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Connacher is a growing exploration, development and production company with a focus on producing bitumen and expanding its in-situ oil sands projects located near Fort McMurray, Alberta
Message: NEWS
Connacher reports strong second quarter 2009 earnings, buoyed by foreign exchange gains; Positive upstream and downstream results; Finances strengthened; Algar construction progressing favorably; Drilling of Algar SAGD well pairs underway
Last Update: 8/12/2009 3:07:00 PM
CALGARY, Aug. 12, 2009 (Canada NewsWire via COMTEX) -- Connacher Oil and Gas Limited (CLL-TSX) made substantial progress during the second quarter of 2009 ("Q2 2009"). Strong earnings were achieved, buoyed by foreign exchange gains and much improved upstream and downstream operating results, compared to the prior quarter ("Q1 2009"). Including the value of intercompany sales of diluent to our Great Divide Pod One ("Pod One"), our refining division earned a net margin of $3.5 million, or seven percent in the quarter. Year-to-date ("YTD" or "YTD 2009"), our refining margin totaled approximately $6 million on sales of approximately $102 million or approximately six percent. We remain optimistic about third quarter 2009 ("Q3 2009") refining results due to anticipated strong asphalt sales, although we do have a planned refinery turnaround in September 2009. Our upstream division recorded much improved results over the difficult prior quarter. As a consequence we had positive cash flow from operations before changes in non-cash working capital and other ("cash flow") which more than offset negative cash flow in Q1 2009.
Our focus in the reporting period was on strengthening our financial condition to be positioned to reactivate our Algar project, which we have done successfully. We are making good progress in our plant construction and recently initiated drilling of the 17 steam-assisted gravity drainage ("SAGD") well pairs now planned on three drilling pads with two modern rigs. We continue to post pictures of our progress on our website on the cover page at www.connacheroil.com as we count down our progress to completion of the plant and related facilities.
We remain optimistic about our outlook as we continue our rampup of bitumen production at Pod One, which averaged 6,284 bbl/d in the second quarter. Our production rampup has been held back, in part arising from the decision to curtail production earlier in the year, as a result of the installation of four electrical submersible pumps ("ESP") in the second quarter and because of a number of anomalous operating issues. We continue to target bitumen production rampup to near design capacity later in 2009, after completion of a mini-plant turnaround and anticipate installation of additional ESP's. We remain focused on our long term goal of developing and producing 50,000 bbl/d of bitumen by 2015.
These Q2 2009 results will be subject to a Conference Call event at 9:00 a.m. MDT August 13, 2009. To listen to or participate in the live conference call please dial either (416) 644-3426 or (800) 731-5774. A replay of the event will be available from August 13, 2009 at 11:00 p.m. MT until August 20, 2009 at 11:59 p.m. MT. To listen to the replay please dial either (416) 640-1917 or (877) 289-8525 and enter the passcode 21311159 followed by the pound sign.
OVERVIEW
The overall operating environment for the Canadian crude oil and natural gas industry improved during the second quarter of 2009, as crude oil prices were considerably stronger than during the prior reporting period ("Q1 2009"), although they remained much below levels realized one year ago. However, the recent strength in crude oil prices was offset by a decline in natural gas prices, which were considerably weaker than during the prior quarter and last year. While the impact of a stronger Canadian dollar on our revenues in Q2 2009 muted some of the benefit of increased oil prices, it favorably impacted the carrying cost of our U.S. dollar-denominated debt, resulting in substantial unrealized foreign exchange gains for the period.
Both upstream and downstream netbacks were stronger and contributed to improved financial results in Q2 2009. A strong third quarter 2009 ("Q3 2009") is anticipated in the downstream division from the realization of high priced asphalt sales, which were slower than expected due to poor weather conditions for paving activity.
Positive cash flow was achieved after two quarters of negative cash flow, which had resulted from the collapse of energy prices. Earnings were strong in Q2 2009, due to a significant foreign exchange gain and almost offset the adverse effects of a weakening Canadian dollar in Q1 2009. Despite this improvement, 1H 2009 results remained below those achieved in the same period in 2008, primarily due to the collapse of energy prices on a comparative basis.
Our emphasis during Q2 2009 and YTD 2009 (or "1H 2009") was on restoring Connacher's overall financial strength and liquidity, which had been adversely impacted upon since year end 2008 by the weakness in commodity prices and their impact on operating and financial results; the effect of our decision to reduce bitumen production to minimize losses at Pod One in late 2008 and early 2009, when prices were low and heavy oil differentials were very high; normal seasonal weakness in our downstream refining division; and our decision in Q1 2009 to cancel our credit facilities aggregating in excess of $200 million. These developments, when combined with negative first quarter cash flow, a responsible but controlled outlay of cash for capital projects and a reduction in accounts payable, together with debt servicing requirements, had reduced our cash balances and meant that our ability to be able to restore and complete the Algar project, with confidence, required more corporate liquidity.
Fortunately, Connacher was able to access equity and debt markets in Q2 2009 and raised total net proceeds of $370 million, which added the requisite liquidity and positioned the company to restore its growth profile. Subsequent to closing both our equity and debt issues, we were able to announce the resumption of construction at Algar, our second 10,000 bbl/d steam-assisted gravity drainage project. Our ability to access capital markets and to attract a high level of sponsorship from significant institutional investors underscored the attractiveness of Connacher's growth prospects and the ongoing long-term appeal of the oil sands sector.
Our equity issue was a fully-marketed deal, allowing existing shareholders to participate through the investment dealer syndicate if they elected to do so. While the size of the issue resulted in a discount to the prevailing market, its success enabled us to successfully place and realize improved pricing for our new long-term debt offering.
Our new bond issue, which matures in 2014 and does not require principal repayments until that time, was well received and was also largely acquired by recognized long-term investors. This added capital was secured without exposing the company and its operations to a myriad of problematic maintenance covenants. We continue to negotiate the terms of a follow-on revolving bank credit facility to further enhance our total corporate financial flexibility.
Our liquidity runway was extended as a consequence of this financing activity and this gave us the confidence to conclude we could reactivate Algar, supported by the improvement in crude oil markets from the devastating lows experienced in late 2008.
Algar is now proceeding favorably and we anticipate completing the plant and related SAGD horizontal well pairs by approximately April, 2010. Thereafter, we envisage approximately one month to commission the plant, followed by approximately three months of steaming of the well pairs, with a view to first bitumen production at Algar by mid-summer 2010 and ramping up thereafter, to near plant capacity by late 2010 or early 2011. At that time, our bitumen production should be approximately double or more than what it is today. We believe there are few if any other Canadian companies that have this visibility of solid, predictable and near-term production growth ahead of them. We hope to double it again in the ensuing two-three years, once our Environmental Impact Assessment ("EIA") is approved and we realize more of the established productive potential from our oil sands properties in the Divide region of northeast Alberta ("Great Divide"). We continue to adhere to our target of 50,000 bbl/d of bitumen production by 2015.
Highlights of the second quarter and first half of 2009 were as follows:
-
$370 million of new equity and debt capital raised; liquidity runway
extended
-
Algar project reinstated in early July 2009
-
Improved financial and operating results achieved during Q2 2009
-
Pod One rampup continues with lower operating costs and improving
netbacks
Summary Results
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Three months ended June 30
Six months ended June 30
-------------------------------------------------------------------------
%
%
2009
2008
Change
2009
2008
Change
-------------------------------------------------------------------------
FINANCIAL ($000
except per share
amounts)
Revenues, net
of royalties
100,219
202,016
(50)
161,976
302,672
(46)
Cash flow(1)
9,570
20,550
(53)
4,878
28,375
(83)
Per share,
basic(1)
0.04
0.10
(60)
0.02
0.14
(86)
Per share,
diluted(1)
0.03
0.10
(70)
0.02
0.13
(85)
Net earnings
(loss)
39,966
6,683
489
(6,878)
4,850
(255)
Per share,
basic (loss)
0.15
0.03
400
(0.03)
0.02
(250)
Per share,
diluted (loss)
0.14
0.03
367
(0.03)
0.02
(250)
Property and
equipment
additions
40,236
80,403
(50)
104,491
196,388
(47)
Cash on hand
401,160
232,704
72
Working capital
455,001
234,110
94
Long term debt
960,593
684,705
40
Shareholders'
equity
622,235
479,477
30
Total assets
1,723,370 1,338,705
29
UPSTREAM
OPERATING RESULTS
Daily production/
sales volumes
Bitumen -
bbl/d(2)
6,284
6,123
3
6,227
3,948
58
Crude oil -
bbl/d
1,114
981
14
1,147
988
16
Natural gas -
Mcf/d
12,144
14,220
(15)
12,484
12,356
1
Barrels of oil
equivalent
- boe/d(3)
9,421
9,474
(1)
9,455
6,996
35
Product pricing(4)
Bitumen -
$/bbl(2)
40.95
60.80
(48)
31.84
59.05
(46)
Crude oil -
$/bbl
54.87
105.28
(48)
47.07
92.29
(49)
Natural gas -
$/Mcf
3.35
10.02
(67)
4.13
9.08
(55)
Barrels of oil
equivalent -
$/boe(3)
38.11
65.25
(42)
32.13
62.41
(49)
DOWNSTREAM
OPERATING RESULTS
Refining
throughput -
crude charged
- bbl/d
9,145
9,329
(2)
8,012
9,580
(16)
Refinery
utilization (%)
96
98.2
(2)
84
100.8
(17)
Margins (%)
5
(0.1)
5,100
6
0.2
2,900
COMMON SHARES
OUTSTANDING (000)
Weighted average
Basic
266,425
210,658
26
239,008
210,446
14
Diluted
286,985
214,530
34
239,008
213,324
12
End of period
Issued
403,546
211,027
91
Diluted
439,890
250,522
76
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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 net earnings. Cash flow, commonly used in the oil
and gas industry, is reconciled with net earnings on the Consolidated
Statements of Cash Flows and in the accompanying Management's
Discussion & Analysis. 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) The recognition of bitumen sales from Great Divide Pod One commenced
March 1, 2008, when it was declared "commercial". Prior thereto, all
operating costs, net of revenues, were capitalized.
(3) 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.
(4) Product pricing excludes realized financial derivative gains/losses
and unrealized mark-to-market non-cash accounting gains/losses.
Operating conditions improved for the Canadian oil industry during Q2 2009 as crude oil prices improved considerably. Our conventional oil prices were up 38 percent from Q1 2009 to $54.87 per barrel. Our bitumen selling prices almost doubled to $40.95 per barrel compared to Q1 2009. Also, in June 2009 our crude oil prices were at their highest level of the year at $65.56 per barrel for our quality of conventional crude oil sales and at $50.29 per barrel of bitumen, net of diluent and transportation charges.
This strength in crude oil pricing was particularly important to Connacher, as we are highly leveraged to crude oil prices and their impact on our valuation and our operating results. However, like all producers, we also felt the adverse effect of weak natural gas prices, which were only about 45 percent of 1H 2008 levels at $4.13/mcf, when compared to $9.08/mcf last year. Fortunately, these lower prices contributed to lower bitumen operating costs as Connacher is substantially indifferent to natural gas price levels, in that we consume approximately the same amount of natural gas as the company's current production levels. This underscores the importance of the integrated strategy we adopted for our oil sands business several years ago.
Improved overall prices enabled Connacher to record positive Q2 2009 improvements in our upstream production netbacks, which were almost triple those recorded in our Q1 2009 reporting period. While these remain below the much stronger levels achieved in 1H 2008, when product pricing per barrel of oil equivalent ("boe") was almost 50 percent higher than that achieved YTD 2009, the direction and rate of improvement during Q2 2009 was discernible.
As overall capital market and industry operating conditions remained quite volatile, our 1H 2009 results did not fully capture the improved pricing impact as a consequence of crude oil hedging programs put in place on a portion of our production during the dark days of early 2009. These hedges were designed to protect Connacher against continuing operating losses from production, had crude oil prices further deteriorated below or remained at the very low levels realized in December 2008. At that time, WTI had declined to the U.S.$34/bbl level and heavy oil price differentials were as high as $22/bbl, resulting in negative wellhead bitumen prices, before operating costs. Obviously, hedging to enhance the probability of positive netbacks from production made sense at the time. We will continue to manage our risk profile utilizing timely and advantageous derivative programs during periods of high capital expenditures, as we have a leveraged balance sheet.
We are pleased to report that both our upstream and downstream divisions recorded positive netbacks during the Q2 2009 and, in particular, the upstream results more than offset negative recorded netbacks in Q1 2009. We also can report that our cash flow from operations before working capital and other changes ("cash flow") was much stronger in Q2 2009 and more than offset the negative cash flow of Q1 2009.
Earnings were also significantly improved in Q2 2009, primarily arising from unrealized foreign exchange gains on the translation of our U.S. dollar-denominated debt, resulting from a stronger Canadian dollar. These unrealized gains more than offset unrealized foreign exchange losses sustained in Q1 2009. As a result, we had earnings of $40 million in Q2 2009 and recorded a modest loss for the first half of 2009. Again, these results were below last year due to substantially lower commodity price levels in the current year.
Restoring Liquidity and Growth
Our major activity during Q2 2009 was to restore our corporate liquidity so we could again focus on growth. Since year end 2008, our cash balances were reduced from approximately $224 million and would have declined to approximately $31 million at June 30, 2009, had we not secured new sources of funding for the company.
Accordingly, this would not have allowed us to reinstate Algar without new funding, especially as we had cancelled our $200 million plus credit facility in Q1 2009. We had counted on this funding being available to complete Algar when we earlier advised we had the requisite funds for completions.
Shareholders have asked where the cash was invested or spent so we are happy to elaborate. During Q1 2009, we had capital expenditure outlays of $64 million, financed operations to the extent of $5 million and used $59 million of cash for working capital purposes, including paying down our accounts payable and financing our asphalt and other inventory buildups in our downstream operation. This reduced our March 31, 2009 cash balances to $96 million. Our capital outlays of $40 million in Q2 2009, combined with further financing of working capital to the extent of $41 million was offset by $6 million in foreign exchange gains on U.S. dollar cash balances and cash flow of $9.6 million, but our liquidity was strained.
