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Gear Energy Ltd. Announces 2018 Year-End Reserves


CALGARYFeb. 27, 2019 /CNW/ – Gear Energy Ltd. (“Gear” or the “Company”) (TSX:GXE) is pleased to present the following results and analysis of its 2018 year-end independent reserve report prepared by its new independent evaluator Sproule Associates Limited (“Sproule”).

In 2018 Gear invested $110.0 million consisting of $43.8 million of development capital and $66.2 million in acquisition and divestiture (“A&D”) capital. The combined investment provided Gear with four per cent annual production growth and an average of 15 per cent reserves growth compared to 2017. Production growth was tempered as a result of strategic late year production limitations due to pricing and egress, and reserves growth was also limited by the associated lack of production history from new wells impacting forecast certainty, and the removal of undeveloped gas reserves due to lower pricing. For details on the annual operating results please see the Management’s Discussion and Analysis dated February 27, 2019, which is available on SEDAR at www.sedar.com.

HIGHLIGHTS

  • Gear achieved the following reserves highlights through 2018 activity:

Proved Developed Producing (“PDP”)

    • 3.59 MMboe of additions
    • Reserves increased 14 per cent, or 2 per cent per debt adjusted share
    • Reserves value on a Before Tax 10 per cent discounted basis (“BT10”) increased 36 per cent, or 22 per cent per debt adjusted share
    • Replaced 145 per cent of 2018 annual production
    • Finding, Development and Acquisition (“FD&A”) cost of $30.56/boe including change in Future Development Capital (“FDC”)
    • Recycle ratio of 0.7x based on 2018 operating netback of $21.97/boe

Total Proved (“TP”)

    • 5.15 MMboe of additions
    • Reserves increased 18 per cent, or 6 per cent per debt adjusted share
    • Reserves value BT10 increased 36 per cent, or 21 per cent per debt adjusted share
    • Replaced 208 per cent of 2018 annual production
    • FD&A cost of $34.64/boe including change in FDC
    • Recycle ratio of 0.6x on 2018 netback

Total Proved plus Probable (“P+P”)             

    • 6.01 MMboe of additions
    • Reserves increased 14 per cent, or 2 per cent per debt adjusted share
    • Reserves value BT10 increased 31 per cent, or 17 per cent per debt adjusted share
    • Replaced 243 per cent of 2018 annual production
    • FD&A cost of $38.11/boe including change in FDC
    • Recycle ratio of 0.6x on 2018 netback
  • Corporate liquids weighting increased to 90 per cent from 86 per cent for the P+P reserves case. This increase was the result of the acquisition of Steppe Resources, continued successful oil development and the removal of several undeveloped gas drilling locations due to low forecasted future gas prices. Corporate P+P liquids reserves are now balanced 52 per cent heavy oil, 45 per cent light and medium oil, and 3 per cent NGLs.
  • In aggregate, the P+P reserves associated with the 2018 capital development program came in on target. In particular, the following highlights were achieved:
    • The 7 well multi-lateral un-lined heavy oil drilling and re-entry program was successful in adding production and reserves, as well as proving up two new core areas in Lindbergh and Maidstone and a new zone in the Sparky at Wildmere. The program achieved strong average P+P reserves bookings of 91 mboe per well.
    • The 10 well horizontal drilling program in Paradise Hill, (Celtic), realized average P+P reserves bookings of 60 mboe per well.
    • The 2 well horizontal drilling program in Hoosier achieved average P+P reserves bookings of 98 mboe per well.
    • The 7 well (4.9 net) light oil drilling program in Wilson Creek and Ferrier realized average P+P reserves bookings of approximately 160 mboe per well (gross).
    • Waterflood development activities in Killam and Wilson Creek resulted in over 500 mboe of booked P+P reserves. However, until the associated oil production response is seen, PDP reserves will not be recognized by Sproule.Managements annual estimate of future potential drilling locations increased by 7 per cent over 2017 to 630 net locations. The Sproule evaluation currently recognizes 108 net locations in the TP category and 187 in the P+P category. These booked locations represent only 17 and 30 per cent of the management estimates, respectively. The 187 net booked P+P locations include 38 multi-lateral horizontals, 127 single lateral horizontals and 22 vertical wells.
  • Managements annual estimate of future potential drilling locations increased by 7 per cent over 2017 to 630 net locations. The Sproule evaluation currently recognizes 108 net locations in the TP category and 187 in the P+P category. These booked locations represent only 17 and 30 per cent of the management estimates, respectively. The 187 net booked P+P locations include 38 multi-lateral horizontals, 127 single lateral horizontals and 22 vertical wells.
  • Corporate Net Asset Values (“NAV”) BT10 are $0.85 per share for TP and $1.72 per share for P+P utilizing the Average Independent Engineering price forecast at January, 2019. These values represent a respective 4 per cent and 7 per cent increase from the prior year.
  • Company Reserves Life Index (“RLI”) of 5.4 years for TP, and 7.7 years for P+P. These values are 2 per cent higher and 5 per cent lower than the prior year’s values, respectively.
  • PDP Reserves balances and annual addition costs through 2018 were negatively impacted by a combination of reduced forecast certainty on new wells as a result of fourth quarter production deferrals, limited current year PDP bookings granted to waterflood development activities, and the acquisition costs associated with Steppe Resources. In particular, the PDP recycle ratio was negatively impacted as a result of the full cost of the Steppe acquisition being balanced against the minimal annual benefits of the increased light oil operating netback due to the late year closing of the deal.
  • TP and P+P Reserves balances and annual addition costs through 2018 were negatively impacted by similar factors as occurred in the PDP case. In addition, an increased level of conservatism was applied across the portfolio to P+P production forecasts, and reduced gas price forecasts  resulted in the removal of most undeveloped gas booking in Ekwan, BC.

