ANNUAL REPORT 2011 - Connacher Oil and Gas

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AR 2011 PG 34 PERFORMANCE Our financial and operating performance is potentially affected by a number of factors, including, but not limited to the following: • Our ability to reliably operate our conventional and oil sands facilities and our refinery is important in meeting production targets. • Operating costs could be impacted by inflationary pressures on labor, volatile pricing for natural gas used as an energy source in oil sands processes and planned and unplanned maintenance. We continue to address these risks though such strategies as application of technologies and an increased focus on regular preventative maintenance. The Refinery is in its final year of operation prior to the scheduled turnaround in 2013. • While fiscal regimes in Alberta, Canada and the USA are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company’s planned investments and rates of return on existing investments. • Management expects that fluctuations in demand and supply for refined products, margin and price volatility, market competition and the seasonal demand fluctuations for some of our refined products will continue to impact our refining business. • There are certain risks associated with the execution of capital projects, including the risk of cost overruns and delays. Numerous risks and uncertainties can affect construction schedules, including the availability of labor and other impacts of competing projects drawing on the same resources during the same time period. CAPITAL REQUIREMENTS The company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of bitumen and crude oil reserves and refining in the future. As the company’s revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the global economic situation exposes the company to additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the company. The inability of the company to access sufficient capital for its operations and growth could have a material adverse effect on the company’s business financial condition, results of operations and prospects. THIRD PARTY CREDIT RISK Credit risk is a risk of failure of performance by counter-parties. We attempt to mitigate this credit risk before contract initiation and ensuring product sales and delivery contracts are made with well-known and financially strong crude oil and natural gas marketers. The company may be exposed to third party credit risk through its contractual arrangements with its current counter-parties. In the event such entities fail to meet their contractual obligations to the company, such failures may have a material adverse effect on the company’s business, financial condition, results of operations and prospects. ENVIRONMENTAL All phases of the oil and gas and refining business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial, state and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. There has been much public debate with respect to Canada’s alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil, gas and refining operations, including those of the company. Given the evolving nature of the issues related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the company and its operations and financial condition. The company may be subject to remedial environmental and litigation costs resulting from potential unknown and unforeseeable environmental impacts arising from the company’s operations. While these costs have not been material to the company in the past, there is no guarantee that this will continue to be the case in the future as the company carries on with development of technologies. At our Refinery, we now make ultra-low sulphur diesel and gasoline. We are also mandated to remove benzene from our refined gasoline commencing in 2011. This project is ongoing however we were required to purchase benzene credits in 2011 and will continue to do so until commissioning of the project. Thereafter, our benzene purchase requirements will be reduced but not 100 percent mitigated. Our upstream and downstream businesses are closely regulated with respect to land disturbance, water usage and green house gas emission. To meet these requirements, our operations personnel closely follow established environmental policies and procedures and regularly report to regulators. The quality of these reports has been affirmed by recent audits.
AR 2011 PG 35 ACCOUNTING POLICIES AND ESTIMATES ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS On January 1, 2011, the company adopted International Financial Reporting Standards (“IFRS”) for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2011, including required comparative information, have been prepared in accordance with International Financial Reporting Standards 1, First-time Adoption of International Financial Reporting Standards. The following provides a summary reconciliation of Connacher’s 2010 net loss before taxes calculated in accordance with previous GAAP and Connacher’s 2010 net loss after taxes calculated in accordance with IFRS, along with a discussion of the significant IFRS accounting policy changes. Summary Net Loss Reconciliation (Canadian dollar in thousands) YTD 2010 Net loss per previous GAAP $ (38,798) Exploration and evaluation expense (964) Depletion, depreciation, amortization and impairment 1,305 Disposition of oil and gas properties (5,287) Compensation 44 Unwinding of discount on decommissioning liabilities 812 Interest in associate 3,140 Unrealized loss on revaluation of Convertible Debentures (228) Income taxes (4,693) Net loss per IFRS $ (44,669) ACCOUNTING POLICY CHANGES The following discussion explains the significant differences between Connacher’s previous GAAP accounting policies and those applied by the company under IFRS. IFRS policies have been retrospectively and consistently applied except where specific IFRS 1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. IFRS 1 requires the presentation of comparative information as at the January 1, 2010 (“transition date”) and subsequent comparative periods as well as the consistent and retrospective application of IFRS accounting policies. To assist with the transition, the provisions of IFRS 1 allow for certain mandatory exceptions and optional exemptions for first-time adopters. The significant mandatory exceptions and optional exemptions applied under IFRS 1 in preparing the consolidated financial statements are set out below followed by a discussion regarding the impact of individually significant items. Deemed cost election for oil and gas properties Under previous GAAP, the company followed the “full cost” method of accounting for petroleum and natural gas activities under which all costs directly associated with the acquisition of, the exploration for, and the development of petroleum and natural gas reserves were capitalized on a country– by–country cost centre basis. The company had one cost centre, Canada, for the upstream segment. Costs accumulated within this one cost centre were depleted using the unit–of–production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, the company was required to adopt new accounting policies for upstream activities, including the segregation of exploration and evaluation costs and petroleum and natural gas properties. Under IFRS, exploration and evaluation costs are those expenditures for which technical feasibility and commercial viability has not yet been determined, are presented separately on the balance sheet as exploration and evaluation assets and may or may not be amortized based on the company’s accounting policy. Petroleum and natural gas properties include those expenditures where technical feasibility and commercial viability has been determined, are presented as a part of property, plant and equipment on the balance sheet and are depleted and depreciated on a segregated basis based on the company’s accounting policy. The company adopted the IFRS 1 exemption whereby the company deemed its January 1, 2010 IFRS upstream asset costs to be equal to its previous GAAP historical upstream property, plant and equipment net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the petroleum and natural gas properties costs were deemed equal to the remaining upstream full cost pool balance. The petroleum and natural gas property costs were allocated for depletion, depreciation and impairment testing purposes on a pro rata basis using proved reserves values at the transition date. Leases The company has elected not to reassess whether an arrangement contains a lease under International Financial Reporting Interpretations Committee Interpretation 4 for contracts that were assessed under previous GAAP. Business Combinations IFRS 3, “Business Combinations” has not been applied to business combinations that occurred before the transition date. Borrowing Costs Borrowing costs directly attributable to the acquisition or construction of qualifying assets were not retrospectively restated prior to transition date.
