Niko Resources Ltd.
TSX : NKO

Niko Resources Ltd.

November 09, 2006 08:45 ET

Niko Resources Announces 2nd Quarter Financial Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 9, 2006) - Niko Resources Ltd. (TSX:NKO) reports results for the three and six months ended September 30, 2006.

OPERATIONAL AND FINANCIAL HIGHLIGHTS

OPERATIONAL

- The MG-1 well in the D6 Block encountered two new high potential natural gas zones

- D6 natural gas development on track for start up in mid-2008

- Submitted application for commerciality for the MA-1 discovery and target for first production in mid-2008

- Block 9 added 45 billion cubic feet (Bcf) proved and 35 Bcf probable reserves (year to date 99 Bcf proved and 36 Bcf probable)

- Bangora-2 well tested at rates over 40 million cubic feet (MMcf) per day

- Seismic operations commenced at Cauvery

- 3D seismic program was completed in Thailand



Three months ended Six months ended
September 30 September 30

2006 2005 2006 2005

FINANCIAL

(thousands of dollars,
except per share amounts)
Oil and natural gas revenue 28,129 32,899 57,756 65,605
Funds from operations 15,535 18,648 30,235 39,195
Per share, diluted ($) 0.39 0.47 0.77 1.00

Net (loss) income (11,117) 4,393 (22,743) 8,736
Per share, diluted ($) (0.28) 0.11 (0.58) 0.22
Capital expenditures (30,240) (30,306) (39,537) (49,417)

OPERATIONS
Average daily production
Oil and condensate (bbls/day) 261 85 313 99
Natural gas (MMcf/day) 85 84 87 84
---------------------------------------------------------------------------
Total combined (Mcfe/day) 86,500 84,660 88,797 85,038
Revenues, royalties and operating costs
Gross revenue received ($/Mcfe) 3.53 4.22 3.55 4.22
Royalties ($/Mcfe) (0.21) (0.56) (0.22) (0.53)
Profit petroleum ($/Mcfe) (0.65) (0.50) (0.62) (0.48)
Operating costs ($/Mcfe) (0.34) (0.26) (0.37) (0.27)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating netback ($/Mcfe) 2.33 2.90 2.34 2.94
Drilling activity
Gross wells 2 3 2 5
Net wells 1.2 1.4 1.2 2.5
---------------------------------------------------------------------------


Mcfe is a measure used throughout this report. Mcfe is derived by converting oil and condensate to natural gas in the ratio of 1 bbl: 6 Mcf. A Mcfe conversion of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. The Company's activities are carried out primarily in U.S. dollars as well as the currencies of each country in which the Company operates. The Company reports financial results in Canadian dollars.

THE SELECTED FINANCIAL INFORMATION PRESENTED ABOVE IS PREPARED IN ACCORDANCE WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP), EXCEPT FOR FUNDS FROM OPERATIONS AND FUNDS FROM OPERATIONS PER SHARE, WHICH ARE USED BY THE COMPANY TO ANALYZE THE RESULTS OF OPERATIONS AND LIQUIDITY. BY EXAMINING FUNDS FROM OPERATIONS, THE COMPANY IS ABLE TO DETERMINE ITS ABILITY TO FUND FUTURE CAPITAL PROJECTS AND INVESTMENTS. FUNDS FROM OPERATIONS IS CALCULATED AS CASH FLOWS PRIOR TO THE CHANGE IN NON-CASH WORKING CAPITAL AND LONG TERM ACCOUNTS RECEIVABLE RELATED TO OPERATING ACTIVITIES. FUNDS FROM OPERATIONS IS NOT AN ALTERNATIVE TO CASH FLOW FROM OPERATING ACTIVITIES AS DETERMINED IN ACCORDANCE WITH CANADIAN GAAP AND MAY NOT BE COMPARABLE WITH THE CALCULATION OF SIMILAR MEASURE FOR OTHER COMPANIES. FUNDS FROM OPERATIONS PER SHARE-DILUTED IS CALCULATED BY DIVIDING THE FUNDS FROM OPERATIONS BY THE WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING.

