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WESTERN CANADADRILLING CYCLE

OPTIMIZATION

Prepared for:

June 2003

Ministry ofEnergy and Mines

CONFIDENTIALITY

The data contained in this Study, although believed to be accurate, is not warranted or represented byZiff Energy Group to be so. Ziff Energy Group expressly disclaims all responsibility for, andliability in respect of all loss and/or damage howsoever caused, including consequential, economic,direct or indirect loss, to any party who relies on the information contained in the Study.

WESTERN CANADA DRILLING CYCLE OPTIMIZATION

TABLE OF CONTENTS

Section Page

INTRODUCTION.................................................................................................................. 1Overview ................................................................................................................... 1Provincial Drilling ....................................................................................................... 2

CONCLUSIONS................................................................................................................... 3Financial .................................................................................................................... 3

Response to Cyclical Energy Prices ............................................................... 3Natural Gas Price Influence ............................................................................ 3Oil Price Influence........................................................................................... 4Drilling and Seismic Activity Costs.................................................................. 4Budget Cycle .................................................................................................. 5

Operational ................................................................................................................ 5Seismic Activity Drives Exploration................................................................. 5Winter versus Summer Activity ....................................................................... 6Road Bans During Spring Break-up................................................................ 6Industry Focus is on the Needs of the Producers, Not Service Providers....... 7Learning Curve Benefits ................................................................................. 7First Nations Issues ........................................................................................ 7

Environmental/Regulatory ......................................................................................... 8Land Access Due to Wildlife Concerns ........................................................... 8Regulatory Approvals...................................................................................... 8

RECOMMENDATIONS........................................................................................................ 9

WESTERN CANADA SEISMIC AND DRILLING TRENDS ................................................ 11Gas and Oil Drilling.................................................................................................. 11

Type of Drilling.............................................................................................. 11Exploration and Development....................................................................... 12Western Canada 2002 Drilling ...................................................................... 13

Alberta ..................................................................................................................... 14Alberta Gas Drilling....................................................................................... 15Alberta Oil Drilling ......................................................................................... 16Alberta “Other” Wells .................................................................................... 17Alberta Standing Well Drilling ....................................................................... 18

British Columbia – Extremely Q1............................................................................. 19Total B.C. Drilling.......................................................................................... 20B.C. Gas Drilling ........................................................................................... 21B.C. Oil Drilling ............................................................................................. 22B.C. “Other” Wells......................................................................................... 23

B.C. Standing Well Drilling ............................................................................ 24Horizontal Drilling..................................................................................................... 25Sour Drilling ............................................................................................................. 27Drilling Strategy (Shallow, Medium, and Deep) ....................................................... 29

Alberta Shallow Drilling ................................................................................. 30Alberta Medium Drilling ................................................................................. 31Alberta Deep Wells (Spud Date) ................................................................... 32Alberta Deep Drilling (Final Drill Date) .......................................................... 33Alberta Shallow vs. Medium and Deep Gas Drilling ...................................... 34Alberta Shallow Gas Drilling.......................................................................... 35Alberta Medium and Deep Gas Drilling ......................................................... 36

COMPANY TYPE ............................................................................................................... 37Majors ...................................................................................................................... 38

ConocoPhillips 2002 Alberta Drilling ............................................................. 38Imperial Oil 2002 Alberta Drilling................................................................... 39Petro-Canada 2002 Alberta and B.C. Drilling................................................ 40Shell Canada 2002 Alberta Drilling ............................................................... 41

Canadian Independents........................................................................................... 42EnCana 2002 Alberta Drilling ........................................................................ 42EnCana 2002 Alberta Oil and Gas Drilling .................................................... 43CNRL 2002 Alberta and B.C. Drilling ............................................................ 44

American/Foreign Controlled ................................................................................... 45Anadarko 2002 Alberta and B.C. Drilling....................................................... 45Burlington 2002 Alberta and B.C. Drilling...................................................... 46Devon 2002 Alberta and B.C. Drilling............................................................ 47EOG 2002 Alberta Drilling ............................................................................. 48Husky 2002 Western Canada Drilling ........................................................... 49

Royalty Trusts .......................................................................................................... 50Advantage 2002 Alberta Drilling.................................................................... 50Enerplus 2002 Alberta Drilling....................................................................... 51

Seismic Issues......................................................................................................... 52Western Canada Infrastructure................................................................................ 53

PEOPLE ISSUES ............................................................................................................... 54Competition for Operational Staff............................................................................. 55Safety....................................................................................................................... 55

APPENDICES .................................................................................................................... 56Appendix A – Criteria for Industry Interviews ........................................................... 56Appendix B – List of Industry Interviewees .............................................................. 57Appendix C – Interview Questions ........................................................................... 58Appendix D – Scope of the Ziff Energy Drilling Cycle Study .................................... 60Appendix E – Ziff Energy Background ..................................................................... 62

Alberta Energy, BC Energy, CAGC, CAODC, CAPP, PSAC Western Canada Drilling Cycle Optimization 1

INTRODUCTION

Overview

The Western Canadian oil and gas industry operates in annual and seasonal cycles. A consequenceis the need for a large skilled labour force and related equipment to handle peak activity periods.The cyclic nature of the industry creates significant challenges – such as low equipment utilisationon an annualised basis, retention of a competent field work force, potential for increased accidentand worker injuries. To identify potential actionable solutions, two provincial governments (AlbertaEnergy and British Columbia Ministry of Energy and Mines), and four leading Canadian petroleumindustry associations (Canadian Association of Geophysical Contractors (CAGC), CanadianAssociation of Oilwell Drilling Contractors (CAODC), Canadian Association of PetroleumProducers (CAPP), and the Petroleum Services Association of Canada (PSAC)) retained Ziff EnergyGroup in March 2003 to undertake a seismic and drilling industry cycle optimisation study.

The Ziff Energy study examines reasons why seismic and drilling activity is more predominantduring the first quarter of each year in Western Canada, as opposed to more evenly distributed overthe entire year. A key deliverable of the study is to provide actionable recommendations that assistoptimisation of the industry cycle and to raise the awareness of the consequences for the industry.The study includes three distinct phases:

• analysis of historical trends that validate the industry first quarter peakingactivity (charts, tables, and illustrations)

• interviews1 with 362 industry representatives at the executive level3,4; theircontributions (insight, rationale, and suggestions) provide seasoned insightand validation of trends

• preparation of a brief report5,6 with Ziff Energy’s7 recommendations andsuggestions.

Ideally, industry and Government over time will implement the recommendations of this study.Several of the senior industry executive leaders who were interviewed, commented that reading thisstudy would enhance understanding by oil and gas ‘patch’ personnel of the significant challengesfacing the energy services sectors.

1 Appendix A provides a summary of the criteria for the selection of companies to be interviewed.2 While the original scope included up to 15 interviews, due to feedback from the six study sponsors, the total interviews

undertaken for the study exceeded three dozen. Also, the planned duration of the interviews was 30 to 45 minutes;however, the actual duration approached two hours in many cases (primarily due to the strong importance mostinterviewees placed on this study).

3 Appendix B provides a detailed listing of the executives who participated in the interviews.4 Appendix C summarises the typical formal questions that Ziff Energy discussed during the interviews. Most

interviews also discussed other issues.5 Appendix D provides the initial scope, project structure, and timing.6 The plan was to prepare a report under 25 pages. With industry enthusiasm regarding the importance of these issues,

the report more than doubled in size.7 Appendix E provides a background on the Ziff Energy Group.

2 Western Canada Drilling Cycle Optimization Alberta Energy, BC Energy, CAGC, CAODC, CAPP, PSAC

Provincial Drilling

Of the three Western Canadian provinces, Alberta represents three quarters of drilling activity overthe past 5 years. Saskatchewan drilling activity has grown significantly over the past five years andpeaks in the summer months due largely to its year-round access. Overall Saskatchewan drillingactivity is a fifth of the western Canada well total although less on a footage basis. The summerdrilling in Saskatchewan tends to offset some of the extreme drilling peaks experienced in BritishColumbia and Alberta. During 2002, 71% of British Columbia’s wells were drilled in the firstquarter versus 39% for Alberta.

The annual drilling activity significantly oscillates and that requires the drilling sector to maintainsignificant equipment to meet the peak requirements. Alberta annual drilling activity increased by60% in four years (1998 to 2001)8 yet declined 25% in 20029. This is a major swing in annualequipment requirements and a significant challenge for the drilling service companies toaccommodate. Annual and seasonal load levelling of drilling activity would significantly assistthe service sector which represents a long term benefit to the oil and gas producer by ensuringexperienced and complete crews10 are available to complete the activity. Figure 1 illustrates therecent historical drilling activity by province.

8 In British Columbia, drilling increased over 40% (1,250 wells in 2001, vs 880 wells in 1998).9 In British Columbia, drilling decreased over 30% in 2002 over 2001.10 The service sector advises that well over 100 rigs had two crews this past winter (as opposed to three), and a few

dozen rigs did not leave the equipment storage locations due to a lack of qualified service staff.

Figure 1WCSB Total Drilling by Province

0

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Note: Excludes North of 60° drilling1998 1999 2000 2001 2002

Categories EachReferenced to Zero

5 Yr Average %7520

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AlbertaSask.B .C .

Alberta Drilling in 2001 (18,620 wells) Increased by 60% over

1998 (11,570 wells)

Categories EachReferenced to Zero


CONCLUSIONS

Financial

Response to Cyclical Energy Prices

It is apparent that free commercial enterprise drives oil and gas companies towards economicalbusiness opportunities. As a result, industry activity responds to ongoing changes to oil and gascommodity prices and the oscillation of the prices over the years. While control of energy prices isnot possible (due to world influences), understanding the response by industry to price changes isimportant.

