CALGARY, ALBERTA–(Marketwired – Aug. 8, 2013) – Crescent Point Energy Corp. (“Crescent Point” or the “Company”) (TSX:CPG) is pleased to announce its operating and financial results for the quarter ended June 30, 2013. The Company also announces that its unaudited financial statements and management’s discussion and analysis for the quarter ended June 30, 2013, will be available on the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com and on Crescent Point’s website at www.crescentpointenergy.com.
FINANCIAL AND OPERATING HIGHLIGHTS
| Three months ended June 30 | Six months ended June 30 | ||||||||||||||||||
| (Cdn$000s except shares, per share and per boe amounts) | 2013 | 2012 | % Change | 2013 | 2012 | % Change | |||||||||||||
| Financial | |||||||||||||||||||
| Funds flow from operations (1) | 504,420 | 386,318 | 31 | 960,363 | 787,227 | 22 | |||||||||||||
| Per share (1) (2) | 1.31 | 1.19 | 10 | 2.51 | 2.53 | (1 | ) | ||||||||||||
| Net income | 72,332 | 287,430 | (75 | ) | 70,720 | 283,542 | (75 | ) | |||||||||||
| Per share (2) | 0.19 | 0.89 | (79 | ) | 0.18 | 0.91 | (80 | ) | |||||||||||
| Operating income (1) | 130,308 | 135,009 | (3 | ) | 244,653 | 234,212 | 4 | ||||||||||||
| Per share (1) (2) | 0.34 | 0.42 | (19 | ) | 0.64 | 0.75 | (15 | ) | |||||||||||
| Dividends paid or declared | 267,033 | 225,212 | 19 | 534,899 | 435,769 | 23 | |||||||||||||
| Per share (2) | 0.69 | 0.69 | – | 1.38 | 1.38 | – | |||||||||||||
| Payout ratio (%) (1) (3) | 53 | 58 | (5 | ) | 56 | 55 | 1 | ||||||||||||
| Per share (%) (1) (2) (3) | 53 | 58 | (5 | ) | 55 | 55 | – | ||||||||||||
| Net debt (1) | 1,825,340 | 2,003,711 | (9 | ) | 1,825,340 | 2,003,711 | (9 | ) | |||||||||||
| Capital acquisitions (net) (4) | 30 | 773,364 | (100 | ) | 22,145 | 2,079,269 | (99 | ) | |||||||||||
| Development capital expenditures (5) | 256,434 | 235,984 | 9 | 789,149 | 711,599 | 11 | |||||||||||||
| Decommissioning and environmental expenditures (5) | 2,614 | 2,838 | (8 | ) | 6,887 | 8,603 | (20 | ) | |||||||||||
| Weighted average shares outstanding (mm) | |||||||||||||||||||
| Basic | 383.5 | 321.4 | 19 | 381.0 | 308.9 | 23 | |||||||||||||
| Diluted | 385.1 | 323.8 | 19 | 382.4 | 311.3 | 23 | |||||||||||||
| Operating | |||||||||||||||||||
| Average daily production | |||||||||||||||||||
| Crude oil and NGLs (bbls/d) | 106,609 | 88,798 | 20 | 106,564 | 85,675 | 24 | |||||||||||||
| Natural gas (mcf/d) | 67,142 | 49,046 | 37 | 67,004 | 47,721 | 40 | |||||||||||||
| Total (boe/d) | 117,799 | 96,972 | 21 | 117,731 | 93,629 | 26 | |||||||||||||
| Average selling prices(6) | |||||||||||||||||||
| Crude oil and NGLs ($/bbl) | 84.65 | 78.42 | 8 | 82.51 | 82.72 | – | |||||||||||||
| Natural gas ($/mcf) | 3.93 | 2.06 | 91 | 3.75 | 2.25 | 67 | |||||||||||||
| Total ($/boe) | 78.85 | 72.85 | 8 | 76.82 | 76.84 | – | |||||||||||||
| Netback ($/boe) | |||||||||||||||||||
| Oil and gas sales | 78.85 | 72.85 | 8 | 76.82 | 76.84 | – | |||||||||||||
| Royalties | (13.15 | ) | (11.52 | ) | 14 | (13.60 | ) | (12.62 | ) | 8 | |||||||||
| Operating expenses | (12.04 | ) | (11.12 | ) | 8 | (12.05 | ) | (10.82 | ) | 11 | |||||||||
| Transportation | (2.27 | ) | (2.11 | ) | 8 | (2.15 | ) | (2.00 | ) | 8 | |||||||||
| Netback prior to realized derivatives | 51.39 | 48.10 | 7 | 49.02 | 51.40 | (5 | ) | ||||||||||||
| Realized loss on derivatives | (0.79 | ) | (0.79 | ) | – | (0.61 | ) | (1.87 | ) | (67 | ) | ||||||||
| Netback (1) | 50.60 | 47.31 | 7 | 48.41 | 49.53 | (2 | ) | ||||||||||||
| (1) | Funds flow from operations, operating income, 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 for further information. |
| (2) | The per share amounts (with the exception of per share dividends) are the per share – diluted amounts. |
| (3) | Payout ratio is calculated as dividends paid or declared (including the value of dividends paid pursuant to the Company’s dividend reinvestment plans) divided by funds flow from operations. |
| (4) | Capital acquisitions represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs. |
| (5) | Decommissioning and environmental expenditures includes environmental emission reduction expenditures, which are also included in development capital expenditures in the table above. |
| (6) | The average selling prices reported are before realized derivatives and transportation charges. |
SECOND QUARTER 2013 HIGHLIGHTS
In second quarter 2013, 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.
