Exhibit 99.3
MANAGEMENT’S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS
For the Fiscal Year Ended December 31, 2007
Management’s Discussion and Analysis
This management’s discussion and analysis (“MD&A”) is the Trust management’s analysis of its financial performance and significant trends or external factors that may affect future performance. It is dated February 13, 2008 and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2006 and MD&A for the quarters ended March 31, 2007, June 30, 2007, September 30, 2007 as well as the Trust’s Annual Information Form.
The MD&A contains forward-looking statements and readers are cautioned that the MD&A should be read in conjunction with the Trust’s disclosure under “Forward-Looking Statements” included at the end of this MD&A.
Non-GAAP Measures
Historically, management used the non-GAAP measure Cash Flow or cash flow from operations to analyze operating performance, leverage and liquidity. We have now chosen to utilize the GAAP measure cash flow from operating activities instead of Cash Flow. There are two differences between the two measures; positive or negative changes in non-cash working capital and the deduction of expenditures on site restoration and reclamation as they appear on the Consolidated Statements of Cash Flows. Although management feels that Cash Flow is a valued measure of funds generated by the Trust during the reported year, we have changed our disclosure to only discuss the GAAP measure in the MD&A in order to avoid any potential confusion by readers of our financial information and in our opinion, to more fully comply with the intent of certain regulatory requirements.
Our historical measure of Cash Flow reflected revenues and costs for the reported year. This amount, however, comprised accruals for at least one month of revenue and approximately two months of costs. The oil and gas industry is designed such that revenues are typically collected on the 25th day of the month following the actual production month. Royalties are typically paid two months following the actual production month and operating costs are paid as the invoices are received. This can take several months; however, most invoices for operated properties are paid within approximately two months of the production month. In the event that commodity prices and or volumes have changed significantly from the last month of the previous reporting period over the last month of the current reporting period, a difference could occur between cash flow from operating activities and our historical non-GAAP measure of Cash Flow or cash flow from operations. Additionally, periods where the Trust spends a significant amount on site restoration and reclamation would result in a difference between cash flow from operating activities and Cash Flow.
At the time of writing this MD&A, substantially all revenues have been collected for the production period of December 2007. Management performs analysis on the amounts collected to ensure that the amounts accrued for December are accurate. Analysis is also performed regularly on royalties and operating costs to ensure that amounts have been properly accrued.
Management uses certain key performance indicators (“KPIs”) and industry benchmarks such as distributions as a per cent of cash flow from operating activities, operating netbacks (“netbacks”), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, reserves per unit and production per unit to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for the Trust. These KPIs and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.
1
Executive Overview
ARC Energy Trust (“the Trust”) is one of the top 20 producers of conventional oil and gas in western Canada. In terms of oil and gas entities operating in western Canada and listed on the Toronto Stock Exchange, ARC ranks 14 with a total capitalization as at February 13, 2008 of $5.7 billion based on a closing unit price of $23.15.
It is the Trust’s objective to provide superior and sustainable long-term returns to unitholders by focusing on the key strategic objectives of the business plan. The Trust, which to date has conducted business exclusively in western Canada, acquires, develops and optimizes oil and natural gas properties to generate a cash flow stream. The Trust at December 31, 2007, held an interest in over 18,000 wells with approximately 5,500 wells operated by the Trust and the remainder operated by joint venture partners, primarily major oil and gas companies. ARC’s 2007 production averaged 62,723 boe per day of which 74 per cent was operated by the Trust. The Trust’s business plan is to continually develop its reserves and/or acquire new reserves and undeveloped land in order to maintain or grow its productive capacity while distributing the remainder of its cash flows to unitholders in the form of monthly distributions. The Trust employs a conservative payout policy to provide for cash funding of a portion of ongoing capital development programs and maintaining low debt levels to facilitate further growth.
The key objectives of the Trust’s business plan are identified below. The Trust was successful in meeting all of its objectives in 2007 as discussed below and will continue to focus on these items in 2008.
· Managing commodity price risk – Commodity prices are by far the key variable in determining the profitability of the Trust. Each $1 per barrel change in the Canadian price of oil impacts the annual revenue of the Trust by approximately $10 million and each $0.25 per mcf change in natural gas prices at AECO impacts annual revenue by $16 million. Commodity prices are outside of management’s control, however, it is a strategic objective of the Trust to maintain a balanced production profile between natural gas and crude oil. Also, the Trust maintains an active risk management program to protect a portion of cash flow giving greater certainty to distributions and increasing the certainty that acceptable rates of returns are achieved on capital deployed during the course of the year.
· Replacing annual reserves – The Trust’s proved plus probable reserves were maintained after producing 22.9 mmboe during 2007. As at December 31, 2007, company interest reserves of 286.4 mmboe were within one per cent of the 286.1 mmboe recorded as at December 31, 2006. The reserves were slightly increased through a combination of the $397 million 2007 capital development program and property acquisitions (net of dispositions) of $42.5 million. The Trust recorded an all-in annual Finding, Development and Acquisition (“FD&A”) cost of $19.00 per barrel of oil equivalent (“boe”) in 2007 before consideration of future development capital (“FDC”) for the proved plus probable reserves category. This is a 15 per cent reduction from the $22.42 per boe FD&A cost realized in 2006. Including FDC, the FD&A cost was $20.03 per boe. For additional information please refer to the reserves section.
· Ensuring acquisitions are strategic and enhance unitholder returns – The Trust added producing properties in southeast Saskatchewan that were synergistic with the Trust’s existing operations in 2007 and also significantly increased its land ownership in northeastern British Columbia providing an increase in its inventory of future development opportunities.
· Controlling costs – The Trust has been diligent in ensuring that costs incurred for capital projects were reasonable and competitive amongst service providers, which has led to a moderate cost savings throughout 2007. The Trust drills approximately 300 wells per year that are added to its operating base. It is expected that operating costs will continue to increase over time as there is a high percentage of fixed costs for the Trust’s properties that results in a trend of increasing operating costs as new production is brought on to replace declines on existing properties.
· Conservatively utilizing debt – The Trust’s net debt levels were under 15 per cent of total capitalization and debt to 2007 cash flow from operating activities was less than 1.1 times for the year ended 2007. The Trust’s debt levels are among the lowest in the oil and gas sector.
· Continuously developing the expertise of our staff and seeking to hire and retain the best in the industry – The Trust runs an active training and development program for its employees and encourages personal development. The Trust continually assesses compensation levels in the industry to ensure that the Trust’s compensation is competitive in order to attract and retain the best employees. The Trust’s long-term incentive plan for employees is directly tied to the Trust’s units providing alignment between employees and investors.
· Building relationships and conducting business in a way that is viewed as fair and equitable – ARC employees, leadership team and directors work hard to build the ARC “franchise value” through honest, transparent dealings with our business partners. “Treating all people with respect” is a key message inside and outside the organization. This basic business fundamental allows us to build enduring relationships with joint venture partners, land owners, investors, banks and lending institutions, governments and the investment community.
· Promoting the use of proven and effective technologies – The Trust continues to research new technologies in an effort to conduct its operations in the most efficient and cost effective manner. The Trust has committed a portion of its 2008 capital expenditure budget towards continued research into tertiary recovery methods.
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· Being an industry leader in health, safety and environmental performance – The Trust continues to focus on operating in a safe, reliable and responsible fashion. The Trust is committed to the platinum level of CAPP Stewardship reporting and continues to achieve Gold Level Champion reporter status under the Canada Climate Change voluntary climate registry initiative. The Trust’s commitment to pursue additional CO2 injection opportunities is expected to have the two-fold benefit of enhanced recovery of oil reserves and the capture and containment of CO2 emissions that will benefit the environment. The Trust’s commitment to safety is evidenced by zero lost time incidents for both employees and contractors of the Trust in 2007.
· Continuing to actively support local initiatives in the communities in which we live and work – The Trust is actively involved in charitable and philanthropic causes both in Calgary and in the rural communities in which it operates. ARC continued to be a strong supporter of the United Way, Alberta Cancer Foundation, Canadian Sport Centre Calgary, Alberta Children’s Hospital and many community organizations in rural centres. The Trust allocates up to 0.5 per cent of its three year rolling average net income for donations, which resulted in $1.8 million of cash donations made to charitable organizations in 2007. The Trust also provided business expertise and employee volunteers to charities.
Historical Performance
Management and the Trust’s directors are committed to providing superior long-term returns to unitholders. In the future the Trust’s business strategy will continue to be reviewed to address changes in the business and regulatory environment in order to ensure that unitholder value is optimized. The Trust, while primarily focused on adding value through internal development of drilling opportunities, continually looks to execute minor property acquisitions and dispositions in order to enhance and streamline the Trust’s portfolio of oil and natural gas assets. The Trust will continue to assess larger accretive acquisition opportunities. Acquisitions are evaluated internally and acquisitions in excess of $25 million are subject to Board approval.
The following table illustrates ARC’s production and reserves per unit that have been achieved while distributing $6.79 per unit or $1.4 billion over the last three years.
Per Trust Unit |
| 2007 |
| 2006 |
| 2005 |
| |||
Normalized production per unit (1) |
| 0.30 |
| 0.31 |
| 0.32 |
| |||
Normalized reserves per unit (1) |
| 1.35 |
| 1.40 |
| 1.51 |
| |||
Distributions per unit |
| $ | 2.40 |
| $ | 2.40 |
| $ | 1.99 |
|
(1) Normalized indicates that all years as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional trust units were issued (or repurchased) at a period end price for the reserves per unit calculation and at an annual average price for the production per unit calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of annual per unit values.
The result of the Trust’s business plan have provided unitholders with the following one, three and five year returns, on the basis of reinvestment of distributions in trust units:
TOTAL RETURNS
($ per unit except for per cent) |
| One Year |
| Three Year |
| Five Year |
| ||||||
Distributions per unit |
| $ | 2.40 |
| $ | 6.79 |
| $ | 10.39 |
| |||
Capital appreciation per unit |
| $ | (1.90 | ) | $ | 2.50 |
| $ | 8.50 |
| |||
Total return per unit |
| $ | 0.50 |
| $ | 9.29 |
| $ | 18.89 |
| |||
Annualized total return per unit |
| % | 2.3 |
| % | 15.3 |
| % | 24.3 |
| |||
To the end of 2007, the Trust has provided cumulative distributions of $21.03 per unit and capital appreciation of $10.40 per unit for a total return of $31.43 per unit (21.9 per cent annualized total return) for unitholders who invested in the Trust at inception in 1996. The Trust has announced 2008 distributions of $0.20 per unit per month through March 2008.
Regulatory Changes
Beyond 2008, regulatory issues include the implementation of new royalty rates for production in the Province of Alberta in 2009. The Alberta government announced changes in the royalty rates in 2007 that will result in an approximate 10 per cent increase in the Trust’s royalty rates at year-end 2007 commodity prices, from approximately 18 per cent of revenue to 20 per cent of revenue commencing on January 1, 2009. The impact of the royalty increase was to decrease the net present value of the Trust’s reserves by approximately two to three per cent when using a 10 per cent discount rate and GLJ forecast prices as at January 1, 2008. At higher prices, the impact would be greater.
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Further, the Trust will be subject to a Federal income tax on distributions commencing on January 1, 2011. The Trust’s management is reviewing the options for structural changes and is working closely with legal and business advisors to determine a course of action and potential restructuring to maximize value in the best interest of unitholders.
2007 Annual Financial and Operational Results
Following is a discussion of ARC’s 2007 annual financial and operating results.
FINANCIAL HIGHLIGHTS
(CDN $ millions, except per unit and volume data) |
| 2007 |
| 2006 |
| % Change |
|
Cash flow from operating activities |
| 704.9 |
| 734.0 |
| (4 | ) |
Cash flow from operating activities per unit (1) |
| 3.35 |
| 3.59 |
| (7 | ) |
Net income |
| 495.3 |
| 460.1 |
| 8 |
|
Net income per unit (2) |
| 2.39 |
| 2.28 |
| 5 |
|
Distributions per unit (3) |
| 2.40 |
| 2.40 |
| — |
|
Distributions as a per cent of cash flow from operating activities |
| 71 |
| 66 |
| 8 |
|
Average daily production (boe/d) (4) |
| 62,723 |
| 63,056 |
| (1 | ) |
(1) |
| Per unit amounts are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares at year-end. |
|
|
|
(2) |
| Based on net income after non-controlling interest divided by weighted average trust units outstanding excluding trust units issuable for exchangeable shares. |
|
|
|
(3) |
| Based on number of trust units outstanding at each cash distribution date. |
|
|
|
(4) |
| Reported production amount is based on company interest before royalty burdens. Where applicable in this MD&A natural gas has been converted to barrels of oil equivalent (“boe”) based on 6 mcf:1 bbl. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the well head. Use of boe in isolation may be misleading. |
NET INCOME
Net income in 2007 was $495.3 million ($2.39 per unit), an increase of $35.2 million from $460.1 million ($2.28 per unit) in 2006. This resulted from a $13 million gain on the sale of the Trust’s long-term investment as well as a significant future income tax recovery of $121.3 million, attributed to the reduction in legislated future corporate income tax rates in addition to recording a future tax asset for tax legislation commencing in 2011 related to ARC Energy Trust.
CASH FLOW FROM OPERATING ACTIVITIES
Cash flow from operating activities decreased by four per cent in 2007 to $704.9 million from $734 million in 2006. The decrease in 2007 cash flow from operating activities is detailed in the following table.
|
| ($ millions) |
| ($ per trust unit) |
| (% variance) |
|
2006 Cash flow from Operating Activities |
| 734.0 |
| 3.59 |
|
|
|
Volume variance |
| (6.5 | ) | (0.03 | ) | (1 | ) |
Price variance |
| 27.6 |
| 0.14 |
| 4 |
|
Cash gains on risk management contracts |
| (15.1 | ) | (0.07 | ) | (2 | ) |
Royalties |
| 2.8 |
| 0.01 |
| — |
|
Expenses: |
|
|
|
|
|
|
|
Transportation |
| (1.9 | ) | (0.01 | ) | — |
|
Operating (1) |
| (23.9 | ) | (0.11 | ) | (3 | ) |
Cash G&A |
| (9.6 | ) | (0.05 | ) | (1 | ) |
Interest |
| (5.2 | ) | (0.03 | ) | (1 | ) |
Taxes |
| 0.4 |
| — |
| — |
|
Realized foreign exchange gain |
| (0.4 | ) | — |
| — |
|
Weighted average trust units |
| — |
| (0.10 | ) | — |
|
Non-cash and other items (2) |
| 2.7 |
| 0.01 |
| — |
|
2007 Cash flow from Operating Activities |
| 704.9 |
| 3.35 |
| (4 | ) |
(1) Excludes non-cash portion of LTIP expense recorded in operating costs.
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(2) Includes the changes in non-cash working capital and expenditures on site restoration and reclamation.
PRODUCTION
Production volume averaged 62,723 boe per day in 2007 compared to 63,056 boe per day in 2006 as detailed in the table below. Late in the fourth quarter of 2007, the Trust brought on new production in both the Dawson and Pouce areas, achieving exit production of approximately 65,000 boe per day by the end of December 2007.
