CALGARY, ALBERTA–(Marketwired – March 11, 2015) – Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX:CPG) (NYSE:CPG) is pleased to announce its operating and financial results for the year ended December 31, 2014. The Company also announces that its audited financial statements and management’s discussion and analysis for the year ended December 31, 2014, will be available shortly on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml and on Crescent Point’s website at www.crescentpointenergy.com. A printed copy of these documents is available, free of charge, by contacting Crescent Point’s investor relations line at 1-855-767-6923 or by requesting it through Crescent Point’s website.
| FINANCIAL AND OPERATING HIGHLIGHTS | ||||||||||||
| Three months ended December 31 |
Year ended December 31 |
|||||||||||
| (Cdn$000s except shares, per share and per boe amounts) | 2014 | 2013 | % Change | 2014 | 2013 | % Change | ||||||
| Financial | ||||||||||||
| Funds flow from operations (1) | 572,868 | 533,310 | 7 | 2,408,045 | 2,047,817 | 18 | ||||||
| Per share (1) (2) | 1.28 | 1.35 | (5) | 5.72 | 5.28 | 8 | ||||||
| Net income (loss) (3) | 121,359 | (13,723) | (984) | 508,894 | 144,876 | 251 | ||||||
| Per share (2) | 0.27 | (0.03) | (1,000) | 1.21 | 0.37 | 227 | ||||||
| Adjusted net earnings from operations (1) | (12,424) | 150,912 | (108) | 546,663 | 558,384 | (2) | ||||||
| Per share (1) (2) | (0.03) | 0.38 | (108) | 1.30 | 1.44 | (10) | ||||||
| Dividends paid or declared | 310,461 | 274,797 | 13 | 1,174,628 | 1,081,551 | 9 | ||||||
| Per share (2) | 0.69 | 0.69 | – | 2.76 | 2.76 | – | ||||||
| Payout ratio (%) (1) (4) | 54 | 52 | 2 | 49 | 53 | (4) | ||||||
| Per share (%) (1) (2) (4) | 54 | 51 | 3 | 48 | 52 | (4) | ||||||
| Net debt (1) | 3,191,109 | 2,077,078 | 54 | 3,191,109 | 2,077,078 | 54 | ||||||
| Net debt to funds flow from operations (1) (5) | 1.3 | 1.0 | 30 | 1.3 | 1.0 | 30 | ||||||
| Capital acquisitions (net) (6) | 16,875 | 20,109 | (16) | 2,192,991 | 118,267 | 1,754 | ||||||
| Development capital expenditures (7) | 698,256 | 485,460 | 44 | 2,095,610 | 1,724,507 | 22 | ||||||
| Decommissioning and environmental expenditures (7) | 10,038 | 4,272 | 135 | 38,699 | 15,008 | 158 | ||||||
| Weighted average shares outstanding (mm) | ||||||||||||
| Basic | 445.0 | 393.8 | 13 | 418.7 | 386.3 | 8 | ||||||
| Diluted | 446.8 | 395.3 | 13 | 421.1 | 387.7 | 9 | ||||||
| Operating | ||||||||||||
| Average daily production | ||||||||||||
| Crude oil and NGLs (bbls/d) | 140,767 | 115,971 | 21 | 128,458 | 109,129 | 18 | ||||||
| Natural gas (mcf/d) | 78,332 | 70,017 | 12 | 74,070 | 66,952 | 11 | ||||||
| Total (boe/d) | 153,822 | 127,641 | 21 | 140,803 | 120,288 | 17 | ||||||
| Average selling prices (8) | ||||||||||||
| Crude oil and NGLs ($/bbl) | 69.51 | 82.81 | (16) | 86.94 | 86.32 | 1 | ||||||
| Natural gas ($/mcf) | 4.17 | 3.90 | 7 | 4.95 | 3.61 | 37 | ||||||
| Total ($/boe) | 65.74 | 77.38 | (15) | 81.92 | 80.32 | 2 | ||||||
| Netback ($/boe) | ||||||||||||
| Oil and gas sales | 65.74 | 77.38 | (15) | 81.92 | 80.32 | 2 | ||||||
| Royalties | (11.45) | (13.92) | (18) | (14.60) | (14.67) | – | ||||||
| Operating expenses | (12.61) | (10.64) | 19 | (12.60) | (11.50) | 10 | ||||||
| Transportation | (2.26) | (2.15) | 5 | (2.29) | (2.17) | 6 | ||||||
| Netback prior to realized derivatives | 39.42 | 50.67 | (22) | 52.43 | 51.98 | 1 | ||||||
| Realized gain (loss) on derivatives | 4.46 | (2.20) | (303) | (2.04) | (2.07) | (1) | ||||||
| Netback (1) | 43.88 | 48.47 | (9) | 50.39 | 49.91 | 1 | ||||||
| (1) | Funds flow from operations, adjusted net earnings from operations, payout ratio, net debt, net debt to funds flow from operations 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 for further information. |
| (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, 2014 includes before tax impairment loss of $588.2 million. Net income (loss) for the three months and year ended December 31, 2013 includes before tax impairment loss of $98.3 million. |
| (4) | Payout ratio is calculated as dividends paid or declared (including the value of dividends paid pursuant to the Company’s dividend reinvestment plans and share dividend plan) divided by funds flow from operations. |
| (5) | Net debt to funds flow from operations is calculated as the period end net debt divided by the sum of funds flow from operations for the trailing four quarters. |
