FINANCIAL AND OPERATING HIGHLIGHTS
| Three months ended December 31 |
Year ended December 31 |
||||||||||||
| (Cdn$000s except shares, per share and per boe amounts) | 2012 | 2011 | % Change | 2012 | 2011 | % Change | |||||||
| Financial | |||||||||||||
| Funds flow from operations (1) | 430,386 | 381,922 | 13 | 1,601,850 | 1,293,257 | 24 | |||||||
| Per share (1) (2) | 1.18 | 1.32 | (11 | ) | 4.83 | 4.65 | 4 | ||||||
| Net income (loss) (3) | (95,241 | ) | (86,197 | ) | 10 | 190,653 | 201,134 | (5 | ) | ||||
| Per share (2) (3) | (0.26 | ) | (0.30 | ) | (13 | ) | 0.57 | 0.72 | (21 | ) | |||
| Dividends paid or declared | 255,621 | 199,869 | 28 | 931,400 | 771,362 | 21 | |||||||
| Per share (2) | 0.69 | 0.69 | – | 2.76 | 2.76 | – | |||||||
| Payout ratio (%) (1) (4) | 59 | 52 | 7 | 58 | 60 | (2 | ) | ||||||
| Per share (%) (1) (2) (4) | 58 | 52 | 6 | 57 | 59 | (2 | ) | ||||||
| Net debt (1) (5) | 1,760,324 | 1,220,144 | 44 | 1,760,324 | 1,220,144 | 44 | |||||||
| Capital acquisitions (net) (6) | 926,985 | 2,765 | 33,426 | 3,021,230 | 201,313 | 1,401 | |||||||
| Development capital expenditures (7) | 463,438 | 458,874 | 1 | 1,488,947 | 1,238,795 | 20 | |||||||
| Decommissioning and environmental expenditures (7) | 4,478 | 2,888 | 55 | 15,440 | 7,307 | 111 | |||||||
| Weighted average shares outstanding (mm) | |||||||||||||
| Basic | 361.2 | 286.6 | 26 | 329.4 | 275.4 | 20 | |||||||
| Diluted | 363.4 | 289.3 | 26 | 331.8 | 278.2 | 19 | |||||||
| Operating | |||||||||||||
| Average daily production | |||||||||||||
| Crude oil and NGLs (bbls/d) | 97,731 | 73,667 | 33 | 89,704 | 66,604 | 35 | |||||||
| Natural gas (mcf/d) | 61,654 | 45,257 | 36 | 54,284 | 43,172 | 26 | |||||||
| Total (boe/d) | 108,007 | 81,210 | 33 | 98,751 | 73,799 | 34 | |||||||
| Average selling prices(8) | |||||||||||||
| Crude oil and NGLs ($/bbl) | 78.78 | 90.88 | (13 | ) | 80.51 | 87.62 | (8 | ) | |||||
| Natural gas ($/mcf) | 3.36 | 3.48 | (3 | ) | 2.61 | 3.87 | (33 | ) | |||||
| Total ($/boe) | 73.20 | 84.37 | (13 | ) | 74.57 | 81.35 | (8 | ) | |||||
| Netback ($/boe) | |||||||||||||
| Oil and gas sales | 73.20 | 84.37 | (13 | ) | 74.57 | 81.35 | (8 | ) | |||||
| Royalties | (13.97 | ) | (14.42 | ) | (3 | ) | (12.95 | ) | (13.95 | ) | (7 | ) | |
| Operating expenses | (12.15 | ) | (11.17 | ) | 9 | (11.65 | ) | (11.16 | ) | 4 | |||
| Transportation | (1.74 | ) | (2.01 | ) | (13 | ) | (1.83 | ) | (1.91 | ) | (4 | ) | |
| Netback prior to realized derivatives | 45.34 | 56.77 | (20 | ) | 48.14 | 54.33 | (11 | ) | |||||
| Realized gain (loss) on derivatives | 1.15 | (3.37 | ) | 134 | (0.49 | ) | (2.97 | ) | (84 | ) | |||
| Netback (1) | 46.49 | 53.40 | (13 | ) | 47.65 | 51.36 | (7 | ) | |||||
| (1) | Funds flow from operations, payout ratio, net debt and netback as presented do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Please refer to the Non-GAAP Financial Measures section of this press release. |
| (2) | The per share amounts (with the exception of per share dividends) are the per share – diluted amounts. |
| (3) | Net income for the three months and year ended December 31, 2012, includes unrealized derivative losses of $20.1 million and unrealized derivative gains of $185.7 million, respectively. Net income for the three months and year ended December 31, 2011, includes unrealized derivative losses of $271.4 million and $6.2 million, respectively. |
| (4) | Payout ratio is calculated as dividends paid or declared (including the value of dividends paid pursuant to the Company”s dividend reinvestment plans) divided by funds flow from operations. |
| (5) | Net debt includes long-term debt, working capital and long-term investments, but excludes derivative asset, derivative liability and unrealized foreign exchange on translation of US dollar senior guaranteed notes. |
| (6) | Capital acquisitions represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs. |
| (7) | Decommissioning and environmental expenditures for the three months and year ended December 31, 2012 includes environmental emission reduction expenditures of $1.4 million and $3.3 million, respectively. Decommissioning and environmental expenditures for the three months and year ended December 31, 2011 includes environmental emission reduction expenditures of $1.6 million and $3.6 million, respectively. Environmental emission reduction expenditures are also included in Development capital expenditures in the table above, whereas decommissioning expenditures are not. |
| (8) | The average selling prices reported are before realized derivatives and transportation charges. |
FOURTH QUARTER 2012 HIGHLIGHTS
In fourth quarter 2012, Crescent Point continued to execute its integrated business strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties.