OPERATIONS REVIEW
Second Quarter Operations Summary
During second quarter 2013, 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 second quarter and averaged 117,799 boe/d, a 20,827 boe/d increase over second quarter 2012. This represents production per share growth of more than 2 percent over second quarter 2012. This also represents an increase over first quarter 2013, despite having budgeted for quarter-over-quarter declines due to the expected impact of spring break-up. The Company’s strong organic production performance during the quarter was driven by its successful drilling program, particularly in Utah, where Crescent Point drilled nearly 50 percent of all wells drilled in second quarter. Other factors contributing to production performance include the Company’s continued waterflood success, lower corporate declines and a spring break-up that was less severe than expected.
During the quarter, the Company spent $199.4 million on drilling and development activities, drilling 83 (55.8 net) oil wells with a 100 percent success rate. Crescent Point also spent $57.0 million on land, seismic and facilities, for total capital expenditures of $256.4 million.
Drilling Results
The following tables summarize our drilling results for the three and six months ended June 30, 2013:
| Three months ended June 30, 2013 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success |
| Southeast Saskatchewan and Manitoba | – | 22 | – | – | 1 | 23 | 17.2 | 100 |
| Southwest Saskatchewan | – | 11 | – | – | – | 11 | 11.0 | 100 |
| South/Central Alberta and West/Central SK | – | 1 | – | – | – | 1 | 0.3 | 100 |
| United States (1) | – | 49 | – | – | – | 49 | 28.3 | 100 |
| Total | – | 83 | – | – | 1 | 84 | 56.8 | 100 |
| Six months ended June 30, 2013 | Gas | Oil | D&A | Service | Standing | Total | Net | % Success |
| Southeast Saskatchewan and Manitoba | – | 128 | – | 1 | 1 | 130 | 105.2 | 100 |
| Southwest Saskatchewan | – | 40 | – | – | – | 40 | 40.0 | 100 |
| South/Central Alberta and West/Central SK | – | 26 | – | – | – | 26 | 18.6 | 100 |
| United States (1) | – | 116 | – | – | – | 116 | 58.3 | 100 |
| Total | – | 310 | – | 1 | 1 | 312 | 222.1 | 100 |
| (1) | The net well count is subject to final working interest determination. |
Southeast Saskatchewan and Manitoba
In early third quarter, the Government of Saskatchewan provided technical approval for the first of four Bakken waterflood units proposed by the Company. This approval is a significant milestone in the development of the waterflood program in the Viewfield Bakken resource play.
Overall production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed Crescent Point’s expectations. Currently, water injection support is positively affecting more than 5,000 boe/d of the Company’s Bakken production, which has resulted in shallower declines and contributed to Crescent Point’s record first and second quarter 2013 results. In addition, the Company’s independent engineering firm has completed preliminary studies on existing waterflood patterns with sufficient history and have found ultimate long-term recovery factors up to 30 percent are achievable in those areas. The independent engineers will be including results from these studies, where appropriate, in their year-end reserves assignments.
In second quarter 2013, Crescent Point participated in the drilling of 22 (16.2 net) oil wells in southeast Saskatchewan and Manitoba, achieving a 100 percent success rate. Of the wells drilled, 18 (14.8 net) were drilled in the Saskatchewan Bakken light oil resource play. In second quarter, the Company also participated in the drilling of 5 (2.4 net) horizontal wells in conventional zones. In 2013, the Company expects to spend approximately $490 million in the Saskatchewan Bakken play, including expenditures on land, seismic and facilities, as well as the drilling of up to 169 net wells, 82 net wells of which are planned for the second half of the year.
