updated to include natural gas liquids (ngls) · ngls, it does not solve for the price of ngls.) 2...

CANADIAN ENERGY RESEARCH INSTITUTE

CONVENTIONAL NATURAL GAS

SUPPLY COSTS IN WESTERN

CANADA – AN UPDATE

Updated to Include

Natural Gas Liquids (NGLs)

Study No. 136 Update December 2013

Canadian Energy Research Institute | Relevant • Independent • Objective

CONVENTIONAL NATURAL GAS SUPPLY COSTS IN WESTERN CANADA

AN UPDATE

Conventional Natural Gas Supply Costs in Western Canada – An Update

Copyright © Canadian Energy Research Institute, 2013 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute ISBN 1-927037-18-8 Author: Julie Dalzell

Acknowledgements: The author wishes to acknowledge those involved in the production, reviewing, and editing of the material, including but not limited to Peter Howard and Megan Murphy. CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca December 2013 Printed in Canada

Front Cover Photo Courtesy of www.davidsuzuki.org/publications/finding-solutions/2011/summer/report-concludes-natural-gas-is-not-a-climate-solution/

http://www.ceri.ca/

http://www.davidsuzuki.org/publications/finding-solutions/2011/summer/report-concludes-natural-gas-is-not-a-climate-solution/

http://www.davidsuzuki.org/publications/finding-solutions/2011/summer/report-concludes-natural-gas-is-not-a-climate-solution/

Conventional Natural Gas Supply Costs in 1 Western Canada – An Update

December 2013

Introduction The abundance of shale gas developments in the United States has led to sustained low natural gas prices across North America, making the majority of Canada’s dry gas resources uneconomic to develop.

1 The exception is those resources that contain significant amounts of

natural gas liquids (NGLs).

This report updates CERI Study No. 136, Conventional Natural Gas Supply Costs in Western Canada released in June 2013 to include the supply cost of producing gas on a liquids-basis (that is, including the revenues and costs for both dry gas and NGLs) for numerous areas across Western Canada. Previously, the study only looked at supply costs on a dry-gas basis, effectively ignoring the liquids component.

Produced natural gas is primarily methane (CH4), but it also contains heavier hydrocarbons that are separated from the natural gas stream as liquids, including ethane (C2H6), propane (C3H8), butane (C4H10) and pentanes plus (C5H12 and greater). With the price of NGLs generally linked to oil prices instead of natural gas prices, the presence of liquids in the gas stream improves the potential returns from developing these types of resources. The higher the spread between natural gas prices and oil prices, the higher the incentive to extract the liquids.

The supply cost calculation provides an indicator of the economic viability of producing gas in each of the study areas. With the inclusion of NGLs in the analysis, this update presents a more realistic evaluation of the economic viability of natural gas production in liquids-rich areas across Western Canada.

Results The supply cost represents the natural gas price that is required to recover all costs (capital, operating, royalties and taxes) and earn a positive return on investment (10 percent real). Simply put, if the supply cost is lower than the current natural gas price, that area is considered economically viable to develop. (Note that the supply cost calculation assumes a price for NGLs, it does not solve for the price of NGLs.)

2

The presence of liquids improves the economics of gas extraction. The analysis shows that the dry-gas portion of the supply cost can decline significantly in the presence of liquids. In some cases, the dry-gas costs are almost completely offset by revenues from the liquids.

Given the favourable economics for liquids-rich gas, there has been a substantial shift in drilling towards exploiting these resources across Western Canada. The share of new connections in southeast Alberta, a typically dry-gas region, dropped from 41 percent in 2011 to 20 percent in 2012, while the share in the foothills region of Alberta, a typically liquids-rich region, increased

1 CERI Study No. 136 Conventional Natural Gas Supply Costs in Western Canada, June 2013. Available for

download at www.ceri.ca. 2 The AECO-C price averaged $2.07/mcf in 2012 while the Henry Hub price averaged $2.64/mcf. All results are in

2012 Canadian dollars.

2 Canadian Energy Research Institute

December 2013

from 39 percent in 2011 to 62 percent in 2012.3 The Montney formation in British Columbia has

also emerged as a key producing region over the past 5 years. These changes are primarily driven by the shift towards liquids-rich gas resources as producers take advantage of the additional revenue associated with the production of NGLs.

