EARNINGS / Blue Range Resources Annual Report (PartII)
1. A thorough review of well and reservoir performance, economics and
other factors resulted in significant downward adjustments in
reserves. The following table summarizes these changes.
SUMMARY OF SIGNIFICANT REVISIONS
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Natural Gas NGLs
(BCF) (MST)
Proved Probable Proved Probable
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Central Alberta (15.8) (9.1) (822) (329)
Highway/Beg B.C. (10.6) (3.5) (321) (105)
Louise/Sakwatamau (3.8) (2.4) (104) (39)
Clear Hills (5.8) 0.0 (42) 61
Skwat, B.C. (6.2) 2.8 (73) 33
Other (1.4) 4.7 (37) 3
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Total (43.6) (7.5) (1,399) (376)
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Crude Oil BOE
(MSTB) (MBOE)
Proved Probable Proved Probable
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Central Alberta (1,610) (355) (4,012) (1,594)
Highway/Beg B.C. 0 0 (1,381) (455)
Louise/Sakwatamau 0 0 (484) (279)
Clear Hills 0 0 (622) 61
Skwat, B.C. 0 0 (693) 313
Other 0 (195) (177) 278
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Total (1,610) (550) (7,369) (1,676)
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A 1.9 MMBBL downward revision in proved plus probable oil reserves in
Central Alberta resulted from a review of a number of smaller Viking B oil
pools and was not related to our Joffre Viking A Pool, which is currently
under waterflood.
The most significant downward revision to our gas reserves related to a
re-evaluation of several gas reservoirs in Central Alberta. Previously booked
volumetric estimates were reduced by 24.9 Bcf based on production performance.
In the Highway/Beg area of B.C., drilling results did not meet expectations
and previously booked estimates were reduced by 14.1 Bcf. Certain other areas
were also reduced a total of 12.1 Bcf of reserves.
NGLs reserves were adjusted based on corresponding reductions in natural
gas reserves. In several areas actual NGLs yields have been lower than
previously estimated yields and as a result these reserves were reduced to
reflect the actual values.
2. Natural gas production for the year averaged 108.1 mmcf/d, a 16%
increase over last year while natural gas liquids production averaged 1,592
bbl/d, up 6% from 1997. Crude oil production averaged 1,111 bbl/d, a decrease
of 3% from 1997. For the three month period ended March 31, 1998, natural gas
production averaged 116.5 mmcf/d, a 19% increase over the same period in 1997
while natural gas liquids production averaged 1,524 bbl/d, a slight decrease
from 1997 and oil production averaged 1,595 bbl/d, up 50% from 1997.
Production forecasts included the addition in September and October of
approximately 20 mmcf/d of gas from wells drilled during the summer at
Beg/Highway. New production from Beg/Highway totaled 8 mmcf/d and was not
brought on stream until late December 1997. A portion of the difference from
our forecasted gas production related to continuing downtime suffered on the
Westcoast system. Crude oil production was adversely affected by a 4 month
delay in receiving AEUB approval for the Joffre Viking I pool waterflood.
Fourth quarter oil production was higher as a result of the implementation of
the waterflood as well as new discoveries in West Central Alberta.
Dispositions of properties with 15.6 mmcf/d of production occurred during the
year and accordingly will impact production rates in fiscal 1999. A total of
$26 million was raised through the sale of these properties.
3. Natural gas prices for the year averaged $1.66/mcf, up 6% from the
1997 average of $1.57/mcf while the prices for related natural gas liquids
decreased 10% from $22.54/bbl to $20.38/bbl. Average oil prices for the year
decreased 11% from $25.92 to $23.05 per barrel. Average prices for the last
quarter for natural gas, natural gas liquids and crude oil were $1.78/mcf,
$19.02/bbl and $19.97/bbl respectively.
4. The sale of our interest in Humble Petroleum Marketing Ltd. resulted
in a $3.2 million gain which is included in ''Other'' revenue. This compares
with investment income of $3.5 million from the sale of investments in 1997.
As previously announced, Enron Capital and Trade will now be marketing Blue
Range's natural gas production. Through the use of Enron's distinct marketing
capabilities, Blue Range is positioned to enhance the value of its natural gas
portfolio over the course of this long-term arrangement.
5. Blue Range's drilling activity was focused in Northeast British
Columbia/Clear Hills, Valleyview (W5), and Central/Red Deer. Over 80% of the
wells were operated with the Company's average working interest of 76%. Blue
Range participated in 64 wells (48.7 net) resulting in 32 (26.6 net) gas
wells, 15 (9.6 net) oil wells and 17 (12.5 net) dry holes.
The majority of the exploratory activity occurred in the Northeast
British Columbia/Clear Hills area, where the Company drilled 21 gas wells and
2 oil wells. At Boundary Lake, oil discoveries in the Halfway/Doig formations
tested over 800 bbl/d. At Chinchaga, a Gilwood gas well was tied-in at 8
Mmcf/d. At Beg, 11 wells (4 horizontal) were cased and completed for Halfway,
Baldonnel and Cadomin gas. After installation of a second compressor, initial
deliverability from this area totaled 21 mmcf/d. At Fireweed, a substantial
joint venture covering 75,000 acres was completed with Berkley Petroleum Corp.
