QUARTERLY PRODUCTION ANNOUNCEMENT
FOR THE PERIOD ENDED 31 MARCH 2000
1 Highlights
Year-to-date gas sales of 148.1 bcf are up 19 per cent on the corresponding period in the previous financial year.
Maui gas sales continued at high levels. Sales of 26.3 bcf were four per cent above the corresponding quarter in
1998/99.
Canadian gas sales year to date were 7.5 per cent higher than the corresponding period in the 1998/99 year.
Maharaja Lela field in Brunei completed its first full year of production.
Continued strong growth in Canadian oil production with the completion of several additional heavy oil developments.
The Pohokura-1 exploration well produced 17 mmscf/day of gas and 68 bbl of condensate per mmscf under test. An
appraisal well is currently under consideration by the Pohokura Joint Venture partners with drilling expected to begin
no later than May.
The Brunei exploration campaign commenced with the spudding of Bendahara Selatan A1 (BSA-1). The BSA-1 well is the
first in a minimum 3 well exploration programme. The well will test the oil and gas potential of multiple reservoirs
over an interval of 3,000m.
2 Sales
Sales March
Quarter
FY 2000 March
Quarter
FY 1999
YTD
FY 2000
YTD
FY 1999
Natural Gas (bcf)
NZ Offshore (1) 26.3 25.3 83.7 74.0
NZ Onshore 4.0 4.0 12.8 12.6
North America 13.8 13.2 40.3 37.5
Brunei 4.1 0.5 11.3 0.5
Total 48.2 43.0 148.1 124.6
Condensate (000 bbls)
NZ Offshore 1,133 1,727 3,576 4,125
Brunei 60 15 222 15
Total 1,193 1,742 3,798 4,140
Oil (000 bbls)
NZ Offshore 633 1,029 1,331 2,194
NZ Onshore 482 786 1,827 2,421
North America 1,399 1,292 3,882 4,001
Total 2,514 3,107 7,040 8,616
LPG (000 tonnes)
NZ Offshore 23 21 80 76
NZ Onshore 4 6 14 15
Total 27 27 94 91
Total Sales (mboe) (2)
NZ Offshore 6,377 7,182 19,655 19,412
NZ Onshore 1,195 1,513 4,106 4,671
North America 3,699 3,495 10,599 10,254
Brunei 743 98 2,105 98
Total 12,014 12,288 36,465 34,435
(1) Pre-paid gas treated as not yet produced
(2) A conversion factor of 6bcf:1mmboe is utilised in calculating the oil equivalence of gas
Because of movements in oil and condensate inventory levels, the sales numbers disclosed above do not always accurately
reflect actual production. Where these movements have been material production numbers are disclosed in the following
table.
Production
Total Production March
Quarter
FY 2000 March
Quarter
FY 1999
YTD
FY 2000
YTD
FY 1999
Condensate (kbbls)
NZ Offshore 1,268 1,381 3,922 4,185
Brunei 99 15 265 15
Total 1,367 1,396 4,187 4,200
Oil (kbbls)
NZ Offshore 395 645 1,347 2,389
NZ Onshore 507 786 1,754 2,421
North America 1,399 1,292 3,882 4,001
Total 2,301 2,723 6,983 8,811
Total Production (mboe)
NZ Offshore 6,275 6,452 20,017 19,667
NZ Onshore 1,220 1,513 4,033 4,671
North America 3,704 3,495 10,599 10,254
Brunei 782 98 2,148 98
Total 11,981 11,558 36,797 34,690
Daily Sales
Average Daily Sales March
Quarter
FY 2000 March Quarter
FY 1999
YTD
FY 2000
YTD
FY 1999
Natural Gas (mmscf/day)
NZ Offshore 289 281 304 270
NZ Onshore 44 44 47 46
North America 152 147 147 137
Brunei 45 6 41 2
Total 530 478 539 455
Condensate (bopd)
NZ Offshore 12,453 19,189 13,004 15,055
Brunei 659 167 807 55
Total 13,112 19,356 13,811 15,110
Oil (bopd)
NZ Offshore 6,953 11,433 4,839 8,007
NZ Onshore 5,297 8,733 6,644 8,836
North America 15,374 14,360 14,116 14,600
Total 27,624 34,526 25,599 31,443
LPG (tonnes/day)
NZ Offshore 251 233 290 277
NZ Onshore 45 67 51 55
Total 296 300 341 332
Total Sales (boe/day)
NZ Offshore 70,079 79,800 71,472 70,847
NZ Onshore 13,062 16,807 14,910 17,047
North America 40,648 38,833 38,541 37,362
Brunei 8,168 1,089 7,656 358
Total 131,957 136,529 132,579 125,614
3 Production and Development Activities
(i) New Zealand Offshore
Gas sales during this quarter were 26.3 bcf; the same level as the previous (December 1999) quarter, and 1.0 bcf higher
then the corresponding quarter of the 1998/99 year. Methanex operated at close to maximum capacity. The electricity
sector has continued to take at high rates as a consequence of low rainfall for hydro-generation and the ongoing effects
of the electricity sector restructuring. Year-to-date Maui gas sales are 13.1 per cent above the corresponding period in
the previous financial year.