| (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 includes environmental emission reduction expenditures, which are also included in development capital expenditures in the table above. |
| (8) | The average selling prices reported are before realized derivatives and transportation. |
Fourth quarter 2014 solidified yet another year of successful execution of Crescent Point’s integrated business strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties. Crescent Point continued to advance the development of its core Bakken, Torquay, Shaunavon and Uinta Basin resource plays and capitalized on several acquisitions throughout the year that further strengthened its large drilling location inventory. The Company’s advancements in technology continued to support growth in recovery factors and reserves during 2014. Crescent Point continues to execute on its commitment to maintaining a financially sound organization while maximizing shareholder return through a combination of long-term growth and dividend income.
FOURTH QUARTER 2014 HIGHLIGHTS
2014 HIGHLIGHTS
OPERATIONS REVIEW
Fourth Quarter Operations Summary
Crescent Point grew production per share by approximately seven percent over fourth quarter 2013. Production averaged 153,822 boe/d in the quarter, which was weighted 92 percent to light and medium crude oil and liquids. The Company’s strong organic production performance during the quarter was driven by its successful drilling program, the Company’s ongoing waterflood success and continued strong results from cemented liner completion techniques.
In 2014, Crescent Point was the top operator in Canada ranked by development and exploratory metres drilled. The Company finished the year with 1.63 million metres drilled, which is approximately 200,000 metres more than the next operator.
During fourth quarter, the Company spent $564.3 million on drilling and development activities, drilling 306 (222.2 net) wells with a 100 percent success rate. Crescent Point also spent $134.0 million on land, seismic and facilities, for total capital expenditures of $698.3 million.
Drilling Results
The following tables summarize our drilling results for the three months and year ended December 31, 2014:
| Three months ended December 31, 2014 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success |
| Southeast Saskatchewan & Manitoba | – | 149 | – | – | 1 | 150 | 110.1 | 100 |
| Southwest Saskatchewan | – | 60 | – | – | – | 60 | 58.9 | 100 |
| Alberta and West Central SK | – | 36 | – | – | – | 36 | 20.0 | 100 |
| United States (1) | – | 60 | – | – | – | 60 | 33.2 | 100 |
| Total | – | 305 | – | – | 1 | 306 | 222.2 | 100 |
| Year ended December 31, 2014 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success |
| Southeast Saskatchewan and Manitoba | – | 419 | – | 2 | 7 | 428 | 352.2 | 100 |
| Southwest Saskatchewan | – | 189 | – | 3 | – | 192 | 180.8 | 100 |
| Alberta and West Central SK | – | 93 | – | 2 | – | 95 | 58.1 | 100 |
| United States (1) | – | 199 | – | – | – | 199 | 100.3 | 100 |
| Total | – | 900 | – | 7 | 7 | 914 | 691.4 | 100 |
| (1) The net well count is subject to final working interest determination. | ||||||||
Southeast Saskatchewan and Manitoba
In fourth quarter, Crescent Point continued to successfully execute its large capital program in southeast Saskatchewan and Manitoba. Successful results in the Company’s Viewfield Bakken and Flat Lake Torquay resource plays in southeast Saskatchewan continue to be strong drivers of Crescent Point’s production growth.
The Company is pleased with drilling results to date in the Torquay play at Flat Lake, having drilled 16 (16.0 net) oil wells during the quarter. Crescent Point is seeing positive results with step-out wells that continue to delineate the area. The Company has been strategic in its consolidation and organic development of the play and, since year-end 2013, has approximately doubled 2P reserves to 33.6 MMboe. In mid-2015, Crescent Point expects it will begin a waterflood pilot project in the Flat Lake area targeting the Torquay zone. During the quarter, the Company experimented with the amount and types of fracture-stimulation fluid used to complete wells in the area. Results have been encouraging to date and the Company believes that the refined fracture stimulation process has the potential to increase economically recoverable reserves across the resource play.
