M E G E N E R G Y C O R P.
2 0 1 0 F I R S T Q U A R T E R R E P O R T Q1 F O R T H E T H R E E M O N T H S E N D E D M A R C H 3 1 , 2 0 1 0 MEG ENERGY CORP.
C O R P O R A T E O V E R V I E W
MEG Energy Corp. (“MEG” or the “Corporation”) is a private company based in Calgary solely focused on oil sands
development in the Athabasca region of Alberta, Canada. MEG owns a 100% working interest in over 800 square miles of oil
sands leases. The Corporation currently has identified two commercial projects, the first being its Christina Lake Project (the
“Christina Lake Project”) which, according to GLJ Petroleum Consultants Ltd. (“GLJ”), an independent reservoir engineering
firm, is capable of producing over 200,000 bpd of sustained bitumen production for over 30 years. The Christina Lake Project
is being developed through a phased development plan which is designed to reduce project capital investment risk and
execution risk as well as provide for ease of expansion. Phases 1 and 2 are operational and currently have production
capacity of 25,000 bpd of bitumen. Phase 2 was started in August of 2009 and is forecast to reach its design capacity of an
incremental 22,000 bpd by late 2010 or early 2011. The second commercial project is at Surmont which GLJ estimates will
support 50,000 bpd of sustained bitumen production for over 30 years. The remainder of the Corporation's leases are known
as the Growth Properties which are in the resource definition stage. At December 31, 2009, GLJ estimated MEG's total
remaining recoverable resource to be 5.2 billion barrels, of which over 1.7 billion barrels are classified as proven and
probable reserves.
T A B L E O F C O N T E N T S
1 Corporate Overview 3 Letter to Our Shareholders 6 Management’s Discussion and Analysis 21 Consolidated Balance Sheet 22 Consolidated Statement of Operations and Deficit 23 Consolidated Statement of Other Comprehensive Income (Loss) 23 Consolidated Statement of Accumulated Other Comprehensive Loss 24 Consolidated Statement of Cash Flows 25 Notes to Consolidated Financial Statements 32 Corporate Information
1 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
C O R P O R A T E O V E R V I E W
MEG’S OIL SAND HOLDINGS AND AREA OF FOCUS
T83 REMAINING RECOVERABLE RESOURCE Growth Properties 63 (34% of leases evaluated by GLJ) Surmont 1,481 mmbbl Christina Lake 647 mmbbl Surmont Growth Properties 881
Christina Lake 3,109 mmbbl
e n li e ip P s s e c c A T71
R19 R1W4M
FIRST QUARTER 2010 REPORT 2 MEG ENERGY CORP.
L E T T E R T O O U R S H A R E H O L D E R S
Our quarterly reports to shareholders summarize a broad range of matters related to the Company's development. All of those matters, from accounting policies to water disposal zones, are interesting and important, but this quarter I think our shareholders are most interested in just one thing - the progress we're making with the start up of our commercial operations at Christina Lake.
CHRISTINA LAKE OPERATIONS
Following many years of oil sands lease acquisition, delineation, regulatory filings and construction, MEG has commenced commercial operations at its Christina Lake Project. Phase 1, our 3,000 barrels per day pilot facility, commenced production in 2008 and has been integrated with the 22,000 barrels per day Phase 2 facility which was started up in August of last year.
Start up is a process that, for most steam assisted gravity drainage (“SAGD”) oil sands projects, takes over two years. There are four main processes that must work together:
First, source water must be found, produced and treated to remove hardness so that it is suitable for use as boiler feed water in the steam generation and cogeneration facilities. When steady state operations have been achieved, 90-95% of the water used in our SAGD process is recycled from produced water. The remaining 'make-up' water is provided by three water source wells drilled into non-potable water formations that could not otherwise be used for domestic or agricultural purposes.
Second, treated water enters the steam generation process. MEG's operations use two once through steam generators (“OSTG”) and one heat recovery steam generator (“HRSG”). The HRSG forms part of the power cogeneration facility as it recovers energy from the hot combustion gases of an 85 megawatt natural gas turbine generator.
Third, steam is sent by pipeline to six production pads and distributed to our horizontal well pairs. For approximately three months, steam is circulated in both the upper and lower horizontal wells to heat the reservoir and reduce the viscosity of the bitumen. When sufficient heat is in the reservoir following the circulation period, the lower well bore is converted from steam injection to production, and the condensed steam and bitumen emulsion is moved to surface by gas lift or by using electrical submersible pumps (“ESPs”).
Fourth, the emulsion is transported to our central processing facility via pipeline, where treating processes separate the bitumen from the produced water. Produced water is treated to be recycled for steam generation. The bitumen is cleaned and blended with condensate. The bitumen blend must contain no more that 0.5% of sediments and water to meet pipeline and refinery specifications.
The commissioning and start up of these processes must be done safely and methodically. During this start up period, experience shows that one should anticipate complications. MEG is fortunate to have attracted a team of engineers and field operations personnel with a broad range and depth of experience in SAGD operations. They continue to demonstrate their expertise by addressing the normal issues that arise during this critical period. To date, MEG's employees and contractors have delivered the most effective start up of a commercial SAGD project that industry has seen thus far. Their performance has exceeded our high expectations.
What were our expectations? Notwithstanding that, to our knowledge, no commercial SAGD project has consistently produced even 80 percent of its design rates within 24 months of the commencement of steaming, MEG's plans call for reaching Phase 1 and 2 capacity of 25,000 barrels per day by the end of 2010 - 16 months after first steam.
3 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
L E T T E R T O O U R S H A R E H O L D E R S
What have our people accomplished so far? By the end of 2009, steam was being circulated in 29 well pairs - 3 from Phase 1 and 26 new wells for Phase 2. Fifteen well pairs were converted from circulation to SAGD by the end of 2009; eleven additional wells pairs were converted to production in the first quarter of 2010, and the remaining three were converted to production in April. Bitumen production rates for the first quarter of 2010 averaged 13,398 barrels per day. The average production rate in March was 16,990 bbls/d, about 9% ahead of the budget for the month.
Production rates are, obviously, important but another factor that is critical is the steam oil ratio (“SOR”). The SOR of a project has a strong influence on both capital and operating costs. The lower the SOR, the less steam generation equipment is required per barrel of bitumen produced. A lower SOR also requires lower natural gas use per barrel of bitumen produced, reducing operating costs and air emissions. While Phase 2 was still in the early stage of start-up in the first quarter of 2010, MEG achieved an SOR of only 2.7 for the wells on production. Our three Phase 1 well pairs, which have been on production since 2008, achieved an SOR of only 2.2 for the three months ended March 31, 2010. Both production rates and SORs are better than our expectations.
How does April look? The month is not quite complete, but we expect that bitumen production volumes will average over 21,000 barrels per day - more than 80 percent of Christina Lake Phase 1 and 2 capacity within 8 months of the commencement of Phase 2 steaming.
We are thrilled with the progress our operations and reservoir engineering personnel have achieved and with the performance of our Christina Lake reservoir. Our enthusiasm must be restrained to an extent because, as I have mentioned previously, experience shows that unexpected situations often arise during start ups. We are also planning a plant turnaround in September to assess our equipment and perform scheduled maintenance.
DEVELOPMENT PLANS
Christina Lake Phase 2B, a 35,000 barrels per day expansion, received regulatory approvals in 2009. Much of the capital required to fund this project was raised in 2009 and MEG is moving forward with detailed engineering and the procurement of long lead time equipment. Field construction is being scheduled to commence in the first quarter of 2011. The drilling of approximately 40 horizontal production well pairs is being planned to start late this year or early in 2011. Phase 2B will more than double our production capacity to 60,000 barrels per day and is planned to commence steaming in 2013.
Our Phase 3 regulatory application, for a total of an additional 150,000 barrels per day of bitumen production, was filed with provincial regulatory authorities in 2008. The Company has received supplemental information requests from Alberta Environment and the Energy Resources Conservation Board in accordance with standard procedures. MEG has replied to these queries and plans to make a formal request for project approval later this year.
RESOURCE EXPLORATION AND DELINEATION
While the focus of this letter is on operations, I should also mention that MEG had a successful resource exploration and delineation program in the first quarter of 2010. The program was organized in a very tight time frame late in 2009. MEG's regulatory, permitting, and drilling teams executed a successful program that included 65 core holes and 6 observation wells on our Christina Lake leases to assist in the determination of Phase 2B horizontal well placement and to further delineate our leases. In addition, 24 core holes were drilled in the Growth Properties, and one water source well was drilled at Surmont. Costs of the program were approximately 15-20% below the costs experienced in 2008.