Production |
| 2007 |
| 2006 |
| % Change |
|
Light & medium crude oil (bbl/d) |
| 27,366 |
| 27,674 |
| (1 | ) |
Heavy oil (bbl/d) |
| 1,316 |
| 1,368 |
| (4 | ) |
Natural gas (mcf/d) |
| 180,086 |
| 179,067 |
| 1 |
|
NGL (bbl/d) |
| 4,027 |
| 4,170 |
| (3 | ) |
Total production (boe/d) (1) |
| 62,723 |
| 63,056 |
| (1 | ) |
% Natural gas production |
| 48 |
| 47 |
|
|
|
% Crude oil and liquids production |
| 52 |
| 53 |
|
|
|
(1) Reported production for a period may include minor adjustments from previous production periods.
Oil production decreased slightly to 28,682 boe per day from 29,042 boe per day in 2006. Natural gas production was 180.1 mmcf per day in 2007, essentially unchanged from the 179.1 mmcf per day produced in 2006. The stable production was a result of ARC’s active 2007 internal drilling program particularly in northern and southeast Alberta as well as southwestern Saskatchewan. The Trust drilled six horizontal natural gas wells in the Dawson area as well as 144 natural gas wells in southeastern Alberta and southwestern Saskatchewan during 2007.
The Trust’s objective is to maintain annual production through the drilling of wells and other development activities. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During 2007, the Trust drilled 278 gross wells (220 net wells) on operated properties; 99 gross oil wells, three water injection wells and 172 gross natural gas wells with a 99 per cent success rate.
The Trust expects that 2008 full year production will be approximately 63,000 boe per day and that 310 gross wells (252 net wells) will be drilled by ARC on operated properties with participation in an additional 140 gross wells to be drilled on the Trust’s non-operated properties. The Trust estimates that the 2008 drilling program will add sufficient production from new wells to offset production declines on existing properties.
The following table summarizes the Trust’s production by core area:
|
| 2007 |
| 2006 |
| ||||||||||||
Production |
| Total |
| Oil |
| Gas |
| NGL |
| Total |
| Oil |
| Gas |
| NGL |
|
Central AB |
| 7,967 |
| 1,596 |
| 30.3 |
| 1,319 |
| 8,206 |
| 1,553 |
| 31.3 |
| 1,433 |
|
Northern AB & BC |
| 19,797 |
| 5,773 |
| 74.8 |
| 1,552 |
| 18,897 |
| 6,194 |
| 67.6 |
| 1,452 |
|
Pembina & Redwater |
| 13,703 |
| 9,474 |
| 19.2 |
| 1,034 |
| 13,950 |
| 9,453 |
| 20.0 |
| 1,157 |
|
S.E. AB & S.W. Sask. |
| 10,040 |
| 1,044 |
| 53.9 |
| 10 |
| 10,743 |
| 1,071 |
| 58.0 |
| 9 |
|
S.E. Sask. & MB |
| 11,216 |
| 10,795 |
| 1.9 |
| 112 |
| 11,260 |
| 10,771 |
| 2.2 |
| 119 |
|
Total |
| 62,723 |
| 28,682 |
| 180.1 |
| 4,027 |
| 63,056 |
| 29,042 |
| 179.1 |
| 4,170 |
|
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is southwest.
COMMODITY PRICES PRIOR TO HEDGING
|
| 2007 |
| 2006 |
| % Change |
|
Average Benchmark Prices |
|
|
|
|
|
|
|
AECO gas ($/mcf) (1) |
| 6.61 |
| 6.98 |
| (5 | ) |
WTI oil (US$/bbl) (2) |
| 72.37 |
| 66.25 |
| 9 |
|
US$/C$ foreign exchange rate |
| 0.94 |
| 0.88 |
| 7 |
|
WTI oil (CDN $/bbl) |
| 77.35 |
| 75.00 |
| 3 |
|
ARC Realized Prices Prior to Hedging |
|
|
|
|
|
|
|
Oil ($/bbl) |
| 69.24 |
| 65.26 |
| 6 |
|
Natural gas ($/mcf) |
| 6.75 |
| 6.97 |
| (3 | ) |
NGL ($/bbl) |
| 54.79 |
| 52.63 |
| 4 |
|
Total commodity revenue before hedging ($/boe) |
| 54.54 |
| 53.33 |
| 2 |
|
Other revenue ($/boe) |
| 0.13 |
| 0.13 |
| — |
|
Total revenue before hedging ($/boe) |
| 54.67 |
| 53.46 |
| 2 |
|
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(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
Although oil prices have achieved record highs throughout 2007 peaking at US$95.58 per barrel and averaging US$72.37 per barrel for the full year, the strengthening of the Canadian dollar relative to the U.S. dollar was responsible for eroding most of the gains and negatively impacted the price of oil in Canadian dollar terms. The price of oil in U.S. dollars increased by nine per cent for the full year of 2007, however, the Canadian dollar equivalent increased by only three per cent. The foreign exchange rate reached record highs in 2007 with the Canadian dollar peaking at an exchange rate of 1.1030 US$/C$ in November 2007. The average US$/C$ foreign exchange rate was 0.93 US$/C$ for the full year of 2007 and the Canadian dollar Bank of Canada noon day rate on December 31, 2007 was 1.01 US$/C$.
The Trust’s oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than three per cent of the Trust’s liquids production. The realized price for the Trust’s oil, before hedging, increased six per cent to $69.24 from $65.26 for the full year of 2006.
Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $6.61 per mcf in 2007 compared to $6.98 per mcf in 2006. Natural gas prices were stronger in the first half of the year but declined throughout the third and fourth quarters. ARC’s realized gas price, before hedging, decreased by three per cent to $6.75 per mcf compared to $6.97 per mcf in 2006. ARC’s realized gas price is based on prices received at the various markets in which the Trust sells its natural gas. ARC’s natural gas sales portfolio consists of gas sales priced at the AECO monthly index, the AECO daily spot market, eastern and mid-west United States markets and a portion to aggregators.
Prior to hedging activities, ARC’s total realized commodity price was $54.67 per boe in 2007, a two per cent increase from the $53.46 per boe received prior to hedging in 2006.
REVENUE
Revenue increased to a historical high of $1.25 billion in 2007. The increase in revenue was attributable to higher realized oil prices which were partially offset by lower realized natural gas prices as compared to 2006.
A breakdown of revenue is as follows:
Revenue ($ millions) |
| 2007 |
| 2006 |
| % Change |
|
Oil revenue |
| 724.8 |
| 691.8 |
| 5 |
|
Natural gas revenue |
| 443.4 |
| 455.7 |
| (3 | ) |
NGL revenue |
| 80.5 |
| 80.1 |
| — |
|
Total commodity revenue |
| 1,248.7 |
| 1,227.6 |
| 2 |
|
Other revenue |
| 2.9 |
| 2.9 |
| — |
|
Total revenue |
| 1,251.6 |
| 1,230.5 |
| 2 |
|
RISK MANAGEMENT AND HEDGING ACTIVITIES
ARC continues to maintain an ongoing risk management program to reduce the volatility of revenues in order to enhance stability of distributions, protect acquisition economics, and fund capital expenditures. The risk management program was revised in 2005 to maintain a significant portion of upside price participation on production volumes that has resulted in cash hedging gains, net of premiums, of $14.1 million in 2007 and $29.3 million in 2006.
The Trust currently limits the amount of forecast production that can be hedged to 55 per cent with the other 45 per cent of production being sold for market prices.
During 2007, the WTI U.S. dollar posted oil price increased to a high of US$95.98 per barrel with an annual average posted price of US$72.37 per barrel. From a corporate perspective this has had a positive impact on the Trust’s revenue, however, this has resulted in a loss recorded for the Trust’s oil risk management contracts. During 2007 ARC had an unrealized total mark-to-market loss year-over-year of $55.9 million with a net unrealized mark-to-market liability of $68 million as at December 31, 2007. The mark-to-market values represent the market price to buy-out the Trust’s contracts as of December 31, 2007 and may be different from what will eventually be realized.
The most significant portion of ARC’s total unrealized mark-to-market position at year end was a $35.3 million loss relating to the Redwater and NPCU hedged volumes of 5,000 bbl per day, which limits upside price potential to $85 and $90 per barrel in 2008 and 2009 respectively. When these
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properties were acquired in 2005, the acquisition economics were based on crude oil prices of approximately CAD$57.50 per barrel. The remainder of the mark-to-market loss results in potential settling of commodity, foreign exchange and interest rates above the level of the Trust’s hedges as disclosed in Note 11 to the Consolidated Financial Statements.
During 2007 ARC entered into a number of hedging transactions including the following:
· Energy equivalent swap: ARC entered into an energy equivalent swap in order to shift its price exposure to be more heavily weighted towards crude oil for the period of April 1 through October 31, 2008. Through the use of financial contracts, ARC has rebalanced its price exposure from a forecasted 50:50 to a 52:48 oil-gas weighting. ARC achieved this rebalancing by selling AECO natural gas at $7.10 per GJ and buying crude oil at CDN$73.95 per barrel.
· In light of the significant increase in value of the Canadian dollar during the last 12 months, ARC implemented a program to lock in exchange rates on future principal repayments on U.S. dollar denominated senior secured notes. These transactions effectively lock in the unrealized foreign exchange gains on the U.S. denominated debt. Although the unrealized foreign exchange gains will continue to fluctuate quarter-to-quarter with changes in the exchange rate, these financial transactions have effectively fixed the economic gains of the change in exchange rates from the rate at which the U.S. denominated debt was issued and the rate at which the future payments have been committed. At the end of the year ARC had US$218 million of U.S. denominated senior secured debt outstanding (CDN$215.5 million) requiring annual principal repayments of varying amounts extending until December 15, 2017. As at December 31, 2007, ARC had locked in the foreign exchange rate for a total of US$127.2 million of its principal repayments in years 2012 through 2017 at an average rate with the Canadian dollar slightly greater than par (1.02 US$/C$).
· Natural gas protection through to March 2009: In the fall of 2007 ARC entered into natural gas collars to protect prices as far out as March 2009. For the period from November 2008 to March 2009, ARC has purchased NYMEX natural gas puts at $8.50 per mmbtu and sold calls at $11.00 per mmbtu.
The percentage of forecast volumes hedged in 2008 is: 43 per cent in the first quarter, 36 per cent in the second quarter, 26 per cent in the third quarter and 23 per cent in the fourth quarter.
The following table is an indicative summary of the Trust’s positions for crude oil, natural gas and related foreign exchange for the next twelve months as at December 31, 2007.
Hedge Positions
As at December 31, 2007 (1)(2) |
| Q1 2008 |
| Q2 2008 |
| Q3 2008 |
| Q4 2008 |
| ||||||||
Crude Oil |
| US$/bbl |
| bbl/day |
| US$/bbl |
| bbl/day |
| US$/bbl |
| bbl/day |
| US$/bbl |
| bbl/day |
|
Sold Call |
| 94.08 |
| 19,000 |
| 89.04 |
| 13,000 |
| 90.00 |
| 10,000 |
| 90.00 |
| 10,000 |
|
Bought Put |
| 75.14 |
| 20,000 |
| 70.47 |
| 15,500 |
| 68.13 |
| 10,000 |
| 68.13 |
| 10,000 |
|
Sold Put |
| 54.91 |
| 11,500 |
| 54.96 |
| 11,500 |
| 51.07 |
| 7,000 |
| 51.07 |
| 7,000 |
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Natural Gas |
| CDN$/GJ |
| GJ/day |
| CDN$/GJ |
| GJ/day |
| CDN$/GJ |
| GJ/day |
| CDN$/GJ |
| GJ/day |
|
Sold Call |
| 8.02 |
| 47,478 |
| 8.41 |
| 41,101 |
| 8.41 |
| 41,101 |
| 8.88 |
| 27,840 |
|
Bought Put |
| 6.87 |
| 47,478 |
| 6.64 |
| 41,101 |
| 6.64 |
| 41,101 |
| 6.82 |
| 27,840 |
|
Sold Put |
| 4.75 |
| 10,551 |
| 4.97 |
| 31.101 |
| 4.97 |
| 31,101 |
| 5.04 |
| 10,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange |
| C$/US$ |
| $Million |
| C$/US$ |
| $Million |
| C$/US$ |
| $Million |
| C$/US$ |
| $Million |
|
Bought Put |
| 1.0750 |
| 3.0 |
| 1.0750 |
| 3.0 |
| 1.0750 |
| 3.0 |
| 1.0750 |
| 3.0 |
|
Sold Put |
| 1.0300 |
| 3.0 |
| 1.0300 |
| 3.0 |
| 1.0300 |
| 3.0 |
| 1.0300 |
| 3.0 |
|
Swap |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
(1) The prices and volumes noted above represents averages for several contracts and the average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. The natural gas price shown translates all NYMEX positions to an AECO equivalent price. In addition to positions shown here, ARC has entered into additional basis positions.
(2) Please refer to the Trust’s website at www.arcenergytrust.com under “Hedging Program” within the “Investor Relations” section for details on the Trust’s hedging positions as of December 31, 2007.
The above table should be interpreted as follows using the first quarter 2008 Crude oil hedges as an example. To accurately analyze the Trust’s hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.
· If the market price is below $54.91, ARC will receive $75.14 less the difference between $54.91 and the market price on 11,500 barrels per day. For example if the market price is $54.90, the Trust will receive $75.13 on 11,500 barrels per day.
· If the market price is between $54.91 and $75.14, ARC will receive $75.14 on 20,000 barrels per day.
· If the market price is between $75.14 and $94.08, ARC will receive the market price on 20,000 barrels per day.
7
• If the market price exceeds $94.08, ARC will receive $94.08 on 19,000 barrels per day and the market price for the remaining 1,000 hedged volumes.
GAIN OR LOSS ON RISK MANAGEMENT CONTRACTS
Gain or loss on risk management contracts comprise realized and unrealized gains or losses on risk management contracts that do not meet the accounting definition requirements of an effective hedge, even though the Trust considers all risk management contracts to be effective economic hedges. Accordingly, gains and losses on such contracts are shown as a separate category in the statement of income.
ARC realized gains on natural gas contracts throughout the year as a result of soft prices where ARC’s floor protection level exceeded the market price. ARC’s crude oil contracts posted a loss for the year of $5.7 million as a result of record high oil prices that exceeded some of the Trust’s ceiling contracts during the second half of the year. On foreign exchange and interest rates, ARC realized gains during the last three quarters of the year particularly on U.S. dollar put-spreads that protected ARC from an appreciating Canadian dollar.
The following is a summary of the total gain (loss) on risk management contracts for the year-over-year change as of the 2007 year-end:
Risk Management Contracts |
| Crude Oil |
| Natural |
| Interest & |
| 2007 |
| 2006 |
|
($ millions) |
| & Liquids |
| Gas |
| Foreign Currency |
| Total |
| Total |
|
Realized cash (loss) gain on contracts (1) |
| (5.7 | ) | 15.4 |
| 4.4 |
| 14.1 |
| 29.3 |
|
Unrealized (loss) gain on contracts (2) |
| (60.2 | ) | (2.9 | ) | 7.2 |
| (55.9 | ) | (4.6 | ) |
Total (loss) gain on risk management contracts |
| (65.9 | ) | 12.5 |
| 11.6 |
| (41.8 | ) | 24.7 |
|
(1) Realized cash gains and losses represent actual cash settlements or receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair value of the contracts during the period.
