 | MANAGEMENT’S DISCUSSION AND ANALYSIS |
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with the unaudited interim consolidated financial statements of Harvest Operations Corp. (“Harvest”, “we”, “us”, “our” or the “Company”) for the three months ended March 31, 2011 and the audited consolidated financial statements and MD&A for the year ended December 31, 2010. The information and opinions concerning our future outlook are based on information available at June 13, 2011.
On January 1, 2011, Harvest adopted International Financial Reporting Standards (“IFRS”). Harvest’s previously reported consolidated financial statements in Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) have been adjusted to be in compliance with IFRS on January 1, 2010, the transition date.
In this MD&A, all dollar amounts are expressed in Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars, except where noted. Natural gas volumes are converted to barrels of oil equivalent (“boe”) using the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel of oil (“bbl”). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, petroleum and natural gas revenues are reported on a gross basis before deduction of Crown and other royalties. In addition to disclosing reserves under the requirements of National Instrument (NI) 51-101, Harvest also discloses our reserves on a company interest basis which is not a term defined under NI 51-101. This information may not be comparable to similar measures by other issuers.
Additional information concerning Harvest, including its Annual Information Form (“AIF”) can be found on SEDAR atwww.sedar.com.
NON-IFRS MEASURES
Throughout this MD&A, the Company has referred to certain measures of financial performance that are not specifically defined under IFRS, herein after referred to as GAAP, such as “operating netbacks”, “gross margin”, “earnings from operations”, “cash contributions from operations”, “cash from operations”, “total debt”, “total capitalization” and “EBITDA”. “Operating netbacks” are always reported on a per boe basis and used extensively in the Canadian energy sector for comparative purposes. “Operating netbacks” include revenues, operating expenses, and transportation and marketing expenses. “Gross margin” is commonly used in the refining industry to reflect the net funds received from the sale of refined products after considering the cost to purchase the feedstock and is calculated by deducting purchased products for resale and processing from total revenue. “Earnings from operations”, “cash contributions from operations” and “cash from operations” are commonly used for comparative purposes in the petroleum and natural gas and refining industries to reflect operating results before items not directly related to operations. “Total debt”, “total capitalization” and “EBITDA” are used to assist management in assessing liquidity and the Company’s ability to meet financial obligations. The non-GAAP measures may not be comparable to similar measures by other issuers.
FORWARD-LOOKING INFORMATION
This MD&A highlights significant business results and statistics from our unaudited interim consolidated financial statements for the three months ended March 31, 2011 and the accompanying notes thereto. In the interest of providing our lenders and potential lenders with information regarding Harvest, including our assessment of our future plans and operations, this MD&A contains forward-looking statements that involve risks and uncertainties.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Such risks and uncertainties include, but are not limited to: risks associated with conventional petroleum and natural gas operations; risks associated with refining and marketing operations; the volatility in commodity prices and currency exchange rates; risks associated with realizing the value of acquisitions; general economic, market and business conditions; changes in environmental legislation and regulations; the availability of sufficient capital from internal and external sources; and, such other risks and uncertainties described from time to time in our regulatory reports and filings made with securities regulators.
Forward-looking statements in this MD&A include, but are not limited to, the forward looking statements made in the “Outlook” section as well as statements made throughout with reference to production volumes, refinery throughput volumes, royalty rates, operating costs, commodity prices, administrative costs, price risk management activities, acquisitions and dispositions, capital spending, reserve estimates, access to credit facilities, income taxes, cash from operating activities, and regulatory changes. For this purpose, any statements that are contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as “may”, “will”, “should”, “anticipate”, “expect”, “target”, “plan”, “potential”, “intend”, and similar expressions.
Readers are cautioned not to place undue reliance on forward-looking statements as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Although we consider such information reasonable at the time of preparation, it may prove to be incorrect and actual results may differ materially from those anticipated. Harvest assumes no obligation to update forward-looking statements should circumstances, estimates or opinions change, except as required by law. Forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
SELECTED INFORMATION
The table below provides a summary of our financial and operating results for the three months ended March 31, 2011 and 2010.
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| FINANCIAL | | | | | | | | | |
| Revenues(1) | $ | 1,218,702 | | $ | 569,480 | | | 114% | |
| Cash from operating activities | | 146,828 | | | 78,107 | | | 88% | |
| Net income (loss) | | 37,961 | | | (19,952 | ) | | 290% | |
| | | | | | | | | | |
| Bank debt | | 29,660 | | | 187,884 | | | (84% | ) |
| Senior notes | | 470,676 | | | 214,894 | | | 119% | |
| Convertible debentures | | 744,490 | | | 771,597 | | | (4% | ) |
| Total financial debt | | 1,244,826 | | | 1,174,375 | | | 6% | |
| | | | | | | | | | |
| Total assets | $ | 6,041,118 | | $ | 4,757,865 | | | 27% | |
| | | | | | | | | | |
| UPSTREAM OPERATIONS | | | | | | | | | |
| Daily sales volumes (boe/d) | | 53,331 | | | 50,178 | | | 6% | |
| Average realized price | | | | | | | | | |
| Oil and NGLs ($/bbl)(2) | | 73.75 | | | 71.12 | | | 4% | |
| Gas ($/mcf) | | 3.83 | | | 5.13 | | | (25% | ) |
| Operating netback ($/boe)(2) | | 33.67 | | | 36.20 | | | (7% | ) |
| | | | | | | | | | |
| Capital asset additions (excluding acquisitions) | $ | 237,649 | | $ | 113,526 | | | 109% | |
| Property and business acquisitions (dispositions), net | $ | 515,496 | | $ | 30,938 | | | 1568% | |
| Abandonment and reclamation expenditures | $ | 1,967 | | $ | 5,650 | | | (65% | ) |
| Net wells drilled | | 104.9 | | | 65.9 | | | 59% | |
| Net undeveloped land acquired in business combination | | | | | | | | | |
| (acres)(3) | | 223,405 | | | - | | | 100% | |
| Net undeveloped land additions (acres) | | 53,480 | | | 22,387 | | | 139% | |
| | | | | | | | | | |
| DOWNSTREAM OPERATIONS | | | | | | | | | |
| Average daily throughput (bbl/d) | | 97,438 | | | 41,016 | | | 138% | |
| Average Refining Margin (US$/bbl) | | 10.96 | | | - | | | 100% | |
| | | | | | | | | | |
| | | | | | | | | | |
| Capital asset additions | | 35,879 | | | 8,683 | | | 313% | |
| (1) | Revenues are net of royalties and the effective portion of Harvest’s crude oil hedges. |
| (2) | Excludes the effect of risk management contracts designated as hedges. |
| (3) | Excludes carried interest lands acquired in business combination. |
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
REVIEW OF OVERALL PERFORANCE
Upstream
Sales volumes increased by 3,153 boe/d to 53,331 boe/d from the first quarter of 2010 primarily due to production from recently acquired properties.
Cash flow from operating activities was $117.0 million in the first quarter of 2011, which is 63% higher than cash flows of $71.7 million in the same quarter in the previous year. This increase is primarily due to increased sales volumes.
Capital spending of $237.6 million include the drilling of 115.0 gross (104.9 net) wells with a success ratio of 98%. Capital spending has approximately doubled from the first quarter of 2010 with $113.5 million of capital spending and 80.0 gross (65.9 net) wells drilled.
Harvest’s operating netback was $33.67/boe prior to hedging for the first quarter of 2011; a decrease of 7% from the same quarter in the previous year, reflecting lower natural gas prices and royalties and higher operating costs.
Harvest successfully closed the acquisition of assets from Hunt Oil Company of Canada, Inc. (“Hunt”) for $505 million in cash on February 28, 2011.
Downstream
Throughput volume averaged 97,438 bbl/d as compared to 41,016 bbl/d in the same quarter of 2010 reflecting normal operating levels in the first quarter of 2011. Refining gross margin averaged $10.96/bbl in the first quarter of 2011 as compared to $nil/bbl in the first quarter of 2010 due to an unplanned shutdown of refinery process units in the first quarter of 2010, stronger global refinery margins in 2011 and higher throughput.
Cash flow from operating activities totaled $29.8 million in the first quarter of 2011 as compared to $6.4 million in 2010. The improved cash flow is primarily due to higher throughput and refinery margins in 2011.
