31, 2014 and 2013 consisted of our commodity derivative contracts. Fair values for options are based on counterparty market prices. The counterparties use market standard valuation methodologies incorporating market inputs for volatility and risk free interest rates in arriving at a fair value for each option contract. Prices are verified by us using analytical tools. There are no performance obligations related to the call options purchased to hedge our oil production.
We utilize independent third-party pricing services to determine the fair values of derivative contracts. The independent third party determines fair values using models based on a range of observable market inputs, including pricing models, quoted market prices of publicly traded securities with similar duration and yield, time value, yield curve, prepayment spreads, default rates and discounted cash flow and the values for these contracts are disclosed in Level 2 of the fair value hierarchy. Generally, we obtain a single price or quote per instrument from independent third parties to assist in establishing the fair value of these contracts. We review prices received from service providers for unusual fluctuations to ensure that the prices represent a reasonable estimate of fair value.
The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2014:
|
Fair Value Measurement Classification |
|
|||||||||||||
|
Quoted Prices in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active Markets for |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identical Assets or |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|||
|
Liabilities |
|
|
Observable Inputs |
|
|
Unobservable Inputs |
|
|
|
|
|
|||
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
||||
|
(in thousands) |
|
|||||||||||||
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
$ |
– |
|
|
$ |
31,587 |
|
|
$ |
– |
|
|
$ |
31,587 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible notes |
|
- |
|
|
|
(47,400 |
) |
|
|
- |
|
|
|
(47,400 |
) |
Total |
$ |
– |
|
|
$ |
(15,813 |
) |
|
$ |
– |
|
|
$ |
(15,813 |
) |
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 |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|||
|
Liabilities |
|
|
Observable Inputs |
|
|
Unobservable Inputs |
|
|
|
|
|
|||
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
||||
|
(in thousands) |
|
|||||||||||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
$ |
– |
|
|
$ |
(7,967 |
) |
|
$ |
– |
|
|
$ |
(7,967 |
) |
Total |
$ |
– |
|
|
$ |
(7,967 |
) |
|
$ |
– |
|
|
$ |
(7,967 |
) |
F-29
14. Commitments
Our aggregate annual commitments, other than our loans payable, as of December 31, 2014 were as follows:
|
|
Payments Due By Year |
|
|||||||||||||||||||||||||
|
|
Total |
|
|
2015 |
|
|
2016 |
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
Thereafter |
|
|||||||
|
|
(in thousands) |
|
|||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest |
|
$ |
26,288 |
|
|
$ |
11,077 |
|
|
$ |
9,598 |
|
|
$ |
4,977 |
|
|
$ |
595 |
|
|
$ |
41 |
|
|
$ |
- |
|
Leases |
|
|
7,097 |
|
|
|
2,826 |
|
|
|
346 |
|
|
|
195 |
|
|
|
33 |
|
|
|
- |
|
|
|
3,697 |
|
Total |
|
$ |
33,385 |
|
|
$ |
13,903 |
|
|
$ |
9,944 |
|
|
$ |
5,172 |
|
|
$ |
628 |
|
|
$ |
41 |
|
|
$ |
3,697 |
|
Normal operations purchase arrangements are excluded from the table as they are discretionary or being performed under contracts which are cancelable immediately or with a 30-day notice period.
We lease office space in Dallas, Texas, Bulgaria, Albania and Turkey. We also lease apartments in Turkey and Dallas, as well as operations yards in Turkey. Rent expense for the years ended December 31, 2014, 2013 and 2012 was $2.2 million, $3.3 million and $3.5 million, respectively.
15. Contingencies
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
During 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
During 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 government’s 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. 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 a $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” for the year ended December 31, 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 December 31, 2014, we had not recorded a contingent liability for this contingent consideration.
F-30
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 provision for this contingent consideration will be recorded when it becomes probable and estimable.
16. Related party transactions
Equity transactions
On September 1, 2010, we issued 730,000 common share purchase warrants to Dalea Partners, LP (“Dalea”) pursuant to a credit agreement with Dalea. The common share purchase warrants had an exercise price of $60.00 per share, and expired on September 1, 2013. Dalea is an affiliate of Mr. Mitchell.
On December 31, 2014, the Company issued 134,169 common share purchase warrants to Mr. Mitchell and 23,333 common share purchase warrants to each of Mr. Mitchell’s children (collectively, the “Warrants”) pursuant to warrant agreements. These Warrants were issued to Mr. Mitchell and his children as shareholders of the entity Gundem, which agreed to pledge its primary asset, a Turkish resort, in exchange for an extension of the maturity date of a credit agreement between the Company and a Turkish bank. As consideration for the pledge of the Gundem resort, the independent members of the Company’s board of directors approved the issuance of the Warrants to be allocated in accordance with each shareholder’s ownership percentage of Gundem. Pursuant to the warrant agreements, the Warrants are immediately exercisable, expire 18 months from the date of the release of the pledge on the Gundem resort, and entitle the holder to purchase one Common Share for each Warrant at an exercise price of $5.99 per share.
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 and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by 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 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.
Service transactions
Effective May 1, 2008, we entered into a service agreement, as amended (the “Service Agreement”), with Longfellow Energy, LP (“Longfellow”), Viking Drilling LLC (“Viking Drilling”), MedOil Supply, LLC and Riata Management, LLC (“Riata Management”). Mr. Mitchell and his wife own 100% of Riata Management. In addition, Mr. Mitchell, his wife and his children indirectly own 100% of Longfellow. Riata Management owns 100% of MedOil Supply, LLC. Dalea owns 85% of Viking Drilling. Under the terms of the Service Agreement, we pay, or are paid, for the actual cost of the services rendered plus the actual cost of reasonable expenses on a monthly basis.
Effective January 1, 2011, our wholly owned subsidiary, TEMI, entered into an accommodation agreement under which it leased rooms, flats and office space at a facility owned by Gundem. Under the accommodation agreement, TEMI leases six rooms and pays the TRY equivalent of $6,000 per month.
On August 23, 2011, the Company’s wholly owned subsidiary, TransAtlantic Petroleum (USA) Corp. (“TransAtlantic USA”), entered into an office lease with Longfellow to lease approximately 5,300 square feet of corporate office space in Addison, Texas. The initial lease term under the lease commenced on July 1, 2013, the date that TransAtlantic USA subleased a portion of its previous office space in Dallas, Texas (the “Commencement Date”). The lease expires five years after the Commencement Date, unless earlier terminated in accordance with the lease. During the initial lease term, TransAtlantic USA will pay monthly rent of $6,625 to Longfellow plus, utilities, real property taxes and liability insurance. Prior to the Commencement Date, no rent, utilities, real property taxes and/or liability insurance were required to be paid to Longfellow under the lease.
F-31
On June 13, 2012, we entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri AS (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business to a joint venture owned by Dalea and funds managed by Abraaj Investment Management Limited. 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 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.
On June 13, 2012, we entered into a transition services agreement with Viking Services Management, Ltd. (“Viking Management”) in connection with the sale of our oilfield services business to a joint venture owned by Dalea and funds managed by Abraaj Investment Management Limited. 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. The transition services agreement terminated on June 13, 2014. 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 addendum terminated on April 1, 2014.
On April 5, 2013 (the “First Floor Commencement Date”), TransAtlantic USA entered into an office lease with Longfellow to lease approximately 4,700 square feet of additional corporate office space in Addison, Texas. The initial lease term commenced on the First Floor Commencement Date and expires five years after the First Floor Commencement Date, unless earlier terminated in accordance with the lease. For the first year of the lease, TransAtlantic USA will pay monthly rent of $7,533 to Longfellow plus utilities, real property taxes and liability insurance.
On March 26, 2014, our wholly owned subsidiaries, TEMI and TBNG, entered into an equipment yard services agreement effective as of April 1, 2014 with Viking International for services related to the use of oilfield equipment yards located in Diyarbaki, Tekirdag and Muratli, Turkey. The initial term of the agreement is for twelve months, and the term of the agreement renews automatically for additional twelve-month periods unless earlier terminated. During the initial term, TEMI will pay monthly services fees of $17,250 to Viking International for services related to the use of Diyarbakir equipment yard, and TBNG will pay monthly service fees of $17,250 to Viking International for services related to the use of Tekirdag and Muratli equipment yards.
For the years ended December 31, 2014 and 2013, we incurred capital and operating expenditures of $96.4 million and $85.7 million, respectively, related to our various related party agreements.
Debt transactions
As of December 31, 2014 we sold $47.4 million of Notes in a non-brokered private placement. Dalea purchased $2.0 million of the Notes; trusts benefitting Mr. Mitchell’s four children each purchased $2.0 million of the Notes; Pinon Foundation, a non-profit charitable organization directed by Mr. Mitchell’s spouse, purchased $10.0 million of the Notes; the three children of Brian Bailey, a director of the Company, each purchased $100,000 of the Notes; Wil Saqueton, the Company’s vice president and chief financial officer, purchased $100,000 of the Notes; Matthew McCann, the Company’s general counsel and corporate secretary, purchased $200,000 of the Notes; and a trust benefitting Barbara and Terry Pope, Mr. Mitchell’s sister-in-law and brother-in-law, purchased $200,000 of the Notes.
On September 16, 2014, Stream issued to Viking International a note in the principal amount of $6.8 million. At December 31, 2014, we had $6.8 million outstanding under the Viking International note. At March 12, 2015, we had repaid the note (see Note 9).
Other related party transactions
During the year we incurred $60,000 of geology consulting services from Roxanna Oil Company, a private oil and natural gas exploration and production company (“Roxanna”). One of our directors is the chairman of the board of Roxanna.
F-32
The following table summarizes related party accounts receivable and accounts payable as of December 31, 2014 and December 31, 2013:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Related party accounts receivable: |
|
|
|
|
|
|
|
Viking International master services agreement |
$ |
355 |
|
|
$ |
939 |
|
Riata Management Service Agreement |
|
159 |
|
|
|
65 |
|
Dalea promissory note |
|
88 |
|
|
|
– |
|
Total related party accounts receivable |
$ |
602 |
|
|
$ |
1,004 |
|
Related party accounts payable: |
|
|
|
|
|
|
|
Viking International master services agreement |
$ |
16,754 |
|
|
$ |
15,956 |
|
Riata Management Service Agreement |
|
1,734 |
|
|
|
334 |
|
Viking Geophysical master services agreement |
|
– |
|
|
|
6,800 |
|
Total related party accounts payable |
$ |
18,488 |
|
|
$ |
23,090 |
|
17. Discontinued operations
Discontinued operations in Morocco
On June 27, 2011, we decided to discontinue our operations in Morocco. 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.
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, to a joint venture owned by 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 and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale of our oilfield services business to pay down approximately $45.2 million in outstanding indebtedness under our Amended and Restated Credit Facility. We have presented the oilfield services segment operating results as discontinued operations for the years ended December 31, 2014 and 2013.
The assets and liabilities held for sale at December 31, 2014 and 2013 were as follows:
|
2014 |
|
|
2013 |
|
||
|
(in thousands) |
|
|||||
Cash |
$ |
16 |
|
|
$ |
23 |
|
Other assets |
|
12 |
|
|
|
513 |
|
Total assets held for sale |
$ |
28 |
|
|
$ |
536 |
|
|
|
|
|
|
|
|
|
Accrued expenses and other liabilities |
$ |
6,928 |
|
|
$ |
7,559 |
|
Total liabilities held for sale |
$ |
6,928 |
|
|
$ |
7,559 |
|
F-33
Our operating results from discontinued operations for the years ended December 31, 2014, 2013 and 2012 are summarized as follows:
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
|||
|
(in thousands) |
|||||||||||
Total revenues |
$ |
– |
|
|
$ |
– |
|
|
$ |
19,956 |
|
|
Total costs and expenses |
|
(20 |
) |
|
|
(505 |
) |
|
|
(24,682 |
) |
|
Total other income (expense) |
|
– |
|
|
|
63 |
|
|
|
(357 |
) |
|
Loss from discontinued operations before income taxes |
|
(20 |
) |
|
|
(442 |
) |
|
|
(5,083 |
) |
|
Gain on disposal of discontinued operations |
|
– |
|
|
|
– |
|
|
|
35,999 |
|
|
Income tax provision |
|
– |
|
|
|
– |
|
|
|
(8,297 |
) |
|
Net (loss) income from discontinued operations |
$ |
(20 |
) |
|
$ |
(442 |
) |
|
$ |
22,619 |
|
|
18. Subsequent events
Convertible Notes
Subsequent to December 31, 2014, we sold an additional $7.6 million of Notes in a non-brokered private placement, bringing the total sale of the Notes to $55.0 million. We completed the private placement on February 20, 2015.
Exchange Notes
On February 20, 2015, we issued $55.0 million of Exchange Notes in exchange for all outstanding Notes. The Exchange Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association, as trustee (the “Trustee”).
The Exchange Notes bear interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year, commencing on July 1, 2015. The Exchange Notes will mature on July 1, 2017, unless earlier redeemed or converted.
Holders may, at any time after July 1, 2015 and from time to time at such holder’s option, convert, subject to certain terms and conditions, any or all of the principal of any Exchange Note into fully paid and nonassessable Common Shares at the conversion price. The initial conversion price is $6.80 per Common Share, subject to adjustment as described in the Indenture. Prior to or contemporaneously with the conversion of any of the principal of an Exchange Note, all accrued but unpaid interest on the principal amount being converted will be paid in cash. The Exchange Notes may not be converted into Common Shares on the maturity date or the redemption date.
At any time on or after July 1, 2015, we may redeem all or a part of the Exchange Notes at the redemption prices specified below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid interest to the redemption date.
Period Beginning |
Redemption Price |
July 1, 2015 |
107.5% |
January 1, 2016 |
105.0% |
July 1, 2016 |
102.5% |
January 1, 2017 |
100.0% |
If we experience a fundamental change (as defined in the Indenture), we will be required to make an offer to repurchase the Exchange Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase. Additionally, if we sell certain assets in exchange for $50.0 million or more in cash consideration, in certain circumstances, we will be required to use a portion of the net cash proceeds of such sale to make an offer to repurchase Exchange Notes at a price equal to the price we would be required to pay for an optional redemption at such time, plus accrued and unpaid interest, if any, up to but excluding the date of repurchase. The Indenture provides for customary events of default. The Indenture contains limited covenants, including a covenant that will limit our ability to incur liens securing funded debt.
F-34
TRANSATLANTIC PETROLEUM LTD.
Supplemental Information
(unaudited)
Supplemental quarterly financial data (unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2014 and 2013.
|
Three Months Ended |
|
|||||||||||||
|
March 31, |
|
|
June 30, |
|
|
September 30, |
|
|
December 31, |
|
||||
|
(in thousands, except per share data) |
|
|||||||||||||
For the year ended December 31, 2014: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
$ |
33,646 |
|
|
$ |
41,061 |
|
|
$ |
36,077 |
|
|
$ |
29,944 |
|
Net income |
|
3,973 |
|
|
|
1,437 |
|
|
|
8,313 |
|
|
|
15,353 |
|
Comprehensive income (loss) |
|
678 |
|
|
|
6,529 |
|
|
|
(4,343 |
) |
|
|
11,887 |
|
Basic and diluted net income (loss) per common shares from continuing operations |
$ |
0.11 |
|
|
$ |
0.04 |
|
|
$ |
0.22 |
|
|
$ |
0.39 |
|
For the year ended December 31, 2013: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
$ |
34,044 |
|
|
$ |
30,516 |
|
|
$ |
32,345 |
|
|
$ |
33,922 |
|
Net income (loss) |
|
2,939 |
|
|
|
2,903 |
|
|
|
(4,973 |
) |
|
|
(14,582 |
) |
Comprehensive income (loss) |
|
103 |
|
|
|
(10,640 |
) |
|
|
(15,599 |
) |
|
|
(24,550 |
) |
Basic and diluted net income (loss) per common shares from continuing operations |
$ |
0.08 |
|
|
$ |
0.08 |
|
|
$ |
(0.13 |
) |
|
$ |
(0.39 |
) |
(1) |
The sum of the individual quarterly net income (loss) amounts per share may not agree with year-to-date net income (loss) per share as each quarterly computation is based on the net income or loss for that quarter and the weighted-average number of shares outstanding during that quarter. |
Supplemental oil and natural gas reserves information (unaudited)
As required by the FASB and SEC, the standardized measure of discounted future net cash flows (the “Standardized Measure”) presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10% to proved reserves. We do not believe the Standardized Measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and natural gas properties or of the value of its proved oil and natural gas reserves. The Standardized Measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year-to-year as prices change.
Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. We engaged DeGolyer & MacNaughton and Deloitte LLP to prepare our reserves estimates in Turkey and Albania, respectively. These estimates comprise 100% of our estimated proved reserves (by volume) at December 31, 2014.
F-35
The following unaudited schedules are presented in accordance with required disclosures about oil and natural gas producing activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.
All of our proved reserves are located in Turkey and Albania, and all prices are held constant in accordance with SEC rules.
Oil and natural gas prices used to estimate reserves were computed by applying the un-weighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 2014, 2013 and 2012. The oil and natural gas prices used to estimate reserves are shown in the table below.
|
12-Month |
|
|||||
|
Average Price |
|
|||||
|
Oil |
|
|
Natural Gas |
|
||
|
per (Bbl) |
|
|
per (Mcf) |
|
||
|
|
|
|
|
|
|
|
Turkey |
|
|
|
|
|
|
|
2014 |
$ |
94.53 |
|
|
$ |
8.71 |
|
2013 |
$ |
102.07 |
|
|
$ |
9.92 |
|
2012 |
$ |
108.66 |
|
|
$ |
8.74 |
|
|
|
|
|
|
|
|
|
Albania |
|
|
|
|
|
|
|
2014 |
$ |
69.55 |
|
|
$ |
10.00 |
|
F-36
The following table sets forth our estimated net proved reserves (natural gas converted to Mboe by dividing Mmcf by six), including changes therein, and proved developed reserves:
Disclosure of reserves quantities
|
Oil |
|
|
Natural Gas |
|
|
Total |
|
|||
|
(Mbbl) |
|
|
(Mmcf) |
|
|
(Mboe) |
|
|||
Total proved reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011 |
|
11,215 |
|
|
|
13,223 |
|
|
|
13,419 |
|
Extensions and discoveries |
|
1,794 |
|
|
|
3,055 |
|
|
|
2,303 |
|
Revisions of previous estimates |
|
(2,540 |
) |
|
|
423 |
|
|
|
(2,470 |
) |
Sales volumes |
|
(949 |
) |
|
|
(4,238 |
) |
|
|
(1,655 |
) |
December 31, 2012 |
|
9,520 |
|
|
|
12,463 |
|
|
|
11,597 |
|
Extensions and discoveries |
|
1,563 |
|
|
|
2,652 |
|
|
|
2,005 |
|
Revisions of previous estimates |
|
(436 |
) |
|
|
3,436 |
|
|
|
137 |
|
Sales volumes |
|
(933 |
) |
|
|
(3,512 |
) |
|
|
(1,518 |
) |
December 31, 2013 |
|
9,714 |
|
|
|
15,039 |
|
|
|
12,221 |
|
Acquisitions |
|
14,296 |
|
|
|
8,249 |
|
|
|
15,671 |
|
Extensions and discoveries |
|
4,740 |
|
|
|
2,809 |
|
|
|
5,208 |
|
Revisions of previous estimates |
|
1,254 |
|
|
|
1,668 |
|
|
|
1,532 |
|
Sales volumes |
|
(1,339 |
) |
|
|
(3,262 |
) |
|
|
(1,883 |
) |
December 31, 2014 |
|
28,665 |
|
|
|
24,503 |
|
|
|
32,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012: |
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing |
|
4,241 |
|
|
|
5,228 |
|
|
|
5,112 |
|
Proved developed non-producing |
|
910 |
|
|
|
2,887 |
|
|
|
1,391 |
|
Total |
|
5,151 |
|
|
|
8,115 |
|
|
|
6,503 |
|
December 31, 2013: |
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing |
|
4,540 |
|
|
|
7,189 |
|
|
|
5,738 |
|
Proved developed non-producing |
|
335 |
|
|
|
3,261 |
|
|
|
879 |
|
Total |
|
4,875 |
|
|
|
10,450 |
|
|
|
6,617 |
|
December 31, 2014: |
|
|
|
|
|
|
|
|
|
|
|
Proved developed producing |
|
10,783 |
|
|
|
5,572 |
|
|
|
11,712 |
|
Proved developed non-producing |
|
9,974 |
|
|
|
3,979 |
|
|
|
10,637 |
|
Total |
|
20,757 |
|
|
|
9,551 |
|
|
|
22,349 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2012 |
|
4,369 |
|
|
|
4,348 |
|
|
|
5,094 |
|
As of December 31, 2013 |
|
4,839 |
|
|
|
4,589 |
|
|
|
5,604 |
|
As of December 31, 2014 |
|
7,908 |
|
|
|
14,952 |
|
|
|
10,400 |
|
For the year ended December 31, 2014, we had a proved reserve increase of 20,528 Mboe, or 168.0%, compared to 2013. This increase was primarily attributable to the acquisition of Stream, the continued success of our horizontal drilling campaigns in the Selmo oil field and the Thrace Basin and the successful appraisal of the Bahar oil field. The Albanian assets of Stream constituted 15,634 Mboe or 76.2% of the increase. Of the proved reserves, 88.9% are in the proved developed category and are part of the producing oil assets in Albania. The increase in proved reserves was partially offset by sales volumes of 1,883 Mboe in 2014, consisting of 1,339 Mbbls of oil and 3,262 Mmcf of natural gas.
F-37
At December 31, 2014, we recorded an increase in proved reserves of 5,208 Mboe through extensions and discoveries. These increases were due to the following factors: (i) horizontal drilling in Selmo, which resulted in the conversion of 2,234 Mboe from probable or possible reserves to proved reserves due to successful wells in the previously under-drilled southeast portion of the field and confirming that oil still remains at, or below, the current oil-water contact; (ii) the addition of 467 Mboe in the Thrace Basin as a result of the Gurgen discovery and successful Sogucak test in the Kuzey Emirali-1 well; (iii) the addition of 2,243 Mboe due to successful appraisal wells on the Bahar structure and (iv) the addition of 264 Mbbls in the Arpatepe oil field as a result of the Arpatepe-7 appraisal well success which extended the field to the southeast.
At December 31, 2014, we recorded an increase in reserves due to technical revisions of 1,254 Mbbl and 1,668 Mmcf (1,532 Mboe total). The revision in oil of 1,254 Mbbls was an increase from December 31, 2013, in which we recorded a loss of 436 Mbbls, and was mostly attributable to well performance in Selmo. Prior to initiating the horizontal well campaign in Selmo in 2013, drilling had been halted due to poor vertical well performance. This resulted in negative revisions to estimates for 2013. By contrast, the horizontal wells drilled in late 2013 and throughout 2014 have performed better than original estimates and thus resulted in positive technical revisions. The revision in gas of 1,668 Mmcf was a decrease from December 31, 2013, in which we recorded 3,436 Mmcf in technical revisions and was mostly attributable to a decrease in activity in the Thrace Basin, where we did not introduce any new technology to the gas fields. In 2013, we successfully fracture stimulated the Mezardere formation for the first time. This led to an aggressive recompletion program as we fine-tuned our stimulation methodology which, in turn, greatly increased many behind pipe reserves. The performance of these fracture stimulated wells versus the unstimulated type curves allowed for positive reserve revisions.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2014, 2013 and 2012 are shown in the table below. In our calculation of standardized measure we have utilized statutory tax rates of 20% and 50% for Turkey and Albania, respectively.
|
Turkey |
|
|
Albania |
|
|
Total |
|
|||
|
(in thousands) |
|
|||||||||
As of and for the year ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
$ |
1,504,369 |
|
|
$ |
921,237 |
|
|
$ |
2,425,606 |
|
Future production costs |
|
(309,528 |
) |
|
|
(239,149 |
) |
|
|
(548,677 |
) |
Future development costs |
|
(234,675 |
) |
|
|
(123,085 |
) |
|
|
(357,760 |
) |
Future income tax expense |
|
(148,437 |
) |
|
|
(243,774 |
) |
|
|
(392,211 |
) |
Future net cash flows |
|
811,729 |
|
|
|
315,229 |
|
|
|
1,126,958 |
|
10% annual discount for estimated timing of cash flows |
|
(272,649 |
) |
|
|
(182,227 |
) |
|
|
(454,876 |
) |
Standardized measure of discounted future net cash flows related to proved reserves |
$ |
539,080 |
|
|
$ |
133,002 |
|
|
$ |
672,082 |
|
As of and for the year ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
$ |
1,141,775 |
|
|
$ |
- |
|
|
$ |
1,141,775 |
|
Future production costs |
|
(190,337 |
) |
|
|
- |
|
|
|
(190,337 |
) |
Future development costs |
|
(131,643 |
) |
|
|
- |
|
|
|
(131,643 |
) |
Future income tax expense |
|
(127,971 |
) |
|
|
- |
|
|
|
(127,971 |
) |
Future net cash flows |
|
691,824 |
|
|
|
- |
|
|
|
691,824 |
|
10% annual discount for estimated timing of cash flows |
|
(196,055 |
) |
|
|
- |
|
|
|
(196,055 |
) |
Standardized measure of discounted future net cash flows related to proved reserves |
$ |
495,769 |
|
|
$ |
- |
|
|
$ |
495,769 |
|
As of and for the year ended December 31, 2012 |
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows |
$ |
1,143,346 |
|
|
$ |
- |
|
|
$ |
1,143,346 |
|
Future production costs |
|
(227,876 |
) |
|
|
- |
|
|
|
(227,876 |
) |
Future development costs |
|
(93,267 |
) |
|
|
- |
|
|
|
(93,267 |
) |
Future income tax expense |
|
(122,582 |
) |
|
|
- |
|
|
|
(122,582 |
) |
Future net cash flows |
|
699,621 |
|
|
|
- |
|
|
|
699,621 |
|
10% annual discount for estimated timing of cash flows |
|
(221,712 |
) |
|
|
- |
|
|
|
(221,712 |
) |
Standardized measure of discounted future net cash flows related to proved reserves |
$ |
477,909 |
|
|
$ |
- |
|
|
$ |
477,909 |
|
F-38
Changes in the standardized measure of discounted future net cash flows
The following are the principal sources of changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2014, 2013 and 2012.
|
2014 |
|
|
2013 |
|
|
2012 |
|
|||
|
(in thousands) |
|
|||||||||
Standardized measure, January 1, |
$ |
495,769 |
|
|
$ |
477,909 |
|
|
$ |
531,797 |
|
Net change in sales and transfer prices and in production (lifting) costs related to future production |
|
(75,912 |
) |
|
|
(7,868 |
) |
|
|
(594 |
) |
Changes in future estimated development costs |
|
(151,238 |
) |
|
|
(73,753 |
) |
|
|
(66,178 |
) |
Sales and transfers of oil and natural gas during the period |
|
(118,083 |
) |
|
|
(108,674 |
) |
|
|
(116,477 |
) |
Net change due to extensions and discoveries |
|
245,643 |
|
|
|
112,814 |
|
|
|
124,643 |
|
Net change due to purchases of minerals in place |
|
235,855 |
|
|
|
- |
|
|
|
- |
|
Net change due to revisions in quantity estimates |
|
72,222 |
|
|
|
7,678 |
|
|
|
(133,637 |
) |
Previously estimated development costs incurred during the period |
|
63,250 |
|
|
|
47,252 |
|
|
|
50,810 |
|
Accretion of discount |
|
44,439 |
|
|
|
56,376 |
|
|
|
64,584 |
|
Other |
|
(19,340 |
) |
|
|
(12,070 |
) |
|
|
(10,644 |
) |
Net change in income taxes |
|
(120,523 |
) |
|
|
(3,895 |
) |
|
|
33,605 |
|
Standardized measure, December 31, |
$ |
672,082 |
|
|
$ |
495,769 |
|
|
$ |
477,909 |
|
Costs incurred in oil and natural gas property acquisition, exploration and development
Costs incurred in oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2014, 2013 and 2012 are summarized as follows:
|
Turkey |
|
|
Albania |
|
|
Bulgaria |
|
|
Total |
|
||||
|
(in thousands) |
|
|||||||||||||
For the year ended December 31, 2014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
$ |
- |
|
|
$ |
99,927 |
|
|
$ |
- |
|
|
$ |
99,927 |
|
Unproved |
|
- |
|
|
|
16,140 |
|
|
|
- |
|
|
|
16,140 |
|
Exploration |
|
39,143 |
|
|
|
2,161 |
|
|
|
1,291 |
|
|
|
42,595 |
|
Development |
|
63,250 |
|
|
|
110 |
|
|
|
44 |
|
|
|
63,404 |
|
Total costs incurred |
$ |
102,393 |
|
|
$ |
118,338 |
|
|
$ |
1,335 |
|
|
$ |
222,066 |
|
For the year ended December 31, 2013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Unproved |
|
6,750 |
|
|
|
- |
|
|
|
- |
|
|
|
6,750 |
|
Exploration |
|
40,258 |
|
|
|
- |
|
|
|
2,742 |
|
|
|
43,000 |
|
Development |
|
47,252 |
|
|
|
- |
|
|
|
- |
|
|
|
47,252 |
|
Total costs incurred |
$ |
94,260 |
|
|
$ |
- |
|
|
$ |
2,742 |
|
|
$ |
97,002 |
|
For the year ended December 31, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisitions of properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Unproved |
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Exploration |
|
36,465 |
|
|
|
- |
|
|
|
- |
|
|
|
36,465 |
|
Development |
|
43,824 |
|
|
|
- |
|
|
|
867 |
|
|
|
44,691 |
|
Total costs incurred |
$ |
80,289 |
|
|
$ |
- |
|
|
$ |
867 |
|
|
$ |
81,156 |
|
F-39
EXHIBIT INDEX
2.1 |
|
Stock Purchase Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Longe Energy Limited, TransAtlantic Petroleum (USA) Corp., TransAtlantic Petroleum Cyprus Limited, Viking International Limited, Viking Geophysical Services, Ltd., Viking Oilfield Services SRL and Dalea Partners, LP. (incorporated by reference to Exhibit 2.1 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 10, 2012). |
|
|
|
2.2 |
|
Arrangement Agreement, dated as of September 2, 2014, between TransAtlantic Petroleum Ltd. and Stream Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated September 2, 2014, filed with the SEC on September 8, 2014). |
|
|
|
3.1 |
|
Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009). |
|
|
|
3.2 |
|
Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014). |
|
|
|
3.3 |
|
Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014). |
|
|
|
4.1 |
|
Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009). |
|
|
|
4.2 |
|
Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011). |
|
|
|
4.3 |
|
Specimen Common Share certificate (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated March 4, 2014, filed with the SEC on March 6, 2014). |
|
|
|
4.4 |
|
Indenture, dated as of February 20, 2015, between TransAtlantic Petroleum Ltd. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated February 20, 2015, filed with the SEC on February 25, 2015). |
|
|
|
4.5 |
|
Form of 13.0% Convertible Note due 2017 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated February 20, 2015, filed with the SEC on February 25, 2015). |
|
|
|
10.1 |
|
Service Agreement, effective as of May 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited and Riata Management, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009). |
|
|
|
10.2 |
|
Amendment to Service Agreement, effective as of October 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited, MedOil Supply LLC and Riata Management, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009). |
|
|
|
10.3 |
|
Domestic Crude Oil Purchase/Sale Agreement, dated as of January 26, 2009, by and between Türkiye Petrol Rafinerileri A.Ş. and TransAtlantic Exploration Mediterranean International Pty. Ltd. (incorporated by reference to Exhibit 10.13 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011). |
|
|
|
10.4† |
|
Executive Employment Agreement, effective January 1, 2008, by and between TransAtlantic Petroleum Corp. and Jeffrey S. Mecom (incorporated by reference to Exhibit 4.8 to the Company’s Annual Report on Form 20-F (File No. 000-31643), filed with the SEC on May 14, 2008). |
|
|
10.5† |
|
TransAtlantic Petroleum Corp. 2009 Long-Term Incentive Plan (incorporated by reference to Appendix B to the Definitive Proxy Statement filed by TransAtlantic Petroleum Corp. with the SEC on April 30, 2009). |
|
|
|
10.6† |
|
Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 16, 2009, filed with the SEC on June 22, 2009). |
|
|
|
10.7 |
|
Amended and Restated Credit Agreement, dated as of May 18, 2011, by and between DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc and BNP Paribas (Suisse) SA, as joint mandated lead arrangers and joint bookrunners, and Standard Bank Plc as letter of credit issuer, administrative agent, collateral agent and technical agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 17, 2011, filed with the SEC on May 19, 2011). |
|
|
|
10.8 |
|
Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of August 4, 2011, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, and Standard Bank Plc as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 9, 2011). |
|
|
|
10.9 |
|
Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of September 14, 2011, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors and Standard Bank Plc as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 9, 2011). |
|
|
|
10.10 |
|
Office Lease, dated August 23, 2011, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated August 23, 2011, filed with the SEC on August 25, 2011). |
|
|
|
10.11† |
|
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated July 13, 2011, filed with the SEC on July 19, 2011). |
|
|
|
10.12 |
|
Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking International Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated June 13, 2012, filed with the SEC on June 19, 2012). |
|
|
|
10.13 |
|
Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, dated June 13, 2012, filed with the SEC on June 19, 2012). |
|
|
|
10.14 |
|
Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Geophysical Services, Ltd. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K, dated June 13, 2012, filed with the SEC on June 19, 2012). |
|
|
|
10.15 |
|
Transition Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum, Ltd. and Viking Services Management, Ltd. (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K, dated June 13, 2012, filed with the SEC on June 19, 2012). |
|
|
|
10.16 |
|
Convertible Promissory Note made by Dalea Partners, LP to the order of TransAtlantic Petroleum Ltd., dated June 13, 2012 in the principal sum of $11,500,000 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K, dated June 13, 2012, filed with the SEC on June 19, 2012). |
|
|
|
10.17 |
|
Amendment No. 3 to the Amended and Restated Credit Agreement, dated as of November 21, 2012, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Insaat Sanayive Ticaret A.S., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors and Standard Bank Plc as administrative agent and collateral agent (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K, filed with the SEC on May 16, 2013). |
|
|
|
10.18 |
|
Office Lease, dated April 5, 2013, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated May 8, 2013, filed with the SEC on May 14, 2013). |
|
|
|
10.19 |
|
Equipment Yard Services Agreement, by and between TransAtlantic Exploration Mediterranean International Pty Ltd, Thrace Basin Natural Gas (Turkiye) Corporation and Viking International Limited, dated as of April 1, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 26, 2014, filed with the SEC on March 28, 2014). |
|
|
|
10.20 |
|
Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 8, 2014). |
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|
|
10.21† |
|
Summary of annual restricted stock award arrangement with Mr. Wil F. Saqueton (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 6, 2014). |
|
|
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10.22* |
|
Facility Agreement, dated December 15, 2011, by and among Stream Oil & Gas Ltd., Stream Oil & Gas Ltd. (BC), and Raiffeisen Bank Sh.A. |
|
|
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10.23* |
|
Amended and Restated Facility Agreement, dated September 17, 2014, by and among Stream Oil & Gas Ltd., Stream Oil & Gas Ltd. (BC), and Raiffeisen Bank Sh.A. |
|
|
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10.24* |
|
Amendment and Restatement Agreement, dated September 17, 2014, by and among Stream Oil & Gas Ltd., Stream Oil & Gas Ltd. (BC), and Raiffeisen Bank Sh.A. |
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10.25* |
|
Prepayment Agreement, dated April 18, 2013, by and between Stream Oil & Gas Ltd. and Trafigura PTE Ltd. |
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10.26* |
|
Coordination Agreement, dated May 22, 2013, by and among Raiffeisen Bank Sh.A, Trafigura PTE Ltd., Stream Oil & Gas Ltd. and Stream Oil & Gas Ltd. (BC). |
|
|
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10.27* |
|
Promissory Note made by Stream Oil & Gas Ltd. to the order of Viking International Ltd., dated September 12, 2014 in the principal sum of $6,800,000. |
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21.1* |
|
Subsidiaries of the Company. |
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23.1* |
|
Consent of KPMG LLP. |
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23.2* |
|
Consent of DeGolyer and MacNaughton. |
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23.3* |
|
Consent of Deloitte LLP. |
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31.1* |
|
Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2* |
|
Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1* * |
|
Certification of the Chief Executive Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2** |
|
Certification of the Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
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99.1* |
|
Report of DeGolyer and MacNaughton, dated March 6, 2015. |
|
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99.2* |
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Report of Deloitte LLP, dated February 27, 2015. |
|
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101.INS* |
|
XBRL Instance Document. |
|
|
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101.SCH* |
|
XBRL Taxonomy Extension Schema Document. |
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|
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101.CAL* |
|
XBRL Taxonomy Extension Calculation Linkbase Document. |
|
|
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101.DEF* |
|
XBRL Taxonomy Extension Definition Linkbase Document. |
|
|
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101.LAB* |
|
XBRL Taxonomy Extension Label Linkbase Document. |
|
|
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101.PRE* |
|
XBRL Taxonomy Extension Presentation Linkbase Document. |
† |
Management contract or compensatory plan arrangement. |
* |
Filed herewith. |
** |
Furnished herewith. |
Exhibit 10.22
EXECUTION VERSION |
|
|
|
$20,000,000 trade finance term loan facility
|
|
Dated December 2011 |
|
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) (as Borrower) Stream Oil & Gas Ltd (BC) (as Guarantor) Raiffeisen Bank Sh.A (as Lender)
|
|
London EC4M 7WS United Kingdom DX 242 |
Contents
1 |
Definitions and construction |
1 |
2 |
The Facility |
11 |
3 |
Purpose |
11 |
4 |
Conditions of utilisation |
11 |
5 |
Utilisation |
12 |
6 |
Repayment |
12 |
7 |
Prepayment and cancellation |
13 |
8 |
Interest |
14 |
9 |
Interest Periods |
15 |
10 |
Changes to the calculation of interest |
16 |
11 |
Fees |
17 |
12 |
Tax gross-up and indemnities |
17 |
13 |
Increased Costs |
19 |
14 |
Other indemnities |
20 |
15 |
Mitigation by the Lender |
21 |
16 |
Costs |
22 |
17 |
Guarantee, indemnity and cash injection undertaking |
22 |
18 |
Representations and warranties |
27 |
19 |
Information undertakings |
32 |
20 |
Financial covenants |
35 |
21 |
Positive undertakings |
38 |
22 |
Negative undertakings |
42 |
23 |
Events of Default |
47 |
24 |
Changes to the Parties |
51 |
25 |
Rights and discretions of the Lender |
51 |
26 |
Payment mechanics |
52 |
27 |
Set-off |
54 |
28 |
Notices |
54 |
29 |
Calculations and certificates |
56 |
30 |
Partial invalidity |
56 |
31 |
Remedies and waivers |
56 |
32 |
Amendments and waivers |
57 |
33 |
Counterparts |
57 |
34 |
Governing law and enforcement |
57 |
Schedule 1 - Conditions precedent |
59 |
|
Schedule 2 - Form of Utilisation Request |
62 |
Contents (i)
Facility agreement
Dated December 2011
Between
(2) |
Stream Oil & Gas Ltd (BC), a company incorporated in British Columbia, Canada with registration number BC0713471, its registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (the Guarantor); and |
(3) |
Raiffeisen Bank Sh.A a financial institution established and existing under the laws of Albania registered with Court Order No. 17426 on 10 July 1997 (the Lender). |
It is agreed as follows
In this Agreement the following definitions apply.
Accounting Principles means for the Guarantor, the accounting principles, concepts, bases and policies generally accepted in its jurisdiction of incorporation and consistently applied.
Affiliate means, for any person, a Subsidiary of that person or a Holding Company of that person or any other Subsidiary of that Holding Company.
Authorisation means an authorisation, consent, approval, resolution, permit, licence, exemption, clearance, filing, notarisation or registration or other similar requirement of a governmental, judicial or other public body or authority.
Availability Period means the period from and including the date of this Agreement to and including the date that is 12 Months after the date of this Agreement, or any later date the Borrower and Lender agree.
Available Facility means the Commitment minus:
(a) |
the amount of any outstanding Loans; and |
(b) |
in relation to any proposed Utilisation, the amount of any Loans that are due to be made on or before the proposed Utilisation Date. |
Break Costs means the amount (if any) by which:
(a) |
the interest the Lender should have received for the period: |
(i) |
starting on the date of receipt of all or part of its participation in a Loan or Unpaid Sum; and |
Page 2
(ii) |
ending on the last day of the current Interest Period for that Loan or Unpaid Sum, |
had the principal amount or Unpaid Sum received been paid on the last day of that Interest Period,
exceeds:
(b) |
the amount the Lender would be able to earn by placing an amount equal to the principal amount or Unpaid Sum received on deposit with a leading bank in the London interbank market for a period: |
(i) |
starting on the Business Day following receipt; and |
(ii) |
ending on the last day of that Interest Period. |
Business Day means:
(a) |
for any payment or determination of an interest rate, a day (other than a Saturday or Sunday) on which banks are open for general business in London, Tirana and New York; and |
(b) |
for any other purpose, a day (other than a Saturday or Sunday) on which banks are open for general interbank business in Tirana. |
Buyer means a person that is party to a Commodity Contract as buyer.
Certified Copy means a copy of an original document that is:
(a) |
certified by a director or equivalent authorised officer of the relevant person as being a true, complete and up-to-date copy; or |
(b) |
notarised as being a true copy, |
and which, if the original document has been changed, has a document containing details of that change attached to it.
Commercial Contract means any of the Commodity Contracts, the Production Facilities Contracts, the Petroleum Agreements and any other contract of a commercial nature to which the Borrower is or becomes a party.
Commercial Contracts Security Agreement means the Commercial Contracts Security Agreement dated around the date of this Agreement between the Borrower and the Lender and relating to the Commercial Contracts.
Commitment means $20,000,000 to the extent not cancelled or reduced under this Agreement.
Commodity Contract means any contract for the sale of Commodity by the Borrower, including any Export Contract.
Commodity means crude oil and any oil products.
Consignment means a consignment of Commodity that is being or will be delivered under an Export Contract.
Consignment Documents means, for a Consignment, all documents (with the requisite number of copies or originals) against delivery of which payment is to be made under any relevant letter of credit, or, as the case may be, the relevant Buyer is obliged to pay under the relevant Export Contract.
Page 3
Crude Oil Reserve Report means a report, in form and substance acceptable to the Lender, by an independent expert acceptable to the Lender setting out (a) the volume of proved, probable and possible crude oil still to be located in the fields that are the subject of the Petroleum Agreements; and (b) the projected cashflows attributable to the depletion of those crude oil reserves.
Dangerous Materials means any substance (in any form) that is subject to regulatory control as being hazardous or dangerous or that can harm or damage the Environment.
Default means an Event of Default or any event or circumstance mentioned in Clause 23 (Events of Default) that would, with the:
(a) |
expiry of a grace period; |
(b) |
giving of notice; |
(c) |
making of any determination; or |
(d) |
satisfaction of any condition under the Finance Documents, |
or any combination of any of these, be an Event of Default.
Dollar and $ means the lawful currency of the United States of America.
Environment means ecological systems, living organisms (including humans) and any (or any combination) of the following media:
(a)air (including air within natural or man-made structures and air underground);
(b)water (including water underground or in pipe or sewerage systems, sea and inland, ground and surface water); and
(c)land (including land covered with water).
Environmental Claim means any claim, proceeding, formal notice or investigation by any person under any Environmental Law.
Environmental Law means any applicable law or regulation that relates to:
(a) |
the pollution or protection of the Environment; |
(b) |
the conditions of the workplace; or |
(c) |
any substance that (alone or in combination with any other) can harm the Environment, including waste. |
Environmental Permit means any Authorisation required by any Environmental Law for the operation of the Borrower's business or its ownership or occupation of any property.
Equipment and Inventory Security Agreement means the Securing Charge Agreement Over Movable Assets and Inventories dated around the date of this Agreement between the Borrower and the Lender and relating to certain equipment, machinery and oil stocks of the Borrower.
Event of Default means any event or circumstance described as an Event of Default in Clause 23 (Events of Default).
Page 4
Export Contract means any of:
(a) |
the Crude Oil Sales Contract No. SKO-011-453470 dated 3 October 2011 between the Borrower as seller and Trafigura Beheer BV as buyer for the sale and purchase of Commodity for an initial period of 12 months; and |
(b) |
any other contract for the sale by the Borrower of Commodity for export from Albania that is designated as an Export Contract by the Lender and the Borrower. |
Facility means the term loan facility described in Clause 2 (The Facility).
Facility Office means the office or offices through which the Lender will perform its obligations under this Agreement, being Blvd. “Bajram Curri”, ETC, 6th Floor, Tirana, Albania (or, any office or offices notified by the Lender to the Borrower in writing after the date of this Agreement by not less than five Business Days' written notice).
Finance Document means any of:
(a) |
this Agreement; |
(b) |
any Transaction Security Document; and |
(c) |
any other document designated as a Finance Document by the Lender and the Borrower. |
Financial Indebtedness means any indebtedness for or in respect of:
(b) |
any amount raised by acceptance under any acceptance credit facility or dematerialised equivalent; |
(c) |
any amount raised under any note purchase facility or from the issue of bonds, notes, debentures, loan stock or any similar instrument; |
(d) |
receivables sold or discounted (except to the extent they are sold on non-recourse terms); |
(e) |
any amount raised under any other transaction (including any forward sale or advance or deferred purchase agreement) having the commercial effect of a borrowing; |
(g) |
any counter-indemnity or reimbursement obligation for any guarantee, indemnity, bond, standby or documentary letter of credit or any other instrument issued by a bank or financial institution; |
(h) |
any liability for or in respect of: |
(i) |
any lease or hire purchase contract which would, under the Accounting Principles, be treated as a finance or capital lease; |
(ii) |
any advance payment or other trade credit received more than 60 days before the scheduled delivery date for the goods to which it relates; |
(iii) |
any derivative transaction to protect against or benefit from change in any rate or price (and, when calculating the value of any derivative transaction, only the |
Page 5
marked to market value (or the value at close-out or termination, if applicable) shall be considered); |
(i) |
any indebtedness under any guarantee or indemnity for any of the items referred to in any of the paragraphs (a) to (g) above and (i) to (iv). |
Group means the Guarantor and all Subsidiaries and Affiliates of the Guarantor.
Holding Company means, for a company or corporation, any other company or corporation of which it is a Subsidiary.
Insurances has the meaning given to it in Clause 21.7.1(c).
Interest Period means, for a Loan, each period determined under Clause 9 (Interest Periods) and, for an Unpaid Sum, each period determined under Clause 8.3 (Default interest).
Inventory means the Borrower's stock of Commodity from time to time.
Invoice means an invoice, advance payment request or similar instrument acceptable to the Lender relating to an amount that is payable and unpaid by the Borrower to a supplier for goods or services in relating to improvement or exploitation of the Production Facilities.
Legal Opinion means any legal opinion delivered to the Lender under Clause 4 (Conditions of utilisation).
LIBOR means, for any Loan or Unpaid Sum and Interest Period the higher of one and a half per cent (1.5%) and:
(a) |
the applicable Screen Rate; or |
(b) |
(if no Screen Rate is available for that Interest Period) the arithmetic mean (rounded upwards to four decimal places) of the rates, as supplied to the Lender at its request by the Reference Banks in each case at the rate at which the relevant Reference Bank could borrow Dollars in the London interbank market for a period comparable to that Interest Period, were it to do so by asking for and then accepting interbank offers for deposits in reasonable market size, |
as of 11 a.m. on the Quotation Day.
Loan means a loan made or to be made under the Facility or the principal amount outstanding of that loan.
Margin means five and a half per cent (5.5%) per annum.
Material Adverse Effect means, in the opinion of the Lender, a material adverse effect on:
(a) |
any Obligor's ability to comply with any of its obligations under any Finance Document; |
(b) |
the business, financial condition, assets or prospects of any Obligor; or |
(c) |
the validity, enforceability, effectiveness or ranking of any Security granted or expressed to be granted pursuant to any Transaction Security Document; or |
(d) |
the validity or enforceability of the rights or remedies of the Lender under any Finance Document, or of the Borrower under any Export Contract. |
Page 6
Month means a period starting on one day in a calendar month and ending on the numerically corresponding day in the next calendar month, except that:
(b) |
if there is no numerically corresponding day in the calendar month in which that period is to end, that period shall end on the last Business Day in that calendar month; and |
(c) |
if an Interest Period begins on the last Business Day of a calendar month, that Interest Period shall end on the last Business Day in the calendar month in which that Interest Period is to end. |
The above rules (a) to (c) will only apply to the last Month of any period.
Obligor means the Borrower or the Guarantor.
Original Financial Statements means for the Guarantor, its audited consolidated financial statements for its financial year ended 30 November 2010 (including all additional information and notes to those financial statements), together with the relevant directors' report and auditors' reports.
Party means a party to this Agreement.
Permitted Security means any Security falling into one of the categories in Clauses 22.3.3(a) through 22.3.3(g) (Negative pledge).