FIRST QUARTER 2010 REPORT 4 MEG ENERGY CORP.
L E T T E R T O O U R S H A R E H O L D E R S
Over the past year, MEG has made the transition from being an early stage oil sands company, to being a significant operating entity. Our people are demonstrating the ability to successfully execute world-scale projects. Our Christina Lake reservoir is showing production and SOR performance that compares favorably with major companies' competitive projects in the southern Athabasca oil sands region. All of this is happening in an environment of stable oil prices, reduced heavy oil price differentials and low natural gas prices. The wind is firmly at our back.
We are very pleased with the successes we are seeing and are proud to be able to share these accomplishments with you. We look forward to continued success and would like to thank our shareholders and lenders for your continued support.
On Behalf of the Board of Directors,
William (Bill) McCaffrey Chairman, President and Chief Executive Officer April 29, 2010
5 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
The following discussion of financial condition and performance is dated April 29, 2010 and should be read in conjunction with the Management's Discussion and Analysis (“MD&A”) for the year ended December 31, 2009, the audited consolidated financial statements for the year ended December 31, 2009 and the unaudited consolidated financial statements for the three months ended March 31, 2010. All tabular amounts are stated in thousands of Canadian dollars unless indicated otherwise.
FORWARD-LOOKING INFORMATION
This report of MEG Energy Corp. ("MEG" or the "Corporation") may contain forward-looking information including but not limited to expectations of future production, revenues, cash flow, profitability and capital investments, anticipated reductions in operating costs as a result of optimization of certain operations, development of additional oil sands resources, and anticipated sources of funding for operations and capital investments. Such forward-looking information is based on management's expectations regarding future growth, results of operations, production, 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. Such forward- looking information also 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: risks associated with financial market volatility, 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 investments; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses; health, safety and environmental risks; the risk of legislative and regulatory changes to, amongst other things, taxes, royalties and environmental laws), the risk of commodity price and foreign exchange rate fluctuations; and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Christina Lake Project and the development of the Corporation's other projects. Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. The forward-looking information included in this report is expressly qualified in its entirety by the foregoing cautionary statements. The forward-looking information included in this report is made as of April 29, 2010 and the Corporation assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances. Statements relating to reserves and recoverable resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the described reserves and resources, as the case may be, exist in the quantities predicted or estimated, and can be profitably produced in the future.
NON-GAAP FINANCIAL MEASURES
The Management's Discussion and Analysis includes references to financial measures commonly used in the crude oil and natural gas industry, such as bitumen sales, net bitumen revenue, and operating cash netback. These financial measures are not defined by generally accepted accounting principles in Canada (“GAAP”) and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Corporation may not be comparable to similar measures presented by other companies. The Corporation uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net income (loss), as determined in accordance with Canadian GAAP, as an indication of the Corporation's performance. The non-GAAP cash flow from operations and cash operating netback measures are reconciled to net income (loss), as determined in accordance with Canadian GAAP, in the “Summarized Highlights” and “Operating Summary” sections of this MD&A.
FIRST QUARTER 2010 REPORT 6 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
OVERVIEW
MEG is a private company based in Calgary solely focused on in situ oil sands development and production, a process for recovering bitumen from oil sands by means other than surface mining, in the Athabasca Oil Sands Region of Alberta, Canada. MEG owns a 100% working interest in over 800 square miles of oil sands leases. The Corporation currently has identified two commercial projects, the first being its Christina Lake Regional Project (the "Christina Lake Project") which, according to GLJ Petroleum Consultants Ltd. ("GLJ"), an independent reservoir engineering firm, is capable of producing over 200,000 bpd of sustained bitumen production for over 30 years. The second commercial project is at Surmont which GLJ estimates will support 50,000 bpd of sustained bitumen production for over 30 years. The remainder of the Corporation's leases are known as the Growth Properties which are in the resource definition stage.
MEG also holds a 50% interest in a dual pipeline system, which connects the Christina Lake Project to a large regional upgrading, refining and transportation hub in the Edmonton area (the “Access Pipeline”). The Access Pipeline and its associated blending facilities are in operation and provide the Corporation with the ability to transport diluents to the Christina Lake Project and a blend of bitumen and condensate (called dilbit) from Christina Lake to Edmonton, Alberta to supply a range of North American and global refining markets.
Corporation's projects
The Corporation's first development project, the Christina Lake Project, is on 80 contiguous square miles of oil sands leases in the southern Athabasca Oil Sands Region of Alberta. The Corporation is pursuing a staged approach to the development of this project, which is expected to continue being developed over the next 10 years. The initial two phases of development at the Christina Lake Project are complete. Phase 1 is in operation and is capable of producing at its designed capacity of 3,000 bpd of bitumen. Phase 2, with an incremental designed production capacity of 22,000 bpd, commenced steaming in August 2009. Phase 2 is planned to be at its design capacity by the end of 2010 or early 2011. The Corporation anticipated volatility in operating results with the start up of Phase 2 and expects the volatility to continue through 2010. The Corporation anticipates steady state operations a year or two after Phase 2 reaches its operating capacity. The Corporation's next phase of development, Phase 2B, is being designed to produce an incremental 35,000 bpd of bitumen and has received regulatory approval from the Alberta Energy Resources Conservation Board. It is anticipated that the Corporation's existing capital will allow for the completion of engineering and design, purchase of long lead equipment and early site preparation in preparation for the construction of Phase 2B. Phase 2B is planned to be completed in 2013 with the timing being dependent on a number of factors, including securing additional financing and the approval of the board of directors. Development of Phase 2B and other future phases is discretionary, and there can be no assurance that development will be completed as currently planned. A regulatory application for Phase 3 (incremental 150,000 bpd) was filed on April 30, 2008 with an anticipated review and approval period of up to three years.
At Surmont, 30 miles north of the Christina Lake Project, the Corporation holds a 100% working interest in 19 contiguous square miles of oil sands leases. A detailed environmental impact assessment for the Surmont Project is substantially complete and the Corporation is currently preparing to file a regulatory application in late 2010 or early 2011.
7 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Summarized highlights
Three month ended March 31 ($000s, except as noted and per share amounts) 2010 2009 Bitumen production - bbl/d 13,398 3,093 Bitumen realization - $/bbl $ 58.10 $ 21.94
Revenue, net of royalties $ 126,354 $ 1,320 Net loss $ (485) $ (33,585) Per share, basic $ 0.00 $ (0.26) Per share, diluted $ 0.00 $ (0.26) Cash flow from operations (1) $ (9,584) $ (8,686) Per share, basic (1) $ (0.06) $ (0.07) Per share, diluted (1) $ (0.06) $ (0.07)
Capital investment $ 91,809 $ 124,879
(1) Cash flow from operations and cash flow from operations 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. The Corporation uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the Corporation's ability to internally fund future growth expenditures. The reconciliation "Cash Flow from Operations" presented below lists certain non-cash items that are included in the Corporation's financial results.