2012 HIGHLIGHTS
| Per boe, except Recycle Ratios | Total Proved | Total Proved plus Probable | ||
| F&D | ||||
| 5-year weighted average cost, excluding | $ | 21.94 | $ | 17.34 |
| change in FDC(1) | ||||
| 2012 cost, excluding change in FDC | $ | 26.08 | $ | 19.80 |
| 2012 average recycle ratio(2) | 1.8 | 2.4 | ||
| 2012 cost, including change in FDC | $ | 33.04 | $ | 27.25 |
| FD&A | ||||
| 5-year weighted average cost, excluding | $ | 30.16 | $ | 21.68 |
| change in FDC | ||||
| 2012 cost, excluding change in FDC | $ | 29.23 | $ | 20.64 |
| 2012 average recycle ratio(2) | 1.6 | 2.3 | ||
| 2012 cost, including change in FDC | $ | 31.78 | $ | 23.19 |
| (1) | Future Development Capital. |
| (2) | Based on 2012 netback (prior to realized derivatives) of $48.14 per boe. |
OPERATIONS REVIEW
Fourth Quarter Operations Summary
During fourth quarter 2012, Crescent Point continued to aggressively implement management”s business strategy of creating sustainable, value-added growth in reserves, production and cash flow through acquiring, exploiting and developing high- quality, long-life light and medium oil and natural gas properties.
Crescent Point achieved a new production record in the fourth quarter and averaged 108,007 boe/d, weighted 90 percent to light and medium crude oil and liquids. This represents a growth rate of 8 percent over third quarter 2012 and 33 percent over fourth quarter 2011.
During the quarter, the Company spent a record $405.6 million on drilling and development activities, drilling 169 (127.1 net) wells with a 98 percent success rate. Crescent Point also spent $57.8 million on land, seismic and facilities, for total capital expenditures of $463.4 million.
Drilling Results
The following tables summarize our drilling results for the three months and year ended December 31, 2012:
| Three months ended December 31, 2012 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success | ||
| Southeast Saskatchewan and Manitoba | 1 | 76 | 1 | – | – | 78 | 66.1 | 98 | ||
| Southwest Saskatchewan | – | 33 | – | – | – | 33 | 31.6 | 100 | ||
| South/Central Alberta and West/Central SK | – | 24 | – | – | 1 | 25 | 20.6 | 95 | ||
| Northeast BC and Peace River Arch, Alberta | – | – | – | – | – | – | – | – | ||
| United States (1) | – | 33 | – | – | – | 33 | 8.8 | 100 | ||
| Total | 1 | 166 | 1 | – | 1 | 169 | 127.1 | 98 | ||
| Year ended December 31, 2012 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success | ||
| Southeast Saskatchewan and Manitoba | 1 | 258 | 1 | – | 1 | 261 | 197.7 | 99 | ||
| Southwest Saskatchewan | – | 90 | – | – | – | 90 | 75.3 | 100 | ||
| South/Central Alberta and West/Central SK | 1 | 107 | – | – | 1 | 109 | 68.9 | 99 | ||
| Northeast BC and Peace River Arch, Alberta | – | 7 | – | – | – | 7 | 4.7 | 100 | ||
| United States (1) | – | 94 | – | 1 | – | 95 | 22.4 | 100 | ||
| Total | 2 | 556 | 1 | 1 | 2 | 562 | 369.0 | 99 | ||
| (1) | The net well count is subject to final working interest determination. |
Southeast Saskatchewan and Manitoba
In fourth quarter 2012, Crescent Point participated in the drilling of 78 (66.1 net) wells in southeast Saskatchewan and Manitoba, achieving a 98 percent success rate. Of the wells drilled, 62 (56.8 net) were drilled in the Bakken light oil resource play. In fourth quarter, the Company also participated in the drilling of 16 (9.3 net) horizontal wells in conventional zones. In total, the Company drilled 198 (168.7 net) Bakken horizontal wells during 2012, achieving a 99 percent success rate. The Company plans to drill up to 163 net wells in the Viewfield Bakken play during 2013 and to spend approximately $452 million, including expenditures on land, seismic and facilities.
