CALGARY, March 20, 2012 /CNW/ - Legacy Oil + Gas Inc. ("Legacy" or the "Company") (TSX: LEG) is pleased to announce it has filed on SEDAR its audited financial statements and related Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2011 as well as its annual information form ("AIF") for the year ended December 31, 2011. Selected financial and operational information is outlined below and should be read in conjunction with Legacy's audited financial statements, the related MD&A and the AIF which are available for review at www.legacyoilandgas.com or www.sedar.com.
FINANCIAL + OPERATIONAL HIGHLIGHTS
|Three Months Ended||Year Ended|
|2011||2010||% change||2011||2010||% change|
|Financial ($000's, except per share amounts)|
|Petroleum and natural gas sales, net of royalties||94,358||60,248||57||300,591||179,111||68|
|Funds generated by operations (1)||60,310||36,320||66||188,852||118,520||59|
|Per share basic||0.42||0.29||45||1.34||1.18||14|
|Per share diluted (2)||0.42||0.28||50||1.32||1.16||14|
|Per share basic||0.05||0.2||(75)||0.14||0.2||(30)|
|Per share diluted (2)||0.05||0.19||(74)||0.13||0.2||(35)|
|Capital expenditures (excluding acquisitions)||117,754||51,733||128||334,783||169,742||97|
|Acquisitions (cash consideration) (4)||1,043||42,814||(98)||112,589||293,888||(62)|
|Net debt and working capital surplus (deficit) (1)||(376,543)||(255,556)||47||(376,543)||(255,556)||47|
|Crude oil (Bbls per day)||11,100||8,339||33||8,984||6,913||30|
|Heavy oil (Bbls per day)||209||251||(17)||271||63||330|
|Natural gas (Mcf per day)||14,018||13,437||4||13,557||7,392||83|
|Natural gas liquids (Bbls per day)||1,235||1,073||15||1,135||557||104|
|Barrels of oil equivalent (Boe per day) (3)||14,880||11,902||25||12,650||8,765||44|
|Average realized price|
|Crude oil ($ per Bbl)||95.39||78.99||21||92.82||76.35||22|
|Heavy oil ($ per Bbl)||79.54||66.24||20||71.24||66.24||8|
|Natural gas ($ per Mcf)||3.79||4.02||(6)||4.02||3.89||3|
|Natural gas liquids ($ per Bbl)||74.73||50.96||46||68.76||52.71||30|
|Barrels of oil equivalent ($ per Boe) (3)||82.03||65.87||25||77.93||67.33||16|
|Netback per Boe ($) (1)|
|Petroleum and natural gas sales||82.03||65.87||25||77.93||67.33||16|
|Operating Netback ($ per Boe) (1)||49.97||40.07||25||47||42.61||10|
|Undeveloped land holdings||(gross acres)||665,026||711,352||(7)||655,026||711,352||(7)|
|Common Shares (000's)|
|Common shares outstanding, end of period||143,259||127,234||13||143,259||127,234||13|
|Weighted average common shares (basic)||143,259||126,916||13||140,901||100,758||40|
|Weighted average common shares (diluted) (2)||143,795||129,571||11||143,365||102,201||40|
|(1)||Management uses funds generated by operations, net debt and working capital surplus (deficit) and operating netback to analyze operating performance and leverage. These terms, as presented, do not have any standardized meaning prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculation of similar measures for other entities.|
|(2)||In calculating the net income (loss) per share diluted, Legacy Oil + Gas Inc. ("Legacy" or the "Company") excludes the effect of outstanding stock options and share warrants outstanding and uses the weighted average common shares (basic) where the Company has a net loss for the period. In calculating, funds generated by operations per share diluted, the Company includes the effect of outstanding stock options and share warrants using the treasury stock method.|
|(3)||Boe means barrel of oil equivalent. All Boe conversions in this report are derived by converting natural gas to oil equivalent at a ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Boe: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.|
|(4)||In addition to cash consideration paid for acquisitions and as part consideration, thereof, for the year ended December 31, 2011, the Company issued 6.2 million common shares valued at $102.7 million using the share price of Legacy on the acquisition date (2010 - 29.5 million common shares valued at $341.2 million on the acquisition dates) and for the three months ended December 31, 2011, the Company issued no common shares as part consideration for acquisitions (2010 - 0.9 million common shares valued at $10.9 million).|
