Full SAGD Bitumen Production Underway at Algar; Connacher Reports Second
Quarter 2010 and First Half 2010 Comparative Results
CALGARY, Aug. 11 /CNW/ - Connacher Oil and Gas Limited (CLL - TSX) today reported that full steam assisted gravity drainage ("SAGD") bitumen production has commenced at Algar, the company's second 10,000 bbl/d oil sands plant located at its Great Divide Project in northeastern Alberta. The conversion of wells to full SAGD production commenced on August 4, 2010, following a steam circulation phase which has been underway since May 2010. This process will eventually result in all 17 of Algar's current SAGD well pairs being placed on full production as the company ramps up daily rates towards the plant's rated capacity. It is anticipated full productive capacity will be approached by the middle of 2011. Production and related revenues and costs will be capitalized and will not be included in the company's operating and financial results until a determination of commerciality later this year.
Connacher's progress continued throughout the second quarter of 2010. Algar was commissioned, steam production was initiated and the circulation phase activated, with 15 of 17 SAGD well pairs receiving steam. Pod One production was lower than anticipated, primarily due to the adverse impact of numerous periodic power outages and pump failures, some of which were a result of the unreliable power supply in the region. Also, results were impacted by the decision to conduct a full turnaround in May 2010 as opposed to later in the year, when significant new production from Algar is anticipated. We anticipate this should help streamline the integration of Algar production into our sales and marketing efforts as sales volumes expand towards our goal of 15,500 bbl/d - 16,500 bbl/d of bitumen by year end 2010, with further increases anticipated by early 2011.
We have lowered our anticipated full year estimates for bitumen production due to the impact of these exogenous factors on our actual first half 2010 results. This is described in greater detail in our Management's Discussion and Analysis for the reporting period. We continue to focus on reliability as an operational objective, as it is important to produce and inject steam on a consistent basis and frequent power outages have upset this quotient. We also continue to introduce added pumping capacity; this program already reduced the steam:oil ratio ("SORs") for wells with pumps to 2.9 during the first six months of this year. We currently have pumps in 14 of our wells and we anticipate having 17 out of 19 wells at Pod One on pump by the end of August 2010. Improved power reliability overall for Connacher will be aided by the startup of our cogeneration facility at Algar and by the anticipated completion, in spring 2011, of a regional electrical substation which will service Pod One.
With rising production, low natural gas prices, improved volumes at Great Divide, anticipated strong third quarter 2010 returns from our refinery in Great Falls, Montana similar or better than those achieved in the second quarter 2010 and firm crude oil prices, we remain optimistic on our overall outlook for 2011 as we begin the planning process for next year's programs.
These results will be the subject of a Conference Call at 9:00 AM MT on August 12, 2010. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Thursday, August 12, 2010 at 12:00 MT until 21:59 MT on Thursday, August 19, 2010. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-800-642-1687 and enter the pass code 90975219. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=3170200.
An updated corporate presentation will be posted on Thursday, August 12, 2010 at 7:00 AM MT. To access the presentation, go to Connacher's website at www.connacheroil.com, click the Investor Info link, and then Presentations & Webcasts.
Highlights
- Proved plus probable ("2P") reserves exceeded 511 million
barrels, at June 30, 2010, up 32 percent since year end 2009
- 10 percent present value ("PV") of 2P reserves $2.8 billion
- 10 percent PV of proved plus probable plus possible ("3P")
reserves, including 104 million barrels of possible reserves,
exceeded $3.5 billion
- Best estimate contingent and best estimate prospective resources
of 223 million and 72 million barrels respectively, with 10
percent PV an additional $422 million and $129 million,
respectively
- Algar, our second oil sands project with a rated capacity of
10,000 bbl/d, completed ahead of schedule and under budget
- First full SAGD bitumen production underway at Algar following
steam circulation phase
- EIA application for Great Divide Development Program (to
44,000 bbl/d rated capacity) submitted to regulators
- Excellent refinery results in second quarter, outlook positive
Summary Results
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Three months ended and as at June 30
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FINANCIAL ($000 except per
share amounts) 2010 2009 Change
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Revenues $141,270 $100,219 41
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Cash flow(1) $8,668 $9,570 (9)
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Per share, basic(1) $0.02 $0.04 (50)
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Per share, diluted(1) $0.02 $0.03 (33)
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Net earnings (loss) $(33,126) $39,966 (183)
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Per share, basic $(0.08) $0.15 (153)
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Per share, diluted $(0.08) $0.14 (157)
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Property and equipment additions $59,316 $40,236 47
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Cash on hand $69,412 $401,160 (83)
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Working capital $99,834 $455,001 (78)
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Long-term debt $888,323 $960,593 (8)
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Shareholders' equity $644,166 $622,235 4
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Total assets $1,713,121 $1,723,370 (1)
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OPERATIONAL
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Upstream daily production/sales volumes
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Bitumen (bbl/d) 6,211 6,284 (1)
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Crude oil (bbl/d) 906 1,114 (19)
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Natural gas (Mcf/d) 9,278 12,144 (24)
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Equivalent (boe/d)(2) 8,663 9,421 (8)
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Upstream pricing(3)
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Bitumen ($/bbl) $43.13 $40.95 5
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Crude oil ($/bbl) $61.90 $54.87 13
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Natural gas ($/mcf) $3.78 $3.35 13
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Barrels of oil equivalent ($/boe)(2) $41.44 $38.11 9
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Downstream
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Refining throughput and Crude
charged (bbl/d) 9,373 9,145 2
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Refinery utilization (%) 99% 96% 3
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Margins (%) 12% 5% 140
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Six months ended and as at June 30
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FINANCIAL ($000 except per
share amounts) 2010 2009 Change
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Revenues $259,681 $161,976 60
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Cash flow(1) $12,616 $4,878 159
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Per share, basic(1) $0.03 $0.02 50
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Per share, diluted(1) $0.03 $0.02 50
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Net earnings (loss) $(27,580) $(6,878) 301
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Per share, basic $(0.06) $(0.03) 100
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Per share, diluted $(0.06) $(0.03) 100
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Property and equipment additions $177,588 $104,491 70
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Cash on hand $69,412 $401,160 (83)
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Working capital $99,834 $455,001 (78)
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Long-term debt $888,323 $960,593 (8)
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Shareholders' equity $644,166 $622,235 4
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Total assets $1,713,121 $1,723,370 (1)
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OPERATIONAL
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Upstream daily production/sales volumes
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Bitumen (bbl/d) 6,572 6,227 6
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Crude oil (bbl/d) 921 1,147 (20)
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Natural gas (Mcf/d) 9,469 12,184 (24)
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Equivalent (boe/d)(2) 9,071 9,455 (4)
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Upstream pricing(3)
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Bitumen ($/bbl) $47.77 $31.84 50
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Crude oil ($/bbl) $66.54 $47.07 41
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Natural gas ($/mcf) $4.33 $4.13 5
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Barrels of oil equivalent ($/boe)(2) $45.89 $32.13 43
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Downstream
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Refining throughput and Crude
charged (bbl/d) 9,360 8,012 17
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Refinery utilization (%) 99% 84% 18
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Margins (%) 4% 6% (33)
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(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in non-
cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be cash flow from operating activities. Cash flow is
reconciled with cash flow from operating activities on the
Consolidated Statement of Cash Flows and in the accompanying
Management's Discussion & Analysis ("MD&A"). Commonly used in the oil
and gas industry, management uses these non-GAAP measurements for its
own performance measures and to provide its shareholders and
investors with a measurement of the company's efficiency and its
ability to internally fund future growth expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf: 1 bbl. This conversion is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. Boes may
be misleading, particularly if used in isolation.
(3) Product pricing is net of transportation costs but before realized
and unrealized risk management contracts gains/losses.
Connacher's focus for the balance of 2010 is to optimize its bitumen production from Great Divide Pod One and Algar. Our goal is to realize bitumen production levels of 15,500 bbl/d - 16,500 bbl/d by year end 2010. This will be achieved by ramping up Algar production during the remaining months of this year, by stabilizing Pod One plant operations, by completing our planned downhole pump installation program and by bringing on two new Pod One wells, which, until recently, have been undergoing steam circulation. Further production increases are also expected during the early months of 2011 as Algar production ramps up towards rated or design capacity.
This combination of stable Pod One production and ramped up Algar production should afford us the possibility of achieving consistent and successive quarter over quarter and year over year gains in production. Our focus is on delivering improved financial results as we strive to realize the productive plant capacities from both Pod One and Algar.
Connacher reported very positive developments during the second quarter. Primarily as a result of our effective core hole exploration program, which was financed by proceeds of a successful flow-through share financing in the latter part of 2009, our bitumen reserve base expanded considerably. The majority of the 2010 additions to 2P bitumen and crude oil reserves, which exceeded 123 million barrels and much of the $700 million increase in the 10 percent PV of our 2P reserve base since year end 2009, were a direct consequence of our $25 million core hole drilling and seismic programs conducted earlier this year. By systematically evaluating our acreage, we stay ahead of the regulatory and planning curve required to compete effectively in the oil sands, while replacing our growing production and expanding our underlying per share value. This is an antidilutive method of financing our evaluation programs and in this manner, we have added value for our shareholders on a consistent basis for several years.
Also, as a result of this sound forward planning and the consistent upgrading of our resources to reserves and reserves to production, such as we have accomplished at Pod One and Algar, Connacher was able to submit an application to further develop our main lease block towards an interim goal of 44,000 bbl/d of bitumen capacity. This was accompanied by detailed environmental information to support our Environmental Impact Assessment ("EIA"). Not surprisingly, the productive capacity of our 3P reserves (as estimated by GLJ Petroleum Consultants Ltd., ("GLJ"), independent qualified reserves evaluators) coincided with our planned expansion objective, while also allowing for further expansion potential to approximately 56,000 bbl/d from our 3P reserve base. We have a well-defined growth path ahead of us.
It will likely require 18 months to receive regulatory approval for the planned expansion of our rated productive capacity from 20,000 bbl/d to 44,000 bbl/d. This will provide adequate time to determine the pace of expansion and the preferred financing alternatives for the company's growth program.
We control our own timetable and destiny, as we own a 100 percent working interest in most of our leases in the Great Divide region. In the interim, our emphasis will be on reliable production growth. Accordingly, our technical staff is determined to maximize the efficient distribution of steam capacity to optimize bitumen production at lowest cost. The successful introduction of electric submersible pumps, of both the regular and high temperature variety, progressive cavity pumps and other technical innovations associated with SAGD production, has proven to be effective in lowering SORs. SORs from Pod One wells on pumps averaged SOR of 2.9 in the first half of 2010. Overall average SOR in the first half of 2010 was approximately 3.7 Including steam used in two new wells without yet receiving new production. The improve efficiency from pump use freed up steam volumes for these new wells.
Algar was completed ahead of schedule and under budget. Final costs are estimated to be $366 million, $9 million below the $375 million budgeted amount. We achieved excellent efficiency in our SAGD well pair drilling program. We initiated the steam circulation phase after a successful and on-time commissioning and were steaming 15 of the 17 well pairs at the commencement of full SAGD production in early August 2010. We anticipate we will gradually bring all well pairs on-stream over the ensuing six to nine months, with a view to ramping up towards the plant's rated capacity during the first half of 2011. This should permit reasonably consistent growth in successive quarter over quarter and year over year production and financial results. Hopefully, this will translate into greater stock market recognition of our accomplishments.
Our refinery in Great Falls, Montana enjoyed much improved results in the second quarter 2010. This reflects the increase in asphalt sales as the paving season got underway. This business is affected by the weather, which was not exceedingly cooperative during the quarter, but regardless our business did quite well. Product margins overall compared favorably with our peers. We remain optimistic that similar or better results will be obtained in the third quarter 2010.
We conducted an extensive turnaround at Pod One in May 2010. The timing was accelerated to avoid having this type of significant event underway when meaningful production commences at Algar later this year. As a result of the lost production due to the turnaround, compounded by an abnormally high number of electrical outages and pump failures, which constrained production and upset our reliability quotient, we reported lower than anticipated second quarter bitumen production levels for Pod One. We continue to believe we can successfully increase sustainable Pod One output levels through the impact of our 2010 pump installation program and by effective management of daily operational issues. Our cogeneration facility at Algar is scheduled for startup later this year, to be followed by the subsequent completion of a nearby electrical substation in the spring of 2011. Activating the Algar cogeneration facility is expected improve the stability of power supply at Pod One and help us avoid the deleterious impact on production and pump reliability of periodic shutdowns due to power outages such as we have experienced at Pod One in the past and particularly during the second quarter 2010. Additionally, it is anticipated that the completion of the substation will substantially improve the reliability of the power supply at Pod One.
We have successfully recruited the necessary field personnel to effectively operate Algar and welcome our new employees at both Pod One and Algar. We were able to capitalize on the experience gained at Pod One by transferring some key personnel to Algar. All of our employees contributed to the very successful construction and commissioning program at Algar and their engagement is respected and appreciated. We had a successful opening ceremony on June 22, 2010 attended by a broad cross section of individuals who played a role in the engineering, design, construction, approval process and drilling of our SAGD well pairs at Algar. Alberta's Sustainable Resource Minister, Mel Knight, was our guest of honor and noted in his comments that Connacher was an example of Alberta's entrepreneurial spirit, proving smaller companies could compete effectively with large companies in the oil sands.
Recently Mr. Russ Longley resigned as Vice President, Refining and Conventional Operations. We wish Russ well in his new endeavors.
Following our last Annual Meeting in May 2010, Mr. Richard A. Gusella assumed the role of Chairman and Chief Executive Officer as part of the company's succession process. Mr. Gusella indicated he intends to remain active in the company in this executive capacity until he reaches 70 years of age, in approximately four years. In recognition of his contribution to Connacher's growth and development during the past five years, Mr. Peter D. Sametz was appointed President and will continue as Chief Operating Officer.
We are fortunate in having a committed, stable management group guiding the affairs of the company and this was the first step in ensuring proper succession is achievable while growing the company for its shareholders.
FORWARD-LOOKING INFORMATION
This press release contains forward looking information including but not limited to the anticipated timing for completion of ramp-up at Algar and determination of commerciality in respect thereof, expectations of future production growth at Pod One and Algar during 2010 and 2011, plans for continued optimization of Pod One, development of additional oil sands resources (including the expansion of bitumen productive capacity from 20,000 bbl/d to 44,000 bbl/d and the anticipated timing of required regulatory approvals associated therewith), expected timing for completion of the cogeneration facility at Algar and subsequent completion of an electrical substation which is anticipated to improve the stability of power at Pod One and Algar, estimates of reserves and resources and future net revenue associated therewith, anticipated improvements in operating and financial results in 2010 and 2011 as a result of increased production, low natural gas prices, improved operating efficiencies, anticipated refinery margins, stabilized crude oil prices and narrow heavy oil differentials, anticipated reductions in SORs and operating costs as a result of the installation of additional ESPs and the anticipated timing of installation of these additional ESPs in Pod One wells to improve productivity. Additional forward looking information including forecast 2010 financial outlook and a reduction of the anticipated full year estimates for bitumen production is contained in the Management's Discussion and Analysis ("MD&A") attached to this press release. See "Forward Looking Information" in the MD&A.
Forward looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions. Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: the risks associated with the oil and gas industry (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; timing difficulties or delays and additional costs relating to the start-up of Algar and the cogeneration facility; the uncertainty of reserve and resource estimates, the uncertainty of geological interpretations, the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), the risk of commodity price and foreign exchange rate fluctuations, risks associated with the impact of general economic conditions, risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the operation and continued expansion of the Great Divide oil sands project. Additional risks and uncertainties affecting Connacher and its business and affairs are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009, which is available at www.sedar.com. Readers are cautioned that refinery margins and cash flow are non-GAAP measures. These measures are discussed in detail and reconciled to net earnings in the MD&A attached hereto. Although Connacher believes that the expectations in such forward looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward looking information included in this press release is expressly qualified in its entirety by this cautionary statement. The forward looking information included herein is made as of the date of this press release and Connacher assumes no obligation to update or revise any forward looking information to reflect new events or circumstances, except as required by law.
This press release includes information pertaining to the reserves, resources and the value of future net revenue of the Corporation as at June 30, 2010 as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in their report dated July 7, 2010 (the "GLJ Report"). Statements relating to reserves and resources are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. The GLJ Report is based on a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of bitumen, crude oil, natural gas liquids and natural gas, operating costs, well abandonment and salvage values, royalties and other government levies that may be imposed during the producing life of the reserves. Moreover, there is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variances could be material. The reserves and resources estimates of Connacher's properties described herein are estimates only. The actual reserves and resources on Connacher's properties may be greater or less than those calculated. The present value of estimated future net revenues referred to herein should not be construed as the current market value of estimated bitumen, crude oil, natural gas and natural gas liquids reserves attributable to Connacher's properties.
Contingent resources disclosed herein were assigned in regions with lower core-hole drilling density than the reserve regions and are outside Connacher's current areas of application for development. These resource estimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work. Contingent resources entail additional commercial risk than reserves. Adjustments for commercial risks were not incorporated in the estimates of contingent resources set forth herein. A range of Contingent Resource estimates (Low, Best and High) were prepared to reflect a range of technical uncertainty. Low Estimate Contingent Resources were assigned to mapped regions of oil-in-place with at least 12 m of continuous bitumen pay along with a conservative estimate of recovery factor. Best Estimate Contingent Resources were assigned to mapped regions of oil-in-place of identified pods outside areas of application for development with at least 10 m of continuous bitumen pay along with a best estimate of recovery factor. High Estimate Contingent Resources were assigned to mapped regions of oil-in-place of identified pods outside areas of application for development with at least 9 m of continuous bitumen pay along with a more optimistic estimate of recovery factor. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.
