October 2014 2% $25.00 4% CERI Commodity Report ......LNG re-gasification capacity; while there were...

Relevant • Independent • Objective

bcf/d (BP, 2014). Therefore, the sum of all proposed LNG export projects in North America is 2.5 times greater than the total existing worldwide LNG trade, or roughly the equivalent of North America’s total natural gas consumption for 2013. As seen on Figure 1, almost half of this capacity is being planned in BC where proponents are looking for options to export low cost Western Canadian Sedimentary Basin (WCSB) natural gas to the more lucrative Asia-Pacific market where prices are much higher (Figure 2), and where it is estimated that 75% of global LNG demand occurred in 2013 (International Group of Liquefied Natural Gas Importers (GIIGNL), 2014). Figure 1: Planned and Existing LNG Export/Liquefaction Capacity in North America (MMtpa), by Region

Source: CERI

Figure 2: Global Natural Gas Prices ($/GJ), 2002-2014

Sources: (Alberta Energy, 2014), and (International Monetary Fund (IMF), 2014).

47%

41%

6%

2%

4%

British Columbia

US Gulf Coast (TX, LA, MS)

US West Coast (AK, OR)

US East Coast (GE, MD, ME)

Nova Scotia

Total Capacity: 645.8 MMtpa

$(5.00)

$-

$5.00

$10.00

$15.00

$20.00

$25.00

Jan

Jun

No

v

Ap

r

Se

p

Fe

b

Jul

De

c

Ma

y

Oct

Ma

r

Au

g

Jan

Jun

No

v

Ap

r

Se

p

Fe

b

Jul

De

c

Ma

y

Oct

Ma

r

Au

g

Jan

Jun

No

v

Ap

r

Se

p

Fe

b

Jul

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

$/G

J

WCSB - ASIA PACIFIC ARBITRAGE ($/GJ)

AECO-C @ AB ($/GJ)

HENRY HUB @ USGC ($/GJ)

RUSSIAN GAS @ GERMANY ($/GJ)

INDONESIAN LNG @ JAPAN ($/GJ)

NORTH SEA BRENT @ EUROPE ($/GJ)

October 2014

CERI Commodity Report — Natural Gas

British Columbia (BC) Liquefied Natural Gas (LNG) Economics Carlos A. Murillo Recent media coverage around prospective LNG projects in BC has focused on the newly released LNG income tax and the LNG greenhouse gas (GHG) emissions’ benchmark proposed by the provincial government in late October. This article explores the impacts of these and other variables on the economics of a hypothetical LNG export (or liquefaction) facility located on the BC coast, targeting the Asia-Pacific LNG market. Various projects…maybe too many projects? According to the International Group of Liquefied Natural Gas Importers (GIIGNL) and the International Gas Union (IGU), total worldwide LNG trade in 2013 was estimated at 237 million tonnes (t) per year (MMtpa) or the equivalent of 32 bcf/d.1 It is also estimated that by year-end (YE) 2013 there were 29 importing countries with 104 receiving terminals and 721 MMtpa (96 bcf/d) of LNG re-gasification capacity; while there were 17 countries exporting LNG from 86 liquefaction trains with a total capacity of 286 MMtpa of LNG (38 bcf/d) (International Group of Liquefied Natural Gas Importers (GIIGNL), 2014) (International Gas Union (IGU), 2014). According to CERI’s research, the sum of all existing and proposed LNG export terminals in North America, a total of 51 separate projects, adds up to close to 646 MMtpa of capacity (or 86 bcf/d) (Figure 1). To further put that number into context, consider that estimates from the BP Statistical Review of World Energy indicate that natural gas consumption in North America (the United States, Canada, and Mexico, combined) in 2013 was 89

CERI Commodity Report – Natural Gas Editor-in-Chief: Dinara Millington ([email protected]) Contents Featured Article ................................................................................. 1 Natural Gas Prices.............................................................................. 7 Weather ............................................................................................ 9 Consumption and Production............................................................. 11 Transportation................................................................................... 13 Storage .............................................................................................. 15 Liquefied Natural Gas ........................................................................ 18 Drilling Activity .................................................................................. 16


CERI’s analysis indicates that at most two large and one small LNG project off the BC coast will get built to serve the global LNG market. Not all projects will get built. Liquefaction facility capital costs (CAPEX): don’t let them run wild and free Compared to proposed projects in the US, most projects in BC, while having the advantage of being located in a cooler climate (lower operating costs) and closer to markets in the Asia-Pacific region (lower shipping distances and costs), will be built from scratch in remote areas where infrastructure is not as readily available (greenfield facilities). This compares to brownfield sites such as existing LNG re-gasification facilities and industrial clusters such as in the US Gulf Coast (USGC). This will generally translate into higher overall capital costs for BC projects. Capital costs, as will be discussed below, is in turn one of the most important considerations of the economics of an LNG (liquefaction) facility. While most projects in BC are at preliminary stages, CERI has gathered data on potential costs associated with various projects to be located on the West Coast of the continent, but primarily those in BC (Figure 3). The information was gathered from the project proponent’s websites, publicly available investor documents, and project description documents filed for export license purposes with the National Energy Board (NEB), as well as environmental impact assessments with the Canadian Environmental Assessment Agency (CEAA) and the BC Environmental Assessment Office (EAO). Figure 3: North American West Coast LNG Projects' Capital Cost Estimates ($/t)

Source: CERI Research

$395

$448

$600

$616

$619

$741

$782

$804

$942

$1,008

$1,112

$1,190

$1,343

$- $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600

Douglas Channel Energy (BC LNG)

Kitimat LNG

Kitsault Energy

Oregon LNG

Pacific Northwest LNG

Prince Rupert LNG

Woodfibre LNG

Aurora

Steelhead LNG

Jordan Cove

Alaska South Central LNG

Woodside Energy LNG (Grassy Point LNG)

