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Economic Impacts of Drilling, Completing and Operating Conventional Oil Wells in Western Canada (2010-2035)

June 2011

ECONOMIC IMPACTS OF DRILLING, COMPLETING AND OPERATING CONVENTIONAL OIL WELLS IN WESTERN CANADA (2010-2035)

Economic Impacts of Drilling, Completing and Operating Conventional Oil Wells in Western Canada (2010-2035)

Copyright © Canadian Energy Research Institute, 2011 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute ISBN 1-927037-01-0 Authors: Peter Howard Afshin Honarvar Carlos A. Murillo Acknowledgements: The authors of this report would like to extend their thanks and gratitude to everyone involved in the production and editing of the material, including, but not limited to Megan Murphy CANADIAN ENERGY RESEARCH INSITTUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca June 2011 Printed in Canada

http://www.ceri.ca/

Economic Impacts of Drilling, Completing and Operating iii Conventional Oil Wells in Western Canada (2010-2035)

June 2011

Table of Contents LIST OF FIGURES .............................................................................................................................. v

LIST OF TABLES ................................................................................................................................ vii

EXECUTIVE SUMMARY .................................................................................................................... ix

Major Findings ................................................................................................................................ xiii Terminology and Assumptions ....................................................................................................... xiv

CHAPTER 1 INTRODUCTION ....................................................................................................... 1

Methodology .................................................................................................................................. 2

CHAPTER 2 ECONOMIC IMPACTS OF CONVENTIONAL OIL DEVELOPMENTS – ALBERTA ..................................................................................................... 5

Canadian Impacts ........................................................................................................................... 5 US Impacts ...................................................................................................................................... 7

CHAPTER 3 ECONOMIC IMPACTS OF CONVENTIONAL OIL DEVELOPMENTS – SASKATCHEWAN ......................................................................................... 9


CHAPTER 4 ECONOMIC IMPACTS OF CONVENTIONAL OIL DEVELOPMENTS – BRITISH COLUMBIA ..................................................................................... 13


OBSERVATIONS ON AREA ANALYSIS ............................................................................................... 17

APPENDIX A ................................................................................................................................ 19

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Economic Impacts of Drilling, Completing and Operating v Conventional Oil Wells in Western Canada (2010-2035)

June 2011

List of Figures Figure E.1 CERI Drilling Forecast by Province and Well Type (Realistic Scenario) ............................ x Figure E.2 CERI Production Projection (Realistic Scenario) ............................................................... xi Figure E.3 CERI Production Projection by Province and Well Vintage (Realistic Scenario) ............... xii Figure E.4 CERI Capital Requirements by Province (Realistic Scenario)............................................ xiii Figure 1.1 Well Type by Province versus Production Rate................................................................ 1 Figure 2.1 Jobs (x1000) Created and Preserved in Canada as a Result of Drilling for Conventional Oil in Alberta, 2010-2035 ......................................................... 6 Figure 2.2 Royalties Paid to the Alberta Government for Conventional Oil Developments ............. 7 Figure 2.3 Jobs (x1000) Created and Preserved in the United States as a Result of Drilling for Conventional Oil in Alberta, 2010-2035 ......................................................... 8 Figure 3.1 Jobs (x1000) Created and Preserved in Canada as a Result of Drilling for Conventional Oil in Saskatchewan, 2010-2035 .............................................. 10 Figure 3.2 Royalties Paid to the Saskatchewan Government for Conventional Oil

Developments .................................................................................................................. 11 Figure 3.3 Jobs (x1000) Created and Preserved in the United States as a Result of Drilling for Conventional Oil in Saskatchewan, 2010-2035 .............................................. 12 Figure 4.1 Jobs (x1000) Created and Preserved in Canada as a Result of Drilling for Conventional Oil in British Columbia, 2010-2035 .......................................... 14 Figure 4.2 Royalties Paid to the British Columbia Government for Conventional Oil

Developments .................................................................................................................. 15 Figure 4.3 Jobs (x1000) Created and Preserved in the United States as a Result of Drilling for Conventional Oil in British Columbia, 2010-2035 .......................................... 16

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Economic Impacts of Drilling, Completing and Operating vii Conventional Oil Wells in Western Canada (2010-2035)

June 2011

List of Tables Table 2.1 Economic Impacts of Conventional Oil Developments in Alberta, 2010-2035, Investments and Operations......................................................................... 6 Table 2.2 Tax Receipts as a Result of Conventional Oil Drilling in Alberta, 2010-2035, Federal and Provincial-Municipal ................................................................. 7 Table 2.3 Total Economic Impacts of Alberta Conventional Oil Drilling by

US PADD, 2010-2035 ........................................................................................................ 8 Table 3.1 Economic Impacts of Conventional Oil Developments in Saskatchewan, 2010-2035, Investments and Operations......................................................................... 10 Table 3.2 Tax Receipts as a Result of Conventional Oil Drilling in Saskatchewan, 2010-2035, Federal and Provincial-Municipal ................................................................. 11 Table 3.3 Total Economic Impacts of Saskatchewan Conventional Oil Drilling by

US PADD, 2010-2035 ........................................................................................................ 12 Table 4.1 Economic Impacts of Conventional Oil Developments in British Columbia, 2010-2035, Investments and Operations......................................................................... 14 Table 4.2 Tax Receipts as a Result of Conventional Oil Drilling in British Columbia, 2010-2035, Federal and Provincial-Municipal ................................................................. 15 Table 4.3 Total Economic Impacts of British Columbia Conventional Oil Drilling by

US PADD, 2010-2035 ........................................................................................................ 16

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Economic Impacts of Drilling, Completing and Operating ix Conventional Oil Wells in Western Canada (2010-2035)

June 2011

Executive Summary Conventional oil production (i.e., excluding pentanes plus, bitumen and synthetic crude oil) from

the Western Canada Sedimentary Basin (WCSB) has been declining since the early 1970s after

reaching a peak production of approximately 2 million barrels per day (MMBPD). Over the past

ten years the production rate has continued to decline, dropping from 1.2 MMBPD in 2001 to

0.9 MMBPD in 2010. Over this same time period, new oil well completions have increased from

4,000 in 2002 to 5,500 in 2008.1 The WCSB is considered a mature basin and it was becoming

obvious at the time that maintaining the output from the basin was going to take significantly

more new wells each year.