Because we had approximately $150 million of stranded capital already invested in Algar and because we could not realize on this significant investment and restore growth to the company without new funding, a decision was made to raise cash funds to be able to proceed with Algar, with the certainty we would have sufficient funds to complete while still meeting our financial obligations and carrying the project through commissioning, steaming, startup and rampup until Algar could begin to contribute higher levels of production and resultant operating income and be recorded in our accounts.
We were able to access the equity markets during Q2 2009 and raised $164 million of net proceeds through an underwritten marketed sale of common equity from treasury. While we attempted to secure the highest possible price for this issue, market conditions dictated a clearing price of $0.90 per common share to raise the amount of capital we felt we needed to achieve our financing objectives. It resulted in the issuance of 192 million shares, bringing our total shares outstanding to 403 million. As a marketed deal which occurred over several days, all of our shareholders (except management and directors) had the opportunity, if they chose to exercise it, to participate in the financing through their broker/dealers. Regrettably, regulators precluded "insider" participation (specifically management and directors), despite the indicated willingness of certain of these individuals to acquire shares in support of the transaction and the expressed preference by prospective institutional buyers for insider participation and support of the financing. Several insiders did subsequently acquire shares in public markets at higher prices as a result of this regulatory decision, indicating their continuing financial commitment to the growth and potential of the company.
At the time of the equity financing, we had hoped to be able to secure new bank financing in the form of a construction loan and revolving working capital facility to have the desired certainty of funding before proceeding with the reinstatement of Algar. Unfortunately suitable terms for a construction loan were not forthcoming and accordingly we opted to access the high yield bond market with the successful issuance of U.S.$200 million of first lien senior secured notes. This issue was placed with a strong contingent of long-term institutional buyers and has since traded at a premium to the issue price of 93.678%. The notes have an 11.75% coupon and mature on July 15, 2014. No principal payments are required in the intervening period. Net proceeds received were $206 million at the time of closing of the debt transaction.
As a result of these two successful financings, Connacher not only secured an expanded body of shareholders and noteholders with indicated long-term investment objectives, but also was able to announce it was reinstating the Algar project, reactivating the construction of its cogeneration project and undertaking the building of a dilbit sales transfer line from Algar to Pod One, while strengthening its working capital position and overall corporate liquidity.
We are now underway with construction at Algar and also should shortly commence the drilling of the SAGD horizontal well pairs in order to be completed within the approximate 275 day completion timetable established by the company. We are regularly posting a slide show on our website at www.connacheroil.com to demonstrate our progress at Algar and we have a countdown clock to indicate our commitment to a timely completion of the project. We will need cooperation from the weather to achieve our objective. Also, where we can, we are attempting to secure improved costing of the balance of the project, recognizing that many long lead items were built throughout 2008 after we had established the original funding for the project.
The deterioration in industry conditions, cancellation of our $200 million plus credit facilities in Q1 2009, delays necessitated by the extreme economic and capital market uncertainty, weak commodity prices and the burden of ongoing financial obligations, including a significant reduction in accounts payable from approximately $100 million to approximately $47 million, while also funding $104 million of capital expenditures in the first half of 2009, were behind the capital raising decisions. This was the only viable manner by which we could have liberated the significant stranded capital already invested in the Algar project. Our timing was fortuitous, as since we completed our financing activity, commodity prices and capital markets have been volatile, suggesting we would have been hard pressed to enter these markets at a later date than needed. Also, the successful equity issue enabled us to successfully place and secure better pricing and terms for our long-term first lien notes.
We now have an extended liquidity "runway", with no maintenance covenants. We are operating with the certainty that our money is in the bank and not subject to second-guessing by bank credit committees or the vagaries of the credit markets, which remain extremely tight and expensive. We are nearing conclusion of our negotiations to secure satisfactory terms and conditions for a follow-on revolving bank credit facility, which if completed would give us increased financial flexibility for our normal course business activities, including the issuance of letters of credit and hedging transactions to manage corporate risk.
It is gratifying to be able to again focus on growth and progress. We believe our assets are well-situated and of high quality and we are confident in our plan going forward from here. We are advancing our EIA for further development of our Great Divide reserves to an interim production level of 44,000 bbl/d of bitumen, representing a further 24,000 bbl/d beyond Pod One and Algar. We hope to have the EIA approved in 2011, so that we can proceed to expand to the 44,000 bbl/d level by approximately 2013, followed by a further jump to 50,000 bbl/d of bitumen by 2015.
We anticipate a significant improvement in the contribution to our overall results from our downstream activities during Q3 2009, as the impact of high priced asphalt sales and generally better economic conditions assist this portion of our integrated business activity. Asphalt sales were generally hampered by cold and wet weather in Montana and Alberta during Q2 2009, which delayed road paving activities. As at June 30, 2009 we had over 430,000 barrels of asphalt in inventory, the majority of which had been contracted for sale at prices in excess of U.S.$100 per barrel. We will be conducting a scheduled turnaround at the Montana refinery during September 2009, but will continue our aggressive asphalt sales from inventory during that period.
Our upstream conventional activity remains quiet but stable as we await indications of better natural gas markets to follow up on capturing already-identified productive capacity. This would enable us to retain our natural gas self-sufficiency quotient within our business model, timed to meeting Algar start-up requirements.
During Q2 2009, bitumen production at Pod One averaged approximately 63 percent of plant capacity. Production was affected by a number of minor planned and unplanned interruptions. Power outages at the Pod One plant, failure of a flare stack and unplanned evaporator maintenance all contributed to a reduction in bitumen production during the quarter. Also we now have installed five electric submersible pumps ("ESP's") which are contributing to lower steam-oil ratios ("SOR's") and are also helping to lower operating costs at a time when our focus is on optimization. This process has also been assisted by lower natural gas prices and we have recently lowered unit operating costs at Pod One to under $15 per barrel of bitumen. In July 2009, we converted two new SAGD well pairs from the steam circulation phase to full production, which will positively impact our bitumen production ramp-up. Our Q3 2009 objective is to achieve steady state production at Pod One and gradually move our plant utilization to 90 percent or better later this year. We have a minor turnaround scheduled at Pod One in September 2009, lasting between two days and four days. This will modestly impact on average daily production levels.
Our working capital at June 30, 2009 totaled $455 million including $401 million of cash. This underscored our preparedness for Algar and we anticipate being able to manage any issues that might come our way until Algar comes on stream. Our revised full year capital budget for Connacher for 2009 is now $325 million, which will be financed from these cash balances and from cash flow. The prize is the potential to more than double our bitumen production by late 2010 or early 2011.
The cost to complete Algar, excluding capitalized items and contingencies, is estimated to be $360 million. Savings arising from remaining activities occurring in a more "normalized" construction and labour environment have been offset by minor scope changes to the project and the decision to drill and complete two additional SAGD well pairs at Algar, bringing the total SAGD well pairs to 17, to ensure effective exploitation of the reservoir.
In addition, to recognize unplanned events that often occur during a major construction project and to factor unpredictable and often severe weather that can occur in northern Alberta, management has added a $15 million contingency to the Algar budget, bringing the total cost for Algar, excluding capitalized items, to $375 million of which $128 million was incurred pre-2009, $175 million is estimated to be incurred in 2009 and the $72 million balance is forecast to be incurred in 2010.
We look forward to delivering these results to you. We welcome our new shareholders and appreciate the strong vote of confidence given to us in moving ahead with our programs, as evidenced by the success of our recent financings. We also appreciate the continuing support of all of our shareholders as we work our way through these difficult but exciting times to achieve our goals. We welcome Ms. Jennifer Kennedy, Mr. Peter Sametz and Mr. Kelly Ogle as newly elected Directors and note the appointment of Ms. Rashi Sengar, a partner of Macleod Dixon, as Connacher's Corporate Secretary.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is dated as of August 12, 2009 and should be read in conjunction with the unaudited consolidated financial statements of Connacher Oil and Gas Limited ("Connacher" or the "company") for the six months ended June 30, 2009 and 2008 as contained in this interim report and the MD&A and audited consolidated financial statements for the years ended December 31, 2008 and 2007, as contained in the company's 2008 annual report. All of these consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. This 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 is 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, and cash operating netback. 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 is a useful financial measurement which assists in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow 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. Cash flow and cash operating netbacks are reconciled to net earnings within this MD&A.
FORWARD-LOOKING INFORMATION
This report, including the Letter to Shareholders, contains forward-looking information including but not limited expectations of future production, refinery utilization rates and asphalt demand, future refined product sales volumes and selling prices, netbacks, net operating income, liquidity and cash flow, profitability and capital expenditures, operating margins, anticipated reductions in operating costs as a result of optimization of certain operations, development of additional oil sands resources (including Algar and the timeline and capital costs for construction of Algar), timing and duration of the planned refinery turnaround, development of internally-generated growth prospects, utilization and alternative financial derivative strategies to protect the company's cash flow and plans for improving liquidity which may include securing a new banking credit facility, corporate acquisitions or business combinations, joint venture arrangements and restructuring components of the balance sheet. 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; 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, 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 current financial crisis has resulted in severe economic uncertainty and resulting 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. There can be no assurance that the company will be able to continue to secure sources of liquidity. These and other risks and uncertainties are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2008, 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 are expressly qualified in their entirety by this cautionary statement. The forward-looking information included in this report is made as of August 12, 2009 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.
SUMMARIZED HIGHLIGHTS
Three months ended
Six months ended
June 30
June 30
2009
2008
2009
2008
-------------------------------------------------------------------------
FINANCIAL
($000)
Upstream revenues, net
of royalties
$
33,882
$
83,483
$
62,028
$
111,409
Downstream revenues
69,094
117,820
102,246
189,719
Upstream cash operating
netback(1)
12,893
30,857
17,894
45,113
Downstream margin
3,483
(106)
5,915
400
Cash flow
9,570
20,550
4,878
28,375
Net earnings (loss)
39,966
6,683
(6,878)
4,850
Cash on hand
401,160
232,704
Working capital
455,001
234,110
Total assets
1,723,370
1,338,705
OPERATING
Upstream production/
sales volumes
Oil sands - bitumen
- bbl/d
6,284
6,123
6,227
3,948
Crude oil - bbl/d
1,114
981
1,147
988
Natural gas - Mcf/d
12,144
14,220
12,484
12,356
Barrels of oil
equivalent - boe/d
9,421
9,474
9,455
6,996
Upstream cash
netback/boe(1)
$
15.04
$
35.79
$
10.46
$
35.43
Downstream
Crude charged - bbl/d
9,145
9,329
8,012
9,580
Downstream margin per
barrel refined
$
4.05
$
(0.09) $
4.25
$
0.21
Downstream margins as
a percentage of
revenue - %
5
(0.1)
6
-
-------------------------------------------------------------------------
(1) Excluding unrealized non-cash mark-to-market accounting losses.
MARKETING - UPSTREAM
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 or other end users at either spot reference prices or at prices subject to commodity contracts based on U.S. WTI for crude oil and AECO for natural gas. As a means of managing the risk of commodity price volatility, Connacher enters into financial derivative commodity price-hedging contracts from time to time.
At August 12, 2009, Connacher had the following WTI crude oil price-hedging contracts in place:
-
February 1, 2009 - August 31, 2009 - 2,500 bbl/d - WTI
U.S.$46.00/bbl;
-
April 1, 2009 - December 31, 2009 - 2,500 bbl/d - WTI U.S.$49.50/bbl;
and
-
September 1, 2009 - December 31, 2009 - 2,500 bbl/d - minimum of WTI
U.S.$60.00/bbl and a maximum of WTI U.S.$84.00/bbl.
As at June 30, 2009, the WTI crude oil forward price curve exceeded the hedging contract prices resulting in a current liability and an unrealized mark-to-market ("MTM") non-cash accounting loss of $16.5 million for these contracts. For the year to date, realized losses on these contracts totalled $5.7 million. These losses are included in upstream revenues.
Additionally, in order to mitigate foreign exchange exposure to commodity pricing, Connacher entered into a foreign exchange revenue collar which throughout 2009 sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of CAD$1.30 per U.S.$1.00 on a notional amount of U.S.$10 million of monthly production revenue. For clarity, this contract provides the company a benefit from a strengthening Canadian dollar. As at June 30, 2009, based on the forward foreign exchange rate curve, the foreign exchange revenue collar had a value of $3.1 million; at December 31, 2008 it had a value of $1.8 million. The change in these values resulted in an unrealized non-cash foreign exchange gain of $1.3 million in the first half of 2009. Additionally, in the first half of 2009, Connacher realized a hedging gain (and received cash) in the amount of $1.1 million on this contract. These gains are included in foreign exchange gains/losses.
During the first half of 2009, Connacher also entered into a six-month term contract for the sale of dilbit to a company operating a bitumen upgrader in northern Alberta.
MARKETING - DOWNSTREAM
Sales of refined products are generally made on monthly sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel and diesel and construction contractors and road builders for asphalt. Occasionally, sales contracts are for periods in excess of one month. To date, Connacher has not hedged these revenue streams. As at June 30, 2009, the Montana refinery had contracts in place for the sale of approximately 250,000 barrels of asphalt at an average price exceeding U.S.$100/bbl for delivery in the third quarter of 2009.
PRICING
Together with many other uncontrolled variables, general economic conditions and international and local supplies influence the price for WTI light gravity crude oil. Weather, domestic supplies and other variables influence the market price for natural gas.
In the first half of 2009, WTI crude oil averaged U.S.$51.57/bbl (first half 2008 - U.S.$110.94/bbl) and AECO natural gas averaged $4.64/Mcf (first half 2008 - $8.24/Mcf).
Connacher's crude oil and bitumen production slate is generally heavier than the referenced WTI. Consequently, the market price realized by the company is typically lower than WTI.
Before hedging gains and unrealized MTM non-cash accounting losses, Connacher realized the following commodity selling prices:
Six months ended June 30
2009
2008
-------------------------------------------------------------------------
Bitumen - $/bbl
$
31.84
$
59.05
Crude oil - $/bbl
47.07
92.29
Natural gas - $/Mcf
4.13
9.08
-------------------------------------------------------------------------
Refined product selling prices are also influenced by general economic
conditions and local and international supply and demand factors. Average
prices realized by the company in the first half of 2009 are noted below.
