Mr. Trent Yanko reports
LEGACY OIL + GAS INC. ANNOUNCES OVER 31% INCREASE IN 2014 YEAR-END RESERVES AND PROVIDES OPERATIONAL UPDATE
Legacy Oil + Gas Inc. has released its year-end 2014 reserves and has provided an operational update. The financial and operational information contained herein is based on the company's unaudited expected results for the year ended Dec. 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 barrel of oil equivalent, and three-year weighted-average total proved plus probable finding, development and acquisition costs (including changes in future development costs) were $24.55 per boe.
- Two thousand fourteen total proved plus probable F&D (including changes in future development costs) was $22.10 per boe, and 2014 total proved plus probable FD&A (including changes in future development costs) was $26.71 per boe.
- The company 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 per cent to 154.1 million boe (81 per cent oil and natural gas liquids) at year-end 2014 from 117.2 million boe (84 per cent oil and NGLs) at year-end 2013.
- Total proved reserves grew by 40 per cent to 93.6 million boe at year-end 2014 from 66.7 million boe at year-end 2013.
- Two thousand fourteen production averaged 23,471 boe per day, an increase of 23 per cent over 2013 average production of 19,013 boe per day.
- Fourth quarter 2014 production averaged 27,475 boe per day, an increase of 31 per cent over fourth quarter 2013 average production of 20,905 boe per day.
- The company replaced 301 per cent of production on a total proved plus probable basis organically and 533 per cent, 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 Ltd. in accordance with National Instrument 51-101 (standards of disclosure for oil and gas activities), effective Dec. 31, 2014. Legacy's annual information form for the year ended Dec. 31, 2014, 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 attached tables are a summary of Legacy's petroleum and natural gas reserves as evaluated by Sproule, effective Dec. 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 Natural gas NGLs Total oil equivalent
(Mbbl) (MMcf) (Mbbl) (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 pricing, exchange rate and inflation rate assumptions as of Dec. 31, 2014, in estimating reserves data using forecast prices and costs. For the year ended Dec. 31, 2014, Legacy's average realized sales prices before hedging were $4.03 per thousand cubic feet for natural gas and $87.41 per barrel for crude oil and natural gas liquids.
PRICING ASSUMPTIONS
Year WTI Cushing, Okla., Canadian light sweet Cromer LSB 35-degree
40-degree API (U.S.$/bbl) 40-degree API ($/bbl) API ($/bbl)
2014 (actual) $93.00 $94.18 $93.26
2015 65.00 70.35 69.85
2016 80.00 87.36 86.86
2017 90.00 98.28 97.78
2018 91.35 99.75 99.25
2019 92.72 101.25 100.75
2020 94.11 103.85 103.35
2021 95.52 105.40 104.90
2022 96.96 106.99 106.49
2023 98.41 108.59 108.09
2024 99.89 110.22 109.72
2025 101.38 111.87 111.37
Year AECO -- C spot Pentanes Plus Exchange rate
($/MMBtu) ($/bbl) ($U.S./$Cdn)
2014(actual) $4.50 $102.33 $0.905
2015 3.32 78.60 0.850
2016 3.71 97.60 0.870
2017 3.90 109.80 0.870
2018 4.47 111.44 0.870
2019 5.05 113.12 0.870
2020 5.13 116.02 0.870
2021 5.22 117.76 0.870
2022 5.31 119.53 0.870
2023 5.40 121.32 0.870
2024 5.49 123.14 0.870
2025 5.58 124.99 0.870
Thereafter escalation rate of 1.5 per cent
Reconciliation of changes in reserves
The attached reconciliation of changes in reserves table sets forth a reconciliation of Legacy's gross reserves as at Dec. 31, 2014, to the gross reserves as at Dec. 31, 2013.
RECONCILIATION OF CHANGES IN RESERVES
Light and medium crude oil Natural gas liquids Natural gas Total oil equivalent
Proved (Mbbl) (Mbbl) (MMcf) (Mboe)
Balance at Dec. 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 Dec. 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 Dec. 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 Dec. 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 Dec. 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 Dec. 31, 2014 105,909.1 19,404.9 172,547.0 154,071.8
Future development costs
The attached future development costs table 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.
FUTURE DEVELOPMENT COSTS
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 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.
Net asset value per share
The attached net assset value per share table outlines Legacy's estimated NAV per basic common share (unaudited) using the proved plus probable reserve value at Dec. 31, 2014, before tax and discounted at 10 per cent, and forecast pricing and costs.
NET ASSET VALUE PER SHARE
Proved plus probable reserve value NPV10 BT (incl. future capital) (million $) $2,741.4
Undeveloped land (557,302 acres) (unaudited) (million $) $104.1
Investment in LGX (unaudited) (million $) $3.2
Estimated net debt (unaudited) (million $) ($857.0)
Total net assets (basic) (million $) $1,991.7
Basic common shares outstanding (million) 199.7
Estimated NAV per basic common share $9.97
Operational update
Legacy drilled 159 (137.0 net) wells in 2014, with a 99-per-cent success rate. The company met its 2014 production guidance, averaging 23,471 barrels of oil equivalent per day, an increase of 23 per cent 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 general and administrative, 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-per-cent 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 three (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 barrels 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 first quarter 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 derisked inventory, have further improved the robust economics of the Midale play to an industry-leading level despite low commodity prices.
The company drilled two (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. Most of these wells were short (700-metre lateral) horizontal wells, drilled with a cost savings of up to $250,000 per well over the long (1,400 m) lateral wells. Some of the Bottineau county wells continue to produce in excess of 80 bbl of oil per day after five months.
In the Bakken, the company drilled three (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 No. 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 pace-setting $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 $52 (U.S.) per barrel WTI through 2015.
Conference call details
Legacy expects to release its year-end 2014 operational and financial results March 25, 2015. Management will be holding a conference call for investors, financial analysts, media and any interested persons on March 26, 2015, at 9 a.m. (MDT) (11 a.m. EDT) to discuss the year-end 2014 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: 82752074
To join this conference call, you will be required to provide the conference ID number.
We seek Safe Harbor.
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