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2002 Annual Report > Development Opportunities |
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BUSINESS UNIT OVERVIEW
During 2002, Enerplus reorganized from a traditional functionally-aligned
organization into a business unit structure with four geographically distinct
business units and a joint venture business unit. This restructuring will allow us to
better focus our activities, improve operational and technical excellence, improve
operating results and increase capital efficiency. Each of these five business units is
a profit centre with a complement of engineers, geologists, operations personnel,
and landmen supported by an efficient corporate structure. Skill sets within each
business unit are tailored to compliment the unique demands and opportunities
within each area. The following is a summary of the business units and the value
creation activities pursued in 2002.
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In 2002, Enerplus
reorganized into a business
unit structure to improve
operating results and
capital efficiency.
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JOINT VENTURE BUSINESS UNIT
This business unit accounts for one third of Enerplus' production and
encompasses all partner-operated properties in Western Canada from northeast
British Columbia to southeast Saskatchewan. These properties provide exposure to
a wide variety of reservoirs, play types, and enhanced recovery projects that offer
diversification to our asset base. The Joint Venture Business Unit also provides
exposure to higher impact, more technically sophisticated projects that the Fund
would not pursue on its own.
Major Properties
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| Mount Benjamin |
10 |
11,063 |
1,854 |
14.4 |
| Elmworth |
360 |
5,001 |
1,194 |
9.5 |
| Progress |
118 |
4,104 |
802 |
6.2 |
| South Wapiti |
168 |
3,491 |
750 |
6.9 |
| Hayter |
679 |
16 |
682 |
5.5 |
| Other |
6,488 |
61,795 |
16,786 |
12.5 |
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2002 Value Creation
The Joint Venture Business Unit invested $30.8 million during 2002 resulting in
incremental production of 2,400 BOE/day at an average cost of $12,800 per
BOE/day. Key capital projects in 2002 included the sweet, liquids rich natural gas
plays in Deep Basin operated by Burlington and the foothills deep natural gas play
in Mount Benjamin operated by Petro-Canada. Both areas have shown significant
production increases since Enerplus acquired its interests.
The Joint Venture Business Unit also includes a unique nitrogen injection pilot in
the Turner Valley area outside of Calgary. This pilot, operated by Talisman, began
operation in September of 2002 and if successful, will lead to a full scale
development program designed to recover an estimated additional 3% to 10% of
the one billion barrels of original oil in place, 1.5 to 5.0 million barrels of crude
oil net to the Fund.
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key metrics:
- Production:
7,823 bbls/day Liquids
85,470 Mcf/day
Natural gas
22,068 Total BOE/day
- Established Reserves:
33.1 MMbbl Liquids
440.7 Bcf Natural Gas
106.5 MMBOE Total
- Reserve Life Index:
11.8 years
- Total 2002 Development
Spending: $30.8 million
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2002 Key Capital Projects
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| Deep Basin |
Drilled 28 wells |
Nat. Gas |
$ |
2.8 |
250 |
$ |
11,200 |
| Mount Benjamin |
Drilled 3 wells |
Nat. Gas |
|
5.7 |
1,000 |
|
5,700 |
| Jenner |
Drilled 10 wells |
Oil |
|
1.2 |
200 |
|
6,000 |
| Other |
|
|
|
21.1 |
950 |
|
22,200 |
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| Total |
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$ |
30.8 |
2,400 |
$ |
12,800 |
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Mount Benjamin is a deep foothills natural gas play operated by Petro-Canada.
During 2002, three wells were drilled and successfully completed, testing between
10 MMcf/day and 20 MMcf/day of natural gas. As shown in the graph below, the
additional production was tied in late in 2002 providing in excess of 15 MMcf/day
of sales as we enter 2003. Since acquiring this property in 2000, a total of 5 wells
have been drilled with a 100% success rate, increasing production in a prolific
natural gas area where significant production declines are common.
