CALGARY, Alberta, March 05, 2019 (GLOBE NEWSWIRE) — 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, 2018, as prepared by McDaniel and Associates Consultants Ltd. (“McDaniel”), an operational update and 2019 guidance.
Altura’s audit of its 2018 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.
2018 YEAR-END RESERVE HIGHLIGHTS
- Year-over-year, proved developed producing (“PDP”) reserves increased by eight percent from 1,595 mBoe to 1,725 mBoe. Total proved (“1P”) reserves increased by 102 percent from 3,107 mBoe to 6,270 mBoe. Total proved plus probable (“2P”) reserves increased by 89 percent from 5,370 mBoe to 10,126 mBoe. Percentage increases were the same on a per share basis.
- These reserve additions were achieved notwithstanding the May 2018 disposition of approximately 73 percent, 49 percent and 60 percent of the Company’s year-end 2017 PDP, 1P and 2P reserve volumes respectively.
- In the Leduc-Woodbend Upper Mannville Rex oil pool, year-over-year reserve growth was significant with PDP increasing from 437 mBoe to 1,487 mBoe; 1P increased from 1,221 mBoe to 6,032 mBoe; and 2P increased from 2,140 mBoe to 9,818 mBoe.
- Finding, development and acquisition (“FD&A”) costs1 were $17.30 per Boe for PDP, $16.48 per Boe for 1P and $12.53 per Boe for 2P reserves, including the changes in future development costs (“FDC”). This includes $6.4 million, or 19 percent of exploration and development capital expenditures, to construct a multi-well battery and pipelines at Leduc-Woodbend.
- Recycle ratio1 of 1.4 times for PDP, 1.5 times for 1P, and 2.0 times for 2P reserves based on the 2018 FD&A costs and Altura’s estimated 2018 operating netback1 of $24.54 per Boe.
- Replaced1 130 percent of annual production with new PDP reserves, 839 percent of annual production with new 1P reserves and 1,212 percent of annual production with new 2P reserves, based on 2018 production of 1,172 Boe per day.
- 2P reserves are booked on only 18 net sections of land at Leduc-Woodbend which is 26 percent of total lands in the area.
- Increased the 1P reserve life index1 (“RLI”) from 7.0 years to 12.1 years, and 2P RLI from 12.1 years to 19.5 years, from year-end 2017 to year-end 2018.
- Increased net asset value1 per share 42 percent from $0.71 to $1.01, on a 2P reserves basis.
2019 OPERATIONAL UPDATE
On December 21, 2018, the Company announced that November and December 2018 production volumes were voluntarily curtailed in response to weak oil prices caused by wide Canadian oil differentials. The Canadian oil differentials narrowed significantly in January 2019 and Altura brought the curtailed production back on line.
In January, Altura completed the equipping operations for the last well of Altura’s 2018 summer drilling program, which was drilled and fracked in 2018. This well commenced production on February 4, 2019 and initial production rates are consistent with the Company’s other wells in the Leduc-Woodbend area.
2019 GUIDANCE
The board of directors of the Company has approved an initial capital budget of $15 million for 2019, funded with forecasted cash flow from operating activities. The budget is weighted to the second half of 2019 and includes drilling four extended reach horizontal (“ERH”) wells at Leduc-Woodbend. Additionally, Altura plans to implement a waterflood pilot project which includes drilling on reduced inter-well spacing.
Altura’s base production coupled with production from its capital program is forecasted to grow 2019 annual average production to range between 1,700 to 1,800 Boe per day in 2019, compared to 1,172 Boe per day in 2018, representing more than 45 percent growth on an absolute and per share basis.
Management intends to continuously monitor well performance and commodity prices throughout the year and may at any time adjust the 2019 capital program if well performance is exceeding expectations or if oil prices deteriorate or strengthen. The budget leaves Altura with a conservative balance sheet and the flexibility to accelerate development in the second half of 2019 if results and commodity prices are supportive.