Prospective resources disclosed herein were attributable to undiscovered pods in unexplored regions, utilizing average parameters from the pods discovered to date and the statistical success within the explored regions of the leases. Prospective Resources entail additional commercial exploration risks than reserves and Contingent Resources. A range of Prospective Resources estimates were prepared to reflect a range of technical uncertainty. Best and High estimates of Prospective Resources were assigned using net pay thresholds of 10 m and 9 m, respectively. No Low Estimate Prospective Resources were assigned, given the risk of not encountering an undiscovered pod of sufficient size to be considered commercial. Adjustments for commercial risks were not incorporated in the estimates of Prospective Resources set forth herein. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources.
MANAGEMENT'S DISCUSSION AND ANALYSIS
This Management's Discussion and Analysis ("MD&A") is dated as of August 11, 2010 and should be read in conjunction with Connacher's interim consolidated financial statements for the three months ended June 30, 2010 ("Q2 2010") and 2009 ("Q2 2009") and six months ended June 30, 2010 ("YTD 2010") and 2009 ("YTD 2009") and the MD&A and the audited consolidated financial statements for the years ended December 31, 2009 and 2008. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods. Additional information relating to Connacher, including Connacher's Annual Information Form ("AIF"), can be found on SEDAR at www.sedar.com.
NON-GAAP MEASUREMENTS
The MD&A contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, netback, bitumen netback, conventional netback, refinery margins or netback, corporate netback and adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"). These terms are not defined by GAAP and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with GAAP as an indicator of Connacher's performance. Management believes that in addition to net earnings, cash flow, netbacks and adjusted EBITDA are useful financial measurements which assist in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow, netbacks, margins and adjusted EBITDA may not be comparable to that reported by other companies. All references to cash flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital, pension funding and asset retirement expenditures. The company calculates cash flow per share by dividing cash flow by the weighted average number of common shares outstanding. Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from revenues. Downstream margins or netbacks are calculated by deducting crude oil and operating costs from refining sales revenues. Adjusted EBITDA is calculated as net earnings before finance charges, taxes, depreciation, amortization and accretion, stock based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest/other income, equity earnings/losses and dilution gains/losses. Cash flow is reconciled to cash flow from operating activities and netbacks and adjusted EBITDA are reconciled to net earnings herein. Additionally, future anticipated 2010 netbacks and 2010 adjusted EBITDA are reconciled to actual results in the MD&A on a quarterly basis.
FORWARD-LOOKING INFORMATION
This report, including the Letter to Shareholders and the updated 2010 financial outlook contained in the MD&A, contains forward-looking information including but not limited to estimates of reserves and resources and future net revenue associated therewith, anticipated future operating and financial results, forecast netbacks and margins, forecast realized gain (loss) on risk management contracts, future corporate general and administration expenses, forecast adjusted EBITDA, future profitability, expectations of future production in 2010, the anticipated timing of achieving commerciality at Algar, anticipated sales volumes, further anticipated reductions in operating costs as a result of continued operational optimization at Great Divide Pod One and Algar, development of additional oil sands resources (including the expansion of Algar from 10,000 bbl/d to 34,000 bbl/d of bitumen capacity and the anticipated timing of required regulatory approvals associated therewith), expected timing for completion of the cogeneration facility at Algar and subsequent completion of an electrical substation which is anticipated to improve the stability of power at Pod One and Algar, anticipated capital expenditures, anticipated sources of funding for capital expenditures and current financial obligations, future development and exploration activities, future heavy oil differentials, expectations regarding the fulfillment of fixed price sales of asphalt in 2010 and anticipated improvements in refining netbacks during the third quarter of 2010, anticipated improvements in steam distribution and anticipated reductions in SORs as a result, potential future steam generation levels at Pod One and Algar and associated production levels related thereto, anticipated use of the Revolving Credit Facility, utilization of alternative financial derivative strategies to protect the company's cash flow and the anticipated impact of the conversion to International Financing Reporting Standards ("IFRS") on the company's consolidated financial statements. Forward-looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities, future economic conditions and the plans and expected impacts of adopting IFRS. Forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to operational risks in development, exploration, production, construction and start-up activities; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; the risk of commodity price and foreign exchange rate fluctuations; risks associated with the impact of general economic conditions; and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide oil sands project. In addition, the recent financial crisis has resulted in economic volatility and illiquidity in credit and capital markets which increases the risk that actual results will vary from forward-looking expectations in this report and these variations may be material. The 2010 financial outlook contained in the MD&A is based on certain assumptions regarding revenue (including production levels, refinery throughput, commodity prices, heavy oil pricing differentials, quality of bitumen produced, foreign exchange rates and transportation costs), operating and other costs, royalties, general and administrative costs and risk management contracts which are detailed in the notes to the tables contained in the MD&A. Actual netbacks and adjusted EBITDA realized by Connacher in 2010 could differ materially from the estimates contained in the 2010 financial outlook. Material risks and uncertainties that may impact achievement of the 2010 netbacks and adjusted EBITDA are described in the MD&A. These and other risks and uncertainties are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009, which is available at www.sedar.com.
Although Connacher believes that the expectations in such forward-looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward-looking information included in this report is expressly qualified in its entirety by this cautionary statement, The forward-looking information included in this report is made as of August 11, 2010 and Connacher assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.
Throughout the MD&A, per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation.
PRICING
General economic conditions and international and local supplies, together with many other uncontrollable variables, influence the price for crude oil (which is typically priced by reference to West Texas Intermediate or "WTI", benchmark prices). Weather, domestic supplies, restricted continental markets, inventory levels and other variables influence the market price for natural gas.
Our revenues, cash flow and earnings are significantly influenced by the volatility of crude oil and natural gas prices. The following tables show the benchmark prices of these commodities.
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Average prices
for the period
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Three months ended June 30 2010 2009 Change %
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West Texas Intermediate (WTI)
crude oil US$/barrel at Cushing $77.88 $59.69 $18.19 30
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Natural Gas (Alberta spot)
Cdn$/Mcf at AECO $3.90 $3.46 $0.44 13
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Average prices
for the period
-------------------------------------------------------------------------
Six months ended June 30 2010 2009 Change %
-------------------------------------------------------------------------
West Texas Intermediate (WTI)
crude oil US$/barrel at Cushing $78.35 $51.57 $26.78 52
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Natural Gas (Alberta spot)
Cdn$/Mcf at AECO $4.41 $4.17 $0.24 6
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Upstream
Connacher's crude oil and bitumen production slate is heavier gravity than the referenced WTI. Consequently, the market price realized by the company is lower than the WTI reference price. This difference is commonly referred to as the "heavy oil differential".
Before risk management contract gains and losses and after deducting applicable diluent and transportation costs, Connacher realized the following commodity selling prices.
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Upstream average realized prices Three months ended June 30
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2010 2009 Change %
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Bitumen - $/bbl $43.13 $40.95 $2.18 5
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Crude oil - $/bbl $61.90 $54.87 $7.03 13
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Natural gas - $/Mcf $3.78 $3.35 $0.43 13
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Upstream average realized prices Six months ended June 30
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2010 2009 Change %
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Bitumen - $/bbl $47.77 $31.84 $15.93 50
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Crude oil - $/bbl $66.54 $47.07 $19.47 41
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Natural gas - $/Mcf $4.33 $4.13 $0.20 5
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Diluted bitumen ("dilbit"), crude oil and natural gas are generally sold on month-to-month sales contracts negotiated with major Canadian or U.S. marketers, refiners, regional upgraders or other end users, at either spot reference prices or at prices based on WTI reference prices for crude oil and AECO reference prices for natural gas. In this regard, Connacher has entered into various contracts for the supply of dilbit to a variety of heavy oil purchasers in central and northern Alberta. In order to secure preferred diluent supplies, Connacher has also entered into several short-term diluent purchase contracts. As a means of managing the risk of commodity price volatility, Connacher enters into risk management commodity sales contracts from time to time.
Connacher has fulfilled a variety of short-term supply contracts for the sale of dilbit to a variety of purchasers in central and northern Alberta. Our upstream results in the three and six months period ended June 30, 2010 were also influenced by the following WTI crude oil price hedging sales contracts:
- Calendar year 2010 - 2,500 bbl/d at WTI US$78.00/bbl;
- February 1, 2010 - April 30, 2010 - 2,500 bbl/d at WTI US$79.02/bbl;
- May 1, 2010 - December 31, 2010 - 2,500 bbl/d at a minimum of WTI
US$75.00/bbl and a maximum of WTI US$95.00/bbl;
- January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$86.10/bbl;
- January 1, 2011 - March 31, 2011 - 1,000 bbl/d at WTI US$88.10/bbl;
and
- January 1, 2011 - March 31, 2011 - 2,000 bbl/d at a minimum of WTI
US$80.00/bbl and a maximum of WTI US$100.25/bbl.
Subsequent to June 30, 2010, the company entered into the following WTI crude oil price hedging sales contract:
- April 1, 2011 - June 30, 2011 - 2,000 bbl/d at WTI US$85.25/bbl.
The following table shows the realized and unrealized gains and losses recorded for these contracts.
-------------------------------------------------------------------------
Three months ended Six months ended
(Canadian dollar in thousands) June 30 June 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized gain (loss) $10,436 $(8,243) $9,658 $(16,510)
-------------------------------------------------------------------------
Realized gain (loss) (325) (6,161) (497) (5,756)
-------------------------------------------------------------------------
Gain (loss) on risk management
contracts $10,111 $(14,404) $9,161 $(22,266)
-------------------------------------------------------------------------
Downstream
Higher refined petroleum product prices in Q2 2010 and YTD 2010 were consistent with higher average WTI prices. Selling prices of refined petroleum products are also influenced by general economic conditions and local and international supply and demand factors. Realized selling prices for MRCI's refined products are noted below.
-------------------------------------------------------------------------
Downstream average realized prices Three months ended June 30
-------------------------------------------------------------------------
US$/bbl 2010 2009 Change %
-------------------------------------------------------------------------
Gasoline $88.41 $70.28 $18.13 26
-------------------------------------------------------------------------
Diesel $94.32 $69.71 $24.61 35
-------------------------------------------------------------------------
Asphalt $90.22 $71.95 $18.27 25
-------------------------------------------------------------------------
Jet fuel $96.28 $76.48 $19.80 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Downstream average realized prices Six months ended June 30
-------------------------------------------------------------------------
US$/bbl 2010 2009 Change %
-------------------------------------------------------------------------
Gasoline $86.59 $59.94 $26.65 44
-------------------------------------------------------------------------
Diesel $91.34 $63.91 $27.43 43
-------------------------------------------------------------------------
Asphalt $71.79 $56.72 $15.07 27
-------------------------------------------------------------------------
Jet fuel $95.32 $75.27 $20.05 27
-------------------------------------------------------------------------
Sales of refined petroleum products are generally made on monthly sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel and diesel and with construction contractors and road builders for asphalt. Occasionally, sales contracts are for periods in excess of one month. Higher realized refined product selling prices in Q2 2010 and YTD 2010 were attributed to the influence of higher WTI pricing, refined product pricing in our market area and the benefit of lucrative asphalt sales arrangement. Currently, MRCI has agreements to sell approximately 400,000 additional barrels of asphalt at prices approximating US$100/bbl.
The following risk management sales contract to hedge MRCI's gasoline revenue was outstanding as at June 30, 2010.
April 1, 2010 - September 30, 2010 - 2,000 bbl/d at the calendar month average WTI price in US$/bbl plus US$9.00/bbl.
The following table shows the realized and unrealized gains and losses recorded for this contract.
-------------------------------------------------------------------------
Three months ended Six months ended
(Canadian dollar in thousands) June 30 June 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized gain (loss) $70 $- $91 $-
-------------------------------------------------------------------------
Realized gain (loss) (767) - (767) -
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $(62) $- $(676) $-
-------------------------------------------------------------------------
FINANCIAL AND OPERATING REVIEW
UPSTREAM NETBACKS ($000)
-------------------------------------------------------------------------
Three months ended June 30, 2010
-------------------------------------------------------------------------
Oil sands Crude oil Natural gas Total
-------------------------------------------------------------------------
Gross revenues(1) $44,616 $5,132 $3,195 $52,943
-------------------------------------------------------------------------
Diluent purchased(2) (17,067) - - (17,067)
-------------------------------------------------------------------------
Transportation costs (3,170) (30) - (3,200)
-------------------------------------------------------------------------
Production revenue 24,379 5,102 3,195 32,676
-------------------------------------------------------------------------
Royalties (965) (1,317) 128 (2,154)
-------------------------------------------------------------------------
Operating costs (12,770) (928) (1,473) (15,171)
-------------------------------------------------------------------------
Netbacks(3) $10,644 $2,857 $1,850 $15,351
-------------------------------------------------------------------------
Netbacks as percent of
gross revenues 24% 56% 58% 29%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended June 30, 2009
-------------------------------------------------------------------------
Oil sands Crude oil Natural gas Total
-------------------------------------------------------------------------
Gross revenues(1) $40,571 $5,649 $3,697 $49,917
-------------------------------------------------------------------------
Diluent purchased(2) (14,669) - - (14,669)
-------------------------------------------------------------------------
Transportation costs (2,487) (88) - (2,575)
-------------------------------------------------------------------------
Production revenue 23,415 5,561 3,697 32,673
-------------------------------------------------------------------------
Royalties (89) (1,431) (111) (1,631)
-------------------------------------------------------------------------
Operating costs (8,459) (949) (2,580) (11,988)
-------------------------------------------------------------------------
Netbacks(3) $14,867 $3,181 $1,006 $19,054
-------------------------------------------------------------------------
Netbacks as percent of
gross revenues 37% 56% 27% 38%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2010
-------------------------------------------------------------------------
Oil sands Crude oil Natural gas Total
-------------------------------------------------------------------------
Gross revenues(1) $99,789 $11,131 $7,425 $118,345
-------------------------------------------------------------------------
Diluent purchased(2) (36,584) - - (36,584)
-------------------------------------------------------------------------
Transportation costs (6,379) (35) - (6,414)
-------------------------------------------------------------------------
Production revenue 56,826 11,096 7,425 75,347
-------------------------------------------------------------------------
Royalties (2,350) (2,886) 33 (5,203)
-------------------------------------------------------------------------
Operating costs (24,811) (2,041) (3,232) (30,084)
-------------------------------------------------------------------------
Netbacks(3) $29,665 $6,169 $4,226 $40,060
-------------------------------------------------------------------------
Netbacks as percent of
gross revenues 30% 55% 57% 34%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2009
-------------------------------------------------------------------------
Oil sands Crude oil Natural gas Total
-------------------------------------------------------------------------
Gross revenues(1) $69,242 $9,926 $9,337 $88,505
-------------------------------------------------------------------------
Diluent purchased(2) (28,036) - - (28,036)
-------------------------------------------------------------------------
Transportation costs (5,324) (158) - (5,482)
-------------------------------------------------------------------------
Production revenue 35,882 9,768 9,337 54,987
-------------------------------------------------------------------------
Royalties (219) (2,493) (1,499) (4,211)
-------------------------------------------------------------------------
Operating costs (19,790) (2,251) (5,085) (27,126)
-------------------------------------------------------------------------
Netbacks(3) $15,873 $5,024 $2,753 $23,650
-------------------------------------------------------------------------
Netbacks as percent of
gross revenues 23% 51% 30% 27%
-------------------------------------------------------------------------
(1) No bitumen sales have yet been recognized at Algar, as all costs and
incidental revenue are capitalized until such operations are
considered "commercial". Bitumen produced at Pod One is mixed with
purchased diluent and sold as "dilbit". Diluent is a light
hydrocarbon that improves the marketing and transportation quality of
bitumen. In the above tables, gross revenues represent sales of
dilbit, crude oil and natural gas. In the financial statements
Upstream Revenues represent sales of dilbit, crude oil and natural
gas, net of royalties and Upstream Operating Costs include the cost
of purchased diluent.
(2) Diluent volumes purchased and blended into dilbit sales have been
deducted in calculating production revenue and production volumes
sold. Diluent purchased includes purchases from our downstream
segment. Although they have been included in these upstream netback
calculations, these intercompany transactions have been eliminated in
our consolidated financial statements.
(3) Netbacks are calculated before adding/deducting risk management
contracts gains/losses. Netbacks on a per-unit basis are calculated
by dividing netbacks by production volumes. Netbacks do not have a
standardized meaning prescribed by GAAP and, therefore, may not be
comparable to similar measures used by other companies. This non-GAAP
measurement is widely used in the oil and gas industry as a
supplemental measure of the company's efficiency and its ability to
fund future growth through capital expenditures. Netbacks are
reconciled to net earnings below.