Figure 1 shows the number of wells completed in Alberta and British Columbia, by study area since 2010.

4 Total drilling rates have been declining since 2008, in line with the decline in

natural gas prices and the advent of horizontal drilling and multi-stage hydraulic fracturing. The shift to liquids-rich resources is also evident, as areas that had traditionally shown strong gas production, such as southeast Alberta (Area 1), have shown steep declines over the past three years. In the case of southeast Alberta, wells completed dropped from over 1,000 wells in 2010 to only 36 in 2012.

Figure 1: Number of Wells Completed in Alberta and British Columbia, 2010-12

Source: CERI

Those areas with the largest drilling and completion rates are those with a strong liquids-rich gas resource. Figure 2 shows the number of wells completed in 2012 and the average liquids content of those areas. Only a handful of areas in Western Canada had completion rates of above 100 wells in 2012, and those areas generally have an average liquid content of over 40 bbls of NGLs per mmcf of gas.

3 ERCB, ST98-2013:Alberta’s Energy Reserves 2012 and Supply/Demand Outlook 2013-2022, May 2013

4 For a map and list of study areas see Appendix A

-

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2010 2011

2012


December 2013

Typically, liquid-rich plays in Alberta run from the northwest near Grand Prairie diagonally

southeast to the Medicine Hat area encompassing the Duvernay, Montney and Muskwa formations.

5 Liquid-rich plays in British Columbia are centered on the Montney formation in the

northeast of the province.

Figure 2: Wells Completed and Average Liquid Content by Area

Source: CERI

Table 1 shows the supply costs for all areas on a dry-gas basis (as in CERI Study No. 136) and on a liquids basis (updated to include NGLs). The new supply cost is then split into a gas portion and liquids portion. The liquids portion reflects the amount of the supply cost that is covered by revenues from liquids produced. The gas portion is then calculated as the gas price required to cover the remaining costs and earn a positive rate of return. It is the gas portion that should be compared to the current gas price to determine the economic viability of gas production.

The areas in bold represent those areas with a completion rate of more than 100 wells in 2012. It is evident that for these areas, the liquids revenue makes up a greater proportion of the total supply cost, resulting in a lower gas portion, and greater profitability.

Note that the addition of NGLs in the supply cost calculation causes the total supply cost for each area to increase from the dry-gas estimate. This is because additional operating and

5 AGS, Summary of Alberta’s Shale- and Siltstone-Hosted Hydrocarbon Resource Potential, October 2012

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December 2013

processing costs for the liquids have been included (gas processing/liquids extraction, NGLs

transportation, fractionation, etc.). However, after accounting for the additional revenues gained from the liquids, the gas price required to cover the remainder of the costs falls (the gas portion).

Table 1: Supply Cost Summary Table – All Areas

Liquids content (bbls per

mmcf)

Vertical wells Horizontal wells

Supply cost ($/mcf) Supply cost ($/mcf)