- Closed the Pierson Spearfish asset acquisition; acquired high quality, high netback, light oil assets with an associated significant development horizontal drilling inventory in the Company's Williston Basin core area
- Drilled 133 gross (99.0 net) oil wells in 2011, with a 100 percent success rate. Drilled 42 gross (33.0 net) oil wells in the fourth quarter of 2011, with a 100 percent success rate
- Increased average production from 8,765 Boe per day in 2010 to 12,650 Boe per day in 2011 (44 percent increase); increased average production from 11,920 Boe per day in the fourth quarter of 2010 to 14,880 Boe per day in the fourth quarter of 2011 (25 percent increase); exceeded 16,250 Boe per day 2011 exit production rate guidance, a 59 percent increase from second quarter 2011 average production
- Increased funds generated from operations from $118.5 million in 2010 to $188.9 million in 2011 (59 percent increase); increased funds generated from operations from $36.3 million in the fourth quarter of 2010 to $60.3 million in the fourth quarter of 2011 (66 percent increase)
- Increased funds generated from operations per share (diluted) from $1.16 in 2010 to $1.32 in 2011 (14 percent); increase funds generated from operations per share (diluted) from $0.28 in the fourth quarter of 2010 to $0.42 in the fourth quarter of 2011 (50 percent increase)
- Increased gross proved plus probable reserves from 77.8 MMBoe at December 31, 2010 to 88.0 MMBoe at December 31, 2011 (13 percent increase); proved plus probable reserve additions replaced 318 percent of production in the year
- Generated solid three year total proved plus probable finding, development and acquisition ("FD&A") costs of $22.08 per Boe excluding changes in future development costs ("FDC"), representing a 2.3 times recycle ratio based on fourth quarter of 2011 operating netbacks of $49.97 per Boe
- Maintained proved plus probable reserve life index of 16.2 years at December 31, 2011, based on fourth quarter average production
- Closed one equity financing totaling $140 million
- Entered into a new syndicated banking facility and increased available line of credit to $450 million. Year end 2011 net debt was $376.5 million, representing approximately 1.3 times estimated forward cash flow (using strip pricing)
- Legacy received the APEX Award for Annual Report of the Year for its 2010 annual report and also was awarded best financial statements and analysis by Oilweek Magazine/ATB Financial at the 36th Annual Report Awards
Although the Company had to navigate challenging operating conditions due to the unprecedented spring runoff and pervasive flooding in the majority of its core operating areas, Legacy was able to successfully advance a number of its key development and emerging light oil resource plays. The Company drilled 133 gross (99.0 net) oil wells in 2011, up from 97 gross (66.9 net) wells in 2010, with a 100 percent success rate. In the fourth quarter of 2011, the Company drilled 42 gross (33.0 net) oil wells, with a 100 percent success rate. Activity in the fourth quarter included the drilling of 11 gross (9.8 net) Spearfish horizontal wells in the Company's Pierson and Bottineau County areas.
Legacy was forward-thinking and anticipated a potential "services crunch" in the third and fourth quarter of 2011, due to most of industry trying to catch up on capital activities after the flooding and weather conditions in mid-2011. The Company's fracture services arrangement and proactive management of its drilling fleet enabled Legacy to not only meet but exceed its originally forecast exit rate guidance. This accomplishment is a testament to the Company's ability to manage its base corporate declines as well as the performance of its organic capital program. This successful operational momentum has continued into the first quarter 2012, with Legacy having drilled 47 gross (34.8 net) wells to-date, with a 100 percent success rate.