During the quarter, the Company converted five additional Viewfield Bakken producing wells to water injection wells for a total of 46 water injection wells in the play. Production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed Crescent Point”s expectations and we believe has demonstrated the field-wide applicability of waterflood to the play. Discussions with the Saskatchewan government to implement the first of four proposed units for water flooding are advancing.
In the Saskatchewan Bakken, Crescent Point has re-entered existing wells that were originally completed with 8-stage and 16- stage cemented liners and increased them to 25-stage and 30-stage cemented liner completions. The Company is encouraged by results to date and has identified 90 wells in the play as candidates for this process. Crescent Point drilled a fourth 2-mile horizontal well in fourth quarter 2012 in the Flat Lake area. Based on the initial success of these wells, the Company plans to drill six additional 2-mile horizontal wells in 2013. We expect that these wells will be drilled at considerable savings to similar wells drilled across the border in North Dakota, where demand has driven well costs up.
Crescent Point continues to increase deliveries of crude oil through its Stoughton rail facility, allowing the Company to diversify its markets for Bakken crude oil, to more effectively manage pipeline disruptions and to increase netbacks. On average, more than 19,000 bbl/d of Bakken production was delivered through the facility during fourth quarter. The Stoughton rail facility has been expanded to increase shipping capacity to more than 45,000 bbl/d and first quarter 2013 deliveries are expected to be approximately 30,000 bbl/d.
Southwest Saskatchewan
During fourth quarter, the Company participated in the drilling of 33 (31.6 net) oil wells in southwest Saskatchewan, achieving a 100 percent success rate. Of these wells, 30 (30.0 net) were drilled in the Shaunavon area. In total in 2012, the Company drilled 73 (66.6 net) wells in the Shaunavon formation. The Company plans to drill up to 89 net wells in the Shaunavon area in 2013, including 19 Lower Shaunavon wells spaced at 8 wells per section and two at 16 wells per section. Four Upper Shaunavon wells are also planned at 8 wells per section. In 2013, Crescent Point expects to spend approximately $283 million in the area, including expenditures on land, seismic and facilities.
Water is currently being injected into 30 converted wells in both the Lower and Upper Shaunavon unconventional zones. The Company has submitted applications to the Saskatchewan government to establish the first Lower Shaunavon unit for the purpose of implementing a unit-wide water injection scheme.
Crescent Point completed its rail-loading facility in the Dollard area and delivered its first loads in October. During the quarter, the Company railed approximately 2,000 bbl/d. Current capacity is approximately 5,000 bbl/d and the Company plans to expand the facility during the first half of 2013 to accommodate 8,000 bbl/d.
During the quarter, Crescent Point also completed construction of the third of three new batteries planned for 2012. The battery was commissioned in January 2013.
South/Central Alberta and West Central Saskatchewan
During fourth quarter, Crescent Point participated in the drilling of 24 (19.6 net) oil wells in this area, achieving a 95 percent success rate. Of these, 7 (3.5 net) were drilled in the Beaverhill Lake light oil resource play and 9 (8.1 net) were drilled in the Viking area. The Company”s plans for its first waterflood pilot in the Beaverhill Lake play are well underway and the first pilot is expected to be operational in early 2013. In 2013, the Company plans to reduce its capital expenditures in the area to $77 million and to drill 11 net wells to take advantage of expected declines in future capital costs in the play.
