Crescent Point Energy Corp. Announces Year-End 2011 Results, Bakken Acquisition and Upwardly Revised Guidance
CALGARY, Alberta, March 15, 2012 /PRNewswire/ --
Crescent Point Energy Corp. ("Crescent Point" or the "Company") (TSX: CPG) is pleased to announce its operating and financial results for the year ended December 31, 2011. The Company also announces that its audited financial statements and management's discussion and analysis for the year ended December 31, 2011, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at http://www.sedar.com and on Crescent Point's website at http://www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended December 31 Year ended December 31
(Cdn$000s
except shares,
per share and
per boe
amounts) 2011 2010 % Change 2011 2010 % Change
Financial
Funds flow
from
operations
(1) 381,922 263,221 45 1,293,257 882,862 46
Per share (1)
(2) 1.32 0.98 35 4.65 3.70 26
Net income
(loss) (3) (86,197) (50,905) 69 201,134 50,921 295
Per share (2)
(3) (0.30) (0.19) 58 0.72 0.21 243
Dividends paid
or declared 199,869 184,688 8 771,362 657,520 17
Per share (2) 0.69 0.69 - 2.76 2.76 -
Payout ratio
(%) (1) (4) 52 70 (18) 60 74 (14)
Per share (%)
(1) (2) (4) 52 70 (18) 59 75 (16)
Net debt (1)
(5) 1,220,144 1,116,463 9 1,220,144 1,116,463 9
Capital
acquisitions
(net) (6) 2,765 81,456 (97) 201,313 2,077,733 (90)
Development
capital
expenditures 458,874 246,548 86 1,238,795 958,606 29
Weighted
average shares
outstanding
(mm)
Basic 286.6 263.4 9 275.4 234.9 17
Diluted 289.3 267.4 8 278.2 238.7 17
Operating
Average daily
production
Crude oil and
NGLs (bbls/d) 73,667 62,640 18 66,604 55,070 21
Natural gas
(mcf/d) 45,257 42,831 6 43,172 39,318 10
Total (boe/d) 81,210 69,779 16 73,799 61,623 20
Average
selling
prices(7)
Crude oil and
NGLs ($/bbl) 90.88 76.01 20 87.62 73.46 19
Natural gas
($/mcf) 3.48 3.88 (10) 3.87 4.12 (6)
Total ($/boe) 84.37 70.61 19 81.35 68.28 19
Netback
($/boe)
Oil and gas
sales 84.37 70.61 19 81.35 68.28 19
Royalties (14.42) (12.00) 20 (13.95) (12.56) 11
Operating
expenses (11.17) (11.37) (2) (11.16) (11.03) 1
Transportation (2.01) (1.68) 20 (1.91) (1.65) 16
Netback prior
to realized
derivatives 56.77 45.56 25 54.33 43.04 26
Realized gain
(loss) on
derivatives (3.37) (0.80) 321 (2.97) 0.25 (1,288)
Netback (1) 53.40 44.76 19 51.36 43.29 19
(1) Funds flow from operations, payout ratio, net debt and netback as
presented do not have any standardized meaning prescribed by
International Financial Reporting Standards ("IFRS") and, therefore,
may not be comparable with the calculation of similar measures
presented by other entities. Please refer to the Non-GAAP Financial
Measures section of this press release. Comparative amounts have been
restated to comply with IFRS.
(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, 2011,
includes unrealized derivative losses of $271.4 million and $6.2
million, respectively. Net income for the three months and year ended
December 31, 2010, includes unrealized derivative losses of $104.5
million and unrealized derivative gains of $96.3 million,
respectively.
(4) Payout ratio is calculated as dividends paid or declared (including
the value of dividends issued pursuant to the Company's dividend
reinvestment plan) divided by funds flow from operations.
(5) Net debt includes long-term debt, working capital and long-term
investments, but excludes derivative asset, derivative liability and
unrealized foreign exchange on translation of US dollar senior
guaranteed notes.
(6) Capital acquisitions represent total consideration for the
transactions, including long-term debt and working capital assumed,
and exclude transaction costs.
(7) The average selling prices reported are before realized derivatives
and transportation charges.
FOURTH QUARTER 2011 HIGHLIGHTS
In fourth quarter 2011, Crescent Point continued to execute its integrated business strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties.
- Crescent Point achieved a new production record in fourth quarter 2011 and averaged 81,210 boe/d, weighted 91 percent to light and medium crude oil and liquids. This represents an overall growth rate over fourth quarter 2010 of 16 percent, including more than 15 percent of organic growth. Production increased 12 percent over third quarter 2011.
- In fourth quarter 2011, the Company spent $458.9 million on development capital activities, including $378.4 million on drilling and development activities and $80.5 million on land, seismic and facilities. Crescent Point drilled 178 (132.3 net) wells targeting oil and 1 (1.0 net) service well with a 100 percent success rate.
- Crescent Point's funds flow from operations increased by 45 percent to a record $381.9 million ($1.32 per share - diluted) in fourth quarter 2011, compared to $263.2 million ($0.98 per share - diluted) in fourth quarter 2010.
- In fourth quarter 2011, the Company's netback increased by 19 percent to $53.40 per boe from $44.76 in fourth quarter 2010.
