ARC Resources Ltd. Reports Second Quarter 2011 Results
Aug 3, 2011
CALGARY, Aug. 3, 2011 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") is pleased to report its second quarter operating and financial results. Second quarter production was 82,367 boe per day, funds from operations were $210.1 million ($0.73 per share) and net income was $150.1 million ($0.52 per share). The related unaudited Condensed Consolidated Financial Statements and Notes, as well as Management's Discussion and Analysis ("MD&A"), are available on ARC's website at www.arcresources.com and on SEDAR at www.sedar.com.
|
Three Months Ended June 30 |
Six Months Ended June 30 |
|||||
| 2011 | 2010 (1) | 2011 | 2010 (1) | |||
| FINANCIAL | ||||||
| (Cdn$ millions, except per share and per boe amounts) | ||||||
| Funds from operations(2) | 210.1 | 150.9 | 404.2 | 318.8 | ||
| Per share(3) | 0.73 | 0.60 | 1.42 | 1.26 | ||
| Net income | 150.1 | 58.8 | 215.3 | 208.6 | ||
| Per share(3) | 0.52 | 0.23 | 0.75 | 0.83 | ||
| Operating income(4) | 76.4 | 62.7 | 149.2 | 142.5 | ||
| Per share(3) | 0.27 | 0.25 | 0.52 | 0.56 | ||
| Dividends | 85.8 | 75.3 | 171.4 | 150.3 | ||
| Per share(3) | 0.30 | 0.30 | 0.60 | 0.60 | ||
| Capital expenditures | 144.5 | 144.0 | 301.7 | 272.3 | ||
| Net debt outstanding(5) | 744.8 | 728.8 | 744.8 | 728.8 | ||
| Shares outstanding, weighted average and diluted(6) | 286.0 | 253.2 | 285.4 | 252.5 | ||
| Shares outstanding, end of period | 286.5 | 253.6 | 286.5 | 253.6 | ||
| OPERATING | ||||||
| Production | ||||||
| Crude oil (bbl/d) | 26,038 | 27,354 | 27,067 | 27,496 | ||
| Condensate (bbl/d) | 2,105 | 1,325 | 1,989 | 1,286 | ||
| Natural gas (mmcf/d) | 311.8 | 211.2 | 279.3 | 214.5 | ||
| Natural gas liquids (bbl/d) | 2,250 | 2,330 | 2,540 | 2,169 | ||
| Total (boe/d)(7) | 82,367 | 66,208 | 78,147 | 66,705 | ||
| Average prices | ||||||
| Crude oil ($/bbl) | 97.11 | 71.98 | 89.45 | 74.12 | ||
| Condensate ($/bbl) | 100.57 | 78.33 | 94.85 | 79.14 | ||
| Natural gas ($/mcf) | 4.05 | 4.12 | 4.05 | 4.78 | ||
| Natural gas liquids ($/bbl) | 48.40 | 38.62 | 45.86 | 42.99 | ||
| Oil equivalent ($/boe) | 49.94 | 45.82 | 49.38 | 48.84 | ||
| Operating netback ($/boe) | ||||||
| Commodity and other sales | 50.02 | 45.93 | 49.46 | 48.93 | ||
| Transportation costs | (1.25) | (1.28) | (1.18) | (1.14) | ||
| Royalties | (7.40) | (7.89) | (7.13) | (8.24) | ||
| Operating costs | (9.22) | (11.46) | (9.64) | (10.38) | ||
| Netback before hedging | 32.15 | 25.30 | 31.51 | 29.17 | ||
| Hedging gain (loss)(8) | 0.44 | 3.08 | 1.06 | 1.53 | ||
| Netback after hedging | 32.59 | 28.38 | 32.57 | 30.70 | ||
| TRADING STATISTICS(9) | ||||||
| High price | 26.79 | 22.33 | 28.40 | 22.49 | ||
| Low price | 23.89 | 19.20 | 23.89 | 19.20 | ||
| Close price | 25.01 | 19.73 | 25.01 | 19.73 | ||
| Average daily volume (thousands) | 998 | 1,043 | 1,314 | 1,164 | ||
| (1) | Beginning January 1, 2011, all Canadian publicly accountable enterprises are required to prepare their financial statements using International Financial Reporting Standards ("IFRS"). Accordingly, ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2010 to comply with IFRS. See Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 for information on ARC's transition to IFRS and a reconciliation of its affected financial information. |
| (2) | Funds from operations is not a recognized performance measure under Generally Accepted Accounting Principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Historically, management disclosed cash flow from operating activities. Funds from operations has been presented herein for comparative purposes. See the "Non-GAAP Measures" section in the MD&A for the three and six months ended June 30, 2011 and 2010 for a reconciliation of net income to funds from operations. |
| (3) | Upon conversion to a corporation, ARC trust units were exchanged for common shares. In all cases, the term per share can be interpreted as per unit prior to December 31, 2010. Per share amounts (with the exception of dividends) are based on diluted shares. |
| (4) | Operating income is a non-GAAP measure, which adjusts net income for significant items that are not indicative of operating performance and that management believes reduces the comparability of the financial performance between periods. See "Operating Income" section in this news release for a reconciliation of operating income to net income for the three and six months ended June 30, 2011. |
| (5) | Net debt is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP. Net debt is defined as long-term debt plus working capital deficit plus unrealized losses on risk management contracts related to prior production periods. Working capital deficit is calculated as current liabilities less the current assets as they appear on the Consolidated Balance Sheets, and excludes current unrealized amounts pertaining to risk management contracts, assets held for sale, asset retirement obligations contained within liabilities directly associated with assets held for sale and liabilities associated with exchangeable shares. |
| (6) | Based on weighted average shares plus the dilutive impact of share options outstanding during the period. See Note 12 "Shareholders' Capital" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011. |
| (7) | Boe may be misleading, particularly if used in isolation. In accordance with NI 51-101, a boe conversion ratio of 6 Mcf : 1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. |
| (8) | Includes cash gains (losses) on risk management contracts and unrealized losses on annually settled call contracts relating to prior production periods. |
| (9) | Trading prices are stated in Canadian dollars and based on intra-day trading. |
FINANCIAL AND OPERATIONAL HIGHLIGHTS
Production volumes for the second quarter were 82,367 boe per day, up 11 per cent relative to the first quarter of 2011, despite operational challenges posed by the flooding in southern Saskatchewan and Manitoba and forest fires and pipeline restrictions in northern Alberta. High oil prices throughout the quarter had a positive impact on operating income, net income and funds from operations. ARC maintained a strong financial position with debt levels reduced from year-end 2010 levels. To capitalize on the near-term strength of oil prices, ARC accelerated certain crude oil and liquids projects in its 2011 capital program while continuing to develop its natural gas prospects in the Montney play in northern British Columbia.