2018 OPERATING HIGHLIGHTS
- The Company closed the sale of its eastern Alberta and Saskatchewan assets (the “Disposition”) producing 668 Boe per day in May 2018 for $27.3 million (net of transaction costs and adjustments) leaving Altura with production of 502 Boe per day in June.
- Following the eight-well summer drilling program and construction of key infrastructure, production increased to 2,053 Boe per day in October but was voluntarily curtailed in November to 1,512 Boe per day and in December to 675 Boe per day due to weak oil prices caused by wide Canadian oil differentials.
- Fourth quarter 2018 production averaged 1,412 Boe per day which was impacted by Altura’s production curtailment. 2018 production volumes averaged 1,172 Boe per day (81 percent oil and liquids), an increase of four percent from 2017.
- Drilled 10 (9.95 net) wells, including nine (8.95 net) ERH wells in the Leduc-Woodbend area and one (1.0 net) horizontal well in the Macklin area. Additionally, the Company invested in key infrastructure at Leduc-Woodbend including the construction of a multi-well battery and a natural gas gathering pipeline that connects Altura’s northern area production to a third-party gas plant.
- Capital expenditures totaled $33.5 million, including $24.8 million on drilling, completion and equipping, and $6.4 million on facilities and pipelines.
- Closed two separate acquisitions, acquiring 3.0 net sections of highly prospective lands in the Upper Mannville oil pool at Leduc-Woodbend and a 60 percent working interest in a producing oil unit in the Leduc-Woodbend area, adding net production of approximately 120 Boe per day (90 percent oil & liquids) of low decline, Glauconite oil (33° API) production for aggregate cash consideration of $3.6 million.
- Operating and transportation costs totaled $10.93 per Boe, down 11 percent from 2017. This decrease is largely a result of lower cost production growth into the new multi-well battery at Leduc-Woodbend and the Disposition which had higher average operating costs. Fourth quarter operating and transportation costs further improved to $8.60 per Boe.
- Operating netback2 was $24.54 per Boe, down 11 percent from 2017 due to the sharp commodity price decline in the fourth quarter.
2018 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 and National Instrument 51-101 (“NI 51-101”). The reserves evaluation was based on the average of the published price forecasts for McDaniel, GLJ Petroleum Consultants Ltd., and Sproule Associates Ltd. (the “Consultant Average Price Forecast”) at January 1, 2019. 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, 2018, which will be filed on SEDAR by April 30, 2019.
2018 Capital Expenditures
Altura drilled 10 (9.95 net) wells, including nine (8.95 net) ERH wells in the Leduc-Woodbend area, and one (1.0 net) horizontal well in the Macklin area. Additionally, the Company invested in key infrastructure at Leduc-Woodbend including the construction of a multi-well battery and a natural gas gathering pipeline that connects Altura’s northern area production to a third-party gas plant.
In 2018, the Corporation closed two separate acquisitions, acquiring 3.0 net sections of highly prospective lands in the Upper Mannville oil pool at Leduc-Woodbend and a 60 percent working interest in a producing oil unit in the Leduc-Woodbend area, adding net production of approximately 120 Boe per day (90 percent oil & liquids) of low decline, Glauconite oil (33° API) production for aggregate cash consideration of $3.6 million. The acquisitions secured Altura operatorship of the Glauconite Unit battery.
In 2018, Altura closed the disposition of the Corporation’s crude oil and natural gas assets in east central Alberta and Saskatchewan for $27.3 million of cash, net of customary post-closing adjustments and transaction costs of $0.4 million.
Estimated 2018 capital expenditures include:
($000)(1) | |||||
Geological and geophysical | 38 | ||||
Land | 720 | ||||
Drilling and completions | 23,481 | ||||
Workovers | 826 | ||||
Equipping and tie-in | 1,366 | ||||
Facilities and pipelines | 6,384 | ||||
Other | 642 | ||||
Capital expenditures | 33,457 | ||||
Property acquisitions | 3,597 | ||||
Property dispositions | (27,275) | ||||
Total capital expenditures, acquisitions and dispositions | 9,779 |
(1) Estimated and unaudited
Company Gross Reserves as at December 31, 2018
The following table summarizes the Company’s gross reserve volumes at December 31, 2018 utilizing the Consultant Average Price Forecast and cost estimates outlined further below in this press release.