RESERVES SUMMARY

Year-end 2018 reserves were evaluated by independent reserves evaluator Sproule in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). A reserves committee, comprised of independent board members, reviews the qualifications and appointment of the independent reserves evaluator and reviews the procedures for providing information to the evaluators. The reserves evaluation was based on Evaluator Average forecast pricing and foreign exchange rates at January 1, 2019. Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without inclusion of any royalty interests) unless noted otherwise. Additional reserves information required under NI 51-101 will be included in Gear’s Annual Information Form to be filed on SEDAR on or before March 31, 2019.

The following tables outline Gear’s reserves as at December 31, 2018. No provision for interest, risk management contracts, debt service charges and general and administrative expenses have been made and it should not be assumed that the net present values of the reserves estimated by Sproule represents the fair market value of the reserves.

Reserves Summary at Dec 31, 2018 Using Sproule Costs and January 1, 2019 Evaluator Average Forecast Prices

Company Gross

Light &
Medium
Oil

(Mbbl)

 Heavy Oil

(Mbbl)

NGL’s

(Mbbl)

Natural
Gas

(MMcf)

Equivalent

(Mboe)

Liquids
Ratio

(%)

Proved Developed Producing

3,722

3,604

437

7,585

9,027

86

Proved Non-Producing & Undeveloped

3,485

3,679

221

4,333

8,107

91

Total Proved

7,207

7,282

658

11,918

17,134

88

Total Probable

4,265

6,467

332

5,044

11,903

93

Total Proved plus Probable

11,472

13,749

990

16,962

29,037

90

Net Present Value of Future Revenues Before Income Taxes Under Forecast Prices and Costs

Company Gross

Undiscounted

Discounted

Discounted

Discounted

Discounted

($ thousands)

@ 5%

@ 10%

@ 15%

@ 20%

Proved Developed Producing

232,947

200,894

177,571

159,947

146,135

Proved Non-Producing & Undeveloped

161,462

116,934

87,068

66,267

51,157

Total Proved

394,409

317,828

264,639

226,214

197,292

Total Probable

350,985

251,698

192,192

152,807

124,974

Total Proved plus Probable

745,394

569,525

456,831

379,021

322,266

Net Future Development Costs (“FDC”) Under Forecasted Prices and Costs

($ thousands)

Proved

Probable

Total

2019

57,477

20,048

77,525

2020

47,360

30,038

77,398

2021

25,396

28,877

54,273

2022

22,268

16.879

39,147

2023

1,929

12,001

13,930

Subsequent Years

0

3,542

3,542

Undiscounted Total

154,431

111,385

265,816

Discounted at 10%

133,501

90,148

223,648

EFFICIENCY RATIOS

The following table highlights annual capital efficiency through finding and development (“F&D”) and FD&A costs per boe metrics.

