Niko reported its results for the three and nine months ended December 31, 2008.
Oil Development: Production from the MA discovery commenced in September 2008 and the field produced over 790,000 Bbls (79,000 Bbls working interest to the Company) up to December 9, 2008. The first cargo sale of over 430,000 Bbls (43,000 Bbls working interest to the Company) was made in November. Remaining volumes were inventoried. On December 9, 2008, production ceased as there was a rupture in a short pipe spool connected to the flare header in the FPSO. Production is expected to recommence in March 2009 after completion of necessary repairs and modifications as well as the tie-in of the recently drilled MA5H horizontal well. This will result in three producing oil wells. In addition, there is a scheduled shutdown in late March or early April to allow tie-in modifications for the next set of horizontal wells.
The initial field development costs, excluding the capital cost of the FPSO as it is currently being leased, are budgeted at US $1.5 billion (US $150 million net to the Company) and the Company had spent US $109 million of this amount at December 31, 2008. The remainder of the budgeted costs will be spent to drill and tie in three additional wells and, after a period of oil production, to convert some of the oil wells to gas producers and complete tie-ins to allow the gas produced to be delivered to the onshore gas processing plant and sold.
Gas Development: Commencement of production from the Dhirubhai 1 and 3 discoveries is targeted in the next few weeks. Delays have occurred due to adverse weather conditions, complex logistics, tight supply chain market and a global shortage of manpower.
The development plan for the Dhirubhai 1 and 3 gas fields provides for natural gas production at a rate of 2.8 Bcf/d (280 MMcf/d working interest to the Company) envisaged within the first year of production operations. The Phase I initial field development costs are budgeted at US $5.2billion (US $520 million net to the Company). The Company had spent US $408 million of this amount to December 31, 2008. The Company expects Phase I costs to be over the budgeted amount due to the causes of delay in start-up as described above. Costs will be spent after start-up to tie in the remaining wells.
Nine natural gas discoveries in addition to the Dhirubhai 1 and 3 gas discoveries have been made and a development plan for these discoveries has been submitted to the Government of India. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently under development. If the development plan is approved, it is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities. The design of the critical components of the Dhirubhai 1 and 3 facilities would allow an increase in production to 4.2 Bcf/d (420 MMcf/d working interest to the Company).
NEC-25 Block: In the previous quarter, the B3 well was drilled in 64 meters of water to a total true vertical depth of 3,928 meters. A gas zone was encountered at 1,900 meters.
Development plans have been submitted for the six gas discoveries that have been declared commercial by the Indian regulatory authorities.
Approximately 1,000 square kilometers of 3D seismic have been acquired along the central portion of the northwest boundary of the previous 3D surveys. Processing and interpretation of the seismic is underway.
Cauvery: Site construction is underway in preparation for the drilling of the first of three possible onshore wells in calendar 2009. The first well, CY-MK-01, is due to spud in April 2009 with a planned true vertical depth of 4,100 meters. The primary target of the well is the Cretaceous-Jurassic interval.
D4 Block: Acquisition of a 3,600 square kilometer 3D seismic survey is expected to be complete in February 2009. Initial interpretation of the data within this survey that has already been acquired has identified several areas of interest, which will be fully analysed as part of the ongoing evaluation. Processing and interpretation of the data is expected to be completed in time to allow for first well selection by mid-calendar 2010.
Hazira and Surat: The Hazira field is currently producing 43 MMcf/d (14 MMcf/d working interest to the Company). A 30 square kilometer transition zone 3D seismic survey commenced in January 2009 and is expected to be completed in February 2009. This 3D survey is designed to explore for deeper oil and gas targets in the eastern half of the Hazira block. The survey will merge with the offshore seismic previously acquired and provide 3D coverage for almost the entire Hazira block. Dependent on results of processing and interpretation of the 3D program, a multi-well drilling program will be initiated in late calendar 2009 or early 2010.
Current production from the Surat field is approximately 10 MMcf/d. This includes production from the three wells drilled in fiscal 2008.