Cash flow from operations
Three month ended March 31 ($000s) 2010 2009 Net loss $ (485) $ (33,585) Non-cash items: Stock-based compensation 3,629 2,186 Depletion, depreciation and accretion 19,069 188 Unrealized net (gain) loss on foreign exchange (26,159) 24,595 Unrealized (gain) loss on risk management (1,852) 219 Future income tax benefit (3,821) (2,289) Other 35 - Cash flow from operations $ (9,584) $ (8,686)
FIRST QUARTER 2010 REPORT 8 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
The following table shows the Corporation’s results and benchmark information on a quarterly basis to assist in understanding the impact of commodity prices and foreign exchange rates on the Corporation's financial results:
2010 2009 2008 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Benchmarks Crude oil prices West Texas Intermediate (WTI) US$/bbl $78.71 $76.19 $68.30 $59.62 $43.08 $58.73 $117.98 $123.98 Western Canadian Select (WCS) CDN$/bbl 72.51 67.66 63.74 60.64 42.60 47.73 103.92 103.38 Differential - WTI/WCS (CDN$/bbl) 9.42 12.82 11.21 8.95 11.05 23.49 19.00 21.84 Differential - WTI/WCS (%) 11.5% 15.9% 15.0% 12.9% 20.6% 33.0% 15.5% 17.4% Natural gas prices AECO (CDN$/mcf) 5.33 4.21 3.01 3.64 5.61 6.75 9.20 9.31 Electrical power prices Alberta Pool average price (CDN$/MW) $40.78 $46.06 $49.49 $32.30 $63.35 $95.14 $80.21 $107.52 Foreign exchange rates Canadian / U.S. dollar exchange rate 1.0409 1.0563 1.0974 1.1672 1.2453 1.2125 1.0418 1.0100 Corporation results Blend sales (CDN$/bbl) 68.06 61.11 58.36 55.37 33.22 29.32 91.08 82.06 Differential - WTI//Blend (CDN$/bbl) 13.88 19.37 16.59 14.21 20.43 41.89 31.83 43.16 Differential - WTI/Blend (%) 16.9% 24.1% 22.1% 20.4% 38.1% 58.8% 25.9% 34.5% Diluent cost (CDN$/bbl) 88.56 83.79 74.52 65.78 59.10 98.52 108.87 85.25 Bitumen sales (CDN$/bbl) 58.10 51.70 52.08 50.95 21.94 2.63 84.34 80.53 Bitumen sales (bbl/d) 13,447 5,920 2,493 2,138 3,093 2,427 2,312 338
Operating summary
First steam for Phase 2 was achieved in August 2009 and production has steadily increased to an average production of 16,999 bpd in the month of March 2010 for the integrated Phase 1 and Phase 2 facilities. As of March 31, 2010 there were 26 well pairs, including the three Phase 1 well pairs, on SAGD production and an additional 3 well pairs were circulating steam. During the quarter the Corporation converted 11 well pairs from steam circulation to SAGD production and plans to convert the remaining well pairs currently on steam circulation to SAGD production in the second quarter of 2010. The Corporation anticipates that the production slope of the ramp up profile to flatten as the well production rates increase to their capacity. Phase 1 and 2 is planned to be at their design capacity of 25,000 bpd by the end of 2010 or early 2011. The Corporation anticipated volatility in operating results with the start up of Phase 2 and expects the volatility to continue through 2010. The Corporation anticipates steady state operations a year or two after Phase 2 reaches its operating capacity. The 85 megawatt cogeneration facility is operating at near capacity and MEG's oil processing facility is utilizing approximately 8 - 10 megawatts of the power generated. The remainder of the power is sold into the Alberta power pool.
Steam-Oil Ratio (“SOR”) is an important efficiency indicator as it measures the amount of steam that is injected into the reservoir for each barrel of bitumen produced; the lower the SOR, the more efficient the SAGD process. The commencement of Phase 2 operations is currently resulting in an overall SOR being higher than the Phase 1 steady state due to the initial circulation period and ramp up. In the three months ended March 31, 2010 an average wellhead SOR of 2.7 was achieved for the wells on production. Once plant capacity is reached and steady state achieved it is anticipated that the overall SOR could be lower than the plant designed rate of 2.8. The Phase 1 wells average SOR for the three months ended March 31, 2010 was 2.2.
9 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Net operating costs
Three month ended March 31 ($000s) 2010 2009 Blend sales (1) $ 122,384 $ 13,278 Cost of diluent (2) (52,072) (7,170) Bitumen sales 70,312 6,108 Transportation and other selling costs (3,754) (3,456) Royalties (3,102) (36) Net bitumen revenue 63,456 2,616 Operating costs (47,214) (16,595) Power sales (5) 6,313 - Cash operating netback (3) 22,555 (13,979) Cash operating netback capitalized (4) - (13,979) Cash operating netback in statement of operations (4) $ 22,555 $ -
Production and sales volume summary
Three month ended March 31 (bbls/d) 2010 2009 Blend sales (1) 19,980 4,441 Diluents (2) (6,533) (1,348) Bitumen sales 13,447 3,093 Increase in inventory (49) - Total bitumen production 13,398 3,093
Power generated (MWh) 163,658 - Power sales (CDN$/MWh) $ 38.57 $ -
Cash operating netback before capitalization
Three month ended March 31 ($ per barrel) 2010 2009 Bitumen sales $ 58.10 21.94 Transportation and other selling costs (3.10) (12.42) Royalties (2.56) (0.13) Net bitumen revenue 52.44 9.39 Operating costs (5) 33.80 60.40 Netback (3) $ 18.64 $ (51.01)
(1) Bitumen produced at the Christina Lake Project is mixed with purchased diluents and sold as bitumen blend. Diluent is a light hydrocarbon that improves the marketing and transportation quality of bitumen. (2) Diluent volumes purchased and sold have been deducted in calculating bitumen production revenue and production volumes sold. (3) Cash operating netbacks are calculated by deducting the related diluent, transportation and selling, field operating costs and royalties from revenues. 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 by other companies. The 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. (4) Effective December 1, 2009, the Corporation commenced planned principal operations and ceased capitalizing net operating costs. (5) Power sales are netted against operating costs as the Corporation considers the revenue generated by the cogeneration facility as a recovery of operating costs. FIRST QUARTER 2010 REPORT 10 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Bitumen sales in the three months ended March 31, 2010 were $122.4 million compared to $13.3 million in 2009. The increase of $109.1 million is due to higher production volumes resulting from Phase 2 commencing production in October 2009 and higher selling prices. WTI averaged US$78.71 (C$81.93) in the first quarter of 2010 compared to US$43.08 (C$53.65) in same period of 2009. Blend revenue for the Corporation's Access Western Blend (“AWB”), a blend of bitumen and diluent, averaged $68.06 in the first three months of 2010. The Corporation's blend product has sold at a discount to WCS due to lower quantities of AWB being produced, higher TAN (Total Acid Number) and sulphur content in AWB. The discount to WCS has narrowed over the past two years as quantities of AWB have increased and refineries have become more familiar with AWB qualities and yields. Pipeline specifications require product to contain less than 0.5% of basic sediments and water and in the three months ended March 31, 2010 only 2.5% of the blend product produced did not meet this specification and was sold at a discount. With the start-up of a new facility such as Phase 2 it is normal that it takes time to work through the processing and treating of the produced bitumen in order to get the bitumen to pipeline specifications.
Power sales for the first three months of 2010 were $6.3 million with a realized price of $38.57 per megawatt hour. There will be variances to the Alberta Pool Average Price benchmark as it is based on the average daily price while power sales are priced on an hourly basis and can vary significantly each hour during the day.
During commissioning and start up it takes time for the reservoir to respond and for operations to work through the normal processing and treating issues associated with a new facility. Since Phase 1 was a pilot plant and Phase 2 is ramping up production through 2009 and 2010, current operating netback per barrel do not yet reflect the economies associated with a steady state facility operating at its design capacity. Operating cost per barrel has decreased in the first quarter of 2010 compared to the same period in 2009 as fixed costs are spread over the higher production volumes in the first quarter of 2010. The Corporation anticipated volatility in operating results with the start up of Phase 2 and expects the volatility to continue through 2010. The Corporation anticipates steady state operations a year or two after Phase 2 reaches its operating capacity.
Reconciliation of operating cash netback to net loss
Three month ended March 31 ($000s) 2010 2009 Operating cash netback, as above $ 22,555 $ (13,979) Net operating results capitalized (1) - 13,979 Interest income 759 1,320 General and administrative (8,612) (6,055) Stock-based compensation (3,629) (2,186) Research and development (1,633) (1,337) Net foreign exchange gain (loss) 23,422 (23,272) Risk management loss (6,885) (4,132) Interest expense (11,214) (24) Depreciation, depletion and accretion (1) (19,069) (188) Income taxes 3,821 2,289 Net loss $ (485) $ (33,585)
(1) Effective December 1, 2009 the Corporation commenced planned principal operations, ceased capitalizing net operating costs and commenced depletion of oil sands and natural gas properties and equipment.
11 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Interest income
For the three months ended March 31, 2010, interest income decreased to $0.8 million from $1.3 million for the same period in 2009. The decrease was due to lower interest rates in 2010 partially offset by an increase in average investment balances.
General and administrative costs Three month ended March 31 ($000s) 2010 2009 G&A Expense $ 8,612 $ 6,055 Capitalized G&A 2,465 2,472 Total G&A Costs $ 11,077 $ 8,527
General and administrative costs for the three months ended March 31, 2010 totaled $11.1 million, compared with $8.6 million for the same period in 2009. The increase in costs primarily resulted from the planned growth in the Corporation's professional staff and costs to support the operations and development of its oil sands assets. The head office employee headcount grew from 127 as of March 31, 2009 to 155 at March 31, 2010. For the three months ended March 31, 2010 the Corporation capitalized salaries related to capital investment of $2.5 million (2009 - $2.5 million).