The worldwide recession in 2008 affected the oil industry in the same fashion as other

industries. Demand for oil products retracted, oil prices fell and new drilling activity in the WCSB

dropped by close to 40 percent between 2008 and 2009. Conventional oil production declined

further than expected as the reduced number of new wells failed to offset the decline from

existing wells. 2010 was a restart year for the industry as new well licensing activity picked back

up reaching the 5,000 well level equal to the activity three years prior in 2007 (see Figure E.1).

Prior to the recession, a change in the type of drilling towards horizontal wells had started to

take place and the effects of those changes were first being noticed in Saskatchewan. The

advent of horizontal well technology which became popular in the development of tight and

shale gas formations had started to make inroads in Saskatchewan, especially over the past 5

years. In Saskatchewan, the percentage of horizontal wells grew from 24 to 49 percent between

2004 and 2009 and the assumption is that this percentage will continue to grow.

The Canadian Energy Research Institute’s (CERI) drilling forecast is based on the assumption that

the short-term outlook (5 years) for oil drilling in the WCSB is one of continued growth based

partly on the perception of an increasing oil market price and partly on the attraction of

increased production rates from horizontal well developments. Figure E.1 represents CERI’s

“realistic case” for drilling conventional oil in British Columbia, Alberta and Saskatchewan and is

based on the following assumptions:

Drilling for oil will continue to grow year over year for the next 5 years following the trend line established in the years 2004 to 2008.

Drilling will plateau by 2016 and decline after that by 2 percent per year for Alberta and Saskatchewan. This assumption is based on the unknown nature of continuing to increase drilling in mature basins coupled with the situation that oil sands developments and shale gas developments will be attracting increased attention in the latter part of the decade.

1Data provided by the BC Oil and Gas Commission; the Alberta Energy Resources Conservation Board, and the

Saskatchewan Ministry of Energy and Resources.

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The relationship between vertical wells and horizontal wells will continue to change in the future in favour of drilling more horizontal wells. The rate of change is assumed to be a 5 percentage point per year increase in areas that are currently drilling less than 35 percent horizontal wells and a 20 percentage point per year increase in areas that currently drill more than 35 percent horizontal wells.

Figure E.1: CERI Drilling Forecast by Province and Well Type (Realistic Scenario)

Based on the drilling forecast presented in Figure E.1 and accounting for the decline curves,

initial production rates, and changing relationship between drilling vertical and horizontal wells

as presented in Appendix A, Figure E.2 depicts the resulting oil production forecast for the WCSB

broken down by province. Also included on this chart is the conventional oil forecast for the

WCSB published by the Canadian Association of Petroleum Producers (CAPP) in June 2011 (for

comparison purposes).

The CERI projection model not only takes into consideration the historical production declines

(type curve) and the positive and negative changes in historical initial production rates but it

also accounts for the incorporation of a changing drill type, favouring horizontal well

developments over vertical well developments, and the potential for increasing initial

production rates in the future based on longer horizontal legs. Examples include the “PIA08”

play as described in Appendix A, where the average initial production rate that has grown from

8 m3/day (50 BPD) to just under 10 m3/day (63 BPD) in 3 years. Area “PIA11” has shown even

more dramatic results with increases from 8 m3/day (50 BPD) to 27 m3/day (170 BPD), also in 3

years. The Bakken oil play in the southeastern part of Saskatchewan has not shown the same

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Forecast

Economic Impacts of Drilling, Completing and Operating xi Conventional Oil Wells in Western Canada (2010-2035)

June 2011

change in initial production rates but, on average, a horizontal well in that area consistently

starts with a production rate that is 3 times greater than a vertical well. Area “PIA56” (southeast

Saskatchewan) indicates an average vertical well displayed an initial production rate of less than

5 m3/day (31 BPD) while an average horizontal well starts at an initial production rate of greater

than 15 m3/day (94 BPD).

Figure E.2 shows the results of CERI’s production forecast based on the drilling forecast

presented in Figure E.1 and incorporating the assumptions of future changes to initial

production rates and the increasing influence of horizontal wells. For consistency, production

from Manitoba and the Northwest Territories has been adopted from CAPP’s June 2011 forecast

and appended to Figure E.2. In Alberta, in 2010, the number of horizontal oil directed licenses

grew to 62 percent of all oil directed wells. This is a significant change from 2006 where the

number was 24 percent. Figure E.2 demonstrates that fewer more productive horizontal wells

will stabilize and grow the production output of oil from Alberta and Saskatchewan. Alberta will

be able to maintain the output level longer than Saskatchewan primarily based on the assumed

increasing initial production rates.

In the later years (2020-2035) of this forecast, the production volume from Alberta declines at a

slower rate as compared to Saskatchewan. The reason for this is the initial production rates

from areas 10, 11 and 15 (central Alberta) are significantly larger than areas 51 and 52 (central

west and northwest Saskatchewan) and area 56 (southeast Saskatchewan). Based on this

observation this forecast assumes that drilling intensity in these areas will be greater in future

years as compared to the base year of 2009 which was used to establish the initial percentage

split in drilling activity per area.

Figure E.2: CERI Production Projection (Realistic Scenario)

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British Columbia Conventional Crude Alberta Conventional Crude Saskatchewan

Manitoba Northwest Territories CAPP Forecast

xii Canadian Energy Research Institute

June 2011

Figure E.3 depicts the changing contribution of production from existing wells versus production

from forecasted new wells also separated out by province of origin.

