CALGARY, ALBERTA–(Marketwired – Feb. 24, 2016) – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce the results of its independent oil and gas reserves evaluation as of December 31, 2015, prepared by GLJ Petroleum Consultants Ltd. (“GLJ”), summarized below.
Tamarack’s stringent capital allocation complemented by a constant focus on cost reductions and improving capital efficiencies has resulted in another significant year of reserve growth in 2015, despite challenges associated with lower commodity prices. During 2015, Tamarack adopted a three pronged strategy in the Wilson Creek and Alder Flats areas of Alberta: 1) re-design the drilling and completion programs to permanently reduce capital costs per well and improve capital efficiencies; 2) reduce operating expenses to improve netbacks which translates into enhanced economics on future drilling; and 3) add drilling inventory through tuck-in acquisitions to take advantage of existing infrastructure and maintain a low cost, high netback structure. Tamarack executed all three elements of this strategy in 2015 and successfully delivered per share reserves growth while reducing net debt. The Company’s significant reserves growth includes a 32% increase in proved developed producing reserves, a 46% increase in proved (“1P”) reserves and a 35% increase in proved plus probable (“2P”) reserves.
2015 RESERVES REPORT HIGHLIGHTS
- Increased 1P reserves per fully diluted share by 13.3% and 2P reserves per fully diluted share by 5.1%.
- Increased 1P reserves by 46% to 25.0 million boe, and 2P reserves by 35% to 45.0 million boe, weighted 52% and 54% to oil and natural gas liquids (“NGLs”), respectively.
- Including acquisitions, the Company replaced 356% of production on a 1P basis and 481% on a 2P basis.
- Maintained a conservative approach to reserves booking, with 1P reserves including only 65 (53.3 net) proved undeveloped horizontal Cardium drilling locations and 2P reserves including only 111 (90.0 net) proved plus probable undeveloped horizontal Cardium drilling locations.
- Achieved 1P finding and development (“F&D”) costs of approximately $11.01/boe including the change in future development capital (“FDC”), a 71% reduction from the prior year. The Company also achieved 1P finding, development and acquisition (“FD&A”) costs of approximately $13.26/boe, including the change in FDC, representing a 66% reduction over 2014.
- Realized three year average 2P F&D costs of approximately $17.44/boe and 2P FD&A costs of $19.26/boe including the change in FDC.
- Generated a 1P F&D recycle ratio of 1.58 times and a 1P FD&A recycle ratio of 1.31 times using the estimated 2015 funds from operations netback of $17.35/boe (unaudited), which represents an increase of 52% and 31% over 2014, respectively, despite commodity prices averaging more than 40% lower in 2015.
- Maintained a 2P reserve life index of 12.5 years based on estimated fourth quarter 2015 average production of 9,870 boe/d.
2015 YEAR-END RESERVES & OPERATIONS UPDATE
Tamarack realized tremendous reserves and production growth through 2015, and was able to maintain a conservatively booked reserves report, while reducing net debt. In 2015 the Company drilled 15 (13.9 net) horizontal Cardium oil wells in the core Wilson Creek and Alder Flats areas and on June 15, 2015 closed a strategic acquisition of assets within these areas, further contributing to Tamarack’s growth. The operational success realized in 2015 coupled with ongoing cost reduction initiatives ensure Tamarack is well positioned for continued measured growth and long-term sustainability.
The following tables highlight Tamarack’s 2015 year-end independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2015 (the “GLJ Report”). The GLJ Report has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook. All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.