Block 9: Two wells in Block 9, Bangora-1 and Bangora-5, are currently producing at a combined rate of 100 MMcf/d (67 MMcf/d working interest to the Company). Facilities upgrades were completed and have increased capacity to in excess of 120 MMcf/d (80 MMcf/d working interest to the Company). Production is expected to increase to nearly 120 MMcf/d (80 MMcf/d working interest to the Company) when the Bangora-3 well is put on-stream in March. A condensate plant module is scheduled to be installed and operational by mid-calendar 2009, which will increase condensate yields. Further drilling of prospects identified in the block has been postponed pending the availability of a drilling rig.
Feni and Chattak: Production from the Feni field is 3 MMcf/d. Future drilling activities at Feni and Chattak remain postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.
Four production sharing agreements (PSAs) were signed in March 2008 and a 3D seismic program of 2,000 square kilometers commenced in November 2008 and was completed in January 2009. Historical seismic over the blocks was limited to 2D only. The 3D program is expected to identify stratigraphic potential, resolve structural complexity and possibly indicate the presence of hydrocarbons, all of which is not possible with 2D seismic. Processing of the 3D data should be completed in the third calendar quarter of 2009 with interpretation and possible selection of drilling locations to follow.
In May 2008 the Company signed a production sharing contract (PSC) for the Qara Dagh block. Data acquisition of a 350 to 400-kilometer 2D seismic program commenced in February and is expected to be complete in July 2009. The seismic program will be acquired over the very large surface structure that totally dominates the Qara Dagh block. Interpretation of the data is expected to resolve the sub-surface structural picture and identify possible reservoir targets to provide multiple drilling locations. Processing and interpretation will follow with possible selection of drilling locations in the third calendar quarter of 2009.
In October 2008 the Company farmed-in to a PSC for a property located off the west coast of Madagascar. The farm-in agreement and appointment of the Company as operator have been approved by the Office of National Mines and Strategic Industries, which acts on behalf of the Republic of Madagascar. In January 2009 the Company agreed to assign 10 percent of its interest in Madagascar to a third party. The Company will earn a 65 percent interest in the block.
The joint venture is nearing completion of reprocessing 7,600 kilometers of 2D seismic. Interpretation of the reprocessed 2D seismic will follow and further evaluation of the block is planned including a high resolution multi-beam survey and sea floor coring program. Future work as prescribed in Phase II includes the acquisition of a 3D seismic program.
In November 2008, the Company signed four PSCs for interests in four deep-water offshore blocks covering almost 20,000 square kilometers. The Company will operate two of the blocks and earn a 51 percent working interest. In the other two blocks, which will not be operated by the Company, the Company will earn a 25 percent working interest. The two blocks operated by Niko are in the deep waters of the prolific Kutei Basin, where over seven billion barrels of oil equivalent have been proved to date on land and in shallow water. The two non-operated blocks are also associated with areas containing in excess of two billion barrels of oil equivalent.
Also in November 2008, the Company acquired the right to earn a 25 percent interest in another deep-water offshore exploration block covering almost 5,000 square kilometers.
D6 gas development start-up is expected in the next few weeks. Production has not been estimated for the quarter ending March 31, 2009 as it is dependent on the start-up date and ramp-up rate. Volumes are expected to ramp-up to 2.8 Bcf/d (280 MMcf/d working interest to the Company) envisaged within the first year of operations.
Production from Block 9 increased significantly in the quarter with completion of facilities upgrades, which increased plant capacity. Production was less than previously forecast due to lower demand from the customer during Bangladesh holidays and lower production immediately after the completion of facilities upgrades and during pressure surveys.
Actual oil sales volume from the D6 block in the third quarter of fiscal 2009 was 468 Bbls/d compared to 1,250 Bbls/d previously estimated. On December 9, 2008, production ceased as there was a rupture in a short pipe spool connected to the flare header in the FPSO. In addition, the Company had expected additional wells to be on production by the end of the period. Production is expected to recommence in March 2009, which will allow the startup of the recently drilled MA5H horizontal well in addition to the two existing horizontal wells. In addition, there is a scheduled shutdown in late March or early April to allow tie-in modifications for the next set of horizontal wells. As a result, the fourth quarter fiscal 2009 estimate has been revised to 100 Bbls/d.
