Bitumen by Rail or Pipe?

Transcription

1 Bitumen by Rail or Pipe? October 2012

2 Forward-Looking Statements Certain statements, estimates and financial information contained in this presentation ("Estimates") constitute forwardlooking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the Estimates or results implied or expressed in such forward-looking statements. While presented with numerical specificity, the Estimates are based (i) on certain assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, and competitive uncertainties, contingencies and risks including, without limitation, assumptions of resource, ability to obtain debt and equity financing, capital costs, construction costs, well production performances, operating costs, commodity pricing, differentials, royalty structures, regulatory approvals, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the control of ULC ("Grizzly"); and (ii) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the Estimates or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the Estimates. Under no circumstances should the inclusion of the Estimates be regarded as a representation, undertaking, warranty or prediction by Grizzly, or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that Grizzly will achieve or is likely to achieve any particular results. The Estimates are made as of the date of this presentation and Grizzly disclaims any intent or obligation to update publicly or to revise any of the Estimates, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein. There are significant differences in the criteria associated with the classification of reserves, prospective resources and contingent resources. Contingent resources and prospective resources estimates involve additional risks, specifically the risk of not achieving commerciality and exploration risk, respectively, not applicable to reserves estimates. No adjustments for these risks have been made in the groupings of reserves and recoverable resources. All reference to dollars in this presentation should be assumed to refer to Canadian dollars, unless otherwise noted. All references to reserves and or resources represent Grizzly s interest in reserves and resources prior to the deduction of Crown royalties, unless otherwise noted. 2

3 Grizzly Overview High Quality Resource Base with Significant Upside Canadian, privately owned, pure play SAGD oil sands development company 800,000+ net acres under long-term lease (100% operated, ~ 100% WI) > 3 billion barrels of recoverable bitumen resources 1 First production in 2013; ~90,000 bbls/d of production potential by 2020 Top Tier Management Team Management team with an average of 29 years of experience Led by John Pearce, Chief Executive Officer Executive team experience on Imperial Oil Cold Lake, Devon Dover, Surmont and Jackfish, Suncor Mackay River and Firebag projects. Unique Modular Oil Sands Development Reduced cost, downtime and risk through proprietary ARMS development model More efficient production and improved reserve life over traditional SAGD Scaled, flexible development enables exploitation of smaller bitumen pools and acceleration of larger pools 1 Based on GLJ estimates of reserves and best estimate contingent resources. 3

4 800,000 + Net Acres of Alberta Oil Sands Leases Leases Other Oil Sand Leases Alberta Oil Sands Areas Thermal Producer Under Construction ~280 mi (~450 km) Liege-Harper West Ells Asphalt Creek McClelland Lake Ells North Silvertip Ells Central & South Husky/BP - Sunrise Firebag River Suncor - Firebag Dover Suncor McKay River North Star- Nina Driftwood Lake Cadotte Shell Peace River Slave Loon Prairie Muskwa Wabasca Birchwood Saleski West House Thickwood Hills Athabasca Rapids Saleski East Laricina - Saleski Laricina - Germain Black Bear Southern Pacific McKay River Riverside Fishery Creek Algar Lake Horse River Kodiak Fort McMurray Jacos - Hangingstone Connacher Algar Connacher Pod One Nexen/CNOOC - Long Lake Conoco-Phillips/Total - Surmont ~170 mi (~270 km) Cherpeta Statoil/PTTEP - Leismer May River MEG Christina Lake Cenovus/Conoco-Phillips KNOC BlackGold Christina Lake Devon - Jackfish CNRL - Kirby Exposure to All Play Types in Athabasca & Peace River 4

5 Rapidly Growing Production Profile Potential Project Development Schedule (bbls/d) Total 91, ,000 (1) 20, ,400+ May River May 74,800 River 74,800 20,400+ 5,500+ 5, ,600 5,500+ Algar Algar May River Thickwood May River May River Phase 1 Phase 2 1 & & 4 & 5 6 & 7 & (1) Production Potential Based on GLJ s estimate of probable reserves plus best estimate contingent resources. May River 9 & 10 & Thickwood 5,500 Algar 1&2 11,000 Total 2030 Lower Risk with Multiple Projects in Diversified Reservoirs 5 5

6 Key Rail Messages Growing volumes of heavy oil are now moving by rail to markets not accessible by pipe (PADD 3 along the Mississippi River and Houston Ship Channel, California, East Coast) Rail accesses the WORLD oil price (i.e. Maya 21 API / Castilla 18 API / #6 Residual Fuel Oil / Bunker C) At Brent = $100/Bbl and with the new drilling technology, oil supply growth will be continuous (mostly light shale oil) and the market access issues for Western Canada will continue Cushing/Brent disconnect is costing Alberta producers $10 - $20/Bbl. Producer needs alternative to PADD 2 right now, not 3-5 years from now. As rail car supply is the issue, the key to volume growth is reducing the cycle times to a minimum larger block sizes, minimal interconnects with other RR, efficient loading/unloading sounds easy but difficult in practice 6