Stock-based compensation
The Corporation recognizes the fair value of compensation associated with granting stock options to employees and directors in its financial statements. Fair value is determined using the Black-Scholes option pricing model. In the three months ended March 31, 2010, MEG issued 84,000 options to employees at an exercise price of $24.00 per share. As of March 31, 2010, 12,603,582 options were outstanding with a weighted average exercise price of $19.90 per share. Stock-based compensation expense for three months ended March 31, 2010 was $3.6 million (three months ended March 31, 2009 - $2.2 million). The Corporation has capitalized a portion of the stock based compensation expense associated with capitalized salaries. For the three months ended March 31, 2010 the Corporation capitalized $0.9 million (three months ended March 31, 2009 $0.8 million) of stock-based compensation to property, plant and equipment.
Research and development
Research and development expenditures of $1.6 million in the three months ended March 31, 2010 (three months ended March 31, 2009 - $1.3 million) relate to the Corporation's research of greenhouse gas management, upgrading and related technologies and have been expensed.
Foreign exchange
For the three months ended March 31, 2010 there was a net foreign exchange gain of $23.4 million (three months ended March 31, 2009 - $23.3 million loss). The table below summarizes the components of the net (gain) loss. Three month ended March 31 ($000s) 2010 2009 Foreign exchange (gain) loss on: Long-term debt $ (31,296) $ 24,468 Debt service reserve 3,043 (1,620) US$ denominated cash and cash equivalents 5,137 127 Other (306) 297 Foreign exchange (gain) loss $ (23,422) $ 23,272
FIRST QUARTER 2010 REPORT 12 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Risk management
For the three months ended March 31, 2010 there was a risk management loss of $6.9 million (three months ended March 31, 2009 - $4.1 million).
Three month ended March 31 ($000s) 2010 2009 Realized loss on interest rate swaps $ 8,737 $ 3,913 Unrealized fair value gain on interest rate swaps (7,568) (1,786) Amortization of unrealized loss on interest rate swaps from accumulated other comprehensive income 5,716 2,005 Total risk management loss $ 6,885 $ 4,132
The fair value of the interest swaps on March 31, 2010 was a $25.1 million liability, a decrease of $7.6 million from December 31, 2009 and has been included in risk management loss. During the three months ended March 31, 2009, the Corporation realized an increase in interest costs of $8.7 million due to the interest rate swaps which has been charged to operations as risk management loss. The Corporation had previously applied hedge accounting to its interest rate swap contracts which was subsequently discontinued as the hedges were no longer effective. As a result, the change in the fair value of the related contracts in the three months ended March 31, 2010 has been recognized in earnings. As at March 31, 2010, there was $10.7 million, net of income taxes, remaining in accumulated other comprehensive income related to these swaps which will be amortized into earnings over the remaining term of the contracts.
Interest expense
Three month ended March 31 ($000s) 2010 2009 Total interest $ 16,254 $ 12,725 Capitalized to property, plant and equipment (5,040) (12,701) Interest expense $ 11,214 $ 24
Effective December 1, 2009 the Corporation commenced planned principal operations and ceased capitalizing interest on the development of Phases 1 and 2 of the Christina Lake Project. Interest associated with the development of Phase 2B of the Christina Lake Project is being capitalized as of December 1, 2009. For the three months ended March 31, 2010 interest expense was $11.2 million (three months ended March 31, 2009 - $0.02 million).
Depletion, depreciation and accretion
Depletion of the Christina Lake Project developed assets commenced December 1, 2009 and was calculated using the unit-of- production method based on total estimated proved reserves. This equated to $15.49 per barrel of production. Depletion is based on invested capital to the end of March 2010 and the forecast of future development costs required to develop the current proved reserves. The future development costs and proved reserves are from the December 2009 GLJ reserve report. The $15.49 is comprised of $3.51 of depletion on invested capital, $9.42 of depletion on future development cost in 2010 dollars and $2.56 of depletion on the inflation on the future development costs. Prior to December 2009, depreciation expense related only to MEG's corporate assets.
13 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Income taxes
MEG did not pay income taxes in 2010 or 2009. At March 31, 2010, the Corporation had approximately $3.0 billion of available tax pools, comprised of approximately $952.8 million of undepreciated capital cost, $183.3 million of Canadian development expense, $306.7 million of Canadian exploration expense, $1,417.1 million of non capital losses ($212.6 million expiring in 2026, $253.9 million expiring in 2027, $341.4 million expiring in 2028, $515.3 million expiring in 2029 and $94.0 million expiring in 2030), and $141.4 million of Canadian oil and gas property expense and other tax pools. In addition, at March 31, 2010 the Corporation had $100.9 million of capital investment in respect of incomplete projects which will be added to available tax pools upon completion of the projects. As of March 31, 2010, the Corporation had recognized a net future tax liability of $11.9 million.
CAPITAL INVESTING
The following table summarizes the capital investments for the periods presented.
Summary of capital investment
Three month ended March 31 ($000s) 2010 2009 Christina Lake Project: Resource exploration and delineation $ 21,036 $ 3,601 Horizontal drilling - 796 Facilities, procurement and construction 44,309 92,677 Other 345 820 Total Christina Lake Project 65,690 97,894 Surmont and Growth Properties 11,676 1,048 Access pipeline 471 5,339 Capitalized interest and fees 4,606 11,469 Other 8,041 7,537 Total cash investments 90,484 123,287 Non-cash 1,325 1,592 Total capital investment $ 91,809 $ 124,879
During the first three months ended March 31, 2010, the Corporation invested cash totaling $90.5 million compared with $123.3 million in the same period in 2009. Capital investment in the first three months of 2010 was focused on Christina Lake Project Phase 2 development and resource delineation at Christina Lake and on the Growth Properties.
Christina Lake Project
During the three months ended March 31, 2010 the Corporation drilled 65 core holes and 6 observation wells to assist in the determination of Phase 2B horizontal wells placement and further delineation of the Christina Lake lands. Facilities investment in the first three months of 2010 was directed towards maintenance and reliability of the Phase 2 facility, Phase 2B detailed engineering and commencing the purchase of long lead equipment for the Phase 2B expansion. The Corporation anticipates the completion of the AFE estimate for the expansion in late 2010 for board approval.
Management determined that the Corporation is no longer in the pre-production stage and effective December 1, 2009 planned principal operations commenced. The Corporation therefore ceased capitalizing net operating and interest costs associated with Phases 1 and 2 as of December 1, 2009. Net operating costs for the three months ended March 31, 2009 totaled $14.2 million and have been capitalized as they were incurred prior to the commencement of planned principal operations (For further details, see the tables under the subheading "Operating Summary"). FIRST QUARTER 2010 REPORT 14 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Surmont and Growth Properties
The Corporation invested $11.7 million during the first three months of 2010 to drill 24 core holes in the Growth Properties to increase the resource definition and to drill a water source well in Surmont.
Capitalized interest and fees
The Corporation capitalizes interest expense and amortization of deferred finance charges for undeveloped property acquisitions and major development projects. Interest associated with the development of Phase 2B is being capitalized commencing December 1, 2009. During the three months ended March 31, 2010 the Corporation capitalized $5.0 million of interest and fees (three months ended December 31, 2009 - $11.5 million). Capitalization of interest for Phase 1 and 2 was discontinued effective December 1, 2009 due to the commencement of planned principal operations.
Other
Other costs include the costs to maintain the right to participate in a potential pipeline project, capitalized salaries and consulting costs and investment in tangible assets for the Corporation's offices.
Non-cash
The composition of the non-cash investment is summarized in the following table:
Three month ended March 31 ($000s) 2010 2009 Financing transaction costs $ 434 $ 602 Stock based compensation 891 771 Asset retirement obligation accretion - 219 Total non-cash investments $ 1,325 $ 1,592
SHARES OUTSTANDING
As at April 29, 2010, the Corporation had 169,160,003 common shares and 12,603,582 common share options outstanding. In addition, the Corporation had 1,104,936 approved common share options available for future grants.
OUTLOOK FOR 2010
MEG is utilizing a phased approach to development of its Christina Lake Project. Phase 1 and 2 are complete and has been forecasted to be at the combined design capacity of 25,000 bpd by the end of 2010 or early 2011. The Corporation anticipates it could take up to two years after design capacity has been reached to achieve steady state operations.