THE FISCAL PERIOD FOR THE COMPANY IS THE 12 MONTHS ENDED MARCH 31 OF EACH YEAR. THE TERM "FISCAL 2006" IS USED THROUGHOUT THIS REPORT AND REFERS TO THE PERIOD FROM APRIL 1, 2005 THROUGH MARCH 31, 2006. THE TERM "FISCAL 2007" IS USED THROUGHOUT THIS REPORT AND REFERS TO THE PERIOD FROM APRIL 1, 2006 THROUGH MARCH 31, 2007.

OPERATIONS REVIEW

OPERATIONS UPDATE

India

In the D6 Block, drilling operations resumed with the arrival of the Deepwater Frontier deepwater drilling rig. Drilling commenced in late July 2006 with the MG-1 well. The MG-1 well was drilled in the deepest water (1,943 metres) and reached the deepest depth (6,153 metres) of any well drilled to date in the D6 block. Evaluation of the well indicates two new high potential natural gas zones have been encountered in the Pliocene and the Miocene intervals. These natural gas zones have not been discovered in previous drilling and extend the known natural gas further into the deeper-water area of the prolific D6 block.

The MG-1 well was also targeting the potential of another Mesozoic section not encountered in the MA-1 well, but recognized on seismic at the MG-1 location. This section, although having indications of hydrocarbons, was considered non-commercial and was not tested. The Mesozoic section penetrated at the MG-1 well was associated only with the MG-1 location and does not impact the Mesozoic prospectivity throughout D6 confirmed by the MA-1 well. The MG-1 well was the 19th consecutive successful well in the deepwater D6 Block.

The Deepwater Frontier rig is currently drilling the MB-1 well. The MB-1 well is an exploration well designed as a Cretaceous follow-up to the successful MA-1 discovery well. It is approximately 11 kilometres east of the MA-1 location and will test a shallower separate structure with similar targets and geologic setting as the MA-1 well. An application for commerciality has been submitted to the Directorate General of Hydrocarbons (DGH) and is expected to be approved shortly. A field development plan for the MA-1 discovery is being prepared and will be submitted once commerciality is approved. Commencement of production from the MA-1 discovery is targeted for mid-2008.

Subsequent to the MB-1 well, further drilling of Cretaceous prospects is planned to fully evaluate the Cretaceous potential in the D6 Block. Upon completion of the Cretaceous program, drilling to evaluate deeper-water prospects identified by the 2004 and 2005 3D seismic will commence, utilizing the Deepwater Frontier rig as well as the Transocean D-534 and the Deepwater Expedition rigs, which are expected to arrive in April 2007 and December 2007, respectively.

Essentially all of D6 is now covered with 3D seismic. Processing and integration of all the separate surveys are expected to be completed by year-end. The Company is looking forward to continued drilling success on this block.

The design and installation of the production facilities is well underway. Major tender packages have been issued and the civil construction of the natural gas plant site is substantially complete. Development drilling will commence in calendar 2007 using the same three-rig fleet as for the exploration drilling, along with the installation of the sub-sea manifolds, pipelines, and wellhead equipment.

In the NEC-25 Block, an eight-well drilling program is scheduled to commence in December 2006 as a follow-up to the six natural gas discoveries made to date on the block. Some of the eight drilling locations are in the original 3D seismic area, where all of the discoveries have been made to date, and the remainder will be drilled within the 1,700-square-kilometre 3D seismic area which was acquired in 2005 and 2006. The prospectivity of this block continues to be very attractive and the Company looks forward to additional discoveries. Development plans for the six discoveries, which have been declared commercial by the Indian regulatory authorities, are being prepared with a target for commencement of production in late calendar 2009.

Oil production began in Hazira in March 2006 and production during the quarter averaged 160 barrels of oil per day (net). Natural gas production from Hazira during the quarter averaged 30 million cubic feet per day (net). Production in Surat averaged 11 million cubic feet per day.