7 Market Developments Southern Lights diluent pipeline reduced differentials between Mt Belvieu, TX and Alberta - the basis has again expanded to approach the marginal rail cost with Southern Lights IT toll at 200% of firm toll, this appears inevitable (Pipe IT toll = rail minus a penny). Continuing pipeline issues on old Enbridge system around Chicago and some older Alberta gathering pipelines has highlighted the need for alternatives to pipelines Coiled and insulated rail car lead time (18-24 months) has slowed the growth of heavy oil and bitumen by rail. Major entry by large market participants with new cars is still 6 months off. Basis differential between WCS Hardisty (heavy) and WTI Cushing (light) is volatile, ranging from $-37/B to $-10/B over the last 6 months, suggesting that small volumes by rail can have a large effect on the heavy oil netback. 7

8 Futures Oil Value $US/B for Jan 2013 (A. E. Bruggemann, National Oct 19, 2012) Brent $ Jan 13 Futures USGC # 6 Residual F.O. $96.55 Brent WTI Cushing $93.62 Brent WCS Hardisty $72.62 WTI C5+ Edmonton $ WTI Diluent Penalty $12.86 (30/70)*(21+9) Lo Tan* Hardisty $59.76 WCS Hi Tan* Hardisty $52.62 Estimate only: $- 5/B divided by 0.7 * TAN is Total Acid Number value discounts when TAN>1 8

9 Bitumen transport cost is higher than quoted tolls for 30/70 dilbit Firm (10 20 yr commitment) Interruptible (150% of firm) Pipeline Toll Hardisty - USGC $ 8.00 $12.00 Pipeline Toll Field - Hardisty $ 2.00 $ 3.00 Pipeline Storage $ 1.00 $ 1.00 Line Fill 40 days $ 1.00 $ 1.00 Dilbit Pipe Total $12.00 $17.00 Diluent Transport Mt Belvieu-Edmonton $10.00 $15.00 Diluent Transport Edmonton-Field $ 2.00 $ 3.00 Diluent Penalty at (30/70) of sum of above $10.28 (.428*$24) $14.98 (.428*$35) Total Bitumen Transport Cost $22.28 $31.98 RAIL IS LESS 9

10 Pipeline Hydraulics 101 Because of oil viscosity dilbit throughput equals 50% of light oil throughput at constant station spacing and pressure drop In the 70 s, when light oil was seen to be in decline, and heavy oil on the rise, the pipeline builders offered tolls on existing lines for heavy oil of only 120% of light oil to help justify expansion this was a form of subsidy Light oil is now the commodity on the rise and many pipes (Enbridge and XL included) have fixed tolls which means that extra throughput means extra profit to the pipeline as they are no longer using strict cost-of-service Scenario 1 36 carries 350 KBPD heavy oil at $6/Bbl and 350 KBPD light oil at $5/Bbl = $3.85 MM/day Scenario 2 36 carries 1.5 MMBPD light oil at $5/Bbl = $7.5 MM/day WHICH WOULD YOU WANT IF YOU OWNED THE PIPELINE? 10

11 Pipe vs. Rail Conclusion: Rail is a weight limited system so rail volumetric capacity for heavy oil vs. light oil is equal to the density ratio (820 / 1000) ($22.28 / $12 for bitumen cost vs. dilbit toll by pipe) * 200% (for light oil capacity vs. dilbit capacity in the same pipe) * (820/1000 density) = 3 It is 3 times more efficient to rail bitumen and pipe light oil than the other way around. 11

12 Other Access Factors Field access specifics could subtract $5-12/Bbl from a net-back calculated at hubs such as Hardisty and Edmonton Pipeline toll from the field to Hardisty for dilbit is $1-3/Bbl Diluent transport cost from Edmonton to the field is $2-3/Bbl Field pipelines require major lines of credit or else one has to truck, this can cost 2-3 times as much as pipe Water removal can add $1/Bbl USGC can handle > 0.5% BS&W Trucking distance and terminal wait times can add an incremental $1 - $3/Bbl (current trucking rates are about $0.70/Bbl/hr) 12

13 Marketing Options The main issue today is lack of coiled, insulated rail cars the lead time is the 3 rd quarter of 2014 for new cars There are two methods for a producer to participate in rail marketing Sell at railhead at index price plus a premium (Western Canada Select index at Hardisty) to a party that has rail cars Lease rail-cars, secure loading and unloading, sell into coastal market at their index (Brent, LLS, 3% Residual Fuel Oil or Mayan/Castilla Heavy Oil) 13

14 Conclusion Alberta and Saskatchewan oil producers have lost $ Billions by not having more rail capacity for loading, rail cars and unloading. Mainline capacity is not an issue. Bakken oil contracted all the spare North American rail car manufacturing capacity while Canadian oil waited for pipelines that never got built Major beneficiary is PADD 2 markets that purchase trapped Canadian oil by pipe XL pipeline is still a few years away, faces social and political opposition and could evolve into a North Dakota - Bakken based, light oil pipeline Gateway and Trans Mountain Pipeline are still years away and face social and political opposition they are more efficient as light oil pipelines Heavy oil by rail is CHEAPER than new dilbit pipelines on any measure chosen that excludes subsidy or roll-in rail is less risky, is more flexible, has a faster start-up, has minimal dependence on economy of scale only downside risk is the railroads increasing their rates beyond pipe competitive economics Bitumen need for a rail option is greater than ever 14