Petroleum Agreement means any of:
(a) |
the Petroleum Agreement for the Development and Production of Petroleum in Gorisht-Kocul Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; |
(b) |
the Petroleum Agreement for the Development and Production of Petroleum in Delvina Block dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; |
(c) |
the Petroleum Agreement for the Development and Production of Petroleum in Cakran-Mollaj Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; and |
(d) |
the Petroleum Agreement for the Development and Production of Petroleum in Ballsh-Hekal Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower. |
Production Facilities means the facilities of the Borrower used for extracting the Commodity at Delvina Block, Cakran-Mollaj, Ballsh-Hekal Field and Gorisht-Kocul Field.
Production Facilities Contract means any contract under which an Invoice is issued or that relates to Work in Progress.
Quasi-Security means any transaction described in Clause 22.3.2 (Negative pledge).
Quotation Day means, when fixing an interest rate for any period, two Business Days before the first day of that period.
Reference Banks means the principal London offices of Raiffeisen Bank International AG, Barclays Bank PLC and HSBC Bank plc or such other banks as the Lender may select in consultation with the Borrower.
Page 7
Relevant Jurisdiction means any of:
(a) |
any Obligor’s jurisdiction of incorporation; |
(b) |
any jurisdiction where a Security Asset is situated; |
(c) |
any jurisdiction where the Borrower conducts business relating to any Commercial Contract; and |
(d) |
any jurisdiction whose laws govern the perfection of any Transaction Security. |
Repayment Date has the meaning given to it in Clause 6.1 (Repayment of Loans).
Repayment Instalment has the meaning given to it in Clause 6.1 (Repayment of Loans).
Repeating Representations means each of the representations and warranties set out in Clause 18 (Representations and warranties) except the representations and warranties in Clause 18.8 (Deduction of Tax).
Screen Rate means the British Bankers' Association Interest Settlement Rate for Dollars for a period of one year, as displayed on the applicable Reuters page. If the Reuters service stops displaying this rate, the Lender may specify another service displaying it after consulting with the Borrower.
Security means a mortgage, charge, pledge, hypothecation, lien, assignment by way of security, retention of title provision, right of set‑off, trust or flawed asset arrangement (for, or which has the effect of, granting security) or other security interest securing any obligation of any person, whether or not conditional, or any other agreement or arrangement in any jurisdiction having a similar effect.
Security Assets means the assets that are, or are expressed to be, the subject of the Transaction Security.
Security Period means the period starting on the date of this Agreement and ending on the date on which the Lender is satisfied that:
(a) |
the liabilities of all Obligors under the Finance Documents are irrevocably and fully discharged; and |
(b) |
the Lender has no commitment or liability in relation to the Facility. |
Subsidiary means, for a company or corporation, any other company or corporation in or over which that first company or corporation:
(a) |
holds a majority of the voting rights; |
(b) |
is a member and has the right to appoint or remove the majority of the members of the executive body; |
(c) |
has the right to exercise a dominant influence, by virtue of provisions contained in that company or corporation's constitutional documents or in a control contract; |
(d) |
is a member and controls alone, or pursuant to an agreement with other members, a majority of the voting rights. |
Tax means any tax, levy, impost, duty or other charge or withholding of a similar nature (including any penalty or interest payable for any failure to pay or any delay in paying any of the same).
Page 8
Tax Deduction means a deduction or withholding for or on account of Tax from a payment under a Finance Document.
Termination Date means 30 December 2016.
Transaction Security means the Security created or expressed to be created in favour of the Lender under or in accordance with the Transaction Security Documents.
Transaction Security Document means:
(a) |
the Commercial Contracts Security Agreement; |
(b) |
the Equipment and Inventory Security Agreement; and |
(c) |
any other document creating, evidencing or acknowledging Security in favour of the Lender that covers any Obligor's obligations under any of the Finance Documents and is in form and substance satisfactory to the Lender. |
Unpaid Sum means any sum due and payable but unpaid by an Obligor under the Finance Documents.
Utilisation means a utilisation of the Facility.
Utilisation Date means the date of a Utilisation, being the date on which the relevant Loan is made.
Utilisation Request means a notice substantially in the form set out in Schedule 2 (Form of Utilisation Request).
VAT means any turnover tax, sales tax, value added tax and any other tax of a similar nature (however called) imposed in any applicable jurisdiction.
Work in Progress means work progressing on the exploitation or improvement of the Production Facilities in accordance with any Work Plans & Budget.
Work Plans & Budget means an annual work plan and budget that the Borrower has agreed with Albpetrol Sh.A. in connection with one or more of the Petroleum Agreements and that the Lender has approved, such as the Work Plans & Budget for 2012.
1.2.1 |
Unless a contrary indication appears, any reference in any Finance Document to: |
(a) |
assets includes present, future, actual and contingent properties, revenues and rights of every description, whether tangible or intangible (including uncalled share capital); |
(b) |
any bank account is a reference to that account as it may be renumbered, redesignated or replaced and includes any of its sub-accounts from time to time; |
(c) |
a Clause or Schedule is a reference to the relevant clause or schedule to, the Finance Document in which that reference appears; |
(d) |
debt or indebtedness includes any obligation whether incurred as principal or as surety for the payment or repayment of money, whether present or future and whether owed jointly or severally or in any other capacity; |
(e) |
any Finance Document or any other agreement or instrument is a reference to that Finance Document or other agreement or instrument as amended, novated, supplemented, extended, reinstated or replaced from time to time; |
Page 9
(f) |
guarantee means (other than in Clause 17 (Guarantee, indemnity and cash injection undertaking) any guarantee, letter of credit, bond, indemnity or similar assurance against loss, or any obligation, direct or indirect, actual or contingent, to: |
(i) |
buy or assume any indebtedness of; |
(ii) |
make an investment in, or loan to; or |
(iii) |
buy assets of, |
any person where, in each case, that obligation is assumed to support that person or to help that person to meet its indebtedness;
(g) |
the words include, includes, including and in particular shall be construed as being for illustration or emphasis only and shall not be construed as, nor shall they take effect as, limiting the generality of any preceding words; |
(h) |
liability and liabilities includes any obligation whether incurred as principal or as surety, whether or not for indebtedness, whether present or future, actual or contingent and whether owed jointly or severally or in any other capacity; |
(i) |
any person includes any assignee, transferee, successor in title, delegate, sub-delegate or appointee of that person (but, in the case of Parties, only permitted assignees, transferees etc). It also includes any individual, firm, company, corporation, body corporate, government, state or agency of a state or any unincorporated body, association, trust, joint venture, consortium or partnership (whether or not having separate legal personality); |
(j) |
a regulation includes any regulation, rule, official directive, request or guideline (whether or not having the force of law) of any governmental, intergovernmental or supranational body, agency, department or regulatory, self-regulatory or other authority or organisation; |
(k) |
any statute or statutory provision includes: |
(i) |
any statute or statutory provision that amends, extends, consolidates or replaces it; |
(ii) |
any statute or statutory provision that it has amended, extended, consolidated or replaced; and |
(iii) |
any orders, regulations, instruments or other subordinate legislation made under it; |
(l) |
accounting terms shall be construed to be consistent with the relevant Accounting Principles; and |
(m) |
a time of day is a reference to Tirana time. |
1.2.2 |
Section, clause and schedule headings are for ease of reference only. |
1.2.3 |
Unless a contrary indication appears, a term used in any other Finance Document or in any notice given under or in connection with any Finance Document has the same meaning in that Finance Document or notice as in this Agreement. |
1.2.4 |
A Default (other than an Event of Default) is continuing if it has not been remedied or waived in writing and an Event of Default is continuing if it has not been waived in writing. |
1.2.5 |
If it is necessary to decide whether a non‑Dollar amount (either alone or with other amounts) has reached or breached an amount or limit in Dollars, the Lender will calculate the equivalent |
Page 10
in Dollars of that non-Dollar amount using its relevant spot rate of exchange at the relevant time. |
(a) |
change any term of this Agreement; and |
(b) |
rescind, vary, waive, release, assign, novate or otherwise dispose of all or any of their respective rights or obligations under this Agreement, |
without the consent of any person who is not a Party.
Subject to the terms of this Agreement, the Lender makes available to the Borrower a Dollar term loan facility in a total amount equal to the Commitment.
The Borrower shall apply all amounts borrowed by it under the Facility towards capital expenditure for improvement of the Production Facilities.
The Lender is not bound to monitor or verify how the Borrower uses any amount borrowed under this Agreement.
Until the Lender has received all the documents and other evidence listed in Schedule 1 (Conditions precedent) in form and substance satisfactory to it:
(a) |
the Borrower may not deliver a Utilisation Request; and |
(b) |
the Lender shall not be obliged to make available the Facility. |
The Lender will notify the Borrower promptly on being so satisfied.
The Lender will only be obliged to comply with Clause 5.3 (Availability of Loans) if, on the date of the Utilisation Request and on the proposed Utilisation Date:
(a) |
no Default is continuing or would result from the proposed Loan; and |
Page 11
The Borrower may use the Facility by delivering a completed Utilisation Request to the Lender. Delivery must be not later than 11 a.m. on the third Business Day before the proposed Utilisation Date.
Each Utilisation Request is irrevocable and will not be regarded as completed unless:
(a) |
the proposed Utilisation Date is a Business Day within the Availability Period; |
(b) |
the Utilisation is denominated in Dollars; and |
5.3 |
Availability of Loans |
If the conditions set out in this Agreement have been met, the Lender shall make each Loan available by that Loan's Utilisation Date through its Facility Office. Unless the Borrower and the Lender agree otherwise, the Lender will make the Loan available by paying on the Borrower’s behalf the Invoices to which the Loan relates.
5.4 |
Cancellation of unutilised Commitment |
The unutilised portion of the Commitment shall be immediately cancelled at the end of the Availability Period.
The Borrower shall repay the Loans by paying to the Lender:
(a) |
on each date set out in Column 1 below (each a Repayment Date); |
Page 12
(b) |
the amount set out in Column 2 below opposite that date, adjusted to take account of any voluntary prepayment made under Clause 7.3 (Voluntary prepayment of Loans) (each a Repayment Instalment). |
Column 1 Repayment Date |
Column 2 Repayment Instalment ($) |
The last Business Day of each March, June, September and December (except December 2011) falling after (and excluding) the first Utilisation Date and before (and including) the last day of the Availability Period.
|
The lower of (a) the total Loans outstanding; and (b) the amount that is one twentieth of the Commitment rounded up to the nearest $10. |
The last Business Day of each March, June, September and December falling after (and excluding) the last day of the Availability Period and before (and excluding) the Termination Date. |
3/x of the total Loans outstanding at the end of the last day of the Availability Period, rounded up to the nearest $10 where x = the number of Months between the last day of the Availability Period and the Termination Date.
|
The Termination Date |
All Loans then outstanding.
|
6.2 |
Re-borrowing |
If it becomes unlawful anywhere for the Lender to perform any of its obligations under this Agreement or to continue providing any Loan:
(a) |
the Lender must notify the Borrower promptly on realising this; |
(b) |
the Lender notifying the Borrower of this will immediately cancel the Commitment; and |
(c) |
the Borrower must repay the Loans. Repayment must take place on: |
(i) |
the last day of the Interest Period that ends after the Lender notifies the Borrower; or |
(ii) |
if earlier, the date specified by the Lender in its notice (which must be no earlier than the last day of any grace period allowed by law). |
(b) |
the Lender will not be obliged to fund any Utilisation; |
(c) |
if the Lender so notifies the Borrower by not less than 10 days' notice and within 10 days of the Borrower notifying the Lender under Clause 7.2.1(a) above: |
(i) |
the Commitment will be cancelled; and |
Page 13
(ii) |
all outstanding Loans and all other amounts accrued under the Finance Documents will become due and payable. |
7.3.1 |
The Borrower may prepay all or part of the Loans. To do this the Borrower must give the Lender at least 15 Business Days' (or any shorter period the Lender agrees) notice. If it prepays part of the Loans that part must be at least $500,000 and a multiple, of $10,000. |
7.3.2 |
The Borrower may only prepay after the last day of the Availability Period (or, if earlier, the day on which the Available Facility is zero). |
7.3.3 |
Any prepayment under this Clause will be applied across all future Repayment Instalments due under Clause 6.1 (Repayment of Loans) to reduce each of them equally. |
7.4.1 |
Any notice of prepayment given under this Clause 7 will be irrevocable and, unless a contrary indication appears in this Agreement, must state: |
(a) |
the date or dates when the prepayment will happen; and |
(b) |
the amount of that prepayment. |
7.4.2 |
When the Borrower prepays any amount it must at the same time pay: |
(a) |
accrued interest on the amount prepaid; |
(b) |
except if the prepayment is made under Clause 7.1 (Illegality): |
(i) |
any Break Costs; and |
(ii) |
the prepayment fee specified in Clause 11.2 (Prepayment fee). |
7.4.3 |
The Borrower may not re-borrow any part of the Facility it has prepaid. |
7.4.4 |
The Borrower may only repay or prepay all or part of any Loan or cancel all or part of any Commitment as expressly set out in this Agreement. |
The rate of interest on each Loan for each Interest Period is the percentage rate per annum determined by the Lender to be the sum of the applicable:
(a) |
Margin; and |
(b) |
LIBOR. |
Page 14
The Borrower must pay accrued interest on the Loans on the last day of each Interest Period.
8.3.2 |
If any overdue amount consists of all or part of the Loans that became due on a day that was not the last day of an Interest Period: |
(a) |
the first Interest Period for that overdue amount will have a duration equal to the unexpired portion of then current Interest Period for the Loans; and |
(b) |
the rate of interest applying to the overdue amount during that first Interest Period will be two per cent higher than the rate that would have applied if the overdue amount had not become due. |
8.3.3 |
Default interest on an overdue amount (if unpaid) will be compounded with the overdue amount at the end of each Interest Period but will remain immediately due and payable. |
The Lender must promptly notify the Borrower of each rate of interest determined under this Agreement.
9.1.2 |
Each Interest Period for a Loan will end on the first Repayment Date to happen after start date for that Interest Period. No Interest Period for a Loan may extend beyond the Termination Date. |
If an Interest Period would otherwise end on a non-Business Day, it will instead end on:
(a) |
the next Business Day in the same calendar month, if there is one; or |
(b) |
the preceding Business Day, if there is not. |
Page 15
This Clause is subject to Clause 10.2 (Market disruption). If:
(a) |
the Lender must determine LIBOR using quotations from the Reference Banks; and |
(b) |
one Reference Bank does not supply a quotation by 11 a.m. on the Quotation Day, |
the Lender must determine LIBOR using the quotations from the other Reference Banks.
10.2.1 |
If a Market Disruption Event happens and affects a Loan and its Interest Period, the interest rate for that Interest Period will be the percentage rate per annum that is the sum of the: |
(a) |
Margin; and |
(b) |
the cost to the Lender of funding that Loan from whatever source the Lender reasonably selects. |
(a) |
at or about noon on the Quotation Day for the relevant Interest Period the Screen Rate is not available and: |
(i) |
none or only one of the Reference Banks supplies a quotation to the Lender; or |
(ii) |
the Lender decides that, because of circumstances affecting the London interbank market generally, reasonable and adequate means do not exist for finding out LIBOR; or |
(b) |
before close of business in London on the Quotation Day for the relevant Interest Period, the Lender determines that in its opinion: |
(i) |
the cost to it of obtaining matching deposits in the London interbank market would be more than LIBOR; or |
(ii) |
matching deposits may not be available to it in the London interbank market in the ordinary course of business. |
(a) |
a Market Disruption Event happens; and |
(b) |
the Lender or Borrower so wishes, |
the Lender and the Borrower must try (for not more than 30 days) to agree a substitute basis for deciding the rate of interest.
10.3.2 |
If the Lender and the Borrower agree an alternative basis under Clause 10.3.1, the alternative basis will be binding on all Parties. |
Page 16
If:
(a) |
all or part of a Loan or Unpaid Sum is not paid on the last day of its Interest Period; and |
(b) |
the Lender so demands, |
the Borrower must pay to the Lender its related Break Costs.
The Borrower must pay to the Lender an arrangement fee of $100,000 on the earlier of: (a) the first Utilisation Date; and (b) the date that is 30 days after the date of this Agreement.
If the Borrower prepays any of the Facility under Clause 7.3 (Voluntary prepayment of Loans) it must, at the time it makes the prepayment, pay the Lender a prepayment fee of three per cent of the amount prepaid.
12.1.1 |
Each Obligor must make all of its payments under the Finance Documents without any Tax Deduction, unless a Tax Deduction is required by law. |
(a) |
an Obligor has had or will have to make a Tax Deduction; or |
(b) |
there has been or will be any change in the rate, or the basis of calculation, of any Tax Deduction. |
Similarly, the Lender must notify the Borrower on realising that a payment to the Lender has been or will be so affected.
12.1.4 |
If an Obligor must by law make a Tax Deduction, that Obligor must make: |
(a) |
the Tax Deduction; and |
(b) |
any related payment to the relevant tax authority, |
within the time allowed and in the minimum amount required by law.
(a) |
a Tax Deduction; or |
(b) |
a related payment to the relevant tax authority, |
Page 17
the relevant Obligor must deliver to the Lender evidence that it has made the Tax Deduction or related payment. The evidence must be reasonably satisfactory to the Lender.
(a) |
subject to any liability; or |
(b) |
required to make any payment, |
for or on account of Tax in relation to any sum received or receivable (or any sum deemed for Tax purposes to be received or receivable) under any Finance Document. If this happens, the Borrower must pay the Lender, within three Business days of demand, an amount equal to the loss, liability or cost the Lender will suffer or has suffered (directly or indirectly) as a result of that liability or payment. The Lender will determine the amount of its cost, loss or liability in its absolute discretion. The Borrower must pay within three Business Days of demand by the Lender.
(a) |
in relation to any Tax assessed on the Lender under the law of any jurisdiction in which the Lender: |
(i) |
is incorporated; |
(ii) |
is resident for tax purposes; or |
(iii) |
has its Facility Office, in relation to amounts received or receivable in that jurisdiction, |
if that Tax is imposed on, or calculated by reference to, the net income received or receivable (but not any sum deemed to be received or receivable) by the Lender; or
(b) |
to the extent the liability or requirement is compensated for by an increased payment under Clause 12.1 (Tax gross-up). |
12.3 |
Stamp taxes |
The Borrower must indemnify the Lender against any cost, loss or liability the Lender incurs for any stamp duty, registration tax or other similar Tax payable in respect of any Finance Document. The Borrower must pay within three Business Days of demand.
12.4.1 |
All amounts payable to the Lender under a Finance Document are exclusive of VAT. If VAT is chargeable on any supply made by the Lender to another Party under a Finance Document, that Party must, when it pays for the supply, also pay an amount equal to the VAT. |
(a) |
an Obligor must reimburse the Lender for a cost; |
(b) |
the Lender has incurred VAT in respect of that cost; and |
(c) |
the Lender reasonably determines that neither: |
(i) |
it; nor |
Page 18
(ii) |
any other member of any group of which it is a member for VAT purposes, |
is entitled to any credit or repayment from the relevant tax authority for that VAT,
that Obligor must indemnify the Lender against the VAT the Lender has incurred when it pays the reimbursement.
13.1.1 |
This Clause is subject to Clause 13.3 (Exceptions). If the Lender or any of its Affiliates incurs any Increased Costs as a result of: |
(a) |
the introduction of or any change in (or in the interpretation, administration or application of) any law or regulation; |
(b) |
compliance with any law or regulation relating to capital adequacy; or |
(c) |
compliance with any other law or regulation made after the date of this Agreement, |
the Borrower must, within three Business Days of demand by the Lender, pay the Lender an amount equal to those Increased Costs.
13.1.2 |
Increased Costs means: |
(a) |
a fall in the rate of return from the Facility or on the Lender's (or its Affiliate's) overall capital; |
(b) |
an extra or increased cost; or |
(c) |
a reduction of any amount due and payable under any Finance Document, |
that:
(i) |
the Lender or any of its Affiliates incurs or suffers; and |
(ii) |
is attributable to the Lender having entered into the Commitment or funding or performing its obligations under any Finance Document. |
13.2.1 |
If the Lender intends to make a claim under Clause 13.1, it must, as soon as practicable: |
(a) |
notify the Borrower of the event giving rise to the claim; and |
(b) |
provide the Borrower with a certificate of its Increased Costs. |
Clause 13.1 (Increased Costs) does not apply to the extent any Increased Cost is:
(a) |
attributable to a Tax Deduction the Borrower must by law make; |
(b) |
compensated for by Clause 12.2 (Tax indemnity) (or would have been had Clause 12.2.2 not applied); or |
(c) |
attributable to the wilful breach by the Lender or its Affiliates of any law or regulation. |
Page 19
14.1.1 |
If it is necessary to convert any: |
(a) |
sum due from an Obligor under the Finance Documents (a Sum); or |
(b) |
order, judgment or award given or made in relation to a Sum, |
from the currency (the First Currency) in which that Sum is payable into another currency (the Second Currency) to:
(i) |
make or file a claim or proof against that Obligor; or |
(ii) |
obtain or enforce an order, judgment or award, |
that Obligor must indemnify the Lender against any cost, loss or liability arising from the conversion. That cost, loss or liability may include any difference between:
(aa) |
the rate of exchange used to convert that Sum from the First Currency into the Second Currency; and |
(bb) |
the rate or rates of exchange available to the Lender when it receives that Sum. |
That Obligor's obligation under this Clause is independent of its obligation to pay the original Sum and must be satisfied within three Business Days of demand.
14.1.2 |
Each Obligor waives any right it may have in any jurisdiction to pay any amount in a currency other than that in which it is payable under the Finance Documents. |
The Borrower must indemnify the Lender against any cost, loss or liability the Lender incurs because of:
(a) |
an Event of Default; |
(b) |
the Lender relying on any notice, request or instruction appearing to be from an Obligor that the Lender reasonably believes is genuine, correct and properly authorised; |
(c) |
any Obligor failing to pay when due any amount payable under a Finance Document; |
(e) |
the Lender exercising any right, power, discretion or remedy vested in the Lender by the Finance Documents or by law; |
(f) |
the Lender funding, or arranging to fund, a Loan that: |
(i) |
the Borrower requested in a Utilisation Request; and |
(ii) |
was not made, not solely because of default or negligence by the Lender, but because of one or more of the provisions of this Agreement operating; or |
(g) |
all or part of a Loan not being prepaid in accordance with a notice of prepayment from the Borrower. |
Page 20
The Borrower must satisfy its obligation under this Clause within three Business Days of demand.
(a) |
Clause 7.1 (Illegality); |
(b) |
Clause 12 (Tax gross-up and indemnities); or |
(c) |
Clause 13 (Increased Costs), |
the Lender will, in consultation with the Borrower, take all reasonable steps to mitigate the effects of this, including transferring its rights and obligations under the Finance Documents to an Affiliate or another Facility Office.
15.1.2 |
Clause 15.1.1 does not in any way limit the obligations of any Obligor under the Finance Documents. |
15.2.1 |
The Borrower must indemnify the Lender for all costs the Lender reasonably incurs taking steps under Clause 15.1. |
15.2.2 |
The Lender is obliged to take any steps under Clause 15.1 that it thinks (acting reasonably) might be disadvantageous to it. |
The Borrower must, promptly on demand, pay all costs (including legal fees) the Lender reasonably incurs negotiating, preparing, printing, executing, syndicating or perfecting the Finance Documents or the Lender taking, holding or protecting the Transaction Security.
This Clause applies if any Obligor asks for an amendment, waiver or release of, or consent under, any Finance Document. The Borrower must, within three Business Days of demand, pay all costs (including legal fees) the Lender reasonably incurs responding to, evaluating, negotiating or complying with that Obligor's request.
The Borrower must, within three Business Days of demand, pay to the Lender all costs (including legal fees) the Lender incurs:
(a) |
looking into any possible Default; |
(b) |
enforcing or preserving the Transaction Security or any other rights under the Finance Documents; or |
(c) |
taking or defending any proceedings involving the Lender that relate to the Transaction Security or any Finance Document. |
Page 21
For the benefit of the Lender, the Guarantor irrevocably and unconditionally:
(a) |
guarantees punctual performance by the Borrower of the Borrower's obligations under the Finance Documents; |
(b) |
undertakes, if the Borrower does not pay an amount when expressed to be due under any Finance Document, immediately on demand to pay that amount as if it were the principal obligor; and |
17.2 |
Cash injection undertaking |
17.2.1 |
The Guarantor undertakes to comply, within 30 days, with any request by the Lender to provide a cash injection of Dollars to the Borrower and in particular to its Albanian branch. The Guarantor may make the cash injection by means of equity, a loan or any other method acceptable to the Lender. If the cash injection is made by a loan that loan must be subordinated in accordance with Clause 22.1.1(d). |
17.2.2 |
Any request the Lender makes under this Clause must specify the amount of the cash injection, which may be no more than any of: |
(a) |
the total amount outstanding (including accrued interest) under the Finance Documents at that time; and |
(b) |
the Lender's reasoned estimate of the Borrower's Cashflow Shortfall during the period from the date of the Lender's request to second Repayment Date to occur after the date of that request. |
For the purposes of this Clause, the Borrower's Cashflow Shortfall for any period means the amount (if any) by which the Borrower's predicted expenditures exceed its predicted revenues for that period, as determined by the Lender on the basis of the financial information the Borrower supplies to it under Clause 19.7 (Production information) and any other relevant information the Lender receives under Clause 19.4(c) or otherwise.
17.2.3 |
If the Guarantor does not wish to comply with any request the Lender makes under this Clause, the Guarantor may prepay the Loans in accordance with Clause 7.3 (Voluntary prepayment of Loans). |
The guarantee in this Clause is:
(a) |
a continuing guarantee and will extend to the ultimate balance of sums payable by the Borrower under the Finance Documents, regardless of any intermediate payment or discharge in whole or in part; and |
Page 22
(b) |
is in addition to, is not in any way prejudiced by, and shall not merge with, any other guarantee or Security now or in the future held by the Lender. |
If any:
(a) |
discharge; |
(b) |
release; |
(c) |
accounting; or |
(d) |
arrangement, |
(whether in respect of the obligations of the Borrower or any Security for those obligations or otherwise) is made by the Lender in whole or in part on the basis of any:
(i) |
payment; |
(ii) |
security; |
(iii) |
recovery; or |
(iv) |
other disposition, |
that is avoided or must be restored in insolvency, liquidation, administration or otherwise,
then the liability of the Guarantor under this Clause will continue or be reinstated as if that discharge, release, accounting or arrangement had not occurred.
The obligations of the Guarantor under this Clause will not be affected by an act, omission, matter or thing (whether or not known to it or the Lender) that, but for this Clause, would reduce, release or prejudice any of them, including:
(a) |
any time, waiver or consent granted to the Borrower or any other person; |
(b) |
the release of the Borrower or any other person under the terms of any composition or arrangement with any creditor of any person; |
(c) |
the taking, variation, compromise, exchange, renewal, enforcement or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or Security over assets of, the Borrower or any other person; |
(d) |
any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any Transaction Security; |
(e) |
any incapacity or lack of power, authority or legal personality of, or dissolution or change in the constitution, members or status of, the Borrower or any other person; |
(f) |
any amendment, novation, supplement, extension, replacement, assignment, avoidance or termination of any Finance Document or any other document or Transaction Security, in each case however fundamental and whether or not more onerous including any change in the purpose of, any extension of or any increase in, any facility, or the addition of any new facility; |
Page 23
(g) |
any unenforceability, illegality or invalidity of any obligation of, or any Transaction Security or any other Security; or |
(h) |
any insolvency, liquidation, administration or similar procedure. |
Without prejudice to the generality of Clause 17.5 (Waiver of defences), the Guarantor expressly confirms that it intends that this guarantee shall extend from time to time to any (however fundamental) variation, increase, extension or addition of or to any of the Finance Documents and any facility or amount made available under any of the Finance Documents for the purposes of or in connection with any of the following:
(a) |
acquisitions of any nature; |
(b) |
increasing working capital; |
(c) |
enabling investor distributions to be made; |
(d) |
carrying out restructurings; |
(e) |
refinancing existing facilities; |
(f) |
refinancing any other indebtedness; |
(g) |
any other variation or extension of the purposes for which any such facility or amount might be made available from time to time; and |
(h) |
any fees, costs and expenses associated with any of the foregoing. |
17.7 |
Immediate recourse |
The Guarantor waives any right it may have of first requiring the Lender (or any trustee or agent on its behalf) to proceed against or enforce any other rights or Security or claim payment from any person before claiming from the Guarantor under this Clause. This waiver applies irrespective of any law or any provision of a Finance Document to the contrary.
During the Security Period, the Lender may:
(a) |
refrain from applying or enforcing any other moneys, Security or rights held or received by it (or any trustee or agent on its behalf) for amounts that may be or become payable by the Borrower under the Finance Documents, or apply and enforce the same in such manner and order as it sees fit (whether against those amounts or otherwise) and the Guarantor will not be entitled to the benefit of the same; and |
(b) |
hold in an interest-bearing suspense account any moneys received from the Guarantor or on account of the Guarantor's liability under this Clause 17. |
(a) |
receive or claim payment from or be indemnified by the Borrower; |
Page 24
(b) |
claim any contribution from any other guarantor of, or provider of Security for, the Borrower's obligations under the Finance Documents; |
(c) |
take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Lender under any Finance Document or of any guarantee or Security taken pursuant to, or in connection with, the Finance Documents by the Lender; |
(e) |
exercise any right of set-off against the Borrower; or |
(f) |
claim or prove as a creditor of the Borrower in competition with the Lender. |
17.9.2 |
If the Guarantor receives any benefit, payment or distribution in relation to any rights referred to in Clause 17.9.1 it shall hold that benefit, payment or distribution on trust for the Lender and shall promptly pay or transfer the same to the Lender or as the Lender may direct for application in accordance with Clause 26 (Payment mechanics). The Guarantor must comply with this Clause only to the extent necessary to enable all amounts which may be or become payable to the Lender by the Borrower under or in connection with the Finance Documents to be repaid in full. |
During the Security Period, the Guarantor must not take, or retain, any Security from the Borrower or any other person in connection with any of the Guarantor's liabilities under this Agreement without the consent of the Lender.
17.11 |
Interest provisions applicable to the Guarantor |
17.11.1 |
For the purposes of the Interest Act (Canada) and disclosure under it, the rates of interest under this Agreement are nominal rates, and not effective rates or yields. The principle of deemed reinvestment of interest does not apply to any interest calculation under this Agreement. |
17.11.2 |
Any provision of this Agreement that would oblige the Guarantor to pay any fine, penalty or rate of interest on any arrears of principal or interest secured by a mortgage on real property or hypothec on immovables that has the effect of increasing the charge on arrears beyond the rate of interest payable on principal money not in arrears shall not apply to the Guarantor. In this case, the Guarantor shall be required to pay interest on money in arrears at the same rate of interest payable on principal money not in arrears. |
17.11.3 |
If any provision of this Agreement would oblige the Guarantor to make any payment of interest or other amount payable to the Lender in an amount or calculated at a rate that would be prohibited by Canadian law or would result in a receipt by the Lender of "interest" at a "criminal rate" (as such terms are construed under the Criminal Code (Canada)), then, notwithstanding that provision, that amount or rate shall be deemed to have been adjusted with retroactive effect to the maximum amount or rate of interest, as the case may be, as would not be so prohibited by applicable law or so result in a receipt by the Lender of "interest" at a "criminal rate", such adjustment to be effected, to the extent necessary (but only to the extent necessary), as follows: |
(a) |
first, by reducing the amount or rate of interest; and |
(b) |
thereafter, by reducing any fees, commissions, costs, expenses, premiums and other amounts required to be paid that would constitute interest for purposes of section 347 of the Criminal Code (Canada). |
Page 25
Each Obligor warrants and represents to the Lender as set out in this Clause 18. The Lender is relying on these representations when entering this Agreement.
18.1.1 |
The Borrower is an exempted company duly incorporated with limited liability under the laws of the Cayman Islands and the Guarantor is a company duly incorporated under the laws of the province of British Columbia, Canada and each is duly organised and validly existing and in good standing under the laws of its jurisdiction of incorporation. |
18.1.2 |
It has the power to: |
(a) |
sue and be sued in its own name; |
(b) |
own its assets; and |
(c) |
carry on its business as it is doing currently. |
18.2 |
Binding obligations |
Subject to any general principles of law limiting its obligations that are specifically mentioned in any Legal Opinion:
(a) |
each Transaction Security Document creates the Security that Transaction Security Document purports to create and that Security is valid and effective in each Relevant Jurisdiction; and |
(b) |
the obligations expressed to be assumed by it in each Finance Document are legal, valid, binding and enforceable. |
18.3 |
Non-conflict with other obligations |
Its entry into and performance of, and the transactions contemplated by, the Finance Documents, and the granting of the Transaction Security, do not and will not conflict with:
(a) |
any law or regulation applicable to it or any of its assets; |
(b) |
its constitutional documents; or |
(c) |
any agreement or instrument binding on it or any of its assets or trigger a default or termination event (however described) under any such agreement or instrument. |
18.4 |
Power and authority |
18.4.1 |
It has the power to: |
(a) |
enter into, execute, deliver and perform its obligations under the Finance Documents; and |
(b) |
carry out its role in the transactions contemplated by them, |
and all corporate, shareholder and other action necessary to authorise that entry into, execution, delivery and performance has been taken.
Page 26
18.4.2 |
In the case of the: |
(a) |
Borrower, borrowing the Commitment, granting the Transaction Security and giving the indemnities it gives under the Finance Documents will not exceed any limit on its powers; and |
(b) |
Guarantor, guaranteeing the Commitment and giving the indemnities it gives under this Agreement will not exceed any limit on its powers. |
18.5.1 |
It has obtained or effected all Authorisations required or desirable in any Relevant Jurisdiction: |
(a) |
for it lawfully to enter into, and exercise its rights and perform its obligations under the Finance Documents and, in the case of the Borrower, the Commercial Contracts; |
(b) |
to make the Finance Documents and, in the case of the Borrower, the Commercial Contracts admissible in evidence; and |
(c) |
for it to carry on its business, trade and ordinary activities, |
and these are in force.
18.6 |
Governing law and enforcement |
18.6.1 |
The choice of governing law of each Finance Document will be recognised and enforced in each Relevant Jurisdiction. |
18.6.2 |
Any arbitral award obtained in relation to a Finance Document in the jurisdiction of the governing law chosen for that Finance Document (i.e. England and English law for this Agreement) will be recognised and enforced in each Relevant Jurisdiction. |
18.6.3 |
The Transaction Security is enforceable in each Relevant Jurisdiction and will be recognised as giving the Lender secured creditor status over the assets to which it relates. |
It has not taken any action nor (to the best of its knowledge and belief) have any steps been taken or legal proceedings been started or threatened against it:
(a) |
for its winding-up, dissolution or re-organisation; |
(c) |
to appoint a liquidator, supervisor, receiver, administrator, administrative receiver, compulsory manager, trustee or other similar officer of it or over any of its assets, |
nor (to the best of its knowledge and belief) have any of these events occurred in relation to any Buyer under an Export Contract.
It is not required to make any deduction for or on account of Tax from any payment it may make under any Finance Document.
Page 27
18.9 |
No filing or stamp taxes |
(a) |
file, record or enrol any of the Finance Documents with any court or other authority; or |
(b) |
pay any stamp, registration or similar Tax on or in relation to any of the Finance Documents or the transactions contemplated by them, |
in any Relevant Jurisdiction.
18.10 |
Compliance with Tax laws |
In all jurisdictions in which it is subject to Tax:
(a) |
it has complied with all Tax laws; |
(b) |
it has paid all Taxes due and payable by it; and |
(c) |
no claims for Tax are being asserted against it except: |
(i) |
for Tax liabilities arising in the ordinary course of its day-to-day trading activities; and |
(ii) |
claims it is contesting in good faith where it has made adequate provision for these claims and has disclosed this provision to the Lender in its latest financial statements or some other document. |
18.11 |
No default |
18.11.1 |
No Event of Default is continuing or might reasonably be expected to result from any Utilisation. |
18.11.2 |
No other event or circumstance is outstanding that is likely to have a Material Adverse Effect and that: |
(a) |
is a default or termination event (however described); or |
(b) |
would, with any one or more of the following, be a default or termination event (however described): |
(i) |
the expiry of a grace period; |
(ii) |
the giving of notice; |
(iii) |
the making of any determination; or |
(iv) |
the satisfaction of any other condition, |
under any agreement or instrument (other than a Finance Document) binding on it or any of its assets.
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18.12 |
No misleading information |
18.12.1 |
All factual information provided by or for it in writing in connection with the Facility or any Finance Document: |
(a) |
was accurate in all material respects when provided or as at the date (if any) at which it is stated; and |
(b) |
remains accurate (to the extent that no corrections have been notified in writing to the Lender by or for it). |
18.12.2 |
There is no fact or circumstance about its affairs that has not been disclosed in writing to the Lender where that non-disclosure makes any of that information misleading. |
18.12.3 |
All expressions of expectation, intent, belief and opinion in any of that information were honestly made on reasonable grounds after careful consideration. |
18.13 |
Full disclosure |
It has fully disclosed in writing to the Lender all facts about itself, the Production Facilities and the Commercial Contracts that:
(a) |
it knows or reasonably should know; and |
(b) |
are material for disclosure to the Lender in the context of the Finance Documents. |
18.14 |
Financial statements |
18.14.1 |
The Guarantor’s Original Financial Statements were prepared using the relevant Accounting Principles consistently applied. |
18.14.2 |
The Guarantor’s Original Financial Statements fairly represent its (or, in the case of the Guarantor, the Group's) financial condition and operations as at the end of and for the relevant financial year. |
18.14.3 |
There has been no material adverse change in its business, financial condition, assets or prospects since 30 November 2010. |
18.14.4 |
Each set of management accounts it most recently delivered under Clause 19.1(b) or 19.1(c) shows with reasonable accuracy its financial condition during the period to which they relate. |
18.15 |
Ranking |
18.15.1 |
Its payment obligations under the Finance Documents rank at least equally with the claims of all its unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally. |
18.15.2 |
The Transaction Security has or will have first ranking priority and it is not subject to any higher- or equal-ranking Security. |
18.16 |
No proceedings pending or threatened |
18.16.2 |
No judgment or award given against it by any court, tribunal, arbitral or other body or agency remains unsatisfied. |
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18.16.3 |
To the best of its knowledge and belief nothing mentioned in Clause 18.16.1 or 18.16.2 applies to any Buyer under an Export Contract. |
18.17.1 |
Neither its execution of the Finance Documents, nor it exercising its rights or performing its obligations under them, will trigger the creation of, or any obligation to create, any Security (other than the Transaction Security) over any of its assets. |
18.17.2 |
In the case of the Borrower only, no Security other than Permitted Security exists or will come into existence over any of its assets. |
18.18.1 |
The Borrower is complying with Clause 21.6 (Environmental compliance). |
18.18.2 |
It has every Environmental Permit required under Environmental Law to: |
(a) |
conduct its business; or |
(b) |
own, use, exploit or occupy its assets, |
and it is not aware of anything that would entitle the relevant issuing body to revoke, suspend, or unfavourably change any of those Environmental Permits.
18.18.3 |
There is no Environmental Claim outstanding or (to the best of its knowledge and belief) threatened against it that has, or if determined against it is reasonably likely to have, a Material Adverse Effect. |
18.19.1 |
No Security or Quasi-Security exists over any of its assets other than as allowed under the Finance Documents. |
18.19.2 |
It has no Financial Indebtedness outstanding other than as allowed under the Finance Documents. |
18.20.1 |
It has a good, valid and marketable title to, or valid leases or licences of, and all necessary Authorisations to use, the assets it needs to carry on its business as now conducted. |
18.20.2 |
Ignoring any rights the Lender may have under the Transaction Security, the Borrower is the sole legal and beneficial owner of any and all the Security Assets. |
18.21 |
Commodity Contracts |
18.21.1 |
Each Commodity Contract: |
(a) |
constitutes the legal, valid and binding obligations of the parties to it; |
(b) |
is enforceable in accordance with its terms and is in force; and |
(c) |
has not been terminated or varied except as expressly allowed under the Finance Documents. |
18.21.2 |
All amounts expressed to be payable under each Commodity Contract are payable in full on the dates stated in that contract. |
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18.21.3 |
There are no written or oral agreements or arrangements between it and any Buyer under any Commodity Contract that derogate from the obligations of that Buyer under any Commodity Contract. |
18.22 |
Force majeure |
It is not aware of any existing event, fact or circumstance that constitutes a force majeure (however named or described) under any Commodity Contract.
The Borrower has the technical and financial abilities and the Production Facilities have the production capacity necessary for the Borrower to fulfil its obligations under the Commodity Contracts.
The representations in this Clause 18 will survive the execution of this Agreement. Each Obligor is deemed to repeat the Repeating Representations on:
(a) |
the date of each Utilisation Request; and |
(b) |
the first day of each Interest Period, |
by reference to the facts and circumstances then existing.
The undertakings in this Clause 19 remain in force until the Security Period ends.
The Guarantor must supply to the Lender as soon as they become available but in any event within:
(a) |
120 days after the end of each of its financial years, its audited and consolidated financial statements for that financial year; |
(b) |
60 days after the end of each half of each of its financial years, its consolidated financial statements for that half of its financial year; |
(c) |
60 days after the end of each of its financial quarters, its consolidated management accounts for that financial quarter, |
in each case, in form and substance satisfactory to the Lender.
19.2.1 |
A director or the chief financial officer of the Guarantor must certify each set of financial statements delivered under Clause 19.1 (Financial statements). The certification must confirm that the consolidated financial statements fairly represent the Guarantor's consolidated financial condition and operations as at the end of, and for the period to which, those financial statements relate. |
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19.2.2 |
The Guarantor must procure that each set of financial statements it delivers under Clause 19.1 (Financial statements) is prepared using: |
(a) |
the relevant Accounting Principles; and |
(b) |
subject to Clause 19.2.3, accounting practices and financial reference periods consistent with those used to prepare its Original Financial Statements. |
(a) |
notify the Lender of this; and |
(b) |
procure that its auditors deliver to the Lender a description of the differences. The description must contain enough information to enable the Lender to make an accurate comparison between the financial positions shown in those financial statements and the Original Financial Statements. It must be delivered before or when those financial statements are delivered under Clause 19.1 (Financial statements). |
19.3 |
Notice of Orders |
The Borrower undertakes to provide the Lender with a copy of any Order (as defined below) it receives if complying with that Order will have or is likely to have a Material Adverse Effect. In this Clause Order means any notice, order, claim or other requirement from a regulatory body, court or third party. If the Borrower must provide the Lender with an Order it will provide it, together with relevant background information, within five Business Days of receiving the Order.
19.4 |
Information: miscellaneous |
Each Obligor must supply to the Lender:
(a) |
all documents sent by that Obligor to its: |
(i) |
shareholders (or any class of them) in their shareholder capacity; or |
(ii) |
creditors generally, |
at the same time as they are sent;
(b) |
promptly on becoming aware of them, details of: |
(i) |
any litigation, arbitration or administrative proceedings or Environmental Claim that is current, threatened or pending against any Obligor; and |
(ii) |
any event or circumstance that is reasonably likely to result in litigation, arbitration or administrative proceedings or an Environmental Claim being started or threatened against any Obligor, |
that, if determined against that Obligor, would be reasonably likely to have a Material Adverse Effect; and
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19.5 |
Notification of default |
19.5.1 |
The Borrower must notify the Lender of any Default (and the steps, if any, being taken to remedy it) promptly on realising it has happened. |
19.5.2 |
If the Lender so requests, the Borrower must promptly provide a certificate signed by two of its directors or senior officers. The certificate must confirm that no Default is continuing (or if a Default is continuing, specify the Default and the steps, if any, being taken to remedy it). |
19.6 |
"Know your customer" checks |
Each Obligor must when asked promptly supply, or procure the supply of, any documentation and other evidence the Lender reasonably considers it needs to comply with all "know your customer" or other similar checks in connection with the Finance Documents.
19.7.1 |
The Borrower undertakes to send to the Lender, within 10 Business Days of the end of each of its financial quarters: |
(a) |
a consignment schedule setting out the quantity, specification and invoice value of: |
(i) |
the Consignments delivered under the Export Contracts during that financial quarter; |
(ii) |
the consignments of Commodity delivered under the other Commodity Contracts during that financial quarter; |
(iii) |
the Consignments scheduled to be delivered under the Export Contracts during the financial quarter immediately following that financial quarter; and |
(iv) |
the consignments of Commodity scheduled to be delivered under the other Commodity Contracts during the financial quarter immediately following that financial quarter; |
(b) |
a stock report setting out: |
(i) |
the quantity and specification of the Inventory as at the last day of that financial quarter; |
(ii) |
the total quantity and specification of Commodity delivered under Commodity Contracts during that financial quarter; |
(iii) |
the estimated total quantity and specification of Commodity to be delivered under Commodity Contracts during the financial quarter immediately following that financial quarter; and |
(iv) |
the quantity of Commodity extracted from the Production Facilities during that financial quarter; |
(v) |
the estimated quantity of Commodity that will be extracted from the Production Facilities during the financial quarter immediately following that financial quarter. |
19.7.2 |
The Borrower undertakes to send to the Lender, each calendar year during the Security Period on or before 15 March, a Crude Oil Reserve Report. |
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19.8 |
Change of shareholder structure |
The Obligors undertake to ensure that the Lender receives at least 15 Business Days' (or such shorter period as the Lender agrees) notice of any change in the structure of the Borrower's issued shares including any new issue of shares, any reduction in the Borrower's issued share capital and any change in the rights attaching to any shares in the Borrower or any rights in them.
The undertakings in this Clause remain in force until the Security Period ends.
In this Agreement the following definitions apply. Any financial terms used in this Agreement in connection with the Borrower that are not defined in this Agreement must, unless otherwise indicated, be interpreted in accordance with the Tax Authority Principles.
Borrowings means, at any time, the aggregate outstanding principal, capital or nominal amount (and any fixed or minimum premium payable on prepayment or redemption) of any indebtedness of the Borrower for or in respect of:
(b) |
any acceptances under any acceptance credit or bill discount facility (or dematerialised equivalent); |
(c) |
any note purchase facility or the issue of bonds, notes, debentures, loan stock or any similar instrument; |
(d) |
any Finance Lease; |
(e) |
receivables sold or discounted (other than any receivables to the extent they are sold on a non-recourse basis); |
(f) |
any counter-indemnity obligation in respect of a guarantee, bond, standby or documentary letter of credit or any other instrument issued by a bank or financial institution at the Borrower's request; |
(g) |
any amount raised by the issue of shares which are redeemable (other than at the option of the issuer); |
(h) |
any amount of any liability under an advance or deferred purchase agreement if (i) one of the primary reasons behind the entry into the agreement is to raise finance or to finance the acquisition or construction of the asset or service in question or (ii) the agreement is in respect of the supply of assets or services and payment is due more than 90 days after the date of supply; |
(j) |
(without double counting) the amount of any liability in respect of any guarantee or indemnity for any of the items referred to in paragraphs (a) to (i) above. |
EBIT means, in respect of any Relevant Period, the operating profit of the Borrower before taxation:
(a) |
before deducting any Finance Charges; |
Page 34
(b) |
not including any accrued interest owing to the Borrower; |
(c) |
before taking into account any Exceptional Items; and |
(d) |
before taking into account any realised and unrealised exchange gains and losses that do not relate to ordinary trading activities, |
in each case, to the extent added, deducted or taken into account, as the case may be, for the purposes of determining operating profits of the Borrower before taxation.
EBITDA means, in respect of any Relevant Period, EBIT for that Relevant Period after adding back any amount attributable to the amortisation or depreciation of non-current assets of the Borrower.
Exceptional Items means any exceptional, one off, non-recurring or extraordinary items.
Finance Charges means, for any Relevant Period, the total amount of the accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments in respect of Borrowings whether paid or payable by the Borrower in respect of that Relevant Period and all other amounts payable that are classified as finance charges under the Tax Authority Principles:
(a) |
including any upfront fees or costs; |
(b) |
including the interest (but not the capital) element of payments in respect of Finance Leases; |
(c) |
including any commission, fees, discounts and other finance payments payable by (and deducting any such amounts payable to) the Borrower under any interest rate hedging arrangement; |
(d) |
(if not already taken into account) deducting the net amount receivable or adding the net amount payable by the Borrower in relation to that Relevant Period under any hedging agreement relating to financing and excluding amounts included in the profit and loss account which represent changes in the value of derivatives relating to cash flows in future periods; and |
(e) |
taking no account of any unrealised gains or losses on any a hedge item recognised in profit or loss arising from its accounting treatment as a hedge item in a fair value hedge as defined by IAS 39, |
so that no amount shall be added (or deducted) more than once.
Finance Lease means any lease, hire agreement, credit sale agreement, hire purchase agreement, conditional sale agreement or instalment sale and purchase agreement that should be treated as a finance lease or in the same way as a finance lease under the Tax Authority.