Condensate sales were 1.133 mmbl for the quarter, an increase of 0.044 mmbl on the previous quarter, but down by 34 per
cent on the corresponding quarter of 1998/99. The improvement for this quarter over the previous one is attributed to
higher Maui B operating availability. This enables its higher condensate-yielding wells to be produced in preference to
the lower condensate-yielding Maui A wells. The decline in condensate over the same period last year is due to the
natural depletion of the higher condensate yielding reservoir zones.
Maui B oil sales were 0.633 mmbl for the quarter, which is up from 0.308 mmbl for the previous quarter. This increase is
as a result of sales scheduling rather than a change production fundamentals. Production of 0.395 mmbl for the quarter,
is down 0.028 mmbl from the previous quarter.
The first oil from the Maui BD incremental oil development programme is not expected until May. This delay of one month
is due to complications encountered during the drilling operations.
(ii) New Zealand Onshore
The Toetoe-6 well was successfully completed as a future gas producer. Geological results have been incorporated into
the structural model and reserves re-determined. As a result, the McKee reserves are likely to be downgraded by
approximately 7 mmbls oil and a further 7 mmboe of gas. Despite this downgrade the field is estimated to have a further
8-11 years of life with an increasing emphasis on gas rather than oil production.
The sales gas volumes of 4.0 bcf were down 0.4 bcf from the December 1999 quarter, but is the same as the corresponding
quarter in 1998/99.
Oil production was 0.482 mmbl, down 50,000 bbl from the previous quarter, and down 39 per cent (or 304,000 bbl) from the
corresponding quarter in 1998/99. This is a direct result of the declining production rates from the fields.
LPG sales were 4,000 tonnes, the same as the previous quarter.
(iii) Canada
Oil production for the third quarter averaged 15,374 bopd, an increase of 17 per cent from the previous quarter, and up
seven per cent from the corresponding period in the prior year. Heavy oil production has increased significantly with
all the previously shut-in wells now back on full production, and additional heavy oil developments in the Saskatchewan
District have also been completed.
Light oil developments in Central Alberta have contributed an additional 500 bopd of premium oil. In the Provost
District, light oil development in the Viking zone at Hamilton Lake added 100 bbls/day of production, and a new well at
Wolf Creek in the Central District is producing 300 bbls/day. Workovers at the Bashaw D3A unit in the Central District
have added a further 100 bbls/day.
Gas production for the period averaged 152 million cubic feet per day, an increase of three per cent on both the
previous quarter and the corresponding period in the prior year. In the Provost District, the increase is mainly
attributable to eight wells at Monitor, which were drilled in the second quarter and have now been tied in to the
Monitor plant. Additional tie-ins of previously drilled wells in Bashaw and W5 in the Central District have also
contributed to the increase in production.
(iv) Brunei
On March 31st 2000, Maharaja Lela successfully completed 12 months of production, meeting obligations under the Gas
Supply Agreement with BLNG.
4 Exploration and Appraisal Activities
(i) New Zealand
The Pohokura-1 exploration well was drilled and tested during this quarter. It encountered a gross hydrocarbon column of
130metres, 50 metres of which are net. Two zones were tested. The shallower zone flowed up to 17 mmscf/day of gas, at a
condensate-to-gas ratio of 68 bbl per mmscf, from a 17m interval.
Pending formal JV approval, a Pohokura field appraisal well is expected to spud in early May utilising the Ensco-50 rig
which is currently still on site. Subject to successful appraisal, reserves bookings are possible by mid calendar 2000,
coincident with the commencement of gas commercialisation efforts.
(ii) Canada
Fletcher Challenge Energy Canada drilled 11 successful net exploration wells during the quarter of which three were
completed as oil wells and eight were completed as gas wells. In addition, 30 successful development wells were drilled,
of which 18 were completed as oil wells and 12 as gas wells.
(iii) Brunei
An offshore exploration drilling programme in Blocks A and CD was approved by the FCL Board in February. Drilling
commenced with Bendahara Selatan A, on 15 April 2000. A minimum of three wildcat wells will be drilled with a further
two follow up wells possible. These wells will explore for oil and gas in Pleistocene, Pliocene and Miocene environments
down to depths of circa 4600m True Vertical Depth Sub- Sea, with Japan Drilling Company’s semi submersible rig
“Hakuryu-3”.
(iv) Argentina
Two exploration wells were drilled during the quarter: Ramblon Verde x-1 was cased with a non-commercial Loma Montosa
oil pay zone, and Puesto Lujan x-1 was dry and abandoned.
A 200 sq km 3D program on the northwest corner of the block has been acquired and is currently being processed. The
survey will delineate a paleo-valley complex, which is similar to the El Medanito oil field where very large volumes of
oil are trapped. Any further drilling will await the interpretation of this 3D.
The operator, Chevron San Jorge, is implementing a commercialisation and development plan. The latter will include
additional drilling as well as the construction of processing facilities and pipelines.
