CALGARY, Feb. 22, 2018 /CNW/ – Altura Energy Inc. (“Altura” or the “Company”) (TSX-V: ATU) is pleased to announce the results of the independent evaluation of the Company’s oil and natural gas reserves (the “McDaniel Report”), effective December 31, 2017, as prepared by McDaniel and Associates Consultants Ltd. (“McDaniel”), and an operational update.
Altura’s audit of its 2017 annual financial statements is not yet complete and accordingly all financial amounts referred to in this news release are unaudited and represent management’s estimates. Readers are advised that these financial estimates are subject to audit and may be subject to change as a result.
2017 OPERATING HIGHLIGHTS
- Production volumes averaged 1,128 boe per day, a per share increase of 97% from 2016. Exceeded exit rate guidance of 1,350 boe per day in December and averaged 1,202 boe per day in the fourth quarter, a per share increase of 22% from the fourth quarter of 2016.
- Drilled eight 100% working interest (“WI”) horizontal wells, including three in the Leduc-Woodbend area, three in the Eyehill area, one in the Macklin area, and one in the Killam area.
- Capital expenditures totaled $21.2 million, including $14.7 million on drilling, completion and equipping, $1.8 million on land, $3.8 million on facilities and pipelines, $1.3 million on workovers and $0.7 million on other, less $1.1 million of property dispositions.
- Progressed its key growth property at Leduc-Woodbend with three new wells drilled, including two 1.5-mile extended reach horizontal wells (“ERH”), the conversion of two standing wells to water disposal wells, and constructed gas gathering, emulsion and water disposal pipelines, which will allow Altura to conserve natural gas and improve operating cost efficiencies by significantly reducing produced water trucking and disposal costs.
- Established a second growth area at Macklin with 9.5 sections of 100% WI land in a Sparky oil pool. Altura drilled one successful horizontal well in 2017, which was followed up with a second horizontal well drilled in January 2018 and a water disposal pipeline to improve operating cost efficiencies.
- Completed the water injection infrastructure at Eyehill and commenced the waterflood pilot project in August.
2017 YEAR-END RESERVE HIGHLIGHTS
- The 2017 year-end reserves are indicative of the exploration and capture phase of Altura’s new Leduc-Woodbend and Macklin Upper Mannville oil pools where the capital focus has been on capturing land, delineation drilling and investing in infrastructure to position the Company as it transitions to the development phase in 2019.
- Proved developed producing (“PDP”) reserves increased by 45 percent from 1,099 mboe to 1,595 mboe. Total proved (“1P”) reserves increased by 71 percent from 1,821 mboe to 3,107 mboe. Total proved plus probable (“2P”) reserves increased by 68 percent from 3,195 mboe to 5,370 mboe.
- All-in finding, development and acquisition (“FD&A”) costs[1] were $23.36 per boe for PDP, $21.97 per boe for 1P and $17.21 per boe for 2P reserves, including the changes in future development costs (“FDC”). This includes $5.6 million of non-reserve adding capital (27% of capital expenditures) to acquire undeveloped land and construct pipelines and facilities.
- Recycle ratio2 of 1.2 times for PDP, 1.3 times for 1P, and 1.6 times for 2P reserves based on the all-in 2017 FD&A costs and Altura’s estimated 2017 operating netback2 of $27.49 per boe. Using the Q4 2017 estimated operating netback of $29.39 per boe, the recycle ratios increase to 1.3 times for PDP, 1.3 times for 1P, and 1.7 times for 2P reserves.
- Replaced[2] 220 percent of annual production with new PDP reserves, 412 percent of annual production with new 1P reserves and 628 percent of annual production with new 2P reserves, based on 2017 estimated production of 412 mboe.
- Based on the strong well results, the majority of 2P reserves additions (88%) were at Leduc-Woodbend.
- Increased PDP reserve life index2 (“RLI”) from 3.0 years to 3.6 years, 1P RLI from 5.0 years to 7.0 years, and 2P RLI from 8.8 years to 12.1 years, all from year-end 2016 to year-end 2017
2018 OPERATIONAL UPDATE
Altura drilled and completed a 1.5-mile ERH well (100/02-02-049-26W4 or “02-02”) at Leduc-Woodbend in the first quarter of 2018. The well was drilled to a vertical depth of 1,300 meters with a horizontal length of approximately 2,000 meters with 46 frac stages and is expected to be placed on production by the end of February. Drilling and completion costs for 02-02 are estimated at $2.4 million.
