Legacy Oil + Gas Inc. announces 2012 year-end reserves, strong finding, development and acquisition costs and provides operational update

CALGARY, Feb. 12, 2013 /CNW/ - Legacy Oil + Gas Inc. ("Legacy" or the "Company") (TSX: LEG) is pleased to announce its 2012 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, 2012.

HIGHLIGHTS

  • 2012 total proved plus probable finding, development and acquisitions costs (including changes in future development costs) were $22.72 per Boe
  • Generated a recycle ratio of 2.0 times based on estimated 2012 average netbacks of $44.41 per Boe
  • Total proved plus probable reserves grew to 94.2 MMBoe (84 percent oil and NGL's) at year end 2012 from 88.0 MMBoe (84 percent oil and NGL's) at year end 2011, net of 2012 production of 6.0 MMBoe
  • Total proved reserves grew to 55.4 MMBoe at year end 2012 from 52.4 MMBoe at year end 2011
  • 2012 production averaged 16,301 Boe per day, an increase of 29 percent over 2011 average production of 12,650 Boe per day
  • Production reached Legacy's forecast 2012 exit rate of 17,900 Boe per day in November of 2012
  • Total capital expenditures on organic opportunities for 2012 were $307.7 million (not including capitalized G&A, corporate fixed assets or net acquisitions and divestitures) compared to guidance of $305 million
  • Proved developed producing reserves comprise 73 percent of the total proved reserves
  • Total proved reserves comprise 59 percent of the total plus probable reserves
  • Replaced 205 percent of production on a total proved plus probable basis
  • Total proved plus probable reserve life index equates to an industry-leading 14.8 years based on fourth quarter 2012 average production
  • Legacy reiterates its 2013 guidance of average production of 17,900 Boe per day with associated capital expenditures of $290 million

RESERVES

In this press release, all references to reserves are to gross company reserves, meaning Legacy's working interest reserves before calculations 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, 2012.  Legacy's annual information form for the year ended December 31, 2012 (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, 2013.

The following tables are a summary of Legacy's petroleum and natural gas reserves as evaluated by Sproule effective December 31, 2012 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.

Reserves Summary

         
  Light and       Total Oil
  Medium Oil  Natural Gas  NGL's  Equivalent
  (MBbl)  (MMcf)  (MBbl)  (MBoe)
Proved Producing  28,631.1  42,067  4,988.3  40,630.7
Proved Developed Non-Producing  419.4  123  22.6  462.5
Proved Undeveloped  9,628.3  17,974  1,689.9  14,313.9
Total Proved  38,678.8  60,165  6,700.8  55,407.1
Probable  30,638.8  27,736  3,489.6  38,751.1
Total Proved plus Probable  69,317.7  87,901  10,190.4  94,158.2
         

Net Present Value of Future Net Revenue

  Before Future Income Tax Expenses and Discounted at
  0%   5%   10%   15%   20%
       
  (M$)   (M$)   (M$)   (M$)   (M$)
Proved                  
  Developed Producing 1,519,576   1,122,365   904,552   768,019   673,852
  Developed Non-Producing 18,109   15,040   12,916   11,367   10,190
  Undeveloped 453,412   271,841   176,793   118,685   79,856
Total Proved 1,991,097   1,409,246   1,094,261   898,071   763,899
Probable 1,730,122   933,866   597,553   419,216   310,921
Total Proved plus Probable 3,721,219   2,343,112   1,691,813   1,317,287   1,074,820
                   

  After Future Income Tax Expenses and Discounted at
  0%   5%   10%   15%   20%
       
  (M$)   (M$)   (M$)   (M$)   (M$)
Proved                  
  Developed Producing 1,422,495   1,078,839   882,321   755,631   666,508
  Developed Non-Producing 13,412   11,933   10,810   9,910   9,163
  Undeveloped 340,732   202,778   130,193   85,490   55,359
Total Proved 1,776,639   1,293,550   1,023,324   851,031   731,030
Probable 1,288,114   688,713   436,467   303,153   222,531
Total Proved plus Probable 3,064,753   1,982,262   1,459,791   1,154,184   953,560
                   

Pricing Assumptions - Forecast Prices and Costs

Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2012 in estimating reserves data using forecast prices and costs. The weighted average historical prices received by Legacy for 2012 are also reflected in the table below.