Legacy's exposure to the Spearfish light oil resource play increased dramatically in 2011, with the acquisition of the Pierson asset in Manitoba. At the end of 2011, Legacy had 75,160 net undeveloped acres in both Pierson and Bottineau County, North Dakota. In a year challenged by weather-caused access issues, the Company was able to drill 20 (18.6 net) wells in the play. Operational momentum has progressed in 2012, with 12 (10.3 net) wells already drilled to date.
Legacy continues to evolve the completion design at Pierson and is demonstrating much better performance than the previous operator, a phenomenon that has been witnessed in a number of other Legacy acquired assets. In Pierson, Legacy-drilled wells have produced 85 percent more oil in the first five months of production compared to the previous operator's wells in the area. The Company believes this performance will lead to superior long term performance and ultimately higher per well reserve bookings. Success also continues in Bottineau County, with wells meeting or exceeding internal expectations. Bottineau County is an extension of the Spearfish play from Canada into North Dakota, and represents a significant unbooked drilling inventory.
In the Spearfish, Legacy has identified in excess of 440 net undeveloped locations (88 percent unbooked), at a spacing of eight wells per section. This risked inventory only includes a portion of the Bottineau County lands and incorporates the well results, geological control and 3D seismic at Pierson. The Company's spacing assumption of eight wells per section could prove to be conservative as other operators are drilling the Spearfish at 24 wells per section. Legacy has been developing the play with one mile long horizontal wells while other operators have been drilling one-half mile horizontal wells. Based on similar spacing, Legacy's number of undeveloped locations would increase by 50 percent.
The Company has also been at the forefront in identifying the waterflood potential in the Spearfish. Based on analogy to the South Pierson Unit, which has been under waterflood since 1993, Legacy anticipates waterflood to result in a 14 percent recovery factor of the original oil in-place.
At Turner Valley, the Company drilled 4 (3.2 net) successful horizontal Rundle oil wells in 2011 (2 gross (1.7 net) in the fourth quarter of 2011) and completed one of these wells with a multistage acid fracture stimulation before year-end. This first well came on production in November 2011 with an initial production of 225 Boe per day and has stabilized at a rate of approximately 170 Boe per day. The three other horizontal wells came on production at various times in the first quarter of 2012 and are exhibiting encouraging rates that are improving over time as water cuts continue to decrease. The recompletion of an existing Rundle horizontal well (7 year old well) in February 2011 with a multistage acid fracture stimulation increased production from 25 Boe per day to 110 Boe per day and the well currently is producing at 100 Boe per day. Also at Turner Valley, Legacy had additional success with another test of its jet pump skid. The subject well was producing at 18 Boe per day prior to installing the jet pump, and the rate has since increased to 45 Boe per day. The Company will provide an operational update on these wells in the coming months.
At Taylorton, modification of the fracture stimulation treatments has led to continual improvements in production rates, with a number of wells achieving the highest initial production rates to-date. Legacy drilled 9 wells that had 30 day initial production rates in excess of 260 Boe per day per well. These wells have continued to perform, with 90 day average production rates of 260 Boe per day per well and six month production rates averaging 190 Boe per day per well. The Company also began injection in April 2011 in a pilot waterflood and has plans to expand this project in 2012. This pilot waterflood could lead to incremental reserve bookings and lower production decline rates and could be expanded depending upon results.
At Star Valley, Legacy has applied its leading fracture stimulation design developed in Heward to this area with good success. As a result, 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 Heward/Stoughton, the Company initiated a pilot waterflood at Heward in November 2011, which could lead to incremental reserve bookings and lower production decline rates and could be expanded depending upon results.