During fourth quarter, Crescent Point drilled 61 (56.7 net) oil wells in the Viewfield Bakken resource play. The Viewfield Bakken play, which is in the free cash flow stage of its life cycle, continues to be optimized through down-spacing, advancements in technology and continued cost control. The Company continues to refine its one-mile, 25-stage cemented liner completion technique and to expand its waterflood program in the play, which are driving strong rates of return and further contributing to the significant free cash flow in the Viewfield Bakken play.
Based on results to date, the Company estimates it has reduced decline rates by up to 10 percent in waterflood-affected areas compared to areas not under waterflood. Over the past two years, Crescent Point’s independent reserve evaluators have assigned the Company’s developed waterflood patterns a 26 percent increase in 2P ultimate recoverable reserves over the previously assigned 2P primary ultimate recoverable reserves, which equates to a 2P recovery factor increase of four percent due to waterflood performance. Despite the recent downturn in commodity prices, the Company is committed to converting 30 producing wells to injection wells, in line with previous years.
In addition, the Company has begun to utilize a closable sliding sleeve during the fracture stimulation of wells drilled in the Viewfield Bakken resource play, as well as the Shaunavon resource play. The closable sleeve has the potential to increase the efficiency and productivity of the Company’s waterfloods in both the Viewfield Bakken and Shaunavon resource plays. This technology will allow increased control over water displacement and, in combination with the waterflood, could lead to significant increases in recovery factor. The closable sleeve also has the potential to lower capital costs by reducing the frequency of well clean-outs caused by proppant flowing back into the well. Crescent Point is initially using this completion technique in its Viewfield Bakken and Shaunavon resource plays, with plans to expand implementation across all of the Company’s areas of operation.
During fourth quarter, the Company also drilled 72 (36.4 net) oil wells in other areas of southeast Saskatchewan and Manitoba. Crescent Point’s conventional and unconventional drilling location inventory in southeast Saskatchewan and Manitoba continues to provide the Company with a source of low-risk, high-netback opportunities to generate strong future cash flows.
Southwest Saskatchewan
Crescent Point continued to expand its waterflood program in the Shaunavon resource play during fourth quarter and currently has 38 active horizontal water injection wells in operation. Based on results to date, the Company estimates it has reduced decline rates by more than 10 percent in waterflood-affected areas in the play, compared to areas not under waterflood.
During fourth quarter, the Company drilled 58 (57.8 net) oil wells in the Shaunavon resource play. The Company executed the largest Shaunavon drilling program in Company history in 2014, and continues to refine its cemented liner completion technology with positive production response.
In fourth quarter 2014, Crescent Point continued to execute its Battrum/Cantuar drilling program, drilling a total of 2 (1.1 net) horizontal oil wells in the Cantuar area. The Company is pleased with results to date, as the wells have come on production at or better than the anticipated rates. On September 1, 2014, Crescent Point assumed full operatorship of the Cantuar Unit. Production has increased by approximately 26 percent since then, largely as a result of the Company’s drilling and production optimization practices. Both the Cantuar and Battrum assets continue to contribute significant free cash flow to the Company.
Alberta and West Central Saskatchewan
Crescent Point and its partner continue to expand the waterflood pilot in the Beaverhill Lake play, with four injection wells now in operation. The Company’s first operated waterflood pilot is on schedule to be in operation in first quarter 2015.
During the quarter, the Company continued its development program in the Dodsland area in the Saskatchewan Viking play, drilling 33 (18.8 net) oil wells and refining its 19-stage cemented liner completion technology. Crescent Point is pleased with production to date, as the wells have been coming on production at, or better than, forecasted rates.
United States
During fourth quarter, the Company participated in the drilling of 53 (30.2 net) oil wells in the Uinta Basin, achieving a 100 percent success rate.
Crescent Point continues to be pleased with early-stage results to date in its Uinta Basin resource play. During the quarter, the Company continued to implement its operated horizontal drilling program in both the Uteland Butte and Douglas Creek zones. Production is expected to begin from these two initial wells during first quarter 2015.
The Company continues to gain incremental oil production with minimal cost from bypassed pay zones targeted through its ongoing vertical recompletion program. New vertical well completion techniques are also being tested in the area to further increase fracture stimulation efficiency, production rates and ultimate recoveries. The 3-D seismic program, which covers a large portion of the Company’s operated lands in the Randlett area, is now complete. Processing of the data is expected to begin in first quarter 2015. During 2014, Crescent Point continued to advance its Uinta Basin resource play resulting in continued reserve growth. Since entering the Uinta Basin in late 2012, the Company has increased total 2P reserves by 58 percent.
Crescent Point has received state regulatory approval for a second waterflood injection pilot in the Randlett area of the Uinta Basin. Water injection in both pilots is expected to begin in 2016.