Under the terms of the Berkley joint venture 15 drilling locations have been
identified for the 1998/99 drilling season. At Clear Hills, two new Halfway
gas pools were discovered and brought on-stream at 2 mmcf/d net per well. In
the Valleyview area, 23 wells were drilled resulting in 7 gas and 7 oil wells.
Four discoveries defined extensive prospects at Louise, resulting in 15 mmcf/d
of initial production; Virginia Hills, 2 gas wells and a major oil discovery
flowing 1000 bbl/d; Sakwatamau, a major Notikewan/Viking gas discovery of 3
mmcf/d; and Pine Creek, a major Wabamum/Gething gas discovery. In the Central
Alberta area, 4 oil and 3 gas wells were drilled and tied in with initial
production rates of 6 mmcf/d and 300 barrels per day of liquids.
The exploration strategy initiated in 1997/98 was to focus on a gas/oil
prospects ratio of 75/25% and an exploration/development ratio of 35/65%. In
areas of controlled infrastructure, the Company maintained working interests
of over 90%. In new exploratory areas, several joint ventures were
established with other bona fide industry partners in order to spread the risk
and increase the play portfolio. The joint venture participants included
Poco, Canrise, New Cache and Canadian Conquest in W5 and Founders and Berkley
in Northeastern B.C. For 1998/99 the plan is to drill 72 wells, to increase
the exploration/development ratio to 40%/60%, to continue expanding joint
venture deals, to farmin and acquire strategic acreage within core areas, and
to locate a major joint venture partner who is capable of spending $30MM to
$50MM of capital on our internally generated prospects. By achieving the
latter objective we will be able to expand our drilling portfolio to a minimum
of 100 wells.
6. The following table outlines BRRC's revenues and expenses on a barrel
of oil equivalent basis utilizing a conversion factor of 10 mcf per 1 BOE.
Twelve Months ended March 31
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1998 1997 Change
($/BOE) ($/BOE) ($/BOE) %
REVENUE
Petroleum and natural gas sales 17.61 17.51 .10 .6
Royalties (2.62) (2.13) (.49) 23.0
ARTC 0.24 0.37 (.13) (35.1)
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15.23 15.75 (.52)
Other 1.07 1.16 (.09) (7.8)
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16.30 16.91 (.61)
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EXPENSES
Production 5.47 4.78 .69 14.4
General and administrative 0.56 0.75 (.19) (25.3)
Interest on long-term debt 1.31 1.16 .15 12.9
Current income taxes 0.21 0.18 .03 16.7
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7.55 6.87 .68
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Funds flow from operations 8.75 10.04 (1.29) (12.9)
______ ______ ______ ______
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The most significant changes from 1997 relate to royalty and production
expenses. In 1997, royalty expenses were reduced by recoveries of prior
years' royalties of approximately $0.41/BOE. In addition, ARTC in 1998 was
lower by $0.09/BOE, primarily due to changes in ARTC rates. The increase in
production costs reflects the continuing development of new reserves in
Northeastern B.C. which have higher field operating costs, as well as
increases in the lease costs of production facilities ($1.26/BOE in 1998
compared to $0.69/BOE in 1997).
Expectations for 1999 are for production expenses to drop by about 10% or
$0.55/BOE as a result of the sale of higher operating cost properties and an
overall reduction in lease costs. The recently announced sale of a 52%
interest in the Clear Hills processing plant to ANG Gathering & Processing
Ltd. (''AG&P'') will initially reduce the amount of third party recoveries,
but this will be offset by a reduction in the amount of facilities under lease
and by the addition of third party gas production over the next few years. As
part of its management function, AG&P will seek new business opportunities for
the Clear Hills plant.
7. Capital expenditures for the year were $100.1 million compared to
$109.8 million last year, categorized as follows:
1998 1997
---- ----
$000 $000
- Exploration and development expenditures 74,806 56,808
- Production equipment 33,041 27,280
- Net property acquisitions / dispositions (8,224) 25,302
- Other 434 443
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100,057 109,833
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8. For fiscal 1999, BRRC anticipates capital expenditures of
approximately $60MM resulting in the drilling of a minimum of 72 wells (60%
development and 40% exploratory) and the acquisition of additional property
interests within our current core areas.
9. The Company expects average production levels for fiscal 1999 of 120
mmcf/d of natural gas, 1,700 bbl/d of natural gas liquids and 2,400 bbl/d of
oil. With prices at $2.00/mcf and $17.00 and $20.00 per barrel of NGLs and
oil respectively, cash flow is estimated at $59 million ($1.77 per share
basic).
Blue Range Resource Corporation is a natural resource company with
headquarters in Calgary, Alberta and engaged in the exploration, development,
production and processing of natural gas and petroleum reserves. Blue Range's
common shares trade on The Toronto Stock Exchange and The Alberta Stock
Exchange under the trading symbol BBR.A. |