Natural Gas Price Influence

Figure 2 shows a key conclusion: how natural gas directed drilling activity is strongly correlatedwith changes in natural gas prices11. The analysis indicates that as natural gas prices rise, gas welldrilling activity rises as well. For example, the recent very strong natural gas prices resulted in verystrong gas directed drilling in the 2,500 to 3,000+ natural gas wells drilled per quarter. In locationswhere producers can tie in the well shortly after drilling and completion (e.g. shallow gas), theproducer economics are generally enhanced if the producer can capture the higher winter commodityprice on volumes produced prior to significant production decline.

11 The monthly gas wells drilled have been summed for every three month period. The quarterly drilling total is lagged

three months, and is plotted against the average gas price per quarter (Green Markers: January to March drilling isplotted against average October to December monthly gas price).

Figure 2WCSB Gas Drilling Response to Price

(AECO Monthly)

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Average Gas Wells Drilled per Quarter

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Strong Drilling Activity at Higher Gas Prices

Blue Markers: Second Quarter Gas Drilling, Based on First Quarter Gas Price


Oil Price Influence

Figure 3 shows a general correlation for Western Canada drilling with increasing oil prices12. Theoil drilling activity responds to oil prices from the prior quarter (a three month delay). Interestingly,the first quarter drilling activity is not always the period of the highest oil prices. The first quarterdrilling activity is highlighted in blue.

Drilling and Seismic Activity Costs

Typically drilling and seismic costs are higher during winter months13 primarily because ofincreased demand for the equipment, services, and that winter drilling operations require a dieselfired boiler14 to provide steam heat. Some producers contract for seismic and drilling services on alonger term basis than a single seismic program or single well program. The longer term contractualcommitment provided by the producer assists the service provider (improved revenue stability),consequently, lower service rates apply for the entire longer program.

12 The monthly oil wells drilled have been summed for every three month period. The quarterly drilling total is lagged

three months, and is plotted against the average monthly oil price per quarter (January to March drilling is plottedagainst average October to December monthly price).

13 While specific percentages are not available, however initial estimates indicate 10 to 35% premium may be applied toassist with recovery of summer discounting of depreciation, overhead, and some sunk fixed costs. While this shortterm operating strategy may temporarily assist with keeping equipment working, this type of operating strategy cannot be maintained in the long term.

14 Boilers typically cost about Cdn$1,500/day including fuel; thus a 100 day winter season would cost Cdn$150,000.

Figure 3WCSB Oil Drilling Response to Price

(Edmonton Sweet Light)

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Average Oil Wells Drilled per Quarter

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It is important to emphasis that the service sector is able to respond to higher winter activity levelsbecause of the over capacity of equipment (based on an average yearly equipment utilisation rate)15.As a consequence, the oil and gas well operator pays a premium to offset the added financial burdenassociated with the equipment not utilised. Should seismic and drilling services receive more workthat is allocated over the entire year, then the service sectors would over time be able to reduce thesurplus equipment.

Budget Cycle

Many operators and service groups indicated that the traditional annual cycle of budgetingexpenditures typically results in new funding for seismic, drilling, and related services not beingapproved until late in the year. Consequently, seismic and drilling activity may be reduced towardsyear end. While common, this results in several challenges for the industry:

• December is a often a good time to undertake some winter access activity, yet manytimes, a producer may have minimal budgeted funds remaining and activity might bedelayed until the start of the new year.

• while the theoretical opportunity exists for companies to shift their financial year endto September 30 (similar to Anderson Exploration), which would better match thephysical reality of the Canadian energy sector, most companies felt they could notinfluence the financial markets to shift from a December fiscal year end (althoughmany interviewees privately suggested it would be a good idea to consider).

• occasionally a producer may have to react on short notice as petroleum and naturalgas leases may be expiring. An earlier review of expiring lands during the annualbudget cycle may assist with longer term planning.

• during the budget cycle, a producer may have to modify the budget plans toaccommodate exploration strategy (if exploration success, land acquisition, seismic,and additional drilling activity may need to be accelerated – and this could impact anideal seismic and or drilling plan).

Operational

Seismic Activity Drives Exploration

Figure 3 illustrates the correlation of Alberta seismic activity to Alberta Exploration Drilling. Thefirst quarter high activity of seismic crews does correlate well with the next year’s explorationdrilling activity (both oil/gas/dry). This confirms that increases in seismic activity during one winter(first quarter) are an indicator of forthcoming exploration drilling activity in Western Canada.

15 Industry has 670 drilling rigs with an average annual utilisation rate of 53% over the 1993 to 2002 period.


Winter versus Summer Activity

Activity from the Canada / United States border up to the tree line regions is generally possible on ayear round basis. However, drilling and seismic activity in the northern portions of Alberta andBritish Columbia is significantly more challenging due to muskeg, swamps, forests, river crossings,and lack of roads. These regions have historically been deemed winter activity regions since low-cost access is generally only possible while the muskeg if frozen. Some shifting of activity tosummer operations in the traditional winter activity regions is being facilitated by all-weather roadconstruction, mat technology16, and other practises17. While some producers indicated that theycould access sites via helicopter in spring/summer, they conclude that the incremental costs areprohibitive. Other producers indicated that summer activity can be impaired through issues such as:centre pivot water wheel irrigation, high value agriculture crops, top soil stripping, military trainingactivity, and localised environmental issues.

Road Bans During Spring Break-up

During the winter, moisture within the road substructure freezes, however, when the spring arrives,the sub-structure thaws (frost comes out) and the road network becomes soft and susceptible todamage from heavy loads. To mitigate damage to the road network, the governments introduceweight restriction limits18 over the roads19. Usually the limit is a percentage of total loads. The road

16 Mat technology reflects the adding of milled wooden mats across the lease road and well site area. Mats are laid out

with a forklift and may require several weeks to complete. Once the well is completed, the mats are removed andmay be used elsewhere. Mat technology has been used in Louisiana, USA for generations.

17 Other enhancements may include helicopter access, multi-well pads, and low bearing pressure vehicles.18 May include ice bridges.

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0 500 1,000 1,500 2,000 2,500Quartely Exploration Well Count

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Example: Data Illustrates Exploration Drilling in Q1 '02 versus Seismic activity from Q1 '01

Figure 4Seismic Activity vs. Exploration Drilling (Alberta)

Q1' 99

First Quarter Activity


ban occurs during the second quarter and significantly restricts work activity. Alternatives such asusing additional wheels or low bearing pressure vehicles may permit emergency access (incuradditional costs) during the six to eight weeks road ban period.

Industry Focus is on the Needs of the Producers, Not Service Providers

There appears to be somewhat of a lack of understanding in the business concerns of the contractingand service industry from senior levels of the oil and gas producer community:

• many contractors and service companies are now publicly held and must competeglobally for capital, the same as producers

• producers may or may not fully appreciate the importance of a healthy long-termcontracting/service industry to the attainment of their own business objectives(virtually all of the operational level work in the industry is performed by theemployees of contractors and service companies)

• there are no direct consequences to the producer community for the deteriorationin industry safety performance associated with rapidly oscillating activity levels.Producers tend to increase seismic and drilling operations based on energy prices andbudget levels, which has an adverse impact on related energy service providers thatare required to respond quickly to achieve the producer requirements.

This lack of understanding may be exacerbating the amplitude of the activity cycles as it inhibitsefforts to perform only that activity that physically must be performed during the winter in Quarter 1,with summer land accessible activity performed during Quarter 3 and Quarter 4.

Learning Curve Benefits

A common theme that most producers and service sectors encouraged is keeping the actual crewson seismic operations, drilling rigs, completions, and related service operations together as long aspossible. The feedback indicated that operational efficiency and overall safety levels are improvedwhen a team works together for a long duration. Several producers indicated that they also want tokeep the crews together since they committed training time with that crew (and therefore wanted toreap the performance benefits). One producer felt so strongly on this point that if the crew was split(due to competitor drilling requirements) then that producer would seek a new service operator.

First Nations Issues

Uncertainties with respect to First Nation’s traditional land use and consultation rights introduceadditional risks for seismic and drilling activity because of direct access delays. Further, in somecases, First Nations contracting opportunities and expectations may not be competitive with

19 British Columbia, through the Ministry of Transportation, has begun adjusting road bans based on actual conditions.

The Ministry of Energy and Mines is working with the transportation department to develop a methodology andprotocol to ensure that industry is not impeded by unnecessary road bans.


alternative service providers20. This may further complicate seismic and drilling project approval,land access, and consequently diminish overall project economics. Operational experience andformal training are noted as potential barriers to employment and contract opportunities. This issuemay require further analysis, which is beyond the scope of this optimisation study.

Environmental/Regulatory

Land Access Due to Wildlife Concerns

Environmental management is an important consideration for the long term development of oil andgas activity. Most participants stressed that they actively consider wildlife concerns in their seismic,drilling, and related follow-up activities. Several environmental issues such as caribou migration,ungulate breeding, grizzly bear encounters, burrowing owls, fish spawning, and other importantwildlife concerns can cause significant impediments in certain seismic and drilling programs, asinability to access land may result in the actual work window becoming extremely limited. Perhapsan opportunity exists for Government to review policy for a balance between socio and economicfactors without sacrificing wildlife concerns while ensuring provinces maximise oil and gas resourcerecovery. This may include fiscal incentives to reflect incremental costs for wildlife protectionmeasures during seismic and drilling activity access to sensitive areas.

Regulatory Approvals

Regulatory approval of seismic and drilling operations is recognised as an important component ofthe drilling cycle. Some producers have indicated that with the high activity level during the corewinter months, some regulatory approvals in British Columbia and Alberta may take longer thananticipated. This can result in delays for the producer, which may postpone the activity for an entireyear. The regulatory delay may be perceived by some industry veterans to be particularly acute inBritish Columbia. Several Alberta operators also indicated that the high winter work load mightoverload the Alberta Energy Utilities Board (AEUB) staff. Provincial regulators should evaluateapproval performance data to determine if these peak season delays are valid and significant.Regulatory delay is perceived to originate with federal Department of Fisheries and Oceans.