Company Gross Reserves(1)(2) |
||||||||
Category | Crude Oil (Mbbl) |
Conventional Natural Gas (Mmcf) |
Natural Gas Liquids (Mbbl) |
2018 Oil Equivalent (MBoe) |
2017 Oil Equivalent (MBoe) |
2018/ 2017 Percent Change |
||
Proved | ||||||||
Developed Producing | 1,226.9 | 2,560.8 | 70.9 | 1,724.6 | 1,594.5 | 8% | ||
Developed Non-Producing | 106.0 | 181.6 | 4.5 | 140.8 | 96.6 | 46% | ||
Undeveloped | 3,107.7 | 6,764.6 | 169.1 | 4,404.2 | 1,416.3 | 211% | ||
Total Proved(3) | 4,440.6 | 9,507.0 | 244.6 | 6,269.7 | 3,107.4 | 102% | ||
Total Probable | 2,653.2 | 6,264.8 | 158.7 | 3,856.0 | 2,262.5 | 70% | ||
Total Proved + Probable(3) | 7,093.9 | 15,771.8 | 403.2 | 10,125.7 | 5,369.9 | 89% |
(1) Gross reserves are Company working interest reserves before royalty deductions.
(2) Based on the January 1, 2019 Consultant Average Price Forecast.
(3) Numbers may not add due to rounding.
In the Leduc-Woodbend Upper Mannville Rex oil pool, reserve growth was significant with PDP increasing from 437 mBoe to 1,487 mBoe which represents 86% of total PDP reserves. 1P increased from 1,221 mBoe to 6,032 mBoe which represents 96% of total 1P reserves. 2P increased from 2,140 mBoe to 9,818 mBoe which represents 97% of total 2P reserves. Altura’s other reserves consist of the Glauconitic oil assets that were acquired in 2018.
Reconciliation of Company Gross Reserves for 2018(1)(2)
Total Proved Oil Equivalent (mBoe) |
Total Proved + Probable Oil Equivalent (mBoe) |
||
December 31, 2017 | 3,107.4 | 5,369.9 | |
Extensions & Improved Recovery | 4,592.5 | 7,833.1 | |
Technical Revisions | 517.3 | 144.1 | |
Discoveries | – | – | |
Acquisitions | 247.4 | 317.5 | |
Dispositions | (1,767.4) | (3,111.4) | |
Economic Factors | – | – | |
Production | (427.6) | (427.6) | |
December 31, 2018 | 6,269.7 | 10,125.7 |
(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 reserves 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 $49.5 million and FDC for 2P undeveloped reserves increased by $55.3 million compared to year-end 2017. The increases in FDC were driven by additional locations at Leduc-Woodbend consistent with the increases in 1P and 2P reserve volumes.
Total Proved FDC(1)(2) ($000) |
Total Proved Wells(2) Gross (Net) |
Total Proved + Probable FDC(1)(2) ($000) |
Total Proved + Probable Wells(2) Gross (Net) |
||
2019 | 10,200 | 4 (4.0) | 10,200 | 4 (4.0) | |
2020 | 22,468 | 9 (8.7) | 22,468 | 9 (8.7) | |
2021 | 30,152 | 13 (11.3) | 30,152 | 13 (11.3) | |
2022 | 12,506 | 7 (4.5) | 32,650 | 15 (11.8) | |
Total Undiscounted | 75,327 | 33 (28.5) | 95,471 | 41 (35.8) |
(1) Numbers may not add due to rounding.
(2) FDC and well counts as per the McDaniel Report and based on the January 1, 2019 Consultant Average Price Forecast.
The forecasted future net operating income for the next four years from the McDaniel Report based on the January 1, 2019 Consultant Average Price Forecast is estimated to be $118.9 million for 1P reserves and $146.9 million for 2P reserves, which is sufficient to fund Altura’s FDC.