Actual oil sales volume from the Hazira block in the third quarter of fiscal 2009 was 219 Bbls/d compared to 163 Bbls/d previously estimated. There was a successful acid stimulation of the oil well resulting in increased production during the quarter. The full effect of the acid stimulation is not expected to continue and therefore forecast production for the fourth quarter remains at 161 Bbls/d.
During the three and nine months ended December 31, 2008, operating expenses averaged $0.60/Mcfe and $0.43/Mcfe, respectively. Operating expenses increased in the quarter due to the start-up costs related to the commencement of D6 oil production and are anticipated to fall significantly when D6 gas goes on-stream.
The Company plans to meet its commitments with cash on hand, funds from operation and a restructured credit facility. However, there can be no assurance that the facility can be restructured. The Company's exposure to liquidity risks has increased from the previous period primarily as a result of the delay in start-up of the D6 gas project.
Cauvery - Capital expenditures of $0.6 million during the quarter were mainly for preparation of the drilling site and construction of an access road for the first of three locations to be drilled in calendar 2009. Year-to-date costs also include the carrying costs of the block.
D4 - A 3,600-square-kilometer 3D seismic program is currently in progress. Capital expenditures during the quarter of $0.2 million, of $2.0 million year-to-date and forecast for the remainder of fiscal 2009 are primarily for this seismic program.
D6 - Oil Development: The initial field development costs are budgeted at US$1.5 billion (US$150 million net to the Company) and the Company had spent US$109 million of that amount to December 31, 2008. The remainder of the budgeted costs will be spent to drill and tie in three additional wells and, after a period of oil production, to convert some of the oil wells to gas producers and complete tie-ins to allow gas produced to be delivered to the onshore gas processing plant and sold.
Gas Development: Phase I initial field development costs are budgeted at US$5.2 billion (US$520 million net to the Company). The Company had spent US$408 million of that amount to December 31, 2008. The remainder of the budgeted costs will be spent to tie-in wells subsequent to start-up. The Company expects Phase I costs to be over the budgeted amount due to the causes of delay in start-up.
Capital expenditures at D6 in the quarter and year-to-date were $75.5 million and $236.0 million, respectively. Spending related primarily to natural gas and oil developments but also included ongoing exploration. Forecast activity for the remainder of fiscal 2009 includes the continuation of the gas development for the Dhirubhai 1 and 3 natural gas fields, development of the MA oil field and exploration drilling activities.
Hazira - Capital expenditures in the quarter of $1.1 million and $1.3 million year-to-date were for a transitional 3D seismic program and well recompletions for natural gas wells. The remaining costs forecast for fiscal 2009 are for the completion of the 3D program.
Surat - There is currently no significant capital activity in Surat.
NEC-25 - Capital expenditures in the quarter and year-to-date were $1.3 million and $11.7 million, respectively, primarily for the acquisition of 3D seismic and drilling the most recent exploration well, the B3 well.
Block 9 - Capital expenditures during the quarter and year-to-date were $4.0 million and $14.6 million, respectively. Expenditures were for the tie-in of the Bangora-3 well, for well testing and for upgrading of the production facility. The remaining forecast capital spending for fiscal 2009 includes continued well testing.
Feni and Chattak - Capital expenditures during the quarter of $0.1 million and year-to-date of $0.6 million were primarily for carrying costs of the blocks. Future drilling activities at Feni and Chattak have been postponed pending resolution of overdue payment for gas owed to the Company by the Government of Bangladesh.
Capital expenditures of $21.8 million during the quarter and $22.7 million year-to-date were primarily for the acquisition of 2,000 square kilometers of 3D seismic. Remaining forecast capital expenditures for fiscal 2009 are for the completion of the seismic data acquisition.
Capital expenditures during the quarter of $2.2 million and year-to-date of $20.4 million were primarily for various bonuses required as per the PSC. Remaining forecast capital expenditures for fiscal 2009 include various payments under the PSC and acquisition of 350 to 400 kilometers of 2D seismic data.
Capital expenditures during the quarter and year-to-date were $5.1 million and were related to the acquisition and reprocessing of existing 2D seismic data.
Capital spending during the quarter of $5.7 million was for bonuses payable upon signing the PSCs. Year-to-date expenditures of $16.3 million also include the purchase of a seismic data package.
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