Capital spending was $35.9 as compared to $8.7 million in the same quarter of 2010. During the first quarter of 2011 and 2010, $14.6 million and $5.9 million were spent on the debottlenecking project respectively.
Corporate
- Harvest received a capital injection of $505.4 million from KNOC to fund the acquisition of the Hunt assets.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
UPSTREAM OPERATIONS
Summary of Financial and Operating Results
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| FINANCIAL | | | | | | | | | |
| Petroleum and natural gas sales | $ | 281,051 | | $ | 271,731 | | | 3% | |
| Royalties | | (35,858 | ) | | (41,756 | ) | | (14% | ) |
| Revenues | | 245,193 | | | 229,975 | | | 7% | |
| | | | | | | | | | |
| Operating expenses | | 83,595 | | | 64,253 | | | 30% | |
| Transportation and marketing | | 3,003 | | | 2,207 | | | 36% | |
| General and administrative expenses | | 13,522 | | | 12,417 | | | 9% | |
| Depreciation, depletion and amortization | | 121,344 | | | 116,334 | | | 4% | |
| Exploration and evaluation | | 6,215 | | | 26 | | | 238% | |
| Gain on disposition of property, plant and equipment | | (240 | ) | | (263 | ) | | (9% | ) |
| Earnings From Operations(1) | $ | 17,754 | | $ | 35,001 | | | (49% | ) |
| | | | | | | | | | |
| Capital asset additions (excluding acquisitions) | $ | 237,649 | | $ | 113,526 | | | 109% | |
| Property and business acquisitions (dispositions) | $ | 515,496 | | $ | 30,938 | | | 1568% | |
| Abandonment and reclamation expenditures | $ | 1,967 | | $ | 5,650 | | | (65% | ) |
| | | | | | | | | | |
| OPERATING | | | | | | | | | |
| Light / medium oil (bbl/d) | | 25,523 | | | 24,487 | | | 4% | |
| Heavy oil (bbl/d) | | 9,038 | | | 9,250 | | | (2% | ) |
| Natural gas liquids (bbl/d) | | 3,455 | | | 2,816 | | | 23% | |
| Natural gas (mcf/d) | | 91,888 | | | 81,752 | | | 12% | |
| Total (boe/d) | | 53,331 | | | 50,178 | | | 6% | |
(1)This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
Commodity Price Environment
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| West Texas Intermediate crude oil (US$ per barrel) | | 94.10 | | | 78.71 | | | 20% | |
| Edmonton light crude oil ($ per barrel) | | 88.04 | | | 80.27 | | | 10% | |
| Bow River blend crude oil ($ per barrel) | | 71.33 | | | 73.55 | | | (3% | ) |
| AECO natural gas daily ($ per mcf) | | 3.76 | | | 4.95 | | | (24% | ) |
| Canadian / U.S. dollar exchange rate | | 1.014 | | | 0.961 | | | 6% | |
| | Three Months Ended March 31 |
| Differential Benchmarks | 2011 | 2010 |
| Bow River Blend differential to Edmonton Par ($/bbl) | $16.71 | $6.72 |
| Bow River Blend differential as a % of Edmonton Par | 19.0% | 8.4% |
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
The average WTI benchmark price in the first quarter of 2011 was 20% higher than the first quarter 2010 average price. The average Edmonton light crude oil price (“Edmonton Par”) also experienced an increase over the first quarter of the prior year, due to the higher WTI prices but partially offset by the stronger Canadian dollar and a wider sweet differential. The Bow River blend crude oil price (“Bow River”) remained relatively consistent with the first quarter 2010 price, with the higher WTI price offset by the stronger Canadian dollar and a wider Bow River differential.
Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets and the seasonal demand for heavy oil. In the first quarter of 2011, Bow River heavy oil differential relative to Edmonton Par increased to an average of $16.71/bbl (19.0%) compared to $6.72/bbl (8.4%) in the prior year.
Realized Commodity Prices
| | Three Months Ended March 31 | |
| | 2011 | | | 2010 | | | Change | |
| Light to medium oil prior to hedging ($/bbl) | | 78.69 | | | 74.35 | | | 6% | |
| Heavy oil ($/bbl) | | 61.51 | | | 65.98 | | | (7% | ) |
| Natural gas liquids ($/bbl) | | 69.32 | | | 59.89 | | | 16% | |
| Natural gas ($/mcf) | | 3.83 | | | 5.13 | | | (25% | ) |
| Average realized price prior to hedging ($/boe) | | 59.19 | | | 60.17 | | | (2% | ) |
| | | | | | | | | | |
| Light to medium oil after hedging ($/bbl) | | 77.37 | | | 74.35 | | | 4% | |
| Average realized price after hedging ($boe) | | 58.55 | | | 60.17 | | | (3% | ) |
Prior to hedging activities, our realized price for light to medium oil increased by 6% in the first quarter of 2011 as compared to the same period in the prior year. This increase is lower than the 10% increase in Edmonton Par, mainly due to a wider light sour differential in 2011.
In order to mitigate the risk of fluctuating cash flows due to crude oil price volatility, Harvest has entered into fixed-for-floating swaps. The impact of this hedging activity resulted in a decrease of $1.32/bbl (2010 – $nil) in Harvest’s realized light to medium oil price to $77.37/bbl in the first quarter of 2011. With respect to our cash flow risk management program, see “Cash Flow Risk Management” in this MD&A.
Harvest’s realized heavy oil prices decreased by 7%, reflecting the decrease in the Bow River prices.
The average realized price for Harvest’s natural gas production decreased by 25% compared to the first quarter of 2010, reflecting the 24% decrease in the AECO benchmark price.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Sales Volumes
| | | | | | Three Months Ended March 31 | | | | |
| | | 2011 | | | | | | 2010 | | | | | | | |
| | | Volume | | | Weighting | | | Volume | | | Weighting | | | % Volume | |
| | | | | | | | | | | | | | | Change | |
| Light to medium oil (bbl/d)(1) | | 25,523 | | | 49% | | | 24,487 | | | 49% | | | 4% | |
| Heavy oil (bbl/d) | | 9,038 | | | 17% | | | 9,250 | | | 18% | | | (2% | ) |
| Natural gas liquids (bbl/d) | | 3,455 | | | 6% | | | 2,816 | | | 6% | | | 23% | |
| Total liquids (bbl/d) | | 38,016 | | | 72% | | | 36,553 | | | 73% | | | 4% | |
| Natural gas (mcf/d) | | 91,888 | | | 28% | | | 81,752 | | | 27% | | | 12% | |
| Total oil equivalent (boe/d) | | 53,331 | | | 100% | | | 50,178 | | | 100% | | | 6% | |
(1) Harvest classifies our oil production, except that produced from Hay River, as light to medium and heavy according to NI 51-101 guidance. The oil produced from Hay River has an average API of 24o (medium grade) and is classified as a light to medium oil, notwithstanding that, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101.
Harvest’s sales volumes increased to 53,331 boe/d in the first quarter of 2011, a 6% increase over the first quarter of 2010. The increase is primarily attributable to the acquisition of assets at the end of the third quarter of 2010 and the acquisition of the Hunt assets in February 2011.
 | Harvest’s average daily sales of light/medium oil was 25,523 bbl/d in the first quarter of 2011 compared to 24,487 bbl/d in the first quarter of 2010, resulting in an increase of 1,036 bbl/d. This increase is mainly attributable to the third quarter 2010 and first quarter 2011 acquisitions. |
Heavy oil sales volumes declined from an average of 9,250 in the first quarter of 2010 to 9,038 bbl/d in 2011. The decline is primarily due to natural declines. |  |
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
 | Natural gas sales averaged 91,888 mcf/d in the first quarter of 2011 compared to 81,752 mcf/d in 2010 mainly due to the acquisition of Hunt assets at the end of February 2011. |
Revenues
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| Light / medium oil sales after hedging(1) | $ | 177,725 | | $ | 163,857 | | | 8% | |
| Heavy oil sales | | 50,032 | | | 54,931 | | | (9% | ) |
| Natural gas sales | | 31,679 | | | 37,765 | | | (16% | ) |
| Natural gas liquids sales and other(2) | | 21,615 | | | 15,178 | | | 42% | |
| Petroleum and natural gas sales | | 281,051 | | | 271,731 | | | 3% | |
| Royalties | | (35,858 | ) | | (41,756 | ) | | (14% | ) |
| Revenues | $ | 245,193 | | $ | 229,975 | | | 7% | |
(1)Inclusive of realized commodity risk management activity.