- Crescent Point maintained consistent monthly dividends of $0.23 per share, totaling $0.69 per share for fourth quarter 2011. This is unchanged from $0.69 per share paid in fourth quarter 2010. On an annualized basis, the fourth quarter dividend equates to a yield of 6.5 percent, based on a volume weighted average quarterly share price of $42.44.
2011 HIGHLIGHTS
- Crescent Point grew average daily production in 2011 to 73,799 boe/d, a 20 percent increase over 2010. Production was weighted 90 percent to light and medium crude oil and liquids. Despite a prolonged 2011 spring break-up due to unusual flooding in Saskatchewan, Crescent Point exceeded its 2011 annual average and exit production targets.
- In 2011, the Company spent $1.24 billion on development capital activities, including $951.4 million on drilling and development activities and $287.4 million on land, seismic and facilities. Crescent Point drilled 516 (373.0 net) wells in 2011 with a 100 percent success rate.
- In 2011, Crescent Point announced success in its new core areas in Alberta's emerging Beaverhill Lake light oil resource play and in the North Dakota Bakken/Three Forks resource play. Within the past two years and including acquisitions to date in 2012, the Company has acquired more than 280 net sections and more than 140 net sections in each play, respectively. In 2012, the Company plans to drill 27 net wells in the Beaverhill Lake light oil resource play and 14 net wells in the North Dakota Bakken/Three Forks resource play.
- The Company increased proved plus probable reserves by 12 percent to 424.8 million boe ("mmboe") at year-end 2011, weighted more than 92 percent to light and medium crude oil and liquids. Proved reserves also increased by 12 percent to 281.0 mmboe.
- Crescent Point replaced 248 percent of 2011 production on a proved plus probable basis, excluding reserves added through acquisitions. This is the tenth consecutive year of strong positive technical and development reserve additions.
- This is also the tenth consecutive year of growth in Net Asset Value ("NAV") per fully diluted share, production and cash flow. NAV per share increased to $38.42 per fully diluted share discounted at 10 percent, representing growth of 7 percent over 2010, not including dividends paid during the year. Including dividends paid in 2011, this represents a 14 percent growth in value per share.
- Crescent Point achieved 2011 finding and development ("F&D") costs of $18.52 per proved plus probable boe and $23.06 per proved boe of reserves, excluding changes in future development capital ("FDC"). This represents recycle ratios of 2.9 and 2.4 for proved plus probable and proved, respectively.
Total Proved
Total plus
Per boe, except Recycle Ratios Proved Probable
F&D
5-year weighted average cost, excluding change in
FDC(1) $18.45 $14.30
2011 cost, excluding change in FDC $23.06 $18.52
2011 average recycle ratio(2) 2.4 2.9
2011 cost, including change in FDC $33.35 $28.67
Finding, Development & Acquisition ("FD&A")
5-year weighted average cost, excluding change in
FDC $28.73 $20.78
2011 cost, excluding change in FDC $25.20 $19.95
2011 average recycle ratio(2) 2.2 2.7
2011 cost, including change in FDC $34.87 $29.35
(1) Future Development Capital.
(2) Based on 2011 netback (prior to realized derivatives) of $54.33 per boe.
- Including acquisitions that are expected to close in first quarter 2012, the Company's proved plus probable reserves increase by 12 percent to 475.8 mmboe, representing a proved plus probable reserve life index of 15.0 years. Proved reserves increase by 12 percent to 314.4 mmboe.
- Crescent Point's funds flow from operations increased by 46 percent to $1.29 billion ($4.65 per share - diluted) in 2011, compared to $882.9 million ($3.70 per share - diluted) in 2010.
- 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 2010. Since inception in 2001, Crescent Point has paid approximately $2.7 billion in dividends.
- The Company's balance sheet remains strong, with projected average net debt to 12-month cash flow of less than 1.0 times and approximately $1.0 billion unutilized on its bank lines as at December 31, 2011.
- Crescent Point continued to implement its disciplined hedging strategy to provide increased certainty over cash flow and dividends. As at March 7, 2012, the Company had hedged 59 percent, 49 percent, 32 percent and 16 percent of its expected oil production, net of royalty interest, for 2012, 2013, 2014 and the first half of 2015, respectively. Average quarterly hedge prices range from Cdn$94 per bbl to Cdn$100 per bbl.
- Crescent Point is pleased to announce that Mr. Kent Mitchell joined the Company in January 2012 in the role of President of Crescent Point U.S. Energy Corp. Mr. Mitchell most recently held the position of President at Long View USA.
OPERATIONS REVIEW
Fourth Quarter Operations Summary
During fourth quarter 2011, Crescent Point continued to aggressively implement management's business strategy of creating sustainable, value-added growth in reserves, production and cash flow through acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties.
Crescent Point achieved a new production record in the fourth quarter and averaged 81,210 boe/d, which represents an overall 16 percent increase and an organic growth rate of greater than 15 percent over fourth quarter 2010.
During fourth quarter, the Company spent a record $378.4 million on drilling and development, drilling 178 (132.3 net) oil wells and 1 (1.0 net) service well with a 100 percent success rate. Crescent Point also spent $80.5 million on land, seismic and facilities, for total capital expenditures of $458.9 million during the quarter.
