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Altura Energy Inc. Announces an Operational Update and 2019 Reserve


CALGARY – Altura Energy Inc. (“Altura” or the “Company”) (TSX-V: ATU) is pleased to announce an operational update and the results of the independent evaluation of the Company’s oil and natural gas reserves (the “McDaniel Report”), effective December 31, 2019, as prepared by McDaniel and Associates Consultants Ltd. (“McDaniel”).

Altura’s audit of its 2019 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.

OPERATIONAL UPDATE

2019 production averaged 1,742 Boe per day (70% oil and liquids), consistent with guidance of 1,700 to 1,800 Boe per day and representing a 49 percent increase from average 2018 production on an absolute and per share basis.  Fourth quarter 2019 production averaged 1,561 Boe per day (64% oil and liquids).  Fourth quarter 2019 production was affected by natural declines as no new wells were brought on production in the quarter and by the disposition of a seven percent working interest of production, as announced on December 4, 2019.

In 2019, Altura invested approximately $12.8 million in capital projects.  The Company drilled three gross (3.0 net) and completed two gross (2.0 net) wells in the Leduc-Woodbend area, invested in an electrification project and a solution gas compressor at Leduc-Woodbend, as well as changed its artificial lift system on 11 wells to improve run-time efficiencies and reduce operating and capital workover events.

Altura evaluated a new potential oil play targeting medium to light oil in the Entice area of Alberta, south of Strathmore.   The Corporation has acquired 89 gross (83 net) sections of land in the area which has year-round access.  Vertical well data, combined with extensive 3D seismic coverage in the area, provided a means to identify and map the hydrocarbon accumulation.  In June 2019, Altura drilled a vertical exploratory stratigraphic well to obtain additional geological data.

In December 2019, Altura announced it had entered into a definitive agreement for the asset sale of a 12.5% working interest (the “Asset Disposition”) in the Company’s production, wells, lands and facilities for $7.0 million in two transactions. The first transaction closed on December 4, 2019, whereby Altura divested a seven percent working interest for $3.1 million.  Proceeds from the first transaction were directed to the Company’s exploratory prospect at Entice in 2020.

Based on the geological data obtained from the vertical exploration well, Altura drilled and completed a horizontal well (93% working interest) targeting the Pekisko Formation in January 2020.  The well was successfully drilled and cased to a vertical depth of 1,775 meters with a horizontal length of 2,004 meters and subsequently completed with 45 frac stages placing approximately 13 tonnes of sand per stage.  Production testing operations are ongoing and expected to continue through March as Altura evaluates the well.

At Leduc-Woodbend, Altura completed a horizontal oil well (93% working interest) in January 2020 that was drilled in the third quarter of 2019.   The well was equipped for production and brought on stream on February 8, 2020.  Additionally, Altura drilled a horizontal oil well (93% working interest) and expects to complete it in the second quarter of 2020.

2019 YEAR-END RESERVE HIGHLIGHTS

  • Net of the seven percent Asset Disposition, Altura’s proved developed producing (“PDP”) reserves increased two percent from 1,725 MBoe at December 31, 2018 to 1,755 MBoe. Total proved (“1P”) reserves increased one percent from 6,270 MBoe at December 31, 2018 to 6,347 MBoe. Total proved plus probable (“2P”) reserves increased 10 percent from 10,126 MBoe at December 31, 2018 to 11,150 MBoe.
  • Finding, development and acquisition (“FD&A”) costs1 were $14.61 per Boe for PDP reserves.
  • Recycle ratio1 of 1.7 times for PDP reserves based on the 2019 FD&A costs and Altura’s estimated 2019 operating netback1 of $24.95 per Boe.
  • Replaced1 105 percent of annual production with new PDP reserves, 112 percent of annual production with new 1P reserves and 261 percent of annual production with new 2P reserves, based on 2019 production of 1,742 Boe per day.
  • 2P reserves at Leduc-Woodbend are booked on 18 net sections of land which is only 27 percent of Altura’s lands in the area.
  • The forecast cost of all of Altura’s future abandonment, decommissioning and reclamation obligations (“ADR”) is $1.8 million (discounted at 10%), which represents only 6.6% of the total $27.2 million of future net revenue of PDP reserves (before tax, discounted at 10%), excluding ADR.