(2)Inclusive of sulphur revenue.
Harvest’s revenue is impacted by changes in sales volumes, commodity prices and currency exchange rates. The Upstream operation’s total sales revenue for the three months ended March 31, 2011 increased by $9.3 million from the same quarter in the previous year. The 3% increase is attributable to increased sales volumes, partially offset by the decreased average realized price.
Royalties
Harvest pays Crown, freehold and overriding royalties to the owners of mineral rights from which production is generated. These royalties vary for each property and product and our Crown royalties are based on a sliding scale dependent on production volumes and commodity prices.
Throughout the first quarter of 2011, royalties as a percentage of gross revenue averaged 12.8% (2010 – 15.4%) . The decrease from the first quarter in 2010 is primarily due to adjustments made to Freehold Mineral Tax estimates for 2009 and 2010 in the first quarter of 2011 combined with the impact of lower gas prices in 2011.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Operating Expenses
| | | | | | Three Months Ended March 31 | | | | |
| | | | | | | | | | | | | | | Per BOE | |
| | | 2011 | | | Per BOE | | | 2010 | | | Per BOE | | | Change | |
| Operating expense | | | | | | | | | | | | | | | |
| Power and fuel | $ | 21,551 | | $ | 4.49 | | $ | 13,045 | | $ | 2.89 | | $ | 1.60 | |
| Well servicing | | 16,912 | | | 3.52 | | | 12,917 | | | 2.86 | | | 0.66 | |
| Repairs and maintenance | | 12,871 | | | 2.68 | | | 10,639 | | | 2.35 | | | 0.33 | |
| Lease rentals and property tax | | 7,768 | | | 1.62 | | | 8,116 | | | 1.80 | | | (0.18 | ) |
| Labor - internal | | 7,048 | | | 1.47 | | | 6,254 | | | 1.38 | | | 0.09 | |
| Labor - contract | | 4,073 | | | 0.85 | | | 4,021 | | | 0.89 | | | (0.04 | ) |
| Chemicals | | 3,826 | | | 0.80 | | | 3,801 | | | 0.84 | | | (0.04 | ) |
| Trucking | | 2,554 | | | 0.53 | | | 2,105 | | | 0.47 | | | 0.06 | |
| Processing and other fees | | 1,307 | | | 0.27 | | | 3,915 | | | 0.87 | | | (0.60 | ) |
| Other | | 5,685 | | | 1.19 | | | (560 | ) | | (0.12 | ) | | 1.31 | |
| Total operating expenses | $ | 83,595 | | $ | 17.42 | | $ | 64,253 | | $ | 14.23 | | $ | 3.19 | |
| | | | | | | | | | | | | | | | |
| Transportation and marketing | $ | 3,003 | | $ | 0.63 | | $ | 2,207 | | $ | 0.49 | | $ | 0.14 | |
First quarter 2011 operating costs totaled $83.6 million, an increase of $19.3 million as compared to the same period in the prior year. The increase in operating costs is attributable to the acquisition of assets at the end of September 2010 and February 2011 combined with increased power and fuel costs, well servicing and repairs and maintenance.
Operating costs on a per barrel basis have increased to $17.42/boe as compared to $14.23/boe in the first quarter of 2010. The 22% increase on a per barrel basis is substantially attributed to higher power and fuel costs, as well as higher activity levels on well servicing and repairs and maintenance.
| | | Three Months Ended March 31 | |
| ($ per boe) | | 2011 | | | 2010 | | | Change | |
| Electric power and fuel costs | $ | 4.49 | | $ | 2.89 | | $ | 1.60 | |
| Realized loss (gain) on electricity risk management contracts | | (0.47 | ) | | 0.22 | | | (0.69 | ) |
| Net electric power and fuel costs | $ | 4.02 | | $ | 3.11 | | | 0.91 | |
| Alberta Power Pool electricity price ($ per MWh) | $ | 83.34 | | $ | 40.89 | | $ | 42.45 | |
Power and fuel costs, comprised primarily of electric power costs, represented approximately 26% of our total operating costs during the first quarter of 2011 (2010 – 20%). The 55% increase from the first quarter of 2010 in power and fuel costs is primarily attributable to the increase in the power price. The average Alberta electric power price of $83.34/MWh in the first quarter of 2011 was 104% higher than the first quarter 2010 average price of $40.89/MWh.
First quarter 2011 transportation and marketing expense increased marginally from the first quarter of 2010. These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and our cost of trucking clean crude oil to pipeline receipt points. As a result, the total dollar amount of costs fluctuates in relation with our production volumes.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Operating Netback
| | | Three Months Ended March 31 | |
| ($ per BOE) | | 2011 | | | 2010 | | | Change | |
| Petroleum and natural gas sales | $ | 59.19 | | $ | 60.17 | | | (2% | ) |
| Royalties | | (7.47 | ) | | (9.25 | ) | | (19% | ) |
| Operating expense | | (17.42 | ) | | (14.23 | ) | | 22% | |
| Transportation expense | | (0.63 | ) | | (0.49 | ) | | 29% | |
| Operating netback prior to hedging(1) | | 33.67 | | | 36.20 | | | (7% | ) |
| Hedge gain (loss) | | (0.63 | ) | | - | | | - | |
| Operating netback after hedging(1) | $ | 33.04 | | $ | 36.20 | | | (9% | ) |
(1)This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
Harvest’s operating netback represents the net amount realized on a per boe basis after deducting directly related costs. In the first quarter of 2011, our operating netback prior to hedging decreased by $2.53/boe or 7% compared to the same period in the prior year. The decrease in our operating netback is primarily attributed to increased operating expenses and lower revenues, partially offset by lower royalties.
General and Administrative (“G&A”) Expense
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| Total G&A | $ | 13,522 | | $ | 12,417 | | | 9% | |
| G&A per boe ($/boe ) | $ | 2.82 | | $ | 2.75 | | | 3% | |
For the three months ended March 31, 2011, G&A expense increased nominally by $1.1 million from $12.4 million in the same quarter of 2010. The increase in G&A is primarily due to increased salary expense to accommodate Harvest’s growing business. Approximately 85% of the G&A expenses are related to salaries and other employee related costs. Harvest does not have a stock option program, however there is a long-term cash incentive program.
Depletion, Depreciation and Amortization
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| Depletion, depreciation and amortization | $ | 121,344 | | $ | 116,334 | | | 4% | |
| Per BOE ($/BOE) | $ | 25.28 | | $ | 25.76 | | | (2% | ) |
Our overall depletion, depreciation and amortization (“DDA”) expense for the three months ended March 31, 2011 was $5.0 million (4%) higher compared to the same period in the prior year, mainly due to higher sales volumes.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Capital Expenditures
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| Drilling and completion | $ | 137,599 | | $ | 71,731 | | | 92% | |
| Well equipment, pipelines and facilities | | 57,689 | | | 29,505 | | | 96% | |
| Geological and geophysical | | 10,800 | | | 8,550 | | | 26% | |
| Land and undeveloped lease rentals | | 5,690 | | | 144 | | | 3,851% | |
| Capitalized G&A expenses | | 2,450 | | | 3,407 | | | (28% | ) |
| Furniture, leaseholds and office equipment | | 646 | | | 189 | | | 242% | |
| Conventional oil and gas capital expenditures | | 214,874 | | | 113,526 | | | 89% | |
| BlackGold oil sands | | 22,775 | | | - | | | 100% | |
| Total development capital expenditures excluding acquisitions | $ | 237,649 | | $ | 113,526 | | | 109% | |
Conventional
The first quarter of 2011 was particularly active for Harvest as the Company executed significant drilling programs in its large resource oil pools. In Hay River Harvest drilled 38.0 gross (38.0 net) wells pursuing medium gravity oil in the Bluesky formation for a total expenditure of $49.1 million. Included in the Hay River program were three exploration wells drilled to evaluate extensions of the Bluesky oil pool and the preliminary results would indicate commercial oil deposits beyond the current boundaries of the pool. At Red Earth, Harvest drilled 23.0 gross (21.0 net) wells including 15 horizontal wells into the Slave Point light oil formation using multi-stage fractured completions for a total expenditure of $67.6 million. At Kindersley, Harvest drilled 7.0 gross (7.0 net) horizontal wells into the Viking light oil formation all completed using multistage fracture technology for a total expenditure of $10.1 million. Harvest’s SE Saskatchewan light oil drilling program included 3.0 gross (3.0 net) wells. The Company’s heavy oil drilling program included 2.0 gross (2.0 net) wells at Suffield and 8.0 gross (8.0 net) wells at Lloydminster for a total expenditure of $15.1 million. At Rimbey/Markerville Harvest drilled 9.0 gross (4.5 net wells) for a total expenditure of $18.4 million including a follow-up Ellerslie light oil well that tested at over 600 boe/d. Harvest also drilled a successful Montney exploration oil well in West Central Alberta and is in the process of evaluating the productivity and areal extent of this pool.