IAS together with a number means the international accounting standard issued by the Board of the International Accounting Standards Committee and adopted by the International Accounting Standards Board and identified by reference to that number.
Relevant Period means:
(a) |
a period of 12 months starting no earlier than 1 January 2012 and ending on the date as at which the Borrower prepares a balance sheet for submission to the Tax Authority each year; or |
Page 35
(b) |
any other period of 12 months that the Lender specifies in a request it makes under Clause 20.3.3. |
Tax Authority means the tax authority responsible for corporate taxation in Albania.
Tax Authority Principles means the accounting principles, concepts, bases and policies in accordance with which the Tax Authority requires the Albanian branches of non-Albanian companies to provide fiscal data to it on an annual basis, or, in the absence of any such applicable accounting principles, concepts, bases and policies, the International Financial Reporting Standards issued or adopted by the International Accounting Standards Board.
The Borrower will ensure that during each Relevant Period, unless the Lender otherwise agrees:
(a) |
its EBITDA is not less than $10,000,000; |
(b) |
its Borrowings are never more than twice its EBITDA; and |
(c) |
its EBITDA is at least ten times greater than its Finance Charges. |
(a) |
when it receives approval from the Tax Authority; or |
(b) |
if the Tax Authority queries or disagrees with any. |
of the fiscal data the Borrower has filed. If the fiscal data the Tax Authority approves is different to the fiscal data originally filed by the Borrower and delivered to the Lender, the Lender will re-test compliance with the financial covenants set out in Clause 20.2 (Financial covenants) using the fiscal data the Tax Authority approved.
The undertakings in this Clause 21 remain in force until the Security Period ends.
21.1 |
Authorisations |
The Borrower undertakes to obtain, comply with and maintain in force, and when asked promptly to supply Certified Copies to the Lender of, any Authorisation required in any Relevant Jurisdiction to:
(a) |
carry on its business, trade or ordinary activities; |
Page 36
(b) |
exercise its rights or perform its obligations under any Finance Document or Commercial Contract; or |
(c) |
make any Finance Document or Commercial Contract admissible in evidence. |
21.2 |
Compliance with laws |
The Borrower undertakes to comply in all respects with all laws to which it may be subject, if failure to do so would materially impair its ability to perform its obligations under the Finance Documents or any Commercial Contract.
21.3.1 |
This undertaking is subject to Clause 21.3.2. The Borrower undertakes to pay all Taxes and governmental charges payable by it before they become overdue. |
(a) |
are being contested in good faith; and |
(b) |
may lawfully be withheld, |
and for which the Borrower has set aside adequate reserves.
21.4 |
Access |
The Borrower undertakes to allow:
(a) |
the Lender; and |
(b) |
any person that is an accountant, auditor, solicitor, valuer or other professional adviser of the Lender, |
access, during normal business hours and on reasonable notice to:
(i) |
the Production Facilities; |
(ii) |
all other property and premises of the Borrower; and |
(iii) |
all officers, accounting books, records, computer programs and other data or information of the Borrower, |
to the extent reasonably necessary to monitor the Borrower's compliance with, and performance under, the Finance Documents or any Commercial Contract.
21.5 |
Further assurance |
The Borrower undertakes, when asked by the Lender, to:
(a) |
do or procure the doing of all things; and |
(b) |
execute or procure the execution of all documents, |
the Lender considers necessary or desirable (acting reasonably) to ensure the Lender obtains all the rights and benefits intended to be conferred on it under the Finance Documents.
Page 37
The Borrower undertakes to:
(a) |
comply in all material respects with Environmental Law; |
(b) |
obtain, maintain and comply with all Environmental Permits required to conduct its business or to own, use, exploit or occupy its assets; and |
(c) |
have in place procedures to check compliance with and to prevent liability under Environmental Law. |
(a) |
insure all its assets and business of an insurable nature with reputable insurers of good standing; |
(b) |
comply with all insurance conditions imposed by any lease, agreement for lease or tenancy under which the Borrower derives an interest; |
(i) |
are on the same terms and cover the same risks as those normally taken out by prudent companies owning or possessing similar assets and carrying on similar businesses to the Borrower's; and |
(ii) |
are in such amounts as is prudent (including for the full replacement value from time to time of any assets destroyed or otherwise becoming a total loss); |
(d) |
where the assets in question are Security Assets, ensure the Lender is endorsed on the policies as loss payee; |
(e) |
pay when due all premiums and other amounts payable under the Insurances and, promptly when asked by the Lender, produce receipts for payment of the premiums; |
(f) |
promptly when asked by the Lender, deposit with or produce for inspection to the Lender all policies and other contracts for the Insurances; and |
(g) |
use reasonable endeavours to prevent any act, omission or circumstance that would be reasonably likely to render void or voidable any of the Insurances. |
The Borrower undertakes to maintain full ownership and control over the management and operation, of the Production Facilities.
Page 38
For each Export Contract, the Borrower undertakes to present all Consignment Documents to the Buyer (or the Buyer's bank, or the relevant issuing or confirming bank) via the Lender.
The Borrower undertakes to notify the Lender immediately on realising that a material quantity of Commodity in a Consignment:
(a) |
is destroyed, lost, stolen or damaged in any way; or |
(b) |
does not meet the specification required by the relevant Export Contract, |
and, if appropriate, to file a claim under any relevant insurance policy and keep the Lender informed about that claim.
The Borrower undertakes to perform, when due or within any applicable grace periods, its obligations and enforce its rights (including by taking legal proceedings where appropriate) under:
(a) |
each Export Contract; and |
(b) |
each other contract, agreement, instrument or other document to which it is a party, including any concessions, leases, licences and customer contracts where the failure to so perform or enforce would be likely to have a Material Adverse Effect. |
The Borrower undertakes to ensure that each Buyer pays all amounts payable by that Buyer under any Commodity Contract pursuant to an invoice issued after the date of this Agreement:
(a) |
directly to a bank account held with the Lender in the name of the Borrower; and |
(b) |
in full and without any set‑off, deduction, counterclaim or condition. |
If the Lender notifies the Borrower that:
(a) |
in the Lender's opinion; |
(b) |
for whatever reason (be it breach of contract, reduction in the price of Commodity or otherwise); and |
(c) |
there is a risk that the payments for the Consignments to be delivered under the Export Contracts will not be enough to satisfy the Borrower's obligations under the Finance Documents as they fall due, |
the Borrower undertakes, within ten Business Days of the Lender's notice, to:
(i) |
designate one or more additional or replacement Export Contracts; or |
(ii) |
amend the terms of one or more of the existing Export Contracts, |
Page 39
so that the total volume and value of Commodity to be delivered under the Export Contracts will increase to such a level that the circumstances specified in the Lender's notice are, in the Lender's opinion, no longer likely to occur.
The Borrower undertakes to ensure:
(a) |
for each Consignment, that it has enough Commodity available to deliver that Consignment in accordance with the terms of the relevant Export Contract; and |
21.15 |
Bank accounts |
The Borrower undertakes to open and maintain its main bank accounts in Albania with the Lender and to ensure that all amount due to or from it under any Commercial Contract are paid to, from or through a bank account the Borrower holds with the Lender.
The undertakings in this Clause 22 remain in force until the Security Period ends.
22.1.1 |
The Borrower undertakes not to incur or allow to remain outstanding any Financial Indebtedness other than: |
(b) |
Financial Indebtedness existing on the date of this Agreement and already notified to the Lender to the extent that the amount and tenor of that Financial Indebtedness is not increased or extended; |
(c) |
trade credit with a duration of no more than 90 days that it entered into in the ordinary course of its day-to-day trading activities; |
(e) |
Financial Indebtedness approved by the Lender in advance. |
22.1.2 |
If the Borrower wishes to obtain approval from the Lender for any Financial Indebtedness, it must request approval of at least 15 Business Days before it will incur that Financial Indebtedness (or such shorter period as the Lender agrees) and provide the Lender with all information about the proposed Financial Indebtedness that the Lender reasonably requests including its amount, currency, type, tenor and the identity of the creditor(s). |
22.1.3 |
The Guarantor undertakes to ensure that the Borrower does not incur any Financial Indebtedness to any member of the Group other than Financial Indebtedness that falls within Clause 22.1.1(d). |
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22.2.1 |
This Clause is subject to Clause 22.2.2. The Borrower undertakes not, without the Lender's consent, to enter into a single transaction or a series of transactions whether: |
(a) |
related or not; |
(b) |
voluntary or involuntary; and |
(c) |
at the same time or over a period, |
to sell, lease, transfer, license or otherwise dispose of any asset.
22.2.2 |
While no Default is continuing, Clause 22.2.1 will not apply to a disposal of an asset that is Inventory, or that is not a Security Asset, as long as that disposal is: |
(b) |
of cash, not otherwise prohibited by the Finance Documents; |
(c) |
on arm's-length terms in exchange for other assets of comparable or superior type, value and quality; |
(d) |
on arm's-length terms where the Borrower uses the proceeds of that disposal within one Month to purchase an asset to replace directly the asset disposed of; or |
(e) |
on arm's-length terms where the sum of the higher of the market value or consideration receivable for: |
(i) |
that disposal; and |
(ii) |
every other disposal by the Borrower in the same financial year that is not allowed under paragraphs (a) to (d) above, |
is not more than $100,000 (or its equivalent in any other currency or currencies),
or to the disposal of a Security Asset that is expressly contemplated by, and allowed under, the Finance Documents.
22.3.1 |
This Clause is subject to Clause 22.3.3. The Borrower undertakes not to create or allow to subsist any Security over any of its assets. |
(a) |
sell, transfer or otherwise dispose of any of its assets on terms whereby they will or may be leased to or re-acquired by the Borrower; |
(b) |
sell, transfer or otherwise dispose of any of its receivables on recourse terms; |
(c) |
enter into any arrangement under which money or the benefit of a bank or other account may be applied, set off or made subject to a combination of accounts; or |
(d) |
enter into any other preferential arrangement having a similar effect, |
in circumstances where the arrangement or transaction is entered into chiefly to raise Financial Indebtedness or to finance the purchase of an asset.
Page 41
(b) |
any netting or set-off arrangement the Borrower enters into in the ordinary course of its banking arrangements to net off debit and credit balances, but only so long as those arrangements do not allow credit balances of the Borrower to be netted or set off against the debit balances of any other person; |
(c) |
any lien arising by law and in the ordinary course of the Borrower's day-to-day trading activities (and not as a result of any default or omission by the Borrower) that relates to an obligation that is: |
(i) |
less than 60 days overdue; or |
(ii) |
being contested in good faith by appropriate means; |
(d) |
any Security or Quasi-Security over any asset the Borrower acquires after the date of this Agreement if: |
(i) |
the Security or Quasi-Security was not created in contemplation of the acquisition; |
(ii) |
the principal amount secured has not been increased in contemplation of, or since, the acquisition; and |
(iii) |
the Security or Quasi-Security is removed within two Months of the date of the acquisition; |
(e) |
any guarantee, indemnity or Security given, or any disposal required, under any Finance Document. |
(f) |
any retention of title to goods supplied to the Borrower in the ordinary course of its day-to-day trading activities; or |
22.4 |
Dividends and other funds withdrawals |
22.4.1 |
This Clause is subject to Clause 22.4.2. The Obligors undertake to ensure that, during the Security Period, unless the Lender agrees otherwise: |
(a) |
no dividends are declared or paid on any of the Borrower's issued share capital or any other form of paper issued by the Borrower; |
(b) |
the Borrower does not redeem, buy back, reduce or repay any of its issued share capital or any other form of paper it has issued; |
(c) |
the Borrower does not transfer funds to any other member of the Group: |
(i) |
to pay, repay or service any Financial Indebtedness owed by the Borrower (whether as principal or as a secondary obligor) to another member of the Group; or |
(ii) |
to grant any Financial Indebtedness to any other member of the Group, |
Page 42
or for any other reason the purpose of which is wholly or partially to extract funds from the Borrower for the benefit of other members of the Group or the Group as a whole;
(d) |
the Borrower does not fail to pursue any amount owing to it by any person or pay any amount owed by another member of the Group to any person in place of that member of the Group or allow any cross-Group set-off to be exercised by any person against any of its assets; and |
(e) |
no funds are extracted from the Borrower by any other method wholly or partially with the intention of benefiting other members of the Group or the Group as a whole, |
and in particular that no funds are extracted from the Borrower's Albanian branch.
22.4.3 |
In this Clause the financial definitions in Clause 20.1 (Financial definitions) and the following definitions apply. |
Excess Cash Flow means, for the relevant period:
EBITDA plus
(a) |
any decrease in Working Capital as at the last day of that period when compared to Working Capital on the first day of that period; |
(b) |
cash receipts for any exceptional one-off, non-recurring or extraordinary items; |
(c) |
any tax rebates or credits in cash; |
(d) |
the amount of any dividends or other profit distributions received in cash by the Borrower; |
(e) |
the amount of any increase in provisions, other non-cash debits and other non-cash charges; |
(f) |
the amount of proceeds received from disposals of fixed assets; and |
(g) |
any realized gains in cash on any financial instrument (other than any derivative instrument on a hedge accounting basis). |
minus
(i) |
any increase in Working Capital as at the last day of that period when compared to Working Capital on the first day of that period, |
(ii) |
any amount actually paid in respect of taxes; |
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(iii) |
the amount of any non-cash credits; |
(iv) |
the amount of any capital expenditure unless funded from the proceeds of a capex loan available for this purpose; |
(v) |
the amount of any cash costs of pension items; and |
(vi) |
any realized losses in cash on any financial instrument (other than any derivative instrument on a hedge accounting basis). |
Working Capital means as at any date, the Borrower's short term assets minus its short term liabilities on that date.
22.5 |
Merger |
The Borrower undertakes not to enter into any amalgamation, demerger, merger or corporate reconstruction or any joint venture or partnership agreement without the consent of the Lender.
The Borrower undertakes not to incorporate any company as its Subsidiary.
22.7 |
Change of business |
The Borrower undertakes not to make any substantial change the general nature or scope of its business from that carried on at the date of this Agreement.
The Borrower undertakes not to use, deposit, handle, store, produce, release or dispose of any Dangerous Materials in, on, over or under any real property it owns or occupies, except as permitted under and in compliance with applicable Environmental Law.
22.9 |
Loans |
The Borrower undertakes not to make any loans or grant any credit, other than trade credit with a tenor of no more than 60 days in the normal course of its day-to-day trading activities.
22.10.1 |
The Borrower undertakes not to: |
(a) |
cancel, terminate, amend or waive any default under any Export Contract; or |
(b) |
allow any Buyer to do the same, |
except as allowed under Clause 22.10.2.
22.10.2 |
The Borrower and the relevant Buyer may agree any amendment to an Export Contract so long as: |
(a) |
it relates to the day-to-day operation of that contract; |
(b) |
it is usual for contracts of the same type as that contract; |
(c) |
it is not, in the opinion of the Lender, prejudicial to the interests of the Lender; and |
(d) |
the Borrower notifies the Lender of the amendment promptly after it is agreed. |
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Each of the events and circumstances in this Clause 23, apart from Clause 23.16 (Acceleration), is an Event of Default.
An Obligor does not pay on the due date any amount payable under a Finance Document at the place at and in the currency in which it is expressed to be payable unless:
(a) |
the cause of its failure to pay is an administrative or technical error that is not its fault; and |
(b) |
it makes the payment within three Business Days of its due date. |
The Borrower does not comply with Clause 20 (Financial covenants).
23.3 |
Other obligations |
23.3.2 |
No Event of Default will occur under Clause 23.3.1 if, in the Lender's opinion, the relevant Obligor: |
(a) |
can correct its failure to comply; and |
(b) |
does correct its failure within five Business Days of the Lender notifying that Obligor or that Obligor becoming aware of the failure. |
23.4 |
Misrepresentation etc. |
Any representation, warranty or statement an Obligor made or is deemed to have made in any:
(a) |
Finance Document; or |
(b) |
other document delivered by or for that Obligor in connection with any Finance Document, |
was incorrect or misleading in any material respect when made or deemed made.
23.5.2 |
An Obligor fails to pay any of its Financial Indebtedness when due or within any originally applicable grace period. |
23.5.3 |
Any Financial Indebtedness of an Obligor is declared or otherwise becomes due before its specified maturity because of an event of default (however described). |
23.5.4 |
Any commitment for Financial Indebtedness of an Obligor is cancelled or suspended because of an event of default (however described). |
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23.5.5 |
Any creditor of an Obligor becomes entitled to declare any Financial Indebtedness of that Obligor due before its specified maturity because of an event of default (however described). |
23.6 |
Insolvency |
(a) |
is unable or admits inability to pay its debts as they fall due; or |
(b) |
because of current or anticipated financial difficulties: |
(i) |
suspends payments on any of its debts; or |
(ii) |
proposes or starts negotiations with one or more of its creditors to reschedule any of its indebtedness. |
23.6.2 |
The value of an Obligor's assets is less than its liabilities (taking into account contingent and prospective liabilities). |
23.6.3 |
A moratorium or other protection from its creditors is declared or imposed in respect of any indebtedness of an Obligor. |
23.7.1 |
Any corporate action, legal proceedings or other procedure or step is taken in relation to: |
(a) |
an Obligor suspending payments on any of its debts where that suspension is because of, or allegedly because of, current or anticipated financial difficulties of that Obligor; |
(b) |
a moratorium of any indebtedness of an Obligor; |
(c) |
the dissolution, striking-off, administration, reorganisation, liquidation or winding-up of an Obligor (including by voluntary arrangement or scheme of arrangement); |
(d) |
a composition, compromise, assignment or arrangement with any creditor of an Obligor; |
or any analogous procedure or step is taken in any jurisdiction.
Any expropriation, attachment, sequestration, distress or execution;
(a) |
affects any of an Obligor's assets; and |
(b) |
is not discharged within seven days. |
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23.9 |
Stopping business |
An Obligor suspends, stops, or threatens to suspend or stop, the carrying on of all or a substantial part of its business.
23.10.1 |
It is or becomes unlawful for an Obligor to perform any of its obligations under the Finance Documents. |
23.10.2 |
It is or becomes unlawful for: |
(a) |
any party to an Export Contract to perform any of its obligations under that contract; or |
(b) |
for the Borrower to enforce any of its rights under any Export Contract, |
and that Export Contract is not replaced within five Business Days of the Lender notifying the Borrower or the Borrower becoming aware of the unlawfulness.
23.11.1 |
An Obligor repudiates, or shows it intends to repudiate, a Finance Document. |
23.11.2 |
Any party to a Commercial Contract repudiates, or shows it intends to repudiate, that contract and that contract is not replaced within five Business Days of the Lender notifying the Borrower or the Borrower becoming aware of the repudiation or intent. |
Any Security over any of the assets of an Obligor becomes enforceable.
23.13 |
Sureties and providers of Security |
Any of the events mentioned in Clause 23 happens in relation to any surety or provider of Security for an Obligor's obligations under any Finance Document.
23.14 |
Material adverse change |
Any one or more events or circumstances happens that has or could reasonably be expected to have a Material Adverse Effect.
23.15 |
Commodity Contract payments |
23.15.1 |
A payment to the Borrower under an Export Contract is: |
(a) |
not credited directly to a bank account held with the Lender; and |
(b) |
not transferred by the Borrower to a bank account held with the Lender within three Business days of receipt by the Borrower. |
23.15.2 |
Any amount payable by a Buyer under an Export Contract is not paid when due or within any originally applicable grace period. |
While an Event of Default is continuing the Lender may, by notice to the Borrower do any of the following:
Page 47
(b) |
declare all or any of the amounts accrued or outstanding under the Finance Documents to be immediately due, after which they will be immediately due; |
(c) |
declare all or part of the Loans to be payable on demand, after which they will immediately be payable on demand by the Lender; and |
(d) |
exercise, any of its rights under the Finance Documents including rights to enforce the Transaction Security. |
The Lender may assign any of its rights under the Finance Documents to a:
(a) |
bank or financial institution; or |
(b) |
trust, fund or other entity that is set up to make, buy or invest in loans, securities or other financial assets, or regularly does so. |
The Lender may disclose to:
(a) |
any of its Affiliates or professional advisers; |
(b) |
any rating agency; |
(c) |
any other person: |
(i) |
to (or through) whom it assigns any of its rights under this Agreement (or may do so); |
(ii) |
with (or through) whom it enters into any sub-participation relating to, or any other transaction under which payments will be made by reference to, this Agreement or any Obligor (or may do so); or |
(iii) |
to whom, and to the extent that, it must by law or regulation disclose; |
any information about any Obligor, the Group, the Finance Documents and the Commercial Contracts as the Lender considers appropriate.
No Obligor may assign any of its rights or transfer any of its rights or obligations under the Finance Documents.
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25.1.2 |
Notwithstanding the provisions of Clause 26 (Payment mechanics), the Lender shall not be liable to the Borrower for the failure, or the consequences of any failure, of any cross-border payment system to effect same-day settlement to an account of any person. |
No provision of this Agreement will:
(a) |
interfere with the right of the Lender to arrange its affairs (tax or otherwise) in whatever manner it thinks fit; |
(b) |
oblige the Lender to investigate or claim any credit, relief, remission or repayment available to it or the extent, order and manner of any claim; or |
(c) |
oblige the Lender to disclose any information relating to its affairs (tax or otherwise) or any computations in respect of Tax. |
25.3.1 |
The Borrower waives, to the extent permitted by applicable law, any right it has to require: |
(a) |
the Transaction Security or any part of it to be enforced in a particular order or manner; or |
(b) |
the proceeds of its enforcement or any part of them to be applied in a particular order or manner. |
25.3.2 |
The Lender will be liable to any other Party for any failure or delay in: |
(a) |
enforcing or giving instructions for the enforcement of the Transaction Security; or |
(b) |
(subject to the requirements of applicable law) maximising the receipts or recoveries from enforcement of the Transaction Security. |
26.1.1 |
When on Obligor must make a payment under a Finance Document, it must pay the Lender (unless a contrary indication appears in a Finance Document): |
(a) |
for value on the due date; and |
(b) |
at the time and in the funds specified by the Lender as being usual for settlement of transactions in the relevant currency in the place of payment. |
26.1.2 |
The relevant Obligor must make the payment to the account the Lender specifies. This account must be held with a bank in the principal financial centre for the currency of that payment. |
Page 49
(b) |
secondly, in or towards payment pro rata of any accrued interest, fee or commission due but unpaid under this Agreement; |
(c) |
thirdly, in or towards payment pro rata of any principal due but unpaid under this Agreement; and |
(d) |
fourthly, in or towards payment pro rata of any other sum due but unpaid under the Finance Documents. |
26.2.3 |
Clauses 26.2.1 and 26.2.2 will override any appropriation any Obligor makes. |
Each Obligor must make and calculate all its payments under the Finance Documents without (and without any deduction for) set-off or counterclaim.
26.4.1 |
Any payment due on a day that is not a Business Day must be made: |
(a) |
on the next Business Day in the same calendar month (if there is one); or |
(b) |
the preceding Business Day (if there is not). |
26.4.2 |
During any extension of the due date for payment of any principal or Unpaid Sum interest is payable on the principal or Unpaid Sum at the rate payable on the original due date. |
26.5.1 |
This Clause is subject to Clauses 26.5.2 and 26.5.3. Dollars is the currency of account and payment for any sum due from an Obligor under any Finance Document. |
26.5.2 |
The relevant Obligor must make each payment relating to costs or Taxes in the currency of those costs or Taxes. |
26.5.3 |
The relevant Obligor must pay any amount expressed to be payable in a currency other than Dollars in that other currency. |
26.6 |
Authority to debit |
The Borrower authorises the Lender to:
(a) |
withdraw money from any bank account held in the name of the Borrower with the Bank; and |
(b) |
use that money to pay all or part of any payment due from the Borrower and unpaid under the Finance Documents. |
The Lender may do this at any time without telling the Borrower in advance.
The Lender may set off any matured obligation due from an Obligor under the Finance Documents against any obligation (whether or not matured) owed by the Lender to that Obligor. This Clause applies:
(a) |
to the extent that Obligors' obligation is beneficially owned by the Lender; and |
Page 50
(b) |
regardless of the place of payment, booking branch or currency of either obligation. |
If the obligations are in different currencies, to perform the set-off the Lender may convert either obligation at a market rate of exchange in its usual course of business.
This Clause 28 is about notices, deliveries of documents and other communications between the Parties under the Finance Documents. All communications must be in writing. Utilisation Requests and other notices requiring signature by an authorised signatory of an Obligor must be sent by fax or post or by email as a pdf or jpeg attachment. Any notice the Bank gives under Clause 7.1 (Illegality), 7.2 (Change of control) or 23.16 (Acceleration) or to demand payment must be given by fax or post. In all other cases, unless indicated otherwise, Notices can be given by fax, post or email.
28.2.2 |
Notices are sent at the Borrower’s or Guarantor’s risk. The Lender is entitled, acting in good faith, to assume that any notice or instruction it receives from an Obligor or appearing to be from an Obligor by fax, post or email is from that Obligor and is duly authorised. If the Lender questions the authenticity (which it is not obliged to do) of any notice or instruction and seeks to verify its authenticity before acting on that notice or instruction, it will not be liable to any Obligor for any delay this causes. |
28.2.3 |
The Lender may treat any notice sent to it by email that appears to be sent from the email account of an individual that is (or sent from the email account of one individual, and copied to the email accounts of other individuals who together are) authorised to bind an Obligor, as being authorised by that Obligor. |
Rr. Ismail Qemali
Samos Tower, Kati 5
Tirana, Albania
with a copy to:
#300, 609 – 14th Street N.W.,
Calgary, Alberta T2N 2A1
Attention: |
Dr. Sotirios Kapotas, Chief Executive Officer |
Fax: |
+355 38540385 with a copy to +1 403 531 2695 |
Email: |
skapotas@streamoilandgas.com |
|
with a copy to nxoro@streamoilandgas.com |
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(b) |
The Guarantor: |
#300, 609 - 14th Street N.W.
Calgary, Alberta T2N 2A1
Attention: |
James R. Hodgson, Chief Financial Officer |
Fax: |
+1 403 531 2695 |
Email: |
jhodgson@streamoilandgas.com |
|
with a copy to skapotas@streamoilandgas.com |
(c) |
The Lender: |
European Trade Center, 6th Floor
Blvd. “Bajram Curri”
Tirana, Albania
Attention: |
Elona Koci, Head of Large Corporate and Mid Market Division |
Fax: |
+ 355 4 2275550 |
Email: |
elona.koci@raiffeisen.al |
|
with a copy to jorida.zaimi@raiffeisen.al |
28.3.1 |
If a Party's contact details specify a particular department or officer, any communication to that Party will only be effective if addressed to that department or officer. Communications by fax are effective only when received in legible form. Communications by letter are effective: |
(b) |
two Business Days (or for airmail, five Business Days) after being posted, postage prepaid (or, airmail postage prepaid), to the relevant address. |
28.3.2 |
Any communication to the Lender will be effective only when actually received by that Party. |
28.4.1 |
All notices under the Finance Documents must be in English. |
28.4.2 |
All other documents provided under the Finance Documents must be: |
(a) |
in English; or |
(b) |
if not in English and the Lender so requires, with a certified English translation. In this case, the English translation will prevail unless the document is a constitutional, statutory or other official document. |
In any legal proceedings connected with any Finance Document, the account entries of the Lender are prima facie evidence of the matters to which they relate.
Unless it contains an obvious error, any certification or determination by the Lender of a rate or amount under any Finance Document is conclusive evidence of that rate or amount.
Page 52
Any interest, commission or fee accruing under a Finance Document will:
(a) |
accrue from day to day; and |
(b) |
be calculated based on: |
(i) |
the number of days elapsed; and |
(ii) |
a year of 360 days, |
or, where the practice in the relevant interbank market differs, following that market practice.
The invalidity, illegality or unenforceability of any provision of the Finance Documents under the law of any jurisdiction will not affect the validity, legality or enforceability of:
(a) |
any other provision of the Finance Documents under the law of that jurisdiction; or |
(b) |
any other provision of the Finance Documents under the law of any other jurisdiction. |
This Clause is about the rights and remedies of the Lender under the Finance Documents. They do not exclude any rights or remedies provided by law but add to them. If the Lender becomes entitled to exercise any right or remedy under the Finance Documents or by law, no:
(a) |
failure to exercise; |
(b) |
delay in exercise; or |
(c) |
single or partial exercise of, |
that right or remedy will:
(i) |
adversely affect that right or remedy; |
(ii) |
waive it; or |
(iii) |
prevent any further exercise of it or of any other right or remedy. |
To waive or amend any term of the Finance Documents requires the written consent of the Lender and the Borrower. Any amendment or waiver with this consent will bind all Parties. The Guarantor agrees to any amendment or waiver permitted by this Clause 32 that the Borrower agrees. This includes any amendment or waiver that would, but for this Clause, require the consent of the Guarantor.
The representatives of the Parties may sign this Agreement in any number of counterparts, each of which counts as part of an original. This has the same effect as if the representatives of all the Parties signed the same original of this Agreement. A set of counterparts signed by the representatives of all the Parties forms one original. The representatives of the Parties may sign more than one original of this Agreement.
Page 53
34.1 |
Governing law |
English law governs this Agreement, its interpretation and any non-contractual obligations arising from or connected with it.
The courts of England:
(a) |
have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute about its existence, validity or termination) (a Dispute); and |
(b) |
are the most appropriate and convenient courts to settle Disputes and therefore no Party will argue to the contrary. |
This Clause is for the benefit of the Lender only. It will not prevent the Lender from taking proceedings (including concurrent proceedings) against an Obligor in any other courts with jurisdiction.
34.3.1 |
This Clause is subject to Clause 34.3.2. Despite Clause 34.2, the Lender may refer a Dispute to be finally resolved by arbitration. |
34.3.2 |
The Lender may only exercise the option in Clause 34.3.1 if the Dispute in question is not already the subject of proceedings: |
(a) |
brought by any Party in accordance with Clause 34.2; and |
(b) |
that have not been dismissed or stayed, |
and is not suitable to bring as a counterclaim in any such proceedings.
34.3.3 |
Any Dispute referred to arbitration under this Clause must be decided using the Rules of Conciliation and Arbitration of the London Court of International Arbitration. Those Rules are deemed to be incorporated by reference into this Clause to the extent they do not conflict with its express provisions. The tribunal will consist of one arbitrator. The seat of the arbitration will be London, even if any hearings take place elsewhere. The language of the arbitration will be English. The tribunal must give a written record of its award and the reasons for it. |
34.3.4 |
The main Parties involved in the Dispute must jointly appoint the arbitrator not later than 28 days after service of a written request by any Party to do so. If they are unable to agree within 28 days on the appointment of the arbitrator, any Party may apply to the London Court of International Arbitration to appoint the sole arbitrator. |
34.4 |
Consent to enforcement |
(a) |
enforcement; |
(b) |
execution; and |
(c) |
attachment, |
(whether before judgment, in aid of execution, or otherwise) against any of its assets.
Page 54
34.4.2 |
In this Clause legal proceedings includes any: |
(a) |
service of process, suit, or judgment; |
(b) |
execution or attachment (whether before judgment, in aid of execution, or otherwise); |
(c) |
court proceedings under Clause 34.2; |
(d) |
arbitral proceedings under Clause 34.3; and |
(e) |
other dispute resolution mechanism. |
34.5.1 |
If the Lender so requests, the Borrower must, within three Business Days, appoint (for itself and each other Obligor) an agent (with an office in London, United Kingdom) for service of all claim forms, application notices, judgments, orders or other notices of English legal process relating to this Agreement and notify the agent’s address to the Lender. If the Borrower does not do this, the Lender may appoint a service agent on the Borrower’s behalf and at its expense. If the Lender does this, it must notify the Borrower it has done so and provide details of the service agent as soon as reasonably practicable. The Borrower agrees to reimburse to the Lender on its demand the expenses relating to the appointment of the service agent. |
34.5.2 |
If the Borrower wishes to change the Obligors' address for service it may do so by giving the Lender at least 20 Business Days' written notice of its new address for service. |
The Parties have entered into this Agreement on the date stated at the beginning of this Agreement.
Page 55
Schedule 1 - Conditions precedent
The documents and other evidence referred to in Clause 4.1 (Initial conditions precedent) are as follows:
1 |
The Borrower |
1.1 |
Certified Copies of the constitutional documents of the Borrower. |
1.2 |
Certified Copies of the unanimous written resolutions of the board of directors of the Borrower: |
(a) |
approving and authorising the execution, delivery and performance of each Finance Document on the terms and conditions of those documents; and |
(b) |
authorising any directors or named individuals named in those resolutions whose specimen signature is provided to the Lender, to sign or otherwise attest the execution of the Finance Documents and any other document to be delivered under them. |
1.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of any Finance Document for the Borrower. |
1.4 |
Certified Copies of all Authorisations required by the Borrower in connection with the execution, delivery, performance, validity or enforceability of the Finance Documents or any document to be delivered under them or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
1.5 |
Certified Copies of the Borrower's register of directors, register of members and register of mortgages and charges (the latter showing details of the Transaction Security Documents). |
1.6 |
A certificate of an authorised signatory of the Borrower certifying that each copy document relating to it that is listed in this Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
1.7 |
A certificate signed by a director of the Borrower and addressed to Maples and Calder, the Lender's Cayman Islands counsel, certifying certain matters in relation to the legal opinion of Maples and Calder. |
1.8 |
A certificate of good standing issued by the Registrar of Companies in the Cayman Islands dated within three days of the date of this Agreement. |
1.9 |
Evidence the Borrower has complied in full with all anti-money laundering regulations of the Lender. |
2 |
The Guarantor |
2.1 |
Certified Copies of the constitutional documents of the Guarantor (its certificate of incorporation, any certificate on change of name, its notice of articles and its articles of association). |
2.2 |
Certified Copies of the minutes of a meeting of the board of directors (or equivalent executive body) of the Guarantor (including the resolutions passed at that meeting): |
(a) |
approving and authorising the execution, delivery and performance of this Agreement; |
(b) |
showing that the meeting was quorate; and |
(c) |
authorising any directors or named individuals named in those resolutions whose specimen signature is set out in those minutes or otherwise provided to the Lender, to |
Page 56
sign or otherwise attest the execution of this Agreement and any other document to be delivered under it. |
2.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of this Agreement for the Guarantor. |
2.4 |
Certified Copies of all Authorisations required by the Guarantor in connection with the execution, delivery, performance, validity or enforceability of this Agreement or any document to be delivered under it or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
2.5 |
A Certified Copy of the register of directors of the Guarantor. |
2.6 |
A certificate of an authorised signatory of the Guarantor certifying that each copy document relating to it that is listed in this Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
2.7 |
The Guarantor's Original Financial Statements. |
2.8 |
Evidence the Guarantor has complied in full with all anti-money laundering regulations of the Lender. |
2.9 |
A certificate of good standing in respect of the Guarantor issued by the Registrar of Companies (British Columbia) dated within three days of the date of this Agreement. |
2.10 |
A certificate of a director of officer of the Guarantor relating to such matters as the Lender reasonably requires in order for the legal opinions referred to in section 4 of this Schedule to be issued. |
3 |
Finance Documents |
3.1 |
This Agreement, executed by the Parties. |
3.2 |
Each Transaction Security Document, executed by the parties to it together with all documents deliverable with each of those Transaction Security Documents. |
4.1 |
A legal opinion of SNR Denton UK LLP, legal advisers to the Lender in England, and all documents and other evidence required for issue of that opinion. |
4.2 |
A legal opinion of Maples and Calder the legal advisers to the Lender in the jurisdiction of incorporation of the Borrower, and all documents and other evidence required for issue of that opinion. |
4.3 |
A legal opinion of Gowlings the legal advisers to the Lender in the jurisdiction of incorporation of the Guarantor, and all documents and other evidence required for issue of that opinion. |
5 |
Other documents and evidence |
5.1 |
Evidence the fees and costs then due from the Borrower under Clause 11 (Fees) and Clause 16 (Costs) have been paid or will be paid by the first Utilisation Date. |
5.2 |
Evidence the Borrower has the insurances necessary to comply with Clause 21.7 (Insurance). |
5.3 |
A certified Copy of each Export Contract. |
Page 57
5.4 |
Evidence that: |
(a) |
a Notice of Security over Contract (as described in the Commercial Contracts Security Agreement) has been served on each Buyer under an Export Contract and on Albpetrol Sh.A. in relation to the Petroleum Agreements; and |
(b) |
the Lender has received an acknowledgement to that notice (as described in the Commercial Contracts Security Agreement) from each such Buyer and from Albpetrol Sh.A.. |
5.5 |
Any other agreements, documents or evidence the Lender requires in connection with the Facility and the Finance Documents and notices to the Borrower. |
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Schedule 2 - Form of Utilisation Request
From: |
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) |
To: |
Raiffeisen Bank Sh.A |
|
Dated: [·] |
Dear Sirs
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) - trade finance term facility agreement dated [·] December 2011(the Agreement)
1 |
We refer to the Agreement. This is a Utilisation Request. In this Utilisation Request, unless indicated otherwise: |
(a) |
definitions in the Agreement apply; and |
(b) |
references to Clauses are to clauses in the Agreement. |
2 |
We wish to borrow a Loan on the following terms. |
Proposed Utilisation Date: |
[·] (or, if that is not a Business Day, the next Business Day) |
Amount: |
$[·] or, if less, the Available Facility |
3 |
We confirm that each condition in Clause 4.2 (Further conditions precedent) is satisfied. |
5 |
This Utilisation Request is irrevocable. |
6 |
We attach copies of the Invoices and details of the Work in Progress that this Loan will finance. |
Yours faithfully
…………………………………
authorised signatory for
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd)
|
1 Use this option for the first Utilisation only.
Page 59
Execution page
The Borrower
Signed by a person who is authorised for Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) as Borrower. |
|
|
/s/ Sotirios Kapotas |
|
Name: Sotirios Kapotas |
|
Position: Director |
The Guarantor
Signed by a person who are authorised for Stream Oil & Gas Ltd (BC) as Guarantor. |
|
|
/s/ Sotirios Kapotas |
|
Name: Sotirios Kapotas |
|
Position: Director |
The Lender
Signed by person(s) who are authorised for Raiffeisen Bank Sh.A as Lender. |
|
|
/s/ Christian Canacaris |
|
Name: Christian Canacaris |
|
Position: CEO |
|
Name: Alexander Zsolnai |
|
Position: Deputy-CEO |
Page 60
Exhibit 10.23
Amended and Restated Facility Agreement relating to a $20,000,000 trade finance term loan facility |
Originally dated 15 December 2011 as amended on 8 May 2013, as further amended on 26 December 2013 and as further amended and restated on 17 September 2014
|
|
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) (as Borrower) Stream Oil & Gas Ltd (BC) (as Guarantor) Raiffeisen Bank Sh.A (as Lender)
Dentons UKMEA LLP One Fleet Place London EC4M 7WS United Kingdom DX 242 |
Page i
Contents
1 |
Definitions and construction |
1 |
2 |
The Facility |
10 |
3 |
Purpose |
11 |
4 |
Conditions of utilisation |
11 |
5 |
Utilisation |
11 |
6 |
Repayment |
12 |
7 |
Prepayment and cancellation |
12 |
8 |
Interest |
14 |
9 |
Interest Periods |
14 |
10 |
Changes to the calculation of interest |
15 |
11 |
Fees |
16 |
12 |
Tax gross-up and indemnities |
16 |
13 |
Increased Costs |
18 |
14 |
Other indemnities |
19 |
15 |
Mitigation by the Lender |
20 |
16 |
Costs |
20 |
17 |
Guarantee, indemnity and cash injection undertaking |
21 |
18 |
Representations and warranties |
25 |
19 |
Information undertakings |
30 |
20 |
Financial covenants |
33 |
21 |
Positive undertakings |
36 |
22 |
Negative undertakings |
39 |
23 |
Events of Default |
44 |
24 |
Changes to the Parties |
47 |
25 |
Rights and discretions of the Lender |
48 |
26 |
Payment mechanics |
49 |
27 |
Set-off |
50 |
28 |
Notices |
50 |
29 |
Calculations and certificates |
52 |
30 |
Partial invalidity |
52 |
31 |
Remedies and waivers |
53 |
32 |
Amendments and waivers |
53 |
33 |
Counterparts |
53 |
34 |
Governing law and enforcement |
53 |
Schedule 1 - Conditions precedent |
1 |
|
Schedule 2 - Form of Utilisation Request |
4 |
Page ii
Facility agreement
Between
(2) |
Stream Oil & Gas Ltd (BC), a company incorporated in British Columbia, Canada with registration number BC0713471, its registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (the Guarantor); and |
(3) |
Raiffeisen Bank Sh.A a financial institution established and existing under the laws of Albania registered with Court Order No. 17426 on 10 July 1997 (the Lender). |
It is agreed as follows
In this Agreement the following definitions apply.
Accounting Principles means IFRS.
Affiliate means, for any person, a Subsidiary of that person or a Holding Company of that person or any other Subsidiary of that Holding Company.
Amendment and Restatement Agreement means an amendment and restatement agreement made between the Borrower, the Guarantor and the Lender pursuant to which the facility agreement originally dated 15 December 2011 as amended on 8 May 2013 and as further amended on 26 December 2013 has been amended and restated on the terms set out in this Agreement.
Authorisation means an authorisation, consent, approval, resolution, permit, licence, exemption, clearance, filing, notarisation or registration or other similar requirement of a governmental, judicial or other public body or authority.
Availability Period means the period from and including the date of this Agreement to and including the date that is 12 Months after the date of this Agreement, or any later date the Borrower and Lender agree.
Available Facility means the Commitment minus:
(a) |
the amount of any outstanding Loans; and |
(b) |
in relation to any proposed Utilisation, the amount of any Loans that are due to be made on or before the proposed Utilisation Date. |
Bond Programme means an up to $60,000,000 three year EMTN or equivalent debt issuance programme to be entered into by the Borrower after the date of the Amendment and Restatement Agreement and pursuant to which the Borrower will issue subordinated bonds.
Page 1
Break Costs means the amount (if any) by which:
(a) |
the interest the Lender should have received for the period: |
(i) |
starting on the date of receipt of all or part of its participation in a Loan or Unpaid Sum; and |
(ii) |
ending on the last day of the current Interest Period for that Loan or Unpaid Sum, |
had the principal amount or Unpaid Sum received been paid on the last day of that Interest Period,
exceeds:
(b) |
the amount the Lender would be able to earn by placing an amount equal to the principal amount or Unpaid Sum received on deposit with a leading bank in the London interbank market for a period: |
(i) |
starting on the Business Day following receipt; and |
(ii) |
ending on the last day of that Interest Period. |
Business Day means:
(a) |
for any payment or determination of an interest rate, a day (other than a Saturday or Sunday) on which banks are open for general business in London, Tirana and New York; and |
(b) |
for any other purpose, a day (other than a Saturday or Sunday) on which banks are open for general interbank business in Tirana. |
Buyer means a person that is party to a Commodity Contract as buyer.
Certified Copy means a copy of an original document that is:
(a) |
certified by a director or equivalent authorised officer of the relevant person as being a true, complete and up-to-date copy; or |
(b) |
notarised as being a true copy, |
and which, if the original document has been changed, has a document containing details of that change attached to it.
Commercial Contract means any of the Commodity Contracts, the Production Facilities Contracts, the Petroleum Agreements and any other contract of a commercial nature to which the Borrower is or becomes a party.
Commercial Contracts Security Agreement means the Commercial Contracts Security Agreement dated around the date of this Agreement between the Borrower and the Lender and relating to the Commercial Contracts.
Commitment means $20,000,000 to the extent not cancelled or reduced under this Agreement.
Commodity Contract means any contract for the sale of Commodity by the Borrower, including any Export Contract.
Commodity means crude oil and any oil products.
Page 2
Consignment means a consignment of Commodity that is being or will be delivered under an Export Contract.
Consignment Documents means, for a Consignment, all documents (with the requisite number of copies or originals) against delivery of which payment is to be made under any relevant letter of credit, or, as the case may be, the relevant Buyer is obliged to pay under the relevant Export Contract.
Crude Oil Reserve Report means a report, in form and substance acceptable to the Lender, by an independent expert acceptable to the Lender setting out (a) the volume of proved, probable and possible crude oil still to be located in the fields that are the subject of the Petroleum Agreements; and (b) the projected cashflows attributable to the depletion of those crude oil reserves.
Dangerous Materials means any substance (in any form) that is subject to regulatory control as being hazardous or dangerous or that can harm or damage the Environment.
Default means an Event of Default or any event or circumstance mentioned in Clause 23 (Events of Default) that would, with the:
(a) |
expiry of a grace period; |
(b) |
giving of notice; |
(c) |
making of any determination; or |
(d) |
satisfaction of any condition under the Finance Documents, |
or any combination of any of these, be an Event of Default.
Dollar and $ means the lawful currency of the United States of America.
Environment means ecological systems, living organisms (including humans) and any (or any combination) of the following media:
(a) |
air (including air within natural or man-made structures and air underground); |
(b) |
water (including water underground or in pipe or sewerage systems, sea and inland, ground and surface water); and |
(c) |
land (including land covered with water). |
Environmental Claim means any claim, proceeding, formal notice or investigation by any person under any Environmental Law.
Environmental Law means any applicable law or regulation that relates to:
(a) |
the pollution or protection of the Environment; |
(b) |
the conditions of the workplace; or |
(c) |
any substance that (alone or in combination with any other) can harm the Environment, including waste. |
Environmental Permit means any Authorisation required by any Environmental Law for the operation of the Borrower's business or its ownership or occupation of any property.
Equipment and Inventory Security Agreement means the Securing Charge Agreement Over Movable Assets and Inventories dated around the date of this Agreement between the
Page 3
Borrower and the Lender and relating to certain equipment, machinery and oil stocks of the Borrower.
Event of Default means any event or circumstance described as an Event of Default in Clause 23 (Events of Default).
Export Contract means any of:
(a) |
the Crude Oil Sales Contract No. SKO-011-453470 dated 3 October 2011 between the Borrower as seller and Trafigura Beheer BV as buyer for the sale and purchase of Commodity for an initial period of 12 months; |
(b) |
export contract no. SKO-012-453470 dated 16 January 2013 between the Borrower as seller and Trafigura Beheer BV as buyer for the sale and purchase of Commodity; and |
(c) |
any other contract for the sale by the Borrower of Commodity for export from Albania that is designated as an Export Contract by the Lender and the Borrower. |
Facility means the term loan facility described in Clause 2 (The Facility).
Facility Office means the office or offices through which the Lender will perform its obligations under this Agreement, being Blvd. “Bajram Curri”, ETC, 6th Floor, Tirana, Albania (or, any office or offices notified by the Lender to the Borrower in writing after the date of this Agreement by not less than five Business Days' written notice).
Finance Document means any of:
(a) |
this Agreement; |
(b) |
the Amendment and Restatement Agreement; |
(c) |
the Trafigura Coordination Agreement; |
(d) |
any Transaction Security Document; and |
(e) |
any other document designated as a Finance Document by the Lender and the Borrower. |
Financial Indebtedness means any indebtedness for or in respect of:
(b) |
any amount raised by acceptance under any acceptance credit facility or dematerialised equivalent; |
(c) |
any amount raised under any note purchase facility or from the issue of bonds, notes, debentures, loan stock or any similar instrument; |
(d) |
receivables sold or discounted (except to the extent they are sold on non-recourse terms); |
(e) |
any amount raised under any other transaction (including any forward sale or advance or deferred purchase agreement) having the commercial effect of a borrowing; |
Page 4
(g) |
any counter-indemnity or reimbursement obligation for any guarantee, indemnity, bond, standby or documentary letter of credit or any other instrument issued by a bank or financial institution; |
(h) |
any liability for or in respect of: |
(i) |
any lease or hire purchase contract which would, under the Accounting Principles, be treated as a finance or capital lease; |
(ii) |
any advance payment or other trade credit received more than 60 days before the scheduled delivery date for the goods to which it relates; |
(iii) |
any derivative transaction to protect against or benefit from change in any rate or price (and, when calculating the value of any derivative transaction, only the marked to market value (or the value at close-out or termination, if applicable) shall be considered); |
(i) |
any indebtedness under any guarantee or indemnity for any of the items referred to in any of the paragraphs (a) to (g) above and (i) to (iv). |
Group means the Guarantor and all Subsidiaries and Affiliates of the Guarantor.
Holding Company means, for a company or corporation, any other company or corporation of which it is a Subsidiary.
IFRS means international accounting standards within the meaning of IAS Regulation 1606/2002 to the extent relevant to the applicable financial statements.
Insurances has the meaning given to it in Clause 21.7.1(c).
Interest Period means, for a Loan, each period determined under Clause 9 (Interest Periods) and, for an Unpaid Sum, each period determined under Clause 8.3 (Default interest).
Inventory means the Borrower's stock of Commodity from time to time.
Invoice means an invoice, advance payment request or similar instrument acceptable to the Lender relating to an amount that is payable and unpaid by the Borrower to a supplier for goods or services in relating to improvement or exploitation of the Production Facilities.