       
Year WTI
Cushing
Oklahoma
40° API
(US$/Bbl)
Edmonton
Par Price
40° API
($/Bbl)
Cromer
Medium
29.3º API
($/Bbl)
AECO - C Spot
($/MMBtu)
Pentanes
Plus
($/Bbl)
Exchange
Rate
($US/$Cdn)
2012
(Actual)
94.19 86.53 80.95 2.43 100.76 1.001
2013 89.63 84.55 77.79 3.31 90.53 1.001
2014 89.93 89.84 82.66 3.72 96.19 1.001
2015 88.29 88.21 81.15 3.91 94.44 1.001
2016 95.52 95.43 88.75 4.70 102.18 1.001
2017 96.96 96.87 90.09 5.32 103.71 1.001
2018 98.41 98.32 91.44 5.40 105.27 1.001
2019 99.89 99.79 92.81 5.49 106.85 1.001
2020 101.38 101.29 94.20 5.58 108.45 1.001
2021 102.91 102.81 95.61 5.67 110.08 1.001
2022 104.45 104.35 97.05 5.76 111.73 1.001
2023 106.02 105.92 98.50 5.85 113.40 1.001

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, 2012 to the gross reserves as at December 31, 2011.

    Light and
Medium Crude
Oil
Natural Gas
Liquids
Natural Gas Total Oil
Equivalent
Proved (MBbls) (MBbls) (MMcf) (MBoe)
  Balance at December 31, 2011 35,960.4 6,368.6 60,452 52,404.1
  Extensions and Improved Recovery 2,861.7 45.6 561.0 3,000.8
  Technical Revisions 3,249.8 752.8 3,712 4,621.3
  Infill Drilling 1,363.8 46.5 398 1,476.6
  Discoveries - - - -
  Acquisitions 250.1 15.5 123 286.1
  Dispositions (108.3) - (51) (116.8)
  Economic Factors (290.3) (29.1) (460) (396.1)
  Production (4,608.4) (499.1) (4,570) (5,869.2)
  Balance at December 31, 2012 38,678.8 6,700.8 60,165 55,407.1
           

    Light and
Medium Crude
Oil
Natural Gas
Liquids
Natural Gas Total Oil
Equivalent
Probable (MBbls) (MBbls) (MMcf) (MBoe)
  Balance at December 31, 2011 28,468.1 2,940.6 25,076 35,588.2
  Extensions and Improved Recovery 3,740.8 172.4 1,792 4,211.9
  Technical Revisions (2,919.2) 335.6 525 (2,496.1)
  Infill Drilling 1,384.7 32.1 232 1,455.5
  Discoveries - - - -
  Acquisitions 92.8 8.9 72 113.7
  Dispositions (132.2) - (30) (137.2)
  Economic Factors 3.9 - 69 15.4
  Production - - - -
  Balance at December 31, 2012 30,638.8 3,489.6 27,736 38,751.1
           

    Light and
Medium Crude
Oil
Natural Gas
Liquids
Natural Gas Total Oil
Equivalent
Proved + Probable (MBbls) (MBbls) (MMcf) (MBOoe)
  Balance at December 31, 2011 64,428.5 9,309.2 85,528 87,992.4
  Extensions and Improved Recovery 6,602.5 218.0 2,353 7,212.7
  Technical Revisions 330.6 1,088.4 4,237 2,125.2
  Infill Drilling 2,748.5 78.6 630 2,932.1
  Discoveries - - - -
  Acquisitions 342.9 24.4 195 399.8
  Dispositions (240.5) - (81) (254.0)
  Economic Factors (286.4) (29.1) (391) (380.7)
  Production (4,608.4) (499.1) (4,570) (5,869.2)
  Balance at December 31, 2012 69,317.7 10,190.4 87,901 94,158.2
           

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
Probable Reserves
     
    (M$)   (M$)
2013   128,909   215,362
2014   88,890   198,569
2015   27,660   93,413
2016   9,061   67,060
2017   7,972   23,916
Remaining Years   2,578   2,578
Total Undiscounted   265,070   600,897

CAPITAL EXPENDITURES AND FINDING, DEVELOPMENT AND ACQUISITION COSTS

Legacy incurred capital expenditures of $311.1 million in 2012, of which ($0.6) million was realized on strategic net asset acquisitions and divestitures and $311.7 million on organic opportunities, including $4.1 million of capitalized general and administrative costs.