Harvest continued to invest in undeveloped land participating in Crown and other land sales acquiring a total of 19,757 net hectares for a total cost of $5.7 million.
Below is a summary of the wells drilled by Harvest in the first quarter of 2011. Harvest overall success rate was 98%.
| Area | Gross | Net |
| Hay River | 38.0 | 38.0 |
| Red Earth | 23.0 | 21.0 |
| Rimbey/Markerville | 9.0 | 4.5 |
| Lloydminster Heavy Oil | 8.0 | 8.0 |
| Kindersley | 7.0 | 7.0 |
| SE Saskatchewan | 3.0 | 3.0 |
| Crossfield | 3.0 | 2.4 |
| Suffield | 2.0 | 2.0 |
| Other Areas | 10.0 | 7.0 |
| Oil sands | 12.0 | 12.0 |
| Total | 115.0 | 104.9 |
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Oil sands
The BlackGold oil sands project continued to progress in the first quarter of 2011 with site clearing and preparation for construction of the central processing facility as well as the drilling of 12 observation wells to monitor the performance and efficiency of the in-situ SAGD process, for a total expenditure of $22.8 million.
BlackGold is located in northeastern Alberta and has existing Energy Resources Conservation Board (“ERCB”) approval for phase 1 project of 10,000 bbl/d and an application has been made for a phase 2 project that is targeted to increase production to 30,000 bbl/d. Approval for phase 2 of the project is expected from the ERCB in 2012. The project will utilize steam assisted gravity drainage, a proven technology that uses innovation in horizontal drilling, with the first oil expected in early 2013 at an estimated production of 10,000 bbl/d.
Decommissioning Liabilities
In connection with property acquisitions and development activities, Harvest records the related decommissioning liabilities in the same year the expenditures occur. The offset to the decommissioning liabilities is capitalized as part of the carrying amount of the assets and are depleted and depreciated over the estimated net proved developed reserves. Once the initial decommissioning liability is measured, it is adjusted at the end of each period to reflect the passage of time as well as changes in the estimated future cash flows of the underlying obligation. Harvest’s decommissioning liabilities increased by $50.3 million during the first three months of 2011 mainly as a result of $38.0 million of liabilities acquired from Hunt, combined with the unwinding of discount of $5.7 million, new liabilities of $5.5 million incurred on new drills and a revision of estimates of $3.1 million, partially offset by $2.0 million of asset settlements.
Goodwill
Goodwill is recorded when the purchase price of an acquired business exceeds the fair value of the net identifiable assets and liabilities of that acquired business. At March 31, 2011, Harvest had $404.9 million (December 31, 2010 - $404.9 million) of goodwill on the balance sheet related to the Upstream segment.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
DOWNSTREAM OPERATIONS
Summary of Financial and Operating Results
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| FINANCIAL | | | | | | | | | |
| Refined products sales(1) | $ | 973,509 | | $ | 339,505 | | | 187% | |
| Purchased products for processing and resale | | 861,791 | | | 331,396 | | | 160% | |
| Gross margin(2) | | 111,718 | | | 8,109 | | | 1278% | |
| | | | | | | | | | |
| Operating expense | | 26,083 | | | 28,655 | | | (9% | ) |
| Purchased energy expense | | 27,856 | | | 15,430 | | | 81% | |
| Marketing expense | | 1,694 | | | 951 | | | 78% | |
| General and administrative | | 441 | | | 441 | | | - | |
| Depreciation and amortization | | 19,400 | | | 20,445 | | | (5% | ) |
| Earnings (Loss) from operations(2) | $ | 36,244 | | $ | (57,813 | ) | | 163% | |
| | | | | | | | | | |
| Capital expenditures | $ | 35,879 | | $ | 8,683 | | | 313% | |
| | | | | | | | | | |
| OPERATING | | | | | | | | | |
| Feedstock volume (bbl/d)(3) | | 97,438 | | | 41,016 | | | 138% | |
| | | | | | | | | | |
| Yield (% of throughput volume)(4) | | | | | | | | | |
| Gasoline and related products | | 32% | | | 24% | | | 33% | |
| Ultra low sulphur diesel and jet fuel | | 35% | | | 29% | | | 21% | |
| High sulphur fuel oil | | 29% | | | 34% | | | (15% | ) |
| | | 96% | | | 87% | | | 10% | |
| | | | | | | | | | |
| Average refining gross margin (US$/bbl)(5) | | 10.96 | | | - | | | 100% | |
(1) Refined product sales and purchased products for processing and resale are net of intra-segment sales of $116.4 million and $87.7 million for the three months ended March 31, 2011 and March 31, 2010, respectively, reflecting the refined products produced by the refinery and sold by the marketing division.
(2)These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.
(3) Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil.
(4)Based on production volumes after adjusting for changes in inventory held for resale.
(5) Average refining gross margin is calculated based on per barrel of feedstock throughput.
Refining Benchmark Prices
| | | Three Months Ended March 31 | |
| | 2011 | | | 2010 | | | Change | |
| WTI crude oil (US$/bbl) | | 94.10 | | | 78.71 | | | 20% | |
| Brent crude oil (US$/bbl) | | 105.01 | | | 77.32 | | | 36% | |
| Mars premium (discount) (US$/bbl) | | 7.45 | | | (2.93 | ) | | 354% | |
| RBOB crack spread (US$/bbl) | | 17.78 | | | 9.47 | | | 88% | |
| Heating Oil crack spread (US$/bbl) | | 23.95 | | | 7.29 | | | 229% | |
| High Sulphur Fuel Oil discount (US$/bbl) | | (5.51 | ) | | (7.97 | ) | | (31% | ) |
| Canadian / U.S. dollar exchange rate | | 1.014 | | | 0.961 | | | 6% | |
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Summary of Gross Margins
| | | | | | Three Months Ended March 31 | | | | |
| | | | | | 2011 | | | | | | | | | 2010 | | | | |
| | | | | | Volumes | | | | | | | | | Volumes | | | | |
| | | | | | (000’s bbls) | | | (US$/bbl) | | | | | | (000’s bbls) | | | (US$/ bbl) | |
| Refinery Sales | | | | | | | | | | | | | | | | | | |
| Gasoline products | $ | 345,883 | | | 3,194 | | $ | 109.81 | | $ | 85,364 | | | 947 | | $ | 86.63 | |
| Distillates | | 374,391 | | | 3,091 | | | 122.82 | | | 112,307 | | | 1,215 | | | 88.83 | |
| High sulphur fuel oil | | 212,038 | | | 2,475 | | | 86.87 | | | 113,369 | | | 1,530 | | | 71.21 | |
| | | 932,312 | | | 8,760 | | | 107.92 | | | 311,040 | | | 3,692 | | | 80.96 | |
| Refinery Feedstock(1) | | | | | | | | | | | | | | | | | | |
| Middle Eastern | | 809,752 | | | 8,648 | | | 94.95 | | | 179,456 | | | 2,249 | | | 76.68 | |
| Russian | | 1,311 | | | 14 | | | 94.95 | | | 112,583 | | | 1,358 | | | 79.67 | |
| South American | | - | | | - | | | - | | | 4,484 | | | 62 | | | 69.50 | |
| | | 811,063 | | | 8,662 | | | 94.95 | | | 296,523 | | | 3,669 | | | 77.67 | |
| Vacuum Gas Oil | | 10,050 | | | | | | | | | 1,861 | | | | | | | |
| Other(2) | | 16,396 | | | | | | | | | 13,116 | | | | | | | |
| Refinery gross margin(3) | $ | 94,803 | | | | | $ | 10.96 | | $ | (460 | ) | | | | $ | - | |
| Marketing | | | | | | | | | | | | | | | | | | |
| Sales(1) | $ | 157,583 | | | | | | | | $ | 116,151 | | | | | | | |
| Cost of products sold | | 140,668 | | | | | | | | | 107,582 | | | | | | | |
| Marketing gross margin(3) | $ | 16,915 | | | | | | | | $ | 8,569 | | | | | | | |
(1) Cost of feedstock includes all costs of transporting the crude oil to the refinery in Newfoundland.