Legal Opinion means any legal opinion delivered to the Lender under Clause 4 (Conditions of utilisation).
LIBOR means, for any Loan or Unpaid Sum and Interest Period the higher of one and a half per cent (1.5%) and:
(a) |
the applicable Screen Rate; or |
(b) |
(if no Screen Rate is available for that Interest Period) the arithmetic mean (rounded upwards to four decimal places) of the rates, as supplied to the Lender at its request by the Reference Banks in each case at the rate at which the relevant Reference Bank could borrow Dollars in the London interbank market for a period comparable to that Interest Period, were it to do so by asking for and then accepting interbank offers for deposits in reasonable market size, |
as of 11 a.m. on the Quotation Day.
Page 5
Loan means a loan made or to be made under the Facility or the principal amount outstanding of that loan.
Margin means five and a half per cent (5.5%) per annum.
Material Adverse Effect means, in the opinion of the Lender, a material adverse effect on:
(a) |
any Obligor's ability to comply with any of its obligations under any Finance Document; |
(b) |
the business, financial condition, assets or prospects of any Obligor; or |
(c) |
the validity, enforceability, effectiveness or ranking of any Security granted or expressed to be granted pursuant to any Transaction Security Document; or |
(d) |
the validity or enforceability of the rights or remedies of the Lender under any Finance Document, or of the Borrower under any Export Contract. |
Month means a period starting on one day in a calendar month and ending on the numerically corresponding day in the next calendar month, except that:
(b) |
if there is no numerically corresponding day in the calendar month in which that period is to end, that period shall end on the last Business Day in that calendar month; and |
(c) |
if an Interest Period begins on the last Business Day of a calendar month, that Interest Period shall end on the last Business Day in the calendar month in which that Interest Period is to end. |
The above rules (a) to (c) will only apply to the last Month of any period.
Obligor means the Borrower or the Guarantor.
Original Financial Statements means for the Guarantor, its audited consolidated financial statements for its financial year ended 30 November 2010 (including all additional information and notes to those financial statements), together with the relevant directors' report and auditors' reports.
Party means a party to this Agreement.
Permitted Security means any Security falling into one of the categories in Clauses 22.3.3(a) through 22.3.3(g) (Negative pledge).
Petroleum Agreement means any of:
(a) |
the Petroleum Agreement for the Development and Production of Petroleum in Gorisht-Kocul Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; |
(b) |
the Petroleum Agreement for the Development and Production of Petroleum in Delvina Block dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; |
(c) |
the Petroleum Agreement for the Development and Production of Petroleum in Cakran-Mollaj Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower; and |
(d) |
the Petroleum Agreement for the Development and Production of Petroleum in Ballsh-Hekal Field dated 8 August 2007 between Albpetrol Sh.A. and the Borrower. |
Page 6
Production Facilities means the facilities of the Borrower used for extracting the Commodity at Delvina Block, Cakran-Mollaj, Ballsh-Hekal Field and Gorisht-Kocul Field.
Production Facilities Contract means any contract under which an Invoice is issued or that relates to Work in Progress.
Programme Document means any document creating or ancillary to the Bond Programme or any issuance of bonds under it.
Quasi-Security means any transaction described in Clause 22.3.2 (Negative pledge).
Quotation Day means, when fixing an interest rate for any period, two Business Days before the first day of that period.
Reference Banks means the principal London offices of Raiffeisen Bank International AG, Barclays Bank PLC and HSBC Bank plc or such other banks as the Lender may select in consultation with the Borrower.
Relevant Jurisdiction means any of:
(a) |
any Obligor’s jurisdiction of incorporation; |
(b) |
any jurisdiction where a Security Asset is situated; |
(c) |
any jurisdiction where the Borrower conducts business relating to any Commercial Contract; and |
(d) |
any jurisdiction whose laws govern the perfection of any Transaction Security. |
Repayment Date has the meaning given to it in Clause 6.1 (Repayment of Loans).
Repayment Instalment has the meaning given to it in Clause 6.1 (Repayment of Loans).
Repeating Representations means each of the representations and warranties set out in Clause 18 (Representations and warranties) except the representations and warranties in Clause 18.8 (Deduction of Tax).
Screen Rate means the London interbank offered rate administered by ICE Benchmark Administration Limited (or any person which takes over the administration of that rate) for a period of one year, as displayed on the applicable Reuters page. If the Reuters service stops displaying this rate, the Lender may specify another service displaying it after consulting with the Borrower.
Security means a mortgage, charge, pledge, hypothecation, lien, assignment by way of security, retention of title provision, right of set‑off, trust or flawed asset arrangement (for, or which has the effect of, granting security) or other security interest securing any obligation of any person, whether or not conditional, or any other agreement or arrangement in any jurisdiction having a similar effect.
Security Assets means the assets that are, or are expressed to be, the subject of the Transaction Security.
Security Period means the period starting on the date of this Agreement and ending on the date on which the Lender is satisfied that:
(a) |
the liabilities of all Obligors under the Finance Documents are irrevocably and fully discharged; and |
(b) |
the Lender has no commitment or liability in relation to the Facility. |
Page 7
Subsidiary means, for a company or corporation, any other company or corporation in or over which that first company or corporation:
(a) |
holds a majority of the voting rights; |
(b) |
is a member and has the right to appoint or remove the majority of the members of the executive body; |
(c) |
has the right to exercise a dominant influence, by virtue of provisions contained in that company or corporation's constitutional documents or in a control contract; |
(d) |
is a member and controls alone, or pursuant to an agreement with other members, a majority of the voting rights. |
Tax means any tax, levy, impost, duty or other charge or withholding of a similar nature (including any penalty or interest payable for any failure to pay or any delay in paying any of the same).
Tax Deduction means a deduction or withholding for or on account of Tax from a payment under a Finance Document.
Termination Date means 31 December 2016.
Trafigura means Trafigura PTE Ltd, branch office Geneva, a company incoporated in Singapore with a branch office located at 5 Rue de Jargonnant, Geneva 1207, Switzerland.
Trafigura Coordination Agreement means the agreement dated 22 May 2013 between the Lender and Trafigura relating to the intercreditor rights of the Lender and Trafigura in respect of this Agreement and the Trafigura Prepayment Agreement.
Trafigura Permitted Security means the charge granted or to be granted by the Borrower in favour of Trafigura in respect of equipment and machinery for the expansion of production of the Cakran, Gorisht, Ballsh and Delvina Field projects the Borrower has purchased or shall purchase exclusively with the proceeds of a prepayment made under the Trafigura Prepayment Agreement.
Trafigura Prepayment Agreement means the prepayment agreement dated 18 April 2013, between the Borrower (as seller), the Guarantor (as guarantor) and Trafigura (as buyer), relating to prepayments under the Export Contract dated 16 January 2013 contract number SKO-012-453470 entered into between the Borrower and Trafigura.
Transaction Security means the Security created or expressed to be created in favour of the Lender under or in accordance with the Transaction Security Documents.
Transaction Security Document means:
(a) |
the Commercial Contracts Security Agreement; |
(b) |
the Equipment and Inventory Security Agreement; and |
(c) |
any other document creating, evidencing or acknowledging Security in favour of the Lender that covers any Obligor's obligations under any of the Finance Documents and is in form and substance satisfactory to the Lender. |
Unpaid Sum means any sum due and payable but unpaid by an Obligor under the Finance Documents.
Utilisation means a utilisation of the Facility.
Page 8
Utilisation Date means the date of a Utilisation, being the date on which the relevant Loan is made.
Utilisation Request means a notice substantially in the form set out in Schedule 2 (Form of Utilisation Request).
VAT means any turnover tax, sales tax, value added tax and any other tax of a similar nature (however called) imposed in any applicable jurisdiction.
Work in Progress means work progressing on the exploitation or improvement of the Production Facilities in accordance with any Work Plans & Budget.
Work Plans & Budget means an annual work plan and budget that the Borrower has agreed with Albpetrol Sh.A. in connection with one or more of the Petroleum Agreements and that the Lender has approved, such as the Work Plans & Budget for 2012.
1.2.1 |
Unless a contrary indication appears, any reference in any Finance Document to: |
(a) |
assets includes present, future, actual and contingent properties, revenues and rights of every description, whether tangible or intangible (including uncalled share capital); |
(b) |
any bank account is a reference to that account as it may be renumbered, redesignated or replaced and includes any of its sub-accounts from time to time; |
(c) |
a Clause or Schedule is a reference to the relevant clause or schedule to, the Finance Document in which that reference appears; |
(d) |
debt or indebtedness includes any obligation whether incurred as principal or as surety for the payment or repayment of money, whether present or future and whether owed jointly or severally or in any other capacity; |
(e) |
any Finance Document or any other agreement or instrument is a reference to that Finance Document or other agreement or instrument as amended, novated, supplemented, extended, reinstated or replaced from time to time; |
(f) |
guarantee means (other than in Clause 17 (Guarantee, indemnity and cash injection undertaking) any guarantee, letter of credit, bond, indemnity or similar assurance against loss, or any obligation, direct or indirect, actual or contingent, to: |
(i) |
buy or assume any indebtedness of; |
(ii) |
make an investment in, or loan to; or |
(iii) |
buy assets of, |
any person where, in each case, that obligation is assumed to support that person or to help that person to meet its indebtedness;
(g) |
the words include, includes, including and in particular shall be construed as being for illustration or emphasis only and shall not be construed as, nor shall they take effect as, limiting the generality of any preceding words; |
(h) |
liability and liabilities includes any obligation whether incurred as principal or as surety, whether or not for indebtedness, whether present or future, actual or contingent and whether owed jointly or severally or in any other capacity; |
Page 9
(i) |
any person includes any assignee, transferee, successor in title, delegate, sub-delegate or appointee of that person (but, in the case of Parties, only permitted assignees, transferees etc). It also includes any individual, firm, company, corporation, body corporate, government, state or agency of a state or any unincorporated body, association, trust, joint venture, consortium or partnership (whether or not having separate legal personality); |
(j) |
a regulation includes any regulation, rule, official directive, request or guideline (whether or not having the force of law) of any governmental, intergovernmental or supranational body, agency, department or regulatory, self-regulatory or other authority or organisation; |
(k) |
any statute or statutory provision includes: |
(i) |
any statute or statutory provision that amends, extends, consolidates or replaces it; |
(ii) |
any statute or statutory provision that it has amended, extended, consolidated or replaced; and |
(iii) |
any orders, regulations, instruments or other subordinate legislation made under it; |
(l) |
accounting terms shall be construed to be consistent with the Accounting Principles; and |
(m) |
a time of day is a reference to Tirana time. |
1.2.2 |
Section, clause and schedule headings are for ease of reference only. |
1.2.3 |
Unless a contrary indication appears, a term used in any other Finance Document or in any notice given under or in connection with any Finance Document has the same meaning in that Finance Document or notice as in this Agreement. |
1.2.4 |
A Default (other than an Event of Default) is continuing if it has not been remedied or waived in writing and an Event of Default is continuing if it has not been waived in writing. |
(a) |
change any term of this Agreement; and |
(b) |
rescind, vary, waive, release, assign, novate or otherwise dispose of all or any of their respective rights or obligations under this Agreement, |
without the consent of any person who is not a Party.
Subject to the terms of this Agreement, the Lender makes available to the Borrower a Dollar term loan facility in a total amount equal to the Commitment.
Page 10
The Borrower shall apply all amounts borrowed by it under the Facility towards capital expenditure for improvement of the Production Facilities.
The Lender is not bound to monitor or verify how the Borrower uses any amount borrowed under this Agreement.
Until the Lender has received all the documents and other evidence listed in Schedule 1 (Conditions precedent) in form and substance satisfactory to it:
(a) |
the Borrower may not deliver a Utilisation Request; and |
(b) |
the Lender shall not be obliged to make available the Facility. |
The Lender will notify the Borrower promptly on being so satisfied.
The Lender will only be obliged to comply with Clause 5.3 (Availability of Loans) if, on the date of the Utilisation Request and on the proposed Utilisation Date:
(a) |
no Default is continuing or would result from the proposed Loan; and |
The Borrower may use the Facility by delivering a completed Utilisation Request to the Lender. Delivery must be not later than 11 a.m. on the third Business Day before the proposed Utilisation Date.
Each Utilisation Request is irrevocable and will not be regarded as completed unless:
(a) |
the proposed Utilisation Date is a Business Day within the Availability Period; |
(b) |
the Utilisation is denominated in Dollars; and |
5.3 |
Availability of Loans |
If the conditions set out in this Agreement have been met, the Lender shall make each Loan available by that Loan's Utilisation Date through its Facility Office. Unless the Borrower and
Page 11
the Lender agree otherwise, the Lender will make the Loan available by paying on the Borrower’s behalf the Invoices to which the Loan relates.
5.4 |
Cancellation of unutilised Commitment |
The unutilised portion of the Commitment shall be immediately cancelled at the end of the Availability Period.
The Borrower shall repay the Loans by paying to the Lender:
(a) |
on each date set out in Column 1 below (each a Repayment Date); |
(b) |
the amount set out in Column 2 below opposite that date, adjusted to take account of any voluntary prepayment made under Clause 7.3 (Voluntary prepayment of Loans) ; (each a Repayment Instalment). |
Column 1 Repayment Date |
Column 2 Repayment Instalment ($) |
The last Business Day of each March, June, September and December (except December 2011) falling after (and excluding) the first Utilisation Date and before (and including) the last day of the Availability Period. |
The lower of (a) the total Loans outstanding; and (b) the amount that is one twentieth of the Commitment rounded up to the nearest $10. |
The last Business Day of each March, June, September and December falling after (and excluding) the last day of the Availability Period and before (and excluding) the Termination Date, |
3/x of the total Loans outstanding (less the Repayment Instalment due but unpaid by the Borrower on 30 June 2014) at the end of the last day of the Availability Period, rounded up to the nearest $10 where x = the number of Months between the last day of the Availability Period and the Termination Date. |
The Termination Date |
All Loans then outstanding. |
6.2 |
Re-borrowing |
If it becomes unlawful anywhere for the Lender to perform any of its obligations under this Agreement or to continue providing any Loan:
(a) |
the Lender must notify the Borrower promptly on realising this; |
(b) |
the Lender notifying the Borrower of this will immediately cancel the Commitment; and |
Page 12
(c) |
the Borrower must repay the Loans. Repayment must take place on: |
(i) |
the last day of the Interest Period that ends after the Lender notifies the Borrower; or |
(ii) |
if earlier, the date specified by the Lender in its notice (which must be no earlier than the last day of any grace period allowed by law). |
(b) |
the Lender will not be obliged to fund any Utilisation; |
(c) |
if the Lender so notifies the Borrower by not less than 10 days' notice and within 10 days of the Borrower notifying the Lender under Clause 7.2.1(a) above: |
(i) |
the Commitment will be cancelled; and |
(ii) |
all outstanding Loans and all other amounts accrued under the Finance Documents will become due and payable. |
7.3.1 |
The Borrower may prepay all or part of the Loans. To do this the Borrower must give the Lender at least 15 Business Days' (or any shorter period the Lender agrees) notice. If it prepays part of the Loans that part must be at least $500,000 and a multiple, of $10,000. |
7.3.2 |
The Borrower may only prepay after the last day of the Availability Period (or, if earlier, the day on which the Available Facility is zero). |
7.3.3 |
Any prepayment under this Clause will be applied across all future Repayment Instalments due under Clause 6.1 (Repayment of Loans) to reduce each of them equally. |
7.4.1 |
Any notice of prepayment given under this Clause 7 will be irrevocable and, unless a contrary indication appears in this Agreement, must state: |
(a) |
the date or dates when the prepayment will happen; and |
(b) |
the amount of that prepayment. |
7.4.2 |
When the Borrower prepays any amount it must at the same time pay: |
(a) |
accrued interest on the amount prepaid; |
(b) |
except if the prepayment is made under Clause 7.1 (Illegality): |
(i) |
any Break Costs; and |
(ii) |
the prepayment fee specified in Clause 11.2 (Prepayment fee). |
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7.4.3 |
The Borrower may not re-borrow any part of the Facility it has prepaid. |
7.4.4 |
The Borrower may only repay or prepay all or part of any Loan or cancel all or part of any Commitment as expressly set out in this Agreement. |
The rate of interest on each Loan for each Interest Period is the percentage rate per annum determined by the Lender to be the sum of the applicable:
(a) |
Margin; and |
(b) |
LIBOR. |
The Borrower must pay accrued interest on the Loans on the last day of each Interest Period.
8.3.2 |
If any overdue amount consists of all or part of the Loans that became due on a day that was not the last day of an Interest Period: |
(a) |
the first Interest Period for that overdue amount will have a duration equal to the unexpired portion of then current Interest Period for the Loans; and |
(b) |
the rate of interest applying to the overdue amount during that first Interest Period will be two per cent higher than the rate that would have applied if the overdue amount had not become due. |
8.3.3 |
Default interest on an overdue amount (if unpaid) will be compounded with the overdue amount at the end of each Interest Period but will remain immediately due and payable. |
The Lender must promptly notify the Borrower of each rate of interest determined under this Agreement.
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9.1.2 |
Each Interest Period for a Loan will end on the first Repayment Date to occur after the start date for that Interest Period. No Interest Period for a Loan may extend beyond the Termination Date. |
If an Interest Period would otherwise end on a non-Business Day, it will instead end on:
(a) |
the next Business Day in the same calendar month, if there is one; or |
(b) |
the preceding Business Day, if there is not. |
This Clause is subject to Clause 10.2 (Market disruption). If:
(a) |
the Lender must determine LIBOR using quotations from the Reference Banks; and |
(b) |
one Reference Bank does not supply a quotation by 11 a.m. on the Quotation Day, |
the Lender must determine LIBOR using the quotations from the other Reference Banks.
10.2.1 |
If a Market Disruption Event happens and affects a Loan and its Interest Period, the interest rate for that Interest Period will be the percentage rate per annum that is the sum of the: |
(a) |
Margin; and |
(b) |
the cost to the Lender of funding that Loan from whatever source the Lender reasonably selects. |
(a) |
at or about noon on the Quotation Day for the relevant Interest Period the Screen Rate is not available and: |
(i) |
none or only one of the Reference Banks supplies a quotation to the Lender; or |
(ii) |
the Lender decides that, because of circumstances affecting the London interbank market generally, reasonable and adequate means do not exist for finding out LIBOR; or |
(b) |
before close of business in London on the Quotation Day for the relevant Interest Period, the Lender determines that in its opinion: |
(i) |
the cost to it of obtaining matching deposits in the London interbank market would be more than LIBOR; or |
(ii) |
matching deposits may not be available to it in the London interbank market in the ordinary course of business. |
(a) |
a Market Disruption Event happens; and |
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(b) |
the Lender or Borrower so wishes, |
the Lender and the Borrower must try (for not more than 30 days) to agree a substitute basis for deciding the rate of interest.
10.3.2 |
If the Lender and the Borrower agree an alternative basis under Clause 10.3.1, the alternative basis will be binding on all Parties. |
If:
(a) |
all or part of a Loan or Unpaid Sum is not paid on the last day of its Interest Period; and |
(b) |
the Lender so demands, |
the Borrower must pay to the Lender its related Break Costs.
The Borrower must pay to the Lender an arrangement fee of $100,000 on the earlier of: (a) the first Utilisation Date; and (b) the date that is 30 days after the date of this Agreement.
If the Borrower prepays any of the Facility under Clause 7.3 (Voluntary prepayment of Loans) it must, at the time it makes the prepayment, pay the Lender a prepayment fee of three per cent of the amount prepaid.
12.1.1 |
Each Obligor must make all of its payments under the Finance Documents without any Tax Deduction, unless a Tax Deduction is required by law. |
(a) |
an Obligor has had or will have to make a Tax Deduction; or |
(b) |
there has been or will be any change in the rate, or the basis of calculation, of any Tax Deduction. |
Similarly, the Lender must notify the Borrower on realising that a payment to the Lender has been or will be so affected.
12.1.4 |
If an Obligor must by law make a Tax Deduction, that Obligor must make: |
(a) |
the Tax Deduction; and |
(b) |
any related payment to the relevant tax authority, |
Page 16
within the time allowed and in the minimum amount required by law.
(a) |
a Tax Deduction; or |
(b) |
a related payment to the relevant tax authority, |
the relevant Obligor must deliver to the Lender evidence that it has made the Tax Deduction or related payment. The evidence must be reasonably satisfactory to the Lender.
(a) |
subject to any liability; or |
(b) |
required to make any payment, |
for or on account of Tax in relation to any sum received or receivable (or any sum deemed for Tax purposes to be received or receivable) under any Finance Document. If this happens, the Borrower must pay the Lender, within three Business days of demand, an amount equal to the loss, liability or cost the Lender will suffer or has suffered (directly or indirectly) as a result of that liability or payment. The Lender will determine the amount of its cost, loss or liability in its absolute discretion. The Borrower must pay within three Business Days of demand by the Lender.
(a) |
in relation to any Tax assessed on the Lender under the law of any jurisdiction in which the Lender: |
(i) |
is incorporated; |
(ii) |
is resident for tax purposes; or |
(iii) |
has its Facility Office, in relation to amounts received or receivable in that jurisdiction, |
if that Tax is imposed on, or calculated by reference to, the net income received or receivable (but not any sum deemed to be received or receivable) by the Lender; or
(b) |
to the extent the liability or requirement is compensated for by an increased payment under Clause 12.1 (Tax gross-up). |
12.3 |
Stamp taxes |
The Borrower must indemnify the Lender against any cost, loss or liability the Lender incurs for any stamp duty, registration tax or other similar Tax payable in respect of any Finance Document. The Borrower must pay within three Business Days of demand.
12.4.1 |
All amounts payable to the Lender under a Finance Document are exclusive of VAT. If VAT is chargeable on any supply made by the Lender to another Party under a Finance Document, that Party must, when it pays for the supply, also pay an amount equal to the VAT. |
Page 17
(a) |
an Obligor must reimburse the Lender for a cost; |
(b) |
the Lender has incurred VAT in respect of that cost; and |
(c) |
the Lender reasonably determines that neither: |
(i) |
it; nor |
(ii) |
any other member of any group of which it is a member for VAT purposes, |
is entitled to any credit or repayment from the relevant tax authority for that VAT,
that Obligor must indemnify the Lender against the VAT the Lender has incurred when it pays the reimbursement.
13.1.1 |
This Clause is subject to Clause 13.3 (Exceptions). If the Lender or any of its Affiliates incurs any Increased Costs as a result of: |
(a) |
the introduction of or any change in (or in the interpretation, administration or application of) any law or regulation; |
(b) |
compliance with any law or regulation relating to capital adequacy; or |
(c) |
compliance with any other law or regulation made after the date of this Agreement, |
the Borrower must, within three Business Days of demand by the Lender, pay the Lender an amount equal to those Increased Costs.
13.1.2 |
Increased Costs means: |
(a) |
a fall in the rate of return from the Facility or on the Lender's (or its Affiliate's) overall capital; |
(b) |
an extra or increased cost; or |
(c) |
a reduction of any amount due and payable under any Finance Document, |
that:
(i) |
the Lender or any of its Affiliates incurs or suffers; and |
(ii) |
is attributable to the Lender having entered into the Commitment or funding or performing its obligations under any Finance Document. |
13.2.1 |
If the Lender intends to make a claim under Clause 13.1, it must, as soon as practicable: |
(a) |
notify the Borrower of the event giving rise to the claim; and |
(b) |
provide the Borrower with a certificate of its Increased Costs. |
Page 18
Clause 13.1 (Increased Costs) does not apply to the extent any Increased Cost is:
(a) |
attributable to a Tax Deduction the Borrower must by law make; |
(b) |
compensated for by Clause 12.2 (Tax indemnity) (or would have been had Clause 12.2.2 not applied); or |
(c) |
attributable to the wilful breach by the Lender or its Affiliates of any law or regulation. |
14.1.1 |
If it is necessary to convert any: |
(a) |
sum due from an Obligor under the Finance Documents (a Sum); or |
(b) |
order, judgment or award given or made in relation to a Sum, |
from the currency (the First Currency) in which that Sum is payable into another currency (the Second Currency) to:
(i) |
make or file a claim or proof against that Obligor; or |
(ii) |
obtain or enforce an order, judgment or award, |
that Obligor must indemnify the Lender against any cost, loss or liability arising from the conversion. That cost, loss or liability may include any difference between:
(aa) |
the rate of exchange used to convert that Sum from the First Currency into the Second Currency; and |
(bb) |
the rate or rates of exchange available to the Lender when it receives that Sum. |
That Obligor's obligation under this Clause is independent of its obligation to pay the original Sum and must be satisfied within three Business Days of demand.
14.1.2 |
Each Obligor waives any right it may have in any jurisdiction to pay any amount in a currency other than that in which it is payable under the Finance Documents. |
The Borrower must indemnify the Lender against any cost, loss or liability the Lender incurs because of:
(a) |
an Event of Default; |
(b) |
the Lender relying on any notice, request or instruction appearing to be from an Obligor that the Lender reasonably believes is genuine, correct and properly authorised; |
(c) |
any Obligor failing to pay when due any amount payable under a Finance Document; |
(e) |
the Lender exercising any right, power, discretion or remedy vested in the Lender by the Finance Documents or by law; |
Page 19
(f) |
the Lender funding, or arranging to fund, a Loan that: |
(i) |
the Borrower requested in a Utilisation Request; and |
(ii) |
was not made, not solely because of default or negligence by the Lender, but because of one or more of the provisions of this Agreement operating; or |
(g) |
all or part of a Loan not being prepaid in accordance with a notice of prepayment from the Borrower. |
The Borrower must satisfy its obligation under this Clause within three Business Days of demand.
(a) |
Clause 7.1 (Illegality); |
(b) |
Clause 12 (Tax gross-up and indemnities); or |
(c) |
Clause 13 (Increased Costs), |
the Lender will, in consultation with the Borrower, take all reasonable steps to mitigate the effects of this, including transferring its rights and obligations under the Finance Documents to an Affiliate or another Facility Office.
15.1.2 |
Clause 15.1.1 does not in any way limit the obligations of any Obligor under the Finance Documents. |
15.2.1 |
The Borrower must indemnify the Lender for all costs the Lender reasonably incurs taking steps under Clause 15.1. |
15.2.2 |
The Lender is obliged to take any steps under Clause 15.1 that it thinks (acting reasonably) might be disadvantageous to it. |
The Borrower must, promptly on demand, pay all costs (including legal fees) the Lender reasonably incurs negotiating, preparing, printing, executing, syndicating or perfecting the Finance Documents or the Lender taking, holding or protecting the Transaction Security.
This Clause applies if any Obligor asks for an amendment, waiver or release of, or consent under, any Finance Document. The Borrower must, within three Business Days of demand, pay all costs (including legal fees) the Lender reasonably incurs responding to, evaluating, negotiating or complying with that Obligor's request.
The Borrower must, within three Business Days of demand, pay to the Lender all costs (including legal fees) the Lender incurs:
Page 20
(a) |
looking into any possible Default; |
(b) |
enforcing or preserving the Transaction Security or any other rights under the Finance Documents; or |
(c) |
taking or defending any proceedings involving the Lender that relate to the Transaction Security or any Finance Document. |
For the benefit of the Lender, the Guarantor irrevocably and unconditionally:
(a) |
guarantees punctual performance by the Borrower of the Borrower's obligations under the Finance Documents; |
(b) |
undertakes, if the Borrower does not pay an amount when expressed to be due under any Finance Document, immediately on demand to pay that amount as if it were the principal obligor; and |
17.2 |
Cash injection undertaking |
17.2.2 |
Without prejudice to Clause 17.2.1 the Guarantor undertakes by at the latest 31 December 2014 to provide a cash injection in Dollars to the Borrower (and to its Albanian branch if required by the Lender) in a minimum amount of $15,000,000 by means of equity or any other method acceptable to the Lender. |
17.2.3 |
Any request the Lender makes under Clause 17.2.1 must specify the amount of the cash injection, which may be no more than any of: |
(a) |
the total amount outstanding (including accrued interest) under the Finance Documents at that time; and |
(b) |
the Lender's reasoned estimate of the Borrower's Cashflow Shortfall during the period from the date of the Lender's request to second Repayment Date to occur after the date of that request. |
For the purposes of this Clause, the Borrower's Cashflow Shortfall for any period means the amount (if any) by which the Borrower's predicted expenditures exceed its predicted revenues for that period, as determined by the Lender on the basis of the financial information the Borrower supplies to it under Clause 19.7 (Production information) and any other relevant information the Lender receives under Clause 19.4(c) or otherwise.
Page 21
17.2.4 |
If the Guarantor does not wish to comply with any request the Lender makes under this Clause, the Guarantor may prepay the Loans in accordance with Clause 7.3 (Voluntary prepayment of Loans). |
The guarantee in this Clause is:
(a) |
a continuing guarantee and will extend to the ultimate balance of sums payable by the Borrower under the Finance Documents, regardless of any intermediate payment or discharge in whole or in part; and |
(b) |
is in addition to, is not in any way prejudiced by, and shall not merge with, any other guarantee or Security now or in the future held by the Lender. |
If any:
(a) |
discharge; |
(b) |
release; |
(c) |
accounting; or |
(d) |
arrangement, |
(whether in respect of the obligations of the Borrower or any Security for those obligations or otherwise) is made by the Lender in whole or in part on the basis of any:
(i) |
payment; |
(ii) |
security; |
(iii) |
recovery; or |
(iv) |
other disposition, |
that is avoided or must be restored in insolvency, liquidation, administration or otherwise,
then the liability of the Guarantor under this Clause will continue or be reinstated as if that discharge, release, accounting or arrangement had not occurred.
The obligations of the Guarantor under this Clause will not be affected by an act, omission, matter or thing (whether or not known to it or the Lender) that, but for this Clause, would reduce, release or prejudice any of them, including:
(a) |
any time, waiver or consent granted to the Borrower or any other person; |
(b) |
the release of the Borrower or any other person under the terms of any composition or arrangement with any creditor of any person; |
(c) |
the taking, variation, compromise, exchange, renewal, enforcement or release of, or refusal or neglect to perfect, take up or enforce, any rights against, or Security over assets of, the Borrower or any other person; |
Page 22
(d) |
any non-presentation or non-observance of any formality or other requirement in respect of any instrument or any failure to realise the full value of any Transaction Security; |
(e) |
any incapacity or lack of power, authority or legal personality of, or dissolution or change in the constitution, members or status of, the Borrower or any other person; |
(f) |
any amendment, novation, supplement, extension, replacement, assignment, avoidance or termination of any Finance Document or any other document or Transaction Security, in each case however fundamental and whether or not more onerous including any change in the purpose of, any extension of or any increase in, any facility, or the addition of any new facility; |
(g) |
any unenforceability, illegality or invalidity of any obligation of, or any Transaction Security or any other Security; or |
(h) |
any insolvency, liquidation, administration or similar procedure. |
Without prejudice to the generality of Clause 17.5 (Waiver of defences), the Guarantor expressly confirms that it intends that this guarantee shall extend from time to time to any (however fundamental) variation, increase, extension or addition of or to any of the Finance Documents and any facility or amount made available under any of the Finance Documents for the purposes of or in connection with any of the following:
(a) |
acquisitions of any nature; |
(b) |
increasing working capital; |
(c) |
enabling investor distributions to be made; |
(d) |
carrying out restructurings; |
(e) |
refinancing existing facilities; |
(f) |
refinancing any other indebtedness; |
(g) |
any other variation or extension of the purposes for which any such facility or amount might be made available from time to time; and |
(h) |
any fees, costs and expenses associated with any of the foregoing. |
17.7 |
Immediate recourse |
The Guarantor waives any right it may have of first requiring the Lender (or any trustee or agent on its behalf) to proceed against or enforce any other rights or Security or claim payment from any person before claiming from the Guarantor under this Clause. This waiver applies irrespective of any law or any provision of a Finance Document to the contrary.
During the Security Period, the Lender may:
(a) |
refrain from applying or enforcing any other moneys, Security or rights held or received by it (or any trustee or agent on its behalf) for amounts that may be or become payable by the Borrower under the Finance Documents, or apply and enforce the same in such manner and order as it sees fit (whether against those amounts or otherwise) and the Guarantor will not be entitled to the benefit of the same; and |
Page 23
(b) |
hold in an interest-bearing suspense account any moneys received from the Guarantor or on account of the Guarantor's liability under this Clause 17. |
(a) |
receive or claim payment from or be indemnified by the Borrower; |
(b) |
claim any contribution from any other guarantor of, or provider of Security for, the Borrower's obligations under the Finance Documents; |
(c) |
take the benefit (in whole or in part and whether by way of subrogation or otherwise) of any rights of the Lender under any Finance Document or of any guarantee or Security taken pursuant to, or in connection with, the Finance Documents by the Lender; |
(e) |
exercise any right of set-off against the Borrower; or |
(f) |
claim or prove as a creditor of the Borrower in competition with the Lender. |
17.9.2 |
If the Guarantor receives any benefit, payment or distribution in relation to any rights referred to in Clause 17.9.1 it shall hold that benefit, payment or distribution on trust for the Lender and shall promptly pay or transfer the same to the Lender or as the Lender may direct for application in accordance with Clause 26 (Payment mechanics). The Guarantor must comply with this Clause only to the extent necessary to enable all amounts which may be or become payable to the Lender by the Borrower under or in connection with the Finance Documents to be repaid in full. |
During the Security Period, the Guarantor must not take, or retain, any Security from the Borrower or any other person in connection with any of the Guarantor's liabilities under this Agreement without the consent of the Lender.
17.11 |
Interest provisions applicable to the Guarantor |
17.11.1 |
For the purposes of the Interest Act (Canada) and disclosure under it, the rates of interest under this Agreement are nominal rates, and not effective rates or yields. The principle of deemed reinvestment of interest does not apply to any interest calculation under this Agreement. |
17.11.2 |
Any provision of this Agreement that would oblige the Guarantor to pay any fine, penalty or rate of interest on any arrears of principal or interest secured by a mortgage on real property or hypothec on immovables that has the effect of increasing the charge on arrears beyond the rate of interest payable on principal money not in arrears shall not apply to the Guarantor. In this case, the Guarantor shall be required to pay interest on money in arrears at the same rate of interest payable on principal money not in arrears. |
17.11.3 |
If any provision of this Agreement would oblige the Guarantor to make any payment of interest or other amount payable to the Lender in an amount or calculated at a rate that would be prohibited by Canadian law or would result in a receipt by the Lender of "interest" at a "criminal rate" (as such terms are construed under the Criminal Code (Canada)), then, notwithstanding that provision, that amount or rate shall be deemed to have been adjusted |
Page 24
with retroactive effect to the maximum amount or rate of interest, as the case may be, as would not be so prohibited by applicable law or so result in a receipt by the Lender of "interest" at a "criminal rate", such adjustment to be effected, to the extent necessary (but only to the extent necessary), as follows: |
(a) |
first, by reducing the amount or rate of interest; and |
(b) |
thereafter, by reducing any fees, commissions, costs, expenses, premiums and other amounts required to be paid that would constitute interest for purposes of section 347 of the Criminal Code (Canada). |
Each Obligor warrants and represents to the Lender as set out in this Clause 18. The Lender is relying on these representations when entering this Agreement.
18.1.1 |
The Borrower is an exempted company duly incorporated with limited liability under the laws of the Cayman Islands and the Guarantor is a company duly incorporated under the laws of the province of British Columbia, Canada and each is duly organised and validly existing and in good standing under the laws of its jurisdiction of incorporation. |
18.1.2 |
It has the power to: |
(a) |
sue and be sued in its own name; |
(b) |
own its assets; and |
(c) |
carry on its business as it is doing currently. |
18.2 |
Binding obligations |
Subject to any general principles of law limiting its obligations that are specifically mentioned in any Legal Opinion:
(a) |
each Transaction Security Document creates the Security that Transaction Security Document purports to create and that Security is valid and effective in each Relevant Jurisdiction; and |
(b) |
the obligations expressed to be assumed by it in each Finance Document are legal, valid, binding and enforceable. |
18.3 |
Non-conflict with other obligations |
Its entry into and performance of, and the transactions contemplated by, the Finance Documents, and the granting of the Transaction Security, do not and will not conflict with:
(a) |
any law or regulation applicable to it or any of its assets; |
(b) |
its constitutional documents; or |
(c) |
any agreement or instrument binding on it or any of its assets or trigger a default or termination event (however described) under any such agreement or instrument. |
Page 25
18.4 |
Power and authority |
18.4.1 |
It has the power to: |
(a) |
enter into, execute, deliver and perform its obligations under the Finance Documents; and |
(b) |
carry out its role in the transactions contemplated by them, |
and all corporate, shareholder and other action necessary to authorise that entry into, execution, delivery and performance has been taken.
18.4.2 |
In the case of the: |
(a) |
Borrower, borrowing the Commitment, granting the Transaction Security and giving the indemnities it gives under the Finance Documents will not exceed any limit on its powers; and |
(b) |
Guarantor, guaranteeing the Commitment and giving the indemnities it gives under this Agreement will not exceed any limit on its powers. |
18.5.1 |
It has obtained or effected all Authorisations required or desirable in any Relevant Jurisdiction: |
(a) |
for it lawfully to enter into, and exercise its rights and perform its obligations under the Finance Documents and, in the case of the Borrower, the Commercial Contracts; |
(b) |
to make the Finance Documents and, in the case of the Borrower, the Commercial Contracts admissible in evidence; and |
(c) |
for it to carry on its business, trade and ordinary activities, |
and these are in force.
18.6 |
Governing law and enforcement |
18.6.1 |
The choice of governing law of each Finance Document will be recognised and enforced in each Relevant Jurisdiction. |
18.6.2 |
Any arbitral award obtained in relation to a Finance Document in the jurisdiction of the governing law chosen for that Finance Document (i.e. England and English law for this Agreement) will be recognised and enforced in each Relevant Jurisdiction. |
18.6.3 |
The Transaction Security is enforceable in each Relevant Jurisdiction and will be recognised as giving the Lender secured creditor status over the assets to which it relates. |
It has not taken any action nor (to the best of its knowledge and belief) have any steps been taken or legal proceedings been started or threatened against it:
(a) |
for its winding-up, dissolution or re-organisation; |
(c) |
to appoint a liquidator, supervisor, receiver, administrator, administrative receiver, compulsory manager, trustee or other similar officer of it or over any of its assets, |
Page 26
nor (to the best of its knowledge and belief) have any of these events occurred in relation to any Buyer under an Export Contract.
It is not required to make any deduction for or on account of Tax from any payment it may make under any Finance Document.
18.9 |
No filing or stamp taxes |
(a) |
file, record or enrol any of the Finance Documents with any court or other authority; or |
(b) |
pay any stamp, registration or similar Tax on or in relation to any of the Finance Documents or the transactions contemplated by them, |
in any Relevant Jurisdiction.
18.10 |
Compliance with Tax laws |
In all jurisdictions in which it is subject to Tax:
(a) |
it has complied with all Tax laws; |
(b) |
it has paid all Taxes due and payable by it; and |
(c) |
no claims for Tax are being asserted against it except: |
(i) |
for Tax liabilities arising in the ordinary course of its day-to-day trading activities; and |
(ii) |
claims it is contesting in good faith where it has made adequate provision for these claims and has disclosed this provision to the Lender in its latest financial statements or some other document. |
18.11 |
No default |
18.11.1 |
No Event of Default is continuing or might reasonably be expected to result from any Utilisation. |
18.11.2 |
No other event or circumstance is outstanding that is likely to have a Material Adverse Effect and that: |
(a) |
is a default or termination event (however described); or |
(b) |
would, with any one or more of the following, be a default or termination event (however described): |
(i) |
the expiry of a grace period; |
(ii) |
the giving of notice; |
(iii) |
the making of any determination; or |
Page 27
(iv) |
the satisfaction of any other condition, |
under any agreement or instrument (other than a Finance Document) binding on it or any of its assets.
18.12 |
No misleading information |
18.12.1 |
All factual information provided by or for it in writing in connection with the Facility or any Finance Document: |
(a) |
was accurate in all material respects when provided or as at the date (if any) at which it is stated; and |
(b) |
remains accurate (to the extent that no corrections have been notified in writing to the Lender by or for it). |
18.12.2 |
There is no fact or circumstance about its affairs that has not been disclosed in writing to the Lender where that non-disclosure makes any of that information misleading. |
18.12.3 |
All expressions of expectation, intent, belief and opinion in any of that information were honestly made on reasonable grounds after careful consideration. |
18.13 |
Full disclosure |
It has fully disclosed in writing to the Lender all facts about itself, the Production Facilities and the Commercial Contracts that:
(a) |
it knows or reasonably should know; and |
(b) |
are material for disclosure to the Lender in the context of the Finance Documents. |
18.14 |
Financial statements |
18.14.1 |
The Guarantor’s Original Financial Statements were prepared using the Accounting Principles consistently applied. |
18.14.2 |
The Guarantor’s Original Financial Statements fairly represent its (or, in the case of the Guarantor, the Group's) financial condition and operations as at the end of and for the relevant financial year. |
18.14.3 |
There has been no material adverse change in its business, financial condition, assets or prospects since 30 November 2010. |
18.14.4 |
Each set of management accounts it most recently delivered under Clause 19.1(b) or 19.1(c) shows with reasonable accuracy its financial condition during the period to which they relate. |
18.15 |
Ranking |
18.15.1 |
Its payment obligations under the Finance Documents rank at least equally with the claims of all its unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally. |
18.15.2 |
The Transaction Security has or will have first ranking priority and it is not subject to any higher or equal-ranking Security. |
18.16 |
No proceedings pending or threatened |
18.16.1 |
No litigation, arbitration or administrative proceedings before any court, tribunal or other arbitral body or agency have been started or (to the best of its knowledge and belief) are |
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pending or threatened against it that, if adversely determined, could reasonably be expected to have a Material Adverse Effect. |
18.16.2 |
No judgment or award given against it by any court, tribunal, arbitral or other body or agency remains unsatisfied. |
18.16.3 |
To the best of its knowledge and belief nothing mentioned in Clause 18.16.1 or 18.16.2 applies to any Buyer under an Export Contract. |
18.17.1 |
Neither its execution of the Finance Documents, nor it exercising its rights or performing its obligations under them, will trigger the creation of, or any obligation to create, any Security (other than the Transaction Security) over any of its assets. |
18.17.2 |
In the case of the Borrower only, no Security other than Permitted Security and the Trafigura Permitted Security exists or will come into existence over any of its assets. |
18.18.1 |
The Borrower is complying with Clause 21.6 (Environmental compliance). |
18.18.2 |
It has every Environmental Permit required under Environmental Law to: |
(a) |
conduct its business; or |
(b) |
own, use, exploit or occupy its assets, |
and it is not aware of anything that would entitle the relevant issuing body to revoke, suspend, or unfavourably change any of those Environmental Permits.
18.18.3 |
There is no Environmental Claim outstanding or (to the best of its knowledge and belief) threatened against it that has, or if determined against it is reasonably likely to have, a Material Adverse Effect. |
18.19.1 |
No Security or Quasi-Security exists over any of its assets other than as allowed under the Finance Documents. |
18.19.2 |
It has no Financial Indebtedness outstanding other than as allowed under the Finance Documents. |
18.20.1 |
It has a good, valid and marketable title to, or valid leases or licences of, and all necessary Authorisations to use, the assets it needs to carry on its business as now conducted. |
18.20.2 |
Ignoring any rights the Lender may have under the Transaction Security, the Borrower is the sole legal and beneficial owner of any and all the Security Assets. |
18.21 |
Commodity Contracts |
18.21.1 |
Each Commodity Contract: |
(a) |
constitutes the legal, valid and binding obligations of the parties to it; |
(b) |
is enforceable in accordance with its terms and is in force; and |
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(c) |
has not been terminated or varied except as expressly allowed under the Finance Documents. |
18.21.2 |
All amounts expressed to be payable under each Commodity Contract are payable in full on the dates stated in that contract. |
18.21.3 |
There are no written or oral agreements or arrangements between it and any Buyer under any Commodity Contract that derogate from the obligations of that Buyer under any Commodity Contract. |
18.22 |
Force majeure |
It is not aware of any existing event, fact or circumstance that constitutes a force majeure (however named or described) under any Commodity Contract.
The Borrower has the technical and financial abilities and the Production Facilities have the production capacity necessary for the Borrower to fulfil its obligations under the Commodity Contracts.
The representations in this Clause 18 will survive the execution of this Agreement. Each Obligor is deemed to repeat the Repeating Representations on:
(a) |
the date of each Utilisation Request; and |
(b) |
the first day of each Interest Period, |
by reference to the facts and circumstances then existing.
The undertakings in this Clause 19 remain in force until the Security Period ends.
The Guarantor must supply to the Lender as soon as they become available but in any event within:
(a) |
120 days after the end of each of its financial years, its audited and consolidated financial statements for that financial year; |
(b) |
60 days after the end of each half of each of its financial years, its consolidated financial statements for that half of its financial year; |
(c) |
60 days after the end of each of its financial quarters, its consolidated management accounts for that financial quarter, |
in each case, in form and substance satisfactory to the Lender, together with any additional financial information created by the Guarantor in the ordinary course of its financial reporting which the Lender requests for the purpose of testing the Borrower's compliance with the covenants in Clause 20.2 (Financial Covenants).
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19.2.1 |
A director or the chief financial officer of the Guarantor must certify each set of financial statements delivered under Clause 19.1 (Financial statements). The certification must confirm that the consolidated financial statements fairly represent the Guarantor's consolidated financial condition and operations as at the end of, and for the period to which, those financial statements relate. |
19.2.2 |
The Guarantor must procure that each set of financial statements it delivers under Clause 19.1 (Financial statements) is prepared using: |
(a) |
the Accounting Principles; and |
(b) |
subject to Clause 19.2.3, accounting practices and financial reference periods consistent with those used to prepare its Original Financial Statements. |
(a) |
notify the Lender of this; and |
(b) |
procure that its auditors deliver to the Lender a description of the differences. The description must contain enough information to enable the Lender to make an accurate comparison between the financial positions shown in those financial statements and the Original Financial Statements. It must be delivered before or when those financial statements are delivered under Clause 19.1 (Financial statements). |
19.3 |
Notice of Orders |
The Borrower undertakes to provide the Lender with a copy of any Order (as defined below) it receives if complying with that Order will have or is likely to have a Material Adverse Effect. In this Clause Order means any notice, order, claim or other requirement from a regulatory body, court or third party. If the Borrower must provide the Lender with an Order it will provide it, together with relevant background information, within five Business Days of receiving the Order.
19.4 |
Information: miscellaneous |
Each Obligor must supply to the Lender:
(a) |
all documents sent by that Obligor to its: |
(i) |
shareholders (or any class of them) in their shareholder capacity; or |
(ii) |
creditors generally, |
at the same time as they are sent;
(b) |
promptly on becoming aware of them, details of: |
(i) |
any litigation, arbitration or administrative proceedings or Environmental Claim that is current, threatened or pending against any Obligor; and |
(ii) |
any event or circumstance that is reasonably likely to result in litigation, arbitration or administrative proceedings or an Environmental Claim being started or threatened against any Obligor, |
Page 31
that, if determined against that Obligor, would be reasonably likely to have a Material Adverse Effect; and
19.5 |
Notification of default |
19.5.1 |
The Borrower must notify the Lender of any Default (and the steps, if any, being taken to remedy it) promptly on becoming aware that it has occurred. |
19.5.2 |
If the Lender so requests, the Borrower must promptly provide a certificate signed by two of its directors or senior officers. The certificate must confirm that no Default is continuing (or if a Default is continuing, specify the Default and the steps, if any, being taken to remedy it). |
19.6 |
"Know your customer" checks |
Each Obligor must when asked promptly supply, or procure the supply of, any documentation and other evidence the Lender reasonably considers it needs to comply with all "know your customer" or other similar checks in connection with the Finance Documents.
19.7.1 |
The Borrower undertakes to send to the Lender, within 10 Business Days of the end of each of its financial quarters: |
(a) |
a consignment schedule setting out the quantity, specification and invoice value of: |
(i) |
the Consignments delivered under the Export Contracts during that financial quarter; |
(ii) |
the consignments of Commodity delivered under the other Commodity Contracts during that financial quarter; |
(iii) |
the Consignments scheduled to be delivered under the Export Contracts during the financial quarter immediately following that financial quarter; and |
(iv) |
the consignments of Commodity scheduled to be delivered under the other Commodity Contracts during the financial quarter immediately following that financial quarter; |
(b) |
a stock report setting out: |
(i) |
the quantity and specification of the Inventory as at the last day of that financial quarter; |
(ii) |
the total quantity and specification of Commodity delivered under Commodity Contracts during that financial quarter; |
(iii) |
the estimated total quantity and specification of Commodity to be delivered under Commodity Contracts during the financial quarter immediately following that financial quarter; and |
(iv) |
the quantity of Commodity extracted from the Production Facilities during that financial quarter; |
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(v) |
the estimated quantity of Commodity that will be extracted from the Production Facilities during the financial quarter immediately following that financial quarter. |
19.7.2 |
The Borrower undertakes to send to the Lender, each calendar year during the Security Period on or before 15 March, a Crude Oil Reserve Report. |
19.8 |
Change of shareholder structure |
The Obligors undertake to ensure that the Lender receives at least 15 Business Days' (or such shorter period as the Lender agrees) notice of any change in the structure of the Borrower's issued shares including any new issue of shares, any reduction in the Borrower's issued share capital and any change in the rights attaching to any shares in the Borrower or any rights in them.