Some producers observed that occasionally their regulatory application is deemed incomplete byregulatory approval staff. Frequently, the revision is quickly submitted, however, the producersindicate that their application tends to drop to the bottom of the ladder (and cause a long delay).Regulatory should review the merits and implications of this practice. Other feedback indicated thatwhile senior British Columbia Government officials were supportive of producer’s ideas andsuggestions, the producers observed that many times the government field staff was not fully awareof the initiatives. Producers offered ongoing encouragement for additional internal governmentcommunication to all levels. One suggestion which may reduce the overall perceived regulatorydelay, may be to increase the working hours of regulatory approval employees during the higheractivity period. This technique is similar to the Federal Government’s astute approach for managingthe high peak load during the income tax filing season.

20 There is a perception by many companies in the ‘oil and gas’ patch that the use of First Nation’s services and / or

people is mandatory.


RECOMMENDATIONS

The specific recommendations provided pertain to several aspects of the industry cycle:

1. Strengthen the industry knowledge of the cyclic nature of the business and theimplications. The Study sponsors (Alberta and British Columbia governments, andthe industry associations) can increase awareness to leaders in the oil and gas industry(plus financial analysts, money managers, and investors) that the historical cycle thatthe business has been built around may not be the optimum approach. The currentcyclic approach leads to idle equipment for long periods (thus higher day rates whenactually used) and oscillating labour requirement leads to inefficiencies, and a higherincidence of worker injuries. Alternative approaches should be developed.

2. Fiscal incentives for wells spudded after spring break up and before winterfreeze up. The Alberta Government may wish to consider fiscal incentives such asthose recently initiated by the British Columbia Government21, such as royalty, taxreductions, or other measures, which contribute in an effective and significant way tothe optimisation of the Alberta drilling cycle, as Alberta drilling represents threequarters of all wells drilled in Western Canada. This strategy would encourageproducers to consider drilling wells in year round accessible regions during thesummer months (as opposed to the peak winter months).

3. Expand infrastructure22 (roads) sharing in remote access regions. The leadershipof sharing the cost of the ‘Sierra-Yoyo-Desan road23’ Northeast of Fort Nelson,British Columbia is an excellent approach to shifting some winter access activity tothe summer months. The government of British Columbia (via royalty credits) andthe producer jointly fund the cost of the new road system. Producers prefer to recoverthe credit as quickly as possible, ideally in the same year. Producers indicate that thecredit would not apply to the lease road to the actual well site. The AlbertaGovernment may wish to consider the applicability of these incentives.

4. Inter-industry co-ordination of road construction. While the current agreementscentre around equal funding, the British Columbia (and Alberta) Government maywish to consider expanding the ‘sharing mechanism’ to capture other industries suchas forestry, wildlife (fishing/hunting), and other recreational users (whereappropriate). An expanded ‘user pay’ system would reduce the heavy financialburden placed on the exploration sector.

21 British Columbia recently introduced a summer drilling royalty credit of the lesser of $100,000 or 10% of drilling and

completion costs for wells spudded between April 1 and November 3022 British Columbia announced up to $10 million annually for royalty credits to support road infrastructure

development. As part of the provincial transportation investment program, British Columbia included funding of$270 million for strengthening rural and resource roads, and $37 million for roads that specifically support thepetroleum industry.

23 115 miles of gravelled and maintained all weather 20 foot wide road north east of Fort Nelson, upgraded in 1998.


5. Expand road systems into remote regions that exhibit strong petroleum resourcepotential. This would assist the seismic and drilling industries with initial access tothese regions at times other than winter. By providing initial access to remoteregions, the overall costs of industry activity may be reduced and that may spurincremental activity over the entire season. Future exploration and developmentactivity would benefit from the easier access, potentially resulting in increasedactivity and royalties (due to reduced costs). All Stakeholders should be consulted toensure their concerns are addressed (e.g. additional roads in certain regions mayincrease hunting access).

6. Consider a detailed British Columbia road assessment study aimed at liftingroad bans based on actual conditions. This road assessment may identify thetechnical rationale to reduce the length of the road ban period. One initial approachthat the Government may wish to consider is to evaluate the results from a pilotproject to validate early lifting of road bans.

7. The development and implementation of new technologies that allow theextension of the drilling season in remote regions. A successful example of recentaccess management resulting in minimal disturbance is the use of mats (addingwooden mats across the lease site) being employed in Northeast British Columbia.This would enhance the ability of the industry to develop some projects more quickly(thereby enhancing overall economics).

8. Seasonal drilling and alternative drilling strategy costs. The Petroleum ServicesAssociation of Canada (PSAC) may wish to consider including a comparison ofdrilling costs in similar regions by quarter and a drilling cost comparison of a mattedwell vs. winter drilled well in the Well Cost Study publication. This would assistindustry by clarifying the financial incentive for various drilling programs.

9. Multi-function training for field staff. Industry should strongly consider usingexisting staff for multiple functions. For example, a drilling rig crew may be re-deployed to undertake service rig activities in the summer, thereby providing moreyear round stable employment and continuity of trained personnel.

10. Industry associations increase industry visibility at trade schools, First NationsReserves, and high schools for potential long term employment opportunities inthe ‘oil patch’. Attracting additional personnel for oil and gas activity is essential forlong term maintenance of the entire industry.

11. Governments may want to investigate the feasibility of encouraging all industryparticipants to establish robust safety management systems (like Alberta HumanResources Employment Certificate of Recognition) as a prudent measure. Theremight also be a consequence (financial and/or legal) for all energy sectors personnelwho adversely influence safety performance of seismic and drilling operations. Ifintroduced, the consequences might include management from producing, service,and contracting companies who could not clearly demonstrate adherence to anindependently audited safety management system.


WESTERN CANADA SEISMIC AND DRILLING TRENDS

A key objective for this seismic and drilling cycle study is to present the ‘facts, insight, andopinions’ on why companies focus the majority of their seismic and drilling activity in the firstquarter (versus spreading the work level over the balance of the year). Underpinning our analysis isa structured interview process of critical sectors in the industry. Ziff Energy reviews historicalactivity from important perspectives.

Gas and Oil Drilling

The type of drilling target (gas and oil) is an important consideration in this drilling analysis. Ouranalysis utilises the “Final Drill” date for Alberta and Saskatchewan and the “Rig Release” date forBritish Columbia as the primary indicator of when the well was drilled (British Columbia does notprovide a final drill date). This differs from using the “well completion date” because annual wellcompletions include wells drilled in previous years and may not give a true representation of annualdrilling only.

Type of Drilling

Over the past 5 years, drilling activity in Western Canada has varied sharply from year to year andfrom 250 to 2,950 wells on a monthly basis! While gas and oil wells comprise almost 60% of thewells drilled, other24 wells and wells not classified (standing25 wells) represent a large portion.Figure 5 presents the past 5 years of widely oscillating Western Canadian drilling activity.

24 Other wells include: abandoned (unclassified), injection, service, and other non-gas or oil designated wells.25 Standing wells are wells that have been drilled but not yet classified (for example, oil, gas, or abandoned).

Figure 5WCSB Total Drilling by Well Classification

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1998 1999 2000 2001 2002Note: Excludes North of 60° Drilling

2,145

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2,508

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5 Yr Average %40231918

GasOtherStandingOil


Exploration and Development

Development gas represents 60% of Alberta’s 2002 exploration and development drilling. In the last5 years, only twice (1998 and 2002) has the highest development gas drilling occurring in the firstquarter. In contrast, exploration gas drilling always has the highest percentage in the first quarter ofthe year. Figure 6 shows Alberta oil and gas drilling activity, allocated between Development andExploration activity.

Figure 6Alberta Exploration and Development Drilling

(Oil and Gas) 1998 to 2002

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Exploration GasDrilling AlwaysHighest in FirstQuarter of Year

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Western Canada 2002 Drilling

Figure 7 shows the location of the wells drilled during 2002 in the western Canadian provinces. Thewells in red indicate wells drilled in the first quarter of each year, predominantly in the North asshown in the yellow area. The majority of the blue drilling (2nd to 4thquarter) occurs in the bottomhalf of Alberta plus Saskatchewan. The boundary between the first quarter and the remainder of theyear approximately represents a ‘forested area’ demarcation (i.e. forested to the north and less forestsin the south).

Figure 7Western Canada 2002 Drilling Allocation (Q1 vs. Q2 - Q4)

Majority of Drillingin First Quarter

Regina

Edmonton

Calgary

Q1 Q2 to Q4

AlbertaB.C. Sask.


Alberta

Figure 8 shows total Alberta drilling activity by month for the past five years (pink area), and 2002drilling as bars. Several observations:

• 2002 Alberta total drilling activity during the first quarter is 39%, compared to the 5 yearhistorical average of 35%

• historically the first quarter has double the drilling activity of the second quarter (which islow because of spring break-up)

• the third and fourth quarter are relatively flat with a proportionate share of drillingactivity

• drilling levels peak at 2,449 wells per month in January 2001 and have been as low as203 in April 1999. This oscillating requirement of 12: 1 causes significant capital to beunder-utilised in the drilling and support industries.

Figure 8Total Alberta Drilling

2002 vs. Last 5 Year Trend

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39% drilling First Quarter 2002


Alberta Gas Drilling

Figure 9 examines gas directed activity in Alberta. Gas drilling varies significantly in the past fiveyears – from a high of 900 wells in January 2001 to a low of 52 wells in December 2002.

• current Alberta gas drilling activity during the first quarter is 40%, a third greaterthan the 5 year historical average of 30%

• historically the first quarter has 50% more gas drilling activity than the second quarter• the last two quarters of the year are relatively balanced (and comprise half of the drilling).

