ANNUAL REPORT 2011 - Connacher Oil and Gas

AR 2011
PG 24
UPSTREAM REVENUE (1)
Three months ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Gross upstream revenues (2) $ 123,150 $ 3,441 $ 889 $ 127,480 $ 99,456 $ 5,377 $ 2,633 $ 107,466
Diluent costs (3) (43,727) - - (43,727) (37,810) - - (37,810)
Transportation costs (14,741) (3) - (14,744) (8,273) (15) (1) (8,289)
Revenues $ 64,682 $ 3,438 $ 889 $ 69,009 $ 53,373 $ 5,362 $ 2,632 $ 61,367
Price ($ per bbl / Mcf / boe) (4) $ 53.04 $ 89.57 $ 3.27 $ 52.96 $ 45.08 $ 66.72 $ 3.44 $ 44.09
Year ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Gross upstream revenues (2) $ 443,768 $ 12,929 $ 5,565 $ 462,262 $ 247,187 $ 21,229 $ 12,942 $ 281,358
Diluent costs (3) (162,410) - - (162,410) (91,644) - - (91,644)
Transportation costs (50,757) (81) - (50,838) (18,806) (66) (1) (18,873)
Revenues $ 230,601 $ 12,848 $ 5,565 $ 249,014 $ 136,737 $ 21,163 $ 12,941 $ 170,841
Price ($ per bbl / Mcf / boe) (4) $ 47.59 $ 82.44 $ 3.70 $ 47.41 $ 45.65 $ 65.63 $ 3.90 $ 44.13
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Bitumen produced at our oil sands project is mixed with purchased diluent and sold as “dilbit”. Gross revenues represent sales of dilbit, crude oil and natural gas and are presented before royalties. In the
consolidated financial statements, upstream revenues are presented net of royalties.
(3) The cost of diluent has been deducted from gross revenues in calculating revenues, above, whereas the diluent costs have been included in “Blending and costs of product sold” in the consolidated financial
statements. Diluent costs, above, include purchases of $3.8 million and $15.2 million from our subsidiary, MRCI in Q4 2011 and YTD 2011, respectively (Q1 2010 and YTD 2010 - $3.8 million and $14.3
million, respectively) at market prices. These intercompany transactions have been eliminated in our consolidated financial statements.
(4) Per unit prices are calculated using revenues divided by bitumen, crude oil and natural gas actual volumes sold.
The bitumen produced by Connacher requires blending to reduce its viscosity in order to transfer the bitumen to market. Diluent used represented
approximately 23 percent of the dilbit barrel sold in Q4 2011 and YTD 2011 (26 percent in Q4 2010 and 25 percent in YTD 2010). In 2011, we
purchased 3,889 bbl/d of diluent at $114.41 per bbl, including transportation costs, compared to 2,806 bbl/d at $89.48 per barrel for the same
period last year. The cost of blending diluent is recovered at the sale price of the blended product.
Transportation costs represent costs to transport dilbit and crude oil to customers. Transportation costs increased by 78 percent in Q4 2011
compared to Q4 2010 and 169 percent in YTD 2011 compared to YTD 2010, due to increased bitumen sales volumes as wells as higher trucking
costs resulting from both industry cost pressures and increased long-haul trucking to markets in 2011 arising from sales market disruptions.
Additionally, we commenced railing dilbit to new USA markets to alleviate downstream barriers, to access new sales markets that are less connected
to current WTI/WCS pricing levels and which give evidence of being more aligned with higher Brent oil pricing. In conjunction with our goal of
optimizing netbacks, railing dilbit is a part of our marketing diversification strategy, primarily aimed at mitigating the risk of plant curtailment due to any
inability to sell production in congested markets, combined with minimal on-site storage facilities. Transportation and marketing costs for 2011 also
include the carrying cost of temporary storage facilities secured in Tacoma, Washington during the year.
ROYALTIES (1)
Three months ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Royalties $ 3,772 $ 544 $ (98) $ 4,218 $ 2,188 $ 1,587 $ 70 $ 3,845
Royalties ($ per bbl / Mcf / boe) (2) $ 3.09 $ 14.17 $ (0.36) $ 3.24 $ 1.85 $ 19.76 $ 0.09 $ 2.76
Year ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Royalties $ 13,740 $ 2,556 $ (938) $ 15,358 $ 5,440 $ 5,713 $ 172 $ 11,325
Royalties ($ per bbl / Mcf / boe) (2) $ 2.83 $ 16.40 $ (0.62) $ 2.92 $ 1.82 $ 17.72 $ 0.05 $ 2.93
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Per unit royalties are calculated using royalties divided by bitumen, crude oil and natural gas actual volumes sold.
Royalties represent charges against production or revenue by governments and landowners. From period to period, royalties vary due to changes in the
product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices.
Royalties in Q4 2011 and YTD 2011 increased by 10 percent and 36 percent compared to Q4 2010 and YTD 2010, respectively, primarily due to
higher sales volumes and higher WTI benchmark prices on which royalties are calculated, partially offset by Alberta gas cost allowance recoveries.