The Company's total proved plus probable finding, development and acquisition costs for 2012 were $22.72 per Boe (including change in FDC), which generated a 2.0 times recycle ratio based on Legacy's 2012 estimated average operating netback of $44.41 per Boe.

     
2012 Capital Expenditures                                                 Total Proved plus Probable (1) Total Proved (1)
Capital costs ($ thousands)    
  Exploration & development drilling & associated costs 306,632 306,632
  Land & seismic 5,131 5,131
  Net acquisitions and divestitures (619) (619)
  Change in FDC  (37,735) (61,207)
2012 Reserve Additions (MBoe) (2)    
Exploration & development 11,889 8,703
Net acquisitions 146 169
     
Finding & Development Costs ($ per Boe) (3)    
2012 excluding change in FDC 26.22 35.82
2012 including change in FDC 23.05 28.79
     
2011 excluding change in FDC 25.44 43.75
2011 including change in FDC 36.66 54.10
     
3-year weighted average cost, excluding change in FDC 25.69 39.39
3-year weighted average cost, including change in FDC 31.77 43.55
     
Finding, Development & Acquisition Costs ($ per Boe) (4)    
     
2012 excluding change in FDC 25.85 35.07
2012 including change in FDC 22.72 28.17
     
2011 excluding change in FDC 37.43 62.29
2011 including change in FDC 47.46 71.25
     
3-year weighted average cost, excluding change in FDC 25.94 40.03
3-year weighted average cost, including change in FDC 30.09 43.60
     

(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.
(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.
   

NET ASSET VALUE PER SHARE

The following table outlines Legacy's NAV per Basic Common Share (unaudited) using the Proved plus Probable reserve value at December 31, 2012 and forecast pricing and costs:

($MM except share and per share amounts)  
Proved Plus Probable Reserve Value NPV10 BT (incl. future capital) $1,691.8
Undeveloped Land (370,605 acres @ carrying value) $183.4
Investment in LGX $10.0
Estimated Net Debt (unaudited) ($488)
Total Net Assets (basic) $1,397.2
Basic Common Shares Outstanding (MM) 143.3
Estimated NAV per Basic Common Share $9.75



OPERATIONAL UPDATE

The Company drilled 145 (110.4 net) wells in 2012 including 32 (24.7 net) wells in the fourth quarter of 2012, all targeting light oil, with a 100 percent success rate.  This total included 14 (10.3 net) horizontal wells in its Spearfish play at Pierson, Manitoba and Bottineau County, North Dakota in the fourth quarter of 2012.

The Company met its 2012 production guidance, averaging 16,301 Boe per day, an increase of 29 percent over 2011 average production of 12,650 Boe per day.  Production reached Legacy's forecast 2012 exit rate of 17,900 Boe per day in November of 2012.  Total capital expenditures on organic opportunities for 2012 were $307.7 million (not including capitalized G&A, corporate fixed assets or net acquisitions and divestitures) compared to guidance of $305 million.

SPEARFISH PLAY

At Pierson, Manitoba, the Company continues to deliver excellent production results in the Spearfish compared to the previous operator's drilling and these results have significantly influenced the type curve used in the 2012 year-end independent engineering report.  Undeveloped locations included in the 2012 independent engineering report have been assigned reserves 25 percent higher than in the 2011 independent engineering report.  Legacy has achieved these rates while constraining production to maximize ultimate recovery.  The Company believes these achievements will lead to superior long term performance, higher per well reserve bookings plus additional locations booked.

Similarly, at Bottineau County, North Dakota, undeveloped locations included in the 2012 independent engineering report have been assigned reserves 25 percent higher than in the 2011 independent engineering report.  Legacy has achieved these rates while constraining production to maximize ultimate recovery.

The total Spearfish play development drilling inventory of 440 net potential locations (84 percent unbooked) is based on eight wells per section.  Based on other operators' results in the play, Legacy's location count could increase by 50 percent through downspacing.  In addition, the Company is evaluating the waterflood potential in the play and anticipates recovery factors of up to 14 percent, based on analogous pools.