LNG Canada

$/t

As can be observed, these costs range from as little as $395/t of liquefaction capacity, to as much as $1,343/t of liquefaction capacity (with a weighted average of $859/t). Meanwhile, research conducted by Credit Suisse and the Oxford Institute for Energy Studies (OIES) indicates that the costs illustrated above could be conservative, as recent experience suggests that costs can be as high as over $2,000/t to over $3,000/t (Figure 4).2 This research also indicates, that in general, brand new facilities (like those being planned in BC) tend to have much higher costs than expansions/modifications of existing facilities or facilities to be developed on brownfield sites (such as those in the USGC). Figure 4: Recently Completed, Under Construction, and Planned LNG Project Costs

Source: (Ernst & Young (EY), 2013) after (Credit Suisse , 2012), and (Oxford Institute for Energy Studies (OIES), 2014)


With a wide band of possible capital costs required for LNG liquefaction projects, this will be an important, if not the most important consideration with regard to LNG project economics for projects in BC. BC LNG economics example: tolling facility CERI has developed a model to better understand the different cost components of the LNG supply chain and their effects on the total project cost. This is a supply cost model based on the discounted cash flow (DCF) methodology which solves for the price required for a project proponent to recover all its costs (including capital costs, operating costs, and taxes) and earn a return on its investment (IRR=10% in the Base Case). In this case (Case 1), the example is for a hypothetical LNG tolling facility. The purpose of this facility is to take natural gas from a producer (at the LNG plant gate), liquefy it, and then load it onto a ship to be delivered to the end user. The shipping will be paid for by the buyer (freight on board (FOB)) or the seller (delivered ex-ship (DES)), depending on the sales agreement. Therefore, the supply cost which is being solved for in this model is the toll which is required to be charged by the liquefaction facility owner in order to recover all of its costs and receive a return on its investment. Alternatively, if this was an integrated project where the project proponent owns natural gas reserves, natural gas transmission, and liquefaction facilities, the supply cost solved for by this model, will be the equivalent to the liquefaction costs portion of the total integrated project’s LNG supply costs. In summary, for a tolling facility the results of this analysis are the required toll to be charged, while for an integrated project the resulting costs reflect the liquefaction costs of the integrated LNG project.

Table 1 displays the main assumptions used in this model while Figure 5 and Table 2 display the results for the base case. Table 1: Model Assumptions

Figure 5: Liquefaction Costs/Toll by Component

Hypothetical BC LNG Facility

Train Capacity 6 MMtpa 801 MMcf/d

Number of Trains 3 #

Total Capacity 18 MMtpa 2,402 MMcf/d

CAPEX $ 859 $/t

Project's CAPEX $ 15,458 $MM

Construction Time 5 Years

Decommisioning Costs $ 1,546 $MM

Foreign Expenditure = USD % of Capex 54% % of Total

Facility Fixed OPEX $ 0.54 $/mcf

Pipeline Transportation Costs $ 0.50 $/mcf

Project's GHG Intensity 0.22 t CO2 eq./t LNG

Liquefaction Portion GHG Intensity 0.10 t CO2 eq./t LNG

BC LNG Emissions Benchmark 0.16 t CO2 eq./t LNG

mcf of gas for PG/mcf of LNG 0.04

Estimated Gas Treating Shrinkage Vol. 5% of input volume

CAPEX Inflation 3.5% %/yr

OPEX Inflation 2.5% %/yr

Price Inflation 2.0% %/yr

Discount Rate (DR) 10.00% %

CAD/USD 1.10 $CAD/$US

Federal Corporate Tax Rate 15% %

Provincial Corporate Tax Rate 11% %

Natural Gas Carbon Tax Rate $ 1.6 $/mcf

Carbon Tax $ 30.0 $/t

BC LNG Income Tax Structure

Pre-Payout 1.5% %

Post-Payout 3.5% %

Post-Payout after 2037 5.0% %

Wegithed Avg. Depreciation Rate (LNG Plant: Class 47) 14.8% %

Alernative Wegithed Avg. Depreciation Rate (LNG Plant: Class 43) 24.1% %

Gas Heating Value 1.09 GJ/mcf 22.50 GJ/t of LNG

WCSB Gas Price AECO-C $ 3.50 $/GJ

WCSB Gas Price AECO-C $ 3.82 $/mcf

Taxation

Prices

BC LNG ECONOMICS: CASE 1: TOLLING FACILITY

Project Description

Project's Costs

Inflation/Return/Exchange Rates

61%

17%

11%8%

1%2%

Capital Costs

LNG Facility Fixed OPEX

LNG Facility Var OPEX

Corporate Taxes

LNG Income Taxes

Carbon Taxes

Total Costs ($/GJ): $6.51


Table 2: Base Case Results

The results indicate that an 18 MMtpa facility with a weighted average CAPEX of $859/t – assuming construction occurs starting in 2014-2015, with first LNG in 2018 and decommissioning by 2047 – will require a toll of $6.51/GJ (in real $2014) over the project’s life to obtain an internal rate of return (IRR) of 10 percent.3 This analysis also indicates that capital costs account for 61% of the total project cost, compared to 28% for operating costs (fixed plus variable), and 11% for all forms of taxes combined (including federal and provincial corporate income taxes, carbon taxes, and the LNG income tax). For an integrated project – assuming a dry-gas supply cost of about $2.4/GJ4 for a producer in the Montney area, a $1.0/GJ processing and transportation fee from the field to liquefaction facility, and a $1.3/GJ shipping cost to the Asia-Pacific market – this will result in total delivered LNG supply costs of $11.2/GJ today.5 Alternatively, if this was a merchant facility where the LNG facility owner would buy feed gas at the local market price/pool (AECO-C/Station 2) and cover all the other costs, assuming a $3.50/GJ AECO-C/Station 2 price (2013-14 (J-A) avg.), the delivered LNG price would be $12.3/GJ today.6 These examples show that the liquefaction costs will remain the single largest cost component of an LNG project across any of the different supply chain cases. Given that capital costs account for over half of the total liquefaction costs,7 this implies that having strong controls on these costs will be very important for the success and economic viability of LNG projects in BC.

