SELECTED INFORMATION
The table below provides a summary of our financial and operating results for the three and nine months ended September 30, 2010.
| | | Three Months Ended | | | Nine Months Ended | |
FINANCIAL ($000s except where noted) | | September 30, 2010 | | | September 30, 2010 | |
| | | | | | | |
Revenue, net (1) | | | 951,735 | | | | 2,546,393 | |
| | | | | | | | | |
| Cash From Operating Activities | | | 97,711 | | | | 298,180 | |
| | | | | | | | | |
Net Income (Loss)(2) | | | (22,079 | ) | | | (43,115 | ) |
| | | | | | | | | |
| Bank debt | | | 288,700 | | | | 288,700 | |
77/8% Senior debt | | | 216,931 | | | | 216,931 | |
Convertible debentures(3) | | | 769,920 | | | | 769,920 | |
Total financial debt(3) | | | 1,275,551 | | | | 1,275,551 | |
| | | | | | | | | |
| Total Assets | | | 5,262,694 | | | | 5,262,694 | |
| | | | | | | | | |
| UPSTREAM OPERATIONS | | | | | | | | |
| Total daily sales volumes (boe/day) | | | 47,777 | | | | 49,175 | |
| Operating Netback ($/boe) | | $ | 30.05 | | | $ | 32.00 | |
| | | | | | | | | |
| Capital asset additions (excluding acquisitions) | | | 90,268 | | | | 256,111 | |
| Property and business acquisitions (dispositions), net | | | 146,507 | | | | 176,742 | |
| Abandonment and reclamation expenditures | | | 5,796 | | | | 13,813 | |
| | | | | | | | | |
| DOWNSTREAM OPERATIONS | | | | | | | | |
| Average daily throughput (bbl/d) | | | 96,514 | | | | 77,658 | |
| Average Refining Margin (US$/bbl) | | | 3.02 | | | | 4.67 | |
| | | | | | | | | |
| Capital asset additions | | | 21,501 | | | | 38,643 | |
| (1) | Revenues are net of royalties. |
| (2) | Net Income (Loss) includes a future income tax recovery of $17.6 million and $37.6 million for the three and nine months ended September 30, 2010 respectively and an unrealized net loss from risk management activities of $1.0 million and a net gain of $1.3 million for the three and nine months ended September 30, 2010 |
| (3) | Includes current portion of convertible debentures. |
MANAGEMENT’S DISCUSSION AND ANALYSIS
Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations of Harvest Operations Corp. should be read in conjunction with the unaudited interim consolidated financial statements of Harvest Operations Corp. for the three and nine months ended September 30, 2010 and the MD&A for the three and six months ended June 30, 2010. The information and opinions concerning our future outlook are based on information available at November 5, 2010.
On December 22, 2009, KNOC Canada Ltd. (“KNOC Canada”), a wholly owned subsidiary of Korea National Oil Corporation (“KNOC”), purchased all of the issued and outstanding trust units of Harvest Energy Trust (the “Trust) and applied December 31, 2009 as the deemed acquisition date. The acquisition of all the issued and outstanding trust units of the Trust resulted in a change of control in which KNOC Canada became the sole unitholder of the Trust.
On May 1, 2010, an internal reorganization was completed pursuant to which the Trust was dissolved and the Trust’s wholly owned subsidiary and manager of the Trust, Harvest Operations Corp., was amalgamated into KNOC Canada to continue as one corporation under the name Harvest Operations Corp. (“Harvest” or the “Company”). The carrying values of Harvest’s assets and liabilities were determined from the existing carrying values of KNOC Canada’s assets and liabilities and therefore reflect the fair values established through the purchase.
KNOC Canada was incorporated on October 9, 2009 and did not have any results from operations or cash flows in the period from October 9, 2009 to December 31, 2009 aside from capital injections from Korea National Oil Corporation to finance the purchase of the Trust. As KNOC Canada acquired the Trust on December 22, 2009 the Company’s financial statements for the interim period ended September 30, 2010 do not include prior year comparative information. Unaudited pro forma consolidated results of operations have been included in this MD&A to reflect the impact of the acquisition of the Trust, had the acquisition occurred on January 1, 2009.
In this MD&A, reference to "Harvest", “Company”, "we", "us" or "our" refers to Harvest Operations Corp. and all of its controlled entities on a consolidated basis. All references are to Canadian dollars unless otherwise indicated. Tabular amounts are in thousands of dollars unless otherwise stated. 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 51-101, we also disclose our reserves on a company interest basis which is not a term defined under National Instrument 51-101. This information may not be comparable to similar measures by other issuers.
NON-GAAP MEASURES
Throughout this MD&A we have referred to certain measures of financial performance that are not specifically defined under Canadian GAAP. Cash G&A and Operating Netbacks are non-GAAP measures used extensively in the Canadian energy sector for comparative purposes. Cash G&A are G&A expenses excluding the effect of our unit based compensation plans, while Operating Netbacks are always reported on a per boe basis, and include gross revenue, royalties, operating expenses, and transportation and marketing expenses. Gross Margin is also a non-GAAP measure and 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 and Cash From Operations are also non-GAAP measures and 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. This information may not be comparable to similar measures by other issuers.
FORWARD-LOOKING INFORMATION
This MD&A highlights significant business results and statistics from our consolidated financial statements for the three and nine months ended September 30, 2010 and the accompanying notes thereto. In the interest of providing our investors and potential investors 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. 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 activity, acquisitions and dispositions, capital spending, reserve estimates, distributions, 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”, “expects”, 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. We assume 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.
REVIEW OF OVERALL PERFORMANCE
Consolidated cash flow from operating activities was $97.7 million and $298.2 million for the three and nine months ended September 30, 2010. Third quarter cash flow represents a decrease of $24.6 million from the second quarter of 2010. This decrease is due to a $37.9 million decrease in cash contribution from our Downstream operations offset by a $10.9 million decrease in working capital requirement.
Upstream Operations
The cash contribution from Upstream operations remained relatively unchanged at $122.4 million in the third quarter compared to $122.3 million in the second quarter of 2010. Third quarter 2010 sales volumes were down by 1,820 boe/d compared to the second quarter of 2010, with the main decreases in light/medium oil and natural gas as a result of power outages and third party plant processing constraints arising from turnarounds. Third quarter 2010 operating costs decreased $5.0 million primarily due to the 56% decrease in the average Alberta Power Pool electricity price. Third quarter upstream capital spending of $90.3 million includes the drilling of 27 (net 23.0) wells with a success ratio of 99%. In addition, we acquired a package of petroleum and natural gas assets which included the remaining 40% interest in Red Earth Partnership for total cash consideration of $146.2 million.
Downstream Operations
The negative cash contribution of $9.2 million from the Downstream operations in the third quarter compared to a $28.7 million contribution in the prior quarter reflects the impact of an unplanned shutdown of the hydrogen and isomax units and the resulting shift in our product yields. The average daily throughput for the third quarter increased 1,681 bbls/d over the second quarter to 96,514 bbls/d, but remained below the nameplate capacity of 115,000 bbls/d due to the unplanned shutdown. Operating expenses were $43.2 million in the third quarter of 2010 and were $4.86/bbl of throughput compared to $51.5 million and $5.97/bbl of throughput in the prior quarter. The decrease reflects the impact of lower maintenance and purchased energy costs as well as slightly higher throughput in the third quarter of 2010. Capital expenditures totaled $21.5 million during the third quarter including $12.3 million related to debottlecking projects.
Corporate
In August 2010, Harvest issued 37.4 million shares to KNOC in exchange for KNOC’s BlackGold oilsands project assets; subsequent to the acquisition, Harvest issued an additional 4.7 million shares to KNOC for cash consideration of $47 million to fund a portion of the 2010 BlackGold capital expenditures. As at September 30, 2010, our bank borrowings totaled $291.6 million ($288.7 million net of transaction costs) with $208.4 million of undrawn credit facility available. On October 4, 2010, Harvest completed its offering of US$500 million aggregate principal amount of 67/8% senior notes due 2017. Of the US$484.6M net proceeds, $210.2 million was used to redeem the outstanding 77/8% Senior Notes due 2011.