Figure E.3: CERI Production Projection by Province and Well Vintage (Realistic Scenario)

The drilling well forecast presented in Figure E.1 is converted to a capital outlay forecast by utilizing the well cost data from the Petroleum Services Association of Canada (PSAC) depth corrected to the average drilling depth by area. In addition, operating costs, connection costs, geological and geophysical costs and operating costs for continued operation of existing oil wells (wells drilled prior to the base year and forecasted to continue to operate in the future) are accounted for and displayed in Figure E.4. These costs are based on data presented in CAPP’s statistical handbook for Canada’s upstream petroleum industry (May 2011).

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Economic Impacts of Drilling, Completing and Operating xiii Conventional Oil Wells in Western Canada (2010-2035)

June 2011

Figure E.4: CERI Capital Requirements by Province (Realistic Scenario)

Major Findings Over the 2010-2035 period the estimated investments, reinvestments, and revenues

from operation of the existing and future conventional oil developments in western

Canada are $1,059 billion.

Total Canadian GDP impact as a result of the investment shocks is estimated at close to

$1,056 billion over the 25-year period.

Canadian employee compensation will reach almost $259 billion over this time period.

Employment in Canada (direct, indirect, and induced) is expected to grow from 152,000

jobs to a peak of 227,000 jobs in 2020.

Alberta royalties are expected to grow from $0.75 billion in 2010 to a peak of $4.7

billion in 2027.

British Columbia royalties are expected to grow from $0.06 billion in 2010 to a peak of

$0.075 billion over the study period.

Saskatchewan royalties are expected to grow from $1.2 billion in 2010 to a peak of $1.8

billion in 2014.

US GDP impact from 2010-2035, as a result of the investment shocks, is estimated at

close to CAD$100 billion.

US employee compensation will exceed $47 billion over the period.

US employment totals are expected to grow from 32,000 jobs to a peak of 49,000 jobs

in 2018.

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xiv Canadian Energy Research Institute

June 2011

Terminology and Assumptions Forecast Period – The forecast period is 25 years, starting at the end of 2010, with 2011

being the first year of capital injections for the new oil well developments and going out

to 2035.

All currency figures are in real 2010 (base year) Canadian dollars, unless specified

otherwise.

Employment (Thousand Person Years): Thousands of jobs created and preserved every

year. For instance, if a new conventional oil project starts operation by hiring 60 people

in the initial year, the employment is 0.06 thousand person years in the first year. If this

new conventional oil project adds incremental capacity in the second year and hires 25

more employees to operate the new facility, in the second year the in situ project has

created and preserved 0.085 thousand person years of employment. Of the 0.085

thousand person years of employment, 0.06 represents preserved jobs and 0.025 refers

to new jobs.

Jobs – Thousands of person years and thousands of jobs are used interchangeably

throughout this report. Thousand person years is the unit for the number of people

employed in a job for a year. A job is an occupation that one needs to do in order to be

employed. This should not be confused with stating that a job is a position that one is

hired into (i.e., as a plumber). For example, a company could hire 10 people in a year for

a position as manager and not hire any managers for later years. In the first year, the

total number of jobs is 10 and the total amount of person years for that year is 10.

However, by the end of the second year, the total number of manager jobs is still 10 but

the cumulative number of person years will have risen to 20 as 10 people will have

worked for 2 years. While the definitions of job and person years of employment may

be subject to interpretation, for the purposes of this report, the terms 10,000 jobs and

10 thousand person years both characterize 10,000 people employed for a year.

Taxes – Note that all of the tax estimates presented in this study include direct, indirect

and induced impacts. Generally speaking, taxes on income are considered direct taxes,

while taxes on expenditures (such as GST, HST, and PST) and all taxes deductible by

corporations for income tax purposes (such as property taxes) are considered indirect

taxes. The tax impact on a province includes taxes generated by economic activity

within a province payable to federal, provincial, and municipal governments.

PADD – Petroleum Administration for Defense Districts. These are five groups of US

states that were organized as such during WWII to ensure efficient distribution of

petroleum resources. The groupings remain in place today and are used to present

CERI’s results for the US.

- PADD I – Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine,

Maryland, Massachusetts, New Hampshire, New Jersey, New York, North Carolina,

Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia, West Virginia

- PADD II – Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri,

Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee, Wisconsin

- PADD III – Alabama, Arkansas, Louisiana, Mississippi, New Mexico, Texas

- PADD IV – Colorado, Idaho, Montana, Utah, Wyoming

- PADD V – Alaska, Arizona, California, Hawaii, Nevada, Oregon, Washington

Economic Impacts of Drilling, Completing and Operating 1 Conventional Oil Wells in Western Canada (2010-2035)

June 2011

Chapter 1 Introduction Oil production from the Western Canada Sedimentary Basin (WCSB) has been declining since the

early 1970s when production peaked at over 2 million barrels per day (BPD). This decline in

production has continued to current day where production in 2009 averaged just over 945,000

barrels per day. Production for the WCSB is made up of light, medium and heavy crudes

produced in the provinces of Alberta, British Columbia, Saskatchewan, Manitoba and the

Northwest Territories. Alberta and Saskatchewan make up 94 percent of the 2009 production.

Comparing Alberta and Saskatchewan for the period 2003 to 2008, as shown in Figure 1.1, the

number of newly connected vertical wells per year has remained relatively consistent over the

time period, 1,300-1,600 wells in Alberta and 1,200-1,400 wells in Saskatchewan. However, the

emerging horizontal well technology that had been employed extensively in the Saskatchewan

Bakken play (area PIA56) has increased the number of wells from 384 in 2003 to over 1,233 in

2008. The use of horizontal wells has effectively stabilized the production volume for

Saskatchewan whereas the production from Alberta has continued its downward trend. The

recession of 2008 curtailed drilling activity in all provinces however, the drilling of horizontal

wells in Saskatchewan remained at 45 percent of new Saskatchewan oil wells. The number of oil

directed well licenses issued by the Alberta Energy Resources Conservation Board (ERCB) in

2010 was 3,095 with 62 percent utilizing a horizontal well. CERI’s oil projection model utilizes

historical information and statistical relationships to develop a future forecast for oil production

emanating from the WCSB. The following section discusses the methodology used in this model.