-
ARC's second quarter production was 82,367 boe per day, an 11 per cent
increase relative to the first quarter of 2011 and 24 per cent higher
than the second quarter of 2010. Higher second quarter production at
Dawson was partially offset by production downtime attributed to
flooding, forest fires, pipeline restrictions and a third party plant
turnaround, which contributed to a combined production loss of
approximately 4,300 boe per day during the second quarter. Second
quarter production was reduced by approximately 6 mmcf per day (1,000
boe per day) as a result of the Dawson Phase 1 gas plant operating at
reduced capacity for approximately three weeks in April due to
mechanical issues that were resolved in the quarter. Flooding in
southern Saskatchewan and Manitoba and forest fires and pipeline
restrictions in northern Alberta reduced second quarter production by
approximately 2,600 boe per day. Shut-in production was predominantly
oil production and the most significant impact was in southeast
Saskatchewan and Manitoba. With the exception of approximately 200 boe
per day in southeast Saskatchewan, all shut-in production in flood
areas was back on-stream by the end of the second quarter.
Approximately 350 boe per day of production in northern Alberta remains
shut-in due to pipeline restrictions. First half 2011 production
averaged 78,147 boe per day, a 17 per cent increase from the first half
of 2010. ARC expects full year 2011 production volumes to average
80,000 - 85,000 boe per day with exit production of approximately
90,000 boe per day.
- The Dawson Phase 2 gas plant came on-stream at full capacity of 60 mmcf per day in April and operational issues impacting the Dawson Phase 1 gas plant were resolved in the quarter. Total Dawson production, including third party processed gas, averaged 149 mmcf per day in the second quarter, up 103 per cent from 73 mmcf per day in the first quarter. Current production from Dawson is approximately 165 mmcf per day, with all facilities operating at planned capacity.
- Funds from operations of $210.1 million ($0.73 per share) in the second quarter of 2011 were up 39 per cent from $150.9 million ($0.60 per share) in the second quarter of 2010. First half 2011 funds from operations of $404.2 million ($1.42 per share) were up 27 per cent relative to the same period of 2010. Higher production volumes and crude oil prices were partially offset by lower natural gas prices and increased total royalties, transportation and operating costs in the second quarter and first half of 2011.
- Net income was $150.1 million ($0.52 per share) in the second quarter of 2011, up significantly from $58.8 million ($0.23 per share) in the second quarter of 2010. The increase was mainly due to an unrealized gain on risk management contracts of $74 million ($55.5 million net of tax) in the second quarter of 2011 relative to an unrealized gain of $6.6 million ($5 million net of tax) in 2010. Net income for the first six months of 2011 was $215.3 million ($0.75 per share), a three per cent increase from 2010 as higher sales on increased production and prices in 2011 were partially offset by unrealized losses on risk management contracts.
- Operating income was $76.4 million ($0.27 per share) in the second quarter of 2011, a 22 per cent increase from operating income of $62.7 million ($0.25 per share) in the second quarter of 2010. First half 2011 operating income was $149.2 million ($0.52 per share), up five per cent from 2010. The increase in operating income was due to higher volumes and increased crude oil prices, offset by lower natural gas prices and increases in total royalties, transportation, operating and general and administrative costs associated with higher production in 2011.
- ARC's total realized price was $49.94 per boe in the second quarter of 2011, up nine per cent from the $45.82 per boe realized in the second quarter of 2010. ARC's second quarter 2011 crude oil price of $97.11 per barrel increased 35 per cent relative to 2010. Natural gas prices, still depressed by high inventory levels and increased natural gas production in the United States, were down two per cent relative to 2010 levels to average $4.05 per mcf. While crude oil and liquids accounted for 37 per cent of second quarter production, they contributed 69 per cent of second quarter sales revenue due to strong crude oil prices.
- ARC realized cash hedging gains of $25.5 million in the second quarter, primarily associated with the hedging of natural gas. The second quarter cash hedging gains were offset by a $21.3 million unrealized loss on crude oil annually settled call contracts to arrive at net hedging gains of $4.2 million ($0.56 per boe) in the quarter. First half cash hedging gains of $51.3 million were offset by a $33.3 million unrealized loss on crude oil annually settled call contracts to arrive at net hedging gains of $18 million ($1.27 per boe). The second quarter unrealized mark-to-market ("MTM") hedging gain of $74 million was mainly attributed to a reduction in average forward prices for crude oil relative to the first quarter of 2011. ARC has protected the price on 20,000 barrels per day in 2011 and 18,000 barrels per day in 2012 at an average price of US$91 per barrel. Approximately 55 per cent of expected 2011 total production is currently hedged with additional volumes hedged for 2012 and 2013.
- Capital expenditures for the second quarter totaled $144.5 million. On a year-to-date basis, capital expenditures are $301.7 million. ARC drilled 11 gross operated oil wells and 13 gross operated natural gas wells with a 100 per cent success rate during the second quarter, bringing total wells drilled to 44 gross operated oil wells and 23 gross operated natural gas wells with a 100 per cent success rate for the first half of 2011. Year-to-date capital spending includes $44.8 million for unbudgeted purchases of predominately oil-prone lands in and around our core areas. Restricted access in areas affected by floods and forest fires resulted in delays in the execution of capital programs in the second quarter; however ARC anticipates that all programs will be back on schedule during the second half of 2011.
- ARC's Board approved an increase in the 2011 capital budget to $690 million. The higher budget allows ARC to execute all original capital plans for 2011 and invest in new growth opportunities. Approximately $50 million of the increased capital budget is allocated to land purchases of which $44.8 million was spent in the first half of 2011. A portion of the increased 2011 capital budget will be allocated to the purchase of long lead-time equipment and materials for the Phase 1 Sunrise gas plant. ARC received regulatory approval for the construction of the Phase 1 Sunrise gas plant in the second quarter of 2011 and currently expects to have it on-line in the first half of 2013. The 2011 capital expenditure budget continues to focus on oil and liquids rich opportunities at Ante Creek, Pembina and Parkland and supports paced development of the Montney natural gas opportunities in northeast British Columbia along with exploitation of new areas to assess future development potential.