During the quarter, the Company completed a 20-acre down-spacing pilot in the area to test maximum producing well density. Crescent Point is encouraged by results to date from the down-spacing pilot, as it has the potential to significantly increase the drilling location inventory in the area.
The Company has been successful in improving capital efficiencies as well as lowering its capital costs, with expectations that further savings can be achieved throughout the year. Increased market access has also resulted in more favorable differentials.
During fourth quarter, the Company also participated in the drilling of 7 (3.0 net) oil wells in North Dakota, targeting both the Bakken and Three Forks formations. The Company continues to be pleased with results to date in both formations.
RESERVES
The Company’s reserves were independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) and Sproule Associates Ltd. (“Sproule”) as at December 31, 2014, and were aggregated by GLJ. The reserves evaluation and reporting was conducted in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and in National Instrument 51-101 Standards for Disclosure of Oil and Gas Activities (“NI 51-101”).
In 2014, Crescent Point increased 2P reserves by 97.1 MMboe, excluding reserves added through acquisitions. This includes approximately 79.1 MMboe in its core Bakken, Torquay, Shaunavon and Uinta Basin resource plays and represents the thirteenth consecutive year of strong positive technical and development reserves additions.
In total, including acquisitions, the Company increased 2P reserves by 195.0 MMboe, excluding production, and grew 2P reserves to 807.4 MMboe.
Summary of Reserves
As at December 31, 2014 (1) (2) (3)
| Light and Medium Oil (Mbbls) |
Heavy Oil (Mbbls) |
Natural Gas (MMcf) |
Natural Gas Liquids (Mbbls) |
Total Oil Equivalent (Mboe)(4) |
|||||||
| Reserves Category | Company Gross | Company Net | Company Gross | Company Net | Company Gross | Company Net | Company Gross | Company Net | Company Gross | Company Net | |
| Proved Developed Producing | 266,145 | 235,201 | 515 | 519 | 122,970 | 112,833 | 19,436 | 17,904 | 306,591 | 272,430 | |
| Proved Developed Non-Producing | 10,749 | 9,648 | 367 | 347 | 8,545 | 7,700 | 815 | 732 | 13,355 | 12,011 | |
| Proved Undeveloped | 175,824 | 158,500 | 132 | 119 | 95,273 | 85,109 | 16,343 | 14,673 | 208,178 | 187,476 | |
| Total Proved (4) | 452,719 | 403,349 | 1,014 | 985 | 226,788 | 205,642 | 36,594 | 33,309 | 528,124 | 471,917 | |
| Total Probable | 238,868 | 209,166 | 739 | 673 | 125,650 | 112,560 | 18,713 | 16,730 | 279,262 | 245,329 | |
| Total Proved plus Probable (4) | 691,587 | 612,514 | 1,753 | 1,659 | 352,437 | 318,202 | 55,307 | 50,040 | 807,386 | 717,246 | |
| (1) | Based on GLJ’s January 1, 2015, 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. |
| (3) | “Net Reserves” are the total Company’s interest share after deducting royalties and including any royalty interest. |
| (4) | Numbers may not add due to rounding. |
Summary of Before and After Tax Net Present Values
As at December 31, 2014 (1)
| Before Tax Net Present Value ($MM) | After Tax Net Present Value ($MM) | |||||||||
| Discount Rate | Discount Rate | |||||||||
| Reserves Category | 0% | 5% | 10% | 15% | 20% | 0% | 5% | 10% | 15% | 20% |
| Proved Developed Producing | 13,185 | 9,667 | 7,657 | 6,367 | 5,473 | 11,423 | 8,459 | 6,745 | 5,639 | 4,868 |
| Proved Developed Non-Producing | 539 | 408 | 326 | 270 | 231 | 406 | 306 | 243 | 200 | 170 |
| Proved Undeveloped | 6,601 | 4,159 | 2,742 | 1,853 | 1,263 | 5,057 | 3,058 | 1,904 | 1,186 | 715 |
| Total Proved (2) | 20,325 | 14,235 | 10,725 | 8,490 | 6,966 | 16,886 | 11,822 | 8,891 | 7,025 | 5,753 |
| Total Probable | 14,107 | 8,185 | 5,454 | 3,945 | 3,012 | 10,208 | 5,898 | 3,917 | 2,819 | 2,137 |
| Total Proved plus Probable (2) | 34,432 | 22,420 | 16,178 | 12,436 | 9,978 | 27,094 | 17,720 | 12,808 | 9,844 | 7,890 |
| (1) | Based on GLJ’s January 1, 2015, 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
| 2014 (1) (2) (3) |
2013 | 2012 | 2011 | 2010 | 2009 | 2008 | 2007 | 2006 | 2005 | |
| PV 0% | $75.33 | $75.69 | $68.39 | $71.39 | $71.38 | $72.01 | $80.66 | $61.03 | $34.08 | $21.99 |