During the quarter, Crescent Point began construction to expand its Viewfield gas plant from 30 mmscf/d to 42 mmscf/d to accommodate continued increased production from the success of the drilling program and shallowing decline rates. The expansion is expected to be complete during early 2014 and has been designed to allow for additional future expansion of 12 mmscf/d.
Southwest Saskatchewan
In second quarter, the Government of Saskatchewan issued a permit approving Crescent Point’s application for a waterflood unit in the Lower Shaunavon resource play. The approval of the Leitchville North Shaunavon Voluntary Unit #1 is a major milestone for the Company’s Lower Shaunavon development plans and will allow Crescent Point to implement the Lower Shaunavon waterflood across a larger area. Crescent Point currently has 3 water injection wells operating in the Leitchville North Shaunavon Voluntary Unit #1. The Company plans to convert a total of 5 wells to water injection wells in 2013 and up to an additional 10 wells in 2014. As well, Crescent Point plans to submit an application for the approval of a second unit adjacent to Unit #1 in fourth quarter 2013. Field wide, the Company is currently injecting water into 31 converted wells in both the Lower and Upper Shaunavon unconventional zones, with several of the offset producers showing positive response through shallowing declines and increased production.
During second quarter, the Company participated in the drilling of 11 (11.0 net) oil wells in southwest Saskatchewan, all in the Shaunavon area, achieving a 100 percent success rate. To date, the Company has successfully drilled 40 of the 95 net wells planned for the Shaunavon area in 2013, including drilling 8 of the 19 Lower Shaunavon infill wells spaced at 8 wells per section. In 2013, Crescent Point expects to spend approximately $315 million in the area, including expenditures on land, seismic and facilities.
In second quarter, Crescent Point expanded its rail-loading facility, increasing capacity to 12,000 bbl/d from 8,000 bbl/d, and began construction of two oil storage tanks, with 120,000 barrels of total working storage. The tanks are adjacent to the rail-loading facility and are expected to be operational in early 2014.
Early in the quarter, the regional pipeline transporting much of the Company’s southwest Saskatchewan production was shut-in by the operator for approximately one month as a precaution due to local flooding conditions downstream of Crescent Point’s production. Through a combination of rail, storage and trucking to other facilities, Crescent Point was able to maintain its budgeted production levels in the area, which highlights our flexibility and effective operational risk management to move production outside of pipeline constraints. The incremental trucking increased the Company’s second quarter transportation costs.
South/Central Alberta and West Central Saskatchewan
Crescent Point has reduced its drilling pace in the south/central Alberta area to further evaluate 2012 drilling results, to focus on optimizing and evaluating new completion techniques and to reduce costs. During second quarter, Crescent Point participated in the drilling of 1 (0.3 net) oil wells in the Beaverhill Lake light oil resource play, achieving a 100 percent success rate. In early May, Crescent Point and its partner began injecting water into their first waterflood pilot in the Beaverhill Lake play. Plans are underway to submit an application for a second, and operated, waterflood pilot, located south of the existing pilot, with plans to begin water injection in the first half of 2014.
United States
The Company continues to be pleased with results to date in the Uinta Basin, with wells operating at or above expectations and current production levels greater than 10,000 boe/d, a 28 percent increase from the production acquired with Ute Energy. The Company is testing various new completions techniques in the area to further increase fracture stimulation efficiency and improve production rates and ultimate recoveries. Crescent Point also expects to implement a 3-D seismic program covering a large portion of the Company’s operated lands in the Randlett area in fourth quarter 2013.
During second quarter, the Company participated in the drilling of 41 (26.6 net) oil wells in the Uinta Basin, achieving a 100 percent success rate. In all, Crescent Point plans to spend $195 million in the Uinta Basin in 2013, including the drilling of up to 74 net wells. To date, the Company has drilled 53.4 of the 74 net wells planned for the Uinta Basin in 2013.
During second quarter, the Company began using its own equipment and staff to load oil at a third-party rail site in Utah. Rail operations in Utah have allowed the Company to broaden the market for Uinta Basin crude beyond the Salt Lake City refining market. Crescent Point expects to transfer its staff and equipment to its own permanent site later in 2013, with initial capacity at the permanent site designed for greater than 10,000 bbl/d. Rail volumes at the temporary site are currently approximately 2,000 bbl/d.