Reserves Data (Forecast Prices and Costs)
| RESERVES CATEGORY | CRUDE OIL (1) |
CONVENTIONAL NATURAL GAS |
NATURAL GAS LIQUIDS |
TOTAL OIL EQUIVALENT |
||||||||||||
| Gross (Mbbls) |
Net (Mbbls) |
Gross (Mmcf) |
Net (Mmcf) |
Gross (Mbbls) |
Net (Mbbls) |
Gross (Mboe) |
Net (Mboe) |
|||||||||
| PROVED: | ||||||||||||||||
| Developed Producing | 5,496 | 5,037 | 43,121 | 39,459 | 1,645 | 1,174 | 14,328 | 12,620 | ||||||||
| Developed Non-Producing | 41 | 37 | 3,391 | 2,726 | 74 | 47 | 680 | 538 | ||||||||
| Undeveloped | 4,885 | 4,423 | 24,968 | 23,127 | 938 | 767 | 9,985 | 9,045 | ||||||||
| TOTAL PROVED | 10,422 | 9,497 | 71,480 | 64,312 | 2,657 | 1,988 | 24,992 | 22,203 | ||||||||
| PROBABLE | 9,168 | 8,048 | 52,590 | 47,342 | 2,028 | 1,495 | 19,960 | 17,433 | ||||||||
| TOTAL PROVED PLUS PROBABLE | 19,589 | 17,545 | 124,069 | 111,655 | 4,685 | 3,483 | 44,953 | 39,637 | ||||||||
| Note: | ||
| (1) | Heavy oil included in the Crude Oil product type represents less than 8% of any reserves category and as such is immaterial. | |
| (2) | Columns may not add due to rounding. | |
Net Present Values of Future Net Revenue Before Income Taxes Discounted at (%/yr)
| RESERVES CATEGORY | 0% ($000s) |
5% ($000s) |
10% ($000s) |
15% ($000s) |
20% ($000s) |
Unit Value Before Income Tax Discounted at 10% Per Year(1) ($/Boe) | ||
| PROVED: | ||||||||
| Developed Producing | 212,690 | 182,858 | 158,541 | 139,623 | 124,886 | 12.56 | ||
| Developed Non-Producing | 8,426 | 4,424 | 2,729 | 1,875 | 1,379 | 5.07 | ||
| Undeveloped | 146,544 | 94,662 | 60,381 | 37,761 | 22,540 | 6.68 | ||
| TOTAL PROVED | 367,660 | 281,944 | 221,651 | 179,259 | 148,805 | 9.98 | ||
| PROBABLE | 493,485 | 297,344 | 193,592 | 134,389 | 97,961 | 11.10 | ||
| TOTAL PROVED PLUS PROBABLE | 861,145 | 579,289 | 415,243 | 313,648 | 246,766 | 10.48 | ||
| Note: | ||
| (1) | Unit values based on Company net reserves | |
| (2) | Columns may not add due to rounding. | |
Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs
| MBOE | ||||
| FACTORS | Proved | Probable | Proved + Probable |
|
| December 31, 2014 | 17,135 | 16,101 | 33,236 | |
| Discoveries | 0 | 0 | 0 | |
| Extensions and Improved Recovery | 3,873 | (525) | 3,348 | |
| Technical Revisions | 1,483 | 305 | 1,788 | |
| Acquisitions(1) | 6,184 | 4,551 | 10,735 | |
| Dispositions | (5) | (5) | (10) | |
| Economic Factors | (605) | (467) | (1,072) | |
| Production | (3,074) | 0 | (3,074) | |
| December 31, 2015 | 24,992 | 19,960 | 44,953 | |
| Note: | ||
| (1) | Includes reserve additions from earning wells that were drilled on the Company’s Cardium farm-in | |
Future Development Capital Costs
The following is a summary of GLJ’s estimated future development capital required to bring proved and probable undeveloped reserves on production.