Upstream Sales and Production Volumes
-------------------------------------------------------------------------
Three months ended June 30 Six months ended June 30
-------------------------------------------------------------------------
% %
2010 2009 Change 2010 2009 Change
-------------------------------------------------------------------------
Dilbit sales
- bbl/d 8,294 8,517 (3) 8,770 8,524 3
-------------------------------------------------------------------------
Diluent purchased
- bbl/d (2,083) (2,233) (7) (2,198) (2,297) (4)
-------------------------------------------------------------------------
Bitumen produced
and sold - bbl/d 6,211 6,284 (1) 6,572 6,227 6
-------------------------------------------------------------------------
Crude oil produced
and sold - bbl/d 906 1,114 (19) 921 1,147 (20)
-------------------------------------------------------------------------
Natural gas produced
and sold - Mcf/d 9,278 12,144 (24) 9,469 12,484 (24)
-------------------------------------------------------------------------
Total - boe/d 8,663 9,421 (8) 9,071 9,455 (4)
-------------------------------------------------------------------------
Upstream Netbacks Per Unit of Production
-------------------------------------------------------------------------
Three months ended June 30, 2010
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $43.13 $61.90 $3.78 $41.44
-------------------------------------------------------------------------
Royalties (1.71) (15.98) 0.15 (2.73)
-------------------------------------------------------------------------
Operating costs (22.59) (11.26) (1.75) (19.25)
-------------------------------------------------------------------------
Netback $18.83 $34.66 $2.18 $19.46
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Three months ended June 30, 2009
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $40.95 $54.87 $3.35 $38.11
-------------------------------------------------------------------------
Royalties (0.16) (14.12) (0.10) (1.90)
-------------------------------------------------------------------------
Operating costs (14.79) (9.37) (2.33) (13.98)
-------------------------------------------------------------------------
Netback $26.00 $31.38 $0.92 $22.23
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2010
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $47.77 $66.54 $4.33 $45.89
-------------------------------------------------------------------------
Royalties (1.98) (17.31) 0.02 (3.17)
-------------------------------------------------------------------------
Operating costs (20.86) (12.24) (1.89) (18.32)
-------------------------------------------------------------------------
Netback $24.93 $36.99 $2.46 $24.40
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2009
-------------------------------------------------------------------------
Natural
Bitumen Crude oil gas Total
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $31.84 $47.07 $4.13 $32.13
-------------------------------------------------------------------------
Royalties (0.19) (12.01) (0.66) (2.46)
-------------------------------------------------------------------------
Operating costs (17.56) (10.84) (2.25) (15.85)
-------------------------------------------------------------------------
Netback $14.09 $24.22 $1.22 $13.82
-------------------------------------------------------------------------
Gross upstream production revenues of $52.9 million in Q2 2010 were 6 percent higher than gross production revenues in Q2 2009. Higher bitumen, crude oil and natural gas selling prices in Q2 2010 partially offset lower crude oil and natural gas production and sales volume in Q2 2010. WTI averaged US$77.88/bbl in Q2 2010, a 30 percent increase over the comparative period and natural gas selling prices increased by 13 percent to $3.90/Mcf.
YTD 2010 gross production revenues increased by 34 percent to $118.3 million, compared to $88.5 million in YTD 2009. This increase was primarily attributable to higher bitumen and crude oil pricing, which was slightly offset by lower crude oil and natural gas production and sales volumes in YTD 2010. Lower crude oil and natural gas production and sales volumes in YTD 2010 reflected the impact of reduced development capital spending in 2009 and 2010 because of low selling natural gas prices as well as the impact of production declines.
Our Q2 and YTD 2010 upstream results were also impacted by realized and unrealized risk management contract gains and losses. Details of these contracts and the gains and losses on risk management contracts are addressed in "Pricing-Upstream", above.
In Q2 2010, upstream diluent purchases of $17.1 million (Q2 2009 - $14.7 million) were required for our oil sands operations. YTD 2010 upstream diluent purchases were $36.6 million as compared to $28.0 million in YTD 2009. These purchases include $3.6 million and $7.6 million of diluent purchased at market prices directly from our subsidiary, MRCI, in Q2 2010 and YTD 2010, respectively (Q2 2009 and YTD 2009 - $3.0 million and $3.5 million, respectively). Although these intercompany costs were included in our netback calculations above to accurately present bitumen netbacks, for consolidated financial statement presentation purposes, these intercompany purchases were eliminated.
Bitumen produced at Pod One is mixed with purchased diluent and sold as "dilbit." Diluent is a light liquid hydrocarbon used in our oil sands treating processes and enables the efficient marketing and transportation of bitumen. Diluent purchased represented approximately 25 percent of the dilbit barrel sold in Q2 and YTD 2010, with bitumen the remaining 75 percent; in Q2 2009, these splits were 26 percent and 74 percent, respectively whereas in YTD 2009, these splits were 27 percent and 73 percent, respectively. The price of diluent closely tracks WTI crude oil prices. Consequently, diluent costs were higher in Q2 2010 relative to the comparative Q2 2009 periods.
Transportation costs represent costs to transport dilbit and crude oil to customers. Transportation costs were slightly higher in Q2 and YTD 2010 than Q2 2009 and YTD 2009 ($3.2 million in Q2 2010 compared to $2.6 million in Q2 2009 and $6.4 million in YTD 2010 compared to $5.5 million in YTD 2009). These costs were reported as an expense in our consolidated statement of operations but have been deducted in calculating average realized selling prices. The overall increase of 23 percent in Q2 2010 compared to Q2 2009 and 16 percent in YTD 2010 compared to YTD 2009 was due to higher trucking costs and an increase in dilbit sales travel distances to markets in 2010.
Royalties represent charges against production or revenue by governments and landowners. From quarter to quarter, royalties can change based on 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 Q2 2010 and YTD 2010 were $2.2 million and $5.2 million, respectively, as compared to $1.6 million and $4.2 million in Q2 2009 and YTD 2010, respectively. The increase in overall royalties was primarily due to higher oil prices. This was reflected in higher per unit royalty costs for bitumen ($1.71/bbl compared to $0.16/bbl in Q2 2009 and $1.98/bbl compared to $0.19/bbl in YTD 2009) and crude oil ($15.98/bbl compared to $14.12/bbl in Q2 2009 and $17.31/bbl compared to $12.01/bbl in YTD 2009). The reduction in the Q2 2010 and YTD 2010 per unit royalty cost for natural gas compared to Q2 2009 and YTD 2009 reflected Alberta gas cost allowance recoveries associated with lower natural gas prices.
Operating costs in Q2 2010 of $15.2 million were 27 percent higher than $12.0 million in Q2 2009. Similarly, operating costs in YTD 2010 of $30.1 million were 11 percent higher than $27.1 million in YTD 2009. Bitumen operating costs were $12.8 million ($22.59/bbl of bitumen) in Q2 2010 and $24.8 million ($20.86/bbl of bitumen) in YTD 2010, compared to $8.5 million ($14.79/bbl of bitumen) in Q2 2009 and $19.8 million ($17.56/bbl of bitumen) in YTD 2009, respectively. This represents an increase of 51 percent in Q2 2010 as compared to Q2 2009 and an increase of 25 percent in YTD 2010 as compared to YTD 2009.
The increase in bitumen operating costs was partly due to the decision to advance the scheduling of annual repairs and maintenance activities carried out at Pod One from Q3 2010 to Q2 2010. In 2009, these annual turnaround and inspection costs were performed in Q3. Power costs, evaporator waste disposal costs (associated with evaporator issues) and initial downhole pump replacement costs were higher in Q2 2010 and YTD 2010 than in the comparative 2009 periods. Personnel, power, chemicals, facility, workover and evaporator waste disposal costs (primarily fixed in nature) comprised $9.6 million, or 75 percent of oilsands operating costs in Q2 2010 (Q2 2009 - $5.5 million, or 65 percent) and $17.1 million, or 69 percent in YTD 2010 (YTD 2009 - $12.9 million, or 65 percent). Natural gas costs (primarily variable in nature) comprised $3.2 million, or 25 percent, of Q2 2010 oil sands operating costs (Q2 2009 - $3.0 million, or 35 percent) whereas natural gas costs comprised $7.7 million, or 31 percent of YTD 2010 oil sands operating costs (YTD 2009 - $6.9 million, or 35 percent). At our Pod One facility, in Q2 2010 we used 8,887 Mcf/d of natural gas at an average cost of $3.94/Mcf (Q2 2009 - 9.8 MMcf/d at $3.39/Mcf) and in YTD 2010 we used 9,453 Mcf/d of natural gas at an average cost of $4.50/Mcf (YTD 2009 - 9.2 MMcf/d at $4.11/Mcf). This equates to 1.44 Mcf of natural gas consumed to produce 1 bbl of bitumen in each of Q2 2010 and YTD 2010. The consumption of natural gas to produce 1 bbl of bitumen in 2009 was 1.53 Mcf in Q2 2009 and 1.48 Mcf for YTD 2009. The successful introduction of electric submersible pumps, both of the regular and high temperature variety, progressive cavity pumps and other technical innovations associated with SAGD has recently proven to be effective in lowering steam:oil ratios ("SORs"). SORs from Pod One wells on pumps averaged 2.9 in the first half of 2010. Our overall average SOR in the first half of 2010 was approximately 3.7. Overall SORs reflect the commencement of steaming of two new SAGD well pairs at Pod One in Q2 2010 with no consequent production anticipated until August 2010.
Conventional crude oil operating costs were slightly reduced on an absolute basis ($930,000 in Q2 2010 compared to $950,000 in Q2 2009 and $2.0 million in YTD 2010 compared to $2.3 million in YTD 2009) but were slightly higher on a per unit basis ($11.26 per bbl in Q2 2010 compared to $9.37 per bbl in Q2 2009 and $12.24 per bbl in YTD 2010 compared to $10.84 per bbl in YTD 2009), primarily due to lower production volumes in Q2 2010 and YTD 2010 (906 bbl/d in Q2 2010 compared to 1,114 bbl/d in Q2 2009 and 921 bbl/d in YTD 2010 compared to 1,147 bbl/d in YTD 2009). The majority of this crude oil production was from the Battrum area of south west Saskatchewan. Battrum is a late-stage water flood project, the operating costs of which are primarily fixed in nature.
Natural gas operating costs of $1.5 million ($1.75/Mcf) in Q2 2010 and $3.2 million ($1.89/Mcf) in YTD 2010 were lower than in Q2 2009 and YTD 2009 when they were $2.6 million ($2.33/Mcf) and $5.1 million ($2.25/Mcf), due to improved operating efficiencies, lower well workover costs and lower natural gas production in 2010.
On a per unit basis, total upstream operating costs of $19.25 per boe in Q2 2010 and $18.32 in YTD 2010 were higher compared to $13.98 per boe in Q2 2009 and $15.85 per boe in YTD 2009, primarily reflecting the repairs and maintenance activities at our Pod One oil sands facility, noted above.
Netbacks are a widely used industry measure of a company's efficiency and its ability to internally fund its growth. Netbacks were $15.4 million in Q2 2010 ($19.46 per boe) compared to $19.1 million ($22.23 per boe) in Q2 2009, a 20 percent decrease on an absolute basis and 12 percent decrease on per unit basis. Although WTI prices increased by 30 percent in Q2 2010 compared to Q2 2009, the netback in Q2 2010 decreased compared to Q2 2009, primarily because of higher operating costs as a result of repairs and maintenance activities at Pod One.
Netbacks were $40.1 million in YTD 2010 ($24.40 per boe) compared to $23.7 million ($13.82 per boe) in Q2 2009. This reflects an increase in YTD 2010 compared to YTD 2009 of 70 percent on an absolute basis and 77 percent on a per unit basis. This was primarily because our realized bitumen price was 50 percent higher and our realized crude oil selling price was 41 percent higher. The higher realized bitumen and crude oil prices were in line with the increase in WTI crude oil prices.
RECONCILIATION OF UPSTREAM NETBACKS TO NET EARNINGS
-------------------------------------------------------------------------
Three months ended June 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netbacks,
as above $15,351 $19.46 $19,054 $22.23
-------------------------------------------------------------------------
Interest and other income 49 0.06 246 0.29
-------------------------------------------------------------------------
Downstream margin - net 10,038 12.73 3,483 4.06
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts 10,049 12.75 (14,404) (16.80)
-------------------------------------------------------------------------
General and administrative (4,278) (5.43) (3,224) (3.77)
-------------------------------------------------------------------------
Stock-based compensation (1,137) (1.44) (551) (0.64)
-------------------------------------------------------------------------
Finance charges (13,222) (16.77) (8,877) (10.35)
-------------------------------------------------------------------------
Foreign exchange gain
(loss) (32,545) (41.28) 65,411 76.30
-------------------------------------------------------------------------
Depletion, depreciation
and accretion (18,026) (22.87) (16,538) (19.29)
-------------------------------------------------------------------------
Income tax recovery
(provision) 4,837 6.14 (5,490) (6.40)
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings (loss) 31 0.04 856 1.00
-------------------------------------------------------------------------
Dilution loss (4,273) (5.42) - -
-------------------------------------------------------------------------
Net earnings (loss) $(33,126) $(42.03) $39,966 $46.63
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30
-------------------------------------------------------------------------
2010 2009
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netbacks,
as above $40,060 $24.40 $23,650 $13.82
-------------------------------------------------------------------------
Interest and other income 120 0.07 1,174 0.69
-------------------------------------------------------------------------
Downstream margin - net 5,338 3.25 5,915 3.46
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts 8,485 5.17 (22,266) (13.01)
-------------------------------------------------------------------------
General and administrative (9,830) (5.99) (7,698) (4.50)
-------------------------------------------------------------------------
Stock-based compensation (3,028) (1.84) (1,821) (1.06)
-------------------------------------------------------------------------
Finance charges (25,951) (15.81) (18,037) (10.54)
-------------------------------------------------------------------------
Foreign exchange gain
(loss) (8,602) (5.24) 37,545 21.94
-------------------------------------------------------------------------
Depletion, depreciation
and accretion (36,643) (22.32) (32,987) (19.28)
-------------------------------------------------------------------------
Income tax recovery
(provision) 7,361 4.48 6,508 3.80
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings (loss) (617) (0.38) 1,139 0.67
-------------------------------------------------------------------------
Dilution loss (4,273) (2.60) - -
-------------------------------------------------------------------------
Net earnings (loss) $(27,580) $(16.81) $(6,878) $(4.01)
-------------------------------------------------------------------------
DOWNSTREAM REVENUES AND MARGINS
Connacher's 9,500 bbl/d heavy oil refinery, located in Great Falls, Montana (the "Refinery"), is a strategic fit with our oil sands development. It is the closest U.S. refinery to Alberta's oil sands and processes Canadian heavy crude oil (similar to Great Divide dilbit) into a range of higher value refined petroleum products, including regular and premium gasoline, jet fuel, diesel and asphalt. Accordingly, the Refinery provides a notional hedge for our bitumen revenues by recovering a portion of the heavy oil differential under normal operating conditions.
The Refinery is a complex operation and includes reforming, isomerization and alkylation processes for formulation of gasoline blends, hydro-treating for sulphur removal and fluid catalytic cracking for conversion of heavy gas oils to gasoline and distillate products. It also is a major supplier of paving grade asphalt, polymer modified grades and asphalt emulsions for road construction. The Refinery delivers products in Montana and neighboring regions by truck and rail transport.
The Refinery is subject to a number of seasonal factors which cause product sales revenues to vary throughout the year. The Refinery's primary asphalt market is paving for road construction, which is in greater demand during the summer. Consequently, prices and volumes for our asphalt tend to be higher in the summer and lower in the colder seasons. During the winter, most of the Refinery's asphalt production is stored in tankage for sale in the subsequent summer. Seasonal factors also affect the production and sale of gasoline, which has a higher demand in summer months and the production and sale of diesel, which has a higher winter demand. As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.
The Refinery operates in a "niche" market that incorporates Great Falls and surrounding area, Western Montana, Northern Idaho, Eastern Washington and Southern Alberta. While the "niche" market provides some insulation from challenging North American refining market MRCI's margins significantly improved in Q2 2010 because of higher product prices and increased product demand in our market area.
Downstream revenues of $83.9 million in Q2 2010 were 22 percent higher than $69.1 million of refined products sold in Q2 2009. In YTD 2010, downstream revenues were $145.6 million compared to $102.2 million in YTD 2009, an increase of 42 percent. The increase was attributable to increased sales volumes and higher average refined product selling prices in 2010 as compared to 2009. Increased refining volumes sold in 2010 were primarily due to the improved stability of refining operations subsequent to the completion of the ultra low sulphur diesel ("ULSD") project, which curtailed production and sales in the comparative 2009 periods.
Downstream revenues and refining margins (in the table below) include the benefit of diluent sales revenue of $3.6 million in Q2 2010 and $7.6 million for the YTD 2010 ($3.0 million - Q2 2009 and $3.5 million - YTD 2009) sold to our oil sands operation, which were transacted at prevailing fair market prices. These transactions were eliminated on consolidation for financial statement presentation purposes.
General economic conditions affect refined product demand and pricing. We anticipate they will continue to influence our downstream financial results in the future. To mitigate some of the risk of reduced gasoline selling prices and margins, the company entered into a risk management sales contract to sell 2,000 bbl/d of gasoline at the calendar month average WTI price in US$/bbl plus US$9.00/bbl for the period of April 1, 2010 to September 30, 2010. Details of realized and unrealized gains and losses on this contract are noted in Pricing - Downstream, above.
The quarterly operating results of our Refinery are summarized below.
Refinery Throughput
-------------------------------------------------------------------------
June 30, Sept 30, Dec 31, Dec 31, June 30,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Crude charged - bbl/d(1) 9,145 7,076 8,188 9,347 9,373
-------------------------------------------------------------------------
Refinery production
- bbl/d(2) 10,438 8,131 8,674 10,814 10,546
-------------------------------------------------------------------------
Sales of produced refined
products - bbl/d 9,222 10,596 8,841 8,267 9,842
-------------------------------------------------------------------------
Sales of refined products
(includes purchased
products) - bbl/d(3) 9,451 11,697 9,646 8,439 10,076
-------------------------------------------------------------------------
Refinery utilization(4) 96% 75% 86% 98% 99%
-------------------------------------------------------------------------
(1) Crude charged represents the barrels per day of crude oil processed
at the Refinery.
(2) Refinery production represents the barrels per day of refined
products yielded from processing crude and other refinery feedstock.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
Refinery.
Feedstocks
-------------------------------------------------------------------------
June 30, Sept 30, Dec 31, Mar 31, June 30,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Sour crude oil 91% 91% 97% 87% 90%
-------------------------------------------------------------------------
Other feedstocks
& blends 9% 9% 3% 13% 10%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
Revenues and Margins ($000)
-------------------------------------------------------------------------
June 30, Sept 30, Dec 31, Mar 31, June 30,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Refining sales
revenue(1) $69,094 $92,714 $63,440 $61,589 $83,988
-------------------------------------------------------------------------
Refining - crude oil
and operating costs 65,611 85,015 67,491 66,289 73,950
-------------------------------------------------------------------------
Refining margin $3,483 $7,699 $(4,051) $(4,700) $10,038
-------------------------------------------------------------------------
Refining margin (%) 5% 8% (7%) (8%) 12%
-------------------------------------------------------------------------
(1) Includes intersegment sales which have been eliminated from
consolidated statements of operations and retained earnings.
