Quarterly Production Announcement For The Period Ended 31 December 2000
1 Highlights
Total production for Fletcher Challenge Energy of 12.317 million barrels of oil equivalent (mmboe) for the three
months to 31 December 2000, up 5 per cent over the corresponding period in the prior year.
Gas production in Canada up 7 per cent over the corresponding period in the prior year.
Oil production in Canada up 8 per cent over the corresponding period in the prior year.
Maui oil production increased 49 per cent over the previous (June) quarter following production from the Maui BD oil
development project.
Pohokura reserves were revised upwards as a result of detailed analysis of data obtained from the Pohokura 1 and 2
wells. Reserves increased 30 per cent at the proved level to 169* bcf plus 7.6 mmb condensate, equivalent to 35.8*
mmboe. At the proved and probable (2P) level a 32 per cent upward revision occurred, increasing estimated 2P reserves to
66* mmboe net to Fletcher Challenge Energy.
* All figures net to Fletcher Challenge 33.3 per cent interest
2 Sales
Sales December
Quarter
FY 2001 December
Quarter
FY 2000
YTD
FY 2001
YTD
FY 2000
Natural Gas (bcf)
NZ Offshore (1) 27.5 26.3 58.2 57.4
NZ Onshore 4.2 4.4 8.3 8.8
North America (3) 14.4 13.5 28.8 26.5
Brunei 3.6 3.5 7.4 7.2
Total 49.7 47.7 102.7 99.9
Condensate (000 bbls)
NZ Offshore 1,129 1,089 2,250 2,443
Brunei 96 101 217 162
Total 1,225 1,190 2,467 2,605
Oil (000 bbls)
NZ Offshore 926 308 1,083 698
NZ Onshore 577 532 1,022 1,345
North America 1,306 1,210 2,639 2,483
Total 2,809 2,050 4,744 4,526
LPG (000 tonnes)
NZ Offshore 26 25 55 57
NZ Onshore 4 5 9 10
Total 30 30 64 67
Total Sales (000 boe) (2)
NZ Offshore 6,898 6,030 13,588 13,278
NZ Onshore 1,323 1,315 2,504 2,912
North America 3,703 3,460 7,436 6,900
Brunei 698 685 1,445 1,361
Total 12,622 11,490 24,973 24,451
(1) Pre-paid gas treated as not yet produced
(2) A conversion factor of 6 bcf: 1 million barrels of oil equivalent (mmboe) is utilised in calculating the oil
equivalence of gas
(3) Canadian gas volumes calculated assuming heating value of 1000 btu/scf
Note: 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 December
Quarter
FY 2001 December
Quarter
FY 2000
YTD
FY 2001
YTD
FY 2000
Condensate (000 bbls)
NZ Offshore 1,191 1,177 2,493 2,654
Brunei 74 90 192 166
Total 1,265 1,267 2,685 2,820
Oil (000 bbls)
NZ Offshore 665 789 1,109 1,744
NZ Onshore 492 788 1,018 1,635
North America 1,306 1,210 2,639 2,483
Total 2,463 2,787 4,766 5,862
Total Production (mboe)
NZ Offshore 6,698 6,233 13,857 13,743
NZ Onshore 1,240 1,373 2,501 2,814
North America 3,703 3,460 7,436 6,900
Brunei 676 674 1,420 1,365
Total 12,317 11,740 25,214 24,822
Daily Sales
Average Daily Sales December
Quarter
FY 2001 December Quarter
FY 2000
YTD
FY 2001
YTD
FY 2000
Natural Gas (mmscf/day)
NZ Offshore 299 286 316 312
NZ Onshore 46 48 45 48
North America (3) 157 147 157 144
Brunei 39 38 40 39
Total 541 519 558 543
Condensate (bopd)
NZ Offshore 12,267 11,837 12,226 13,277
Brunei 1,043 1,098 1,179 880
Total 13,310 12,935 13,405 14,157
Oil (bopd)
NZ Offshore 10,070 3,348 5,888 3,793
NZ Onshore 6,272 5,783 5,554 7,310
North America 14,195 13,152 14,342 13,495
Total 30,537 22,283 25,784 24,598
LPG (tonnes/day)
NZ Offshore 283 272 299 310
NZ Onshore 43 54 49 54
Total 326 326 348 364
Total Daily Sales (boe/day)
NZ Offshore 74,983 65,547 73,850 72,161
NZ Onshore 14,386 14,297 13,611 15,824
North America 40,243 37,609 40,410 37,498
Brunei 7,583 7,438 7,851 7,402
Total 137,195 124,891 135,722 132,885
3 Production and Development Activities
(i) New Zealand Offshore
Gas production (and sales) from Maui during the December quarter 2000 totaled 27.5 billion cubic feet (bcf), a decrease
of 3.2 bcf on the proceeding September quarter. However, this represented an increase of 1.2 bcf over the December 1999
quarter. This year-on-year increase is primarily the result of high gas take by electricity generators.