(2)Includes inventory adjustments, additives and blendstocks
(3)This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A.
Feedstock throughput averaged 97,438 bbl/d in the first quarter of 2011, an increase of 138% over 41,016 bbl/d average feedstock throughput in the first quarter of the prior year. Throughput rates in 2011 were reflective of normal operations. The substantially lower throughput rate during the three months ended March 31, 2010 was the result of a ten-week unplanned shutdown.
The increase in the refinery gross margin for the three months ended March 31, 2011 as compared to the first quarter of the prior year reflects the significantly stronger global refinery margin and improved operational performance, partially offset by the increase in the sour crude premium. The Downstream operations’ refining gross margin is impacted by several factors including the configuration of the refinery product yields, timing of sales under the Supply and Offtake Agreement (‘SOA”) with Vitol Refining S.A., transportation costs, location differentials, quality differentials and variability in our throughput volume over a given period of time.
Refinery sales increased by $621.3 million in the first quarter of 2011 from $311.0 million in the same quarter of 2010 due to the increase in sales volumes and higher market prices for refined products.
The cost of refinery feedstock in the first quarter of 2011 was a US$0.85/bbl premium to the benchmark WTI as compared to a discount of US$1.04/bbl in the same period of the prior year, with the change from a discount to a premium in correlation with the market sour crude differential.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
During the three months ended March 31, 2011, the Canadian dollar continued to strengthen as compared to the US dollar. The strengthening of the Canadian dollar in 2011 has negatively impacted the contribution from the refinery operations relative to the prior year as substantially all of its gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.
Operating Expenses
| | | | | | Three Months Ended March 31 | | | | |
| | | | | | 2011 | | | | | | | | | 2010 | | | | |
| | | Refining | | | Marketing | | | Total | | | Refining | | | Marketing | | | Total | |
| | | | | | | | | | | | | | | | | | | |
| Operating cost | $ | 21,577 | | $ | 4,506 | | $ | 26,083 | | $ | 25,968 | | $ | 2,687 | | $ | 28,655 | |
| Purchased energy | | 27,856 | | | - | | | 27,856 | | | 15,430 | | | - | | | 15,430 | |
| | $ | 49,433 | | $ | 4,506 | | $ | 53,939 | | $ | 41,398 | | $ | 2,687 | | $ | 44,085 | |
| ($/bbl of feedstock throughput) | | | | | | | | | | | | | | | | | | |
| Operating cost | $ | 2.46 | | | - | | | - | | $ | 7.04 | | | - | | | - | |
| Purchased energy | | 3.18 | | | - | | | - | | | 4.18 | | | - | | | - | |
| | $ | 5.64 | | | - | | | - | | $ | 11.22 | | | - | | | - | |
During the three months ended March 31, 2011, refining operating expenses of $2.46/bbl decreased 65% as compared to the $7.04/bbl in the prior period. The lower cost in the first quarter of 2011 is indicative of normal operations whereas the higher cost per barrel in the prior year reflects higher maintenance costs and lower average daily throughput.
Purchased energy, consisting of low sulphur fuel oil (“LSFO”) and electricity, is required to provide heat and power to refinery operations. The 81% increase in purchased energy costs in the first quarter of 2011 over the $15.4 million in the prior period is due to a volume variance of $10.8 million combined with a price variance of $1.6 million. The decrease in the per barrel cost of energy is attributable to the increased throughput rate in the first quarter of 2011.
Capital Expenditures
Capital spending for the three months ended March 31, 2011 totaled $35.9 million (2010 - $8.7 million) relating to various capital improvement projects including $14.6 million (2010 - $5.9 million) for the debottlenecking project.
Depreciation and Amortization Expense
| | | | | | Three Months Ended March 31 | | | | |
| | | | | | 2011 | | | | | | | | | 2010 | | | | |
| | | Refining | | | Marketing | | | Total | | | Refining | | | Marketing | | | Total | |
| Depreciation and amortization | $ | 18,479 | | $ | 921 | | $ | 19,400 | | $ | 19,573 | | $ | 872 | | $ | 20,445 | |
The process units are amortized over an average useful life of 20 to 30 years.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
RISK MANAGEMENT, FINANCING AND OTHER
Cash Flow Risk Management
The following is a summary of Harvest’s risk management contracts outstanding at March 31, 2011:
| Contracts not Designated as Hedges | |
| Contract Quantity | | Type of Contract | | | Term | | | Contract Price | | | Fair value | |
| 30 MWh | | Electricity price swap contracts | | | Jan - Dec 2011 | | | Cdn $46.87 | | $ | 4,561 | |
| USD$16,900 | | Foreign exchange contract | | | Mar - April 2011 | | $ | 0.9714Cdn/USD | | | (29 | ) |
| | | | | | | | | | | $ | 4,532 | |
| Contracts Designated as Hedges | |
| Contract quantity | | Type of Contract | | | Term | | | Contract Price | | | Fair value | |
| 8200 bbls/day | | Crude oil price swap contract | | | Jan - Dec 2011 | | | US $91.23/bbl | | $ | (36,525 | ) |
| 5000 bbls/day | | Crude oil price swap contract | | | Feb - Dec 2011 | | | US $95.82/bbl | | | (16,152 | ) |
| 3200 bbls/day | | Crude oil price swap contract | | | Mar - Dec 2011 | | | US $95.87/bbl | | | (10,295 | ) |
| 16,400 bbls/day | | | | | | | | | | $ | (62,972 | ) |
For the three months ended March 31, 2011, the total realized gain and unrealized gain recognized in the consolidated statement of income relating to the electricity price swap contracts was $2.3 million and $3.6 million respectively. In comparison to the first quarter of 2010, Harvest had electricity price swap contracts in place for 25.0 MWh at an average contract price of $59.22/MWh. Harvest recognized a realized loss of $1.0 million and an unrealized loss of $0.1 million in 2010 from these contracts.
During the first quarter of 2011, Harvest entered into foreign exchange forward contracts to reduce its exposure to fluctuations in the U.S. dollar exchange rate. For the three months ended March 31, 2011, Harvest recognized an unrealized loss of $0.03 million.
Harvest entered into crude oil swap contracts and designated them as cash flow hedges to reduce its exposure to crude oil price fluctuations in its forecast petroleum sales. The effective portion of the unrealized loss of $40.4 million (net of deferred tax asset of $14.7 million) relating to the hedges was included in other comprehensive income (2010 – $nil). The ineffective portion of the cash flow hedges recognized in the consolidated income statement for the three months ended March 31, 2011 was $0.3 million (2010 – $nil). During the first quarter of 2011, a loss of $3.0 million (2010 - $nil) was reclassified from accumulated other comprehensive income to petroleum, natural gas, and refined product sales.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Financing Costs
| | | Three Months Ended March 31 | |
| | | 2011 | | | 2010 | | | Change | |
| Bank loan | $ | 1,633 | | $ | 1,370 | | | 19% | |
| Convertible Debentures | | 12,327 | | | 11,927 | | | 3% | |
| Senior notes | | 8,776 | | | 3,984 | | | 120% | |
| Amortization of deferred finance charges | | 281 | | | 1,986 | | | (86% | ) |
| Interest and other financing charges | $ | 23,017 | | $ | 19,267 | | | 19% | |
| Capitalized interest | | (1,296 | ) | | - | | | - | |
| | | 21,721 | | | 19,267 | | | 13% | |
| Unwinding of discount on decommissioning liabilities | | 5,796 | | | 5,723 | | | 1% | |
| Total finance costs | $ | 27,517 | | $ | 24,990 | | | 10% | |
Interest and other financing charges, including the amortization of related financing costs, increased by $3.8 million (19%) compared to the prior year interest expense. The increase from prior year is primarily due to the increased amount of senior notes principle outstanding at March 31, 2011, compared to 2010.
