Crescent Point Energy Corp.
TSX : CPG
NYSE : CPG

Crescent Point Energy Corp.

March 11, 2015 08:00 ET

Crescent Point Energy Announces Year-End 2014 Results, 40 Percent Increase in Syndicated Bank Line Capacity and 22 Percent Increase in Reserves

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

  • Crescent Point achieved a new production record in fourth quarter 2014, and 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. This represents an increase of more than 26,000 boe/d over fourth quarter 2013. The Company generated significant production growth in 2014, surpassing exit production guidance of 155,000 boe/d earlier than expected in November 2014.
  • 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.
  • Crescent Point generated funds flow from operations of $572.9 million ($1.28 per share - diluted) in fourth quarter 2014, representing a seven percent increase over fourth quarter 2013 funds flow from operations of $533.3 million ($1.35 per share - diluted). Funds flow from operations was driven by significant production growth and strong operating netbacks prior to realized derivatives of $39.42 per boe, despite a 15 percent decline in the average selling price versus fourth quarter 2013.
  • Crescent Point maintained consistent monthly dividends of $0.23 per share, totaling $0.69 per share for fourth quarter 2014. This is unchanged from $0.69 per share paid in fourth quarter 2013. On an annualized basis, the fourth quarter dividend equates to a yield of 8.8 percent, based on a volume weighted average quarterly share price of $31.29.

2014 HIGHLIGHTS

  • Crescent Point executed strong production growth across its core areas in 2014, growing production per share by approximately eight percent over 2013. Production averaged 140,803 boe/d in the year, which was weighted 91 percent to light and medium crude oil and liquids. This represents an increase of more than 20,000 boe/d over 2013 average annual production.
  • In 2014, the Company spent $2.1 billion on development capital activities, including $1.7 billion on drilling and development activities and $439.6 million on land, seismic and facilities. Crescent Point drilled 914 (691.4 net) wells in 2014 with a 100 percent success rate.
  • The Company increased proved plus probable ("2P") reserves by 22 percent to 807.4 million boe ("MMboe") at year-end 2014, weighted 93 percent to light and medium crude oil and liquids. Proved ("1P") reserves also increased by 22 percent to 528.1 MMboe. This represents annual reserves per share growth of seven percent for 2P reserves and eight percent for 1P reserves.
  • Crescent Point reported a 2P Net Asset Value ("NAV") of $34.74 per fully diluted share, discounted at 10 percent.
  • Crescent Point achieved 2014 Finding and Development ("F&D") costs of $21.59 per 2P boe and $24.95 per 1P boe of reserves, excluding changes in Future Development Capital ("FDC"). This represents 2P and 1P recycle ratios of 2.4 times and 2.1 times, respectively, based on the Company's strong netback prior to realized derivatives of $52.43 per boe. Including changes in FDC, 2014 F&D costs were $22.11 per 2P boe and $24.75 per 1P boe of reserves, generating 2P and 1P recycle ratios of 2.4 times and 2.1 times, respectively.
  • Crescent Point's five-year weighted average F&D cost, including expenditures on land, seismic and facilities, is $19.33 per 2P boe and $24.01 per 1P boe of reserves, representing five-year weighted average recycle ratios for 2P and 1P reserves of 2.6 times and 2.1 times, respectively, based on the Company's five-year average netback prior to realized derivatives of $50.58 per boe.
  • Crescent Point achieved 2014 Finding, Development and Acquisition ("FD&A") costs of $22.07 per 2P boe of reserves and $29.32 per 1P boe of reserves, excluding changes in FDC.
  • In 2014, Crescent Point added 97.1 MMboe of 2P reserves, 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.
  • For the second consecutive year, Crescent Point's strong reserve additions included reserves attributed to the Company's waterfloods in the Viewfield Bakken resource play. At year-end 2014, an additional 4.3 MMboe of 2P reserves were recognized by the Company's independent reserve evaluators due to the performance of the waterfloods. 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. The Company continues to advance its waterflood program in the Viewfield Bakken and Shaunavon resource plays and plans to implement waterflood programs in its other core areas of operation.
  • Crescent Point generated record funds flow from operations of $2.4 billion ($5.72 per share - diluted) in 2014. This represents an 18 percent increase over 2013 funds flow from operations of $2.0 billion ($5.28 per share - diluted). The Company's record funds flow from operations was driven by higher than expected production and its strong netback prior to realized derivatives of $52.43 per boe.
  • Crescent Point maintained consistent monthly dividends of $0.23 per share, totaling $2.76 per share for the year. This is unchanged from $2.76 per share paid in 2013. Since inception, Crescent Point has paid more than $5.9 billion in dividends to shareholders.
  • Subsequent to year-end 2014, Crescent Point increased its syndicated credit facility by 40 percent from $2.5 billion to $3.5 billion. Including the Company's $100 million revolving term operating facility, Crescent Point's total bank line increases to $3.6 billion. At December 31, 2014, approximately $1.27 billion, or 35 percent of current capacity, was drawn on these facilities, providing a significant unutilized source of capital and financial flexibility to the Company, which is increasingly valuable in the current oil price environment. Crescent Point remains committed to maintaining a financially strong organization with a conservative balance sheet.
  • Crescent Point continued to hedge its oil production to protect its cash flows and balance sheet. As at March 9, 2015, the Company had hedged 56 percent, net of royalty interest, for 2015 at a weighted average price of approximately CDN$89.00/bbl and 33 percent for 2016 at a weighted average price of approximately CDN$84.00/bbl. Crescent Point's hedge program provides upside participation when oil prices increase while also providing low-risk, steady cash flow.