UPSTREAM OPERATIONS
Summary of Financial and Operating Results
| | | Three Months Ended September 30 | | | Nine Months Ended September 30 | |
| (in $000’s except where noted) | | 2010 | | | 2009 (Pro Forma 2 ) | | | Change | | | 2010 | | | 2009 (Pro Forma2 ) | | | Change | |
| Revenues | | | 231,694 | | | | 226,920 | | | | 2 | % | | | 748,992 | | | | 631,955 | | | | 19 | % |
| Royalties | | | (33,698 | ) | | | (35,794 | ) | | | (6 | )% | | | (116,655 | ) | | | (88,522 | ) | | | 32 | % |
| Net revenues | | | 197,996 | | | | 191,126 | | | | 4 | % | | | 632,337 | | | | 543,433 | | | | 16 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating | | | 63,363 | | | | 60,330 | | | | 5 | % | | | 195,944 | | | | 196,982 | | | | (1 | )% |
| General and administrative | | | 9,720 | | | | 10,006 | | | | (3 | )% | | | 33,863 | | | | 26,274 | | | | 29 | % |
| Transportation and marketing | | | 2,485 | | | | 4,569 | | | | (46 | )% | | | 6,760 | | | | 11,085 | | | | (39 | )% |
| Depreciation, depletion and accretion | | | 112,311 | | | | 112,137 | | | | (0 | )% | | | 333,914 | | | | 352,681 | | | | (5 | )% |
Earnings (Loss) From Operations(1) | | | 10,117 | | | | (4,084 | ) | | | 148 | % | | | 61,856 | | | | (43,589 | ) | | | 242 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Capital asset additions (excluding acquisitions) | | | 90,268 | | | | 12,455 | | | | 625 | % | | | 256,111 | | | | 154,556 | | | | 66 | % |
| Property and business acquisitions (dispositions), net | | | 146,507 | | | | (766 | ) | | | 19,226 | % | | | 176,742 | | | | (61,494 | ) | | | 387 | % |
| Abandonment and reclamation expenditures | | | 5,796 | | | | 3,658 | | | | 58 | % | | | 13,813 | | | | 8,672 | | | | 59 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| OPERATING | | | | | | | | | | | | | | | | | | | | | | | | |
| Daily sales volumes | | | | | | | | | | | | | | | | | | | | | | | | |
| Light / medium oil (bbl/d) | | | 22,886 | | | | 22,793 | | | | 0 | % | | | 24,076 | | | | 23,775 | | | | 1 | % |
| Heavy oil (bbl/d) | | | 9,235 | | | | 10,066 | | | | (8 | )% | | | 9,192 | | | | 10,520 | | | | (13 | )% |
| Natural gas liquids (bbl/d) | | | 2,465 | | | | 2,648 | | | | (7 | )% | | | 2,537 | | | | 2,719 | | | | (7 | )% |
| Natural gas (mcf/d) | | | 79,147 | | | | 89,163 | | | | (11 | )% | | | 80,222 | | | | 92,284 | | | | (13 | )% |
| Total | | | 47,777 | | | | 50,368 | | | | (5 | )% | | | 49,175 | | | | 52,395 | | | | (6 | )% |
| (1) | These are non-GAAP measures; please refer to "Non-GAAP Measures" in this MD&A. |
| (2) | The 2009 comparative financial statement values are based on the "proforma" financials of Harvest Operations Corp.; see Note 1 to the September 30, 2010 Consolidated Financial Statements. |
Commodity Price Environment
| | | September 30, 2010 | |
| Benchmarks | | Three Months Ended | | | Nine Months Ended | |
| | | | | | | |
| West Texas Intermediate crude oil (US$/bbl) | | | 76.20 | | | | 77.65 | |
| Edmonton light crude oil ($/bbl) | | | 74.52 | | | | 76.64 | |
| Bow River blend crude oil ($/bbl) | | | 63.97 | | | | 68.03 | |
| AECO natural gas daily ($/mcf) | | | 3.55 | | | | 4.13 | |
| | | | | | | | | |
| Canadian / U.S. dollar exchange rate | | | 0.962 | | | | 0.965 | |
The average WTI benchmark price for the third quarter of 2010 decreased marginally by 2% from US $78.03/bbl in the second quarter of 2010. The average Edmonton light crude oil price (“Edmonton Par”) decreased marginally by 1% from the prior quarter average of $75.14/bbl. The average Bow River blend crude oil price (“Bow River”) decreased by 4% from $66.56/bbl in the second quarter of 2010. The average third quarter 2010 AECO daily natural gas price was 9% lower than the second quarter 2010 average of $3.89/mcf due to decreased demand resulting from increased storage levels and decreased economic activity.
| | | 2010 | |
| Differential Benchmarks | | Q3 | | | Q2 | | | Q1 | |
| Bow River Blend differential to Edmonton Par ($/bbl) | | | 10.55 | | | | 8.58 | | | | 6.72 | |
| Bow River Blend differential as a % of Edmonton Par | | | 14.2 | % | | | 11.0 | % | | | 8.4 | % |
In the third quarter of 2010, Bow River Blend differential relative to Edmonton Par increased to an average of $10.55/bbl (14.2%) compared to $8.58/bbl (11.0%) in the prior quarter. Heavy oil differentials fluctuate based on a combination of factors including the level of heavy oil inventories, pipeline capacity to deliver heavy crude to U.S. markets and the seasonal demand for heavy oil.
Realized Commodity Prices(1)
The following table summarizes our average realized price by product for the three and nine months ended September 30, 2010:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| Light to medium oil ($/bbl) | | | 67.71 | | | | 70.30 | |
| Heavy oil ($/bbl) | | | 58.52 | | | | 60.33 | |
| Natural gas liquids ($/bbl) | | | 53.85 | | | | 58.15 | |
| Natural gas ($/mcf) | | | 3.74 | | | | 4.35 | |
| Average Realized price ($/boe) | | | 52.71 | | | | 55.79 | |
| (1) | Realized commodity prices exclude the impact of price risk management activities. |
Our realized price for light to medium oil decreased marginally by 2% in the third quarter of 2010 as compared to $68.78/bbl in the second quarter of 2010, reflecting the 1% decrease in Edmonton Par. Despite the 4% decrease in the average Bow River benchmark price from the second to third quarter of 2010, Harvest’s average realized price of heavy oil increased by 4% from $56.51/bbl in the prior quarter to $58.52 in the third quarter of 2010. This is due to increased sales volumes in the month of July when the monthly average for the Bow River benchmark price was the highest of the quarter at $68.08/bbl, resulting in a higher realized price than the second quarter of 2010. The decrease in the average realized price for gas of 10% for the third quarter of 2010 from $4.17/mcf in the second quarter of 2010 is consistent with the decrease in benchmark prices.
Sales Volumes
The average daily sales volumes by product were as follows:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | Volume | | | Weighting | | | Volume | | | Weighting | |
Light / medium oil (bbl/d) (1) | | | 22,886 | | | | 48 | % | | | 24,076 | | | | 49 | % |
| Heavy oil (bbl/d) | | | 9,235 | | | | 19 | % | | | 9,192 | | | | 19 | % |
| Natural gas liquids (bbl/d) | | | 2,465 | | | | 5 | % | | | 2,537 | | | | 5 | % |
| Total liquids (bbl/d) | | | 34,586 | | | | 72 | % | | | 35,805 | | | | 73 | % |
| Natural gas (mcf/d) | | | 79,147 | | | | 28 | % | | | 80,222 | | | | 27 | % |
| Total oil equivalent (boe/d) | | | 47,777 | | | | 100 | % | | | 49,175 | | | | 100 | % |
| (1) | Harvest classifies our oil production, except that produced from Hay River, as light, medium and heavy according to NI 51-101 guidance. The oil produced from Hay River has an average API of 24° (medium grade), however, it benefits from a heavy oil royalty regime and therefore would be classified as heavy oil according to NI 51-101. |
In the third quarter of 2010, Harvest’s average daily sales of light/medium oil was 22,886 bbl/d compared to prior quarter of 24,874 bbl/d resulting in a decrease of 1,988 bbl/d mainly due to power outages and shipping restrictions at Hay River. Our heavy oil sales increased to 9,235 bbl/d from 9,090 bbl/d in the prior quarter reflecting additional wells that were brought online at Metiskow in September 2010. Natural gas liquids increased marginally to 2,465 bbl/d compared to prior period of 2,334 bbl/d. Natural gas sales averaged 79,147 mcf/d in the third quarter of 2010 compared to prior quarter of 79,797 mcf/d as a result of numerous third party facility turnarounds partially offset by increases in sales volumes at Chedderville and Crossfield due to lower downtime and tie-in of a new well and recompletion of an existing well at Crossfield that occurred in September 2010.
Revenues
| | | September 30, 2010 | |
| ($000’s) | | Three Months Ended | | | Nine Months Ended | |
| Light / medium oil sales | | $ | 142,557 | | | $ | 462,093 | |
| Heavy oil sales | | | 49,719 | | | | 151,397 | |
| Natural gas sales | | | 27,205 | | | | 95,223 | |
| Natural gas liquids sales and other | | | 12,213 | | | | 40,279 | |
| Total sales revenue | | | 231,694 | | | | 748,992 | |
| Royalties | | | (33,698 | ) | | | (116,655 | ) |
| Net Revenues | | $ | 197,996 | | | $ | 632,337 | |
Our revenue is impacted by changes to sales volumes, commodity prices and currency exchange rates. Our total sales revenue for the three months ended September 30, 2010 of $231.7 million is $13.9 million lower than prior quarter total sales revenue of $245.6 million. The 6% decrease is attributable to lower realized commodity prices and sales volumes, partially offset by the weakening of the Canadian dollar against the US dollar.
Royalties
We pay 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. Royalties for the third and second quarter of 2010 were $33.7 million and $41.2 million respectively (nine months ended September 30, 2010 - $116.7 million). For the third quarter of 2010, royalties as a percentage of gross revenue were 14.5% as compared to 16.8% in the second quarter of 2010. The decrease in our royalty rate from prior quarter is mainly due to the lower commodity price environment.