Summary of Before Tax Net Present Value (“NPV”) of Future Net Revenue as at December 31, 2018
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 the Consultant Average Pricing Forecast at January 1, 2019 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 | 40,085 | 36,613 | 33,645 | 31,155 | 29,068 | ||||
Developed Non-Producing | 3,903 | 3,592 | 3,330 | 3,109 | 2,923 | ||||
Undeveloped | 59,568 | 44,019 | 32,576 | 24,117 | 17,793 | ||||
Total Proved | 103,556 | 84,224 | 69,551 | 58,381 | 49,784 | ||||
Total Probable | 93,012 | 64,848 | 47,070 | 35,471 | 27,611 | ||||
Total Proved + Probable | 196,568 | 149,072 | 116,621 | 93,852 | 77,395 |
(1) Based on the January 1, 2019 Consultant Average Price Forecast.
(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, 2018 and 2017 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 2018 year-end reserve report and the 2017 year-end reserve report.
Before Tax NPV @ 10% Discount Rate | ||||||||||||
2018 | 2017 | |||||||||||
($000) | ($/Diluted Share(7)) |
($000) | ($/Diluted Share(7)) |
Per Share % Change |
||||||||
NPV of Future Net Revenue | ||||||||||||
Developed Producing(1)(2) | 33,645 | 0.29 | 28,832 | 0.25 | 16% | |||||||
Total Proved(1)(2) | 69,551 | 0.59 | 42,335 | 0.36 | 64% | |||||||
Total Proved + Probable(1)(2) | 116,621 | 0.99 | 76,059 | 0.65 | 52% | |||||||
Net Asset Value(3) | ||||||||||||
Total Proved + Probable(1)(2) | 116,621 | 0.99 | 76,059 | 0.65 | 52% | |||||||
Decommissioning liability(4) | (1,443) | (0.01) | (2,726) | (0.02) | (50%) | |||||||
Undeveloped acreage(5) | 6,210 | 0.05 | 10,267 | 0.09 | (44%) | |||||||
Net debt(6) | (4,819) | (0.04) | (3,730) | (0.03) | 33% | |||||||
Proceeds from stock options(7) | 2,850 | 0.02 | 2,408 | 0.02 | – | |||||||
Net asset value(7) | 119,419 | 1.01 | 82,278 | 0.71 | 42% |
(1) Evaluated by McDaniel as at December 31, 2018 and December 31, 2017. Net present value of future net revenue does not represent the fair market value of the reserves.
(2) 2018 Net present values are based on the January 1, 2019 Consultant Average Price Forecast and 2017 net present values are based on McDaniel’s January 1, 2018 price forecast.
(3) Net asset value does not have a standardized meaning. See “Oil and Gas Metrics” contained in this news release.
(4) The decommissioning liability included above is unaudited, discounted at 10% and is incremental to the amount included in the net present value of reserves as evaluated by McDaniel.
(5) Undeveloped acreage was determined from independent land valuation reports by Seaton-Jordan & Associates Ltd. as at December 31, 2018 and December 31, 2017. Fair market values were determined in accordance with NI 51-101 5.9(1)(e).
(6) Net debt as at December 31, 2018 is estimated and unaudited. Net debt does not have a standardized meaning. See “Oil and Gas Metrics” contained in this news release.
(7) Diluted shares as at December 31, 2018 were 108.9 million basic common shares plus 8.4 million stock options that were in-the-money as at December 31, 2018. Diluted shares as at December 31, 2017 were 108.9 million basic common shares plus 7.2 million stock options that were in-the-money as at December 31, 2017.
Performance Metrics(1)
Altura’s 2018 Finding, Development & Acquisitions (“FD&A”) costs were burdened with the investment of $6.4 million, 19% of total capital expenditures, to construct facilities and pipeline infrastructure. The infrastructure investments will benefit future development, 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 2018, 2017 and 2016.