Condensate production was 1.191 million barrels (mmbbl) for the quarter, 14,000 barrels higher than the corresponding
1999 quarter. The condensate yield expected from higher year-on-year gas production was limited due to the shut-in of
high condensate yield wells on the Maui B platform, necessitated by the BD oil development project.
Maui B oil production for the December quarter was 0.665 mmbbl, an increase of 0.221 mmbbl or 50 per cent compared to
the previous quarter, but down 0.124 mmbbl or 16 per cent compared to the December 1999 quarter. The quarter’s oil
production reflects natural long-term decline, partially arrested by BD incremental oil development, plus some deferral
of production associated with weather-induced shipping delays.
The latter resulted in a storage tank tops situation for the first 10 days of October. Total deferred production during
the quarter as a consequence of this was approximately 84,000 bbls of production. Due to crude equity lifting
entitlement, this production deferral was more than offset by equity sales entitlements during the quarter.
(ii) New Zealand Onshore
Onshore gas sales were 4.2 bcf, an increase of 0.1 bcf over the previous quarter, although down 0.2 bcf over the
corresponding 1999 quarter. Onshore oil production was 0.492 mmbbl, a decrease 0.296 mmbbl (38 per cent) compared to
production in the corresponding 1999 quarter. This is a direct result of the natural decline in reservoir performance
The quarterly LPG production, from both onshore and offshore combined, at 30,000 tonnes was down 4,000 tonnes (12 per
cent) this quarter over the preceding quarter, but exactly the same as the corresponding quarter for 1999.
During the quarter, two gas sales agreements totaling 35 PJ were agreed with Methanex. The first of these, for the
supply of 15 PJ over fifteen months commencing July 2001, underwrites the initial development of the Mangahewa field, in
which Fletcher Challenge Energy holds a 100 per cent interest. Mangahewa gas plant construction was committed and
onstream date of 1 July 2001 is targeted. Capex committed to this phase of Mangahewa development amounts to $7 million.
The second gas sales agreement for 20 PJ effectively extends the prior McKee gas contract that fulfilled its contractual
delivery requirements in December 2000. Under the new contract gas deliveries will occur over a three year period,
commencing December 2001. No additional capital expenditure is required to meet delivery under this contract.
(iii) Canada
Gas production for the period averaged 157 million cubic feet per day (mmscf/d), a decrease of 1 per cent on the
previous quarter and an improvement of 7 per cent on the corresponding period in the prior year. The latest phase of the
Hatton infill programme was successfully completed in the second quarter, with a total 61 development wells being
drilled and completed in the first six months, adding incremental production of 2.8 mmscf/d. Similarly, all 12 Viking
wells drilled in the first quarter are now on production adding 2.7 mmscf/d.
Oil production for the second quarter averaged 14,195 bopd, a decrease of 2 per cent from the previous quarter, and up 8
per cent from the corresponding period in the prior year. Development activity at Sugden commenced with the drilling of
four successful development wells. A further 10 wells are scheduled for the third quarter and if successful will prove
up significant heavy oil reserves.
(iv) Brunei
Sales were lower than the previous (September) quarter due to a planned 12-day shutdown in October to install a
permanent mercury-removal vessel.
Gas sales for the quarter averaged 39 mmscf/d (net to Fletcher Challenge Energy), down 4 per cent from the previous
(September) quarter and equal to the corresponding period last year.
Liquids production for the quarter was 0.074 mmbbl (net to Fletcher Challenge Energy), down 37 per cent from the
previous (September) quarter and a 17 per cent decrease on the corresponding period last year. The decline is due to the
natural depletion of the oil reservoirs.
The Maharaja Lela plant successfully completed a high rate gas test in December and was consequently certified to
operate at a gas rate 29 per cent above its design gas rate. This enables greater flexibility of gas supply for the
customer, and additional support for Fletcher Challenge Energy’s requested gas contract extension and expansion.
4 Exploration and Appraisal Activities
(i) New Zealand
Appraisal of the Pohokura discovery continues. An offshore 3D seismic survey commenced in December. Preparations are
underway for an onshore well, Pohokura South, to test the southern extent of the field. This well is due to be spudded
in early February. A transitional zone 3D seismic survey is planned to address the possible near shore and onshore
extension of the field. Subject to approvals, this seismic survey will commence in the March quarter.
Pohokura reserves were revised upwards as a result of detailed analysis of core and PVT data obtained from the Pohokura
1 and 2 wells. Reserves increased 30 per cent at the proved level to 169 bcf plus 7.6 mmb condensate, equivalent to 35.8
mmboe (all figures net to Fletcher Challenge Energy at a 33.3 per cent equity level).
At the proved and probable level a 32 per cent upward revision occurred resulting in estimated 2P reserves of 66 mmboe
net to Fletcher Challenge Energy.
On a gross basis the mean reserves of the Pohokura field are now estimated to be 964 bcf plus 53 mmb condensate,
equivalent to 212 mmboe.