MRCI Realized
Six months ended June 30, 2009 (U.S.$/bbl)
Selling Price
-------------------------------------------------------------------------
Gasoline
$
59.94
Diesel
63.91
Jet fuel
75.27
Asphalt
56.72
-------------------------------------------------------------------------
FINANCIAL AND OPERATING REVIEW
UPSTREAM NETBACKS ($000)
For the three months
ended June 30, 2009
Oil Sands(1)
Crude Oil
Natural Gas
Total
-------------------------------------------------------------------------
Gross revenues(2)
$
40,571
$
5,649
$
3,697
$
49,917
Diluent purchased(3)
(14,669)
-
-
(14,669)
Transportation costs
(2,487)
(88)
-
(2,575)
-------------------------------------------------------------------------
Production revenue
23,415
5,561
3,697
32,673
Realized financial
derivative losses(4)
(6,161)
-
-
(6,161)
Unrealized mark-to-
market losses(5)
(8,243)
-
-
(8,243)
Royalties
(89)
(1,431)
(111)
(1,631)
Operating costs
(8,459)
(949)
(2,580)
(11,988)
-------------------------------------------------------------------------
Calculated netback
$
463
$
3,181
$
1,006
$
4,650
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses(6)
$
8,706
$
3,181
$
1,006
$
12,893
-------------------------------------------------------------------------
For the three months
ended June 30, 2008
Oil Sands(1)
Crude Oil
Natural Gas
Total
-------------------------------------------------------------------------
Gross revenues(2)
$
68,087
$
9,397
$
12,968
$
90,452
Diluent purchased(3)
(31,272)
-
-
(31,272)
Transportation costs
(2,934)
-
-
(2,934)
-------------------------------------------------------------------------
Production revenue
33,881
9,397
12,968
56,246
Realized financial
derivative losses(4)
-
-
(402)
(402)
Unrealized mark-to-
market losses(5)
-
-
(1,217)
(1,217)
Royalties
(374)
(2,730)
(2,246)
(5,350)
Operating costs
(16,281)
(810)
(2,546)
(19,637)
-------------------------------------------------------------------------
Calculated netback
$
17,226
$
5,857
$
6,557
$
29,640
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses(6)
$
17,226
$
5,857
$
7,774
$
30,857
-------------------------------------------------------------------------
For the six months
ended June 30, 2009
Oil Sands(1)
Crude Oil
Natural Gas
Total
-------------------------------------------------------------------------
Gross revenues(2)
$
69,242
$
9,926
$
9,337
$
88,505
Diluent purchased(3)
(28,036)
-
-
(28,036)
Transportation costs
(5,324)
(158)
-
(5,482)
-------------------------------------------------------------------------
Production revenue
35,882
9,768
9,337
54,987
Realized financial
derivative losses(4)
(5,756)
-
-
(5,756)
Unrealized mark-to-
market losses(5)
(16,510)
-
-
(16,510)
Royalties
(219)
(2,493)
(1,499)
(4,211)
Operating costs
(19,790)
(2,251)
(5,085)
(27,126)
-------------------------------------------------------------------------
Calculated netback
$
(6,393) $
5,024
$
2,753
$
1,384
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses(6)
$
10,117
$
5,024
$
2,753
$
17,894
-------------------------------------------------------------------------
For the six months
ended June 30, 2008
Oil Sands(1)
Crude Oil
Natural Gas
Total
-------------------------------------------------------------------------
Gross revenues(2)
$
85,237
$
16,603
$
20,417
$
122,257
Diluent purchased(3)
(39,375)
-
-
(39,375)
Transportation costs
(3,428)
-
-
(3,428)
-------------------------------------------------------------------------
Production revenue
42,434
16,603
20,417
79,454
Realized financial
derivative losses(4)
-
-
(402)
(402)
Unrealized mark-to-
market losses(5)
-
-
(2,033)
(2,033)
Royalties
(460)
(4,545)
(3,408)
(8,413)
Operating costs
(19,684)
(1,870)
(3,972)
(25,526)
-------------------------------------------------------------------------
Calculated netback
$
22,290
$
10,188
$
10,602
$
43,080
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses(6)
$
22,290
$
10,188
$
12,635
$
45,113
-------------------------------------------------------------------------
(1) In the first quarter of 2008, Connacher completed the conversion of a
majority of its fifteen horizontal well pairs to production status at
Great Divide Pod One and processed increasing levels of bitumen
through its facility. This provided the company with the necessary
confidence that this first oil sands project could economically
produce, process and sell bitumen on a continuous basis. Therefore,
effective March 1, 2008 Connacher declared it to be "commercial". As
a result, the company discontinued the capitalization of all pre-
operating costs, moved accumulated capital costs into the full cost
pool, commenced the depletion of these costs, and began reporting Pod
One production and operating results as part of the oil and gas
reporting segment. The above tables, therefore, do not include
operating results prior to March 1, 2008.
(2) Bitumen produced at Great Divide 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
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.
(3) Diluent volumes purchased and sold have been deducted in calculating
production revenue and production volumes sold.
(4) Realized financial derivative gains/losses reflect cash
receipts/disbursements in respect of financial derivative commodity
price-hedging contracts.
(5) Unrealized mark-to-market accounting gains/losses reflect changes in
the market value of unsettled commodity price derivative contracts.
From period to period the market value of these contracts change due
to the volatility of the commodity's forward pricing curve.
(6) Cash operating netbacks, by product, are calculated by deducting the
related diluent, transportation, field operating costs and royalties
from revenues before deducting MTM accounting gains/losses. Netbacks
on a per-unit basis are calculated by dividing related production
revenue, costs and royalties 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
For the three months ended June 30
2009
2008
% Change
-------------------------------------------------------------------------
Dilbit sales - bbl/d(1)
8,517
8,403
1
Diluent purchased - bbl/d(1)
(2,233)
(2,280)
(2)
-------------------------------------------------------------------------
Bitumen produced and sold - bbl/d(1)
6,284
6,123
3
Crude oil produced and sold - bbl/d
1,114
981
14
Natural gas produced and sold - Mcf/d
12,144
14,220
(15)
-------------------------------------------------------------------------
Total - boe/d
9,421
9,474
(1)
-------------------------------------------------------------------------
For the six months ended June 30
2009
2008
% Change
-------------------------------------------------------------------------
Dilbit sales - bbl/d(1)
8,524
5,424
57
Diluent purchased - bbl/d(1)
(2,297)
(1,476)
56
-------------------------------------------------------------------------
Bitumen produced and sold - bbl/d(1)
6,227
3,948
58
Crude oil produced and sold - bbl/d
1,147
988
16
Natural gas produced and sold - Mcf/d
12,484
12,356
1
-------------------------------------------------------------------------
Total - boe/d
9,455
6,996
35
-------------------------------------------------------------------------
(1) Since declaring Great Divide Pod One "commercial" effective March 1,
2008.
UPSTREAM NETBACKS PER UNIT OF PRODUCTION
For the three months
Bitumen
Crude Oil
Natural Gas
Total
ended June 30, 2009
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue
$
40.95
$
54.87
$
3.35
$
38.11
Realized financial
derivative losses
(10.78)
-
-
(7.19)
Unrealized mark-to-
market losses
(14.41)
-
-
(9.61)
Royalties
(0.16)
(14.12)
(0.10)
(1.90)
Operating costs
(14.79)
(9.37)
(2.33)
(13.98)
-------------------------------------------------------------------------
Calculated netback
$
0.81
$
31.38
$
0.92
$
5.43
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses
$
15.22
$
31.38
$
0.92
$
15.04
-------------------------------------------------------------------------
For the three months
ended June 30, 2008
-------------------------------------------------------------------------
Production revenue
$
60.80
$
105.28
$
10.02
$
65.25
Realized financial
derivative losses
-
-
(0.31)
(0.47)
Unrealized mark-to-
market losses
-
-
(0.94)
(1.41)
Royalties
(0.67)
(30.58)
(1.74)
(6.21)
Operating costs
(29.22)
(9.07)
(1.97)
(22.78)
-------------------------------------------------------------------------
Calculated netback
$
30.91
$
65.63
$
5.06
$
34.38
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses
$
30.91
$
65.63
$
6.00
$
35.79
-------------------------------------------------------------------------
For the six months
Bitumen
Crude Oil
Natural Gas
Total
ended June 30, 2009
($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue
$
31.84
$
47.07
$
4.13
$
32.13
Realized financial
derivative losses
(5.11)
-
-
(3.36)
Unrealized mark-to-
market losses
(14.65)
-
-
(9.65)
Royalties
(0.19)
(12.01)
(0.66)
(2.46)
Operating costs
(17.56)
(10.84)
(2.25)
(15.85)
-------------------------------------------------------------------------
Calculated netback
$
(5.67) $
24.22
$
1.22
$
0.81
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses
$
8.98
$
24.22
$
1.22
$
10.46
-------------------------------------------------------------------------
For the six months
ended June 30, 2008
-------------------------------------------------------------------------
Production revenue
$
59.05
$
92.29
$
9.08
$
62.41
Realized financial
derivative losses
-
-
(0.18)
(0.32)
Unrealized mark-to-
market losses
-
-
(0.90)
(1.60)
Royalties
(0.64)
(25.28)
(1.52)
(6.61)
Operating costs
(27.39)
(10.40)
(1.77)
(20.05)
-------------------------------------------------------------------------
Calculated netback
$
31.02
$
56.61
$
4.71
$
33.83
-------------------------------------------------------------------------
Cash operating netback,
excluding unrealized
mark-to-market
accounting losses
$
31.02
$
56.61
$
5.61
$
35.43
-------------------------------------------------------------------------
In response to a collapse in crude oil prices and widening of heavy oil differentials, the company announced in December 2008 that it was curtailing production at Pod One from levels that had exceeded 9,000 bbl/d earlier in that month, through the reduction of steam to be injected into the bitumen reservoir. On January 21, 2009, the company announced the resumption of full production ramp-up at Pod One in anticipation of the reinstatement of profitability at Pod One, as a result of improved product prices; in response to narrower heavy oil pricing differentials; reduced transportation costs; anticipated reduced diluent blending ratios due to increased dilbit sales to upgraders operating near our SAGD oil sands facility; and due to WTI crude oil hedges entered into that provided some protection against further weakness in selling prices. Bitumen production is gradually ramping up to design capacity from curtailed bitumen production levels of approximately 4,200 bbl/d in January 2009.
In the second quarter of 2009, bitumen, crude oil, and natural gas revenues were down 45 percent to $49.9 million from $90.5 million in the second quarter of 2008. This was due to bitumen and crude oil prices being 48 percent lower and natural gas prices being 67 percent lower than the comparative period.
For the same reasons, year to date upstream revenues were $33.7 million lower than in the first six months of 2008 ($88.5 million compared to $122.2 million).
Second quarter 2009 upstream revenues were, however, 29 percent higher than first quarter 2009 upstream revenues ($49.9 million compared to $38.6 million) as commodity prices moderately improved.
Royalties represent charges against production or revenue by governments and landowners. Royalties in the second quarter of 2009 were $1.6 million compared to $5.4 million in the second quarter of 2008 and royalties for the first six months of 2009 were $4.2 million compared to $8.4 million in the first half of 2008. From year to year, 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. The most notable change in royalties this year came as a result of reduced product pricing.
In the second quarter of 2009, upstream diluent purchases of $14.7 million (year to date $28.0 million) were required for our oil sands operations. Diluent purchases for the second quarter of 2009 include $3 million ($3.5 million year to date) of diluent purchased from our subsidiary, Montana Refining Company, Inc. in the netback calculations, above. These intercompany purchases have been eliminated on consolidation and for financial statement presentation purposes. There were no intercompany purchases in the prior year periods. Bitumen produced at Great Divide is mixed with purchased diluent and sold as "dilbit". Diluent is a light hydrocarbon that improves the marketing and transportation quality of bitumen. For the reported volumes, diluent purchased represented approximately 26 percent of the dilbit barrel sold, with bitumen the remaining 74 percent. It is anticipated that less diluent will be necessary when oil sands production and handling operations are optimized and higher volumes are processed.
Field operating costs of $12.0 million in the second quarter were substantially lower than $19.6 million reported in the second quarter of 2008 as a result of our concerted efforts to reduce costs and optimize our production processes.
Oil sands field operating costs of $8.5 million in the second quarter averaged $14.79 per barrel of bitumen produced, and was approximately one half the per barrel cost last year. Although lower natural gas costs contributed, reductions in other cost components were also realized from our optimization strategy.
Transportation costs of $2.6 million in the second quarter of 2009 were slightly lower than the $2.9 million recorded in the prior year comparative period due to successful marketing arrangements in selling similar volumes to closer markets.
Realized financial derivative losses and unrealized MTM non-cash accounting losses were sustained in the current year as a result of commodity prices being higher than our commodity price contracts. These losses are included in our reported revenues on our Statements of Operations.
Netbacks are a widely used industry measure of a company's efficiency and its ability to internally fund its growth. The company's overall second quarter 2009 upstream netback of $15.04 per produced boe (a 58 percent decrease over the same 2008 period due to lower commodity prices) was significantly influenced by its oil sands production, which had a netback of $15.22 per bitumen barrel produced.