Operating Expenses
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| ($000’s) | | Total | | | Per boe | | | Total | | | Per boe | |
| Operating expense | | | | | | | | | | | | |
| Power and fuel | | $ | 11,977 | | | $ | 2.72 | | | $ | 43,694 | | | $ | 3.27 | |
| Well servicing | | | 12,815 | | | | 2.92 | | | | 37,060 | | | | 2.76 | |
| Repairs and maintenance | | | 11,950 | | | | 2.72 | | | | 32,787 | | | | 2.44 | |
| Lease rentals and property tax | | | 7,575 | | | | 1.72 | | | | 23,404 | | | | 1.74 | |
| Processing and other fees | | | 3,657 | | | | 0.83 | | | | 10,636 | | | | 0.79 | |
| Labour - internal | | | 5,484 | | | | 1.25 | | | | 17,222 | | | | 1.28 | |
| Labour - contract | | | 3,903 | | | | 0.89 | | | | 11,820 | | | | 0.88 | |
| Chemicals | | | 2,489 | | | | 0.57 | | | | 10,346 | | | | 0.77 | |
| Trucking | | | 2,428 | | | | 0.55 | | | | 7,111 | | | | 0.53 | |
| Other | | | 1,085 | | | | 0.25 | | | | 1,864 | | | | 0.14 | |
| Total operating expenses | | $ | 63,363 | | | $ | 14.42 | | | $ | 195,944 | | | | 14.60 | |
| | | | | | | | | | | | | | | | | |
| Transportation and marketing expense | | $ | 2,485 | | | $ | 0.57 | | | $ | 6,760 | | | $ | 0.50 | |
Third quarter 2010 operating costs totaled $63.4 million, a decrease of $4.9 million as compared to prior quarter operating costs of $68.3 million. On a per barrel basis, operating costs have decreased to $14.42/boe in the third quarter of 2010 as compared to $15.14/boe in the second quarter of 2010. The 5% decrease is substantially attributed to lower power and fuel costs due to the decrease in the average Alberta Power Pool electricity price from $80.56/MWh in the second quarter of 2010 to $35.69/MWh for the third quarter of 2010. This resulted in a decrease in power and fuel costs by $6.7 million from the prior quarter
Power and fuel costs, comprised primarily of electric power costs, represented approximately 19% of our total operating costs during the three months ended September 30, 2010. Harvest electricity usage in Alberta is exposed to market prices and to mitigate our exposure to electric power price fluctuations we had electric power price risk management contracts in place. The following table details the electric power costs per boe before and after the impact of our price risk management program.
| | | September 30, 2010 | |
| ($ per boe) | | Three Months Ended | | | Nine Months Ended | |
| Electric power and fuel costs | | $ | 2.72 | | | $ | 3.27 | |
| Realized losses on electricity risk management contracts | | | 0.29 | | | | 0.08 | |
| Net electric power and fuel costs | | | 3.01 | | | | 3.35 | |
| Alberta Power Pool electricity price ($ per MWh) | | $ | 35.69 | | | $ | 52.38 | |
Third quarter 2010 transportation and marketing expense increased to $2.5 million ($0.57/boe) as compared to $2.1 million ($0.46/boe) in the second quarter of 2010; this increase is due to the decrease in sales volumes in the third quarter and the transportation credits received from the Alberta Crown in the second quarter. These costs relate primarily to delivery of natural gas to Alberta’s natural gas sales hub, the AECO Storage Hub, and our cost of trucking clean crude oil to pipeline receipt points.
Operating Netback
| | | September 30, 2010 | |
| ($ per boe) | | Three Months Ended | | | Nine Months Ended | |
| Revenues | | $ | 52.71 | | | $ | 55.79 | |
| Royalties | | | (7.67 | ) | | | (8.69 | ) |
| Operating expense | | | (14.42 | ) | | | (14.60 | ) |
| Transportation expense | | | (0.57 | ) | | | (0.50 | ) |
Operating netback (1) | | $ | 30.05 | | | $ | 32.00 | |
(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 third quarter of 2010, our operating netback increased by $0.37/boe from $29.68/boe in the prior quarter. The increase is due to lower royalties and lower operating costs, partially offset by a lower average realized price.
General and Administrative (“G&A”) Expense
| | | September 30, 2010 | |
| ($000s except per boe) | | Three Months Ended | | | Nine Months Ended | |
| Total G&A | | $ | 9,720 | | | $ | 33,863 | |
| G&A per boe ($/boe) | | | 2.21 | | | | 2.52 | |
For the three months ended September 30, 2010, G&A expense decreased 17% to $9.7 million compared to $11.7 million in the second quarter of 2010. The decrease in G&A is primarily due to professional and consulting fees paid in the second quarter, largely in relation to the reorganization that occurred in the second quarter of 2010. In addition, bonuses were paid in June 2010 with no comparable expenditures during the third quarter of 2010. Generally, approximately 80% of our G&A expenses are related to salaries and other employee related costs.
Depletion, Depreciation, Amortization and Accretion Expense (“DDA&A”)
| | | September 30, 2010 | |
| ($000s except per boe) | | Three Months Ended | | | Nine Months Ended | |
| Depletion and depreciation | | $ | 97,156 | | | $ | 288,211 | |
| Depletion of capitalized asset retirement costs | | | 8,886 | | | | 26,919 | |
| Accretion on asset retirement obligation | | | 6,269 | | | | 18,784 | |
| Total depletion, depreciation and accretion | | $ | 112,311 | | | $ | 333,914 | |
| Per boe ($/boe) | | $ | 25.55 | | | $ | 24.87 | |
Our overall DDA&A expense for the three months ended September 30, 2010 was $1.9 million higher than DDA&A in the prior quarter of $110.4 million.
Capital Expenditures
| | | September 30, 2010 | |
| ($000's) | | Three Months Ended | | | Nine Months Ended | |
| Conventional oil and gas | | | | | | |
| Land and undeveloped lease rentals | | $ | 6,183 | | | $ | 16,849 | |
| Geological and geophysical | | | 417 | | | | 11,846 | |
| Drilling and completion | | | 49,060 | | | | 141,115 | |
| Well equipment, pipelines and facilities | | | 26,448 | | | | 72,177 | |
| Capitalized G&A expenses | | | 4,440 | | | | 10,083 | |
| Furniture, leaseholds and office equipment | | | 104 | | | | 425 | |
| Total conventional oil and gas capital expenditures | | $ | 86,652 | | | $ | 252,495 | |
| Oilsands | | | | | | | | |
| BlackGold oilsands | | | 3,616 | | | | 3,616 | |
| Total development capital expenditures excluding acquisitions | | $ | 90,268 | | | $ | 256,111 | |
Conventional Oil and Gas
Capital expenditures are up during the third quarter of 2010 as a result of drilling 27 gross wells (23.0 net) compared to drilling 13 gross wells (10.8 net) in the second quarter of 2010. Despite wet conditions in most areas that limited drilling activity, Harvest continued to focus our activities on our oil properties with 6 gross light oil wells drilled in our SE Saskatchewan area ($9.3 million) and 10 oil wells and one gas well drilled in our SE Alberta area ($15.3 million). In our Markerville/Rimbey area, Harvest drilled a total of 6 wells including 4 Cardium horizontal light oil wells and one Ellerslie light oil well for a total capital of $17.3 million.
During the third quarter of 2010 Harvest invested $6.2 million in undeveloped land opportunities in various areas to be used for future exploration and development.
In the first nine months of 2010, Harvest had a 99% success rate for all wells drilled. The following summarizes Harvest’s participation in gross and net wells drilled during the three and nine month ending September 30, 2010:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| Area | | Gross(1) | | | Net | | | Gross(2) | | | Net | |
| Hay River | | | 0.0 | | | | 0.0 | | | | 8.0 | | | | 8.0 | |
| SE Alberta | | | 11.0 | | | | 9.8 | | | | 18.0 | | | | 13.4 | |
| Rimbey/Markerville | | | 6.0 | | | | 3.9 | | | | 15.0 | | | | 8.5 | |
| SE Saskatchewan | | | 6.0 | | | | 6.0 | | | | 16.0 | | | | 15.5 | |
| Red Earth | | | 0.0 | | | | 0.0 | | | | 18.0 | | | | 14.7 | |
| Suffield | | | 1.0 | | | | 1.0 | | | | 6.0 | | | | 6.0 | |
| Lloydminster Heavy Oil | | | 2.0 | | | | 2.0 | | | | 25.0 | | | | 23.0 | |
| Crossfield | | | 0.0 | | | | 0.0 | | | | 3.0 | | | | 2.9 | |
| Kindersley | | | 0.0 | | | | 0.0 | | | | 6.0 | | | | 4.7 | |
| Other Areas | | | 1.0 | | | | 0.3 | | | | 5.0 | | | | 3.0 | |
| Total | | | 27.0 | | | | 23.0 | | | | 120.0 | | | | 99.7 | |
| (1) | Excludes 2 additional wells that we have royalties interest in. |
| (2) | Excludes 6 additional wells that we have royalties interest in. |
Oilsands
On August 6, 2010, Harvest closed on the acquisition of the BlackGold Oilsands Project (“BlackGold”) from KNOC. As KNOC is the sole shareholder of Harvest, KNOC will be retaining control over BlackGold; therefore, as there was no substantive change in the ownership interest of the BlackGold assets, these assets were recorded at the existing carrying values as previously recorded by KNOC.
BlackGold is located in northeastern Alberta and has existing ERCB approval for a Phase 1 project of 10,000 bpd and an application has been made for a phase 2 project that would increase production to 30,000 bpd. 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 first oil expected in early 2013 at an estimated production of 10,000 bpd.
During the third quarter of 2010, we signed an engineering, procurement and construction lump sum contract with a third party to build a central processing facility for BlackGold oilsands for an aggregate of $311 million. A 10% deposit of $31.1 million was paid in the third quarter of 2010, with estimated expenditures of $10.8 million in 2010, $156.4 million in 2011 and $113.2 million in 2012. In the third quarter of 2010 we began site clearing in preparation for the construction of our central processing facility and production pad sites for a total expenditure of $3.6 million. Detailed engineering of the facility commenced in October 2010; procurement, construction and fabrication are expected to commence in 2011.
