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TMY > SEC Filings for TMY > Form 10-K on 16-Mar-2006 All Recent SEC Filings
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Form 10-K for TRANSMERIDIAN EXPLORATION INC
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16-Mar-2006
Annual Report
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis addresses changes in our financial position and results of operations during the three year period 2003 through 2005. There is limited or no comparability for revenue and operating expense in 2003, as sales and production did not commence until the third quarter of 2003.
Management's primary goals for 2005 were to:
• Continue development drilling in the Field;
• Increase production from all wells in the Field;
• Improve efficiency of drilling and completion programs;
• Improve prices received for oil sales;
• Negotiate a long-term production contract; and
• Secure additional financing for Caspi Neft.
We believe that these goals were largely achieved in 2005. Our primary goals for 2006 include optimizing completions of the existing wells in the Field to maximize production from those wells, accelerating development
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of the Field by increasing the number of drilling rigs under operation from one to at least four, continuing to improve the price received for our oil sales, completing production and treatment facilities and connecting to the regional pipeline system.
Current Activities
Through December 31, 2005, we had drilled a total of eight wells in our South Alibek evaluation and development program. The SA-14 and the SA-3 were completed and placed into production in May and October 2005, respectively. Drilling of the eighth well in the program, the SA-15, began in late September 2005 and reached target depth in December 2005. The well was perforated in January 2006 and allowed to begin flowing naturally without stimulation. These three wells are infill development wells. With the exception of SA-4, all the wells in the Field have been producing oil on an extended production testing program. The ninth and tenth wells in the Field, the SA-11 and SA-12, were spudded on January 30 and February 1, 2006 respectively.
Our field operations and scheduled workovers were adversely affected by abnormally extreme subzero temperatures during late December and early 2006 that affected the region's transportation, infrastructure and contractor services. The interruptions caused by these circumstances significantly affected timing of planned work and our ability to meet year-end production goals, with two of the seven producing wells temporarily shut-in. Once scheduled work is completed and these wells are placed back on production, we expect production from the existing wells producing simultaneously to be approximately 2,500-3,000 bopd.
Production from the wells is currently run through temporary production facilities, with oil storage capacity at the site of this facility as well as at the site of the central production facility. Production is currently being constrained by equipment and flowline limitations pending completion of the central facility, which has been delayed by the inability of the previous general contractor to complete the required installation. That contractor has been dismissed, and we engaged a leading international contractor in February 2006 to inspect and submit a plan to complete the facilities. We expect to have a revised plan and definitive construction schedule during the first quarter of 2006, resume construction work in the second quarter and commission the facility by the fourth quarter. We are implementing an interim solution to improve production capacity until the central facility is completed. The design and permitting work on our pipeline connection to the Alibekmola-Kenkiyak pipeline, and the associated support facilities began in 2005, and commissioning is also planned before the fourth quarter of 2006. See "Item 2.
Properties-Transportation and Marketing" for an overview of pipeline connections and activity in the South Alibek area.
During 2005, workover programs initiated in 2004 were completed and new programs for selected wells were initiated to prepare the wells for long-term commercial production. These programs included reservoir stimulation, installation of more efficient production tubing and packers and the testing of down-hole electric submersible pumps with the aim to increase production. To address numerous delays and inefficiences encountered in our execution of the workover program, a dedicated workover rig has been sourced for the Field that will replace the locally provided workover units used previously. This new unit is expected to significantly reduce the time required to conduct our workovers and reduce the shut-in time experienced while work is in progress. We expect the unit to begin working in the second quarter of 2006, when Field activity levels increase as a result of the accelerated drilling program.
Our drilling program is currently using two drilling rigs contracted from Great Wall Drilling Company, the second of which arrived in the Field in December 2005. We plan to accelerate the program by adding at least two additional drilling rigs during the first half of 2006, bringing the total rigs in operation in the Field to four. In addition, the Company is evaluating opportunities to further speed development by adding a fifth and possibly a sixth drilling rig later in the year.
We have significantly reduced the time required to drill to our programmed final depths through improvement in drilling practices, bit selection and drilling fluids control. SA-15 reached its total depth of 12,600
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feet in 87 days and was the first of our wells that met the benchmark of 92 days established from competitor drilling data. We expect to continue to improve on the timing for drilling and completion of wells as increased equipment and new highly skilled personnel will allow for more continuity in operations.
Results of Operations
Oil Production and Revenue
For the year ended December 31, 2005, we produced 400,425 barrels ("Bbls") of crude oil, or an average of 1,097 Bbls per day (Bopd), as compared to 313,305 Bbls, or an average of 858 Bopd, for the year ended December 31, 2004 and 117,376 Bbls, or an average of 641 Bopd for the year ended December 31, 2003. The increase in 2005 when compared to 2004, and the increase in 2004 from 2003, are primarily a result of the Field having five wells contributing to production in 2005 as compared to three wells in 2004 and only one well in 2003, and the Field being on production throughout 2004 versus only six months in 2003, as production from the Field commenced in July of 2003.