Discounted ($2014)

LNG Output (GJ) 3,232,051,506.44

($MM) $/GJ $/mcf % of Total

Tolling Revenues $ 21,025 $ 6.51 $ 7.10 100.0%

Capital Costs $ 12,746 $ 3.94 $ 4.30 60.6%

LNG Facility Fixed OPEX $ 3,596 $ 1.11 $ 1.21 17.1%

LNG Facility Var OPEX $ 2,298 $ 0.71 $ 0.78 10.9%

Corporate Taxes $ 1,630 $ 0.50 $ 0.55 7.8%

LNG Income Taxes $ 330 $ 0.10 $ 0.11 1.6%

Carbon Taxes $ 425 $ 0.13 $ 0.14 2.0%

NCF $ (0) $ (0.00) $ (0.00) 0.0%

Total Costs $ 21,025 $ 6.51 $ 7.10 100.0%

Capital Costs $ 12,746 $ 3.94 $ 4.30 60.6%

Operating Costs $ 5,893 $ 1.82 $ 1.99 28.0%

Taxes $ 2,386 $ 0.74 $ 0.81 11.3%

Total Costs $ 21,025 $ 6.51 $ 7.10 100.0%

Model Results: Base Case

Don’t be so sensitive capital: sensitivity analysis Table 3 displays the result of a sensitivity analysis on the different variables used in the model and their effect on the resulting facility toll/liquefaction costs. Table 3: Sensitivity Analysis

As can be observed, the capital costs of the facility have the highest effect on the project’s economics when using our toll/liquefaction supply costs metric. As an example, using a $1,343/t CAPEX instead of $859/t (or a 56% increase in CAPEX) results in a 39% increase in the required toll/liquefaction costs pushing the toll up to $9.07/GJ. On the other hand, a $395/t capital cost (or a 54% reduction from the $859/t base case) results in a 38% decrease in the facility required toll at $4.07/GJ. This also indicates that for every 1% change in capital expenditures, the required toll will change by 0.70% (% change in toll/% change in variable = elasticity). Thus the higher the toll/variable’s elasticity, the larger the impact of the variable in question on the required toll. After capital costs, the most important variables include the exchange rate and the discount rate, followed by fixed operating costs, and variable operating costs. Surprisingly, the least sensitive variables, as seen on Table 3, are the LNG income tax rate and the applied capital cost allowance (CCA) depreciation rate. In regard to the LNG income tax rate, while there is no question that different taxation rates will result in different total amounts of tax paid on an annual and a cumulative basis, the sensitivity analysis indicates that to

CAPITAL COSTSVariable % Change from

Base CaseToll ($/GJ)

Toll %

Change

From Base

Case

Toll/Variable Elasticity

= % chg. In Toll/% chg.

In Var.

CAPEX Base Case $ 859 $/t 0.0% $ 6.51 0.0% n/a

High CAPEX $ 1,343 $/t 56.3% $ 9.07 39.4% 0.70

Low CAPEX $ 395 $/t -54.0% $ 4.07 -37.5% 0.70

EXCHANGE RATE

Exchange Rate Case Case 1.10 CAD/USD 0.0% $ 6.51 0.0% n/a

High Exchange Rate 1.21 CAD/USD 10.0% $ 6.76 3.9% 0.39

Low Exchange Rate 0.99 CAD/USD -10.0% $ 6.25 -3.9% 0.39

DISCOUNT RATE

Discount Rate Base Case 10.0% % 0.0% $ 6.51 0.0% n/a

High Discount Rate 12.5% % 25.0% $ 6.94 6.8% 0.27

Low Discount Rate 7.5% % -25.0% $ 6.14 -5.6% 0.23

OPERATING COSTS

Fixed OPEX

Fixed OPEX Base Case $ 0.54 $/mcf 0.0% $ 6.51 0.0% n/a

High Fixed OPEX $ 0.68 $/mcf 25.0% $ 6.78 4.3% 0.17

Low Fixed OPEX $ 0.41 $/mcf -25.0% $ 6.23 -4.3% 0.17

Variable OPEX

Var. OPEX Base Case (AECO Price) $ 3.50 $/GJ 0.0% $ 6.51 0.0% n/a

High Var. OPEX $ 4.38 $/GJ 25.0% $ 6.68 2.7% 0.11

Low Var. OPEX $ 2.63 $/GJ -25.0% $ 6.33 -2.7% 0.11

TAXES

LNG Income Tax Rate

Post-Payout Base Case 1.5% -->3.5% -->5.0% % 0.0% $ 6.51 0.0% n/a

Post-Payout High Case 3.5% -->5.5% -->7.0% % 42.9% $ 6.63 2.0% 0.05

Post-Payout Low Case 0.0% -->2.0% -->3.5% % -42.9% $ 6.44 -1.0% 0.02

Depreciation Rate

W.AV Dep. Rate CCA Class 47 14.8% % 0.0% $ 6.51 0.0% n/a

W.AV Dep. Rate CCA Class 43 24.1% % 62.3% $ 6.47 -0.6% (0.01)