Area Dry-gas

basis Liquids basis

Gas portion

Liquids portion

Dry-gas basis

Liquids basis

Gas portion

Liquids portion

ALBERTA Area 1 2.8 7.51 7.63 7.56 0.08 21.28 21.33 21.25 0.07

Area 2 18.4 3.65 4.10 3.29 0.81 7.06 7.51 6.72 0.79 Area 3 51.6 41.62 43.13 41.02 2.10 1.38 2.60 0.56 2.05 Area 4 40.7 4.74 5.59 4.02 1.57 6.56 7.44 5.94 1.50 Area 5 42.0 8.34 9.42 7.43 1.99 16.48 17.55 15.66 1.89 Area 6 62.6 5.71 7.06 4.51 2.55 4.34 5.76 3.34 2.42 Area 7 38.4 22.92 23.90 22.46 1.44 3.18 4.08 2.70 1.39 Area 8 24.6 15.36 15.97 15.10 0.87 9.65 10.15 9.31 0.84 Area 9 80.5 8.85 10.69 7.27 3.42 3.24 5.16 1.86 3.31 Area 9-2660 67.8 19.84 21.22 19.03 2.19 12.90 14.21 12.08 2.13 Area 9-4325 113.2 5.62 7.77 3.78 4.00 17.31 19.63 15.78 3.85 Area 10 105.4 10.21 12.35 8.44 3.92 2.76 5.01 1.23 3.78 Area 10-3000 90.6 28.45 30.40 27.26 3.14 12.16 13.98 10.97 3.01 Area 10-3009 87.9 14.18 15.87 12.95 2.92 6.09 7.82 4.99 2.83 Area 11 105.3 11.58 13.77 9.74 4.02 2.38 4.96 1.09 3.86 Area 12 22.0 9.94 10.43 9.69 0.74 39.53 39.96 39.26 0.70 Area 13 68.7 4.47 5.81 3.34 2.47 2.63 4.07 1.67 2.40 Area 13-2640 58.7 23.33 24.62 22.66 1.96 6.50 7.68 5.73 1.95 Area 13-3100 85.8 33.80 35.75 32.71 3.04 6.56 8.34 5.38 2.96 Area 13-3480 64.0 3.43 4.53 2.59 1.94 9.51 10.70 8.79 1.91 Area 14 67.1 3.68 4.96 2.59 2.37 3.13 4.51 2.23 2.29 Area 14-5240 64.4 12.85 14.22 11.83 2.39 4.68 6.06 3.73 2.33 Area 15 106.5 9.13 11.27 7.33 3.94 3.39 5.65 1.86 3.79 Area 16 56.2 6.94 8.13 5.95 2.18 3.56 4.79 2.70 2.09 Area 17 53.2 9.83 11.06 8.83 2.23 14.66 15.90 13.77 2.13 Area 18 37.4 9.24 10.03 8.69 1.35 3.79 4.64 3.36 1.27 Area 19 0.8 6.07 6.15 6.12 0.04 5.34 5.36 5.33 0.03 Area 20 53.8 3.78 4.82 2.85 1.97

Area 21 62.1 3.97 5.24 2.84 2.40 4.61 6.12 3.84 2.27 Area 22 80.6 4.83 6.58 3.18 3.40

Area 23 5.4 5.65 5.80 5.63 0.17 BRITISH COLUMBIA

Area 30 4.9 1.52 1.60 1.51 0.09 1.12 1.29 1.19 0.10 Area 31 18.5 1.16 1.47 1.06 0.41 9.06 10.34 9.89 0.45 Area 32 28.2 23.17 23.63 22.90 0.72 20.67 23.55 22.76 0.79 Area 33 53.1 2.13 3.11 1.60 1.50 0.97 1.78 0.14 1.64 Area 34-A9022 70.9 2.27 3.61 1.38 2.23 12.24 14.62 12.19 2.43 Area 34-F5000 70.9 5.67 7.02 4.79 2.23 3.64 4.98 2.55 2.43 Area 34 70.9 10.57 11.90 9.67 2.23 10.70 11.58 9.15 2.43 Area 35 46.9 20.30 21.12 19.78 1.33

Area 36 89.5 3.48 5.20 2.31 2.88 Area 38 41.6

54.45 54.34 52.85 1.48


December 2013

Liquids content (bbls per

mmcf)

Vertical wells Horizontal wells

Supply cost ($/mcf) Supply cost ($/mcf)

Area Dry-gas

basis Liquids basis

Gas portion

Liquids portion

Dry-gas basis

Liquids basis

Gas portion

Liquids portion

Area 39 6.1 5.69 5.80 5.58 0.22 9.36 9.32 9.09 0.24 Area 40 15.0 30.04 30.29 29.69 0.60 36.18 36.81 36.15 0.66 Area 41 32.5 10.22 10.82 9.83 0.99 18.71 19.52 18.44 1.08 Area 42 9.5 10.93 11.11 10.73 0.38 15.56 15.67 15.25 0.42 Area 45 1.7 2.24 2.27 2.24 0.02

Source: CERI

The analysis shows that those areas that experienced significant drilling in 2012 are also areas that enjoy high liquids content, with most of those areas enjoying a liquids content of over 50 bbls/mmcf. While this pattern is generally true, there are also areas within Alberta and British

Columbia that show high liquids content but low drilling and completion activity. In these cases the production profile of both gas and liquids do not make the economics of extraction attractive.