Figure 1.1: Well Type by Province versus Production Rate

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2 Canadian Energy Research Institute

June 2011

Methodology Basic information is collected from the ERCB, Saskatchewan Energy and Mines (SEAM) and the

British Columbia Oil and Gas Commission (BCOGC) that details the historic production of

hydrocarbon fluids. In addition, the three provincial regulators provide data pertaining to the

individual well configuration as to its finish drilling date, initial production date, major

production fluid (oil, gas, coalbed methane, bitumen, etc.), original status, current status, total

depth, true vertical depth and location (township, meridian, range, section, and legal

subdivision). As this classification system in British Columbia is employed within the Peace River

block, a National Topographic System (NTS) location is used for wells drilled elsewhere in BC.

This information is used to establish such elements as: the Initial production rate (peak month of

production in the first 3 months of production), annual production by year, first production

date, and last production date (if abandoned). Monthly production of oil is summed and

averaged on a calendar year basis to establish an average daily production rate (m3/day) for

each year. Individual well production details are assigned to a specific study area based on the

Dominion Land Survey System (DLS) location or a National Topographic System (NTS) location.

The average initial daily production rate for all wells within a study area that commenced

production in the same year is established and a harmonic or exponential decline curve is

assigned in order to project production from the second year onward. This establishes a family

of production curves for each study area for vintages 2000 through 2009, separately for vertical

and horizontal wells.

The “Type” curve for each area as depicted in Appendix A is used to establish the decline path

for wells that are currently on stream (as of the base year 2009), based on the average number

of years the existing operating wells have been operating. The average on stream years defines

the starting point on the “Type” curve where the production rate will be for the forecast years.

This same curve starting at time zero is used to define the production path for new wells drilled

and connected in the future.

The initial production rates for the years 2000 through 2009 are shown on the same chart and

used to extrapolate the future declines or inclines in initial production rate for wells drilled in

the future. Simple regression curves are established to forecast the change in the initial

production rate (per well) in the future for a given study area and well type.

External to the model, a drilling forecast is determined on a provincial level and is based partially

on historical well developments and partially on the perceived future for oil drilling. The CERI

“Realistic Case” for oil well development drilling assumes a continuation of the year over year

growth in new wells, extrapolated from the historic period 2004 through 2008, continuing out 5

years into the future followed by a decline of 2 percent per year for the years following. The 5-

year growth window is based on the uncertainty in industry activity and is not an absolute

measure of the basin drilling opportunities.

The number of vertical wells drilled during any year in the future is determined by extrapolating

the percentage of vertical wells drilled in relation to total wells drilled in the historic years 2004


June 2011

through 2009 into the future years subject to a minimum 20 percent share for vertical wells to

reflect their continuing role in some reservoir types.

The following are some brief observations for the province of Saskatchewan as depicted in

Appendix A: Play ID “SKALL”. This set of charts depicts provincial average conditions including

the heavy oil area around Lloydminster and the light/medium oil play from southeastern

Saskatchewan where the Bakken oil play is situated. The details displayed on the “SKALL” page

include a graphic representation of vintage production, from both vertical and horizontal oil

wells, the daily production rate by year and the current operating wells by year also separated

out as vertical and horizontal wells. On examining the vintage production curves, it can be seen

that the decline in production from horizontal wells is steep in the beginning years, but by the

end of the 8th year of production, the production rates are comparable at 2.5 m3/day (15.7

BPD). As shown in the “Production by Year” chart for 2009, the average horizontal well had an

initial production rate of 15.3 m3/day (95 BPD) compared to the average vertical well’s 5.1

m3/day (32 BPD).


June 2011


June 2011

Chapter 2 Economic Impacts of Conventional Oil Developments - Alberta This chapter details the economic impacts of conventional oil developments, both existing and

future drilling of new wells in the province of Alberta and the associated impacts on the North

American economies. The impacts are calculated both for Canada and the United States, with

Canadian impacts examined at the provincial level and US impacts broken down to the PADD

level. The impacts under consideration are Gross Domestic Product (GDP), employee

compensation, employment, tax and royalty implications. These impacts cover all upstream

activities (geological and geophysical, drilling, completion and tie-in, and operation of existing

wells (as of December 2009) and new wells as defined by the CERI Realistic Case.

Canadian Impacts

The cumulative sum of additional Canadian GDP from 2010-2035, as a result of continued

operation of existing wells and the addition of new wells, is estimated at $572 billion (see Table

2.1). Employment in Canada (direct, indirect and induced) is expected to grow from 87,000 jobs

to a peak of 130,000 jobs in 2018. Direct employment in Alberta is estimated at 29,000 jobs at

the beginning of the study period, reaching a peak of 42,000 jobs in 2018. Compensation of

Canadian employees will reach a cumulative total of $155 billion by 2035.

Figure 2.1 depicts the national pattern of employment creation and preservation in each year

over the 25-year time frame of the study. The maximum employment impact occurs in the year

2018.

Table 2.2 summarizes the tax impacts by type of tax and by taxpayer’s province. Note that in this

format, federal, provincial and municipal taxes are shown together. Alberta is the largest

contributor to government based on the fact that the hydrocarbon development and corporate

headquarters are located within the province of Alberta. Ontario and British Columbia are the

second biggest contributors as a result of the contribution of tubular manufacturing industries in

eastern Canada and the close nature of hydrocarbon developments in western Canada.