OPERATING NETBACKS
The Trust’s operating netback, after realized hedging gains, decreased one per cent to $35.44 per boe in 2007 compared to $35.95 per boe in 2006. The decrease in netbacks in 2007 is primarily due to a decrease in the realized gain on risk management contracts, a decrease in gas prices, as well as an increase in operating and transportation costs. These items were partially offset by a decrease in royalties and an increase in revenues as a result of higher oil prices in 2007.
The components of operating netbacks are shown below:
|
| Crude Oil |
| Heavy Oil |
| Gas |
| NGL |
| 2007 Total |
| 2006 Total |
|
Netbacks ($ per boe) |
| ($/bbl) |
| ($/bbl) |
| ($/mcf) |
| ($/bbl) |
| ($/boe) |
| ($/boe) |
|
Weighted average sales price |
| 70.20 |
| 49.17 |
| 6.75 |
| 54.79 |
| 54.54 |
| 53.33 |
|
Other revenue |
| — |
| — |
| — |
| — |
| 0.13 |
| 0.13 |
|
Total revenue |
| 70.20 |
| 49.17 |
| 6.75 |
| 54.79 |
| 54.67 |
| 53.46 |
|
Royalties |
| (11.33 | ) | (4.34 | ) | (1.25 | ) | (14.90 | ) | (9.59 | ) | (9.66 | ) |
Transportation |
| (0.27 | ) | (1.09 | ) | (0.20 | ) | — |
| (0.72 | ) | (0.63 | ) |
Operating costs (1) |
| (11.84 | ) | (12.16 | ) | (1.26 | ) | (7.73 | ) | (9.54 | ) | (8.49 | ) |
Netback prior to hedging |
| 46.76 |
| 31.58 |
| 4.04 |
| 32.16 |
| 34.82 |
| 34.68 |
|
Realized (loss) gain on risk management contracts |
| (0.07 | ) | — |
| 0.23 |
| — |
| 0.62 |
| 1.27 |
|
Netback after hedging |
| 46.69 |
| 31.58 |
| 4.27 |
| 32.16 |
| 35.44 |
| 35.95 |
|
(1) Operating expenses are composed of direct costs incurred to operate oil and gas wells. A number of assumptions have been made in allocating these costs between oil, heavy oil, natural gas and natural gas liquids production.
Royalties as a percentage of pre-hedged commodity revenue net of transportation costs remained constant at 18 per cent for both 2007 and 2006 at $9.59 per boe and $9.66 per boe respectively. The Trust has made a preliminary assessment of the impact of the new Alberta Royalty legislation effective January 1, 2009 and we estimate that the total royalties payable on the Trust’s production will increase by approximately 10 per cent at year-end 2007 commodity prices calculated using expected 2009 production rates. This estimate will vary based on prices, production decline of existing wells and performance and location of new wells drilled. The 10 per cent increase in royalties payable which equates to approximately a two per cent increase in the Trust’s royalty rate takes into account that approximately 37 per cent of the Trust’s production is outside the Province of Alberta. The royalty change in 2009 on a property by property basis is highly variable with decreased royalties on some properties, primarily shallow gas wells, and a doubling of royalties on Alberta high rate oil production properties. The New Alberta Royalty Framework will impact future drilling
8
decisions in order for the Trust to maintain acceptable rates of return on its capital deployed.
Operating costs increased to $9.54 per boe compared to $8.49 per boe in 2006. Total operating costs increased $23 million or, 12 per cent, in 2007. This increase was due primarily to the additional operating costs associated with approximately 300 new wells brought on stream in 2007, increased labour costs for field staff and some service providers particularly in northern operations, increased electricity consumption and costs for well re-activations in the Redwater and NPCU areas. There are a high percentage of fixed operating costs for the Trust’s properties resulting in a trend of increased operating costs on a per boe basis as the properties’ production declines over time. The Trust estimates that full year 2008 operating costs will be approximately $235 million or approximately $10.20 per boe based on annual production of approximately 63,000 boe per day.
Transportation costs increased 14 per cent to $0.72 per boe in 2007 compared to $0.63 per boe in 2006 as a result of ongoing challenges in Saskatchewan where shipping restrictions are in place for the Enbridge pipeline. The Trust is required to truck all new production that exceeds our historical capacity for the Enbridge pipeline. Investors can expect transportation prices to increase again once the winter drilling program begins and new production levels increase. An expansion of the Enbridge pipeline is expected to be completed sometime in early 2008, however, transportation costs for 2008 are still expected to increase to $0.80 per boe based on annual production of 63,000 boe per day.
GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) AND TRUST UNIT INCENTIVE COMPENSATION
G&A net of overhead recoveries on operated properties increased four per cent to $49.1 million in 2007 from $47.1 million in 2006. Increases in G&A expenses for 2007 were due to increased staff levels, higher compensation costs and increased long-term incentive benefits. As a result of a tight labour market, the costs associated with hiring, compensating and retaining employees and consultants have risen. The anticipated increase in G&A costs was partially offset by higher overhead recoveries attributed to high levels of capital and operating activity throughout 2007 and as a result of incremental overhead charged on new and existing operated properties.
The Trust paid out $12.7 million under the Whole Trust Unit Incentive Plan (“Whole Unit Plan”) in 2007 compared to $5.2 million in 2006 ($9.6 million and $3.5 million of the payouts were allocated to G&A in 2007 and 2006, respectively, and the remainder to operating costs and property, plant and equipment). The higher cash payment in 2007 resulted from the Trust’s first payments for performance units issued under the plan in 2004. The next cash payment under the Whole Unit Plan is scheduled to occur in April 2008.
The following is a breakdown of G&A and trust unit incentive compensation expense:
G&A and Trust Unit Incentive Compensation Expense
($ millions except per boe) |
| 2007 |
| 2006 |
| % Change |
|
G&A expenses |
| 52.7 |
| 45.8 |
| 15 |
|
Operating recoveries |
| (16.4 | ) | (12.9 | ) | 27 |
|
Cash G&A expenses before Whole Unit Plan |
| 36.3 |
| 32.9 |
| 10 |
|
Cash Expense – Whole Unit Plan |
| 9.6 |
| 3.5 |
| 174 |
|
Cash G&A expenses including Whole Unit Plan |
| 45.9 |
| 36.4 |
| 26 |
|
Accrued compensation - Rights Plan |
| — |
| 2.5 |
| (100 | ) |
Accrued compensation - Whole Unit Plan |
| 3.2 |
| 8.2 |
| (61 | ) |
Total G&A and trust unit incentive compensation expense |
| 49.1 |
| 47.1 |
| 4 |
|
Total G&A and trust unit incentive compensation expense per boe |
| 2.15 |
| 2.05 |
| 5 |
|
A non-cash trust unit incentive compensation expense (“non-cash compensation expense”) of $3.2 million ($0.14 per boe) was recorded in 2007 compared to $10.7 million ($0.47 per boe) in 2006. This non-cash amount relates to estimated costs of the Whole Unit Plan to December 31, 2007. The 2006 amounts also include estimated costs of the Trust Unit Incentive Rights Plan (“Rights Plan”) that was fully expensed at December 31, 2006 with the exception of a small portion recorded in March 2007.
RIGHTS PLAN
The rights plan was replaced by a Whole Unit Plan during 2004 after which no further rights under the rights plan were issued. The Rights Plan provided employees, officers and independent directors the right to purchase units at a specified price. The rights have a five year term and vest equally over three years. The exercise price of the rights is adjusted downwards from time to time by the amount that distributions to unitholders in any calendar quarter exceed 2.5 per cent of the Trust’s net book value of property, plant and equipment. During 2007, 0.1 million rights were exercised and 0.2 million rights remained outstanding as at December 31, 2007. All of the rights have been fully expensed since March 31, 2007 and
9
are scheduled to expire on or before December 31, 2008.
WHOLE UNIT PLAN
In March 2004, the Board of Directors approved a new Whole Unit Plan to replace the Rights Plan for new awards granted subsequent to the first quarter of 2004. The new Whole Unit Plan results in employees, officers and directors (the “plan participants”) receiving cash compensation in relation to the value of a specified number of underlying units. The Whole Unit Plan consists of Restricted Trust Units (“RTUs”) for which the number of units is fixed and will vest over a period of three years and Performance Trust Units (“PTUs”) for which the number of units is variable and will vest at the end of three years.
Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying trust units plus accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the performance of the Trust compared to its peers and indicated by the performance multiplier. The performance multiplier is based on the percentile rank of the Trust’s total unitholder return compared to its peers. Total return is calculated as the sum of the change in the market price of the trust units in the period plus the amount of distributions in the period. The performance multiplier ranges from zero, if ARC’s performance ranks in the bottom quartile, to two for top quartile performance.
The following table shows the changes during the year of RTUs and PTUs outstanding:
Whole Unit Plan |
| Number of |
| Number of |
| Total |
| |||
(units in thousands and $ millions except per unit) |
| RTUs |
| PTUs |
| RTUs and PTUs |
| |||
Balance, beginning of year |
| 648 |
| 683 |
| 1,331 |
| |||
Granted in the year |
| 422 |
| 362 |
| 784 |
| |||
Vested in the year |
| (286 | ) | (110 | ) | — |
| |||
Forfeited in the year |
| (38 | ) | (32 | ) | (70 | ) | |||
Balance, end of year (1) |
| 746 |
| 903 |
| 1,649 |
| |||
Estimated distributions to vesting date (2) |
| 226 |
| 350 |
| 576 |
| |||
Estimated units upon vesting after distributions |
| 972 |
| 1,25 |
| 2,225 |
| |||
Performance multiplier (3) |
| — |
| 1.7 |
| — |
| |||
Estimated total units upon vesting |
| 972 |
| 1,958 |
| 2,931 |
| |||
Trust unit price at December 31, 2007 |
| $ | 20.40 |
| $ | 20.40 |
| $ | 20.40 |
|
Estimated total value upon vesting |
| $ | 19.8 |
| $ | 39.9 |
| $ | 59.8 |
|
(1) Based on underlying units before performance multiplier and accrued distributions.
(2) Represents estimated additional units to be issued equivalent to estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to be 1.7 at December 31, 2007 based on a weighted average calculation of all outstanding grants. The performance multiplier is assessed each period end based on actual results of the Trust relative to its peers. Estimated total units upon vesting will not reconcile due to rounding.
The value associated with the RTUs and PTUs is expensed in the statement of income over the vesting period with the expense amount being determined by the unit price, the number of PTUs to be issued on vesting, and distributions. Therefore, the expense recorded in the statement of income fluctuates over time.
10
Below is a summary of the range of future expected payments under the Whole Unit Plan based on variability of the performance multiplier:
Value of Whole Unit Plan as at December 31, 2007 |
| Performance multiplier |
| |||||||
(units thousands and $ millions except per unit) |
| — |
| 1.0 |
| 2.0 |
| |||
Estimated trust units to vest |
|
|
|
|
|
|
| |||
RTUs |
| 972 |
| 972 |
| 972 |
| |||
PTUs |
| — |
| 1,253 |
| 2,513 |
| |||
Total units (1) |
| 972 |
| 2,225 |
| 3, 485 |
| |||
Trust unit price (2) |
| $ | 20.40 |
| $ | 20.40 |
| $ | 20.40 |
|
Trust unit distributions per month (2) |
| $ | 0.20 |
| $ | 0.20 |
| $ | 0.20 |
|
Value of Whole Unit Plan upon vesting |
| 19.8 |
| 45.4 |
| 71.1 |
| |||
Officers |
| 2.1 |
| 13.9 |
| 25.8 |
| |||
Directors |
| 1.5 |
| 1.5 |
| 1.5 |
| |||
Staff |
| 16.2 |
| 30.0 |
| 43.8 |
| |||
Total payments under Whole Unit Plan (3) |
| 19.8 |
| 45.4 |
| 71.1 |
| |||
2008 |
| 8.8 |
| 16.0 |
| 23.1 |
| |||
2009 |
| 6.9 |
| 14.9 |
| 23.0 |
| |||
2010 |
| 4.1 |
| 14.5 |
| 25.0 |
|
(1) Includes additional estimated units to be issued for accrued distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility of the underlying trust unit price and distribution levels. Assumes future trust unit price of $20.40 per trust unit and distributions of $0.20 per unit per month based on current levels.
(3) Upon vesting, a cash payment is made equivalent to the value of the underlying trust units. The payment is made on vesting dates in April and October of each year and at that time is reflected as a reduction of cash flow from operating activities.
Due to the variability in the future payments under the plan, the Trust estimates that between $19.8 million and $71.1 million will be paid out from 2008 through 2010 based on the current trust unit price, distribution levels and the Trust’s market performance relative to its peers.
INTEREST EXPENSE
Interest expense increased to $36.9 million in 2007 from $31.8 million in 2006 due to an increase in short-term interest rates, and higher debt balances as a result of the Trust’s capital expenditure and acquisitions activity which was funded $135.7 million with debt. As at December 31, 2007, the Trust had $714.5 million of debt outstanding, of which $215.5 million was fixed at a weighted average rate of 5.1 per cent and $499 million was floating at current market rates plus a credit spread of 60 basis points. Fifty-two per cent of the Trust’s debt is denominated in U.S. dollars. The cumulative decline of 1.25 per cent in the U.S. interest rates announced in January 2008 by the Federal Reserve Board should result in lower borrowing costs for the Trust in 2008.
FOREIGN EXCHANGE GAINS AND LOSSES
The Trust recorded a gain of $69.4 million ($3.03 per boe) on foreign exchange transactions compared to a loss of $4.2 million ($0.18 per boe) in 2006. These amounts include both realized and unrealized foreign exchange gains and losses.
Unrealized foreign exchange gains and losses are due to revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain/loss impacts net income but does not impact cash flow from operating activities as it is a non-cash amount. From December 31, 2006 to December 31, 2007, the US$/C$ exchange rate has increased from 0.86 to 1.01 creating an unrealized gain of $64.6 million on U.S. dollar denominated debt.
Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements. Included in the 2007 realized foreign exchange gain was a gain of $5 million relating, in part, to a repayment of US$6 million of debt in October 2007. The debt was issued in 2002 when the US$/C$ foreign exchange rate was approximately 0.64 and strengthened considerably to 1.04 on repayment in 2007.
11
TAXES
In 2007, a future income tax recovery of $121.3 million was included in income compared to an $87.1 million recovery in 2006. The significant increase in the future income tax recovery in 2007 was due to the legislated reduction in the future corporate income tax rates in the fourth quarter of 2007 whereby the Trust’s expected future corporate income tax rate decreased to 25.8 per cent from the 29.4 per cent prior to the rate reduction. The future income tax recovery in 2006 was also due to legislated reductions in the future corporate income tax rates.
At December 31, 2007, the Trust and the Trust’s subsidiaries had tax pools of approximately $1.84 billion. The tax pools consist of $1.66 billion of tangible and intangible capital assets, $13.8 million of non-capital loss carry-forwards which expire at various periods to 2026, and $171.4 million of other tax pools. Included in the above tax basis are the Trust’s tax pools of approximately $537.7 million.