Sensitivity Analysis


compensate for those higher or lower rates, the tolls/liquefaction costs would need to change minimally. As an example, a lower LNG income tax rate of 2.0% post-payout (and 3.5% post-payout after 2037) would result in a 1.0% (or $0.06/GJ) decrease in the toll/liquefaction costs. Meanwhile, an increase in the tax rate (5.5% post-payout and 7.0% after 2037) will require the toll to be higher by 2.0% (or by $0.13/GJ). When we consider different CCA rates,8 a higher CCA rate allows for the owner of the facility to depreciate its equipment/assets faster and thus re-invest their capital. Thus, on an annual cash-flow basis, the impact of different CCA rates would be more pronounced, and be reflected in the project’s rate of return. Yet under both circumstances only 100% of the capital is depreciated. This means that different depreciation rates result in a shift in the tax burden over time with a higher depreciation rate indicating that there are more tax deductions for the project proponent on the earlier years of the project and less tax deductions later on (which from the project owner’s perspective means that they can recover their money faster for re-investment purposes). The opposite is true for a lower depreciation rate, however the overall deduction is the same in both cases (100%). In this analysis, given the long-term nature of the project (34 years from construction to decommissioning), and given that the costs are discounted over such a long-term timeframe, it is reasonable to expect that different CCA rates would have a small impact on the resulting toll as seen in the sensitivity analysis. And, so we conclude Recently we have heard analogies alluding to the BC provincial government killing the goose before it lays the golden egg with their fiscal regime. Fiscal terms and government take, while controversial, do not appear to have a significant impact on project economics (when using our developed LNG supply cost metric). Our analysis indicates that the golden goose perhaps needs to focus more on other aspects of their projects.

Our model suggests that the key make or break issue surrounding these projects is around capital costs, followed by exchange rates, discount rates, and operating costs. Exchange rates and variable operating costs will largely be driven by commodity prices, macro-economic factors, and overall market conditions, and thus are generally beyond the proponents’ control. The onus will then fall on the project proponents’ ability to manage capital costs (or to adjust their expectations on returns (discount rates)). Managing projects’ costs, however, has proven to be a difficult task in other instances where oil and gas mega-projects have been built with large cost overruns.9 Lessons from those experiences need to be applied to prospective LNG projects in BC for them to be successful. Successful companies will need to enforce strong cost controls during the construction phase. Long-term sales contracts with end-users will also be key in getting assurance on LNG prices in order to drive final investment decisions (FIDs), which we have yet to hear about in regards to BC LNG projects. And while project costs are important, LNG buyers will also benefit from supply diversification by investing in and purchasing output from Canadian LNG projects. Without a doubt, there are numerous challenges ahead for proponents of BC LNG projects. Yet identifying those challenges is the first step in dealing with them. In the meantime, CERI will continue to monitor and analyze energy and environmental issues that affect Canadian producers and consumers. Endnotes 1Using a conversion factor of 48.7 mcf of natural gas per tonne of LNG 2It is important to note that both sets of costs are not always comparable as the costs for the projects in North America are generally associated with the liquefaction and export facilities while some of the estimates for other projects around the world might include upstream and midstream (transportation and processing) costs in addition to the liquefaction and export facilities. Some project costs also include additional infrastructure costs such as for carbon dioxide injection (as in the case with Gorgon (NW Australia) and Snohvit (Norway)) 3Other recently developed estimates by Macquarie and the International Energy Agency (IEA) suggest the liquefaction


costs for Canadian LNG projects to be around $5/GJ to $6/GJ. See: (International Energy Agency (IEA), 2014), and (Macquarie Private Wealth , 2012) 4See: (Dalzell, 2013), Page 30 5Alternatively, if the original DCF analysis is extended to include the upstream and midstream components of an integrated project (plus shipping), the resulting supply costs (which are equal to the market price required in the Asia-Pacific for the producer to recover all costs plus a 10% after-tax rate of return) are calculated to be $14.9/GJ. This compares to about $14/GJ for Canadian LNG projects as estimated by the IEA. See Figure 2.24, Page 114 (International Energy Agency (IEA), 2014). 6This is similar to the Cheniere Energy model for its Sabine Pass and Corpus Christi facilities in the USGC. See: (Bloomberg Businessweek, 2014) and www.cheniere.com. Assuming a $4.5/GJ Henry Hub price, a $0.4/GJ pipeline toll, a $3.6/GJ liquefaction toll, and a shipping cost of $2.8/GJ to the Asia-Pacific market, the comparable landed price from a Gulf Coast facility like Cheniere’s would be $11.3/GJ today. 7Meanwhile, labour costs can account for about 1/3 or more of the total capital costs: See: (Oxford Institute for Energy Studies (OIES), 2014), and (KBR, n/a) 8Weighted average CCA rates are used in this model because the LNG liquefaction project will have different types of assets which will be depreciated at different rates 9These include oil sands projects in northeastern Alberta, LNG projects in Australia, and other specific examples such as development of the Kashagan oil field in the Caspian Sea, and the Escravos GTL facility in Nigeria, among others References Alberta Energy. (2014). Monthly Reference Price Calculations.

Retrieved from Alberta Energy: http://energy.alberta.ca/NaturalGas/1316.asp

Bloomberg Businessweek. (2014, November 6). Energy - US Natural Gas Exports Will Fire Up in 2015. Retrieved from Bloomberg Businessweek - Energy: http://www.businessweek.com/articles/2014-11-06/u-dot-s-dot-natural-gas-exports-will-fire-up-in-2015

BP. (2014). BP. Retrieved from BP Statistical Review of World Energy 2014: http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html

Alberta Energy. (2014). Monthly Reference Price Calculations. Retrieved from Alberta Energy: http://energy.alberta.ca/NaturalGas/1316.asp

Bloomberg Businessweek. (2014, November 6). Energy - US Natural Gas Exports Will Fire Up in 2015. Retrieved from Bloomberg Businessweek - Energy: http://www.businessweek.com/articles/2014-11-06/u-dot-s-dot-natural-gas-exports-will-fire-up-in-2015

BP. (2014). BP. Retrieved from BP Statistical Review of World Energy 2014: http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html

