Niko Resources Posts Results for Year Ended March 2009
Niko Resources has reported its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the fiscal year ended March 31, 2009 ("fiscal 2009"). The operating results are effective June 22, 2009.
PRESIDENT'S REPORT TO THE SHAREHOLDERS
The start-up of the D6 oil and gas projects has fundamentally changed the Company. As a result, Niko expects fiscal 2010 sales volumes to average over 269 MMcfe/d, which is a 217 percent improvement over fiscal 2009. We are proud to have achieved this step-change while maintaining a strong balance sheet. In fact, at March 31, 2009 the Company's cash exceeded its debt.
In addition to development activity, Niko also made a significant change in the diversity and opportunity in our exploration portfolio. We entered the fiscal year with nine active exploration blocks in two countries and are now actively pursuing opportunities in our 19 exploration blocks in five countries.
In addition to the significant increase in forecasted sales volumes for fiscal 2010 compared to fiscal 2009, we expect to receive approval for the development of the D6 satellite fields and the NEC-25 discoveries.
We will also actively explore in the coming year. Seismic and drilling activity is planned in multiple blocks. It will be the largest program in the Company's history.
- Production from the D6 gas field began subsequent to the end of the fiscal year, in April 2009, and current production is averaging in excess of 1,000 MMcf/d (100 MMcf/d working interest to Niko), which is over 35 percent of the 2,800 MMcf/d (280 MMcf/d working interest to Niko) target that is now expected before calendar year-end.
- D6 oil production commenced in September 2008 and expected peak liquids production is 40,000 bbls/d (4,000 bbls/d working interest to Niko).
- The development plan for the D6 satellite fields was submitted in July 2008.
- Facilities upgrades during fiscal 2009 at Block 9 have resulted in a 21 percent year-over-year increase in Niko's share of natural gas production, to 54 MMcf/d for the year.
- At D6, the L1 well was the first significant discovery in the Pleistocene channel complex. Drilling of this well concluded in the second quarter of fiscal 2009. The AR2 gas discovery was drilled in April 2009, the AS1 well finished being drilled in May 2009 and the BA2 well is currently being drilled.
- At Cauvery, the Khoja-1 well is currently being drilled.
- At NEC-25, the NEC-AJ2 well is currently being drilled.
- 3D Seismic activity in:
- Kurdistan; and
- In Indonesia, Niko signed production sharing contracts (PSC) in November 2008 and May 2009 resulting in interests in 8 blocks and 40,000 square kilometers of gross acreage in Indonesia. Niko's working interests in these blocks range from 25 percent to 67 percent with an average of 37 percent.Niko farmed-in to a 16,845 square kilometer block in Madagascar in October 2008 whereby it will operate and earn a 65 percent participating interest.
- Niko signed a PSC in the Kurdistan Region of Iraq in May 2008 whereby it will operate and currently has a 36 percent participating interest in the 846 square kilometer Qara Dagh block.
PRODUCTION AND DEVELOPMENT
From a reserve perspective, the highlight for the year was in moving undeveloped reserves to the developed reserves category, which enables a substantial ramp-up in production and operating cashflow for fiscal 2010 and beyond.
Overall, proved plus probable reserves were relatively flat year over year. For the potential development plans referred to below, the Company will add to its reserve base.
The Company developed 37 percent of its total proved plus probable reserves during the year. The development was primarily in the D6 Blocks and also included the tie-in of an additional well in Block 9. Development costs of US$368 million were incurred during the year to develop reserves. The Company has forecast spending at US$236 million in fiscal 2010 to further develop reserves.
D6 Block -- MA Oil Development: A portion of the reserves from the MA discovery was reclassified to developed with the commencement of oil production from the field in September 2008. The revised field development costs, excluding the capital cost of the FPSO as it is currently being leased, are budgeted at US$1.9 billion (US$194 million net to the Company) and the Company had spent US$119 million of this amount at March 31, 2009. 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.