By end of fourth quarter 2012, the Company had drilled 18 (18.0 net) wells with a 100 percent success rate in the Viking area on lands acquired in the Cutpick Energy Inc. acquisition. Crescent Point plans to drill 30 net wells on these lands in 2013. The Company plans to convert an additional three producing Viking wells to water injection wells on these lands in 2013. Crescent Point has also added rail shipping capacity in the area, with current loading capacity of 3,000 bbl/d.
Crescent Point has access to a significant land base in southern Alberta and has been pursuing several exploration projects in the area. In fourth quarter 2012, the Company drilled 8 (8.0 net) wells to follow up on previously drilled unconventional exploration wells in the Alberta Bakken play. These wells are currently under evaluation.
United States
During fourth quarter, the Company participated in the drilling of 33 (8.8 net) oil wells, of which 27 (5.4 net) were in North Dakota, achieving a 100 percent success rate. Crescent Point has been greatly encouraged by the development success and positive reserves revisions in the North Dakota Bakken and Three Forks plays. In 2013, the Company plans to reduce its capital expenditures to $47 million and to drill 2 net wells in the area to take advantage of expected declines in future capital costs in the play.
Of the wells drilled during fourth quarter, 6 (3.4 net) were in the company”s new core area in the Uinta basin of Utah. Crescent Point also participated in fracture stimulating 13 (9.1 net) wells. The Company successfully integrated its field operations in the Uinta basin and is well-positioned to execute and achieve its 2013 operating and capital program targets. In all, Crescent Point plans to spend $195 million in the Randlett area of the Uinta Basin in 2013, including the drilling of up to 74 net wells, 2 of which are expected to be horizontal wells in the Wasatch formation.
Environmental Responsibility
As part of Crescent Point”s ongoing commitment to the environment and to reduce greenhouse gas emissions, Crescent Point has a voluntary reclamation fund for future decommissioning costs and environmental emissions reduction costs. During 2012, the Company contributed $0.50 per produced boe to the fund, of which $0.20 per boe was for future decommissioning costs and $0.30 per boe was directed to environmental emissions reduction.
The reclamation fund increased by $2.7 million during 2012 due to contributions of $18.1 million, partially offset by expenditures of $15.4 million. The expenditures included $12.1 million related primarily to decommissioning work completed in southwest and southeast Saskatchewan, Alberta and Manitoba. The remaining $3.3 million related to environment emissions work completed in southeast Saskatchewan, Alberta and North Dakota to reduce greenhouse gas emissions and to meet and exceed provincial and federal targets. Since inception, $56.0 million has been contributed to the reclamation fund and $45.5 million has been spent.
Effective January 1, 2013, Crescent Point contributes $0.70 per produced boe to the fund, of which $0.40 per boe is for future decommissioning costs and $0.30 per boe is directed to environmental emissions reduction.
RESERVES
In 2012, Crescent Point replaced 208 percent of production on a proved plus probable basis, excluding reserves added through acquisitions. Including acquisitions, the Company replaced 609 percent of production and increased its year-end proved plus probable reserves by 43 percent to 608.8 mmboe and its proved reserves by 42 percent to 400.4 mmboe. Year- end 2011 reserves were 424.8 mmboe proved plus probable and 281.0 mmboe proved.
The Company”s reserves were independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Ltd. (“Sproule”) as at December 31, 2012, and the following highlights are based on such evaluations.