The biggest uncertainty in analyzing NGLs is the price that producers receive for liquids. Two sensitivity analyses were undertaken to examine this uncertainty. Since prices for NGLs (C3+) are generally linked to the price of oil, a high and low oil price scenario was examined. In addition, given recent fluctuations in the price of propane, a high and low propane price scenario was also analyzed.

The results show that a high oil price brings about more favourable economics for liquids-rich

gas development as producers are receiving a higher price for their liquids. This leads to greater revenue from liquids, and therefore a lower gas price required to make the development economically viable. The opposite is true for low oil prices. In total, the supply cost for each area changes very little with the change in oil prices, however, it is the breakdown between the gas and liquids portion that is more important. Figure 3 shows the sensitivity analysis results for just one area, Area 13 in central western Alberta. The total supply cost under the high oil price case is $0.11 higher, with the liquids component increasing $0.29 and the gas component falling $0.18.

The propane sensitivity scenarios show the same relationship as the oil price scenarios, but to a lesser extent. Full sensitivity analysis results are presented in Appendix B.


December 2013

Figure 3: Sensitivity Analysis Example, Area 13 – Gold Creek to Edson Area

Supply Cost Proportion of Gas and Liquids

Source: CERI

Plays such as the Montney and Duvernay, along with other liquid-rich resources, are set to

remain the focus of development in the Canadian gas industry into the future. Given the outlook for sustained low natural gas prices, developers will continue to pursue those resources that produce the highest economic value-added. The expansion of the Canadian shale gas industry and the continued refinement of production processes will only result in better economics for these liquid-rich plays.

Appendix B presents detailed supply cost estimates for those areas with completion rate of 100 or more in 2012.

Methodology and Assumptions The overall supply cost method and assumptions are the same as those used in CERI Study No. 136. Only those that are different or new are outlined below.

Liquids content – Natural gas reserve and composition data was used to derive the average liquid content of each study area. These data were provided by the Alberta Energy Resources Conservation Board (ERCB) – now the Alberta Energy Regulator (AER) – and the British Columbia Oil and Gas Commission (BCOGC). The gas and liquid composition of each area is a weighted average based on the remaining producible volumes of natural gas.

Liquids recovery – Two liquid recovery scenarios were developed: Shallow cut and Deep cut. The Deep cut scenario has been used as the main scenario for this analysis.

$1.67 $1.57 $1.77 $1.49

$1.86

$2.40 $2.54 $2.25 $2.69 $2.11

$4.07 $4.12 $4.03 $4.18

$3.97

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

Base case Highpropane

price

Lowpropane

price

High oilprice

Low oilprice

Gas portion Liquids portion

41% 38% 44% 36%

47%

59% 62% 56% 64%

53%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Basecase

Highpropane

price

Lowpropane

price

High oilprice

Low oilprice



December 2013

Table 2: Liquids Recovery Rate Assumptions

Shallow cut Deep cut

Ethane 1% 90%

Propane 90% 95%

Butane 99% 99%

Pentanes + 99% 99%

Operating costs – CERI Study No. 136 presented supply cost estimates that were measured at the field gate, that is, it did not include the costs of transportation or processing. This report has

updated the supply cost estimates to include these costs for both the dry gas and liquids components.

NGL operating cost estimates include:

Processing and treating - estimated by CERI from various company data

NGL raw mix transportation – estimated by CERI from various company data

NGL fractionation – fractionation costs estimated from the Alberta Department of Energy fractionation allowance

While the same operating costs have been assumed for all areas, some areas may have higher or lower operating costs depending on their individual circumstances, and this would change

the results.

Transportation costs – Gas transport costs and NGL product transport costs were estimated by CERI from various company data

NGL prices – Unlike the natural gas price, which is a product of the supply cost calculation, NGL prices are exogenous to the model.

Ethane – Typically trades at gas value plus a premium. Ethane prices have been calculated as NOVA Inventory Transfer (NIT) purchase prices with uplift calculated by CERI.

Propane, butane and pentanes plus typically trade as a proportion of WTI, prices have been assumed as 30, 80 and 106 percent of WTI, respectively.

Sensitivity analysis – two sensitivity scenarios are presented in Appendix B:

Low/High Propane Price – the low propane price scenario assumes a propane price equivalent to 20 percent of WTI, while the high propane price scenario assumes a propane price of 40 percent of WTI.