Crescent Point continues to delineate the geology towards the north end of the Randlett field, where a gas-gathering system was added in early 2013. Up to 12 (10.8 net) wells are planned for this area in 2013, of which 6 (6.0 net) have been drilled to date and are currently being evaluated. The Company is also currently preparing a waterflood injection pilot application in the Randlett area over a 4-section area.
Crescent Point is working with partners to design and participate in the drilling of up to 14 (2.1 net) horizontal wells in the Wasatch and Uteland Butte formations in 2013. To date, 10 (1.7 net) of the wells have been drilled. Initial production rates are encouraging and Crescent Point is monitoring the early decline profile of these wells. The Company anticipates using completion techniques similar to those successfully used in the Viewfield Bakken play to increase recovery factors in Utah.
During second quarter, the Company also participated in the drilling of 8 (1.7 net) oil wells in North Dakota, targeting both the Bakken and Three Forks formations.
OUTLOOK AND UPWARDLY REVISED GUIDANCE FOR PRODUCTION AND FUNDS FLOW FROM OPERATIONS
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.
Crescent Point delivered another record quarter, with significant organic production growth and an active hedging program that has allowed the Company to capitalize on increasing WTI oil prices and a weaker Canadian dollar.
As a result of the Company’s record results year to date, Crescent Point is upwardly revising its 2013 guidance for production and funds flow from operations. Crescent Point’s average daily production in 2013 is expected to increase to 117,500 boe/d from 114,000 boe/d and its 2013 exit production rate is expected to increase to 119,000 boe/d from 117,000 boe/d. Funds flow from operations for 2013 is expected to be approximately $2.0 billion ($5.15 per share – diluted), up from $1.8 billion ($4.63 per share – diluted).
Crescent Point remains disciplined in its approach to capital spending and acquisition opportunities. Capital expenditures for 2013 currently remain unchanged at $1.5 billion. The Company’s 2013 capital program is designed to reduce impacts due to weather and to maximize capital efficiencies. The drilling rig utilization in Crescent Point’s original budget was planned to start in mid-July, which helps mitigate the effects of traditionally wet weather in June. Crescent Point is on track with this capital program, which has allowed the Company to maintain its $1.5 billion capital program while upwardly revising its production forecasts. The Company’s upwardly revised guidance is the result of its successful drilling program in Utah, combined with continued waterflood success in the Bakken and Shaunavon resource plays, lower corporate declines and a delayed spring break-up that was less severe than expected. The Company is well-positioned to meet the new guidance.
Crescent Point has the flexibility to spend additional capital later in 2013 to develop its existing assets and will review its capital expenditures budget later in the year within the context of preliminary 2014 plans and prevailing commodity prices.
“The organic production growth we had during second quarter really highlights the strength of our assets, as well as the continued success of our waterfloods,” said Scott Saxberg, president and CEO. “Though spring break-up was less severe than expected, we continue to be disciplined in our spending. We’re well ahead of our targets for the year and believe we are set up for a successful second half of 2013 and a strong start to 2014.”
Crescent Point has strategically consolidated several large oil-in-place resource plays in western Canada and the United States. This portfolio depth has positioned the Company well for future growth, as Crescent Point believes that the application of infill drilling, waterfloods and new technology across its asset base, combined with potential decreased costs and improved recovery factors, should create additional long-term value for shareholders. For the remainder of 2013, the Company expects to focus on advancing the development of several new production, development and completion techniques and concepts and on executing organic growth projects across its asset base.
As well, Crescent Point expects to continue to develop its expanding waterflood programs in the Bakken and Shaunavon, where recent approvals by the Government of Saskatchewan are helping to advance the Company’s waterflood plans. These waterfloods, along with the waterflood in the Viking resource play, continue to show positive results, and Crescent Point continues to monitor results of its recently initiated waterflood program in the Beaverhill Lake resource play. Next year, the Company also expects to initiate a waterflood program in the Uinta Basin.
Crescent Point is in a strong financial position due to its conservative balance sheet, upwardly revised production and cash flow guidance, and the current commodity price environment. The Company expects to proactively manage DRIP participation levels in future quarters to optimize its balance sheet relative to its short- and long-term growth opportunities and its high rate-of-return drilling inventory. Crescent Point plans to reduce the expected amount of equity issued under its DRIP effective in the fourth quarter through the suspension of the premium component of its DRIP, while maintaining its current dividend of $0.23 per share and the regular component of the DRIP. Factoring in this expected change to the DRIP, the Company’s balance sheet remains strong, with projected average net debt to 12-month cash flow of approximately 1.0 times and significant unutilized credit capacity. The Company continues to be disciplined in its approach to capital spending, acquisition opportunities and balance sheet management.