Drilling Results
The following tables summarize our drilling results for the three and 12 months ended December 31, 2011:
Three months ended
December 31, 2011 Gas Oil D&A Service Standing Total Net % Success
Southeast Saskatchewan
and Manitoba - 87 - - - 87 71.4 100
Southwest Saskatchewan - 47 - 1 - 48 42.6 100
South/Central Alberta - 33 - - - 33 15.6 100
Northeast BC and Peace
River Arch, Alberta - 1 - - - 1 0.6 100
United States (1) - 10 - - - 10 3.1 100
Total - 178 - 1 - 179 133.3 100
Twelve months ended
December 31, 2011 Gas Oil D&A Service Standing Total Net % Success
Southeast Saskatchewan
and Manitoba - 246 - 2 - 248 198.5 100
Southwest Saskatchewan - 173 - 1 - 174 132.2 100
South/Central Alberta - 63 - - - 63 32.5 100
Northeast BC and Peace
River Arch, Alberta - 5 - - - 5 3.3 100
United States (1) - 26 - - - 26 6.5 100
Total - 513 - 3 - 516 373.0 100
(1) The net well count is subject to final working interest determination.
Southeast Saskatchewan and Manitoba
In fourth quarter 2011, Crescent Point participated in the drilling of 87 (71.4 net) oil wells in southeast Saskatchewan and Manitoba, achieving a 100 percent success rate. Of the wells drilled, 67 (57.5 net) were horizontal wells in the Bakken light oil resource play. In total, during 2011, the Company drilled 193 (166.8 net) Bakken horizontal oil wells, achieving a 100 percent success rate. The Company plans to drill up to 154 net wells in the Viewfield Bakken play during 2012 and to spend approximately $425 million, including approximately $50 million for land, seismic and facilities.
Production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed the Company's expectations and has demonstrated the applicability of waterflood to the play. During the quarter, the Company began injecting water into four additional wells. By year-end 2011, the Company had converted a total of 24 producing wells to injection wells in the play. Including wells converted to date in 2012, Crescent Point has 32 water injection wells in the play and expects to have approximately 60 by year-end 2012. With the recently announced agreement to acquire PetroBakken Energy Ltd.'s ("PetroBakken") interests in the proposed Viewfield Bakken waterflood area, the Company plans to accelerate plans to implement unit-wide waterfloods.
During the quarter, Crescent Point completed the construction of approximately 100 kilometres of pipeline-gathering systems in the Viewfield area. The Company also completed lease preparation in the Stoughton area for oil-loading rail facilities and ordered trans-loaders to fill rail cars with trucked-in oil. Rail transport will allow the Company to diversify its markets for Bakken crude oil and to more effectively manage pipeline disruptions. The facility became operational in first quarter 2012. More than 2,500 bbl/d of Bakken production was delivered through the facility in February and the Company expects March deliveries through the facility to be approximately 6,000 bbl/d.
Also during the quarter, 20 (13.9 net) horizontal oil wells were drilled in the Glen Ewen, Manor, Innes and Wapella areas, targeting the Midale, Frobisher and Spearfish formations, achieving a 100 percent success rate.
Southwest Saskatchewan
During fourth quarter, the Company participated in the drilling of 47 (41.6 net) oil wells and 1 (1.0 net) service well in southwest Saskatchewan, achieving a 100 percent success rate. In 2011, the Company drilled a total of 127 (106.5 net) oil wells in the Shaunavon area. The Company plans to drill up to 91 net wells in the Shaunavon area in 2012 and to spend approximately $260 million on drilling, seismic, facility construction and land acquisition activities.
The Company is currently injecting water into six horizontal injection wells in four pressure maintenance programs in the Lower Shaunavon zone. Crescent Point is encouraged by results to date. Plans to convert up to four wells in the Upper Shaunavon zone to water injection wells in 2012 are also underway and are expected to bring the total number of injection wells into the play to 10 by year-end 2012.
During fourth quarter, the Company completed construction of a 6 mmcf/d gas plant, which is designed to be expandable to 12 mmcf/d. The plant is expected to be operational during second quarter 2012. Also during fourth quarter, approximately 70 kilometres of pipeline were constructed to tie-in recently drilled wells. Plans to design and construct three additional batteries in 2012 to accommodate increased production have commenced and construction is expected to begin during the second and third quarters of 2012, with commissioning anticipated by fourth quarter 2012.
Also during the quarter, 3 (1.5 net) wells were drilled in the Viking area and 5 (2.7 net) wells were drilled and completed in Cantuar, achieving a 100 percent success rate. The Cantuar wells are currently being tied in and will be tested during first quarter 2012.
Alberta
During fourth quarter, 34 (16.2 net) oil wells were drilled, including 20 (8.0 net) wells in the Beaverhill Lake light oil resource play. In 2011, the Company participated in a total of 39 (15.1 net) successful wells in the Beaverhill Lake play.
As announced in first quarter 2012, Crescent Point has expanded its land position in the Beaverhill Lake light oil resource play by more than 85 net sections through a series of Crown land sales and acquisitions and another 15 net sections through an arrangement agreement with Wild Stream Exploration Inc. ("Wild Stream"). In total, the Company has more than 280 net sections in the area. There are currently seven non-operated drilling rigs and one operated drilling rig running on working interest lands. Under the terms of the joint venture and farm-in agreement with Second Wave Petroleum Inc. in respect of certain lands in the Swan Hills and Judy Creek areas, Crescent Point expects to take over full operatorship on these lands in the second quarter of 2012.