| PV 5% | $48.62 | $51.04 | $46.49 | $49.81 | $47.65 | $46.91 | $49.30 | $40.21 | $21.61 | $15.12 |
| PV 10% | $34.74 | $38.13 | $35.11 | $38.42 | $36.02 | $35.08 | $34.97 | $30.05 | $15.70 | $11.45 |
| PV 15% | $26.41 | $30.25 | $28.15 | $31.35 | $29.10 | $28.27 | $26.85 | $24.04 | $12.27 | $9.10 |
| (1) | Based on GLJ’s January 1, 2015, escalated price forecast. |
| (2) | Based on 450.2 million shares fully-diluted. |
| (3) | Net debt of $3.2 billion as at December 31, 2014. |
Reserves Reconciliation
Gross Reserves (1)
| Light and Medium Oil (Mbbls) |
Heavy Oil (Mbbls) |
Natural Gas Liquids (Mbbls) |
|||||||
| Factors | Proved | Probable | Proved plus Probable | Proved | Probable | Proved plus Probable | Proved | Probable | Proved plus Probable |
| January 1, 2014 | 376,683 | 201,896 | 578,580 | 1,274 | 672 | 1,947 | 19,035 | 9,222 | 28,257 |
| Extensions and Improved Recovery | 45,827 | 25,014 | 70,840 | – | – | – | 3,299 | 2,541 | 5,839 |
| Technical Revisions | 14,826 | (23,152) | (8,326) | (160) | 64 | (96) | 16,137 | 6,411 | 22,548 |
| Acquisitions | 60,267 | 33,621 | 93,887 | – | – | – | 769 | 553 | 1,322 |
| Dispositions | (53) | (25) | (78) | – | – | – | (6) | (3) | (8) |
| Economic Factors | (577) | 1,514 | 937 | – | 2 | 2 | (107) | (10) | (117) |
| Production | (44,254) | – | (44,254) | (100) | – | (100) | (2,533) | – | (2,533) |
| December 31, 2014 (2) | 452,719 | 238,868 | 691,587 | 1,014 | 739 | 1,753 | 36,594 | 18,713 | 55,307 |
| Natural Gas (MMcf) | Total Oil Equivalent (Mboe) | |||||
| Factors | Proved | Probable | Proved plus Probable | Proved | Probable | Proved plus Probable |
| January 1, 2014 | 214,647 | 115,200 | 329,848 | 432,767 | 230,990 | 663,758 |
| Extensions and Improved Recovery | 19,783 | 12,334 | 32,117 | 52,424 | 29,609 | 82,033 |
| Technical Revisions | 11,302 | (7,530) | 3,771 | 32,685 | (17,930) | 14,755 |
| Acquisitions | 10,614 | 6,366 | 16,979 | 62,805 | 35,233 | 98,039 |
| Dispositions | (32) | (15) | (47) | (64) | (30) | (94) |
| Economic Factors | (2,492) | (705) | (3,197) | (1,100) | 1,388 | 288 |
| Production | (27,036) | – | (27,036) | (51,393) | – | (51,393) |
| December 31, 2014 (2) | 226,788 | 125,650 | 352,437 | 528,124 | 279,262 | 807,386 |
| (1) | Based on GLJ’s January 1, 2015, 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
| Finding & Development | Acquisitions (Net of Dispositions) | FD&A Subtotal | Change in FDC | F&D Total (incl. change in FDC) | FD&A Total (incl. change in FDC) | |||
| Capital ($M) (1) | ||||||||
| Total Proved plus Probable | 2,095,610 | 2,207,776 | 4,303,386 | 51,024 | 2,146,634 | 4,354,410 | ||
| Total Proved | 2,095,610 | 2,207,776 | 4,303,386 | (16,673) | 2,078,937 | 4,286,713 | ||
| Reserves (Mboe) (2) | ||||||||
| Total Proved plus Probable | 97,076 | 97,945 | 195,021 | – | 97,076 | 195,021 | ||
| Total Proved | 84,009 | 62,741 | 146,750 | – | 84,009 | 146,750 |
| (1) | 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. |
| (2) | 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). |
| Excluding change in FDC | Including change in FDC | |||||
| ($/boe, except recycle ratios) | ($/boe, except recycle ratios) | |||||
| 2014 | 2013 | 3 Years Ended Dec. 31, 2014 (Weighted Avg.) | 2014 | 2013 | 3 Years Ended Dec. 31, 2014 (Weighted Avg.) | |
| F&D Cost | ||||||
| Total Proved plus Probable | $21.59 | $18.42 | $19.97 | $22.11 | $20.09 | $22.85 |
| Total Proved | $24.95 | $23.84 | $24.87 | $24.75 | $21.51 | $25.87 |
| F&D Recycle Ratio (1) | ||||||
| Total Proved plus Probable | 2.4 | 2.8 | 2.6 | 2.4 | 2.6 | 2.2 |
| Total Proved | 2.1 | 2.2 | 2.1 | 2.1 | 2.4 | 2.0 |
| FD&A Cost | ||||||
| Total Proved plus Probable | $22.07 | $18.64 | $20.80 | $22.33 | $20.22 | $22.29 |
| Total Proved | $29.32 | $24.15 | $28.24 | $29.21 | $21.95 | $28.80 |
| FD&A Recycle Ratio (1) | ||||||
| Total Proved plus Probable | 2.4 | 2.8 | 2.5 | 2.3 | 2.6 | 2.3 |
| Total Proved | 1.8 | 2.2 | 1.8 | 1.8 | 2.4 | 1.8 |
| (1) | Based on a 2014 netback (prior to realized derivatives) of $52.43 per boe, a 2013 netback (prior to realized derivatives) of $51.98 per boe and a three-year weighted average netback (prior to realized derivatives) of $51.10 per boe. |
OUTLOOK