“Reducing DRIP participation levels is part of our ongoing strategy of executing our business plan on all fronts and will result in less equity being issued through the program,” said Saxberg. “We are focused on applying new technologies to our large oil-in-place asset base, which will increase recovery factors and grow reserves. And we’re being disciplined on costs, which will further increase rates of return on our large drilling inventory.”
Crescent Point continues to implement its disciplined WTI hedging strategy to provide increased certainty over cash flow and dividends. As at August 1, 2013, the Company had hedged 66 percent, 52 percent, 28 percent and 11 percent of its expected oil production, net of royalty interest, for the balance of 2013, 2014, 2015 and 2016, respectively. Average quarterly oil hedge prices range from Cdn$90 per bbl to Cdn$93 per bbl. In addition, the Company has locked in 18,000 bbl/d of fixed price differential contracts from WTI for the balance of 2013. These selling prices are fixed at levels greater than Cdn$90 per bbl.
Crescent Point’s management believes that with the Company’s high-quality reserve base and development drilling inventory, excellent balance sheet and solid risk management program, the Company is well-positioned to continue generating strong operating and financial results through 2013 and beyond.
2013 GUIDANCE
The Company’s upwardly revised guidance for 2013 is as follows:
| Production | Prior | Revised | |||
| Oil and NGL (bbls/d) | 103,500 | 106,667 | |||
| Natural gas (mcf/d) | 63,000 | 65,000 | |||
| Total (boe/d) | 114,000 | 117,500 | |||
| Exit (boe/d) | 117,000 | 119,000 | |||
| Funds flow from operations ($000) | 1,790,000 | 1,990,000 | |||
| Funds flow per share – diluted ($) | 4.63 | 5.15 | |||
| Cash dividends per share ($) | 2.76 | 2.76 | |||
| Capital expenditures (1) | |||||
| Drilling and completions ($000) | 1,288,000 | 1,288,000 | |||
| Facilities, land and seismic ($000) | 212,000 | 212,000 | |||
| Total ($000) | 1,500,000 | 1,500,000 | |||
| Pricing | |||||
| Crude oil – WTI (US$/bbl) | 92.00 | 98.00 | |||
| Crude oil – WTI (Cdn$/bbl) | 93.88 | 101.03 | |||
| Corporate oil differential (%) | 14 | 13 | |||
| Natural gas – AECO (Cdn$/mcf) | 3.75 | 3.25 | |||
| Exchange rate (US$/Cdn$) | 0.98 | 0.97 | |||
| (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
August 8, 2013
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”, “funds flow from operations per share – diluted”, “operating income”, “operating income per share”, “operating income per share – diluted”, “net debt”, “netback”, “market capitalization”, “total capitalization” and “payout ratio”. 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 basic and diluted shares outstanding, respectively. 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 June 30 |
Six months ended June 30 |
||||||||||||||
| ($000s) | 2013 | 2012 | % Change | 2013 | 2012 | % Change | |||||||||
| Cash flow from operating activities | 463,194 | 417,518 | 11 | 922,433 | 718,365 | 28 | |||||||||
| Changes in non-cash working capital | 38,010 | (37,495 | ) | (201 | ) | 27,556 | 54,450 | (49 | ) | ||||||
| Transaction costs | 1,935 | 4,505 | (57 | ) | 5,349 | 7,432 | (28 | ) | |||||||
| Decommissioning expenditures | 1,281 | 1,790 | (28 | ) | 5,025 | 6,980 | (28 | ) | |||||||
| Funds flow from operations | 504,420 | 386,318 | 31 | 960,363 | 787,227 | 22 | |||||||||
Operating income is calculated based on net income before amortization of exploration and evaluation (“E&E”) undeveloped land, 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 marketable securities and long-term investments. Operating income per share and operating income per share – diluted are calculated as operating income divided by the number of weighted average basic and diluted shares outstanding, respectively. Management utilizes operating income to present a measure of financial performance that is more comparable between periods. Operating income as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS.