Due to the Company's positive results to date in the Beaverhill Lake light oil resource play, Crescent Point plans to spend approximately $170 million in the area in 2012, drilling up to 27 net wells and investing up to $22 million in infrastructure projects, land and seismic. As of the end of fourth quarter, 29 (11.0 net) wells had been placed on stream in the Swan Hills area, with 27 (10.2 net) of those wells on stream for more than 30 days. The average initial 30-day rate for those wells exceeded 630 boe/d.
Crescent Point has access to a significant land base in southern Alberta and has been pursuing several exploration projects in the area. During fourth quarter, the Company participated in the drilling of 6 (6.0 net) oil wells, of which 2 (2.0 net) were to follow up on previously drilled unconventional exploration wells in the Alberta Bakken play, for a total of 3.0 net unconventional exploration wells in 2011. Plans for 2012 include drilling up to 19 net wells on these lands.
United States
During fourth quarter, the Company participated in the drilling of 10 (3.1 net) oil wells, of which 3 (2.2 net) were operated, achieving a 100 percent success rate. The two operated wells drilled in third quarter and the three drilled in fourth quarter are expected to be completed by early 2012, as part of Crescent Point's two-year service agreement with a leading U.S. fracture stimulation company. In total, the Company participated in drilling 26 (6.5 net) wells in 2011, including 5 gross operated wells.
Crescent Point has amassed more than 140 net sections of land in North Dakota. The Company expects to allocate approximately $130 million of the 2012 budget to the state, including drilling up to 14 net wells targeting the Bakken and Three Forks zones.
Acquisitions
During first quarter 2012, Crescent Point announced that it entered into an arrangement agreement with Wild Stream to acquire approximately 5,400 boe/d of Wild Stream's production, 91 percent of which is contiguous with Crescent Point's assets in the Shaunavon and Battrum/Cantuar areas of southwest Saskatchewan. Upon successful closing of the arrangement agreement, the Company expects to acquire more than 200 net sections of land in the Shaunavon resource play, 15 net sections of land in the emerging Beaverhill Lake light oil resource play in the Swan Hills area and 37 net sections of land in the Battrum/Cantuar area of southwest Saskatchewan. The arrangement is expected to close on or about March 15, 2012.
Also during first quarter 2012, the Company announced that it entered into an agreement with PetroBakken to acquire more than 2,900 boe/d of production and more than 25 net sections of land in the core of the Viewfield Bakken resource play, primarily within the boundaries of the Company's proposed waterflood units. The agreement is expected to close on or about March 16, 2012.
On February 16, 2012, Crescent Point announced that it closed an agreement to acquire approximately 940 boe/d of production in southwest Manitoba. The Company believes this property has significant upside potential through infill drilling and waterflood optimization.
During first quarter 2012, Crescent Point acquired approximately 3 net sections of land in the Viewfield Bakken resource play, the majority of which is undeveloped, for cash consideration of $28.5 million. The assets are within Crescent Point's proposed Viewfield Bakken waterflood area and are adjacent to and contiguous with the Company's existing assets. The acquisition is expected to accelerate and simplify the Company's waterflood plans. The Company has internally identified 23.4 net low-risk drilling locations on the lands.
Also during first quarter 2012, the Company acquired an approximate 0.8 percent interest in the Weyburn unit in southeast Saskatchewan, increasing its total unit interest to 3.2 percent. The assets acquired include more than 200 boe/d of production and independently assigned proved plus probable reserves of 1.7 mmboe, as of February 29, 2012. Total consideration paid was approximately $38.0 million.
RESERVES
In 2011, Crescent Point replaced 248 percent of production on a proved plus probable basis, excluding reserves added through acquisitions. Including acquisitions, the Company replaced 268 percent of production and increased its year-end proved plus probable reserves by 12 percent to 424.8 mmboe and its proved reserves by 12 percent to 281.0 mmboe. Year-end 2010 reserves were 379.5 mmboe proved plus probable and 250.8 mmboe proved.
- Crescent Point achieved 2011 F&D costs of $18.52 per proved plus probable boe and $23.06 per proved boe, excluding changes in FDC, generating proved plus probable and proved recycle ratios of 2.9 times and 2.4 times, respectively.
- Including changes in FDC, 2011 F&D costs were $28.67 per proved plus probable boe and $33.35 per proved boe, generating proved plus probable and proved recycle ratios of 1.9 times and 1.6 times, respectively.
- Crescent Point's 5-year weighted average F&D cost, including expenditures on land, seismic and facilities, is $14.30 per proved plus probable boe and $18.45 per proved boe, representing recycle ratios of 3.4 and 2.6 times, respectively. This highlights the Company's technical ability to efficiently add value to its large resource-in-place asset base and accurately reflects the full cycle nature of investments in land, seismic and facilities.
- The Company's cumulative proved plus probable technical and development reserves additions since inception increased to 246.8 mmboe, which represents 58 percent of year-end 2011 proved plus probable reserves.
