ANNUAL REPORT 2011 - Connacher Oil and Gas

AR 2011
PG 25
OPERATING COSTS (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
Operating costs $ 23,923 $ 781 $ 560 $ 25,264 $ 22,447 $ 1,331 $ 1,145 $ 24,923
Operating costs ($ per bbl / Mcf / boe) (2) $ 19.62 $ 20.35 $ 2.07 $ 19.39 $ 18.96 $ 16.57 $ 1.50 $ 17.91
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
Operating costs $ 97,295 $ 2,929 $ 2,912 $ 103,136 $ 60,344 $ 4,407 $ 5,403 $ 70,154
Operating costs ($ per bbl / Mcf / boe) (2) $ 20.08 $ 18.80 $ 1.93 $ 19.64 $ 20.15 $ 13.67 $ 1.63 $ 18.12
(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 costs are calculated using operating costs divided by bitumen, crude oil and natural gas actual volumes sold.
Total oil sands operating costs increased by 7 percent in Q4 2011 compared to Q4 2010, reflecting general industry cost conditions and increased by
61 percent in YTD 2011 compared to YTD 2010 due to the incremental production at Algar. Operating costs in 2011 also include incremental costs
related to our SAGD+ pilot project.
The table below summarizes information related to our oil sands operating costs:
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
($000) ($ per bbl) ($000) ($ per bbl) ($000) ($ per bbl) ($000) ($ per bbl)
Natural gas costs (1) $ 6,696 5.49 $ 7,187 6.07 $ 29,263 6.04 $ 18,142 6.06
Other operating costs 17,227 14.13 15,260 12.89 68,032 14.04 42,202 14.09
Total oil sands operating costs $ 23,923 $ 19.62 $ 22,447 $ 18.96 $ 97,295 $ 20.08 $ 60,344 $ 20.15
(1) Excluding risk management contract gains and losses. Includes natural gas consumed by boilers at the cogeneration facility and by other vessels at Great Divide.
We utilize natural gas primarily for our boilers at both plants and our cogeneration facility at Algar. In Q4 2011, the combined steam: oil ratio (“SOR”)
from Pod One and Algar was 4.1 compared to 3.8 in Q4 2010. On a YTD basis, SOR was 4.0 in 2011 compared to 4.3 in 2010. The company had
been producing high levels of steam at Algar to test the reservoir performance while in ramp-up, but recently reduced steam production without any
attendant reduction of bitumen production. At Pod One, the higher SORs reflect the impact of underperforming wells on the north pad. The drilling of
new wells and new technologies such as SAGD+ are anticipated to lower SORs and improve individual well and overall productivity.
We commissioned our 13 megawatt cogeneration plant at Algar in 2010 and as a consequence have experienced the benefits of improved power
stability in our oil sands operations. Although this has resulted in higher natural gas utilization and related costs, it has reduced our reliance on third
party power suppliers and has improved operational reliability at both Pod One and Algar.
The company also recorded risk management contract losses of $1.9 million in Q4 2011 and $2.5 million in YTD 2011 relating to AECO natural
gas purchase contracts. These losses are not included in the calculation of operating costs noted in the table above. Currently, the company has the
following AECO natural gas price risk management contracts:
• January 1, 2012 – December 31, 2012 – 5,000 GJ/d at a minimum of AECO CAD$3.70/GJ and a maximum of AECO CAD$4.30/GJ;
• January 1, 2012 – December 31, 2012 – 5,000 GJ/d at a minimum of AECO CAD$2.80/GJ and a maximum of AECO CAD$4.00/GJ;
• March 1, 2012 – June 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $2.90/GJ; and
• July 1, 2012 – September 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $3.20/GJ.
SAGD+
Connacher completed a steam with solvent (SAGD+) field trial on two of its wells located on Pad 203 at Algar in 2011, as a pilot project designed
to enhance reservoir recovery and bitumen production, while lowering steam injection volumes. Results were encouraging, with an approximate
29 percent increase in base-line bitumen production and a reduction in SOR by approximately 17 percent. The company is currently completing a
commercial front-end engineering design study on this project. While solvent recoveries and related production impact have exceeded expectations,
facility modifications will have to be implemented to fully capture and recycle the recovered solvent.