December 2013

Low/High Oil Price – the low oil price scenario assumes an oil price 15 percent lower

than the WTI, while the high oil price scenario assumes an oil price 15 percent higher than WTI.

Please refer to CERI Study No. 136 for all other assumptions.


December 2013

Appendix A: List and Map of Study Areas

Table A.1: Western Canadian Sedimentary Basin Natural Gas Supply Cost Study Areas

Area ID Province Description

PIA01-9999-GAS Alberta Suffield Medicine Hat Area

PIA02-9999-GAS Alberta Bow Island Area

PIA03-9999-GAS Alberta Foothills Area west of Calgary

PIA04-9999-GAS Alberta Hussar to Princess Area

PIA05-9999-GAS Alberta Didsbury to Hussar Area

PIA06-9999-GAS Alberta Nevis and Ghostpine Area

PIA07-9999-GAS Alberta Bens Lake to Princess (North Lateral) Area

PIA08-9999-GAS Alberta Bens Lake to Canendish (East Lateral)

PIA09-9999-GAS Alberta Edson to Caroline (Plains Mainline)

PIA09-2660-GAS Alberta Notikewin formation

PIA09-4325-GAS Alberta Rock Creek formation

PIA10-9999-GAS Alberta McLeod to Caroline (Foothills Mainline)

PIA10-3000-GAS Alberta Glauconitic formation



PIA11-9999-GAS Alberta Edmonton Area

PIA12-9999-GAS Alberta Bens Lake upstream to Calling Lake

PIA13-9999-GAS Alberta Gold Creek to Edson Area

PIA13-2640-GAS Alberta Spirit River formation

PIA13-3100-GAS Alberta Blue Sky formation

PIA13-3480-GAS Alberta Cadomin formation

PIA14-9999-GAS Alberta Vahalla to Gold Creek Area

PIA14-5200-GAS Alberta Doig formation

PIA14-5240-GAS Alberta Montney formation

PIA15-9999-GAS Alberta Judy Creek, Kaybon to Edson and McLeod

PIA16-9999-GAS Alberta Doe Creek to Teepee Creek Area

PIA17-9999-GAS Alberta Heart River Wolverine Creek Area

PIA18-9999-GAS Alberta Darling Creek to Slave Lake Compressor

PIA19-9999-GAS Alberta Fort McMurray Area

PIA20-9999-GAS Alberta Owl Lake Area

PIA21-9999-GAS Alberta Thunder Creek to Tanghe Creek

PIA22-9999-GAS Alberta Zama Lake to Meikle Compressor

PIA23-9999-GAS Alberta Princess to Empress Mainline


December 2013

Area ID Province Description

PIA30-X9999-GAS British Columbia Pine River Lateral

PIA31-X9999-GAS British Columbia Tupper Creek/Noel Area

PIA31-A9030-GAS British Columbia Deep Basin Area

PIA32-X9999-GAS British Columbia Groundbirch Area

PIA33-X9999-GAS British Columbia Dawson Creek

PIA34-X9999-GAS British Columbia Fort St John Area

PIA34-A6200-GAS British Columbia Montney Area

PIA34-A9022-GAS British Columbia Northern Montney

PIA34-F5000-GAS British Columbia Montney formation

PIA35-X9999-GAS British Columbia Chinchauga River

PIA36-X9999-GAS British Columbia Ring Area

PIA37-X9999-GAS British Columbia Kahntah Area

PIA38-X9999-GAS British Columbia Shekilie Area

PIA39-X9999-GAS British Columbia Peggo-Pesh Area

PIA40-X9999-GAS British Columbia Helmut North Area

PIA41-X9999-GAS British Columbia Fort Nelson to CS2

PIA41-A9022-GAS British Columbia Montney Area

PIA42-X9999-GAS British Columbia Fort Nelson to NWT Border

PIA45-X9999-GAS British Columbia CS2 To Summit Lake Area

Source: CERI


December 2013

Figure A.1: Map of Alberta Study Areas


December 2013

Figure A.2: Map of British Columbia Study Areas


December 2013

Appendix B: Detailed Supply Cost Results

The following pages present the supply cost estimates for the top drilling areas in Western Canada in 2012.