Credit Suisse . (2012, June 07). Global LNG Sector - Update . Retrieved from Credit Suisse, Global Equity Research : https://research-and-analytics.csfb.com/docView?language=ENG&format=PDF&document_id=977153251&source_id=em&serialid=lLnIHOuVvGf%2BeB6YKN9IA%2Bot%2FumB3JhDoxYEUUEK08s%3D

Dalzell, J. (2013, December). Conventional Natural Gas Supply Costs in Western Canada - An Update . Retrieved from Canadian Energy Research Institute (CERI): http://ceri.ca/images/stories/2013-12-17_CERI_Study_136__Update_Conventional_Natural_Gas_Supply_Costs.pdf

Ernst & Young (EY). (2013). Global LNG: Will new demand and new supply mean new pricing? Retrieved from Ernst & Young (EY): http://www.ey.com/Publication/vwLUAssets/Global_LNG_New_pricing_ahead/$FILE/Global_LNG_New_pricing_ahead_DW0240.pdf

International Energy Agency (IEA). (2014, November). Africa Energy Outlook - World Energy Outlook (WEO) Special Report . Retrieved from International Energy Agency (IEA): http://www.iea.org/publications/freepublications/publication/WEO2014_AfricaEnergyOutlook.pdf

International Gas Union (IGU). (2014). IGU World LNG Report - 2014 Edition. Retrieved from International Gas Union (IGU): http://www.igu.org/sites/default/files/node-page-field_file/IGU%20-%20World%20LNG%20Report%20-%202014%20Edition.pdf

International Group of Liquefied Natural Gas Importers (GIIGNL). (2014). The LNG Industry in 2013. Retrieved from International Group of Liquefied Natural Gas Importers (GIIGNL): http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_the_lng_industry_fv.pdf

International Monetary Fund (IMF). (2014). IMF Primary Commodity Prices . Retrieved from International Monetary Fund (IMF): http://www.imf.org/external/np/res/commod/index.aspx

KBR. (n/a). LNG Liquefaction - Not All Plants Are Created Equal. Retrieved from KBR: http://www.kbr.com/Newsroom/Publications/Technical-Papers/LNG-Liquefaction-Not-All-Plants-Are-Created-Equal.pdf

Macquarie Private Wealth . (2012, September 10). Canadian LNG: The race to the coast - Our views on Canadian LNG. Retrieved from Macquarie Private Wealth : http://www.investorvillage.com/uploads/8056/files/Cdn_LNG_100912.pdf

Oxford Institute for Energy Studies (OIES). (2014, February). LNG Plant Cost Escalation. Retrieved from Oxford Institute for Energy Studies (OIES): http://www.oxfordenergy.org/wpcms/wp-content/uploads/2014/02/NG-83.pdf

US Energy Information Administration (EIA). (2014). Natural Gas Spot and Future Prices (NYMEX). Retrieved from US Energy Information Administration (EIA): http://www.eia.gov/dnav/ng/ng_pri_fut_s1_d.htm

http://www.cheniere.com

http://energy.alberta.ca/NaturalGas/1316.asp


http://www.businessweek.com/articles/2014-11-06/u-dot-s-dot-natural-gas-exports-will-fire-up-in-2015



http://www.bp.com/en/global/corporate/about-bp/energy-economics/statistical-review-of-world-energy.html











https://research-and-analytics.csfb.com/docView?language=ENG&format=PDF&document_id=977153251&source_id=em&serialid=lLnIHOuVvGf%2BeB6YKN9IA%2Bot%2FumB3JhDoxYEUUEK08s%3D




http://ceri.ca/images/stories/2013-12-17_CERI_Study_136__Update_Conventional_Natural_Gas_Supply_Costs.pdf




http://www.ey.com/Publication/vwLUAssets/Global_LNG_New_pricing_ahead/$FILE/Global_LNG_New_pricing_ahead_DW0240.pdf



http://www.iea.org/publications/freepublications/publication/WEO2014_AfricaEnergyOutlook.pdf

http://www.iea.org/publications/freepublications/publication/WEO2014_AfricaEnergyOutlook.pdf

http://www.igu.org/sites/default/files/node-page-field_file/IGU%20-%20World%20LNG%20Report%20-%202014%20Edition.pdf



http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_the_lng_industry_fv.pdf

http://www.giignl.org/sites/default/files/PUBLIC_AREA/Publications/giignl_the_lng_industry_fv.pdf

http://www.imf.org/external/np/res/commod/index.aspx

http://www.imf.org/external/np/res/commod/index.aspx

http://www.kbr.com/Newsroom/Publications/Technical-Papers/LNG-Liquefaction-Not-All-Plants-Are-Created-Equal.pdf



http://www.investorvillage.com/uploads/8056/files/Cdn_LNG_100912.pdf



http://www.oxfordenergy.org/wpcms/wp-content/uploads/2014/02/NG-83.pdf

http://www.oxfordenergy.org/wpcms/wp-content/uploads/2014/02/NG-83.pdf

http://www.eia.gov/dnav/ng/ng_pri_fut_s1_d.htm

http://www.eia.gov/dnav/ng/ng_pri_fut_s1_d.htm


SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly P

rice

Gu

ide.

SO

UR

CE:

CER

I, P

latt

s G

as D

aily

Pri

ce G

uid

e.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly P

rice

Gu

ide.

SO

UR

CE:

CER

I, P

latt

s G

as D

aily

Pri

ce G

uid

e.