Altura’s first two ERH wells that were brought on production in the fourth quarter of 2017 are currently producing in line with management’s expectations. Please refer to the corporate presentation on the Company’s website at www.alturaenergy.ca.
At Macklin, Altura has drilled and completed one 1.0-mile horizontal well (09-33-039-28W3 or “09-33”) in the first quarter of 2018. The well was drilled to a vertical depth of 725 meters with a horizontal length of 1,485 meters with 36 frac stages and was placed on production on February 1, 2018. Drilling and completion costs are estimated at $1.3 million.
Altura plans to update shareholders with initial production rates for the Leduc-Woodbend 02-02 and Macklin 09-33 wells on March 22, 2018 when year-end results are released.
In February, the Company commissioned a new produced water disposal pipeline at Macklin which is connected to third party water disposal facilities. This has eliminated water hauling and is expected to reduce area operating costs.
Altura’s 2018 capital budget is expected to be $15.0 million. The budget is split approximately 60% to drilling, completion, equipping and tie-in capital and 40% to infrastructure and other capital. The significant weighting to infrastructure investments positions Altura to reduce operating costs and grow production profitably as it continues to evaluate the Leduc-Woodbend pool.
Management intends to monitor commodity prices and may adjust the 2018 capital program if oil prices deteriorate or strengthen. For details on Altura’s 2018 capital budget, see the Company’s December 14, 2017 news release.
2017 INDEPENDENT RESERVES EVALUATION
The McDaniel Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 (“NI 51-101”). The reserve evaluation was based on McDaniel’s forecast pricing and foreign exchange rates at January 1, 2018. The Reserves Committee of the Board and the Board of Directors of Altura have reviewed and approved the evaluation prepared by McDaniel.
Unless noted otherwise, reserves included herein are stated on a company gross basis, which is the Company’s working interest before deduction of government royalties and excluding any other additional royalty interests. This news release contains several cautionary statements under the heading “Reader Advisory” and throughout the release. In addition to the information contained in this news release, more detailed reserves information will be included in Altura’s Annual Information Form for the year ended December 31, 2017, which will be filed on SEDAR by April 30, 2018.
2017 Capital Expenditures
Altura’s activity in 2017 included drilling eight (8.0 net) horizontal wells, including three (3.0 net) in the Leduc-Woodbend area, three (3.0 net) in the Eyehill area, one (1.0 net) in the Macklin area, and one (1.0 net) in the Killam area. Estimated 2017 capital expenditures include:
($000)(1) |
|||
Geological and geophysical |
138 |
||
Land |
1,840 |
||
Drilling and completions |
12,751 |
||
Well equipping |
1,958 |
||
Capitalized workovers |
1,343 |
||
Facilities and pipelines |
3,798 |
||
Other |
465 |
||
Exploration and development capital expenditures |
22,293 |
||
Property dispositions |
(1,106) |
||
Total capital expenditures, acquisitions and dispositions |
21,187 |
||
(1) Estimated and unaudited |
Company Gross Reserves as at December 31, 2017
The following table summarizes the Company’s gross reserve volumes at December 31, 2017 utilizing McDaniel’s forecast pricing and cost estimates outlined further below in this press release.