D6 Block -- Dhirubhai 1 and 3 Gas Development: Commencement of production from the Dhirubhai 1 and 3 discoveries occurred in April 2009 and a significant portion of the reserves was reclassified to developed. The Phase I costs (costs to bring production to 2.8 Bcf/d, which is 280 MMcf/d working interest to the Company) are budgeted at US$6.3 billion (US$627 million net to the Company). The Company had spent US$479 million of this amount to March 31, 2009. Costs will be incurred after start-up to tie in the remaining wells. Additional reserves will move from undeveloped to developed upon completion of Phase I. The then remaining undeveloped reserves will move to developed reserves over the life of the field as additional wells are drilled and compression is added.
Potential Future Developments
A field development plan has been submitted to the Government of India for nine natural gas discoveries in the D6 Block in addition to the Dhirubhai 1 and 3 gas discoveries. The discoveries are adjacent to the Dhirubhai 1 and 3 gas fields that are currently producing. If the development plan is approved, it is intended that these satellite discoveries be tied back to the Dhirubhai 1 and 3 facilities.
For the NEC Block, a development plan has been submitted for the six natural gas discoveries that have been declared commercial by the Indian regulatory authorities.
Gas production from the Dhirubhai 1 and 3 gas fields commenced in April 2009 and is expected to increase average Company production for the year ending March 31, 2010 to 269 MMcfe/d, which is a 217 percent increase over fiscal 2009. Production from the Dhirubhai 1 and 3 gas fields is currently averaging in excess of 1,000 MMcf/d (100 MMcf/d working interest to the Company) and is targeted to reach 2,800 MMcf/d (280 MMcf/d working interest to the Company) before calendar year-end. Average oil production from the MA field for fiscal 2009 was 2,781 Bbls/d (279 Bbls/d working interest to the Company) and is targeted to reach 38,000 Bbls/d (3,800 Bbls/d working interest to the Company) before March 31, 2010. Sales from the MA field during the year were 88,000 BBls working interest to the Company. Production from Block 9 was 55 MMcfe/d during the year and is expected to increase to over 100 MMcf/d (60 MMcf/d working interest to the Company) in fiscal 2010. Production from the Hazira and Surat fields was 57 MMcfe/d (26 MMcfe/d working interest to the Company). The forecast production is consistent with the Company's reserve report for these fields.
The Company has been successful in adding exploration blocks to its portfolio. As shown above, ten blocks have been added since March 31, 2008 and the Company is now active in 19 exploration blocks in five countries. The Company operates 11 of the blocks: two in India; four in Pakistan; one in Madagascar; one in Kurdistan and three in Indonesia.
Exploration During Fiscal 2009
Since March 31, 2008, the Company has participated in drilling four exploration wells in India: the L1, MK1 and AR2 wells in the D6 Block and the B3 well in the NEC-25 Block. The L1 well encountered significant quantities of hydrocarbons and the MK1 well was not successful. The AR2 well is located in water depth of 1,844 meters and is approximately 5.7 kilometers northwest of the R1 late Miocene gas discovery in the D6 Block. The well extended the gas accumulation originally discovered by the R1 well and as a result enhanced the potential natural gas resource in this area. The B3 well was drilled in 64 meters of water to a total true vertical depth of 3,928 meters and encountered a gas zone at 1,900 meters. The Company has not updated its contingent resources to take into account these discoveries.
During the year, the Company completed a 3,600-square-kilometer 3D seismic survey in the D4 Block in India; a 1,000-square-kilometer 3D seismic survey in the NEC-25 Block in India; a 30-square-kilometer transition zone 3D seismic survey in the Hazira Block in India; a 2,000-square-kilometer 3D seismic survey in Pakistan; and reprocessing of 7,600 kilometers of 2D seismic in Madagascar. The Company is currently nearing completion of a 350-kilometer 2D seismic program in Kurdistan.
The Company expects to spend US$121 million to complete the planned exploration work program for the year ending March 31, 2010. The chart below shows the planned work program for fiscal 2010 and the tentative work program until December 31, 2011. With the exception of D6, NEC-25 and Hazira Blocks, the activity shown on the chart below is based on the minimum work commitments under PSC/PSAs. The chart also includes wells that are expected to be drilled by other companies in the same geological basin as the Company's acreage.