RECONCILIATION OF UPSTREAM OPERATING NETBACK TO NET EARNINGS
For three months
ended June 30
2009
2008
-------------------------------------------------------------------------
($000, except per
unit amounts)
Total
Per boe
Total
Per boe
-------------------------------------------------------------------------
Upstream netback,
as above
$
4,650
$
5.43
$
29,640
$
34.38
Refining margin - net
3,483
4.06
(106)
(0.12)
Interest income
246
0.29
713
0.83
General and administrative
(3,224)
(3.77)
(2,911)
(3.38)
Stock-based compensation
(551)
(0.64)
(1,181)
(1.37)
Finance charges
(8,877)
(10.35)
(10,298)
(11.94)
Foreign exchange
(loss) gain
65,411
76.30
(3,317)
(3.85)
Depletion, depreciation
and accretion
(16,538)
(19.29)
(13,825)
(16.04)
Income taxes
(5,490)
(6.40)
(1,033)
(1.20)
Equity interest in
Petrolifera earnings
and dilution gain
856
1.00
9,001
10.44
-------------------------------------------------------------------------
Net earnings
$
39,966
$
46.63
$
6,683
$
7.75
-------------------------------------------------------------------------
For the six months
ended June 30
2009
2008
-------------------------------------------------------------------------
($000, except per
unit amounts)
Total
Per boe
Total
Per boe
-------------------------------------------------------------------------
Upstream netback
as above
$
1,384
$
0.81
$
43,080
$
33.83
Refining margin - net
5,915
3.46
400
0.31
Interest income
1,174
0.69
1,544
1.21
General and administrative
(7,698)
(4.50)
(5,977)
(4.69)
Stock-based compensation
(1,821)
(1.06)
(2,697)
(2.12)
Finance charges
(18,037)
(10.54)
(14,729)
(11.57)
Foreign exchange
(loss) gain
37,545
21.94
(5,209)
(4.09)
Depletion, depreciation
and accretion
(32,987)
(19.28)
(21,289)
(16.72)
Income taxes
6,508
3.80
313
0.25
Equity interest in
Petrolifera earnings
and dilution gain
1,139
0.67
9,414
7.39
-------------------------------------------------------------------------
Net earnings (loss)
$
(6,878) $
(4.01) $
4,850
$
3.80
-------------------------------------------------------------------------
DOWNSTREAM REVENUES AND MARGINS
Operations at the Montana refinery are subject to a number of seasonal factors which typically cause product sales revenues to vary throughout the year. The refinery's primary asphalt market is for paving roads, which is predominantly a summer demand. Consequently, prices and sales 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 months. Seasonal factors also affect sales revenues for gasoline (higher demand in summer months) as well as distillate and diesel fuels (higher winter demand). As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.
Refinery throughput -
June 30,
Sept 30,
Dec 31, March 31,
June 30,
three months ended
2008
2008
2008
2009
2009
-------------------------------------------------------------------------
Crude charged (bbl/d)(1)
9,329
9,239
8,333
6,867
9,145
Refinery production
(bbl/d)(2)
10,052
10,284
9,075
7,946
10,438
Sales of produced
refined products
(bbl/d)
12,274
11,897
6,404
5,290
9,222
Sales of refined
products (bbl/d)(3)
12,878
12,385
7,564
5,890
9,451
Refinery utilization(4)
98%
97%
88%
72%
96%
-------------------------------------------------------------------------
(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 feedstocks.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
refinery.
During the first quarter of 2009, the U.S.$20 million ultra low sulphur diesel project was completed at the Montana refinery. Due to down time required to tie-in the new hydrogen plant to complete this project and as a result of certain operational upsets due to significant cold weather, throughput volumes were lower in the fourth quarter of 2008 and the first half of 2009 than in prior quarters. The Montana refinery is now producing and selling ultra low sulphur diesel and gasoline.
Second quarter 2009 refining revenues ($69.1 million) more than doubled first quarter 2009 revenues ($33.2 million) but were still well below the level realized in the second quarter of 2008 ($117.8 million), when refined selling prices and sales volumes were much higher. Due to lower refined product selling prices, downstream revenues for the six months ended June 30, 2009 of $102.2 million were significantly less than the $189.7 million reported in the first six months of 2008. Downstream revenues and refining margins noted in the tables, below, include intersegment diluent sales of $3 million in the second quarter of 2009 and $3.5 million for the year to date 2009, which have been eliminated on consolidation for financial statement presentation purposes. There were no intersegment sales in the prior year periods.
Increased processing throughput and sales volumes and higher selling prices occurred in the second quarter of 2009, compared to the first quarter 2009 when processing downtime and the seasonality of our downstream business unit occurred. Higher volumes and prices led to improved refining revenues and operating margins. General economic conditions also affect refined product demand and pricing and we anticipate will continue to influence our financial results in the future.
Notwithstanding lower current year sales volumes and pricing, year to date downstream margins were higher in the first half of 2009 ($5.9 million, or 6 percent) compared to the first six months of 2008 ($400,000 or 0.2 percent), as crude oil input costs have come down faster than selling prices have been reduced.
We anticipate a significant improvement in the contribution to our overall results from our downstream activities during Q3 2009, as the impact of high priced asphalt sales and generally better economic conditions assist this portion of our integrated business activity. Asphalt sales were generally hampered by cold and wet weather in Montana and Alberta during Q2 2009, which delayed road paving activities. As at June 30, 2009 we had over 430,000 barrels of asphalt in inventory, the majority of which had been contracted for sale at prices in excess of U.S.$100 per barrel. We will be conducting a scheduled turnaround at the Montana refinery during September 2009, but will continue our aggressive asphalt sales from inventory during that period.
Feedstocks -
June 30,
Sept 30,
Dec 31,
Mar 31,
June 30,
three months ended
2008
2008
2008
2009
2009
-------------------------------------------------------------------------
Sour crude oil
93%
93%
94%
91%
91%
Other feedstocks and blends
7%
7%
6%
9%
9%
-------------------------------------------------------------------------
Total
100%
100%
100%
100%
100%
-------------------------------------------------------------------------
Revenues and Margins
($000)
-------------------------------------------------------------------------
Refining sales revenue
$117,820
$127,726
$ 56,803
$ 33,152
$ 69,094
Refining - crude oil
and operating costs
117,926
125,455
66,964
30,720
65,611
-------------------------------------------------------------------------
Refining margin
$
(106) $
2,271
$(10,161) $
2,432
$
3,483
-------------------------------------------------------------------------
Refining margin
(0.1%)
1.8%
(17.9%)
7%
5%
-------------------------------------------------------------------------
Sales of Produced Refined
Products (Volume %)
-------------------------------------------------------------------------
Gasolines
32%
35%
44%
55%
48%
Diesel fuels
11%
19%
25%
22%
11%
Jet fuels
5%
5%
8%
7%
7%
Asphalt
48%
38%
19%
12%
31%
LPG and other
4%
3%
4%
4%
3%
-------------------------------------------------------------------------
Total
100%
100%
100%
100%
100%
-------------------------------------------------------------------------
Per Barrel of Refined
Product Sold
-------------------------------------------------------------------------
Refining sales revenue
$ 100.54
$ 112.10
$
81.62
$
62.54
$
80.34
Less: refining - crude
oil purchases and
operating costs
100.63
110.10
96.23
57.95
76.29
-------------------------------------------------------------------------
Refining margin
$
(0.09) $
2.00
$ (14.61) $
4.59
$
4.05
-------------------------------------------------------------------------
INTEREST AND OTHER INCOME
In the second quarter of 2009, the company earned interest of $246,000 (second quarter June 30, 2008 - $713,000; 2009 year to date - $699,000; 2008 year to date - $1.5 million) on excess funds invested in secure short-term investments and realized a gain of $475,000 on the repurchase of U.S.$660,000 (face value) of Second Lien Notes in the first quarter of 2009.
GENERAL AND ADMINISTRATIVE EXPENSES
In the second quarter of 2009, general and administrative ("G&A") expenses were $3.2 million compared to $2.9 million in the second quarter of 2008, an increase of 11 percent, reflecting increased staffing and activity levels. Additionally, G&A of $1.1 million was capitalized in the second quarter of each of 2009 and 2008.
For the first six months of 2009, G&A expenses were $7.7 million compared to $6 million in the first six months of 2008, after capitalizing $2.6 million in the first half of 2009 and $3 million in the first half of 2008.
FINANCE CHARGES
Finance charges include interest expense relating to the Convertible Debentures, standby fees associated with the company's undrawn lines of credit, which we cancelled in March 2009, fees on letters of credit issued and a portion of the Second Lien Senior Notes interest attributable to Great Divide Pod One since it was declared commercial, effective March 1, 2008. 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.
Finance charges of $8.9 million in the second quarter of 2009 were $1.4 million lower than the 2008 comparative period, as the prior year period included a non-cash mark-to-market charge on our cross-currency interest rate swap then in place. No such charge applied in 2009, as the cross-currency swap was unwound in the fourth quarter of 2008 for an $89 million net cash gain.
Year to date finance charges of $18 million are $3.3 million higher than the 2008 comparative period as a result of not capitalizing interest to the Pod One project since declaring it "commercial" on March 1, 2008 and due to interest charges on higher debt levels, since issuing the First Lien Senior Notes in mid-June 2009.
We continued to capitalize interest to our Algar project for that portion of our debt attributed to the project.
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)
2009
2008
2009
2008
-------------------------------------------------------------------------
Charged to G&A expense
$
551
$
1,181
$
1,821
$
2,697
Capitalized to property
and equipment
114
224
507
1,022
-------------------------------------------------------------------------
$
665
$
1,405
$
2,328
$
3,719
-------------------------------------------------------------------------
The reduction from the prior period is due to fewer options being granted in the current year.
FOREIGN EXCHANGE GAINS AND LOSSES
Over the past few months, the value of the Canadian dollar has strengthened relative to the U.S. dollar. This has had a significant impact to Connacher upon translating its U.S. dollar denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes.
In 2009, we had unrealized foreign exchange translation gains of $61.5 million in the second quarter and $33.6 million for the year to date. We also realized foreign exchange gains of $3.9 million in the second quarter and in the year to date 2009 from the foreign exchange revenue collar and upon the settlement of U.S. dollar denominated obligations.
Throughout most of 2008 we had a cross-currency swap in place to hedge one-half of the foreign exchange exposure on our U.S. dollar debt. This insulated us from some foreign currency volatility and reduced the impact of a weaker Canadian dollar, which resulted in the unrealized foreign exchange translation losses reported in the comparative 2008 periods.
Having unwound the cross-currency swap in the fourth quarter of 2008 for a net cash gain of $89 million, Connacher is now fully exposed to changes in the U.S.: Canadian dollar exchange rate when translating its U.S. dollar debt to Canadian dollars for financial reporting purposes and for purposes of paying U.S. denominated interest and repaying such indebtedness. To mitigate some of this exposure, the company may put into place another cross-currency swap in the future.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
Depletion expense is calculated using the unit-of-production method based on total estimated proved reserves. Refining properties and other assets are depreciated over their estimated useful lives. Effective March 1, 2008 Pod One's accumulated capital costs were added to the depletion pool and have been depleted from that date. DD&A in the second quarter of 2009 was $16.5 million, and for the first six months of 2009 was $33 million. These charges are 20 percent and 55 percent higher, respectively, than the 2008 comparative periods, reflecting a full six months of depletion on Pod One capital costs in 2009. Depletion equates to $16.28 per boe of production year to date compared to $13.43 per boe in the 2008 comparative period.
Future development costs of $1.3 billion (2008 - $999 million) for proved undeveloped reserves were included in the year to date depletion calculation. Capital costs of $369 million (2008 - $193 million) related to oil sands projects currently in the pre-production stage and undeveloped land acquisition costs of $12.2 million (2008 - $14.0 million) were excluded from the depletion calculation.
Included in year to date DD&A is an accretion charge of $981,000 (2008 - $845,000) in respect of the company's estimated asset retirement obligations. These charges will continue in future years in order to accrete the currently booked discounted liability of $27.7 million to the estimated total undiscounted liability of $48.2 million over the remaining economic life of the company's oil sands, crude oil and natural gas properties.
At June 30, 2009, the recoverable value of the company's productive crude oil, oil sands and natural gas assets and its major development projects significantly exceeded their carrying values and, therefore, no ceiling test write-down was required.
INCOME TAXES
The income tax recovery of $6.5 million in the first six months of 2009 includes a current income tax provision of $293,000, principally related to Canadian capital and other taxes and a future income tax recovery of $6.8 million reflecting the benefit of increased tax pools during the period.
At June 30, 2009 the company had approximately $233 million of non-capital losses which expire between 2010 and 2028, $610 million of deductible resource pools and $33 million of deductible financing costs. The future income tax benefit of these have been recognized at June 30, 2009. Additionally, the company had $32 million of capital losses available to reduce capital gains in future. These capital losses have no expiry date and their future income tax benefit has not been recognized, due to uncertainty of their realization at June 30, 2009.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA") AND
DILUTION GAINS
In June 2008, Petrolifera issued an additional 4.4 million common shares to raise $40 million. Connacher did not subscribe for any of these shares. Consequently, Connacher's equity interest in Petrolifera was reduced from 26 percent to 24 percent. However, the financing resulted in a dilution gain of $8 million, which was recognized by Connacher in the second quarter of 2008.
Connacher accounts for its 24 percent equity investment in Petrolifera under the equity method of accounting. Connacher's share of Petrolifera's earnings in the first six months of 2009 was $1.1 million (six months ended June 30, 2008 - $1.4 million). In the second quarter of 2009, Connacher's share of Petrolifera's earnings was $856,000 (second quarter 2008 - $935,000).
NET EARNINGS
In the second quarter of 2009, the company reported earnings of $40 million ($0.15 per basic and $0.14 per diluted share outstanding) compared to earnings of $6.7 million ($0.03 per basic and diluted share outstanding) in the second quarter of 2008.
In the first six months of 2009, the company reported a loss of $6.9 million ($0.03 loss per basic and diluted share outstanding) compared to earnings of $4.9 million or $0.02 per basic and diluted share for the first six months of 2008.
Explanations for the period to period fluctuations are included in the narrative above, by earnings component.
SHARES OUTSTANDING
For the first six months of 2009, the weighted average number of common shares outstanding was 239,007,899 (2008 - 210,446,291) and the weighted average number of diluted shares outstanding, as calculated by the treasury stock method, was 239,007,899 (2008 - 213,324,122).
As at August 11, 2009, the company had the following equity securities issued and outstanding:
-
403,567,309 common shares;
-
15,362,784 share purchase options; and
-
489,292 share units under the non-employee director share awards
plan.
Additionally, 20,002,800 common shares are issuable upon conversion of the Convertible Debentures. Details of the exercise provisions and terms of the outstanding options are noted in the consolidated financial statements, included in this interim report.