-113579

11

13

15 Jan

-05

Ju

l-06

Jan

-08

Ju

l-09

Jan

-11

Ju

l-12

Jan

-14

Dif

fere

nti

al

He

nry

Hu

bR

ock

ies

He

nry H

ub

/R

oc

kie

s

Beg

in

ning

o

f N

ext M

onth S

pot P

rice

(U

S$

/M

MB

tu

)

-113579

11

13

15 Jan

-05

Ju

l-06

Jan

-08

Ju

l-09

Jan

-11

Ju

l-12

Jan

-14

Dif

fere

nti

al

He

nry

Hu

bS

ou

the

rn C

ali

forn

ia

He

nry H

ub

/S

ou

th

ern

C

alifo

rn

ia

Beginning of N

ext M

onth S

pot P

rice (U

S$/M

MB

tu)

-202468

10

12

14 Jan

-05

Ju

l-06

Jan

-08

Ju

l-09

Jan

-11

Ju

l-12

Jan

-14

Dif

fere

nti

al

Hen

ry H

ub

AE

CO

-C

He

nry H

ub

/A

EC

O-C

Beg

in

ning

o

f N

ext M

onth S

pot P

rice

(U

S$

/M

MB

tu

)

-7-5-3-113579

11

13

15 Jan

-05

Ju

l-06

Jan

-08

Ju

l-09

Jan

-11

Ju

l-12

Jan

-14

Dif

fere

nti

al

He

nry

Hu

bC

hic

ag

o

He

nry H

ub

/C

hic

ag

o

Beginning of N

ext M

onth S

pot P

rice (U

S$/M

MB

tu)

CERI Commodity Report - Natural Gas

SOU

RC

E: C

anad

ian

Gas

Ass

oci

atio

n.

SOU

RC

E: C

ERI,

Can

adia

n G

as A

sso

ciati

on

, Sta

tisti

cs C

anad

a.

SOU

RC

E: N

OA

A.

SOU

RC

E: C

ERI,

NO

AA

, EIA

.

0

100

200

300

400

50

0

60

0

70

0

80

0

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

Ca

na

dia

n H

ea

tin

g D

eg

re

e D

ays

0

100

200

300

400

500

600

700

800

900

1,0

00

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

US

H

ea

tin

g D

eg

re

e D

ays

01234567

0

20

0

40

0

600

800

1,0

00

1,2

00 J

an

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Deg

ree D

ay

sC

on

su

mp

tio

n

Ca

na

dia

n H

eatin

g D

eg

re

e D

ays vs R

esid

en

tia

l a

nd

Co

mm

erc

ia

l C

on

su

mptio

n

Deg

ree D

ays

BC

FP

D 010

20

30

40

50

60

0

200

40

0

600

800

1,0

00

1,2

00 J

an

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Deg

ree D

ay

sC

on

su

mp

tio

n

US

H

ea

tin

g D

eg

re

e D

ays vs

Re

sid

en

tia

l a

nd

C

om

me

rc

ia

l C

on

su

mp

tio

n

Deg

ree D

ays

BC

FP

D


SOU

RC

E: E

nvi

ron

men

t C

anad

a.

SOU

RC

E: E

nvi

ron

men

t C

anad

a.

SOU

RC

E: N

OA

A.

SOU

RC

E: N

OA

A.


SOU

RC

E: N

OA

A.

SOU

RC

E: E

nvi

ron

men

t C

anad

a.

SOU

RC

E: N

OA

A.


SOU

RC

E: S

tati

stics

Can

ada.

SO

UR

CE:

Sta

tisti

cs C

anad

a, N

EB.

SOU

RC

E: E

IA.

SOU

RC

E: E

IA.

02468

10

12

14

16 J

an

-09

Jan

-10

Ja

n-1

1J

an

-12

Jan

-13

Ja

n-1

4

Ind

ustr

ial

& P

ow

er

Co

mm

erc

ial

Res

ide

nti

al

Ca

na

dia

n C

on

su

mp

tio

n

By S

ector (B

cfp

d)

02468

10

12

14

16

18

20 J

an

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

BC

, Y

uko

n,

NW

TA

BS

KE

. C

oas

t

Ca

na

dia

n M

arke

ta

ble

P

ro

du

ctio

n

By P

ro

vin

ce

/R

eg

io

n (B

cfp

d)

0

20

40

60

80

10

0

12

0

14

0 Jan

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Ind

ustr

ial

Ele

ctr

ic P

ow

er

Co

mm

erc

ial

Res

ide

nti

al

US

C

on

su

mp

tio

n

By S

ec

tor (B

cfp

d)

0

10

20

30

40

50

60

70

80 J

an

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

US

To

tal

Lo

uis

ian

aG

OM

Fed

era

l W

ate

rsT

ex

as

US

M

ark

eta

ble

P

ro

du

ctio

n (B

cfp

d)


SOU

RC

E: S

tati

stics

Can

ada,

NEB

. SO

UR

CE:

Sta

tisti

cs C

anad

a, N

EB.

SOU

RC

E: S

tati

stics

Can

ada,

NEB

. SO

UR

CE:

Sta

tisti

cs C

anad

a, N

EB.

0.0

1.0

2.0

3.0

4.0

5.0

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

BC

, Y

uk

on

, N

WT

M

ark

eta

ble

P

ro

du

ctio

n (B

cfp

d)

02468

10

12

14

16

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

Alb

erta

M

ark

eta

ble

P

ro

du

ctio

n (B

cfp

d)

0.0

0.5

1.0

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

Sa

sk

atc

he

wan M

arke

ta

ble

P

ro

du

ctio

n (B

cfp

d)

0.0

0

0.2

5

0.5

0

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

Ea

st C

oa

st M

ark

eta

ble

P

ro

du

ctio

n (B

cfp

d)


SOU

RC

E: C

ERI.

SO

UR

CE:

CER

I.

SOU

RC

E: N

EB.

SOU

RC

E: N

EB.

