CALGARY, March 5, 2014 /CNW/ – Legacy Oil + Gas Inc. (“Legacy” or the “Company”) (TSX: LEG) is pleased to announce its 2013 year-end reserves and provide an operational update.
The financial and operational information contained below is based on the Company’s unaudited expected results for the year ended December 31, 2013.
- 2013 net asset value per share grew by 20 percent over 2012 to $11.71 per share
- 2013 total proved plus probable finding and development costs (“F&D”) (including changes in future development costs) decreased 12 percent from 2012 to $20.20 per Boe
- 2013 total proved plus probable finding, development and acquisition costs (“FD&A”) (including changes in future development costs) decreased 3 percent from 2012 to $22.01 per Boe
- Generated a recycle ratio of 2.5 times (F&D) and 2.3 times (FD&A) based on estimated 2013 average netbacks of $49.86 per Boe
- Total proved plus probable reserves grew by 24 percent to 117.2 MMBoe (84 percent oil and NGL’s) at year end 2013 from 94.2 MMBoe (84 percent oil and NGL’s) at year end 2012
- Total proved reserves grew by 20 percent to 66.7 MMBoe at year end 2013 from 55.4 MMBoe at year end 2012
- 2013 production averaged 19,013 Boe per day, an increase of 17 percent over 2012 average production of 16,301 Boe per day
- Proved developed producing reserves comprise 71 percent of the total proved reserves
- Total proved reserves comprise 57 percent of the total plus probable reserves
- Replaced 276 percent of production on a total proved plus probable basis organically and 434 percent total including acquisitions
- Total proved plus probable reserve life index equates to an industry-leading 15.2 years based on fourth quarter 2013 average production
- Total future development costs represent approximately one year of cash flow for total proved reserves and two years for total proved plus probable reserves
In this press release, all references to reserves are to gross company reserves, meaning Legacy’s working interest reserves before deductions of royalties and before consideration of Legacy’s royalty interests. The reserves were evaluated by Sproule Associates Limited (“Sproule”) in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) effective December 31, 2013. Legacy’s annual information form for the year ended December 31, 2013 (the “AIF”) will contain Legacy’s reserves data and other oil and natural gas information as mandated by NI 51-101. Legacy is required to file the AIF on SEDAR on or before March 31, 2014.
The following tables are a summary of Legacy’s petroleum and natural gas reserves as evaluated by Sproule effective December 31, 2013 using forecast prices and costs. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates provided herein. Reserves information may not add due to rounding.
|Light and||Total Oil|
|Medium Oil||Natural Gas||NGL’s||Equivalent|
|Proved Developed Non-Producing||652.0||149||26.6||703.4|
|Total Proved plus Probable||83,863.9||111,006||14,792.7||117,157.7|
Net Present Value of Future Net Revenue
|Before Future Income Tax Expenses and Discounted at|
|Total Proved plus Probable||4,904,320||3,195,923||2,355,598||1,858,941||1,530,695|
|After Future Income Tax Expenses and Discounted at|
|Total Proved plus Probable||3,995,386||2,659,770||1,990,317||1,588,857||1,320,481|
Pricing Assumptions – Forecast Prices and Costs
Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2013 in estimating reserves data using forecast prices and costs. For the year ended December 31, 2013, Legacy’s average realized sales prices before hedging were $2.91/Mcf for natural gas and $87.40/bbl for crude oil and NGLs.
|AECO – C Spot
Thereafter escalation rate of 1.5%
Reconciliation of Changes in Reserves
The following table sets forth a reconciliation of Legacy’s gross reserves as at December 31, 2013 to the gross reserves as at December 31, 2012.
| Light and
|Natural Gas||Total Oil
|Balance at December 31, 2012||38,678.8||6,700.8||60,165.0||55,407.1|
|Extensions and Improved Recovery||3,822.7||576.5||5,053.0||5,241.4|
|Balance at December 31, 2013||44,952.3||9,549.7||73,242.0||66,709.0|
| Light and
|Natural Gas||Total Oil
|Balance at December 31, 2012||30,638.8||3,489.6||27,736.0||38,751.2|
|Extensions and Improved Recovery||3,346.2||473.3||4,123.0||4,506.7|
|Balance at December 31, 2013||38,911.6||5,243.0||37,764.0||50,448.7|
| Light and
|Natural Gas||Total Oil
|Proved + Probable||(MBbls)||(MBbls)||(MMcf)||(MBoe)|
|Balance at December 31, 2012||69,317.7||10,190.4||87,901.0||94,158.3|
|Extensions and Improved Recovery||7,168.9||1,049.8||9,176.0||9,748.1|
|Balance at December 31, 2013||83,863.9||14,792.7||111,006.0||117,157.6|
Future Development Costs
The table below sets out the total future development costs (“FDC”) deducted in the estimation by Sproule of the future net revenue attributable to proved reserves and proved plus probable reserves.