- ARC has a strong balance sheet with a net debt to annualized first half funds from operations ratio of 0.9 times, with net debt representing approximately nine per cent of ARC's total capitalization; both well within ARC's target levels.
- ARC declared and paid a dividend of $0.30 per share to shareholders for the second quarter of 2011 and has confirmed a dividend of $0.10 per share to shareholders for July 2011 to be paid on August 15, 2011. ARC has conditionally declared a dividend of $0.10 per share, payable monthly, for August, September and October of 2011 subject to confirmation by monthly news release and further resolution of the Board of Directors.
LEADERSHIP TEAM APPOINTMENTS
ARC is pleased to announce the following promotions:
Terry Anderson has been promoted to Senior Vice President, Engineering. Terry started with ARC in 2000 as an Operations Engineer, progressed to Manager of Operations and was promoted to Vice President Operations in 2005. In May 2010, Terry took on responsibility as Vice President Engineering. During his time with ARC, Terry has worked on almost all of ARC's assets.
Van Dafoe has been promoted to Senior Vice President, Finance. Van joined ARC in 1999 and has 25 years of business experience with various companies in the finance and accounting areas of the oil and gas industry. At ARC, he has held the positions of Controller, Treasurer and Vice President, Finance.
Wayne Lentz has been appointed Vice President, Strategic Planning. Wayne joined ARC 12 years ago starting out as a Senior Operations Engineer and has taken on various assignments of increasing responsibility over the years, most recently as Manager, Strategic Planning.
Jay Billesberger has been appointed Vice President, Information Technology. In his new role, Jay will be responsible for leading the information and data integrity for all systems within ARC. Jay joined ARC in 2000 and over the years he has been instrumental in creating a strong information technology platform at ARC.
FINANCIAL REVIEW
ARC had a solid second quarter with higher production and higher sales on the strength of crude oil prices, which partially mitigated the effect of continued low natural gas prices. ARC exited the quarter with lower debt levels relative to year-end 2010 due to strong first half funds from operations and the receipt of $170 million of proceeds from the sale of properties in the first quarter. ARC maintained a dividend of $0.30 per share in the second quarter.
Funds from operations
ARC's second quarter funds from operations of $210.1 million ($0.73 per share) were up 39 per cent compared to the second quarter of 2010 funds from operations of $150.9 million ($0.60 per share). Second quarter sales increased 35 per cent due to a 24 per cent increase in second quarter production and a nine per cent increase in realized price relative to 2010. Higher total royalties, operating costs and transportation costs on higher second quarter volumes reduced the gains in production volumes and commodity prices.
First half 2011 funds from operations of $404.2 million ($1.42 per share) were up 27 per cent compared to the first half of 2010 funds from operations of $318.8 million ($1.26 per share). The increase in first half funds from operations was due to higher production and realized prices offset by higher royalties, operating costs and transportation costs.
Second quarter and first half 2011 funds from operations were reduced by $21.3 million and $33.3 million, respectively, for unrealized losses on crude oil annually settled call contracts pertaining to contracted volumes in the second quarter and first half of 2011.
Following is a reconciliation of net income to funds from operations for the second quarter and first half of 2011 and 2010.
|
Three Months Ended June 30 |
Six Months Ended June 30 |
||||
| 2011 | 2010 | 2011 | 2010 | ||
| Net income | 150.1 | 58.8 | 215.3 | 208.6 | |
| Adjusted for the following non-cash items: | |||||
| Depletion, depreciation and amortization | 106.2 | 85.1 | 172.2 | 170.1 | |
| Accretion of asset retirement obligation | 3.3 | 3.0 | 6.8 | 6.0 | |
| Deferred tax expense (recovery) | 48.8 | (3.9) | 67.9 | 19.5 | |
| Unrealized (gains) losses on risk management contracts | (73.9) | (6.6) | 74.7 | (90.3) | |
| Other | (0.5) | 1.5 | 1.6 | 3.4 | |
| Foreign exchange (gain) loss on revaluation of debt | (2.6) | 13.0 | (12.2) | 1.5 | |
| Gains on disposals of petroleum and natural gas properties | - | - | (87.9) | - | |
| Unrealized losses on risk management contracts related to prior production periods (1) | (21.3) | - | (33.3) | - | |
| Funds from operations | 210.1 | 150.9 | 404.2 | 318.8 | |
| Funds from operations per share | $0.73 | $0.60 | $1.42 | $1.26 | |
| (1) | Unrealized losses on crude oil annually settled call contracts pertaining to second quarter and first half contracted volumes. The annually settled call contracts are commodity price risk management contracts, which pertain to production periods spanning the entire calendar year but that are cash settled at the end of the year based on the annual average benchmark crude oil price. The portion of total losses on these contracts that relates to production periods for the three and six months ended June 30, 2011, have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after the effect of all contracts used for economic hedging in the period, regardless of the timing of cash settlement. |
The following table details the items contributing to the change in funds from operations for the second quarter and first half of 2011 relative to 2010.