In the Cauvery Block in Southern India, where the Company holds 100 percent interest, acquisition commenced on a 550-square-kilometre 3D program. By the end of October 2006, 367 square kilometres were completed and the work was suspended with the onset of the monsoon season. This portion of the survey is currently being processed. The remainder of the 3D program will be completed in April or May 2007. A multiple-well drilling program is planned to commence in July 2007.

In the deepwater block MN-DWN-2003/1 (D4) located in the Mahanadi basin, in which Niko holds a 15 percent interest, a 2,365-kilometre 2D seismic acquisition program has been completed and the data is currently being processed. A 1,800-square-kilometre 3D seismic program is anticipated to commence in calendar 2007, followed by exploratory drilling in late 2007 or early 2008.

Bangladesh

Combined natural gas production from the three wells in the Feni field averaged 17 million cubic feet per day during the quarter.

Future drilling activities at Feni and Chattak have been postponed pending further developments in the various disputes between the Company and the Government of Bangladesh.

In Block 9, acquisition of the 620-square-kilometre 3D seismic program over the Lalmai/Bangora anticline is complete and processing is substantially complete. Production through the recently installed natural gas production and processing facilities continued throughout the quarter at an average rate of 41 million cubic feet per day (27 million cubic feet per day, net) from the Bangora-1 well. During the quarter the Bangora-2 well was tested at a combined rate of over 40 million cubic feet per day from two zones. Production from the two wells is expected to increase production to between 60 and 70 million cubic feet per day (40 and 46 million cubic feet per day, net) in November 2006. The Company anticipates commerciality to be declared in fiscal 2007, at which time the Company expects to collect the receivable owed for all natural gas and condensate produced in Block 9.

An appraisal well, Bangora-3, began drilling in July 2006 and reached total depth in early September 2006. The well encountered natural gas pay similar to that encountered in the Bangora-1 and Bangora-2 wells and the well has been completed for production and is awaiting testing. The Bangora-3 well was drilled approximately 3.9 kilometres to the south of Bangora-2 and confirms the continuity of the productive sands to the south.

At September 30, 2006, Company reservoir engineers estimated that the Company's working interest proved reserves at Block 9 had increased by 99 Bcf (328 percent) as a result of analyzing data obtained from drilling the Bangora-2 and Bangora-3 wells and production data from the Bangora-1 well. This figure is net of the Company's 66.7 percent share of the 6.4 Bcf produced from Bangora-1 during the ongoing production test. Proved plus probable reserves also increased by over 135 Bcf (195 percent) as the Bangora-3 well extended the confirmed area of natural gas reserves to the south. These figures represent increases over reserve figures determined as at March 31, 2006.

These increases to the Company's internal estimate of the proved and proved plus probable reserves for Block 9 have not yet been reviewed by an independent reserves evaluator. They are based on the Company's assumptions about Block 9, which the Company believes to be reasonable at the time they were made. At year-end, reserves reported by the Company will be those estimated by the independent reserves evaluator and these may or may not be not be exactly consistent with the Company's internal estimates.

Drilling of the Bangora-4 well commenced in October 2006 and will be followed by one or two more appraisal wells on the anticline containing the Bangora and Lalmai discoveries. Production rates are expected to increase with the tie-in of the Bangora-3 well and the drilling of additional appraisal wells.

Thailand

Acquisition of a 140-square-kilometre 3D seismic program was completed in August 2006 and processing of the data is substantially complete. Several drilling prospects have been identified by the 3D seismic program and drilling is expected to commence in January 2007 utilizing a modern, state-of-the-art drilling rig that is currently being moved to Thailand from Canada. Re-completions of the existing wells in the Mae Soon oilfield commenced in November 2006. The Company looks forward to commencing oil production from its Thailand blocks, based on the anticipated success of the re-completion and drilling programs.