|Proved Reserves||Proved Plus
CAPITAL EXPENDITURES AND FINDING, DEVELOPMENT AND ACQUISITION COSTS
Legacy incurred capital expenditures of $508.3 million in 2013, of which $187.1 million was related to strategic net asset acquisitions and divestitures and $321.2 million on organic opportunities, including $4.7 million of capitalized general and administrative costs.
The Company’s total proved plus probable finding, development and acquisition costs for 2013 were $22.01 per Boe (including change in FDC), which generated a 2.3 times recycle ratio based on Legacy’s 2013 estimated average operating netback of $49.86 per Boe.
|2013 Capital Expenditures||Total Proved plus Probable (1)||Total Proved (1)|
|Capital costs ($ thousands)|
|Exploration & development drilling & associated costs||307,129||307,129|
|Land & seismic||13,639||13,639|
|Net acquisitions and divestitures||187,086||187,086|
|Change in FDC||149,752||83,828|
|2013 Reserve Additions (MBoe) (2)|
|Exploration & development||18,986||11,599|
|Finding & Development Costs ($ per Boe) (3)|
|2013 excluding change in FDC||16.90||27.66|
|2013 including change in FDC||20.20||30.77|
|2012 excluding change in FDC||26.22||35.82|
|2012 including change in FDC||23.05||28.79|
|3-year weighted average cost, excluding change in FDC||21.97||34.47|
|3-year weighted average cost, including change in FDC||25.88||36.40|
|Finding, Development & Acquisition Costs ($ per Boe) (4)|
|2013 excluding change in FDC||17.00||27.94|
|2013 including change in FDC||22.01||32.55|
|2012 excluding change in FDC||25.85||35.07|
|2012 including change in FDC||22.72||28.17|
|3-year weighted average cost, excluding change in FDC||24.18||38.04|
|3-year weighted average cost, including change in FDC||28.76||40.86|
|(1)||The aggregate of the exploration and development costs incurred in the most recent financial period and the change during that period in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that period.|
|(2)||Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 1 Boe: 6 Mcf natural gas has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent a value equivalency at the wellhead.|
|(3)||Includes revisions. Determined by dividing the sum of exploration, development, land & seismic costs and, where indicated, changes to FDC by additions to reserves, other than additions through net acquisitions. Changes to FDC for the purposes of this calculation do not include $87.0 million on a total proved plus probable basis and $47.7 million on a total proved basis of changes in FDC attributable to reserve additions through net acquisitions.|
|(4)||Includes revisions. Determined by dividing the sum of exploration, development, land, seismic and acquisition costs and, where indicated, changes to FDC, by additions to reserves, including additions through net acquisitions. This supplemental measure has been included as Legacy believes it provides important information respecting the cost effectiveness of net acquisitions.|
Net asset value (“NAV”) per share
The following table outlines Legacy’s NAV per basic common share (unaudited) using the Proved plus Probable reserve value at December 31, 2013, before tax and discounted at 10%, and forecast pricing and costs:
|Proved Plus Probable Reserve Value NPV10 BT (incl. future capital) (MM$)||$2,355.6|
|Undeveloped Land (388,806 acres) (1) (unaudited) (MM$)||$137.9|
|Investment in LGX (unaudited) (MM$)||$14.0|
|Estimated Net Debt (unaudited) (MM$)||($667.4)|
|Total Net Assets (basic)||$1,840.1|
|Basic Common Shares Outstanding (MM)||157.2|
|Estimated NAV per Basic Common Share||$11.71|
(1) Represents carrying value of the Company’s exploration and evaluation assets
The Company drilled 22 (17.8 net) wells in the fourth quarter of 2013, all targeting light oil, with a 100 percent success rate. This total included 9 (8.5 net) Midale horizontal wells. In the fourth quarter of 2013, Legacy significantly underspent its funds flow from operations for the quarter while commencing a number of key infrastructure projects that are forecast to be completed in the first quarter of 2014.
Legacy drilled 139 (114.2 net) wells in 2013, with a 99 percent success rate, The Company met its 2013 production guidance, averaging 19,013 Boe per day, an increase of 17 percent over 2012 average production of 16,301 Boe per day. Total capital expenditures on organic opportunities for 2013 were $316.4 million (not including capitalized G&A, corporate fixed assets or net acquisitions and divestitures).