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Production at Mount Benjamin
has more than doubled since
acquired in 2000
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Mount Benjamin Production Profile
2003 Outlook
Robust oil and gas prices are expected to support continued drilling and
development across the industry and therefore we expect capital expenditures to
hold flat or increase in our partner-operated areas in 2003. We anticipate spending
approximately 75% of our joint venture capital budget on gas-weighted projects
and 25% on oil-weighted projects. Additionally, Enerplus will be funding the initial
phases of the Oil Sands Lease #24 SAGD development project and expects to spend
$7.0 million on this project in 2003 with first production expected in 2004.
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Current natural gas prices
continue to support
numerous development
activities
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SOUTHERN BUSINESS UNIT
The Southern Business Unit is our most active development area encompassing
properties in southern Alberta and Saskatchewan. It contains our core shallow gas
development areas as well as a broad range of oil plays. The majority of the Fund's
operated development drilling is conducted in this business unit with over 200
operated shallow natural gas wells drilled in 2002. The Medicine Hat Glauc. "C"
waterflood, in which Enerplus acquired additional working interest this year, is
also in this business unit along with other significant Midale/Ratcliffe oil
production.
Major Properties
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| Hanna |
2 |
12,616 |
2,105 |
41.3 |
| Bantry |
- |
13,757 |
2,293 |
19.7 |
| Med. Hat Glauc. "C" |
1,226 |
1,222 |
1,430 |
24.2 |
| Verger |
8 |
7,609 |
1,276 |
18.6 |
| Med. Hat Sun Valley |
- |
7,318 |
1,220 |
17.8 |
| Other |
2,014 |
13,808 |
4,314 |
12.5 |
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2002 Value Creation
A total of $47.6 million was invested in 2002 resulting in incremental production
of 3,720 BOE/day at a cost of $12,800 per BOE/day. The unit completed a
significant farm-in with a junior exploration company during the year resulting in
the Fund purchasing offset lands to add to our future drilling inventory of low-risk
shallow gas development.
2002 Key Capital Projects
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| Hanna |
Drilled 61 wells |
Nat. Gas |
$ |
12.9 |
520 |
$ |
24,800 |
| Med. Hat North |
Drilled 53 wells |
Nat. Gas |
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8.5 |
420 |
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20,200 |
| Verger |
Drilled 31 wells,
tied-in 51 wells |
Nat. Gas |
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6.0 |
500 |
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12,000 |
| Bantry |
Drilled 48 wells,
refrac 15 wells,
tied-in 52wells |
Nat. Gas |
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6.3 |
650 |
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9,700 |
| Other |
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Nat. Gas |
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13.9 |
1,630 |
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8,500 |
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| Total |
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$ |
47.6 |
3,720 |
$ |
12,800 |
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key metrics:
- Production:
3,250 bbls/day Liquids
56,330 Mcf/day
Natural gas
12,638 Total BOE/day
- Established Reserves:
23.3 MMbbl Liquids
459.3 Bcf Natural Gas
99.8 MMBOE Total
- Reserve Life Index:
21.3 years
- Total 2002 Development
Spending: $47.6 million
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Since 1995, the Fund's shallow gas production has grown from under 10
MMcf/day to approximately 60 MMcf/day in the area through acquisitions and
development drilling. The following graph shows the Fund's increase in
production from the shallow natural gas areas over the past eight years.
Shallow Gas Production Profile
2003 Outlook
We plan to continue our shallow gas development drilling in 2003 including
higher density drilling within our shallow gas locations. The recent Celsius
acquisition has added approximately 300 locations to our existing project
inventory. Confirmation of the viability of increased density of well spacing will
add further development opportunities into the future. Regarding oil
development, Enerplus plans to continue development of the Medicine Hat
Glauc. "C" waterflood and pursue other waterflood opportunities in the area.
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Shallow natural gas drilling
has added over 24 million
BOE of additional reserves
in the last two years
We again plan to drill
approximately 200 shallow
natural gas wells in 2003
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EASTERN BUSINESS UNIT
The Eastern Business Unit focuses on waterflood development projects and
encompasses operated properties and lands in eastern Alberta and western
Saskatchewan along the provincial border. This business unit is predominantly oil
weighted with properties producing light sweet, medium quality and conventional
heavy oil. The majority of these oil properties are under secondary recovery
schemes to improve production and enhance recoverable oil reserves.
Optimization of these secondary recovery projects is key to maximizing the value
of the assets in this business unit.