Company Gross Reserves(1)(2) |
|||||||||
Category |
Light and |
Heavy Oil |
Conventional |
Natural (Mbbl) |
2017 Oil |
2016 Oil |
2017/ 2016 |
||
Proved |
|||||||||
Developed Producing |
729.8 |
458.6 |
2,183.2 |
42.3 |
1,594.5 |
1,099.2 |
45% |
||
Developed Non-Producing |
114.9 |
– |
(98.5) |
(1.8) |
96.6 |
– |
– |
||
Undeveloped |
294.8 |
825.4 |
1,538.4 |
39.6 |
1,416.3 |
722.2 |
96% |
||
Total Proved(3) |
1,139.4 |
1,284.1 |
3,623.2 |
80.1 |
3,107.4 |
1,821.4 |
71% |
||
Total Probable |
588.1 |
1,288.8 |
1,986.7 |
54.5 |
2,262.5 |
1,373.8 |
65% |
||
Total Proved + Probable(3) |
1,727.5 |
2,572.9 |
5,609.8 |
134.5 |
5,369.9 |
3,195.2 |
68% |
(1) |
Gross reserves are Company working interest reserves before royalty deductions. |
(2) |
Based on McDaniel’s January 1, 2018 forecast prices. |
(3) |
Numbers may not add due to rounding. |
At Leduc-Woodbend, reserve growth was significant with PDP increasing from 70 mboe to 437 mboe and represents 27% of total PDP reserves. 1P increased from 70 mboe to 1,221 mboe and represents 39% of total 1P reserves. 2P increased from 235 mboe to 2,140 mboe and represents 40% of total 2P reserves.
Total capital at Leduc-Woodbend in 2017 was $13.4 million, including $9.6 million of drilling, completion, equipping and workover capital, and $3.8 million of non-well related capital including land, pipelines, facilities and other capital. The FD&A at Leduc-Woodbend on a 2P basis was $16.75 per boe with a recycle ratio of 1.5 using its 2017 average area operating netback of $25.11 per boe. Excluding the $3.8 million of non-well related capital, the Leduc-Woodbend FD&A was $14.84 per boe with a recycle ratio of 1.7.
Reconciliation of Company Gross Reserves for 2017(1)(2)
Total Proved Oil |
Total Probable Oil |
Total Proved + |
|
December 31, 2016 |
1,821.4 |
1,373.8 |
3,195.2 |
Extensions & Improved Recovery |
1,250.8 |
722.2 |
1,973.0 |
Technical Revisions |
294.8 |
(237.5) |
57.0 |
Discoveries |
161.3 |
410.7 |
570.9 |
Acquisitions & Dispositions |
(10.0) |
(6.0) |
(16.0) |
Economic Factors |
– |
– |
– |
Production |
(411.7) |
– |
(411.7) |
December 31, 2017 |
3,107.4 |
2,262.5 |
5,369.9 |
(1) |
Gross reserves are Company working interest reserves before royalty deductions. |
(2) |
Numbers may not add due to rounding. |
Technical revisions for 1P and 2P reserve categories are positive due to well performance exceeding the previous year’s forecast. Additionally, 1P reserves include category transfers from total probable reserves.
Future Development Costs (“FDC”) and Well Schedule
The following is a summary of the estimated FDC and number of wells required to bring 1P and 2P undeveloped reserves on production. Changes in forecast FDC occur annually as a result of drilling activities, acquisition and disposition activities, and changes in capital cost estimates based on improvements in well design and performance, as well as changes in service costs. FDC for 1P undeveloped reserves increased by $16.1 million and FDC for 2P undeveloped reserves increased by $23.3 million compared to year-end 2016. The increases in FDC were driven by additional locations at Leduc-Woodend and Macklin and are consistent with the increases in 1P and 2P reserve volumes.
Total Proved ($000) |
Total Proved Wells(2) Gross (Net) |
Total Proved + ($000) |
Total Proved + Gross (Net) |
|
2018 |
7,082 |
3 (1.9) |
11,032 |
4 (2.9) |
2019 |
14,035 |
8 (8.0) |
16,407 |
11 (11.0) |
2020 |
4,689 |
7 (5.7) |
12,711 |
14 (11.7) |
Total Undiscounted |
25,806 |
18 (15.6) |
40,150 |
29 (25.6) |
Total Discounted 10% |
22,701 |
34,779 |
(1) |
Numbers may not add due to rounding. |
(2) |
FDC and well counts as per the McDaniel Report and based on McDaniel’s January 1, 2018 forecast prices. |
The forecasted future net operating income for the next three years from the McDaniel Report based on the January 1, 2018 forecasted pricing is estimated to be $44.4 million for 1P reserves and $62.3 million for 2P reserves, which is sufficient to fund Altura’s FDC for the next three years.