The following table reconciles net income to operating income:
| Three months ended June 30 | Six months ended June 30 | |||||||||||||||||
| ($000s) | 2013 | 2012 | % Change | 2013 | 2012 | % Change | ||||||||||||
| Net income | 72,332 | 287,430 | (75 | ) | 70,720 | 283,542 | (75 | ) | ||||||||||
| Amortization of E&E undeveloped land | 69,568 | 60,191 | 16 | 139,035 | 116,822 | 19 | ||||||||||||
| Unrealized derivative (gains) losses | (43,699 | ) | (369,360 | ) | (88 | ) | 34,476 | (279,917 | ) | (112 | ) | |||||||
| Unrealized foreign exchange loss on translation of US dollar senior guaranteed notes | 34,667 | 18,422 | 88 | 48,903 | 10,878 | 350 | ||||||||||||
| Unrealized loss on long-term investments | 12,545 | 70,616 | (82 | ) | 8,909 | 74,308 | (88 | ) | ||||||||||
| Deferred tax relating to adjustments | (15,105 | ) | 67,710 | (122 | ) | (57,390 | ) | 28,579 | (301 | ) | ||||||||
| Operating income | 130,308 | 135,009 | (3 | ) | 244,653 | 234,212 | 4 | |||||||||||
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) | June 30, 2013 | June 30, 2012 | % Change | |||||||
| Long-term debt | 1,648,799 | 1,949,082 | (15 | ) | ||||||
| Current liabilities | 705,090 | 463,300 | 52 | |||||||
| Current assets | (350,234 | ) | (341,838 | ) | 2 | |||||
| Long-term investments | (75,997 | ) | (97,867 | ) | (22 | ) | ||||
| Excludes: | ||||||||||
| Derivative asset | 5,911 | 54,603 | (89 | ) | ||||||
| Derivative liability | (57,150 | ) | (4,741 | ) | 1,105 | |||||
| Unrealized foreign exchange on translation of US dollar senior guaranteed notes | (51,079 | ) | (18,828 | ) | 171 | |||||
| Net debt | 1,825,340 | 2,003,711 | (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.
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; anticipated oil and natural gas production levels; expected capital expenditure levels; drilling programs; the future cost to drill wells, including anticipated cost savings associated therewith; the use of acid stimulation techniques; the initiation and ongoing development of planned and existing waterflood programs; the expected impact of waterfloods on corporate declines and reserves; the quantity of Crescent Point’s oil and natural gas reserves and anticipated future cash flows from such reserves; the quantity of drilling locations in inventory; projections of commodity prices and costs; supply and demand for oil and natural gas; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; the possible reduction in the amount of new equity available for issuance under the premium component of the Company’s DRIP; expected debt levels and credit facilities; facility expansion and construction plans, and the anticipated timing of completion thereof; expected deliveries by rail; the addition of rail loading facilities, including in Utah; expected spring break-up; and treatment under governmental regulatory regimes and the state of certain governmental approvals.
By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks discussed in our annual information form under “Risk Factors” and our Management’s Discussion and Analysis for the year ended December 31, 2012, under the headings “Risk Factors” and “Forward-Looking Information.” The material assumptions are disclosed in the Management’s Discussion and Analysis for the year ended December 31, 2012, under the headings “Dividends”, “Capital Expenditures”, “Decommissioning Liability”, “Liquidity and Capital Resources”, “Critical Accounting Estimates”, “Future Changes in Accounting Policies” and “Outlook” and in Management’s Discussion and Analysis for the period ended June 30, 2013, under the headings “Dividends”, “Capital Expenditures”, “Decommissioning Liability”, “Liquidity and Capital Resources”, “Changes in Accounting Policies” and “Outlook”. The actual results could differ materially from those anticipated in these forward-looking statements as a result of the material risks set forth under the noted headings, which include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry.
Barrels of oil equivalent (“boes”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.
Additional information on these and other factors that could affect Crescent Point’s operations or financial results are included in Crescent Point’s reports on file with Canadian securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or otherwise and Crescent Point undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law.
Crescent Point is a conventional oil and gas producer with assets strategically focused in properties comprised of high-quality, long-life, operated light and medium oil and natural gas reserves in United States and Canada.
Crescent Point shares are traded on the Toronto Stock Exchange under the symbol CPG.
Crescent Point Energy Corp.
Trent Stangl
Vice President Marketing and Investor Relations
(403) 693-0020 or Toll-free (US & Canada): 888-693-0020
(403) 693-0070 (FAX)
Crescent Point Energy Corp.
Suite 2800, 111-5th Avenue S.W.
Calgary, Alberta T2P 3Y6
www.crescentpointenergy.com