|
Three Months Ended June 30 |
Six Months Ended June 30 |
||||
| $ millions | $ per share | $ millions | $ per share | ||
| Funds from operations - 2010 | 150.9 | 0.60 | 318.8 | 1.26 | |
| Volume variance | |||||
| Crude oil and liquids | (3.8) | (0.02) | 8.5 | 0.03 | |
| Natural gas | 37.7 | 0.15 | 56.1 | 0.22 | |
| Price variance | |||||
| Crude oil and liquids | 66.4 | 0.26 | 80.9 | 0.32 | |
| Natural gas | (2.0) | (0.01) | (36.7) | (0.15) | |
| Realized gains on risk management contracts | 6.7 | 0.03 | 31.2 | 0.12 | |
| Unrealized losses on risk management contracts related to prior production periods (1) | (21.3) | (0.08) | (33.3) | (0.13) | |
| Royalties | (8.0) | (0.03) | (1.4) | (0.01) | |
| Expenses: | |||||
| Operating and transportation | (2.2) | (0.01) | (14.1) | (0.05) | |
| General and administrative | (11.9) | (0.05) | (5.3) | (0.02) | |
| Interest | (1.7) | (0.01) | (0.6) | - | |
| Realized foreign exchange gain | (0.7) | - | 0.1 | - | |
| Diluted shares | - | (0.10) | - | (0.17) | |
| Funds from operations - 2011 | 210.1 | 0.73 | 404.2 | 1.42 | |
| (1) | Unrealized losses on crude oil annually settled call contracts pertaining to second quarter and first half contracted volumes. The annually settled call contracts are commodity price risk management contracts, which pertain to production periods spanning the entire calendar year but that are cash settled at the end of the year based on the annual average benchmark crude oil price. The portion of total losses on these contracts that relates to production periods for the three and six months ended June 30, 2011, have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after the effect of all contracts used for economic hedging in the period, regardless of the timing of cash settlement. |
Operating Netbacks
ARC's operating netback, before hedging, increased 27 per cent to $32.15 per boe in the second quarter of 2011 compared to $25.30 per boe in the same period of 2010. The increase in pre-hedging netbacks is due to the increase in commodity prices, a significant reduction in per boe operating costs, and slightly lower royalty and transportation costs. After hedging, ARC's second quarter netback was $32.59 per boe, a 15 per cent increase from the same period in 2010. The second quarter 2011 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during the quarter of $3.3 million ($0.44 per boe) compared to a net gain of $3.08 per boe recorded for the same period in 2010. ARC's first half 2011 netback after hedging was $32.57 per boe, a six per cent increase from the same period in 2010.
Lower operating costs in 2011 were attributed to the sale of higher cost properties in the first quarter of 2011 along with a higher proportion of low cost natural gas production in 2011 relative to 2010.
The following table details components of operating netbacks for the second quarter and first half of 2011.
| Netbacks - Q2 |
Crude Oil ($/bbl) |
Heavy Oil ($/bbl) |
Condensate ($/bbl) |
Natural Gas ($/mcf) |
NGL ($/bbl) |
Q2 2011 Total ($/boe) |
Q2 2010 Total ($/boe) |
| Average sales price | 97.75 | 78.59 | 100.57 | 4.05 | 48.40 | 49.94 | 45.82 |
| Other | - | - | - | - | - | 0.08 | 0.11 |
| Total sales | 97.75 | 78.59 | 100.57 | 4.05 | 48.40 | 50.02 | 45.93 |
| Royalties | (18.17) | (9.20) | (25.57) | (0.22) | (10.95) | (7.40) | (7.89) |
| Transportation | (0.43) | (2.23) | (0.24) | (0.29) | (0.32) | (1.25) | (1.28) |
| Operating costs (1) | (14.45) | (12.18) | (7.43) | (1.10) | (12.16) | (9.22) | (11.46) |
| Netback before hedging | 64.70 | 54.98 | 67.33 | 2.44 | 24.97 | 32.15 | 25.30 |
| Hedging gain (loss) (2) | (9.62) | - | - | 0.89 | - | 0.44 | 3.08 |
| Netback after hedging | 55.08 | 54.98 | 67.33 | 3.33 | 24.97 | 32.59 | 28.38 |
| Netbacks - YTD |
Crude Oil ($/bbl) |
Heavy Oil ($/bbl) |
Condensate ($/bbl) |
Natural Gas ($/mcf) |
NGL ($/bbl) |
YTD 2011 Total ($/boe) |
YTD 2010 Total ($/boe) |
| Average sales price | 90.00 | 73.41 | 94.85 | 4.05 | 45.86 | 49.38 | 48.84 |
| Other | - | - | - | - | - | 0.08 | 0.09 |
| Total sales | 90.00 | 73.41 | 94.85 | 4.05 | 45.86 | 49.46 | 48.93 |
| Royalties | (15.64) | (8.36) | (24.74) | (0.22) | (11.61) | (7.13) | (8.24) |
| Transportation | (0.46) | (1.81) | (0.34) | (0.28) | (0.39) | (1.18) | (1.14) |
| Operating costs (1) | (15.07) | (14.29) | (7.09) | (1.10) | (10.84) | (9.64) | (10.38) |
| Netback before hedging | 58.83 | 48.95 | 62.68 | 2.45 | 23.02 | 31.51 | 29.17 |
| Hedging gain (loss) (2) | (6.99) | - | - | 0.95 | - | 1.06 | 1.53 |
| Netback after hedging | 51.84 | 48.95 | 62.68 | 3.40 | 23.02 | 32.57 | 30.70 |
| (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, condensate, natural gas and natural gas liquids production. |
| (2) | Hedging gain (loss) includes realized cash gain (loss) on risk management contracts including the settlement amounts for crude oil and natural gas contracts and unrealized loss on risk management contracts relating to prior production periods of $21.3 million and $33.3 million, respectively, for the second quarter and first half of 2011. Foreign exchange, power and interest contracts are excluded from the netback calculation. |
Net Income
Net income increased 155 per cent in the second quarter to $150.1 million ($0.52 per share) from $58.8 million ($0.23 per share) in the second quarter of 2010. Second quarter net income included a $74 million unrealized MTM gain on risk management contracts, predominantly attributed to crude oil contracts where the futures price declined at the end of the second quarter relative to the first quarter. This $74 million unrealized MTM gain compared to an unrealized MTM gain of $6.6 million in the second quarter of 2010. Second quarter net income also included an unrealized foreign exchange gain of $2.6 million due to the strengthening of the Canadian dollar and associated revaluation of U.S. denominated debt balances ($13 million unrealized foreign exchange loss in 2010).
First half 2011 net income of $215.3 million ($0.75 per share) was up three per cent from net income of $208.6 ($0.83 per share) million for the first half of 2010. First half 2011 net income included an $87.9 million gain on disposal of producing properties (nil 2010) and an unrealized foreign exchange gain of $12.2 million due to the strengthening of the Canadian dollar and associated revaluation of U.S. denominated debt balances ($1.5 million unrealized loss in 2010).
Operating Income
Operating income increased 22 per cent in the second quarter to $76.4 million ($0.27 per share) from $62.7 million ($0.25 per share) in the second quarter of 2010. Higher sales volumes from the increased production and higher crude oil prices were offset by higher total royalties and depletion expense on the increased second quarter volumes as well as higher general and administrative expense.