On October 31, 2006, the Finance Minister announced the Federal Government’s plan regarding the taxation of Income Trusts. Currently, distributions paid to unitholders, other than returns of capital, are claimed as a deduction by the Trust in arriving at taxable income whereby tax is eliminated at the Trust level and is paid by the unitholders. The Trust tax legislation that received Royal Assent on June 22, 2007, will result in a two-tiered tax structure whereby distributions would first be subject to the federal corporate income tax rate plus a deemed 13 per cent provincial income tax at the Trust level commencing in 2011 (or earlier, if trusts that were publicly traded as of October 31, 2006 exceed the normal growth guidelines announced by the Minister on December 15, 2006), and then unitholders would be subject to tax on the distribution as if it were a taxable dividend paid by a taxable Canadian corporation. As a result, the future tax position of the Trust, the parent entity, is now required to be reflected in the consolidated future income tax calculation. The Trust recorded a $35.6 million one time increase in earnings and a corresponding decrease to its future income tax liability in the second quarter as a result of timing differences within the Trust that had not been previously recognized. The initial recognition of $35.6 million comprised $24.7 million for pre-2007 generated temporary differences and $10.9 million for temporary differences relating to the current year.
On October 30, 2007, the Finance Minister announced, as part of the 2007 Economic Statement, changes to the tax system including reduction of the corporate income tax rate from 22.1 per cent to 15 per cent by 2012. The reductions will be phased in between 2008 and 2012. Legislation enacting the measures announced in the Economic Statement received Royal Assent on December 14, 2007. The reduction in the general corporate tax rate will also apply to the taxation of Income Trusts, reducing the combined federal and deemed Provincial tax rate for distributions to 28 per cent in 2012.
The Federal Government has also indicated that they will seek to collaborate with the provinces and territories to reach a combined federal-provincial-territorial statutory corporate income tax rate of 25 per cent, reflecting a 10 per cent provincial rate, equal to the current Alberta tax rate. It is uncertain whether this collaboration will also affect the tax on Income Trusts by reducing the proposed deemed provincial rate of 13 per cent.
On December 20, 2007, the Finance Minister announced technical amendments to provide some clarification to the Trust tax legislation. As part of the announcement the Minister indicated that the federal government intends to provide legislation in 2008 to permit Income Trusts to convert to taxable Canadian corporations without any undue tax consequences to investors or the Trust.
Management and the Board of Directors continue to review the impact of this tax on our business strategy and while there has not been a decision as to ARC’s future direction at this time we are of the opinion that the conversion from a trust to a corporation may be the most logical and tax efficient alternative for ARC unitholders. We expect future technical interpretations and details will further clarify the legislation. At the present time, ARC believes that if structural or other similar changes are not made, the after-tax distribution amount in 2011 to taxable Canadian investors will remain approximately the same, however, will decline for both tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign investors.
The Trust tax rate applicable to 2007 is 34 per cent, however, the application of the Trust tax should be deferred until 2011 as the Trust has not exceeded the normal growth guidelines announced by the Minister. The Trust does not anticipate that the Trust taxation legislation guidelines, which limit the growth of the Trust up to 2011, will impair the Trust’s ability to annually replace or grow reserves in the next three years as the guidelines allow sufficient growth targets. The corporate income tax rate applicable to 2007 is 32.1 per cent, however the Trust and its subsidiaries did not pay any material cash income taxes for fiscal 2007. Due to the Trust’s structure, currently, both income tax and future tax liabilities are passed on to the unitholders by means of royalty payments made between ARC Resources and the Trust.
Federal capital taxes were eliminated effective January 1, 2006 pursuant to the Federal Government budget of May 2, 2006.
12
DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
The depletion, depreciation and accretion (“DD&A”) rate increased to $16.23 per boe in 2007 from $15.64 per boe in 2006. The higher DD&A rate is driven by an increase in the Trust’s property, plant and equipment (“PP&E”) value on the Trust’s balance sheet along with an increase in the future development costs and a small decrease in the proved reserves recorded in the Trust’s January 1, 2008 reserve report.
A breakdown of the DD&A rate is a follows:
DD&A Rate ($ millions except per boe amounts) |
| 2007 |
| 2006 |
| % Change |
|
Depletion of oil & gas assets (1) |
| 360.0 |
| 348.9 |
| 3 |
|
Accretion of asset retirement obligation (2) |
| 11.5 |
| 11.1 |
| 4 |
|
Total DD&A |
| 371.5 |
| 360.0 |
| 3 |
|
DD&A rate per boe |
| 16.23 |
| 15.64 |
| 4 |
|
(1) Includes depletion of the capitalized portion of the asset retirement obligation that was capitalized to the PP&E balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation during the year.
GOODWILL
The goodwill balance of $157.6 million arose as a result of the acquisition of Star Oil and Gas in 2003. The goodwill balance was determined based on the excess of total consideration paid plus the future income tax liability less the fair value of the assets for accounting purposes acquired in the transaction.
Accounting standards require that the goodwill balance be assessed for impairment at least annually or more frequently if events or changes in circumstances indicate that the balance might be impaired. If such impairment exists, it would be charged to income in the period in which the impairment occurs. The Trust has determined that there was no goodwill impairment as of December 31, 2007.
CAPITAL EXPENDITURES AND NET ACQUISITIONS
Total capital expenditures, excluding acquisitions and dispositions, totaled $397.2 million in 2007 compared to $364.5 million in 2006. This amount was incurred on drilling and completions, geological, geophysical and facilities expenditures, and undeveloped acreage. The $77.5 million purchases of undeveloped land in 2007 have increased the Trust’s land holdings to 536,232 net acres that will help sustain the drilling opportunities of the Trust which will, if successful, provide future production and reserves.
In addition to capital expenditures on development activities, the Trust completed net property acquisitions of $42.5 million in 2007. The most significant property acquisition was the purchase of properties in southeast Saskatchewan late in the third quarter for $24.8 million. The acquisition contributed approximately 350 boe per day of incremental production to the Trust’s fourth quarter results.
During the year, the Trust drilled 278 gross wells (220 net wells) on operated properties; consisting of 99 gross oil wells, three water injection wells, and 172 gross natural gas wells most of which were shallow gas wells with a success rate of 99 per cent. In addition, the Trust participated in 156 gross wells (33 net wells) drilled by other operators.
Proved plus probable oil and gas reserves increased slightly to 286.4 mmboe at year-end 2007 as a result of the Trust’s 2007 capital expenditure program and property acquisitions.
Over the course of 2006 and 2007, the Trust has spent $762 million on capital expenditures, a portion of which has funded the
following activities:
· At our Dawson area in British Columbia, ARC spent $99 million of capital to drill, complete and tie-in 10 horizontal and 13 vertical wells. ARC also expanded its compression facilities and signed a long-term contract with a third party processor to facilitate processing additional gas volumes in the area. ARC’s production grew from 19 mmcf per day to 45 mmcf per day over the two year period. In addition, ARC has been building for the future by spending $100 million on acquiring 44,000 net acres of undeveloped land in the area.
· At our Ante Creek area, ARC has focused on a combination of infill and highly successful stepout pool extension drilling. ARC has spent $61 million on drilling, completions, tie-ins, facilities, and land purchases. ARC drilled 25 wells that resulted in positive reserves growth and record production in the area of 5,100 boe per day for the month of December 2007.
· In Southeast Saskatchewan we have spent $108 million and increased production as a result of drilling 41 wells in the area including 35 new horizontal oil wells, two successful exploration locations and one new vertical injection well.
13
· �� ARC’s 2007 exit production at Redwater was 4,300 boe per day, which represents a 20 per cent increase over production at the time that ARC closed the Redwater acquisition in December 2005. To achieve these results, ARC invested $20 million focused mainly on a combination of optimization and reactivation projects and the drilling of infill vertical wells that were identified through seismic data acquired in 2006.
· ARC drilled 150 wells in our Southeast Alberta and Southwest Saskatchewan area including 132 shallow gas wells and 18 new oil wells.
A breakdown of capital expenditures and net acquisitions is shown below:
Capital Expenditures ($ millions) |
| 2007 |
| 2006 |
| % Change |
|
Geological and geophysical |
| 14.9 |
| 11.4 |
| 31 |
|
Drilling and completions |
| 229.5 |
| 240.5 |
| (5 | ) |
Plant and facilities |
| 72.1 |
| 77.6 |
| (7 | ) |
Undeveloped land |
| 77.5 |
| 32.4 |
| 139 |
|
Other capital |
| 3.2 |
| 2.6 |
| 23 |
|
Total capital expenditures |
| 397.2 |
| 364.5 |
| 9 |
|
Producing property acquisitions (1) |
| 47.1 |
| 124.0 |
| (62 | ) |
Producing property dispositions (1) |
| (4.6 | ) | (8.8 | ) | 48 |
|
Corporate acquisitions (2) |
| — |
| 16.6 |
| (100 | ) |
Total capital expenditures and net acquisitions |
| 439.7 |
| 496.3 |
| (11 | ) |
(1) Value is net of post-closing adjustments.
(2) Represents total consideration for the transactions, including fees but is prior to the related future income tax liability, asset retirement obligation and working capital assumed on acquisition.
Approximately 49 per cent of the $397.2 million capital program was financed with cash flow from operating activities in 2007 compared to 65 per cent in 2006. Property acquisitions were financed through debt and working capital.
Source of Funding of Capital Expenditures and Net Acquisitions
|
| 2007 |
| 2006 |
| ||||||||
|
| Development |
| Net |
| Total |
| Development |
| Net |
| Total |
|
($ millions) |
| Capital |
| Acquisitions |
| Expenditures |
| Capital |
| Acquisitions |
| Expenditures |
|
Expenditures |
| 397.2 |
| 42.5 |
| 439.7 |
| 364.5 |
| 131.8 |
| 496.3 |
|
Per cent funded by: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities |
| 49 | % | — |
| 44 | % | 65 | % | — |
| 48 | % |
Proceeds from DRIP and Rights Plan |
| 28 | % | — |
| 25 | % | 30 | % | — |
| 22 | % |
Debt |
| 23 | % | 100 | % | 31 | % | 5 | % | 100 | % | 30 | % |
|
| 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % |
ARC has announced a $395 million capital expenditure budget for 2008 that consists of a robust drilling and development program on its diverse asset base. The 2008 capital budget is being deployed as a balanced drilling program of low and moderate risk wells, well tie-ins and other related costs, and the acquisition of undeveloped land. The Trust continues to focus on major properties with significant upside, with the objective to replace production declines through internal development opportunities. The 2008 capital expenditure budget anticipates the drilling of 252 net operated wells and the addition of new production from the capital development program to replace declines at existing properties and develop the recently acquired land holdings in the Dawson area of British Columbia. The 2008 capital budget also allows for a portion of spending to further research and pursue Enhanced Recovery Initiatives such as CO2 injection and NGC development. Current projections of cash flows, low debt levels and a strong working capital position provide the Trust with the financial flexibility to fund the 2008 capital expenditure program.
LONG-TERM INVESTMENT
During the second quarter of 2007, the Trust sold its investment in the shares of a private company that was involved in the acquisition of oil sands leases. The transaction closed on June 25, 2007. The Trust recorded a cash gain of $13.3 million with total proceeds of $33.3 million recorded as part of cash flow from investing activities.
14
ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND
At December 31, 2007, the Trust has recorded an Asset Retirement Obligation (“ARO”) of $140 million ($177.3 million at December 31, 2006) for future abandonment and reclamation of the Trust’s properties. The ARO decreased in 2007 as a result of a change in management’s estimate of the timing of when costs will be incurred. The estimated ARO includes assumptions of actual costs to abandon wells or reclaim the property as well as annual inflation factors in order to calculate the undiscounted total future liability. The undiscounted total future liability has increased to $1.3 billion as at December 31, 2007 as compared to $1 billion at December 31, 2006, as a significant portion of the costs are now projected to be incurred in years 2048 to 2058 as compared to years 2017 to 2021 as estimated on December 31, 2006. The present value impact of this change in estimate resulted in a $34.4 million reduction in the ARO balance at December 31, 2007.
Included in the December 31, 2007 ARO balance is a $3.8 million increase related to development activities in 2007. The ARO liability was also increased by $11.5 million for accretion expense in 2007 ($11.1 million in 2006) and was reduced by $18.2 million ($10.6 million in 2006) for actual abandonment expenditures incurred in 2007.
As a result of the Redwater acquisition in December 2005, the Trust set up a second reclamation fund (the “Redwater Fund”) in 2006 to fund future abandonment obligations attributed solely to the Redwater properties. The Trust makes annual contributions to the Redwater fund and may utilize the funds only for abandonment activities for the Redwater property. With the addition of the Redwater Fund, the Trust now maintains two reclamation funds that together held $26.1 million at December 31, 2007. Future contributions for the two funds will vary over time in order to provide for the total estimated future abandonment and reclamation costs that are to be incurred upon abandonment of the Trust’s properties. The Trust currently estimates that $220 million will be contributed to the funds over the next 50 years to provide for future abandonment and reclamation costs.
In total, ARC contributed $12.1 million cash to its reclamation funds in 2007 ($12.1 million in 2006) and earned interest of $1.4 million ($1 million in 2006) on the fund balances. The fund balances were reduced by $18.1 million for cash-funded abandonment expenditures in 2007 ($5.7 million in 2006). Under the terms of the Trust’s investment policy, reclamation fund investments and excess cash can only be invested in Canadian or U.S. Government securities, investment grade corporate bonds, or investment grade short-term money market securities.
CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY
A breakdown of the Trust’s capital structure is as follows as at December 31, 2007 and 2006:
Capital Structure and Liquidity |
|
|
|
|
|
($ millions except per unit and per cent amounts) |
| 2007 |
| 2006 |
|
Amount drawn under revolving credit facilities |
| 499.0 |
| 426.1 |
|
Senior secured notes |
| 215.5 |
| 261.0 |
|
Working capital deficit excluding short-term debt (1) |
| 38.2 |
| 52.0 |
|
Net debt obligations |
| 752.7 |
| 739.1 |
|
Trust units outstanding and issuable for exchangeable shares (thousands) |
| 213.2 |
| 207.2 |
|
Market price per unit at end of year |
| 20.40 |
| 22.30 |
|
Market value of trust units and exchangeable shares |
| 4,349.3 |
| 4,620.0 |
|
Total capitalization (2) |
| 5,102.0 |
| 5,359.1 |
|
Net debt as a percentage of total capitalization |
| 14.8 | % | 13.8 | % |
Net debt obligations |
| 752.7 |
| 739.1 |
|
Cash flow from operating activities |
| 704.9 |
| 734.0 |
|
Net debt to cash flow from operating activities |
| 1.1 |
| 1.0 |
|
(1) The working capital deficit excludes the balances for the current portion of risk management contracts and the current portion of future income taxes.
(2) Total capitalization as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Total capitalization is not intended to represent the total funds from equity and debt received by the Trust.