Figure 9Total Alberta Gas Wells Drilled


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90040% First Quarter 2002

5 year avg:


Alberta Oil Drilling

Figure 10 provides a five year overview of oil drilling activity in Alberta. While the past year trend(2002) suggests a flatter drilling profile, the five year of 1998 to 2002 (in pink) suggest oscillatingactivity between the first and second quarters. Several observations:

• 28% of historical Alberta oil drilling activity occurs during the first quarter• historical first quarter oil drilling activity is a third more than the second quarter• the majority of oil well drilling is development, thus roads are in place to drill the wells• access is generally year round• the third and fourth quarters are fairly flat and balanced.

Figure 10Total Alberta Oil Wells Drilled


0

100

200

300

400


Oil Wells

0

100

200

300

400Oil Wells

Note: Includes abandoned oil wells

1st Q, 28% 2nd Q, 21% 3rd Q, 27% 4th Q, 24%

- Highest Months Different from Gas- More Balanced than Gas Drilling336

5 year avg:


Alberta “Other” Wells

Figure 11 shows Other well drilling activity in Alberta. This activity includes abandoned wells(green), miscellaneous wells, and remaining wells (see definition below in chart). The majority ofother wells are drilled in the first quarter. Observations include:

• half (48%) of historical Alberta other drilling activity occurs during the first quarter,although this grew to 69% during the first quarter of 2002

• historical first quarter Other drilling activity is more than 3 times greater than the secondquarter

• abandoned wells average three-quarters (73%) of all monthly non-oil or gas classifiedwells during 2002, with a high of 90% in January.

0

200

400

600

800

1,000


Other Wells

0

200

400

600

800

1,000AbandonedMiscellaneousRemaining

Other Wells

Note: Excludes standing wells. Remaining includes gas storage, observation, solvent injection, water disposal, injection or supply.

834 63% of Drilling inFirst Quarter 2002

1st Q, 48 % 2nd Q, 14% 3rd Q, 18% 4th Q, 20%5 year avg:

Figure 11Allocation of 2002 Alberta "Other " Drilled Wells



Alberta Standing Well Drilling

Figure 12 summarises Standing wells in Alberta. These wells have been drilled, however not yetclassified. Several producers indicated that standing wells might peak at year end as producers try to‘wrap-up’ their year end drilling program. Some points include:

• over a third (37%) of historical Alberta standing drilling occurs during the first quarter• historical first quarter standing drilling activity is more than 3 times greater than the

second quarter• over a third of the December 2002 Alberta standing wells are attributed to EnCana.

Figure 12Alberta Standing Well Count

0

200

400

600

800

1,000

1,200

J M S J M S J M S J M S J M S J

Wells per Month

0

200

400

600

800

1,000

1,200

Note: Based on Final Drill Date

Wells per Month

1998 1999 2000 2001 2002

209

491

1,112


British Columbia – Extremely Q1

Figure 13 provides a geographic allocation of 2002 British Columbia oil and gas drilling, with themajority located in the central and northern region of Northeast British Columbia. The majority ofBritish Columbia drilling is gas targets, although in central British Columbia several oil plays exist.British Columbia drilling is primarily (67%) undertaken during the first quarter. Most gas inBritish Columbia is slightly sour (minimum of 1 to 2% H2S).

Figure 13British Columbia 1998 to 2002 Oil and Gas Drilling

Note: Oil and gas wells were searched on a province basis. Wells not classified as oil or gas bythe operator does not appear on the map.

Calgary

Edmonton

Gas Oil

AlbertaB.C. Sask.

67% of B.C. Gas WellsDrilled in First Quarter

Oil Drilling (Blue)Concentrated


Total B.C. Drilling

With less infrastructure than Alberta, drilling activity is even more seasonal in British Columbia.Many producers initiate drilling activity mid December, and try to wrap up by March 15 to 31. Thepossibility to construct and maintain additional all weather gravel access roads in oil and gasprolific regions within Northeastern British Columbia is a key consideration for oil and gas explorers(and development activity) to consider shifting some activity to summer months.

While the producer and service sectors both recognise that costs are lower in summer months (due toless activity), the remote and challenging access issues (muskeg, creek crossings, environmentalissues) during summer months drive costs such that winter access is actually the lower cost option.

Figure 14 summarises total British Columbia drilling activity for five years (pink band) and past year(blue bars). Observations include:

• current British Columbia total drilling activity during the first quarter is 71%as compared to the 5 year historical average of 65%

• drilling activity in the first quarter is a dozen times greater then the second quarter• the rig release dates for rigs during March is equal in the first and second half of the

month, indicating that drilling activity is 75 to 90 days in British Columbia.

Figure 14Total B.C. Drilling


0

100

200

300


Total Wells

0

100

200

300

Total Wells

Note: Includes all wells

71% of Total Drilling Occurred in First Quarter 2002 331

1st Q, 65% 2nd Q, 5% 3rd Q, 14% 4th Q, 16%5 year avg:

Mar 1-15 (74)

Mar 16-31 (67)


B.C. Gas Drilling

Figure 15 provides insight to the gas drilling activity in Northeast British Columbia. Historically,the activity is focused primarily in the winter months (January through March) and essentially shutdown during the spring break up period of the second quarter.

• current British Columbia gas drilling activity during the first quarter is 75%as compared to the 5 year historical average of 69%

• drilling activity in the first quarter is 20 to 25 times greater then the second quarter• ‘mat technology’ may help increase summer drilling activity in remote locations• a gas well in British Columbia costs about Cdn$2,000,00026.

26 PSAC 2003 Well Cost Study, April 30, 2003, for a 9,000 foot vertical sweet gas well in Northeast British Columbia.

Figure 15Total B.C. Gas Wells Drilled


0

50

100

150

200


Gas Wells

0

50

100

150

200Gas Wells

Note: Includes abandoned gas wells

75% of Gas Drilling Occurred in First First Quarter 2002187



B.C. Oil Drilling

Oil drilling activity within Northeast British Columbia is also very oriented towards the first quarter.Figure 16 shows the five year trend (pink area) and the observations for the past year (2002).Observations include:

• a whopping 92% of 2002 oil drilling activity occurs in the first quarter with two-thirds(64%) in February alone; Nexen accounted for the majority (88%) of first quarter 2002oil drilling with their Hay River drilling program

• total oil drilling in British Columbia is relatively small (about 100 wells/year) or under15% of total wells

• very little (10%) oil drilling activity occurs during the second quarter.

Figure 16Total B.C. Oil Wells Drilled


0

10

20

30

40

50

60

70


Oil Wells

0

10

20

30

40

50

60

70Oil Wells

Note: Includes abandoned oil wells

59


First Quarter 2002 Accounted for 92%of Activity (February was Two-thirds)


B.C. “Other” Wells

Figure 17 summarises the types of wells drilled (other than oil and gas) which include abandoned,unclassified, and remaining:

• 62% of Other drilling activity occurs in the first quarter over the past 5 years as comparedto 59% in the first quarter 2002

• the first quarter has ten times more other drilling activity than the second quarter!

Figure 17Total B.C. "Other " Wells Drilled


0

20

40

60

80

100


Other Wells

0

20

40

60

80

100AbandonedUnclassified

Remaining

Note: Excludes standing wells. Remaining includes suspended, unclassified, miscellaneous, water disposal, and injection.

Other Wells


Over Half (59%) Drilledin First Quarter 2002

88


B.C. Standing Well Drilling

Figure 18 illustrates the past years of Standing wells in British Columbia:

• two thirds (67%) of historical British Columbia Standing drilling occursduring the first quarter

• historical first quarter Standing drilling activity is more than 25 times greaterthan the second quarter.

Figure 18B.C. Standing Well Count

0

10

20

30

J M S J M S J M S J M S J M S

Wells per Month

0

10

20

30

Note: Based on Rig Release Date

Wells per Month

1998 1999 2000 2001 2002

15

29

13


Horizontal Drilling

Horizontal drilling helps improve the overall productivity of the oil and gas well through muchgreater contact with the reservoir zone. Further, producers have the opportunity to drill several wellsfrom a common pad, thus reducing some operational costs. As many of the oil pools in westernCanada are near existing roads, horizontal oil well drilling (often re-entry development wells) can inmost locations be drilled year round. Natural gas directed horizontal wells are typically adevelopment program, however, recently have been located in regions that have traditionallyrequired winter access. Horizontal wells represent 4 to 5% of 2002 WCSB drilling27. Figure 19illustrates that horizontal oil well drilling (green) is already a year round function, whereashorizontal gas well drilling (red) is primarily a first quarter activity. Perhaps this provides anopportunity exists to move some winter first quarter oil horizontal wells to the summer because thesehorizontal oil wells generally have year round access to all weather roads.

• the highest number of 2002 horizontal gas wells (49 wells representing 42% of theannual quantity) are drilled in January

• horizontal oil well drilling is much more distributed over the year• horizontal gas28 drilling in Northeast British Columbia has increased the overall

development of some gas pools.

27 944 horizontal wells out of 20,000 WCSB wells drilled in 2002 (4.7%).28 Many gas directed horizontal wells are drilled using under-balanced drilling techniques.

Figure 19WCSB 2002 Horizontal Drilling

0

20

40

60

80

100

120

140


Wells per Month

0

20

40

60

80

100

120

140

Oil ( 755) Gas (117) Service/Abandoned (72)

Wells per Month

32% of the 944 Horizontal Wells are Drilled in the First Quarter


Figure 20 illustrates the location of horizontal drilling in Western Canada. Three gas prone regions(Northeast British Columbia, Alberta Foothills, and Northwest Alberta) are highlighted separately asregions where significant horizontal gas wells were drilled during the first quarter of 2002.

• seasonal winter access is the key reason for drilling in the first quarter in these areas• maximising first year production (especially early in the year when gas prices are

traditionally stronger) helps maximise the explorers cash flow and earnings as gasproduction is maximised in the same year as the investment

• horizontal oil wells are typically drilled in readily accessible regions, with access roads inplace; consequently, they are typically drilled on a year round basis

• horizontal oil wells cost Cdn$1,100,00029.