Summary of Before Tax Net Present Value (“NPV”) of Future Net Revenue as at December 31, 2017
Benchmark oil and NGL prices used are adjusted for quality of oil or NGL produced and for transportation costs. The calculated NPVs are based on McDaniel’s forecast pricing and foreign exchange rates at January 1, 2018 as outlined in the price forecast table further below in this press release. The NPVs include a deduction for estimated future well abandonment and reclamation but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimate represents the fair market value of the reserves.
Before Tax Net Present Value ($000) (1)(2)(3) |
||||||
Discount Rate |
||||||
Category |
Undiscounted |
5% |
10% |
15% |
20% |
|
Proved |
||||||
Developed Producing |
37,929 |
32,795 |
28,832 |
25,765 |
23,355 |
|
Developed Non-Producing |
3,953 |
3,494 |
3,068 |
2,700 |
2,390 |
|
Undeveloped |
21,193 |
14,965 |
10,435 |
7,126 |
4,675 |
|
Total Proved |
63,074 |
51,254 |
42,335 |
35,591 |
30,420 |
|
Total Probable |
67,600 |
46,505 |
33,725 |
25,557 |
20,053 |
|
Total Proved + Probable |
130,675 |
97,760 |
76,059 |
61,148 |
50,473 |
(1) |
Based on McDaniel’s January 1, 2018 forecast prices. |
(2) |
Includes abandonment and reclamation costs. |
(3) |
Numbers may not add due to rounding. |
Company Net Asset Value
The Company’s net asset value as at December 31, 2017 and 2016 are detailed in the following table. This net asset value determination is a “point-in-time” measurement and does not take into account the possibility of Altura being able to recognize additional reserves through successful future capital investment in its existing properties beyond those included in the 2017 year-end reserve report and the 2016 year-end reserve report.
Before Tax NPV @ 10% Discount Rate |
||||
2017 |
2016 |
|||
($000) |
($/Share) |
($000) |
($/Share) |
|
NPV of Future Net Revenue |
||||
Developed Producing(1)(2) |
28,832 |
0.25 |
23,328 |
0.20 |
Total Proved(1)(2) |
42,335 |
0.36 |
31,353 |
0.27 |
Total Proved + Probable(1)(2) |
76,059 |
0.65 |
54,540 |
0.47 |
Net Asset Value(3) |
||||
Total Proved + Probable(1)(2) |
76,059 |
0.65 |
54,540 |
0.47 |
Undeveloped acreage(4) |
10,267 |
0.09 |
5,488 |
0.05 |
Working capital surplus (deficit)(5) |
(3,730) |
(0.03) |
8,455 |
0.07 |
Proceeds from stock options(6) |
2,408 |
0.02 |
1,744 |
0.02 |
Net asset value (diluted)(6) |
85,004 |
0.73 |
70,227 |
0.61 |
(1) |
Evaluated by McDaniel as at December 31, 2017 and December 31, 2016. Net present value of future net revenue does not represent the fair market value of the reserves. |
(2) |
Net present values are based on McDaniel’s January 1, 2018 price forecast and January 1, 2017 price forecast. |
(3) |
Net asset value does not have a standardized meaning. See “Oil and Gas Metrics” contained in this news release. |
(4) |
Undeveloped acreage was determined by an independent land valuation report by Seaton-Jordan & Associates Ltd. as at December 31, 2017. Fair market value was determined in accordance with NI 51-101 5.9(1)(e). As at December 31, 2016, undeveloped acreage was valued internally by Altura at an average of $100 per acre over 54,877 net undeveloped acres. |
(5) |
Working capital deficit as at December 31, 2017 (estimated and unaudited). |
(6) |
Diluted shares as at December 31, 2017 was 108.9 million basic common shares plus 7.2 million stock options that were in-the-money as at December 31, 2017. Diluted shares as at December 31, 2016 was 108.9 million basic common shares plus 5.6 million stock options that were in-the-money as at December 31, 2016. |
Performance Metrics(1)
Altura’s 2017 all-in FD&A costs were burdened with the investment of $5.6 million (27% of capital expenditures) to acquire undeveloped land and construct pipelines and facilities infrastructure. The land and infrastructure investments will benefit future development as well as lower water handling costs and increase gas handling capabilities. The following table highlights Altura’s FD&A, recycle ratio, reserve replacement and reserve life index for 2017 and 2016.