Summary of Reserves (Escalated Pricing)
As at December 31, 2012 (1)
| RESERVES(2) | |||||||||||||||
| Oil (Mbbl) | Gas (MMscf) | NGL (Mbbl) | Total (Mboe) | ||||||||||||
| Description | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||
| Proved producing | 187,647 | 164,493 | 105,301 | 96,149 | 7,284 | 6,589 | 212,482 | 187,107 | |||||||
| Proved non- | |||||||||||||||
| producing | 163,467 | 146,850 | 97,753 | 88,427 | 8,133 | 7,491 | 187,891 | 169,079 | |||||||
| Total proved | 351,114 | 311,343 | 203,053 | 184,576 | 15,417 | 14,080 | 400,373 | 356,186 | |||||||
| Probable | 182,688 | 160,128 | 107,319 | 96,877 | 7,849 | 7,037 | 208,424 | 183,311 | |||||||
| Total proved plus | |||||||||||||||
| probable (3) | 533,802 | 471,472 | 310,373 | 281,453 | 23,266 | 21,117 | 608,797 | 539,497 | |||||||
| (1) | Based on GLJ”s January 1, 2013, escalated price forecast. |
| (2) | “Gross Reserves” are the total Company”s interest share before the deduction of any royalties and without including any royalty interest of the Company. “Net Reserves” are the total Company”s interest share after deducting royalties and including any royalty interest. |
| (3) | Numbers may not add due to rounding. |
Summary of Before and After Tax Net Present Values (Escalated Pricing)
As at December 31, 2012 (1)
| BEFORE TAX NET PRESENT VALUE ($MM) | ||||||||||
| Discount Rate | ||||||||||
| Description | Undiscounted | 5 | % | 10 | % | 15 | % | 20 | % | |
| Proved producing | 9,560 | 7,042 | 5,700 | 4,851 | 4,258 | |||||
| Proved non-producing | 5,753 | 3,924 | 2,804 | 2,070 | 1,563 | |||||
| Total proved(2) | 15,313 | 10,966 | 8,505 | 6,921 | 5,821 | |||||
| Probable | 10,087 | 6,157 | 4,314 | 3,268 | 2,601 | |||||
| Total proved plus probable(2) | 25,400 | 17,123 | 12,819 | 10,189 | 8,423 | |||||
| AFTER TAX NET PRESENT VALUE ($MM) | ||||||||||
| Discount Rate | ||||||||||
| Description | Undiscounted | 5 | % | 10 | % | 15 | % | 20 | % | |
| Proved producing | 8,855 | 6,612 | 5,399 | 4,622 | 4,076 | |||||
| Proved non-producing | 4,417 | 2,902 | 1,981 | 1,382 | 972 | |||||
| Total proved(2) | 13,273 | 9,514 | 7,379 | 6,004 | 5,048 | |||||
| Probable | 7,253 | 4,426 | 3,097 | 2,338 | 1,852 | |||||
| Total proved plus probable(2) | 20,526 | 13,940 | 10,476 | 8,342 | 6,900 | |||||
| (1) | Based on GLJ”s January 1, 2013, escalated price forecast. |
| (2) | Numbers may not add due to rounding. |
Before Tax Net Asset Value Per Share, Fully Diluted, Utilizing Independent Engineering Escalated Pricing
| 2012 | 2011 | 2010 | 2009 | 2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||||
| PV 0% | $ | 68.39 | $ | 71.39 | $ | 71.38 | $ | 72.01 | $ | 80.66 | $ | 61.03 | $ | 34.08 | $ | 21.99 | $ | 16.19 | ||||||||
| PV 5% | $ | 46.49 | $ | 49.81 | $ | 47.65 | $ | 46.91 | $ | 49.30 | $ | 40.21 | $ | 21.61 | $ | 15.12 | $ | 11.22 | ||||||||
| PV 10% | $ | 35.11 | $ | 38.42 | $ | 36.02 | $ | 35.08 | $ | 34.97 | $ | 30.05 | $ | 15.70 | $ | 11.45 | $ | 8.56 | ||||||||
| PV 15% | $ | 28.15 | $ | 31.35 | $ | 29.10 | $ | 28.27 | $ | 26.85 | $ | 24.04 | $ | 12.27 | $ | 9.10 | $ | 6.85 |
Reserves Reconciliation
(Escalated Pricing)
Gross Reserves (1)
For the year ended December 31, 2012
| CRUDE OIL AND NGL (Mbbl) | NATURAL GAS (MMscf) | BOE (Mboe) | |||||||||||||||||||||||
| Proved | Probable | Total | Proved | Probable | Total | Proved | Probable | Total | |||||||||||||||||
| Opening Balance January 1, 2012 | 258,713 | 132,562 | 391,274 | 133,910 | 67,112 | 201,021 | 281,031 | 143,747 | 424,778 | ||||||||||||||||
| Acquired | 90,123 | 41,927 | 132,051 | 66,872 | 34,132 | 101,004 | 101,268 | 47,616 | 148,884 | ||||||||||||||||
| Disposed | (648 | ) | (220 | ) | (867 | ) | (13,369 | ) | (5,042 | ) | (18,411 | ) | (2,876 | ) | (1,060 | ) | (3,936 | ) | |||||||
| Production | (32,832 | ) | – | (32,832 | ) | (19,868 | ) | – | (19,868 | ) | (36,143 | ) | – | (36,143 | ) | ||||||||||
| Development | 29,510 | 23,886 | 53,396 | 13,771 | 10,979 | 24,750 | 31,805 | 25,715 | 57,520 | ||||||||||||||||
| Technical revisions | 21,664 | (7,618 | ) | 14,047 | 21,737 | 139 | 21,876 | 25,287 | (7,595 | ) | 17,692 | ||||||||||||||
| Closing Balance December 31, 2012 (2) | 366,531 | 190,538 | 557,068 | 203,053 | 107,319 | 310,373 | 400,373 | 208,424 | 608,797 | ||||||||||||||||
