Legacy Oil + Gas Inc. announces over 31% increase in 2014 year-end reserves and provides operational update

CALGARY, March 5, 2015 /CNW/ - Legacy Oil + Gas Inc. ("Legacy" or the "Company") (TSX: LEG) is pleased to announce its 2014 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, 2014 and final audited results may vary.

HIGHLIGHTS

• Three year weighted average total proved plus probable finding and development costs ("F&D") (including changes in future development costs) were $21.66 per Boe and three year weighted average total proved plus probable finding, development and acquisition costs ("FD&A") (including changes in future development costs) were $24.55 per Boe
• 2014 total proved plus probable F&D (including changes in future development costs)  were $22.10 per Boe and  2014 total proved plus probable ("FD&A") (including changes in future development costs) were $26.71 per Boe
• Generated a 2014 proved plus probable recycle ratio of 2.2 times (F&D) and 1.8 times (FD&A) based on estimated 2014 average annual operating netback of $48.72 per Boe
• Total proved plus probable reserves grew by 31 percent to 154.1 MMBoe (81 percent oil and NGL's) at year end 2014 from 117.2 MMBoe (84 percent oil and NGL's) at year end 2013
• Total proved reserves grew by 40 percent to 93.6 MMBoe at year end 2014 from 66.7 MMBoe at year end 2013
• 2014 production averaged 23,471 Boe per day, an increase of 23 percent over 2013 average production of 19,013 Boe per day
• Fourth quarter 2014 production averaged 27,475 Boe per day, an increase of 31 percent over fourth quarter 2013 average production of 20,905 Boe per day
• Replaced 301 percent of production on a total proved plus probable basis organically and 533 percent including acquisitions
• Total proved plus probable reserve life index equates to 15.4 years based on fourth quarter 2014 average production

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, 2014.  Legacy's annual information form for the year ended December 31, 2014 (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, 2015.

The following tables are a summary of Legacy's petroleum and natural gas reserves as evaluated by Sproule effective December 31, 2014 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 Medium Oil (MBbl)	Natural Gas (MMcf)	NGL's (MBbl)	Total Oil Equivalent (MBoe)
Proved Producing	33,509.2	66,300.0	7,900.1	52,459.3
Proved Developed Non-Producing	1,167.4	737.0	53.7	1,343.9
Proved Undeveloped	26,916.4	47,474.0	5,002.8	39,831.5
Total Proved	61,593.0	114,511.0	12,956.6	93,634.8
Probable	44,316.1	58,036.0	6,448.2	60,437.0
Total Proved plus Probable	105,909.1	172,547.0	19,404.9	154,071.9

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$)
Proved
	Developed Producing	1,759,654		1,354,642		1,112,484		951,113		835,220
	Developed Non-Producing	48,245		39,793		33,601		28,922		25,291
	Undeveloped	1,255,780		737,986		486,007		337,768		240,705
Total Proved		3,063,679		2,132,422		1,632,092		1,317,803		1,101,216
Probable		2,524,074		1,573,804		1,109,261		835,579		656,346
Total Proved plus Probable		5,587,752		3,706,226		2,741,353		2,153,382		1,757,561
		After Future Income Tax Expenses and Discounted at
		0%		5%		10%		15%		20%
		(M$)		(M$)		(M$)		(M$)		(M$)
Proved
	Developed Producing	1,724,503		1,342,328		1,107,537		948,924		834,180
	Developed Non-Producing	35,580		32,975		29,816		26,761		24,025
	Undeveloped	944,761		554,668		364,988		252,485		177,998
Total Proved		2,704,845		1,929,971		1,502,341		1,228,171		1,036,203
Probable		1,862,464		1,152,412		806,549		603,566		471,228
Total Proved plus Probable		4,567,309		3,082,383		2,308,889		1,831,736		1,507,431

Pricing Assumptions – Forecast Prices and Costs

Sproule employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2014 in estimating reserves data using forecast prices and costs. For the year ended December 31, 2014, Legacy's average realized sales prices before hedging were $4.03/Mcf for natural gas and $87.41/bbl for crude oil and NGLs.

Year	WTI Cushing Oklahoma 40° API (US$/Bbl)	Canadian Light Sweet 40° API ($/Bbl)	Cromer LSB 35° API ($/Bbl)	AECO - C Spot ($/MMBtu)		Pentanes Plus ($/Bbl)		Exchange Rate ($US/$Cdn)
2014 (Actual)	93.00	94.18	93.26	4.50		102.33		0.905
2015	65.00	70.35	69.85	3.32		78.60		0.850
2016	80.00	87.36	86.86	3.71		97.60		0.870
2017	90.00	98.28	97.78	3.90		109.80		0.870
2018	91.35	99.75	99.25	4.47		111.44		0.870
2019	92.72	101.25	100.75	5.05		113.12		0.870
2020	94.11	103.85	103.35	5.13		116.02		0.870
2021	95.52	105.40	104.90	5.22		117.76		0.870
2022	96.96	106.99	106.49	5.31		119.53		0.870
2023	98.41	108.59	108.09	5.40		121.32		0.870
2024	99.89	110.22	109.72	5.49		123.14		0.870
2025	101.38	111.87	111.37	5.58		124.99		0.870

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, 2014 to the gross reserves as at December 31, 2013. 

		Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Total Oil Equivalent
Proved		(MBbl)	(MBbl)	(MMcf)	(MBoe)
	Balance at December 31, 2013	44,952.3	9,549.7	73,242.0	66,709.0
	Extensions and Improved Recovery	5,285.9	961.2	10,693.0	8,029.3
	Technical Revisions and Category Changes	6,019.1	1,717.8	23,482.0	11,650.6
	Infill Drilling	3,364.4	138.6	1,529.0	3,757.9
	Acquisitions	9,041.1	1,344.4	12,390.0	12,450.3
	Economic Factors	(282.2)	(52.3)	(625.0)	(438.7)
	Production	(6,787.6)	(702.8)	(6,200.0)	(8,523.8)
	Balance at December 31, 2014	61,593.0	12,956.6	114,511.0	93,634.7

		Light and Medium Crude  Oil	Natural Gas Liquids	Natural Gas	Total Oil Equivalent
Probable		(MBbl)	(MBbl)	(MMcf)	(MBoe)
	Balance at December 31, 2013	38,911.6	5,243.0	37,764.0	50,448.6
	Extensions and Improved Recovery	6,712.7	1,119.8	12,157.0	9,858.7
	Technical Revisions and Category Changes	(8,604.5)	(448.5)	2,924.0	(8,565.7)
	Infill Drilling	1,319.5	56.6	554.0	1,468.4
	Acquisitions	5,958.1	529.0	4,894.0	7,302.8
	Economic Factors	18.7	(51.6)	(257.0)	(75.7)
	Production	-	-	-	-
	Balance at December 31, 2014	44,316.1	6,448.3	58,036.0	60,437.1

		Light and Medium Crude Oil	Natural Gas Liquids	Natural Gas	Total Oil Equivalent
Proved + Probable		(MBbl)	(MBbl)	(MMcf)	(MBoe)
	Balance at December 31, 2013	83,863.9	14,792.7	111,006.0	117,157.6
	Extensions and Improved Recovery	11,998.6	2,081.0	22,851.0	17,888.1
	Technical Revisions and Category Changes	(2,585.4)	1,269.3	26,407.0	3,085.0
	Infill Drilling	4,683.9	195.2	2,083.0	5,226.3
	Acquisitions	14,999.2	1,873.4	17,283.0	19,753.1
	Economic Factors	(263.5)	(103.9)	(882.0)	(514.4)
	Production	(6,787.6)	(702.8)	(6,200.0)	(8,523.8)
	Balance at December 31, 2014	105,909.1	19,404.9	172,547.0	154,071.8

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$)		(M$)
2015		186,183		264,216
2016		203,432		336,894
2017		145,057		295,224
2018		50,426		148,504
2019		20,315		34,025
Remaining Years		10,252		14,028
Total Undiscounted		615,665		1,092,891

CAPITAL EXPENDITURES AND FINDING, DEVELOPMENT AND ACQUISITION COSTS

Legacy incurred capital expenditures of $871.5 million in 2014, of which $468.0 million was related to strategic asset acquisitions and divestitures and $403.5 million on organic opportunities, including $6.0 million of capitalized general and administrative costs.

The Company's total proved plus probable finding and development costs for 2014 were $22.10 per Boe (including change in FDC), which generated a 2.2 times recycle ratio based on Legacy's 2014 estimated average operating netback of $48.72 per Boe.

2014 Capital Expenditures                                                 Capital costs ($ thousands)     Exploration & development drilling & associated costs     Land & seismic     Net acquisitions and divestitures     Change in FDC		Total Proved plus Probable ^(1)   379,929 23,537 467,970 342,242	Total Proved ^(1)   379,929 23,537 467,970 266,767
2014 Reserve Additions (MBoe)^(2) Exploration & development Net acquisitions		25,684 19,753	22,999 12,450
Finding & Development Costs ($ per Boe)^(3)   2014 excluding change in FDC 2014 including change in FDC   2013 excluding change in FDC 2013 including change in FDC   3-year weighted average cost, excluding change in FDC 3-year weighted average cost, including change in FDC   Finding, Development & Acquisition Costs ($ per Boe)^(4)   2014 excluding change in FDC 2014 including change in FDC   2013 excluding change in FDC 2013 including change in FDC   3-year weighted average cost, excluding change in FDC 3-year weighted average cost, including change in FDC		15.71 22.10   16.90 20.20   18.32 21.66       19.18 26.71   17.00 22.01   19.35 24.55	17.54 23.34   27.66 30.77   23.93 26.43       24.58 32.11   27.94 32.55   27.05 31.68

(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 $178.2 million on a total proved plus probable basis and $133.3 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 estimated NAV per basic common share (unaudited) using the Proved plus Probable reserve value at December 31, 2014, before tax and discounted at 10%, and forecast pricing and costs:

Proved Plus Probable Reserve Value NPV10 BT (incl. future capital) (MM$)	$2,741.4
Undeveloped Land (557,302 acres)  (unaudited) (MM$)	$104.1
Investment in LGX (unaudited) (MM$)	$3.2
Estimated Net Debt (unaudited) (MM$)	($857.0)
Total Net Assets (basic) (MM$)	$1,991.7
Basic Common Shares Outstanding (MM)	199.7
Estimated NAV per Basic Common Share	$9.97

OPERATIONAL UPDATE

Legacy drilled 159 (137.0 net) wells in 2014, with a 99 percent success rate. The Company met its 2014 production guidance, averaging 23,471 Boe per day, an increase of 23 percent over 2013 average production of 19,013 Boe per day.  Total capital expenditures on organic opportunities for 2014 were $397.5 million (not including capitalized G&A, corporate fixed assets or net acquisitions and divestitures).