LIQUIDITY AND CAPITAL RESOURCES
At June 30, 2009, the company had working capital of $455 million, including $401 million of cash on hand of which $10 million was segregated to collateralize letters of credit. These balances reflect the receipt of net proceeds from the recently completed common share equity issuance and the First Lien Senior Note financing.
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 $172.6 million.
On June 16, 2009 the company issued U.S.$200 million face value of 11.75 percent First Lien Senior Secured Notes (the "First Lien Senior Notes") at a price of 93.678 percent for gross proceeds of U.S.$187.4 million. The First Lien Senior Notes are not repayable until July 15, 2014 and are secured on a first priority basis (subject to specified liens up to U.S.$50 million for prior ranking senior debt) by liens on all of the company's assets, excluding Connacher's investment holding in Petrolifera. The company is currently in discussions with its banker to put in place a U.S.$30 - U.S.$50 million revolving banking facility which would rank in priority to the First Lien Senior Notes.
Proceeds from the equity and First Lien Senior Note financings, net of issuance costs, were approximately $370 million. These funds were raised for working capital and general corporate purposes, including to fund the remaining costs associated with the construction of Algar, the company's second 10,000 bbl/d SAGD oil sands project and the drilling and completion of the associated SAGD well pairs.
As the company has no principal debt repayment obligations until June 2012, management believes that the company has sufficient liquidity to complete the Algar project, to fund its ongoing capital program and to satisfy its financial obligations.
The financial crisis has severely reduced liquidity in capital and bank markets. Economic uncertainty and significant volatility in commodity markets and stock markets have also occurred around the world. Connacher's share price and the trading value of its Second Lien Senior Notes and Convertible Debentures have been adversely affected by the uncertainty of future crude oil and natural gas prices, as well as by the impact of anticipated new environmental regulations, which could affect the economics of our business. Notwithstanding the challenges imposed by this crisis and current economic conditions, management believes that the company has attractive internally-generated growth prospects which, with our cash balances and the impact of an improvement in commodity prices, will allow us to expand our operations. In the interim, however, lower world oil prices are expected to result in lower per unit revenues, netbacks, cash flow and earnings. We anticipate increasing production and sales volumes throughout 2009, which could partially offset the impact of lower world commodity prices.
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 continues to assess alternative hedging strategies to protect the company's cash flow from the risk of potentially lower crude oil and refined product pricing and adverse exchange rate fluctuations. Although the company's integrated business model provides some protection, it does not provide a perfect hedge. The purpose of any such hedge(s) would be to ensure sufficient cash flow to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in a volatile and weak commodity price and weakened economic environment.
In order to mitigate foreign exchange exposure to commodity pricing, the company entered into a foreign exchange revenue collar which throughout 2009 sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of CAD$1.30 per U.S.$1.00 on a notional amount of U.S.$10 million of production revenue per month.
Additionally, in 2009 the company entered into WTI derivatives at crude oil prices of U.S.$46.00/bbl and U.S.$49.50/bbl on two tranches of 2,500 bbl/d of notional production with staggered August 2009 and December 2009 maturities and has put in place a WTI crude oil "collar" contract on a notional volume of 2,500 bbl/d of production from September to December 2009 with a floor of WTI U.S.$60.00/bbl and a ceiling of WTI U.S.$84.00/bbl.
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 net earnings. Cash flow is reconciled with net earnings on the Consolidated Statement of Cash Flows and below.
Reconciliation of net earnings to cash flow from operations before working capital and other changes:
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
2009
2008
2009
2008
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Net earnings (loss)
$
39,966
$
6,683
$
(6,878) $
4,850
Items not involving cash:
Depletion, depreciation
and accretion
16,538
13,825
32,987
21,289
Stock-based compensation
551
1,181
1,821
2,697
Finance charges-non-
cash portion
1,134
4,058
2,175
5,307
Future employee benefits
107
114
294
227
Future income tax
provision (recovery)
5,369
373
(6,801)
(1,790)
Unrealized foreign
exchange (gain) loss
(61,482)
3,317
(33,616)
5,209
Unrealized loss on risk
management contracts
8,243
-
16,510
-
Gain on repurchase of
Second Lien Senior Notes
-
-
(475)
-
Equity interest in
Petrolifera earnings
(856)
(935)
(1,139)
(1,390)
Dilution gain
-
(8,066)
-
(8,024)
-------------------------------------------------------------------------
Cash flow from operations
before changes in non-
cash working capital
and other changes
$
9,570
$
20,550
$
4,878
$
28,375
-------------------------------------------------------------------------
In the second quarter of 2009 cash flow was $9.6 million ($0.04 per basic and $0.03 per diluted share), 53 percent lower than the $20.6 million reported ($0.10 per basic and diluted share) for the second quarter of 2008 and in the first half of 2009 cash flow was $4.9 million ($0.02 per basic and diluted share) compared to cash flow of $28.4 million ($0.14 per basic and $0.13 per diluted share) reported in the first half of 2008. The primary reason for lower reported cash flows in 2009 compared to 2008 was lower commodity selling prices for each of our upstream and downstream business segments, as noted in the detailed explanations of our business activities, above.
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.
The company's only financial instruments are cash, restricted cash, accounts receivable and payable, amounts due from Petrolifera, the Convertible Debentures, and the First and Second Lien Senior Notes. The company maintains no off-balance sheet financial instruments.
As the First and Second Lien Senior Notes are denominated in U.S. dollars, there is a foreign exchange risk associated with their semi-annual interest payments and the repayment of their principal balances in 2014 and 2015, using Canadian currency. The next semi-annual interest payment of U.S.$43 million is due in December 2009.
Connacher's capital structure is composed of:
As at
As at
June 30,
December 31,
2009
2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Long term debt(1)
$
960,593
$
778,732
Shareholders' equity
Share capital, contributed surplus
and equity component
606,493
437,899
Accumulated other comprehensive
income (loss)
(766)
7,802
Retained earnings
16,508
23,386
-------------------------------------------------------------------------
Total
$
1,582,828
$
1,247,819
-------------------------------------------------------------------------
Debt to book capitalization(2)
61%
62%
Debt to market capitalization(3)
71%
81%
-------------------------------------------------------------------------
(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.
Connacher currently has a high calculated ratio of debt to capitalization. This is due to pre-funding the full cost of Algar. As at June 30, 2009, the company's net debt (long-term debt, net of cash on hand) was $559.4 million and its calculated ratio of net debt to book capitalization was 47 percent and the percentage of its net debt to market capitalization was 59 percent.
FINANCINGS COMPLETED IN 2009
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 net proceeds of $164 million after fees and expenses. The proceeds were raised for working capital and general corporate purposes to fund the company's capital expenditures, including Algar.
To June 30, 2009, the proceeds of the common share issuance have been utilized as follows:
As stated
at the time
As actually
of financing
applied
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Gross proceeds
$
172,586
$
172,586
Underwriters commissions and issue costs
(8,629)
(8,785)
-------------------------------------------------------------------------
Net proceeds for working capital and
general corporate purposes to fund
capital expenditures
$
163,957
$
163,801
-------------------------------------------------------------------------
First Lien Senior Secured Notes
On June 16, 2009 the company issued U.S.$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for net proceeds of $205.6 million after fees and expenses. The proceeds were to be used for working capital and general corporate purposes, including to fund a portion of the remaining construction, drilling and completion costs associated with the construction of Algar.
To June 30, 2009, the proceeds of the First Lien Senior Note financing have been utilized as follows:
As stated
at the time
As actually
of financing
applied
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Gross proceeds
$
226,475
$
226,475
Underwriters commissions and issue costs
(20,875)
(20,858)
-------------------------------------------------------------------------
Net proceeds to be used for working capital
and general corporate purposes, including
to fund a portion of the remaining
construction, drilling and completion costs
associated with the construction of Algar
$
205,600
$
205,617
-------------------------------------------------------------------------
PROPERTY AND EQUIPMENT EXPENDITURES
Property and equipment expenditures totaled $40.2 million in the second
quarter of 2009 and $104.5 million year to date. A breakdown of these
expenditures together with prior year comparatives follows.
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
($000)
2009
2008
2009
2008
-------------------------------------------------------------------------
Oil sands, crude oil and
natural gas expenditures
$
36,724
$
75,475
$
97,723
$ 188,432
Refinery expenditures
3,512
4,928
6,768
7,956
-------------------------------------------------------------------------
$
40,236
$
80,403
$ 104,491
$ 196,388
-------------------------------------------------------------------------
In the second quarter of 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 our co-generation and transfer pipeline facilities; and $13 million of interest and G&A costs were capitalized.
For the year to date, $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 ESP's 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.
Refinery capital costs in the second quarter and year to date for 2009 were primarily directed to the completion and tie-in of our new hydrogen plant to complete our ultra-low sulphur diesel project.
Oil sands, crude oil and natural gas capital costs of $75.5 million in the second quarter of 2008 were comprised of preliminary facility expenditures and costs incurred for long lead-order equipment items for the Algar project, truck loading facilities at Pod One, core hole and conventional drilling costs and capitalized interest costs and G&A costs.
For the 2008 year to date, oil sands and conventional exploration expenditures totaled $70 million, Algar facility and equipment expenditures totaled $49 million; conventional natural gas facilities totaled $12 million; Pod One trucking facility and capitalized pre-operating costs totaled $20 million and capitalized interest, G&A and other expenditures totaled $37 million.
Most of the 2008 capital expenditures at our refinery were incurred on the ultra low sulphur diesel conversion project.
Second half 2009 capital expenditures will be focused on Algar.
OUTLOOK
We anticipate that the current general economic conditions and product price volatility will continue to challenge industry profitability and growth in the short-term. However, recent oil price improvements have provided a basis for some investment optimism. Together with the optimization of some of our operational and marketing processes, moderately higher oil prices have contributed to Connacher's improved operating and financial results in the second quarter of 2009.
We continue to anticipate a greater contribution to profitability from our refining operations, primarily due to improved throughput volumes and anticipated healthy asphalt markets, with wider margins, as newly-announced U.S. government infrastructure projects are anticipated to result in an unprecedented demand for asphalt. This improvement is now starting to be apparent. However, the Montana refinery will undergo a scheduled one-month turnaround commencing in mid-September 2009, which will have an adverse effect on throughput and refined product sales volumes later in the year.
We also anticipate improved netbacks from our upstream operations during the balance of 2009, as a result of recent marketing arrangements and anticipated reductions in transportation and operating costs. At Pod One, we surpassed 10,000 bbl/d in April on a test basis and have adopted a more measured ramp-up process to introduce steady state conditions which should allow for better reservoir conformance on a sustained basis.
Four new electric submersible pumps were also installed at Pod One in April 2009. This required the shut-in of the related well pairs for a one week period, which affected average daily production rates in the second quarter of 2009. Two new SAGD well pairs were recently completed at Pod One and have commenced bitumen production. Pod One is currently producing approximately 7,000 bbl/d and we anticipate approaching design capacity of 10,000 bbl/d by year-end 2009.
Our recently completed financings have added significant financial liquidity. Our cash balances, together with anticipated positive operating income in 2009, are anticipated to be sufficient to meet all our financial and capital obligations, including the completion of Algar. Upon the completion of the equity and First Lien Senior Note financings, Connacher's Board of Directors sanctioned the resumption of construction of Algar (which was suspended in December 2008). To date, approximately $162 million has been invested in Algar. The majority of the long-lead equipment items have been built and the roads to the plant site and three well pads have been constructed. We estimated that it would require approximately 275 days from the re-start of the project in early July 2009, to completion of the project. Algar is expected to begin contributing to operating results in late 2010 or early 2011.
The cost to complete Algar, excluding capitalized items and contingencies, is estimated to be $360 million. Savings arising from remaining activities occurring in a more "normalized" construction and labour environment have been offset by minor scope changes to the project and the decision to drill and complete two additional SAGD well pairs at Algar, bringing the total SAGD well pairs to 17, to ensure effective exploitation of the reservoir.
In addition, to recognize unplanned events that often occur during a major construction project and to factor unpredictable and often severe weather that can occur in northern Alberta, management has added a $15 million contingency to the Algar budget, bringing the total cost for Algar, excluding capitalized items, to $375 million, of which $128 million was incurred pre-2009, $175 million is estimated to be incurred in 2009 and the $72 million balance is forecast to be incurred in 2010. Connacher's revised capital budget for 2009 is as follows:
($ millions)
-------------------------------------------------------------------------
Conventional
$
11
Pod One
24
Algar
175
Algar capitalized items
54
Cogeneration facility, sales transfer lines and EIA
34
Coreholes/seismic
8
Refining
19
-------------------------------------------------------------------------
$
325
-------------------------------------------------------------------------
The revised Pod One budget reflects additional electric submersible pumps and an evaporator condenser to be added in the fall of 2009.
The company's business plan anticipates continued long-term growth with continued increases in revenue and cash flow from our oilsands projects, conventional crude oil and natural gas production and from stable refining operations.
Future-oriented financial projections for the year 2010 have been included in the company's recent corporate presentations. Management believes the assumptions underlying the projections are reasonable, given a U.S.$65/bbl price for crude oil during that year. No changes are currently required to those projections.
Information relating to Connacher, including Connacher's Annual Information Form is on SEDAR at www.sedar.com . See also the company's website at www.connacheroil.com .
NEW SIGNIFICANT ACCOUNTING POLICIES
In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets." The new Section became applicable in 2009 and the company adopted the new standard effective January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062, and did not cause any change to the company's financial statements.
In January 2009, the CICA Emerging Issues Committee ("EIC") issued EIC-173, "Credit risk and the fair value of financial assets and liabilities", which requires that an entity's own credit risk and counterparty credit risk be taken into account in determining the fair value of financial assets and liabilities, including derivative financial instruments. The provisions of EIC-173 apply to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. The adoption of this standard had no material impact on the company's financial statements.
In June 2009, the CICA issued amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures related to the fair value of financial instruments and the liquidity risk associated with financial instruments. The amendments will be effective for annual financial statements for fiscal years ending after September 30, 2009 and are consistent with recent amendments to financial instrument disclosure standards in IFRS. The company will include these additional disclosures in its annual consolidated financial statements for the year ending December 31, 2009.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards ("IFRS") in place of Canadian GAAP for interim and annual reporting purposes for fiscal years beginning on or after January 1, 2011.