Figure 2.2 displays the growth in royalties paid to the province of Alberta starting at $0.7 billion

in 2010 and growing to $4.7 billion in 2027. These royalty payments include both existing and

new wells as defined by the drilling forecast and utilizing the provincial royalty formulas as of

January 2011.


June 2011

Table 2.1: Economic Impacts of Conventional Oil Developments in Alberta, 2010-2035, Investments and Operations

*Government abroad.

Figure 2.1: Jobs (x1000) Created and Preserved in Canada as a Result of Drilling for

Conventional Oil in Alberta, 2010-2035

Thousand

Person Years

GDP Compensation

of Employees

Employment

Alberta 543,631 138,670 2,415

British Columbia 7,158 3,867 103

Manitoba 1,046 566 16

New Brunswick 203 100 3

Newfoundland & Labrador 91 32 1

Northwest Territories 36 18 0

Nova Scotia 208 106 3

Nunavut 7 4 0

Ontario 15,571 8,972 212

Prince Edward Island 15 8 0

Quebec 3,384 1,891 51

Saskatchewan 1,110 477 13

Yukon Territory 10 6 0

Gabd* 0 0 0

Total Canada 572,470 154,717 2,819

$CAD Million


June 2011

Table 2.2: Tax Receipts as a Result of Conventional Oil Drilling in Alberta, 2010-2035, Federal and Provincial-Municipal

Figure 2.2: Royalties Paid to the Alberta Government for Conventional Oil Developments ($millions)

US Impacts Total cumulative impact in the US as a result of continued operation and future drilling of

conventional oil wells in Alberta will contribute an estimated $52 billion over the 25-year

projection period (see Table 2.3). Figure 2.3 indicates the employment projection, which

suggests that total employment in the US is projected to grow from 17,000 jobs created and

preserved to a peak of 26,000 jobs in 2018. Cumulative compensation of employees in the US

will reach $25 billion by the end of the study period in 2035. This is based on the assumption

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$4

,67

9

$4

,68

9

$4

,69

6

$4

,69

4

$4

,69

6

$4

,67

5

$4

,67

3

$4

,65

3

$4

,63

1

$4

,60

0

$4

,56

7

$-

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

$5,000

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

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28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

Historical Forecast

Conventional Crude Oil Royalties


June 2011

that no other source of imported oil could be found to replace oil from Alberta. If a similar

quality oil could be imported, the downstream-related impacts would be insignificant.

Table 2.3: Total Economic Impacts of Alberta Conventional Oil Drilling by US PADD, 2010-2035

Figure 2.3: Jobs (x1000) Created and Preserved in the United States as a Result of Drilling for

Conventional Oil in Alberta, 2010-2035


June 2011

Chapter 3 Economic Impacts of Conventional Oil Developments - Saskatchewan This chapter details the economic impacts of conventional oil developments, both existing and

future drilling of new wells in the province of Saskatchewan and the associated impacts on the

North American economies. The impacts are calculated both for Canada and the United States,

with Canadian impacts examined at the provincial level and US impacts broken down to the

PADD level. The impacts under consideration are Gross Domestic Product (GDP), employee




Canadian Impacts


operation of existing wells and the addition of new wells, is estimated at $469 billion (see Table


to a peak of 95,000 jobs in 2018. Direct employment in Saskatchewan is estimated at 15,000

jobs at the beginning of the study period, reaching a peak of 25,000 jobs in 2018 (shown in blue

on Figure 3.1). Compensation of Canadian employees will reach a cumulative total of $99 billion

by 2035.


over the 25-year time frame of the study. The maximum employment impact occurs in the year

2018.


format, federal, provincial and municipal taxes are shown together. Saskatchewan is the largest

contributor to government based on the fact that the hydrocarbon development is located

within the province of Saskatchewan. Ontario and Alberta are the second biggest contributors as

a result of the contribution of tubular manufacturing industries in eastern Canada and the close

nature of hydrocarbon developments in western Canada.

Figure 3.2 displays the growth in royalties paid to the province of Saskatchewan starting at $1.2

billion in 2010 and growing to $1.8 billion in 2014. These royalty payments include both existing

and new wells as defined by the drilling forecast and utilizing the provincial royalty formulas as

of January 2011.


June 2011

Table 3.1: Economic Impacts of Conventional Oil Developments in Saskatchewan, 2010-2035, Investments and Operations

*Government abroad.


Conventional Oil in Saskatchewan, 2010-2035


June 2011

Table 3.2: Tax Receipts as a Result of Conventional Oil Drilling in Saskatchewan,

2010-2035, Federal and Provincial-Municipal

Figure 3.2: Royalties Paid to the Saskatchewan Government for Conventional Oil Developments

($millions)


conventional oil wells in Saskatchewan will contribute an estimated $47 billion over the 25-year

projection period (see Table 3.3) unless an alternative source of imported oil can be found.

Figure 3.3 indicates the employment projection, which suggests that total employment in the US

is projected to grow from 14,000 jobs created and preserved to a peak of 22,000 jobs in 2018.

$1

,47

6

$1

,71

0

$1

,58

5

$1

,39

0

$1

,18

2

$1

,37

9

$1

,59

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$1

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$1

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9

$1

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$1

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1

$1

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3

$1

,60

7

$1

,50

7

$1

,41

0

$1

,32

6

$1

,25

4

$1

,18

7

$1

,12

3

$1

,06

5

$1

,01

2

$9

65

$9

23

$8

85

$8

45

$8

12

$7

81

$7

50

$7

23

$6

98

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

20

06

20

07

20

08

20

09

20

10

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11

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20

35

Historical Forecast



June 2011

Cumulative compensation of employees in the US will reach $21 billion by the end of the study

period in 2035.