Interest expense on Harvest’s bank loan was $1.6 million (2010 - $1.4 million), in the first quarter of 2011, which was relatively consistent with the same quarter in the prior year. During the quarter, interest charges on our bank loan reflected an effective interest rate of 3.06% (2010 – 1.56%) .
Interest expense on our senior notes has increased by $4.8 million from the first quarter of 2011 due to the higher principle balance of the 67/8% senior notes issued in the fourth quarter of 2010, as compared to the 77/8% senior notes outstanding during the first quarter of 2010, which were fully redeemed by the end of the 2010 fiscal year.
During the first quarter of 2011, $1.3 million (2010 - $nil) of interest expense was capitalized to the BlackGold oil sands project and the Downstream debottlenecking project.
Currency Exchange
Currency exchange gains and losses are attributed to the changes in the value of the Canadian dollar relative to the U.S. dollar on our U.S. dollar denominated 67/8% Senior Notes as well as any other U.S. dollar cash balances. At March 31, 2011 the Canadian dollar has strengthened compared to March 31, 2010 and December 31, 2010, resulting in an unrealized foreign exchange gain of $9.6 million for the three months ended March 31, 2011 (2010 - $6.7 million loss). The realized foreign exchange gain was $0.2 million for the three months ended March 31, 2011 (2010 - $0.4 million loss), resulting from the settlement of U.S. dollar denominated transactions.
The cumulative translation adjustment recognized in other comprehensive income represents the translation of the Downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars using the current rate method. During the first quarter of 2011, the strengthening of the Canadian dollar relative to the U.S. dollar resulted in $23.9 million of a net cumulative translation loss (2010 – $26.9 million) as the weaker U.S. dollar results in a decrease in the relative value of the net assets in our Downstream operations.
Deferred Income Taxes
For the three months ended March 31, 2011, Harvest has recorded a deferred income tax expense of $3.8 million. Our deferred income tax liability will fluctuate during each accounting period to reflect changes in the respective temporary differences between the book value and tax basis of their assets as well as further legislative tax rate changes. Currently, the principal source of our temporary differences is the difference between the net book value of the Company’s property, plant and equipment versus their unclaimed tax pools.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Contractual Obligations and Commitments
Harvest has contractual obligations and commitments entered into in the normal course of operations including the purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and land lease obligations. These obligations are of recurring and consistent nature and impact cash flow in an ongoing manner. As at March 31, 2011, Harvest has the following significant contractual commitments:
| | | | | | Maturity | | | | |
| | | 1 year | | | 2-3 years | | | 4-5 years | | | After 5 years | | | Total | |
| Debt Repayments(1) | $ | - | | $ | 529,394 | | $ | 236,579 | | $ | 484,800 | | $ | 1,250,773 | |
| Debt interest payments(1) | | 94,959 | | | 151,587 | | | 87,483 | | | 49,995 | | | 384,024 | |
| Purchase Commitments(2) | | 208,241 | | | 102,380 | | | - | | | - | | | 310,621 | |
| Operating Leases | | 8,122 | | | 14,264 | | | 6,256 | | | 423 | | | 29,065 | |
| Transportation Agreements(3) | | 11,207 | | | 14,848 | | | 5,432 | | | 3,124 | | | 34,611 | |
| Feedstock & other purchase commitments | | 719,992 | | | - | | | - | | | - | | | 719,992 | |
| Pension contributions(4) | | 5,271 | | | 8,570 | | | 7,883 | | | 3,019 | | | 24,743 | |
| Decommissioning liabilities(3) | | 20,932 | | | 34,479 | | | 39,855 | | | 1,297,519 | | | 1,392,785 | |
| Total | $ | 1,068,724 | | $ | 855,522 | | $ | 383,488 | | $ | 1,838,880 | | $ | 4,146,614 | |
| (1) | Assumes constant foreign exchange rate. |
| (2) | Relates to drilling commitments, AFE commitments, BlackGold oil sands project commitment and Downstream purchase commitments. |
| (3) | Relates to firm transportation commitments. |
| (4) | Relates to the expected contributions to employee benefit plans. |
| (5) | Represents the undiscounted obligation by period. |
Off Balance Sheet Arrangements
As of March 31, 2011, there were no off balance sheet arrangements in place.
LIQUIDITY
For the three months ended March 31, 2011, cash flow from operating activities was $146.8 million (2010 - $78.1 million) including $32.8 million (2010 - $6.1 million) provided by a reduction in non-cash working capital and $2.0 million (2010 - $5.7 million) used in the settlement of asset retirement obligations. At March 31, 2011, Harvest’s financing activities provided $524.1 million of cash, including $505.4 million of capital injection from KNOC and $18.6 million of net borrowings from its credit facility. The capital injection from KNOC was used to fund the acquisition of the Hunt assets. Harvest funded $275.5 million of capital expenditures and net asset acquisition activity during the first quarter of 2011 with cash generated from operating activities and financing activities.
Harvest had working capital deficiency of $146.0 million at March 31, 2011, as compared to a $2.1 million deficiency at December 31, 2010. The negative working capital at March 31, 2011 is primarily related to the use of the $40 million deposit paid in 2010 for the Hunt acquisition, increased capital accruals to fund capital expenditures in the first quarter of 2011 and the increased liability arising from the risk management contracts. The Company’s working capital is expected to fluctuate from time to time, and will be funded from cash flows from operations and borrowings from Harvest’s credit facility, as required.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
Through a combination of cash available at March 31, 2011, cash from operating activities and available undrawn credit facility, it is anticipated that Harvest will have adequate liquidity to fund future operations, debt repayments and forecasted capital expenditures (excluding major acquisitions). Refer to the “Contractual Obligations and Commitments”section above for Harvest’s future commitments and the discussion below on certain significant items.
BlackGold Oil Sands Project
Harvest signed a $311 million engineering, procurement and construction (“EPC”) contract in 2010 for phase 1 of our oil sands project, of which $55.1 million (including a $31.1 million deposit), has been paid to date at March 31, 2011. Phase 1 development of the BlackGold assets is expected to be completed by early 2013. Harvest expects to fund the future capital expenditures with capital injections funded by KNOC, future cash flow from operating activities and the undrawn credit facility.
Supply and Offtake Agreement (“SOA”)
The SOA provides working capital financing for its inventories of crude oil and substantially all refined products held for sale. Pursuant to the SOA, Harvest estimates that Vitol held inventories of VGO and crude oil feedstock (both delivered and in-transit) valued at approximately $609.6 million at March 31, 2011 and $774.7 million at December 31, 2010, which would have otherwise been assets of Harvest. Subsequent to March 31, 2011 Vitol provided Harvest a six-month notice to terminate the SOA effective November 1, 2011. Harvest is currently in the process of evaluating various options to procure crude feedstock subsequent to the termination date.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
CAPITAL RESOURCES
The following table summarizes our capital structure as at March 31, 2011 and December 31, 2010 as well as provides the key financial ratios contained in Harvest’s revolving credit facility.