2019 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, 2020.  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, 2019, which will be filed on SEDAR by April 30, 2020.

Commencing in 2019, McDaniel began to include additional ADR in the Company’s reserves, resulting in a decrease of values compared to 2018. The Company previously reported certain Asset Restoration Obligations (“ARO”) separately from those contained in the Company’s December 31, 2018 evaluation in the Annual Information Form. This substantial change to the prior years’ practices, which were consistent with the reporting of many other companies in the industry, was based on new Canadian Oil and Gas Evaluation Handbook  (“COGE Handbook”) guidelines that recommend the inclusion of ADR costs associated with the Company’s assets in the reserve report. This change incorporates costs for active and inactive wells, including producing wells, suspended wells, service wells, gathering systems, facilities, and surface land reclamation for all of Altura’s assets. McDaniel’s evaluation of Altura’s NPV10 BT at December 31, 2019 (estimated before tax net present value of future net revenues associated with the Company’s reserves, discounted at 10%) for ADR related to PDP, 1P and 2P reserves was $1.8 million, $2.2 million, and $2.2 million, respectively, reflecting an increase of $1.4 million, $1.2 million, and $1.4 million compared to the ADR measures at year-end 2018.

Company Gross Reserves as at December 31, 2019

The following table summarizes the Company’s gross reserve volumes at December 31, 2019 utilizing the Consultant Average Price Forecast and cost estimates outlined further below in this press release.

Company Gross Reserves(1)(2)

Category

Light &
Medium
Oil (Mbbl)

Heavy
Oil
(Mbbl)

Conventional
Natural Gas
(MMcf)

Natural
Gas
Liquids
(“NGLs”)

(Mbbl)

2019 Oil
Equivalent
(MBoe)

2018 Oil
Equivalent
(MBoe)

2019/

2018
Percent
Change

Proved

Developed Producing

161.2

777.3

4,270.2

104.3

1,754.5

1,724.6

2%

Developed Non-
Producing

102.3

307.8

7.4

161.0

140.8

14%

Undeveloped

2,815.4

8,473.9

203.4

4,431.1

4,404.2

1%

Total Proved(3)

161.2

3,695.0

13,052.0

315.1

6,346.5

6,269.7

1%

Total Probable

164.3

2,336.6

12,109.9

284.7

4,803.9

3,856.0

25%

Total Proved +

Probable(3)

325.4

6,031.6

25,161.9

599.7

11,150.4

10,125.7

10%

(1)

Gross reserves are Company working interest reserves before royalty deductions.

(2)

Based on the January 1, 2020 Consultant Average Price Forecast.

(3)

Numbers may not add due to rounding.

Reconciliation of Company Gross Reserves for 2019(1)(2)

Light &
Medium Oil
(Mbbl)

Heavy Oil
(Mbbl)

Conventional
Natural Gas
(MMcf)

Natural Gas
Liquids

(Mbbl)

Oil Equivalent
(MBoe)

Total Proved

December 31, 2018

213.4

4,227.2

9,507.0

244.6

6,269.7

Extensions

204.5

615.7

14.8

321.9

Technical Revisions

(2.0)

(101.5)

4,669.5

103.3

778.1

Acquisitions

Dispositions

(12.0)

(261.5)

(592.3)

(15.4)

(387.7)

Economic Factors

Production

(38.2)

(373.7)

(1,147.9)

(32.1)

(635.5)

December 31, 2019

161.2

3,695.0

13,052.0

315.1

6,346.5

Total Proved + Probable

December 31, 2018

276.2

6,817.6

15,771.8

403.2

10,125.7

Extensions

111.0

521.4

2,251.0

47.4

1,055.1

Technical Revisions

(7.3)

(493.3)

9,300.3

207.3

1,256.8

Acquisitions

Dispositions

(16.3)

(440.4)

(1,013.3)

(26.1)

(651.7)

Economic Factors

Production

(38.2)

(373.7)

(1,147.9)

(32.1)

(635.5)

December 31, 2019

325.4

6,031.6

25,161.9

599.7

11,150.4

(1)

Gross reserves are Company working interest reserves before royalty deductions.

(2)

  Numbers may not add due to rounding.

Technical revisions for heavy oil, natural gas and NGLs, in both the 1P and 2P reserves categories, are due to changes in the Leduc-Woodbend production forecast based on higher natural gas production in 2019 than previous year’s forecast.