Table 3.3: Total Economic Impacts of Saskatchewan Conventional Oil Drilling by US PADD, 2010-2035


Conventional Oil in Saskatchewan, 2010-2035


June 2011

Chapter 4 Economic Impacts of Conventional Oil Developments – British Columbia This chapter details the economic impacts of conventional oil developments, both existing and

future drilling of new wells in the province of British Columbia and the associated impacts on the

North American economies. The impacts are calculated both for Canada and the United States,

with Canadian impacts examined at the provincial level and US impacts broken down to the

PADD level. The impacts under consideration are Gross Domestic Product (GDP), employee




Canadian Impacts


operation of existing wells and the addition of new wells, is estimated at $15.2 billion (see Table


to a peak of 2,800 jobs by the end of the forecast period. Direct employment in British Columbia

is estimated at 900 jobs at the beginning of the study period, reaching a peak of 1,100 jobs by

the end of the forecast period. Compensation of Canadian employees will reach a cumulative

total of $3.4 billion by 2035.


over the 25-year time frame of the study. The maximum employment impact occurs at the end

of the forecast period.


format, federal, provincial and municipal taxes are shown together. British Columbia is the

largest contributor to government based on the fact that the hydrocarbon development is

located within the province of British Columbia. Ontario and Alberta are the second and third

biggest contributors as a result of the contribution of tubular manufacturing industries in these

provinces and their proximity to hydrocarbon developments in western Canada.

Figure 4.2 displays the growth in royalties paid to the province of British Columbia starting at

$0.06 billion in 2010 and growing to $0.07 billion in 2035. These royalty payments include both

existing and new wells as defined by the drilling forecast and the provincial royalty formulas as

of January 2011.


June 2011

Table 4.1: Economic Impacts of Conventional Oil Developments in British Columbia, 2010-2035, Investments and Operations

*Government abroad.


Conventional Oil in British Columbia, 2010-2035


June 2011

Table 4.2: Tax Receipts as a Result of Conventional Oil Drilling in British Columbia, 2010-2035,

Federal and Provincial-Municipal

Figure 4.2: Royalties Paid to the British Columbia Government for Conventional Oil Developments

($millions)


conventional oil wells in British Columbia will contribute an estimated $1.2 billion over the 25-

year projection period (see Table 4.3). Figure 4.3 indicates the employment projection, which

suggests that total employment in the US is projected to grow from 500 jobs created and

$1

34

$1

15

$1

28

$4

2

$6

0

$5

7

$5

8

$5

9

$6

0

$6

0

$6

1

$6

1

$6

2

$6

2

$6

2

$6

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$6

3

$6

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$6

4

$6

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$6

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$6

6

$6

7

$6

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$6

9

$7

0

$7

1

$7

2

$7

3

$7

4

$-

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

$130

$140

20

06

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20

34

20

35

Historical Forecast



June 2011

preserved to a peak of 600 jobs by the end of the forecast period. Cumulative compensation of

employees in the US will reach $0.6 billion by the end of the study period in 2035.

Table 4.3: Total Economic Impacts of British Columbia Conventional Oil Drilling by US PADD, 2010-2035


Conventional Oil in British Columbia, 2010-2035


June 2011

Observations on Area Analysis For the base year 2009, the average conventional oil well in the WCSB (Appendix A, area

“WCSB”) starts with an initial production rate of 6 m3/day (38 BPD) for a vertical well

and 15.5 m3/day (98 BPD) for a horizontal well.

For the base year 2009, the average conventional oil well in Alberta (Appendix A, area

“ABALL”) starts with an initial production rate of 6 m3/day (38 BPD) for a vertical well

and 14.5 m3/day (91 BPD) for a horizontal well.

For the base year 2009, the average conventional oil well in Saskatchewan (Appendix A,

area “SKALL”) starts with an initial production rate of 5 m3/day (31 BPD) for a vertical

well and 15.2 m3/day (96 BPD) for a horizontal well.

For the base year 2009, the average conventional oil well in British Columbia (Appendix

A, area “BCALL”) starts with an initial production rate of 3.5 m3/day (22 BPD) for a

vertical well and 14 m3/day (8 BPD) for a horizontal well.

For the base year 2009, the areas with the highest initial production rates for vertical

wells are “PIA22”, “PIA11”, “PIA12” and “PIA09”. For horizontal wells the highest initial

production rates occurred in areas “PIA11”, “PIA10”, and “PIA02” in Alberta, “PIA34” in

British Columbia and “PIA56” and “PIA51” in Saskatchewan.

Over the past 10 years, the average conventional horizontal oil well in the WCSB

(Appendix A, area “WCSB”) declines faster in the initial years of production than the

average vertical well but the two curves come into close proximity after 8-10 years of

operation.


June 2011


June 2011

Appendix A WCSB Oil Production Decline Analysis The following pages capture the results of the analysis of historical oil production with respect

to a representative decline curve (vintage production curves), the historical change in initial

production rates (IP rates), average daily production rate and the number of operating wells.

This analysis is broken out by study area, by year and well type (horizontal versus vertical).

These results are used to determine the estimated well type decline curve, the decline or incline

curve to be used in determining the IP rate for future completed oil wells, and the historical

change in the number of horizontal wells to total wells drilled.

For Alberta, the areas are identified as “PIA01” to “PIA23”, British Columbia areas are identified

as “PIA30” to “PIA45” and Saskatchewan areas are identified as “PIA50” to “PIA56”. Provincial

averages are identified as “ABALL” for Alberta, “BCALL” for British Columbia, and “SKALL” for

Saskatchewan. The basin average is identified as “WCSB”. A map showing these study areas is

available on the company website (www.ceri.ca).

For each study area the following information is presented. Play ID identifies the analysis area as

described above. Play Group identifies the Canadian province where the area is situated. Play

Description describes the location of the area within the province. Decline Curve Type refers to

the curve equation that generates the “Type” curve. Reference is used to position the “Type”

curve on the chart for display purposes and has no meaning in the analysis.