Asset Retirement Obligation (“ARO”)
In connection with property acquisitions and development expenditures, we record the fair value of the ARO as a liability in the same year the expenditures occur. The associated asset retirement costs are capitalized as part of the carrying amount of the assets and are depleted and depreciated over our estimated net proved reserves. Once the initial ARO 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. Our asset retirement obligation increased by $8.3 million during the third quarter of 2010 as a result of accretion expense of $6.3 million and new liabilities recorded of $7.8 million, offset by $5.8 million of asset retirement liabilities settled.
DOWNSTREAM OPERATIONS
Summary of Financial and Operational Results
| | | Three Months Ended September 30 | | | Nine Months Ended September 30 | |
| (in $000’s except where noted below) | | 2010 | | | 2009(5) | | | Change | | | 2010 | | | 2009(5) | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| Revenues | | | 753,739 | | | | 800,729 | | | | (6 | )% | | | 1,914,056 | | | | 1,742,514 | | | | 10 | % |
Purchased feedstock for processing and products purchased for resale (4) | | | 711,823 | | | | 731,871 | | | | (3 | )% | | | 1,774,174 | | | | 1,436,563 | | | | 24 | % |
Gross margin(1) | | | 41,916 | | | | 68,858 | | | | (39 | )% | | | 139,882 | | | | 305,951 | | | | (54 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating | | | 25,680 | | | | 23,351 | | | | 10 | % | | | 85,717 | | | | 74,291 | | | | 15 | % |
| Purchased energy | | | 23,152 | | | | 30,385 | | | | (24 | )% | | | 65,622 | | | | 58,153 | | | | 13 | % |
| Marketing | | | 1,507 | | | | 3,617 | | | | (58 | )% | | | 4,822 | | | | 9,718 | | | | (50 | )% |
| General and administrative | | | 441 | | | | 490 | | | | (10 | )% | | | 1,323 | | | | 1,365 | | | | (3 | )% |
| Depreciation and amortization | | | 21,914 | | | | 21,434 | | | | 2 | % | | | 62,538 | | | | 68,530 | | | | (9 | )% |
Earnings (Loss) From Operations(1) | | | (30,778 | ) | | | (10,419 | ) | | | (195 | )% | | | (80,140 | ) | | | 93,894 | | | | (185 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Capital expenditures | | | 21,501 | | | | 7,945 | | | | 171 | % | | | 38,643 | | | | 34,778 | | | | 11 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Feedstock volume (bbl/day)(2) | | | 96,514 | | | | 102,940 | | | | (6 | )% | | | 77,658 | | | | 86,677 | | | | (10 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Yield (000’s barrels) | | | | | | | | | | | | | | | | | | | | | | | | |
| Gasoline and related products | | | 2,469 | | | | 3,318 | | | | (26 | )% | | | 6,302 | | | | 8,011 | | | | (21 | )% |
| Ultra low sulphur diesel and jet fuel | | | 2,722 | | | | 3,942 | | | | (31 | )% | | | 7,351 | | | | 9,266 | | | | (21 | )% |
| High sulphur fuel oil | | | 3,421 | | | | 2,387 | | | | 43 | % | | | 6,983 | | | | 5,940 | | | | 18 | % |
| Total | | | 8,612 | | | | 9,647 | | | | (11 | )% | | | 20,636 | | | | 23,217 | | | | (11 | )% |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average refining gross margin (US$/bbl)(3) | | | 3.02 | | | | 5.37 | | | | (44 | )% | | | 4.67 | | | | 9.77 | | | | (52 | )% |
(1) These are non-GAAP measures; please refer to “Non-GAAP Measures” in this MD&A.
(2) Barrels per day are calculated using total barrels of crude oil feedstock and vacuum gas oil.
(3) Average refining gross margin is calculated based on per barrel of feedstock throughput.
(4) Purchased feedstock for processing and products purchased for resale includes inventory write-downs, net of reversals, of ($0.8) million and $2.5 million for the three and nine months ended September 30, 2010, respectively.
(5) The 2009 comparative financial statement values are based on the “pro-forma” financials of the Downstream operations of Harvest Operations Corp.; see Note 1 to the September 30, 2010 Consolidated Financial Statements
Refining Benchmark Prices
The following average benchmark prices and currency exchange rates are the reference points from which we discuss our refinery’s financial performance:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| WTI crude oil (US$/bbl) | | | 76.20 | | | | 77.65 | |
| Brent crude oil (US$/bbl) | | | 77.06 | | | | 77.95 | |
| Mars Discount (US$/bbl) | | | (1.43 | ) | | | (1.57 | ) |
| RBOB gasoline (US$/bbl) | | | 84.01 | | | | 87.75 | |
| RBOB gasoline crack spread (US$/bbl) | | | 7.81 | | | | 10.10 | |
| Heating Oil (US$/bbl) | | | 86.43 | | | | 86.99 | |
| Heating Oil crack spread (US$/bbl) | | | 10.23 | | | | 9.34 | |
| High Sulphur Fuel Oil (US$/bbl) | | | 68.39 | | | | 69.46 | |
| High Sulphur Fuel Oil discount | | | (7.81 | ) | | | (8.19 | ) |
| Canadian / U.S. dollar exchange rate | | | 0.962 | | | | 0.965 | |
The RBOB gasoline crack spread decreased from the prior quarter crack spread of US$13.04/bbl as market prices adjusted to the continuing weak demand for gasoline products. During the same period the Heating oil crack spread remained comparable with the second quarter crack spread while the discount of HSFO improved over the second quarter discount of US$8.78/bbl.
During the three months ended September 30, 2010, the Canadian/U.S. dollar exchange rate remained strong. The strengthening of the Canadian dollar in 2010 has slightly decreased the contribution from our Downstream operations as substantially all of its gross margin, cost of purchased energy and marketing expense are denominated in U.S. dollars.
Summary of Gross Margin
The following table summarizes our Downstream gross margin for the three and nine months ended September 30, 2010 segregated between refining activities and petroleum marketing and other related businesses.
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| (000’s of Canadian dollars) | | Refining | | | Marketing | | | Total | | | Refining | | | Marketing | | | Total | |
| | | | | | | | | | | | | | | | | | | |
Sales revenue(1) | | | 719,879 | | | | 150,332 | | | | 753,739 | | | | 1,822,206 | | | | 416,768 | | | | 1,914,056 | |
Cost of feedstock for processing and products for resale(1) | | | 691,986 | | | | 136,309 | | | | 711,823 | | | | 1,719,694 | | | | 379,398 | | | | 1,774,174 | |
Gross margin(2) | | | 27,893 | | | | 14,023 | | | | 41,916 | | | | 102,512 | | | | 37,370 | | | | 139,882 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average refining gross margin (US$/bbl) | | | 3.02 | | | | | | | | | | | | 4.67 | | | | | | | | | |
| (1) | Downstream sales revenue and cost of products for processing and resale are net of intra-segment sales of $116.5 million and $324.9 million for the three and nine months ended September 30, 2010, respectively, reflecting the refined products produced by the refinery and sold by the Marketing Division. |
| (2) | This is a non-GAAP measure; please refer to “Non-GAAP Measures” in this MD&A. |
For the three months ended September 30, 2010, our refining gross margin decreased 63% to $27.9 million from the prior quarter of $75.9 million. The decrease reflects the impact of an unplanned shutdown of the hydrogen and isomax units for repairs and catalyst change-out resulting in decreased production of high margin distillates and increased production of negative margin HSFO. As well, the third quarter gross margin includes the negative impact of decreased sour crude differentials. The contribution from the marketing operations is fairly consistent from month to month.
As a consequence of a fire in early January of 2010, the unplanned shutdown of the refinery units during the first three months of the year had a negative impact on revenues and operations for the nine months ended September 30, 2010.
During the unplanned shutdown of the hydrogen and isomax units during the third quarter, the company sold VGO along with our production of HSFO. The net negative contribution from the sales of HSFO and VGO during the third quarter was US$8.1 million. This has been offset by a positive gross margin impact of US$23.1 million from the sales of gasoline and related products and a positive gross margin impact of US$41.4 million from the sales of distillates.
Refinery Sales Revenue
A comparison of our refinery yield, product pricing and revenue for the three and nine months ended September 30, 2010 is presented below:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | Refinery Revenues | | | Volume | | | Sales Price(1) | | | Refinery Revenues | | | Volume | | | Sales Price(1) | |
| | | (000’s of Cdn $) | | | (000s of bbls) | | | (US$ per bbl/ US$ per US gal) | | | (000’s of Cdn $) | | | (000s of bbls) | | | (US$ per bbl/ US$ per US gal) | |
| Gasoline products | | | 241,082 | | | | 2,829 | | | | 81.98 | | | | 601,469 | | | | 6,801 | | | | 85.34 | |
| Distillates | | | 253,518 | | | | 2,744 | | | | 88.88 | | | | 717,516 | | | | 7,797 | | | | 88.80 | |
| High sulphur fuel oil | | | 225,279 | | | | 3,047 | | | | 71.13 | | | | 503,221 | | | | 6,908 | | | | 70.30 | |
| | | | 719,879 | | | | 8,620 | | | | 80.34 | | | | 1,822,206 | | | | 21,506 | | | | 81.76 | |
| Inventory adjustment | | | | | | | (8 | ) | | | | | | | | | | | (870 | ) | | | | |
| Total production | | | | | | | 8,612 | | | | | | | | | | | | 20,636 | | | | | |
Yield (as a % of Feedstock) (2) | | | | | | | 97 | % | | | | | | | | | | | 97 | % | | | | |
(1)Average product sales prices are based on the deliveries at our refinery loading facilities.