A summary of exploration and development costs incurred during the quarter is set out in the following table:
NZ$ ‘000s Exploration Costs Development Costs
NZ Offshore 3,959 11,633
NZ Onshore 770 1,103
North America 15,735 37,133
Brunei 1,722 -
South America 2,435 -
Total 24,621 49,869
Note: Fletcher Challenge Energy accounts for exploration expenditure on a successful efforts basis with unsuccessful
exploration expenditure being written off rather than capitalised. Expenditure classified as “Exploration Costs”
associated with successful exploration efforts will be capitalised in Fletcher Challenge Energy’s financial statements.
5 Risk Management
In line with Fletcher Challenge Energy’s stated risk management policy the following positions are current in the
forward markets. FY00 includes the full year position from July 1999.
OIL AND CONDENSATE
---------FY 00 FY 01 FY 02
WTI Put Options
Volume (mmbbls) 1.80 1.80
Average Strike US$/bbl 17.70 17.70
Average Premium US$/bbl 1.68 1.68
Quarterly settled, deferred premium Asian options
WTI Swaps
Volume (mmbbls) 8.51 2.10
Average Strike US$/bbl 16.52 15.59
WTI Collars
Volume (mmbbls) 1.56 2.28 2.28
Floor US$/bbl 16.00 18.00 18.00
Ceiling US$/bbl 21.00 21.00 21.00
Average Premium US$/bbl 0.39 0.86 0.86
Tapis Collars
Volume (mmbbls) 0.72 0.72
Floor US$/bbl 18.00 18.00
Ceiling US$/bbl 21.00 21.00
Average Premium US$/bbl 0.60 0.60
Tapis Differential
Volume (mmbbls) 3.65 1.20
Average Strike US$/bbl 0.00 -0.05
Represents the discount to WTI that Tapis product receives (negative means Tapis > WTI)
LLK Differential
Volume (mmbbls) 0.37 0.18
Average Strike US$/bbl 5.37 5.50
Represents the discount to WTI that LLK product receives
LLG Differential
Volume (mmbbls) 0.14
Average Strike US$/bbl 4.55
Represents the discount to WTI that LLG product receives
Bow River Differential
Volume (mmbbls) 0.25 0.11
Average Strike US$/bbl 3.81 3.95
Represents the discount to WTI that Bow River product receives
LLB Differential Floor
Volume (mmbbls) 0.14 0.14
Average Strike US$/bbl 4.75 4.75
Represents the maximum discount to WTI that LLB receives
Dubai Collars
Volume (mmbbls) 0.72 0.96 0.96
Floor US$/bbl 16.63 16.63 16.63
Ceiling US$/bbl 19.63 19.63 19.63
Average Premium US$/bbl 1.00 1.00 1.00
Dubai instruments are used to manage our Brunei gas price exposure
CANADIAN NATURAL GAS
FY 00 FY 01 FY 02 FY 03
NYMEX Swaps
Volume (PJ) 11.58 7.66 3.89
Average Strike US$/mmbtu 2.33 2.33 2.33
NYMEX Put Options
Volume (PJ) 3.89
Average Strike US$/mmbtu 2.36
Average Premium US$/mmbtu 0.23
AECO Swaps
Volume (PJ) 23.81 21.90 14.64 3.69
Average Strike C$/GJ 2.21 2.29 2.69 3.09
AECO Put Options
Volume (PJ) 7.29 3.69 7.26 3.07
Average Strike C$/GJ 2.95 2.95 3.15 3.15
Average Premium C$/GJ 0.29 0.29 0.38 0.38
AECO Differential
FY00 FY01 FY02 FY03
Volume (PJ) 1.44 12.15 15.40 21.78
Average Strike US$/mmbtu 0.40 0.37 0.37 0.37
FY04 FY05 FY06 FY07
Volume (PJ) 25.09 25.02 25.02 25.02
Average Strike US$/mmbtu 0.38 0.40 0.42 0.44
Represents the discount to NYMEX that AECO gas receives
For further information regarding this report, please contact:
Stephen Jones, Fletcher Challenge Energy
Telephone: (649) 525-9230 e-mail: stephen.jones@fce.co.nz
Appendix 1
District March
Quarter
FY 2000 March
Quarter
FY 1999
YTD
FY 2000
YTD
FY 1999
Natural Gas (bcf)
Saskatchewan 4.9 4.7 14.7 13.7
Central Alberta 4.1 4.3 12.1 12.7
Provost 4.8 4.2 13.5 11.1
13.8 13.2 40.3 37.5
Oil (000 bbls)
Saskatchewan 616 463 1,671 1,476
Central Alberta 323 330 868 899
Provost 460 499 1,344 1,626
Total 1,399 1,292 3,882 4,001
Average
Daily
Production March
Quarter
FY 2000 March
Quarter
FY 1999
YTD
FY 2000
YTD
FY 1999
Natural Gas (mmscf)
Saskatchewan 55 52 54 50
Central Alberta 45 48 44 46
Provost 52 47 49 41
Total 152 147 147 137
Oil (bbls)
Saskatchewan 6,772 5,144 6,073 5,383
Central Alberta 3,551 3,671 3,157 3,281
Provost 5,051 5,545 4,886 5,936
Total 15,374 14,360 14,116 14,600