For the chart “Vintage Production Curves”:

Historical information, segregated into vertical and horizontal well types, has been utilized to produce a family of production curves that are independent of time. For a given year, all wells that commenced production in that year, an average initial production rate is determined and assigned to time T1. For each subsequent year an average production rate is determined and assigned to time T2 through T12. The initial production rate for a well is defined as the peak daily rate (taken as volume produced in a month divided by the hours on stream in the same month) that was recorded in the first 6 months of production. For a given area, all wells that commenced production between 2000 and 2009 are included in the curves based on the year of first production.

The “Type” curve is an estimate of a decline curve that closely approximates the vintage decline over the past 10 years. This curve will be used to describe the decline for future wells.

Vertical wells are conventional oil wells drilled and completed vertically into a producing formation while horizontal wells are conventional oil wells drilled vertically to above the

http://www.ceri.ca/


June 2011

producing formation followed by drilling an arc to enter and extend horizontally into the producing formation.

Vertical wells are included in the left chart while horizontal wells are included in the right chart.

For the chart “All Wells: Production by Year”:

Total Daily Rate (left axis): refers to the total daily production rate (m3/day) from all conventional oil wells located within a given area, regardless of when they commenced production, for each year between 2000 and 2009.

Average Initial Production Rate (right axis): refers to the average of the maximum initial production rates for all conventional oil wells located within a given area based on the year that production commenced.

Vertical and Horizontal wells are displayed separately.

For the chart “Operating Wells By Year”:

Operating Well Count (left axis): refers to the number of wells that produced oil within a given area and given year. To qualify as an operating well, the well must have produced oil for a minimum of 1 month during the calendar year.

Vertical and horizontal wells are displayed separately.

Following is a text description of where each study area is located within the three western provinces.


June 2011

WCSB Oil Production Decline Analysis Study Areas

PIA01 Alberta Suffield Medicine Hat Area

PIA02 Alberta Bow Island Area

PIA03 Alberta Foothills Area west of Calgary

PIA04 Alberta Hussar to Princess Area

PIA05 Alberta Didsbury to Hussar Area

PIA06 Alberta Nevis and Ghostpine Area

PIA07 Alberta Bens Lake to Princess (North Lateral) Area

PIA08 Alberta Bens Lake to Canendish (East Lateral)

PIA09 Alberta Edson to Caroline (Plains Mainline)

PIA10 Alberta McLeod to Caroline (Foothills Mainline)

PIA11 Alberta Edmonton Area

PIA12 Alberta Bens Lake upstream to Calling Lake

PIA13 Alberta Gold Creek to Edson Area

PIA14 Alberta Vahalla to Gold Creek Area

PIA15 Alberta Judy Creek, Kaybon to Edson and McLeod

PIA16 Alberta Doe Creek to Teepee Creek Area

PIA17 Alberta Heart River Wolverine Creek Area

PIA18 Alberta Darling Creek to Slave Lake Compressor

PIA19 Alberta Fort McMurray Area

PIA20 Alberta Owl Lake Area

PIA21 Alberta Thunder Creek to Tanghe Creek

PIA22 Alberta Zama Lake to Meikle Compressor

PIA23 Alberta Princess to Empress Mainline

PIA30 British Columbia Pine River Lateral

PIA31 British Columbia Tupper Creek/Noel Area

PIA32 British Columbia Groundbirch Area

PIA33 British Columbia Dawson Creek

PIA34 British Columbia Fort St John Area

PIA35 British Columbia Chinchauga River

PIA36 British Columbia Ring Area

PIA37 British Columbia Kahntah Area

PIA38 British Columbia Shekilie Area

PIA39 British Columbia Peggo-Pesh Area

PIA40 British Columbia Helmut North Area

PIA41 British Columbia Fort Nelson to CS2

PIA42 British Columbia Fort Nelson to NWT Border

PIA45 British Columbia CS2 To Summit Lake Area

PIA50 Saskatchewan Southwest

PIA51 Saskatchewan Central West

PIA52 Saskatchewan Central Northwest

PIA53 Saskatchewan Not Used

PIA54 Saskatchewan Central Northeast

PIA55 Saskatchewan Central East

PIA56 Saskatchewan Southeast

PIA88 Other Pipeline Area PIA88

PIA99 Other Pipeline Area PIA99

WCSB Total WCSB Total WCSB

ABAll Total AB Total Alberta

BCAll Total BC Total British Columbia

SKAll Total SK Total Saskatchewan


June 2011


June 2011

WCSB Oil Production Decline Analysis by Pipeline Influence Area

1 Play ID PIA01 PIA012 Play Group Alberta

3 Play Description Suffield Medicine Hat Area

4 Decline Curve Type Har300 Decline Curve Type Har400

5 Reference 4.0 Reference 7.0

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Vintage Production Curves (Vertical Wells)

2000

2001

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2009

Type

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All Wells: Production By Year

Vertical Wells: red color, Horizontal Wells: green color

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Vintage Production Curves (Horizontal Wells)

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Type

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Operating Wells By Type and Year



June 2011



3 Play Description Bow Island Area

4 Decline Curve Type HAR160 Decline Curve Type HAR400


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June 2011



3 Play Description Foothills Area west of Calgary

4 Decline Curve Type EXP200 Decline Curve Type HAR140


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0.00

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10.00

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June 2011



3 Play Description Hussar to Princess Area



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June 2011



3 Play Description Didsbury to Hussar Area

4 Decline Curve Type EXP200 Decline Curve Type EXP200


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0.00

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10.00

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20.00

22.00

24.00

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ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

10

20

30

40

50

60

70

80

90

100

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Nevis and Ghostpine Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

500

1000

1500

2000

2500

3000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Bens Lake to Princess (North Lateral) Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

0

200

400

600

800

1000

1200

1400

1600

1800

2000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

700

800

900

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Bens Lake to Canendish (East Lateral)