(2) After adjusting for changes in inventory held for resale.
The table below details the composition of the refinery yield for the three and nine months ended September 30, 2010:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| Gasoline and related products | | | 28 | % | | | 30 | % |
| Distillates | | | 32 | % | | | 36 | % |
High sulphur fuel oil (1) | | | 40 | % | | | 34 | % |
(1) Includes 1.2 million bbls of produced VGO
The refinery yield was comprised of 34% gasoline products, 40% distillates and 26% HSFO for the second quarter of 2010. The change in product yields in the third quarter is a consequence of the unplanned shutdown of the hydrogen and isomax units resulting in a decrease in the production of gasoline products and distillates and an increase in the production of HSFO and VGO.
The realized average crack spreads over WTI as compared to the benchmark crack spreads were as follows:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| (US $ per bbl) | | Refinery | | | Benchmark | | | Refinery | | | Benchmark | |
| Gasoline and related products | | | 5.78 | | | | 7.81 | | | | 7.69 | | | | 10.10 | |
| Distillates | | | 12.68 | | | | 10.23 | | | | 11.15 | | | | 9.34 | |
| High sulphur fuel oil | | | (5.07 | ) | | | (7.81 | ) | | | (7.35 | ) | | | (8.19 | ) |
The average crack spread of our refinery products differs from the benchmark crack spreads as a result of timing of sales under the SOA, transportation costs, location differentials and quality differentials. The lower discount of our HSFO as compared to the benchmark discount is due to the positive impact from the sales of excess VGO during the third quarter of 2010.
For the nine months ended September 30, 2010, the comparison of the refinery crack spreads to the benchmark crack spreads is complicated by the ten week unplanned shutdown in the first quarter.
Refinery Feedstock
A comparison of crude oil and VGO feedstock processed for the three and nine months ended September 30, 2010 is presented below:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| | | Cost of Feedstock | | | Volume | | | Cost per Barrel (1) | | | Cost of Feedstock | | | Volume | | | Cost per Barrel (1) | |
| | | (000’s of Cdn $) | | | (000s of bbls) | | | (US$/bbl) | | | (000’s of Cdn $) | | | (000s of bbls) | | | (US$/bbl) | |
| | | | | | | | | | | | | | | | | | | |
| Middle Eastern | | | 436,467 | | | | 5,649 | | | | 74.33 | | | | 1,106,059 | | | | 14,437 | | | | 73.93 | |
| Russian | | | 145,624 | | | | 1,879 | | | | 74.56 | | | | 274,104 | | | | 3,431 | | | | 77.09 | |
| South American | | | 79,996 | | | | 1,125 | | | | 68.41 | | | | 177,451 | | | | 2,555 | | | | 67.02 | |
| Crude Oil Feedstock | | | 662,087 | | | | 8,653 | | | | 73.61 | | | | 1,557,614 | | | | 20,423 | | | | 73.60 | |
| Vacuum Gas Oil | | | 19,082 | | | | 226 | | | | 81.23 | | | | 64,152 | | | | 777 | | | | 79.67 | |
| | | | 681,169 | | | | 8,879 | | | | 73.80 | | | | 1,621,766 | | | | 21,200 | | | | 73.82 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Net inventory adjustment (2) | | | (28,561 | ) | | | | | | | | | | | (11,078 | ) | | | | | | | | |
| Additives and blendstocks | | | 40,204 | | | | | | | | | | | | 106,518 | | | | | | | | | |
Inventory write-down (recovery) (3) | | | (826 | ) | | | | | | | | | | | 2,488 | | | | | | | | | |
| | | | 691,986 | | | | | | | | | | | | 1,719,694 | | | | | | | | | |
(1) Cost of feedstock includes all costs of transporting the crude oil to the refinery in Newfoundland.
(2) Inventories are determined using the weighted average cost method.
(3) Inventory write-downs are calculated on a product by product basis using the lower of cost or net realizable value.
Throughput averaged 96,514 bbl/d in the third quarter of 2010 and 77,658 bbl/d for the nine months ended September 30, 2010, reflecting a marginal increase over the average daily throughput for the second quarter of 94,833 bbl/d. Third quarter throughput is less than the nameplate capacity of 115,000 bbl/d as a result of the unplanned shutdown of the hydrogen plant and isomax units.
The cost of our crude oil feedstock in the third quarter was US$2.59/bbl less than WTI and for the nine months ended September 30, 2010 averaged US$4.05/bbl less than WTI. The discount to WTI in the third quarter decreased 57% from US$6.08/bbl in the prior quarter, reflecting the continuation of the decreasing sour crude differentials for 2010.
Operating Expenses
The following summarizes the operating expenses for the refinery and marketing division for the three and nine months ended September 30, 2010:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
| (000’s of Canadian dollars) | | Refining | | | Marketing | | | Total | | | Refining | | | Marketing | | | Total | |
| | | | | | | | | | | | | | | | | | | |
| Operating costs | | | 20,038 | | | | 5,642 | | | | 25,680 | | | | 69,691 | | | | 16,026 | | | | 85,717 | |
| Purchased energy | | | 23,152 | | | | - | | | | 23,152 | | | | 65,622 | | | | - | | | | 65,622 | |
| | | | 43,190 | | | | 5,642 | | | | 48,832 | | | | 135,313 | | | | 16,026 | | | | 151,339 | |
During the three and nine months ended September 30, 2010, refining operating costs were $2.26/bbl and $3.29/bbl of throughput respectively. Operating costs per barrel of throughput decreased 20% from $2.84/bbl in the second quarter of 2010 due to lower maintenance costs and slightly higher throughput during the third quarter.
Purchased energy, consisting of low sulphur fuel oil and electricity, is required to provide heat and power to refinery operations. Our purchased energy for the three and nine months ended September 30, 2010 was $2.61/bbl and $3.10/bbl of throughput, respectively. Purchased energy for the second quarter of 2010 was $3.13/bbl of throughput, the 17% decrease in the third quarter is primarily due to a decrease in the purchased volume of low sulphur fuel oil.
Marketing Expense and Other
During the three months ended September 30, 2010, marketing expense comprised $0.2 million of marketing fees (nine months ended September 30, 2010 - $0.5 million) and $1.3 million of TVM charges (nine months ended September 30, 2010 - $4.3 million) both pursuant to the terms of the SOA. Marketing fees and TVM charges decreased marginally from $0.3 million and $2.1 million respectively in second quarter of 2010. As at September 30, 2010, Harvest had commitments totaling approximately $688.7 million in respect of future crude oil feedstock purchases from Vitol.
Capital Expenditures
Capital spending for the three and nine months ended September 30, 2010 totaled $21.5 million and $38.6 million, respectively, relating to various capital improvement projects including $12.3 million and $21.9 million of expenditures, respectively, related to the debottlenecking project.
Depreciation and Amortization Expense
The following summarizes the depreciation and amortization expense for the three and nine months ended September 30, 2010:
| | | September 30, 2010 | |
| | | Three Months Ended | | | Nine Months Ended | |
(000’s of Canadian dollars) | | Refining | | | Marketing | | | Total | | | Refining | | | Marketing | | | Total | |
| | | | | | | | | | | | | | | | | | | |
| Tangible assets | | | 21,028 | | | | 886 | | | | 21,914 | | | | 59,941 | | | | 2,597 | | | | 62,538 | |
The process units are amortized over an average useful life of 20 to 30 years.
RISK MANAGEMENT, FINANCING AND OTHER
Cash Flow Risk Management
Harvest employs an integrated approach to cash flow risk management. The details of our commodity price contracts outstanding at September 30, 2010 are included in the notes to our consolidated financial statements which are also filed on SEDAR at www.sedar.com.
For the three months ended September 30, 2010, Harvest had electricity price swap contracts in place for 25.0 MWh from January to December 2010 at an average price of $59.22 per MWh as well as electricity price swap contracts for 25.0 MWh from January to December 2011 at an average price of $47.61 per MWh. Our electricity price contracts realized losses of $1.3 million and $1.1 million for the three and nine months ended September 30, 2010, respectively.
At September 30, 2010 we also had a short term currency exchange rate contract in place on U.S. $100 million to be settled October 4, 2010 at an average of Canadian $1.03098 per U.S. $1.00.
As at September 30, 2010, the mark-to-market deficiency on our electric power contracts aggregated to $1.0 million., while the mark-to-market value on our currency exchange rate contract was $0.2 million.
Interest Expense
| | | September 30, 2010 | |
| ($000s) | | Three Months Ended | | | Nine Months Ended | |
| Interest on short term debt | | | | | | |
| Bank loan | | $ | - | | | $ | 1,370 | |
| Convertible debentures | | | 308 | | | | 401 | |
| Senior notes | | | - | | | | 30 | |
| Total interest on short term debt | | | 308 | | | | 1,801 | |
| | | | | | | | | |
| Interest on long term debt | | | | | | | | |
| Bank loan | | | 1,818 | | | | 3,342 | |
| Convertible debentures | | | 12,511 | | | | 38,725 | |
| Senior notes | | | 4,021 | | | | 12,347 | |
| Total interest expense on long term debt | | $ | 18,350 | | | $ | 54,414 | |
| Total interest expense | | $ | 18,658 | | | $ | 56,215 | |
Total interest expense for the third and second quarter of 2010 including the amortization of related financing costs was $18.7 million and $18.3 million, respectively. This marginal increase is attributed to the increase in interest expense on our bank loan.