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, 2014GasOilD&AServiceStandingTotalNet% Success
Southeast Saskatchewan & Manitoba-149--1150110.1100
Southwest Saskatchewan-60---6058.9100
Alberta and West Central SK-36---3620.0100
United States (1)-60---6033.2100
Total-305--1306222.2100
Year ended December 31, 2014GasOilD&AServiceStandingTotalNet% Success
Southeast Saskatchewan and Manitoba-419-27428352.2100
Southwest Saskatchewan-189-3-192180.8100
Alberta and West Central SK-93-2-9558.1100
United States (1)-199---199100.3100
Total-900-77914691.4100
(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.

  • Crescent Point achieved 2014 F&D costs of $21.59 per 2P boe and $24.95 per 1P boe of reserves, excluding changes in FDC, generating 2P and 1P recycle ratios of 2.4 times and 2.1 times, respectively. Including changes in FDC, 2014 F&D costs were $22.11 per 2P boe and $24.75 per 1P boe of reserves, generating 2P and 1P recycle ratios of 2.4 times and 2.1 times, respectively.
  • Crescent Point's five-year weighted average F&D cost, including expenditures on land, seismic and facilities, is $19.33 per 2P boe and $24.01 per 1P boe of reserves, representing five-year weighted average recycle ratios for 2P and 1P reserves of 2.6 times and 2.1 times, respectively, based on the Company's five-year average netback prior to realized derivatives of $50.58 per boe. This highlights the Company's technical ability to efficiently add value to its large resource-in-place asset base and accurately reflects the full-cycle nature of investments in land, seismic and facilities.
  • Crescent Point achieved 2014 FD&A costs of $22.07 per 2P boe and $29.32 per 1P boe of reserves, excluding changes in FDC. This represents recycle ratios for 2P and 1P reserves of 2.4 times and 1.8 times, respectively. Including changes in FDC, 2014 FD&A costs were $22.33 per 2P boe and $29.21 per 1P boe of reserves, generating 2P and 1P recycle ratios of 2.3 times and 1.8 times, respectively.
  • At year-end 2014, Crescent Point's FDC, excluding acquisitions, increased by $51.0 million on a 2P basis and decreased by $16.7 million on a 1P basis. The Company's FDC does not reflect any capital cost reductions that have been realized thus far in 2015.
  • Crescent Point replaced 189 percent of 2014 total production on a 2P basis, excluding reserves added through acquisitions. Including acquisitions, the Company replaced 379 percent of 2014 total production on a 2P basis.
  • Crescent Point reported a Net Asset Value ("NAV") of $34.74 per fully diluted share, discounted at 10 percent. This NAV accounts for a 22 percent increase in 2P reserves and a lower commodity price environment. However, this does not incorporate future cost savings going forward in capital or operating expense.

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.

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.

Contact Information

  • 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