The Corporation's 2010 capital budget of $439 million was increased to $523 million by the board of directors on February 23, 2010. The 2010 budget will be directed towards detailed engineering and long lead equipment purchases for Phase 2B, maintenance and reliability capital for the Phase 2 facility, and continued resource definition of Christina Lake, Surmont and Growth Properties.
15 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
The construction of Phase 2B is subject to the receipt of additional capital and the approval of the board of directors. Included in the revised 2010 capital investment was the approval to purchase lands and assets associated with a tank farm construction project east of the Access Pipeline Sturgeon Terminal. Once construction of the tank farm is complete, it is anticipated to have a storage capacity of 900,000 barrels. The transaction closed on April 13, 2010 and the Corporation paid $42.4 million cash for the assets acquired.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Corporation has used the net cash generated from its debt and equity financing activities to fund the net operating expenses and the capital investments related to seismic and drilling, expanding the resource base through the acquisition of additional oil sands properties, developing the Christina Lake Project and constructing the Access Pipeline.
The Corporation believes its current capital resources and its ability to manage cash flow and working capital levels will allow the Corporation to meet its current and future obligations, to make scheduled principal and interest payments, and to fund the 2010 capital program and the other needs of the business for at least the next 12 months. However, no assurance can be given that this will be the case or that future sources of capital will not become necessary.
In addition to funding the capital investments described above, the Corporation anticipates that it will be required to maintain existing letters of credit and provide further letters of credit to support its operational and marketing activities. As at March 31, 2010 the Corporations has not utilized any of its US$185.0 million revolving credit facility that was established on December 23, 2009. The Corporation intends to replace the $12.8 million of letters of credit that are secured by its US$28.2 million cash collateral account with letters of credit supported by the revolving credit facility.
As of March 31, 2010, the Corporation's capital resources included $855.0 million of working capital, excluding risk management and debt service reserve. Working capital is comprised of $853.4 million of cash and short-term investments and non-cash working capital of $1.6 million made up of accounts receivable and inventories less accounts payable and accrued liabilities. The US$72.1 million debt service reserve is to fund principal and interest payments on the amended senior secured credit facility until December 31, 2010.
Other assets include $13.4 million of floating rate notes received on the restructuring of Canadian non-bank commercial paper and US$3.2 million of US Auction Rated Securities ("ARS"). The ARS were previously held in the Corporation's debt service reserve account and could not be liquidated due to the breakdown of the ARS market. Due to the illiquidity of these assets the Corporation has classified them as a long-term investment. The investments are recorded at fair value determined on a discounted cash flow valuation using observable information regarding the timing of payments and the credit rating of the securities. These investments are classified as held-for-trading which requires them to be measured at fair value at each period end with changes in fair value included in the consolidated statement of operations in the period in which they arise. As at March 31, 2010 an impairment provision of $7.9 million has been recorded on the floating rate notes and ARS investments.
The Corporation's cash and cash equivalents are held in accounts managed by third party financial institutions and consist of invested cash and cash in the Corporation's operating accounts. The invested cash is invested in high grade liquid short term debt such as commercial and bank paper. To date, the Corporation has experienced no loss or lack of access to its cash in operating accounts, invested cash or cash equivalents other than the investment in the restructured floating rate notes and the ARS that were held in the Debt Service Reserve. However, the Corporation can provide no assurance that access to its invested cash and cash equivalents will not be impacted by adverse conditions in the financial markets. While the Corporation monitors daily the cash balances in its operating accounts and adjusts the cash balances as appropriate, these cash balances could be impacted if the underlying financial institutions or corporations fail or are subject to other adverse conditions in the financial markets.
FIRST QUARTER 2010 REPORT 16 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Cash flows summary
Three month ended March 31 ($000s) 2010 2009 Net cash provided by (used in) Operating activities (50,527) $ (588) Investing activities (51,501) (108,167) Financing activities (2,442) (1,172) Foreign exchange losses on cash and cash equivalents held in foreign currency (5,137) (127) Decrease in cash and cash equivalents $ (109,607) $ (110,054)
Operating activities
The Corporation was considered to be a development stage company prior to December 1, 2009 as cash flows were primarily comprised of financing activities net of investment made in the Corporation's development. The completion of Phase 2 and the ramp- up of bitumen production volumes and associated revenues have resulted in management determining that planned principal operations have commenced effective December 1, 2009. Cash provided by or used in operations after this date also includes product and power sales net of operating expenses.
Investing activities
Net cash used for investing activities in the three months ended March 31, 2010 decreased $56.7 million compared to the same three month period in 2009. Capital investments in the three months ended 2010 decreased $35.9 million compared to the same period in 2009. Refer to the "Capital Investment" section of this MD&A for further details.
Financing activities
Financing activities for the three months ended March 31, 2010 and 2009 consists of principal payments on the Corporation's long term debt and proceeds received from the exercise of stock options.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
The information presented in the table below reflects management's estimate of the contractual maturities of the Corporation's obligations. These maturities may differ significantly from the actual maturities of these obligations. In particular, debt under the senior secured credit facilities may be retired earlier in certain circumstances.
17 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
< 1 1 - 3 4-5 More than ($000s) Total year years years 5 years Long-term debt (1) $ 1,022,712 $ 10,279 $ 20,557 $ 60,856 $ 931,020 Interest on long-term debt (1) 359,645 59,567 117,332 113,289 69,457 Asset retirement obligation (2) 80,237 181 - 663 79,393 Contracts and purchase orders (3) 256,345 242,605 9,213 3,576 951 Operating leases (4) 31,521 2,522 5,640 5,641 17,718 Other commitments (5) 1,483 1,483 - - - $ 1,751,943 $ 316,637 $ 152,742 $ 184,025 $ 1,098,539
(1) This represents the scheduled principal repayment on the senior secured credit facility and associated interest payments based on interest rates in effect on March 31, 2010. (2) This represents the undiscounted obligation associated with the retirement of oil and gas properties. (3) This represents the future commitments associated with capital equipment maintenance and purchases, diluent purchases and horizontal well drilling rig. (4) This represents the future commitments for Calgary corporate office space. (5) The Corporation has committed to pay $1.5 million for the right to participate in a potential pipeline project.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Corporation's unaudited consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and should be read in conjunction with the Corporation's audited consolidated financial statements for the year ended December 31, 2009. The critical accounting estimates remain unchanged from those disclosed in the 2009 annual consolidated financial statements.
TRANSACTIONS WITH RELATED PARTIES
For the three months ended March 31, 2010 the Corporation did not have any related party transactions. In the first quarter of 2009 the Corporation entered into a Standby Purchase Agreement with WP X LuxCo S.à.r.l. (“WPX”), an affiliate of an owner of more than 20% of the Corporation's common shares which has nominated three members of the Corporation's board of directors. Pursuant to the agreement, provided that certain conditions were met, the Corporation had the right to require WPX to purchase up to 10,416,666 MEG common shares at a price of $24.00 per share on or before June 1, 2009 for an aggregate purchase price of approximately $250 million. In consideration for the standby commitment, the Corporation agreed to pay WPX a fee equal to 7.5% of the commitment. On May 15, 2009 the Corporation exercised its rights under the Standby Purchase Agreements, and thereby received gross proceeds of $250.0 million and paid WPX fees totaling $18.8 million, equal to 7.5% of the commitments.
OFF-BALANCE SHEET ARRANGEMENTS
At March 31, 2010 and December 31, 2009, the Corporation did not have any off-balance sheet arrangements.
NEW ACCOUNTING POLICIES
There are no new accounting policies for the Corporation in the three months ended March 31, 2010.
FIRST QUARTER 2010 REPORT 18 MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
FUTURE ACCOUNTING CHANGES
International financial reporting standards
In February 2008, the Canadian Accounting Standards Board confirmed that the use of IFRS will be required for interim and annual financial statements of publicly accountable enterprises effective for fiscal years beginning on or after January 1, 2011. Although not a publicly accountable enterprise, the Corporation has voluntarily elected to adopt IFRS effective January 1, 2011.
The Corporation has commenced the process to transition from Canadian GAAP to IFRS. It has established a project plan and timeline for the implementation of IFRS which consists of three phases; initiation, detailed assessment and design and implementation.