15
The Trust has a syndicated three year revolving credit facility allowing for maximum borrowing of up to $800 million. The debt is secured by all the Trust’s oil and gas properties and has the following major covenants:
COVENANT |
| POSITION AS AT DECEMBER 31, 2007 |
Long-term debt and letters of credit not to exceed three times annualized net income before non-cash expense |
| Long-term debt and letters of credit of 0.9 times annualized net income before non-cash items and interest items and interest expense |
|
|
|
Long-term debt, letters of credit and subordinated debt not to exceed four times annualized net income before non-cash items and interest expense |
| Long-term debt, letters of credit and subordinated debt of 0.9 times annualized net income before non-cash items and interest expenses |
|
|
|
Long-term debt and letters of credit not to exceed 50 per cent of the sum of the book value of unitholders’ equity, long-term debt, letters of credit, and subordinated debt |
| Long-term debt and letters of credit of 26.5 per cent of the sum of unitholders’ equity, long-term debt, letters of credit, and subordinated debt |
As indicated by the above table, the Trust is not close to breaching any of its covenants and has additional potential borrowing capacity above the $800 million credit facility. The Trust’s objective is to limit debt to under 2.0 times cash flow from operating activities and 20 per cent of total capitalization. In addition to the $800 million credit facility, the Trust has outstanding senior secured notes in the amount of $215.5 million as at December 31, 2007, which do not reduce the available borrowings under the credit facility. The Trust had $4.8 million of letters of credit outstanding at December 31, 2007 and no subordinated debt. As at December 31, 2007, the Trust was in compliance with all covenants.
During the third quarter the Trust entered into treasury lock contracts in order to manage its interest rate exposure on future debt issuances. Treasury locks enable the Trust to synthetically secure current market rates for a future fixed rate funding. These instruments hedge only the underlying treasury yield and not the credit spread applicable to ARC that is determined at the time of issuance. Based on the transactions completed during the quarter the Trust has locked in an effective U.S. ten year treasury rate of 4.8082 per cent on a notional amount of US$125 million. As at December 31, 2007 the mark-to-market value of these contracts was CDN$7.4 million loss.
The Trust intends to finance its $395 million 2008 capital program with cash flow from operating activities and the proceeds of the DRIP with any remainder financed with debt. If necessary, ARC has access to additional capital through its current credit facility, a new issue of senior secured notes, or by issuing equity. In the event that the Trust enters into a material acquisition where the purchase price exceeds 10 per cent of the book value of the Trust’s assets, the ratios in the first two covenants above are increased to 3.5 and 5.5 times, respectively.
UNITHOLDERS’ EQUITY
At December 31, 2007, there were 213.2 million trust units issued and issuable for exchangeable shares, an increase of six million trust units from December 31, 2006. The increase in number of trust units outstanding is mainly attributable to the 5.6 million trust units issued pursuant to the DRIP during 2007 at an average price of $19.93 per unit.
The Trust had 0.2 million rights outstanding as of December 31, 2007 under an employee plan where further rights issuances were discontinued in 2004. The rights have a five-year term and vested equally over three years from the date of grant. The remaining rights may be exercised to purchase trust units at an average adjusted exercise price of $8.50 per unit as at December 31, 2007. All of the rights were fully vested at December 31, 2007 and will expire on or before December 31, 2008.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for employees, officers and directors of the Trust and does not involve any units being issued from treasury. The Trust has made provisions whereby employees may elect to have units purchased for them on the market with the cash received upon vesting.
Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at a five per cent discount to the prevailing market price with no additional fees or commissions. During 2007, the Trust raised proceeds of $110.7 million and issued 5.6 million trust units pursuant to the DRIP.
16
DISTRIBUTIONS
ARC declared distributions of $498 million ($2.40 per unit), representing 71 per cent of 2007 cash flow from operating activities compared to distributions of $484.2 million ($2.40 per unit), representing 66 per cent of cash flow from operating activities in 2006.
Monthly distributions for 2007 were $0.20 per unit. Revisions, if any, to the monthly distribution are normally announced on a quarterly basis in the context of prevailing and anticipated commodity prices at that time.
The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:
· The portion of capital expenditures that are funded with cash flow from operating activities. In 2007, the Trust withheld 27 per cent of 2007 cash flow from operating activities to fund 49 per cent of the capital program excluding acquisitions. The remaining portion of capital expenditures was financed by proceeds from the DRIP program and debt.
· An annual contribution to the reclamation funds, with $13.5 million being contributed in 2007 including interest earned on the fund balances. The reclamation funds are segregated bank accounts or subsidiary trusts and the balances will be drawn on in future periods as the Trust incurs abandonment and reclamation costs over the life of its properties.
· Debt principal repayments from time to time as determined by the board of directors. The Trust’s current debt level is well within the covenants specified in the debt agreements and, accordingly, there are no current mandatory requirements for repayment. Refer to the “Capital Structure and Liquidity” section of this MD&A for a detailed review of the debt covenants.
· Income taxes that are not passed on to unitholders. The Trust has a liability for future income taxes due to the excess of book value over the tax basis of the assets of the Trust and its corporate subsidiaries. The Trust currently, and up until January 1, 2011, may minimize or eliminate cash income taxes in corporate subsidiaries by maximizing deductions, however in future periods there may be cash income taxes if deductions are not sufficient to eliminate taxable income. Taxability of the Trust is currently passed on to unitholders in the form of taxable distributions whereby corporate income taxes are eliminated at the Trust level. The Trust taxation legislation, which will take effect in 2011, will result in taxes payable at the Trust level and therefore distributions to unitholders will decrease.
· Working capital requirements as determined by the board of directors. Certain working capital amounts may be deducted from cash flow from operating activities, however such amounts would be minimal and the Trust does not anticipate any such deductions in the foreseeable future.
· The Trust has certain obligations for future payments relative to employee long-term incentive compensation. Presently, the Trust estimates that $19.8 million to $71.1 million will be paid out pursuant to such commitments in 2008 through 2010 subject to vesting provisions and future performance of the Trust. These amounts will reduce cash flow from operating activities and may in turn reduce distributions in future periods.
Cash flow from operating activities and distributions in total and per unit were as follows:
Cash Flow From Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
and Distributions |
| 2007 |
| 2006 |
| % Change |
| 2007 |
| 2006 |
| % Change |
|
|
| ($ millions) |
|
|
| ($ per unit) |
|
|
| ||||
Cash flow from operating activities |
| 704.9 |
| 734.0 |
| (4 | ) | 3.35 |
| 3.59 |
| (7 | ) |
Reclamation fund contributions (1) |
| (13.5 | ) | (13.1 | ) | 3 |
| (0.06 | ) | (0.06 | ) | — |
|
Capital expenditures funded with cash flow from operating activities |
| (193.4 | ) | (236.7 | ) | (18 | ) | (0.92 | ) | (1.16 | ) | (21 | ) |
Other (2) |
| — |
| — |
| — |
| 0.03 |
| 0.03 |
| — |
|
Distributions |
| 498.0 |
| 484.2 |
| 3 |
| 2.40 |
| 2.40 |
| — |
|
(1) | Includes interest income earned on the reclamation fund balances that is retained in the reclamation funds. |
|
|
(2) | Other represents the difference due to distributions paid being based on actual trust units outstanding at each distribution date whereas per unit cash flow from operating activities, reclamation fund contributions and capital expenditures funded with cash flow from operated activities are based on weighted average outstanding trust units in the year plus trust units issuable for exchangeable shares at year-end. |
17
The Trust continually assesses distribution levels, in light of commodity prices and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of the Trust as per the following guidelines:
· To maintain a level of distributions that, in the opinion of Management and the Board of Directors, is sustainable for a minimum period of six months. The Trust’s objective is to normalize the effect of volatility of commodity prices rather than to pass on that volatility to unitholders in the form of fluctuating monthly distributions.
· To ensure that the Trust’s financial flexibility is maintained by a review of the Trust’s debt to equity and debt to cash flow from operating activities levels. The use of cash flow from operating activities to fund capital development activities reduces the requirements of the Trust to use debt to finance these expenditures. In 2007 the Trust funded 49 per cent of capital development activities with 27 per cent of cash flow from operating activities. The actual amount of cash flows withheld to fund the Trust’s capital expenditure program is dependent on the commodity price environment and is at the discretion of the Board of Directors.
The actual amount of future monthly distributions is proposed by management and is subject to the approval and discretion of the Board of Directors. The Board reviews future distributions in conjunction with their review of quarterly financial and operating results.
Monthly distributions for the first quarter of 2008 have been set at $0.20 per unit subject to monthly review based on commodity price fluctuations. Revisions, if any, to the monthly distribution are normally announced on a quarterly basis in the context of prevailing and anticipated commodity prices at that time.
HISTORICAL DISTRIBUTIONS BY CALENDAR YEAR
The following table presents distributions paid and payable for each calendar period.
Calendar Year |
| Distributions |
| Taxable Portion |
| Return of Capital |
| |||
2008 YTD (1) |
| 0.20 |
| 0.20 |
| 0.00 |
| |||
2007 |
| 2.40 |
| 2.32 |
| 0.08 |
| |||
2006 (2) |
| 2.60 |
| 2.55 |
| 0.05 |
| |||
2005 |
| 1.94 |
| 1.90 |
| 0.04 |
| |||
2004 |
| 1.80 |
| 1.69 |
| 0.11 |
| |||
2003 |
| 1.78 |
| 1.51 |
| 0.27 |
| |||
2002 |
| 1.58 |
| 1.07 |
| 0.51 |
| |||
2001 |
| 2.41 |
| 1.64 |
| 0.77 |
| |||
2000 |
| 1.86 |
| 0.84 |
| 1.02 |
| |||
1999 |
| 1.25 |
| 0.26 |
| 0.99 |
| |||
1998 |
| 1.20 |
| 0.12 |
| 1.08 |
| |||
1997 |
| 1.40 |
| 0.31 |
| 1.09 |
| |||
1996 |
| 0.81 |
| — |
| 0.81 |
| |||
Cumulative |
| $ | 21.23 |
| $ | 14.41 |
| $ | 6.82 |
|
(1) | Based on distributions declared at January 31, 2008 and estimated taxable portion of 2008 distributions of 98 per cent. |
|
|
(2) | Based on distributions paid and payable in 2006. |
Please refer to the Trust’s website at www.arcenergytrust.com for details on 2007 monthly distributions and distribution dates for 2008.
TAXATION OF DISTRIBUTIONS
Distributions comprise a return of capital portion (tax deferred) and a return on capital portion (taxable). The return of capital component reduces the cost basis of the trust units held. For 2007, distributions paid in the calendar year will be 97 per cent return on capital or $2.32 per unit for the year (taxable) and three per cent return of capital or $0.08 per unit for the year (tax deferred). For a more detailed breakdown, please visit our website at www.arcenergytrust.com.
PER UNIT RESULTS AND SUSTAINABILITY
Due to natural production declines, the Trust must continually develop its reserves and/or acquire new reserves in an effort to maintain reserves, production and cash flow levels on which distributions are paid. The Trust facilitates this by withholding a portion of cash flow from operating activities to fund a portion of ongoing capital development activities and maintain moderate debt levels; this is evidenced by the Trust’s moderate
18
payout of distributions as compared to cash flow from operating activity levels. Oil and gas royalty trusts hold assets that are depleting and unitholders should expect production, revenue, cash flows and distributions to decline over the long-term if reserves cannot be economically replaced. The Trust has an inventory of internal development prospects that we expect will enable the Trust to maintain production for a minimum period of two years. The Trust measures its sustainability and success in terms of per unit distributions, production, reserves, and cash flow from operating activities in addition to the ability to maintain low debt levels and the annual replacement of reserves.
Following is a summary of the historical debt-adjusted production and reserves per unit and reserve life index (“RLI”) on which the Trust assesses performance and sustainability:
Per Trust Unit Ratios |
| 2007 |
| 2006 |
| 2005 |
| 3 Year Total |
| ||||
Production per unit (1): |
|
|
|
|
|
|
|
|
| ||||
Unadjusted |
| 0.30 |
| 0.31 |
| 0.29 |
| — |
| ||||
Debt-adjusted (3) |
| 0.26 |
| 0.27 |
| 0.26 |
| — |
| ||||
Normalized (4) |
| 0.30 |
| 0.31 |
| 0.32 |
| — |
| ||||
Reserves per unit (2): |
|
|
|
|
|
|
|
|
| ||||
Unadjusted |
| 1.34 |
| 1.38 |
| 1.42 |
| — |
| ||||
Debt-adjusted (3) |
| 1.15 |
| 1.19 |
| 1.28 |
| — |
| ||||
Normalized (4) |
| 1.35 |
| 1.40 |
| 1.51 |
| — |
| ||||
Reserve life index (5) |
| 12.5 |
| 12.4 |
| 12.9 |
| — |
| ||||
Cash flow from operating activities per unit |
| $ | 3.35 |
| $ | 3.59 |
| $ | 3.23 |
| $ | 10.17 |
|
Distributions per unit |
| $ | 2.40 |
| $ | 2.40 |
| $ | 1.99 |
| $ | 6.79 |
|
Distributions as a per cent of cash flow from operating activities |
| 71 |
| 66 |
| 61 |
| 66 |
| ||||
Per cent of cash flow from operating activities retained |
| 29 |
| 34 |
| 39 |
| 34 |
|
(1) | Represents daily average production per thousand units. Calculated based on annual daily average production divided by weighted average trust units outstanding including trust units issuable for exchangeable shares. |
|
|
(2) | Calculated based on proved plus probable reserves divided by period end trust units outstanding including trust units issuable for exchangeable shares. |
|
|
(3) | Debt-adjusted indicates that all years as presented have been adjusted to reflect a nil net debt to capitalization. It is assumed that additional trust units were issued at a period end price for the reserves per unit calculation and at an annual average price for the production per unit calculation in order to reduce the net debt balance to zero in each year. The debt-adjusted amounts are presented to enable comparability of annual per unit values. |
|
|
(4) | Normalized indicates that all years as presented have been adjusted to reflect a net debt to capitalization of 15 per cent. It is assumed that additional trust units were issued (or repurchased) at a period end price for the reserves per unit calculation and at an annual average price for the production per unit calculation in order to achieve a net debt balance of 15 per cent of total capitalization each year. The normalized amounts are presented to enable comparability of annual per unit values. |
|
|
(5) | Calculated based on proved plus probable reserves divided by annual 2008 production estimate of 63,000 boe per day for 2007 RLI. |
During the 2005 to 2007 time period the Trust’s normalized production per unit has decreased only slightly from 0.32 to 0.30 boe of daily average production per thousand trust units. Normalized reserves per unit have decreased just over 10 per cent during this time to 1.35 from 1.51 boe of proved plus probable reserves per trust unit. These levels of production and reserves per unit occurred even with the payout of $1.4 billion of distributions ($6.79 per trust unit and 66 per cent of cash flow from operating activities) during the 2005 through 2007 time period. This indicates that the Trust has grown production levels to help offset natural production declines and developed its reserve base. The normalized production per unit is a key measure as it indicates the ability to generate cash flows from core operations that in turn impacts the level of cash that may be distributed to unitholders. The Trust expects to replace production in 2008 from internal development opportunities.
To compare the Trust’s results with oil and gas companies that retain all of their cash flow from operating activities to grow production and reserves, the Trust looks at normalized and distribution-adjusted production and reserves per unit which calculates the total reserves and production per initial investment with the assumption that distributions are reinvested through the DRIP plan. Consequently, the reserves and production per initial investment increase over time as the investor’s number of trust units increase with distribution reinvestment. The Trust’s normalized daily average production per initial investment has increased from 0.35 boe per thousand trust units in 2005 to 0.40 in 2007, while normalized reserves per initial investment have increased from 1.66 boe at January 1, 2005 to 1.82 boe at December 31, 2007. Based on the assumption of re-investment of the distributions for additional trust units, one trust unit purchased on January 1, 2005 would have grown to 1.35 trust units on December 31, 2007. A unitholder can replicate this by participating in the DRIP so that the number of units they own increases over time.