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 decreased by $11.7 million and FDC for 2P undeveloped reserves decreased by $6.7 million compared to year-end 2018. The decreases in FDC were driven by the Asset Disposition in 2019 and lower expected capital cost estimates at Leduc-Woodbend.

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)

2020

9,798

4   (3.6)

12,816

4   (3.6)

2021

20,768

10   (8.7)

20,768

10   (8.7)

2022

23,385

12   (9.4)

23,385

12   (9.4)

2023

9,717

6   (3.9)

19,009

10   (7.6)

2024

12,843

6   (5.0)

Total Undiscounted

63,668

32 (25.6)

88,820

42 (34.3)

(1)

Numbers may not add due to rounding.

(2)

FDC and well counts as per the McDaniel Report and based on the January 1, 2020 Consultant Average Price Forecast.

The forecasted future net operating income for the next four years from the McDaniel Report based on the January 1, 2020 Consultant Average Price Forecast is estimated to be $98.7 million for 1P reserves and $116.2 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, 2019

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, 2020 as outlined in the price forecast table further below in this press release.  The NPVs include ADR 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

28,097

27,322

25,403

23,420

21,643

Developed Non-Producing

2,657

2,272

1,964

1,716

1,515

Undeveloped

61,043

44,583

32,854

24,412

18,232

Total Proved

91,797

74,177

60,220

49,548

41,390

Total Probable

92,600

61,413

42,656

30,834

23,027

Total Proved + Probable

184,396

135,590

102,876

80,381

64,417

(1)

Based on the January 1, 2020 Consultant Average Price Forecast.

(2)

Numbers may not add due to rounding.

Summary of Undeveloped Locations Converted to Producing Wells

The following table shows the Company’s past performance in converting future undeveloped locations into producing wells at a better cost than was forecast.

Reserve
Year

Total

Gross
Wells

Drilled

Booked
Gross
Locations
Converted

Booked/
Total
Drills

%

Forecast Outcome(2)

Forecast
Cost per
Unit(2)

$/boe

Actual Outcome(3)

Actual Cost
per Unit(3)

$/Boe

Actual/
Forecast Cost
per Unit

% Change

MBoe

Capex(1)
($000)

MBoe

Capex(1)
($000)

2016

7

4

57%

357

3,460

9.68

445

2,976

6.69

-31%

2017

8

4

50%

403

4,100

10.18

394

4,446

11.28

11%

2018

10

4

40%

659

9,350

14.19

721

9,360

12.97

-9%

2019

4

3

75%

573

6,983

12.19

654

7,405

11.32

-7%

Total

29

15

52%

1,992

23,893

11.99

2,215

24,187

10.92

-9%

(1)

Capex includes drilling, completion, and equipping expenses. 

(2)

Forecast outcome represents what was included for future drilling locations in each year’s reserve evaluation on a 2P basis.

(3)

Actual outcome represents the actual cost and actual 2P reserves recognized for the wells drilled during that year.

In 2019 Altura drilled four gross wells.  Of these four wells, three were originally booked in the year end 2018 evaluation totalling 573 MBoe of Proved Undeveloped + Probable Additional reserves for a forecast capital investment of $7.0 million ($12.19/Boe).  The actual capital spent on these three wells was $7.4 million resulting in Proved Developed Producing + Probable Additional reserves of 654 MBoe ($11.32/Boe).

Company Net Asset Value

The Company’s net asset value as at December 31, 2019 and 2018 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 recognizing additional reserves through successful future capital investment in its existing properties beyond those included in the 2019 year-end reserve report and the 2018 year-end reserve report.

Before Tax NPV @ 10% Discount Rate

2019

2018

($000)

($/Share(7))

($000)

($/Share(7))

Per Share

% Change

NPV of Future Net Revenue

Developed Producing(1)(2)(3)

25,403

0.23

32,202

0.31

(26%)

Total Proved(1)(2)(3)

60,220

0.55

68,108

0.64

(14%)

Total Proved + Probable(1)(2)(3)

102,876

0.94

115,178

1.06

(11%)

Net Asset Value(4) 

Total Proved + Probable(1)(2)(3)

102,876

0.94

115,178

1.06

(11%)

Undeveloped acreage(5)

5,727

0.05

6,210

0.06

Net debt(6)

(563)

(0.01)

(4,820)

(0.04)

(75%)

Net asset value(7)

108,040

0.98

116,568

1.07

(7%)

(1)

Evaluated by McDaniel as at December 31, 2019 and December 31, 2018. Net present value of future net revenue does not represent the fair market value of the reserves.