The Torquay (Three Forks) coreflooding study at Frys/Antler was completed in 2011 and Legacy combined the study with a comprehensive geological and geophysical review of the area. Reservoir characteristics, including net pay, porosity and permeability appear similar to the highly successful waterflood in the Sinclair Three Forks 'B' pool located in Manitoba, directly offsetting the Company's lands. This waterflood project has been underway since mid-2006 and has now been expanded to more than 24 sections and is expected to recover up to 30 percent of the Petroleum Initially in Place ("PIIP"), a more than five‐fold increase in recovery factor over primary production. The Legacy study indicates similar potential waterflood recoveries of approximately 30 percent of the PIIP. Legacy has exposure to more than 90 MMSTB of net PIIP in the Torquay at Frys/Antler area (as independently mapped by GLJ Petroleum Consultants Ltd., August 1, 2009). Pilot waterflood implementation on Legacy operated lands is expected later in 2012. No reserves are assigned to waterflood in this area in the December 31, 2011 reserves report.
At Maxhamish, Legacy constructed an all-season road and an additional well pad to permit year-round drilling activity. The Company drilled and fracture stimulated two additional Chinkeh horizontal wells. Liner difficulties in the first well resulted in only half the wellbore being effectively stimulated. However, initial production rates have been encouraging. The second well came on production in January 2012 and continues to recover load fluid and formation oil, but is rate constrained due to surface production equipment limitations. Legacy continues to be encouraged with the play, as the two horizontal wells drilled in 2010 have been producing at a stabilized rate of approximately 55 Boe per day per well after almost two years of production.
Legacy, as operator, drilled and completed two strat to horizontal wells in the Big Valley (Three Forks) formation in the southern Alberta Bakken light oil play. Results have been encouraging but in line with an exploratory, early stage play. Both strat wells encountered multiple oil saturated horizons and the horizontal laterals were drilled into a light oil bearing, overpressured reservoir. Technical work continues on analyzing the geological and reservoir model based on the data gathered from these two wells and will be integrated with recent successes other operators have announced in immediate proximity to Legacy's land. Together, all the information will be used to determine the pace of development in 2012.
In accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), Sproule Associates Ltd. ("Sproule") evaluated, as at December 31, 2011, materially all of Legacy's oil, natural gas liquids and natural gas reserves. Legacy's annual information form for the year ended December 31, 2011 (the "AIF") contains Legacy's reserves data and other oil and natural gas information for the period ended December 31, 2011 as mandated by NI 51-101. A copy of the AIF can be obtained under Legacy's profile at www.sedar.com or at www.legacyoilandgas.com. The summary information provided below should be read in conjunction with the detailed information in the AIF.
As of December 31, 2011, Legacy's total gross proved plus probable reserves base was 88.0 MMBoe, an increase of 13% year over year. Total proved plus probable reserves additions [before divestitures] were 14.7 MMBoe. These additions represent 318 percent of the 4.6 MMBoe produced during 2011. Light and medium oil and NGL's accounted for 84 percent of the proved plus probable reserves base.
Legacy's gross total proved reserves base was 52.4 MMBoe. Total proved reserves represent 60 percent of the total proved plus probable reserves. Proved producing reserves represent 66 percent of the total proved reserves base. Total proved reserves additions [before divestitures] were 8.8 MMBoe. These additions represent 191 percent of the 4.6 MMBoe produced during 2011. Light and medium oil and NGL's accounted for 81 percent of the total proved reserves base.
The following table is a summary, as at December 31, 2011, of Legacy's petroleum and natural gas reserves as evaluated by Sproule. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less then the estimates provided herein. Reserves information may not add due to rounding.
|Gross Company Reserves Summary (1)|
|Using Sproule December 31, 2011 Forecast Prices and Costs|
|As at December 31, 2011|
|Light and||Total Oil|
|Medium Oil||Natural Gas||NGL's||Equivalent|
|Proved Developed Non-Producing||539.6||75.9||21.8||574.0|
|Total Proved plus Probable||64,428.5||85,528.2||9,309.2||87,992.4|
|(1)||Gross Company Reserves means the Company's working interest reserves before calculations of royalties and before consideration of the Company's royalty interest.|
CAPITAL EXPENDITURES AND FINDING, DEVELOPMENT AND ACQUISITION COSTS
Legacy incurred capital expenditures of $549.2 million in 2011, of which $215.3 million was spent on strategic corporate and property acquisitions and $334.0 million on organic opportunities.