Interest expense on our bank loan was $1.8 million for the third quarter of 2010 compared to $1.5 million in the prior quarter. The increase is attributed to the increase in bank debt from $182.4 at June 30, 2010 to $288.7 million at September 30, 2010 as well as an increase in the average interest rate of 2.9% in the third quarter of 2010 compared to 1.95% in the second quarter of 2010.
Interest expense for the third quarter of 2010 on our convertible debentures and senior notes of $12.8 million and $4.0 million respectively remained consistent with prior quarter.
The bank loan, convertible debentures and 77/8% senior notes are recorded at amortized cost and as such interest is calculated using the effective interest method. Therefore, total interest includes non-cash interest income of $0.9 million and $5.6 million for the three and nine months ended September 30, 2010 relating to the amortization of the premium on the convertible debentures and 77/8% senior notes and the fees incurred on the credit facility.
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 77/8% senior notes as well as any other U.S. dollar cash balances. Realized foreign exchange losses were $0.1 million and $5.3 million for the three and nine months ended September 30, 2010 respectively, resulting from the settlement of U.S. dollar denominated transactions. At September 30, 2010 the Canadian dollar has strengthened compared to June 30, 2010 resulting in an unrealized foreign exchange gain of $2.1 million and loss of $1.3 million for the three and nine months ended September 30, 2010.
Our downstream operations are considered a self-sustaining operation with a U.S. dollar functional currency. The foreign exchange gains and losses incurred by our downstream operations relate to Canadian dollar transactions converted to U.S. dollars as their functional currency is U.S. dollars. The cumulative translation adjustment recognized in other comprehensive income represents the translation of our Downstream operation’s U.S. dollar functional currency financial statements to Canadian dollars using the current rate method. During the three and nine months ended September 30, 2010, net cumulative translation losses were $33.9 million and $13.9 million respectively. Losses resulted due to the strengthening of the Canadian dollar against the U.S. dollar at September 30, 2010 compared to June 30, 2010; reflecting a decrease in the relative value of the net assets in our Downstream operations.
Future Income Tax
As KNOC Canada acquired the Trust on the deemed acquisition date of December 31, 2009, the opening future income tax liability is calculated as part of the purchase price allocation recorded at that date. The opening future income tax liability of $211.2 million represents a tax liability driven by the excess book over tax value of net assets. For nine months ended September 30, 2010, we have recorded a future income tax reduction of $37.6 million to reflect the changes in the temporary differences. At the end of the nine months ended September 30, 2010, Harvest had a net future income tax liability on the balance sheet of $181.3 million comprised of an $82.3 million future income tax liability for the downstream corporate entities and a future income tax liability of $99.0 million for the upstream entities.
Income Tax Assessment
In January 2009 Canada Revenue Agency issued a Notice of Reassessment to Harvest Energy Trust in respect of its 2002 through 2004 taxation years claiming past taxes, interest and penalties totaling $6.2 million. The CRA has adjusted Harvest Energy Trust’s taxable income to include their net profits interest royalty income on an accrual basis whereas the tax returns had reported this revenue on a cash basis. A Notice of Objection has been filed with CRA requesting the adjustments to an accrual basis be reversed. The Harvest Energy Trust 2005 tax return has also been prepared on a cash basis for royalty income with no taxes payable and, if reassessed by CRA on a similar basis, there would have been approximately $40 million of taxes owing. The Harvest Energy Trust 2006 tax return has been prepared on an accrual basis including incremental payments required to align the prior year’s cash basis of reporting with no taxes payable. Management along with the Company’s legal advisors believe the CRA has not properly applied the provisions of the Income Tax Act (Canada) that entitle income from a royalty to be included in taxable income on a cash basis and that the dispute will be resolved with no taxes payable by Harvest Operations Corp. The Trust has filed a Notice of Objection with the CRA and filed a Notice of Appeal with the Tax Court. A trial date has been set for January 2011.
Contractual Obligations and Commitments
We have 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 a recurring and consistent nature and impact cash flow in an ongoing manner. As at September 30, 2010, we also have contractual obligations and commitments that are of a less routine nature as disclosed in the following table:
| | | Maturity | |
| ($000’s) | | Total | | | Less than 1 year | | | 1-3 years | | | 4-5 years | | | After 5 years | |
Long-term debt(1) | | $ | 1,265,028 | | | $ | 23,810 | | | $ | 322,439 | | | $ | 682,200 | | | $ | 236,579 | |
Interest on long-term debt(1) | | | 225,215 | | | | 20,302 | | | | 136,231 | | | | 61,390 | | | | 7,292 | |
| Operating and premise leases | | | 30,482 | | | | 2,148 | | | | 14,463 | | | | 12,425 | | | | 1,446 | |
Purchase commitments(2) | | | 318,707 | | | | 44,169 | | | | 274,538 | | | | - | | | | - | |
Asset retirement obligations(3) | | | 1,262,985 | | | | 16,630 | | | | 22,554 | | | | 26,858 | | | | 1,196,943 | |
Transportation (4) | | | 4,555 | | | | 815 | | | | 3,535 | | | | 205 | | | | - | |
Pension contributions(5) | | | 23,564 | | | | 1,800 | | | | 8,448 | | | | 8,789 | | | | 4,527 | |
| Feedstock commitments | | | 688,728 | | | | 688,728 | | | | - | | | | - | | | | - | |
| Total | | $ | 3,819,264 | | | $ | 798,402 | | | $ | 782,208 | | | $ | 791,867 | | | $ | 1,446,787 | |
| (1) | Assumes constant foreign exchange rate. |
| (2) | Relates to drilling commitments, AFE commitments, BlackGold oilsands project commitment and downstream purchase commitments. |
| (3) | Represents the undiscounted obligation by period. |
| (4) | Relates to firm transportation commitment on the Nova pipeline. |
| (5) | Relates to the expected contributions for employee benefit plans. |
We have a number of operating leases for moveable field equipment, vehicles and office space and our commitments under those leases are noted in our annual contractual obligations table above. The leases require periodic lease payments and are recorded as either operating costs or G&A. Purchase commitments include Harvest’s commitment in the BlackGold oilsands project. Refer to the Upstream capital expenditures section of this MD&A for details of the BlackGold oilsands project.
Off Balance Sheet Arrangement
As of September 30, 2010, we have no off balance sheet arrangements in place.
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes our capital structure as at September 30, 2010 and December 31, 2009 as well as provides the key financial ratios contained in our revolving credit facility. For a complete description of our revolving credit facility, 77/8% senior notes and convertible debentures, see Notes 9, 10 and 11, respectively, to our interim consolidated financial statements for the period ended September 30, 2010 filed on SEDAR at www.sedar.com.
| (in millions) | | September 30, 2010 | | | December 31, 2009 | |
Revolving credit facility(1) | | $ | 291.6 | | | $ | 428.0 | |
77/8% senior notes, at principal amount (US$209.6 million) (2) | | | 215.6 | | | | 262.8 | |
| Convertible debentures, at principal amount | | | 757.8 | | | | 914.2 | |
| Total Debt | | | 1,265.0 | | | | 1,605.0 | |
| | | | | | | | | |
| Shareholder’s Equity | | | | | | | | |
| 330,953,567 issued at September 30, 2010 | | | 3,244.0 | | | | | |
| 242,268,802 issued at December 31, 2009 | | | | | | | 2,422.7 | |
| | | | | | | | | |
| TOTAL CAPITALIZATION | | $ | 4,509.0 | | | $ | 4,027.7 | |
| | | | | | | | | |
FINANCIAL RATIOS(3) | | | | | | | | |
Secured Debt to Annualized EBITDA (4) | | | 0.6 | | | | 0.7 | |
Total Debt to Annualized EBITDA (4) (5) | | | 2.6 | | | | 2.7 | |
| Secured Debt to Total Capitalization | | | 7 | % | | | 11 | % |
| Senior Debt to Total Capitalization | | | 29 | % | | | 40 | % |
| (1) | Net of transaction costs – $288.7 million |
| (2) | Principal amount converted at the period end exchange rate. |
| (3) | Calculated based on Harvest’s credit facility covenant requirements (see note 9 of the September 30, 2010 financial statements) |
| (4) | Annualized Earnings Before Interest, Taxes, Depreciation and Amortization based on twelve month rolling average. |
| (5) | “Total Debt” includes the convertible debentures in 2010 due to the economic elimination of the conversion feature subsequent to the acquisition of Harvest Energy Trust by KNOC Canada. |
KNOC Canada’s acquisition of Harvest Energy Trust triggered the “change of control” provisions included within the convertible debentures and the 77/8% senior notes indentures, as well as within our $1.6 billion extendible revolving credit facility. These change of control provisions resulted in the renewal of our credit facility on May 1, 2010 with a new capacity limit of $500 million and the redemption of $156.4 million principal amount of our convertible debentures and US$40.4 million principal amount or our 77/8% senior notes in the first quarter. These redemptions and reduction in our credit facility were funded through the January 2010 issuance of 46,567,852 shares to KNOC at $10.00 per share for total consideration of $465.7 million.
In August 2010, Harvest issued 37.4 million shares to KNOC at a stated value of $10.00 per share in exchange for the BlackGold oilsands project assets; later in the month an additional 4.7 million shares were issued to KNOC at $10.00 per share for total cash consideration of $47.0 million to provide funding for BlackGold capital expenditures. On October 25, 2010, an additional 3.87 million shares were issued to KNOC at $10.00 per share for total consideration of $38.7 million for further funding of BlackGold 2010 capital expenditures. In addition, on October 4, 2010, 0.7 million shares were issued to KNOC at $10.00 per share for total consideration of $7.1 million to provide funding for the initial set up and operation of the KNOC Global Technology and Research Centre that will be owned and operated by Harvest.