Revenues and Margins Per Barrel of Refined Product Sold
-------------------------------------------------------------------------
June 30, Sept 30, Dec 31, Mar 31, June 30,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Refining sales
revenue $80.34 $86.16 $71.73 $81.09 $91.58
-------------------------------------------------------------------------
Refining - crude oil
and operating costs 76.29 79.00 76.36 87.28 80.65
-------------------------------------------------------------------------
Refining margin $4.05 $7.16 $(4.63) $(6.19) $10.93
-------------------------------------------------------------------------
Sales of Refined Products (Volume %)
-------------------------------------------------------------------------
June 30, Sept 30, Dec 31, Mar 31, June 30,
2009 2009 2009 2010 2010
-------------------------------------------------------------------------
Gasoline 48% 36% 39% 51% 45%
-------------------------------------------------------------------------
Diesel fuels 11% 10% 10% 20% 13%
-------------------------------------------------------------------------
Jet fuels 6% 6% 4% 8% 7%
-------------------------------------------------------------------------
Asphalt 31% 46% 45% 17% 32%
-------------------------------------------------------------------------
Other 4% 2% 2% 4% 3%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
INTEREST AND OTHER INCOME
In Q2 2010 and YTD 2010, the company earned interest and other income of $49,000 and $120,000 (Q2 2009 - $246,000 and YTD 2009 - $1.2 million), primarily from investing surplus funds in secure short-term investments. A portion of the interest earned was recognized as income and a portion (in respect of cash balances on hand from pre-funding oil sands projects under development) was credited to capitalized costs. Interest and other income in 2009 included a gain of $475,000 on the repurchase of Second Senior Lien Notes. No similar repurchases were made in 2010.
GENERAL AND ADMINISTRATIVE EXPENSES
In Q2 2010, general and administrative ("G&A") expenses were $4.3 million, compared to $3.2 million in Q2 2009, an increase of 34 percent and $9.8 million in YTD 2010 compared to $7.7 million in YTD 2009, an increase of 27 percent. The increase primarily reflected additional staffing to support the operation of Pod One and Algar. G&A of $1.2 million in Q2 2010 and $3.3 million in YTD 2010 was also capitalized (Q2 2009 - $1.1 million and YTD 2009 - $2.6 million).
FINANCE CHARGES
Finance charges include interest expense relating to the Convertible Debentures, standby fees associated with the company's Revolving Credit Facility, fees on letters of credit issued and a portion of the First and Second Lien Senior Notes interest not attributable to major development/capital projects. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and a portion of the First and Second Lien Senior Notes. The company capitalizes interest on a portion of its long-term debt raised to finance oil sands projects.
In Q2 2010, finance charges expensed were $13.2 million, which was $4.3 million higher than in Q2 2009 and in YTD 2010, finance charges expensed were $25.9 million, which was $7.9 million higher than in YTD 2009. The higher finance charges were primarily a result of higher debt levels since issuing the First Lien Senior Notes in mid-June 2009. Connacher capitalized finance charges of $12.7 million in Q2 2010 (Q2 2009 - $12.7 million) and $25.4 million in YTD 2010 (YTD 2009 - $26.0 million) in respect of oil sands activities.
STOCK BASED COMPENSATION
The company recorded non-cash stock-based compensation charges in the respective periods as follows.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Charged to expense $1,137 $551 $3,028 $1,821
-------------------------------------------------------------------------
Capitalized to property
and equipment 534 114 1,186 507
-------------------------------------------------------------------------
Total $1,671 $665 $4,214 $2,328
-------------------------------------------------------------------------
The increase from the prior period is due to a higher fair market value for options granted in 2010.
FOREIGN EXCHANGE GAINS AND LOSSES
In Q2 and YTD 2010, the value of the Canadian dollar weakened relative to the U.S. dollar. This had a significant impact on Connacher upon translating its U.S. dollar denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes.
Connacher had unrealized foreign exchange translation losses of $32.9 million in Q2 2010 (Q2 2009 - gain of $61.5 million) and $9.9 million in YTD 2010 (YTD 2009 - gain of $33.6 million). Connacher also realized foreign exchange gains of $365,000 in Q2 2010 (Q2 2009 - $3.9 million) and $1.3 million in YTD 2010 (YTD 2009 - $3.9 million) upon the settlement of U.S. dollar denominated transactions.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
Depletion expense is calculated using the unit-of-production method based on total estimated proved reserves. Downstream refining properties and other assets are depreciated over their estimated useful lives. DD&A in Q2 2010 and YTD 2010 was $18.0 million and $36.6 million, respectively (Q2 2009 - $16.5 million and YTD 2009 - $33.0 million). Depletion of $14.4 million in Q2 2010 (Q2 2009 - $13.9 million) equated to $18.26 per boe of production in Q2 2010 ($16.21 per boe in Q2 2009). In YTD 2010, depletion was $29.3 million ($17.80 per boe) compared to $27.8 million in YTD 2009 ($16.28 per boe). The slight increase in depletion rate per boe of production was due to the increase in current and estimated future capital expenditures related to our increased proved reserves.
Future development costs of $1.6 billion (Q2 2009 - $1.3 billion) were included in the depletion calculation while capital costs of $682 million (Q2 2009 - $369 million) related to oil sands projects currently in the pre-production stage and undeveloped land costs of $12.3 million (Q2 2009 - $12.2 million) were excluded from the depletion calculation.
Included in DD&A for Q2 2010 was MRCI refinery depreciation of $2.3 million (Q2 2009 - $1.8 million), depreciation of furniture, equipment and leaseholds of $536,000 (Q2 2009 - $255,000) and an accretion charge of $748,000 (Q2 2009 - $491,000) in respect of the company's estimated asset retirement obligations ("ARO"). In YTD 2010, DD&A included, MRCI refinery deprecation of $4.8 million (YTD 2009 - $3.7 million), depreciation of furniture, equipment and leaseholds of $1.1 million (YTD 2009 - $486,000) and an accretion charge of $1.4 million in respect of ARO (YTD 2009 - $981,000). These ARO charges will continue in future years in order to accrete the currently booked discounted liability of $37.8 million to the estimated total undiscounted liability of $86.7 million over the remaining economic life of the company's oil sands, crude oil and natural gas properties.
INCOME TAXES
The total income tax recovery of $4.8 million in Q2 2010 and $7.4 million in YTD 2010 (Q2 2009 - income tax provision of $5.4 million and YTD 2009 - income tax recovery of $6.5 million) included a current income tax provision of $150,000 in Q2 2010 and $356,000 in YTD 2010 (Q2 2009 - $121,000 and YTD 2009 - $293,000), principally related to Canadian taxes. The future income tax recovery of $5.0 million in Q2 2010 and $7.7 million in YTD 2010 (Q2 2009 - future income tax provision of $5.4 million and YTD 2009 - future income tax recovery of $6.8 million) reflected the change in tax pools during the periods.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")
Connacher accounts for its equity investment in Petrolifera under the equity method of accounting. Connacher's share of Petrolifera's earnings in Q2 2010 was $31,000 (Q2 2009 - $856,000 earnings) and in YTD 2010 was a $617,000 loss (YTD 2009 - $1.1 million earnings).
In April 2010, Petrolifera closed a public offering of 23,678,500 common shares at a price of $0.85 per common share for gross proceeds of $20.1 million (the "Offering"). The company did not subscribe for shares in the Offering and accordingly, the company's equity interest in Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest resulted in a dilution loss of $4.2 million in the three months ended June 30, 2010. Given Connacher's representation on Petrolifera's Board of Directors and other factors, Connacher continues to equity account for this investment.
NET EARNINGS (LOSS)
In Q2 2010, the company reported net loss of $33.1 million ($0.08 per basic and diluted shares outstanding) compared to earnings of $40.0 million ($0.15 per basic and $0.14 per diluted shares outstanding) in Q2 2009. For the YTD 2010, the company reported a net loss of $27.6 million ($0.06 per basic and diluted shares outstanding) compared to net loss of $6.9 million ($0.03 per basic and diluted shares outstanding) in YTD 2009. The primary reasons for these period to period variations have been noted above.
SHARES OUTSTANDING
In Q2 2010, the basic and diluted weighted average number of common shares outstanding was 429.0 million (Q2 2009 - 266.4 million basic and 287.0 million diluted). The increase from the prior year was due to the equity issuances late in 2009.
As at August 11, 2010, the company had the following securities issued and outstanding.
- 429,106,992 common shares;
- 28,737,015 share purchase options; and
- 380,598 share units under the share award plan.
Additionally, the company's $100 million of outstanding Convertible Debentures are convertible into 20,002,800 common shares of the company.
PROPERTY AND EQUIPMENT EXPENDITURES
A breakdown of the expenditures is as follows.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Crude oil, natural gas and
oil sands expenditures $58,057 $36,724 $175,190 $97,723
-------------------------------------------------------------------------
Refinery expenditures 1,259 3,512 2,398 6,768
-------------------------------------------------------------------------
$59,316 $40,236 $177,588 $104,491
-------------------------------------------------------------------------
In Q2 2010, expenditures of $16 million were incurred on the Algar project; $8 million was incurred at Pod One for facility enhancement and pump installation expenditures; $6 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide expansion project; $20 million was capitalized interest, G&A costs and asset retirement costs and $8 million was capitalized for Algar pre-production expenditures.
For the YTD 2010, expenditures of $64 million were incurred on the Algar project, $18 million was incurred on Pod One to finish drilling and completing two additional SAGD well pairs and for other facility enhancement and pump installation expenditures; $21 million was incurred in drilling 68 exploratory core holes at Great Divide, 13 (6.5 net) exploratory core holes at Halfway Creek and for seismic expenditures related to the 2010 winter exploration program; $17 million of capital expenditures were incurred for co-generation, pipeline facilities and the Great Divide Expansion project; $35 million was for capitalized interest, G&A and asset retirement costs; and $8 million of Algar pre-production costs was capitalized. Additionally, $12 million was incurred for conventional drilling (one oil well, four natural gas wells and four abandoned wells), land acquisitions, seismic, well workovers, facilities and corporate and administrative assets. Included in the YTD 2010 expenditures were $10 million of non-cash capitalized items.
In Q2 2009, oil sands capital expenditures totaled $36 million, $12 million of which was incurred on our Algar oil sands project, while this project was "on-hold", for the continued construction of long-lead order equipment items and for associated project-delay costs; additionally, $6 million of capital costs were incurred at Pod One for the completion of the two additional SAGD well pairs, for costs to install four electric submersible pumps and for other facility enhancement expenditures; $5 million was incurred on co-generation and transfer pipeline facilities; and $13 million of interest and G&A costs were capitalized.
For YTD 2009, $33 million was incurred on the Algar project for engineering, civil work, facilities, equipment and project delay costs; $18 million was incurred at Pod One to drill and complete the two additional SAGD well pairs and to install pumps and for other facility enhancement expenditures; and $47 million was incurred on drilling 23 exploratory core holes, two conventional wells, for co-generation and pipeline facilities and for capitalized interest and G&A costs. Included in the YTD 2009 expenditures were $2 million of non-cash capitalized items.
The majority of the 2010 refinery capital expenditures were incurred for various small capital projects. The 2009 refinery capital expenditures were incurred for the ultra low sulphur diesel/gasoline project.
RECENT FINANCINGS
Common Share Issuance
On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share, for gross proceeds of $173 million. The proceeds were raised for working capital to fund the company's capital expenditures, including Algar and for general corporate purposes.
At June 30, 2010, the proceeds had been fully utilized to fund capital expenditures, including oil sands capital costs.
First Lien Senior Secured Notes
On June 16, 2009, the company issued US$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for gross proceeds of $212 million in equivalent Canadian funds. These financing proceeds were raised for working capital and general corporate purposes, including funding a portion of the remaining expenditures associated with the construction and drilling costs of Algar.
At June 30, 2010, the proceeds had been utilized to fund capital expenditures primarily related to Algar.
Flow-Through Shares
In October 2009, to fund the company's 2010 exploration program, the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share, for gross proceeds of $30.1 million. At June 30, 2010, proceeds of $26 million of the flow-through financing had been utilized for the exploration program and the balance of the proceeds was included in cash balances and will be utilized for additional qualified expenditures. The company renounced the income tax benefits of these expenditures ($30.1 million) to the subscribing investors, effective December 31, 2009.
Revolving Credit Facilities
In November 2009, the company successfully arranged a US$50 million Revolving Credit Facility. The two year facility is available for general corporate purposes and was provided by a syndicate of Canadian and international banks. The Revolving Credit Facility provided Connacher with additional liquidity and financial flexibility. It also facilitated the issuance of letters of credit and the conduct of hedging activities. The Revolving Credit Facility is secured by a first priority security interest in all present and after-acquired assets of Connacher, except Connacher's investment in Petrolifera and the pipeline assets of an inactive subsidiary. As arranged when Connacher issued its First Lien Senior Notes earlier in 2009, the Revolving Credit Facility ranks senior to all of Connacher's indebtedness. The Revolving Credit Facility has certain financial covenants, as is customary for this type of credit. As at June 30, 2010, Connacher was in compliance with all its debt covenants.
At June 30, 2010, $5.7 million of letters of credit were issued in the course of normal business activities pursuant to the Revolving Credit Facility.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2010, the company had working capital of $100 million (December 31, 2009 - $245 million), including $69 million of cash (December 31, 2009 - $257 million). The company's indebtedness is long-term in nature, with no principal repayment obligation until June 2012. Management believes that the company presently has sufficient liquidity and financial capacity to fund its planned capital program and to satisfy its financial obligations under its long-term debt agreements.
In light of the volatility of current commodity prices and the U.S.:Canadian dollar exchange rate and their significance to the company's operating performance, management constantly assesses alternative hedging strategies to protect the company's cash flow from the risk of potentially lower crude oil and refined product pricing and adverse foreign exchange rate fluctuations. Although the company's integrated business model provides some risk mitigation, it does not provide a perfect hedge, particularly against commodity price volatility. The purpose of any hedging activity we undertake is to ensure more predictable cash flow availability to supplement cash balances. This allows us to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in an uncertain and volatile commodity price environment.
In 2010 the company entered into WTI risk management contracts on a portion of its anticipated crude oil production and a portion of its anticipated refined gasoline sales. Details of the outstanding risk management contracts are provided in the Pricing - Upstream and Downstream section earlier in this MD&A.
In Q2 2010, Connacher generated cash flow of $8.7 million ($0.02 per basic and diluted share outstanding) compared to $9.6 million ($0.04 per basic and $0.03 per diluted share outstanding) in Q2 2009. In YTD 2010, cash inflow was $12.6 million ($0.03 per basic and diluted share outstanding) compared to $4.9 million ($0.02 per basic and diluted share outstanding) in YTD 2009. Change in basic and diluted per share amounts in 2010 compared to 2009 also reflect the equity issuances in Q2 2009.
Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with cash flow for three and six months ended June 30, 2010 and 2009 as follows.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash flow $8,668 $9,570 $12,616 $4,878
-------------------------------------------------------------------------
Non-cash working capital
changes (169) (26,364) (11,046) (50,668)
-------------------------------------------------------------------------
Asset retirement expenditures (100) (29) (468) (133)
-------------------------------------------------------------------------
Pension funding - (234) - (234)
-------------------------------------------------------------------------
Cash flow from operating
activities $8,399 $(17,057) $1,102 $(46,157)
-------------------------------------------------------------------------
Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures.
Connacher's objectives in managing its cash, debt and equity and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital structure that allows multiple financing options when a financing need arises and to optimize its use of short-term and long-term debt and equity at an appropriate level of risk.
The company manages its capital structure and follows a financial strategy that considers economic and industry conditions, the risk characteristics of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. Connacher monitors its capital structure using a number of financial ratios and industry metrics to ensure its objectives are being met and to ensure continued compliance with financial covenants.
Connacher's capital structure and certain financial ratios are noted below.
-------------------------------------------------------------------------
June 30, December 31,
($000) 2010 2009
-------------------------------------------------------------------------
Long term debt(1) $888,323 $876,181
-------------------------------------------------------------------------
Shareholders' equity 644,166 671,588
-------------------------------------------------------------------------
Total book capitalization $1,532,489 $1,547,769
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to book capitalization(2) 58% 57%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to market capitalization(3) 62% 62%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of
transaction costs and the Convertible Debentures' equity component
value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.
As at June 30, 2010, the company's net debt (long-term debt, net of cash on hand) was $818.9 million, its net debt to book capitalization was 53 percent and its net debt to market capitalization was 57 percent.
The company reported the following debt outstanding.
-------------------------------------------------------------------------
June 30, December 31,
($000) 2010 2009
-------------------------------------------------------------------------
First Lien Senior Notes, 11 3/4%,
due July 15, 2014 $194,802 $191,509
-------------------------------------------------------------------------
Second Lien Senior Notes, 10 1/4%,
due December 15, 2015 602,948 596,184
-------------------------------------------------------------------------
Convertible Debentures, 4 3/4%,
due June 30, 2012 90,573 88,488
-------------------------------------------------------------------------
Total - no current maturities $888,323 $876,181
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OUTLOOK
We expect stronger financial results in 2010 compared to 2009, due to anticipated improved operating performance at Pod One; higher and more stabilized commodity prices (supported by our hedging program); the anticipation of increased production and sales volumes as Algar comes on stream in the latter part of 2010 and due to increased contributions from our refining operations, which anticipates healthy asphalt markets.