Crescent Point had an excellent 2014 and advanced all of its core areas due to a strong capital program and several strategic acquisitions completed in the year. The Company generated significant production growth in 2014, surpassing exit production guidance of 155,000 boe/d ahead of schedule in November 2014, and grew reserves efficiently by more than 20 percent over 2013.
“We essentially doubled our reserves in Flat Lake in 2014 while also growing reserves in Uinta by approximately 60 percent since entering the play in late 2012,” said Scott Saxberg. “This reserve growth continues to demonstrate the strength of our business strategy of acquiring, developing and exploiting large oil in place pools with low recovery factors.”
The Company’s strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties in Canada and the United States is structured to guide the organization in both high and low oil price environments. Crescent Point is committed to maintaining a financially strong organization and to maximizing shareholder return with a total return comprised of long-term growth and dividend income.
Consistent with its strategy of maintaining a financially strong organization, Crescent Point is pleased to announce that, subsequent to the quarter, it increased its syndicated credit facility by 40 percent, or $1 billion. This increase brings the Company’s total credit facilities to $3.6 billion. As at December 31, 2014, $1.27 billion, or 35 percent of the Company’s current credit facilities were utilized. The Company’s significant unutilized credit capacity provides substantial financial flexibility, which is increasingly important given the current low oil price environment.
For 2015, Crescent Point will continue to place a strong emphasis on prudent cost and risk management. Its strong balance sheet, combined with its world-class asset base, allows the Company to deliver on its business strategy, even during weak commodity price environments. The Company exited 2014 with a debt to annualized funds flow from operations ratio of 1.3 times, which is excellent given the current economic conditions. With approximately 56 percent of oil production hedged for 2015 at an average floor price of approximately CDN$89.00/bbl and 33 percent of its oil production for 2016 hedged at an average floor price of approximately CDN$84.00/bbl, the Company continues to ensure that its balance sheet remains strong, while still being able to move forward on its long-term growth objectives. The Company’s oil and gas hedge books extend into 2018 with unrealized mark-to-market gains of approximately $485 million, as of March 9, 2015.
“Our responsible approach to the balance sheet and active hedging program has positioned us well to capitalize on the current low oil price environment while also protecting our dividend,” said Scott Saxberg, president and CEO of Crescent Point. “Our conservative financial strategy and our world-class asset base allow us to be patient, opportunistic and proactive.”
Crescent Point has also undertaken a concentrated effort to partner with its vendors to reduce costs as a result of the continuing low oil price environment. The Company projects cost savings of between 15 percent and 20 percent in certain projects relative to 2014 and expects that further savings can be achieved.
With continuing cost reductions, Crescent Point maintains additional flexibility to manage its current 2015 capital budget despite fluctuations in commodity prices. The Company expects to review its capital expenditures plans after spring break-up to determine allocation of cost reduction savings. The Company continues to allocate capital internally, within its large, high-quality inventory base, with a focus on improving its overall capital efficiencies. Similar to in previous downturns, Crescent Point retains a number of internal levers to manage both its balance sheet and its dividend. The Company remains committed to maintaining a strong financial position as well as its long-term growth profile.
“We believe the steps we are taking now, in terms of lowering our cost structure and improving our efficiencies, will benefit the company in all price environments,” said Saxberg.