02468

10

12

14

16

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

Syste

m F

ie

ld

R

ec

eip

ts

Tra

nsC

an

ad

a +

W

estc

oa

st; M

on

th

ly A

ve

ra

ge

(B

cfp

d)

02468

10

12

14

16

Oct-

13

Dec-1

3F

eb

-14

Ap

r-14

Ju

n-1

4A

ug

-14

Oct-

14

Em

pre

ss

Mc

Ne

ill

AB

-BC

All

ian

ce

Alb

erta

S

yste

m D

elive

rie

s (B

cfp

d)

0123456789

10

Se

p-1

3N

ov-1

3J

an

-14

Ma

r-1

4M

ay-1

4J

ul-

14

Sep

-14

Kin

gs

ga

teM

on

ch

yE

lmo

reH

un

tin

gd

on

Ca

na

dia

n G

as E

xp

orts to

th

e U

S

By E

xpo

rt P

oin

t -W

est (B

cfp

d)

0123456

Se

p-1

3N

ov-1

3J

an

-14

Ma

r-1

4M

ay

-14

Ju

l-1

4S

ep

-14

Em

ers

on

Iro

qu

ois

Oth

ers

Nia

ga

ra

Ca

na

dia

n G

as E

xp

orts to

th

e U

S

By E

xp

ort P

oin

t -E

ast (B

cfp

d)


SOU

RC

E: N

EB.

SOU

RC

E: N

EB.

SOU

RC

E: N

EB, E

IA.

SOU

RC

E: N

EB.

02468

10

12

Se

p-1

3N

ov-1

3J

an

-14

Ma

r-1

4M

ay-1

4J

ul-

14

Se

p-1

4

We

st

Mid

We

st

Ea

st

US

Im

po

rts o

f C

an

ad

ia

n G

as

By U

S R

eg

io

n (B

cfp

d)

02468

10

12

14

16

18

Se

p-1

3N

ov-1

3J

an

-14

Ma

r-1

4M

ay

-14

Ju

l-1

4S

ep

-14

We

st

Mid

We

st

Ea

st

Ave

ra

ge

C

an

ad

ia

n E

xp

ort P

ric

e

By U

S R

eg

io

n (C

$/G

J)

01234

Se

p-1

3N

ov-1

3J

an

-14

Ma

r-1

4M

ay

-14

Ju

l-1

4S

ep

-14

Co

urt

rig

ht

Sarn

iaS

t. C

lair

Oth

er

Ca

na

dia

n G

as Im

po

rts

By Im

po

rt P

oin

t (B

cfp

d)

02468

10

12

14 Au

g-1

3O

ct-

13

Dec-1

3F

eb

-14

Ap

r-14

Ju

n-1

4A

ug

-14

Can

ad

aM

exic

o

To

ta

l U

S P

ip

elin

e G

as Im

po

rts (B

cfp

d)


SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

0

100

200

300

40

0

500

600

70

0

80

0

900

1,0

00

JF

MA

MJ

JA

SO

ND

5-Y

ea

r A

vg

.2

01

32

01

4

Ca

na

dia

n W

ork

in

g G

as S

to

ra

ge

(B

cf, M

on

th

-e

nd

)

0

500

1,0

00

1,5

00

2,0

00

2,5

00

3,0

00

3,5

00

4,0

00

4,5

00

Oct-

13

Dec-1

3F

eb

-14

Ap

r-14

Ju

n-1

4A

ug

-14

Oct-

14

Ea

st

We

st

Pro

du

cin

g R

eg

ion

US

S

torage by R

egion (B

cf, M

onth-end)

0

500

1,0

00

1,5

00

2,0

00

2,5

00

3,0

00

3,5

00

4,0

00

4,5

00

JF

MA

MJ

JA

SO

ND

5-Y

ea

r A

vg

.2

01

32

01

4

US

L

ow

er-4

8 W

ork

ing

G

as S

to

ra

ge

(B

cf, M

on

th

-e

nd

)

0

10

0

20

0

300

400

50

0

600

700

80

0

900

Oct-

13

Dec-1

3F

eb

-14

Ap

r-14

Ju

n-1

4A

ug

-14

Oct-

14

West

Ea

st

Canadian S

torage by R

egion (B

cf, M

onth

-end)


SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

-140

-120

-100

-80

-60

-40

-200

20

40

60

JF

MA

MJ

JA

SO

ND

WC

_IJ

_W

D

5-Y

ear

Avg

.20

13

20

14

We

ste

rn

C

an

ad

a S

to

ra

ge

In

je

ctio

ns/W

ith

dra

wals

(B

cf, M

on

th

-e

nd

)

-250

-200

-150

-100

-500

50

100

150

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

Canadian S

torage

Injections/W

ithdraw

als (B

cf, M

onth

-end)

-100

-80

-60

-40

-200

20

40

60

80

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

Eastern C

anadian S

torage Injections/W

ithdraw

als

(B

cf, M

onth-end)


SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

SOU

RC

E: C

ERI,

Pla

tts

Gas

Dai

ly.

-150

-100

-500

50

100

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

US

W

estern C

onsum

ing R

egion S

torage

Injections/W

ithdraw

als (B

cf, M

onth

-end)

-400

-300

-200

-1000

100

200

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

US

P

roducing R

egion S

torage Injections/W

ithdraw

als

(B

cf, M

onth-end)

-1200

-1000

-800

-600

-400

-2000

200

400

600

800

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

US

S

torage

Injections/W

ithdraw

als (B

cf, M

onth

-end)

-700

-500

-300

-100

100

300

500

JF

MA

MJ

JA

SO

ND

5-Y

ear

Avg

.20

13

20

14

US

E

astern S

torage

Injections/W

ithdraw

als (B

cf, M

onth

-end)


SOU

RC

E: U

S D

OE.

SO

UR

CE:

US

DO

E.

SOU

RC

E: U

S D

OE.

SO

UR

CE:

US

DO

E.