Major Properties
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| Joarcam |
2,235 |
5,726 |
3,189 |
9.7 |
| Giltedge |
1,635 |
386 |
1,699 |
19.7 |
| Gleneath |
1,026 |
407 |
1,094 |
21.9 |
| Auburndale |
582 |
553 |
674 |
5.8 |
| Kessler |
571 |
101 |
588 |
7.6 |
| Other |
2,834 |
2,876 |
3,314 |
11.0 |
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2002 Value Creation
The key waterflood recovery projects in the business unit were reviewed in 2002
to ensure that they were fully optimized. These reviews provided opportunities to
infill drill, recomplete and restimulate wells to improve production capability and
enhance oil recovery. The business unit invested $36.4 million in 2002 adding
2,990 BOE/day of production at a cost of approximately $12,200 per BOE/day.
2002 Key Capital Projects
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| Joarcam |
Drilled 14 wells |
Oil |
$ |
22.0 |
1,700 |
$ |
12,900 |
| Gleneath |
Drilled 10 wells |
Oil |
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4.8 |
590 |
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8,100 |
| Giltedge |
Drilling/Facilities |
Oil |
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1.9 |
300 |
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6,300 |
| Gleneath |
Drilling/Facilities |
Oil |
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1.1 |
170 |
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6,500 |
| Other |
Drilling |
Oil |
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6.6 |
230 |
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28,700 |
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| Total |
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$ |
36.4 |
2,990 |
$ |
12,200 |
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key metrics:
- Production:
8,883 bbls/day Liquids
10,049 Mcf/day
Natural gas
10,558 Total BOE/day
- Established Reserves:
41.3 MMbbl Liquids
62.1 Bcf Natural Gas
51.6 MMBOE Total
- Reserve Life Index:
12.7 years
- Total 2002 Development
Spending: $36.4 million
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A key project in 2002 was the continued development of Joarcam in central
Alberta. Acquired in late 2000, Joarcam is our largest single producing field and
has seen a significant decrease in the decline rate since we assumed operatorship.
Through a series of optimization and development efforts we have leveled the
decline rate from in excess of 30% to less than 10% per year and added 2.9 million
barrels of established reserves.
Joarcam Production Profile
2003 Outlook
Development activities for 2003 will build off our historical success and continue
to focus on improving and expanding our existing waterfloods to increase
production and recovery. New shallow gas and coal bed methane potential will also
be pursued in the area. Divestments of minor interests and acquisitions in our core
properties will provide additional focus in the area.
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We have added 2.9
MMBOE of established
light, sweet crude oil reserves
in Joarcam since its
acquisition in 2000
We will continue to focus on
improving and expanding
our existing waterfloods to
increase production and
recovery
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CENTRAL BUSINESS UNIT
The Central Business Unit is a mature producing area which lies to the west and
southwest of the city of Edmonton and provides a variety of production
predominantly weighted to light quality sweet oil and liquids rich natural gas.
Given the relatively higher operating costs in many fields in this area, profitability
is sensitive to commodity pricing and we focus our attention on controlling
operating costs in order to maximize the value of these assets.
Major Properties
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| Pembina |
2,265 |
1,450 |
2,507 |
32.3 |
| Ferrier |
218 |
4,358 |
944 |
6.3 |
| Sylvan Lake |
574 |
1,959 |
901 |
8.0 |
| Kaybob South |
227 |
2,920 |
714 |
17.7 |
| Cherhill |
171 |
2,901 |
655 |
3.4 |
| Other |
1,011 |
22,525 |
4,764 |
7.5 |
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2002 Value Creation
Development activity was primarily targeted at maintaining light oil production in
the Pembina and Sylvan Lake areas and developing new shallow gas production in
Pembina, Bashaw and Sylvan Lake. A total of $13.9 million was invested in
development activity during 2002, resulting in incremental production of
1,110 BOE/day at a cost of approximately $12,500 per BOE/day. An initiative to
exploit the shallow gas potential in the Central Business Unit commenced in the
latter half of 2002. The early results of this project have been encouraging and have
led to further development planned in 2003 to assess the economic viability of the
program.