Current cash balances, together with available unused revolving lines of bank credit and positive full year upstream netbacks and downstream margins, are anticipated to be sufficient to meet all our budgeted capital expenditures and ongoing financial obligations throughout 2010. We have identified reserves and resources to support our confidence in our future growth prospects. To stabilize our outlook in a volatile period and protect against the possibility of renewed crude oil weakness, we have arranged favorable WTI derivative hedges on approximately one half of our bitumen production throughout 2010, for a portion of bitumen production in Q1 and Q2 2011 and on a portion of refined gasoline sales through September 2010. Relative to our consumption of natural gas at Pod One, Algar and the Refinery, we currently have a built-in partial notional hedge with our own natural gas production in northern Alberta. This minimizes the impact of volatility to natural gas prices on our overall operations.
Based on year to date expenditures, including nine million of savings realized in the construction of Algar and current development plans, the company has reduced its previously forecast 2010 cash capital budget by $14 million from $247 million to $233 million. The revised cash capital budget does not include any potential minor asset acquisitions or dispositions and does not include non-cash capitalized items. Details of 2010 projected cash capital expenditures are as follows:
-------------------------------------------------------------------------
($millions)
-------------------------------------------------------------------------
Complete Algar $69
-------------------------------------------------------------------------
Algar capitalized interest, G&A and pre-commercial operations 48
-------------------------------------------------------------------------
Algar ESP pre-work and facility optimization 3
-------------------------------------------------------------------------
Cogeneration and sales transfer lines 23
-------------------------------------------------------------------------
Pod One, including two new SAGD wells, nine high temperature
ESPs/PC pumps and facility optimization 26
-------------------------------------------------------------------------
EIA application 2
-------------------------------------------------------------------------
Expand Pod One trucking terminal 5
-------------------------------------------------------------------------
Exploration program 28
-------------------------------------------------------------------------
Conventional and head office capital 17
-------------------------------------------------------------------------
Refinery 12
-------------------------------------------------------------------------
$233
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Future cash flows will be substantially sheltered from current cash taxes by the company's tax pools, which currently exceed $1.2 billion and which will be augmented by future capital expenditures.
Estimated 2010 Netback and Adjusted EBITDA
In our 2009 MD&A, as contained in our annual report and as filed separately on SEDAR, we provided guidance with regard to Connacher's estimated 2010 adjusted EBITDA per barrel of bitumen produced and sold and we updated that guidance in our Q1 2010 MD&A (the "Q1 2010 estimate"). Estimated 2010 adjusted EBITDA is calculated on an annual basis and, consequently, actual year-to-date ("YTD") 2010 adjusted EBITDA will vary from the estimated average annual adjusted EBITDA. The table below compares the company's consolidated results for the first six months of 2010 to the Q1 2010 estimate. Explanations for variances are provided below the table.
The table below also contains a revised estimate for full year 2010 adjusted EBITDA per barrel of bitumen produced and sold based on actual results for the six months ended June 30, 2010 and revised assumptions, reflecting current industry and market information (the "Revised Estimate"). An explanation of the revised assumptions is also provided under the tables below.
-------------------------------------------------------------------------
Estimated Full Year 2010 Adjusted EBITDA
-------------------------------------------------------------------------
YTD 2010 actual results Q1 2010 estimate Revised Estimate
-------------------------------------------------------------------------
Total Total Total
$/bbl of ($ $/bbl of ($ $/bbl of ($
bitumen millions) bitumen millions) bitumen millions)
-------------------------------------------------------------------------
Bitumen
netback $24.93 $30 $32.67 $122 $27.85 $91
-------------------------------------------------------------------------
Conventional
netback 8.74 10 4.91 18 6.00 20
-------------------------------------------------------------------------
Refining margin
or netback 4.49 5 3.10 12 6.05 20
-------------------------------------------------------------------------
Realized gain
(loss) on risk
management
contracts (1.06) (1) (0.52) (2) (0.10) (0)
-------------------------------------------------------------------------
Corporate
netback 37.10 44 40.16 150 39.80 131
-------------------------------------------------------------------------
Corporate G&A (8.26) (10) (4.92) (19) (5.73) (19)
-------------------------------------------------------------------------
Adjusted
EBITDA $28.84 $34 $35.24 $131 $34.07 $112
-------------------------------------------------------------------------
-------------------------------------------------------------------------
First half of 2010 adjusted EBITDA of $34 million was $9 million less than the Q1 2010 estimate for the same period for the reasons cited below.
Total first half 2010 bitumen netback of $30 million was below our Q1 2010 estimate for the same period. Lower WTI pricing, wider heavy oil differentials, higher operating and transportation costs in Q2 2010 were offset by lower diluent costs, a weaker Canadian dollar and lower royalties. The YTD 2010 actual daily bitumen production and sales volumes were below our Q1 2010 estimate for the same period due to the impact of abnormally high electrical outages and pump failures at Pod One.
First half 2010 conventional netback of $10 million was in line with Q1 2010 estimate. On a per barrel of bitumen basis conventional netbacks were higher due to lower YTD 2010 bitumen production.
The first half 2010 refining margin or netback of $5 million was higher than our Q1 2010 estimate for the same period primarily due to seasonality effects on refined product sales volumes, wider heavy oil differentials and lower input crude costs. First half 2010 refinery margin per barrel of bitumen was higher than the Q1 2010 estimate due to lower actual YTD 2010 bitumen production.
First half 2010 realized losses on risk management contracts were lower than estimated in Q1 2010 for the same period primarily due to a lower WTI crude oil price.
First half 2010 Corporate G&A of $10 million was in line with our Q1 2010 estimate for the same period, but on a per barrel of bitumen basis was higher due to lower actual YTD 2010 bitumen production.
The following table reconciles actual first half 2010 adjusted EBITDA per barrel of bitumen produced and in total to actual first half 2010 net loss.
-------------------------------------------------------------------------
$/bbl of Total
bitumen ($ millions)
-------------------------------------------------------------------------
Adjusted EBITDA $28.84 $34
-------------------------------------------------------------------------
Interest and other income 0.10 0
-------------------------------------------------------------------------
Unrealized gain on risk management contracts 8.20 10
-------------------------------------------------------------------------
Stock-based compensation (2.55) (3)
-------------------------------------------------------------------------
Finance charges (21.85) (26)
-------------------------------------------------------------------------
Foreign exchange loss (7.23) (8)
-------------------------------------------------------------------------
Depletion, depreciation and accretion (30.83) (37)
-------------------------------------------------------------------------
Income taxes 6.19 7
-------------------------------------------------------------------------
Equity interest in Petrolifera loss (0.40) (1)
-------------------------------------------------------------------------
Dilution loss (3.59) (4)
-------------------------------------------------------------------------
Net loss $(23.12) $(28)
-------------------------------------------------------------------------
The following tables are calculated on an annualized basis and may not be reflective of actual quarterly netbacks or adjusted EBITDA. Volatility in quarterly netbacks and adjusted EBITDA will occur due to, among other things, seasonality factors affecting our operations, especially in our refining operations. Estimated 2010 bitumen netbacks and 2010 adjusted EBITDA constitute forward-looking information. See "Forward-Looking Information" and "Risk Factors" sections in this MD&A and in our AIF. The key assumptions relating to the 2010 outlook are set out in the notes following the tables below. The revised estimated full year 2010 bitumen netback and full year 2010 adjusted EBITDA reflected below include actual results for YTD 2010 and forecast results for the balance of 2010. The revised estimated full year bitumen netback and full year 2010 adjusted EBITDA will form the basis of comparison for future reporting periods.
The full year 2010 bitumen production and sales estimate for Pod One has been reduced from 8,500 bbl/d, in our Q1 2010 estimate, to 7,200 bbl/d. The decrease reflects the impact of actual plant downtime experienced in Q2 2010 caused by an abnormally high occurrence of unplanned electrical outages and power bumps. There were six such incidents recorded in Q2 2010, compared to an approximate average of one per quarter since the start up of the Pod One plant operations in late 2007. In addition, we experienced an unusually high number of pump failures in Q2 2010, attributed to mechanical issues and normal wear and tear. These occurrences had a consequent negative impact on Pod One's plant instrumentation, pump and boiler operations and well performance resulting in lower Q2 2010 actual bitumen production levels and higher SORs than anticipated in the Q1 2010 estimate. Our electrical provider has acknowledged the unusually high frequency of power outages and has attributed them to higher draws on the power grid, to equipment and system upsets and weather related issues. Our electrical provider is in the process of adding a new substation in the Great Divide area for completion in Q1 2011 which is anticipated to significantly reduce the frequency of unplanned electrical upsets at Pod One and stabilize our oil sands area as a whole. In addition, the startup of our cogeneration facility at Algar, scheduled for later this year, is expected to reduce the frequency of periodic power shutdowns that we have experienced to date. We are also working with our pump providers to assess and improve the reliability of pump operations and pump installations. Nonetheless, we have reduced our revised bitumen production forecast for Pod One to factor the potential for continued upsets and consequent negative impact on the operations of our facility, pumps and wells for the remainder of 2010. Our revised Pod One bitumen production forecast also incorporates production from our newest two SAGD well pairs at Pod One, expected to be converted to full-time production in Q3 2010. The consequent reduction in forecast adjusted EBITDA as reflected in the Revised Estimate is anticipated to be largely offset by realized savings and reductions to our remaining 2010 capital program, as discussed previously.
Revised Estimated Full Year 2010 Bitumen Netback(1)
-------------------------------------------------------------------------
Total $/bbl of bitumen
-------------------------------------------------------------------------
Bitumen price at wellhead(2)(3) $47.18
-------------------------------------------------------------------------
Royalties(4) (1.79)
-------------------------------------------------------------------------
Operating costs
-------------------------------------------------------------------------
Natural gas(5) (5.50)
-------------------------------------------------------------------------
Other operating costs(6) (12.04)
-------------------------------------------------------------------------
Bitumen netback $27.85
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Assumes estimated total average daily bitumen production of
9,000 bbl/d in 2010; 7,200 bbl/d from Pod One and 1,800 bbl/d from
Algar and has not been adjusted for inflation. See "Forward-Looking
Information" and "Risk Factors" sections of our AIF. Production from
Algar assumes commerciality is declared effective October 1, 2010 and
has been annualized for calendar 2010.
(2) Based on average full year WTI price of US$77.23/bbl, a heavy oil
differential of US$11.58/bbl (average of 15 percent) and a quality
charge of US$6.45/bbl, resulting in a dilbit price of $61.57/bbl for
Pod One. Based on an average Q4 2010 WTI price of US$76.00/bbl, a
heavy oil differential of US$12.16/bbl (average of 16 percent) and a
quality charge of US$5.77/bbl, resulting in a dilbit price of
$60.39/bbl for Algar. Also assumes an average foreign exchange rate
of $1.04 US$1.00.
(3) The assumed bitumen price at the wellhead of $47.66/bbl for Pod One
and $45.26/bbl for Algar is net of dilbit transportation costs of
$5.16/bbl of bitumen and assumed diluent blending cost of $29.27/bbl
of bitumen ($21.95/bbl of dilbit), including $1.70/bbl of bitumen of
diluent transportation costs ($5.12/bbl of diluent), a 4.0 percent
average diluent premium to WTI and a blending ratio of 25 percent for
Pod One; and a diluent blending cost of $36.02/bbl of bitumen
($25.21/bbl of dilbit), including $2.14/bbl of bitumen of diluent
transportation costs, ($5.00/bbl of diluent), a zero percent average
diluent premium to WTI and a blending ratio of 30 percent for Algar.
(4) Royalties are calculated on a pre-payout basis and are estimated to
be $1.83/bbl for Pod One and $1.62/bbl for Algar.
(5) Based on an average SOR of 3.5 for Pod One and 3.7 for Algar and a
natural gas price of US$4.00/Mcf, which equates to $5.48/bbl or
approximately 9,476 Mcf/d of natural gas burned to produce
7,200 bbl/d of bitumen at Pod One and a natural gas price of
US $3.85/Mcf, which equates to $5.60/bbl or approximately 2,520 Mcf/d
of natural gas burned to produce 1,800 bbl/d of bitumen at Algar. The
SORs for Pod One are a conservative estimate reflecting the impact of
higher SORs experienced to date in the wells that don't have ESPs and
the impact of steaming the two new SAGD well pairs in 2010. The SORs
from Algar reflect the relative infancy of the SAGD well pairs and
are expected to trend downwards as the wells are optimized and as
ESPs are added.
(6) Assumes $12.51/bbl of non-natural gas operating costs for Pod One and
$10.14/bbl of non-natural gas operating costs at Algar. Higher Pod
One non-natural gas operating costs compared to the Q1 2010 estimate
is due primarily to the impact of power and pump reliability issues
as discussed previously.
Revised Estimated Full Year 2010 Adjusted EBITDA(1)
-------------------------------------------------------------------------
Total $/bbl Total
of bitumen ($millions)
-------------------------------------------------------------------------
Corporate netback contribution
-------------------------------------------------------------------------
Bitumen netback(2) $27.85 $91
-------------------------------------------------------------------------
Conventional netback(3) 6.00 20
-------------------------------------------------------------------------
Refining margin or netback(4) 6.05 20
-------------------------------------------------------------------------
Loss on risk management contracts(5) (0.10) (0)
-------------------------------------------------------------------------
Corporate netback 39.80 131
-------------------------------------------------------------------------
Corporate G&A(6) (5.73) (19)
-------------------------------------------------------------------------
Adjusted EBITDA $34.07 $112
-------------------------------------------------------------------------
(1) Assumes estimated total average daily bitumen production of
9,000 bb/d in 2010; 7,200 bbl/d from Pod One and 1,800 bbl/d from
Algar and has not been adjusted for inflation. Also assumes an
average foreign exchange rate of $1.04=US$1.00.
(2) See the table above for assumptions.
(3) Assumes estimated production of 929 bbl/d of conventional crude oil
and 9,257 Mcf/d of natural gas production. Conventional oil assets
anticipated revenue based on average realized oil price of
US$65.11/bbl and natural gas assets revenue based on average realized
natural gas price of US$4.02/Mcf. Conventional asset netback is based
on 17 percent average royalty rate and average operating costs of
$11.97/boe. Improved conventional netback compared to the Q1 2010
estimate is due primarily to the impact of gas cost allowance
recoveries and lower royalties expected in 2010.
(4) Assumes estimated refinery crude charged of 9,642 bbl/d, feedstock
purchased at US$74.31/bbl, refined products sold with a spread of
US$11.34/bbl to the full year average WTI estimate of US$77.23/bbl
and operating costs of US$8.79/bbl, implying a refining margin of
US$5.47/bbl of crude charged. The higher refining margin compared to
the Q1 2010 estimate reflects widening heavy oil differentials and
stronger asphalt results, due to sales contract commitments and a
softening of crude oil prices compared to the Q1 2010 estimate.
(5) Anticipated net cost from a US$78.00/bbl WTI swap on 2,500 bbl/d of
bitumen production for calendar 2010, a US$79.02/bbl WTI swap on
2,500 bbl/d of bitumen production from February to April 2010 and a
US$9.00/bbl spread to WTI swap on 2,000 bbl/d of gasoline from April
to September 2010.
(6) Excludes capitalized G&A of $1.60/bbl of bitumen.
Actual netbacks and adjusted EBITDA achieved during 2010 could differ materially from the estimates contained in our 2010 outlook. The material risk factors that we have identified toward achieving these future netbacks and adjusted EBITDA are outlined in the "Risk Factors" and "Forward-Looking Information" sections of our 2009 annual MD&A and in our AIF and include, without limitation, difficulties or interruptions and additional costs during the production of bitumen, crude oil and natural gas; we may encounter timing difficulties or delays and additional costs relating to the commissioning, steaming or start-up of the Algar project; we may experience difficulties in delivering diluent to our oil sands projects and dilbit to commercial markets; the performance and availability of facilities owned by third parties may adversely affect our operations; crude oil and natural gas prices may fluctuate from current estimates; there may be changes in refining spreads to WTI and changes in the differential pricing between heavy and light crude oil prices; there may be adverse currency fluctuations; general economic conditions may remain uncertain or volatile thus affecting demand for our products and/or the costs for labour, equipment and services and changes in, or the introduction of new, government regulations relating to our business may increase operating costs.
Sensitivity Analysis
The following table shows sensitivities to adjusted EBITDA for changes to oil prices, production volumes and foreign exchange rates. The analysis is based on recent prices and production volumes.
-------------------------------------------------------------------------
Change $ million $/share(1)
-------------------------------------------------------------------------
WTI price US$5.00/bbl 6 $0.01
-------------------------------------------------------------------------
Bitumen production 500 bbl/d 4 $0.01
-------------------------------------------------------------------------
Exchange rate (U.S./Canadian) $0.05 7 $0.02
-------------------------------------------------------------------------
(1) Based on 429 million shares outstanding at June 30, 2010.
RISK FACTORS AND RISK MANAGEMENT
Connacher is engaged in the oil and gas exploration, development, production, and refining industry. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Operational risks include competition, reservoir performance uncertainties, production reliability, performance of third party services and supplies, environmental factors, and regulatory and safety concerns. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, currency exchange rates and the cost of goods and services.
Connacher's financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the oil and gas industry, commodity prices and exchange rates, the impacts of varying weather conditions on product sales, and operating performance, environmental legislation, changes to royalty and income tax legislation, credit and capital market conditions, credit risk for failure of performance of third parties and other risks and uncertainties described in more detail in Connacher's AIF for the year ended December 31, 2009 filed with securities regulatory authorities.
Connacher employs highly qualified people, uses sound operating and business practices and evaluates all potential and existing wells using the latest applicable technology. The company has designed policies and procedures for compliance with government regulations and has in place an up-to-date emergency response program. Connacher monitors and seeks to adhere to environment and safety policies and standards. Asset retirement obligations are recognized upon acquisition, construction and development of the assets. Connacher maintains property and liability insurance coverage. The coverage provides a reasonable amount of protection from risk of loss; however, not all risks are foreseeable or insurable.
INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")
The company is executing a conversion project to complete the transition to IFRS by Q1 2011, including the preparation of 2010 required comparative information. The conversion plan consists of four phases: diagnostic; design and planning; solution development and implementation. A fulsome description of the company's IFRS conversion project phases and the company's progress to the end of 2009 is contained within the company's MD&A for the year ended December 31, 2009. The company is currently in the implementation phase and is still in the process of determining the full impact of adopting IFRS. However, we have determined that the differences that could have the greatest impact on Connacher's consolidated financial statements relate to accounting for exploration and development activities, property, plant and equipment, goodwill, asset retirement obligations and income taxes.
The majority of the adjustments made on transition to IFRS will be recorded retrospectively to the opening balance of retained earnings at January 1, 2010. Changes arising from the transition where the accounting standards do not require retrospective application will be applied prospectively to transactions occurring subsequent to January 1, 2010.
IFRS 1 "First-Time Adoption of International Financial Reporting Standards" provides entities adopting IFRS for the first time with a number of optional and mandatory exemptions, in certain specific areas, to the general requirement for full retrospective application of IFRS. The company is analyzing the various accounting policy choices available and will implement those determined to be most appropriate in the company's circumstances.
One such exemption we expect to utilize is the amendment to IFRS 1 issued by the International Accounting Standards Board (IASB) in July 2009 respecting the determination of opening balances of property, plant and equipment. That amendment permits oil and gas companies currently using the full cost method of accounting to allocate the balance of property, plant and equipment as determined under Canadian GAAP to the IFRS categories of exploration and evaluation assets and development and producing properties without requiring full retrospective restatement of historic property, plant and equipment balances to the IFRS basis of accounting.
Other exemptions from retrospective application of IFRS which we may use are those available for foreign currency translation differences recorded in accumulated other comprehensive income, actuarial gains and losses relating to MRCI's defined benefit pension plan, stock-based compensation, leases and business combinations.
The following discussion provides an overview of the areas that could have the greatest impact on Connacher's consolidated financial statements. The items discussed below should not be considered a complete list of the changes which may occur as a result of the transition to IFRS. The discussion is intended to highlight the areas of most significant impact on Connacher based on the work completed to date. However, the company's analysis of the changes is ongoing. Additionally, Connacher has not finished quantifying the anticipated effects of the transition to IFRS on the consolidated financial statements.
Property, Plant & Equipment
International Accounting Standard (IAS) 16 "Property, Plant & Equipment" and Canadian GAAP contain the same basic principles. However there are some differences. IFRS requires that significant components of an asset be depreciated separately. Depreciation under IFRS commences when an asset is available for use. Capitalization of costs under IFRS ceases when an item of PP&E is in the location and condition necessary for it to be capable of operating in the manner intended by management. IFRS also permits property, plant and equipment to be measured using the fair value model or the historical cost model. The company does not plan to adopt the fair value model to measure its property, plant and equipment.
Additionally, under IFRS exploration and evaluation assets are accounted for separately from development and production assets which are accounted for as property, plant and equipment.
IFRS 1 contains an elective exemption where an entity may elect to reset as the new cost basis for property, plant and equipment, its fair value at the date of transition. The company is not planning to use this exemption and will continue to measure its property, plant and equipment at cost.
Impairment Testing of Assets
Impairment testing of non-financial assets under IFRS, including property, plant and equipment, is measured using discounted cash flows and fair values. Under Canadian GAAP, an asset's carrying amount was first compared to its undiscounted future cash flows. If the carrying value exceeded that amount, the impairment was measured as the excess of the carrying value over the asset's discounted future cash flows. Under IFRS, there is no initial assessment using undiscounted cash flows. Therefore, impairments may occur more frequently under IFRS as compared to Canadian GAAP. However, under IFRS there is an opportunity to reverse impairment losses for assets other than goodwill where there is a favourable change in the circumstances which gave rise to the impairment. Under Canadian GAAP, impairments were not reversed.
Additionally, under Canadian GAAP, Connacher's oil and gas assets were tested for impairment in a single, country-wide full cost pool. Under IFRS, assets must be segregated into "cash-generating units" ("CGUs") for purposes of impairment testing. A CGU is defined as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. As a result, impairments may occur with respect to certain of the company's assets which would not have been incurred under Canadian GAAP because of the ability under full cost accounting to shelter assets using the cash flow from the all of the company's oil and gas properties included in the full cost pool. The effect of this difference on Connacher's oil and gas assets is not presently determinable.
Asset Retirement Obligations
Differences exist between Canadian GAAP and IFRS with respect to the measurement of asset retirement obligations. Specifically, under Canadian GAAP asset retirement obligations were measured at fair value using a credit-adjusted risk-free discount rate. Under IFRS, asset retirement obligations are measured using the best estimate of the expenditure required to settle the obligation, and are discounted using a risk-free interest rate. This will likely result in an increase in Connacher's asset retirement obligation recorded on the consolidated balance sheet.
In addition, IFRS requires changes to the timing of cash flows, estimated amounts of cash flows and discount rates to be accounted for prospectively. Canadian GAAP is similar; however, changes to the discount rates for ARO are only applied to the incremental changes in the liability and not to the entire liability.
Income Taxes
Under IAS 12 "Income Taxes", deferred taxes are not recognized for temporary differences arising from the initial recognition of an asset or liability in a transaction which is not a business combination and which at the time of the transaction affects neither accounting nor taxable income. Canadian GAAP contains no such exemption.
Additionally, under IFRS current and deferred taxes are normally recognized in the income statement, except to the extent that deferred tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share- based payment transaction. If a deferred tax asset or liability is remeasured subsequent to initial recognition, the impact of remeasurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the remeasurement of taxes back to the item which originally triggered the recognition is commonly referred to as "backwards tracing." Canadian GAAP prohibits backwards tracing except in relation to business combinations and financial reorganizations.
Internal Controls
Connacher is currently assessing the impact of the conversion to IFRS on internal controls and business processes. Based on our initial assessment, the impact is not expected to be significant. However, some additional controls will be required in regard to recording transitional adjustments and new processes for identifying and separately accounting for exploration and evaluation assets.
DISCLOSURE CONTROLS AND PROCEDURES
The company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the company is made known to the company's CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of the company's financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.
The company's CEO and CFO are required to cause the company to disclose any change in the company's internal controls over financial reporting that occurred during the company's most recent interim period that has materially affected, or is reasonably likely to materially affect, the company's internal controls over financial reporting. No changes in the company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the company's internal controls over financial reporting.
It should be noted that a control system, including the company's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
QUARTERLY RESULTS
Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices, production and sales volumes and foreign exchange rates relative to U.S. dollar denominated debt. Significant volatility and declining commodity prices, together with severe economic uncertainty in the fourth quarter of 2008 and Q1 2009 are the primary factors affecting financial results during those quarters. The magnitude of the changes in commodity prices during these periods was unprecedented.
-------------------------------------------------------------------------
2008 2008 2009 2009
-------------------------------------------------------------------------
Three Months Ended Sept 30 Dec 31 Mar 31 June 30
-------------------------------------------------------------------------
Revenues, net of royalties 224,558 102,109 61,757 100,219
-------------------------------------------------------------------------
Cash flow(1) 31,130 (4,688) (4,692) 9,570
-------------------------------------------------------------------------
Basic, per share(1) 0.15 (0.02) (0.02) 0.04
-------------------------------------------------------------------------
Diluted, per share(1) 0.14 (0.02) (0.02) 0.03
-------------------------------------------------------------------------
Net earnings (loss) 12,139 (43,592) (46,844) 39,966
-------------------------------------------------------------------------
Basic per share 0.06 (0.21) (0.22) 0.15
-------------------------------------------------------------------------
Diluted per share 0.06 (0.21) (0.22) 0.14
-------------------------------------------------------------------------
Property and equipment additions 69,175 86,174 64,255 40,236
-------------------------------------------------------------------------
Cash on hand 236,375 223,663 96,220 401,160
-------------------------------------------------------------------------
Working capital 200,177 197,914 120,035 455,001
-------------------------------------------------------------------------
Long-term debt 689,673 778,732 803,915 960,593
-------------------------------------------------------------------------
Shareholders' equity 496,509 469,087 428,276 622,235
-------------------------------------------------------------------------
Operating Information
-------------------------------------------------------------------------
Upstream: Daily production/
sales volumes
-------------------------------------------------------------------------
Bitumen - bbl/d 6,810 7,086 6,170 6,284
-------------------------------------------------------------------------
Crude oil - bbl/d 957 1,187 1,180 1,114
-------------------------------------------------------------------------
Natural gas - Mcf/d 13,188 12,405 12,828 12,144
-------------------------------------------------------------------------
Equivalent - boe/d(2) 9,966 10,341 9,488 9,421
-------------------------------------------------------------------------
Product sales prices(3)
-------------------------------------------------------------------------
Bitumen - $/bbl 65.34 12.06 22.45 40.95
-------------------------------------------------------------------------
Crude oil - $/bbl 103.60 48.13 39.63 54.87
-------------------------------------------------------------------------
Natural gas - $/Mcf 8.92 6.61 4.89 3.35
-------------------------------------------------------------------------
Selected highlights - $/boe(2)
-------------------------------------------------------------------------
Weighted average sales price(3) 66.41 21.73 26.13 38.11
-------------------------------------------------------------------------
Royalties 4.65 3.19 3.02 1.90
-------------------------------------------------------------------------
Operating costs 20.41 20.76 17.73 13.98
-------------------------------------------------------------------------
Netback(4) 41.35 (2.22) 5.38 22.23
-------------------------------------------------------------------------
Downstream: Refining
-------------------------------------------------------------------------
Crude charged - bbl/d 9,239 8,333 6,867 9,145
-------------------------------------------------------------------------
Refining utilization - % 97 88 72 96
-------------------------------------------------------------------------
Margins - % 2 (18) 7 5
-------------------------------------------------------------------------
Common Share Information
-------------------------------------------------------------------------
Shares outstanding end of
period (000) 211,182 211,182 211,291 403,546
-------------------------------------------------------------------------
Weighted average shares
outstanding for the period
-------------------------------------------------------------------------
Basic (000) 211,093 211,182 211,286 266,425
-------------------------------------------------------------------------
Diluted (000) 213,174 211,575 211,286 286,985
-------------------------------------------------------------------------
Volume traded (000) 112,401 110,244 67,387 249,700
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 4.65 2.95 1.00 1.66
-------------------------------------------------------------------------
Low 2.63 0.60 0.61 0.74
-------------------------------------------------------------------------
Close (end of period) 2.75 0.74 0.74 0.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2009 2009 2010 2010
-------------------------------------------------------------------------
Three Months Ended Sept 30 Dec 31 Mar 31 June 30
-------------------------------------------------------------------------
Revenues, net of royalties 151,360 108,354 118,411 141,270
-------------------------------------------------------------------------
Cash flow(1) 10,410 (2,766) 3,948 8,668
-------------------------------------------------------------------------
Basic, per share(1) 0.03 (0.07) 0.01 0.02
-------------------------------------------------------------------------
Diluted, per share(1) 0.03 (0.06) 0.01 0.02
-------------------------------------------------------------------------
Net earnings (loss) 47,767 (14,731) 5,546 (33,126)
-------------------------------------------------------------------------
Basic per share 0.12 (0.03) 0.01 (0.08)
-------------------------------------------------------------------------
Diluted per share 0.11 (0.03) 0.01 (0.08)
-------------------------------------------------------------------------
Property and equipment additions 100,727 116,846 118,272 59,316
-------------------------------------------------------------------------
Cash on hand 333,634 256,787 118,382 69,412
-------------------------------------------------------------------------
Working capital 347,139 245,067 127,186 99,834
-------------------------------------------------------------------------
Long-term debt 889,113 876,181 851,978 888,323
-------------------------------------------------------------------------
Shareholders' equity 658,336 671,588 668,722 644,166
-------------------------------------------------------------------------
Operating Information
-------------------------------------------------------------------------
Upstream: Daily production/
sales volumes
-------------------------------------------------------------------------
Bitumen - bbl/d 6,551 6,090 6,936 6,211
-------------------------------------------------------------------------
Crude oil - bbl/d 993 880 937 906
-------------------------------------------------------------------------
Natural gas - Mcf/d 10,377 10,319 9,662 9,278
-------------------------------------------------------------------------
Equivalent - boe/d(2) 9,274 8,690 9,483 8,663
-------------------------------------------------------------------------
Product sales prices(3)
-------------------------------------------------------------------------
Bitumen - $/bbl 45.30 48.23 51.98 43.13
-------------------------------------------------------------------------
Crude oil - $/bbl 60.58 67.24 71.08 61.90
-------------------------------------------------------------------------
Natural gas - $/Mcf 2.91 4.34 4.86 3.78
-------------------------------------------------------------------------
Selected highlights - $/boe(2)
-------------------------------------------------------------------------
Weighted average sales price(3) 41.74 45.76 49.99 41.44
-------------------------------------------------------------------------
Royalties 2.13 2.45 3.57 2.73
-------------------------------------------------------------------------
Operating costs 15.43 20.61 17.47 19.25
-------------------------------------------------------------------------
Netback(4) 24.18 22.70 28.95 19.46
-------------------------------------------------------------------------
Downstream: Refining
-------------------------------------------------------------------------
Crude charged - bbl/d 7,076 8,188 9,347 9,373
-------------------------------------------------------------------------
Refining utilization - % 75 86 98 99
-------------------------------------------------------------------------
Margins - % 8 (7) (8) 12
-------------------------------------------------------------------------
Common Share Information
-------------------------------------------------------------------------
Shares outstanding end of
period (000) 403,567 427,031 428,246 429,103
-------------------------------------------------------------------------
Weighted average shares
outstanding for the period
-------------------------------------------------------------------------
Basic (000) 403,565 421,804 427,830 429,023
-------------------------------------------------------------------------
Diluted (000) 424,058 422,344 430,077 429,023
-------------------------------------------------------------------------
Volume traded (000) 129,206 207,978 167,483 182,419
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 1.15 1.33 1.65 1.88
-------------------------------------------------------------------------
Low 0.76 0.94 1.16 1.20
-------------------------------------------------------------------------
Close (end of period) 1.10 1.28 1.49 1.29
-------------------------------------------------------------------------
(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in non-
cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be cash flow from operating activities. Cash flow is
reconciled with cash flow from operating activities on the
Consolidated Statement of Cash Flows and in the applicable Management
Discussion & Analysis ("MD&A") for the periods referenced. Management
uses these non-GAAP measurements for its own performance measures and
to provide its shareholders and investors with a measurement of the
company's efficiency and its ability to fund its future growth
expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf: 1 bbl. This conversion is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. Boes may
be misleading, particularly if used in isolation.
(3) Product and weighted average sales prices are net of diluent and
transportation costs and exclude risk management contract
gains/losses.