19.9 |
Trafigura Prepayment Agreement |
19.9.1 |
The Borrower must promptly on the Lender’s request provide the Lender with: |
(a) |
a copy of the Trafigura Prepayment Agreement signed by the parties to it; |
(b) |
details of the amounts of prepayments made under the Trafigura Prepayment Agreement and the aggregate amount of such prepayment(s); |
(c) |
a copy of the documents granting or purporting to grant the Trafigura Permitted Security signed by the parties to it; |
(d) |
details of the Trafigura Permitted Security and any assets subject to the Trafigura Permitted Security; and |
(e) |
a copy of the guarantee granted by the Guarantor in favour of Trafigura in respect of the Borrower’s obligations under the Trafigura Prepayment Agreement (the Trafigura Guarantee) and any other security or guarantee being granted to Trafigura by the Borrower or the Guarantor. |
19.9.2 |
The Borrower must notify the Lender of any default (however described) under the Trafigura Prepayment Agreement promptly on becoming aware that it has occurred. |
19.9.3 |
The Borrower shall each month notify the Lender in writing about the aggregate amount which it has set off pursuant to the Trafigura Prepayment Agreement in that month within 5 Business Days from the end of that month |
19.9.4 |
No Obligor shall enter into, or make any amendment to, any document referred to in this Clause 19.9, without the prior written consent of the Lender. |
19.10 |
Bond Programme |
19.11 |
The Borrower must promptly on the Lender’s request provide the Lender with information in relation to the Bond Programme including copies of any Programme Document (including drafts of the same) and any other details of the Borrower's payment and other obligations under the Bond Programme. |
19.11.1 |
The Borrower must notify the Lender of any default (however described) under the Bond Programme immediately on becoming aware that it has occurred. |
The undertakings in this Clause remain in force until the Security Period ends.
Page 33
In this Agreement the following definitions apply. Any financial terms used in this Agreement in connection with the Borrower that are not defined in this Agreement must, unless otherwise indicated, be interpreted in accordance with the Accounting Principles.
Borrowings means, at any time, the aggregate outstanding principal, capital or nominal amount (and any fixed or minimum premium payable on prepayment or redemption) of any indebtedness of the Borrower for or in respect of:
(b) |
any acceptances under any acceptance credit or bill discount facility (or dematerialised equivalent); |
(c) |
any note purchase facility or the issue of bonds, notes, debentures, loan stock or any similar instrument; |
(d) |
any Finance Lease; |
(e) |
receivables sold or discounted (other than any receivables to the extent they are sold on a non-recourse basis); |
(f) |
any counter-indemnity obligation in respect of a guarantee, bond, standby or documentary letter of credit or any other instrument issued by a bank or financial institution at the Borrower's request; |
(g) |
any amount raised by the issue of shares which are redeemable (other than at the option of the issuer); |
(h) |
any amount of any liability under an advance or deferred purchase agreement if (i) one of the primary reasons behind the entry into the agreement is to raise finance or to finance the acquisition or construction of the asset or service in question or (ii) the agreement is in respect of the supply of assets or services and payment is due more than 90 days after the date of supply; |
(j) |
(without double counting) the amount of any liability in respect of any guarantee or indemnity for any of the items referred to in paragraphs (a) to (i) above. |
EBIT means, in respect of any Relevant Period, the operating profit of the Borrower before taxation:
(a) |
before deducting any Finance Charges; |
(b) |
not including any accrued interest owing to the Borrower; |
(c) |
before taking into account any Exceptional Items; and |
(d) |
before taking into account any realised and unrealised exchange gains and losses that do not relate to ordinary trading activities, |
in each case, to the extent added, deducted or taken into account, as the case may be, for the purposes of determining operating profits of the Borrower before taxation.
Page 34
EBITDA means, in respect of any Relevant Period, EBIT for that Relevant Period after adding back any amount attributable to the amortisation or depreciation of non-current assets of the Borrower.
Exceptional Items means any exceptional, one off, non-recurring or extraordinary items.
Finance Charges means, for any Relevant Period, the total amount of the accrued interest, commission, fees, discounts, prepayment fees, premiums, charges and other finance payments in respect of Borrowings whether paid or payable by the Borrower in respect of that Relevant Period and all other amounts payable that are classified as finance charges under the Accounting Principles:
(a) |
including any upfront fees or costs; |
(b) |
including the interest (but not the capital) element of payments in respect of Finance Leases; |
(c) |
including any commission, fees, discounts and other finance payments payable by (and deducting any such amounts payable to) the Borrower under any interest rate hedging arrangement; |
(d) |
(if not already taken into account) deducting the net amount receivable or adding the net amount payable by the Borrower in relation to that Relevant Period under any hedging agreement relating to financing and excluding amounts included in the profit and loss account which represent changes in the value of derivatives relating to cash flows in future periods; and |
(e) |
taking no account of any unrealised gains or losses on any a hedge item recognised in profit or loss arising from its accounting treatment as a hedge item in a fair value hedge as defined by IAS 39, |
(a) |
so that no amount shall be added (or deducted) more than once. |
Finance Lease means any lease, hire agreement, credit sale agreement, hire purchase agreement, conditional sale agreement or instalment sale and purchase agreement that should be treated as a finance lease or in the same way as a finance lease under the Accounting Principles.
IAS together with a number means the international accounting standard issued by the Board of the International Accounting Standards Committee and adopted by the International Accounting Standards Board and identified by reference to that number.
Relevant Period means:
(a) |
a period starting no earlier than 1 January 2012 and ending on the last day of the Borrower's financial year; |
(b) |
each subsequent period of 12 months; and |
(c) |
any other period of 12 months that the Lender specifies in a request it makes under Clause 20.3.2. |
The Borrower will ensure that during each Relevant Period, unless the Lender otherwise agrees:
(a) |
its EBITDA is not less than $10,000,000; |
Page 35
(b) |
its Borrowings are never more than twice its EBITDA; and |
(c) |
its EBITDA is at least ten times greater than its Finance Charges. |
The undertakings in this Clause 21 remain in force until the Security Period ends.
21.1 |
Authorisations |
The Borrower undertakes to obtain, comply with and maintain in force, and when asked promptly to supply Certified Copies to the Lender of, any Authorisation required in any Relevant Jurisdiction to:
(a) |
carry on its business, trade or ordinary activities; |
(b) |
exercise its rights or perform its obligations under any Finance Document or Commercial Contract; or |
(c) |
make any Finance Document or Commercial Contract admissible in evidence. |
21.2 |
Compliance with laws |
The Borrower undertakes to comply in all respects with all laws to which it may be subject, if failure to do so would materially impair its ability to perform its obligations under the Finance Documents or any Commercial Contract.
21.3.1 |
This undertaking is subject to Clause 21.3.2. The Borrower undertakes to pay all Taxes and governmental charges payable by it before they become overdue. |
(a) |
are being contested in good faith; and |
(b) |
may lawfully be withheld, |
and for which the Borrower has set aside adequate reserves.
21.4 |
Access |
The Borrower undertakes to allow:
(a) |
the Lender; and |
Page 36
(b) |
any person that is an accountant, auditor, solicitor, valuer or other professional adviser of the Lender, |
access, during normal business hours and on reasonable notice to:
(i) |
the Production Facilities; |
(ii) |
all other property and premises of the Borrower; and |
(iii) |
all officers, accounting books, records, computer programs and other data or information of the Borrower, |
to the extent reasonably necessary to monitor the Borrower's compliance with, and performance under, the Finance Documents or any Commercial Contract.
21.5 |
Further assurance |
The Borrower undertakes, when asked by the Lender, to:
(a) |
do or procure the doing of all things; and |
(b) |
execute or procure the execution of all documents, |
the Lender considers necessary or desirable (acting reasonably) to ensure the Lender obtains all the rights and benefits intended to be conferred on it under the Finance Documents.
The Borrower undertakes to:
(a) |
comply in all material respects with Environmental Law; |
(b) |
obtain, maintain and comply with all Environmental Permits required to conduct its business or to own, use, exploit or occupy its assets; and |
(c) |
have in place procedures to check compliance with and to prevent liability under Environmental Law. |
(a) |
insure all its assets and business of an insurable nature with reputable insurers of good standing; |
(b) |
comply with all insurance conditions imposed by any lease, agreement for lease or tenancy under which the Borrower derives an interest; |
(i) |
are on the same terms and cover the same risks as those normally taken out by prudent companies owning or possessing similar assets and carrying on similar businesses to the Borrower's; and |
(ii) |
are in such amounts as is prudent (including for the full replacement value from time to time of any assets destroyed or otherwise becoming a total loss); |
(d) |
ensure the Lender is endorsed on the policies as loss payee; |
Page 37
(e) |
pay when due all premiums and other amounts payable under the Insurances and, promptly when asked by the Lender, produce receipts for payment of the premiums; |
(f) |
promptly when asked by the Lender, deposit with or produce for inspection to the Lender all policies and other contracts for the Insurances; and |
(g) |
use reasonable endeavours to prevent any act, omission or circumstance that would be reasonably likely to render void or voidable any of the Insurances. |
The Borrower undertakes to maintain full ownership and control over the management and operation, of the Production Facilities.
For each Export Contract, the Borrower undertakes to present all Consignment Documents to the Buyer (or the Buyer's bank, or the relevant issuing or confirming bank) via the Lender.
The Borrower undertakes to notify the Lender immediately on realising that a material quantity of Commodity in a Consignment:
(a) |
is destroyed, lost, stolen or damaged in any way; or |
(b) |
does not meet the specification required by the relevant Export Contract, |
and, if appropriate, to file a claim under any relevant insurance policy and keep the Lender informed about that claim.
The Borrower undertakes to perform, when due or within any applicable grace periods, its obligations and enforce its rights (including by taking legal proceedings where appropriate) under:
(a) |
each Export Contract; and |
(b) |
each other contract, agreement, instrument or other document to which it is a party, including any concessions, leases, licences and customer contracts where the failure to so perform or enforce would be likely to have a Material Adverse Effect. |
21.12.1 |
The Borrower undertakes to ensure that each Buyer pays all amounts payable by that Buyer under any Commodity Contract pursuant to an invoice issued after the date of this Agreement: |
(a) |
directly to a bank account held with the Lender in the name of the Borrower; and |
Page 38
(b) |
subject to Clause 21.12.2, in full and without any set‑off, deduction, counterclaim or condition. |
21.12.2 |
Any set-off or deductions by Trafigura in respect of amounts payable under its Export Contract with the Borrower no. SKO-012-453470 shall not constitute a breach of Clause 21.12.1(b) to the extent such set-off or deductions are permitted under the terms of the Trafigura Coordination Agreement. |
If the Lender notifies the Borrower that:
(a) |
in the Lender's opinion; |
(b) |
for whatever reason (be it breach of contract, reduction in the price of Commodity or otherwise); and |
(c) |
there is a risk that the payments for the Consignments to be delivered under the Export Contracts will not be enough to satisfy the Borrower's obligations under the Finance Documents as they fall due, |
the Borrower undertakes, within ten Business Days of the Lender's notice, to:
(i) |
designate one or more additional or replacement Export Contracts; or |
(ii) |
amend the terms of one or more of the existing Export Contracts, |
so that the total volume and value of Commodity to be delivered under the Export Contracts will increase to such a level that the circumstances specified in the Lender's notice are, in the Lender's opinion, no longer likely to occur.
The Borrower undertakes to ensure:
(a) |
for each Consignment, that it has enough Commodity available to deliver that Consignment in accordance with the terms of the relevant Export Contract; and |
21.15 |
Bank accounts |
The Borrower undertakes to open and maintain its main bank accounts in Albania with the Lender and to ensure that all amount due to or from it under any Commercial Contract are paid to, from or through a bank account the Borrower holds with the Lender.
The undertakings in this Clause 22 remain in force until the Security Period ends.
22.1.1 |
The Borrower undertakes not to incur or allow to remain outstanding any Financial Indebtedness other than: |
Page 39
(b) |
Financial Indebtedness existing on the date of this Agreement and already notified to the Lender to the extent that the amount and tenor of that Financial Indebtedness is not increased or extended; |
(c) |
trade credit with a duration of no more than 90 days that it entered into in the ordinary course of its day-to-day trading activities; |
(e) |
Financial Indebtedness approved by the Lender in advance; |
(f) |
Financial Indebtedness incurred under the Trafigura Prepayment Agreement, subject to the limit set out in the Trafigura Coordination Agreement; and |
(g) |
Financial Indebtedness incurred under the Bond Programme up to maximum aggregate amount of $60,000,000 (or its equivalent in other currencies). |
22.1.2 |
If the Borrower wishes to obtain approval from the Lender for any Financial Indebtedness, it must request approval of at least 15 Business Days before it will incur that Financial Indebtedness (or such shorter period as the Lender agrees) and provide the Lender with all information about the proposed Financial Indebtedness that the Lender reasonably requests including its amount, currency, type, tenor and the identity of the creditor(s). |
22.1.3 |
The Guarantor undertakes to ensure that the Borrower does not incur any Financial Indebtedness to any member of the Group other than Financial Indebtedness that falls within Clause 22.1.1(d). |
22.2.1 |
This Clause is subject to Clause 22.2.2. The Borrower undertakes not, without the Lender's consent, to enter into a single transaction or a series of transactions whether: |
(a) |
related or not; |
(b) |
voluntary or involuntary; and |
(c) |
at the same time or over a period, |
to sell, lease, transfer, license or otherwise dispose of any asset.
22.2.2 |
While no Default is continuing, Clause 22.2.1 will not apply to a disposal of an asset that is Inventory, or that is not a Security Asset, as long as that disposal is: |
(b) |
of cash, not otherwise prohibited by the Finance Documents; |
(c) |
on arm's-length terms in exchange for other assets of comparable or superior type, value and quality; |
(d) |
on arm's-length terms where the Borrower uses the proceeds of that disposal within one Month to purchase an asset to replace directly the asset disposed of; or |
(e) |
on arm's-length terms where the sum of the higher of the market value or consideration receivable for: |
Page 40
(i) |
that disposal; and |
(ii) |
every other disposal by the Borrower in the same financial year that is not allowed under paragraphs (a) to (d) above, |
is not more than $100,000 (or its equivalent in any other currency or currencies),
or to the disposal of a Security Asset that is expressly contemplated by, and allowed under, the Finance Documents.
22.3.1 |
This Clause is subject to Clause 22.3.3. The Borrower undertakes not to create or allow to subsist any Security over any of its assets. |
(a) |
sell, transfer or otherwise dispose of any of its assets on terms whereby they will or may be leased to or re-acquired by the Borrower; |
(b) |
sell, transfer or otherwise dispose of any of its receivables on recourse terms; |
(c) |
enter into any arrangement under which money or the benefit of a bank or other account may be applied, set off or made subject to a combination of accounts; or |
(d) |
enter into any other preferential arrangement having a similar effect, |
in circumstances where the arrangement or transaction is entered into chiefly to raise Financial Indebtedness or to finance the purchase of an asset.
(b) |
any netting or set-off arrangement the Borrower enters into in the ordinary course of its banking arrangements to net off debit and credit balances, but only so long as those arrangements do not allow credit balances of the Borrower to be netted or set off against the debit balances of any other person; |
(c) |
any lien arising by law and in the ordinary course of the Borrower's day-to-day trading activities (and not as a result of any default or omission by the Borrower) that relates to an obligation that is: |
(i) |
less than 60 days overdue; or |
(ii) |
being contested in good faith by appropriate means; |
(d) |
any Security or Quasi-Security over any asset the Borrower acquires after the date of this Agreement if: |
(i) |
the Security or Quasi-Security was not created in contemplation of the acquisition; |
(ii) |
the principal amount secured has not been increased in contemplation of, or since, the acquisition; and |
(iii) |
the Security or Quasi-Security is removed within two Months of the date of the acquisition; |
Page 41
(e) |
any guarantee, indemnity or Security given, or any disposal required, under any Finance Document. |
(f) |
any retention of title to goods supplied to the Borrower in the ordinary course of its day-to-day trading activities; |
(h) |
the Trafigura Permitted Security. |
22.4 |
Subordination |
The Borrower shall ensure that the rights of the bondholders under the Bond Programme are fully subordinated by the terms of the Bond Programme to the rights of the Lender under the Finance Documents during the Security Period and accordingly the Borrower shall not make any payment to the bondholders (whether or principal, interest or otherwise) prior to the expiry of the Security Period.
22.5 |
Dividends and other funds withdrawals |
22.5.1 |
This Clause is subject to Clause 22.5.2. The Obligors undertake to ensure that, during the Security Period, unless the Lender agrees otherwise: |
(a) |
no dividends are declared or paid on any of the Borrower's issued share capital or any other form of paper issued by the Borrower; |
(b) |
the Borrower does not redeem, buy back, reduce or repay any of its issued share capital or any other form of paper it has issued; |
(c) |
the Borrower does not transfer funds to any other member of the Group: |
(i) |
to pay, repay or service any Financial Indebtedness owed by the Borrower (whether as principal or as a secondary obligor) to another member of the Group; or |
(ii) |
to grant any Financial Indebtedness to any other member of the Group, |
or for any other reason the purpose of which is wholly or partially to extract funds from the Borrower for the benefit of other members of the Group or the Group as a whole;
(d) |
the Borrower does not fail to pursue any amount owing to it by any person or pay any amount owed by another member of the Group to any person in place of that member of the Group or allow any cross-Group set-off to be exercised by any person against any of its assets; and |
(e) |
no funds are extracted from the Borrower by any other method wholly or partially with the intention of benefiting other members of the Group or the Group as a whole, |
and in particular that no funds are extracted from the Borrower's Albanian branch.
Page 42
12-month period ending on the last Business Day of the calendar month immediately before the proposed payment date. It must contain sufficient financial information to allow the Lender to check the Borrower's calculations. The Borrower must deliver this certificate to the Bank at least 10 Business Days before the proposed payment date. If the Lender does not agree with the Borrower's calculation, it must notify the Borrower of this at least two Business Days before the proposed payment date. |
22.5.3 |
In this Clause the financial definitions in Clause 20.1 (Financial definitions) and the following definitions apply. |
Excess Cash Flow means, for the relevant period:
EBITDA plus
(a) |
any decrease in Working Capital as at the last day of that period when compared to Working Capital on the first day of that period; |
(b) |
cash receipts for any exceptional one-off, non-recurring or extraordinary items; |
(c) |
any tax rebates or credits in cash; |
(d) |
the amount of any dividends or other profit distributions received in cash by the Borrower; |
(e) |
the amount of any increase in provisions, other non-cash debits and other non-cash charges; |
(f) |
the amount of proceeds received from disposals of fixed assets; and |
(g) |
any realized gains in cash on any financial instrument (other than any derivative instrument on a hedge accounting basis). |
minus
(i) |
any increase in Working Capital as at the last day of that period when compared to Working Capital on the first day of that period, |
(ii) |
any amount actually paid in respect of taxes; |
(iii) |
the amount of any non-cash credits; |
(iv) |
the amount of any capital expenditure unless funded from the proceeds of a capex loan available for this purpose; |
(v) |
the amount of any cash costs of pension items; and |
(vi) |
any realized losses in cash on any financial instrument (other than any derivative instrument on a hedge accounting basis). |
Working Capital means as at any date, the Borrower's short term assets minus its short term liabilities on that date.
22.6 |
Merger |
The Borrower undertakes not to enter into any amalgamation, demerger, merger or corporate reconstruction or any joint venture or partnership agreement without the consent of the Lender.
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The Borrower undertakes not to incorporate any company as its Subsidiary.
22.8 |
Change of business |
The Borrower undertakes not to make any substantial change the general nature or scope of its business from that carried on at the date of this Agreement.
The Borrower undertakes not to use, deposit, handle, store, produce, release or dispose of any Dangerous Materials in, on, over or under any real property it owns or occupies, except as permitted under and in compliance with applicable Environmental Law.
22.10 |
Loans |
The Borrower undertakes not to make any loans or grant any credit, other than trade credit with a tenor of no more than 60 days in the normal course of its day-to-day trading activities.
22.11.1 |
The Borrower undertakes not to: |
(a) |
cancel, terminate, amend or waive any default under any Export Contract; or |
(b) |
allow any Buyer to do the same, |
except as allowed under Clause 22.11.2.
22.11.2 |
The Borrower and the relevant Buyer may agree any amendment to an Export Contract so long as: |
(a) |
it relates to the day-to-day operation of that contract; |
(b) |
it is usual for contracts of the same type as that contract; |
(c) |
it is not, in the opinion of the Lender, prejudicial to the interests of the Lender; and |
(d) |
the Borrower notifies the Lender of the amendment promptly after it is agreed. |
Each of the events and circumstances in this Clause 23, apart from Clause 23.16 (Acceleration), is an Event of Default.
An Obligor does not pay on the due date any amount payable under a Finance Document at the place at and in the currency in which it is expressed to be payable unless:
(a) |
the cause of its failure to pay is an administrative or technical error that is not its fault; and |
(b) |
it makes the payment within three Business Days of its due date. |
The Borrower does not comply with Clause 20 (Financial covenants).
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23.3 |
Other obligations |
23.3.2 |
No Event of Default will occur under Clause 23.3.1 if, in the Lender's opinion, the relevant Obligor: |
(a) |
can correct its failure to comply; and |
(b) |
does correct its failure within five Business Days of the Lender notifying that Obligor or that Obligor becoming aware of the failure. |
23.4 |
Misrepresentation etc. |
Any representation, warranty or statement an Obligor made or is deemed to have made in any:
(a) |
Finance Document; or |
(b) |
other document delivered by or for that Obligor in connection with any Finance Document, |
was incorrect or misleading in any material respect when made or deemed made.
23.5.2 |
An Obligor fails to pay any of its Financial Indebtedness when due or within any originally applicable grace period. |
23.5.3 |
Any Financial Indebtedness of an Obligor is declared or otherwise becomes due before its specified maturity because of an event of default (however described). |
23.5.4 |
Any commitment for Financial Indebtedness of an Obligor is cancelled or suspended because of an event of default (however described). |
23.5.5 |
Any creditor of an Obligor becomes entitled to declare any Financial Indebtedness of that Obligor due before its specified maturity because of an event of default (however described). |
23.5.7 |
Any of the events described in Clauses 23.5.1 to 23.5.5 (inclusive) occur in relation to the Trafigura Prepayment Agreement, the Bond Programme or issuance of bonds under the Bond Programme. The threshold in Clause 23.5.6 shall not apply to this Clause 23.5.7. |
23.6 |
Insolvency |
(a) |
is unable or admits inability to pay its debts as they fall due; or |
(b) |
because of current or anticipated financial difficulties: |
(i) |
suspends payments on any of its debts; or |
Page 45
(ii) |
proposes or starts negotiations with one or more of its creditors to reschedule any of its indebtedness. |
23.6.2 |
The value of an Obligor's assets is less than its liabilities (taking into account contingent and prospective liabilities). |
23.6.3 |
A moratorium or other protection from its creditors is declared or imposed in respect of any indebtedness of an Obligor. |
23.7.1 |
Any corporate action, legal proceedings or other procedure or step is taken in relation to: |
(a) |
an Obligor suspending payments on any of its debts where that suspension is because of, or allegedly because of, current or anticipated financial difficulties of that Obligor; |
(b) |
a moratorium of any indebtedness of an Obligor; |
(c) |
the dissolution, striking-off, administration, reorganisation, liquidation or winding-up of an Obligor (including by voluntary arrangement or scheme of arrangement); |
(d) |
a composition, compromise, assignment or arrangement with any creditor of an Obligor; |
or any analogous procedure or step is taken in any jurisdiction.
Any expropriation, attachment, sequestration, distress or execution;
(a) |
affects any of an Obligor's assets; and |
(b) |
is not discharged within seven days. |
23.9 |
Stopping business |
An Obligor suspends, stops, or threatens to suspend or stop, the carrying on of all or a substantial part of its business.
23.10.1 |
It is or becomes unlawful for an Obligor to perform any of its obligations under the Finance Documents. |
23.10.2 |
It is or becomes unlawful for: |
(a) |
any party to an Export Contract to perform any of its obligations under that contract; or |
(b) |
for the Borrower to enforce any of its rights under any Export Contract, |
and that Export Contract is not replaced within five Business Days of the Lender notifying the Borrower or the Borrower becoming aware of the unlawfulness.
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23.11.1 |
An Obligor repudiates, or shows it intends to repudiate, a Finance Document. |
23.11.2 |
Any party to a Commercial Contract repudiates, or shows it intends to repudiate, that contract and that contract is not replaced within five Business Days of the Lender notifying the Borrower or the Borrower becoming aware of the repudiation or intent. |
Any Security over any of the assets of an Obligor becomes enforceable.
23.13 |
Sureties and providers of Security |
Any of the events mentioned in Clause 23 happens in relation to any surety or provider of Security for an Obligor's obligations under any Finance Document.
23.14 |
Material adverse change |
Any one or more events or circumstances happens that has or could reasonably be expected to have a Material Adverse Effect.
23.15 |
Commodity Contract payments |
23.15.1 |
A payment to the Borrower under an Export Contract is: |
(a) |
not credited directly to a bank account held with the Lender; and |
(b) |
not transferred by the Borrower to a bank account held with the Lender within three Business days of receipt by the Borrower. |
23.15.2 |
Any amount payable by a Buyer under an Export Contract is not paid when due or within any originally applicable grace period. |
While an Event of Default is continuing the Lender may, by notice to the Borrower do any of the following:
(b) |
declare all or any of the amounts accrued or outstanding under the Finance Documents to be immediately due, after which they will be immediately due; |
(c) |
declare all or part of the Loans to be payable on demand, after which they will immediately be payable on demand by the Lender; and |
(d) |
exercise, any of its rights under the Finance Documents including rights to enforce the Transaction Security. |
The Lender may assign any of its rights under the Finance Documents to a:
(a) |
bank or financial institution; or |
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(b) |
trust, fund or other entity that is set up to make, buy or invest in loans, securities or other financial assets, or regularly does so. |
The Lender may disclose to:
(a) |
any of its Affiliates or professional advisers; |
(b) |
any rating agency; |
(c) |
any other person: |
(i) |
to (or through) whom it assigns any of its rights under this Agreement (or may do so); |
(ii) |
with (or through) whom it enters into any sub-participation relating to, or any other transaction under which payments will be made by reference to, this Agreement or any Obligor (or may do so); or |
(iii) |
to whom, and to the extent that, it must by law or regulation disclose; |
any information about any Obligor, the Group, the Finance Documents and the Commercial Contracts as the Lender considers appropriate.
No Obligor may assign any of its rights or transfer any of its rights or obligations under the Finance Documents.
25.1.2 |
Notwithstanding the provisions of Clause 26 (Payment mechanics), the Lender shall not be liable to the Borrower for the failure, or the consequences of any failure, of any cross-border payment system to effect same-day settlement to an account of any person. |
No provision of this Agreement will:
(a) |
interfere with the right of the Lender to arrange its affairs (tax or otherwise) in whatever manner it thinks fit; |
(b) |
oblige the Lender to investigate or claim any credit, relief, remission or repayment available to it or the extent, order and manner of any claim; or |
(c) |
oblige the Lender to disclose any information relating to its affairs (tax or otherwise) or any computations in respect of Tax. |
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25.3.1 |
The Borrower waives, to the extent permitted by applicable law, any right it has to require: |
(a) |
the Transaction Security or any part of it to be enforced in a particular order or manner; or |
(b) |
the proceeds of its enforcement or any part of them to be applied in a particular order or manner. |
25.3.2 |
The Lender will be liable to any other Party for any failure or delay in: |
(a) |
enforcing or giving instructions for the enforcement of the Transaction Security; or |
(b) |
(subject to the requirements of applicable law) maximising the receipts or recoveries from enforcement of the Transaction Security. |
26.1.1 |
When on Obligor must make a payment under a Finance Document, it must pay the Lender (unless a contrary indication appears in a Finance Document): |
(a) |
for value on the due date; and |
(b) |
at the time and in the funds specified by the Lender as being usual for settlement of transactions in the relevant currency in the place of payment. |
26.1.2 |
The relevant Obligor must make the payment to the account the Lender specifies. This account must be held with a bank in the principal financial centre for the currency of that payment. |
(b) |
secondly, in or towards payment pro rata of any accrued interest, fee or commission due but unpaid under this Agreement; |
(c) |
thirdly, in or towards payment pro rata of any principal due but unpaid under this Agreement; and |
(d) |
fourthly, in or towards payment pro rata of any other sum due but unpaid under the Finance Documents. |
26.2.3 |
Clauses 26.2.1 and 26.2.2 will override any appropriation any Obligor makes. |
Each Obligor must make and calculate all its payments under the Finance Documents without (and without any deduction for) set-off or counterclaim.
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26.4.1 |
Any payment due on a day that is not a Business Day must be made: |
(a) |
on the next Business Day in the same calendar month (if there is one); or |
(b) |
the preceding Business Day (if there is not). |
26.4.2 |
During any extension of the due date for payment of any principal or Unpaid Sum interest is payable on the principal or Unpaid Sum at the rate payable on the original due date. |
26.5.1 |
This Clause is subject to Clauses 26.5.2 and 26.5.3. Dollars is the currency of account and payment for any sum due from an Obligor under any Finance Document. |
26.5.2 |
The relevant Obligor must make each payment relating to costs or Taxes in the currency of those costs or Taxes. |
26.5.3 |
The relevant Obligor must pay any amount expressed to be payable in a currency other than Dollars in that other currency. |
26.6 |
Authority to debit |
The Borrower authorises the Lender to:
(a) |
withdraw money from any bank account held in the name of the Borrower with the Bank; and |
(b) |
use that money to pay all or part of any payment due from the Borrower and unpaid under the Finance Documents. |
The Lender may do this at any time without telling the Borrower in advance.
The Lender may set off any matured obligation due from an Obligor under the Finance Documents against any obligation (whether or not matured) owed by the Lender to that Obligor. This Clause applies:
(a) |
to the extent that Obligors' obligation is beneficially owned by the Lender; and |
(b) |
regardless of the place of payment, booking branch or currency of either obligation. |
If the obligations are in different currencies, to perform the set-off the Lender may convert either obligation at a market rate of exchange in its usual course of business.
This Clause 28 is about notices, deliveries of documents and other communications between the Parties under the Finance Documents. All communications must be in writing. Utilisation Requests and other notices requiring signature by an authorised signatory of an Obligor must be sent by fax or post or by email as a pdf or jpeg attachment. Any notice the Bank gives under Clause 7.1 (Illegality), 7.2 (Change of control) or 23.16 (Acceleration) or to demand payment must be given by post. In all other cases, unless indicated otherwise, Notices can be given by fax, post or email.
Page 50
28.2.2 |
Notices are sent at the Borrower’s or Guarantor’s risk. The Lender is entitled, acting in good faith, to assume that any notice or instruction it receives from an Obligor or appearing to be from an Obligor by fax, post or email is from that Obligor and is duly authorised. If the Lender questions the authenticity (which it is not obliged to do) of any notice or instruction and seeks to verify its authenticity before acting on that notice or instruction, it will not be liable to any Obligor for any delay this causes. |
28.2.3 |
The Lender may treat any notice sent to it by email that appears to be sent from the email account of an individual that is (or sent from the email account of one individual, and copied to the email accounts of other individuals who together are) authorised to bind an Obligor, as being authorised by that Obligor. |
Rr. Ismail Qemali
Samos Tower, Kati 5
Tirana, Albania
with a copy to:
#300, 609 – 14th Street N.W.,
Calgary, Alberta T2N 2A1
Attention: |
Dr. Sotirios Kapotas, Chief Executive Officer |
Email: |
skapotas@streamoilandgas.com |
with a copy to pplater@streamoilandgas.com
(b) |
The Guarantor: |
#300, 609 - 14th Street N.W.
Calgary, Alberta T2N 2A1
Attention: |
Paul Plater, Chief Financial Officer |
Email: |
jhodgson@streamoilandgas.com |
with a copy to pplater@streamoilandgas.com
(c) |
The Lender: |
European Trade Center, 6th Floor
Blvd. “Bajram Curri”
Tirana, Albania
Attention: |
Elona Koci, Head of Large Corporate and Mid Market Division |
Fax: |
+ 355 4 2275550 |
Email: |
elona.koci@raiffeisen.al |
with a copy to jorida.zaimi@raiffeisen.al
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28.3.1 |
If a Party's contact details specify a particular department or officer, any communication to that Party will only be effective if addressed to that department or officer. Communications by fax are effective only when received in legible form. Communications by letter are effective: |
(b) |
two Business Days (or for airmail, five Business Days) after being posted, postage prepaid (or, airmail postage prepaid), to the relevant address. |
28.3.2 |
Any communication to the Lender will be effective only when actually received by that Party. |
28.4.1 |
All notices under the Finance Documents must be in English. |
28.4.2 |
All other documents provided under the Finance Documents must be: |
(a) |
in English; or |
(b) |
if not in English and the Lender so requires, with a certified English translation. In this case, the English translation will prevail unless the document is a constitutional, statutory or other official document. |
In any legal proceedings connected with any Finance Document, the account entries of the Lender are prima facie evidence of the matters to which they relate.
Unless it contains an obvious error, any certification or determination by the Lender of a rate or amount under any Finance Document is conclusive evidence of that rate or amount.
Any interest, commission or fee accruing under a Finance Document will:
(a) |
accrue from day to day; and |
(b) |
be calculated based on: |
(i) |
the number of days elapsed; and |
(ii) |
a year of 360 days, |
or, where the practice in the relevant interbank market differs, following that market practice.
The invalidity, illegality or unenforceability of any provision of the Finance Documents under the law of any jurisdiction will not affect the validity, legality or enforceability of:
(a) |
any other provision of the Finance Documents under the law of that jurisdiction; or |
(b) |
any other provision of the Finance Documents under the law of any other jurisdiction. |
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This Clause is about the rights and remedies of the Lender under the Finance Documents. They do not exclude any rights or remedies provided by law but add to them. If the Lender becomes entitled to exercise any right or remedy under the Finance Documents or by law, no:
(a) |
failure to exercise; |
(b) |
delay in exercise; or |
(c) |
single or partial exercise of, |
that right or remedy will:
(i) |
adversely affect that right or remedy; |
(ii) |
waive it; or |
(iii) |
prevent any further exercise of it or of any other right or remedy. |
To waive or amend any term of the Finance Documents requires the written consent of the Lender and the Borrower. Any amendment or waiver with this consent will bind all Parties. The Guarantor agrees to any amendment or waiver permitted by this Clause 32 that the Borrower agrees. This includes any amendment or waiver that would, but for this Clause, require the consent of the Guarantor.
The representatives of the Parties may sign this Agreement in any number of counterparts, each of which counts as part of an original. This has the same effect as if the representatives of all the Parties signed the same original of this Agreement. A set of counterparts signed by the representatives of all the Parties forms one original. The representatives of the Parties may sign more than one original of this Agreement.
34.1 |
Governing law |
English law governs this Agreement, its interpretation and any non-contractual obligations arising from or connected with it.
The courts of England:
(a) |
have exclusive jurisdiction to settle any dispute arising out of or in connection with this Agreement (including a dispute about its existence, validity or termination) (a Dispute); and |
(b) |
are the most appropriate and convenient courts to settle Disputes and therefore no Party will argue to the contrary. |
This Clause is for the benefit of the Lender only. It will not prevent the Lender from taking proceedings (including concurrent proceedings) against an Obligor in any other courts with jurisdiction.
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34.3.1 |
This Clause is subject to Clause 34.3.2. Despite Clause 34.2, the Lender may refer a Dispute to be finally resolved by arbitration. |
34.3.2 |
The Lender may only exercise the option in Clause 34.3.1 if the Dispute in question is not already the subject of proceedings: |
(a) |
brought by any Party in accordance with Clause 34.2; and |
(b) |
that have not been dismissed or stayed, |
and is not suitable to bring as a counterclaim in any such proceedings.
34.3.3 |
Any Dispute referred to arbitration under this Clause must be decided using the Rules of Conciliation and Arbitration of the London Court of International Arbitration. Those Rules are deemed to be incorporated by reference into this Clause to the extent they do not conflict with its express provisions. The tribunal will consist of one arbitrator. The seat of the arbitration will be London, even if any hearings take place elsewhere. The language of the arbitration will be English. The tribunal must give a written record of its award and the reasons for it. |
34.3.4 |
The main Parties involved in the Dispute must jointly appoint the arbitrator not later than 28 days after service of a written request by any Party to do so. If they are unable to agree within 28 days on the appointment of the arbitrator, any Party may apply to the London Court of International Arbitration to appoint the sole arbitrator. |
34.4 |
Consent to enforcement |
(a) |
enforcement; |
(b) |
execution; and |
(c) |
attachment, |
(whether before judgment, in aid of execution, or otherwise) against any of its assets.
34.4.2 |
In this Clause legal proceedings includes any: |
(a) |
service of process, suit, or judgment; |
(b) |
execution or attachment (whether before judgment, in aid of execution, or otherwise); |
(c) |
court proceedings under Clause 34.2; |
(d) |
arbitral proceedings under Clause 34.3; and |
(e) |
other dispute resolution mechanism. |
34.5.1 |
If the Lender so requests, the Borrower must, within three Business Days, appoint (for itself and each other Obligor) an agent (with an office in London, United Kingdom) for service of all claim forms, application notices, judgments, orders or other notices of English legal process relating to this Agreement and notify the agent’s address to the Lender. If the Borrower does not do this, the Lender may appoint a service agent on the Borrower’s behalf and at its expense. If the Lender does this, it must notify the Borrower it has done so and provide details of the service agent as soon as reasonably practicable. The Borrower agrees to |
Page 54
reimburse to the Lender on its demand the expenses relating to the appointment of the service agent. |
34.5.2 |
If the Borrower wishes to change the Obligors' address for service it may do so by giving the Lender at least 20 Business Days' written notice of its new address for service. |
The Parties have entered into this Agreement on the date stated at the beginning of this Agreement.
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Schedule 1 - Conditions precedent
Note: The documents set out in Schedule 1 were provided and all relevant conditions precedent satisfied at the time of entering into the original agreement. Clause 4.1 (Initial Conditions precedent) and Schedule 1 are retained for historical purposes only. The conditions precedent for the effectiveness of this amended and restated facility agreement are set out in the Amendment and Restatement Agreement.
The documents and other evidence referred to in Clause 4.1 (Initial conditions precedent) are as follows:
1 |
The Borrower |
1.1 |
Certified Copies of the constitutional documents of the Borrower. |
1.2 |
Certified Copies of the unanimous written resolutions of the board of directors of the Borrower: |
(a) |
approving and authorising the execution, delivery and performance of each Finance Document on the terms and conditions of those documents; and |
(b) |
authorising any directors or named individuals named in those resolutions whose specimen signature is provided to the Lender, to sign or otherwise attest the execution of the Finance Documents and any other document to be delivered under them. |
1.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of any Finance Document for the Borrower. |
1.4 |
Certified Copies of all Authorisations required by the Borrower in connection with the execution, delivery, performance, validity or enforceability of the Finance Documents or any document to be delivered under them or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
1.5 |
Certified Copies of the Borrower's register of directors, register of members and register of mortgages and charges (the latter showing details of the Transaction Security Documents). |
1.6 |
A certificate of an authorised signatory of the Borrower certifying that each copy document relating to it that is listed in this Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
1.7 |
A certificate signed by a director of the Borrower and addressed to Maples and Calder, the Lender's Cayman Islands counsel, certifying certain matters in relation to the legal opinion of Maples and Calder. |
1.8 |
A certificate of good standing issued by the Registrar of Companies in the Cayman Islands dated within three days of the date of this Agreement. |
1.9 |
Evidence the Borrower has complied in full with all anti-money laundering regulations of the Lender. |
2 |
The Guarantor |
2.1 |
Certified Copies of the constitutional documents of the Guarantor (its certificate of incorporation, any certificate on change of name, its notice of articles and its articles of association). |
Page 1
2.2 |
Certified Copies of the minutes of a meeting of the board of directors (or equivalent executive body) of the Guarantor (including the resolutions passed at that meeting): |
(a) |
approving and authorising the execution, delivery and performance of this Agreement; |
(b) |
showing that the meeting was quorate; and |
(c) |
authorising any directors or named individuals named in those resolutions whose specimen signature is set out in those minutes or otherwise provided to the Lender, to sign or otherwise attest the execution of this Agreement and any other document to be delivered under it. |
2.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of this Agreement for the Guarantor. |
2.4 |
Certified Copies of all Authorisations required by the Guarantor in connection with the execution, delivery, performance, validity or enforceability of this Agreement or any document to be delivered under it or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
2.5 |
A Certified Copy of the register of directors of the Guarantor. |
2.6 |
A certificate of an authorised signatory of the Guarantor certifying that each copy document relating to it that is listed in this Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
2.7 |
The Guarantor's Original Financial Statements. |
2.8 |
Evidence the Guarantor has complied in full with all anti-money laundering regulations of the Lender. |
2.9 |
A certificate of good standing in respect of the Guarantor issued by the Registrar of Companies (British Columbia) dated within three days of the date of this Agreement. |
2.10 |
A certificate of a director of officer of the Guarantor relating to such matters as the Lender reasonably requires in order for the legal opinions referred to in section 4 of this Schedule to be issued. |
3 |
Finance Documents |
3.1 |
This Agreement, executed by the Parties. |
3.2 |
Each Transaction Security Document, executed by the parties to it together with all documents deliverable with each of those Transaction Security Documents. |
4.1 |
A legal opinion of SNR Denton UK LLP, legal advisers to the Lender in England, and all documents and other evidence required for issue of that opinion. |
4.2 |
A legal opinion of Maples and Calder the legal advisers to the Lender in the jurisdiction of incorporation of the Borrower, and all documents and other evidence required for issue of that opinion. |
4.3 |
A legal opinion of Gowlings the legal advisers to the Lender in the jurisdiction of incorporation of the Guarantor, and all documents and other evidence required for issue of that opinion. |
Page 2
5 |
Other documents and evidence |
5.1 |
Evidence the fees and costs then due from the Borrower under Clause 11 (Fees) and Clause 16 (Costs) have been paid or will be paid by the first Utilisation Date. |
5.2 |
Evidence the Borrower has the insurances necessary to comply with Clause 21.7 (Insurance). |
5.3 |
A certified Copy of each Export Contract. |
5.4 |
Evidence that: |
(a) |
a Notice of Security over Contract (as described in the Commercial Contracts Security Agreement) has been served on each Buyer under an Export Contract and on Albpetrol Sh.A. in relation to the Petroleum Agreements; and |
(b) |
the Lender has received an acknowledgement to that notice (as described in the Commercial Contracts Security Agreement) from each such Buyer and from Albpetrol Sh.A.. |
5.5 |
Any other agreements, documents or evidence the Lender requires in connection with the Facility and the Finance Documents and notices to the Borrower. |
Page 3
Schedule 2 - Form of Utilisation Request
From: |
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) |
To:Raiffeisen Bank Sh.A Dated: [·]
Dear Sirs
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) - trade finance term facility agreement dated [·] December 2011(the Agreement)
1 |
We refer to the Agreement. This is a Utilisation Request. In this Utilisation Request, unless indicated otherwise: |
(a) |
definitions in the Agreement apply; and |
(b) |
references to Clauses are to clauses in the Agreement. |
2 |
We wish to borrow a Loan on the following terms. |
Proposed Utilisation Date: |
[·] (or, if that is not a Business Day, the next Business Day) |
Amount: |
$[·] or, if less, the Available Facility |
3 |
We confirm that each condition in Clause 4.2 (Further conditions precedent) is satisfied. |
5 |
This Utilisation Request is irrevocable. |
6 |
We attach copies of the Invoices and details of the Work in Progress that this Loan will finance. |
Yours faithfully
…………………………………
authorised signatory for
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd)
|
1 |
Use this option for the first Utilisation only. |
Page 4
Exhibit 10.24
EXECUTION VERSION
Amendment and restatement agreement
relating to a facility agreement dated 15 December 2011 in relation to a trade finance term loan facility of up to $20,000,000 as amended on 8 May 2013, as further amended on 26 December 2013 and as further amended from time to time
Dated17 September 2014
Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd)
(as Borrower)
Stream Oil & Gas Ltd (BC)
(as Guarantor)
Raiffeisen Bank Sh.A
(as Lender)
London EC4M 7WS
United Kingdom
DX 242
Contents |
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Definitions and construction |
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Amendment and restatement |
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Waivers |
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Conditions subsequent |
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Confirmations |
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Representations and warranties |
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Further action |
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Expenses |
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Counterparts |
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Governing law and enforcement |
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Finance Documents |
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Schedule 1 - Conditions precedent and conditions subsequent |
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The Borrower |
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The Guarantor |
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Original non-security documentation, etc. |
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Contents (i)
Amendment and restatement agreement
Dated17 September 2014
Between
(2) |
Stream Oil & Gas Ltd (BC), a company incorporated in British Columbia, Canada with registration number BC0713471, its registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (the Guarantor); and |
(3) |
Raiffeisen Bank Sh.A a financial institution established and existing under the laws of Albania registered with Court Order No. 17426 on 10 July 1997 (the Lender). |
Recitals
A. |
This Agreement is supplemental to and amends and restates a facility agreement dated 15 December 2011 in relation to a trade finance term loan facility of up to $20,000,000 as amended on 8 May 2013, as further amended on 26 December 2013 and as further amended from time to time (the Facility Agreement). |
B. |
The Borrower has failed to pay the Repayment Instalment falling due on 29 June 2014 (the June Instalment). Subject to the terms of this Agreement, the Lender has agreed to waive the payment of Default Interest and reschedule the repayment obligations of the Borrower such that the June Instalment will fall due on the Termination Date. |
C. |
The Parties have agreed to amend and restate the Facility Agreement on the terms of this Agreement. |
It is agreed:
Words and expressions defined in the Facility Agreement, as amended and restated by this Agreement, shall have the same meanings in this Agreement. In addition, in this Agreement:
Effective Date means the day on which the Lender notifies the Borrower that it has received, in form and substance satisfactory to it (or that it has waived the receipt of) all of the documents and other evidence listed in Part 1 of Schedule 1 (Conditions precedent).
The principles of construction set out in clause 1.2 (Construction) of the Facility Agreement shall apply to this Agreement, insofar as they are relevant to it, as they apply to the Facility Agreement.
Page 1
The provisions of clause 1.3 (Third party rights) of the Facility Agreement shall apply to this Agreement as they apply to the Facility Agreement.
With effect from the Effective Date, the Facility Agreement shall be amended and restated in the form set out in Appendix 1 (Amended and restated Facility Agreement) to this Agreement.
Event of Default
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Event, act or omission
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Clause 23.1 (Non-payment) of the Facility Agreement. |
Failure by the Borrower to pay the Repayment Instalment falling due on 29 June 2014 pursuant to clause 6.1 (Repayment of Loans) of the Facility Agreement.
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Clause 23.2 (Financial covenants) of the Facility Agreement. |
Breach by the Borrower of the financial covenants set out in Clause 20.2 (a) and (b) (Financial covenants) of the Facility Agreement for the Borrower's financial year ending 2013.
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3.2 |
With effect from the Effective Date the Lender waives its rights to receive Default Interest accrued in respect of the June Instalment. |
4 |
Conditions subsequent |
Each Obligor undertakes to provide all of the documents and other evidence set out in Part 2 of Schedule 1 (Conditions subsequent) on or before the date falling 15 days from the date of this Agreement. A failure by either Obligor to satisfy any item listed in Part 2 of Schedule 1 (Conditions subsequent) will immediately constitute an Event of Default.
5 |
Confirmations |
5.1 |
Without prejudice to the rights of the Lender which have arisen on or before the Effective Date: |
(a) |
each Obligor confirms that, on and after the Effective Date: |
(i) |
the Facility Agreement (as amended and restated by this Agreement), and the other Finance Documents, will remain in full force and effect; and |
(ii) |
the Transaction Security Documents to which it is a party will remain in full force and effect and will continue to secure all liabilities which are expressed to be secured by them; and |
Page 2
Appendix 2
Appendix 3
Appendix 4
Appendix 5
The representations and warranties set out in clause 18 (Representations and Warranties) of the Facility Agreement are deemed to be repeated by each Obligor by reference to the facts and circumstances then existing on:
(c) |
the date of this Agreement; and |
(d) |
the Effective Date. |
Each Obligor shall, at its own expense, promptly take any action and sign or execute any further documents which the Lender may require in order to give effect to the requirements of this Agreement.
The Borrower shall reimburse the Lender for the amount of all costs and expenses (including legal and other professional fees and VAT) reasonably incurred by it in connection with this Agreement.
This Agreement may be executed in any number of counterparts, and this has the same effect as if the signatures on the counterparts were on a single copy of this Agreement.