First half 2011 operating income increased five per cent relative to the first half of 2010 and was attributed to the same factors as noted for the increase in second quarter operating income offset by higher total operating costs on increased production volumes in 2011.
Following is a summary of operating income for the second quarter and first half of 2011 and 2010.
|
Three Months Ended June 30 |
Six Months Ended June 30 |
||||
| 2011 | 2010 | 2011 | 2010 | ||
| Net income | 150.1 | 58.8 | 215.3 | 208.6 | |
| Add (deduct) non-operating items, net of tax: | |||||
| Unrealized (gain) loss on risk management contracts relating to future production periods | (55.5) | (5.0) | 56.0 | (67.7) | |
|
Unrealized loss on risk management contracts relating to prior
production periods (1) |
(16.0) | - | (25.0) | - | |
| Unrealized (gain) loss on foreign exchange | (2.0) | 9.8 | (9.2) | 1.1 | |
| (Gains) on disposal of petroleum and natural gas properties | - | - | (65.9) | - | |
| Recovery on property, plant and equipment | - | - | (21.3) | - | |
| Unrealized gain on short-term investment | (0.2) | - | (0.7) | - | |
| (Gain) loss on revaluation of exchangeable shares | - | (0.9) | - | 0.5 | |
| Operating Income (1) | 76.4 | 62.7 | 149.2 | 142.5 | |
| Operating Income per share (1) | $0.27 | $0.25 | $0.52 | $0.56 | |
| (1) | Unrealized losses on crude oil annually settled call contracts pertaining to second quarter and first half contracted volumes. The annually settled call contracts are commodity price risk management contracts, which pertain to production periods spanning the entire calendar year but that are cash settled at the end of the year based on the annual average benchmark crude oil price. The portion of total losses on these contracts that relates to production periods for the three and six months ended June 30, 2011, have been applied to reduce funds from operations in order to more appropriately reflect the funds from operations generated during the period after the effect of all contracts used for economic hedging in the period, regardless of the timing of cash settlement. |
| (2) | Operating income is not a recognized performance measure under GAAP and does not have a standardized meaning prescribed by GAAP. The term "operating income" is defined as net income excluding the impact of after-tax loss on unrealized gains and losses on risk management contracts, after-tax unrealized gains and losses on foreign exchange, after-tax gains and losses on short-term investments, after-tax gains and losses on revaluation of exchangeable shares, after-tax impairment (recovery) on property, plant and equipment, after-tax gains on disposal of petroleum and natural gas properties and the effect of changes in statutory income tax rates. ARC believes that adjusting net income for these non-operating items presents a better measure of financial performance that is more comparable between periods. The most directly comparable measure of operating income calculated in accordance with GAAP is net income. |
Debt Management
ARC's balance sheet remains strong with net debt to total capitalization of nine per cent. At June 30, ARC had total credit capacity of $1.6 billion with $610 million of borrowings, of which $184.3 million was drawn under a credit facility and $425.7 million of private notes were outstanding, leaving $951.2 million of available credit capacity. Approximately 70 per cent of outstanding debt is fixed-rate with a weighted average remaining term of 5.7 years.
Strong funds from operations in the first half of 2011 along with proceeds of $170 million received from the sale of properties in the first quarter of 2011 resulted in a reduction of debt levels relative to year-end 2010. ARC's net debt to annualized funds from operations was 0.9 times, well below ARC's targeted limit of two times. Net debt to capitalization of nine per cent was also well below ARC's targeted limit of 20 per cent.
ARC expects to finance its 2011 capital program with funds from operations, proceeds from the Dividend Re-investment Plan ("DRIP"), proceeds from asset divestitures, and existing credit capacity.
Risk Management
ARC maintains a risk management program to reduce the volatility of sales, increase the certainty of cash flows and to protect acquisition and development economics. ARC currently limits the amount of total forecast production that can be hedged to a maximum 55 per cent over the next two years with the remaining 45 per cent of production being sold at market prices. ARC's hedging policy allows for further hedging on volumes associated with new production arising from specific capital projects and acquisitions with approval of the Board.
Given the significant contribution of ARC's crude oil and natural gas liquids production to total sales and funds from operations, ARC management recognizes the risk associated with an unanticipated reduction in crude oil pricing. Accordingly, approximately 61 per cent and 51 per cent of ARC's total crude oil and liquids production for the balance of 2011 and 2012, respectively, has been hedged through the use of a variety of crude oil risk management contracts.
During the second quarter of 2011, ARC realized a cash gain of $25.5 million, primarily attributed to natural gas swap contracts on approximately 52 per cent of second quarter natural gas production hedged at an average of Cdn$5.35 per mcf. For the first half of 2011, ARC realized a cash gain of $51.3 million primarily attributed to natural gas contracts. The second quarter and first half cash hedging gains were offset by $21.3 million and $33.3 million, respectively, for unrealized losses on crude oil annually settled call contracts relating to second quarter and first half contracted volumes. Unlike the majority of ARC's risk management contracts that are settled monthly, these annually settled call contracts, which relate to production throughout 2011, will be cash-settled in their entirety in January 2012.
An unrealized MTM gain of $74 million was recorded in the second quarter due primarily to a reduction in crude oil and natural gas forward prices relative to the previous quarter. Average crude oil forward prices for 2011 and 2012 of US$96.90 and US$100.04, respectively, currently exceed ARC's average ceiling prices of US$89.46 and US$91.39, respectively. Average AECO natural gas forward prices of Cdn$3.88 per mcf and Cdn$4.14 per mcf for 2011 and 2012, respectively, are lower than ARC's average floor prices of Cdn$5.13 per mcf and Cdn$4.28 per mcf. At June 30, ARC's total MTM position on crude oil and natural gas hedge contracts was a loss of $50.1 million compared to a loss of $130 million at March 31, 2011. The actual future cash settlements under the commodity hedge contracts will differ from the current unrealized MTM value with changes in commodity prices in future periods.