| (1) | Based on GLJ”s January 1, 2013, escalated price forecast. “Gross reserves” are the Company”s working-interest share before deduction of any royalties and without including any royalty interests of the Company. |
| (2) | Numbers may not add due to rounding. |
Finding, Development and Acquisition Costs (Excluding Future Development Capital)
For the year ended December 31, 2012
| CAPITAL EXPENDITURES (1)(4) | RESERVES (3) | FINDING, DEVELOPMENT AND ACQUISITION COSTS(1)(2) | |||||||||||||
| Total Proved | Proved Plus Probable | Proved | Proved Plus Probable | ||||||||||||
| $000 | % | Mboe | % | Mboe | % | $/boe | $/boe | ||||||||
| Exploration, development and revisions |
1,488,947 |
33 |
57,092 |
37 |
75,212 |
34 |
26.08 |
19.80 |
|||||||
| Acquisitions, net of dispositions | 3,055,258 | 67 | 98,392 | 63 | 144,948 | 66 | 31.05 | 21.08 | |||||||
| Total | 4,544,205 | 100 | 155,484 | 100 | 220,160 | 100 | 29.23 | 20.64 | |||||||
| (1) | Exploration, Development and Revisions exclude the change in estimated FDC during 2012. These costs would add $397.1 million and $560.7 million to the proved and proved plus probable reserves categories, respectively. Including these changes, the proved and proved plus probable F&D costs are $33.04 and $27.25 per boe, respectively. |
| (2) | Including the change in estimated FDC, FD&A costs are $31.78 per proved boe and $23.19 per proved plus probable boe. |
| (3) | Gross Company interest reserves are used in this calculation (working interest reserves, before deduction of any royalties and without including any royalty interests of the Company). |
| (4) | The capital expenditures include the announced purchase price of corporate acquisitions rather than the amounts allocated to property, plant and equipment for accounting purposes. The capital expenditures also exclude capitalized administration costs and transaction costs. |
F&D and FD&A Costs, $/boe (1)
|
2012 |
2011 |
3 Years Ended Dec. 31, 2012 Weighted Average | |||||||
| F&D | |||||||||
| Total Proved Cost, excluding change in FDC | $ | 26.08 | $ | 23.06 | $ | 23.58 | |||
| Total Proved Cost, including change in FDC | $ | 33.04 | $ | 33.35 | $ | 32.97 | |||
| Total Proved plus Probable Cost, excluding change in FDC | $ | 19.80 | $ | 18.52 | $ | 18.64 | |||
| Total Proved plus Probable Cost, including change in FDC | $ | 27.25 | $ | 28.67 | $ | 28.19 | |||
| FD&A | |||||||||
| Total Proved Cost, excluding change in FDC | $ | 29.23 | $ | 25.20 | $ | 30.42 | |||
| Total Proved Cost, including change in FDC | $ | 31.78 | $ | 34.87 | $ | 35.31 | |||
| Total Proved plus Probable Cost, excluding change in FDC | $ | 20.64 | $ | 19.95 | $ | 22.13 | |||
| Total Proved plus Probable Cost, including change in FDC | $ | 23.19 | $ | 29.35 | $ | 26.70 | |||
| (1) | The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. |
OUTLOOK
Crescent Point continues to execute its business plan of creating sustainable value-added growth in reserves, production and cash flow through management”s integrated strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties in United States and Canada.
2012 was one of Crescent Point”s most active and successful years to date. Not only did the Company achieve a new production record and deliver the eleventh consecutive year of growth in reserves, cash flow and production, but it continued to aggressively consolidate its key resource plays, such as the Bakken, Shaunavon and Beaverhill Lake. Through the Ute acquisition in northeast Utah, Crescent Point also established the Uinta Basin as a new core resource play.
Crescent Point”s aggressive consolidation of resource plays where multi-stage fracture stimulation can be implemented has been a key factor in positioning the Company well for future growth. The Company was an early mover in this regard and has now assembled a solid portfolio of high-quality resource play assets in the United States and in western Canada. In 2013, the Company expects to focus on executing organic growth projects across its asset base. Advancing the development of new techniques and concepts is also a priority, as the Company believes that even slight improvements in technology can have big effects on recovery factors when leveraged across its large oil-in-place pools.