2002 Key Capital Projects
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| Pembina |
Drill/Recomplete |
Gas/oil |
$ |
5.6 |
350 |
$ |
16,000 |
| Bashaw |
Drilled 5 wells |
Nat. gas |
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2.1 |
150 |
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14,000 |
| Sylvan Lake |
Drill/Recomplete |
Nat. gas |
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1.1 |
100 |
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11,000 |
| Other |
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5.1 |
510 |
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10,000 |
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| Total |
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$ |
13.9 |
1,110 |
$ |
12,500 |
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key metrics:
- Production:
4,466 bbls/day Liquids
36,113 Mcf/day
Natural gas
10,485 Total BOE/day
- Established Reserves:
33.2 MMbbl Liquids
117.3 Bcf Natural Gas
52.7 MMBOE Total
- Reserve Life Index:
14.9 years
- Total 2002 Development
Spending: 13.9 million
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Pembina is a large, low decline Cardium oil field that has benefited from on-going
development which has increased production by 27% in just over two years.
Recently, we have complimented the existing oil production with a shallow gas
development program which has grown natural gas production by 64% from
1,050 Mcf/day in the third quarter of 2000 to 1,725 Mcf/day in the fourth quarter
of 2002.
Pembina Production Profile
2003 Outlook
Investment activity in 2003 will continue to be a key focus in the Central Business
Unit with further development of our shallow gas program including the
continued evaluation of coal bed methane potential. Our historical infill drilling
and recompletion initiatives will also be continued to maintain our light
oil production.
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Pembina established reserves
are up over 10 MMBOE in
the last two years
In 2003, we will
compliment our light oil
development with shallow
gas development projects.
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NORTHERN BUSINESS UNIT
The Northern Business Unit is a less developed area that encompasses all operated
lands and production in northwest Alberta and northeast British Columbia. The
business unit provides exposure to both light crude oil and liquids rich natural gas
through a variety of Triassic to Cretaceous age reservoirs. This area tends to offer
higher impact potential per well although there are fewer drilling locations.
Major Properties
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| Valhalla |
497 |
8,755 |
1,956 |
7.0 |
| Progress |
726 |
2,318 |
1,112 |
6.2 |
| Bonanza |
12 |
3,406 |
580 |
4.7 |
| Pouce Coupe |
299 |
555 |
392 |
15.6 |
| Utikuma |
353 |
53 |
362 |
8.1 |
| Other |
1,389 |
7,468 |
2,633 |
15.3 |
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2002 Value Creation
During 2002 development activities were primarily focussed on improving light
oil production at Valhalla and optimizing natural gas production at Valhalla,
Bonanza, Progress and Komie through facility upgrades and development drilling.
A total of $13.0 million was invested in this business unit on these activities
and resulted in a production increase of 1,355 BOE/day at a cost of
$9,600 per BOE/day.
2002 Key Capital Projects
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| Valhalla |
Drilled 2 wells |
Oil |
$ |
4.0 |
490 |
$ |
8,200 |
| Bonanza |
Compression |
Nat. gas |
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1.3 |
355 |
|
3,700 |
| Glacier |
Drill/Recompleted
3 wells |
Nat. gas |
|
0.8 |
280 |
|
2,900 |
| Other |
|
|
|
6.9 |
230 |
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30,000 |
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| Total |
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$ |
13.0 |
1,355 |
$ |
9,600 |
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key metrics:
- Production:
3,276 bbls/day Liquids
22,555 Mcf/day
Natural gas
7,035 Total BOE/day
- Established Reserves:
9.5 MMbbl Liquids
61.2 Bcf Natural Gas
19.7 MMBOE Total
- Reserve Life Index:
8.9 years
- Total 2002 Development
Spending: 13.0 million
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Since acquiring Valhalla in 1996, production has steadily increased through our
development efforts. Over the last two years, production has increased 42% from
1,536 BOE/day to 2,185 BOE/day. In 2002, two additional wells were drilled in
the oil leg of the Valhalla Halfway J pool to enhance oil recovery and optimize the
production from this pool.