Legacy drilled 9 (8.5 net) Midale wells in the fourth quarter including a number of step-out and delineation wells over a wide area. The wells have an average 30 day initial rate of 210 Boe per day per well. The Company has proven up a substantial inventory of Midale locations. Based on recent pricing, Legacy expects payouts of less than 8 months and internal rates of return in excess of 100% on these wells.
The Company drilled 3 (2.2 net) wells in the fourth quarter of 2013. A modified frac fluid was used on two wells in Pierson with encouraging results. The wells have average 30 day initial rates of 160 Boe per day per well and average water cuts of 25 percent, both significant improvements over historical results.
The Company drilled 3 (2.0 net) wells in Star Valley in the fourth quarter of 2013. The wells have an average 30 day initial rate of 210 Boe per day per well.
Horizontal wells drilled in late 2012 and throughout 2013 continue to outperform. Average cumulative production from these wells after six months is 122 percent higher than the wells drilled by the previous operator, improving the area internal rates of return, payouts and net present values.
Operational momentum continued through 2013 with Legacy achieving cost effective per share growth in reserves, production and cash flow. Legacy met or exceeded its 2013 performance objectives while spending essentially within budget and demonstrating strong results:
|F&D Costs||$20.20 per Boe|
|P+P Recycle Ratio (F&D)(1)||2.5 X|
|FD&A Costs||$22.01 per Boe|
|P+P Recycle Ratio (FD&A)(1)||2.3 X|
|NAV per share||$11.71 per share|
|NAV per share growth (2012-2013)||20%|
|P+P Reserves per share growth (2012-2013)||14%|
(1) Based on Legacy’s 2013 estimated average operating netback of $49.86 per Boe.
As a light oil weighted (89 percent oil and NGL’s) company, Legacy’s 2013 performance positions the Company for continued solid production growth with good capital efficiencies from its extensive inventory of 2,000 net light oil development locations and waterflood assets.
Conference call details
Legacy expects to release its 2013 year end operational and financial results Tuesday, March 25, 2014. Management will be holding a conference call for investors, financial analysts, media and any interested persons on Wednesday, March 26, 2014 at 9:00 a.m. (MDT) (11:00 a.m. EDT) to discuss the 2013 year end results.
The investor conference call details are as follows:
Participant Dial-In Number(s):
- Operator Assisted Toll-Free Dial-In Number: (888) 231-8191
- Local Dial-In Number: (403) 451-9838
- Conference ID: 7724676
Note: In order to join this conference call, you will be required to provide the Conference ID Number listed above.
The determination of oil and natural gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.
The recovery and reserve estimates of oil, NGL and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The estimated future net revenue from the production of Legacy’s natural gas and petroleum reserves does not represent the fair market value of Legacy’s reserves.
The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in Legacy’s AIF, which will be filed on SEDAR on or before March 31, 2014.
Caution Respecting BOE
In this press release, the abbreviation BOE means barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency conversion ratio of 6 Mcf to 1 BOE, utilizing a conversion ratio of 6 Mcf to 1 BOE may be misleading as an indication of value.
Calculation of Netbacks
Netbacks are calculated by deducting royalties paid and operating costs, including transportation costs, from prices received, excluding the effects of hedging.
Forward Looking Statements
This press release contains forward-looking statements. More particularly, this press release contains statements concerning the expected average internal rates of return and average payout times for Midale wells and Legacy’s total potential number of drilling locations.
The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Legacy, including expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, the viability of waterflood projects, the availability and cost of services and prevailing commodity prices, weather conditions and economic conditions.
Although Legacy believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Legacy can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), constraint in the availability of services, commodity price and exchange rate fluctuations, adverse weather conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects, waterflood projects or capital expenditures. Certain of these risks are set out in more detail herein and in Legacy’s annual information form for the year ended December 31, 2012 which has been filed on SEDAR and can be accessed at www.sedar.com.
The forward-looking statements contained in this press release are made as of the date hereof and Legacy undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
SOURCE Legacy Oil + Gas Inc.
For further information:
Trent J. Yanko, P.Eng.
President + CEO
Legacy Oil + Gas Inc.
4400 Eighth Avenue Place
525 – 8th Avenue SW
Calgary, AB T2P 1G1
Matt Janisch, P.Eng.
Vice-President, Finance + CFO
Legacy Oil + Gas Inc.
4400 Eighth Avenue Place
525 – 8th Avenue SW
Calgary, AB T2P 1G1