For the year ended December 31, 2005, we sold (by physical delivery to the purchaser) 324,355 Bbls of crude oil at an average price of $27.62 per Bbl, for net revenues of $8,442,787, as compared to 336,440 Bbls of crude oil at an average price of $11.87 per Bbl, for net revenues of $3,922,990, for the year ended December 31, 2004 and 77,293 Bbls at an average price of $10.52, for net revenue of $797,411 for the year ended December 31, 2003. The increase in net revenue in 2005 as compared to 2004 was primarily a result of substantially higher sales prices we received for our oil. Through a series of new sales arrangements, we realized increases over 2004 in the net price received for our crude oil to an average of approximately $20.00 per Bbl for the first half of 2005 and an average of approximately $37.00 per Bbl for the second half of 2005. The last price we received in December 2005 was $42.45 per Bbl. The increase in net revenue in 2004 as compared to 2003 is primarily due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field producing for all of 2004 versus only six months of 2003. Sales from the Field commenced in the third quarter of 2003.
We recognize revenue from the sale of oil when the purchaser takes delivery of the oil. As of December 31, 2005, we had 87,296 Bbls of oil in inventory that had not yet been sold, pending commencement of oil sales arrangements with new purchasers. As of December 31, 2004, we had 16,576 Bbls in inventory for which we had received payment but had not recognized revenue because delivery had not yet been taken by the purchaser. The average sales price for this oil was $11.61 per Bbl, which was recognized as revenue in 2005 upon delivery to the purchaser.
Our crude oil sales since June 2005 have primarily take place at a nearby rail terminal. We incurred transportation and storage costs of approximately $1.54 per Bbl to transport our oil by truck to the rail terminal, where it is stored in rented tanks until delivery to the purchasers. Our crude oil sales in the last eight months of 2004 and the first six months of 2005 occurred at the Field and were not subject to transportation costs. See Item 7, "Results of Operation-Transportation Expense".
Exploration Expense
Exploration expense, which includes geological and geophysical expense and the cost of unsuccessful exploratory wells, is recorded as an expense in the period incurred under the successful efforts method of accounting. During the year ended December 31, 2005, we incurred $9,470 in exploration expense, primarily associated with geological interpretations of the Field. During 2004, we recognized exploration expense of $130,926, which included costs associated with geological interpretations of the Field and a write off of the remaining book value of non-producing lease cost of a property in South Texas. During 2003, we incurred $592,553 in exploration expense, which was primarily related to the purchase and interpretation costs of geologic data and a charge for the unsuccessful completion attempt on one of our two U. S. properties.
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Depreciation, Depletion and Amortization
Depreciation, depletion and amortization ("DD&A") of oil and gas properties is calculated under units of production method, following the successful efforts method of accounting. For the year ended December 31, 2005, DD&A of oil and gas properties was $2,442,263, or $6.10 per Bbl, as compared to $709,496, or $2.11 per Bbl for the year ended December 31, 2004 and $189,635, or $2.45 per Bbl, for the year ended December 31, 2003. The increase in 2005 from 2004 is primarily a result of the change in classification of reserves attributable to the KT1 reservoir to "proved undeveloped" from "proved developed behind pipe," due to a change in the assumed Field development plan. The new plan assumes that separate wells will be drilled to produce reserves in the KT1 reservoir, rather than "dual-completing" wells to produce from both the KT2 and KT1 reservoirs simultaneously. As a result, beginning in the fourth quarter of 2005, reserves in the KT1 reservoir, which account for approximately 40% of our total "proved" reserves as of December 31, 2005, have been excluded from the total reserve base currently being depleted. Costs incurred are now spread over a substantially smaller quantity of oil until such time as wells are drilled to produce from the KT1 reservoir and those reserves are classified as "proved developed." In addition, we had an average of four producing wells during 2005 versus only 1.5 producing wells in 2004. The increase in DD&A of oil and gas properties in 2004 from 2003 is primarily due to the increase in oil production between the periods.
Non-oil and gas property DD&A for 2005, 2004 and 2003 was $942,630, $79,262 and $56,077, respectively. The increase between the years is primarily due to additions of transportation and other equipment, and commencement of depreciation on our drilling rig, which we no longer plan to use for development of the Field.