Figure 20WCSB 2002 Horizontal Drilling (Gas and Oil)

29 PSAC 2003 Well Cost Study, April 30, 2003, for a 5,500 foot True Vertical Depth (TVD), 7,500 foot measured depth

(MD), sweet oil well in North Central Alberta, during summer.

Regina

Edmonton

Calgary

Gas (Jan to Mar)Gas (Apr to Dec)Oil (Jan to Mar)Oil (Apr to Dec)

AlbertaB.C. Sask.

2002 Horizontal

FirstQuarter

Gas

FirstQuarter

Gas

FirstQuarter

Gas


Sour Drilling

Figure 21 illustrates Alberta H2S drilling activity which is primarily limited to the Foothills region(with small pockets in Northwest Alberta and south of Edmonton). Unfortunately, British Columbiadoes not record a ‘flag’ in the electronic databases to allow a review of British Columbia sour gasactivity.

Figure 21Alberta H2S Drilling 1998 to 2002

Regina

Edmonton

Calgary

AlbertaB.C. Sask.

Note: No H2S Well DataPublished for B.C. Drilling

FoothillsOriented


Figure 22 provides some information regarding historical gas drilling with H2S.

• in 1998 and 1999, over one-third (40% and 42%) of sour wells were drilled in thefirst quarter; this percentage dropped to 30% in 2000

• the majority of H2S content wells drilled over the last 5 years generally follow theAlberta foothills trend, a forested region with some access and environmental issues

• several producers mentioned that sour wells are challenging to get initial approvalsand require significant community input prior to commencing operations.

Figure 22Alberta Drilling (H 2 S Wells)

1998 to 2002

0

10

20

30

40

50

J M M J S N J M M J S N J M M J S N J M M J S N J M M J S N J

Wells per Month

0

10

20

30

40

50

Note: Limited reporting of 2002 H2S drlling may be partially due to time requiredfor gas analysis work to be undertaken, results reported to the operator, and submitted for incorporation within the AEUB database.

Wells per Month

2000 2001 20021998 1999

Based on Final Drill Date

40% Q1

42% Q1

30% Q1

48

31

24


Drilling Strategy (Shallow, Medium, and Deep)

Figure 23 provides a graphic display of the year 2002 drilling by well depths: shallow (yellow – lessthan 3,500 ft), medium (green - 3,500 to 7,500 ft), and deep (blue - over 7,500 ft). Due to the natureof sediments in Western Canada, in general, the deeper wells are towards the western part of Albertaand in Northeast British Columbia. Over 40% of shallow drilling occurs in the first quarter, similarto deep drilling, whereas for medium drilling, over a third is conducted in the first quarter. Asdisplayed on the map, the first quarter shallow drilling occurs primarily in the northern half ofAlberta and British Columbia.

Figure 23Total 2002 WCSB Drilling (Shallow, Medium and Deep)

Note: The shallow, medium and deep well depth categories are based on generally accepted drillingdepths for single, double, and triple rig classifications.

Regina

Edmonton

CalgaryShallow Drilling (Q1)Shallow Drilling (Q2-Q4)Medium DrillingDeep Drilling

AlbertaB.C. Sask.

MEDIUM35%

Q1 Drilling

DEEP40%

Q1 Drilling

SHALLOWOver 40%Q1 Drilling


Alberta Shallow Drilling

Figure 24 provides a summary of Alberta shallow drilling for the past five years (pink) and therecent trend for 2002 (blue). Several observations include:

• during the previous 5 years 37% of shallow drilling activity occurs in the first quarter• the first quarter has twice as much shallow drilling activity than the second quarter• the May to December period is more evenly balanced• several operators mentioned that shallow drilling activities (drill, complete, tie in) are

more efficient when undertaken during the summer (warmer weather, more sunlight, lessbulky clothing)

• some farmers prefer to have drilling activity undertaken before spring planting or afterfall harvesting (even though they are compensated for crop damage)

• a typical shallow gas well costs under Cdn$250,00030.

30 PSAC 2003 Well Cost Study, April 30, 2003, for a 2,850 foot vertical sweet gas well in East Central Alberta,

drilled during summer.

Figure 24Alberta Shallow Drilling2002 vs. Last 5 Year Trend

0

500

1,000

1,500

2,000


All Wells

0

500

1,000

1,500

2,000All Wells

1,726


Note: Shallow Depth up to 3,500 ft.

41 % of Shallow Drilling Occurred in the First Quarter 2002


Alberta Medium Drilling

Figure 25 examines medium depth drilling activity for the past five years (pink) and the trendobserved in 2002 (blue). Observations include:

• over the last 5 years 32% of medium drilling activity occurs in the first quarter,almost twice the second quarter

• although the first 3 months are higher, medium depth drilling is more evenlydistributed over the year

• many of the medium depth well targets are near existing roads, thus access issomewhat better for this type of well

• typical well costs are under Cdn$1,000,00031.

31 PSAC 2003 Well Cost Study, April 30, 2003, for a 7,400 foot vertical sweet gas well in Northern Alberta,

during summer.

Figure 25Alberta Medium Drilling2002 vs. Last 5 Year Trend

0

200

400

600


All Wells

0

200

400

600All Wells

Note: Medium Depth from 3,500 to 7,500 ft.

597



Alberta Deep Wells (Spud Date)

Figure 26 shows the Alberta deep wells drilled by spud date. We examine spud dates becausedeeper wells typically require a longer duration to drill (up to several months). Several observationsinclude:

• the deep drilling 5 year first quarter average of 32% is more than doublethe second quarter average (15%)

• June to October is more evenly balanced• typical well costs are up to Cdn$7,000,00032, or more.

32 PSAC 2003 Well Cost Study, April 30, 2003, for a 15,000 foot directional sour gas well drilled in the Alberta

Foothills, during summer.

Figure 26Alberta Spud Date for Deep Wells


0

50

100

150

200

250


Wells per Month

0

50

100

150

200

250Wells per Month

230


Note: Deep Depth over 7,500 ft.


Alberta Deep Drilling (Final Drill Date)

Figure 27 shows Alberta deep well drilling by final drill date. This information is comparable toFigure 26 (by spud date) however this data is skewed by up to several months. Observationsinclude:

• the deep drilling 5 year first quarter average of 34% is more than doublethe second quarter average (16%)

• June to December is more evenly balanced.

Figure 27Alberta Deep Drilling


0

50

100

150

200

250


All Wells

0

50

100

150

200

250All Wells

Note: Deep Depth over 7,500 ft.228



Alberta Shallow vs. Medium and Deep Gas Drilling

Figure 28 shows Alberta shallow vs. medium and deep gas drilling. The majority (73%) of gasdirected drilling is shallow.

• while gas directed drilling varies monthly, the annual cycle also varies significantly• the low numbered gas wells for December 2002 may be due to a significant number

of standing wells, which had been drilled but not yet classified (over 1,100).

0

200

400

600

800

1,000

J M S J M S J M S J M S J M S

Gas Wells

0

200

400

600

800

1,000

Shallow Gas (73%) Medium & Deep Gas (27%)

Figure 28Alberta Shallow vs. Medium & Deep Gas Drilling

Gas Wells

Note: Includes Abandoned Gas Wells

1998 1999 2000 2001 2002

929

309 544


Alberta Shallow Gas Drilling

Figure 29 provides an overview of shallow gas drilling. The five year trend is shown in pink, andthe recent trend is illustrated as blue bars. Some observations include:

• the 5 year average (30%) of shallow gas drilling activity occurs in the first quarter;35% more than the second quarter

• June to October drilling is more evenly distributed• producers may want to consider bringing on new shallow gas in November, at the

start of the winter period, to capture the higher winter price prior to the majorproduction rate decline.

Figure 29Alberta Shallow Gas Drilling


0

200

400

600

800

Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec

Gas Wells

0

200

400

600

800Gas Wells

702Note: Includes Abandoned Gas Wells, Shallow Depth up to 3,500 ft.



Alberta Medium and Deep Gas Drilling

Figure 30 combines Alberta medium and deep gas drilling. The observations:

• the 5 year average of medium/deep gas drilling activity for the first quarter is athird (33%)

• the summer months of June through August have the second highest medium anddeep drilling activity

• the smaller drilling activity in the last quarter of 2002 may have resulted from alate freeze up. In addition, wells drilled late in the year that have not beenclassified as gas will not appear in this figure 30.

Figure 30Alberta Medium and Deep Gas Drilling


0

50

100

150

200

250


Gas Wells

0

50

100

150

200

250Gas Wells

237 Note: Includes Abandoned Gas Wells, Medium Depth from 3,500 to 7,500 ft., Deep Depth Over 7,500 ft.



COMPANY TYPE

Ziff Energy undertook an analysis of the drilling activity of selected producers including majors, UScontrolled independents, Canadian controlled independents, British Columbia explorers, SEPACmembers, royalty trusts, recently merged, E&P companies and heavy oil/horizontal drillers.

Figure 31 shows a listing of companies selected for each category. For example, the first companylisted (Shell) drilled 130 wells in 2002, of which 72% were drilled in the first quarter

Figure 31Selected Producing Companies

2002 Wells Drilled in the First Quarter (%)

72

33

31

59

40

23

14

64

68

38

79

44

19

39

41

46

0 25 50 75 100

Shell (130)

ConocoPhillips (470)

Imperial (441)

Anadarko (182)

Devon (575)

Apache (243)

EOG (737)

Husky (764)

CNRL (906)

EnCana (3272)

Nexen (247)

Penn West (294)

Rife Resources (16)

Luke Energy (0)

Advantage (143)

Enerplus (129)

Burlington (642)

Petro-Canada (388)

Percentage

0 25 50 75 100

Majors

US/ForeignControlledIndependents

CanadianControlledIndependents

B.C. Explorers

SEPACMembers

RoyaltyTrusts

RecentlyMerged

Heavy Oil /HorizontalDrilling

Company (2002 Wells)


Majors

ConocoPhillips 2002 Alberta Drilling

Figure 32 provides a drilling profile for ConocoPhillips during 2002. Observations include:

• balanced drilling between the first quarter (33%) and significant drilling activity duringthe summer months of June, July and August.