The Company's reserves were independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and Sproule Associates Ltd. ("Sproule") as at December 31, 2011, and the following highlights are based on such evaluations.
The following reserves information does not include the impact of the pending or completed transactions referenced under the heading "Acquisitions" above.
Summary of Reserves
(Escalated Pricing)
As at December 31, 2011 (1)
RESERVES(2)
Oil (Mbbl) Gas (MMscf) NGL (Mbbl) Total (Mboe)
Description Gross Net Gross Net Gross Net Gross Net
Proved
producing 130,750 114,644 72,411 66,823 4,523 4,157 147,342 129,938
Proved non-
producing 117,587 107,791 61,499 56,834 5,852 5,438 133,688 122,701
Total proved 248,337 222,435 133,910 123,657 10,375 9,595 281,031 252,639
Probable 127,615 113,311 67,112 61,463 4,946 4,551 143,747 128,106
Total proved
plus
probable (3) 375,954 335,746 201,021 185,120 15,321 14,146 424,778 380,745
(1) Based on GLJ's January 1, 2012, escalated price forecast.
"Gross Reserves" are the total Company's interest share before the
deduction of any royalties and without including any royalty interest
of the Company. "Net Reserves" are the total Company's interest share
(2) after deducting royalties and including any royalty interest.
(3) Numbers may not add due to rounding.
Summary of Before and After Tax Net Present Values
(Escalated Pricing)
As at December 31, 2011 (1)
BEFORE TAX NET PRESENT VALUE ($MM)
Discount Rate
Description Undiscounted 5% 10% 15% 20%
Proved producing 7,452 5,588 4,604 3,978 3,536
Proved non-producing 5,331 3,829 2,884 2,249 1,800
Total proved(2) 12,783 9,416 7,488 6,227 5,336
Probable 7,733 4,790 3,386 2,576 2,055
Total proved plus probable(2) 20,516 14,207 10,874 8,803 7,391
AFTER TAX NET PRESENT VALUE ($MM)
Discount Rate
Description Undiscounted 5% 10% 15% 20%
Proved producing 6,733 5,090 4,209 3,644 3,243
Proved non-producing 3,917 2,740 2,005 1,514 1,171
Total proved(2) 10,649 7,830 6,214 5,158 4,414
Probable 5,681 3,501 2,457 1,854 1,465
Total proved plus probable(2) 16,330 11,331 8,670 7,012 5,880
(1) Based on GLJ's January 1, 2012, 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
2011 2010 2009 2008 2007 2006 2005 2004
PV 0% $71.39 $71.38 $72.01 $80.66 $61.03 $34.08 $21.99 $16.19
PV 5% $49.81 $47.65 $46.91 $49.30 $40.21 $21.61 $15.12 $11.22
PV 10% $38.42 $36.02 $35.08 $34.97 $30.05 $15.70 $11.45 $8.56
PV 15% $31.35 $29.10 $28.27 $26.85 $24.04 $12.27 $9.10 $6.85
Reserves Reconciliation
(Escalated Pricing)
Gross Reserves (1)
For the year ended December 31, 2011
CRUDE OIL AND NGL (Mbbl) NATURAL GAS (MMscf)
Proved Probable Total Proved Probable Total
Opening
Balance
January 1,
2011 230,537 119,602 350,139 121,638 54,771 176,408
Acquired 3,141 1,745 4,886 1,743 980 2,723
Disposed - (39) (39) - - -
Production (24,310) - (24,310) (15,758) - (15,758)
Development 38,867 24,922 63,789 18,384 12,154 30,538
Technical
revisions 10,478 (13,668) (3,191) 7,903 (793) 7,110
Closing
Balance
December
31, 2011
(2) 258,713 132,562 391,274 133,910 67,112 201,021
(table continued)
BOE (Mboe)
Proved Probable Total
Opening
Balance
January 1,
2011 250,810 128,731 379,540
Acquired 3,432 1,909 5,340
Disposed - (39) (39)
Production (26,937) - (26,937)
Development 41,931 26,947 68,879
Technical
revisions 11,795 (13,800) (2,006)
Closing
Balance
December
31, 2011
(2) 281,031 143,747 424,778
(1) Based on GLJ's January 1, 2012, escalated price forecast. "Gross
reserves" are the Company's working-interest share before deduction of
any royalties and without including any royalty interests of the
Company.
(2) Numbers may not add due to rounding.
Finding, Development and Acquisition Costs
(Excluding future development capital)
For the year ended December 31, 2011
CAPITAL FINDING, DEVELOPMENT AND
EXPENDITURES(1)(4) RESERVES (3) ACQUISITION COSTS(1)(2)
Total Proved Plus Proved Plus
Proved Probable Proved Probable
$000 % Mboe % Mboe % $/boe $/boe
Exploration
development
and revisions 1,238,795 86 53,726 94 66,873 93 23.06 18.52
Acquisitions,
net of
dispositions 201,313 14 3,432 6 5,301 7 58.66 37.98
Total 1,440,108 100 57,158 100 72,174 100 25.20 19.95
(1) Exploration, Development and Revisions exclude the change in estimated FDC during 2011. These costs would add $552.9 million and $678.3 million to the proved and proved plus probable reserves categories, respectively. Including these changes, the proved and proved plus probable F&D costs are $33.35 and $28.67 per boe, respectively.