Transportation Expense
During the third quarter of 2005, we began incurring transportation and storage costs relating to the transport of our oil to a nearby rail terminal for sale and export. During the second half of 2005, we incurred transportation and storage costs of $321,313, or $1.54 per Bbl. From the second quarter of 2004 through the second quarter of 2005, oil sales were made directly from the Field, with no transportation costs incurred. For the year ended December 31, 2004, transportation and storage costs were $173,847, or $2.12 per Bbl produced. For the year ended December 31, 2003, we incurred transportation and storage costs of $235,264 or $2.00 per Bbl produced. When the treating facilities and pipeline pump station discussed in Item 2, "Properties-Transportation and Marketing," are operational, expected in late 2006, we plan to deliver crude oil production directly into the regional pipeline system, which should result in a significant improvement in sales pricing for our crude oil.
Impairment Loss
In the first quarter of 2006, we reached an agreement to dispose of our drilling rig. An impairment charge writing the value of the rig down to the estimated proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded as of December 31, 2005.
Operating and Administrative Expense-Kazakhstan
For the year ended December 31, 2005, operating and administrative expense in Kazakhstan was $3.9 million, as compared to $3.6 million for the year ended December 31, 2004 and $2.5 million for the year ended December 31, 2003. The increases between years are primarily a result of increased personnel costs due to increased activity in our exploration, development and production program for the Field.
General and Administrative Expense-Houston
For the year ended December 31, 2005, general and administrative expense in Houston was $6.6 million, as compared to $2.6 million for the year ended December 31, 2004 and $2.1 million for the year ended
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December 31, 2003. The increase in 2005 from 2004 is primarily due to costs incurred for listing on the American Stock Exchange, Sarbanes-Oxley Act compliance and addition of new corporate staff, as well as the cost of stock-based compensation related to employee stock options and restricted stock grants recognized during the year. The increase in 2004 from 2003 is primarily due to increased legal costs associated with two lawsuits ongoing during the year.
Interest Expense
Interest expense, net of the capitalized portion, for the years ended December 31, 2005, 2004 and 2003 was $10.3 million, $1.4 million and $.7 million, respectively. The increase in interest expense between years is primarily due to increased debt levels between the periods, as well as the commencement of expensing interest, as opposed to capitalizing interest, on those assets which have been placed in service and are being used for their intended purpose. In addition, $4.4 million of debt discount amortization related to short-term borrowing was recognized in 2005.
Liquidity and Capital Resources
For the years ended December 31, 2005, 2004 and 2003, our on-going capital expenditures were $20.7 million, $26.1 million and $31.2 million, respectively. Our primary sources of funding have been private placements of common and preferred stock, borrowings under our credit facilities with a Kazakhstan bank and our private placement of senior secured notes due 2010 and warrants to purchase shares of common stock (as described in more detail below and in notes 5 and 6 to the notes to consolidated financial statements). The total capitalized cost attributable to the South Alibek Field as of December 31, 2005 was $230.1 million, which includes $12.5 million of capitalized interest.
In February 2002, Caspi Neft entered into a credit facility with a Kazakhstan bank that provided for borrowings totaling $20.0 million with an interest rate of 15% and a fee of 0.5% per annum on the unutilized portion of the commitment. The original maturity date was February 2005; however, the terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or
(ii) December 23, 2005.
In June 2003, Caspi Neft entered into a new $30.0 million credit facility with the same Kazakhstan bank. This facility provided for borrowings up to $30.0 million with an interest rate of 15% and a commitment fee of 0.5% per annum on the unutilized portion. Upon execution of the credit facility, Caspi Neft paid the bank an arrangement fee of $300,000, which was capitalized as a deferred financing cost and was being amortized over the five-year life of the facility. Originally, the amount outstanding as of May 31, 2005 was scheduled to be repaid over 36 equal monthly installments beginning June 2005 through the final maturity date of May 31, 2008; however, those terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or (ii) December 23, 2005.
Both credit facilities were repaid in full in December 2005 in connection with our acquisition of Bramex and our December 2005 private placement of senior secured notes and warrants discussed below.
In November 2004, we sold 1,785.714 shares of our Series A Preferred in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of our common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25.0 million. Proceeds from the private placement of Series A Preferred and warrants were used for general corporate purposes, including funding our development drilling program in the South Alibek Field in Kazakhstan, and to pursue growth opportunities.
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The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders' option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred are entitled to a quarterly dividend payable at the rate of 4.5% per annum, payable in cash. The holders of the Series A Preferred have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of our common stock, and vote together with the holders of common stock as one class. A holder of the Series A Preferred may not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the warrants into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of our common stock owned by such holder at such time, 4.999% of our then issued and outstanding shares of common stock. So long as at least 20% of the Series A Preferred remains outstanding, we may not issue any new securities or financial instruments that rank pari passu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning in July 2006, the Series A Preferred will automatically convert into our common stock at the conversion price of $1.40 per share (subject to adjustments), if our common stock trades at a price greater than $4.15 per share for twenty consecutive trading days and the average daily trading volume of our common stock during such period exceeds 200,000 shares, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation, the excess portion of the Series A Preferred remains outstanding, but ceases to accrue a dividend. During 2005, 238 shares of Series A Preferred were converted into 2,380,000 shares of our common stock.