Average floor prices on hedged volumes for 2011 through 2012 provide a level of certainty to ARC's ability to execute its business plan over the next two years. ARC has partially mitigated the weak outlook for natural gas prices by protecting the selling price on 206 mmcf per day of natural gas production at Cdn$5.13 per mcf for the remainder of 2011. On the liquids side, ARC has protected 20,000 barrels of crude oil per day at an average floor price of US$84.46 per barrel and an average ceiling price of US$89.46 per barrel for the remainder of 2011. ARC currently has hedged 53 per cent, 33 per cent, and two per cent of total production for 2011, 2012 and 2013, respectively, as summarized in the table below. For a complete listing of ARC's hedging contracts, see Note 11 "Risk Management Contracts" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011.
|
Hedge Positions Summary (1) As at June 30, 2011 |
July - December 2011 | 2012 | 2013 | |||
| Crude Oil (2) | US$/bbl | bbl/day | US$/bbl | bbl/day | US$/bbl | bbl/day |
| Sold Call | 89.46 | 20,000 | 91.39 | 18,000 | 110.00 | 2,000 |
| Bought Put | 84.46 | 20,000 | 91.39 | 18,000 | 90.00 | 2,000 |
| Sold Put | 61.09 | 12,000 | 60.00 | 5,000 | - | - |
| Natural Gas (3) | Cdn$/mcf | mcf/day | Cdn$/mcf | mcf/day | Cdn$/mcf | mcf/day |
| Sold Call | 5.45 | 161,352 | 4.28 | 76,680 | - | - |
| Bought Put | 5.13 | 205,755 | 4.28 | 76,680 | - | - |
| (1) | The prices and volumes noted above represent 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. |
| (2) | For 2011 and 2012, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the annual average WTI price. For annual sold calls, volumes are based on full year and ARC will only have a negative settlement if prices average above the strike price for an entire year, providing ARC with greater potential upside price participation for individual months. |
| (3) | The natural gas price shown translates all NYMEX positions to an AECO equivalent price based on offsetting basis positions and the period end exchange rate. The equivalent hedged NYMEX price would be approximately a floor of $5.86 per mmbtu and a ceiling of $6.19 per mmbtu for 2011. ARC has a fixed price of $5.00 per mmbtu for 2012. |
OPERATIONAL REVIEW
During the second quarter of 2011 ARC spent $144.5 million on drilling, facilities, optimization and exploration activities and the purchase of crown lands. ARC drilled 24 gross (23 net) operated wells comprising 11 gross (10 net) oil wells and 13 gross (13 net) natural gas wells with a 100 per cent success rate, bringing total wells drilled for the first half of 2011 to 44 gross (40 net) oil wells and 23 gross (22 net) natural gas wells with a 100 per cent success rate. Oil and liquids-rich natural gas wells represented 85 per cent of total wells drilled in the first half of 2011, reflecting ARC's strategy to capitalize on the strength of oil prices through acceleration of oil and liquids projects in 2011.
Second quarter production of 82,367 boe per day, consisting of 63 per cent natural gas and 37 per cent crude oil and liquids, was up 11 per cent relative to the first quarter of 2011. Higher second quarter production was due primarily to the Dawson Phase 2 gas plant coming on-stream at full capacity of 60 mmcf per day in mid-April. Second quarter production was reduced by approximately 6 mmcf per day (1,000 boe per day) as a result of the Dawson Phase 1 gas plant operating at reduced capacity for approximately three weeks in April due to mechanical issues. Adverse weather conditions in southern Saskatchewan, Manitoba along with northern Alberta forest fires and pipeline restrictions resulted in a second quarter production loss of approximately 2,600 boe per day as production, predominantly oil, was shut-in at the affected areas. Also, a third party plant turnaround resulted in a reduction of second quarter production of approximately 1,700 boe per day. The higher percentage of natural gas production in the second quarter was attributed to higher natural gas production at Dawson and lower oil production was attributed to the shut-in of wells due to flooding and fires.
Second quarter capital programs were delayed in areas affected by flooding and fires with the most significant impact in southeastern Saskatchewan and Manitoba and northern Alberta. ARC expects to resume capital programs in the affected areas in the second half of 2011.
Dawson
Production from the Dawson property in the Montney region of northeast British Columbia averaged 149 mmcf per day of natural gas in the second quarter, up 103 per cent from 73 mmcf per day in the first quarter of 2011. The Dawson Phase 2 gas plant commenced full operations at its 60 mmcf per day design capacity in mid-April and the Phase 1 gas plant resumed full capacity operations in late April following tie-in of the Phase 2 plant and repair of a motor that failed at the re-start of the plant. With the completion of the Phase 2 gas plant, ARC's Dawson operated gas plant processing capacity increased to 120 mmcf per day, bringing total capacity to 165 mmcf per day counting 45 mmcf per day of third-party processing capacity. ARC's Dawson production exited the quarter at full capacity of 165 mmcf per day of natural gas.
In the first half of 2011, ARC drilled and completed five horizontal wells and one vertical well at Dawson.
During the second half of 2011, ARC plans to drill 12 operated natural gas wells. ARC forecasts 2011 full year Dawson production to average approximately 140 mmcf per day with an exit production rate of 165 mmcf per day.
West Montney
ARC's West Montney region includes the Sunrise, Septimus and Sundown properties. Second quarter production averaged 6.5 mmcf per day of natural gas from the Sunrise non-operated property. In the first six months of 2011, ARC drilled two horizontal wells. In anticipation of the Phase 1 Sunrise gas plant, ARC drilled a vertical acid gas disposal well during the second quarter of 2011. ARC currently has seven horizontal wells cased and completed at Sunrise waiting on the facility tie-in and one horizontal well at Sundown awaiting completion and tie-in. ARC plans to bring 15 mmcf per day of operated production on-stream through a third party facility by the start of the fourth quarter.
ARC received approval from the British Columbia Oil and Gas Commission to construct two 60 mmcf per day gas plants at Sunrise. Current plans target the first 60 mmcf per day of capacity to be on-stream in 2013.
During the second half of 2011, ARC plans to tie-in existing wells to third party facilities. ARC expects to exit 2011 with West Montney production of approximately 22 mmcf per day from the Sunrise property.
Parkland
Parkland is a liquids rich property located just ten kilometers northwest of the Dawson field. Second quarter 2011 production averaged 39.5 mmcf per day of natural gas and 1,000 boe per day of natural gas liquids. Second quarter production of 7,600 boe per day was down four per cent relative to the first quarter of 2011 primarily due to a third party plant turnaround, originally scheduled for the third quarter, which resulted in a production loss of approximately 1,700 boe per day in the second quarter.