2018 | 2017 | 2016 | ||||
Capital expenditures, acquisitions and dispositions(2) ($000) | 9,647 | 21,187 | 17,492 | |||
Change in FDC – Total Proved ($000) | 49,520 | 16,109 | 5,704 | |||
Change in FDC – Total Proved + Probable ($000) | 55,320 | 23,329 | 7,664 | |||
Q4 production (Boe/d) | 1,412 | 1,202 | 988 | |||
Annual operating netback ($/Boe)(3) | 24.54 | 27.49 | 25.29 | |||
Proved Developed Producing | ||||||
FD&A costs ($/Boe)(3) | 17.30 | 23.36 | 19.99 | |||
Recycle ratio(3) | 1.4 | 1.2 | 1.3 | |||
Reserve replacement(3) | 130% | 220% | 417% | |||
Reserve life index (“RLI”) (years)(3) | 3.3 | 3.6 | 3.0 | |||
Total Proved | ||||||
FD&A costs ($/Boe)(3) | 16.48 | 21.97 | 17.76 | |||
Recycle ratio(3) | 1.5 | 1.3 | 1.4 | |||
Reserve replacement(3) | 839% | 412% | 622% | |||
Reserve life index (“RLI”) (years)(3) | 12.1 | 7.0 | 5.0 | |||
Total Proved + Probable | ||||||
FD&A costs ($/Boe)(3) | 12.53 | 17.21 | 12.32 | |||
Recycle ratio(3) | 2.0 | 1.6 | 2.1 | |||
Reserve replacement(3) | 1,212% | 628% | 973% | |||
Reserve life index (“RLI”) (years)(3) | 19.5 | 12.1 | 8.8 |
(1) Financial and production information is per the Company’s 2018 preliminary unaudited financial statements and is therefore subject to audit.
(2) Capital expenditures excludes office furniture and computer and office equipment of $132,000 in 2018.
(3) “Operating netback”, “Finding, development & acquisitions costs” or “FD&A costs”, “Recycle ratio”, “Reserve replacement”, and “Reserve life index” or “RLI” do not have standardized meanings. See “Oil and Gas Metrics” contained in this news release.
Altura’s recycle ratios in 2018 were negatively impacted by the sharp decline in Canadian oil prices in the fourth quarter of 2018. Using Altura’s operating netback for the nine months ended September 30, 2018 of $29.77 per Boe, recycle ratios in 2018 are 1.7 for PDP, 1.8 for 1P and 2.4 for 2P.
Price Forecast
The McDaniel Report was based on the Consultant Average Price Forecast at January 1, 2019 as outlined below.
WTI Crude Oil ($US/bbl) |
Western Canadian Select |
Alberta AECO Gas ($CAD/mmbtu) |
Foreign Exchange |
||
2019 | 58.58 | 51.55 | 1.88 | 0.757 | |
2020 | 64.60 | 59.58 | 2.31 | 0.782 | |
2021 | 68.20 | 65.89 | 2.74 | 0.797 | |
2022 | 71.00 | 68.61 | 3.05 | 0.803 | |
2023 | 72.81 | 70.53 | 3.21 | 0.807 | |
2024 | 74.59 | 72.34 | 3.31 | 0.808 | |
2025 | 76.42 | 74.31 | 3.39 | 0.808 | |
2026 | 78.40 | 76.44 | 3.46 | 0.808 | |
2027 | 79.98 | 78.10 | 3.54 | 0.808 | |
2028 | 81.59 | 79.81 | 3.62 | 0.808 | |
2029 | 83.22 | 81.41 | 3.69 | 0.808 | |
2030 | 84.89 | 83.04 | 3.77 | 0.808 | |
2031 | 86.58 | 84.70 | 3.84 | 0.808 | |
2032 | 88.31 | 86.39 | 3.92 | 0.808 | |
2033 | 90.08 | 88.12 | 4.00 | 0.808 | |
thereafter | +2.0%/yr | +2.0%/yr | +2.0%/yr | 0.808 |
ABOUT ALTURA ENERGY INC.
Altura is a junior oil and gas exploration, development and production company with operations in central Alberta. Altura predominantly produces from the Rex reservoir 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.