In May 2005, we borrowed an aggregate of $2,240,000 from a group of individuals pursuant to unsecured, short-term notes. The notes bore interest at 15% per annum and were repaid along with accrued interest in July and September 2005. In July 2005, we borrowed $1,000,000 from an individual pursuant to an unsecured short-term note, which bore interest at 15% per annum and was repaid with accrued interest in December 2005. In connection with these borrowings, we issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.
In August 2005, we issued convertible promissory notes (the "Convertible Notes") in the original aggregate principal amount of $22,500,000. The Convertible Notes, which bore interest at 10% per annum, were repaid in full, including accrued interest, in December 2005. We used a portion of the proceeds from our private placement of senior secured notes and warrants in December 2005 discussed below to repay the Convertible Notes.
In October 2005, one of our wholly-owned subsidiaries, Transmeridian Exploration Inc. ("TEI"), entered into a share sale and purchase agreement with Seeria Alliance Ltd. to purchase 100% of the authorized and issued shares of Bramex, the owner of 50% of Caspi Neft. In December 2005, the transaction was completed and TEI now owns, directly or indirectly, 100% of Caspi Neft. The total purchase price was $168 million, of which approximately $44 million was to repay the bank credit facilities of Caspi Neft discussed above.
In December 2005, TEI, issued in a private placement 250,000 units (the "Units") consisting of (i) an aggregate $250 million principal amount of its senior secured notes due 2010 (the "Notes") and (ii) warrants to purchase in the aggregate approximately 17.3 million shares of our common stock (the "Warrants"). The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 Warrants to purchase an equal number of shares of our common stock. The Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Notes is payable quarterly on March 15, June 15, September 15 and December 15, beginning on March 15, 2006, and at maturity. The first year of interest payments have been escrowed and are recorded as restricted cash on the consolidated balance sheet as of December 31, 2005.
The Notes are secured by first priority pledges of all the capital stock of TEI and of all of our other material subsidiaries. In addition, the Notes are fully and unconditionally guaranteed by us and all of our other material subsidiaries other than TEI. The Notes contain provisions that limit our ability to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets;
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and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the Notes in connection with certain specified change of control events. The Notes are subject to redemption, in whole or in part, at our option at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, we may redeem up to 35% of the Notes with proceeds of certain equity offerings at a specified redemption price.
We used the net proceeds from the private placement of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex, to retire the existing bank credit facility indebtedness of Caspi Neft, to repay the Convertible Notes and related accrued interest and to pre-fund the first year of interest payments of $30 million on the Notes. In addition, in December 2005, we entered into a purchase agreement with Kornerstone Investment Group Ltd. ("Kornerstone") pursuant to which we acquired the 10% carried working interest in the South Alibek Field held by Kornerstone for $15.25 million in cash and one million shares of our common stock. The cash portion of the purchase price obligation was funded from the net proceeds of the placement of Units.
Management expects cash flow from operations to increase throughout 2006 and, together with the excess proceeds from the private placement of Units discussed above, to provide a portion of the funds needed to further develop the field and repay debt. Such cash flow is dependent upon many factors, such as achieving and sustaining adequate production rates, oil prices and other factors which may be beyond the our control.
The following table presents our future contractual obligations, which consist of long-term debt and lease commitments:
2005 2006 2007 2008 Thereafter
Long-term debt(1) $ - $ - $ - $ - $ 250,000,000
Lease commitments(2) 273,324 76,126 - - 349,540
Total contractual obligations $ 273,324 $ 76,126 $ - $ - $ 250,349,540
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(1) See note 5 to the Notes to the Consolidated Financial Statements.
(2) See note 8 to the Notes to the Consolidated Financial Statements.
Critical Accounting Policies and Recent Accounting Pronouncements
We have identified the policies below as critical to our business operations and the understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management's Discussion and Analysis where such policies affect our reported and expected financial results. A complete discussion of our accounting policies is included in note 1 of the Notes to Consolidated Financial Statements.
Principles of Consolidation
The consolidated financial statements include our accounts and our majority-owned or controlled subsidiaries and are prepared in accordance with generally accepted accounting principles in the United States. All significant intercompany transactions and balances have been eliminated in consolidation. The assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations.
We continued to exercise significant control over Caspi Neft after Bramex exercised its option to acquire 50% of Caspi Neft in February 2004 and accordingly, believed the most meaningful accounting treatment was to fully consolidate Caspi Neft with the 50% share owned by Bramex reflected as a minority interest. To exercise its option, Bramex contributed $15.0 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15.0 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount was included in additional paid-in capital on the accompanying 2004 consolidated balance sheet.