The Corporation has completed the initiation phase which involved the completion of a high level review of the major differences between current Canadian GAAP and IFRS, the development of a timeline for addressing these differences in subsequent phases and an initial assessment of the impact on the Corporation's financial systems. Discussions with the Corporation's external auditors have commenced and will continue throughout the subsequent phases. Regular reporting is provided to the Corporation's Audit Committee of the Board of Directors. The Corporation has determined that the most significant impacts of IFRS conversion will be the following:
Property, plant and equipment IFRS does not prescribe specific oil and gas accounting guidance other than for costs associated with the exploration and evaluation phase. The Company currently follows full cost accounting as prescribed in AcG 16, “Oil and Gas Accounting - Full Cost.” Conversion to IFRS will have a significant impact on how the Company accounts for costs pertaining to oil and gas activities.
Impairment of assets Canadian GAAP generally uses a two-step approach to impairment testing: first comparing asset carrying values with undiscounted future cash flows to determine whether impairment exists, and then measuring any impairment by comparing asset carrying values with fair values. International Accounting Standard ("IAS") 36, “Impairment of Assets”, uses a one-step approach for both testing for and measurement of impairment, with asset carrying values compared directly with the higher of fair value less costs to sell and value in use (which uses discounted future cash flows). This may result in more write-downs where carrying values of assets were previously supported under Canadian GAAP on an undiscounted cash flow basis, but could not be supported on a discounted cash flow basis. However, an impairment loss is reversed if there has been an increase in the estimated recoverable amount of a previously impaired asset. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or depletion, if no impairment loss had been recognized. Canadian GAAP prohibits reversal of impairment losses.
Provisions (including asset retirement obligations) IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”, requires a provision to be discounted using a current pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The timing and amount of future expenditures are reviewed regularly, together with the interest rate used in discounting the cash flows and the carrying amount of the provision is adjusted accordingly. Under Canadian GAAP a provision previously recognized is not revised for subsequent changes in interest rates. Also, for those provisions that are required to be discounted there is a difference in the rate applied as Canadian GAAP uses a credit-adjusted risk free rate while IAS 37 does not specify the use of a credit-adjusted risk free rate. The impact of this change has not been determined.
19 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A LY S I S
Income taxes IAS 12, “Income Taxes”, does not recognize a deferred tax liability/asset if it arises from initial recognition of an asset or liability outside a business combination and there is no impact in profit or loss at the time of the transaction. The impact of this change has not been determined.
The Corporation is currently engaged in the detailed assessment and design phase of the project. The detailed assessment and design phase involves completing a comprehensive analysis of the impact of the IFRS differences identified in the initial scoping assessment. In addition, an initial evaluation of IFRS 1 “First-Time Adoption of International Financial Reporting Standards” which provides entities adopting IFRSs for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRSs has been performed. The Corporation is analyzing the various accounting policy choices available and will implement those determined to be most appropriate in our circumstances. The Corporation expects to complete the detailed assessment and design phase of the project by the end of the second quarter of 2010.
In conjunction with the detailed assessment and design phase of the project the Corporation completed an assessment of its information systems and based on this review does not expect any significant changes to the information systems to be required as part of the IFRS conversion process. In addition, the Corporation assessed its initial IFRS training requirements and training of key finance staff involved in the IFRS conversion process was delivered in 2009. Further training requirements for other members of the Corporation will be assessed during the implementation phase of the project.
During the implementation phase, the Corporation will implement the required changes in business processes, accounting policies and internal controls over financial reporting. All necessary changes in business processes, accounting policies and internal controls identified during the implementation phase will be implemented during the fourth quarter of 2010 and will be in place as of January 1, 2011. At this time, the impact on the Corporation's future financial position and results of operations is not reasonably determinable.
RISK FACTORS
The Corporation's primary focus is on the ongoing development and operation of its oil sands assets. In developing and operating these assets, the Corporation is and will be subject to many risks, including the risks which have been described in the MD&A for the year ended December 31, 2009.
FIRST QUARTER 2010 REPORT 20 MEG ENERGY CORP.
C O N S O L I D A T E D B A L A N C E S H E E T S
As at As at March 31, December 31, ($000s, unaudited) 2010 2009 Assets Current assets: Cash and cash equivalents $ 853,411 $ 963,018 Accounts receivable and other (note 2) 72,979 33,662 Inventories 12,599 5,560 Debt service reserve (note 3) 73,237 102,359 1,012,226 1,104,599
Restricted cash (note 4) 12,810 12,810 Other asset (note 5) 7,602 7,743 Property, plant and equipment (note 6) 3,217,302 3,144,341 $ 4,249,940 $ 4,269,493
Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued payables $ 87,000 $ 71,842 Risk management liability (note 10) 25,103 32,671 Current portion of long-term debt (note 8) 10,278 10,593 122,381 115,106
Long-term debt (note 8) 996,624 1,029,687 Asset retirement obligations (note 7) 14,493 14,297 Future income tax liability 11,874 14,290 Commitments and contingencies (note 12)
Shareholders' equity: Share capital (note 9) 3,137,887 3,137,696 Contributed surplus (note 9) 60,304 55,841 Deficit (82,878) (82,393) Accumulated other comprehensive loss (10,745) (15,031) 3,104,568 3,096,113 $ 4,249,940 $ 4,269,493
See accompanying notes to consolidated financial statements.
21 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
C O N S O L I D A T E D S T A T E M E N T O F O P E R A T I O N S A N D D E F I C I T
Three months ended March 31 ($000s, unaudited) 2010 2009 Revenue: Petroleum sales $ 122,384 $ - Royalties (3,102) - Power sales 6,313 - Interest 759 1,320 126,354 1,320
Operating expenses: Operating costs 47,214 - Cost of diluent 52,072 - Transportation and selling costs 3,754 - General and administrative 8,612 6,055 Stock-based compensation (note 9) 3,629 2,186 Research and development 1,633 1,337 Interest expense 11,214 24 Depletion, depreciation and accretion (notes 6 and 7) 19,069 188 147,197 9,790
Revenue less operating expenses (20,843) (8,470)
Other (gain) loss: Foreign exchange (gain) loss, net (23,422) 23,272 Risk management loss (note 10) 6,885 4,132 (16,537) 27,404
Loss before income taxes (4,306) (35,874)
Future income tax recovery (3,821) (2,289)
Net loss (485) (33,585)
Deficit, beginning of period (82,393) (133,569)
Deficit, end of period $ (82,878) $ (167,154)
Earnings per share (note 11) Basic $ 0.00 $ (0.26) Diluted $ 0.00 $ (0.26)
See accompanying notes to consolidated financial statements.
FIRST QUARTER 2010 REPORT 22 MEG ENERGY CORP.
C O N S O L I D A T E D S T A T E M E N T O F O T H E R C O M P R E H E N S I V E I N C O M E ( L O S S )
Three months ended March 31 ($000s, unaudited) 2010 2009 Net loss $ (485) $ (33,585) Other comprehensive income (loss), net of tax Gains (losses) on cash flow hedges (note 10) Unrealized gain (loss) on derivatives designated as cash flow hedges, net of taxes (1) - (1,595) Realized gain on derivatives designated as cash flow hedges capitalized, net of taxes (2) - 2,934 Amortization of balance in AOCI (3) 4,286 1,504 Other comprehensive income 4,286 2,843 Total comprehensive income (loss) $ 3,801 $ (30,742)
C O N S O L I D A T E D S T A T E M E N T O F A C C U M U L A T E D O T H E R C O M P R E H E N S I V E L O S S
Three months ended March 31 ($000s, unaudited) 2010 2009 Balance, beginning of period $ (15,031) $ (31,482)
Other comprehensive income, net of taxes 4,286 2,843 Balance, end of period $ (10,745) $ (28,639)
(1) Net income tax expense, three months ended March 31, 2010 - nil (March 31, 2009 - $532 benefit) (2) Net income tax expense, three months ended March 31, 2010 - nil (March 31, 2009 - $978) (3) Net income tax expense, three months ended March 31, 2010 - $1,430 (March 31, 2009 - $502)
See accompanying notes to consolidated financial statements.