0

25

50

75

100


Wells per Month

0

25

50

75

100

Figure 32ConocoPhillips 2002 Total Alberta Wells Drilled

Wells per Month

7

86One Third of the 465 Wells Drilled are in

the First Quarter


Imperial Oil 2002 Alberta Drilling

Figure 33 illustrates Imperial Alberta drilling for 2002. Typically drilling activity ranges from 24 to50 wells per month. Observations include:

• overall balanced drilling during the year, due to heavy oil orientation• under a third (30%) of drilling occurs in the first quarter.

Figure 33Imperial 2002 Total Alberta Wells Drilled

0

20

40

60


Wells per Month

0

20

40

60Wells per Month

24

5030% of the 440 wells Drilled

are in the First Quarter


Petro-Canada 2002 Alberta and B.C. Drilling

Figure 34 shows Petro-Canada’s Alberta and British Columbia drilling activity, while Figure 35shows Petro-Canada oil vs. gas drilling activity. Observations include: for 2002, 32% of wells aredrilled in first quarter, due to deep gas focus; over 98% of 2002 Petro-Canada drilling was gasoriented.

Figure 34Petro-Canada 2002 Total Drilling

0

20

40

60

80


Wells per Month

0

20

40

60

80Alberta B.C.

Wells per Month

0

10

20

30


Wells Per Month

0

10

20

30

Oil Gas

Wells Per Month

Predominantly Gas Drilling in 2002.One-third (32%) of Gas Wells Drilled in Q1.

Figure 35Petro-Canada 2002 Alberta Oil vs. Gas Drilling


Shell Canada 2002 Alberta Drilling

Figure 36 shows Shell Alberta drilling activity. Observations include:

• almost three-quarters (72%) of 2002 drilling occurring in the first quarter• over half (54%) of Shell’s 2002 drilling occurred in Northeast Alberta as evaluation oil

sand development wells.

Figure 36Shell 2002 Total Alberta Wells Drilled

0

20

40

60


Wells per Month

0

20

40

60Wells per Month

54

72% of the130 Wells Drilled are

in theFirst Quarter


Canadian Independents

EnCana 2002 Alberta Drilling

Figure 37 show EnCana Alberta wells drilled. Observations include:

• EnCana activity accounts for over 20% of all wells drilled in Alberta during 2002• EnCana drilled 38% of their wells in the first quarter of 2002• one-third of the 2002 standing or unclassified wells are the most recently drilled

(December); the majority of these wells will be classified upon further company review.

Figure 37EnCana 2002 Total Alberta Wells Drilled

0

100

200

300

400

500


Wells per Month

0

100

200

300

400

500

Standing Remaining

Wells per Month

143

473


EnCana 2002 Alberta Oil and Gas Drilling

Figure 38 shows EnCana Alberta oil vs. gas well drilling activity. Figure 39 shows EnCana BritishColumbia drilling activity. Observations include: EnCana 2002 gas drilling dominates the first twoquarters, while oil drilling is fairly balanced over the year; EnCana tends to focus on natural gastargets (over 75% is gas); two-thirds (62%) of EnCana’s 2002 British Columbia drilling occurs inthe first quarter and was gas directed, notably at Sierra.

Figure 38EnCana 2002 Alberta Oil vs. Gas Drilling

0

100

200

300


Wells per Month

0

100

200

300Oil Gas

Wells per Month

55% Gas Drilling in First Quarter.

Figure 39EnCana 2002 B.C. Total Drilling

0

10

20

30

40


Wells per Month

0

10

20

30

40Wells per Month

60% of First Quarter Drilling is Gas (53 of 89 Wells)1) Only 12 Wells are Classified as Standing2) No Oil Wells in Current 2002 Well Classifications.


CNRL 2002 Alberta and B.C. Drilling

Figure 40 shows Canadian Natural Resources Limited drilling activity for 2002 and Figure 41 showsAlberta oil vs. gas drilling activity. Observations include: two thirds (68%) of Alberta and BritishColumbia wells were drilled in the first quarter; all British Columbia wells were drilled in the wintermonths only; two-thirds (67%) of 2002 gas wells were drilled in the first quarter, while over half(54%) of oil wells were drilled in the second quarter; CNRL activity accounts for 6% of totalindustry drilling activity.

Figure 41CNRL 2002 Alberta Oil vs. Gas Drilling

0

20

40

60


Wells per Month

0

20

40

60

Oil Gas

Wells per Month

Two-thirds (67%) of Drilling occurs in Q1.CNRL drilled 854 or 5.7% of all 2002 Wells.

0

100

200

300


Wells per Month

0

100

200

300Alberta B.C.

Wells per Month

268

7

Figure 40CNRL 2002 Total Alberta and B.C. Wells Drilled


American/Foreign Controlled

Anadarko 2002 Alberta and B.C. Drilling

Figure 42 shows Anadarko Alberta and British Columbia drilling activity for 2002. The majority(71%) of Anadarko’s British Columbia and (59%) of Alberta and British Columbia combineddrilling occurs in the first 3 months.

0

10

20

30

40


Wells per Month

0

10

20

30

40

Alberta B.C.

Wells per Month

Figure 42Anadarko 2002 Total Alberta and B.C. Wells Drilled

40

2

59% of 180 Wells are Drilled in the First Quarter


Burlington 2002 Alberta and B.C. Drilling

Figure 43 illustrates Burlington’s Alberta and British Columbia wells drilled in 2002. Severalobservations include:

• Overall, 41% of Burlington’s drilling activity is in the first quarter• Burlington drilled the majority (86%) of British Columbia wells in the first quarter• for Alberta the third quarter drilling activity (36%) was similar to the first quarter (35%).

0

20

40

60

80

100

120


Wells per Month

0

20

40

60

80

100

120

Alberta B.C.

Wells per Month

Figure 43Burlington 2002 Total Alberta and B.C. Wells Drilled

4

104

41% of 640 Wells are Drilled in the First Quarter


Devon 2002 Alberta and B.C. Drilling

Figure 44 shows Devon’s Alberta and British Columbia drilling activity for 2002.Observations include:

• the first two months (32%) plus the summer, June through August (42%), were thestrongest drilling periods for Devon

• British Columbia drilling mainly (87%) occurred in the first quarter.

0

25

50

75

100


Wells per Month

0

25

50

75

100

Alberta B.C.

Wells per Month

Figure 44Devon 2002 Total Alberta and B.C. Wells Drilled

5

95

40% of 575 Wells Drilled were in the

First Quarter


EOG 2002 Alberta Drilling

Figure 45 shows EOG Alberta drilling for 2002. EOG is primarily a shallow gas strategy player anddeliberately conducts their drilling program during the summer months. This tends to result in thelowest overall cost for the drilling and related services. Ideally, three key operations occur: drilling,completions, and then the actual tie in. These operations are generally spaced out over the summerand fall to ensure that operations are independent of each other. Observations include:

• a reversal of the first quarter industry drilling trend, EOG predominantly drillsshallow gas wells in the second half of the year

• in 2002, 38% of EOG drilling occurred in the fourth quarter compared to only 14% inthe first quarter.

Figure 45EOG 2002 Total Alberta Wells Drilled

0

50

100

150

200


Wells per Month

0

50

100

150

200Wells per Month

6

18114% of 740 Wells

were Drilled in the First Quarter Completion

CurveIdeal DrillingCurve

Tie-inCurve


Husky 2002 Western Canada Drilling

Figure 46 shows Husky Western Canada wells drilled during 2002 and Figure 47 shows Husky’sAlberta and British Columbia oil vs. gas drilling activity. Observations include: Husky drilledalmost two-thirds (63%) of their wells in the first quarter of 2002; a large portion of drilling activityis heavy oil in Saskatchewan, near Lloydminster; gas and oil drilling was predominantly gas in thefirst quarter, and heavy oil over the summer months; 80% of the gas wells were drilled in the firstquarter.

Figure 46Husky 2002 Total Wells Drilled

0

50

100

150

200

250


Wells per Month

0

50

100

150

200

250Alberta B.C. Saskatchewan

Wells per Month

63% of 750 Wells are Drilled in the

First Quarter

13

0

20

40

60

80

100

120


Wells per Month

0

20

40

60

80

100

120Oil Gas

Wells per Month

80% of 2002 Gas Wells Drilled in the First Quarter.45% of 2002 Oil Wells Drilled in Third Quarter.

Figure 47Husky 2002 Alberta and B.C. Oil vs. Gas Drilling


Royalty Trusts

Advantage 2002 Alberta Drilling

Royalty Trusts generally do not undertake exploration drilling programs and are primarily focused togenerate a stable monthly income for unit holders. Figure 48 shows a royalty trust company(Advantage) drilling program for 2002. Observations include:

• Advantage drilled 145 wells in 2002, half (50%) were drilled in the third quarter,followed by 39% in the first quarter.

Figure 48Advantage 2002 Total Alberta Wells Drilled

0

10

20

30

40


Wells per Month

0

10

20

30

40

Wells per Month

Note: Mainly Shallow Gas Producer

41

39% of 145 Wells Drilled in the First

Quarter (29% in March)


Enerplus 2002 Alberta Drilling

Figure 49 shows the Enerplus drilling program for 2002. Observations include:

• Enerplus drilled 130 wells in 2002, predominantly shallow gas, and very concentrated(63%) in just 2 months (June/July)

• all wells were development• over 98% of the wells were commercially successful• 43% of wells were drilled in July.