ARC drilled six horizontal, liquids rich natural gas wells at Parkland in the second quarter. One horizontal well was drilled into a lower section of the Upper Montney, which ARC believes not to be accessed by existing well bores. The well will be brought on production in the third quarter to determine if there is any interference with other wells. If no interference is observed, development of this portion of the reservoir could require numerous additional locations. To date in 2011, ARC has drilled 10 liquids-rich, natural gas wells (nine horizontal and one vertical) at Parkland, including one horizontal well, which targeted the Upper Montney in the liquids-rich Tower area (north of the main producing pool). Five of the ten wells drilled in 2011 have been completed and the remaining wells will be completed in the third quarter.
Two additional horizontal wells will be drilled and completed in the liquids-rich Tower area by year-end to further evaluate the opportunity.
Attachie
ARC holds a prospective land base of 106 sections in the Attachie property located north and west of Dawson. Currently there are no booked reserves or production at Attachie. ARC's assessment of the block commenced in the first quarter of 2011. ARC completed its first horizontal well at Attachie during the second quarter. Two additional wells, one vertical and one horizontal, were drilled and are awaiting completion, which will commence in the second half of 2011.
The first horizontal well at Attachie achieved a stabilized test production rate of 10 mmcf per day (30 bbls per mmcf of liquids) at a pressure of 9 MPa within a seven day test period. ARC plans to seek contracts to tie-in wells in the Attachie block into third party facilities to help determine the potential of this area for commercial development in the future.
Ante Creek
Second quarter production averaged 7,300 boe per day (42 per cent light crude oil and natural gas liquids, 58 per cent natural gas) at Ante Creek. Successful horizontal, multi-stage completions at Ante Creek average 30 day production rates of 360 boe per day compared to average rates of 100 boe per day for vertical wells. Given the favorable results from horizontal drilling, ARC believes that the Ante Creek property will provide a significant near-term growth opportunity once facility capacity is expanded.
ARC drilled two horizontal oil wells into the Montney formation at Ante Creek during the second quarter. In the first half of 2011, ARC drilled five horizontal Montney oil wells at Ante Creek - four were completed in the first half of 2011 and the remaining well will be completed in the second half.
In response to current capacity constraints, ARC has committed to build a new, 30 mmcf per day gas plant to process solution gas, enabling an increase in liquids production. ARC has completed the engineering and design for the gas plant and has received ERCB approval to construct the plant. The sales pipeline to TCPL has been installed, major equipment has been ordered and pipeline debottlenecking within the field is progressing. The new plant is expected to come on-stream late in the first quarter of 2012. The total cost of the gas plant is expected to be $40 million.
During the second half of 2011, ARC plans to spend $43 million to drill 11 horizontal wells and continue with construction of the gas plant. ARC expects to grow liquids production to approximately 5,000 barrels per day and to increase total production at Ante Creek to approximately 11,000 boe per day over the course of 2012.
Pembina
ARC is the second largest operator in the Pembina area, operating approximately 25 per cent of the Pembina oil field with an average 65 per cent working interest in 166 gross sections (126 net sections). Pembina second quarter production averaged 10,300 boe per day, consisting of approximately 72 per cent light crude oil and liquids and 28 per cent natural gas, an increase of 14 per cent from 9,000 boe per day in the comparable period of 2010. During the second quarter, ARC drilled three gross horizontal wells into the Cardium formation, bringing the total wells drilled in the first six months of 2011 to 14 gross horizontal Cardium wells, 10 of which were completed and on-stream in the first half. ARC is encouraged by results that indicate an initial 30-day production average of 150 barrels of oil per day per well.
ARC is optimistic about the opportunity for increased recovery at Pembina from the application of horizontal drilling and completion technology. Pembina is an extensive area with geological variability, which adds complexity to ARC's efforts to access additional resources using horizontal drilling and completion techniques. ARC will continue to evaluate this field in order to gain a better understanding of where the horizontal completion technology can be most effectively applied.
During the second half of 2011, ARC plans to drill 28 gross horizontal Cardium locations in order to further develop this reservoir. ARC acquired a gas plant during the second quarter to alleviate solution gas handling constraints at Pembina. In addition, extensive work is also planned on waterflood management in order to optimize reservoir recoveries.
Southeast Saskatchewan and Manitoba
Southeast Saskatchewan and Manitoba was the hardest hit area as a result of the flooding in the second quarter, resulting in an approximate 1,200 boe per day production loss in the quarter. ARC had planned to drill 12 wells in southeast Saskatchewan and Manitoba (including four at Goodlands) in the second quarter; however as a result of the flooding none of the wells were drilled. In the first six months of 2011, ARC drilled 15 wells in this area with 12 wells being brought on-stream and eight wells to be completed in the second half of 2011. Two of the Parkman wells brought on-stream had initial production rates of 500 boe per day.
The Goodlands property in Manitoba provides some of the best drilling economics in ARC's portfolio because of the high netback, light crude oil. Second quarter production averaged 930 boe per day of light crude oil, down from 1,400 boe per day in the first quarter of 2011 as a result of shut-in production attributed to flooding and natural decline. Four wells planned at Goodlands for the second quarter were not drilled because of access restrictions.
During the second half of 2011, ARC plans to spend $47 million in this area to drill 36 wells and explore for additional opportunities. ARC is exploring options to contract two additional drilling rigs so as to complete its original full year capital program following delays in the second quarter. The Goodlands battery is running at full capacity and plans are underway to expand oil capacity during the second half of 2011.
DIVIDENDS
ARC paid dividends totaling $0.30 per share for the second quarter of 2011 and $0.60 per share for the first six months of 2011. The Board of Directors has confirmed a dividend of $0.10 per share for July 2011 and has conditionally declared a monthly dividend of $0.10 per share for August, September and October 2011, targeting a total dividend of $0.30 per share for the third quarter of 2011. The dividends have been designated as eligible dividends under the Income Tax Act (Canada) and are payable as follows:
| Ex-dividend date | Record date | Payment date |
Per share amount |
|||
| July 27, 2011 | July 29, 2011 | August 15, 2011 | $0.10(1) | |||
| August 29, 2011 | August 31, 2011 | September 15, 2011 | $0.10(2) | |||
| September 28, 2011 | September 30, 2011 | October 17, 2011 | $0.10(2) | |||
| October 27, 2011 | October 31, 2011 | November 15, 2011 | $0.10(2) |
(1) Confirmed on July 15, 2011.