(2) Including change in FDC, FD&A costs are $34.87 per proved boe and $29.35 per proved plus probable boe.
(3) Gross Company interest reserves are used in this calculation (working interest reserves, before deduction of any royalties and without including any royalty interests of the Company).
(4) The capital expenditures exclude capitalized administration costs and transaction costs.
F&D and FD&A Costs, $/boe (1)
3 Years Ended
Dec. 31, 2011
Weighted
2011 2010 Average
F&D
Total Proved Cost, excluding change in FDC $23.06 $21.07 $20.98
Total Proved Cost, including change in FDC $33.35 $32.45 $30.18
Total Proved plus Probable Cost, excluding
change in FDC $18.52 $17.23 $16.67
Total Proved plus Probable Cost, including
change in FDC $28.67 $28.89 $25.71
FD&A
Total Proved Cost, excluding change in FDC $25.20 $35.94 $32.31
Total Proved Cost, including change in FDC $34.87 $41.85 $37.49
Total Proved plus Probable Cost, excluding
change in FDC $19.95 $26.15 $23.15
Total Proved plus Probable Cost, including
change in FDC $29.35 $31.54 $27.74
(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
The following reserves information includes, in addition to Crescent Point's year-end evaluations of reserves sourced from GLJ and Sproule as of December 31, 2011, the impact of the pending and completed transactions referenced under the heading "Acquisitions" above.
Summary of Reserves, Including First Quarter 2012 Acquisitions and Dispositions
(Escalated Pricing)
As at March 15, 2012 (1) (2)
RESERVES (3)
Oil (Mbbls) Gas (MMscf) NGL (Mbbls) Total (Mboe)
Description Gross Net Gross Net Gross Net Gross Net
Proved
producing 150,689 132,121 77,604 71,567 4,905 4,493 168,528 148,542
Proved
non-producing 128,992 117,957 63,944 59,028 6,211 5,760 145,861 133,554
Total proved 279,681 250,078 141,548 130,595 11,116 10,253 314,389 282,096
Probable 144,007 127,580 72,338 66,386 5,302 4,870 161,364 143,516
Total proved
plus
probable(4) 423,688 377,658 213,886 196,981 16,418 15,122 475,753 425,612
(1) Includes independent engineers' evaluations of both Crescent Point's 2011 year end and all acquisitions that are expected to close in first quarter 2012. Acquired reserves were evaluated as of January 31, 2012, and February 29, 2012.
(2) Based on GLJ's January 1, 2012, escalated price forecast.
(3) "Gross Reserves" are the total Company's interest share before the deduction of any royalties and without including any royalty interests of the Company. "Net Reserves" are the total Company interest share after deducting royalties and including any royalty interests.
(4) Numbers may not add due to rounding.
Summary of Before Tax Net Present Values, Including First Quarter 2012 Acquisitions and Dispositions
(Escalated Pricing)
As at March 15, 2012 (1) (2)
BEFORE TAX NET PRESENT VALUE ($MM)
Discount Rate
Description Undiscounted 5% 10% 15% 20%
Proved producing 8,561 6,348 5,200 4,477 3,971
Proved non-producing 5,792 4,156 3,130 2,440 1,952
Total proved 14,353 10,504 8,330 6,917 5,923
Probable 8,767 5,366 3,771 2,859 2,275
Total proved plus probable (3) 23,120 15,869 12,100 9,776 8,198
(1) Includes independent engineers' evaluations of both Crescent Point's 2011 year end and all acquisitions that are expected to close in first quarter 2012. Acquired reserves were evaluated as of January 31, 2012, and February 29, 2012.
(2) Based on GLJ's January 1, 2012, escalated price forecast.
(3) Numbers may not add due to rounding.
STRATEGIC CONSOLIDATION ACQUISITION OF RELIABLE ENERGY LTD.
Crescent Point is pleased to announce that it has entered into an arrangement agreement (the "Reliable Arrangement") with Reliable Energy Ltd. ("Reliable"), a publicly traded company in which Crescent Point owns a 12.8 percent equity interest. Reliable has production of approximately 1,000 boe/d from the Bakken light oil play in the Kirkella/Manson area and a land base of more than 135 net sections in southern Saskatchewan and southwestern Manitoba. The assets of Reliable include internally assigned proved plus probable reserves of 4.1 mmboe, as of December 31, 2011, and an internally identified drilling inventory of 36 net locations.
The completion of the Reliable Arrangement will allow Crescent Point to consolidate the assets currently held through a joint venture with Reliable in the Bakken light oil play in southwest Manitoba and is complementary to the Company's previously announced Manitoba asset acquisition. The Bakken light oil play in southwest Manitoba is a low-cost, high-netback play that the Company believes has upside potential through both infill and step-out drilling, as well as waterflooding.
Under the terms of the Reliable Arrangement, Crescent Point has agreed to acquire all of the issued and outstanding shares of Reliable at an exchange ratio of 0.00794 of a Crescent Point share for each Reliable share. In addition, Crescent Point expects to assume approximately $20.0 million of Reliable net debt, including deal costs and after taking into account proceeds from Reliable stock options and warrants expected to be exercised prior to the completion of the Reliable Arrangement. Total consideration for the 87.2 percent of Reliable not currently owned by Crescent Point is approximately $99.1 million, including net debt. Including Crescent Point's existing 12.8 percent equity interest in Reliable, total value is approximately $103.9 million, based on a five-day weighted average trading price of $45.61 per Crescent Point share.