As well, Crescent Point expects to continue to develop its expanding waterflood programs in the Bakken, Shaunavon and Viking resource plays, which continue to show positive results. The Company also expects to initiate waterflood programs in Beaverhill Lake and the Uinta Basin.
Crescent Point plans to increase crude oil shipments through its Stoughton, Dollard and Alberta rail facilities, which are providing access to new markets and providing a hedge against price differential volatility. Current capacity at the facilities is approximately 45,000 bbl/d, 5,000 bbl/d and 3,000 bbl/d, respectively. In addition, Crescent Point has more than 15,000 bbl/d of its oil production contracted to rail markets on a firm basis through mid-2014, providing fixed price differentials from WTI. Combined with financial WTI derivatives, these selling prices are fixed at levels greater than CDN$90.00/bbl.
Funds flow from operations for 2013 is expected to be approximately $1.73 billion ($4.48 per share – diluted), based on forecast pricing of US$90.00 per barrel WTI, Cdn$3.50 per mcf AECO gas and a US$/Cdn$1.00 exchange rate.
The Company”s balance sheet remains strong, with projected average net debt to 12-month cash flow of approximately 1.0 times and significant unutilized credit capacity.
Crescent Point continues to implement its disciplined WTI hedging strategy to provide increased certainty over cash flow and dividends. As at March 5, 2013, the Company had hedged 55 percent, 40 percent, 21 percent and 3 percent of its expected oil production, net of royalty interest, for the balance of 2013, 2014, 2015 and the first half of 2016, respectively. Average quarterly hedge prices range from Cdn$90 per bbl to Cdn$93 per bbl.
Crescent Point”s management believes that with the Company”s high-quality reserve base and development drilling inventory, excellent balance sheet and solid risk management program, the Company is well-positioned to continue generating strong operating and financial results through 2013 and beyond.
2013 GUIDANCE
The Company”s guidance for 2013 is as follows:
| Production | ||
| Oil and NGL (bbls/d) | 102,000 | |
| Natural gas (mcf/d) | 60,000 | |
| Total (boe/d) | 112,000 | |
| Exit (boe/d) | 114,000 | |
| Funds flow from operations ($000) | 1,730,000 | |
| Funds flow per share – diluted ($) | 4.48 | |
| Cash dividends per share ($) | 2.76 | |
| Capital expenditures (1) | ||
| Drilling and completions ($000) | 1,170,000 | |
| Facilities, land and seismic ($000) | 180,000 | |
| Total ($000) | 1,350,000 | |
| Pricing | ||
| Crude oil – WTI (US$/bbl) | 90.00 | |
| Crude oil – WTI (Cdn$/bbl) | 90.00 | |
| Corporate oil differential (%) | 14 | |
| Natural gas – AECO (Cdn$/mcf) | 3.50 | |
| Exchange rate (US$/Cdn$) | 1.00 | |
| (1) | The projection of capital expenditures excludes acquisitions, which are separately considered and evaluated. |
ON BEHALF OF THE BOARD OF DIRECTORS
Scott Saxberg
President and Chief Executive Officer
March 14, 2013
Non-GAAP Financial Measures
Throughout this press release, the Company uses the terms “funds flow from operations”, “funds flow from operations per share – diluted”, “net debt”, “netback”, “payout ratio” and “payout ratio per share – diluted.” These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.
Funds flow from operations is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures. Funds flow from operations per share – diluted is calculated as funds flow from operations divided by the number of weighted average diluted shares outstanding. Management utilizes funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Funds flow from operations as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.
The following table reconciles the cash flow from operating activities to funds flow from operations:
| ($000s) | 2012 | 2011 | % Change | |||
| Cash flow from operating activities | 1,543,943 | 1,322,971 | 17 | |||
| Changes in non-cash working capital | 29,375 | (36,078 | ) | 181 | ||
| Transaction costs | 16,436 | 2,679 | 514 | |||
| Decommissioning expenditures | 12,096 | 3,685 | 228 | |||
| Funds flow from operations | 1,601,850 | 1,293,257 | 24 | |||
Net debt is calculated as current liabilities plus long-term debt less current assets and long-term investments, but excludes derivative asset, derivative liability and unrealized foreign exchange on translation of US dollar senior guaranteed notes. Management utilizes net debt as a key measure to assess the liquidity of the Company.