23 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
C O N S O L I D A T E D S T A T E M E N T O F C A S H F L O W S
Three months ended March 31 ($000s, unaudited) 2010 2009 Cash provided by (used in):
Operations: Net loss $ (485) $ (33,585) Items not involving cash: Stock-based compensation 3,629 2,186 Depletion, depreciation and accretion 19,069 188 Other 35 - Unrealized net (gain) loss on foreign exchange (26,159) 24,595 Unrealized (gain) loss on risk management (1,852) 219 Future income tax recovery (3,821) (2,289) Net change in non-cash operating working capital items (note 11) (40,943) 8,098 (50,527) (588)
Investing: Purchase of property, plant and equipment (90,484) (123,287) Changes in debt service reserve 29,122 12,193 Other 116 - Net change in non-cash investing working capital items (note 11) 9,745 2,927 (51,501) (108,167)
Financing: Issue of shares 109 1,032 Repayment of long-term debt (note 8) (2,551) (2,204) (2,442) (1,172)
Foreign exchange loss on cash and cash equivalents held in foreign currency (5,137) (127)
Decrease in cash and cash equivalents (109,607) (110,054)
Cash and cash equivalents, beginning of period 963,018 241,146
Cash and cash equivalents, end of period (note 11) $ 853,411 $ 131,092
See accompanying notes to consolidated financial statements.
FIRST QUARTER 2010 REPORT 24 MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
MEG Energy Corp. (the “Corporation”) was incorporated under the Alberta Business Corporations Act on March 9, 1999. The Corporation owns a 100% interest in over 800 sections of oil sands leases in the Athabasca region of northern Alberta and is primarily engaged in a steam assisted gravity drainage oil sands development at its 80 section Christina Lake Regional Project (“Christina Lake Project”). The Corporation is using a staged approach to development. The development includes co-ownership of Access Pipeline ("Access"), a dual pipeline to transport diluent north from the Edmonton area to the Athabasca oil sands area and a blend of bitumen and diluent south from the Christina Lake Project into the Edmonton area.
1. BASIS OF PRESENTATION
These statements have been prepared in accordance with Canadian generally accepted accounting principles and reflect the same accounting policies and methods of computation as the financial statements for the year ended December 31, 2009. The disclosure herein is incremental to that included with the annual financial statements. The interim financial statements should be read in conjunction with the financial statements and the notes thereto in the Corporation's annual report for the year ended December 31, 2009.
2. ACCOUNTS RECEIVABLE AND OTHER March 31, December 31, 2010 2009 Accounts receivable $ 70,885 $ 28,524 Deposits and advances 2,094 5,138 $ 72,979 $ 33,662
3. DEBT SERVICE RESERVE
On December 23, 2009, as part of the modifications to the Corporation's senior secured credit facilities (note 11) the Corporation placed US$97.8 million in the debt service reserve to fund principal and interest payments through December 31, 2010. Investments are held in a US dollar debt service account and are comprised of high grade liquid short-term debt such as commercial, government, and bank paper.
The US dollar denominated debt service account is translated into Canadian dollars at the period end exchange rate. The foreign exchange loss on the restricted investments was $3.0 million for the three months ended March 31, 2010 (three months ended March 31, 2009 - $1.6 million gain), and has been recognized in operations through foreign exchange.
4. RESTRICTED CASH
Restricted cash consists of cash on deposit which collateralizes letters of credit issued by the Corporation. As at March 31, 2010, US$28.2 million was held as collateral for the issuance of letters of credit in a US dollar denominated cash collateral account. As at March 31, 2010, $12.8 million of these funds were used to support outstanding letters of credit.
5. OTHER ASSETS March 31, December 31, 2010 2009 MAV Notes (formerly asset-backed commercial paper) $ 4,708 $ 4,769 US Auction Rate Securities 2,894 2,974 $ 7,602 $ 7,743
25 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
6. PROPERTY, PLANT AND EQUIPMENT Accumulated depletion and Net book March 31, 2010 Cost depreciation value Oil sands and natural gas properties and equipment $ 3,236,609 $ 21,953 $ 3,214,656 Corporate assets 4,300 1,654 2,646 $ 3,240,909 $ 23,607 $ 3,217,302
December 31, 2009 Oil sands and natural gas properties and equipment $ 3,144,945 $ 3,270 $ 3,141,675 Corporate assets 4,155 1,489 2,666 $ 3,149,100 $ 4,759 $ 3,144,341
Effective December 1, 2009, planned principal operations of the Corporation's Christina Lake Project commenced and the Corporation began depleting the developed oil sands and natural gas properties and equipment costs, excluding pipeline line fill costs of $40.2 million. Prior to the commencement of principal operations operating costs, net of revenues, were capitalized. The cost of undeveloped properties not subject to depletion as at March 31, 2010 was $1,231.6 million (December 31, 2009 - $1,194.6 million).
During the three months ended March 31, 2010 the Corporation capitalized $2.5 million (March 31, 2009 - $2.5 million) of general and administrative expenses, $0.9 million (March 31, 2009 - $0.8 million) of stock-based compensation costs and $5.0 million (March 31, 2009 - $12.1 million) of interest and debt service costs relating to oil sands exploration and development activities.
7. ASSET RETIREMENT OBLIGATIONS
The following table presents the obligation associated with the retirement of oil sands and gas properties:
March 31, December 31, 2010 2009 Asset retirement obligation, beginning of period $ 14,297 $ 12,907 Liabilities incurred - 570 Liabilities settled (25) (75) Accretion 221 895 Asset retirement obligation, end of period $ 14,493 $ 14,297
The estimated future undiscounted asset retirement obligation is $80.2 million (December 31, 2009 - $80.2 million), which has been discounted using an average credit-adjusted risk free rate of 6.26%. This obligation is estimated to be settled in periods up to 2057.
FIRST QUARTER 2010 REPORT 26 MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
8. LONG-TERM DEBT March 31, December 31, 2010 2009 Senior secured term loan B (US$41.8 million; 2009-US$41.9 million) $ 42,431 $ 43,836 Senior secured term loan D (US$965.2 million; 2009-US$967.6 million) 980,280 1,012,741 Financing transaction costs (15,809) (16,297) 1,006,902 1,040,280 Less current portion of senior secured term loan B (426) (439) Less current portion of senior secured term loan D (9,852) (10,154) $ 996,624 $ 1,029,687
The Corporation's senior secured credit facilities are comprised of US$1,012.1 million in term loans and a three year US$185.0 million revolving credit facility. The term loans are comprised of the US$42.0 million term loan B which matures on April 3, 2013 and the US$970.1 million term loan D which matures on April 3, 2016. The term loan B bears a floating interest rate based on either US prime or the London Interbank Offered Rate ("LIBOR"), at the Corporation's option, plus a credit spread of 100 or 200 basis points, respectively. The term loan D bears a floating interest rate based on either US prime or LIBOR, at the Corporation's option, plus a credit spread of 300 or 400 basis points, respectively. In addition, the term loan D bears an interest rate floor of 325 basis points based on US prime and an interest rate floor of 200 basis points based on LIBOR. Under the terms of the credit facility agreement $102.4 million was deposited in the debt service reserve account on December 31, 2009 and is being used to fund required principal and interest payments on the senior secured credit facilities through December 31, 2010. The US dollar denominated debt is translated into Canadian dollars at the period end exchange rate of $1 CAD = $1.0156 US (December 31, 2009 - $1 CAD = $1.0466 US).
9. SHARE CAPITAL
(a) Authorized:
Unlimited number of common shares Unlimited number of preferred shares
(b) Changes in issued common shares are as follows:
Three months ended Year ended March 31, 2010 December 31, 2009 Number of Number of shares Amount shares Amount Balance, beginning of period 169,130,053 $3,137,696 128,123,287 $2,243,618 Stock options exercised 29,950 266 341,017 2,387 Shares issued for cash - - 40,665,749 975,978 Share issue costs, net of taxes of $25 (2009 - $3,698) (75) (84,287) Balance, end of period 169,160,003 $3,137,887 169,130,053 $3,137,696
During the three months ended March 31, 2010, 29,950 options were exercised at a weighted average price of $7.00 per share.
27 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
(c) Stock options:
Options granted under the plan generally are fully exercisable after three years and expire seven years after the grant date. At March 31, 2010 the Corporation had an additional 1,104,936 approved options available for future grants.
March 31, 2010 December 31, 2009 Weighted Weighted average average Stock exercise Stock exercise options per share options per share Balance, beginning of period 12,609,407 $ 19.89 10,892,674 $ 18.86 Granted 84,000 24.00 2,206,500 24.00 Forfeited (59,875) 25.70 (148,750) 38.24 Exercised (29,950) 7.00 (341,017) 5.65 Balance, end of period 12,603,582 $ 19.90 12,609,407 $ 19.89
(d) Contributed surplus: March 31, December 31, 2010 2009 Balance, beginning of period $ 55,841 $ 39,614 Stock based compensation - expensed 3,629 12,912 Stock based compensation - capitalized 891 3,775 Stock options exercised (57) (460) Balance, end of period $ 60,304 $ 55,841
10. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The financial instruments recognized in the balance sheet are comprised of cash and cash equivalents, accounts receivable, debt service reserve, restricted cash, other assets, accounts payable and accrued liabilities, risk management liability and long-term debt.