Figure 49Enerplus 2002 Total Alberta Wells Drilled

0

20

40

60


Wells per Month

0

20

40

60Wells per Month

5643% of 130 Wells Drilled in July


Seismic Issues

Seismic activity is fundamental for successful exploration and is ‘First In, First Out’ (FIFO). Mostseismic activity is conducted during the winter months (80%) because of access issues (similar to thereasons why drilling is frequently conducted in winter months). Over the past several decades 3Dseismic has emerged as a technology enhancement over traditional 2D seismic. The seismic industryindicates that data quality is equally as good in the summer months as winter. Yet some producersare somewhat apprehensive about summer seismic data quality. Other observations include:

• helicopter supported seismic activity allows year round access and minimises theenvironmental footprint left. The seismic operation is conducted quicker (no fencecutting, less brush clearing, no creek crossings). The major drawback is the highercosts (two to three times more expensive).

• the seismic industry appears to be in an over capacity position partially due toproducers who trade seismic data (as opposed to doing new). While several seismiccontractors indicated that they are reducing equipment, the ongoing growth of the‘rental’ seismic business merely compounds the problem.

• one seismic contractor indicated that they would not carve up an experienced seismiccrew to support another seismic operation elsewhere. Their internal strategy wouldbe to turn down the incremental work rather than jeopardise the safety of anoperation. The courage to turn down work (as opposed to fielding an inexperiencedseismic crew) may not be very common.

• several seismic contractors indicated that better advance planning by explorers wouldassist with more efficient and cost effective seismic operations.

• some producers are evaluating the long term benefits of ‘4 D’33 seismic.

• modern seismic operations tend to use narrower cut lines and mulch the timber andstumps. With additional access via 4 wheel drive quads, environmental damage ismitigated.

• most seismic contractors do not get financially compensated for operations beingtemporarily suspended due to inclement weather.

• several seismic contractors indicated that they are able to conduct seismic operationsfaster today, due to technological improvements34

• despite the vast improvement in data quality and operational efficiency, seismic istoday regarded as a commodity, which applies enormous pricing pressure onto thevery competitive seismic industry.

33 4 D seismic is the same as 3 D seismic, except the seismic is undertaken every year. This provides insight regarding

oil, gas, and other fluids movement through the field during production.34 Currently seismic operators can undertake 2 square miles of seismic vs 0.5 square mile per day


Western Canada Infrastructure

Figure 50 illustrates the existing road infrastructure in Western Canada. The road network isextensive through out the southern portions of Alberta and yet underdeveloped in Northern Albertaand Northeast British Columbia. Regions with extensive road systems allow both seismic anddrilling operations to be undertaken throughout the year.

Figure 50Western Canada Infrastructure Map

British Columbia Alberta SaskatchewanRoadsRiversParks


PEOPLE ISSUES

Looking forward over the next decade, four main factors will affect the long-term human resourcesneeds of the petroleum services industry:

a) declining traditional labour pool (as shown in Figure 51). Canada lost a quarter of its farmworkers between 1998 to 2001, with Alberta dropping over a third, possibly due to increases infarming operating costs.

b) competition for labour from other industry’s (construction, forestry, transportation,manufacturing, oil sands and mining) is attracting the farm worker who is generally well versedin technical machine operating skills

c) fewer skilled petroleum personnel replacing the ongoing retirement of long time oil and gasworkers35

d) the seasonal and yearly work requirements contribute to the high employment turnover whichtends to encourage new work force entrants to abandon the energy service sectors and seek morestable, full time employment in other industries. This turnover results in new ‘green’ work forceadditions that at times strains the supervision capability of the experienced crews.

For example, a major source of field operations personnel was the Western Canada farmer during thewinter season. Farm operations in Western Canada have shrunk over the past few decades. Figure51 shows that Western Canada farms have dropped to 146,000, down 10% since 1996.

35 Additionally, the younger (under 34 years) farm operators are migrating to other career opportunities (in Alberta, the

under 34 years group shrunk a third during the 1996 to 2001 period, and by half since 1991). This suggests thatoscillating oil and gas ‘patch’ cycle is discouraging new employees from entering into this industry

Figure 51Western Canada Farms

146162

0

50

100

150

200

1996 2001

Farms (000)

0

50

100

150

200Farms (000)

10% Decrease

Note: Western Canada covers Manitoba to B.C.Decrease of 10% or 16,000 Western Canada farms in 5 years.


Competition for Operational Staff

Historically, oilfield compensation was significantly better than available alternatives and helpedensure than qualified staff returned each year. Over the past few years, the competition for fieldlevel workers has intensified because of more drilling activity and other industries (forestry,oilsands, retail, housing) offering attractive alternative work36. Continuous 12 month employment isa key factor to retain many of the qualified individuals in the work force.

This results in a shift of some workers to other more stable industries (one service provider estimatedthe cost of losing staff at Cdn$9,500/employee). This new challenge for the oil and gas industry hasrequired seismic and well site service providers to expand their human resource searches to acrossNorth America.

Safety

Seismic and drilling operations require a large field level labour force to undertake various services.As the services provided are generally cyclic (mostly winter), a critical challenge exists to hire, train,and retain a competent work force. The energy industry views safety as a key attribute of dailyoperations. In most operations, safety is everyone’s responsibility. Many producers and serviceproviders have financial incentives that encourage and motivate safe operations. Figure 52 providesa recent summary of lost time claims for the Alberta energy sectors. Increased drilling results inincreases to lost claim rates.

36 Stable employment through out the year, less travel, more time with family, and at equally attractive

annual remuneration.

Figure 52Lost-Time Claim Rate

Alberta: 1997 - 2002

0

10

20

30

40

50

1997 1998 1999 2000 2001 20020

4,000

8,000

12,000

16,000

20,000

All Upstream Oil and Gas ExplorationOilfield Maintenance and Construction Well Services with Service RigsOil and Gas Drilling Downhole and Other Oilfield ServicesTar Sands Oil and Gas Exploration and DevelopmentOilfield Trucking Services Total Alberta Drilling

Rate per 100Person-Years

Source: Alberta Human Resources & Employment, Workplace Health & Safety, & Ziff Energy

Total Alberta Drilling


APPENDICES

Appendix A – Criteria for Industry Interviews

Type Company

Maj

or

US

Con

trol

led

Inde

pend

ent

Can

adia

n C

ontr

olle

dIn

depe

nden

t

B.C

. Exp

lore

r

SEPA

C M

embe

r

Rec

ently

Mer

ged

Roy

alty

Tru

st

Util

ise

Hor

izon

tal

Tech

nolo

gy

Con

vent

iona

l Hea

vy O

il

Dril

ling

Con

trac

tor

Serv

ice

Rig

Con

trac

tor

Serv

ice

Com

pany

Seis

mic

E&P

Indu

stry

Ass

ocia

tion

Petr

oleu

m S

ervi

ces

Ass

ocia

tion

Dril

ling

Con

sulta

nt

Safe

ty

Gov

ernm

ent

1 EnCana X X X X X X2 CNRL X X X X X

3 US/ForeignIndependent X X X X X X

4 EOG X X5 Burlington X X X X X6 Devon X X X X X7 ConocoPhillips X X X X X X8 Major X X X X9 Petro-Canada X X X X X10 Penn West X X X X X11 Apache X X X X X12 Royalty Trust X X13 Nexen X X X X X14 Enerplus X X15 Rife Resources X X X

PRODUCERS

16 Small Producer X X X17 Precision X X18 Ensign X X19 Nabors X X20 Concord X X21 Trican X X

SERVICE

22 BJ X X23 WesternGeco X X24 Veritas X X25 Conquest X X

SEISMIC

26 Arcis X X27 CAPP X X28 PSAC X XASSOC.29 CAGC X X X

CONSULTANT 30 Bissett ConsultantsFrontier Engineering

XX

XX

31 Alberta Government X XGOVERNMENT

32 BC Government X X


Appendix B – List of Industry Interviewees

Type Company Name Title

1 EnCana Dan O’Neil Vice President, New Ventures Exploration2 CNRL Brian Illing Executive Vice President, Exploration

3 US/ForeignIndependent Senior Staff Senior function

4 EOG Lanny Fenwick Senior Vice President & General Manager5 Burlington Dave Afseth General Manager, Drilling, Completions and Construction6 Devon Bob Jones Vice President, Exploration7 ConocoPhillips Archie Kennedy Senior Vice President, Operations8 Major Declined Interview Senior Function9 Petro-Canada Peter Haverson Manager, Drilling and Completions10 Penn West Donald Rae Senior Vice President, Exploration11 Apache Floyd Price President & Chief Executive Officer12 Royalty Trust Not Available President13 Nexen Alistair Mooney Vice President, Exploration and Production14 Enerplus Garry Tanner Senior Vice President & Chief Operating Officer15 Rife David Sandmeyer President

PRODUCERS

16 Small Producer Declined Interview President

17 Precision Charles Gowler Contract Representative18 Ensign Selby Porter President19 Nabors Lou Doiron President20 Concord Gord Vivian Vice President21 Trican Sam Luk Senior Technical Specialist

SERVICE

22 BJ Blair Albers Region Manager

23 WesternGeco Ken Lengyel Multiclient Library2425 Veritas Mike Scott

Mike LaurinGeneral ManagerVice President, North America

26 Conquest Milt Tetzlaff General ManagerSEISMIC

27 Arcis Kevin Mitchell General Manager

28 CAPP Dave Pryce Vice President, Western Canada Operations2930 PSAC Roger Soucy

Zane ReiterPresidentManager Corporate Development

INDUSTRYASSOC.

31 CAGC Mike Doyle President

CONSULTANT 3233

Bissett ResourceFrontier Engineering

K. R. (Dick) BissettW. H. (Bill) Garman

PresidentDrilling and Completions Manager

34

3536

Alberta Government

Wally Baer

Jane ClerkR. W. (Bob) Taylor

Director of Compliance, Work Place Health and Safety andEmployment StandardsADOE Business unit leader (Oil Development)Assistant Deputy Minister, Alberta Dept. of EnergyGOVERNMENT

3738 BC Government David Molinski

Carmine VertoneDirector, Markets & Fiscal AnalysisSpecial Projects


Appendix C – Interview Questions

1. The majority of 1st quarter drilling occurs in the northern half of Alberta and BC. Can youshare your insight and explain why this happens, and comment on suggested steps (includingpolicy changes) required to spread drilling out over a full year?