In the fourth quarter of 2014, the Company drilled 10 (7.4 net) wells, all targeting light oil, with a 100 percent success rate, and achieved a production average of 27,475 Boe per day. In the fourth quarter of 2014, 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 2015.

In the Midale, Legacy drilled 3 (1.9 net) wells in the fourth quarter of 2014. Wells brought on production in the quarter have an average 30 day initial oil rate of 325 Bbl per day per well.  Strong results continue to be demonstrated throughout this Legacy dominated play.  Key gathering infrastructure was constructed in the fourth quarter of 2014 and construction of the 16-21 Pinto battery was commenced, with completion anticipated in late Q1 2015.  This infrastructure will service the planned 2015 Midale drilling activity and enable lower full cycle capital costs and faster cycle times.  Strong well results, when coupled with lower capital costs and a de-risked inventory, have further improved the robust economics of the Midale play to an industry leading level despite low commodity prices.

The Company drilled 2 (1.8 net) Spearfish wells in the fourth quarter of 2014.  Wells brought on production in the quarter have an average 30 day initial oil rate of 83 Bbl per day per well.  The majority of these wells were short (700 m lateral) horizontal wells, drilled with a cost savings of up to $250,000 per well over the long (1,400 m) lateral wells.  A number of the Bottineau County wells continue to produce in excess of 80 Bbls of oil per day after five months.

In the Bakken, the Company drilled 3 (1.7 net) wells at Heward and Star Valley in the fourth quarter of 2014.  The wells have an average 30 day initial rate of 175 Boe per day per well.

The Turner Valley Rundle horizontal wells brought on production in the quarter have an average 30 day initial rate of 335 Boe per day per well.  The Hartell #10 triple lateral well was drilled in a record 30 days to a total measured depth of 4,915 m, with 2,395 m of open-hole laterals.  Total cost to drill, complete, equip and tie-in this triple lateral well was a pacesetting $5.5 million. This efficient execution bodes well for further improving the economics of drilling in Turner Valley, even in the current low commodity price environment.

OUTLOOK

Legacy remains committed to improving its balance sheet while preserving its significant upside during these times of low commodity prices. The Company is on track to spend funds flow from operations in the first half of 2015 (based on current strip pricing). The Company has run sensitivities on its borrowing base value and stress tested its balance sheet and continues to expect to be within debt covenants down to oil prices averaging US$52 per barrel WTI through 2015.

CONFERENCE CALL DETAILS

Legacy expects to release its 2014 year end operational and financial results Wednesday, March 25, 2015.  Management will be holding a conference call for investors, financial analysts, media and any interested persons on Thursday, March 26, 2015 at 9:00 a.m. (MDT) (11:00 a.m. EDT) to discuss the 2014 year end results.

The investor conference call details are as follows:  

Participant Dial-In Number(s):

• Operator Assisted Toll-Free Dial-In Number: [phone]
• Local Dial-In Number: [phone]
• Conference ID: 82752074

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, 2015.

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 and Recycle Ratios

Netbacks are calculated by deducting royalties paid and operating costs, including transportation costs, from prices received, excluding the effects of hedging. Recycle ratios are determined by dividing netbacks by F&D or FD&A costs, as applicable.

Test Results and Initial Production Rates

Any references in this news release to initial, early and/or test production/performance rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production. The initial production rate may be estimated based on other third party estimates or limited data available at this time. Initial production or test rates are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons.

Forward Looking Statements

This press release contains forward-looking statements. More particularly, this press release contains statements concerning: (i) the Company being on track to spend funds flow from operations in the first half of 2015, (ii) the anticipated timing of the completion of the 16-21 Pinto Battery, (iii) the impact of Midale infrastructure on capital costs and cycle times, and (iv) the expectation that the Company will be in compliance with its debt covenants on the pricing scenario set out in the press release.

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 prevailing commodity prices, differentials and exchange rates, the success of future drilling and development activities, the performance of existing wells and facilities, the performance of new wells and facilities, the viability of waterflood projects, the availability and cost of services, and prevailing 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, commodity price and exchange rate fluctuations, 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, 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, 2013 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.

Trent J. Yanko, P.Eng., President + CEO, Legacy Oil + Gas Inc., 4400 Eighth Avenue Place, 525 - 8th Avenue SW, Calgary, AB T2P 1G1, Telephone: [phone], Fax: [phone]; 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: [phone], Fax: [phone]