D6 Block: The Company is currently drilling the BA2 and AS1 wells. The company expects a continuous drilling program on numerous prospects within the block.
D4 Block: The initial interpretation of the data within the 3,600 square kilometer 3D seismic survey acquired has identified several areas of interest, which will be fully analysed as part of the ongoing evaluation. Processing and interpretation of the data are expected to be completed in time for the Company to meet the drilling schedule shown above.
Cauvery: The The Khoja-1 well spud in April 2009 and has a planned true vertical depth of 4,100 meters. The primary target of the well is the Cretaceous-Jurassic-Basement interval. Drilling of the well planned in the second quarter of fiscal 2010 is contingent on the results of the Khoja-1 well.
Hazira Block: The 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 is to be initiated as shown above.
NEC-25 Block: Approximately 1,000 square kilometers of 3D seismic have been acquired along the central portion of the northwest boundary of the previous 3D surveys. The AJ2 well is currently being drilled to delineate the J1 discovery.
The 3D seismic program acquired during fiscal 2009 is expected to identify stratigraphic potential, resolve structural complexity and indicate the presence of hydrocarbons. Processing of the 3D data should be completed in the third calendar quarter of 2009 with interpretation and selection of drilling locations to follow.
Interpretation of the reprocessed 2D seismic and further evaluation of the block is planned including a high-resolution multi-beam survey and sea floor coring program intended to identify sea floor oil and gas seeps. Future work as prescribed in Phase II includes the acquisition of a 3D seismic program to be designed based on results of the 2D seismic reprocessing and the multi-beam survey. The Company expects to drill a well in the first quarter ending June 30, 2011.
The 2D seismic program is currently being acquired over the surface structure that dominates the Qara Dagh block. Processing has commenced and interpretation will follow once final processed sections are received. Interpretation of the data is expected to resolve the sub-surface structural picture and characterize potential reservoir sections leading to the selection of a drilling location. Drilling is expected to commence in the first quarter of fiscal 2011.
Niko has acquired several blocks in deepwater offshore Indonesia. Indonesia has long been a prolific oil and gas producing nation with very large reserves, however, the deepwater areas have remained essentially unexplored. All blocks have sea bottom oil and gas seeps, large structural or stratigraphic features and several have direct indication of hydrocarbons on seismic.
The well commitment for each block will follow seismic interpretation. The seismic program planned for each block is outlined below.
Bone Bay: The seismic program planned for the block includes acquisition of 3,000 kilometers of 2D seismic.
Cendrawasih: The seismic program planned for the block includes acquisition 1,200 square-kilometers of 3D seismic, which will cover 24 percent of the 5,000 square kilometer block.
Kofiau: The seismic program planned for the block includes acquisition of 1,062 kilometers of 2D seismic and 3,150 square kilometers of 3D seismic, which will cover 60 percent of the 5,000 square kilometer block.
Kumawa: The seismic program planned for the block includes acquisition of 3,000 kilometers of 2D seismic.
Seram: The seismic program planned for the block includes acquisition of 3,500 kilometers of 2D seismic.
South Matindok: The seismic program planned for the block includes acquisition of 4,400 kilometers of 2D seismic.
Southeast Ganal: The seismic program planned for the block includes acquisition of 284 kilometers of 2D seismic and 2,700 square kilometers of 3D seismic, which will cover over 50 percent of the 5,000 square kilometer block.
West Sageri: The seismic program planned for the block includes acquisition of 371 kilometers of 2D seismic and 702 square kilometers of 3D seismic, which will cover 14 percent of the 5,000 square kilometer block.
During the year ended March 31, 2009, operating expenses averaged US$0.40/Mcfe. Operating expenses increased during the year due to the start-up costs related to the commencement of D6 oil production and are anticipated to fall significantly on a unit-of-production basis once the D6 gas field is producing at designed capacity.
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