BAKKEN PLAY

At Star Valley, Legacy has applied its leading fracture stimulation design developed in Heward to this area with good success.  Legacy brought 5 (4.0 net) wells on production since the start of the fourth quarter of 2012 and these wells have average 30 day initial rates of 200 Boe per day per well and average 60 day initial rates of 170 Boe per day.  As previously disclosed, the Company believes the Bakken play boundaries have expanded and has increased its drilling location inventory to more than 50 net wells in Star Valley.

At Taylorton, the Company has continued to observe improved waterflood response in both the original and expanded pilot areas.  In the section 29 pilot, oil production has increased 2.6 times, with a corresponding increase in fluid rate, fluid level and reduction in water cut.  The pilot was expanded into section 28 in July 2012 and this area has already demonstrated a 3.7 times increase in oil production rate.  Legacy has moved forward with additional waterflood pilot expansion into the section to the south.

At Heward, the pilot waterflood project initiated in December 2011 continues to demonstrate waterflood response as the oil production rate in eight offsetting wells has increased since the commencement of the pilot.  The wells seeing response have exhibited a 6.4 times increase in oil production since commencement of injection and the Company is rapidly expanding the waterflood pilot project into three additional sections in the first half of 2013.

TURNER VALLEY

At Turner Valley, Legacy has continued to evolve drilling and completion practices to optimize both production rate and capital costs.  Drilling to-date has targeted infill locations testing areas of varying water cut, reservoir pressure, proximity to water injection and three different stratigraphic horizons.  As previously disclosed, horizontal wells in Turner Valley have typically come on production with a high water cut and as load fluid is recovered, the water cuts decrease and the oil rates increase.  This phenomenon has been observed in the 22 horizontal wells drilled by the previous operator and in the wells drilled by Legacy.  In turn, the Company expects the Turner Valley horizontal wells to produce at stable, low decline rates based on the production profile demonstrated by both the previously drilled and Legacy drilled wells.

The Hartell #6 well, Boyd #1 well and the Herriman #5 well continue to deliver excellent performance.  Hartell #6 has produced nearly 64 MBoe in just over 14 months of production, Boyd #1 has produced nearly 60 MBoe in less than 10 months of production and Herriman #5 has produced nearly 33 MBoe in less than four months.  All wells continue to be strong producers, averaging 145 Boe per day, 235 Boe per day and 250 Boe per day, respectively.  All wells did not reach peak rates until considerably after first production date.

Production has continued to trend higher on the remainder of the Turner Valley wells as artificial lift optimization has taken place, production run times have improved and recovery of load fluid has resumed.  The most recent example of this characteristic is the Howe #5 well which has seen production increase 10 fold since start-up to 155 Boe per day currently and still improving.

SUMMARY

Operational momentum that began in late 2011 and continued through 2012 has provided Legacy with cost effective per share growth in reserves, production and cash flow. Legacy met or exceeded its 2012 performance objectives while spending essentially within budget and demonstrating strong finding, development and acquisition costs of $22.72 per Boe and a robust recycle ratio of 2.0 times.  As a light oil weighted (89 percent oil and NGL's) company, Legacy's 2012 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 2012 year end operational and financial results Monday, March 18, 2013. Management will be holding a conference call for investors, financial analysts, media and any interested persons on Tuesday, March 19, 2013 at 8:00 a.m. (MDT) (10:00 a.m. EDT) to discuss the 2012 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:  99299373

Note:  In order to join this conference call, you will be required to provide the Conference ID Number listed above.

Reserves Data

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, 2013.

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.

Forward Looking Statements

This press release contains forward-looking statements.  More particularly, this press release contains statements concerning the anticipated average rate of production for 2013, anticipated capital expenditures in 2013, the anticipated impact of constraining production at Legacy's Spearfish properties on well performance and future reserves bookings, the potential number of drilling locations at certain of Legacy's properties and on an overall corporate basis, the waterflood potential of the Spearfish properties and the potential resulting recovery rate and the anticipated production characteristics of  wells at Turner Valley.

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, 2011 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

Telephone: 403.441.2300
Fax: 403.441.2017

Matt Janisch, P.Eng.
Vice-President, Finance + CFO

Legacy Oil + Gas Inc.
4400 Eighth Avenue Place
525 - 8th Avenue SW
Calgary, AB T2P 1G1

Telephone: 403.441.2300
Fax: 403.441.2017