TMY FWIW!!
Current Activities
During the first quarter of 2005, we continued with infield drilling operations. Development well SA-14 reached a total depth of 12,570 feet (3,830 meters) in February 2005. Results from preliminary evaluation of logging and drilling data indicate the presence of the same KT I and KT II carbonate reservoirs in this well as are currently on production from existing wells in the Field. Perforating and testing is scheduled to begin after running casing. The drilling rig used on well SA-14 has been moved to the next development location and well SA-3 has been spuded.
The hydraulic fracture stimulation treatment of well SA-17 was successfully completed in the first quarter of 2005. After recovering the stimulation fluid, the well will undergo long term testing to evaluate its effectiveness of the hydraulic fracture stimulation for application to the other existing and future wells.
Negotiations are progressing to mobilize additional drilling rigs to the field. In addition, changes are being implemented to the drilling program to reduce the cost and time to drill development locations in the Field. Mobilization of the first additional rig is expected to take three to four months after execution of a new contract.
The final construction of the new central production facility was postponed during the quarter. Harsh weather conditions combined with contract disputes have delayed the completing of the facility. Construction is expected to resume in the second quarter of 2005 with completion and field commissioning in the third quarter of 2005.
Results of Operations
Oil production and revenue
In the first quarter of 2005 the Company produced 74,102 barrels ("Bbls") of crude oil or an average of 823 Bopd, as compared to 84,986 Bbls or an average of 934 Bopd in the first quarter of 2004. The decrease in 2005 when compared to 2004 is a result of the SA-1, being on a testing mode during the first quarter of 2004 and producing through a larger choke size. After the well stabilized in the second quarter of 2004, it was determined that the well would perform better producing through a smaller size choke. It was also observed that the flow rates were becoming constricted due to paraffin build-up in the tubing and we are currently evaluating different options to alleviate or reduce the build-up of paraffin.
For the quarter ended March 31, 2005, we sold (by physical delivery to the purchaser) 68,525 Bbls at an average price of $17.25 per Bbl, for net revenues of $1,153,739, as compared to 53,299 Bbls at an average price of $12.24 and net revenue of $642,997 for the comparable period in 2004. The increase in 2005 compared to 2004 is primarily due to the increase in sales price of $5.01 per barrel or $267,028 and an increase in volumes sold of 15,226 Bbls or $262,649.
We recognize revenue from the sale of oil when the purchaser takes delivery of oil at the Field. As of March 31,
2005, the Company had 22,153 Bbls in inventory for which it had received payment, but had not recognized the revenue because delivery had not yet been taken by the purchaser. The average price received was $20.73 per barrel, which will be recognized as revenue in future periods of 2005, upon delivery to the purchaser.
Exploration expense
Exploration expense, which includes geological and geophysical expense and the cost of unsuccessful exploratory wells, is recognized in the period incurred under the successful efforts method of accounting. For the three month period ended March 31, 2005, the Company recognized no exploration expense. In the three month period ended March 31, 2004, we recognized exploration expense of $23,003, primarily associated with the investigation of new international opportunities, and we also expensed the remaining book value of non-producing lease cost of the South Texas properties.
Depreciation, depletion and amortization
Depreciation, depletion and amortization ("DD&A") of oil and gas properties is calculated under the units of production method, following the successful efforts method of accounting. For the three month period ended March 31, 2005, DD&A was $177,809, or an average of $2.59 per barrel. For the three month period ended March 31, 2004, DD&A was $116,529 or an average of $2.18 per barrel. The increase in 2005 when compared to 2004 is due to the Field having three producing wells in 2005 as compared to only one producing well in 2004. The volumes which have been produced but were in inventory at March 31, 2005 are not included in the calculation of DD&A expense. These volumes will be included in the calculation when sold.
Non-oil and gas property DD&A for the three month period ended March 31, 2005 was $21,876, as compared to $18,695, for the comparable period in 2004. This increase is primarily due to additions to transportation and office equipment.
Transportation expense
During the second quarter of 2004, the first of three storage tanks at our permanent production facility was commissioned for use. This allowed us to begin oil sales from the Field, resulting in substantial cost savings. For the three month period ended March 31, 2005, we incurred no transportation and storage costs. For the three month period ended March 31, 2004, we incurred transportation and storage costs of $175,354, or $2.12 per Bbl produced. We are currently exploring several different alternatives for marketing of our production. Additionally, when the treating facilities and pipeline pump station are operational, which is expected during 2005, we expect to deliver crude oil production directly into the regional pipeline system, which should result in a significant improvement in pricing for sales of our crude oil.
Operating and administrative expense - Kazakhstan
For the three month period ended March 31, 2005, operating and administrative expense in Kazakhstan was $1.5 million, compared to $732,080, for the comparable period in 2004. This increase is primarily due to increased activity in our exploration, development and production program for the South Alibek Field.
General and administrative expense - Houston
General and administrative expense in Houston for the three month period ended March 31, 2005 was $1.1 million, compared to $669,803, for the comparable period in 2004. This increase is primarily due to the costs incurred for listing on the American Stock Exchange, Sarbanes Oxley implementation and addition of new staff.
Interest expense
Interest expense, net of the capitalized portion, for the three periods ended March 31, 2005 was $692,000, as compared to $147,318 for the corresponding period in 2004. The difference is primarily due to increased debt levels in the first quarter of 2005 when compared to the first quarter of 2004, and 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.