We have commenced our IFRS conversion project which consists of four phases: diagnostic; design and planning; solution development; and implementation. Regular reporting is provided to management and to the Audit Committee of the Board of Directors.
We have completed the diagnostic phase, which involved a review of the differences between current Canadian GAAP and IFRS. During this phase we determined that the differences which will have the greatest impact on Connacher's consolidated financial statements relate to accounting for exploration and development activities and property and equipment, impairments of capital assets, asset retirement obligations and the reporting of employee future benefits. Their financial impacts have yet to be quantified. We are currently engaged in the design and planning and the solution development phases of our project. We have identified and documented the high impact areas, including an analysis of financial system impacts and have engaged in ongoing discussions with our external auditors. The impact on our disclosure controls, internal controls over financial reporting and the impact on contracts and lending agreements will also be determined.
In July 2009 the International Accounting Standards Board ("IASB") issued an amendment to IFRS accounting standards in respect of property, plant and equipment as at the date of the initial transition to IFRS which permits issuers currently using the full cost method of accounting, (as described in the CICA Handbook - Accounting Guideline 16 Oil and Gas accounting - Full Cost), 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 retroactive restatement of historic balances to the IFRS basis of accounting. We anticipate using the exemption.
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, 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 exploration, development and production of oil and gas, commodity prices and exchange rates, environmental legislation, changes to royalty and income tax legislation, credit and capital market conditions, credit risk for failure of performance by third parties and other risks and uncertainties described in more detail in Connacher's Annual Information Form filed with securities regulatory authorities.
Reference should be made to Connacher's most recent Annual Information Form for a description of its risk factors. The company's Annual Information Form is available on SEDAR at www.sedar.com .
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 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. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's disclosure controls and procedures at December 31, 2008 and have concluded that the company's disclosure controls and procedures were effective.
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. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company's internal controls over financial reporting at the financial year end of the company and concluded that the company's internal controls over financial reporting is effective at the financial year end of the company for the foregoing purpose.
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 material changes in the company's internal controls over financial reporting were identified during such period that has 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 and production/sales volumes. Significant volatility and declining commodity prices, together with severe economic uncertainty in the fourth quarter of 2008 and the first quarter of 2009 are the primary factors affecting financial results during those quarters. The magnitude of the changes in commodity prices during these periods was unprecedented.
2007
2008
-------------------------------------------------------------------------
Three Months Ended
Sep 30
Dec 31
Mar 31
Jun 30
-------------------------------------------------------------------------
($000 except per share amounts)
Revenues, net of royalties
101,991
83,340
100,656
202,016
Cash flow(1)
10,025
7,083
7,825
20,550
Basic, per share(1)
0.05
0.03
0.04
0.10
Diluted, per share(1)
0.05
0.03
0.03
0.10
Net earnings (loss)
14,589
(840)
(1,833)
6,683
Basic per share
0.07
0.00
(0.01)
0.03
Diluted per share
-
-
-
-
Property and equipment additions
64,006
55,852
115,984
80,403
Cash on hand
754
392,271
323,423
232,704
Working capital surplus
(deficiency)
(19,853)
389,789
287,105
234,110
Term debt
260,606
664,462
671,014
684,705
Shareholders' equity
428,764
480,439
471,559
479,477
Operating Highlights
Upstream: Daily production/
sales volumes
Bitumen - bbl/d(2)
-
-
1,773
6,123
Crude oil - bbl/d
781
752
996
981
Natural gas - Mcf/d
9,413
8,889
10,493
14,220
Equivalent - boe/d(3)
2,350
2,233
4,518
9,474
Product pricing(4)
Bitumen - $/bbl(2)
-
-
53.01
60.80
Crude oil - $/bbl
55.98
56.79
79.50
105.28
Natural gas - $/Mcf
4.70
5.82
7.79
10.02
Selected Highlights - $/boe(3)
Weighted average sales price
37.43
42.29
56.44
65.25
Realized derivative gain (loss)
-
-
-
(0.47)
Royalties
6.32
6.34
7.45
6.21
Operating costs
9.00
13.77
14.32
22.78
Cash operating netback(5)
22.11
22.18
34.67
35.79
Downstream: Refining
Crude charged - bbl/d
9,400
9,610
9,830
9,329
Refining utilization - %
100
101
104
98
Margins - %
15
6
1
(0.1)
Common Share Information
Shares outstanding at end
of period (000)
199,447
209,971
210,277
211,027
Weighted average shares
outstanding for the period
Basic (000)
199,167
204,701
210,234
210,658
Diluted (000)
221,554
220,362
210,234
214,530
Volume traded (000)
70,939
52,198
63,718
107,001
Common share price ($)
High
4.40
4.08
3.94
5.26
Low
3.20
3.31
2.59
3.10
Close (end of period)
4.01
3.79
3.13
4.30
-------------------------------------------------------------------------
2008
2009
-------------------------------------------------------------------------
Three Months Ended
Sept 30
Dec 31
Mar 31
June 30
-------------------------------------------------------------------------
($000 except per share amounts)
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
-
-
-
0.14
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 surplus
(deficiency)
200,177
197,914
120,035
455,001
Term debt
689,673
778,732
803,915
960,593
Shareholders' equity
496,509
469,087
428,276
622,235
Operating Highlights
Upstream: Daily production/
sales volumes
Bitumen - bbl/d(2)
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(3)
9,966
10,341
9,488
9,421
Product pricing(4)
Bitumen - $/bbl(2)
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 - $/boe(3)
Weighted average sales price
66.41
21.73
26.13
38.11
Realized derivative gain (loss)
-
-
0.47
(7.19)
Royalties
4.65
3.19
3.02
1.90
Operating costs
20.41
20.76
17.73
13.98
Cash operating netback(5)
41.35
(2.23)
5.85
15.04
Downstream: Refining
Crude charged - bbl/d
9,239
8,333
6,867
9,145
Refining utilization - %
97
88
72
96
Margins - %
2
(18)
7
5
Common Share Information
Shares outstanding at end
of period (000)
211,182
211,182
211,291
403,546
Weighted average shares
outstanding for the period
Basic (000)
211,093
211,182
211,286
266,425
Diluted (000)
213,174
211,575
211,286
286,985
Volume traded (000)
112,401
110,244
67,387
249,700
Common share price ($)
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
-------------------------------------------------------------------------
(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 net earnings. Cash flow is reconciled with net
earnings on the Consolidated Statement of Cash Flows and in the
applicable Management Discussion & Analysis 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) The recognition of bitumen sales from Great Divide Pod One commenced
March 1, 2008, when it was declared "commercial". Prior thereto, no
production volumes were reported and all operating costs, net of
revenues, were capitalized.
(3) 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.
(4) Product pricing excludes realized hedging gains/losses and excludes
unrealized mark-to-market non-cash accounting gains/losses.
(5) 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 less royalties and
operating costs divided by related production/sales volume. Netbacks
are reconciled to net earnings in the applicable MD&A for the periods
referenced.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30,
December 31,
($000)
2009
2008
-------------------------------------------------------------------------
ASSETS
CURRENT
Cash
$
391,160
$
223,663
Restricted cash (Note 9(c))
10,000
-
Accounts receivable
47,794
20,492
Inventories (Note 5)
52,494
35,993
Income taxes recoverable
14,335
13,875
Prepaid expenses
2,566
2,221
Due from Petrolifera
75
42
-------------------------------------------------------------------------
518,424
296,286
Property and equipment
1,053,471
985,054
Goodwill
103,676
103,676
Investment in Petrolifera
47,799
46,659
-------------------------------------------------------------------------
$
1,723,370
$
1,431,675
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities
$
46,913
$
98,372
Risk management contracts (Note 4(b))
16,510
-
-------------------------------------------------------------------------
63,423
98,372
Long term debt (Note 4(e))
960,593
778,732
Future income taxes
48,591
58,296
Asset retirement obligations (Note 6)
27,727
26,396
Employee future benefits
801
792
-------------------------------------------------------------------------
1,101,135
962,588
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital, contributed surplus and
equity component (Note 7)
606,493
437,899
Retained earnings
16,508
23,386
Accumulated other comprehensive income (loss)
(766)
7,802
-------------------------------------------------------------------------
622,235
469,087
-------------------------------------------------------------------------
$
1,723,370
$
1,431,675
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(Unaudited)
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
($000, except per
share amounts)
2009
2008
2009
2008
-------------------------------------------------------------------------
REVENUES
Upstream, net of
royalties (Note 4(b))
$
33,882
$
83,483
$
62,028
$
111,409
Downstream
66,091
117,820
98,774
189,719
Interest and other income
246
713
1,174
1,544
-------------------------------------------------------------------------
100,219
202,016
161,976
302,672
-------------------------------------------------------------------------
EXPENSES
Upstream - diluent
purchases and operating
costs
23,654
50,909
51,690
64,901
Upstream transportation
costs
2,575
2,934
5,482
3,428
Downstream - crude oil
purchases and operating
costs (Note 5)
65,611
117,926
96,331
189,319
General and administrative
3,224
2,911
7,698
5,977
Finance charges
8,877
10,298
18,037
14,729
Stock-based compensation
(Note 7(b))
551
1,181
1,821
2,697
Foreign exchange loss
(gain) (Note 4(d))
(65,411)
3,317
(37,545)
5,209
Depletion, depreciation
and accretion
16,538
13,825
32,987
21,289
-------------------------------------------------------------------------
55,619
203,301
176,501
307,549
-------------------------------------------------------------------------
Earnings (loss) before
income taxes and
other items
44,600
(1,285)
(14,525)
(4,877)
Current income tax
provision
121
660
293
1,477
Future income tax
provision (recovery)
5,369
373
(6,801)
(1,790)
-------------------------------------------------------------------------
5,490
1,033
(6,508)
(313)
-------------------------------------------------------------------------
Earnings (loss) before
other items
39,110
(2,318)
(8,017)
(4,564)
Equity interest in
Petrolifera earnings
856
935
1,139
1,390
Dilution gain (Note 9(d))
-
8,066
-
8,024
-------------------------------------------------------------------------
NET EARNINGS (LOSS)
$
39,966
6,683
$
(6,878)
4,850
RETAINED EARNINGS,
(DEFICIT) BEGINNING
OF PERIOD
(23,458)
48,156
23,386
49,989
-------------------------------------------------------------------------
RETAINED EARNINGS, END
OF PERIOD
$
16,508
$
54,839
$
16,508
$
54,839
-------------------------------------------------------------------------
EARNINGS PER SHARE
(Note 9(a))
Basic
$
0.15
$
0.03
$
(0.03) $
0.02
Diluted
$
0.14
$
0.03
$
(0.03) $
0.02
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
($000)
2009
2008
2009
2008
-------------------------------------------------------------------------
Net earnings (loss)
$
39,966
$
6,683
$
(6,878) $
4,850
Foreign currency
translation adjustment
(12,999)
(429)
(8,568)
3,080
-------------------------------------------------------------------------
Comprehensive income
(loss)
$
26,967
$
6,254
$
(15,446) $
7,930
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Unaudited)
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
($000)
2009
2008
2009
2008
-------------------------------------------------------------------------
Balance, beginning of
period
$
12,233
$
(10,127) $
7,802
$
(13,636)
Foreign currency
translation adjustment
(12,999)
(429)
(8,568)
3,080
-------------------------------------------------------------------------
Balance, end of period
$
(766) $
(10,556) $
(766) $
(10,556)
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
(Unaudited)
Three months ended
Six months ended
June 30
June 30
-------------------------------------------------------------------------
($000)
2009
2008
2009
2008
-------------------------------------------------------------------------
Cash provided by (used in)
the following activities:
OPERATING
Net earnings (loss)
$
39,966
$
6,683
$
(6,878) $
4,850
Items not involving cash:
Depletion, depreciation
and accretion
16,538
13,825
32,987
21,289
Stock-based compensation
551
1,181
1,821
2,697
Finance charges - non
cash portion
1,134
4,058
2,175
5,307
Employee future benefits
107
114
294
227
Future income tax
provision (recovery)
5,369
373
(6,801)
(1,790)
Unrealized loss on risk
management contracts
8,243
-
16,510
-
Unrealized foreign
exchange loss (gain)
(61,482)
3,317
(33,616)
5,209
Gain on repurchase of
Second Lien Senior Notes
-
-
(475)
-
Equity interest in
Petrolifera earnings
(856)
(935)
(1,139)
(1,390)
Dilution gain (Note 9(d))
-
(8,066)
-
(8,024)
-------------------------------------------------------------------------
Cash flow from operations
before changes in non-
cash working capital
and other changes
9,570
20,550
4,878
28,375
Changes in non-cash
working capital
(Note 9(b))
(26,364)
(12,863)
(50,668)
8,907
Asset retirement
expenditures
(29)
(83)
(133)
(206)
Pension funding
(234)
-
(234)
-
-------------------------------------------------------------------------
(17,057)
7,604
(46,157)
37,076
-------------------------------------------------------------------------
FINANCING
Issue of common shares
(Note 7(a))
172,586
-
172,586
-
Share issue costs
(8,785)
-
(8,785)
-
Exercise of stock options
(Note 7)
160
675
160
692
Issuance of First Lien
Senior Notes
226,475
-
226,475
-
Debt issue costs
(20,858)
-
(20,858)
-
Repurchase of Second
Lien Senior Notes
-
-
(309)
-
Deferred financing costs
-
5
-
(77)
-------------------------------------------------------------------------
369,578
680
369,269
615
-------------------------------------------------------------------------
INVESTING
Acquisition and
development of oil
and gas properties
(39,620)
(73,139)
(102,764)
(187,194)
Decrease (increase) in
restricted cash
-
33,546
(10,000)
30,773
Change in non-cash working
capital (Note 9(b))
(14,155)
(25,249)
(49,523)
(12,849)
-------------------------------------------------------------------------
(53,775)
(64,842)
(162,287)
(169,270)
-------------------------------------------------------------------------
NET INCREASE (DECREASE)
IN CASH
298,746
(56,558)
160,825
(131,579)
Foreign exchange gains
(losses) on U.S. dollar
cash balances held
6,194
(615)
6,672
2,785
CASH, BEGINNING OF PERIOD
86,220
257,489
223,663
329,110
-------------------------------------------------------------------------
CASH, END OF PERIOD
$
391,160
$
200,316
$
391,160
$
200,316
-------------------------------------------------------------------------
Supplementary information - Note 9
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.