Valhalla Production Profile
2003 Outlook
Development activities for 2003 will target additional development at Valhalla and
Progress to further enhance production and recoverable reserves. Efforts to leverage
our existing acreage, a review of non-productive wellbores and our extensive
seismic position are expected to further enhance our development opportunities in
2003 and into the future. The divestment of non-core properties in the north
central Alberta area surrounding Gift Lake is being considered to further focus this
business unit.
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Valhalla production has
increased by 42% over the
last two years
Development efforts going
forward will be focused on
the Valhalla/Progress area.
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RISK MANAGEMENT
Active risk management is fundamental to long-term, consistent performance at
Enerplus. During 2002 Enerplus continued to maintain a disciplined approach to
capital spending, a well-diversified portfolio of oil and gas assets, rigorous due
diligence on new acquisitions, an active commodity hedging program, adequate
insurance, and a strong environment and safety program. Through risk mitigation
and an avoidance of exploration activities, Enerplus is able to maximize
distributions to unitholders and maintain a lower cost of capital within the oil and
gas sector. While risk is inherent to the oil and gas industry, proper risk/return
analysis and active risk mitigation has facilitated our long-term track record. Risk
mitigation can be categorized into three primary areas: operations,
environment/safety and financial.
Operations Risk Management
Enerplus is one of Canada's largest oil and gas producers with both an active
acquisition/divestment program and capital development program. To manage risk
in these areas, Enerplus adheres to the following guidelines:
- No one property represents more than 5% of our production which provides
solid diversification and minimizes the potential of production shortfalls;
- Our historical drilling success approaches 100% due to our disciplined approach
to capital expenditures, a focus in proven core areas and concentration on lowrisk
development versus exploration;
- New areas are stringently reviewed to ensure the risk adjusted returns are
attractive and minimal capital is exposed to higher risk activities;
- Our acquisitions typically include over 70% percent proved producing reserves
and a high percentage of proven reserves, minimizing the possibility of negative
reserve revisions;
- Our due diligence with respect to acquisitions is one of the most rigorous in the
industry; and
- Our insurance levels and premiums are continuously reviewed and managed.
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Our historical drilling
success approaches 100% due
to our disciplined approach
to capital expenditures, a
focus on proven core areas
and concentration on lowrisk
development versus
exploration.
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Environment & Safety Risk Management
Enerplus is committed to its goal of conducting
business in a safe and environmentally
responsible manner. Emphasis is focused on
providing the best possible protection and
safety to employees, the public, stakeholders
and the environment. Enerplus' comprehensive
Environment and Safety Management Program
is constantly reviewed and upgraded to meet this commitment. In 2002, Enerplus
registered its existing E&S Management Program with the Canadian Association
of Petroleum Producers (CAPP) Environment Health and Safety Stewardship
Program at the Platinum level, the highest attainable rating, which reflects our
standards within the industry. This program includes the following initiatives:
- Reduced or eliminated flaring and greenhouse gas emissions through vapour
recovery installations, gas plant enhancements and improved flare technology;
- Utilized our Corrosion Risk Management Program to help identify properties
where improvements have a positive impact, resulting in pipeline replacements,
installation of pipeline liners, and improved corrosion protection programs;
- Maintained an active abandonment and reclamation program dedicated to
decommissioning unneeded facilities and restoring these lease sites to their
original state as well as an active idle wellbore abandonment program;
- Maintained our Job Performance Management System (JPMS) as a
comprehensive approach to managing risk training and worker competencies to
ensure that hazardous tasks are carried out safely, responsibly, and effectively;
and
- Provided an internal Loss Control Council (LCC), a rotating team of
experienced and knowledgeable employees consisting of both field and office
staff, to conduct inspections of operated properties each year to ensure the
highest standards are maintained.
Financial Risk Management
Enerplus has a commodity price risk management program that is designed to
provide price protection on a portion of its future production. The program
establishes hedge positions on future crude oil and natural gas prices in an
effort to:
- Protect against adverse commodity price movements;
- Retain significant exposure to upside price movements;
- Lock in economics for development programs;
- Lock in the accretion for acquisitions; and
- Provide a measure of stability for the Fund's cash flow.
Other financial risk management efforts also include interest rate hedging as well
as diversification of debt and equity sources in both Canada and the United States.
Details of our financial risk management positions are outlined in the MD&A and
financial statements.
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