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Form 10-K for TRANSMERIDIAN EXPLORATION INC
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16-Mar-2006
Annual Report
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Introduction
The following discussion and analysis addresses changes in our financial position and results of operations during the three year period 2003 through 2005. There is limited or no comparability for revenue and operating expense in 2003, as sales and production did not commence until the third quarter of 2003.
Management's primary goals for 2005 were to:
• Continue development drilling in the Field;
• Increase production from all wells in the Field;
• Improve efficiency of drilling and completion programs;
• Improve prices received for oil sales;
• Negotiate a long-term production contract; and
• Secure additional financing for Caspi Neft.
We believe that these goals were largely achieved in 2005. Our primary goals for 2006 include optimizing completions of the existing wells in the Field to maximize production from those wells, accelerating development
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of the Field by increasing the number of drilling rigs under operation from one to at least four, continuing to improve the price received for our oil sales, completing production and treatment facilities and connecting to the regional pipeline system.
Current Activities
Through December 31, 2005, we had drilled a total of eight wells in our South Alibek evaluation and development program. The SA-14 and the SA-3 were completed and placed into production in May and October 2005, respectively. Drilling of the eighth well in the program, the SA-15, began in late September 2005 and reached target depth in December 2005. The well was perforated in January 2006 and allowed to begin flowing naturally without stimulation. These three wells are infill development wells. With the exception of SA-4, all the wells in the Field have been producing oil on an extended production testing program. The ninth and tenth wells in the Field, the SA-11 and SA-12, were spudded on January 30 and February 1, 2006 respectively.
Our field operations and scheduled workovers were adversely affected by abnormally extreme subzero temperatures during late December and early 2006 that affected the region's transportation, infrastructure and contractor services. The interruptions caused by these circumstances significantly affected timing of planned work and our ability to meet year-end production goals, with two of the seven producing wells temporarily shut-in. Once scheduled work is completed and these wells are placed back on production, we expect production from the existing wells producing simultaneously to be approximately 2,500-3,000 bopd.
Production from the wells is currently run through temporary production facilities, with oil storage capacity at the site of this facility as well as at the site of the central production facility. Production is currently being constrained by equipment and flowline limitations pending completion of the central facility, which has been delayed by the inability of the previous general contractor to complete the required installation. That contractor has been dismissed, and we engaged a leading international contractor in February 2006 to inspect and submit a plan to complete the facilities. We expect to have a revised plan and definitive construction schedule during the first quarter of 2006, resume construction work in the second quarter and commission the facility by the fourth quarter. We are implementing an interim solution to improve production capacity until the central facility is completed. The design and permitting work on our pipeline connection to the Alibekmola-Kenkiyak pipeline, and the associated support facilities began in 2005, and commissioning is also planned before the fourth quarter of 2006. See "Item 2.
Properties-Transportation and Marketing" for an overview of pipeline connections and activity in the South Alibek area.
During 2005, workover programs initiated in 2004 were completed and new programs for selected wells were initiated to prepare the wells for long-term commercial production. These programs included reservoir stimulation, installation of more efficient production tubing and packers and the testing of down-hole electric submersible pumps with the aim to increase production. To address numerous delays and inefficiences encountered in our execution of the workover program, a dedicated workover rig has been sourced for the Field that will replace the locally provided workover units used previously. This new unit is expected to significantly reduce the time required to conduct our workovers and reduce the shut-in time experienced while work is in progress. We expect the unit to begin working in the second quarter of 2006, when Field activity levels increase as a result of the accelerated drilling program.
Our drilling program is currently using two drilling rigs contracted from Great Wall Drilling Company, the second of which arrived in the Field in December 2005. We plan to accelerate the program by adding at least two additional drilling rigs during the first half of 2006, bringing the total rigs in operation in the Field to four. In addition, the Company is evaluating opportunities to further speed development by adding a fifth and possibly a sixth drilling rig later in the year.
We have significantly reduced the time required to drill to our programmed final depths through improvement in drilling practices, bit selection and drilling fluids control. SA-15 reached its total depth of 12,600
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feet in 87 days and was the first of our wells that met the benchmark of 92 days established from competitor drilling data. We expect to continue to improve on the timing for drilling and completion of wells as increased equipment and new highly skilled personnel will allow for more continuity in operations.
Results of Operations
Oil Production and Revenue
For the year ended December 31, 2005, we produced 400,425 barrels ("Bbls") of crude oil, or an average of 1,097 Bbls per day (Bopd), as compared to 313,305 Bbls, or an average of 858 Bopd, for the year ended December 31, 2004 and 117,376 Bbls, or an average of 641 Bopd for the year ended December 31, 2003. The increase in 2005 when compared to 2004, and the increase in 2004 from 2003, are primarily a result of the Field having five wells contributing to production in 2005 as compared to three wells in 2004 and only one well in 2003, and the Field being on production throughout 2004 versus only six months in 2003, as production from the Field commenced in July of 2003.