The Trust’s reserve life index decreased slightly to 12.5 years in 2007 from 12.9 years in 2005. The RLI is a measure of the remaining average life of the reserves based on a current production estimate for 2008 of 63,000 boe per day. The Trust’s high RLI is indicative of the high quality of assets and the relatively low production decline rate of the properties. The acquisition of the Redwater and NPCU properties in 2005 resulted in an increase in the RLI due to the long reserve life of the properties. In addition, the Trust has been able to replace reserves through the drill bit throughout 2006 and 2007 as no significant acquisitions have been completed during that time and yet the Trust produced almost 46 million barrels of oil equivalent during those two years. A high RLI is key for a royalty trust as it indicates the potential sustainability of production levels and cash flows over a longer period of time.
19
The Trust’s distribution policy centres around the goal of providing a consistent and sustainable level of distributions to unitholders and to provide for future growth. The Trust has maintained distributions at $0.20 per unit per month since October 2005. This consistent level of distributions has allowed the Trust to finance $193.4 million of capital expenditures through cash flow from operating activities in 2007. In addition, low natural gas prices and high Canadian dollar values observed in 2007, which negatively impacted the Trust’s cash flow from operating activities, did not cause the Trust to cut distributions — this was an anomaly amongst the Trust’s peers. The Trust’s distribution as a per cent of cash flow from operating activities for 2007 was 71 per cent. The moderate level of distributions is indicative of the Trust’s commitment to fund ongoing development activities with cash flow from operating activities to enable long-term sustainability.
An additional measure of sustainability is the comparison of net income to distributions. Net income incorporates all costs including depletion expense and other non-cash expenses whereas cash flow from operating activities measures the cash generated in a given period before the cost of the associated reserves. Therefore, net income may be more representative of the profitability of the entity and thus a relevant measure against which to measure distributions to illustrate sustainability. As net income is sensitive to fluctuations in commodity prices, it is expected that there will be deviations between annual net income and distributions. The following table illustrates the annual shortfall of distributions to net income as a measure of long-term sustainability.
Net Income and Distributions |
|
|
|
|
|
|
| Trailing |
|
($ millions except per cent) |
| 2007 |
| 2006 |
| 2005 |
| 3 years |
|
Net income |
| 495.3 |
| 460.1 |
| 356.9 |
| 1,312.3 |
|
Distributions |
| 498.0 |
| 484.2 |
| 376.6 |
| 1,358.8 |
|
Shortfall |
| (2.7 | ) | (24.1 | ) | (19.7 | ) | (46.5 | ) |
Shortfall as per cent of net income |
| (1 | )% | (5 | )% | (6 | )% | (4 | )% |
Distributions as a per cent of cash flow from operating activities |
| 71 | % | 66 | % | 61 | % | 66 | % |
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
The Trust has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, and lease rental obligations and employee agreements. These obligations are of a recurring and consistent nature and impact the Trust’s cash flows in an ongoing manner. The Trust also has contractual obligations and commitments that are of a less routine nature as disclosed in the following table.
Commitments |
|
|
| Payments Due By Period |
|
|
|
|
| ||
($ millions) |
| 2008 |
| 2009 – 2010 |
| 2011-2012 |
| Thereafter |
| Total |
|
Debt repayments (1) |
| 5.9 |
| 540.8 |
| 51.5 |
| 116.3 |
| 714.5 |
|
Interest payments (2) |
| 11.0 |
| 20.2 |
| 15.5 |
| 13.7 |
| 60.4 |
|
Reclamation fund contributions (3) |
| 5.8 |
| 10.2 |
| 8.9 |
| 71.9 |
| 96.8 |
|
Purchase commitments |
| 10.1 |
| 4.1 |
| 4.0 |
| 6.0 |
| 24.2 |
|
Operating leases (4) |
| 6.2 |
| 8.9 |
| 12.4 |
| 88.1 |
| 115.6 |
|
Risk management contract premiums (5) |
| 13.2 |
| 2.3 |
| — |
| — |
| 15.5 |
|
Total contractual obligations |
| 52.2 |
| 586.5 |
| 92.3 |
| 296.0 |
| 1,027.0 |
|
(1) | Long-term and short-term debt, excluding interest. In the event that the credit facility is not extended at any time before the maturity date, the loan balance will become payable on the maturity date which is April 15, 2010. |
|
|
(2) | Fixed interest payments on senior secured notes. |
|
|
(3) | Contribution commitments to a restricted reclamation fund associated with the Redwater property acquired in 2005. |
|
|
(4) | Available option expiring February 2008 to reduce office lease commitment. |
|
|
(5) | Fixed premiums to be paid in future periods on certain risk management contracts. |
The above noted risk management contract premiums are part of the Trust’s commitments related to its risk management program. In addition to the above premiums, the Trust has commitments related to its risk management program. As the premiums are part of the underlying risk management contract, they have been recorded at fair market value at December 31, 2007 on the balance sheet as part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance of the expenditures being made. At a given point in time, it is estimated that the Trust has committed to capital expenditures equal to approximately one quarter of its capital budget by means of giving the necessary authorizations to incur the capital in a future period. The Trust’s 2008 capital budget has been approved by the Board at $395 million. This commitment has not been disclosed in the commitment table as it is of a routine nature and is part of normal course of operations for active oil and gas companies and trusts.
20
The above noted operating leases include amounts for the Trust’s head office lease. The current lease expires in May 2010. In December 2007, the Trust entered into a 13 year lease commitment beginning in 2010 for office space in a new building that is under construction in downtown Calgary. The new lease commitment is reflected in the table above.
The Trust is involved in litigation and claims arising in the normal course of operations. Management is of the opinion that pending litigation will not have a material adverse impact on the Trust’s financial position or results of operations and therefore the commitment table does not include any commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price received by the Trust is dependent upon the contracts entered into by the aggregator. This commitment has not been disclosed in the commitment table as it is of a routine nature and is part of normal course of operations.
OFF BALANCE SHEET ARRANGEMENTS
The Trust has certain lease agreements, all of which are reflected in the Contractual Obligations and Commitments table above, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2007.
FOURTH QUARTER FINANCIAL AND OPERATIONAL RESULTS
The Trust had an active fourth quarter with $139.3 million spent on capital development activities that contributed to quarterly average production of 63,989 boe per day. The Trust distributions were 72 per cent of cash flow from operating activities. The remaining 28 per cent was used to fund $44.5 million of the fourth quarter capital development program and make contributions to the reclamation fund. The fourth quarter was an active one for the Trust with the drilling of 77 gross wells on operated properties and new production coming on-stream in the Dawson area of British Columbia.
· The Trust’s fourth quarter production was 63,989 boe per day, a slight increase from the fourth quarter of 2006 where production was 63,663. As compared to the third quarter of 2007, the Trust’s production increased five per cent or 2,881 boe per day. This was primarily as a result of approximately 350 boe per day from an acquisition that the Trust completed late in the third quarter of 2007 as well as new production in the Dawson area of British Columbia of approximately 1,400 boe per day.
· The Trust spent $139.3 million on capital development activities and undeveloped land in the fourth quarter compared to $121.9 million in 2006. The Trust had a very active fourth quarter with the drilling of 77 gross wells (69 net wells) on operated properties with a 100 per cent success rate. The Trust expanded its inventory of undeveloped land acreage with the purchase of $42.6 million of land in the fourth quarter. The land acquired was in core areas where the Trust has identified strategic development opportunities.
· The fourth quarter netback before hedging increased 17 per cent to $36.63 per boe as compared to $31.37 for the same period of 2006. Record high oil prices, offset by increased royalties, operating costs and lower gas prices contributed to the high netback recorded for the quarter.
· Cash G&A expenses in the fourth quarter increased to $1.96 per boe as compared to $1.74 for the same period in 2006. The majority of the increase is attributable to a larger whole unit plan payment made in October of 2007.
21
FOURTH QUARTER FINANCIAL AND OPERATIONAL HIGHLIGHTS
(CDN$ millions except per unit and per cent) |
| Q4 2007 |
| Q4 2006 |
| % Change |
| ||
Production (boe/d) |
| 63,989 |
| 63,663 |
| 1 |
| ||
Cash flow from operating activities |
| 173.7 |
| 159.3 |
| 9 |
| ||
Per unit |
| $ | 0.82 |
| $ | 0.77 |
| (6 | ) |
Distributions |
| 125.8 |
| 122.3 |
| 3 |
| ||
Per unit |
| $ | 0.60 |
| $ | 0.60 |
| — |
|
Per cent of cash flow from operating activities |
| 72 |
| 77 |
| (6 | ) | ||
Net income |
| 106.3 |
| 56.6 |
| 88 |
| ||
Per unit |
| $ | 0.51 |
| $ | 0.28 |
| 82 |
|
Prices |
|
|
|
|
|
|
| ||
WTI (US$/bbl) |
| 90.63 |
| 60.22 |
| 50 |
| ||
USD/CAD exchange rate |
| 1.02 |
| 0.87 |
| 17 |
| ||
Realized oil price (CDN $/bbl) |
| 77.53 |
| 58.26 |
| 33 |
| ||
AECO gas monthly index (CDN $/mcf) |
| 6.00 |
| 6.36 |
| (6 | ) | ||
Realized gas price (CDN $/mcf) |
| 6.32 |
| 6.99 |
| (10 | ) | ||
Operating netback ($/boe) |
|
|
|
|
|
|
| ||
Revenue, before hedging |
| 57.42 |
| 49.94 |
| 15 |
| ||
Royalties |
| (10.46 | ) | (8.80 | ) | 19 |
| ||
Transportation |
| (0.69 | ) | (0.64 | ) | 8 |
| ||
Operating costs |
| (9.64 | ) | (9.13 | ) | 6 |
| ||
Netback (before hedging) |
| 36.63 |
| 31.37 |
| 17 |
| ||
Cash hedging gain (loss) |
| (0.20 | ) | 1.68 |
| (112 | ) | ||
Netback (after hedging) |
| $ | 36.43 |
| $ | 33.05 |
| 10 |
|
Capital expenditures |
| 139.3 |
| 121.9 |
| 14 |
| ||
Capital funded with cash flow from operating activities (per cent) |
| 32 |
| 28 |
| 14 |
|
CRITICAL ACCOUNTING ESTIMATES
The Trust has continuously evolved and documented its management and internal reporting systems to provide assurance that accurate, timely internal and external information is gathered and disseminated.
The Trust’s financial and operating results incorporate certain estimates including:
· estimated revenues, royalties and operating costs on production as at a specific reporting date but for which actual revenues and costs have not yet been received;
· estimated capital expenditures on projects that are in progress;
· estimated depletion, depreciation and accretion that are based on estimates of oil and gas reserves that the Trust expects to recover in the future;
· estimated fair values of derivative contracts that are subject to fluctuation depending upon the underlying commodity prices and foreign exchange rates;
· estimated value of asset retirement obligations that are dependent upon estimates of future costs and timing of expenditures; and
· estimated future recoverable value of property, plant and equipment and goodwill.
The Trust has hired individuals and consultants who have the skills required to make such estimates and ensures that individuals or departments with the most knowledge of the activity are responsible for the estimates. Further, past estimates are reviewed and compared to actual results, and actual results are compared to budgets in order to make more informed decisions on future estimates.
The ARC leadership team’s mandate includes ongoing development of procedures, standards and systems to allow ARC staff to make the best decisions possible and ensuring those decisions are in compliance with the Trust’s environmental, health and safety policies.
22
DISCLOSURE CONTROLS AND PROCEDURES
As of December 31, 2007, an internal evaluation was carried out of the effectiveness of the Trust’s disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by Multilateral Instrument 52-109, Certification of Disclosure in Issues’ Annual and Interim Filings. Based on that evaluation, the President and Chief Executive Officer and the Senior Vice President Finance and Chief Financial Officer concluded that the disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that the Trust files or submits under the Exchange Act or under Canadian Securities legislation is recorded, processed, summarized and reported, within the time periods specified in the rules and forms therein. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that the information required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act or under Canadian Securities legislation is accumulated and communicated to the Trust’s management, including the senior executive and financial officers, as appropriate to allow timely decisions regarding the required disclosure.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Management has assessed the effectiveness of the company’s internal control over financial reporting as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by Multilateral Instrument 52-109, Certification of Disclosure in Issues’ Annual and Interim Filings. The assessment was based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2007. The effectiveness of the Trust’s internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, as reflected in their report for 2007. No changes were made to our internal control over financial reporting during the year-ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
FINANCIAL REPORTING UPDATE
During 2007, the Trust completed the implementation of the new CICA Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial Instruments – Disclosure and Presentation, and Section 3865, Hedges that deal with the presentation of equity, recognition, measurement, disclosure, and presentation of financial instruments, and comprehensive income. As required by the new standards, adoption has been applied prospectively as at January 1, 2007 and prior periods have not been restated. The adoption of these standards has had no material impact on the Trust’s Net Income or Cash Flows. See notes 3 and 11 in the Notes to the Consolidated Financial Statements for further details.
Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if they result in financial statements that provide more reliable and relevant information. Changes in policy are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in net income. In addition, disclosure is required for all future accounting changes when an entity has not applied a new source of GAAP that has been issued but is not yet effective.
23
Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Section 3862, Financial Instruments – Disclosures, and Section 3863, Financial Instruments – Presentation. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity’s objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. This Section is expected to have minimal impact on the Trust’s financial statements.
Sections 3862 and 3863 specify standards of presentation and enhanced disclosure on financial instruments. Increased disclosure will be required on the nature and extent of risks arising from financial instruments and how the entity manages those risks.
In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The new Section will be effective on January 1, 2009. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Trust is currently evaluating the impact of the adoption of this new Section, however does not expect a material impact on its Consolidated Financial Statements.
Update on Legislation Changes Impacting the Trust
BROAD-BASED FEDERAL TAX REDUCTIONS
On October 30, 2007 the Federal Government presented the fall economic statement that proposed significant reductions in corporate income tax rates from 22.1 per cent to 15 per cent. The reductions will be phased in between 2008 and 2012. In addition, the Government announced that it plans to collaborate with the provinces and territories to reach a 25 per cent combined federal-provincial-territorial statutory corporate income tax rate. The reduction in the federal rate will also reduce the SIFT tax rate to 28 per cent as compared to the rate of 31.5 per cent previously announced.
ALBERTA GOVERNMENT ROYALTY REGIME
In September 2007, the Alberta Government announced the results of the royalty review that was performed by an independent panel and on October 25, 2007, the Alberta Government announced The New Royalty Framework, (“framework”), which will take effect on January 1, 2009 and is projected by the government to increase royalties by approximately $1.4 billion in 2010 or an increase of 20 per cent over revenue forecasts by the Alberta Government for that year. Subsequent to that time the Alberta Government has made some concessions to the proposed royalty increases and industry is still awaiting final legislation in order to fully assess the impact. Our understanding is that at current commodity prices the increases comprise an average 57 per cent increase in conventional oil royalties and a 10 per cent increase in gas royalties. The maximum royalty rates are increasing from the current maximums of 30 per cent and 35 per cent for old and new tier rates respectively to rates that will range up to 50 per cent.