For each area, two figures and one table are presented:

Figure 1: Comparison of Supply Cost - Dry and With Liquids

Table 1: Supply Cost Breakdown

Figure 2: Supply Cost Sensitivity Analysis


December 2013

Area 4 – Hussar to Princess – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL

Dry With liquids* Dry With liquids $ $/mcf $ $/mcf $ $/mcf $ $/mcf

Capital costs 356,309 3.33 356,309 3.36 1,291,862 5.44 1,291,862 5.44

Operating costs - Gas 104,246 0.97 104,246 0.98 104,508 0.44 104,508 0.44

Operating costs - Liquids - - 40,222 0.38 - - 94,758 0.40

Royalties

Methane 25,378 0.24 21,335 0.20 77,830 0.33 88,305 0.37

Liquids

48,895 0.46

103,828 0.44

Taxes 21,805 0.20 21,805 0.21 82,844 0.35 82,844 0.35

Total costs 507,738 4.74 592,812 5.59 1,557,044 6.56 1,766,106 7.44

*Base case - assumes 90% ethane recovery

$4.74 $4.10 $4.02

$1.28 $1.57

$4.74 $5.38 $5.59

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

Dry With liquids - 1%ethane recovery

With liquids - 90%ethane recovery


$6.56 $6.01 $5.94

$1.16 $1.50 $6.56

$7.18 $7.44

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00




December 2013

Figure 2: Supply Cost Sensitivity Analysis, Change from Base Case

VERTICAL HORIZONTAL

$0.07

-$0.07

$0.13

-$0.13

-$0.09

$0.09

-$0.19

$0.19

-$0.02

$0.02

-$0.06

$0.06

-$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.06

-$0.06

$0.12

-$0.12

-$0.09

$0.09

-$0.18

$0.18

-$0.03

$0.03

-$0.07

$0.07

-$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30

Gas portion

Liquids portion

Net impact

Low propane prices (20% of WTI)

High propane prices (40% of WTI) Low oil prices (-15%) High oil prices (+15%)


December 2013

Area 6 – Nevis and Ghostpine – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL

Dry With liquids Dry With liquids $ $/mcf $ $/mcf $ $/mcf $ $/mcf

Capital costs 934,305 4.63 934,305 4.68 2,192,056 3.71 2,192,056 3.71 Operating costs - Gas 104,407 0.52 104,407 0.52 105,168 0.18 105,168 0.18 Operating costs - Liquids - - 116,685 0.58 - - 363,178 0.62 Royalties

Methane 57,573 0.29 45,039 0.23 128,224 0.22 169,923 0.29 Liquids

153,586 0.77

427,993 0.72

Taxes 55,523 0.28 55,523 0.28 140,138 0.24 140,138 0.24

Total costs 1,151,808 5.71 1,409,546 7.06 2,565,587 4.34 3,398,456 5.76


$5.71 $4.63 $4.51

$2.13 $2.55

$5.71

$6.76 $7.06

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00



$4.34 $3.45 $3.34

$1.92 $2.42 $4.34

$5.37 $5.76

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00





December 2013


VERTICAL HORIZONTAL

$0.11

-$0.11

$0.22

-$0.22

-$0.14

$0.14

-$0.32

$0.32

-$0.04

$0.04

-$0.10

$0.10

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.10

-$0.10

$0.19

-$0.19

-$0.14

$0.14

-$0.30

$0.30

-$0.04

$0.04

-$0.11

$0.11

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Gas portion

Liquids portion

Net impact




December 2013

Area 9 – Edson to Caroline (Plains Mainline) – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL


Capital costs 2,223,482 5.90 2,223,482 5.96 4,132,755 2.44 4,132,755 2.44 Operating costs - Gas 800,966 2.12 800,966 2.15 803,491 0.47 803,491 0.47 Operating costs - Liquids - - 280,679 0.75 - - 1,338,087 0.79 Royalties