FINANCIAL STATEMENT PRESENTATION
The Consolidated Financial Statements include the accounts of Connacher
Oil and Gas Limited and its subsidiaries (collectively "Connacher" or the
"company") and are presented in accordance with Canadian generally
accepted accounting principles. Operating in Canada, and in the U.S.
through its subsidiary, Montana Refining Company, Inc. ("MRCI"), the
company is in the business of exploring, developing, producing, refining
and marketing crude oil, bitumen and natural gas.
2.
SIGNIFICANT ACCOUNTING POLICIES
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as
indicated in the annual audited Consolidated Financial Statements for the
year ended December 31, 2008, except as described in Note 3. The
disclosures provided below do not conform in all respects to those
included with the annual audited Consolidated Financial Statements. The
interim Consolidated Financial Statements should be read in conjunction
with the annual audited Consolidated Financial Statements and the notes
thereto for the year ended December 31, 2008.
3.
NEW ACCOUNTING STANDARDS
In February 2008, the Canadian Institute of Chartered Accountants
("CICA") issued Section 3064, "Goodwill and Intangible Assets", replacing
Section 3062, "Goodwill and Other Intangible Assets". The new Section has
been applied since January 1, 2009. Section 3064 establishes standards
for the recognition, measurement, presentation and disclosure of goodwill
subsequent to its initial recognition and of intangible assets by profit-
oriented enterprises. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062 and, therefore, did
not have any impact on the company's consolidated financial statements.
In January 2009, the CICA Emerging Issues Committee ("EIC") issued EIC-
173, "Credit risk and the fair value of financial assets and
liabilities", which requires that an entity's own credit risk and
counterparty credit risk be taken into account in determining the fair
value of financial assets and liabilities, including derivative financial
instruments. The provisions of EIC-173 apply to all financial assets and
liabilities measured at fair value in interim and annual financial
statements for periods ending on or after January 20, 2009. The adoption
of this standard had no material impact on the company's consolidated
financial statements.
In June 2009, the CICA issued amendments to CICA Handbook Section 3862,
Financial Instruments - Disclosures. The amendments include enhanced
disclosures related to the fair value of financial instruments and the
liquidity risk associated with financial instruments. The amendments will
be effective for annual financial statements for fiscal years ending
after September 30, 2009 and are consistent with recent amendments to
financial instrument disclosure standards in IFRS. The company will
include these additional disclosures in its annual consolidated financial
statements for the year ending December 31, 2009.
Over the next two years the CICA will adopt its new strategic plan for
the direction of accounting standards in Canada, which was ratified in
January 2006. As part of the plan, Canadian GAAP for public companies
will converge with International Financial Reporting Standards ("IFRS")
with an effective date of January 1, 2011. The company continues to
monitor and assess the impact of the convergence of Canadian GAAP with
IFRS.
4.
FINANCIAL INSTRUMENTS AND CAPITAL RISK MANAGEMENT
FINANCIAL INSTRUMENTS
Financial assets and financial liabilities "held-for-trading" are
measured at fair value with changes in those fair values recognized in
net earnings. Financial assets "available-for-sale" are measured at fair
value, with changes in those fair values recognized in Other
Comprehensive Income ("OCI"). Financial assets "held-to-maturity," "loans
and receivables" and "other financial liabilities" are measured at
amortized cost using the effective interest rate method of amortization.
The company has classified all of its financial instruments, with the
exception of the First and Second Lien Senior Notes and the Convertible
Debentures as "held for trading". This classification has been chosen due
to the nature of the company's financial instruments, which, except for
the First and Second Lien Senior Notes and the Convertible Debentures are
of a short-term nature such that there are no material differences
between the carrying values and the fair values.
The First and Second Lien Senior Notes and the Convertible Debentures
have been classified as "other financial liabilities" and are accounted
for on the amortized cost method, with transaction costs being amortized
over the life of the instruments using the effective interest rate
method.
CAPITAL RISK MANAGEMENT
The company is exposed to financial risks on a range of financial
instruments including its cash, accounts receivable and payable, amounts
due from Petrolifera, the Convertible Debentures and the First and Second
Lien Senior Notes.
The company is also exposed to risks 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. These risks affecting the company
are discussed below.
(a) Credit risk
Credit risk is the risk that a contracting entity will not fulfill its
obligations under a financial instrument and cause a financial loss to
the company. To help manage this risk, the company has a policy for
establishing credit limits, requiring collateral before extending credit
to customers where appropriate and monitoring outstanding accounts
receivable. The company's financial assets subject to credit risk arise
from the sale of crude oil, bitumen, natural gas and refined products to
a number of large integrated oil companies and product retailers and are
subject to normal industry credit risks. The fair value of accounts
receivable and accounts payable closely approximates their carrying
values due to the relatively short periods to maturity of these
instruments. The maximum exposure to credit risk is represented by the
carrying amount on the consolidated balance sheet. The company regularly
assesses its financial assets for impairment losses. There are no
material financial assets that the company considers past due and no
allowance for uncollectible accounts is considered necessary.
The majority of the company's upstream revenues are composed of bitumen
sales. Substantially all of the company's bitumen sales were made to two
customers in the first half of 2009.
(b) Market risk
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.
The company is exposed to market risk as a result of potential changes in
the market prices of its crude oil, bitumen, natural gas and refined
product sales volumes.
A portion of this risk is mitigated by Connacher's integrated business
model. The cost of purchasing natural gas for use in its oil sands and
refinery operations is offset by the company's monthly conventional
natural gas sales; and the selling price of the company's dilbit sales
largely equates to the purchase price of heavy crude oil required for
processing at its refinery. Petroleum commodity futures contracts, price
swaps and collars may be utilized to reduce exposure to price
fluctuations associated with the sales of additional natural gas and
crude oil sales volumes and for the sale of refined products.
Risk Management Contracts
In November 2008, Connacher entered into a foreign exchange collar which
sets a floor of CAD$1.1925 per U.S.$1.00 and a ceiling of CAD$1.30 per
U.S.$1.00 on a notional amount of U.S.$10 million of production revenue
per month throughout 2009. At June 30, 2009 the fair value of this
contract was an asset of $3.1 million, which is recorded in accounts
receivable on the consolidated balance sheet. For the year to date, an
unrealized foreign exchange gain of $1.3 million and a realized foreign
exchange gain of $1.1 million was included in the net foreign exchange
gain on the consolidated statement of operations in respect of this
contract. A $0.01 change on the USD/CAD exchange rate would result in a
$500,000 change in the fair value of the collar.
Connacher has entered into derivative contracts to fix the WTI crude oil
price on a portion of its production at a price of U.S.$46.00/bbl on a
notional volume of 2,500 barrels per day until August 31, 2009 and at a
price of U.S.$49.50/bbl on a notional volume of 2,500 bbl/d until
December 31, 2009. On June 30, 2009, Connacher put in place a WTI crude
oil "collar" contract on a notional volume of 2,500 bbl/d of bitumen
production from September 1 to December 31, 2009 with a floor of
U.S.$60.00/bbl and a ceiling of U.S.$84.00/bbl. At June 30, 2009 the fair
value of these derivative contracts was a liability of $16.5 million and
a $16.5 million loss was recorded in upstream revenue on the consolidated
statement of operations for the year to date. A U.S.$1.00 change in WTI
would result in a $815,000 change in the value of the derivatives,
resulting in a similar impact on earnings.
(c) Interest rate risk
Interest rate risk refers to the risk that the fair value or future cash
flows of a financial instrument will fluctuate because of changes in
market interest rates. The company's First and Second Lien Senior Notes
and Convertible Debentures have fixed interest rate obligations and,
therefore, are not subject to changes in variable interest rates.
(d) 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.
As Connacher incurs the majority of its expenditures in Canadian dollars,
it is exposed to the impact of fluctuations in the U.S./Canadian dollar
exchange rate on pricing of its sales of crude oil and bitumen (which are
generally priced by reference to U.S. dollars but settled in Canadian
dollars) and for the translation of its U.S. refining operating results,
its U.S. dollar cash holdings and its U.S. dollar denominated First and
Second Lien Senior Notes to Canadian dollars for financial statement
reporting purposes.
In 2009, we had unrealized foreign exchange translation gains of
$61.5 million in the second quarter and $33.6 million for the year to
date; and we realized foreign exchange gains of $3.9 million in the
second quarter and in the year to date, 2009 from the foreign exchange
revenue collar and upon the settlement of U.S. dollar denominated
obligations.
Throughout most of 2008, we had a cross-currency swap in place to hedge
one-half of the foreign exchange exposure on our U.S. dollar debt. This
insulated us from some foreign currency volatility and reduced the impact
of a weaker Canadian dollar, which resulted in the unrealized foreign
exchange translation losses reported in the comparative 2008 periods.
Relative to the company's U.S. dollar cash balances, its crude oil and
bitumen revenue receivables, and its First and Second Lien Senior Notes,
a $0.01 change in the Canadian dollar exchange rate would have resulted
in a change in net earnings of $5.7 million for the six months ended
June 30, 2009 (six months ended June 30, 2008 - $900,000).
(e) Liquidity risk
Liquidity risk is the risk that the company will not have sufficient
funds to repay its debts and fulfill its financial obligations.
To manage this risk, the company follows a conservative financing
philosophy, pre-funds major development projects, monitors expenditures
against pre-approved budgets to control costs, regularly monitors its
operating cash flow, working capital and bank balances against its
business plan, usually maintains accessible revolving banking lines of
credit and maintains prudent insurance programs to minimize exposure to
insurable losses.
On June 16, 2009, the company issued U.S.$200 million face value of
11.75 percent First Lien Senior Secured Notes (the "First Lien Senior
Notes") at a price of 93.678 percent for gross proceeds of
U.S.$187.4 million. The First Lien Senior Notes are not repayable until
July 15, 2014 and are secured on a first priority basis (subject to
specified liens up to U.S.$50 million for prior ranking senior debt) by
liens on all of the company's assets, excluding Connacher's investment
holding in Petrolifera.
The long-term nature of the company's debt repayment obligations is
structured to be aligned to the long-term nature of its assets. The
Convertible Debentures do not mature until June 30, 2012, unless
converted to common shares earlier and principal repayments are not
required on the First Lien Senior Notes until July 15, 2014 and on the
Second Lien Senior Notes until their maturity date of December 15, 2015.
This affords Connacher the opportunity to deploy its conventional, oil
sands and refining cash flow to fund the development of further expansion
projects over the next few years without having to make principal
payments or raise new capital unless expenditures exceed cash flow and
credit capacity.
At June 30, 2009, the fair values of the Convertible Debentures, the
First Lien Senior Notes and Second Lien Senior Notes were $57 million,
$224 million and $406 million, respectively, based on their quoted market
prices.
As at June 30, 2009, the company's long-term debt was repayable as
follows:
-
Convertible Debentures - June 30, 2012 in the amount of $100,014,000,
unless converted into common shares prior thereto;
-
First Lien Senior Notes - July 15, 2014 in the amount of
U.S.$200 million; and
-
Second Lien Senior Notes - December 15, 2015 in the amount of
U.S.$591.3 million.
Connacher's 13.1 million shares held in Petrolifera, which trade on the
TSX, also provides liquidity, as they have not been collateralized.
Although it is not Connacher's intention to sell these shares in the
foreseeable future, the shareholding provides Connacher an additional
margin of financial flexibility.
(f) Capital risks
Connacher's objectives in managing its cash, debt and equity (its capital
or capital structure) 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 using a number of financial
ratios and industry metrics to ensure its objectives are being met.
Connacher's long-term debt contains no financial or maintenance
covenants.
In March 2009, the company cancelled its Revolving Credit Facility and
put in place a $20 million demand operating banking facility ("the L/C
facility") for the purposes of issuing letters of credit. The L/C
facility is secured by cash of $10 million and a first lien claim on
certain assets of the company and contains no financial or maintenance
covenants. At June 30, 2009, the L/C Facility secured letters of credit
in the amount of $5.9 million.
Connacher's current capital structure and certain financial ratios are
noted below.
As at
As at
June 30,
December 31,
2009
2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Long term debt(1)
$
960,593
$
778,732
Shareholders' equity
Share capital, contributed surplus
and equity component
606,493
437,899
Accumulated other comprehensive
income (loss)
(766)
7,802
Retained earnings
16,508
23,386
-------------------------------------------------------------------------
Total
$
1,582,828
$
1,247,819
-------------------------------------------------------------------------
Debt to book capitalization(2)
61%
62%
Debt to market capitalization(3)
71%
81%
-------------------------------------------------------------------------
(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.
Connacher currently has a high calculated ratio of debt to
capitalization. This is due to pre-funding the full cost of Algar. As at
June 30, 2009, the company's net debt (long-term debt, net of cash on
hand) was $559.4 million and its calculated ratio of net debt to book
capitalization was 47 percent and its net debt to market capitalization
was 59 percent.
5.
INVENTORIES
Inventories consist of the following:
June 30,
December 31,
($000)
2009
2008
-------------------------------------------------------------------------
Crude oil
$
5,572
$
3,433
Other raw materials and unfinished
products(1)
1,860
1,762
Refined products(2)
37,565
18,901
Process chemicals(3)
3,670
8,110
Repairs and maintenance supplies
and other(4)
3,827
3,787
-------------------------------------------------------------------------
$
52,494
$
35,993
-------------------------------------------------------------------------
(1) Other raw materials and unfinished products include feedstocks and
blendstocks, other than crude oil. The inventory carrying value
includes the costs of the raw materials and transportation.
(2) Refined products include gasoline, jet fuels, diesels, asphalts,
liquid petroleum gases and residual fuels. The inventory carrying
value includes the cost of raw materials, transportation and direct
production costs.