The Company's total proved plus probable F&D costs for 2011 were $25.44 per Boe (excluding FDC) which generated a 2.0 times recycle ratio, based on the fourth quarter 2011 average operating netback.
|2011 Capital Expenditures||Total Proved plus Probable (2)||Total Proved (2)|
|Capital costs ($ thousands)|
|Exploration & development drilling & associated costs||318,352||318,352|
|Land & seismic||15,601||15,601|
|Change in FDC (1)||147,282||79,017|
|2011 Reserve Additions (MBoe) (3)|
|Exploration & development||13,125||7,634|
|Finding & Development Costs ($ per Boe) (4)|
|3-year weighted average cost, excluding change in FDC||25.25||42.43|
|3-year weighted average cost, including change in FDC||35.72||51.60|
|2011 excluding FDC||25.44||43.75|
|2011 including FDC||36.66||54.10|
|2010 excluding FDC||25.40||38.61|
|2010 including FDC||35.60||47.76|
|Finding, Development & Acquisition Costs ($ per Boe) (5)|
|3-year weighted average cost, excluding change in FDC||22.08||35.05|
|3-year weighted average cost, including change in FDC||28.68||40.46|
|2011 excluding FDC||37.43||62.29|
|2011 including FDC||47.46||71.25|
|2010 excluding FDC||14.54||22.72|
|2010 including FDC||20.09||31.39|
|(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)||Based on gross reserves meaning the total company interest (operated and non-operated) share before deduction of royalties payable to others|
|(3)||Boe conversion ratio for natural gas of 1 Boe: 6 Mcf 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|
|(4)||Includes revisions. Determined by dividing the sum of exploration, development, land & seismic costs and, where indicated, changes to FDC by additions to reserves.|
|(5)||Includes revisions. Determined by dividing the sum of exploration, development, land and seismic costs, acquisition costs and where indicated, changes to FDC by additions to reserves.|
|BOE'S may be misleading, particularly if used in isolation.|
Delays caused by the severe weather in 2011 also impacted reserve bookings, particularly in the Spearfish play. Drilling activity did not commence in Pierson and Bottineau County until August and October, respectively. The encouraging but limited production history resulted in conservative per well reserve bookings and assignment of undeveloped locations. Legacy operated wells continue to outperform both the area historical results and the Sproule proved plus probable type curve. Furthermore, booked undeveloped locations account for only 12 percent of the Legacy identified risked drilling inventory.
The majority of capital spent in Turner Valley also occurred late in the year and had no impact to reserves or values associated with the Rundle infill drilling inventory.
The 3-year weighted average costs above do not include any reserves associated with the acquisition of Bronco Energy Ltd., but do include the capital expenditures for the acquisition.
Legacy is pleased to announce the appointment of Curt Ziemer to Vice President, Accounting. Mr. Ziemer has more than 23 years of industry experience and was the Controller for Legacy since its inception.
Over the past 12 quarters, Legacy has grown production per share more than 62 percent or 17 percent per year. We have been able to maintain this disciplined level of growth while enduring one the most pervasive and difficult spring-breaks on record. Our producing assets have performed favourably and our new production additions have met or exceeded our expectations, as evidenced by the strong rebound in the Company's production rate, up 59 percent since the second quarter of 2011.