On October 4, 2010, Harvest completed an offering of US$500 million principal amount of unsecured 67/8% senior notes for net cash proceeds of US$484.6 million which includes an initial purchaser discount of US$3.4 million and estimated offering expenses of US$12 million. These notes are unsecured, require semi-annual payments of interest on April 1 and October 1 each year, mature on October 1, 2017 and are guaranteed by all of Harvest’s existing and future restricted subsidiaries that guarantee our credit facility and future restricted subsidiary that guarantees certain debt. The notes have not been registered under the US Securities Act of 1933 or the securities law of any other jurisdiction. Harvest has agreed to file an exchange offer registration statement or a shelf registration pursuant to a registration rights agreement within 45 days after the due date of our 20-F for the year ended December 31, 2011 and will use all efforts to cause the registration statement to become effective within 105 days after the filing date. Additional interest on the notes may become payable if this obligation under the registration rights agreement is not fulfilled.
Prior to maturity, redemptions are permitted in whole or in part, at any time at a redemption price equal to 100% of the principal amount redeemed, plus a make whole redemption premium and any unpaid interest to the redemption date. Harvest may also redeem all of the notes at any time in the event that certain changes affecting Canadian withholding taxes occur.
The covenants of the senior notes will, among other things, restrict the sale of assets, restrict the Harvest’s ability to enter into certain types of transactions with affiliates and restrict Harvest’s ability to pay dividends or make other restricted payments should the consolidated leverage ratio be greater than 2.5x. It also restricts the incurrence of additional indebtedness if such issuance would result in an interest coverage ratio as defined of less than 2.0 to 1. Notwithstanding the interest coverage ratio limitation, the incurrence of additional indebtedness under the credit facilities may be limited to the greater of $1.0 billion and 15% of total assets.
The 67/8% senior notes are rated by both Standard and Poor’s Ratings Services (“S&P”) and Moody’s Investors Service (‘Moody’s”) who has rated the notes as “BB-” and “Ba1”, respectively. Of the net proceeds, US$210.2 million was used to redeem the outstanding principal amount of the existing 77/8% senior notes and pay the consent payment described below.
On September 17, 2010 Harvest issued an Offer To Purchase And Consent Solicitation Statement (the “Offer”) to purchase any and all of the outstanding 77/8% senior notes and solicit consent for amendments of the related indenture. Harvest offered US$983.50 for each US$1,000 principal amount of notes tendered; in addition, for consent to the amendments of the indenture a payment of US$20.00 was offered for each US$1,000 principal amount of notes tendered by September 30, 2010. Tenders received subsequent to September 30, 2010 but prior to the expiration of the Offer on October 15, 2010 did not constitute consent and therefore would not receive the Consent Payment. On October 4, 2010, all conditions of the tender offer were met and Harvest accepted the offer and redeemed US$178.3 million of the US$209.6 million principal amount outstanding for total consideration of $179.0 million. Harvest also called the remaining notes for redemption at par under the terms of the amended indenture; the remaining $31.3 million principal amount was redeemed on October 19, 2010.
The supply and offtake agreement with Vitol (the “SOA”) provides Harvest with financial support for its crude oil purchase commitments as well as working capital financing for its inventories of crude oil and substantially all refined products held for sale. Pursuant to the SOA, we estimate that Vitol held inventories of VGO and crude oil feedstock (both delivered and in-transit) valued at approximately $688.7 million at September 30, 2010 (as compared to $582.1 million at December 31, 2009), which would have otherwise been assets of Harvest.
Our ability to adequately fund maintenance, development and acquisition activities as well as meet working capital commitments through cash flow from operating activities, issuances of incremental debt, available undrawn credit facility capacity ($208.4 million at September 30, 2010), the working capital provided by the SOA and capital injections from KNOC remains unchanged from the prior quarter; it is anticipated that we will have enough liquidity to fund future operations and forecasted capital expenditures. In addition, economic and industry factors are substantially unchanged from the prior quarter as the global economic recovery has somewhat stabilized.
SUMMARY OF QUARTERLY RESULTS
The following table and discussion highlights our third quarter of 2010 relative to the preceding quarter:
| | | 2010 | |
| ($000’s) | | Q3 | | | Q2 | | | Q1 | |
| | | | | | | | | | | | | |
| Revenue, net of royalties | | $ | 951,735 | | | $ | 1,024,896 | | | $ | 569,762 | |
| | | | | | | | | | | | | |
| Net income (loss) | | | (22,079 | ) | | | 18,203 | | | | (39,240 | ) |
| | | | | | | | | | | | | |
| Cash from operating activities | | | 97,711 | | | | 122,335 | | | | 78,134 | |
| | | | | | | | | | | | | |
| Total long term debt | | | 1,275,551 | | | | 1,177,945 | | | $ | 1,174,375 | |
| | | | | | | | | | | | | |
| Total assets | | | 5,262,694 | | | | 4,758,472 | | | $ | 4,765,580 | |
Revenues are comprised of revenues net of royalties from our Upstream operations as well as sales of refined products from our Downstream operations. Third quarter Downstream revenues were $753.7 million compared to $820.5 million in the second quarter of 2010. The decrease in Downstream revenues is due to the impact of the unplanned shutdown of the hydrogen and isomax units for repairs and catalyst change-out in the third quarter of 2010. Upstream revenues in the third Quarter of 2010 were $231.7 million compared to $245.6 million in the second quarter due to lower commodity prices for oil and natural gas and various third party turnarounds.
Net income reflects both cash and non-cash items. Changes in non-cash items, including future income tax, DDA&A expense, unrealized foreign exchange gains and losses and unrealized gains on risk management contracts impact net income from period to period. For these reasons, our net income (loss) may not necessarily reflect the same trends as net revenues or cash from operating activities, nor is it expected to. The net loss of $22.1 million in the third quarter compared to net income of $18.2 million in the second quarter of 2010 is due to the decrease in revenues from our Downstream operations for the reasons as discussed above.
Cash from operating activities is closely aligned with the trend in commodity prices for our Upstream operations, reflects the cyclical nature of the Downstream segment, and is significantly impacted by changes in working capital. During the third quarter of 2010 cash from Upstream operating activities was lower than the second quarter due to lower commodity prices and lower sales volumes. The majority of the decrease in cash from operating activities from the second to the third quarter of 2010 resulted from the decrease in Downstream cash from operations as a result of the unplanned shutdown in the third quarter.
Total assets have increased from the second quarter of 2010 due to the acquisition of BlackGold oilsands assets and upstream assets from a third party.
OUTLOOK
During the third quarter, Harvest continued to advance its strategy of building an asset-rich, growth oriented, integrated oil and gas company with a strong balance sheet. The acquisition of the BlackGold oilsands project, the acquisition of additional western Canadian upstream assets from a third party, and the recent equity issuances provide important steps in that direction. Harvest has assembled an enviable asset base with significant growth opportunity that it is looking to complement with additional assets in the years ahead. A strong balance sheet, solid and increasing technical capability, and support for growth from KNOC position Harvest well.
For the upstream business, we now anticipate that our upstream production will average approximately 37,000 bbls/d of liquids and 83,000 mcf/d of natural gas in the fourth quarter of 2010. Full year operating costs are now expected to be approximately $14.60/boe. Although we don’t expect to announce our 2011 budget until later in the quarter, we are anticipating an active winter drilling season focused on attractive opportunities in our oil-weighted asset base. To facilitate that investment, we have increased our capital investment in 2010 by $70 million.
In our upstream business, we will continue to evaluate opportunities to acquire producing oil and/or natural gas properties as well as offer selected properties for divestment to increase or maintain our productive capabilities.
In our downstream business, we currently anticipate spending approximately $90 million on capital projects in 2011, including discretionary Debottleneck Projects. With the deferral of major turnarounds to next year, we now anticipate there will only be approximately $5 million of turnaround or catalyst expenditures in 2010 in preparation for a May 2011 shutdown. Despite the significant reductions in expenditures for capital investment, we expect full year throughput to average 87,000 bbls/d of feedstock with operating costs and purchased energy costs aggregating to approximately $6.50/bbl.
Currently the economic environment is mixed for Harvest with strong crude oil and natural gas liquids prices offsetting weak natural gas prices and refining margins. We anticipate that we will continue to see a volatile commodity price environment in 2010 and 2011. With an oil-weighted upstream business and assuming that crude oil prices remain strong, Harvest should reflect strong cash flow as refining margins and natural gas prices recover over time.
Overall, we expect that based on current commodity price expectations, our 2010 cash from operating activities and capital injections from KNOC will be sufficient to fund our planned capital expenditures and continue to reduce bank debt.
CRITICAL ACCOUNTING ESTIMATES
There are a number of critical estimates underlying the accounting policies applied when preparing the consolidated financial statements due to timing differences between when certain activities are settled and when these activities are recognized for accounting purposes. Changes in these estimates could have a material impact on our reported results. These estimates are described in detail in our MD&A for the quarter ended June 30, 2010 as filed on SEDAR at www.sedar.com. There have been no significant changes to any of our critical accounting estimates in our consolidated financial statements for the three months ended September 30, 2010 from those described in our June 30, 2010 MD&A.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
In December 2008, the CICA issued section 1582, Business Combinations, replacing Section 1581 of the same name. The new Section will be effective on January 1, 2011 with prospective application and early adoption allowed. Under the new guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at their market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, while the current standard requires capitalization as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. While under the current standard only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from non-current assets in the purchase price allocation. Harvest is currently assessing the impact of this standard on our financial position and future results.