(3) Process chemicals include catalysts, additives and other chemicals.
The inventory carrying value includes the cost of the purchased
chemicals and related freight.
(4) Repair and maintenance supplies in crude refining and oil sands
supplies.
Inventories are valued at the lower of cost and net realizable value. At
December 31, 2008, net realizable value was lower than cost and
therefore, net realizable values were used to value most refined
inventory products. At June 30, 2009, the net realizable value of most
refined products was higher than their cost, so average cost was used to
value most refined inventory products. As a result, refined inventory
product values at June 30, 2009 increased from December 31, 2008 by
approximately $11 million and downstream crude oil purchases and
operating costs were lower than they otherwise would have been by
$11 million in the first half of 2009.
Included in downstream crude oil purchases and operating costs for the
three months ended June 30, 2009 was approximately $58 million of
inventory costs (three months ended June 30, 2008 - $110 million) and for
the six months ended June 30, 2009, this amount was approximately
$79 million (six months ended June 30, 2008 - $174 million).
6.
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 oil sands and conventional petroleum and natural gas
properties and facilities.
Six months
Year
ended
ended
June 30,
December 31,
($000)
2009
2008
-------------------------------------------------------------------------
Asset retirement obligations, beginning
of period
$
26,396
$
24,365
Liabilities incurred
483
1,496
Liabilities settled
(133)
(209)
Change in estimated future cash flows
-
(960)
Accretion expense
981
1,704
-------------------------------------------------------------------------
Asset retirement obligations, end of period
$
27,727
$
26,396
-------------------------------------------------------------------------
Liabilities incurred in 2009 have been estimated using a discount rate of
10 percent reflecting the company's credit-adjusted risk free interest
rate given its current capital structure and an inflation rate of two
percent. The company has not recorded an asset retirement obligation for
the Montana refinery 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 to estimate a date
or range of dates for settlement of any asset retirement obligation
related to the refinery.
7.
SHARE CAPITAL, CONTRIBUTED SURPLUS AND EQUITY COMPONENT
Authorized
The authorized share capital comprises the following:
-
Unlimited number of common voting shares
-
Unlimited number of first preferred shares
-
Unlimited number of second preferred shares
Issued
Only common shares have been issued by the company.
Number of
Amount
Shares
($000)
-------------------------------------------------------------------------
Share Capital, December 31, 2008
211,181,815
$
395,023
Issued for cash in public offering(a)
191,762,500
172,586
Issued upon exercise of options in 2009(b)
266,504
160
Assigned value of options exercised in 2009
63
Issued to directors under share award plan(c)
327,623
301
Conversion of debentures(d)
7,200
37
Share issue costs, net of income taxes
(6,489)
-------------------------------------------------------------------------
Share Capital, June 30, 2009
403,545,642
561,681
-------------------------------------------------------------------------
Contributed Surplus, December 31, 2008
26,053
Stock based compensation for share
options in 2009
2,005
Assigned value of options exercised in 2009
(63)
-------------------------------------------------------------------------
Contributed Surplus, June 30, 2009
27,995
-------------------------------------------------------------------------
Equity component of Convertible Debentures,
December 31, 2008
16,823
Conversion of debentures(d)
(6)
-------------------------------------------------------------------------
Equity Component, June 30, 2009
16,817
-------------------------------------------------------------------------
Total Share Capital, Contributed Surplus
and Equity Component
December 31, 2008
437,899
-------------------------------------------------------------------------
June 30, 2009
606,493
-------------------------------------------------------------------------
(a) June 2009 Common Share Issue
In June 2009, the company issued from treasury 191,762,500 common shares
at $0.90 per common share, for gross proceeds of $172.6 million.
(b) Stock Options
A summary of the company's outstanding stock options, as at June 30, 2009
and 2008 and changes during those periods is presented below:
For the six months
ended June 30
2009
2008
-------------------------------------------------------------------------
Weighted
Weighted
Average
Average
Number of
Exercise
Number of
Exercise
Options
Price
Options
Price
-------------------------------------------------------------------------
Outstanding, beginning
of period
16,383,104
$
3.16
17,432,717
$
3.60
Granted
4,375,947
$
0.72
2,743,792
$
3.22
Exercised
(266,504) $
0.60
(946,934) $
0.81
Expired
(4,913,598) $
4.77
(155,782) $
3.85
-------------------------------------------------------------------------
Outstanding, end of
period
15,578,949
$
2.01
19,073,793
$
3.68
-------------------------------------------------------------------------
Exercisable, end of
period
9,880,984
$
2.44
13,254,013
$
3.70
-------------------------------------------------------------------------
All stock options have been granted for a period of five years. Options
granted under the plan are generally fully exercisable after three years.
The table below summarizes unexercised stock options.
-------------------------------------------------------------------------
Weighted
Average
Remaining
Contractual
Number
Life at
Range of Exercise Prices
Outstanding
June 30, 2009
-------------------------------------------------------------------------
$0.20 - $0.99
4,952,934
4.0
$1.00 - $1.99
4,436,940
3.4
$2.00 - $3.99
5,231,566
2.4
$4.00 - $5.56
957,509
2.0
-------------------------------------------------------------------------
15,578,949
3.2
-------------------------------------------------------------------------
In the second quarter of 2009 a non-cash charge of $551,000 million
(2008 - $1.2 million) was expensed, reflecting the fair value of stock
options amortized over the vesting period and the fair value of shares
granted to directors. A further $114,000 (2008 - $224,000) was
capitalized to property and equipment.
During the first half of 2009 a non-cash charge of $1.8 million (2008 -
$2.7 million) was expensed, reflecting the fair value of stock options
amortized over the vesting period and the fair value of shares granted to
directors. A further $507,000 (2008 - $1.0 million) was capitalized to
property and equipment.
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with weighted average
assumptions for grants as follows:
For the six months ended June 30
2009
2008
-------------------------------------------------------------------------
Risk free interest rate
1.3%
3.1%
Expected option life (years)
3
3
Expected volatility
67%
48%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in the first six months of 2009 was $0.32 per option (2008 -
$1.14) and for the three months ended June 30, 2009 was $0.52 per option
(2008 - $1.40).
(c) Share award plan for non-employee directors
Under the share award plan, share units may be granted to non-employee
directors of the company in amounts determined by the Board of Directors
on the recommendation of the Governance Committee. Payment under the plan
is made by delivering common shares to non-employee directors either
through purchases on the TSX or by issuing common shares from treasury,
subject to certain limitations. The Board of Directors may alternatively
elect to pay cash equal to the fair market value of the common shares to
be delivered to non-employee directors upon vesting of such share units
in lieu of delivering common shares.
In January 2009, 108,975 common shares were issued to non-employee
directors in respect of the share units which were then vested. In March
2009, the Board of Directors, on the recommendation of the Governance
Committee, voted to accelerate the vesting of 218,648 share units
originally scheduled to vest on January 1, 2010 and January 1, 2011 such
that they vested immediately. Concurrently, an additional 478,872 share
units were granted with vesting on January 1, 2010. In April, 218,648
common shares were issued to non-employee directors. In the first quarter
of 2009, 54,662 share units held by a deceased director were cancelled.
A total of 489,292 share awards were outstanding at June 30, 2009 and
have vested or vest on the following dates:
-------------------------------------------------------------------------
Vested
5,210
December 31, 2009
5,210
January 1, 2010
478,872
-------------------------------------------------------------------------
489,292
-------------------------------------------------------------------------
In the second quarter of 2009, a non-cash charge of $164,000 (2008 -
$388,000) was accrued as a liability and expensed in respect of shares
yet to be issued under the share award plan. In the first six months of
2009, a non-cash charge of $323,000 (2008 - $433,000) was accrued as an
expense and a liability in respect of shares to be issued under the plan.
(d) Conversion of debentures
In June 2009, $36,000 principal amount of Convertible Debentures were
converted to 7,200 common shares. A portion of each of the liability and
equity components of the debenture together with the principal amount
were transferred to share capital. No gain or loss was recorded.
8.
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 U.S., the company is in the business of refining and
marketing petroleum products.
Three months ended June 30
Inter-
Upstream
Downstream
segment
Canada Oil
USA
Elimin-
($000)
and Gas
Refining
ation(1)
Total
-------------------------------------------------------------------------
2009
Revenues, net of
royalties
$
33,882
$
69,094
(3,003) $
99,973
Equity interest in
Petrolifera earnings
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
Tax provision (recovery)
5,773
(283)
5,490
Net earnings (loss)
40,413
(447)
39,966
Property and
equipment, net
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
-------------------------------------------------------------------------
2008
Revenues, net of
royalties
$
83,483
$
117,820
$
201,303
Equity interest in
Petrolifera earnings
935
-
935
Dilution gain
8,066
-
8,066
Interest and other income
605
108
713
Finance charges
10,199
99
10,298
Depletion, depreciation
and accretion
12,429
1,396
13,825
Tax provision (recovery)
2,532
(1,499)
1,033
Net earnings (loss)
9,230
(2,547)
6,683
Property and
equipment, net
788,042
61,729
849,771
Goodwill
103,676
-
103,676
Capital expenditures
75,475
4,928
80,403
Total assets
$1,183,469
$
155,236
$1,338,705
-------------------------------------------------------------------------
Six months ended June 30
Inter-
Upstream
Downstream
segment
Canada Oil
USA
Elimin-
($000)
and Gas
Refining
ation(1)
Total
-------------------------------------------------------------------------
2009
Revenues, net of
royalties
$
62,028
$
102,246
(3,472) $
160,802
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
Tax provision (recovery)
(5,361)
(1,147)
(6,508)
Net earnings (loss)
(5,238)
(1,640)
(6,878)
Property and
equipment, net
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
-------------------------------------------------------------------------
2008
Revenues, net of
royalties
$
111,409
$
189,719
$
301,128
Equity interest in
Petrolifera earnings
1,390
-
1,390
Dilution gain
8,024
-
8,024
Interest and other income
1,311
233
1,544
Finance charges
14,571
158
14,729
Depletion, depreciation
and accretion
18,645
2,644
21,289
Tax provision (recovery)
1,830
(2,143)
(313)
Net earnings (loss)
7,361
(2,511)
4,850
Property and
equipment, net
788,042
61,729
849,771
Goodwill
103,676
-
103,676
Capital expenditures
188,432
7,956
196,388
Total assets
$1,183,469
$
155,236
$1,338,705
-------------------------------------------------------------------------
(1) Intersegment transactions are eliminated on consolidation.
9.
SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the common shares used in earnings per
share calculations.
For the three months ended June 30 (000)
2009
2008
-------------------------------------------------------------------------
Weighted average common shares outstanding
266,425
210,658
Dilutive effect of stock options, share
units under the non-employee directors
share award plan and Convertible Debentures
20,560
3,872
-------------------------------------------------------------------------
Weighted average common shares outstanding
- diluted
286,985
214,530
-------------------------------------------------------------------------
For the six months ended June 30 (000)
2009
2008
-------------------------------------------------------------------------
Weighted average common shares outstanding
239,008
210,446
Dilutive effect of stock options and share
units under the non-employee directors
share award plan and Converible Debentures
-
2,878
-------------------------------------------------------------------------
Weighted average common shares outstanding
- diluted
239,008
213,324
-------------------------------------------------------------------------
The Convertible Debentures, stock options and share units were
anti-dilutive to the loss per share calculation for the six months ended
June 30, 2009.
(b) Net change in non-cash working capital
For the three months ended June 30
-------------------------------------------------------------------------
($000)
2009
2008
-------------------------------------------------------------------------
Accounts receivable
$
(25,477) $
(6,847)
Inventories
(1,287)
492
Due from Petrolifera
2
44
Prepaid expenses
5,640
192
Accounts payable and accrued liabilities
(19,823)
(32,260)
Income taxes payable/recoverable
426
267
-------------------------------------------------------------------------
Total
$
(40,519) $
(38,112)
-------------------------------------------------------------------------
Summary of working capital changes:
Operations
$
(26,364) $
(12,863)
Investing
(14,155)
(25,249)
-------------------------------------------------------------------------
$
(40,519) $
(38,112)
-------------------------------------------------------------------------
For the six months ended June 30
2009
2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accounts receivable
$
(27,449) $
(34,344)
Due from Petrolifera
(33)
37
Prepaid expenses
(2,696)
1,184
Inventories
(19,819)
(19,162)
Accounts payable and accrued liabilities
(49,063)
48,664
Income taxes payable/recoverable
(1,131)
(321)
-------------------------------------------------------------------------
Total
$
(100,191) $
(3,942)
-------------------------------------------------------------------------
Summary of working capital changes:
Operations
$
(50,668) $
8,907
Investing
(49,523)
(12,849)
-------------------------------------------------------------------------
$
(100,191) $
(3,942)
-------------------------------------------------------------------------
(c) Supplementary cash flow information
For the three months ended June 30
2009
2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Interest paid
$
36,805
$
34,953
Income taxes paid
19
245
-------------------------------------------------------------------------
For the six months ended June 30
2009
2008
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Interest paid
$
37,532
$
35,336
Income taxes paid
1,363
1,372
-------------------------------------------------------------------------
At June 30, 2009 cash of $10 million was restricted to provide cash
collateral to support letters of credit (Note 4(f)).
(d) Dilution gain
In June 2008, Petrolifera issued an additional 4.4 million common shares
to raise $40 million. Connacher did not subscribe for any of these
shares. Consequently, Connacher's equity interest in Petrolifera was
reduced from 26 percent to 24 percent. As a result, a dilution gain of
$8 million was recognized by Connacher in the second quarter of 2008.
(e) Defined benefit pension plan
In the first six months of 2009, $294,000 (2008 - $227,000) three months
ended June 30, 2009 - $107,000 (2008 - $114,000) was changed to expense
in relation to MRCI's defined benefit pension plan.
SOURCE: Connacher Oil and Gas Limited
Richard A. Gusella, President and Chief Executive Officer; OR Grant D. Ukrainetz, Vice President, Corporate Development, Phone: (403) 538-6201, Fax: (403) 538-6225, inquiries@connacheroil.com, Website: www.connacheroil.com
Copyright (C) 2009 CNW Group. All rights reserved.
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