The carrying value of cash and cash equivalents, accounts receivable, debt service reserve, restricted cash and accounts payable and accrued liabilities approximates their fair value due to the short-term maturity of these instruments. Other assets and risk management liability are considered to be held-for-trading and are recorded at fair value. At March 31, 2010 the estimated fair value of long-term debt was $1,001.8 million. The fair value of long-term debt and the risk management liability were determined based on quoted prices from financial institutions. The Corporation has applied a discounted cash flow valuation in determining the fair value of other assets (note 5).
To mitigate a portion of the risk of interest rate increases on long-term debt the Corporation has entered into interest rate swap contracts to fix the interest rate on US$700 million of the US$1,007.0 million total debt. At March 31, 2010 the Corporation had the following interest rate swap contracts outstanding:
Amount ($ million) Remaining term Fixed rate Floating rate US$350 Apr 2010 - Dec 2010 5.29% LIBOR (1) US$60 Apr 2010 - Dec 2010 4.85% LIBOR (1) US$55 Apr 2010 - Dec 2010 4.83% LIBOR (1) US$235 Apr 2010 - Dec 2010 4.80% LIBOR (1)
(1) London Interbank Offered Rate
FIRST QUARTER 2010 REPORT 28 MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
The Corporation has two counterparties to the interest rate swap contracts which the Corporation had designated as cash flow hedges and they are recorded at fair value. The effective portion of the change in fair value was recognized in Other Comprehensive Income. Any gain or loss in fair value relating to the ineffective portion is recognized immediately in the statement of income. Effective October 1, 2008 the Corporation discontinued applying hedge accounting to the interest rate swap contracts held by one of the counterparties as they filed for bankruptcy protection and the requirements to apply hedge accounting were no longer met. As a result, the change in the fair value of the related contracts from October 1, 2008 is recognized in earnings. As at March 31, 2010 $1.9 million after-tax (December 31, 2009 - $2.9 million) remains in accumulated other comprehensive income related to these swaps which will be amortized into earnings over the remaining term of the contracts.
Effective December 23, 2009 the Corporation discontinued applying hedge accounting to the remaining interest rate swap contracts. Amendments made to the Corporation's senior secured credit facility resulted in the hedge no longer being effective and the Corporation has elected to discontinue applying hedge accounting to the swaps. As a result, the change in the fair value of the related contracts from December 23, 2009 onward has been recognized in earnings. As at March 31, 2010 $8.8 million after-tax (December 31, 2009 - $12.1 million) remains in accumulated other comprehensive income related to these swaps which will be amortized into earnings over the remaining term of the contracts. March 31, December 31, 2010 2009 Risk management liability, beginning of period $ 32,671 $ 61,683 Decrease in liability fair value recognized in earnings (7,568) (14,753) Decrease in liability fair value recognized in OCI - (14,259) Risk management liability, end of period $ 25,103 $ 32,671
Three months ended March 31 Risk management expense 2010 2009 Realized loss on interest rate swaps $ 8,737 $ 3,913 Decrease in fair value of interest rate swaps (7,568) (1,786) Amortization of unrealized loss on interest rate swaps from accumulated other comprehensive income 5,716 2,005 $ 6,885 $ 4,132
11. SUPPLEMENTARY INFORMATION
(a) Supplemental cash flow disclosures: Three months ended March 31 Changes in non-cash working capital items 2010 2009 Accounts receivable and other $ (39,317) $ (19,373) Inventories (7,039) 2,271 Accounts payable 15,158 28,127 (31,198) 11,025 Changes in non-cash working capital relating to: Operations $ (40,943) $ 8,098 Investing 9,745 2,927 (31,198) 11,025 Cash and cash equivalents Cash $ 31,886 $ 15,383 Short-term investments 821,525 115,709 $ 853,411 $ 131,092
29 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S Three months ended March 31, 2010. Tabular amounts are expressed in $000s unless otherwise noted.
(b) Per share amounts: Three months ended March 31 2010 2009 Weighted average common shares outstanding 169,152,792 128,177,020 Dilutive effect of stock options - - Weighted average common shares outstanding - diluted 169,152,792 128,177,020
The Corporation's stock options outstanding were anti-dilutive to the earnings per share calculation for the three months ended March 31, 2010 and March 31, 2009.
12. COMMITMENTS AND CONTINGENCIES
(a) Commitments
The Corporation had the following commitments as at March 31, 2010.
Operating: 2010 2011 2012 2013 2014 Thereafter Office lease rentals $ 1,817 $ 2,820 $ 2,820 $ 2,820 $ 2,820 $ 18,424 Diluent purchases 217,500 16,985 - - - - Other commitments 382 523 528 534 28 - Annual commitments $ 219,699 $ 20,328 $ 3,348 $ 3,354 $ 2,848 $ 18,424
Capital: The Corporation has committed to pay $1.5 million in 2010 for the right to participate in a potential pipeline project.
The Corporation has committed to pay $6.8 million for use of a horizontal well drilling rig over a three year period ending May 14, 2011.
The Corporation has committed to pay $8.5 million for the maintenance of capital equipment over a six year period as of March 31, 2010.
The Corporation has committed to pay $1.5 million for the purchase and installation of tanks to be used in the processing of off-spec oil at Christina Lake.
(b) Contingencies
The Corporation is involved in various legal claims associated with the normal course of operations. The Corporation believes that any liabilities that may arise pertaining to such matters would not have a material impact on its financial position.
12. COMPARATIVE FIGURES
Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current period.
13. SUBSEQUENT EVENTS
On April 13, 2010 the Corporation purchased lands and assets associated with a tank farm construction project east of the Access Pipeline Sturgeon Terminal for $42.4 million cash. Once construction of the tank farm is complete, it is anticipated to have a storage capacity of 900,000 barrels.
FIRST QUARTER 2010 REPORT 30 MEG ENERGY CORP.
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31 FIRST QUARTER 2010 REPORT MEG ENERGY CORP.
C O R P O R A T E I N F O R M A T I O N
DIRECTORS OFFICERS AUDITORS
William McCaffrey, P. Eng. William McCaffrey, P. Eng. PricewaterhouseCoopers LLP Chairman, President & CEO, Chairman, President & CEO Chartered Accountants MEG Energy Corp. Calgary, Alberta Calgary, Alberta Andrew Bonvicini, P. Geoph. V.P. Exploration LEGAL COUNSEL A. Boyd Anderson Former Director, Amoco Canada Andrew Fox, P. Geol. Bennett Jones LLP Petroleum Co. Ltd. V.P. Resource Development Calgary, Alberta Calgary, Alberta Dale Hohm, CA HEAD OFFICE Alan D. Archibald Chief Financial Officer CEO, Northpoint Energy Ltd. Calgary, Alberta Jim Kearns V.P. Supply & Marketing Peter R. Kagan Managing Director, Warburg Pincus Ken Marsh, P. Eng. MEG Energy Corp. New York, New York V.P. Operations 10th Floor, 734 - 7 Avenue SW Calgary, Alberta T2P 3P8 David B. Krieger Bryan Weir, P. Eng. Phone: (403) 770-0446 Managing Director, Warburg Pincus V.P. Projects Fax: (403) 264-1711 New York, New York Email: [email protected] David J. Wizinsky, LL.B. www.megenergy.com Hon. E. Peter Lougheed Corporate Secretary Counsel, Bennett Jones LLP Calgary, Alberta ADVISORY Lloyd C. Swift Certain information in this report may contain forward-looking statements. These statements involve known President, Square Butte Resources Inc. and unknown risks, uncertainties and other factors that can cause actual results, events or future Calgary, Alberta developments to differ materially from those anticipated in any forward-looking statements. The corporation does not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise. Forward-looking statements should not David J. Wizinsky, LL.B. be relied upon. Corporate Secretary, MEG Energy Corp. Calgary, Alberta
Li Zheng President, CNOOC Canada Limited Beijing, China
FIRST QUARTER 2010 REPORT 32 M E G E N E R G Y C O R P.
10th Floor, 734 - 7 Avenue SW
Calgary, Alberta T2P 3P8
Phone: (403) 770-0446 Fax: (403) 264-1711
Email: [email protected]
www.megenergy.com