| | | March 31, 2011 | | | December 31, 2010 | |
| Debts | | | | | | |
| Revolving credit facility(1) | $ | 32,000 | | $ | 14,000 | |
| 67/8% senior notes, at principal amount (US$500 million)(2) | | 484,800 | | | 497,300 | |
| Convertible debentures, at principal amount | | 733,973 | | | 733,973 | |
| Total Debt | $ | 1,250,773 | | $ | 1,245,273 | |
| | | | | | | |
| Shareholder’s Equity | | | | | | |
| 386,078,649 issued at March 31, 2011 | $ | 3,495,924 | | $ | - | |
| 335,535,047 issued at December 31, 2010 | | - | | $ | 3,016,855 | |
| | | | | | | |
| Total Capitalization | $ | 4,746,697 | | $ | 4,262,128 | |
| | | | | | | |
| Financial Ratios(3) | | | | | | |
| Secured Debt to Annualized EBITDA(4)(5) | | 0.08 | | | 0.06 | |
| Total Debt to Annualized EBITDA(4)(6) | | 1.89 | | | 2.38 | |
| Senior Debt to Total Capitalization(5)(7) | | 1% | | | 1% | |
| Total Debt to Total Capitalization(6)(7) | | 29% | | | 33% | |
| (1) | Net of transaction costs – $29.7 million (2010 - $11.4 million) |
| (2) | Principal amount converted at the period end exchange rate. |
| (3) | Calculated based on Harvest’s credit facility covenant requirements (see note 11 of the March 31, 2011 financial statements) |
| (4) | Annualized Earnings Before Interest, Taxes, Depreciation and Amortization based on twelve month rolling average. |
| (5) | “Senior Debt” includes letter of credit, bank debt and guarantees |
| (6) | “Total Debt” includes the secured debt, convertible debentures and notes |
| (7) | “Total Capitalization” includes total debt and shareholder’s equity |
Credit Facility
On April 29, 2011, Harvest’s revolving credit facility (“the Facility”) was extended by 2 years to April 30, 2015. The minimum rate charged on the Facility was also amended from 200 bps to 175 bps over bankers’ acceptance rates as long as Harvest’s secured debt to EBITDA ratio remains below or equal to one. The borrowing capacity of the Facility remains at $500 million and the financial covenants calculation as disclosed above remain unchanged.
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| | MANAGEMENT’S DISCUSSION AND ANALYSIS |
SUMMARY OF QUARTERLY RESULTS
The following table and discussion highlights our first quarter of 2011 relative to the preceding 4 quarters:
| | | 2011 | | | | | | 2010 | | | | |
| | | Q1 | | | Q4 | | | Q3 | | | Q2 | | | Q1 | |
| | | | | | | | | | | | | | | | |
| Revenue(1) | $ | 1,218,702 | | $ | 1,255,403 | | $ | 951,384 | | $ | 1,024,565 | | $ | 569,480 | |
| Net income (loss) | | 37,961 | | | (12,332 | ) | | (26,083 | ) | | (22,796 | ) | | (19,952 | ) |
| Cash from operating activities | | 146,828 | | | 131,746 | | | 97,555 | | | 122,076 | | | 78,107 | |
| Total long-term financial debt | | 1,216,162 | | | 1,239,024 | | | 1,251,658 | | | 1,153,972 | | | 1,150,321 | |
| | | | | | | | | | | | | | | | |
| Total assets | | 6,041,118 | | | 5,388,740 | | | 5,303,486 | | | 4,764,141 | | | 4,757,865 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Upstream total daily sales volumes (boe/d) | | 53,331 | | | 50,054 | | | 47,777 | | | 49,597 | | | 50,178 | |
| Upstream realized price prior to hedges ($/boe) | $ | 59.19 | | $ | 56.03 | | $ | 52.71 | | $ | 54.41 | | $ | 60.17 | |
| Downstream average daily throughput (bbl/d) | | 97,438 | | | 111,317 | | | 96,514 | | | 94,833 | | | 41,016 | |
| Downstream average refining margin ($US/bbl) | $ | 10.96 | | $ | 6.13 | | $ | 3.02 | | $ | 8.56 | | $ | - | |
(1) Revenues are comprised of revenues net of royalties from Upstream operations as well as sales of refined products from Downstream operations.
The quarterly revenues and cash from operating activities are impacted by the Upstream sales volume and realized prices and Downstream throughput volume and gross margins. Significant items that impacted Harvest’s quarterly revenues include:
- Revenues were the highest in the fourth quarter of 2010, followed by the first quarter of 2011, reflecting higher commodity prices, strong sales volumes in the Upstream operations and improved throughput volumes from the Downstream operations.
- The increasing Upstream sales volumes since the third quarter of 2010 were mainly attributable to the acquisition of oil and gas assets in the third quarter of 2010 and first quarter of 2011.
- Downstream’s refining margin increased in the fourth quarter or 2010, and then more prominently in the first quarter of 2011, reflecting the improving global refining crack spreads.
- Revenues were the lowest in the first quarter of 2010, primarily due to the shutdown of the refinery units in the Downstream operations.
Net income (loss) reflects both cash and non-cash items. Changes in non-cash items including future income tax, DDA&A expense, impairment of long-lived assets, unrealized foreign exchange gains and losses and unrealized gains on risk management contracts impact net income from period to period. For these reasons, the net income (loss) may not necessarily reflect the same trends as net revenues or cash from operating activities, nor is it expected to.
Total assets have increased significantly from the second quarter of 2010 to the third quarter of 2010 due to the acquisition of the BlackGold assets in August and certain oil and gas assets in September 2010. The significant increase in total assets in the first quarter of 2011 was due to the Hunt acquisition and Harvest’s active winter drilling programs.
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OUTLOOK
We were very pleased with Harvest’s financial and operational performance in the first quarter.
A strengthening Canadian dollar relative to the US dollar, a widening differential between WTI oil prices and ocean borne crude oil prices and an increased spread between the light and heavy oil prices muted the increase in crude oil prices relative to what would have occurred otherwise. Despite this, the 2011 realized liquids prices were higher than expectations and given the liquids-weighted nature of the Upstream asset base, we were very pleased with the Upstream financial performance. While crude oil prices remain volatile, it appears that oil prices will remain attractive with ongoing growth in world demand. On natural gas prices, we have seen stabilization at current levels as lower drilling has reduced supply relative to demand and the first sign that even lower prices are unlikely and an improvement may be coming in the future. Refining margins have also shown significant improvement as global demand for refined products continues to increase.
As anticipated, the first quarter of 2011 was active for our Upstream business with our oil-weighted asset base. Leveraging off the success achieved in our first quarter capital investment program, we are increasing the Upstream capital investment by $116 million to $566 million. We expect production to average approximately 60,000 boe/d for 2011 with strong performance from our assets and capital investment program offsetting the production reductions associated with the non-operated Rainbow Pipeline disruption, the impact of northern Alberta forest fires and flooding in SE Saskatchewan. Due to these recent events, Harvest’s second quarter production is now expected to average approximately 56,000 boe/d.
Production is expected to be approximately 70% crude oil and liquids with the remainder natural gas. For the balance of 2011, our capital spending will continue to focus on our active drilling program and investment in Enhanced Oil Recovery (EOR) projects. Our drilling plan will focus on oil/liquids weighted opportunities and also on economic growth opportunities. The benefit of the incremental capital investment program will largely occur in 2012 as wells are tied in. We are forecasting general and administrative costs at approximately $2.73 per boe and operating costs to be $14.54 per boe.
Downstream operational performance was largely as expected in the first quarter with the improved global refining margins resulting in better than expected financial performance. With a longer turnaround than originally anticipated as we advance our debottleneck projects, we are now anticipating throughput for the second quarter and the year to be approximately 38,000 and 85,000 bbl/d respectively, with unit costs of approximately $7.60/bbl for the remainder of 2011. Capital spending for the year remains at approximately $199 million.
Harvest has managed fluctuations in interest rates through a mix of variable and fixed rate financing. Our bank borrowings under our credit facility totaled $29.7 million at March 31, 2011, representing approximately 3% of our total debt. As a result, the majority of our interest rate exposure is fixed, reducing our exposure to increasing interest rates.
While we do not speculate on commodity prices or refining margins, we may enter into commodity price risk management contracts from time-to-time to mitigate some portion of our price volatility with the objective of stabilizing our cash flow from operating activities. For the remainder of 2011, we have 16,400 bbl/d WTI hedges under contract with an average price of US$93.54/bbl.
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INTERNATIONAL FINANCIAL REPORTING STANDARDS (“IFRS”)
On January 1, 2011, Harvest adopted IFRS, with January 1, 2010 as the “transition date”. A full description of our new accounting policies is outlined in Note 3 to our unaudited interim consolidated financial statements for the three months ended March 31, 2011. Additionally, transition date information and reconciliations between IFRS and Canadian GAAP for comparative periods in 2010 are described in Note 22 to our unaudited interim consolidated financial statements. The adoption of IFRS has not led to any changes in the business operations, capital strategies or funds flow of the Company. Harvest’s nature and type of critical accounting estimates remain unchanged upon transition to IFRS; however some accounting differences exist relating to the recognition and measurement of these estimates, which are discussed below. A description of these estimates is outlined in Note 2 to our unaudited interim consolidated financial statements for the three months ended March 31, 2011.