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

1000

2000

3000

4000

5000

6000

7000

8000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Edson to Caroline (Plains Mainline)

4 Decline Curve Type HAR400 Decline Curve Type Har400


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

30.00

32.00

0

200

400

600

800

1000

1200

1400

1600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description McLeod to Caroline (Foothills Mainline)



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Edmonton Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

0

1000

2000

3000

4000

5000

6000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

500

1000

1500

2000

2500

3000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Bens Lake upstream to Calling Lake



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

0

100

200

300

400

500

600

700

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Gold Creek to Edson Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

30.00

32.00

34.00

36.00

38.00

40.00

0

200

400

600

800

1000

1200

1400

1600

1800

2000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Vahalla to Gold Creek Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

0

1000

2000

3000

4000

5000

6000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

200

400

600

800

1000

1200

1400

1600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Judy Creek, Kaybon to Edson and McLeod



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

30.00

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

200

400

600

800

1000

1200

1400

1600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Doe Creek to Teepee Creek Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

4.00

8.00

12.00

16.00

20.00

24.00

28.00

32.00

36.00

0

200

400

600

800

1000

1200

1400

1600

1800

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Heart River Wolverine Creek Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

4.00

8.00

12.00

16.00

20.00

24.00

28.00

32.00

36.00

40.00

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

500

1000

1500

2000

2500

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Darling Creek to Slave Lake Compressor



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

3.00

6.00

9.00

12.00

15.00

18.00

21.00

24.00

27.00

0

500

1000

1500

2000

2500

3000

3500

4000

4500

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

700

800

900

1000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Fort McMurray Area

4 Decline Curve Type NOPROD Decline Curve Type NOPROD


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Owl Lake Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

0

20

40

60

80

100

120

140

160

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

2

4

6

8

10

12

14

16

18

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Thunder Creek to Tanghe Creek



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

10.00

20.00

30.00

40.00

50.00

60.00

0

100

200

300

400

500

600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

5

10

15

20

25

30

35

40

45

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Zama Lake to Meikle Compressor



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Princess to Empress Mainline



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

0

1000

2000

3000

4000

5000

6000

7000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

200

400

600

800

1000

1200

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID PIA30 PIA302 Play Group British Columbia

3 Play Description Pine River Lateral

4 Decline Curve Type NPPROD Decline Curve Type NOPROD


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Tupper Creek/Noel Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

10

20

30

40

50

60

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

2

4

6

8

10

12

14

16

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Groundbirch Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

0

20

40

60

80

100

120

140

160

180

200

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

2

4

6

8

10

12

14

16

18

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Dawson Creek

4 Decline Curve Type HAR114 Decline Curve Type NOPROD


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

0

5

10

15

20

25

30

35

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

2

4

6

8

10

12

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Fort St John Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

700

800

900

1000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Chinchauga River

4 Decline Curve Type HAR200 Decline Curve Type NOPROD


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

0

5

10

15

20

25

30

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

2

4

6

8

10

12

14

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Ring Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Kahntah Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Shekilie Area

4 Decline Curve Type NOPROD Decline Curve Type HAR400


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

0

200

400

600

800

1000

1200

1400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

10

20

30

40

50

60

70

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Peggo-Pesh Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

0

20

40

60

80

100

120

140

160

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Helmut North Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Fort Nelson to CS2



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Fort Nelson to NWT Border



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

4.00

8.00

12.00

16.00

20.00

24.00

28.00

32.00

36.00

40.00

0

1

2

3

4

5

6

7

8

9

10

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

1

2

3

4

5

6

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description CS2 To Summit Lake Area



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID PIA50 PIA502 Play Group Saskatchewan

3 Play Description Southwest

4 Decline Curve Type HAR140 Decline Curve Type EXP170


6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

500

1000

1500

2000

2500

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Central West



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

0

2000

4000

6000

8000

10000

12000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Central Northwest



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

0

5000

10000

15000

20000

25000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

5

10

15

20

25

30

35

40

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

1000

2000

3000

4000

5000

6000

7000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Central Northeast



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

0

0

0

0

0

1

1

1

1

1

1

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Central East



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

0

200

400

600

800

1000

1200

1400

1600

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

50

100

150

200

250

300

350

400

450

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011



3 Play Description Southeast



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

0

5000

10000

15000

20000

25000

30000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

1000

2000

3000

4000

5000

6000

7000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID WCSB WCSB2 Play Group Total WCSB

3 Play Description Total WCSB



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

30.00

32.00

0

20000

40000

60000

80000

100000

120000

140000

160000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

10000

20000

30000

40000

50000

60000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID ABAll ABAll2 Play Group Alberta

3 Play Description Alberta



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

100000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

20

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

5000

10000

15000

20000

25000

30000

35000

40000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID BCAll BCAll2 Play Group British Columbia

3 Play Description British Columbia



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

100

200

300

400

500

600

700

800

900

1000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t




June 2011


1 Play ID SKAll SKAll2 Play Group Saskatchewan

3 Play Description Saskatchewan



6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

33

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49

50

51

52

53

54

55

0

2

4

6

8

10

12

14

16

18

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0.00

5.00

10.00

15.00

20.00

25.00

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

50000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Avera

ge I

nit

ial P

rod

ucti

on

Rate

(m

3/d

ay)

To

tal D

ail

y R

ate

(m

3/d

ay)



0

2

4

6

8

10

12

14

16

18

1 2 3 4 5 6 7 8 9 10 11 12

Avera

ge A

nn

ual

Dail

y R

ate

(m

3/d

ay)


2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Type

0

5000

10000

15000

20000

25000

30000

35000

40000

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

Op

era

tin

g W

ell

co

un

t



Economic Impacts of Drilling, Completing and Operating ...

Documents

Transcript of Economic Impacts of Drilling, Completing and Operating ...