2. Over one-third (39%) of Alberta 2002 drilling occurs in the first quarter, requiring theindustry to have high levels of both staff and major equipment available for short periods oftime. Do you have suggestions that may assist industry to streamline its drilling pattern‘more smoothly’ over the entire year?

3. Alberta other drilling (abandoned, service, injection) is generally much higher in firstquarter (63% for 1st quarter 2002). Can you shed light on why this is so? Can you shareyour opinion on how this might be changed to provide a flatter industry drilling program?

4. For BC, 1st quarter drilling is more significant. For example, in 2002, 71% of gas and92% of oil drilling occurred in the 1st quarter. Can you explain why most drilling occursduring the winter? Do you have suggestions that may assist industry to optimise the BCdrilling cycle to a more uniform drilling cycle?

5. Can you share insight why WCSB horizontal drilling is more evenly balanced over the year(32% in 1st quarter) as opposed to mostly drilled during the winter? Do you think that yourreasons could apply to other oil and gas drilling patterns?

6. While recent sour well activity is not available, during 1998 and 1999 each, 40% of sourwells were drilled in the 1st quarter (this may have dropped to 30% in Q1 2000). Are thereany unique aspects of sour drilling that requires the drilling to be undertaken during the firstquarter as opposed to ‘planning’ it over a full year? Are there any changes that could beundertaken to improve the drilling cycle to a flatter monthly profile?

7. Alberta 2002 shallow drilling (under 3,500 ft), 41% occurred in the 1st quarter. Do you haveinsight as to why this large percentage of drilling occurs in the first quarter, vs. spreading thedrilling over the year? What steps can be taken to change industry to smooth out the drillingcycle?

8. Our analysis indicates that Alberta medium and deep drilling is less concentrated in the firstquarter than shallow gas drilling. Can you share your thoughts on why? Are there severalimpediments that you may be aware of that are encouraging more shallow drilling in the firstquarter that medium/deep drilling? Do you have some initial suggestions on steps that theindustry can take to convert the medium and deep drilling to a more flat profile?

9. Are there steps that drilling and service contractors could undertake that may assist theirdrilling operations to be more balanced over the year (re-allocate rigs for different times ofthe year)?


10. Drilling staffing requirements are generally higher in the first quarter. This tends to affectstaffing levels for the other 9 months of the year (layoffs and re-hiring, retaining experiencedpersonnel). Consequently, workers require training each year (a cost to industry), and trainedworkers may not return to the industry. Do you have suggestion that may assist to retain staffthrough out the year?

11. Worker safety is also affected by concentrated drilling in the first 3 months of the year(fatigue from working long hours over a period of several months), insufficient manpowerfor a third 12-hour shift to rotate personnel for longer-term continuous rig operations. Thismay be a driver for accidents. Do you have suggestions that would help reduce thepotential for accidents?

12. Concentrated drilling in the first quarter requires additional experienced drilling consultantsto work longer hours in a shorter time period (several months). This may lead to reducesafety on site (less experienced personnel and fatigue) plus having to drive long distance afterworking extended hours for time off (driving safety). Are you aware of any companyinitiatives or do you have insight that you can share which may help alleviate these issues?

13. What government policies (Alberta, BC, Federal) can be initiated, changed, or revised tohelp encourage or persuade the energy industry to have more balanced drilling over the year(which improves worker safety and staffing levels)?

14. What are your thoughts on how industry associations can influence the industry to seek amore balanced drilling cycle activity over the year?

15. Do you have other points or suggestions as to specific recommendations that would assistthe drilling industry with this objective to optimise the drilling cycle?

16. What are the dominant factors that affect the timing of geophysical activity over the year(oil/gas pricing, company mergers, increased profile of royalty trusts, gas exploration,seasonal access, road access, surface conditions for signal transmission, other)?

17. How can the geophysical industry position itself to better accommodate year round activityversus first quarter or winter peaking?

18. Are there other suggestions available to streamline the geophysical activity to a moreconstant level each month? What incentives (via government policy change) may help toachieve this objective?


Appendix D – Scope of the Ziff Energy Drilling Cycle Study

Cross Sectional Industry Sample

A key issue for this drilling cycle assessment is to have the ‘facts, insight, and opinions’ on whymost companies focus the majority of their drilling activity in the first quarter (versus spreading thework level over the balance of the year). Underpinning our analysis will be a structured interviewprocess of critical sectors in the industry. To ensure we select an appropriate cross sectionalindustry sample, Ziff Energy will first review historical drilling activity from several importantperspectives:

• gas vs. light oil vs. heavy oil

• drilling strategy - shallow vs. deep

• company type: major vs. independent vs. royalty trust vs. junior (consider flowthrough shares)

• American vs. Canadian control

• land/road availability vs. Western Canada region vs. government regulation foraccess (environment, animals) vs. well connection process

• people issues: training for staff vs. working hours (overtime) vs. availability ofservice personal vs. safety records

• Ziff Energy will seek initial input from CAPP, which may be a co-sponsor, andfrom a drilling contractor to capture additional insight on perspectives that shouldbe examined.

Our initial analysis will commence with profiles of drilling activity by company that distinguishespatterns, and especially companies, which lie outside the typical drilling pattern.

Industry Interview Process

Gathering specific industry feedback from a cross section of industry will greatly assist inunderstanding the industry rationale why drilling activity is so concentrated in the first quarter. Theinterview process will also ‘zero in’ on potential industry or government solutions that may be actedupon to achieve in the future a better distribution of work activity over the year. While additionalprofile analysis of the specific companies to interview is required, our initial outlook suggests about15 interviews, likely at the VP level:

• exploration and production industry:

- Majors (2 companies)

- US controlled independents (2)

- Canadian controlled independents (2)

- SEPAC members (2)

- recent ‘merged’ company (above)


- royalty trusts (2)

- leading explorer that utilises horizontal well technology (above)

- conventional heavy oil explorer/developer (above)

• leading drilling contractors with strong focus on Canada (2)

• leading service contractors (2)

• E & P industry association (CAPP), and a drilling consultant (Bissett) (2).

We would be pleased to integrate sponsor input in the selection of the companies and individuals tobe interviewed. During the interview process, Ziff Energy will outline the purpose of theassessment, review our initial analysis, and seek additional input whether the company has furtherinsights as to the drivers of why industry incurs more activity in the first quarter. The resultingmatrix of feedback will be analysed and documented. Our recommendations will reflect theknowledge gained from the interviews and our evaluation.

Written Report

Ziff Energy will prepare a written report, with review of trends by sector and by type, and industryfeedback on why drilling is concentrated in the first quarter. The report will provide suggestions orrecommendations that would assist at streamlining industry activity over the year. Illustrations,graphical display, and tabular summaries will be extensively utilised to assist in the understanding ofthe assessment. While a detailed table of contents has not been prepared, Ziff Energy expects thefinal report to be about 20 pages, with supporting detail summarised in Appendices. The sponsorswill be invited to provide final review of the report prior to issuing the final colour report copy.

Timing

An in-depth analysis of this magnitude requires time to plan, gather data, analyse, interview,research, assess, and document. Our interactive consulting approach includes ongoing feedback andstatus summaries with the sponsors to reflect new input and to ensure specific deliverables are ontarget. It is our intent to target to deliver a final written report in June 2003.


Appendix E – Ziff Energy Background

Ziff Energy Group, founded in 1982, is a leading international energy consulting firm providingsophisticated industry and operational business analysis, specialised consulting, and learningservices to the world wide energy industry. We have offices in Houston and Calgary, the twoprincipal oil and gas centers in North America. Our staff of 55+ includes many senior industryspecialists, with 15 - 25+ years of domestic and international experience. The firm focuses itsefforts principally in two areas:

• Gas Services; Ziff Energy Group is recognised for its in-depth analysis of NorthAmerican as well as regional gas markets, gas and liquids supply, transportation,midstream, storage, regulatory affairs, and gas pricing forecasts.

• E & P; more than 100 North American upstream producers have been involved infield level operating cost and finding and development cost studies that cover mostNorth America onshore and offshore production basins, and a growing number inforeign countries.

We are a major provider of natural gas customised consulting services to our growing list of clients.We undertake Gas Consulting assignments that address specific client needs in the areas ofoperations, strategies, and regulatory matters.

Paul H. Ziff - CEO, is a leading consultant to the oil and natural gas industry and isan expert on natural gas industry strategies and corporate performance of the NorthAmerican exploration and producing industry. He has conceived and directed awide range of top class studies in both the areas of gas issues and corporateperformance. Mr. Ziff founded the Ziff Energy Group in 1982 after beingresponsible for a major investment firm's energy research. Previously he wasDirector, Gas Pricing for a key energy agency of the Alberta government. Over thepast two decades he has consulted extensively to a wide range of clients in theNorth American and international energy industry. Mr. Ziff is an honours graduateof Harvard University, and attended the Université de Paris (Sorbonne) and theInstitut d'Études Politiques. He has been a featured guest speaker to many industryassociations and conferences in Canada and the United States, and is widely quotedin business and trade media.

W.P. (Bill) Gwozd, P.Eng. – Vice President, Gas Services, is responsible forcustomised consulting projects pertaining to various gas services. Mr. Gwozd hasover two decades of experience focusing upon gas supply strategies, gas storage,pipelines and NGL projects. Prior to joining Ziff Energy Group in 1998, he wasdirectly involved for a dozen years with development and implementation of acomplex gas supply portfolio, including gas storage requirements and transportationco-ordination for the ATCO group of companies. Earlier experience includesmidstream assignments with Amoco on NGL pipelines and NGL storage projects.Bill has been an active participant with the Pacific Coast Gas Association. Heobtained his Chemical Engineering degree from the University of Calgary (1979)and a diploma in Chemical Engineering Technology from SAIT (1976).

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