FORECAST

Capital Expenditures

The following table displays capital spending during the first two quarters of fiscal 2007 and forecast capital spending for fiscal 2007. The Company revises the forecast on a quarterly basis and any changes are incorporated in the table below:



Exploration and Development Spending (net) Six months ended Estimated
(millions of dollars) September 30, 2006 fiscal 2007
---------------------------------------------------------------------------

India
Cauvery 5.0 7 - 9
D4 0.3 0.3 - 1
D6 10.0 30 - 35
Hazira 1.0 2 - 3
NEC-25 0.4 4 - 6
Surat - -
---------------------------------------------------------------------------
Bangladesh
Block 9 19.6 30 - 35
Chattak (5.9) (5.9)
Feni - -
---------------------------------------------------------------------------
Thailand
Mae Soon 1.3 5 - 7
Fang 5.2 12 - 15
Acquisition of rights 2.6 2.6
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total 39.5 87 - 108
---------------------------------------------------------------------------


India

The Company was granted a Production Exploration License for the Cauvery Block from the Government of India and performed seismic work from August until October 2006, which will be resumed when monsoon season ends. Capital expenditures in the period of $5.0 million and the remaining forecast expenditures relate primarily to the 3D seismic program.

Capital expenditures for the D4 Block in the quarter relate to the acquisition of 2,100 line kilometres of 2D seismic.

Expenditures of $10.0 million in the period for the D6 Block were for construction of the natural gas plant site and drilling the MG-1 well. Activity in the D6 block is expected to continue with the current drilling rig and further facility construction.

Hazira expenditures were for a workover and completion of oil processing and storage facilities at a cost of $1.0 million. The remaining forecast expenditures are for recompleting existing wells and potential seismic activities.

Capital expenditures for the NEC-25 Block in the period were for seismic activities and general and administrative costs. Activity is expected to increase in the NEC-25 Block with the arrival of a jack-up drilling rig that will begin drilling the eight-well program.

Bangladesh

Capital expenditures in the period for Block 9 were $19.6 million, and were related to the drilling and tie-in of Bangora-2; drilling Bangora-3; construction of natural gas processing facilities; seismic activities; engineering; and general and administrative charges. Drilling of Bangora-4 began in October 2006, and one or two additional appraisal wells are planned.

Drilling of the planned wells at Feni, Feni-6 and Feni-7, and wells in Chattak has been postponed pending further developments in the various disputes between the Company and the Government of Bangladesh. During the period, $4.0 million was received from a care, custody and control insurance policy for Chattak, and was a credit to capital additions. In addition, a vendor discount on previously recorded services was realized, resulting in a credit to capital additions of $5.3 million. There was $3.4 million spent on inventory, additional costs associated with the blowout and insurance premiums related to the blowout. The result is net capital reduction of $5.9 million.

Thailand

Thailand costs in the six months ended September 30, 2006 totalled $9.1 million, including $3.9 million for 3D seismic on the Fang property, $2.6 million paid to the operator for costs of acquiring the rights as specified in the agreements and $2.6 million for general and administrative costs and front-end costs associated with the planned workovers in Mae Soon and drilling in Fang. Forecast expenditures for Fiscal 2007 include the 3D seismic, recompletions of existing wells in the Mae Soon oil field, which commenced in November 2006, and drilling of several exploratory drilling prospects as defined by the 3D seismic program commencing late in the third quarter of fiscal 2007.

Production

The following table displays production in the first quarter of fiscal 2007 and forecast production for fiscal 2007. The Company revises the forecast on a quarterly basis and any changes are incorporated in the table below.



Net Production Six months ended Lower estimate Upper estimate
(Daily average) September 30, 2006 fiscal 2007 fiscal 2007
---------------------------------------------------------------------------
Natural Gas (MMcf/d)
India
Hazira 34 30 35
Surat 11 10 12
Bangladesh
Block 9 23 25 30
Feni 19 14 16
Oil (bbls/d)(1)
India
Hazira 218 200 220
---------------------------------------------------------------------------
Total (MMcfe/d) 89 80 94
---------------------------------------------------------------------------

(1) Less than 2 percent of total corporate volumes and revenues are from
Canadian oil, Bangladesh condensate, Bhandut oil, Sabarmati oil and
Hazira condensate production. Therefore, the results from Canadian oil,
Bangladesh condensate, Bhandut oil, Sabarmati oil and Hazira condensate
production are not discussed separately.