| (amounts in $000s) | Total Proved | Total Proved + Probable |
| 2016 | 18,903 | 32,319 |
| 2017 | 65,160 | 84,869 |
| 2018 | 55,113 | 95,618 |
| 2019 and Subsequent | 55,916 | 153,069 |
| Total Undiscounted FDC | 195,091 | 365,874 |
| Total Discounted FDC at 10% per year | 156,450 | 284,604 |
| FD&A Costs | 2015 | Three Year Average | ||
| (amounts in $000s except as noted) | Proved | Proved + Probable |
Proved | Proved + Probable |
| FD&A costs, including FDC | ||||
| Exploration and development capital expenditures (2) | 60,344 | 60,344 | 80,700 | 80,700 |
| Acquisitions, net of dispositions | 47,086 | 47,086 | 92,724 | 92,724 |
| Total change in FDC | 37,509 | (1,002) | 42,860 | 84,361 |
| Total FD&A capital, including change in FDC | 144,940 | 106,428 | 216,285 | 257,786 |
| Reserve additions, including revisions – Mboe | 4,414 | 3,436 | 3,211 | 3,945 |
| Acquisitions, net of dispositions – Mboe | 6,516 | 11,349 | 5,046 | 9,441 |
| Total FD&A Reserves | 10,930 | 14,786 | 8,257 | 13,386 |
| F&D costs, including FDC – $/boe | 11.01 | (6.33) | 24.86 | 17.44 |
| Acquisition costs, net of dispositions – $/boe | 14.79 | 11.29 | 27.04 | 20.02 |
| FD&A costs, including FDC – $/boe | 13.26 | 7.20 | 26.19 | 19.26 |
| Notes: | ||
| (1) | While NI 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above. | |
| (2) | The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. | |
| (3) | The capital expenditures also exclude capitalized administration costs. | |
2016 CAPITAL PROGRAM AND GUIDANCE UPDATE
Tamarack’s 2016 capital program and associated guidance was designed with the top priority of protecting its top tier balance sheet. The capital program and guidance released on January 19, 2016, was based on a 2016 WTI average of $40.00/bbl USD and an AECO average of $2.45/GJ with a plan to adjust capital spending as commodity prices changed. Despite having high quality drilling inventory that achieves 1.5 year payout or less at current strip prices, the Company has begun to adjust capital spending as a result of the recent drop in prices. The Company’s top priority is to maintain a strong balance sheet in order to continue its success of pursuing tuck-in acquisitions within its core areas and continuing to add drilling inventory. This includes deferring approximately $6 to $8 million of capital into the second half of 2016. Tamarack will continue to closely monitor the broader commodity price environment and has the flexibility to further reduce capital expenditures by an additional $12 to $17 million from original levels, if commodity prices do not improve from current levels.
Updated 2016 Guidance Ranges:
- Capital expenditures of $40-57 million (original guidance of $52 – 57 million).
- Average production of 8,700-9,700 boe/d (approximately 51-57% oil & NGLs) (original guidance of 9,500-9,700 boe/d).
- Exit production of 8,600-9,800 boe/d (approximately 50-55% oil & NGLs) (original guidance of 9,600-9,800 boe/d).
- Estimated 2016 year end 12-month trailing debt to cash flow (including hedges) ratio between 1.6 and 2.3 times (original guidance of 1.6 times).
- At least $50 million of liquidity maintained on bank lines (unchanged).
Updated 2016 Assumptions:
- WTI average $33.00/bbl to 40.00/bbl USD.
- Edmonton par price average $41.00/bbl to 51.45/bbl.
- AECO average $2.00/GJ to 2.45/GJ.
- Canadian/US dollar exchange rate range of $0.70 to $0.72.
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction is focused on two key principles – targeting resource plays that provide long-life reserves, and using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk development oil locations in the Pembina, Wilson Creek, Garrington and Lochend Cardium fairway and the Redwater shallow Viking play in Alberta. With a balanced portfolio and an experienced and committed management team, Tamarack intends to continue to deliver on its promise to maximize shareholder return while managing its balance sheet.
Abbreviations
| bbls | barrels |
| bbls/d | barrels per day |
| boe | barrels of oil equivalent |
| boe/d | barrels of oil equivalent per day |
| Mboe | thousands barrels of oil equivalent |
| mcf | thousand cubic feet |
| MMcf | million cubic feet |
| Mbbls | thousand barrels |
| mcf/d | thousand cubic feet per day |