10.1 |
Governing Law |
This Agreement is governed by English law.
10.2 |
Enforcement |
The provisions of clause 34.2 (Jurisdiction) and 34.3 (Arbitration) of the Facility Agreement shall apply to this Agreement as it applies to the Facility Agreement.
The Lender and the Borrower designate this Agreement a Finance Document.
This Agreement has been entered into on the date stated at the beginning of this Agreement.
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Schedule 1 - Conditions precedent and conditions subsequent
Part 1 - Conditions precedent
The documents and other evidence referred to in the definition of Effective Date are as follows:
1.1 |
Certified Copies of the constitutional documents of the Borrower. |
1.2 |
Certified Copies of the unanimous written resolutions of the board of directors of the Borrower: |
(a) |
approving and authorising the execution, delivery and performance of this Agreement and the Facility Agreement (as amended by this Agreement) on the terms and conditions of those documents; and |
(b) |
authorising any directors or named individuals named in those resolutions whose specimen signature is provided to the Lender, to sign or otherwise attest the execution of this Agreement and the Facility Agreement (as amended by this Agreement) and any other document to be delivered under them. |
1.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of this Agreement and the Facility Agreement (as amended by this Agreement) for the Borrower. |
1.4 |
Certified Copies of all Authorisations required by the Borrower in connection with the execution, delivery, performance, validity or enforceability of this Agreement and the Facility Agreement (as amended by this Agreement) or any document to be delivered under them or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
1.5 |
Certified Copies of the Borrower's register of directors, register of members and register of mortgages and charges (the latter showing details of the Transaction Security Documents). |
1.6 |
A certificate of an authorised signatory of the Borrower certifying that each copy document relating to it that is listed in this Part 1 of Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
1.7 |
A certificate signed by a director of the Borrower and addressed to Maples and Calder, the Lender's Cayman Islands counsel, certifying certain matters in relation to the legal opinion of Maples and Calder. |
1.8 |
A certificate of good standing issued by the Registrar of Companies in the Cayman Islands dated within three days of the date of this Agreement. |
1.9 |
Evidence the Borrower has complied in full with all anti-money laundering regulations of the Lender. |
2.1 |
Certified Copies of the constitutional documents of the Guarantor (its certificate of incorporation, any certificate on change of name, its notice of articles and its articles of association). |
Page 4
2.2 |
Certified Copies of the minutes of a meeting of the board of directors (or equivalent executive body) of the Guarantor (including the resolutions passed at that meeting): |
(a) |
approving and authorising the execution, delivery and performance of this Agreement and the Facility Agreement (as amended by this Agreement); |
(b) |
showing that the meeting was quorate; and |
(c) |
authorising any directors or named individuals named in those resolutions whose specimen signature is set out in those minutes or otherwise provided to the Lender, to sign or otherwise attest the execution of this Agreement, the Facility Agreement (as amended by this Agreement) and any other document to be delivered under it. |
2.3 |
A Certified Copy or original specimen signature of each individual that signs or otherwise attests the execution of this Agreement for the Guarantor. |
2.4 |
Certified Copies of all Authorisations required by the Guarantor in connection with the execution, delivery, performance, validity or enforceability of this Agreement, the Facility Agreement (as amended by this Agreement) or any document to be delivered under it or, if none are required, a certificate signed by a director of the Guarantor confirming this is the case. |
2.5 |
A Certified Copy of the register of directors of the Guarantor. |
2.6 |
A certificate of an authorised signatory of the Guarantor certifying that each copy document relating to it that is listed in this Part 2 of Schedule 1 is true, complete and up-to-date as at a date no earlier than the date of this Agreement. |
2.7 |
The Guarantor's Original Financial Statements. |
2.8 |
Evidence the Guarantor has complied in full with all anti-money laundering regulations of the Lender. |
2.9 |
A certificate of good standing in respect of the Guarantor issued by the Registrar of Companies (British Columbia) dated within three days of the date of this Agreement. |
2.10 |
A certificate of a director or officer of the Guarantor relating to such matters as the Lender reasonably requires in order for the legal opinions referred to in section 3 of this Schedule to be issued |
3 |
Original non-security documentation, etc. |
3.1 |
This Agreement, executed by the Parties. |
3.2 |
A legal opinion of the legal advisers to the Lender in the Cayman Islands in relation to the capacity of the Borrower to enter into, and perform its obligations under, this Agreement and the Facility Agreement (as amended by this Agreement). |
3.3 |
A legal opinion of the legal advisers to the Lender in Canada in relation to the capacity of the Guarantor to enter into, and perform its obligations under, this Agreement and the Facility Agreement (as amended by this Agreement). |
3.4 |
A legal opinion of the legal advisers to the Lender in England in relation to the enforceability of this Agreement and the Facility Agreement (as amended by this Agreement) in England. |
Page 5
Part 2 - Conditions subsequent
The documents and other evidence referred to in Clause 5 (Conditions subsequent) are as follows:
1.1 |
Evidence that all fees, costs and expenses then due from the Borrower pursuant to Clause 8 Expenses) have been paid. |
1.2 |
A copy of an amendment agreement to the cooperation agreement between the Borrower, the Lender and Trafigura Pte Ltd dated 24 April 2013 signed by the parties to it in form and substance satisfactory to the Lender. |
1.3 |
A copy of an agreement between Albpetrol Sh.A and the Borrower in relation to postponement of CAPEX. |
Page 6
Execution page
The Borrower
Signed by a person who is authorised for Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) as Borrower |
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/s/ Sotirios Kapotas |
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Name: Sotirios Kapotas |
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Position: Director |
The Guarantor
Signed by a person who is authorised for Stream Oil & Gas Ltd (BC) as Guarantor |
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/s/ Sotirios Kapotas |
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Name: Sotirios Kapotas |
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Position: Director |
The Lender
Signed by person(s) who are authorised for Raiffeisen Bank Sh.A as Lender |
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/s/ Alexander Zsolnai |
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Name: Alexander Zsolnai |
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Position: Vice Chairman
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/s/ Gledis Buxhuku |
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Name: Gledis Buxhuku |
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Position: Head of EWS & CC Department |
Page 7
Appendix 1 - Amended and restated Facility Agreement
Page 8
Exhibit 10.25
THIS PREPAYMENT AGREEMENT (“Agreement”) is made on April 18th 2013
BETWEEN:
(1) |
STREAM OIL & GAS LTD, Albania branch, a company organised and existing under the laws of the Cayman Islands with a branch registered in the Republic of Albania, and having its registered office at Dega ne Shqiperi e Stream Oil & Gas Ltd, NIPT K72205016P, Rr. Ismail Qemali Samos Tower, Kati 5, Tirana, Albania represented by Dr. Sotirios Kapotas ("Seller"); |
(2) |
STREAM OIL & GAS LTD, a company incorporated in British Columbia, Canada, with registration number BC0713471 and with registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (“Guarantor”); and |
(3) |
TRAFIGURA PTE LTD, a company incorporated in Singapore a company duly organised and existing under the laws of Singapore with its registered office at the following addresses: 10 Collyer Quay, Ocean Financial Centre #29-00, Singapore 049315, represented by Alan Suchley and Nicolas Marsac ("Buyer"). |
RECITALS:
(A) |
Seller is engaged in oil and gas exploration, development and production and, in particular, oil, gas and condensate fields in the Republic of Albania. |
(B) |
Buyer is an international trading company which trades, markets and invests in crude oil and petroleum products and related logistics on a global scale. |
(C) |
Buyer and Seller have concluded a Crude Supply Contract pursuant to which Seller sells and Buyer purchases and takes delivery of Crude. |
(D) |
Subject to the terms of the Transaction Documents, Buyer has agreed to pre-pay part of the purchase price for Crude in an aggregate amount not exceeding the Limit and Guarantor has agreed to Guarantee performance of Seller’s obligations under the CrudeSupply Contract and this Agreement. |
IT IS AGREED AS FOLLOWS:
1.Definitions and Interpretation
1.1Definitions
In this Agreement:
"Affiliate" means, in relation to a party, a person who is, from time to time, a subsidiary or a holding company of that party, or is a subsidiary of that party's holding company;
"Authorisation" means an authorisation, consent, approval, resolution, licence, exemption, filing or registration however described;
"Availability Period" means the period commencing on satisfaction of the Conditions Precedent to this Agreement and ending on 31 October 2013;
"Break Costs" means the amount (if any) by which:
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(a) |
the interest which Buyer should have received for the period from the date of receipt of the amount of the Prepayment reimbursed in accordance with Clause 8 to the last day of the current Funding Period, had that amount been paid on the last day of that Funding Period; |
exceeds:
(b) |
the amount which Buyer would be able to obtain by placing an amount equal to the amount of the Prepayment reimbursed in accordance with Clause XX on deposit with a leading bank in the London interbank market for a period starting on the Business Day following receipt of that reimbursement and ending on the last day of the current Funding Period; |
"Business Day" means a day (other than a Saturday, Sunday or public holiday) on which banks are open for general business in Albania, Geneva and New York;
"Contract Payment" means, in relation to a Payment Date, the amount payable by Buyer to Seller on that Payment Date under the Crude Supply Contract.
“Credit Facility” means the $20,000,000 trade finance term loan facility agreement between Seller, Guarantor and Raiffeisen Bank ShA dated December 15, 2011
“Crude” means crude oil as defined in the Crude Supply Contract.
“Crude Supply Contract” means the term contract dated 16 January 2013 contract no: SKO-012-453470 pursuant to which Seller sells and Buyer purchases and takes delivery of Crude.
"Default" means a Termination Event or any event or circumstance specified in Clause 16 (Termination Events) which would (with the expiry of a grace period, the giving of notice, the making of any determination or any combination of them) be a Termination Event;
"Default Rate" means in relation to an Unpaid Amount, the rate which is two per cent (2%) per annum higher than the Interest Rate which would have applied if the Unpaid Amount had, during the period of non-payment, constituted the whole or part of the Prepayments;
"Delivery Schedule" means the schedule of deliveries to be made by Seller to Buyer of Crude in accordance with the terms of the Crude Supply Contract;
“Discharge Amount(s)” means, at any time, the amount of any Prepayment outstanding at such time plus any Funding Charges which have accrued or are due and which have not been paid by Seller to Buyer at such time.
"Discharge Date" means each date when a Repayment is due, in accordance with Schedule 3 (Discharge Schedule) under the column headed "Date";
"Dollars" and "US$" and "USD" means the lawful currency for the time being of the United States of America;
"Effective Date" means the date falling one (1) Business Day after the Conditions Precedent Satisfaction Date and as a result of which Seller can deliver the Prepayment Request in respect of the Prepayment.
"Environment" means living organisms including the ecological systems of which they form part and the following media: (i) air (including air within natural or man-made structures, whether above or below ground); (ii) water (including territorial, coastal and inland waters, water under or within land
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and water in drains and sewers); and (iii) land (including land under water) and "Environmental" shall be construed accordingly;
"Environmental Law" means all applicable laws and regulations which: (i) have as a purpose or effect the protection of, and/or prevention of harm or damage to, the Environment; (ii) provide remedies or compensation for harm or damage to the Environment; or (iii) relate to Hazardous Substances or health and safety matters;
"Environmental Licence" means any Authorisation and the filing of any notification, report or assessment required under any Environmental Law for the operation of the business of Seller conducted on or from the properties owned or used by Seller;
“Equipment” means equipment and materials which shall be purchased by Seller for the expansion of production of the Cakran, Gorisht, Ballsh and Delvina Field projects.
"Facility Agreement" means Buyer’s bank facility arrangements;
"Fee Letter" means the letter dated on or about the date of this Agreement between Seller and Buyer concerning the fees referred to in Clause 9 (Fees);
"Finance Documents" means this Agreement, the Crude Supply Contract, the Guarantee and any other document designated as such from time to time by Buyer and Seller;
"Financing Banks" means any lender(s) under the Facility Agreement.
"Funding Charges" means the costs payable by Buyer under any Transaction Document to fund the Prepayments made under this Agreement including without limitation, all fees, interest, default interest, amounts attributable to Taxes, increased costs, mandatory costs, breakage costs, transaction expenses, amendment costs, enforcement costs and any other sums payable by Buyer from time to time and at any time under any Transaction Document and any relevant security documents and other documents related thereto;
“Funding Period” means in relation to a Prepayment, each period determined in accordance with Clause 7 (Funding Periods);
"Funding Rate" means the rate per annum as calculated in accordance with Clause 6 (Funding Rate);
"Guarantee" means a guarantee entered into by Guarantor in favour of Buyer guaranteeing the performance of Seller's obligations under this Agreement, in a form appearing at Schedule and on terms acceptable to Buyer in its sole discretion.
"Hazardous Substance" means any waste, pollutant, contaminant or other substance (including any liquid, solid, gas, ion, living organism or noise) that may be harmful to human health or other life or the Environment or a nuisance to any person or that may make the use or ownership of any affected land or property more costly.
"Indebtedness" means any obligation (whether incurred as principal or as surety) for the payment or repayment of money, whether present or future, actual or contingent.
“Interest Rate” means one month USD LIBOR plus Margin.
"Mandatory Cost" means the percentage rate per annum that is an addition to the interest rate charged by lenders to Buyer pursuant to the Facility Agreement as part of the cost of funding to
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compensate the lenders for compliance with the requirements of the Bank of England and/or the Financial Services Authority (or, in either case, any other authority which replaces all or any of its functions), or the requirements of the European Central Bank;
"Margin" means six per cent (6.00%) per annum;
"Material Adverse Effect" means an event or circumstance which (when taken alone or together with any previous event or circumstance) has, or (in the opinion of Buyer formed in good faith) could reasonably be expected to have, a materially adverse effect on any of:
(a) |
the assets, business, operations or financial condition of Seller or Guarantor; |
(b) |
the economic or political situation in the Republic of Albania that could reasonably be expected to affect the ability of Seller or Guarantor to perform its obligations under any Transactions Document; or |
(c) |
the validity or enforceability of the Transaction Documents or the rights of Buyer under the Transaction Documents; |
"Original Financial Statements" means each of the most recent annual audited financial statements of Seller and the most recent quarterly interim financial statements of Seller;
"Payment Date" means each date on which a payment is due from Buyer to Seller under the Crude Supply Contract in respect of the delivery of Products;
“Petroleum Contracts” means the petroleum agreements between Albetrol ShA and the Seller dated 8 August 2007;
"Policy" means the insurance policy of Seller relating to, inter alia, environmental liability, third party liability, business interruption and infrastructure containing assignment of proceeds language in favour of Buyer;
"Policy Renewal Date" means 12/31/2012;
"Prepayment" means the prepayment(s) made or to be made by Buyer to Seller in accordance with this Agreement in an amount not exceeding the Prepayment Limit;
"Prepayment Date" means each date on which the Prepayment is made or due to be made under this Agreement;
"Prepayment Limit" means twenty million US Dollars (USD20,000,000) limited to seven million US Dollars (USD7,000,000) until the Supplementary Conditions Precedent have been satisfied;
"Prepayment Request" means a notice in the form set out in Schedule 2 (Prepayment Request), completed with relevant information;
"Purchase Price" means in relation to the Crude Supply Contract, the price at which Buyer has agreed to purchase Crude from Seller;
"Repeating Representations" means each of the representations in Clause 11 (Representations) excluding only Clause 11.25 (Repetition);
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"Security" means a mortgage, charge, pledge, lien, security assignment or other security interest securing any obligation of any person or any other agreement or arrangement having a similar effect or having the effect of providing a security or preferential treatment to a creditor;
“Supplementary Conditions Precedent” means each of the conditions precedent appearing in paragraph 4 of Schedule 1;
"Tax" means any tax, levy, impost, duty, charge, value added tax or other withholding of a similar nature (including any penalty or interest payable in connection with any failure to pay or any delay in paying any of the same);
"Tax Deduction" means a deduction or withholding for or on account of Tax from a payment under a Transaction Document;
"Termination Event" means any event or circumstance specified in Clause 16 (Termination Events) other than Clause 16.20 (Acceleration);
"Transaction Documents" means each of the Finance Documents, the Facility Agreement, the Policy, and any other document designated as a Transaction Document by Buyer and Seller;
"Unpaid Amount" means any amount due and payable to the Buyer but unpaid by Seller under the Transaction Documents;
"Valuation" means the value of the Crude as estimated by Buyer in its reasonable discretion.
1.2 |
Construction |
(a) |
Any reference in this Agreement to: |
(i) |
"asset" includes every kind of property, asset, interest or right (whether present, future or contingent); |
(ii) |
"claims" and "losses" include: |
(1) |
any claim or demand, including any in the nature of or asserted as a total or partial defence, abatement, set-off or counterclaim; |
(2) |
any legal or administrative action; and |
(3) |
any loss, liability or expense, |
including any item which relates to tax and any item the amount or final amount of which remains open or unknown;
(iii) |
"company" includes any partnership, joint venture and unincorporated association; |
(iv) |
"control" means in relation to any person, the power of that person to direct or cause the direction of the management or policies of another person; |
(v) |
"document" includes a deed; also a letter, fax or telex; |
(vi) |
"expense" means any kind of cost, charge or expense (including all legal costs, charges and expenses) and any applicable value added or other tax; |
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(vii) |
“include” and “including” are to be construed to include the phrase "but not limited to." |
(viii) |
"law" includes, any order or decree, any form of delegated legislation, any treaty or international convention and any regulation, directive or decision of the Council of the European Union or the European Commission; and a provision of law is a reference to that provision as amended or re-enacted; |
(ix) |
"liability" includes every kind of debt or liability (present or future, certain or contingent), whether incurred as principal or surety or otherwise, and where any person is under an obligation to guarantee a liability, or to indemnify or hold another person harmless in respect of it, such obligations shall exist notwithstanding that the relevant liability has not been paid or discharged by the person entitled to or claiming the benefit of the guarantee, indemnity or hold harmless obligation as the case may be; |
(x) |
"Transaction Document" or "Finance Document" or any other agreement or instrument is a reference to that Transaction Document, Finance Document or other agreement or instrument as amended, novated, re-stated or replaced; |
(xi) |
unless otherwise stated, a "Clause" or "Schedule" is a reference to a Clause or Schedule of this Agreement; |
(xii) |
a "person" includes any person, firm, company, corporation, government, state or agency of a state or any association, trust or partnership (whether or not having separate legal personality) or two or more of the foregoing; |
(xiii) |
"successor" includes any person who is entitled (by assignment, novation, merger or otherwise) to any other person's rights under the Transaction Documents (or any interest in those rights) or who, as administrator, liquidator or otherwise, is entitled to exercise those rights; and in particular references to a successor include a person to whom those rights (or any interest in those rights) are transferred or pass as a result of a merger, division, reconstruction or other reorganisation of it or any other person; |
(xiv) |
any party includes its successors in title and permitted transferees; |
(xv) |
"tax" includes any present or future tax, duty, impost, levy or charge of any kind which is imposed by any state, any political sub-division of a state or any local or municipal authority (including any such imposed in connection with exchange controls), and any connected penalty, interest or fine. |
(xvi) |
a time of day is a reference to Geneva time unless indicated otherwise; |
(b) |
A term used in any other Transaction Document or in any notice given under or in connection with any Transaction Document and not expressly defined therein has the same meaning in that Transaction Document or notice as in this Agreement; and |
(c) |
A Default is "continuing" if it has not been remedied or waived. |
1.3 |
Period of this Agreement |
This Agreement shall be effective on the Effective Date and shall remain in effect until such time as all of the obligations of the parties under this Agreement have been irrevocably paid and discharged in full.
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2. |
Prepayment Facility |
2.1 |
Subject to the terms of this Agreement, Buyer agrees to pre-pay part of the Purchase Price for Crude to be supplied by Seller under the Crude Supply Contract by way of Prepayment(s), each in an aggregate amount not less than one million US Dollars (USD1,000,000) and not exceeding in aggregate the Prepayment Limit. Subject to Clause 4.2 (Completion of the Prepayment Request), the Prepayments shall be used by Seller to expand production of the Cakran, Gorisht, Ballsh and Delvina Field projects and for no other purpose save with the prior written consent of Buyer. |
2.2 |
Buyer shall be under no obligation to monitor or verify how Seller uses the Prepayments. |
3. |
Conditions of Prepayment |
3.1 |
Initial conditions precedent |
Seller may not deliver any Prepayment Request in respect of the Prepayment and Buyer shall not be obliged to make any Prepayment unless and until Buyer gives written confirmation to Seller that the conditions precedent listed in paragraph 1 of Schedule 1 (Conditions Precedent) have been satisfied and that it has received (or waived the requirement to receive, in whole or in part) all of the documents and other evidence listed in paragraph 2 of Schedule 1 (Conditions Precedent) in each case in form and substance satisfactory to Buyer.
3.2 |
Further conditions precedent |
Buyer shall only be obliged to comply with Clause 4 (Prepayment) if on the date of the Prepayment Request and on the proposed Prepayment Date:
(a) |
no Default or Material Adverse Effect is continuing or would result from the proposed Prepayment; |
(b) |
the Repeating Representations are true in all material respects; |
(c) |
Seller has provided copies of all invoices for Equipment that Seller shall purchase with the proposed Prepayment; and |
(d) |
Buyer is satisfied that sufficient finance pursuant to the Facility Agreement is available to it to enable it to fund the Prepayment. |
3.3 |
Supplementary Conditions Precedent |
Seller may not deliver any Prepayment Request where the aggregate of the Prepayment Requests will be in excess of seven million US Dollars (USD7,000,000) and Buyer shall not be obliged to make any Prepayment where the aggregate Prepayment will be in excess of seven million US Dollars (USD7,000,000) unless and until Buyer gives written confirmation that the conditions precedent listed in paragraph 4 of Schedule 1 (Supplementary Conditions Precedent) have been satisfied and that it has received (or waived the requirement to receive, in whole or in part) all of the documents and other evidence listed in paragraph 4 of Schedule 1 (Supplementary Conditions Precedent) in each case in form and substance satisfactory to Buyer.
3.4 |
Condition subsequent |
It is a condition subsequent to Buyer making a Prepayment that Seller shall execute, deliver to Buyer and register a charge over all of Seller’s rights, title and interest in and to the Equipment that Seller has or shall purchase with the proposed Prepayment within 14 days of: (i) Seller acquiring rights in and to such Equipment; or for already acquired Equipment (ii) execution of this Agreement.
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4. |
Prepayment |
4.1 |
Delivery of the Prepayment Request |
Seller may request a Prepayment by delivering to Buyer a completed Prepayment Request not later than 12 noon (Geneva time) on the fifth Business Day before the proposed Prepayment Date.
4.2 |
Completion of the Prepayment Request |
(a) |
A Prepayment Request is irrevocable and will not be valid unless: |
(i) |
the proposed Prepayment Date is a Business Day within the Availability Period; and |
(ii) |
the amount of the proposed Prepayment does not exceed the Prepayment Limit. |
(b) |
Only one Prepayment may be requested in a Prepayment Request. |
(c) |
For the avoidance of doubt, Seller can issue more than one Prepayment Request. |
(d) |
Seller shall not deliver more than ten1 Prepayment Requests. |
(e) |
All Prepayments shall be denominated in and requested in US Dollars and the aggregate amount of Prepayments made or to be made shall not exceed the Limit. |
4.3 |
If the conditions precedent and other requirements set out in this Agreement have been met, the Buyer shall make the requested Prepayment to the Seller on the Prepayment Date. |
4.4 |
The amounts of any Prepayments shall first be applied in payment to Buyer of the fees to which Buyer is entitled pursuant to Clause 9 (Fees). |
5. |
Payment and Discharge |
5.1 |
Subject to the other terms of this Agreement, Seller shall discharge the Prepayments and the Discharge Amounts by Seller delivering Crude to Buyer in accordance with the Crude Supply Contract and at the times and in the quantities of Crude as set out in the Delivery Schedule, and Buyer deducting such Discharge Amounts (as well as other sums due) from Contract Payments in accordance with this Clause 5. |
5.2 |
For the avoidance of doubt, Seller shall not reborrow any part of the Prepayment which has been discharged in accordance with Clause 5.1 or any other term of this Agreement. |
5.3 |
Subject to clause 5.9, on each Payment Date, provided no Default is continuing, Buyer shall pay to Seller the Contract Payment due on that Payment Date to the Credit Facility account of Seller at Raiffeisen Bank Sha specified in its invoice after deducting, in the following order: |
(a) |
any fees, costs and expenses payable by Seller which have accrued under this Agreement (including without limitation pursuant to Clause 6) and which have not been paid; |
(b) |
all Unpaid Amounts; |
(c) |
an amount accrued at the Funding Rate up to the relevant Payment Date, plus all other Funding Charges payable by Seller under Clause 6 (Funding Charge); |
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(d) |
any outstanding element of the Prepayment due by the Discharge Date following the relevant Payment Date to the extent that such amounts have not previously been paid, deducted or discharged in accordance with this Clause 5; and |
(e) |
any other amount payable by Seller to Buyer under the Transaction Documents on or before that Payment Date, |
provided that the amount which results from the above deductions is a positive number.
5.4 |
If: |
(a) |
any amount referred to in Clauses 5.3 (a) – (e) fall due for payment, Buyer shall deduct such amount from Contract Payments (and such amount shall be deemed paid upon and by virtue of such deduction); and |
(b) |
any amount falls due for payment under or in connection with the Facility Agreement, Buyer is authorised to deduct such amount from any Contract Payment and pay it in accordance with the Facility Agreement. |
5.5 |
If the amount of the Contract Payments are not, or in Buyer’s reasonable determination may not be, sufficient to discharge the Discharge Amount and/or any other sums payable by the Seller under the Transaction Documents, Seller shall in Buyer’s option: |
(a) |
deliver additional Product to Buyer in each case, on the terms set out in the Crude Supply Contract and in a volume sufficient to enable the deduction from Contract Payments in respect of such additional Product of all sums due; and/or |
(b) |
pay to Buyer in respect of a failure or anticipated failure to discharge the Discharge Amount and/or any other sum due by the Discharge Date, an amount equal to the Discharge Amount and/or other sum due less the total of the Contract Payments made prior to the Discharge Date; |
Nothing in this Clause 5.5 shall qualify or otherwise affect the Parties’ respective rights and obligations under Clause 5.6.
5.6 |
Notwithstanding any other term of this Agreement, Seller shall pay and discharge the Prepayment in full together with all Funding Charges and other amounts payable under this Agreement by the Final Discharge Date. |
5.7 |
Buyer shall supply a list of the deductions made under Clause 5.3 in respect of each Contract Payment as soon as reasonably practicable after each Payment Date. |
5.8 |
It is agreed that Buyer shall be entitled to deduct from any payment to be made by it to Seller: |
(a) |
Any sum that is required to ensure Seller’s compliance with Clause 13.8 (Financial Covenants); or |
(b) |
at the request of Seller, any amount which is to be applied in voluntary reimbursement of part of the Prepayments in accordance with Clause 8 (Voluntary Reimbursement). |
5.9 |
Notwithstanding the other provisions of this clause 5 but subject to clauses 13 and 16, until 31 October 2013, Seller shall not be obliged to repay and Buyer shall not be entitled to deduct the amount of any Prepayment outstanding. This clause 5.9 shall not impact upon Seller’s obligation to pay and Buyer’s entitlement to deduct Funding Charges or other amounts due and payable up to 31 October 2013 and thereafter. |
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6. |
Funding Charge |
6.1 |
Funding Rate |
The funding rate on the Prepayment for each Funding Period is the percentage rate per annum equal to the aggregate of (i) the Interest Rate; and (ii) any Mandatory Cost.
6.2 |
Payment of funding charges |
Subject to Clause 10.2 (Additional Funding Costs), Seller shall pay accrued Funding Charges on the Prepayment on each Payment Date as part of the Discharge Amount.
6.3 |
Default Interest |
(a) |
If Seller fails to pay any amount payable by it under a Transaction Document on its due date, interest shall accrue on the Unpaid Amount from the due date up to the date of actual payment (both before and after judgment) at the Default Rate. Any interest accruing under this Clause 6.3 shall be immediately due and payable. |
(b) |
Default interest (if unpaid) arising on an Unpaid Amount shall be compounded with the Unpaid Amount at the end of each Funding Period applicable to that Unpaid Amount but will remain immediately due and payable. |
6.4 |
Notification of rates |
Buyer shall promptly notify Seller of the determination of any Funding Rate or other rate of interest under this Agreement.
6.5 |
Notification of Funding Charges |
(a) |
On or after the commencement of each Funding Period for a Prepayment, Buyer shall (to the extent that it is then able to do so) promptly notify Seller of the amount of Funding Charges applicable to that Prepayment for the relevant Funding Period. |
(b) |
If a Prepayment becomes subject to additional Funding Charges during a Funding Period, Buyer shall promptly notify Seller giving details of the amount of such additional Funding Charges. |
7. |
Funding Periods |
7.1 |
Funding Periods |
(a) |
The first funding period shall start from the Prepayment Date and end on the last day of the calendar month in which the Payment Date falls, and thereafter, each funding period shall be of one calendar month or any other period as determined by Buyer (provided that such other period selected by the Buyer shall not result in increased costs to the Seller), except the last Funding Period which shall end on the Final Discharge Date and provided always that if a Discharge Date falls within a Funding Period, such Funding Period shall end on such Discharge Date (and the next Funding Period shall begin on the following day and end on the last day of the then current calendar month or such other date as is determined by Buyer). |
(b) |
A Funding Period in relation to a Prepayment shall not extend beyond the Final Discharge Date. |
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7.2 |
Changes to Funding Periods |
Buyer shall promptly notify Seller if Buyer makes any change to a Funding Period.
7.3 |
Non-Business Days |
If a Funding Period would otherwise end on a day which is not a Business Day, that Funding Period will instead end on the next Business Day in that calendar month (if there is one) or the preceding Business Day (if there is not).
8. |
Voluntary reimbursement |
8.1 |
From six months after the First Prepayment Date and provide the Availability Period has passed, Seller may reimburse the whole or any part of the Prepayment in cash (but, if in part, being an amount that reduces the amount of the Prepayment by a minimum amount of one million US Dollars (USD1,000,000) or an integral multiple of USD1,000,000) on giving at least ten (10) Business Days' prior written notice to Buyer and paying any Break Costs duly justified by Buyer to Seller. |
8.2 |
All or any part of the Prepayment may only be reimbursed by Seller to Buyer on the last Business Day of a calendar month. |
8.3 |
A voluntary reimbursement by Seller shall not prejudice or limit or undermine or reduce in any way any of the rights of Buyer under the Crude Supply Contract to buy Crude or the obligations of Seller under the Crude Supply Contract to deliver Crude, in accordance with the Crude Supply Contract. |
8.4 |
Any notice of reimbursement shall be irrevocable and shall specify the date or dates upon which the relevant reimbursement is to be made and the amount of that reimbursement. |
8.5 |
Seller shall not reimburse all or any part of the Prepayment except at the times and in the manner provided for in this Agreement. |
9. |
Fees |
9.1 |
Seller shall pay to Buyer an arrangement fee of an amount equal to 1% of the Prepayment Limit plus the Funding Charge within thirty (30) days from execution of this agreement. Such fee shall be payable regardless of whether or not any Prepayment occurs and shall not be refundable under any circumstances. |
9.2 |
A commitment fee shall be payable by Seller to Buyer at the rate of 50% of the Interest Rate payable monthly in arrears on the undrawn balance of the Prepayment Limit from the date of this Agreement until the end of the Availability Period. |
9.3 |
Transaction expenses |
Seller shall reimburse Buyer on demand for all reasonable costs and expenses (including legal fees and all value added and similar taxes) incurred by Buyer in connection with the negotiation, preparation, printing, execution, completion, amendment or variation of and the enforcement or preservation of rights under, the Transaction Documents and any related documents.
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10. |
Other amounts |
10.1 |
Tax Gross Up and Indemnity |
(a) |
Seller shall make all payments to be made by it under the Transaction Documents without any Tax Deduction, unless a Tax Deduction is required by law. Seller shall promptly upon becoming aware that it must make a Tax Deduction (or that there is any change in the rate or the basis of a Tax Deduction) notify Buyer accordingly. If a Tax Deduction is required by law to be made by Seller, the amount of the payment due from Seller shall be increased to an amount which (after making any Tax Deduction) leaves an amount equal to the payment which would have been due if no Tax Deduction had been required. |
(b) |
Without prejudice to paragraph (a) above, if Buyer is required to make any payment of or on account of Tax on or in relation to any sum received or receivable under any Transaction Document (including any sum deemed for purposes of Tax to be received or receivable by Buyer whether or not actually received or receivable) or if any liability in respect of any such payment is asserted, imposed, levied or assessed against Buyer, Seller shall, within three (3) Business Days of demand of Buyer, promptly indemnify Buyer against such payment or liability, together with any interest, penalties, costs and expenses payable or incurred in connection therewith. |
10.2 |
Additional Funding Costs |
Seller shall, within ten (10) Business Days of a demand by Buyer, pay for the account of Buyer the amount of any additional Funding Charges (save to the extent that Buyer is compensated for such costs by the other provisions of this Agreement).
10.3 |
Currency indemnity |
(a) |
If any sum due from Seller under the Transaction Documents (a "Sum"), or any order, judgment or award given or made in relation to a Sum, has to be converted from the currency (the "First Currency") in which that Sum is payable into another currency (the "Second Currency") for the purpose of: |
(i) |
making or filing a claim or proof against Seller; or |
(ii) |
obtaining or enforcing an order, judgment or award in relation to any litigation or arbitration proceedings, Seller shall as an independent obligation, within three Business Days of demand, indemnify Buyer against any cost, loss or liability arising out of or as a result of the conversion including any discrepancy between (A) the rate of exchange used to convert that Sum from the First Currency into the Second Currency and (B) the rate or rates of exchange available to that person at the time of its receipt of that Sum. |
(b) |
Seller waives any right it may have in any jurisdiction to pay any amount under the Transaction Documents in a currency or currency unit other than US Dollars. |
10.4 |
Other indemnities |
(a) |
Seller shall, within ten (10) Business Days of demand, indemnify Buyer on demand against any cost or expense incurred by Buyer or any of its officers, directors, employees, agents or representatives (as the case may be) as a result of: |
(i) |
the occurrence of any Termination Event; |
12
(ii) |
any enquiry, investigation, subpoena (or similar order) or litigation with respect to Seller or with respect to the transactions contemplated or financed under this Agreement; |
(iii) |
a failure by Seller to pay any amount due under a Transaction Document within five (5) Business Days of demand; |
(iv) |
funding, or making arrangements to fund, the Prepayment requested by Seller in the Prepayment Request but not made by reason of the operation of any one or more of the provisions of this Agreement; or |
(v) |
the Prepayment (or part of the Prepayment) not being reimbursed in accordance with a notice of reimbursement given by Seller pursuant to section 8. |
(b) |
Seller shall promptly indemnify Buyer for any cost or expense incurred by Buyer or any of its officers, directors, employees, agents or representatives (as the case may be) as a result of: |
(i) |
investigating any event which it reasonably believes is a Termination Event; or |
(ii) |
acting or relying on any notice, request or instruction which it reasonably believes to be genuine, correct and appropriately authorised. |
11. |
Representations |
11.1 |
General |
Each of Seller and Guarantor makes the representations and warranties set out in this Clause 12 to Buyer on the date of this Agreement and as set out in Clause 11.25 (Repetition).
11.2 |
Status |
(a) |
It is a corporation, duly incorporated and validly existing under the law of its jurisdiction of incorporation. |
(b) |
It has the power to own its assets and carry on its business as it is being conducted. |
11.3 |
Binding obligations |
The obligations expressed to be assumed by it in each Transaction Document are legal, valid, binding and enforceable obligations.
11.4 |
No conflict |
The execution of the Transaction Documents and performance of, the transactions contemplated by, the Transaction Documents do not and will not conflict with:
(a) |
any law or regulation applicable to it, including any currency control regulations in place in the Republic of Albania or Canada; |
(b) |
its constitutional documents; or |
(c) |
any agreement or instrument binding upon it or any of its assets. |
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11.5 |
Power |
It has the power to enter into, perform and deliver, and has taken all necessary action to authorise its entry into, performance and delivery of, the Transaction Documents and the transactions contemplated by those Transaction Documents.
11.6 |
Validity |
All Authorisations required or desirable:
(a) |
to enable it lawfully to enter into, exercise its rights and comply with its obligations in the Transaction Documents; and |
(b) |
to make the Transaction Documents to which it is a party admissible in evidence in its jurisdiction of incorporation, |
have been obtained or effected and are in full force and effect.
11.7 |
Governing law |
The choice of governing law of the Transaction Documents (as applicable in each case) will be recognised and enforced in its jurisdiction of incorporation and any judgment obtained in England or in the Republic of Albania or in Canada in relation to a Transaction Document will be recognised and enforced in its jurisdiction of incorporation.
11.8 |
Tax |
(a) |
It is not required under the law of its jurisdiction of incorporation to make any deduction for or on account of Tax from any payment (whether in cash or in kind) it may make under any Transaction Document. |
(b) |
It has duly and punctually paid and discharged all Taxes imposed upon it or its assets within the time period allowed without incurring penalties (save to the extent that (i) payment is being contested in good faith, (ii) it has maintained adequate reserves for those Taxes and (iii) payment can be lawfully withheld). |
(c) |
It is not materially overdue in the filing of any Tax returns. |
(d) |
No claims are being or are reasonably likely to be asserted against it with respect to Taxes. |
11.9 |
No filing or stamp taxes |
Under the law of its jurisdiction of incorporation it is not necessary that the Transaction Documents be filed, recorded or enrolled with any court or other authority in that jurisdiction or that any stamp, registration or similar tax be paid on or in relation to the Transaction Documents or the transactions contemplated by the Transaction Documents save for:
(a) |
the registration in the Republic of Albania of this Agreement; and |
(b) |
the payment in the Republic of Albania of stamp duty on this Agreement. |
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11.10 |
Residency |
Each of Buyer and Guarantor is not and will not be deemed to be resident, domiciled or carrying on business in the Republic of Albania, or subject to any Tax in that jurisdiction, by reason only of its entry into and performance of its obligations under the Transaction Documents.
11.11 |
Trade Obligations |
Its obligations under the Transaction Documents constitute short term trade obligations and its performance of these obligations is not subject to any rescheduling, readjustment, arrangement or moratorium of debts.
11.12 |
Foreign Currency |
It is legally and beneficially entitled to all foreign currency owed to or held by it and to make payments in foreign currency under the terms of this Agreement.
11.13 |
Immunity |
Neither it nor any of its assets enjoy under the laws of any jurisdiction, any right of immunity from suit, judgment, set-off, execution on a judgment, attachment or other legal process in respect of any of its obligations under the Transaction Documents.
11.14 |
No default |
No Termination Event is continuing or might reasonably be expected to result from the making of the Prepayment and no other event or circumstance is outstanding which constitutes a default under any other agreement or instrument which is binding on it or any of its Affiliates or to which its or any of its Affiliate's assets are subject which might have a Material Adverse Effect.
11.15 |
Information |
All information provided by Seller or Guarantor to Buyer under or in connection with the Transaction Documents was true and accurate in all material respects as at the date it was provided or as at the date (if any) at which it is stated, and nothing has occurred since the date the information was provided which makes that information untrue or misleading in any material respect.
11.16 |
Financial statements |
Its Original Financial Statements were prepared in accordance with internationally accepted auditing standards consistently applied and fairly represent its financial condition and operations during the relevant financial period and there has been no material adverse change in its business or financial condition since the date of the Original Financial Statements.
11.17 |
Pari passu |
Its obligations under the Transaction Documents rank at least pari passu with the claims of all its other unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally.
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11.18 |
Litigation |
No litigation, arbitration or administrative proceedings (including any arising from or relating to Environmental Law) before any court, arbitral body or agency have (to the best of its knowledge and belief) been started or threatened against it which, if adversely determined, might reasonably be expected to have a Material Adverse Effect or would result in a judicial or arbitral indebtedness in aggregate in excess of USD1,000,000.
11.19 |
No winding-up |
It has not taken any corporate action, nor have any other steps been taken or legal proceedings been started or threatened against it for its winding-up, dissolution, administration or reorganisation or for the appointment by it (or on its behalf) of a receiver, administrator, administrative receiver, trustee or similar officer in relation to itself or all or any of its assets or revenues.
11.20 |
Environmental laws and licences |
It has:
(a) |
complied with all Environmental Laws to which it may be subject; |
(b) |
obtained all Environmental Licences required or desirable in connection with its business; and |
(c) |
complied with the terms of those Environmental Licences, |
in each case where failure to do so might constitute or result in a Material Adverse Effect.
11.21 |
Environmental releases |
No:
(a) |
property currently or previously owned, leased, occupied or controlled by it (including any offsite waste management or disposal location utilised by it) is contaminated with any Hazardous Substance; and |
(b) |
discharge, release, leaching, migration or escape of any Hazardous Substance into the Environment has occurred or is occurring on, under or from that property, |
in each case in circumstances where this might constitute or result in a Material Adverse Effect.
11.22 |
Environmental Claims |
So far as it is aware, having made all reasonable enquiries, there are no Environmental claims pending or threatened and there are no past or present acts, omissions, events or circumstances that might form the basis of any Environmental claim against it.
11.23 |
Legal and beneficial ownership |
It is the sole legal and beneficial owner of any asset over which it purports to grant Security to Buyer pursuant to a Transaction Document.
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11.24 |
Insurance |
(a) |
It maintains with reputable insurers such insurance in respect of its assets and business as would normally be maintained by a prudent company carrying on business similar to its business. |
(b) |
It maintains the Policy which includes, without limitation, the rights to assign the proceeds of such insurances as covers the full replacement value of the equipment (“the Insurance Payment Assignment” and non-vitiation in favour of Buyer. |
11.25 |
Repetition |
The Repeating Representations are deemed to be made by Seller by reference to the facts and circumstances then existing on the date of any Prepayment Request and the first day of each Funding Period.
12. |
Undertakings |
12.1 |
For so long as any amount is outstanding under the Transaction Documents or any part of the Limit is available: |
(a) |
Financial statements |
Each of Seller and Guarantor shall supply to Buyer, in English:
(i) |
as soon as they become available, but in any event within one hundred and twenty (120) days after the end of each of its financial years, its audited financial statements for that financial year; |
(ii) |
as soon as they become available, but in any event within sixty (60) days after the end of each quarter of its financial year, its cash-flow report (including figures in respect operating expenses production, sales and exports, inventories, income statements, updates on payments made under financing agreements) for the preceding quarter; |
(iii) |
as soon as the same becomes available but in any event within twenty Business Days after the beginning of each calendar month, its monthly report on actual production volumes of Crude in Albania; |
(iv) |
any other information which Buyer may reasonably request from time to time in relation to Seller's and Guarantor’s business (including without limitation, any information relating to the operations, general economics or capital expenditure program of Seller) or any policy of the Government of the Republic of Albania vis-à-vis regulation of crude export or prices. |
(b) |
Requirements as to financial statements |
(i) |
Each set of financial statements delivered by Seller pursuant to Clause 12.1 (a) (Financial statements) shall be certified by the General Manager and the Chief Financial Officer as fairly representing its financial condition as at the date those financial statements were drawn up. |
(ii) |
Seller shall procure that each set of financial statements delivered pursuant to Clause 12.1 (a) (Financial statements) is prepared using internationally accepted and consistently applied accounting principles. |
17
Any reference in this Agreement to those financial statements shall be construed as a reference to those financial statements as adjusted to reflect the basis upon which the Original Financial Statements were prepared.
(c) |
Information: miscellaneous |
Each of Seller and Guarantor (as applicable) shall supply to Buyer:
(i) |
promptly upon becoming aware of them, the details of any litigation, arbitration or administrative proceedings which are current, threatened or pending against it and which might, if adversely determined, have a Material Adverse Effect; and |
(ii) |
promptly, such further information regarding its financial condition, business and operations or the delivery of Product under the Crude Supply Contract as Buyer may reasonably request; and |
(iii) |
full details of any amendment or addendum to or extension of the terms of: (1) the Credit Facility; and (2) the Petroleum Agreements. |
(d) |
Notification of default |
Each of Seller and Guarantor shall:
(i) |
notify Buyer of any Default (and the steps, if any, being taken to remedy it) promptly upon becoming aware of its occurrence; and |
(ii) |
promptly upon a request by Buyer, supply to Buyer a certificate signed by two of its directors or senior officers on its behalf certifying that no Default is continuing (or if a Default is continuing, specifying the Default and the steps, if any, being taken to remedy it). |
12.2 |
Seller undertakes not to amend, renegotiate or otherwise vary the tenor or any terms or conditions of the Petroleum Agreements without the consent of the Buyer, such consent not to be unreasonably withheld or delayed save that where an amendment is imposed or required pursuant to statute, court order or governmental or state decree, directive, law, rule or regulation, the Petroleum Agreements may be amended upon written notice to Buyer but without Buyer’s consent. |
13. |
General undertakings |
The undertakings in this Clause 13 shall remain in force from the date of this Agreement and for so long as any amount is outstanding under the Transaction Documents or any part of the Limit is available:
13.1 |
Authorisations |
Each of Seller and Guarantor shall promptly:
(a) |
obtain, comply with and do all that is necessary to maintain in full force and effect; and |
(b) |
supply certified copies to Buyer of, |
any Authorisation required under any law or regulation of its jurisdiction of incorporation to enable it to perform its obligations under the Transaction Documents and to ensure the legality, validity, enforceability or admissibility in evidence in its jurisdiction of incorporation of any Transaction Document.
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13.2 |
Compliance with laws |
Each of Seller and Guarantor shall comply in all respects with all laws to which it may be subject.
13.3 |
Compliance |
Each of Seller and Guarantor shall comply in all respects with any agreement or instrument binding upon it or any of its assets, including any currency control regulations existing in the Republic of Albania of Canada.
13.4 |
Negative Pledge |
Seller shall not create, amend, extend, agree to create, amend or extend, or permit to subsist, any Security over:
(a) |
the Transaction Documents, or any Product to be delivered pursuant to the Crude Supply Contract; or |
(b) |
if that Security may have a Material Adverse Effect, any of its other assets or undertaking, |
other than:
(1) |
the Credit Facility; and |
(2) |
Security created by or in favour of Buyer. |
13.5 |
Merger |
Each of Seller and Guarantor shall not enter into any amalgamation, demerger, merger or corporate reconstruction.
13.6 |
Change of business |
Each of Seller and Guarantor shall not make any substantial change to the general nature of its business from that carried on at the date of this Agreement.
13.7 |
Crude Supply Contract |
Seller shall give all necessary instructions and take all such other actions as may be required in order to ensure that it delivers Product in accordance with the Crude Supply Contract and this Agreement.
13.8 |
Financial Covenants |
Seller shall ensure that at all times:
(a) |
the Coverage Ratio is not less than 150%. If at any time, Buyer considers the Coverage Ratio to be less than or equal to 150%, Buyer shall notify Seller of this and Seller shall take immediate action to: |
(i) |
Enter into a binding commitment to Buyer to extend the period of the Crude Supply Contract so as to deliver additional Crude sufficient to meet the Coverage Ratio; and/or |
(ii) |
reimburse to Buyer part of the Prepayment Amount as is necessary to restore the Coverage Ratio; and/or |
19
(iii) |
do such other things as agreed by and as satisfactory in all respects to Buyer acting reasonably, |
in each case to an extent sufficient to ensure that prior to the next Discharge Date or the end of the next Funding Period (as the case may be) and in any case within 7 Business Days of being so notified, the Coverage Ratios are greater than or equal to 150%. Failure to remedy a Shortfall within such time period shall constitute a Termination Event.
(b) |
Each of Seller and Guarantor shall ensure at all times (to be assessed no less frequently than at the end of each Funding Period) that: |
(i) |
Its EBITDA is not less than ten million US Dollars (USD10,000,000); |
(ii) |
Its Indebtedness is never more than twice its EBITDA; and |
(iii) |
Its EBITDA is at least ten times greater than the interest charges payable on its Indebtedness. |
In this Clause 13.8:
"Coverage Ratio" means the ratio (at any time), expressed as a percentage, of:
(a) |
the estimated aggregate Valuation of the volume of Crude to be delivered under the Crude Supply Contract; to |
(b) |
the then outstanding amount of the Prepayment plus any Funding Costs (as determined by Buyer by reference to the most recent Funding Rate or rates) and fees due to be paid on or before the Discharge Date; |
"Shortfall" means at any time the percentage by which the Coverage Ratio is less than 150%.
13.9 |
Payment of shortfall |
If at any time Buyer determines that there is a shortfall in the repayment by Seller of any Funding Charges or other liabilities under any Transaction Document, Seller shall forthwith at the request of Buyer transfer by telegraphic transfer to an account designated by Buyer an amount equal to that shortfall.
13.10 |
Restricted Payments |
Seller shall not:
(a) |
pay, repay or prepay any principal, interest or other amount on or in respect of, or redeem, purchase or cancel any Indebtedness owed actually or contingently, to any shareholder of Seller or to any Affiliate of any shareholder of Seller; or |
(b) |
reduce, return, purchase, repay, cancel or redeem any of its share capital. |
13.11 |
Environmental undertakings |
Seller shall comply with all Environmental Laws to which it may be subject and obtain and comply at all times with all Environmental Licences required or desirable in connection with its business.