The Company had average natural gas production from Hazira of 30 and 34 million cubic feet per day (net) for the three and six months ended September 30, 2006, respectively. The Company expects decreases in production due to natural declines to continue at Hazira and is forecasting average natural gas production for fiscal 2007 of 30 to 35 million cubic feet per day (net). Oil production from Hazira in the quarter and year-to-date was 160 and 218 barrels per day (net), respectively, and the Company expects oil production to increase through pressure maintenance from water injection for a forecast of 200 to 220 barrels per day (net) for fiscal 2007.

Consistent with production in the first quarter and year-to-date, production at Surat is forecast to remain stable at 10 to 12 million cubic feet per day for fiscal 2007.

Production from Block 9 began in May 2006 from one well, Bangora-1. Drilling of Bangora-2 and Bangora-3 has been completed and the production forecast for the year incorporates increases expected when Bangora-2 begins production. As a result of the current producing well and expected production rates from Bangora-2, the Company has forecast average production for Fiscal 2007 from Block 9 of 25 to 30 million cubic feet per day (net).

Feni production was 17 and 19 million cubic feet per day for the three and six months ended September 30, 2006, respectively. The Company expects the natural declines in Feni production to continue until the compression equipment can be placed into service and has a forecast for fiscal 2007 of 14 to 16 million cubic feet per day. Placing compression equipment into service has been postponed pending further developments in the various disputes between the Company and the Government of Bangladesh.

Operating Expense Outlook

During the quarter and year-to-date in fiscal 2007, operating costs averaged $0.34 and $0.37 per MMcfe, respectively, and are anticipated to average $0.35 to $0.40 per MMcfe in fiscal 2007. The forecast operating costs are consistent with those estimated in the previous quarter.

OVERALL PERFORMANCE

Funds from operations

Daily production in the quarter increased by two percent from the prior year to 87 million cubic feet equivalent per day as volumes from Block 9 more than offset natural field declines at Hazira and Feni. Block 9 production in the quarter was 41 million cubic feet per day (27 million cubic feet per day net).

Even though volumes increased by two percent, revenues net of royalties decreased by $2.1 million in the quarter ended September 30, 2006 from the same period in the prior year as the Company realized a lower average price in the quarter. The lower reported realized price is due primarily to Feni natural gas being accrued at US$1.75 per Mcf in the quarter compared to US$2.20 per Mcf in the same period in the prior year, and also due to the prevailing market price in Bangladesh, which is applicable to Block 9 production, being lower than in other countries. In addition, the Company receives its revenues in U.S. dollars, and the strengthening Canadian dollar over the past year also reduced reported revenue.

Profit petroleum expense increased by $1.3 million in the quarter ended September 30, 2006 from the same period in the prior year. Profit petroleum expense increased as a percentage of revenue largely due to the addition of Block 9 volumes where the Government of Bangladesh was entitled to a 39 percent share of the profit petroleum during the quarter. The Government of India was entitled to 20 percent of the profit petroleum for the Hazira field. At Feni, the Government of Bangladesh was entitled to 20 percent of revenues for April and May and 25 percent of revenues for June through September 2006. No profit petroleum expense was incurred with respect to the Surat field in India.

Production expenses were $0.7 million higher in the quarter ended September 30, 2006 than in the same period in the prior year, due primarily to the commencement of production from Block 9. Current income taxes increased by $0.8 million due to lower deductions for the tax in India, partially offset by a decrease in taxes for the reduced revenues in Bangladesh. There was a positive effect on income as there was a realized foreign exchange loss of $1.3 million in the prior year with no corresponding gain or loss in the current year.