(4) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. Netback per boe is calculated
as bitumen, crude oil and natural gas revenue before consideration of
risk management contracts/losses, less royalties and operating costs
divided by related production volumes. Netbacks have been reconciled
to net earnings in the applicable MD&A for the periods referenced.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
-------------------------------------------------------------------------
June 30, December 31,
As at (Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
-------------------------------------------------------------------------
ASSETS
-------------------------------------------------------------------------
CURRENT
-------------------------------------------------------------------------
Cash $69,412 $256,787
-------------------------------------------------------------------------
Accounts receivable 49,545 43,038
-------------------------------------------------------------------------
Inventories 51,911 36,871
-------------------------------------------------------------------------
Due from Petrolifera Petroleum Limited 28 29
-------------------------------------------------------------------------
Prepaid expenses and other assets 13,703 15,874
-------------------------------------------------------------------------
Income taxes recoverable - 2,608
-------------------------------------------------------------------------
Risk management contracts (note 8.2) 5,229 -
-------------------------------------------------------------------------
189,828 355,207
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Property, plant and equipment 1,373,996 1,230,256
-------------------------------------------------------------------------
Goodwill 103,676 103,676
-------------------------------------------------------------------------
Investment in Petrolifera Petroleum Limited
(note 13) 45,621 50,379
-------------------------------------------------------------------------
$1,713,121 $1,739,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
CURRENT LIABILITIES
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $89,801 $105,620
-------------------------------------------------------------------------
Income taxes payable 193 -
-------------------------------------------------------------------------
Risk management contracts (note 8.2) - 4,520
-------------------------------------------------------------------------
89,994 110,140
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long-term debt (note 3) 888,323 876,181
-------------------------------------------------------------------------
Future income taxes 51,445 47,695
-------------------------------------------------------------------------
Asset retirement obligations (note 5) 37,799 32,848
-------------------------------------------------------------------------
Employee future benefits 1,394 1,066
-------------------------------------------------------------------------
1,068,955 1,067,930
-------------------------------------------------------------------------
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
Share capital (note 6.1) 586,366 590,845
-------------------------------------------------------------------------
Equity component of convertible debentures 16,817 16,817
-------------------------------------------------------------------------
Contributed surplus (note 7.1) 33,660 30,560
-------------------------------------------------------------------------
Retained earnings 21,964 49,544
-------------------------------------------------------------------------
Accumulated other comprehensive loss (14,641) (16,178)
-------------------------------------------------------------------------
644,166 671,588
-------------------------------------------------------------------------
$1,713,121 $1,739,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Subsequent event - note 8.2
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(Canadian dollar in thousands,
except per share amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
REVENUE
-------------------------------------------------------------------------
Upstream, net of royalties $50,789 $48,286 $113,142 $84,294
-------------------------------------------------------------------------
Downstream 80,383 66,091 137,934 98,774
-------------------------------------------------------------------------
Gain (loss) on risk management
contracts (note 8.2) 10,049 (14,404) 8,485 (22,266)
-------------------------------------------------------------------------
Interest and other income 49 246 120 1,174
-------------------------------------------------------------------------
141,270 100,219 259,681 161,976
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
-------------------------------------------------------------------------
Upstream - diluent purchases
and operating costs 28,633 23,654 59,025 51,690
-------------------------------------------------------------------------
Upstream transportation costs 3,200 2,575 6,414 5,482
-------------------------------------------------------------------------
Downstream - crude oil
purchases and operating costs 73,950 65,611 140,239 96,331
-------------------------------------------------------------------------
General and administrative 4,278 3,224 9,830 7,698
-------------------------------------------------------------------------
Stock-based compensation
(note 7) 1,137 551 3,028 1,821
-------------------------------------------------------------------------
Finance charges (note 11) 13,222 8,877 25,951 18,037
-------------------------------------------------------------------------
Foreign exchange (gain) loss
(note 8.2) 32,545 (65,411) 8,602 (37,545)
-------------------------------------------------------------------------
Depletion, depreciation and
accretion 18,026 16,538 36,643 32,987
-------------------------------------------------------------------------
174,991 55,619 289,732 176,501
-------------------------------------------------------------------------
Earnings (loss) before income
taxes and other items (33,721) 44,600 (30,051) (14,525)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current income tax provision 150 121 356 293
-------------------------------------------------------------------------
Future income tax (recovery)
provision (4,987) 5,369 (7,717) (6,801)
-------------------------------------------------------------------------
(4,837) 5,490 (7,361) (6,508)
-------------------------------------------------------------------------
Earnings (loss) before
other items (28,884) 39,110 (22,690) (8,017)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity interest in
Petrolifera Petroleum
Limited's earnings (loss) 31 856 (617) 1,139
-------------------------------------------------------------------------
Dilution loss (note 13) (4,273) - (4,273) -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS (LOSS) (33,126) 39,966 (27,580) (6,878)
-------------------------------------------------------------------------
Retained earnings (deficit),
beginning of period 55,090 (23,458) 49,544 23,386
-------------------------------------------------------------------------
Retained earnings, end of
period $21,964 $16,508 $21,964 $16,508
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE
(note 6.3)
-------------------------------------------------------------------------
Basic $(0.08) $0.15 $(0.06) $(0.03)
-------------------------------------------------------------------------
Diluted $(0.08) $0.14 $(0.06) $(0.03)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Net earnings (loss) $(33,126) $39,966 $(27,580) $(6,878)
-------------------------------------------------------------------------
Foreign currency translation
adjustment 6,187 (12,999) 1,537 (8,568)
-------------------------------------------------------------------------
Comprehensive income (loss) $(26,939) $26,967 $(26,043) $(15,446)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Balance, beginning of period $(20,828) $12,233 $(16,178) $7,802
-------------------------------------------------------------------------
Foreign currency translation
adjustment 6,187 (12,999) 1,537 (8,568)
-------------------------------------------------------------------------
Balance, end of period $(14,641) $(766) $(14,641) $(766)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
(UNAUDITED)
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash provided by (used in)
the following activities:
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Net earnings (loss) $(33,126) $39,966 $(27,580) $(6,878)
-------------------------------------------------------------------------
Items not involving cash:
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 18,026 16,538 36,643 32,987
-------------------------------------------------------------------------
Stock-based compensation 1,137 551 3,028 1,821
-------------------------------------------------------------------------
Financing charges -
non-cash portion 1,453 1,134 2,890 2,175
-------------------------------------------------------------------------
Defined benefit pension
plan expense 154 107 309 294
-------------------------------------------------------------------------
Future income tax
(recovery) provision (4,987) 5,369 (7,717) (6,801)
-------------------------------------------------------------------------
Unrealized (gain) loss on
risk management contracts
(note 8.2) (11,141) 8,243 (9,749) 16,510
-------------------------------------------------------------------------
Gain on repurchase of
Second Lien Senior Notes - - - (475)
-------------------------------------------------------------------------
Equity interest in
Petrolifera Petroleum
Limited's loss (earnings) (31) (856) 617 (1,139)
-------------------------------------------------------------------------
Dilution loss (note 13) 4,273 - 4,273 -
-------------------------------------------------------------------------
Unrealized foreign exchange
loss (gain) (note 8.2) 32,910 (61,482) 9,902 (33,616)
-------------------------------------------------------------------------
Cash flow from operations
before working capital
and other changes 8,668 9,570 12,616 4,878
-------------------------------------------------------------------------
Pension funding - (234) - (234)
-------------------------------------------------------------------------
Asset retirement
expenditures (note 5) (100) (29) (468) (133)
-------------------------------------------------------------------------
Changes in non-cash working
capital (169) (26,364) (11,046) (50,668)
-------------------------------------------------------------------------
8,399 (17,057) 1,102 (46,157)
-------------------------------------------------------------------------
FINANCING
-------------------------------------------------------------------------
Proceeds on issue of common
shares 848 172,746 1,379 172,746
-------------------------------------------------------------------------
Share issue costs - (8,785) (80) (8,785)
-------------------------------------------------------------------------
Issuance of First Lien Senior
Notes - 226,475 - 226,475
-------------------------------------------------------------------------
Debt issue cost of First Lien
Senior Notes - (20,858) - (20,858)
-------------------------------------------------------------------------
Repurchase of Second Lien
Senior Notes - - - (309)
-------------------------------------------------------------------------
848 369,578 1,299 369,269
-------------------------------------------------------------------------
INVESTING
-------------------------------------------------------------------------
Capital expenditures (51,613) (39,620) (168,408) (102,764)
-------------------------------------------------------------------------
Proceeds on disposition of
property, plant and equipment - - 1,205 -
-------------------------------------------------------------------------
Decrease in restricted cash - - - (10,000)
-------------------------------------------------------------------------
Changes in non-cash working
capital (8,434) (14,155) (20,141) (49,523)
-------------------------------------------------------------------------
(60,047) (53,775) (187,344) (162,287)
-------------------------------------------------------------------------
NET INCREASE (DECREASE)
IN CASH (50,800) 298,746 (184,943) 160,825
-------------------------------------------------------------------------
Foreign exchange gain (loss)
on cash balances held in
foreign currency 1,830 6,194 (2,432) 6,672
-------------------------------------------------------------------------
CASH, BEGINNING OF PERIOD 118,382 86,220 256,787 223,663
-------------------------------------------------------------------------
CASH, END OF PERIOD $69,412 $391,160 $69,412 $391,160
-------------------------------------------------------------------------
For supplementary cash flow information - see note 12
The accompanying notes to the interim consolidated financial statements
are an integral part of these statements.
NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. NATURE OF OPERATIONS AND ORGANIZATION
Connacher Oil and Gas Limited ("Connacher" or "the company") is a
publicly traded, integrated energy company headquartered in Calgary,
Alberta, Canada.
Management has segmented the company's business based on differences in
products and services and management responsibility. The company's
business is conducted predominantly through two major business segments -
upstream in Canada and downstream in USA, through its wholly owned
subsidiary, Montana Refining Company, Inc. ("MRCI").
Upstream includes exploration for, development and production of crude
oil, natural gas and bitumen. Downstream includes refining of primarily
crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt
and ancillary products.
The company also has an investment in Petrolifera Petroleum Limited
("Petrolifera") which has been accounted for on the equity basis. As at
June 30, 2010 and December 31, 2009, the company owned 26.9 million
Petrolifera common shares representing 18.5 percent and 22 percent
respectively of Petrolifera's issued and outstanding common shares and
6.8 million Petrolifera share purchase warrants. See also Note 13.
Petrolifera is engaged in petroleum and natural gas exploration,
development and production activities in South America.
2. SIGNIFICANT ACCOUNTING POLICIES
The interim consolidated financial statements were prepared in accordance
with Canadian generally accepted accounting standards and follow the same
accounting policies and methods of computation as the most recent annual
consolidated financial statements. Certain information and disclosures
normally required to be included in notes to the annual consolidated
financial statements have been condensed or omitted. Accordingly, these
interim consolidated financial statements should be read in conjunction
with the annual consolidated financial statements and the notes thereto
for the year ended December 31, 2009.
In the opinion of management, these interim consolidated financial
statements contain all adjustments of a normal and recurring nature
necessary to present fairly Connacher's financial position at June 30,
2010 and December 31, 2009 and the results of its operations and cash
flows for the three and six months ended June 30, 2010 and 2009.
3. LONG-TERM DEBT
-------------------------------------------------------------------------
June 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
First Lien Senior Notes $194,802 $191,509
-------------------------------------------------------------------------
Second Lien Senior Notes 602,948 596,184
-------------------------------------------------------------------------
Convertible Debentures 90,573 88,488
-------------------------------------------------------------------------
Long-term debt $888,323 $876,181
-------------------------------------------------------------------------
The following table provides the key terms and conditions of the long-
term debt:
-------------------------------------------------------------------------
Face Interest
Value of rate Interest Principal
Principal Maturity per Payment Payment
(in millions) Date annum Terms Terms
-------------------------------------------------------------------------
First Lien
Senior Notes
(Secured)
Issue date: Semi-annually One payment
June 16, July on January 15 on maturity
2009 US$ 200 15, 2014 11.75% and July 15 (note 3.1)
-------------------------------------------------------------------------
Second Lien
Senior Notes
(Secured)
Issue date: Semi-annually One payment
December 3, December on June 15 and on maturity
2007 US$ 587.3 15, 2015 10.25% December 15 (note 3.1)
-------------------------------------------------------------------------
Convertible
into common
June 30, shares at a
Convertible 2012 conversion
Debentures unless price of
(Unsecured) converted Semi-annually $5.00 per
Issue date: prior to on June 30 and share
May 25, 2007 $100 that date 4.75% December 31 (note 3.1)
-------------------------------------------------------------------------
3.1 The company may redeem some or all of the First and Second Lien
Senior Notes (together the "Notes") and Convertible Debentures prior
to their maturity. Upon a change of control of the company,
Connacher is obliged to offer to purchase the outstanding
Convertible Debentures; additionally, the holders of the First and
Second Lien Senior Notes may require Connacher to purchase the
Notes. There were no changes to the terms and conditions of the
long-term debt during three and six months ended June 30, 2010.
4. REVOLVING CREDIT FACILITY
As at June 30, 2010, the company had a US$50 million revolving credit
facility (the "Facility"). The Facility has a two year term starting from
November 2009 and ranks ahead of the company's First and Second Lien
Senior Notes. It is secured by a first lien charge on all of the
company's assets, excluding certain pipeline assets in the USA and the
company's investment holdings in Petrolifera. The Facility bears interest
at the lenders' Canadian prime rate, a U.S. base rate, a Bankers'
Acceptance rate, or at a LIBOR rate plus applicable margins. Access to
the Facility is subject to certain covenants, which the company was in
compliance with at June 30, 2010. At June 30, 2010, $5.7 million of
letters of credit were issued and outstanding pursuant to the Facility.
5. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the beginning and ending aggregate
carrying amount of the obligation associated with the company's
retirement of its upstream crude oil, natural gas and oil sands
properties and facilities.
-------------------------------------------------------------------------
Six months
ended Year ended
June 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Balance, beginning of period $32,848 $26,396
-------------------------------------------------------------------------
Liabilities incurred 4,260 6,194
-------------------------------------------------------------------------
Liabilities settled (468) (142)
-------------------------------------------------------------------------
Liabilities disposed (264) -
-------------------------------------------------------------------------
Change in estimates - (1,803)
-------------------------------------------------------------------------
Accretion expense 1,423 2,203
-------------------------------------------------------------------------
Balance, end of period $37,799 $32,848
-------------------------------------------------------------------------
At June 30, 2010, the estimated total undiscounted amount required to
settle the asset retirement obligations was $86.7 million (December 31,
2009 - $72.0 million). The company has not recorded an asset retirement
obligation for its refining property, plant and equipment as it is
currently the company's intent to maintain and upgrade the refinery so
that it will be operational for the foreseeable future. Consequently, it
is not possible at the present time to estimate a date or range of dates
for settlement of any asset retirement obligation related to the
refinery.
6. SHARE CAPITAL
Authorized: unlimited number of common voting shares
Authorized: unlimited number of first preferred shares of which none were
outstanding
Authorized: unlimited number of second preferred shares of which none
were outstanding
6.1 ISSUED AND OUTSTANDING COMMON SHARE CAPITAL
-------------------------------------------------------------------------
Amount
(Canadian
Number of dollar in
shares thousands)
-------------------------------------------------------------------------
Balance, January 1, 2010 427,031,362 $590,845
-------------------------------------------------------------------------
Shares issued upon exercise of stock
options (note 7.2) 1,433,134 1,379
-------------------------------------------------------------------------
Assigned value of stock options
exercised (note 7.1) 748
-------------------------------------------------------------------------
Shares issued to directors as
compensation (note 7.3) 638,496 1,002
-------------------------------------------------------------------------
Share issue cost, net of future income tax (59)
-------------------------------------------------------------------------
Tax effect of flow-through shares (note 6.2) (7,549)
-------------------------------------------------------------------------
Balance, June 30, 2010 429,102,992 $586,366
-------------------------------------------------------------------------
6.2 FLOW-THROUGH COMMON SHARES
In October 2009, the company issued 23,172,500 common shares on a
flow-through basis at $1.30 per common share for gross proceeds of
$30.1 million and renounced the qualifying expenditures to investors
effective December 31, 2009. The related tax effect of $7.5 million was
recorded in the six months ended June 30, 2010.
6.3 PER SHARE AMOUNTS
The following table summarizes the common shares used in per share
calculations.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Weighted average common
shares outstanding - basic 429,023 266,425 428,430 239,008
-------------------------------------------------------------------------
Effect of diluted stock
options outstanding - 61 - -
-------------------------------------------------------------------------
Effect of diluted share awards
outstanding - 489 - -
-------------------------------------------------------------------------
Effect of diluted convertible
debentures outstanding - 20,010 - -
-------------------------------------------------------------------------
Weighted average common
shares outstanding - diluted 429,023 286,985 428,430 239,008
-------------------------------------------------------------------------
7. CONTRIBUTED SURPLUS, STOCK OPTIONS AND SHARE AWARD PLAN FOR NON-
EMPLOYEE DIRECTORS
7.1 CONTRIBUTED SURPLUS
The following table shows the changes in contributed surplus.
-------------------------------------------------------------------------
Six months
ended Year ended
June 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Balance, beginning of period $30,560 $26,053
-------------------------------------------------------------------------
Stock based compensation expensed 2,662 3,594
-------------------------------------------------------------------------
Stock based compensation capitalized 1,186 1,096
-------------------------------------------------------------------------
Assigned value of stock options exercised (748) (183)
-------------------------------------------------------------------------
Balance, end of period $33,660 $30,560
-------------------------------------------------------------------------
7.2 STOCK OPTIONS
The stock options have a term of five years to maturity and vest over the
period of two to three years. The following table shows the changes in
stock options and the related weighted average exercise price.
-------------------------------------------------------------------------
Six months ended Six months ended
June 30, 2010 June 30, 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
of Options Price of Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of period 22,579,045 $1.72 16,383,104 $3.16
-------------------------------------------------------------------------
Granted 9,123,084 1.38 4,375,947 0.72
-------------------------------------------------------------------------
Exercised (1,433,134) 0.96 (266,504) 0.60
-------------------------------------------------------------------------
Forfeited (374,145) 1.31 (316,598) 2.13
-------------------------------------------------------------------------
Expired (843,000) 3.00 (190,000) 1.35
-------------------------------------------------------------------------
Cancelled - - (4,407,000) 5.04
-------------------------------------------------------------------------
Outstanding, end of period 29,051,850 $1.62 15,578,949 $2.01
-------------------------------------------------------------------------
Exercisable, end of period 14,404,099 $2.03 9,880,984 $2.44
-------------------------------------------------------------------------
The following table summarizes stock options outstanding and exercisable
under the plan.
-------------------------------------------------------------------------
June 30, 2010 June 30, 2009
-------------------------------------------------------------------------
Weighted Weighted
Weighted Average Weighted Average
Range of Average Remaining Average Remaining
Exercise Number Exercise Contract- Number Exercise Contract-
Prices Outstanding Price ual Life Outstanding Price ual Life
-------------------------------------------------------------------------
$0.20 -
$0.99 4,026,267 $0.75 3.8 4,952,934 $0.73 4.0
-------------------------------------------------------------------------
$1.00 -
$1.99 19,415,025 1.28 4.1 4,436,940 1.33 3.4
-------------------------------------------------------------------------
$2.00 -
$3.99 4,977,049 3.32 1.4 5,231,566 3.31 2.4
-------------------------------------------------------------------------
$4.00 -
$5.99 633,509 4.49 1.2 957,509 4.68 2.0
-------------------------------------------------------------------------
29,051,850 $1.62 3.5 15,578,949 $2.01 3.2
-------------------------------------------------------------------------
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model using the following
weighted average assumptions.
-------------------------------------------------------------------------
Six months ended June 30 2010 2009
-------------------------------------------------------------------------
Risk free interest rate (percent) 1.9 1.3
-------------------------------------------------------------------------
Expected option life (years) 3.0 3.0
-------------------------------------------------------------------------
Expected volatility (percent) 72 67
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of options granted
during the three months ended June 30, 2010 was $0.80 per option (three
months ended June 30, 2009 - $0.52) and during the six months ended
June 30, 2010 was $0.67 per option (six months ended June 30, 2009 -
$0.32).
7.3 SHARE AWARD PLAN FOR NON-EMPLOYEE DIRECTORS
Under the share award plan, share units comprised of one common share per
unit may be granted to non-employee Directors of the company in amounts
determined by the Board of Directors on the recommendation of its
Governance Committee.
-------------------------------------------------------------------------
Six months Six months
ended ended
June 30, June 30,
(Number of share units) 2010 2009
-------------------------------------------------------------------------
Outstanding, beginning of period 648,916 392,705
-------------------------------------------------------------------------
Granted 380,598 478,872
-------------------------------------------------------------------------
Issued (638,496) (327,623)
-------------------------------------------------------------------------
Cancelled (10,420) (54,662)
-------------------------------------------------------------------------
Outstanding, end of period 380,598 489,292
-------------------------------------------------------------------------
Exercisable, end of period - 5,210
-------------------------------------------------------------------------
The 380,598 share awards granted in the six months ended June 30, 2010
vest on January 1, 2011. The 478,872 share awards granted in the six
months ended June 30, 2009 vested on January 1, 2010.