The framework proposes new, simplified royalty formulas for conventional oil and natural gas that will operate on sliding scales which are determined by commodity prices and well productivity. The formulas eliminate the conventional oil and natural gas tiers and several royalty exemption and relief programs. Enhanced Oil Recovery and Innovative Energy Technology Program Royalty relief programs have been retained.
FEDERAL GOVERNMENT’S TRUST TAX LEGISLATION
In 2007, the Federal Government introduced and passed into law Trust taxation that will result in a tax of 29.5 per cent (previously 31.5 per cent as discussed above) on all Trust distributions commencing January 1, 2011. Cash flow earned by the Trust and not distributed has always been and continues to form part of taxable income at the Trust level, which may result in cash taxes being paid if there are not sufficient tax pool claims and deductions obtained upon incurring capital expenditures or acquiring assets.
The Trust recorded a $35.6 million one time increase in earnings and a corresponding decrease to its future income tax liability as a result of timing differences within the Trust that have not been previously recognized as the Trust’s tax pools were in excess of the net book value of the Trust’s assets. The initial recognition of $35.6 million comprises $24.7 million for pre-2007 generated temporary differences and $10.9 million for temporary differences relating to the current year. This amount was recorded in the second quarter results and is reflected in the 2007 year-to-date results.
24
CLIMATE CHANGE PROGRAMS
On March 8, 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases per year must reduce their emissions intensity by 12 per cent over the average emissions levels of 2003, 2004 and 2005; if they are not able to do so, these facilities are required to pay $15 per tonne for every tonne above the 12 per cent target, effective as of July 1, 2007. At this time, the Trust has determined that the impact of this legislation would be minimal based on ARC’s existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan that calls for greenhouse gas emissions to be reduced by 20 per cent below current levels by 2020. Firms may employ the following strategies to achieve the targets. They will be able to:
· make in-house reductions;
· take advantage of domestic emissions trading;
· purchase offsets;
· use the Clean Development Mechanism under the Kyoto Protocol; and
· invest in a technology fund.
The Trust is waiting for additional information so as to fully assess what impact, if any, this new legislation will have on its operations.
On January 24, 2008 the Alberta Government announced their plan to reduce projected emissions in the province by 50 per cent under the new climate change plan by 2050. This will result in real reductions of 14 per cent below 2005 levels. The Alberta Government stated they will form a government-industry council to determine a go-forward plan for implementing technologies, which will significantly reduce greenhouse gas emissions by capturing air emissions from industrial sources and locking them permanently underground in deep rock formations.
In addition the plan calls for energy conservation by individuals and for increased investment in clean energy technologies and incentives for expanding the use of renewable and alternative energy sources such as bioenergy, wind, solar power, hydrogen and geothermal energy. Initiatives under this theme will account for 18 per cent of Alberta’s reductions. A detailed implementation plan will be developed and released in the spring of 2008.
UNITED STATES PROPOSED CHANGES TO QUALIFYING DIVIDENDS
A bill was introduced into United States Congress on March 23, 2007 that could deny qualified dividend income treatment to the distributions made by the Trust to its U.S. unitholders. The bill is in the first step of the legislative process and it is uncertain whether it will eventually be passed into law in its current form. If the bill is passed in its current form, distributions received by U.S. unitholders would no longer qualify for the 15 per cent qualified dividend tax rate.
2007 REVIEW AND 2008 GUIDANCE
Following is a summary of the Trust’s 2008 Guidance issued by way of news release on November 7, 2007 (posted on www.sedar.com) and a review of 2007 actual results compared to 2007 Guidance:
|
| 2007 |
|
|
|
|
| 2008 |
|
|
| Guidance (1) |
| Actual 2007 |
| % Change |
| Guidance |
|
Production (boe/d) |
| 63,000 |
| 62,723 |
| — |
| 63,000 |
|
Expenses ($/boe): |
|
|
|
|
|
|
|
|
|
Operating costs |
| 9.50 |
| 9.54 |
| — |
| 10.20 |
|
Transportation |
| 0.70 |
| 0.72 |
| 3 |
| 0.80 |
|
G&A expenses (2) |
| 2.25 |
| 2.15 |
| (4 | ) | 2.55 |
|
Interest |
| 1.70 |
| 1.61 |
| (5 | ) | 1.90 |
|
Capital expenditures ($ millions)(3) |
| 350 |
| 397 |
| 13 |
| 395 |
|
Weighted average trust units and units issuable (millions) |
| 210 |
| 210 |
| — |
| 216 |
|
(1) 2007 Guidance shown is the revised amounts from the Trust’s third quarter MD&A.
(2) G&A expenses originally split out non-cash expenses with a guidance estimate of $0.10 per boe compared to actual results of $0.14 per boe.
(3) 2008 Capital Expenditure Guidance was revised on January 8, 2008. The additional $40 million is earmarked for the Trust’s Montney resource play.
25
The 2008 Guidance is issued to provide unitholders with information as to management’s expectations for results of operations for 2008. Readers are cautioned that the 2008 Guidance may not be appropriate for other purposes.
Actual 2007 results were in line with 2007 guidance with only minor exceptions as follows:
· Transportation costs were higher than guidance due to additional trucking costs incurred in the fourth quarter in the
Saskatchewan areas.
· Cash G&A expenses were lower than guidance due to higher operating recoveries attributed to high levels of capital and operating activity in the fourth quarter. This was offset by non-cash G&A expenses that were higher than guidance as a result of an increase in the Trust’s performance multiplier at year-end.
· Interest expense was slightly lower than guidance due to the fact that the majority of the Trust’s debt is denominated in U.S. dollars. With the strengthening of the Canadian dollar throughout 2007, the Trust’s Canadian equivalent of U.S. dollar interest payments was reduced.
· Capital expenditures exceeded guidance by $47 million, which comprised unbudgeted purchases of land in the Dawson area of British Columbia in the third and fourth quarters of 2007 for $71.3 million that were offset by cost savings of approximately $20 million on the Trust’s original 2007 capital budget amount.
2008 OPERATING INCOME SENSITIVITY
Below is a table that illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the
business environment:
|
| Impact on Annual Cash Flow |
| |||||||||
Business Environment |
| Assumption |
| Change |
| $ /Unit |
| |||||
Oil price (US$WTI/bbl) (1) |
| $ | 85.00 |
| $ | 1.00 |
| $ | 0.04 |
| ||
Natural gas price (CDN $AECO/mcf) (1) |
| $ | 6.50 |
| $ | 0.10 |
| $ | 0.03 |
| ||
USD/CAD exchange rate |
| 1.03 |
| $ | 0.01 |
| $ | 0.05 |
| |||
Interest rate on debt |
| % | 5.75 |
| % | 1.0 |
| $ | 0.02 |
| ||
Operational |
|
|
|
|
|
|
|
| ||||
Liquids production volume (bbl/d) |
| 32,100 |
| % | 1.0 |
| $ | 0.03 |
| |||
Gas production volumes (mmcf/d) |
| 185.0 |
| % | 1.0 |
| $ | 0.02 |
| |||
Operating expenses per boe |
| $ | 10.20 |
| % | 1.0 |
| $ | 0.01 |
| ||
Cash G&A expenses per boe |
| $ | 2.55 |
| % | 10.0 |
| $ | 0.03 |
| ||
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.
ASSESSMENT OF BUSINESS RISKS
The ARC management team is focused on long-term strategic planning and has identified the key risks, uncertainties and opportunities associated with the Trust’s business that can impact the financial results as follows:
Changes In Tax And Royalty Legislation
Income tax laws, or other laws, or provincial royalty programs relating to the oil and gas industry may in the future be changed or interpreted in a manner that adversely affects the Trust or its Unitholders. Tax authorities having jurisdiction over the Trust or Unitholders may disagree with how the Trust calculates its income for tax purposes or how we calculate payment of crown royalties or could change administrative practices to the detriment of the Trust and its Unitholders.
On October 31, 2006, the Finance Minister announced the federal government’s plan regarding the taxation of Income Trusts. Currently, distributions paid to unitholders, other than returns of capital, are claimed as a deduction by the Trust in arriving at taxable income whereby tax is eliminated at the Trust level and is paid by the unitholders. The Trust tax legislation which received Royal Assent on June 22, 2007, will result in a two-tiered tax structure whereby distributions would first be subject to the federal corporate income tax rate plus a deemed 13 per cent Provincial income tax at the Trust level commencing in 2011 (or earlier, if trusts that were publicly traded as of October 31, 2006 exceed the normal growth guidelines announced by the Minister on December 15, 2006), and then unitholders would be subject to tax on the distribution as if it were a taxable dividend paid by a taxable Canadian corporation.
26
In September 2007, the Alberta Government announced the results of the royalty review that was performed by an independent panel and on October 25, 2007, the Alberta Government announced The New Royalty Framework, (“framework”), which will take effect on January 1, 2009 and is projected by the government to increase royalties by approximately $1.4 billion in 2010 or an increase of 20 per cent over revenue forecasts by the Alberta Government for that year. Subsequent to that time the Alberta government has made some concessions to the proposed royalty increases and industry is still awaiting final legislation in order to fully assess the impact. Our understanding is that at current commodity prices the increases comprise an average 57 per cent increase in conventional oil royalties and a 10 per cent increase in gas royalties. The maximum royalty rates increasing from the current maximums of 30 per cent and 35 per cent for old and new tier rates respectively to rates that will range up to 50 per cent.
Access To Capital Markets
To the extent that external sources of capital, including the issuance of additional trust units become limited or unavailable, ARC’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves could be impaired. To the extent that ARC is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributions could be reduced.
Volatility Of Oil And Natural Gas Prices
The Trust’s operational results and financial condition, and therefore the amount of distributions paid to the unitholders will be dependent on the prices received for oil and natural gas production. Oil and gas prices have fluctuated widely during recent years and are determined by economic and in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions impact prices. Any movement in oil and natural gas prices could have an effect on the Trust’s financial condition and therefore on the distributions to the holders of trust units. ARC may manage the risk associated with changes in commodity prices by entering into oil or natural gas price derivative contracts. If ARC engages in activities to manage its commodity price exposure, the Trust may forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity derivative contracts activities could expose ARC to losses. To the extent that ARC engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts.
Variations In Interest Rates And Foreign Exchange Rates
Variations in interest rates could result in an increase in the amount the Trust pays to service debt, resulting in a decrease in distributions to unitholders. World oil prices are quoted in US dollars and the price received by Canadian producers is therefore affected by the Canadian/US dollar exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact the Trust’s net production revenue. In addition, the exchange rate for the Canadian dollar versus the US dollar has increased significantly over the last 12 months, resulting in the receipt by the Trust of fewer Canadian dollars for its production, which may affect future distributions. ARC has initiated certain derivative contracts to attempt to mitigate these risks. To the extent that ARC engages in risk management activities related to foreign exchange rates, it will be subject to credit risk associated with counterparties with which it contracts. The increase in the exchange rate for the Canadian dollar and future Canadian/US exchange rates may impact future distributions and the future value of the Trust’s reserves as determined by independent evaluators.
Reserves Estimates
The reserves and recovery information contained in ARC’s independent reserves evaluation is only an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserves evaluator. The reserves report was prepared using certain commodity price assumptions that are described in the notes to the reserves tables. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Trust and substituted for the price assumptions utilized in those reserves reports, the present value of estimated future net cash flows for the Trust’s reserves would be reduced and the reduction could be significant, particularly based on the constant price case assumptions.
Depletion Of Reserves And Maintenance Of Distribution
ARC’s future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent on ARC’s success in exploiting its reserves base and acquiring additional reserves. Without reserves additions through acquisition or development activities, the Trust’s reserves and production will decline over time as the oil and natural gas reserves are produced out.
There can be no assurance that the Trust will make sufficient capital expenditures to maintain production at current levels; nor as a consequence, that the amount of distributions by the Trust to unitholders can be maintained at current levels.
There can be no assurance that ARC will be successful in developing or acquiring additional reserves on terms that meet the Trust’s investment objectives.
27
Acquisitions
The price paid for reserves acquisitions is based on engineering and economic estimates of the reserves made by independent engineers modified to reflect the technical views of management. These assessments include a number of material assumptions regarding such factors as recoverability and marketability of oil, natural gas, natural gas liquids and sulphur, future prices of oil, natural gas, natural gas liquids and sulphur and operating costs, future capital expenditures and royalties and other government levies that will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the operators of the working interests, management and the Trust. In particular, changes in the prices of and markets for oil, natural gas, natural gas liquids and sulphur from those anticipated at the time of making such assessments will affect the amount of future distributions and as such the value of the units. In addition, all such estimates involve a measure of geological and engineering uncertainty that could result in lower production and reserves than attributed to the working interests. Actual reserves could vary materially from these estimates. Consequently, the reserves acquired may be less than expected, which could adversely impact cash flows and distributions to unitholders.
Environmental Concerns And Impact On Enhanced Oil Recovery Projects
The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean up orders in respect of ARC or its working interests. Such legislation may be changed to impose higher standards and potentially more costly obligations on ARC. Furthermore, management believes the federal political parties, appear to favor new programs for environmental laws and regulation, particularly in relation to the reduction of emissions, and there is no assurance that any such programs, laws or regulations, if proposed and enacted, will not contain emission reduction targets which ARC cannot meet, and financial penalties or charges could be incurred as a result of the failure to meet such targets. In particular there is uncertainty regarding the Federal Government’s Regulatory Framework for Air Emissions (“Framework”), as issued under the Canadian Environmental Protection Act.
Additionally, the potential impact on the Trust’s operations and business of the Framework, with respect to instituting reductions of greenhouse gases, is not possible to quantify at this time as specific measures for meeting Canada’s commitments have not been developed. Currently, companies are permitted to emit CO2 into the atmosphere with no requirement to capture and re-inject the emissions. In order for the Trust to carry out its enhanced oil recovery program it is necessary to obtain CO2 at a cost effective rate. Given that companies are not forced to capture their emissions, the infrastructure has not been put in place to facilitate this process. Without any additional provisions from the government, the economic parameters of the Trust’s enhanced oil recovery programs would be limited.
Although ARC has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations based on its current knowledge, there can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations.
Operational Matters
The operation of oil and gas wells involves a number of operating and natural hazards that may result in blowouts, environmental damage and other unexpected or dangerous conditions resulting in damage to operating subsidiaries of the Trust and possible liability to third parties. ARC will maintain liability insurance, where available, in amounts consistent with industry standards. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. ARC may become liable for damages arising from such events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. Costs incurred to repair such damage or pay such liabilities will reduce distributable cash.
Continuing production from a property, and to some extent the marketing of production there from, are largely dependent upon the ability of the operator of the property. Approximately 30 per cent of ARC’s production is operated by third parties. ARC has limited ability to influence costs on partner operated properties. Operating costs on most properties have increased steadily over recent years. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of the Trust to certain properties. A reduction of the distributions could result in such circumstances.
28
Debt Service And Additional Financing
Amounts paid in respect of interest and principal on debt will reduce distributions. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of distributions. Certain covenants of the agreements with ARC’s lenders may also limit distributions. Although ARC believes the credit facilities will be sufficient for the Trust’s immediate requirements, there can be no assurance that the amount will be adequate for the future financial obligations of the Trust or that additional funds will be able to be obtained.