In the six months ended September 30, 2006, production increased with the addition of production from Block 9 in May 2006, which more than offset natural field declines at Hazira and Feni. Revenues net of royalties decreased by $3.3 million as the Company realized a lower average price than in the same period in the previous year. Profit petroleum expense increased by $2.5 million with the addition of Block 9 production, partially offset by decreases at Hazira and Feni resulting from lower revenues. Production expenses increased by $1.8 million with the addition of Block 9 operating expenses and oil production in Hazira. In addition, the foreign exchange loss increased by $0.5 million from the same period in the previous year due to strengthening of the Canadian dollar compared to the U.S. dollar applied to U.S. dollar-held cash and receivables. Finally, current taxes increased by $0.8 primarily for additional taxes in India.

Net (loss) income

The reported loss for the quarter ended September 30, 2006 is $11.1 million compared to net income of $4.4 million in the same period in the prior year, a change of $15.5 million. A reduction in funds from operations, as discussed above, accounts for $3.1 million of this change.

The increase in the Company's stock-based compensation expense accounts for a further $4.4 million of the change and is due to additional options issued in January and June 2006 as well as to a change in the vesting structure resulting in increased expense at the beginning of the vesting period.

Depletion, depreciation and accretion expense for the quarter increased by $7.8 million to $21.2 million. The increase is due to a two percent increase in production and a 55 percent increase in the depletion rate per Mcfe. The primary reason for the rate increase is the previously announced downward revision to reserves at the Hazira field, which was reported in the Company's fiscal 2006 results. In Bangladesh, the depletion rate in the quarter ended September 30, 2006 benefited because the Company increased its internal estimate of proved reserves for Block 9 by 99 Bcf year-to-date after analyzing the data from drilling the Bangora-2 and Bangora-3 wells and the production data from the Bangora-1 well. The increase to the Company's internal estimate of the proved reserves for Block 9 has not been reviewed by an independent reserves evaluator and is based on the Company's assumptions about Block 9. The Company believes these assumptions to be reasonable at the time they were made, but they may not be consistent with actual results.

In the six months ended September 30, 2006, the reported loss is $22.7 million compared to net income of $8.7 million in the same period in the prior year. In addition to a reduction in funds from operations, as discussed above, there was an increase in stock-based compensation expense of $6.8 million and an increase in depletion, depreciation and accretion expense of $15.0 million.

Certain statements in this press release are forward-looking statements. Specifically, this press release contains forward-looking statements relating to management's approach to operations, estimates of future sales, production and deliveries, business plans for drilling and development, estimated amounts and timing of capital expenditures, anticipated operating costs, royalty rates, cash flows, transportation plans and capacity, anticipated access to infrastructure or other expectations, beliefs, plans, goals, objectives, assumptions and statements about future events or performance. The reader is cautioned that the assumptions used in the preparation of such information, although considered reasonable by Niko at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the results of exploration and development drilling and related activities; the uncertainty of estimates and projections relating to productions, costs and expenses; uncertainties as to the availability and cost of financing; fluctuations in currency exchange rates; the imprecision in reserve estimates; risks associated with oil and gas operations, such as operational risks in exploring for, developing and producing crude oil and natural gas; risks and uncertainties involving geology of oil and gas deposits; the weather in the Company's area of operations; the ability of suppliers to meet commitments; changes in environmental and other regulations; actions by governmental authorities including changes in laws and increases in taxes; decisions or approvals of administrative tribunals; risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action in countries such as India and Bangladesh); the effect of acts of, or actions against international terrorism; and other factors, many of which are beyond the control of Niko. There is no representation by Niko that the actual results achieved during the forecast period will be the same in whole or in part as those forecast.

Contact Information

  • Niko Resources Ltd.
    Edward Sampson
    Chairman of the Board, President & CEO
    (403) 262-1020
    or
    Niko Resources Ltd.
    Murray Hesje
    Vice President Finance & CFO
    (403) 262-1020