Our goal at Legacy is to deliver 10 to 15 percent per share growth per year, spending cash flow plus our growth rate, for the next three to five years. This sustainable model is designed to deliver superior returns over the near and long term in a low risk platform and is characterized by:
- More than 1,200 net development locations for light oil
- 2012 production is forecast to grow 29 percent year over year compared to 2011
- 2012 budget is essentially fully funded from internally generated cash flow, based on current strip prices.
- Development drilling focused capital program for 2012 (83 percent to drilling, completion, equipping, tie-in)
- Fast-tracking waterflood projects in the Bakken, Torquay (Three Forks) and the Spearfish to build significant net asset value while moderating corporate declines and provide additional opportunity creation
The operational momentum and success that started in the latter part of 2011 has continued into 2012, with Legacy having drilled 47 gross (34.8 net) wells to-date, with a 100 percent success rate. Continuous refinement of mapping, completion programs and production strategies has provided a number of positive results:
- Spearfish production has outperformed the Sproule proved plus probable type curve
- More than 385 net locations are unbooked in the Spearfish which could grow to nearly 600 net locations with inclusion of all Spearfish lands held in North Dakota
- The infill horizontal multi-stage fracture stimulation program in Turner Valley has generated positive early results
- Taylorton Bakken continues to deliver strong results with nine wells averaging more than 260 Boe per day per well over the first 30 days of production and averaging 260 Boe per day per well over the first 90 days of production
- Success in conventional Mississippian at Alameda, Edenvale, Manor and Steelman
In 2012, we are demonstrating better capital efficiencies compared to 2011 which will further improve economics and provide risk protection to the capital program:
- Weather has been more typical compared to 2011
- Contracted fit for purpose horizontal drilling rigs and equipment (top drives, larger pumps)
- Moved to more manufacturing-type development in some of our emerging plays such as the Spearfish
- Costs have stabilized for key services
Legacy's light oil assets and strong financial position not only provide downside mitigation in periods of lower commodity prices or volatility, but also provide upside torque to the continued operational success achieved in the past nine months due to:
- Production that is 85 percent weighted to light oil and NGL's
- Current operating netbacks greater than $52.00 per Boe
- Operating costs have decresed and the expectation of this trend is to continue throughout 2012
- Surplus capacity on banking facility
Legacy embarks on 2012 positioned with high quality light oil assets, a strong balance sheet, significant opportunity inventory and dedicated people for continued aggressive and disciplined growth.
ANNUAL GENERAL MEETING
Legacy's Annual General Meeting, is scheduled for 3:00 pm on May 29, 2012 at The Petroleum Club, McMurray Room, located at 319 - 5th Avenue SW, Calgary, AB.
To view Legacy's audited financial statements, the related MD&A and the AIF for the years ended December 31, 2011, December 31, 2010 and December 31, 2009 please visit our web site at www.legacyoilandgas.com or www.sedar.com. To the extent investors do not have access to the internet, copies of the audited financials the related MD&A and the AIF can be obtained on request without charge by contacting Legacy at 403.441.2300 or at 4400, 525-8th Avenue SW, Calgary, Alberta, T2P 1G1.
FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. More particularly, this press release contains statements concerning the year end debt to forward cash flow ratio, the potential of waterfloods at Taylorton and Heward/Stoughton to increase reserves and lower production decline rates, the proposed timing of the implementation of a waterflood pilot at Frys/Antler and the potential recovery rates achievable through waterflood at that property, the anticipated impact of improved well performance of Legacy drilled wells at Pierson on future reserves bookings, the potential recovery rates achievable through waterflood of Legacy's Spearfish properties, the sufficiency of internally generated cash flow to fund capital expenditures and per share growth, potential drilling locations, forecast growth in production in 2012, expected reduction in operating costs in 2012, and planned exploration and development activities. In addition, the reserves estimates contained in this press release are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
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, the impact of completed facilities on operating costs 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 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.
This press release shall not constitute an offer to sell, nor the solicitation of an offer to buy, any securities in the United States, nor shall there be any sale of securities mentioned in this press release in any state in the United States in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state.
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