02468

Se

p-1

2D

ec

-12

Ma

r-1

3J

un

-13

Se

p-1

3D

ec

-13

Ma

r-1

4J

un

-14

Se

p-1

4

Fre

ep

ort

Lak

e C

ha

rles

Sab

ine

Pa

ss

Cam

ero

nG

old

en

Pas

sG

ulf

LN

G

US

G

oM

L

NG

Im

po

rts B

y F

ac

ility (B

cf)

05

10

15

20

Sep

-12

De

c-1

2M

ar-

13

Ju

n-1

3S

ep

-13

De

c-1

3M

ar-

14

Ju

n-1

4S

ep

-14

Oth

er

Nig

eri

aT

rin

ida

dN

orw

ay

Qa

tar

Ye

me

n

US

L

NG

Im

po

rts B

y O

rig

in

(B

cf)

02468

10

12

14

16

Sep

-12

Dec-1

2M

ar-

13

Ju

n-1

3S

ep

-13

Dec-1

3M

ar-

14

Ju

n-1

4S

ep

-14

Co

ve

Po

int

Elb

a Is

lan

dE

ve

rett

NE

Gate

wa

yN

ep

tun

e

Ea

ste

rn

U

S L

NG

Im

po

rts B

y F

ac

ility (B

cf)

02468

10

12

14

16

18

JF

MA

MJ

JA

SO

ND

20

12

20

13

20

14

Volum

e-W

eighted A

verage LN

G P

rice (U

S$/M

MB

tu)


SOU

RC

E: U

S D

OE,

NEB

. SO

UR

CE:

US

DO

E.

SOU

RC

E: E

IA, U

S D

OE.

SO

UR

CE:

US

DO

E.

0123456

Se

p-1

2D

ec

-12

Ma

r-1

3J

un

-13

Se

p-1

3D

ec

-13

Ma

r-1

4J

un

-14

Sep

-14

Japan

US

L

NG

E

xp

orts to

J

ap

an

(B

cf)

01234567

Se

p-1

2D

ec

-12

Ma

r-1

3J

un

-13

Se

p-1

3D

ec

-13

Ma

r-1

4J

un

-14

Se

p-1

4

Me

xic

oB

razil

Ja

pa

n

US

L

NG

R

e-E

xp

orts

By D

estin

atio

n (B

cf)


SOU

RC

E: C

ERI,

CA

OD

C, B

aker

Hu

ghes

. SO

UR

CE:

CER

I, C

AO

DC

.

SOU

RC

E: C

ERI,

CA

OD

C.

SOU

RC

E: C

ERI,

CA

OD

C.

0

500

1,0

00

1,5

00

2,0

00

2,5

00

3,0

00 Ja

n-0

6J

an

-07

Ja

n-0

8J

an

-09

Ja

n-1

0J

an

-11

Jan

-12

Jan

-13

Ja

n-1

4

US

WC

SB

North A

merican A

ctive R

igs

0

100

20

0

300

400

50

0

600

70

0

800

900

1,0

00 Ja

n-0

6J

an

-07

Jan

-08

Jan

-09

Jan

-10

Jan

-11

Jan

-12

Jan

-13

Jan

-14

Ac

tiv

e R

igs

To

tal

Rig

Dri

llin

g F

lee

t

Ca

na

dia

n R

ig

F

le

et U

tiliza

tio

n

We

ek

ly A

ve

ra

ge

A

ctive

R

ig

s

0

100

20

0

300

40

0

500

600

70

0 Jan

-09

Ja

n-1

0J

an

-11

Ja

n-1

2J

an

-13

Ja

n-1

4

SK

AB

BC

WC

SB

A

ctive

R

ig

s b

y P

ro

vin

ce

We

ek

ly A

ve

ra

ge

-

10

0

20

0

30

0

40

0

50

0

60

0

70

0

80

0

15

91

317

21

25

29

33

37

41

45

49

5-Y

ea

r A

vg

.2013

2014

We

ste

rn

C

an

ad

a A

ctive

R

ig

s

We

ek

ly A

ve

ra

ge

We

ek

Nu

mb

er


SOU

RC

E: C

ERI,

Bak

er H

ugh

es.

SO

UR

CE:

CER

I, B

aker

Hu

ghe

s.

SOU

RC

E: C

ERI,

Bak

er H

ugh

es.

0%

10

%

20%

30%

40%

50%

60

%

70%

80

%

90%

100%

0

200

400

60

0

80

0

1,0

00

1,2

00

1,4

00

1,6

00

1,8

00

2,0

00

2,2

00

2,4

00 Ja

n-0

6J

an

-07

Ja

n-0

8J

an

-09

Ja

n-1

0J

an

-11

Ja

n-1

2J

an

-13

Ja

n-1

4

Oil-d

irec

ted

Gas-d

ire

cte

dG

as-d

ire

cte

d %

US

T

ota

l A

ctive

R

ig

s

0

500

1,0

00

1,5

00

2,0

00

2,5

00 Ja

n-0

6J

an

-07

Jan

-08

Jan

-09

Ja

n-1

0J

an

-11

Jan

-12

Ja

n-1

3J

an

-14

To

tal O

il-d

irec

ted

Go

M G

as-d

ire

cte

dO

nsh

ore

Gas-d

ire

cte

d

US

T

ota

l A

ctive

R

ig

s

0

20

40

60

80

100

12

0 Ja

n-0

6J

an

-07

Ja

n-0

8J

an

-09

Ja

n-1

0J

an

-11

Ja

n-1

2J

an

-13

Ja

n-1

4

Oil-d

irec

ted

Ga

s-d

ire

cte

d

US

G

ulf o

f M

ex

ic

o A

ctive

R

ig

s

October 2014 2% $25.00 4% CERI Commodity Report ......LNG re-gasification capacity; while there were...

Documents

Transcript of October 2014 2% $25.00 4% CERI Commodity Report ......LNG re-gasification capacity; while there were...