20
13.12 |
Environmental claims |
Seller shall promptly notify Buyer of any claim, proceeding, investigation, notice or other communication received by it or any Affiliate in respect of any actual or alleged breach of or liability under Environmental Law which, if substantiated, might constitute or result in a Material Adverse Effect.
13.13 |
Insurance |
(a) |
Seller shall maintain with reputable insurers such insurance in respect of its assets and business as are mandatorily required by all applicable laws and as would otherwise normally be maintained by a prudent company carrying on business similar to its business. |
(b) |
Seller shall at all times maintain the Policy and the rights of Buyer thereunder being the Insurance Payment Assignment and non-vitiation. |
(c) |
Within ten Business Days falling after the date of each anniversary of the Policy Renewal Date Seller shall provide to Buyer a certificate confirming that the Policy has been renewed (including the Insurance Payment Assignment made in favour of Buyer), is in full force and effect and that all insurance premiums have been paid and are up to date. |
13.14 |
Further assurance |
Each of Seller and Guarantor shall immediately at its own cost take all such action (including without limitation, making all filings and registrations (including the registration of this Agreement) and paying any stamp duty (including the payment of any stamp duty on this Agreement)) as may be necessary to ensure the legality, validity, enforceability or admissibility in evidence in its jurisdiction of incorporation of any Transaction Document.
14. |
Inconsistency with Supply Contract |
If there is any inconsistency between the terms of this Agreement and the terms of the Supply Contract, the terms of this Agreement shall prevail to the extent of the inconsistency.
15. |
Illegality |
If it becomes unlawful in any jurisdiction for Buyer to perform any of its obligations as contemplated by this Agreement, the Crude Supply Contract, or under the Finance Documents:
(a) |
Buyer shall promptly notify Seller upon becoming aware of that event; |
(b) |
upon Buyer notifying Seller, the Prepayment (or such part as Buyer may specify) will be immediately cancelled; and |
(c) |
Seller shall reimburse any outstanding Prepaid Amount (or such part as Buyer may specify) in cash upon demand by Buyer on the last day of the then current Funding Period occurring after Buyer has notified Seller or, if earlier, the date specified by Buyer in the notice delivered to Seller. |
16. |
Termination events |
16.1 |
Each of the events or circumstances set out in Clause 16 is a Termination Event (save for Clause 16.20 (Acceleration)). |
21
16.2 |
Non-payment |
Seller or the Guarantor does not pay on the due date any amount payable pursuant to a Transaction Document at the place at and in the currency in which it is expressed to be payable.
16.3 |
Financial covenants and other obligations |
Any requirement of Clause 13.8 (Financial Covenants) is not satisfied or Seller or Guarantor does not comply with the provisions of Clause 12.1 (c) (Information Undertakings).
16.4 |
Other obligations |
Seller or Guarantor does not comply with any provision of the Transaction Documents (other than those referred to in Clause 16.2 (Non-payment), Clause 13.8 (Financial Covenants)) Clause 12.1 (c) (Information Undertakings) and such failure (if capable of remedy in the opinion of Buyer) is not remedied within five (5) Business Days.
16.5 |
Misrepresentation |
Any representation or statement made or deemed to be made by Seller or Guarantor in the Transaction Documents or any other document delivered by or on behalf of Seller or Guarantor under or in connection with any Transaction Document is or proves to have been incorrect or misleading in any material respect when made or deemed to be made.
16.6 |
Change of Control |
Any person or group of persons (other than those who own and control Seller or Guarantor as at the date of this Agreement) acting in concert gains ownership or control of Seller (other than with the prior written consent of Buyer).
16.7 |
Expropriation |
At any time after the date of this Agreement, by or under the authority of any governmental agency or authority:
(a) |
the management board, board of directors or the general director of Seller or Guarantor is wholly or partially displaced or the authority of Seller in the conduct of a material portion of its business is curtailed; |
(b) |
any of the revenues or assets of Seller or Guarantor are seized, nationalised, expropriated or compulsorily acquired; or |
(c) |
Seller or Guarantor is otherwise deprived or prevented from exercising ownership or control of its business, assets or rights. |
16.8 |
Foreign exchange restrictions |
Any foreign exchange law is enacted or threatened to be enacted by or in the Republic of Albania or Canada (as applicable) that in the opinion of Buyer has, or may reasonably be expected to have, the effect of prohibiting, restricting or delaying any payment that Seller or Guarantor is required to make under the Transaction Documents.
22
16.9 |
Restraining Orders |
Any order or declaration is made or judgment is given by any court or authority, the effect of which is to restrain the performance or observance by Seller or Guarantor of any of the terms of any of the Transaction Documents.
16.10 |
Cross default |
(a) |
Any material Indebtedness of Seller or Guarantor is not paid when due nor within any originally applicable grace period. |
(b) |
Any material Indebtedness of Seller or Guarantor is declared to be or otherwise becomes due and payable prior to its specified maturity as a result of an event of default (however described). |
(c) |
Any commitment for any material Indebtedness of Seller or Guarantor is cancelled or suspended by a creditor of Seller or Guarantor as a result of an event of default (however described). |
(d) |
Any creditor of Seller or Guarantor becomes entitled to declare any Indebtedness of Seller or Guarantor due and payable prior to its specified maturity as a result of an event of default (however described). |
16.11 |
Insolvency |
(a) |
Seller or Guarantor is unable or admits inability to pay its debts as they fall due or is deemed to or declared to be unable to pay its debts under applicable law, suspends making payments on any of its debts or, by reason of actual or anticipated financial difficulties, commences negotiations with one or more of its creditors with a view to rescheduling any of its Indebtedness. |
(b) |
The value of the assets of Seller or Guarantor is less than its liabilities (taking into account contingent and prospective liabilities). |
(c) |
A moratorium is declared in respect of any Indebtedness of Seller or Guarantor. |
16.12 |
Insolvency proceedings |
Any corporate action, legal proceedings or other procedure or step is taken in relation to:
(a) |
the suspension of payments, a moratorium of any Indebtedness, winding-up, dissolution, administration or reorganisation (by way of voluntary arrangement, scheme of arrangement or otherwise) of Seller or Guarantor; |
(b) |
a composition, assignment or arrangement with any creditor of Seller or Guarantor which is for more than 90 days; |
(c) |
the appointment of a liquidator, receiver, administrator, administrative receiver, compulsory manager or other similar officer in respect of Seller or Guarantor or any of each of their assets; or |
(d) |
enforcement of any Security over any assets of Seller or Guarantor, |
or any analogous procedure or step is taken in any jurisdiction and, in the case of legal proceedings instituted against seller or Guarantor, same shall continue undismissed, or unstayed and in effect for a period of 20 Business Days.
23
16.13 |
Creditors' process |
Any expropriation, attachment, sequestration, distress or execution affects any material asset or assets of Seller or Guarantor is not discharged within seven days.
16.14 |
Unlawfulness and invalidity |
(a) |
It is or becomes unlawful for Seller or Guarantor to perform any of its obligations under a Transaction Document. |
(b) |
Any obligation of Seller or Guarantor under any Transaction Document is not or ceases to be legal, valid and binding or enforceable and the cessation individually or cumulatively materially and adversely affects the interests of Buyer under any Transaction Document. |
16.15 |
Repudiation |
Seller or Guarantor repudiates or purports to repudiate or rescind a Transaction Document or evidences an intention to repudiate or rescind a Transaction Document.
16.16 |
Material adverse change |
Any event or series of events occurs, which, in the opinion of Buyer, may have a Material Adverse Effect and Seller or Guarantor fails to provide evidence satisfactory to Buyer within five (5) Business Days of the date of Buyer notifying Seller or Guarantor of such event or series of events that the same will not in fact have a Material Adverse Effect.
16.17 |
Transaction Documents |
Any Transaction Document is terminated, suspended or otherwise ceases to be valid and in full force and effect.
16.18 |
Environmental Laws and licences |
Seller or Guarantor does not:
(a) |
comply with any Environmental Laws to which it is subject; or |
(b) |
maintain, and comply with the terms of, all Environmental Licences required or desirable in connection with its business. |
16.19 |
Litigation |
Any court of law or arbitral tribunal awards as final judgement damages and/or fines against Seller or Guarantor an aggregate amount which is in excess of USD1,000,000.
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16.20 |
Acceleration |
At any time after a Termination Event occurs, Buyer may, by notice to Seller do all or any of the following:
(a) |
cancel the Prepayment; |
(b) |
declare all or part of the Prepaid Amount, together with accrued Funding Charges, and all other amounts accrued under the Finance Documents (and if relevant, the Supply Contract) be immediately due and payable; and |
(c) |
declare all or part of the Prepaid Amount to be payable on demand. |
16.21 |
Material |
For the purposes of clauses 16.10 and 16.13, Indebtedness or an asset respectively shall be considered “material” where the value of the Indebtedness or asset is USD500,000 or greater or, in the case of an amount denominated in an alternative currency, the equivalent based on the spot exchange rate on the date of such cross-default or expropriation, attachment, sequestration, distress or execution (as applicable).
17. |
Payment mechanics |
17.1 |
Accounts |
(a) |
Seller shall make each payment due from it to Buyer under each Transaction Document, for value on the due date at the time and in same day funds in the relevant currency in the place of payment. |
(b) |
All payments by a party shall be made to the account designated in writing by the other party for this purpose. |
17.2 |
Business Days |
Any payment which is due to be made on a day that is not a Business Day shall be made on the next Business Day in the same calendar month (if there is one) or the preceding Business Day (if there is not).
17.3 |
Currency of account |
The US Dollar is the currency of account and payment for any sum due from Seller under any Transaction Document provided that:
(a) |
each payment in respect of costs, expenses or Taxes shall be made in the currency in which the costs, expenses or Taxes are incurred; and |
(b) |
any amount expressed to be payable in a currency other than Dollars shall be paid in that other currency; and |
(c) |
Buyer may elect at any time to change the currency of account for payment for any sum due from Seller under any Transaction Document to another currency. In such event, Buyer may determine the rate of exchange which shall be applicable to such new currency. |
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18. |
Stamp Duty and Registration Fees |
Seller shall pay all stamp duty, registration fees and similar taxes or charges which may be payable in any jurisdiction in connection with the execution, delivery, performance or enforcement of the Transaction Documents or any judgment given in connection with any of them and shall indemnify Buyer against all liabilities, including penalties, with respect to or resulting from its delay or omission to pay any such stamp, registration or similar tax or charge.
19. |
Transfer |
19.1 |
Seller may not assign any of its rights and/or transfer any of its obligations under this Agreement. |
19.2 |
Buyer may assign any of its rights and/or transfer any of its obligations under the Transaction Documents to any bank or other institution providing Buyer with finance in connection with this Agreement. |
20. |
Communications |
20.1 |
All communications to be made under this Agreement shall be in writing and in English language and be served at the address, fax number or telex number set out on the execution page of this Agreement (or such other address, fax or telex number as either party may notify the other in writing). |
20.2 |
Communications to Seller shall be deemed to have been given: |
(a) |
if posted, on the second Business Day following the day on which it has been sent by prepaid post; |
(b) |
if sent by fax, on the Business Day on which it is transmitted unless transmitted after 5.00 pm (local time), in which case on the following Business Day; and |
(c) |
if delivered personally or by courier, at the time of actual delivery. |
20.3 |
Communications to Buyer shall be effective only upon actual delivery. |
21. |
Amendments, consents and approvals |
21.1 |
This Agreement may not be amended except in writing executed by each of the parties. |
21.2 |
Any other consent, notice or approval from Buyer to Seller under this Agreement must be obtained in writing and shall be of no effect if it is not in writing. |
22. |
Set-off |
Seller shall have no rights of set-off against Buyer.
23. |
Severability |
Any provision of this Agreement which is unenforceable in any jurisdiction shall, in that jurisdiction, be ineffective to the extent of the unenforceability without affecting the validity or enforceability of that provision in any other jurisdiction or affecting any other provision of this Agreement.
24. |
Counterparts |
This Agreement may be executed in one or more counterparts, each of which shall be an original and all of which taken together shall constitute one and the same instrument.
26
25. |
Continuing obligations |
Each obligation in this Agreement is a continuing obligation, separate and independent from each other obligation.
26. |
Entire Agreement |
This Agreement constitutes the entire agreement between the parties about its subject matter and any previous arrangements, understandings and negotiations on that subject cease to have any effect.
27. |
Further assurance |
Seller shall take any further action and execute any further documents at its own expense as Buyer may reasonably request to give effect to this Agreement and the transactions contemplated by it.
28. |
No Rights of Third Parties |
No person other than a party to this Agreement may enforce this Agreement by virtue of the Contracts (Rights of Third Parties) Act 1999.
29. |
Remedy and Waiver |
No failure to exercise, nor any delay in exercising, on the part of Buyer, any right or remedy under this Agreement shall operate as a waiver, nor shall any single or partial exercise of any right or remedy prevent any further or other exercise or the exercise of any other right or remedy. The rights and remedies provided in this Agreement are cumulative and not exclusive of any rights or remedies provided by law.
30. |
Governing law and jurisdiction |
30.1 |
This Agreement and all non-contractual obligations arising in any way whatsoever out of or in connection with this Agreement shall be governed by, construed and take effect in accordance with English law. |
30.2 |
Subject to the below court option, all claims, disputes or differences whatsoever between the parties arising out of or in connection with this Agreement (including without limitation to any question regarding its existence, validity or termination) (a “Dispute”) shall be referred to arbitration in London in accordance with the Arbitration Act 1996 (or any subsequent amendment or re-enactment thereof) (the “Act”). |
30.3 |
The claiming party shall appoint one arbitrator and give written notice to the other party of the appointment (“Arbitration Notice”). The defending party shall appoint and give notice to the claiming party of the second arbitrator within fourteen (14) days of the Arbitration Notice. The third arbitrator shall be appointed by the two arbitrators so appointed within fourteen (14) days of the defending party’s notice. Failing appointment of an arbitrator by the defending party in accordance with this clause, the claiming party’s arbitrator may act as sole arbitrator, at the claiming party’s option. The arbitrator(s) shall have experience of commodities trading matters. |
30.4 |
Notwithstanding the above arbitration clause above, the Buyer shall have the option of referring any dispute to the High Court of Justice in London, England or any other court having jurisdiction over the dispute (the “Court”). If the Buyer is the defending party, such option must be declared within fourteen (14) days of an Arbitration Notice and, upon such declaration, the parties shall procure that the arbitration be discontinued (without an award being given). |
30.5 |
If the Buyer exercises its option, the parties waive any objection now or later to any proceedings relating to the agreement being brought in the Court and the parties hereby irrevocably submit to the exclusive |
27
jurisdiction of the Court. Nothing in this clause 30 shall limit the right of Buyer to commence and pursue proceedings for interim or conservatory relief against Seller in any other court of competent jurisdiction nor shall the taking of proceedings in one or more jurisdictions preclude the taking of proceedings in any other jurisdiction, whether concurrently or otherwise. |
30.6 |
Seller irrevocably waives any objections on the ground of venue or inconvenient forum or any similar grounds and irrevocably agrees that any judgment in any proceedings brought in any court referred to in this clause shall be conclusive and binding and may be enforced in any other jurisdiction. |
30.7 |
If the Buyer so requests, the Seller must, within three Business Days, appoint (for itself) an agent (with an office in London, United Kingdom) for service of all claim forms, application notices, judgments, orders or other notices of English legal process relating to this |
Agreement and notify the agent’s address to the Buyer. If the Seller does not do this, the Buyer may appoint a service agent on the Seller’s behalf and at its expense. If the Buyer does this, it must notify the Seller it has done so and provide details of the service agent as soon as reasonably practicable. The Seller agrees to reimburse the Buyer on its demand all expenses relating to the appointment of the service agent.
30.8 |
If the Process Agent ceases to be able to act as such or no longer has an address in London, Seller shall appoint a substitute Process Agent acceptable to Buyer and deliver to Buyer a copy of the acceptance of the appointment by the new process agent within 30 days. If Seller fails to appoint such a substitute Process Agent then Buyer shall be entitled to appoint a Process Agent on Seller's behalf and expense and Buyer shall notify Seller of any such appointment. This clause shall not affect the right of Buyer to serve process in any other manner permitted by law. |
31. |
Waiver of immunity |
Seller irrevocably waives, to the fullest extent permitted by any applicable law, with respect to itself and its revenues and assets (irrespective of their use or intended use) all immunity on the grounds of sovereignty or other similar grounds from legal action, the jurisdiction of any court, relief by way of injunction, orders for specific performance or for recovery of property, attachment of its assets (whether before or after judgment) and execution or enforcement of any judgment to which it or its revenues or assets might otherwise be entitled in any proceedings in the courts of any jurisdiction and irrevocably agrees to the extent permitted by applicable law, that it will not claim any such immunity in any proceedings.
Executed by Seller and Buyer on the date written at the start of this Agreement.
Schedule 1
Conditions Precedent
1. |
Approvals |
(a) Documents evidencing authority including certified copies of constitutional documents, board resolutions, powers of attorney, specimen signatures
(b) A specimen of the signature of each person authorised by the authorisation document referred to in paragraph (a) above.
28
(c) A certificate of an authorised signatory of the Seller certifying that each copy document relating to it specified in this Schedule 1 is correct, complete and in full force and effect as at a date no earlier than the date of this Agreement.
(d) Certified copies of all authorisations, approvals, consents, exemptions, licences, permits or similar required including those required from any governmental, financial, regulatory or other authority to enable Seller and Guarantor to perform their obligations under the Transaction Documents, Petroleum Contracts or such other agreements or arrangements as may be required for Seller to engage in oil and gas exploration, development and production, including in the oil, gas and condensate fields in the Republic of Albania.
2. |
Security Documents |
Receipt by Buyer of executed:
2.1 |
On demand Guarantee. |
2.2 |
Charge over Equipment for already acquired Equipment. |
2.3 |
Agreement with Raiffeisen Bank ShA in which the bank, inter alia, consents to the arrangements under this Prepayment Agreement (including the Guarantee appearing at Schedule 4) and waives certain set-off rights under the Credit Facility. |
3. |
Other documents and evidence |
(a) |
A certificate signed by the General Manager of Seller in form and substance acceptable to Buyer. |
(b) |
Evidence that the Process Agent has accepted its appointment in accordance with Clause 30.7 (Process Agent). |
(c) |
A copy of any Authorisation or other document, opinion or assurance which Buyer considers to be necessary or desirable in connection with the entry into and performance of the transactions contemplated by any Transaction Document or for the validity and enforceability of any Transaction Document. |
(d) |
The Original Financial Statements of Seller and Guarantor. |
(e) |
Evidence that the fees, costs and expenses then due from Seller pursuant to Clause 9 (Fees) have been paid or will be paid by the Prepayment Date. |
(f) |
Confirmation by Buyer of the satisfactory completion of technical, financial and legal due diligence in respect of Seller (including legal opinion from legal advisers to Buyer in a form and terms acceptable by Buyer). |
(g) |
Evidence that all necessary or desirable stamp, registration or similar taxes levied in the Republic of Albania in relation to this Agreement and any other Transaction Document or other document have been paid. |
(h) |
Evidence that all necessary or desirable notarisations, filings or registrations in the Republic of Albania in relation to this Agreement and any other Transaction Document or other document, or in relation to the subject matter of any of the foregoing, have been fully and satisfactorily completed. |
29
(i) |
Certified copies of insurance policies and such Original Financial Statements as Buyer may require and to Buyer’s satisfaction |
(j) |
Completion, to the reasonable satisfaction of the Buyer, of due diligence covering the financial status of Seller and Guarantor, the oil and gas production fields of the Seller and third parties engaged to operate those fields, including in respect of insurances held by those third parties (including legal opinion from legal advisers to Buyer in a form and terms acceptable by Buyer). |
(k) |
Copies of Seller’s existing loan agreements including the Credit Facility. |
(l) |
Execution of Transaction Documents |
(m) |
Perfection of security. |
(n) |
No Default by Seller or Guarantor. |
4. |
Supplementary Conditions Precedent |
4.1 |
Receipt by Buyer of : |
(a) |
Executed agreement (in a form acceptable to Buyer) with Raiffeisen Bank ShA in which the bank, inter alia, further waives certain set-off rights under the Credit Facility; |
(b) |
Confirmation by Buyer of the satisfactory completion of further technical, financial and legal due diligence in respect of Seller (including legal opinion from legal advisers to Buyer in a form and terms acceptable by Buyer); |
(c) |
Completion, to the reasonable satisfaction of the Buyer, of due diligence covering the financial status of Seller and Guarantor, the oil and gas production fields of the Seller and third parties engaged to operate those fields, including in respect of insurances held by those third parties (including legal opinion from legal advisers to Buyer in a form and terms acceptable by Buyer); |
(d) |
Charge over Equipment for already acquired Equipment. |
4.2 |
No Default by Seller or Guarantor; |
4.3 |
A copy of any Authorisation or other document, opinion or assurance which Buyer considers to be necessary or desirable in connection with the entry into and performance of the transactions contemplated by any Transaction Document or for the validity and enforceability of any Transaction Document; |
4.4 |
Evidence that the fees, costs and expenses then due from Seller pursuant to Clause 9 (Fees) have been paid on time; |
4.5 |
Certified copies of insurance policies and such Original Financial Statements as Buyer may require and to Buyer’s satisfaction; |
4.6 |
Updated copies of Seller’s existing loan agreements including the Credit Facility. |
30
Schedule 2
Prepayment Request
From: Stream Oil & Gas (CI) Ltd
To: Trafigura Pte Ltd Dated: Dear Sirs
Prepayment Agreement dated 2013 between Stream Oil & Gas (CI) Ltd ("Seller") and Trafigura Pte Ltd ("Buyer") ("Agreement")
Capitalised terms used in the Agreement shall have the same meaning when used herein. This is a Prepayment Request pursuant to the terms of the Agreement.
1. We wish to obtain the Prepayment on the following terms:
Proposed Prepayment Date: [.] (or, if that is not a Business Day, the next Business Day)
Amount: [min USD1,000,000 – max USD20,000,000]
Proposed Funding Period:
2. We confirm that each condition specified in Clause XX (Further conditions precedent) is satisfied on the date of this Prepayment Request.
3. The proceeds of the Prepayment should be applied as follows:
(a) |
in payment to Buyer of the fees to which Buyer is entitled pursuant to Clause 10 (Fees) and Clause 11 (Costs and Expenses); |
(b) |
in payment of any other prepayment financing as referred to in Clause 4.2 (Completion of the Prepayment Request) and accordingly please pay USD [.] directly to [Bank details either of Stream’s account with Raiffeisen Albania Bank or Raiffeisen Bank, Vienna, at the sole discretion of Stream]. |
4. This Prepayment Request is irrevocable.
Yours faithfully
…………………………………………………….……
31
Schedule 3
Repayment Schedule – assuming USD 7 million
Date |
Principal Repayment Amount (in USD) |
Interest |
28 February 2013 |
- |
Monthly interest |
31 March 2013 |
- |
Monthly interest |
30 April 2013 |
- |
Monthly interest |
31 May 2013 |
- |
Monthly interest |
30 June 2013 |
- |
Monthly interest |
31 July 2013 |
- |
Monthly interest |
31 August 2013 |
- |
Monthly interest |
30 September 2013 |
- |
Monthly interest |
31 October 2013 |
304,348 |
Monthly interest |
30 November 2013 |
304,348 |
Monthly interest |
31 December 2013 |
304,348 |
Monthly interest |
31 January 2014 |
304,348 |
Monthly interest |
28 February 2014 |
304,348 |
Monthly interest |
31 March 2014 |
304,348 |
Monthly interest |
30 April 2014 |
304,348 |
Monthly interest |
31 May 2014 |
304,348 |
Monthly interest |
30 June 2014 |
304,348 |
Monthly interest |
31 July 2014 |
304,348 |
Monthly interest |
31 August 2014 |
304,348 |
Monthly interest |
30 September 2014 |
304,348 |
Monthly interest |
31 October 2014 |
304,348 |
Monthly interest |
30 November 2014 |
304,348 |
Monthly interest |
31 December 2014 |
304,348 |
Monthly interest |
31 January 2015 |
304,348 |
Monthly interest |
28 February 2015 |
304,348 |
Monthly interest |
31 March 2015 |
304,348 |
Monthly interest |
30 April 2015 |
304,348 |
Monthly interest |
31 May 2015 |
304,348 |
Monthly interest |
30 June 2015 |
304,348 |
Monthly interest |
31 July 2015 |
304,348 |
Monthly interest |
31 August 2015 |
304,348 |
Monthly interest |
32
Schedule 4
Form of Guarantee
This Guarantee is made the 16th day of April 2013 by STREAM OIL & GAS LTD, a company incorporated in British Columbia, Canada, with registration number BC0713471 and with registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (the “Guarantor”) in favour of Trafigura Pte Ltd, a company incorporated in Singapore, whose registered office is at 1 Marina Boulevard, #28-00, One Marina Boulevard, Singapore 018989 and with a branch office at 5 Rue de Jargonnant, 1207 Geneva, Switzerland (the “Beneficiary”).
1. |
In consideration of the Beneficiary entering into or continuing to enter into certain prepayment arrangements in respect of crude oil transactions (the “Transactions”) to STREAM OIL & GAS LTD, Albania branch, a company organised and existing under the laws of the Cayman Islands with a branch registered in the Republic of Albania, and having its registered office at Dega ne Shqiperi e Stream Oil & Gas Ltd, NIPT K72205016P, Rr. Ismail Qemali Samos Tower, Kati 5, Tirana, Albania (the “Counterparty”), the Guarantor hereby irrevocably and unconditionally guarantees that the Guarantor will, within five (5) business days of a demand in writing by the Beneficiary to the Guarantor, pay all moneys and discharge all liabilities which shall at any time or times be due or owing to the Beneficiary by the Counterparty pursuant to the Transactions (the “Guaranteed Amounts”). |
2. |
The obligations of the Guarantor hereunder shall be as primary obligor and not merely as surety and such obligations shall be in addition to and independent of any other security which the Beneficiary may at any time hold. Neither the obligations of the Guarantor herein contained nor the rights, powers and remedies conferred in respect of the Guarantor upon the Beneficiary by this Guarantee or by law shall be discharged impaired or otherwise affected by: (a) any insolvency, winding-up, liquidation, dissolution, administration, receivership or reorganisation (“Insolvency Event”) of the Counterparty or any material change in the status, function, control or ownership of the Counterparty; (b) any concession, release, waiver, time or other indulgence being granted or agreed to be granted to the Counterparty by the Beneficiary; (c) any amendment or extension to or renewal, variation, waiver or release of any obligation of the Counterparty to the Beneficiary; (d) any other act, event, circumstance or omission (whether or not known to the Beneficiary) which but for this clause 2 might operate to discharge, impair or otherwise affect any of the obligations of the Guarantor herein contained or any of the rights, powers or remedies conferred upon the Beneficiary under this Guarantee or by law; (e) any invalidity, illegality, unenforceability, irregularity or frustration of any actual or purported obligation of the Counterparty under any Transaction; or (f) any change of control or sale of the Counterparty. |
3. |
As a separate and independent obligation and liability from its obligations and liabilities under clause 2, the Guarantor agrees to indemnify and keep indemnified the Beneficiary in full and on demand from and against all and any losses, costs, claims, liabilities, damages, demands and expenses suffered or incurred by the Beneficiary arising out of or in connection with any failure of the Counterparty to perform or discharge any of its obligations or liabilities arising under the Transactions and/or in respect of the Guaranteed Amounts. |
4. |
The Guarantor must not assert as against the Counterparty any right of subrogation in respect of any money paid to the Beneficiary until the Beneficiary has received satisfaction of the whole of the Guaranteed Amounts. |
5. |
If an Insolvency Event occurs with respect to the Counterparty, the Guarantor shall not prove in the bankruptcy or liquidation in competition with the Beneficiary in respect of any money paid by the Guarantor under this Guarantee or in respect of any other amount applied by the Beneficiary in reduction of the Guarantor’s liability under this Guarantee or otherwise until the Beneficiary has received satisfaction of the whole of the Guaranteed Amounts. |
33
6. |
The Beneficiary shall not be obliged before exercising any of the rights powers or remedies conferred upon it in respect of the Guarantor by this Guarantee or by law: (a) to make a demand on the Counterparty; (b) to take any action or obtain judgment in any court against the Counterparty; (c) to make or file any claim or proof in a winding-up or dissolution of the Counterparty; or (d) to enforce or seek to enforce any security taken in respect of any of the obligations of the Counterparty. |
7. |
The Guarantor hereby warrants, represents and undertakes to the Beneficiary that: (a) it is duly incorporated and has full power to enter into and perform its obligations under this Guarantee and all necessary corporate shareholder and other action to enable it to execute deliver and perform the same has been taken and no limitation on its powers to borrow or give guarantees have been exceeded as a result of this Guarantee; (b) this Guarantee has been validly created and constitutes a valid and legally binding obligation on the Guarantor enforceable in accordance with its terms; and (c) the creation of this Guarantee and the performance and observance of the obligations hereunder does not: (i) contravene any existing applicable law or regulation to which it is subject; (ii) conflict with or result in any breach of any of the terms of or constitute a default under any agreement to which it is a party or is subject or by which it or any of its property is bound; or (iii) contravene or conflict with any provision of its memorandum and articles of association or its other constitutional documents. |
8. |
This Guarantee shall not be considered as satisfied by any intermediate payment or satisfaction of any part of any sum or sums of money owing as aforesaid but shall be a continuing security and shall extend to cover any sum or sums of money which shall for the time being constitute the Guaranteed Amounts. If the Guarantor cannot pay in the currency specified in the Transactions due to a legal or other impediment beyond its control, it may pay in an alternative appropriate currency. |
9. |
Any notice, demand or other communication given under this Guarantee shall be in writing and sent by pre-paid first class letter post or delivered by hand addressed to the address of the party set out above or by email to Dr. Sotirios Kapotas (skapotas@streamoilandgas.com) and James Hodgson (jhodgson@streamoilandgas.com) or to such other address as such party may notify in writing to the other in accordance with this clause. Any such notice shall be deemed to have been received by the party to whom it is addressed five (5) business days after posting in the case of notice given by pre-paid first class letter post or if sent by hand upon delivery or if sent by email on the date of transmission of such email provided such date is a business day at the place of receipt and, where not a business day at the place of receipt, on the immediately following business day at the place of receipt. |
10. |
This Guarantee and any dispute arising out of or in connection with it (including in relation to its subject matter, formation or termination) shall be governed by and construed in accordance with the laws of England and the parties hereby submit to the exclusive jurisdiction of the English High Court in London. Nothing in this clause shall limit the right of the Beneficiary to take proceedings against the Guarantor in any other court of competent jurisdiction, nor shall the taking of proceedings in any one or more jurisdictions preclude the taking of proceedings in any other jurisdictions, whether concurrently or not, to the extent permitted by the law of such other jurisdiction. |
11. |
If the Beneficiary so requests, the Guarantor must, within three Business Days, appoint (for itself) an agent (with an office in London, United Kingdom) for service of all claim forms, application notices, judgments, orders or other notices of English legal process relating to this Agreement and notify the agent's address to the Beneficiary. If the Guarantor does not do this, the Beneficiary may appoint a service agent on the Guarantor's behalf and at its expense. If the Beneficiary does this, it must notify the Guarantor it has done so and provide details of the service agent as soon as reasonably practicable. The Guarantor agrees to reimburse the Beneficiary on its demand all expenses relating to the appointment of the service agent. |
12. |
This Guarantee and the rights and obligations hereunder are not assignable or otherwise transferable, provided that the Beneficiary may with the Guarantor's and Counterparty's prior written consent (which is not |
34
to be unreasonably withheld) assign any of its rights under this Guarantee to any bank or other entity providing the Beneficiary with finance in connection with the any of the Transactions. |
13. |
Subject to clause 12, nothing in this Guarantee shall confer on any third party any benefit or the right to enforce any term ofthis Guarantee. |
IN WITNESS of which this Guarantee was executed and is deliver d as a deed and takes effect from
the day and year first above written.
EXECUTED as a deed by |
) |
………………………………………………………………………………. |
|
STREAM OIL & GAS LTD acting by |
) |
Director |
|
Sotirios Kapotas, a director |
) |
|
|
In the presence of: |
|
|
|
[signature, |
) |
………………………………………………………………………………. |
|
name and address of witness] |
) |
|
|
|
|
|
|
EXECUTION PAGE |
||||||
EXECUTED by |
||||||
STREAM OIL & GAS LTD acting by: |
||||||
Name: |
Sotirios Kapotas |
|
(Sign) |
/s/ Sotirios Kapotas |
||
Title : |
President & CEO |
|
(Authorised Signatory) |
…………………...……………………..…… |
||
EXECUTED by |
||||||
TRAFIGURA PTE LTD acting by: |
||||||
Name: |
……………………………………………………………………. |
(Sign) ……………………………………….…………………………………… |
||||
Title: |
……………………………………………………………………. |
(Authorised Signatory) ………………………………………….…….. |
||||
Name: |
……………………………………………………………………. |
(Sign) ……………………………………………………………….…………… |
||||
Title : |
……………………………………………………………………. |
(Authorised Signatory) ……………………………………….……….. |
35
Exhibit 10.26
Dated 22 May 2013
RAIFFEISEN BANK SH.A
- and –
TRAFIGURA PTE LTD
STREAM OIL & GAS LTD (ACTING THROUGH ITS BRANCH IN ALBANIA REGISTERED WITH THE NAME DEGA NE SHQIPERI E STREAM OIL & GAS LTD)
- and –
STREAM OIL & GAS LTD (BC)
_________________________________________
COORDINATION AGREEMENT
_________________________________________
THIS COORDINATION AGREEMENT is dated ___ April 2013 and made between:-
(1) |
RAIFFEISEN BANK Sh.A, a bank registered under the laws of Albania, and existing under the laws of Albania registered with Court Order No. 17426 on 10 July 1997 (the “Bank”); and |
(2) |
TRAFIGURA PTE LTD, branch office Geneva, a company incorporated in Singapore with a branch office located at 5 Rue de Jargonnant, Geneva 1207, Switzerland (“Trafigura”); and |
each of the Bank and Trafigura, a “Creditor”, and together the “Creditors”
(3) |
STREAM OIL & GAS LTD (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd, registered in Albania on 5 October 2007 with NIPT K72205016P and with its office at Rr. Ismail Qemali, Samos Tower, Kati 5, Tirana, Albania), an exempted company incorporated with limited liability in the Cayman Islands with registered number WK188194 whose registered office is at Second Floor, Compass Centre, PO Box 448, George Town, Grand Cayman, KY1-1106, Cayman Islands (“Stream”); and |
(4) |
STREAM OIL & GAS LTD, a company incorporated in British Columbia, Canada, with registration number BC0713471 and with registered office at 19th Floor, 885 West Georgia St, Vancouver BC, V6C 3H4, Canada and its head office at #300, 609 – 14th Street N.W., Calgary, Alberta, T2N 2A1, Canada (“Stream Canada”), |
each of the parties listed in (1) to (4), a “Party”, and together the “Parties”.
RECITALS
(A) |
The Bank has agreed to provide financing to Stream on the terms of a facility agreement for a US$20,000,000 (United States Dollars Twenty Million) trade finance term facility dated 15 December 2011 between Stream, Stream Canada, and the Bank (the “Facility Agreement”). |
(B) |
Under the terms of the Facility Agreement, Stream Canada has given a guarantee for the benefit of the Bank, in respect of all of Steam’s obligations under the Facility Agreement and related finance documents (the “Bank Guarantee”). |
(C) |
As security for the obligations of Stream under the Facility Agreement, Stream has granted to the Bank security pursuant to a commercial contracts security agreement dated 15 December 2011 (the “Security Agreement”) and a securing charge agreement over moveable assets and inventories dated 22 December 2011 (the “Charge Agreement”) (the “Bank Security”). |
(D) |
Stream and Trafigura have entered into a crude oil sales contract dated 16 January 2013 for the provision by Stream to Trafigura of cargoes of crude oil (the “Sales Contract”). |
(E) |
Trafigura have agreed to pre-pay part of the purchase price for the crude oil to be supplied under the Sales Contract on the terms of a prepayment agreement dated on or about the date of this Agreement between Trafigura, Stream and Stream Canada (the “Prepayment Agreement”), pursuant to which Trafigura shall be entitled to set off amounts outstanding under the Prepayment Agreement against the purchase price of the crude oil cargoes under the Sales Contract. |
(F) |
As a condition precedent to the Prepayment Agreement, Stream Canada has given, or will give, a guarantee for the benefit of Trafigura, in respect of Stream’s obligations under the Prepayment Agreement (the “Trafigura Guarantee”). |
1
(G) |
As security for Stream’s obligations under the Prepayment Agreement, Stream has agreed to give security in favour of Trafigura over equipment and materials that Seller purchases with the proceeds of prepayments made under the Prepayment Agreement (the “Trafigura Security”). Further, Stream has agreed to assign to Trafigura the proceeds of Insurances (as defined in paragraph 10) in respect of the Trafigura Security Assets (as defined in paragraph 12). |
(H) |
The Bank, Stream and Stream Canada have agreed to enter into amendment agreements in respect of each of the Facility Agreement and the Charge Agreement to permit Stream to enter into the Prepayment Agreement and to give the Trafigura Security. Entry into this Agreement is a condition precedent to such amendment agreements becoming effective. |
(I) |
The Parties wish to enter into this Agreement in order to coordinate Trafigura’s rights under the Prepayment Agreement to set off certain sums owing to Trafigura by Stream against the value of cargoes delivered to Trafigura by Stream and in respect of the Trafigura Security, with the Bank’s rights under the Facility Agreement, the Charge Agreement, the Security Agreement and related finance documents (together, the “Financing Documents”). |
FOR GOOD AND VALUABLE CONSIDERATION, THE ADEQUACY OF WHICH IS HEREBY ACKNOWLEDGED, IT IS AGREED as follows:
1. |
Notwithstanding the provisions of the Financing Documents, the Bank agrees that Trafigura shall be entitled to set off, pursuant to Clause 5 of the Prepayment Agreement, certain amounts owing to Trafigura by Stream under the Prepayment Agreement against the purchase price of crude oil cargoes under the Sales Contract. Notwithstanding the foregoing and the provisions of Clause 5 of the Prepayment Agreement during the period of time until the Bank has promptly notified Trafigura that there is no indebtedness of Stream under the Financing Documents (the “Bank Facility Period”), each amount set off by Trafigura in any month shall not exceed the Permitted Amount for that month. In any case, at the end of the Bank Facility Period there shall be no restrictions on Trafigura’s right to set off amounts under the Prepayment Agreement against the amounts owed under the Sales Contract. |
For the purpose of this Agreement:
“Amortisation Table” means the amortisation table appearing at Schedule 1 to this Agreement as may be amended from time to time by the prior written consent of Stream, the Bank and Trafigura);
“Permitted Amount” for each month shall be the lower of:
a. |
the amount set out in the Amortisation Table for that month expressed as percentage of the aggregate of (i) the principal amount scheduled to be outstanding under the Facility Agreement in that month and (ii) the amounts due for repayment by Stream under the Prepayment Agreement in that month; and |
b. |
the total amounts then due for repayment by Stream under the Prepayment Agreement (excluding any voluntary repayments). |
2. |
Trafigura and Stream shall ensure that Trafigura pays the amounts payable to Stream under the Prepayment Agreement through Stream’s accounts held with the Bank or with Raiffeisen Bank International, Vienna, at the discretion of Stream. |
2
3. |
The principal amount outstanding under the Prepayment Agreement shall be reduced by way of set-off in accordance with the Amortisation Table appearing at Schedule 1 to this Coordination Agreement. Should Stream fail to deliver sufficient crude oil under the Sales Contract in a month so as to permit set-off of the amount specified in Schedule 1, Stream shall pay to Trafigura the difference between the actual amount set-off and the set-off amount for such month appearing in Schedule 1 (such difference being the “Deficiency Amount”). Notwithstanding any provision of the Financing Documents, payment of the Deficiency Amount shall not constitute a default or termination event under or a breach of the Financing Documents. |
4. |
The aggregate amount of prepayments to be made by Trafigura to Stream under the Prepayment Agreement shall not exceed $7,000,000 without the Bank’s prior written consent. |
5. |
Notwithstanding any provision of the Financing Documents, the Bank: |
a. |
waives its right to a charge over any equipment and materials which shall be purchased by Stream for the expansion of production of the Cakran, Gorisht, Ballsh and Delvina Field projects utilising solely funds received from Trafigura under the Prepayment Agreement (the “Relevant Equipment”); |
b. |
affirms Stream’s right to grant and Trafigura’s right to obtain a charge over such Relevant Equipment; and |
c. |
acknowledges that the granting of a charge by Stream in favour of Trafigura over the Relevant Equipment and the assignment of proceeds of Insurances (as defined in paragraph 10) in respect of the Trafigura Security Assets (as defined in paragraph 12) shall not constitute a default or termination event under or a breach of any or all of the Financing Documents. |
Stream shall notify the Bank within 14 days of purchasing any Relevant Equipment.
6. |
Each of the Parties agrees that: |
a. |
unless otherwise provided for in this Agreement, the liabilities owed by Stream to the Bank and Trafigura shall rank pari passu; and |
b. |
the Bank Security and the Trafigura Security granted by Stream shall secure the following liabilities (but only to the extent that such security is expressed to secure those liabilities): |
i. |
the Bank Security and any other security created pursuant to the Financing Documents shall rank and secure liabilities of Stream to the Bank under the Financing Documents (the “Financing Documents Liabilities”); and |
ii. |
the Trafigura Security shall rank and secure the liabilities of Stream to Trafigura under the Prepayment Agreement (the “Prepayment Agreement Liabilities”). |
7. |
Each Creditor is entitled to make a demand under, or take any other enforcement action in respect of, the Trafigura Guarantee or the Bank Guarantee, as applicable. If any Creditor makes a demand under, or takes any other enforcement action in respect of, the Trafigura Guarantee or the Bank Guarantee, as applicable to it, the other Creditor shall also promptly make a demand or take a similar enforcement action in respect of its guarantee as it is entitled to take under its guarantee and in accordance with the terms of its guarantee. |
3
(a) |
first, in or towards payment pro rata of the costs of that recovery. The costs of any recovery pursuant to the Trafigura Guarantee or the Bank Guarantee shall be shared by the Creditors pro rata to the principal amount of the Prepayment Agreement Liabilities and the Financing Documents Liabilities; and |
(b) |
second, in or towards payment pro rata of the Prepayment Agreement Liabilities and the Financing Documents Liabilities on the pari passu basis. |
9. |
Each Creditor shall hold the amount of any receipt or recovery payable to another Creditor (less the pro rata share of the costs of the recovery attributable to that other Creditor) on trust for that other Creditor and promptly pay that amount to that other Creditor for application in accordance with the terms of this Agreement. |
10. |
Stream shall: |
(a) |
insure all its assets and business of an insurable nature with reputable insurers of good standing; |
(b) |
comply with all insurance conditions imposed by any lease, agreement for lease or tenancy under which Stream derives an interest; |
(c) |
procure that the insurances it must maintain to comply with this Clause (the “Insurances”): |
(i) |
are on the same terms and cover the same risks as those normally taken out by prudent companies owning or possessing similar assets and carrying on similar businesses to Stream’s; and |
(ii) |
are in such amounts as is prudent (including for the full replacement value from time to time of any assets destroyed or otherwise becoming a total loss); |
(d) |
where the assets in question are, or are expressed to be, the subject of the Bank Security or Trafigura Security, ensure the Bank is endorsed on the policies as loss payee and promptly provide evidence to that effect to the Bank; |
(e) |
pay when due all premiums and other amounts payable under the Insurances and, promptly when asked by the Lender, produce receipts for payment of the premiums; |
(f) |
promptly when asked by the Bank, deposit with or produce for inspection to the Bank all policies and other contracts for the Insurances; and |
(g) |
use reasonable endeavours to prevent any act, omission or circumstance that would be reasonably likely to render void or voidable any of the Insurances. |
11. |
The provisions of this Agreement are without prejudice to the Bank’s rights in respect of the Insurances under the Facility Agreement. To the extent that Stream’s obligations under the Prepayment Agreement and the Trafigura Security in respect of Insurances conflict with the provisions of this Agreement, the provisions of this Agreement shall prevail. |
4
12. |
The Bank shall hold the amount of insurance proceeds paid to it under the Insurances in respect of the assets which the Bank reasonably believes to be, or which are expressed to be, the subject the Trafigura Security (“Trafigura Security Assets”) (less the costs referred to in this paragraph) on trust for Trafigura and promptly pay that amount to Trafigura. The costs incurred by the Bank in connection with any such payment of the proceeds of Insurances in respect of the Trafigura Security Assets shall be for the account of Trafigura. The Bank shall be entitled to apply the insurance proceeds paid to it under the Insurances in respect of the Trafigura Security Assets towards the payment of such costs before paying the remaining amount of the proceeds to Trafigura. |
13. |
Stream Canada acknowledges and agrees to provisions set out in paragraphs 7 to 12 inclusive in respect of the Trafigura Guarantee and the Bank Guarantee and in respect of the Insurances. |
14. |
No later than 5 days from the date of this Agreement: |
a. |
Stream shall deliver a notice to Trafigura of the assignment of the Sales Contract pursuant to the Security Agreement in the form set out in Schedule 2 to this Agreement; and |
b. |
Trafigura shall deliver to the Bank an acknowledgement of notice substantially in the form provided in Schedule 2 to this Agreement. |
15. |
Trafigura shall promptly notify the Bank in writing about: |
a. |
the Prepayment Agreement being entered into by the parties and supply the Bank with a copy of the Prepayment Agreement signed by the parties to it; |
b. |
the prepayment being made to Stream pursuant to the Prepayment Agreement and the aggregate amount of such prepayment; and |
c. |
the Trafigura Security and Trafigura Guarantee or any other security or guarantee being granted to Trafigura by Stream or Stream Canada in respect of the prepayment Agreement and supply the Bank with a copy of the relevant security documents and guarantees signed by the parties to them. |
Each document referred to in this paragraph 15 must be in the form approved by the Bank in advance of its signing and may not be amended by the parties during the Bank Facility Period without the Bank’s prior consent.
16. |
During the Bank Facility Period Trafigura shall each month notify the Bank in writing about the aggregate amount, which it has set off pursuant to the Prepayment Agreement in that month within 5 business days from the end of that month; |
17. |
During the Bank Facility Period the Bank shall each month notify Trafigura in writing about the aggregate principal amounts paid by or on behalf of Stream pursuant to the Facility Agreement in that month within 5 business days from the end of that month; |
18. |
During the Bank Facility Period each Creditor shall immediately advise the other of (i) any circumstance or event which comes to its knowledge and upon the happening of which the Trafigura Security and the Bank Security created pursuant to the Financing Documents, respectively, shall become enforceable and (ii) of its intentions with regard to its security. |
5
19. |
During the Bank Facility Period each Creditor shall immediately advise the other of (i) any circumstance or event which comes to its knowledge and upon the happening of which it becomes entitled to make a demand under, or take any other enforcement action in respect of, the Trafigura Guarantee or the Bank Guarantee, as applicable and (ii) of its intentions in respect of its guarantee. |
20. |
Stream and Stream Canada consent to Trafigura and the Bank providing each other with the information envisaged by this Agreement. |
21. |
Trafigura consents to Stream providing the Bank with information about the Prepayment Agreement, including without limitation details of the Relevant Equipment, the amounts of prepayments made under the Prepayment Agreement and any defaults under the Prepayment Agreement. |
22. |
A breach of the terms of this Agreement by Stream, Stream Canada or Trafigura shall be an Event of Default for the purposes of the Facility Agreement and the Prepayment Agreement. |
23. |
In the event of any conflict between any terms of any of the Facility Agreement, Security Agreement, Charge Agreement, Prepayment Agreement, Sales Contract and this Agreement, the terms of this Agreement shall prevail. |
24. |
No person other than a Party may enforce this Agreement by virtue of the Contracts (Rights of Third Parties) Act 1999. |
25. |
Any provision of this Agreement, which is unenforceable in any jurisdiction, shall, in that jurisdiction, be ineffective to the extent of the unenforceability without affecting the validity or enforceability of that provision in any other jurisdiction or affecting any other provision of this Agreement. |
26. |
All communications between the Parties must be in writing in English language. Notices can be given by fax, post or email. For all communications, the postal and email addresses and fax number (and the contact department or officer, if any) for each Party are set out below. |
Stream:
Rr. Ismail Qemali
Samos Tower, Kati 5
Tirana, Albania
with a copy to:
#300, 609 – 14th Street N.W.,
Calgary, Alberta T2N 2A1
Attention: |
Dr. Sotirios Kapotas, Chief Executive Officer |
Fax: |
+355 38540385 with a copy to +1 403 531 2695 |
Email: |
skapotas@streamoilandgas.com |
|
with a copy to nxoro@streamoilandgas.com |
6
Stream Canada:
#300, 609 - 14th Street N.W.