Additionally, contractor Worley have been engaged to conduct a development concept screening study for the Pohokura
field during Q1 2001.
The drilling of the Tuihu prospect (Fletcher Challenge Energy 50 per cent) began during the quarter, with the well still
in progress by 31 December. By mid January the well had reached its objective confirming the presence of sub-commercial
hydrocarbons. Subsequently the well was plugged and suspended, and the rig moved to the Pohokura South drilling
location.
(ii) Canada
Fletcher Challenge Energy drilled two successful net exploration wells during the quarter, both of which were
completed as gas wells. In addition, 34 successful net development wells were drilled, of which 29 were completed as oil
wells and five as gas wells.
(iii) Brunei
The evaluation of Block CD with respect to a portfolio review and a contractual 50 per cent relinquishment proceeds as
planned. The results of the 2000 drilling campaign have been incorporated. The partners are in overall agreement with
the approach to relinquishment. Additional reviews are underway in a few areas and these results along with minor
modifications are being incorporated into a final proposal to be presented to the Government in March 2001.
A Deepwater Study and Bid Agreement between Marathon and Fletcher Challenge Energy was signed during November with
provision for a third party to join the bidding group. Marathon and Fletcher Challenge Energy have made submissions to
the Brunei Government on the fiscal terms proposed for the Deepwater, and unless there is a significant improvement when
the terms are revised the bidding group will likely withdraw from the study.
In December, Fletcher Challenge Energy and Marathon geo-scientists began leveraging Fletcher Challenge Energy’s
extensive Brunei database into an evaluation of the multi-client seismic data in the Deepwater areas.
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 0 20,197
NZ Onshore 3,394 2,223
North America 5,946 32,788
Brunei 1,913 106
South America 516 206
Total 11,769 55,520
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.
OIL AND CONDENSATE
FY 01 FY 02 FY 03 FY 04
WTI Put Options
Volume (mmbbls) 4.20 6.90
Average Strike US$/bbl 17.87 18.00
Average Premium US$/bbl 0.82 0.45
Quarterly settled, deferred premium Asian options
WTI Swaps
Volume (mmbbls) 2.10
Average Strike US$/bbl 15.59
WTI Collars
Volume (mmbbls) 2.28 2.28
Floor US$/bbl 18.00 18.00
Ceiling US$/bbl 21.00 21.00
Average Premium US$/bbl 0.86 0.86
Quarterly settled, deferred premium Asian options
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$/bbl 0.60 0.60
Quarterly settled, deferred premium Asian options
Tapis Differential
Volume (mmbbls) 1.73
Average Strike US$/bbl -0.04
Represents the discount to WTI that Tapis product receives (negative means Tapis > WTI)
Represents the discount to WTI that Tapis product receives (negative means Tapis > WTI)
LLK Differential
Volume (mmbbls) 0.18
Average Strike US$/bbl 5.50
Represents the discount to WTI that LLK product receives Represents the discount to WTI that LLK
product receives
Bow River Differential
Volume (mmbbls) 0.11
Average Strike US$/bbl 3.95
Represents the discount to WTI that Bow River product receives Represents the discount to WTI that Bow
River product receives
LLG Differential Floor
Volume (mmbbls) 0.28
Average Strike US$/bbl 4.80
Represents the maximum discount to WTI that LLG receives Represents the maximum discount to WTI
that LLB receives
BRUNEI NATURAL GAS
Dubai Collars
FY 01
FY 02
FY 03
FY 04
Volume (mmbbls) 0.96 0.96
Average Floor US$/bbl 16.63 16.63
Average Ceiling US$/bbl 19.63 19.63
Average Premium US$/bbl 1.00 1.00
Dubai instruments are used to manage our Brunei gas price exposure Dubai instruments are used to
manage our Brunei gas price exposure
CANADIAN NATURAL GAS
FY 01 FY 02 FY 03 FY 04
NYMEX Swaps
Volume (PJ) 7.66 3.89
Average Strike US$/mmbtu 2.33 2.33
NYMEX Collars
Volume (PJ) 3.89
Average Floor US$/mmbtu 3.00
Average Ceiling US$/mmbtu 3.39
Average Premium US$/mmbtu 0.00
AECO Swaps
Volume (PJ) 21.90 14.64 3.69
Average Strike C$/GJ 2.29 2.69 3.09
AECO Put Options
Volume (PJ) 3.69 7.26 3.07
Average Strike C$/GJ 2.95 3.15 3.15
Average Premium C$/GJ 0.29 0.38 0.38
AECO Differential
FY01 FY02 FY03 FY04
Volume (PJ) 10.36 15.40 21.78 25.09
Average Strike US$/mmbtu 0.37 0.37 0.37 0.38
FY05 FY06 FY07 FY08
Volume (PJ) 25.02 25.02 25.02 8.43
Average Strike US$/mmbtu 0.40 0.42 0.44 0.44
Represents the discount to NYMEX that AECO gas receives