The lenders have security over substantially all of the assets of ARC. If ARC becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lender may foreclose on or sell the working interests.
In the normal course of making capital investments to maintain and expand the oil and gas reserves of the Trust, additional units are issued from treasury that may result in a decline in production per unit and reserves per unit. Additionally, from time to time the Trust issues units from treasury in order to reduce debt and maintain an optimal capital structure. Conversely, to the extent that external sources of capital, including the issuance of additional units, become limited or unavailable, the Trust’s ability to make the necessary capital investments to maintain or expand its oil and gas reserves may be impaired. To the extent that ARC is required to use cash flows to finance capital expenditures or property acquisitions, to pay debt service charges or to reduce debt, the level of distributable income will be reduced.
FORWARD-LOOKING STATEMENTS
This discussion and analysis contains forward-looking statements as to the Trust’s internal projections, expectations or beliefs relating to future events or future performance within the meaning of the “safe harbour” provisions of the United States Private Securities Litigation Reform Act of 1995 and the Securities Act (Ontario). In some cases, forward-looking statements can be identified by terminology such as “may”, “will”, “should”, “expects”, “projects”, “plans”, “anticipates” and similar expressions and, in particular, includes the material under the heading “2007 Review and 2008 Guidance”. These statements represent management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of ARC Energy Trust (“ARC” or “the Trust”). The projections, estimates and beliefs contained in such forward-looking statements are based on management’s assumptions relating to the production performance of ARC’s oil and gas assets, the cost and competition for services throughout the oil and gas industry in 2007, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditure budgets relating to undeveloped land or reserve acquisitions. and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties, including the business risks discussed in this MD&A, and related to management’s assumptions set forth herein, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differ materially from those predicted. Other than the 2008 Guidance which is updated and discussed quarterly, the Trust does not undertake to update any forward looking information in this document whether as to new information, future events or otherwise except as required by securities laws and regulations.
ADDITIONAL INFORMATION
Additional information relating to ARC can be found on SEDAR at www.sedar.com.
29
Annual Historical Review
For the year ended December 31 |
|
|
|
|
|
|
|
|
|
|
|
(CDN $ millions, except per unit amounts) |
| 2007 |
| 2006 |
| 2005 |
| 2004 |
| 2003 |
|
Financial |
|
|
|
|
|
|
|
|
|
|
|
Revenue before royalties |
| 1,251.6 |
| 1,230.5 |
| 1,165.2 |
| 901.8 |
| 743.2 |
|
Per unit (1) |
| 5.95 |
| 6.02 |
| 6.10 |
| 4.85 |
| 4.80 |
|
Cash flow from operating activities (2) |
| 704.9 |
| 734.0 |
| 616.7 |
| 446.4 |
| 405.3 |
|
Per unit – basic (1) |
| 3.35 |
| 3.59 |
| 3.23 |
| 2.40 |
| 2.62 |
|
Per unit – diluted |
| 3.35 |
| 3.58 |
| 3.20 |
| 2.38 |
| 2.54 |
|
Net income |
| 495.3 |
| 460.1 |
| 356.9 |
| 241.7 |
| 284.6 |
|
Per unit – basic (3) |
| 2.39 |
| 2.28 |
| 1.90 |
| 1.32 |
| 1.88 |
|
Per unit – diluted |
| 2.39 |
| 2.27 |
| 1.88 |
| 1.31 |
| 1.82 |
|
Distributions |
| 498.0 |
| 484.2 |
| 376.6 |
| 330.0 |
| 279.3 |
|
Per unit (4) |
| 2.40 |
| 2.40 |
| 1.99 |
| 1.80 |
| 1.80 |
|
Total assets |
| 3,533.0 |
| 3,479.0 |
| 3,251.2 |
| 2,305.0 |
| 2,281.8 |
|
Total liabilities |
| 1,491.3 |
| 1,550.6 |
| 1,415.5 |
| 755.7 |
| 730.0 |
|
Net debt outstanding (5) |
| 752.7 |
| 739.1 |
| 578.1 |
| 264.8 |
| 262.1 |
|
Weighted average trust units (millions) (6) |
| 210.2 |
| 204.4 |
| 191.2 |
| 186.1 |
| 154.7 |
|
Trust units outstanding and issuable at period end (millions) (6) |
| 213.2 |
| 207.2 |
| 202.0 |
| 188.8 |
| 182.8 |
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical |
| 14.9 |
| 11.4 |
| 9.2 |
| 5.4 |
| 5.7 |
|
Land |
| 77.5 |
| 32.4 |
| 9.1 |
| 4.1 |
| 4.0 |
|
Drilling and completions |
| 229.5 |
| 240.5 |
| 191.8 |
| 140.4 |
| 106.2 |
|
Plant and facilities |
| 72.1 |
| 77.6 |
| 55.0 |
| 41.1 |
| 36.5 |
|
Other capital |
| 3.2 |
| 2.6 |
| 3.7 |
| 2.8 |
| 3.4 |
|
Total capital expenditures |
| 397.2 |
| 364.5 |
| 268.8 |
| 193.8 |
| 155.8 |
|
Property acquisitions (dispositions), net |
| 42.5 |
| 115.2 |
| 91.3 |
| (58.2 | ) | (161.6 | ) |
Corporate acquisitions (7) |
| — |
| 16.6 |
| 505.0 |
| 72.0 |
| 721.6 |
|
Total capital expenditures and net acquisitions |
| 439.7 |
| 496.3 |
| 865.1 |
| 207.6 |
| 715.8 |
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbl/d) |
| 28,682 |
| 29,042 |
| 23,282 |
| 22,961 |
| 22,886 |
|
Natural gas (mmcf/d) |
| 180.1 |
| 179.1 |
| 173.8 |
| 178.3 |
| 164.2 |
|
Natural gas liquids (bbl/d) |
| 4,027 |
| 4,170 |
| 4,005 |
| 4,191 |
| 4,086 |
|
Total (boe per day 6:1) |
| 62,723 |
| 63,056 |
| 56,254 |
| 56,870 |
| 54,335 |
|
Average prices |
|
|
|
|
|
|
|
|
|
|
|
Crude oil ($/bbl) |
| 69.24 |
| 65.26 |
| 61.11 |
| 47.03 |
| 36.90 |
|
Natural gas ($/mcf) |
| 6.75 |
| 6.97 |
| 8.96 |
| 6.78 |
| 6.40 |
|
Natural gas liquids ($/bbl) |
| 54.79 |
| 52.63 |
| 49.92 |
| 39.04 |
| 32.19 |
|
Oil equivalent ($/boe) |
| 54.54 |
| 53.33 |
| 56.54 |
| 43.13 |
| 37.29 |
|
Reserves (company interest) (8) |
|
|
|
|
|
|
|
|
|
|
|
Proved plus probable reserves |
|
|
|
|
|
|
|
|
|
|
|
Crude oil and NGL (mbbl) |
| 158,341 |
| 162,193 |
| 163,385 |
| 123,226 |
| 129,663 |
|
Natural gas (bcf) |
| 768.2 |
| 743.6 |
| 741.7 |
| 724.5 |
| 720.2 |
|
Total (mboe) |
| 286,370 |
| 286,125 |
| 286,997 |
| 243,974 |
| 249,704 |
|
Trust Unit Trading (based on intra-day trading) Unit prices |
|
|
|
|
|
|
|
|
|
|
|
High |
| 23.86 |
| 30.74 |
| 27.58 |
| 17.98 |
| 14.87 |
|
Low |
| 18.90 |
| 19.20 |
| 16.55 |
| 13.50 |
| 10.89 |
|
Close |
| 20.40 |
| 22.30 |
| 26.49 |
| 17.90 |
| 14.74 |
|
Average daily volume (thousands) |
| 597 |
| 706 |
| 656 |
| 420 |
| 430 |
|
(1) Per unit amounts (with the exception of per unit distributions) are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure reported in prior quarters. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling interest divided by weighted average trust units outstanding (excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
30
(5) Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition.
(8) Company interest reserves are the gross interest reserves plus the royalty interest prior to the deduction of royalty burdens.
Quarterly Historical Review
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(CDN $ millions, |
| 2007 |
| 2006 |
| ||||||||||||
except per unit amounts) |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
|
Financial |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue before royalties |
| 338.0 |
| 300.2 |
| 305.6 |
| 307.8 |
| 292.5 |
| 312.3 |
| 306.7 |
| 318.9 |
|
Per unit (1) |
| 1.59 |
| 1.42 |
| 1.46 |
| 1.48 |
| 1.42 |
| 1.52 |
| 1.51 |
| 1.58 |
|
Cash flow from operating activities (2) |
| 173.7 |
| 179.6 |
| 179.4 |
| 172.3 |
| 159.4 |
| 203.4 |
| 182.2 |
| 189.0 |
|
Per unit – basic (1) |
| 0.82 |
| 0.85 |
| 0.86 |
| 0.83 |
| 0.77 |
| 0.99 |
| 0.89 |
| 0.93 |
|
Per unit – diluted |
| 0.82 |
| 0.85 |
| 0.86 |
| 0.83 |
| 0.77 |
| 0.98 |
| 0.89 |
| 0.93 |
|
Net income |
| 106.3 |
| 120.8 |
| 184.9 |
| 83.3 |
| 56.6 |
| 116.9 |
| 182.5 |
| 104.1 |
|
Per unit – basic (3) |
| 0.51 |
| 0.58 |
| 0.90 |
| 0.41 |
| 0.28 |
| 0.58 |
| 0.91 |
| 0.52 |
|
Per unit – diluted |
| 0.51 |
| 0.58 |
| 0.89 |
| 0.41 |
| 0.28 |
| 0.58 |
| 0.91 |
| 0.52 |
|
Distributions |
| 125.8 |
| 125.0 |
| 124.1 |
| 123.1 |
| 122.3 |
| 121.4 |
| 120.6 |
| 119.9 |
|
Per unit (4) |
| 0.60 |
| 0.60 |
| 0.60 |
| 0.60 |
| 0.60 |
| 0.60 |
| 0.60 |
| 0.60 |
|
Total assets |
| 3,533.0 |
| 3,460.8 |
| 3,432.8 |
| 3,540.1 |
| 3,479.0 |
| 3,335.8 |
| 3,277.8 |
| 3,279.7 |
|
Total liabilities |
| 1,491.3 |
| 1,421.4 |
| 1,415.3 |
| 1,526.6 |
| 1,550.6 |
| 1,371.3 |
| 1,339.9 |
| 1,434.1 |
|
Net debt outstanding (5) |
| 752.7 |
| 699.8 |
| 653.9 |
| 729.7 |
| 739.1 |
| 579.7 |
| 567.4 |
| 598.9 |
|
Weighted average trust units (6) |
| 212.5 |
| 210.9 |
| 209.5 |
| 207.9 |
| 206.5 |
| 205.1 |
| 203.7 |
| 202.5 |
|
Trust units outstanding and |
| 213.2 |
| 211.7 |
| 210.2 |
| 208.7 |
| 207.2 |
| 205.7 |
| 204.4 |
| 203.1 |
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geological and geophysical |
| 3.0 |
| 2.9 |
| 4.1 |
| 4.9 |
| 3.7 |
| 2.2 |
| 2.8 |
| 2.7 |
|
Land |
| 42.6 |
| 33.0 |
| 1.7 |
| 0.2 |
| 11.8 |
| 1.4 |
| 14.3 |
| 4.9 |
|
Drilling and completions |
| 75.2 |
| 73.4 |
| 25.8 |
| 55.1 |
| 79.1 |
| 76.2 |
| 29.8 |
| 55.4 |
|
Plant and facilities |
| 17.9 |
| 21.1 |
| 16.3 |
| 16.8 |
| 26.5 |
| 24.6 |
| 10.9 |
| 15.6 |
|
Other capital |
| 0.6 |
| 1.5 |
| 0.6 |
| 0.5 |
| 0.8 |
| 0.5 |
| 0.8 |
| 0.5 |
|
Total capital expenditures |
| 139.3 |
| 131.9 |
| 48.5 |
| 77.5 |
| 121.9 |
| 104.9 |
| 58.6 |
| 79.1 |
|
Property acquisitions (dispositions) net |
| 5.0 |
| 27.3 |
| 10.0 |
| 0.2 |
| 76.4 |
| 8.4 |
| 2.8 |
| 27.6 |
|
Corporate acquisitions (7) |
| — |
| — |
| — |
| — |
| 16.6 |
| — |
| — |
| — |
|
Total capital expenditures and net acquisitions |
| 144.3 |
| 159.2 |
| 58.5 |
| 77.7 |
| 214.9 |
| 113.3 |
| 61.4 |
| 106.7 |
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbl/d) |
| 28,682 |
| 28,437 |
| 28,099 |
| 29,520 |
| 29,605 |
| 29,108 |
| 27,805 |
| 29,651 |
|
Natural gas (mmcf/d) |
| 187.4 |
| 173.3 |
| 176.7 |
| 183.0 |
| 179.5 |
| 173.4 |
| 178.5 |
| 185.0 |
|
Natural gas liquids (bbl/d) |
| 4,067 |
| 3,795 |
| 4,088 |
| 4,161 |
| 4,144 |
| 4,166 |
| 4,247 |
| 4,120 |
|
Total (boe per day 6:1) |
| 63,989 |
| 61,108 |
| 61,637 |
| 64,175 |
| 63,663 |
| 62,178 |
| 61,803 |
| 64,600 |
|
Average prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil ($/bbl) |
| 77.53 |
| 73.40 |
| 65.21 |
| 60.79 |
| 58.26 |
| 71.84 |
| 71.86 |
| 59.53 |
|
Natural gas ($/mcf) |
| 6.32 |
| 5.52 |
| 7.38 |
| 7.75 |
| 6.99 |
| 6.10 |
| 6.35 |
| 8.40 |
|
Natural gas liquids ($/bbl) |
| 62.75 |
| 55.64 |
| 52.76 |
| 48.04 |
| 46.51 |
| 56.60 |
| 54.44 |
| 52.91 |
|
Oil equivalent ($/boe) |
| 57.26 |
| 53.28 |
| 54.37 |
| 53.18 |
| 49.82 |
| 54.45 |
| 54.42 |
| 54.74 |
|
Trust Unit Trading (based on intra-day trading) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
| 21.55 |
| 22.60 |
| 23.86 |
| 23.02 |
| 29.22 |
| 30.74 |
| 28.61 |
| 27.51 |
|
Low |
| 18.90 |
| 19.00 |
| 20.78 |
| 20.05 |
| 19.20 |
| 25.25 |
| 24.35 |
| 25.09 |
|
Close |
| 20.40 |
| 21.17 |
| 21.74 |
| 21.25 |
| 22.30 |
| 27.21 |
| 28.00 |
| 27.36 |
|
Average daily volume (thousands) |
| 624 |
| 503 |
| 599 |
| 658 |
| 1,125 |
| 614 |
| 548 |
| 546 |
|
31
(1) Per unit amounts (with the exception of per unit distributions) are based on weighted average trust units outstanding plus trust units issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure reported in prior reports. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling interest divided by weighted average trust units outstanding (excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition including fees but prior to working capital, asset retirement obligation and future income tax liability assumed on acquisition.
32