The following table reconciles long-term debt to net debt:
| ($000s) | 2012 | 2011 | % Change | ||||
| Long-term debt | 1,474,589 | 1,099,028 | 34 | ||||
| Current liabilities | 698,420 | 681,279 | 3 | ||||
| Current assets | (329,711 | ) | (308,515 | ) | 7 | ||
| Long-term investments | (84,906 | ) | (151,917 | ) | (44 | ) | |
| Excludes: | |||||||
| Derivative asset | 19,457 | 10,216 | 90 | ||||
| Derivative liability | (15,349 | ) | (101,997 | ) | (85 | ) | |
| Unrealized foreign exchange on translation of US dollar senior guaranteed notes | (2,176 | ) | (7,950 | ) | (73 | ) | |
| Net debt | 1,760,324 | 1,220,144 | 44 | ||||
Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.
Payout ratio and payout ratio per share – diluted are calculated on a percentage basis as dividends paid or declared (including the value of dividends issued pursuant to the Company”s dividend reinvestment plan) divided by funds flow from operations. Payout ratio is used by management to monitor the dividend policy and the amount of funds flow from operations retained by the Company for capital reinvestment.
Reserves Data
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company”s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51- 101. All of the required information will be contained in the Company”s Annual Information Form for the year ended December 31, 2012, which will be filed on SEDAR (accessible at www.sedar.com) on March 14, 2013.
Forward-Looking Statements
Certain statements contained in this press release constitute forward-looking statements. All forward-looking statements are based on Crescent Point”s beliefs and assumptions based on information available at the time the assumption was made. The use of any of the words “could”, “should”, “can”, “anticipate”, “expect”, “believe”, “will”, “may”, “projected”, “sustain”, “continues”, “strategy”, “potential”, “projects”, ” grow”, “take advantage”, “estimate”, “well-positioned” and similar expressions are intended to identify forward-looking statements. By their nature, such forward-looking 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 statements. Crescent Point believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. These statements speak only as of the date of this press release or, if applicable, as of the date specified in those documents specifically referenced herein.
In particular, this press release contains forward-looking statements pertaining to the following: the performance characteristics of Crescent Point”s oil and natural gas properties; oil and natural gas production levels; capital expenditure programs; drilling programs; the future cost to drill wells in North Dakota; the use of acid stimulation techniques; the initiation and ongoing development of planned and existing waterflood programs; the quantity of Crescent Point”s oil and natural gas reserves and anticipated future cash flows from such reserves; the quantity of drilling locations in inventory; projections of commodity prices and costs; supply and demand for oil and natural gas; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; expected debt levels and credit facilities; expected pipeline capacity additions; facility expansion and construction plans; expected deliveries by rail; and treatment under governmental regulatory regimes and the state of certain governmental approvals.
By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks discussed in our annual information form under “Risk Factors” and our Management”s Discussion and Analysis for the year ended December 31, 2012, under the headings “Risk Factors” and “Forward-Looking Information.” The material assumptions are disclosed in the Management”s Discussion and Analysis for the year ended December 31, 2012, under the headings “Dividends”, “Capital Expenditures”, “Decommissioning Liability”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Future Changes in Accounting Policies” and “Outlook.” The actual results could differ materially from those anticipated in these forward-looking statements as a result of the material risks set forth under the noted headings, which include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry.
Barrels of oil equivalent (“boes”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
Additional information on these and other factors that could affect Crescent Point”s operations or financial results are included in Crescent Point”s reports on file with Canadian securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise and Crescent Point undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law.
Crescent Point is a conventional oil and gas producer with assets strategically focused in properties comprised of high-quality, long-life, operated light and medium oil and natural gas reserves in United States and Canada.
Crescent Point shares are traded on the Toronto Stock Exchange under the symbol CPG.
Crescent Point Energy Corp.
Greg Tisdale
Chief Financial Officer
(403) 693-0020 or Toll-free (US & Canada): 888-693-0020
(403) 693-0070
Crescent Point Energy Corp.
Trent Stangl
Vice President Marketing and Investor Relations
(403) 693-0020 or Toll-free (US & Canada): 888-693-0020
(403) 693-0070
Crescent Point Energy Corp.
Suite 2800, 111-5th Avenue S.W.
Calgary, Alberta T2P 3Y6
www.crescentpointenergy.com