Despite the downturn in oil prices, the Company is committed to testing and implementing new technology to drive cost reductions and increase recoveries. Crescent Point continues to enhance its completion techniques and to advance technology throughout all of its areas of operation. The Company is continuously adding to its technical knowledge base and has had recent success experimenting with varying amounts and types of fracture stimulation fluid in the Flat Lake play, as well as a new closable sliding sleeve completion technique in the Viewfield Bakken and Shaunavon resource plays.
“Advances in technology, such as the closable sliding sleeve in combination with the waterflood, have the potential to generate significant value for shareholders, with increased recovery factors and capital savings when applied across our large drilling inventory,” said Saxberg. “I believe this validates our strategy of patiently and prudently developing our assets, as it extracts the most value in the long term and increases the overall sustainability of the company.”
Crescent Point continues to maintain a conservative approach to capital spending, acquisitions and the balance sheet. The Company is positioned well to continue to generate total returns for shareholders.
2015 GUIDANCE
The Company’s guidance for 2015 is as follows:
| Production | ||
| Oil and NGL (bbls/d) | 140,600 | |
| Natural gas (mcf/d) | 71,400 | |
| Total (boe/d) | 152,500 | |
| Cash dividends per share ($) | 2.76 | |
| Capital expenditures (1) | ||
| Drilling and completions ($000) | 1,270 | |
| Facilities, land and seismic ($000) | 180 | |
| Total ($000) | 1,450 | |
| (1) | The projection of capital expenditures excludes acquisitions, which are separately considered and evaluated. |
[expand title=”Advisories & Contact”]ON BEHALF OF THE BOARD OF DIRECTORS
Scott Saxberg, President and Chief Executive Officer
March 11, 2015
Non-GAAP Financial Measures
Any “financial outlook” or “future oriented financial information” in the press release, as defined by applicable securities legislation, has been approved by management of Crescent Point. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
Throughout this press release, the Company uses the terms “funds flow from operations”, “funds flow from operations per share – diluted”, “adjusted net earnings from operations”, “adjusted net earnings from operations per share – diluted”, “net debt”, “net debt to funds flow from operations”, “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 cash flow from operating activities to funds flow from operations:
| Three months ended December 31 |
Year ended December 31 |
|||||
| ($000s) | 2014 | 2013 | % Change | 2014 | 2013 | % Change |
| Cash flow from operating activities | 651,851 | 508,090 | 28 | 2,455,556 | 1,973,332 | 24 |
| Changes in non-cash working capital | (89,669) | 20,813 | (531) | (99,372) | 57,349 | (273) |
| Transaction costs | 766 | 70 | 994 | 13,818 | 5,761 | 140 |
| Decommissioning expenditures | 9,920 | 4,337 | 129 | 38,043 | 11,375 | 234 |
| Funds flow from operations | 572,868 | 533,310 | 7 | 2,408,045 | 2,047,817 | 18 |
Adjusted net earnings from operations is calculated based on net income before amortization of exploration and evaluation (“E&E”) undeveloped land, impairment to property, plant and equipment (“PP&E”), unrealized derivative gains or losses, unrealized foreign exchange gain or loss on translation of US dollar senior guaranteed notes and unrealized gains or losses on long-term investments. Adjusted net earnings from operations per share – diluted is calculated as adjusted net earnings from operations divided by the number of weighted average diluted shares outstanding. Management utilizes adjusted net earnings from operations to present a measure of financial performance that is more comparable between periods. Adjusted net earnings from operations as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS. The company has previously referred to adjusted net earnings from operations as “operating income”.
The following table reconciles net income to adjusted net earnings from operations:
| Three months ended December 31 |
Year ended December 31 |
|||||
| ($000s) | 2014 | 2013 | % Change | 2014 | 2013 | % Change |
| Net income (loss) | 121,359 | (13,723) | (984) | 508,894 | 144,876 | 251 |
| Amortization of E&E undeveloped land | 41,778 | 66,955 | (38) | 248,854 | 275,504 | (10) |
| Impairment to PP&E | 588,200 | 98,291 | 498 | 588,200 | 98,291 | 498 |
| Unrealized derivative (gains) losses | (837,656) | 10,936 | (7,760) | (880,831) | 111,876 | (887) |
| Unrealized foreign exchange loss on translation of US dollar senior guaranteed notes | 50,465 | 34,820 | 45 | 121,876 | 60,994 | 100 |
| Unrealized loss on long-term investments | 20,635 | 6,712 | 207 | 24,351 | 10,677 | 128 |
| Deferred tax relating to adjustments | 2,795 | (53,079) | (105) | (64,681) | (143,834) | (55) |
| Adjusted net earnings from operations | (12,424) | 150,912 | (108) | 546,663 | 558,384 | (2) |
Net debt is calculated as long-term debt plus accounts payable and accrued liabilities and dividends payable, less cash, accounts receivable, prepaids and deposits and long-term investments, excluding the equity settled component of dividends payable 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.