The Reliable Board of Directors has concluded that the Reliable Arrangement is fair to Reliable shareholders and has resolved to recommend that the Reliable shareholders vote their Reliable shares in favour of the Reliable Arrangement. All of the officers and directors of Reliable exercising control or direction of approximately 10.4 percent of Reliable's fully diluted shares have agreed to vote their Reliable shares in favour of the Reliable Arrangement.
The Reliable Arrangement is expected to close on or about May 1, 2012, allowing Reliable shareholders to receive Crescent Point's anticipated May dividend, which is expected to be paid on or about June 15, 2012.
Peters & Co. Limited acted as advisor to Crescent Point with regards to the Reliable Arrangement.
OUTLOOK AND UPWARDLY REVISED GUIDANCE
Crescent Point continues to execute its business plan of creating sustainable value-added growth in reserves, production and cash flow through management's integrated strategy of acquiring, exploiting and developing high-quality, long-life light and medium oil and natural gas properties in United States and Canada.
2011 was another successful year in which Crescent Point achieved record production, reserves and cash flow. The Company continued to develop and exploit the Viewfield Bakken and Shaunavon resource plays, while also acquiring significant positions in two emerging plays, the Beaverhill Lake light oil resource play in Alberta and the North Dakota Bakken/Three Forks play along the U.S./Canada border.
Crescent Point now has more than 7,150 net low-risk drilling locations in inventory, representing more than 550,000 boe/d of risked potential production additions. This depth of drilling inventory positions the Company well for long-term sustainable growth in production, reserves and NAV and also provides support for long-term dividends.
As a result of the Reliable Arrangement, the Company is upwardly revising its guidance for the year. Crescent Point's average daily production is expected to increase to more than 86,500 boe/d from 86,000 boe/d and its 2012 exit production rate is expected to increase to more than 94,000 boe/d from 93,000 boe/d. The Company's capital expenditures budget for 2012 remains unchanged at $1.2 billion.
The 2012 capital program will focus on several organic growth projects across the Company's asset base, as well as on advancing the Company's emerging resource plays in Beaverhill Lake and North Dakota Bakken/Three Forks. Crescent Point will continue to apply and refine new techniques and concepts in each of its core resource plays, which will provide the Company with a competitive advantage in developing new prospects.
Crescent Point expects to spend approximately 36 percent of its 2012 budget in the Viewfield Bakken and Flat Lake areas of southeast Saskatchewan, 22 percent in the Shaunavon area of southwest Saskatchewan, 14 percent in the Beaverhill Lake light oil resource play and 11 percent in the Bakken/Three Forks resource play in North Dakota. The remainder of the budget will be allocated to the Company's other core conventional properties and to the exploration and development projects in southern Alberta. In total, Crescent Point expects to drill approximately 389 net wells in 2012 and to spend approximately $150 million on facilities infrastructure, primarily in the Bakken and Lower Shaunavon resource plays.
The Company will continue to expand and develop its waterflood programs in the Viewfield Bakken and Shaunavon resource plays. By year-end 2012, the Company expects to have approximately 60 and 10 injection wells in the Bakken play and Shaunavon play, respectively.
Funds flow from operations for 2012 is expected to increase to $1.5 billion ($4.74 per share - diluted), based on forecast pricing of US$100.00 per barrel WTI, Cdn$2.75 per mcf AECO gas and a US$/Cdn$0.98 exchange rate.
The Company's guidance for funds flow from operations includes wider corporate oil differentials for the first half of 2012 to reflect factors impacting the PADD II refining region. The Company expects differentials to improve in the second half of the year. However, to offset these price risks, Crescent Point has begun delivering crude oil through its Stoughton rail terminal, which will provide access to new markets outside of the PADD II region.
The Company's balance sheet remains strong, with projected average net debt to 12-month cash flow of less than 1.0 times and approximately $1.0 billion unutilized on its bank lines as at December 31, 2011.
Crescent Point continues to implement its balanced 3½-year price risk management program, using a combination of swaps, collars and purchased put options with investment grade counterparties. As at March 7, 2012, the Company had hedged 59 percent, 49 percent, 32 percent and 16 percent of its expected oil production, net of royalty interest, for 2012, 2013, 2014 and the first half of 2015, respectively. Average quarterly hedge prices range from Cdn$94 per bbl to Cdn$100 per bbl.
Crescent Point's management believes that with the Company's high-quality reserve base and development drilling inventory, excellent balance sheet and solid risk management program, the Company is well-positioned to continue generating strong operating and financial results through 2012 and beyond.