Page 1 and 2: ANNUAL REPORT 2011 WELL POSITIONED
Page 3 and 4: AR 2011 PG 1 02 HIGHLIGHTS 05 LETTE
Page 5 and 6: AR 2011 PG 3 Years ended December 3
Page 7 and 8: AR 2011 PG 5 Volatility in the oil
Page 9 and 10: AR 2011 PG 7 “Thanks to our liqui
Page 11 and 12: AR 2011 PG 9 Review of Operations I
Page 13 and 14: AR 2011 PG 11 proposals helped to p
Page 15 and 16: AR 2011 PG 13 reservoir description
Page 17 and 18: AR 2011 PG 15 Connacher Oil and Gas
Page 19 and 20: AR 2011 PG 17 the movement of wildl
Page 21 and 22: AR 2011 PG 19 MANAGEMENT’S DISCUS
Page 23 and 24: AR 2011 PG 21 reduced interest rate
Page 25 and 26: AR 2011 PG 23 Connacher’s bitumen
Page 27 and 28: AR 2011 PG 25 OPERATING COSTS (1) T
Page 29 and 30: AR 2011 PG 27 SALES PRODUCT MIX (%)
Page 31 and 32: AR 2011 PG 29 Depletion expense is
Page 33 and 34: AR 2011 PG 31 NEW NOTES We issued U
Page 35: AR 2011 PG 33 Compensation of key m
Page 39 and 40: AR 2011 PG 37 The company classifie
Page 41 and 42: AR 2011 PG 39 Management is respons
Page 43 and 44: AR 2011 PG 41 The production outloo
Page 45 and 46: AR 2011 PG 43 QUARTERLY HIGHLIGHTS
Page 47 and 48: AR 2011 PG 45 Independent Auditor
Page 49 and 50: AR 2011 PG 47 Consolidated Statemen
Page 51 and 52: AR 2011 PG 49 Consolidated Statemen
Page 53 and 54: AR 2011 PG 51 Impairment of assets
Page 55 and 56: AR 2011 PG 53 Goodwill is allocated
Page 57 and 58: AR 2011 PG 55 3.11 Leases Agreement
Page 59 and 60: AR 2011 PG 57 IAS 1 Presentation of
Page 61 and 62: AR 2011 PG 59 Reconciliation of seg
Page 63 and 64: AR 2011 PG 61 8.1 Petroleum and nat
Page 65 and 66: AR 2011 PG 63 10. PROPERTY, Plant a
Page 67 and 68: AR 2011 PG 65 Accounts receivable a
Page 69 and 70: AR 2011 PG 67 December 31, 2010 - C
Page 71 and 72: AR 2011 PG 69 13.3 Refinancing of l
Page 73 and 74: AR 2011 PG 71 Changes in present va
Page 75 and 76: AR 2011 PG 73 The provision for inc
Page 77 and 78: AR 2011 PG 75 The following table s
Page 79 and 80: AR 2011 PG 77 19. FINANCE Charges F
Page 81 and 82: AR 2011 PG 79 Compensation of key m
Page 83 and 84: AR 2011 PG 81 Estimates Hindsight w
Page 85 and 86: AR 2011 PG 83 Reconciliation of Con
Page 87 and 88:
AR 2011 PG 85 27.3 Asset and Liabil
Page 89 and 90:
AR 2011 PG 87 The following table s
Page 91 and 92:
CORPORATE INFORMATION Board of Dire
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ANNUAL REPORT 2011 - Connacher Oil and Gas

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