2017 |
2016 |
||
Total capital expenditures, acquisitions and dispositions ($000) |
21,187 |
17,494 |
|
Change in FDC – Total Proved ($000) |
16,109 |
5,704 |
|
Change in FDC – Total Proved + Probable ($000) |
23,329 |
7,664 |
|
Q4 production (boe/d) |
1,202 |
988 |
|
Q4 operating netback ($/boe)(2) |
29.39 |
30.02 |
|
Annual operating netback ($/boe)(2) |
27.49 |
25.30 |
|
Proved Developed Producing |
|||
FD&A costs ($/boe)(2) |
23.36 |
19.99 |
|
Recycle ratio(2) (Q4 operating netback) |
1.3 |
1.5 |
|
Recycle ratio(2) (annual operating netback) |
1.2 |
1.3 |
|
Reserve replacement(2) |
220% |
417% |
|
Reserve life index (“RLI”) (years)(2) |
3.6 |
3.0 |
|
Total Proved |
|||
FD&A costs ($/boe)(2) |
21.97 |
17.76 |
|
Recycle ratio(2) (Q4 operating netback) |
1.3 |
1.7 |
|
Recycle ratio(2) (annual operating netback) |
1.3 |
1.4 |
|
Reserve replacement(2) |
412% |
622% |
|
Reserve life index (“RLI”) (years)(2) |
7.0 |
5.0 |
|
Total Proved + Probable |
|||
FD&A costs ($/boe)(2) |
17.21 |
12.32 |
|
Recycle ratio(2) (Q4 operating netback) |
1.7 |
2.4 |
|
Recycle ratio(2) (annual operating netback) |
1.6 |
2.1 |
|
Reserve replacement(2) |
628% |
973% |
|
Reserve life index (“RLI”) (years)(2) |
12.1 |
8.8 |
(1) |
Financial and production information is per the Company’s 2017 preliminary unaudited financial statements and is therefore subject to audit. |
(2) |
“Operating netback”, “Finding, development & acquisitions costs” or “FD&A costs”, “Recycle ratio”, “Reserve replacement”, “Reserve life index” or “RLI” do not have standardized meanings. See “Oil and Gas Metrics” contained in this news release. |
Price Forecast
The McDaniel Report was based on McDaniel’s forecast pricing and foreign exchange rates at January 1, 2018 as outlined below.
WTI Crude Oil ($US/bbl) |
Western Canadian Select Crude Oil ($CAD/bbl) |
Alberta AECO Gas ($CAD/mmbtu) |
Foreign Exchange ($US/$CAD) |
|
2018 |
58.50 |
51.90 |
2.25 |
0.790 |
2019 |
58.70 |
57.00 |
2.65 |
0.790 |
2020 |
62.40 |
61.40 |
3.05 |
0.800 |
2021 |
69.00 |
66.00 |
3.40 |
0.825 |
2022 |
73.10 |
67.90 |
3.60 |
0.850 |
2023 |
74.50 |
69.20 |
3.65 |
0.850 |
2024 |
76.00 |
70.60 |
3.75 |
0.850 |
2025 |
77.50 |
72.00 |
3.80 |
0.850 |
2026 |
79.10 |
73.50 |
3.90 |
0.850 |
2027 |
80.70 |
74.90 |
3.95 |
0.850 |
2028 |
82.30 |
76.40 |
4.05 |
0.850 |
2029 |
83.90 |
77.90 |
4.15 |
0.850 |
2030 |
85.60 |
79.50 |
4.25 |
0.850 |
2031 |
87.30 |
81.10 |
4.30 |
0.850 |
2032 |
89.10 |
82.70 |
4.35 |
0.850 |
thereafter |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
0.850 |
ABOUT ALTURA ENERGY INC.
Altura is a junior oil and gas exploration, development and production company with operations in central and east central Alberta. Altura predominantly produces from the Sparky and Rex reservoirs in the Upper Mannville group and is focused on delivering per share growth and attractive shareholder returns through a combination of organic growth and strategic acquisitions.
An updated corporate presentation is available on Altura’s website at www.alturaenergy.ca.