Significant Accounting Differences and Accounting Policies
The following outlines significant accounting policy choices and differences between IFRS and Canadian GAAP applicable from the transition date.
Depletion and Depreciation
Under IFRS, Harvest aggregates its property, plant and equipment (“PP&E”) into major components for depletion, depreciation and amortization. For the Upstream PP&E, costs accumulated within each component are depleted using the unit-of-production method based on estimated proved developed reserves, whereas under Canadian GAAP, estimated proved reserves were used. The carrying value of the PP&E under IFRS differed from that under Canadian GAAP as a result of changes in the accounting of decommissioning liabilities and dispositions of PP&E as discussed below.
Exploration & Evaluation (E&E) Assets
Under IFRS, costs incurred prior to obtaining the legal right to explore must be expensed while under Canadian GAAP these costs were capitalized in PP&E. Once the legal rights to explore are acquired, all costs directly associated with the E&E are capitalized. E&E costs are those expenditures incurred for identifying, exploring and evaluating new pools in an area where technical feasibility and commercial viability has not yet been determined.
When technical feasibility and commercial viability are established, the relevant expenditure is transferred to PP&E after impairment is assessed and any resulting impairment loss is recognized as E&E expense. If there are no future plans for development activity and technical feasibility or commercial viability is not expected, E&E assets are assessed for impairment.
Impairment
Under IFRS, impairment testing is performed at the cash-generating unit (“CGU”) level, which is lower than the country level under Canadian GAAP. As a consequence, impairment provisions are more likely to occur. Under IFRS, impairments other than goodwill impairments may be reversed in the event future conditions change. A one-step approach is used for the testing and measuring impairment under IFRS. Under this approach, the asset or the CGU carrying value is compared against its recoverable amount. Under Canadian GAAP a two-step approach was used; the first step is comparing the asset carrying value with undiscounted cash flows to determine if an impairment exists. If the first step fails, then impairment is measured by comparing the asset carrying value to its fair value.
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Decommissioning Liabilities
Under IFRS, the discount rate is adjusted each reporting period to reflect the current market rate. Recognition criteria under Canadian GAAP and IFRS also differ as under Canadian GAAP, ARO was recorded when a legal obligation exists to abandon an asset, whereas under IFRS, decommissioning liability should be recognized when a legal or constructive obligation exists.
Dispositions
Under Canadian GAAP, proceeds on the dispositions of oil and gas properties were credited to the full cost pool and no gain or loss was recognized unless the effect of the sale would have changed the DD&A rate by 20% or more. Under IFRS, gains and losses are recognized on all oil and gas property dispositions and calculated as the difference between net proceeds and the carrying value of the net assets disposed.
Acquisitions
Under IFRS, acquisition costs for business combinations are expensed. Under Canadian GAAP, such costs were capitalized as part of PP&E.
Post-employment benefits
Under Canadian GAAP, the Company amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the consolidated financial statements. Under IFRS, actuarial gains and losses are recognized directly in other comprehensive income in the period in which they occur.
Deferred Income Taxes
Under IFRS, Harvest is required to recognize future income taxes arising from the difference between historical and current exchange rates on the translation of non-monetary assets, whereas Canadian GAAP precludes this.
First Time Adoption of IFRS
IFRS 1 “First-time Adoption of International Financial Reporting Standards” establishes the transitional requirements for the preparation of financial statements upon first time adoption of IFRS. IFRS 1 generally requires an entity to comply with IFRS effective at the reporting date and to apply these retrospectively to the opening balance sheet, the comparative period and the reporting period. The standard allows certain optional exceptions from full retrospective application and other elections on transition, which the Company has applied as follows:
Business Combinations Exemption
The Company has applied the business combinations exemption in IFRS 1. It has not restated business combinations that took place prior to the January 1, 2010 transition date.
Deemed Cost Election for Oil and Gas Assets
Under Canadian GAAP, the Company accounted for its oil and gas properties in one cost centre using full cost accounting. The Company elected to apply the exemption in IFRS 1 available to full cost oil and gas entities to its Upstream PP&E and measure its oil and gas properties at the transition date on the following basis:
- E&E assets at the amount determined under Canadian GAAP; and
- the remainder allocated to the underlying PP&E assets on a pro rata basis using proved and probable reserve values discounted at 10 percent at the transition date.
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Fair Value as Deemed Cost Exemption
The Company elected to use the fair value as deemed cost exemption on its Downstream PP&E at the transition date.
Lease Exemption
The Company has elected to carry forward assessments made under Canadian GAAP for arrangements containing leases. The assessment of arrangements containing leases results in the same outcome under IAS 17 and IFRIC 4 “Determining whether an Arrangement contains a Lease”.
Decommissioning Liabilities
Harvest has applied the deemed cost election for oil and gas assets under IFRS 1 and as such decommissioning liabilities at the transition date have been measured in accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The Company recognized directly in retained earnings any difference between the remeasured amount and the carrying amount of those liabilities at the transition date.
For the Downstream decommissioning liabilities, Harvest applied the exemption from full retrospective application of IAS 37 under IFRS 1. As such, the Company measured the decommissioning liabilities at the transition date, and recognized the corresponding charge in retained earnings
RECENT PRONOUNCEMENTS
The Company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company.
Effective January 1, 2013, Harvest will be required to adopt IFRS 9, “Financial Instruments”, which is the result of the first phase of the IASB’s project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. Harvest is in the process of determining the potential impact on the adoption of this new standard.
On May 12, 2011 the IASB issued three new standards: IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements” and IFRS 12, “Disclosure of Interest in Other Entities”.These new standards are effective for annual periods beginning on or after January 1, 2013. IFRS 10 replaces the consolidation requirements in SIC-12, “Consolidation – Special Purpose Entities” and a portion of IAS 27, “Consolidated and Separate Financial Statements”. IFRS 10 builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company and provides additional guidance to assist in the determination of control where this is difficult to assess. IFRS 11 provides for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form (as is currently the case) and requires a single method to account for interests in jointly controlled entities (equity method). IFRS 12 is a new and comprehensive standard on disclosure requirements for all forms of interests in other entities, including joint arrangements, associates, special purpose vehicles and other off balance sheet. Harvest will assess for the potential impact on the adoption of these new standards.
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OPERATIONAL AND OTHER BUSINESS RISKS
Harvest’s operational and other business risks remain unchanged from those discussed in our MD&A for the ended December 31, 2010 as filed on SEDAR atwww.sedar.com, except for the addition of the following risks:
Upstream Operations
- The operation of petroleum and natural gas properties requires physical access for people and equipment on a regular basis which could be affected by weather, accidents, government regulations or third party actions.
Downstream Operations
- The refinery utilizes a SOA to facilitate the supply of crude feedstock to the refinery and the offtake of refined products. This agreement has termination rights and replacement arrangements may not be as favorable and may result in an increase in costs.
- The operation of the refinery requires physical access for people and equipment on a regular basis which could be affected by weather, accidents, government regulations or third party actions.
- The demand for skilled labor remains high in Newfoundland and the supply of skilled labor remains limited. There is a risk that we may have difficulty in sourcing skilled labor and the cost of replacement labor would result in increased operating and capital costs.
INTERNAL CONTROL OVER FINANCIAL REPORTING
In connection with the adoption of IFRS, Harvest established additional internal controls over financial reporting, as necessary, to review and validate the conversion to IFRS and relevant transitional activities including restatement of comparative financial information for 2010 and related disclosures. There were no other significant changes in internal controls over financial reporting during the three months ended March 31, 2011 that have materially affected, or are reasonably likely to materially effect our internal controls over financial reporting.
ADDITIONAL INFORMATION
Further information about us, can be accessed under our public filings found on SEDAR atwww.sedar.com or atwww.harvestenergy.ca. Information can also be found by contacting our Investor Relations department at (403) 265-1178 or at 1-866-666-1178.
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