Net debt to funds flow from operations is calculated as the period end net debt divided by the sum of funds flow from operations for the trailing four quarters. The ratio of net debt to funds flow from operations is used by management to measure the Company’s overall debt position and to measure the strength of the Company’s balance sheet. Crescent Point monitors this ratio and uses this as a key measure in making decisions regarding financing, capital spending and dividend levels.
The following table reconciles long-term debt to net debt:
| ($000s) | 2014 | 2013 | % Change | |
| Long-term debt (1) | 2,943,074 | 1,734,114 | 70 | |
| Accounts payable and accrued liabilities | 839,228 | 789,305 | 6 | |
| Dividends payable | 102,697 | 90,849 | 13 | |
| Cash | (3,953) | (15,941) | (75) | |
| Accounts receivable | (418,688) | (352,519) | 19 | |
| Prepaids and deposits | (6,519) | (5,532) | 18 | |
| Long-term investments | (49,878) | (74,229) | (33) | |
| Excludes: | ||||
| Equity settled component of dividends payable | (29,806) | (25,799) | 16 | |
| Unrealized foreign exchange on translation of US dollar senior guaranteed notes | (185,046) | (63,170) | 193 | |
| Net debt | 3,191,109 | 2,077,078 | 54 | |
| (1) | Includes current portion of long-term debt. |
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 and share dividend 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, 2014, which will be filed on SEDAR (accessible at www.sedar.com) and EDGAR (accessible at www.sec.gov/edgar.shtml) on March 11, 2015.
Forward-Looking Statements
Certain statements contained in this press release constitute “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934 and “forward looking information” for the purposes of Canadian securities regulation. The Company has tried to identify such forward-looking statements by use of such words as “could”, “should”, “can”, “anticipate”, “expect”, “believe”, “will”, “may”, “intend”, “projected”, “sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take advantage”, “estimate”, “well-positioned” and other similar expressions, but these words are not the exclusive means of identifying such statements.
In particular, this press release contains forward-looking statements pertaining, to the following: the continued advance of the Company’s waterflood programs and its plans to implement waterflood programs in other core areas of operation; the potential impact of the Company’s fracture stimulation process on economically recoverable reserves in certain plays; the Company’s water injection conversion plans for its core areas; the closable sleeve’s potential to improve recovery factors and lower capital costs and the potential use of the sleeve technique across all of the Company’s areas of operation; the potential impact of the Company’s ongoing refinement of its cemented liner completion technology on reserves; the anticipated timing of the start of water injection in the Beaverhill Lake play; the anticipated timing for production to begin on two wells in the Uteland Butte and Douglas Creek zones; the expected timing for processing 3-D seismic data covering a large portion of the Company’s operated lands in Randlett; the planned timing for water injection into two pilots in Randlett; the potential positive impact the down-spacing pilot in Utah may have on operated inventory; expected further reductions in operating costs during 2015; the ability of the Company to withstand, and even excel, in the current low oil price environment; the Company’s expected ongoing emphasis on prudent cost and risk management; the performance characteristics of Crescent Point’s oil and natural gas properties; and the Company’s 2015 guidance with respect to production, dividends per share and capital expenditures.
All forward-looking statements are based on Crescent Point’s beliefs and assumptions based on information available at the time the assumption was made. Crescent Point believes that the expectations reflected in these 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. 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, expressed or implied by such statements, including those material risks discussed in the Company’s Annual Information Form under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2014, 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, 2014, under the headings “Marketing and Prices”, “Dividends”, “Capital Expenditures”, “Decommissioning Liability”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Changes in Accounting Policies” and “Outlook”.
In addition, risk factors include: 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. The impact of any one risk, uncertainty or factor on a particular forward looking statement is not determinable with certainty as these are interdependent and Crescent Point’s future course of action depends on management’s assessment of all information available at the relevant time.
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 and U.S. 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. All subsequent forward looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Company’s behalf are expressly qualified in their entirety by these cautionary statements.
Crescent Point is one of Canada’s largest light and medium oil producers, with an annual dividend of CDN$2.76 per share.
Crescent Point shares are traded on the Toronto Stock Exchange and New York Stock Exchange, both under the symbol CPG.
Greg Tisdale
Chief Financial Officer
(403) 693-0020 or Toll-free (US & Canada): 888-693-0020
(403) 693-0070 (FAX)
Trent Stangl
Vice President, Marketing and Investor Relations
(403) 693-0020 or Toll-free (US & Canada): 888-693-0020
(403) 693-0070 (FAX)
Website: www.crescentpointenergy.com
Crescent Point Energy Corp.
Suite 2000, 585 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1
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