For the year ended December 31, 2005, we sold (by physical delivery to the purchaser) 324,355 Bbls of crude oil at an average price of $27.62 per Bbl, for net revenues of $8,442,787, as compared to 336,440 Bbls of crude oil at an average price of $11.87 per Bbl, for net revenues of $3,922,990, for the year ended December 31, 2004 and 77,293 Bbls at an average price of $10.52, for net revenue of $797,411 for the year ended December 31, 2003. The increase in net revenue in 2005 as compared to 2004 was primarily a result of substantially higher sales prices we received for our oil. Through a series of new sales arrangements, we realized increases over 2004 in the net price received for our crude oil to an average of approximately $20.00 per Bbl for the first half of 2005 and an average of approximately $37.00 per Bbl for the second half of 2005. The last price we received in December 2005 was $42.45 per Bbl. The increase in net revenue in 2004 as compared to 2003 is primarily due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field producing for all of 2004 versus only six months of 2003. Sales from the Field commenced in the third quarter of 2003.
We recognize revenue from the sale of oil when the purchaser takes delivery of the oil. As of December 31, 2005, we had 87,296 Bbls of oil in inventory that had not yet been sold, pending commencement of oil sales arrangements with new purchasers. As of December 31, 2004, we had 16,576 Bbls in inventory for which we had received payment but had not recognized revenue because delivery had not yet been taken by the purchaser. The average sales price for this oil was $11.61 per Bbl, which was recognized as revenue in 2005 upon delivery to the purchaser.
Our crude oil sales since June 2005 have primarily take place at a nearby rail terminal. We incurred transportation and storage costs of approximately $1.54 per Bbl to transport our oil by truck to the rail terminal, where it is stored in rented tanks until delivery to the purchasers. Our crude oil sales in the last eight months of 2004 and the first six months of 2005 occurred at the Field and were not subject to transportation costs. See Item 7, "Results of Operation-Transportation Expense".
Exploration Expense
Exploration expense, which includes geological and geophysical expense and the cost of unsuccessful exploratory wells, is recorded as an expense in the period incurred under the successful efforts method of accounting. During the year ended December 31, 2005, we incurred $9,470 in exploration expense, primarily associated with geological interpretations of the Field. During 2004, we recognized exploration expense of $130,926, which included costs associated with geological interpretations of the Field and a write off of the remaining book value of non-producing lease cost of a property in South Texas. During 2003, we incurred $592,553 in exploration expense, which was primarily related to the purchase and interpretation costs of geologic data and a charge for the unsuccessful completion attempt on one of our two U. S. properties.
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Depreciation, Depletion and Amortization
Depreciation, depletion and amortization ("DD&A") of oil and gas properties is calculated under units of production method, following the successful efforts method of accounting. For the year ended December 31, 2005, DD&A of oil and gas properties was $2,442,263, or $6.10 per Bbl, as compared to $709,496, or $2.11 per Bbl for the year ended December 31, 2004 and $189,635, or $2.45 per Bbl, for the year ended December 31, 2003. The increase in 2005 from 2004 is primarily a result of the change in classification of reserves attributable to the KT1 reservoir to "proved undeveloped" from "proved developed behind pipe," due to a change in the assumed Field development plan. The new plan assumes that separate wells will be drilled to produce reserves in the KT1 reservoir, rather than "dual-completing" wells to produce from both the KT2 and KT1 reservoirs simultaneously. As a result, beginning in the fourth quarter of 2005, reserves in the KT1 reservoir, which account for approximately 40% of our total "proved" reserves as of December 31, 2005, have been excluded from the total reserve base currently being depleted. Costs incurred are now spread over a substantially smaller quantity of oil until such time as wells are drilled to produce from the KT1 reservoir and those reserves are classified as "proved developed." In addition, we had an average of four producing wells during 2005 versus only 1.5 producing wells in 2004. The increase in DD&A of oil and gas properties in 2004 from 2003 is primarily due to the increase in oil production between the periods.
Non-oil and gas property DD&A for 2005, 2004 and 2003 was $942,630, $79,262 and $56,077, respectively. The increase between the years is primarily due to additions of transportation and other equipment, and commencement of depreciation on our drilling rig, which we no longer plan to use for development of the Field.