Liquidity and Capital Resources
For the three months ended March 31, 2005 and 2004, capital expenditures were $2.7 million and $4.0 million, respectively. The primary sources of funding have been private placements of common and preferred stock, borrowings under our credit facilities with a Kazakhstan bank and loans from the Company and Bramex to Caspi Neft. From inception through March 31, 2005, we have received a total of $12.0 million in net cash proceeds from sales of common stock and $23.4 million in net cash proceeds from the sale of preferred stock. Our cumulative proceeds from all borrowings, net of repayments, have amounted to $34.6 million since inception. These proceeds have been used to conduct remedial work and production tests on SA-29, drill and complete the SA-1, SA-2, SA-4, SA-5 and SA-17 and drill the SA-14, the initial construction costs of support and production facilities and the administrative cost of the office in Kazakhstan. The total capitalized cost attributable to the South Alibek Field as of March 31, 2005, was $79.4 million, which includes $10.5 million of capitalized interest.
The Company has two credit facilities with a Kazakhstan bank, one in the amount of $20.0 million and the other in the amount of $30.0 million. There is no remaining availability under either of the credit facilities. Both credit facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends and incurring additional indebtedness. The Company is required to provide audited financial statements of Caspi Neft to the bank within 90 days of the end of the fiscal year. In 2004 and 2005, the Company did not meet this requirement, but such non-compliance has been waived by the bank. Both credit facilities are secured by substantially all of the assets of Caspi Neft, including the South Alibek License and the stock of Caspi Neft. The Company's wholly-owned British Virgin Islands subsidiary, which holds its interest in Caspi Neft, has also guaranteed the loan. Both facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends and incurring additional indebtedness.
In February 2005, the Company, through its subsidiary Caspi Neft, entered into an agreement with the bank in Kazakhstan to defer all payments of principal and interest due on both credit facilities for six months, or until July 15, 2005. At the expiration of the extension, the total amount of principal and interest deferred, $13.7 million will become due and payable. In exchange for this deferral the Company has agreed to advance up to $10.0 million to Caspi Neft to fund 100% of anticipated capital requirements for the first six months of 2005. Pursuant to the terms of this agreement, the Company advanced $5.0 million to Caspi Neft in February 2005 and the additional $5.0 million in April 2005.
Management expects cash flow from operations to increase throughout 2005 and 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 control of the Company.
By the end of 2005, we expect to drill and complete four new wells, bringing our total number of producing wells to ten, complete the construction of the production facility, tie into the regional pipeline system and complete the negotiation of a Production Contract. We have an approved budget of approximately $36.6 million for capital expenditures and an operating budget (lease operating expense and general and administrative expense) of approximately $12.0 million. We currently anticipate that this capital spending plan will result in a cash shortfall of approximately $10.0 - $15.0 million, before debt service. We are currently discussing new financing alternatives with several financial institutions, but cannot be assured that we will be successful. If an agreement is not achieved for new financing we will have to reduce or suspend our capital program in order to fund operating expenses and debt service. The Company believes it will be successful in obtaining new financing to continue development of the Field in accordance with its current development plan. However, the Company cannot provide assurance that it will be successful, as many factors required to execute its plans are outside the control of the Company.
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 is 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 December 31, 2004 Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2004.
Principles of Consolidation
Our consolidated financial statements include all of our subsidiaries. Our most significant subsidiary is Caspi Neft, which holds License 1557 and the related Exploration Contract for the South Alibek Field. The assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations at March 31, 2005.
During February 2004, Bramex Management, Inc., successor in interest to Kazstroiproekt, Ltd. ("Bramex"), exercised its option to acquire 50% of the common stock of OJSC Caspi Neft TME ("Caspi Neft"), the Company's primary operating subsidiary in Kazakhstan and the entity which holds the license and Exploration Contract covering the South Alibek Field. Accordingly, as of March 31, 2005, the Company owns a 50% equity interest in this subsidiary. Based on the Company's ability to exercise significant control over Caspi Neft, the Company believes that the most meaningful accounting treatment is to fully consolidate this entity, with the 50% share owned by Bramex reflected as a minority interest.
Oil and Gas Reserve Information
The information regarding our oil and gas reserves, the changes thereto and the estimated future net cash flows are dependent upon reservoir evaluation, price and other assumptions used in preparing our annual reserve study. A qualified independent petroleum engineer was engaged to prepare the estimates of our oil and gas reserves in accordance with applicable reservoir engineering standards and in accordance with Securities and Exchange Commission guidelines. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the South Alibek Field. Changes in prices and cost levels, as well as the timing of future development costs, may cause actual results to vary significantly from the data presented. Our oil and gas reserve data represent estimates only and are not intended to be a forecast or fair market value of our assets.
Our oil and gas reserve data and estimated future net cash flows have been prepared assuming we are successful in negotiating a commercial production contract which will allow production for the expected 25-year term of the contract. The current maximum statutory royalty rate of 6%, as provided by new legislation which came into effect in 2004, has been used to calculate the government royalty. Production contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and exploration contract. However, we are not guaranteed the right to a production contract. If we are not successful in negotiating a production contract on acceptable terms, it would materially change our oil and gas reserve data and estimated future net cash flows.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for our investments in oil and gas properties, as more fully described in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2004. This accounting method has a pervasive effect on our reported financial position and results of operations.
Revenue Recognition
The Company sells its production in the domestic market in Kazakhstan on a contract basis. Revenue is recognized when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory, which is offset by deferred revenue. Such oil inventory and deferred revenues are valued at the price of the last oil sold.
Capitalized Interest Costs
We capitalize interest costs on oil and gas projects under development, including the costs of unproved leasehold and property acquisition costs, wells in progress and related facilities. We also capitalized interest on our drilling rig during the time it was being prepared for its intended use. During the three month period ended March 31, 2005 and 2004, we capitalized $796,095 and $1.4 million, respectively, of interest costs, which reduced our reported net interest expense to $692,000 and $147,318, respectively. |