Methane 166,950 0.44 135,597 0.36 274,324 0.16 436,533 0.26 Liquids

400,033 1.07

1,740,736 1.03

Taxes 148,243 0.39 148,243 0.40 279,068 0.16 279,068 0.16

Total costs 3,339,641 8.85 3,989,000 10.69 5,489,637 3.24 8,730,670 5.16


$8.85 $7.40 $7.27

$2.90 $3.42

$8.85

$10.31 $10.69

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00



$3.24 $2.00 $1.86

$2.66 $3.31 $3.24

$4.67 $5.16

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00





December 2013


VERTICAL HORIZONTAL

$0.12

-$0.12

$0.30

-$0.30

-$0.17

$0.17

-$0.44

$0.44

-$0.04

$0.04

-$0.14

$0.14

-$0.60 -$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.11

-$0.11

$0.26

-$0.26

-$0.17

$0.17

-$0.42

$0.42

-$0.05

$0.05

-$0.16

$0.16

-$0.60 -$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Gas portion

Liquids portion

Net impact




December 2013

Area 10 – McLeod to Caroline (Foothills Mainline) – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL



Methane 143,160 0.51 117,031 0.42 141,474 0.14 256,529 0.25 Liquids

317,074 1.14

1,123,007 1.10

Taxes 114,572 0.41 114,572 0.41 120,492 0.12 120,492 0.12

Total costs 2,863,682 10.21 3,426,879 12.35 2,831,401 2.76 5,130,583 5.01


$10.21 $8.63 $8.44

$3.19 $3.92 $10.21

$11.82 $12.35

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00



$2.76 $1.41 $1.23

$2.94 $3.78 $2.76

$4.35 $5.01

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00





December 2013


VERTICAL HORIZONTAL

$0.19

-$0.19

$0.33

-$0.33

-$0.26

$0.26

-$0.48

$0.48

-$0.07

$0.07

-$0.15

$0.15

-$0.60 -$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.18

-$0.18

$0.30

-$0.30

-$0.26

$0.26

-$0.46

$0.46

-$0.08

$0.08

-$0.17

$0.17

-$0.60 -$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Gas portion

Liquids portion

Net impact




December 2013

Area 13 – Gold Creek to Edson - Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL



Methane 173,473 0.22 128,301 0.17 251,266 0.13 388,218 0.20 Liquids

550,372 0.72

1,315,588 0.69

Taxes 155,075 0.20 155,075 0.20 252,853 0.13 252,853 0.13

Total costs 3,470,781 4.47 4,465,614 5.81 5,028,887 2.63 7,764,368 4.07


$4.47 $3.47 $3.34

$1.97 $2.47 $4.47

$5.45 $5.81

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00



$2.63 $1.79 $1.67

$1.82 $2.40 $2.63

$3.62 $4.07

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00





December 2013


VERTICAL HORIZONTAL

$0.11

-$0.11

$0.20

-$0.20

-$0.15

$0.15

-$0.30

$0.30

-$0.04

$0.04

-$0.09

$0.09

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.10

-$0.10

$0.18

-$0.18

-$0.15

$0.15

-$0.29

$0.29

-$0.05

$0.05

-$0.11

$0.11

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40




December 2013

Area 14 – Vahalla to Gold Creek – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL



Methane 173,567 0.18 121,165 0.13 265,265 0.16 382,078 0.23 Liquids

636,495 0.68

1,103,648 0.65

Taxes 163,930 0.17 163,930 0.18 276,304 0.16 276,304 0.16

Total costs 3,472,955 3.68 4,638,606 4.96 5,308,467 3.13 7,641,554 4.51


$3.68 $2.73 $2.59

$1.86 $2.37 $3.68

$4.59 $4.96

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00



$3.13 $2.35 $2.23

$1.71 $2.29 $3.13

$4.06 $4.51

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00





December 2013


VERTICAL HORIZONTAL

$0.10

-$0.10

$0.19

-$0.19

-$0.14

$0.14

-$0.28

$0.28

-$0.04

$0.04

-$0.09

$0.09

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.09

-$0.09

$0.17

-$0.17

-$0.14

$0.14

-$0.27

$0.27

-$0.04

$0.04

-$0.10

$0.10

-$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30

Gas portion

Liquids portion

Net impact




December 2013

Area 14-5240 – Montney Formation – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL


Capital costs 3,222,951 9.37 3,222,951 9.37 4,280,644 3.54 4,280,644 3.54 Operating costs - Gas 800,915 2.33 800,915 2.33 802,587 0.66 802,587 0.66 Operating costs - Liquids - - 216,311 0.63 - - 805,352 0.67 Royalties