Transportation Expense
During the third quarter of 2005, we began incurring transportation and storage costs relating to the transport of our oil to a nearby rail terminal for sale and export. During the second half of 2005, we incurred transportation and storage costs of $321,313, or $1.54 per Bbl. From the second quarter of 2004 through the second quarter of 2005, oil sales were made directly from the Field, with no transportation costs incurred. For the year ended December 31, 2004, transportation and storage costs were $173,847, or $2.12 per Bbl produced. For the year ended December 31, 2003, we incurred transportation and storage costs of $235,264 or $2.00 per Bbl produced. When the treating facilities and pipeline pump station discussed in Item 2, "Properties-Transportation and Marketing," are operational, expected in late 2006, we plan to deliver crude oil production directly into the regional pipeline system, which should result in a significant improvement in sales pricing for our crude oil.
Impairment Loss
In the first quarter of 2006, we reached an agreement to dispose of our drilling rig. An impairment charge writing the value of the rig down to the estimated proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded as of December 31, 2005.
Operating and Administrative Expense-Kazakhstan
For the year ended December 31, 2005, operating and administrative expense in Kazakhstan was $3.9 million, as compared to $3.6 million for the year ended December 31, 2004 and $2.5 million for the year ended December 31, 2003. The increases between years are primarily a result of increased personnel costs due to increased activity in our exploration, development and production program for the Field.
General and Administrative Expense-Houston
For the year ended December 31, 2005, general and administrative expense in Houston was $6.6 million, as compared to $2.6 million for the year ended December 31, 2004 and $2.1 million for the year ended
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December 31, 2003. The increase in 2005 from 2004 is primarily due to costs incurred for listing on the American Stock Exchange, Sarbanes-Oxley Act compliance and addition of new corporate staff, as well as the cost of stock-based compensation related to employee stock options and restricted stock grants recognized during the year. The increase in 2004 from 2003 is primarily due to increased legal costs associated with two lawsuits ongoing during the year.
Interest Expense
Interest expense, net of the capitalized portion, for the years ended December 31, 2005, 2004 and 2003 was $10.3 million, $1.4 million and $.7 million, respectively. The increase in interest expense between years is primarily due to increased debt levels between the periods, as well as the commencement of expensing interest, as opposed to capitalizing interest, on those assets which have been placed in service and are being used for their intended purpose. In addition, $4.4 million of debt discount amortization related to short-term borrowing was recognized in 2005.
Liquidity and Capital Resources
For the years ended December 31, 2005, 2004 and 2003, our on-going capital expenditures were $20.7 million, $26.1 million and $31.2 million, respectively. Our primary sources of funding have been private placements of common and preferred stock, borrowings under our credit facilities with a Kazakhstan bank and our private placement of senior secured notes due 2010 and warrants to purchase shares of common stock (as described in more detail below and in notes 5 and 6 to the notes to consolidated financial statements). The total capitalized cost attributable to the South Alibek Field as of December 31, 2005 was $230.1 million, which includes $12.5 million of capitalized interest.
In February 2002, Caspi Neft entered into a credit facility with a Kazakhstan bank that provided for borrowings totaling $20.0 million with an interest rate of 15% and a fee of 0.5% per annum on the unutilized portion of the commitment. The original maturity date was February 2005; however, the terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or
(ii) December 23, 2005.
In June 2003, Caspi Neft entered into a new $30.0 million credit facility with the same Kazakhstan bank. This facility provided for borrowings up to $30.0 million with an interest rate of 15% and a commitment fee of 0.5% per annum on the unutilized portion. Upon execution of the credit facility, Caspi Neft paid the bank an arrangement fee of $300,000, which was capitalized as a deferred financing cost and was being amortized over the five-year life of the facility. Originally, the amount outstanding as of May 31, 2005 was scheduled to be repaid over 36 equal monthly installments beginning June 2005 through the final maturity date of May 31, 2008; however, those terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or (ii) December 23, 2005.
Both credit facilities were repaid in full in December 2005 in connection with our acquisition of Bramex and our December 2005 private placement of senior secured notes and warrants discussed below.
In November 2004, we sold 1,785.714 shares of our Series A Preferred in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of our common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25.0 million. Proceeds from the private placement of Series A Preferred and warrants were used for general corporate purposes, including funding our development drilling program in the South Alibek Field in Kazakhstan, and to pursue growth opportunities.
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The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders' option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred are entitled to a quarterly dividend payable at the rate of 4.5% per annum, payable in cash. The holders of the Series A Preferred have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of our common stock, and vote together with the holders of common stock as one class. A holder of the Series A Preferred may not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the warrants into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of our common stock owned by such holder at such time, 4.999% of our then issued and outstanding shares of common stock. So long as at least 20% of the Series A Preferred remains outstanding, we may not issue any new securities or financial instruments that rank pari passu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning in July 2006, the Series A Preferred will automatically convert into our common stock at the conversion price of $1.40 per share (subject to adjustments), if our common stock trades at a price greater than $4.15 per share for twenty consecutive trading days and the average daily trading volume of our common stock during such period exceeds 200,000 shares, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation, the excess portion of the Series A Preferred remains outstanding, but ceases to accrue a dividend. During 2005, 238 shares of Series A Preferred were converted into 2,380,000 shares of our common stock.