International Financial Reporting Standards
In February 2008, the CICA Accounting Standards Board (“AcSB”) announced that Canadian public reporting issuers will be required to report under International Financial Reporting Standards (“IFRS”) commencing January 1, 2011, including comparatives for 2010 and an opening balance sheet at January 1, 2010 showing the changes from Canadian GAAP to IFRS.
We have established an IFRS Conversion Plan and have staffed a project team with regular reporting to our senior management team and to the Audit Committee of the Board of Directors to ensure we meet the IFRS transition requirements for 2011. The IFRS project team has developed an IFRS Transition Plan that consists of four key phases:
IFRS Conversion Project Phase
Phase 1 – Diagnostic Phase
| | · | Assessment of key differences between Canadian GAAP and IFRS, planning, assessment, implementation and training. |
Phase 2 – Planning Phase
| | · | Development of a project plan that includes assignment of roles and responsibilities, timeline and budget. |
Phase 3 – Assessment Phase
| | · | Detailed comparison of the IFRS and Canadian standards to identify all applicable differences, IFRS 1 First Time Adoption to IFRS exemptions and exemptions and expected changes to the relative IFRS standards. |
| | · | Impact assessment on accounting policies; information technology and data systems; business processes and data requirements; internal control over financial reporting, disclosure controls and procedures; financial reporting expertise and business activities that may be influenced such as debt covenants, capital requirements and compensation arrangements. |
Phase 4 – Implementation Phase
| | · | Preparing transitional opening IFRS financial statements; implementing accounting policy changes; implementing and test data, process, system and control changes; training |
IFRS Project Status
The diagnostic and planning phases of the project have been completed and Harvest has completed the detailed analysis of the differences for most elements of our financial statements and is currently working with representatives from various operational areas in the Company to finalize the selection of accounting policies and assess the impact of the differences on the data requirements, business processes, financial systems and internal controls. Harvest has commenced training of key employees through this process as well. Korea is on the same IFRS conversion schedule as Canada and as a result the IFRS accounting policies that were initially selected were reassessed to align with KNOC’s accounting policy choices.
Harvest has commenced preparation of the IFRS opening balance sheet and has identified adjustments to Property, Plant and Equipment, Exploration and Evaluation Expenditures, Asset Retirement Obligations and an offsetting adjustment to retained earnings. The KNOC acquisition of Harvest has minimized the IFRS transitional adjustments required due to the fair values assigned to the Company’s assets and liabilities from the KNOC purchase price allocation.
In September 2010, management presented a draft opening balance sheet, draft first quarter and second quarter 2010 statements of income and balance sheets prepared under IFRS as well as key accounting policy choices to the audit committee for their review and are currently being reviewed and approved by KNOC. The audit committee has approved Harvest’s IFRS accounting policy selections that have been presented by management and the IFRS accounting policy selections are now being reviewed by KNOC to ensure alignment with KNOC’s IFRS accounting policies.
Potential Impacts of IFRS Adoption
Significant differences that have been identified between Canadian GAAP and IFRS that will impact Harvest are: accounting for capital assets including exploration costs, depletion and depreciation, impairment testing, asset retirement obligations, employee benefits as well as an increased level of disclosure requirements. These differences have been identified based on the current IFRS standards issued and expected to be in effect on the date of transition. Current IFRS standards may be modified, and as a result, the impact may be different than Harvest’s current expectations; as such, Harvest cannot guarantee that the following information will not change as the date of transition approaches. Harvest will continue to communicate information in relation to its conversion process as it becomes available.
First Time Adoption of IFRS
IFRS 1, “First Time Adoption of International Financial Reporting Standards” (“IFRS 1”) prescribes requirements for preparing IFRS-compliant financial statements in the first reporting period after the changeover date. IFRS 1 requires retrospective application of IFRS as if they were always in effect. IFRS 1 also provides entities adopting IFRS for the first time with a number of mandatory exceptions and optional exemptions from retrospective application of IFRS to ease the transition to IFRS in the transition year. Management is assessing the exemptions available under IFRS 1 and will implement those determined to be most appropriate for Harvest. At present, Harvest believes it will apply the IFRS 1 exemptions associated with business combinations and arrangements containing a lease.
Property, Plant and Equipment (“PP&E”)
IFRS requires costs recognized as PP&E to be allocated to the significant parts of the asset and to depreciate each significant component separately which is different from Harvest’s current depreciation and depletion calculations under Canadian GAAP. The adoption of IFRS will increase the number of components to be amortized separately for both the upstream and downstream segments and will have an impact on the amount of depreciation/depletion expense recognized.
For the upstream assets, the net book value of PP&E excluding Exploration and Evaluation expenditures as at December 31, 2009 will be the opening cost of the upstream PP&E balance at January 1, 2010. This amount will be allocated, based on reserve value, to depletable units which consolidate into cash generating units for impairment purposes. IFRS provides the option to calculate depletion using a reserve base of proved reserves or both proved plus probable reserves, as compared to the Canadian GAAP method of calculating depletion using proved reserves only. In aligning with KNOC’s IFRS accounting policies, Harvest plans to determine its depletion expense using proved developed reserves as its depletion base.
Exploration and Evaluation Expenditures (“E&E”)
Oil and gas companies are required to account for exploration and evaluation expenditures in accordance with IFRS 6 “Exploration for and Evaluation of Mineral Resources”. This standard addresses the recognition, measurement, presentation and disclosure requirements for costs incurred in the exploration phase. IFRS requires the identification and presentation of exploration and evaluation (“E&E”) expenditures to be separated from those expenditures incurred on developed and producing properties. E&E expenditures are transferred to PP&E when technical feasibility and commercial viability has been proved. An impairment test is required to be performed on E&E expenditures when they are transferred to PP&E. Harvest will re-classify all E&E expenditures that are currently included in the PP&E balance and will consist of the book value of E&E land costs, and related drilling costs and seismic costs. E&E assets will not be depleted and will be assessed for impairment when indicators suggest the possibility of impairment.
Impairment of Assets
Under IFRS, impairment of PP&E will be calculated at a more granular level than what is currently required under Canadian GAAP as impairment will be calculated at the cash generating unit (“CGU”) level. In addition, IAS 36 “Impairment of Assets” uses a one-step approach for testing and measuring asset impairments, with asset carrying values being compared to the higher of value in use and fair value less costs to sell. Under IAS 36 impairment losses previously recognized may be reversed where circumstances change. Impairment tests are required to be performed on initial transition to IFRS and as at January 1, 2010, no impairment was identified.
Asset Retirement Obligation (“ARO”)
Under IFRS, the decommissioning liability is required to be remeasured at each reporting date using the current liability specific discount rate requiring retroactive adjustment to the estimated liability, whereas under Canadian GAAP, ARO adjustments are made on a prospective basis. Harvest has made a preliminary decision to risk adjust the cash flows and apply the risk free interest rate to measure the obligation. Under Canadian GAAP, Harvest uses a credit-adjusted interest rate. A lower discount rate will increase the decommissioning obligation.
Employee Benefits
Under IFRS and Canadian GAAP, actuarial gains and losses arising from defined benefit plans can be recognized into earnings through various appropriate methods, however, Canadian GAAP does not permit actuarial gains and losses to be recognized directly in equity whereas IAS 19 “Employee Benefits” provides an additional accounting policy option to recognize actuarial gains and losses directly in other comprehensive income in the period in which they occur.
Deferred Income Taxes
Due to the recent withdrawal of the exposure draft on IAS 12 “Income Taxes” in November 2009, Harvest is currently evaluating the differences between the current version of IAS 12 and the relevant Canadian GAAP standards.
Internal controls over financial reporting (“ICFR”) and disclosure
As the IFRS accounting policies are finalized, an assessment will be made to determine changes required for ICFR. This will be an ongoing process throughout 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements. Harvest has established internal controls associated with the IFRS transition which include approvals at various stages of the project and the involvement of its auditors and other external advisors.
Throughout the transition process, Harvest will be assessing stakeholders’ information requirements and will ensure that adequate and timely information is provided so all stakeholders are informed of the transition progress.
IT systems
The conversion to IFRS will have an impact on the company’s IT system requirements. Harvest is currently completing its IT systems impact assessment and it is expected that modifications will include the requirement to track PP&E costs and E&E costs separately as well as the tracking of costs at a more granular level of detail for IFRS reporting. It is expected that current accounting systems and processes will accommodate the modifications required for IFRS reporting.
OPERATIONAL AND OTHER BUSINESS RISKS
For a detailed discussion of our operational and other business risks, please refer to our MD&A for the quarter ended June 30, 2010 as filed on SEDAR at www.sedar.com.
CHANGES IN REGULATORY ENVIRONMENT
For a detailed discussion of the most recent changes to our regulatory environment, please refer to our MD&A for the quarter ended June 30, 2010 as filed on SEDAR at www.sedar.com.
INTERNAL CONTROL OVER FINANCIAL REPORTING
For a detailed discussion of our internal control over financial reporting, please refer to our MD&A for the quarter ended June 30, 2010 as filed on SEDAR at www.sedar.com. During the three and nine months ended September 30, 2010, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ADDITIONAL INFORMATION
Further information about us can be accessed under our public filings found on SEDAR at www.sedar.com or at www.harvestenergy.ca. Information can also be found by contacting our Investor Relations department at (403) 265-1178 or at 1-866-666-1178.