(2)

Net present values are based on the January 1, 2020 Consultant Average Price Forecast and the January 1, 2019 Consultant Average Price Forecast.

(3)

Includes the net present value of the Company’s estimated decommissioning obligations. Approximately $1.4 million of incremental decommissioning obligation costs were deducted from the amount included in the 2018 present value of reserves as evaluated by McDaniel as at December 31, 2018 to allow a direct comparison to 2019 with full ADR.

(4)

Net asset value does not have a standardized meaning.  See “Oil and Gas Metrics” contained in this news release.

(5)

For 2019, undeveloped acreage was internally valued by management.  For 2018, undeveloped acreage value was determined from independent land valuation reports by Seaton-Jordan & Associates Ltd. as at December 31, 2018. Fair market values were determined in accordance with NI 51-101 5.9(1)(e). 

(6)

Net debt as at December 31, 2019 is estimated and unaudited.  Net debt does not have a standardized meaning.  See “Oil and Gas Metrics” contained in this news release.

(7)

As at December 31, 2019 and 2018, Altura had 108.9 million basic common shares outstanding. 

Performance Metrics(1)

The following table highlights Altura’s FD&A, recycle ratio, reserve replacement and reserve life index for 2019, 2018 and 2017.

2019

2018

2017

Three
Year

Capital expenditures, acquisitions and dispositions(2) ($000)

9,728

9,647

21,187

40,563

Change in FDC – Total Proved ($000)

(11,658)

49,520

16,109

53,971

Change in FDC – Total Proved + Probable ($000)

(6,650)

55,320

23,329

71,998

Q4 production (Boe/d)

1,561

1,412

1,202

Operating netback ($/Boe)(3)

24.95

24.54

27.49

25.66

Proved Developed Producing

FD&A costs ($/Boe)(3)

14.61

17.30

23.36

19.04

Recycle ratio(3)

1.7

1.4

1.2

1.3

Reserve replacement(3)

105%

130%

220%

Reserve life index (“RLI”) (years)(3)

3.1

3.3

3.6

Total Proved

FD&A costs ($/Boe)(3)

(2.71)

16.48

21.97

15.75

Recycle ratio(3)

(9.2)

1.5

1.3

1.6

Reserve replacement(3)

112%

839%

412%

Reserve life index (“RLI”) (years)(3)

11.0

12.1

7.0

Total Proved + Probable

FD&A costs ($/Boe)(3)

1.85

12.53

17.21

11.94

Recycle ratio(3)

13.5

2.0

1.6

2.1

Reserve replacement(3)

261%

1,212%

628%

Reserve life index (“RLI”) (years)(3)

19.4

19.5

12.1

(1)

Financial and production information is per the Company’s 2019 preliminary unaudited financial statements and is therefore subject to audit.

(2)

Capital expenditures excludes office furniture and computer and office equipment.

(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.

 

Price Forecast

The McDaniel Report was based on the Consultant Average Price Forecast at January 1, 2020 as outlined below.

WTI

Crude Oil

($US/bbl)

Western Canadian Select

Crude Oil

($CAD/bbl) 

Alberta AECO

Gas

($CAD/mmbtu) 

Foreign Exchange
($US/$CAD)

2020

61.00

57.57

2.04

0.760

2021

63.75

62.35

2.32

0.770

2022

66.18

64.33

2.62

0.785

2023

67.91

66.23

2.71

0.785

2024

69.48

67.97

2.81

0.785

2025

71.07

69.72

2.89

0.785

2026

72.68

71.49

2.96

0.785

2027

74.24

73.20

3.03

0.785

2028

75.73

74.80

3.09

0.785

2029

77.24

76.43

3.16

0.785

2030

78.79

77.96

3.23

0.785

2031

80.36

79.52

3.29

0.785

2032

81.97

81.11

3.36

0.785

2033

83.61

82.73

3.43

0.785

2034

85.28

84.39

3.49

0.785

thereafter

+2.0%/yr

+2.0%/yr

+2.0%/yr

0.785

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.



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