Methane 223,110 0.65 204,203 0.59 283,024 0.23 366,629 0.30 Liquids

228,703 0.67

780,864 0.65

Taxes 215,815 0.63 215,815 0.63 296,496 0.25 296,496 0.25

Total costs 4,462,792 12.98 4,888,899 14.22 5,662,751 4.68 7,332,572 6.06


$12.85 $11.94 $11.83

$1.94 $2.39 $12.85

$13.89 $14.22

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00



$4.68 $3.84 $3.73

$1.81 $2.33 $4.68

$5.64 $6.06

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00




December 2013


VERTICAL HORIZONTAL

$0.10

-$0.10

$0.11

-$0.32

-$0.14

$0.14

-$0.17

-$0.04

$0.04

-$0.06

$0.13

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.10

-$0.10

$0.10

-$0.29

-$0.14

$0.14

-$0.16

$0.45

-$0.04

$0.04

-$0.06

$0.15

-$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Gas portion

Liquids portion

Net impact




December 2013

Area 15 - Judy Creek, Kaybon to Edson and McLeod – Alberta


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL


Capital costs 3,006,563 6.52 3,006,563 6.59 2,038,513 2.20 2,038,513 2.20 Operating costs - Gas 801,110 1.74 801,110 1.75 802,056 0.87 802,056 0.87 Operating costs - Liquids - - 452,712 0.99 - - 972,475 1.05 Royalties

Methane 210,569 0.46 167,263 0.37 157,085 0.17 261,797 0.28 Liquids

524,424 1.15

1,015,326 1.10

Taxes 193,925 0.42 193,925 0.42 145,776 0.16 145,776 0.16

Total costs 4,212,167 9.13 5,145,997 11.27 3,143,429 3.39 5,235,943 5.65


$9.13 $7.53 $7.33

$3.21 $3.94 $9.13

$10.74 $11.27

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00



$3.39 $2.04 $1.86

$2.95 $3.79 $3.39

$4.99 $5.65

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00





December 2013


VERTICAL HORIZONTAL

$0.20

-$0.20

$0.34

-$0.34

-$0.27

$0.27

-$0.07

$0.07

-$0.15

$0.15

-$0.40 -$0.20 $0.00 $0.20 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.19

-$0.19

$0.30

-$0.30

-$0.27

$0.27

-$0.47

$0.47

-$0.09

$0.09

-$0.17

$0.17

-$0.60 -$0.40 -$0.20 $0.00 $0.20 $0.40 $0.60

Gas portion

Liquids portion

Net impact




December 2013

Area 34-F5000 – Montney Formation – British Columbia


VERTICAL HORIZONTAL


VERTICAL HORIZONTAL


Capital costs 3,945,540 2.99 3,945,540 3.02 9,778,224 2.55 9,778,224 2.55

Operating costs - Gas 2,122,933 1.61 2,122,933 1.63 2,127,885 0.55 2,127,884 0.55

Operating costs - Liquids - - 858,014 0.66 - - 2,747,694 0.72 Royalties

Methane 1,070,829 0.81 1,307,313 1.00 1,356,967 0.35 1,863,094 0.49 Liquids

581,772 0.45

1,862,496 0.49

Taxes 340,259 0.26 340,259 0.26 722,019 0.19 722,019 0.19

Total costs 7,479,561 5.67 9,155,831 7.02 13,985,094 3.64 19,101,411 4.98


$5.67 $4.71 $4.79

$1.75 $2.23 $5.67

$6.46 $7.02

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00



$3.64 $2.58 $2.55

$1.91 $2.43 $3.64

$4.49 $4.98

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00





December 2013


VERTICAL HORIZONTAL

$0.11

-$0.11

$0.20

-$0.20

-$0.15

$0.15

-$0.27

$0.27

-$0.04

$0.04

-$0.07

$0.07

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Low propane prices

High propane prices

Low oil prices

High oil prices

$0.16

-$0.16

$0.29

-$0.29

-$0.16

$0.16

-$0.29

$0.29

$0.00

$0.00

$0.00

$0.00

-$0.40 -$0.30 -$0.20 -$0.10 $0.00 $0.10 $0.20 $0.30 $0.40

Gas portion

Liquids portion

Net impact



updated to include natural gas liquids (ngls) · ngls, it does not solve for the price of ngls.) 2...

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