2012 GUIDANCE
Crescent Point's upwardly revised 2012 guidance is as follows:
Production Prior Revised
Oil and NGL (bbls/d) 78,000 78,500
Natural gas (mcf/d) 48,000 48,000
Total (boe/d) 86,000 86,500
Exit (boe/d) 93,000 94,000
Funds flow from operations ($000) 1,490,000 1,500,000
Funds flow per share - diluted ($) 4.72 4.74
Cash dividends per share ($) 2.76 2.76
Capital expenditures ($000) (1) 1,200,000 1,200,000
Wells drilled, net 389 389
Pricing
Crude oil - WTI (US$/bbl) 95.00 100.00
Crude oil - WTI (Cdn$/bbl) 98.96 102.04
Natural gas - Corporate (Cdn$/mcf) 3.25 2.75
Exchange rate (US$/Cdn$) 0.96 0.98
(1) The projection of capital expenditures excludes acquisitions, which are separately considered and evaluated.
ON BEHALF OF THE BOARD OF DIRECTORS
(signed)
Scott Saxberg
President and Chief Executive Officer
March 15, 2012
Non-GAAP Financial Measures
Throughout this press release, the Company uses the terms "funds flow from operations", "funds flow from operations per share - diluted", "net debt", "netback", "payout ratio" and "payout ratio per share - diluted." These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.
Funds flow from operations is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures. Funds flow from operations per share and funds flow from operations per share - diluted are calculated as funds flow from operations divided by the number of weighted average diluted shares outstanding. Management utilizes funds flow from operations as a key measure to assess the ability of the Company to finance dividends, operating activities, capital expenditures and debt repayments. Funds flow from operations as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS.
The following table reconciles the cash flow from operating activities to funds flow from operations:
($000s) 2011 2010 % Change
Cash flow from operating activities 1,322,971 816,454 62
Changes in non-cash working capital (36,078) 54,349 (166)
Transaction costs 2,679 9,311 (71)
Decommissioning expenditures 3,685 2,748 34
Funds flow from operations 1,293,257 882,862 46
Net debt is calculated as current liabilities plus long-term debt less current assets and long-term investments, but excludes derivative asset, derivative liability and unrealized foreign exchange on translation of US dollar senior guaranteed notes. Management utilizes net debt as a key measure to assess the liquidity of the Company.
The following table reconciles long-term debt to net debt:
($000s) 2011 2010 % Change
Long-term debt 1,099,028 1,006,451 9
Current liabilities 681,279 449,931 51
Current assets (308,515) (212,670) 45
Long-term investments (151,917) (62,164) 144
Excludes:
Derivative asset 10,216 7,087 44
Derivative liability (101,997) (78,707) 30
Unrealized foreign exchange on
translation of US dollar senior
guaranteed notes (7,950) 6,535 (222)
Net debt 1,220,144 1,116,463 9
Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.
Payout ratio and payout ratio per share - diluted are calculated on a percentage basis as dividends paid or declared (including the value of dividends issued pursuant to the Company's dividend reinvestment plan) divided by funds flow from operations. Payout ratio is used by management to monitor the dividend policy and the amount of funds flow from operations retained by the Company for capital reinvestment.
Reserves Data
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2011, which will be filed on SEDAR (accessible at http://www.sedar.com) on or before March 30, 2012.
Forward-Looking Statements
Certain statements contained in this press release constitute forward-looking statements. All forward-looking statements are based on Crescent Point's beliefs and assumptions based on information available at the time the assumption was made. The use of any of the words "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions are intended to identify forward-looking statements. By their nature, such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. These statements speak only as of the date of this press release or, if applicable, as of the date specified in those documents specifically referenced herein.
In particular, this press release contains forward-looking statements pertaining to the following: the performance characteristics of Crescent Point's oil and natural gas properties; oil and natural gas production levels; capital expenditure programs; drilling programs; well conversion and water injection programs; the quantity of Crescent Point's oil and natural gas reserves and anticipated future cash flows from such reserves; the anticipated closing dates for the acquisitions described under "Operations Review - Acquisitions" and the expected impact of such acquisitions on the Company's reserves as at March 15, 2012; the quantity of drilling locations in inventory; projections of commodity prices and costs; supply and demand for oil and natural gas; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; expected debt levels and credit facilities; expected pipeline capacity additions; facility construction plans; and treatment under governmental regulatory regimes.
By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks discussed in our annual information form under "Risk Factors" and our Management's Discussion and Analysis for the year ended December 31, 2011, 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, 2011, under the headings "Dividends", "Capital Expenditures", "Decommissioning Liability", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Future Changes in Accounting Policies" and "Outlook." The actual results could differ materially from those anticipated in these forward-looking statements as a result of the material risks set forth under the noted headings, which include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves and Discovered Petroleum Initially in Place; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry.
Barrels of oil equivalent ("boes") may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
Additional information on these and other factors that could affect Crescent Point's operations or financial results are included in Crescent Point's reports on file with Canadian securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise and Crescent Point undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law.
Crescent Point is a conventional oil and gas producer with assets strategically focused in properties comprised of high-quality, long-life, operated light and medium oil and natural gas reserves in United States and Canada.
Crescent Point shares are traded on the Toronto Stock Exchange under the symbol CPG.
Crescent Point Energy Corp.
Suite 2800, 111-5th Avenue S.W.
Calgary, Alberta T2P 3Y6
For further information:
Greg Tisdale, Chief Financial Officer, or Trent Stangl, Vice President Marketing and Investor Relations.
Telephone: +1(403)693-0020 Toll-free (US & Canada): 888-693-0020
Fax: +1(403)693-0070 Website: http://www.crescentpointenergy.com
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