In May 2005, we borrowed an aggregate of $2,240,000 from a group of individuals pursuant to unsecured, short-term notes. The notes bore interest at 15% per annum and were repaid along with accrued interest in July and September 2005. In July 2005, we borrowed $1,000,000 from an individual pursuant to an unsecured short-term note, which bore interest at 15% per annum and was repaid with accrued interest in December 2005. In connection with these borrowings, we issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.
In August 2005, we issued convertible promissory notes (the "Convertible Notes") in the original aggregate principal amount of $22,500,000. The Convertible Notes, which bore interest at 10% per annum, were repaid in full, including accrued interest, in December 2005. We used a portion of the proceeds from our private placement of senior secured notes and warrants in December 2005 discussed below to repay the Convertible Notes.
In October 2005, one of our wholly-owned subsidiaries, Transmeridian Exploration Inc. ("TEI"), entered into a share sale and purchase agreement with Seeria Alliance Ltd. to purchase 100% of the authorized and issued shares of Bramex, the owner of 50% of Caspi Neft. In December 2005, the transaction was completed and TEI now owns, directly or indirectly, 100% of Caspi Neft. The total purchase price was $168 million, of which approximately $44 million was to repay the bank credit facilities of Caspi Neft discussed above.
In December 2005, TEI, issued in a private placement 250,000 units (the "Units") consisting of (i) an aggregate $250 million principal amount of its senior secured notes due 2010 (the "Notes") and (ii) warrants to purchase in the aggregate approximately 17.3 million shares of our common stock (the "Warrants"). The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 Warrants to purchase an equal number of shares of our common stock. The Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Notes is payable quarterly on March 15, June 15, September 15 and December 15, beginning on March 15, 2006, and at maturity. The first year of interest payments have been escrowed and are recorded as restricted cash on the consolidated balance sheet as of December 31, 2005.
The Notes are secured by first priority pledges of all the capital stock of TEI and of all of our other material subsidiaries. In addition, the Notes are fully and unconditionally guaranteed by us and all of our other material subsidiaries other than TEI. The Notes contain provisions that limit our ability to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets;
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and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the Notes in connection with certain specified change of control events. The Notes are subject to redemption, in whole or in part, at our option at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, we may redeem up to 35% of the Notes with proceeds of certain equity offerings at a specified redemption price.
We used the net proceeds from the private placement of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex, to retire the existing bank credit facility indebtedness of Caspi Neft, to repay the Convertible Notes and related accrued interest and to pre-fund the first year of interest payments of $30 million on the Notes. In addition, in December 2005, we entered into a purchase agreement with Kornerstone Investment Group Ltd. ("Kornerstone") pursuant to which we acquired the 10% carried working interest in the South Alibek Field held by Kornerstone for $15.25 million in cash and one million shares of our common stock. The cash portion of the purchase price obligation was funded from the net proceeds of the placement of Units.
Management expects cash flow from operations to increase throughout 2006 and, together with the excess proceeds from the private placement of Units discussed above, to provide a portion of the funds needed to further develop the field and repay debt. Such cash flow is dependent upon many factors, such as achieving and sustaining adequate production rates, oil prices and other factors which may be beyond the our control.
The following table presents our future contractual obligations, which consist of long-term debt and lease commitments:
2005 2006 2007 2008 Thereafter
Long-term debt(1) $ - $ - $ - $ - $ 250,000,000
Lease commitments(2) 273,324 76,126 - - 349,540
Total contractual obligations $ 273,324 $ 76,126 $ - $ - $ 250,349,540
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(1) See note 5 to the Notes to the Consolidated Financial Statements.
(2) See note 8 to the Notes to the Consolidated Financial Statements.
Critical Accounting Policies and Recent Accounting Pronouncements
We have identified the policies below as critical to our business operations and the understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management's Discussion and Analysis where such policies affect our reported and expected financial results. A complete discussion of our accounting policies is included in note 1 of the Notes to Consolidated Financial Statements.
Principles of Consolidation
The consolidated financial statements include our accounts and our majority-owned or controlled subsidiaries and are prepared in accordance with generally accepted accounting principles in the United States. All significant intercompany transactions and balances have been eliminated in consolidation. The assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations.
We continued to exercise significant control over Caspi Neft after Bramex exercised its option to acquire 50% of Caspi Neft in February 2004 and accordingly, believed the most meaningful accounting treatment was to fully consolidate Caspi Neft with the 50% share owned by Bramex reflected as a minority interest. To exercise its option, Bramex contributed $15.0 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15.0 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount was included in additional paid-in capital on the accompanying 2004 consolidated balance sheet.
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