Calgary, Alberta T2N 2A1
Attention: |
James R. Hodgson, Chief Financial Officer |
Fax: |
+1 403 531 2695 |
Email: |
jhodgson@streamoilandgas.com |
|
with a copy to skapotas@streamoilandgas.com |
Bank:
European Trade Center, 6th Floor
Blvd. “Bajram Curri”
Tirana, Albania
Attention: |
Elona Koci, Head of Large Corporate and Mid Market Division |
Fax: |
+ 355 4 2275550 |
Email: |
elona.koci@raiffeisen.al |
|
with a copy to jorida.zaimi@raiffeisen.al |
Trafigura:
5 rue du Jargonnant
1207 Geneva, Switzerland
Attention: |
Nicolas Djelalian, Structured Finance |
Fax: |
+41 22 786 6401 |
Email: |
nicolas.djelalian@trafigura.com; |
|
StructuredFinanceMiddleEast_CIS&Europe@trafigura.com |
27. |
If a Party's contact details specify a particular department or officer, any communication to that Party will only be effective if addressed to that department or officer. Communications by fax are effective only when received in legible form. Any electronic communication made between the Parties will be effective only when actually received in readable form. Communications by letter are effective: |
a. |
when left at the relevant address; or |
b. |
two business days (or for airmail, five business days) after being posted, postage prepaid (or, airmail postage prepaid), to the relevant address. |
28. |
This Agreement may not be amended except in writing executed by each of the Parties. |
29. |
This Agreement and all non-contractual obligations arising in any way whatsoever out of or in connection with this Agreement shall be governed by, construed and take effect in accordance with English law. |
30. |
All claims, disputes or differences whatsoever between any or all of the Parties arising out of or in connection with this Agreement (including without limitation any question regarding its existence, validity or termination, or any non-contractual obligations) shall be referred to |
7
arbitration in London in accordance with the Arbitration Act 1996 (or any subsequent amendment or re-enactment thereof). |
IN WITNESS WHEREOF this Agreement has been executed by the Parties on the date specified at the beginning of this Agreement. The Bank and Trafigura agree that their mutual rights and obligations set out in this Agreement shall become effective on the date when both of them have executed this Agreement, irrespective of whether Stream and Stream Canada have executed it.
8
SCHEDULE 1: AMORTISATION SCHEDULE
|
RBAL |
|
TRAFIGURA |
|
PERCENTAGE OF TOTAL DEBT |
|
||
|
Net Outstanding Loan |
|
Net Outstanding Loan |
|
RBAL |
TRAFIGURA |
PERMITTED AMOUNT TO BE SET OFF BY TRAFIGURA |
|
01/12/2012 |
16,328,019 |
|
|
|
|
|
|
|
30/01/2013 |
16,328,019 |
|
|
|
|
|
|
|
28/02/2013 |
16,328,019 |
|
|
|
|
|
|
|
31/03/2013 |
15,307,518 |
|
7,000,000 |
|
69% |
31% |
31% |
|
30/04/2013 |
15,307,518 |
|
7,000,000 |
|
69% |
31% |
31% |
|
31/05/2013 |
15,307,518 |
|
7,000,000 |
|
69% |
31% |
31% |
|
30/06/2013 |
14,287,017 |
|
7,000,000 |
|
67% |
33% |
33% |
|
31/07/2013 |
14,287,017 |
|
7,000,000 |
|
67% |
33% |
33% |
|
31/08/2013 |
14,287,017 |
|
7,000,000 |
|
67% |
33% |
33% |
|
30/09/2013 |
13,266,516 |
|
6,695,652 |
|
66% |
34% |
34% |
|
31/10/2013 |
13,266,516 |
|
6,391,304 |
|
67% |
33% |
33% |
|
30/11/2013 |
13,266,516 |
|
6,086,957 |
|
69% |
31% |
31% |
|
31/12/2013 |
12,246,014 |
|
5,782,609 |
|
68% |
32% |
32% |
|
30/01/2014 |
12,246,014 |
|
5,478,261 |
|
69% |
31% |
31% |
|
28/02/2014 |
12,246,014 |
|
5,173,913 |
|
70% |
30% |
30% |
|
31/03/2014 |
11,225,513 |
|
4,869,565 |
|
70% |
30% |
30% |
|
30/04/2014 |
11,225,513 |
|
4,565,217 |
|
71% |
29% |
29% |
|
31/05/2014 |
11,225,513 |
|
4,260,870 |
|
72% |
28% |
28% |
|
30/06/2014 |
10,205,012 |
|
3,956,522 |
|
72% |
28% |
28% |
|
31/07/2014 |
10,205,012 |
|
3,652,174 |
|
74% |
26% |
26% |
|
31/08/2014 |
10,205,012 |
|
3,347,826 |
|
75% |
25% |
25% |
|
30/09/2014 |
9,184,511 |
|
3,043,478 |
|
75% |
25% |
25% |
|
31/10/2014 |
9,184,511 |
|
2,739,130 |
|
77% |
23% |
23% |
|
30/11/2014 |
9,184,511 |
|
2,434,783 |
|
79% |
21% |
21% |
|
31/12/2014 |
8,164,010 |
|
2,130,435 |
|
79% |
21% |
21% |
|
30/01/2015 |
8,164,010 |
|
1,826,087 |
|
82% |
18% |
18% |
|
28/02/2015 |
8,164,010 |
|
1,521,739 |
|
84% |
16% |
16% |
|
31/03/2015 |
7,143,508 |
|
1,217,391 |
|
85% |
15% |
15% |
|
30/04/2015 |
7,143,508 |
|
913,043 |
|
89% |
11% |
15% |
|
31/05/2015 |
7,143,508 |
|
608,696 |
|
92% |
8% |
15% |
|
30/06/2015 |
6,123,007 |
|
304,348 |
|
95% |
5% |
15% |
|
31/07/2015 |
6,123,007 |
|
0 |
|
100% |
0% |
15% |
|
31/08/2015 |
6,123,007 |
|
|
|
100% |
0% |
|
|
30/09/2015 |
5,102,506 |
|
|
|
100% |
0% |
|
|
31/10/2015 |
5,102,506 |
|
|
|
100% |
0% |
|
|
9
|
RBAL |
|
TRAFIGURA |
|
PERCENTAGE OF TOTAL DEBT |
|
||
|
Net Outstanding Loan |
|
Net Outstanding Loan |
|
RBAL |
TRAFIGURA |
PERMITTED AMOUNT TO BE SET OFF BY TRAFIGURA |
|
30/11/2015 |
5,102,506 |
|
|
|
100% |
0% |
|
|
31/12/2015 |
4,082,005 |
|
|
|
100% |
0% |
|
|
30/01/2016 |
4,082,005 |
|
|
|
100% |
0% |
|
|
28/02/2016 |
4,082,005 |
|
|
|
100% |
0% |
|
|
30/03/2016 |
3,061,504 |
|
|
|
100% |
0% |
|
|
30/04/2016 |
3,061,504 |
|
|
|
100% |
0% |
|
|
31/05/2016 |
3,061,504 |
|
|
|
100% |
0% |
|
|
30/06/2016 |
2,041,002 |
|
|
|
100% |
0% |
|
|
31/07/2016 |
2,041,002 |
|
|
|
100% |
0% |
|
|
31/08/2016 |
2,041,002 |
|
|
|
100% |
0% |
|
|
30/09/2016 |
1,020,501 |
|
|
|
100% |
0% |
|
|
31/10/2016 |
1,020,501 |
|
|
|
100% |
0% |
|
|
30/11/2016 |
1,020,501 |
|
|
|
100% |
0% |
|
|
31/12/2016 |
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
SCHEDULE 2: FORM OF NOTICE AND ACKNOWLEDGEMENT TO BE SERVED PURSUANT TO THE SECURITY AGREEMENT
[Letterhead of Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd).]
To:TRAFIGURA PTE LTD
[insert date of notice]
Dear Sirs
Crude oil sales contract dated 16 January 2013, contract no: SKO-012-453470 (the Agreement)
1 |
We hereby give you notice that by a Commercial Contracts Security Agreement dated 15 December 2011 (the Security Agreement), we assigned to Raiffeisen Bank Sh. A. (the Lender) all our rights, title, benefit and interest, whether present or future, proprietary, contractual or otherwise, arising out of or in, to or under the Agreement (the Secured Rights). |
2 |
We hereby request that, upon receipt of this notice, you sign the attached acknowledgement and send the signed acknowledgement to the Lender at the indicated contact. |
3 |
Subject to paragraph 5 below, we hereby instruct you to pay all amounts due to us from you under the Agreement into the account held in our name (Dega ne Shqiperi e Stream Oil) with Raiffeisen Bank Sh. A. bearing account number 0005250208 (IBAN AL17202110370000000005250208) or to such other account or accounts as may from time to time be notified to you by (or with the approval of) at the Lender. Please note, we cannot change these payment instructions without the written consent of the Lender. |
4 |
Please note that, with effect from today and until the Lender has notified you in writing accordingly: |
(a) |
the Agreement may not be terminated, amended or varied except with the prior written consent of the Lender save as permitted by paragraphs 3(a) and 3(d) of the attached acknowledgement; |
(b) |
notwithstanding the Security Agreement, you may treat us as remaining liable to exercise and perform our obligations (if any) expressed to be assumed by us in relation to the Agreement and the Lender shall not be under any obligation of any kind whatsoever in respect of the Agreement; |
(c) |
notwithstanding the Security Agreement, you may continue to treat us as entitled to exercise and enforce all our rights, discretions and remedies under or in respect of the Agreement unless and until you are notified by or on behalf of the Lender that the security created by the Security Agreement has become enforceable and upon receiving such notification, you shall thereafter treat the Lender (and any person nominated by the Lender) as the only persons entitled to exercise and enforce all such rights, discretions and remedies; |
(d) |
this notice is without prejudice to the rights of the Lender under or pursuant to the provisions of the Security Agreement; and |
(e) |
the authority and any instructions contained in this notice cannot be revoked or varied by us without the prior written consent of the Lender. |
11
5 |
We refer to the coordination agreement dated [ ] 2013 entered into between, among others, us, you and the Lender (the “Coordination Agreement”). We request you to confirm that you do not have, and will not make or exercise, any rights of counterclaim, lien, rights of set-off or any other equities against us which would be likely to affect the performance of rights and obligations under the Agreement, save for the rights of set-off permitted by the terms of the Coordination Agreement. |
6 |
This letter shall be governed by and construed in accordance with the laws of the Cayman Islands. |
Yours faithfully
For and on behalf of Stream Oil & Gas Ltd (acting through its
branch in Albania registered with the name
Dega ne Shqiperi e Stream Oil & Gas Ltd)
cc Raiffeisen Bank Sh. A.
12
Form of acknowledgement to be enclosed with the notice
To:Raiffeisen Bank Sh. A.
Bulevardi Bajram Curri
ETC
Tirana
Albania
Attn:Elona Koci, Head of Large Corporate and Mid Market Division
Dear Sirs
Crude oil sales contract dated 16 January 2013, contract no: SKO-012-453470 (the Agreement)
1 |
We hereby acknowledge receipt of the letter (the Notice) from Stream Oil & Gas Ltd (acting through its branch in Albania registered with the name Dega ne Shqiperi e Stream Oil & Gas Ltd) (the Borrower) dated [insert date of Notice] relating to the Commercial Contracts Security Agreement dated 15 December 2011 (the Security Agreement) entered into between yourself and the Borrower. Terms defined in the Notice shall bear the same meaning when used in this letter. |
2 |
We consent to the terms of the Notice and the assignment by the Borrower pursuant to the Security Agreement of the Secured Rights for all purposes in relation to the Agreement. |
3 |
We confirm that: |
(a) |
we will not amend or vary the Agreement without your prior written consent, provided we may agree an amendment to the Agreement which: |
(i) |
relates to the day-to-day operation of the Agreement; |
(ii) |
is usual for contracts of the same type as the Agreement; |
(iii) |
is not prejudicial to the interests of the Lender and |
(iv) |
which you notify the Lender promptly after it is agreed; |
(b) |
we have not as at today's date, received: |
(i) |
any other notice of any other assignment, charge or encumbrance in respect of the Secured Rights; or |
(ii) |
any notice that any third party (other than you) has or will have any right or interest whatsoever in or has made or will be making any claim or demand or taking any action whatsoever in respect of the Secured Rights, and we will notify you upon our receiving any such notice or otherwise becoming aware of such circumstances; |
(c) |
we shall not, without your prior written consent, recognise the exercise or purported exercise by the Borrower of any right that the Borrower may have to amend, vary, cancel, terminate, repudiate or surrender the Agreement; |
13
(d) |
if any event occurs which would permit us to exercise any right against the Borrower to cancel, terminate, repudiate or surrender the Agreement, we undertake: |
(i) |
promptly upon becoming aware of it, to give you notice of such event; and |
(ii) |
not to take steps to exercise such right for thirty days from our written notice to you (and to accept as adequate remedy, performance by you within such 30 day period of the obligations of the Borrower that gave rise to such right); |
(e) |
subject to paragraph 3(f) below, we will unconditionally and irrevocably pay all proceeds payable by us under the Agreement to the account held with Raiffeisen Bank Sh. A. in the name of the Borrower (Dega ne Shqiperi e Stream Oil) with Raiffeisen Bank Sh. A. bearing account number 0005250208 (IBAN AL17202110370000000005250208) or to such other account or accounts as may from time to time be notified to us by you (or by the Borrower with the written approval of any one of you, which approval we will obtain and review before the changes are implemented); |
(f) |
we do not have, and will not make or exercise, any claims or demands, rights of counterclaim, lien, rights of set-off or any other equities against the Borrower or the Secured Rights, except for the rights of set-off permitted by the terms of the Coordination Agreement; and |
(g) |
the undersigned has full authority to acknowledge the Notice and the Lender's security interest over the Secured Rights on behalf of Trafigura PTE Ltd in accordance with the terms of this letter. |
4 |
This letter shall be governed by and construed in accordance with the laws of the Cayman Islands. |
5 |
This letter has been executed and delivered as a deed by us on the date specified above. |
Yours faithfully
Executed as a deed by an
authorised signatory
for and on behalf of
TRAFIGURA PTE LTD
Date:
in the presence of:
Name of witness:
Address:
14
EXECUTION PAGE
EXECUTED by |
|||
RAIFFEISEN BANK SH.A acting by: |
|||
|
|
|
|
Name: |
Christian Canacaris |
(Sign) |
/s/ Christian Canacaris |
|
|
|
|
Title: |
CEO |
|
(Authorised Signatory) |
|
|
|
|
Name: |
Alexander Zsolnai |
(Sign) |
/s/ Alexander Zsolnai |
|
|
|
|
Title: |
Deputy - CEO |
|
(Authorised Signatory) |
|
|
|
|
Date: |
|
|
|
EXECUTED by |
|||
TRAFIGURA PTE LTD acting by: |
|||
|
|
|
|
Name: |
Nicolas Tiarsac |
(Sign) |
/s/ Nicolas Tiarsac |
|
|
|
|
Title: |
Regional Head of Structured Finance |
|
(Authorised Signatory) |
|
|
|
|
Name: |
Christophe Salmon |
(Sign) |
/s/ Christophe Salmon |
|
|
|
|
Title: |
|
|
(Authorised Signatory) |
|
|
|
|
Date: |
22/05/2013 |
|
|
EXECUTED by |
|||
STREAM OIL & GAS LTD (acting through its branch in Albania) acting by: |
|||
|
|
|
|
Name: |
Sotirios Kapotas |
(Sign) |
/s/ Sotirios Kapotas |
|
|
|
|
Title: |
President and CEO |
|
(Authorised Signatory) |
|
|
|
|
Name: |
|
(Sign) |
|
|
|
|
|
Title: |
|
|
(Authorised Signatory) |
|
|
|
|
Date: |
22/05/2013 |
|
|
EXECUTED by |
|||
STREAM OIL & GAS LTD acting by: |
|||
|
|
|
|
Name: |
Sotirios Kapotas |
(Sign) |
/s/ Sotirios Kapotas |
|
|
|
|
Title: |
President and CEO |
|
(Authorised Signatory) |
|
|
|
|
Name: |
|
(Sign) |
|
|
|
|
|
Title: |
|
|
(Authorised Signatory) |
|
|
|
|
Date: |
22/05/2013 |
|
|
15
Exhibit 10.27
PROMISSORY NOTE
$6,800,000.00 |
|
September 12, 2014 |
1. |
Principal and Interest |
For value received, Stream Oil & Gas Ltd., a corporation incorporated under the laws of British Columbia (“SKO”), promises to pay to Viking International Ltd. (the “Holder”) at Dallas, Texas, USA, or at such other place as the Holder may direct in writing, the sum of $6,800,000.00 (the “Principal Amount”), together with interest, before default, at the rate of 18% per annum calculated and compounded monthly, with interest at such rate on any overdue interest and other amounts payable hereunder if not paid when due. Following and after default, maturity, or judgment, the interest rate shall be equal to a rate per annum from day-to-day equal to the maximum nonusurious rate of interest permitted by the applicable laws of Canada on such day that at any time, or from time to time, may be contracted for, taken, reserved, charged, or received, calculated and compounded monthly.
The Principal Amount together with interest thereon shall be payable on the Maturity Date, as defined in that certain Loan Agreement dated as of the date hereof between SKO and the Holder (the “Loan Agreement”).
2. |
Prepayment |
This Note may be prepaid by SKO, in whole or in part, at any time without notice, bonus, or penalty.
3. |
Waiver of Notice |
SKO waives presentment, protest, notice of dishonor, days of grace, and the right of set-off.
4. |
Successors and Assigns |
This Note shall enure to the benefit of the Holder and its successors and assigns, and shall be binding upon SKO and its successors and assigns.
5. |
Incorporation |
This Note is the “Note” referred to in, and evidences indebtedness incurred under, and is subject to the terms and provisions of the Loan Agreement (as amended, restated, supplemented, or otherwise modified from time to time). Reference is made to the Loan Agreement for a statement of the terms and provisions under which this Note may or must be paid prior to its due date or its due date accelerated.
6. |
Assignment |
SKO and the Holder may not assign its rights or obligations under this Note to any other person without the prior written consent of the other party, and any attempted assignment in violation hereof shall be null and void ab initio; however the Holder shall be permitted to assign, without consent of SKO, its rights or obligations under this Note to (i) any affiliate of the Holder or (ii) TransAtlantic Petroleum Limited or any of its affiliates.
7. |
Governing Law and Attornment |
This Note shall be governed by and interpreted in accordance with the laws of the Province of Alberta and the federal laws of Canada applicable therein. Without prejudice to the ability of the Holder to enforce this Note in any other proper jurisdiction, SKO and the Holder hereby irrevocably submit and attorn to the non-exclusive jurisdiction of any Alberta court, in connection with this Note.
8. |
Amendment |
This Note shall be amended pursuant to the terms and conditions of the Loan Agreement.
[Signature Page to Follow]
This Note has been executed and delivered as of the date set forth above.
STREAM OIL & GAS LTD.
By: |
|
/s/ Sotirios Kapotas |
Name: |
|
Sotirios Kapotas |
Title: |
|
President and CEO |
[Signature Page to Note]
Exhibit 21.1
Subsidiaries of TransAtlantic Petroleum Ltd.
March 1, 2015
Subsidiary |
|
Jurisdiction of Incorporation |
Amity Oil International Pty Ltd |
|
Australia |
Incremental Petroleum Pty Ltd |
|
Australia |
TransAtlantic Australia Pty Ltd |
|
Australia |
TransAtlantic Exploration Mediterranean International Pty Ltd |
|
Australia |
TransAtlantic (Holdings) Australia Pty Ltd |
|
Australia |
Anschutz Morocco Corporation |
|
Bahamas |
Direct Petroleum Morocco, Inc. |
|
Bahamas |
DMLP, Ltd. |
|
Bahamas |
Talon Exploration, Ltd. |
|
Bahamas |
TransAtlantic Maroc, Ltd. |
|
Bahamas |
TransAtlantic Turkey, Ltd. |
|
Bahamas |
TransAtlantic Worldwide, Ltd. |
|
Bahamas |
TransAtlantic Holdings, Ltd. |
|
Bahamas |
Stream Oil & Gas Ltd. |
|
British Columbia |
TransAtlantic Holdings B.C. Ltd. |
|
British Columbia |
Longe Energy Limited |
|
Bermuda |
Thrace Basin Natural Gas (Turkiye) Corporation |
|
British Virgin Islands |
Direct Petroleum Bulgaria EOOD |
|
Bulgaria |
TransAtlantic Albania Ltd. |
|
Cayman Islands |
TransAtlantic Petroleum Cyprus Limited |
|
Cyprus |
Viva Exploration Ventures Ltd. |
|
Cyprus |
TransAtlantic Petroleum (USA) Corp. |
|
Delaware |
MOS Viking SARL |
|
Morocco |
TransAtlantic Worldwide Romania SRL |
|
Romania |
Petrogas Petrol Gaz ve Petrokemya Urunleri Insaat Sanayive Ticaret A.S. |
|
Turkey |
TransAtlantic Petroleum Ukraine LLC |
|
Ukraine |
Viva Exploration LLC |
|
Ukraine |
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors
TransAtlantic Petroleum Ltd.:
We consent to the incorporation by reference in the registration statements (Nos. 333‑162814 and 333-200705) on Form S-8 of TransAtlantic Petroleum Ltd. of our reports dated March 16, 2015, with respect to the consolidated balance sheets of TransAtlantic Petroleum Ltd. as of December 31, 2014 and 2013, and the related consolidated statements of comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and all related financial statement schedules, and the effectiveness of internal control over financial reporting as of December 31, 2014, which reports appear in the December 31, 2014 Annual Report on Form 10‑K of TransAtlantic Petroleum Ltd.
Our report dated March 16, 2015, on the effectiveness of internal control over financial reporting as of December 31, 2014, contains an explanatory paragraph that states TransAtlantic Petroleum Ltd acquired Stream Oil & Gas Ltd. during 2014, and management excluded from its assessment of the effectiveness of TransAtlantic Petroleum Ltd’s internal control over financial reporting as of December 31, 2014, Stream Oil & Gas Ltd.’s internal control over financial reporting associated with total assets of $126.6 million and total revenues of $1.9 million included in the consolidated financial statements of TransAtlantic Petroleum Ltd. and subsidiaries as of and for the year ended December 31, 2014. Our audit of internal control over financial reporting of TransAtlantic Petroleum Ltd. also excluded an evaluation of the internal control over financial reporting of Stream Oil and Gas, Ltd.
/s/ KPMG LLP
Dallas, Texas
March 16, 2015
Exhibit 23.2
DeGolyer and MacNaughton
Suite 800 East
Dallas, Texas 75244
March 16, 2015
TransAtlantic Petroleum Ltd.
16803 Dallas Parkway
Addison, Texas 75001
Ladies and Gentlemen:
We hereby consent to references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm under the headings “Glossary of Selected Oil and Natural Gas Terms,” “Part I – Item 1. Business,” “Part I – Item 2. Properties,” “Part I – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Notes to Consolidated Financial Statements – 18. Subsequent Events – Supplemental Oil and Natural Gas Reserves Information” of the Annual Report on Form 10-K for the year ended December 31, 2014, of TransAtlantic Petroleum Ltd. (TransAtlantic) to be filed with the United States Securities and Exchange Commission on or about March 16, 2014 (the Annual Report), including any amendments thereto, and to the inclusion of our third-party letter report dated March 6, 2015, containing our opinion on the proved, probable, and possible reserves attributable to certain properties in Turkey and Bulgaria owned by TransAtlantic as of December 31, 2014.
We hereby further consent to the incorporation by reference of the foregoing in the Registration Statements on Form S-8 (File Numbers 333-162814 and 333‑200705) of TransAtlantic.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Exhibit 23.3
|
Deloitte LLP |
|
700, 850 – 2nd Street SW |
|
Calgary AB T2P 0R8 |
|
Canada |
March 16, 2015
|
Tel: 403-648-3200 |
|
Fax: 586-774-5398 |
|
www.deloitte.ca |
TransAtlantic Petroleum Ltd.
16803 Dallas Parkway
Addison, Texas
Dear Sirs/Mesdames:
RE:Letter of consent
As independent petroleum consultants, we hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-162814 and 333-200705) of TransAtlantic Petroleum Ltd., and in each of the prospectuses, of references to our firm and our report setting forth the estimates of the oil and gas reserves and revenues from the oil and gas reserves of certain properties in Albania owned by TransAtlantic Petroleum Ltd., as of December 31, 2014, and to the inclusion of our report, in the form and context in which it appears, in this Annual Report on Form 10-K for the year ended December 31, 2014 and to all references to our firm included in the Annual Report.
Yours truly,
/s/ Douglas S. Ashton, P. Eng.
Partner
Deloitte LLP
/epm
Exhibit 31.1
CERTIFICATION
I, N. Malone Mitchell 3rd, certify that:
1. I have reviewed this Annual Report on Form 10-K of TransAtlantic Petroleum Ltd.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
March 16, 2015 |
|
/s/ N. Malone Mitchell 3rd |
|
|
N. Malone Mitchell 3rd |
|
|
Chief Executive Officer |
Exhibit 31.2
CERTIFICATION
I, Wil F. Saqueton, certify that:
1. I have reviewed this Annual Report on Form 10-K of TransAtlantic Petroleum Ltd.;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
March 16, 2015 |
|
/s/ Wil F. Saqueton |
|
|
Wil F. Saqueton |
|
|
Chief Financial Officer |
Exhibit 32.1
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of TransAtlantic Petroleum Ltd. (the “Company”) for the year ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, N. Malone Mitchell 3rd, Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.
Dated: |
March 16, 2015 |
|
/s/ N. Malone Mitchell 3rd |
|
|
|
N. Malone Mitchell 3rd |
|
|
|
Chief Executive Officer |
A signed original of this written statement required by Section 906 has been provided to TransAtlantic Petroleum Ltd. and will be retained by TransAtlantic Petroleum Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
Exhibit 32.2
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report on Form 10-K of TransAtlantic Petroleum Ltd. (the “Company”) for the year ended December 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Wil F. Saqueton, Chief Financial Officer of the Company, hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.
Dated: |
March 16, 2015 |
|
/s/ Wil F. Saqueton |
|
|
|
Wil F. Saqueton |
|
|
|
Chief Financial Officer |
A signed original of this written statement required by Section 906 has been provided to TransAtlantic Petroleum Ltd. and will be retained by TransAtlantic Petroleum Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
Exhibit 99.1
DeGolyer and MacNaughton
Suite 800 East
Dallas, Texas 75244
March 6, 2015
TransAtlantic Petroleum Ltd.
16803 Dallas Parkway, Suite 200
Addison, Texas 75001
Gentlemen:
Pursuant to your request, we have conducted an independent evaluation, completed on March 6, 2015, to serve as a reserves audit of the extent and value of the proved, probable, and possible oil, natural gas, and condensate reserves, as of December 31, 2014, of certain properties owned by TransAtlantic Petroleum Ltd. (TransAtlantic) in Turkey and Bulgaria. TransAtlantic has represented that these properties account for 58.1 percent, on a net equivalent barrel basis, of TransAtlantic’s net proved, probable, and possible reserves, as of December 31, 2014. The net proved, probable, and possible reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S-K and is to be used for inclusion in certain SEC filings by TransAtlantic.
Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2014. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by TransAtlantic after deducting interests owned by others. Only net reserves are reported herein.
Gas reserves estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas produced from the reservoir after reduction for shrinkage resulting from field separation, processing, fuel use, and flare available to be delivered into a gas pipeline for sale. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.70 pounds per square inch absolute (psia). Oil and condensate reserves estimated herein are those to be recovered by conventional lease separation.
Values of proved, probable, and possible reserves shown herein are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves adjusted for net profits (where applicable). Future net revenue is defined as the future gross revenue less direct operating expenses, capital costs, abandonment costs, and net profits, where applicable. Direct operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.
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DeGolyer and MacNaughton
Estimates of oil, natural gas, and condensate reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
Data used in this audit were obtained from reviews with TransAtlantic personnel, from TransAtlantic files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by TransAtlantic with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors. In such case, an analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.
In certain cases, reserves were estimated using elements established by analogy with similar wells or reservoirs for which more complete data were available.
The fields have been grouped into three asset groups based on economic considerations: the Thrace Basin Natural Gas Company (TBNGC) asset group, the core TransAtlantic properties (TAT) asset group, and the Edirne asset group (consisting of Edirne field). All fields are subject to a royalty of 12.5 percent. The TBNGC asset group is subject to an additional 1.0-percent overriding royalty interest, except for the Alibey field which has a 0.5-percent overriding royalty interest. Certain wells in TAT and Edirne
3
DeGolyer and MacNaughton
asset groups are also subject to a net profits interest of 5 percent. Net reserves quantities reported herein reflect the appropriate quantity reductions for royalty interests and overriding royalty interests, as well as the quantity reduction yielded from the calculated revenue associated with the net profits payable.
Definition of Reserves
Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering
4
DeGolyer and MacNaughton
analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.
Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
5
DeGolyer and MacNaughton
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (iii) of the proved oil and gas reserves definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been
6
DeGolyer and MacNaughton
proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
The extent to which probable and possible reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable and possible reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable with proved reserves.
Primary Economic Assumptions
The following economic assumptions were used for estimating existing and future prices and costs:
Oil, Condensate, and Natural Gas Prices
Prices used in this evaluation were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. An average reference oil price during this period was Brent at 102.70 United States dollars (U.S.$) per barrel. The oil and condensate prices used to estimate reserves herein were as follows: U.S.$50.97 per barrel in Bulgaria, U.S.$92.70 per barrel in AG field, U.S.$98.20 per barrel in Alibey field, U.S.$94.87 per barrel in Arpatepe field, U.S.$86.69 per barrel in Goksu field, U.S.$74.20 per barrel in Kazanci field, U.S.$94.89 per barrel in the Bahar and Molla fields, and U.S.$95.20 per barrel in the Selmo field. The overall volume‑weighted average oil price in this report was U.S.$94.53. An average reference gas price during this period was the United Kingdom National Balancing Point Index of U.S.$8.35 per million British thermal units. The gas prices used in this report were as follows: U.S.$9.10 per thousand cubic feet (Mcf) for TBNGC asset group, U.S.$8.10 per Mcf for the Edirne asset group, U.S.$4.25 per Mcf for Bulgaria, U.S.$7.62 per Mcf for the Bakuk field, and U.S.$8.10 per Mcf for the remaining fields in TAT asset group. The overall volume-weighted average gas price in this report was U.S.$8.71 per Mcf. These prices were held constant for the lives of the properties.
Net Profits Interest
As represented by TransAtlantic, there is a 5-percent net profits interest burden for certain wells in the AG, Alpullu, CAB, DAK, Edirne, Karapurcek, and REDY fields. Where applicable, the net profits reduced TransAtlantic’s ownership of reserves and revenue values.
Operating Expenses and Capital Costs
Estimates of operating expenses based on current expenses were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions. Future capital expenditures were estimated using current values and were not adjusted for inflation.
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DeGolyer and MacNaughton
Abandonment Costs
Abandonment costs were provided by TransAtlantic. These costs were estimated using current values and were not adjusted for inflation. Abandonment costs herein include well abandonment only. Also, TransAtlantic has represented that it will relinquish operation of the Selmo field to the Turkish Government at the end of June 2025, and therefore will not be responsible for abandonment costs pertaining to wells in the Selmo field that produce beyond June 2025.
Royalty and Taxes
All fields are subject to a royalty of 12.5 percent. Fields in the TBNGC asset group are subject to an additional 1.0-percent overriding royalty interest, except for the Alibey field, which has an 0.5-percent overriding royalty interest. Certain wells in the Edirne field are subject to a third-party carried net revenue interest of 2.625 percent. TransAtlantic has represented that there are no production taxes to be paid in Turkey or Bulgaria. No other taxes, including income taxes for Turkey, Bulgaria, or the United States, were considered in this evaluation.
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2014, oil, condensate, and gas reserves estimated herein.
Summary of Oil and Gas Reserves and Revenue
The estimates of net proved, probable, and possible reserves, as of December 31, 2014, attributable to the interests owned by TransAtlantic in Turkey and Bulgaria, of the properties evaluated herein, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):
|
|
Estimated by DeGolyer and MacNaughton Net Reserves as of December 31, 2014 |
|||||
|
|
Oil (bbl) |
|
Condensate (bbl) |
|
Sales Gas (Mcf) |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
Developed |
|
6,857,363 |
|
0 |
|
9,550,865 |
|
Undeveloped |
|
7,548,724 |
|
0 |
|
6,702,616 |
|
|
|
|
|
|
|
|
|
Total Proved |
|
14,406,087 |
|
0 |
|
16,253,481 |
|
|
|
|
|
|
|
|
|
Probable |
|
|
|
|
|
|
|
Developed |
|
1,400,078 |
|
0 |
|
3,034,009 |
|
Undeveloped |
|
10,031,579 |
|
0 |
|
20,759,520 |
|
|
|
|
|
|
|
|
|
Total Probable |
|
11,431,657 |
|
0 |
|
23,793,529 |
|
|
|
|
|
|
|
|
|
Possible |
|
|
|
|
|
|
|
Developed |
|
1,456,587 |
|
0 |
|
3,073,332 |
|
Undeveloped |
|
10,571,420 |
|
0 |
|
73,666,119 |
|
|
|
|
|
|
|
|
|
Total Possible |
|
12,028,007 |
|
0 |
|
76,739,451 |
|
|
|
|
|
|
|
|
|
Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves. |
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DeGolyer and MacNaughton
The estimated revenue and expenditures attributable to TransAtlantic’s interests in Turkey and Bulgaria in the proved, probable, and possible net reserves, as of December 31, 2014, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows, expressed in United States dollars (U.S.$):
|
|
Estimated by DeGolyer and MacNaughton as of December 31, 2014 |
||||||||
|
|
Proved |
|
|
|
|
||||
|
|
Developed (U.S.$) |
|
Undeveloped (U.S.$) |
|
Total (U.S.$) |
|
Probable (U.S.$) |
|
Possible (U.S.$) |
|
|
|
|
|
|
|
|
|
|
|
Future Gross Revenue |
|
733,285,294 |
|
771,083,916 |
|
1,504,369,210 |
|
1,283,000,278 |
|
1,759,157,222 |
Production Taxes |
|
0 |
|
0 |
|
0 |
|
0 |
|
0 |
Operating Expenses |
|
165,528,104 |
|
139,853,057 |
|
305,381,161 |
|
145,089,251 |
|
188,509,510 |
Capital Costs |
|
3,869,689 |
|
230,805,583 |
|
234,675,272 |
|
200,494,978 |
|
181,979,150 |
Abandonment Costs |
|
2,777,290 |
|
431,964 |
|
3,209,254 |
|
621,538 |
|
762,176 |
Net Profits |
|
237,706 |
|
(700,234) |
|
(937,940) |
|
(879,914) |
|
(20,599,531) |
Future Net Revenue |
|
560,872,505 |
|
399,293,078 |
|
960,165,583 |
|
935,914,597 |
|
1,367,306,855 |
Present Worth at 10 Percent |
|
418,513,961 |
|
230,019,491 |
|
648,533,452 |
|
518,031,340 |
|
663,182,647 |
|
|
|
|
|
|
|
|
|
|
|
Notes: 1. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves. 2. Future income tax expenses were not taken into account in the preparation of these estimates. |
In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved, probable, and possible reserves, and present worth of estimated future net revenue from proved, probable, and possible reserves of oil, condensate, and sales gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932‑235‑50-6, 932‑235‑50-7, 932‑235‑50‑9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
9
DeGolyer and MacNaughton
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in TransAtlantic. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of TransAtlantic. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
|
|
/s/ Lloyd W. Cade, P.E. |
|
|
Lloyd W. Cade, P.E. |
[SEAL] |
|
Senior Vice President |
|
|
DeGolyer and MacNaughton |
DeGolyer and MacNaughton
I, Lloyd W. Cade, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1. |
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to TransAtlantic dated March 6, 2015, and that I, as Senior Vice President, was responsible for the preparation of this report. |
2. |
That I attended Kansas State University, and that I graduated with a Bachelor of Science degree in Mechanical Engineering in the year 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers; and that I have in excess of 32 years of experience in oil and gas reservoir studies and evaluations. |
3. |
That DeGolyer and MacNaughton or its officers have no direct or indirect interest, nor do they expect to receive any direct or indirect interest in any properties or securities of TransAtlantic Petroleum Ltd. or affiliate thereof. |
SIGNED: March 6, 2015
|
|
/s/ Lloyd W. Cade, P.E. |
|
|
Lloyd W. Cade, P.E. |
[SEAL] |
|
Senior Vice President |
|
|
DeGolyer and MacNaughton |
Exhibit 99.2
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700, 850 – 2 Street SW |
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Calgary AB T2P 0R8 |
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Canada |
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|
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Tel: 403-267-1700 |
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Fax: 587-774-5398 |
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www.deloitte.ca |
February 27, 2015
TransAtlantic Petroleum Ltd.
16803 Dallas Parkway
Addison, Texas
USA 75001
Attention: Mr. James Hubing
RE:TransAtlantic Petroleum Ltd.
Reserve estimation and economic evaluation
At your request and authorization, Deloitte LLP (“Deloitte”) has prepared an independent evaluation of certain oil and gas assets of TransAtlantic Petroleum Ltd. (“TransAtlantic”) in Albania, effective December 31, 2014, completed on February 27, 2015. TransAtlantic has represented that these properties account for 41.9 percent, on a net equivalent barrel basis, of TransAtlantic’s net proved, probable and possible reserves, as of December 31, 2014.
This report has been prepared for the use of TransAtlantic in certain filings with the U.S. Securities and Exchange Commission (“SEC”), and Deloitte hereby gives its consent to the use of its name and to the said estimates in such SEC filing. The evaluation was conducted in the months of December 2014, January and February 2015; field information obtained subsequent to the effective date was not used in the evaluation.
Pursuant to the requirements of Item 1202 (a) (8) of Regulation S-K, this report documents the results of the evaluation with the following table summarizing 100 percent of the reserves of TransAtlantic in Albania and their value:
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Summary of Net Reserves as of December 31, 2014 |
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|||||||||
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|
Oil (Mbbl) |
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Condensate (Mbbl) |
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|
Gas (MMcf) |
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|||
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
13,900.4 |
|
|
|
— |
|
|
|
— |
|
Undeveloped |
|
|
— |
|
|
|
359.1 |
|
|
|
8,249.2 |
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Total Proved |
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13,900.4 |
|
|
|
359.1 |
|
|
|
8,249.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Probable |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
9,039.0 |
|
|
|
— |
|
|
|
3,779.0 |
|
Undeveloped |
|
|
— |
|
|
|
974.9 |
|
|
|
16,183.9 |
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Total Probable |
|
|
9,039.0 |
|
|
|
974.9 |
|
|
|
19,962.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Possible |
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
4,879.2 |
|
|
|
— |
|
|
|
1,020.9 |
|
Undeveloped |
|
|
— |
|
|
|
2,272.1 |
|
|
|
30,496.5 |
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Total Possible |
|
|
4,879.2 |
|
|
|
2,272.1 |
|
|
|
31,517.5 |
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TransAtlantic Petroleum Ltd.
Reserve estimation and economic evaluation
Page 2
The oil and gas reserves calculations and income projections, in this report have been prepared in accordance with the SEC’s Regulation S-X Part 210.4-10(a). Deloitte used all methods and procedures it considered necessary under the circumstances to prepare the report. The Evaluation procedure section included in this report details the reserves definitions, price and market demand forecasts and general procedure used by Deloitte in its determination of this evaluation and are appropriate for the purposes served by the report. In accordance with SEC requirements all prices and costs (capital and operating) were held constant. Prices used in this evaluation were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month during January to December 31, 2014. The extent and character of ownership and all factual data supplied by TransAtlantic were accepted as presented. A field inspection and environmental/safety assessment of the properties was not made by Deloitte and the consultant makes no representations and accepts no responsibilities in this regards.
This report contains forward looking statements including expectations of future production and capital expenditures. Possible changes to the current government regulations may cause volumes of proved and proved plus probable reserves actually recovered and amounts of proved and proved plus probable income actually received to differ significantly from the estimated quantities. Information concerning reserves may also be deemed to be forward looking as estimates imply that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause the actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e. operational risks in development, exploration and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; the uncertainty of estimates and projections relating to production, costs and expenses, political and environmental factors), and commodity price and exchange rate fluctuation. Present values for various discount rates documented in this report may not necessarily represent fair market value of the reserves.
A Boe conversion ratio of six (6) Mcf: one (1) barrel has been used within this report. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Yours truly,
Original signed by: “Douglas S. Ashton”
Douglas S. Ashton, P. Eng.
Partner
Deloitte LLP
/ct
Independent petroleum consultants consent
The undersigned firm of Independent Qualified Reserves Evaluators and Auditors of Calgary, Alberta, Canada has prepared an independent audit of reserves and future net revenues derived therefrom, of the Petroleum and Natural Gas assets of the interests of TransAtlantic Petroleum Ltd. These reserves and future net revenues were estimated using prior 12 month average constant prices and costs (before and after income taxes) according to the requirements of SEC’s Regulation S-X, Part 210.4-10 (a). The effective date of this evaluation is December 31, 2014.
In the course of the evaluation, TransAtlantic Petroleum Ltd. provided Deloitte personnel with basic information which included land, well and accounting (product prices and operating costs) information; reservoir and geological studies, estimates of on-stream dates for certain properties, contract information, budget forecasts and financial data. Other engineering, geological or economic data required to conduct the evaluation and upon which this report is based, were obtained from public records, other operators and from Deloitte non confidential files. The extent and character of ownership and accuracy of all factual data supplied for the independent evaluation, from all sources, has been accepted.
A field inspection and environmental/safety assessment of the properties was beyond the scope of the engagement of Deloitte and none was carried out. TransAtlantic Petroleum Ltd. provided assurance that no additional information necessary for the completion of our assignment would have been obtained by a field inspection.
The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward.
Revenue projections presented in this report are subject to uncertainties and may in future differ materially from the forecasts herein. Present values of future net revenues documented in this report do not necessarily represent the fair market value of the reserves evaluated herein.
PERMIT TO PRACTICE |
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Deloitte & Touche LLP |
Permit Number: P-11444 |
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The Association of Professional Engineers and Geoscientists of Alberta |
Certificate of qualification
I, D. S. Ashton, a Professional Engineer, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:
1. |
I am a partner of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests of TransAtlantic Petroleum Ltd. The effective date of this evaluation is December 31, 2014. |
2. |
I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of TransAtlantic Petroleum Ltd. |
3. |
I attended the University of Calgary and graduated with a Bachelor of Science Degree in Chemical Engineering in 1992; that I am a Registered Professional Engineer in the Province of Alberta; and I have in excess of twenty one years of engineering experience. |
4. |
I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2. |
5. |
A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities. |
Original signed by: “D. S. Ashton” |
D. S. Ashton, P. Eng. |
|
February 26, 2015 |
Date |
Certificate of qualification
I, D. L. Horbachewski, a Professional Geologist, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:
1. |
I am an employee of Deloitte LLP, which did prepare an evaluation of certain oil and gas assets of the interests of TransAtlantic Petroleum Ltd. The effective date of this evaluation is December 31, 2014. |
2. |
I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of TransAtlantic Petroleum Ltd. |
3. |
I attended the University of Calgary and graduated with a Bachelor of Science Degree in Geology in 1999; that I am a Registered Professional Geologist in the Province of Alberta; and I have in excess of fifteen years of evaluations experience. |
4. |
I am a Qualified Reserves Auditor as defined in the Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 3.2. |
5. |
A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities. |
Original signed by: “D. L. Horbachewski” |
D. L. Horbachewski, P. Geol. |
|
February 26, 2015 |
Date |
Certificate of qualification
I, L. J. Machula, a Professional Geologist, of 700, 850 – 2nd Street S.W., Calgary, Alberta, Canada hereby certify that:
1. |
I am an employee of Deloitte LLP, which did prepare a detailed analysis of certain oil and gas assets of the interests of TransAtlantic Petroleum Ltd. The effective date of this evaluation is December 31, 2014. |
2. |
I do not have, nor do I expect to receive any direct or indirect interest in the properties evaluated in this report or in the securities of TransAtlantic Petroleum Ltd. |
3. |
I attended the University of Calgary and graduated with a Bachelor of Science in Geology in 2002; that I am a Registered Professional Geologist in the Province of Alberta; and I have in excess of ten years of experience in geological exploration and evaluations of Western Canadian and International oil and gas fields. |
4. |
A personal field inspection of the properties was not made; however, such an inspection was not considered necessary in view of information available from the files of the interest owners of the properties and the appropriate provincial regulatory authorities. |
Original signed by: "L.J. Machula" |
L. J. Machula, P. Geol. |
|
February 26, 2015 |
Date |
PRIVATE
Evaluation procedure
Definitions and methodology
Effective as of December 2014
© Deloitte LLP and affiliates
Table of contents
Definitions
· |
Procedure |
· |
Reserve evaluation |
· |
Reserve classification |
Reserve estimation methodology
Production forecasts
Land schedules and maps
Geology
Royalties and taxes
Capital and operating considerations
Pricing overview
© Deloitte LLP and affiliates
Procedure
Deloitte has prepared estimates of reserves in accordance with the SEC Regulation S-K, 229.1202 and Regulation S-X, 210.4-10.
Reserve evaluation
A “Reserves evaluation” is the process whereby a qualified reserves evaluator estimates the quantities and values of oil and gas reserves by interpreting and assessing all available pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to generate future net revenue, and it is measured using a set of forward-looking assumptions regarding reserves, production, prices, and costs. Evaluations of oil and gas reserves, include a discounted cash flow analysis of estimated future net revenue.
Reserve classification
Reserves are classified by Deloitte in accordance with the definitions that are described in the United States Securities and Exchange Commission Regulation S-X Part 210.4-10(a).
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible -from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) |
The area of the reservoir considered as proved includes: |
(A) |
The area identified by drilling and limited by fluid contacts, if any, and |
(B) |
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) |
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
(iii) |
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
(iv) |
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) |
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
(B) |
The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) |
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
© Deloitte LLP and affiliates
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) |
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. |
(ii) |
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. |
(iii) |
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. |
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) |
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10 percent probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. |
(ii) |
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. |
(iii) |
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. |
(iv) |
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. |
(v) |
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir. |
(vi) |
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations. |
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) |
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and |
(ii) |
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
© Deloitte LLP and affiliates
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) |
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. |
(ii) |
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. |
(iii) |
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. |
© Deloitte LLP and affiliates
Reserve estimation methodology
Deloitte generally assigns reserves to properties via deterministic methods. Probabilistic estimation techniques are typically used where there is a low degree of certainty in the information available when utilized will be stated within the detailed property reports. Both techniques comply as defined in Regulation S-X, 210.4-10(a).
Production forecasts
Production forecasts are based on historical trends or by comparison with other wells in the immediate area producing from analogous reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come on-stream in years three or four from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information.
For reserve volumes that meet all reserve category rules but are behind casing and waiting on depletion of the producing zone, these volumes are forecast to be brought on-stream following the end of the existing production.
© Deloitte LLP and affiliates
Land schedule and maps
The Company provided schedules of land ownership which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by Deloitte was made to verify the records.
Well maps included within this report represent all of the Company’s interests that were evaluated in the specified area.
Geology
An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis.
For properties that are not of a mature production nature a geologic review is conducted. This work consists of:
· |
developing a regional understanding of the play, |
· |
assessing reservoir parameters from the nearest analogous production, |
· |
analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation, |
· |
auditing of client mapping or developing maps to meet Deloitte’s need to establish volumetric hydrocarbons-in-place. |
Procedures specific to the individual properties are discussed in the body of the property report.
© Deloitte LLP and affiliates
Royalties and taxes
All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases or farmout agreements, that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially.
Deloitte utilizes a variety of reserves and valuation products in determining the result sets.
Capital and operating considerations
Reserves estimated to meet the standards for constant prices and costs, are based on Regulation S-X 210.4-10(a).
Capital costs were provided by the Company and reviewed by Deloitte for reasonableness.
Operating costs were determined from historical data on the property as provided by the evaluated Company.
© Deloitte LLP and affiliates
Pricing overview
The Company provided Deloitte with hydrocarbon prices (oil, gas condensate, and natural gas liquids) appropriate for use in the preparation of a reserves report to be filed with the SEC as at the effective date. Prices were calculated in accordance with the definition (22)(v) of Regulation S-X, 210.4-10(a) and were determined by taking the un-weighted average of the prices on the first day of the month for the preceding 12 months.
The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in Deloitte’s individual property evaluations.
|
Benchmark |
Benchmark price ($US) |
Weighted average realized report price ($US) |
Oil |
Brent |
$101.38/bbl |
$69.55/bbl |
Gas |
UK NBP |
$9.50/MMbtu |
$10.00/Mcf |
NGL |
Condensate |
$101.38/bbl |
$101.38/bbl |
© Deloitte LLP and affiliates
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