In three months and six months ended June 30, 2010, $138,000 and
$366,000, respectively, (three and six months ended June 30, 2009 -
$164,000 and $323,000, respectively,) was accrued as a liability and
expensed as stock based compensation in respect of outstanding shares
under the share award plan, using market price of the shares at the end
of each reporting period.
8. FINANCIAL INSTRUMENTS
Connacher's financial instruments include cash, accounts receivable,
amounts due from Petrolifera, accounts payable and accrued liabilities,
risk management contracts and long-term debt (First and Second Lien
Senior Notes and Convertible Debentures).
8.1 FAIR VALUE MEASUREMENTS FOR FINANCIAL INSTRUMENTS
The following table shows the comparison of the carrying and fair values
of the company's financial instruments as at June 30, 2010.
-------------------------------------------------------------------------
Carrying
(Canadian dollar in thousands) Value Fair Value
-------------------------------------------------------------------------
Held for trading
-------------------------------------------------------------------------
Cash $69,412 $69,412
-------------------------------------------------------------------------
Accounts receivable $49,545 $49,545
-------------------------------------------------------------------------
Due from Petrolifera $28 $28
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $89,801 $89,801
-------------------------------------------------------------------------
Risk management contracts $5,229 $5,229
-------------------------------------------------------------------------
Other liabilities
-------------------------------------------------------------------------
First Lien Senior Notes $194,802 $228,029
-------------------------------------------------------------------------
Second Lien Senior Notes $602,948 $604,204
-------------------------------------------------------------------------
Convertible Debentures $90,573 $92,046
-------------------------------------------------------------------------
8.2 RISKS EXPOSURE
The company is exposed to market risks related to the volatility of
commodity prices and foreign exchange rates. In certain instances, the
company uses derivative instruments to manage the company's exposure to
these risks. The company is also exposed, to a lesser extent, to credit
risk on accounts receivable and counterparties to price risk management
contracts and to liquidity risk. The company employs risk management
strategies and policies to ensure that any exposures to risk are in
compliance with the company's business objectives and risk tolerance
levels. Risk management is ultimately established by the company's Board
of Directors and is implemented and monitored by senior management of the
company.
At June 30, 2010, the company's exposure to risks associated with or
arising from the use of financial instruments had not changed
significantly from December 31, 2009 and March 31, 2010.
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk is comprised of commodity price risk and foreign currency
rate risk. The objective of market risk management is to manage and
control market price exposures within acceptable limits, while maximizing
returns.
COMMODITY PRICE RISK
The company is exposed to commodity selling price risk as a result of
potential changes in the market prices of its crude oil, bitumen, natural
gas and refined product sales volumes and the purchase price of diluent
and crude oil for refining.
The following table shows the net risk management asset (liability)
positions as at June 30, 2010 and December 31, 2009.
-------------------------------------------------------------------------
June 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Crude oil asset (liability) - Upstream $5,138 $(4,520)
-------------------------------------------------------------------------
Gasoline asset - Downstream 91 -
-------------------------------------------------------------------------
Asset (liability), end of period $5,229 $(4,520)
-------------------------------------------------------------------------
The following tables summarize the income statement effects of the
company's risk management contracts.
-------------------------------------------------------------------------
Three
months
ended
(Canadian dollar in June 30,
thousands) Three months ended June 30, 2010 2009
-------------------------------------------------------------------------
Upstream Downstream Upstream
Revenue Revenue Total Revenue
-------------------------------------------------------------------------
Unrealized gain (loss) $10,436 $705 $11,141 $(8,243)
-------------------------------------------------------------------------
Realized gain (loss) (325) (767) (1,092) (6,161)
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $10,111 $(62) $10,049 $(14,404)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six
months
ended
(Canadian dollar in June 30,
thousands) Six months ended June 30, 2010 2009
-------------------------------------------------------------------------
Upstream Downstream Upstream
Revenue Revenue Total Revenue
-------------------------------------------------------------------------
Unrealized gain (loss) $9,658 $91 $9,749 $(16,510)
-------------------------------------------------------------------------
Realized gain (loss) (497) (767) (1,264) (5,756)
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts $9,161 $(676) $8,485 $(22,266)
-------------------------------------------------------------------------
The following tables show the details of the risk management asset
(liability) positions as at June 30, 2010 and December 31, 2009.
JUNE 30, 2010 - UPSTREAM OIL CONTRACTS
-------------------------------------------------------------------------
Asset
(liability)
as at
June 30,
2010
Price (Canadian
Volume (WTI dollar in
(bbl/d) Term Type U.S.$/bbl) thousands)
-------------------------------------------------------------------------
2,500 Jan 1, 2010 - Dec 31, 2010 Swap $78.00 $518
-------------------------------------------------------------------------
1,000 Jan 1, 2011 - Mar 31, 2011 Swap $86.10 718
-------------------------------------------------------------------------
1,000 Jan 1, 2011 - Mar 31, 2011 Swap $88.10 908
-------------------------------------------------------------------------
2,000 Jan 1, 2011 - Mar 31, 2011 Call option $100.25 (403)
-------------------------------------------------------------------------
2,000 Jan 1, 2011 - Mar 31, 2011 Put option $80.00 1,762
-------------------------------------------------------------------------
2,500 May 1 - Dec 31, 2010 Call option $95.00 (398)
-------------------------------------------------------------------------
2,500 May 1 - Dec 31, 2010 Put option $75.00 2,033
-------------------------------------------------------------------------
Balance,
as at
June 30,
2010 $5,138
-------------------------------------------------------------------------
-------------------------------------------------------------------------
JUNE 30, 2010 - DOWNSTREAM GASOLINE CONTRACT
-------------------------------------------------------------------------
Asset
(liability)
as at
June 30,
2010
(Canadian
Volume dollar in
(bbl/d) Term Type Price thousands)
-------------------------------------------------------------------------
Floating
price* +
2,000 April 1, 2010 - Sept 30, 2010 Swap U.S. $9.00 $91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
* Floating price is an average WTI price for the calculation period.
DECEMBER 31, 2009 - UPSTREAM OIL CONTRACTS
-------------------------------------------------------------------------
Asset
(liability)
as at
December
31, 2009
Price (Canadian
Volume (WTI dollar in
(bbl/d) Term Type U.S.$/bbl) thousands)
-------------------------------------------------------------------------
2,500 Jan 1 - Dec 31, 2010 Swap $78.00 $(4,115)
-------------------------------------------------------------------------
2,500 Feb 1 - Apr 30, 2010 Swap $79.02 (405)
-------------------------------------------------------------------------
Balance, as at
December 31,
2009 $(4,520)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
As at June 30, 2010, had the forward price for WTI been U.S. $1/bbl
higher or lower, the impact would have been to increase or decrease,
respectively, the loss before income taxes by $900,000.
Subsequent to June 30, 2010, the company entered in the following risk
management contract:
- April 1, 2011 - June 30, 2011 - 2,000 bbl/d at WTI U.S.$85.25/bbl.
CURRENCY RISK
Currency risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in foreign
exchange rates.
The following table summarizes the components of the company's foreign
exchange gain (loss).
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2010 2009 2010 2009
-------------------------------------------------------------------------
Unrealized foreign exchange
gain (loss) on translation of:
-------------------------------------------------------------------------
U.S. denominated First and
Second Lien Senior Notes $(33,903) $50,545 $(7,290) $25,853
-------------------------------------------------------------------------
Foreign currency
denominated cash balances 1,836 7,033 (2,164) 6,799
-------------------------------------------------------------------------
Foreign exchange collar - 3,715 - 1,274
-------------------------------------------------------------------------
Other foreign currency
denominated monetary items (843) 189 (448) (310)
-------------------------------------------------------------------------
Unrealized foreign exchange
gain (loss) (32,910) 61,482 (9,902) 33,616
-------------------------------------------------------------------------
Realized foreign exchange
gain (loss) 365 3,929 1,300 3,929
-------------------------------------------------------------------------
Foreign exchange loss gain
(loss) $(32,545) $65,411 $(8,602) $37,545
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company is exposed to fluctuations in foreign currency as a result of
its U.S. dollar denominated Notes, crude oil sales based on U.S. dollar
indices and commodity price contracts that are settled in U.S. dollars. A
$0.01 change in the U.S. to Canadian dollar exchange rate would have
resulted in a $7.3 million change in foreign exchange gain/loss at
June 30, 2010.
The company's downstream operations operate with a U.S. dollar functional
currency, which gives rise to currency exchange rate risk on translation
of MRCI's operations. The impact is recorded in other comprehensive
income/loss. A $0.01 change in the U.S. to Canadian dollar exchange rate
would have resulted in a $0.3 million change in other comprehensive
income (loss) at June 30, 2010.
In November 2008, Connacher entered into a foreign exchange revenue
collar for the calendar year 2009 which set a floor of CAD $11.925
million and a ceiling of CAD $13 million on a notional amount of
US$10 million of monthly production revenue. No similar contract was
entered in the three and six months ended June 30, 2010.
9. CAPITAL MANAGEMENT
The company is exposed to financial risks on its financial instruments
and in the way it finances its capital requirements. The company manages
these financial and capital structure risks by operating in a manner that
minimizes its exposures to volatility of the company's financial
performance. Connacher continues to structure its capital consistent with
last year. These risks affecting the company are discussed below.
Connacher's objectives in managing its cash, debt and equity and its
future capital requirements are to safeguard its ability to meet its
financial obligations, to maintain a flexible capital structure that
allows multiple financing options when a financing need or opportunity
arises and to optimize its use of long-term debt and equity at an
appropriate level of risk.
The company manages its capital structure and follows a financial
strategy that considers economic and industry conditions, the risk
characteristics of its underlying assets and its growth opportunities. It
strives to continuously improve its credit rating and reduce its cost of
capital. Connacher monitors its capital structure using a number of
financial ratios and industry metrics to ensure its objectives are being
met and to ensure continued compliance with its financial covenants.
Connacher's current capital structure and certain financial ratios are
noted below.
-------------------------------------------------------------------------
June 30, December 31,
(Canadian dollar in thousands) 2010 2009
-------------------------------------------------------------------------
Long term debt(1) $888,323 $876,181
-------------------------------------------------------------------------
Shareholders' equity 644,166 671,588
-------------------------------------------------------------------------
Total Debt plus Equity ("capitalization") $1,532,489 $1,547,769
-------------------------------------------------------------------------
Debt to book capitalization(2) 58% 57%
-------------------------------------------------------------------------
Debt to market capitalization(3) 62% 62%
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of
transaction costs and the Convertible Debentures' equity component
value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.
As at June 30, 2010, the company's net debt (long-term debt, net of cash
on hand) was $818.9 million. Its net debt to book capitalization was
53 percent and its net debt to market capitalization was 57 percent.
10. SEGMENTED INFORMATION
The company has two business segments. In Canada, the company is in the
business of exploring for and producing crude oil, natural gas and
bitumen. In the USA, the company is in the business of refining and
marketing petroleum products. The significant information of these
operating segments is presented below.
-------------------------------------------------------------------------
(Canadian dollar
in thousands) Canada USA
-------------------------------------------------------------------------
Inter-
segment
Three months ended Oil and Gas Refining Elimin-
June 30, 2010 Upstream Downstream ation(1) Total
-------------------------------------------------------------------------
Net revenues $50,789 $83,988 $(3,605) $131,172
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts 10,111 (62) - 10,049
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings (loss) 31 - - 31
-------------------------------------------------------------------------
Interest and other income 26 23 - 49
-------------------------------------------------------------------------
Finance charges 13,216 6 - 13,222
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 15,680 2,346 - 18,026
-------------------------------------------------------------------------
Income tax provision
(recovery) (6,790) 1,953 - (4,837)
-------------------------------------------------------------------------
Net earnings (loss) (35,782) 2,656 - (33,126)
-------------------------------------------------------------------------
Property, plant and
equipment 1,287,360 86,636 - 1,373,996
-------------------------------------------------------------------------
Goodwill 103,676 - - 103,676
-------------------------------------------------------------------------
Capital expenditures 58,057 1,259 - 59,316
-------------------------------------------------------------------------
Total assets $1,533,759 $179,362 $- $1,731,121
-------------------------------------------------------------------------
Three months ended
June 30, 2009
-------------------------------------------------------------------------
Net revenues $48,286 $69,094 $(3,003) $114,377
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts (14,404) - - (14,404)
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings
(loss) 856 - - 856
-------------------------------------------------------------------------
Interest and other income 57 189 - 246
-------------------------------------------------------------------------
Finance charges 8,819 58 - 8,877
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 14,723 1,815 - 16,538
-------------------------------------------------------------------------
Income tax provision
(recovery) 5,773 (283) - 5,490
-------------------------------------------------------------------------
Net earnings (loss) 40,413 (447) - 39,966
-------------------------------------------------------------------------
Property, plant and
equipment 967,786 85,685 - 1,053,471
-------------------------------------------------------------------------
Goodwill 103,676 - - 103,676
-------------------------------------------------------------------------
Capital expenditures 36,724 3,512 - 40,236
-------------------------------------------------------------------------
Total assets $1,543,740 $179,630 $- $1,723,370
-------------------------------------------------------------------------
(1) Intersegment transactions are eliminated on consolidation.
-------------------------------------------------------------------------
(Canadian dollar
in thousands) Canada USA
-------------------------------------------------------------------------
Inter-
segment
Six months ended Oil and Gas Refining Elimin-
June 30, 2010 Upstream Downstream ation(1) Total
-------------------------------------------------------------------------
Net revenues $113,142 $145,577 $(7,643) $251,076
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts 9,161 (676) - 8,485
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings (loss) (617) - - (617)
-------------------------------------------------------------------------
Interest and other income 63 57 - 120
-------------------------------------------------------------------------
Finance charges 25,938 13 - 25,951
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 31,797 4,846 - 36,643
-------------------------------------------------------------------------
Income tax provision
(recovery) (5,205) (2,156) - (7,361)
-------------------------------------------------------------------------
Net earnings (loss) (24,914) (2,666) - (27,580)
-------------------------------------------------------------------------
Property, plant and
equipment 1,287,360 86,636 - 1,373,996
-------------------------------------------------------------------------
Goodwill 103,676 - - 103,676
-------------------------------------------------------------------------
Capital expenditures 175,190 2,398 - 177,588
-------------------------------------------------------------------------
Total assets $1,533,759 $179,362 $- $1,713,121
-------------------------------------------------------------------------
Six months ended
June 30, 2009
-------------------------------------------------------------------------
Net revenues $84,294 $102,246 $(3,472) $183,068
-------------------------------------------------------------------------
Gain (loss) on risk
management contracts (22,266) - - (22,266)
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings 1,139 - - 1,139
-------------------------------------------------------------------------
Interest and other income 791 383 - 1,174
-------------------------------------------------------------------------
Finance charges 17,676 361 - 18,037
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 29,323 3,664 - 32,987
-------------------------------------------------------------------------
Income tax provision
(recovery) (5,361) (1,147) - (6,508)
-------------------------------------------------------------------------
Net earnings (loss) (5,238) (1,640) - (6,878)
-------------------------------------------------------------------------
Property, plant and
equipment 967,786 85,685 - 1,053,471
-------------------------------------------------------------------------
Goodwill 103,676 - - 103,676
-------------------------------------------------------------------------
Capital expenditures 97,723 6,768 - 104,491
-------------------------------------------------------------------------
Total assets $1,543,740 $179,630 $- $1,723,370
-------------------------------------------------------------------------
(1) Intersegment transactions are eliminated on consolidation.
11. FINANCE CHARGES
-------------------------------------------------------------------------
Three months ended Six months ended
(Canadian dollar in thousands) June 30 June 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Interest expense on long-term
debt $25,031 $21,217 $50,410 $42,423
-------------------------------------------------------------------------
Amortization of transaction
costs on revolving credit
facility 209 225 327 739
-------------------------------------------------------------------------
Bank charges and other fees 642 136 642 897
-------------------------------------------------------------------------
25,882 21,578 51,379 44,059
-------------------------------------------------------------------------
Less: Interest capitalized
(note 11.1) (12,660) (12,701) (25,428) (26,022)
-------------------------------------------------------------------------
Finance charges - net $13,222 $8,877 $25,951 $18,037
-------------------------------------------------------------------------
11.1 Interest on the First Lien Senior Notes and interest on that
portion of the Second Lien Senior Notes which has been used to fund the
construction of the Algar project continued to be capitalized during its
construction and pre-operating phases.
12. SUPPLEMENTARY CASH FLOW INFORMATION
-------------------------------------------------------------------------
Three months ended Six months ended
(Canadian dollar in thousands) June 30 June 30
-------------------------------------------------------------------------
2010 2009 2010 2009
-------------------------------------------------------------------------
Interest paid $33,237 $36,805 $47,237 $37,532
-------------------------------------------------------------------------
Income taxes paid $73 $19 $178 $1,363
-------------------------------------------------------------------------
13. INVESTMENT IN PETROLIFERA PETROLEUM LIMITED
In April 2010, Petrolifera closed a public offering of 23,678,500 common
shares at a price of $0.85 per common share for gross proceeds of
$20.1 million (the "Offering"). The company did not subscribe for shares
in the Offering and accordingly, the company's equity interest in
Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in
the ownership interest resulted in a dilution loss of $4.2 million for
the three and six months ended June 30, 2010.
For further information: Richard A. Gusella, Chairman and Chief Executive Officer, or Peter D. Sametz, President and Chief Operating Officer, or Grant D. Ukrainetz, Vice President, Corporate Development, Phone: (403) 538-6201, Fax: (403) 538-6225, [email protected], Website: connacheroil.com
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