(2) Conditionally declared, subject to confirmation by news release and further resolution by the Board of Directors.
The declaration of the dividends is conditional upon confirmation by news release and further resolution of the Board of Directors. Dividends are subject to change in accordance with ARC's dividend policy depending on a variety of factors and conditions existing from time-to-time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of solvency tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends.
OUTLOOK
The pillar of ARC's business strategy is "risk-managed value creation". ARC's goal is to transform this value into shareholder returns through regular dividends and, when appropriate, growth in 2011 and beyond. ARC received Board approval to increase its 2011 capital program to $690 million from $625 million. Approximately $50 million of the increased 2011 capital is allocated to land acquisitions in oil prone areas in and around ARC's existing operations. Additional 2011 capital will be allocated to the purchase of long lead-time equipment and materials for the Sunrise Phase 1 gas plant for which ARC received regulatory approval in the second quarter and for general service cost increases. ARC's 2011 capital program includes the drilling of 166 gross (148 net) wells on operated properties with horizontal wells accounting for 86 per cent. In addition, ARC expects to participate in the drilling of 83 gross (10 net) non-operated wells in 2011.
ARC has a balanced portfolio of high-quality assets with current production of approximately 60 per cent natural gas and 40 per cent crude oil and natural gas liquids. The mix of liquids and natural gas in ARC's portfolio has enabled ARC to respond to the prolonged, low natural gas price environment effectively by redirecting a portion of capital to oil and liquids projects that generate significant returns and cash flow relative to near-term natural gas projects.
Given the strong outlook for crude oil prices, a significant portion of ARC's 2011 capital program has been allocated to oil and liquids projects, which will account for approximately 84 per cent of operated wells to be drilled in 2011. Ante Creek, Pembina and Goodlands will see significant oil drilling activity in 2011 as well as the construction of a new gas processing facility at Ante Creek to address current capacity constraints. ARC will continue to assess the liquids potential of the Montney at Parkland.
ARC will direct considerable resources and capital on the Montney assets in northeast British Columbia in order to set the stage for long-term growth in this area over the next three to five years. Despite continued low natural gas prices, ARC's Montney natural gas economics support development of this area at current natural gas prices. With the completion of the Phase 2 Dawson gas plant in the second quarter, ARC's processing capacity in Dawson has doubled to 120 mmcf per day. Plans for two 60 mmcf per day gas plants at Sunrise will further expand capacity and production in this area over the next five years.
With the increase in the 2011 capital budget to $690 million, ARC plans to spend approximately $390 million in the second half of the year. ARC believes that full year 2011 volumes may average 80,000 - 85,000 boe per day and exit 2011 production is expected to be approximately 90,000 boe per day. ARC's guidance for full year 2011 general and administrative expense increased slightly in relation to higher compensation costs. Variances from full year guidance at the end of the second quarter are timing related and ARC expects that full year 2011 results will match guidance estimates as the year progresses. All other 2011 full year guidance estimates remain unchanged and are summarized in the following table.
| 2011 Guidance | 2011 YTD Actual | % Variance | ||||
| Production (boe/d) | 80,000 - 85,000 | 78,147 | (2) | |||
| Expenses ($/boe): | ||||||
| Operating | 9.40 - 9.70 | 9.64 | - | |||
| Transportation | 1.10 - 1.20 | 1.18 | - | |||
| General and administrative(1) | 2.50 - 2.70 | 2.96 | 10 | |||
| Interest | 1.25 - 1.40 | 1.34 | - | |||
| Capital expenditures ($ millions) | 690 | 301.7 | - | |||
| Diluted shares (millions)(2) | 286 | 285 | - |
| (1) | Full year 2011 G&A guidance increased from previous guidance of $2.45 - $2.60 per boe. The 2011 annual Guidance for general and administrative cost per boe is based on a range of $1.90 - $2.05 prior to the recognition of any expense associated with ARC's long-term incentive plan, $0.60-$0.65 per boe associated with cash payments under ARC's long-term incentive plan and nil per boe associated with accrued compensation under ARC's long-term incentive plan. Actual per boe costs for each of these components for the six months ended June 30, 2011 were $2.10 per boe, $0.73 per boe and a $0.13 per boe, respectively. |
| (2) | Based on weighted average shares plus the dilutive impact of share options outstanding during the period. |
On June 6, 2011 the Federal Government reintroduced the budget from March 22, 2011, which included a proposal to eliminate the ability of a corporation to defer income as a result of timing differences in the year-end of the corporation and of any partnership of which it is a member. ARC Resources Ltd.'s oil and natural gas properties are directly owned and operated by ARC Resources General Partnership, which has a January 31 year-end. The Department of Finance has not yet released the legislation to enact this proposal. However, it is expected that the proposal related to the elimination of the partnership deferral will be enacted this year. When the proposal is enacted, ARC expects that it would be taxable in 2012 instead of 2013 as a result of the loss of the deferral on partnership income.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
Effective January 1, 2011 all Canadian publicly accountable enterprises are required to prepare their financial statements in accordance with International Financial Reporting Standards ("IFRS"). ARC has prepared its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 under IFRS and has restated its unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2010 to comply with IFRS. For further information on ARC's transition to IFRS and a reconciliation of its affected financial information for the three and six months ended June 30, 2010, please refer to Note 16, "Explanation of Transition to International Financial Reporting Standards" in the unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 and 2010 filed on SEDAR at www.sedar.com.
Forward-looking Information and Statements
This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: guidance as to the 2011 production, timing of execution of capital programs and plans relating to the construction of gas plants at Sunrise under the heading "Financial and Operational Highlights", various plans, forecasts and estimates as to drilling operations and completions, production estimates, timing of building and completion of gas plants and other operational forecasts under the heading "Operational Review", and all matters including 2011 guidance under the heading "Outlook".
The forward-looking information and statements contained in this news release reflect material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and Funds from operations to fund its planned expenditures. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $7.7 billion. ARC expects 2011 oil and gas production to average 80,000 to 85,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX.
ARC RESOURCES LTD.
John P. Dielwart,
Chief Executive Officer
For further information:
For further information about ARC Resources Ltd., please visit our website
www.arcresources.com
or contact:
Investor Relations, E-mail: ir@arcresources.com
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ARC Resources Ltd.
Suite 1200, 308 - 4th Avenue S.W.
Calgary, AB T2P 0H7