2018

2017

Reserves (mboes), Capital ($ thousands)

Proved

Proved plus
Probable

Proved

Proved plus
Probable

Development Reserves Additions

1,637

234

3,075

1,957

Net Acquisition Reserves Additions

3,511

5,777

(29)

(50)

Total Reserves Additions

5,148

6,012

3,046

1,907

Development capital

43,859

43,859

47,765

47,765

Development change in FDC

7,292

5,803

5,172

(3,028)

Total development capital including FDC

51,151

49,663

52,937

44,737

Net acquisition capital

66,172

66,172

1,709

1,709

Net acquisition change in FDC

60,964

113,249

Total net acquisition capital including FDC

127,136

179,421

1,709

1,709

Total capital

110,032

110,032

49,474

49,474

Total change in FDC

68,256

119,052

5,172

(3,028)

Total capital including FDC

178,287

229,084

54,646

46,446

F&D costs with FDC per boe

31.26

211.86

17.22

22.86

FD&A costs with FDC per boe

34.64

38.11

17.94

24.36

3 Year average FD&A including FDC per boe

22.63

24.71

16.26

19.22

Recycle ratio (FD&A with FDC)

0.6

0.6

1.2

0.9

Reserves Life Index (“RLI”)

(years)

2018

2017

2016

Total Proved

5.4

5.3

5.9

Total Proved plus Probable

7.7

8.1

9.7

Net Asset Value (“NAV”) at December 31, 2017

($ millions, except per share amounts)

2018

2017

2016

Value of Company Interest Proved plus Probable

Reserves Discounted at 10% (Before Tax)

456.8

349.8

394.6

Undeveloped Land

12.8

8.2

6.2

Net Debt

(91.9)

(43.3)

(37.0)

NAV

377.7

314.7

363.8

Shares Outstanding (millions)

219.1

195.0

192.6

NAV per Share

1.72

1.61

1.89

RESERVES RECONCILIATION

Activity through 2018 was successful in adding reserves across all categories with the largest improvements categorized as Drilling Extensions, Infill Drilling, and Acquisitions associated with the purchase of Steppe Resources. The PDP reserves had positive increases across all categories.  The Proved reserves also had positive increases in every category with the exception of Technical Revisions. The main contributor to this adjustment occurred in Ekwan, BC where an undeveloped drilling location and existing well tie-in location were removed from the portfolio as a result of low gas prices.

The P+P reserves balance experienced a negative Technical Revision of 3.57 MMboe that was offset by a positive 0.35 MMboe economic adjustment, yielding a combined negative adjustment of 3.22 MMBoe. In addition to the removal of 0.75 MMboe in Ekwan, BC, the other factor influencing the year over year reserves changes was a more conservative view of future production profiles for both developed and undeveloped P+P bookings. This view amounted to a negative adjustment estimated between 0.70 to 1.00 MMboe. Base performance issues (0.71 MMboe), the removal or reclassification of uneconomic projects (0.60 MMboe), and finally the removal of drill locations on expired mineral acreage (0.28 MMboe) were the causes of the remaining negative Technical Revisions.

Reserves Reconciliation

Company Gross

Heavy Oil
(Mbbl)

Light &
Medium
Oil

(Mbbl)

Natural
Gas
(MMcf)

Natural
Gas
Liquids
(Mbbl)

Oil
Equivalent
(Mboe)

Proved Producing

Opening Balance, January 1, 2018

3,913

2,148

8,043

509

7,910

Technical Revisions

818

399

1,175

1

1,415

Drilling Extensions

231

60

74

11

314

Infill Drilling

134

1

134

Improved Recovery

Acquisitions

1,578

1,578

Dispositions

Economic Factors

109

39

1

4

152

Production

(1,602)

(501)

(1,708)

(89)

(2,477)

Closing Balance, December 31, 2018

3,604

3,722

7,586

437

9,027

Total Proved

Opening Balance, January 1, 2018

7,728

3,636

14,148

741

14,463

Technical Revisions

107

229

(1,660)

(86)

(27)

Drilling Extensions

540

120

170

26

714

Infill Drilling

354

125

733

35

636

Improved Recovery

3.5

151

23

52

Acquisitions

3,508

7

1

3,511

Dispositions

Economic Factors

156

87

77

6

262

Production

(1,602)

(501)

(1,708)

(89)

(2,477)

Closing Balance, December 31, 2018

7,282

7,207

11,918

658

17,134

Proved plus Probable

Opening Balance, January 1, 2018

15,010

5,871

20,754

1,163

25,503

Technical Revisions

(2,010)

(581)

(4,277)

(261)

(3,565)

Drilling Extensions

1,324

364

665

56

1,854

Infill Drilling

743

155

889

42

1,089

Improved Recovery

337

605

72

510

Acquisitions

5,774

9

1

5,777

Dispositions

Economic Factors

283

53

25

6

347

Production

(1,602)

(501)

(1,708)

(89)

(2,477)

Closing Balance, December 31, 2018

13,749

11,472

16,962

990

29,037

FORECAST PRICES AND COSTS

Evaluator average crude oil and natural gas benchmark reference pricing, inflation, and exchange rates utilized by Sproule as at January 1, 2019 were as follows:

Year

Inflation

(%)

Exchange
Rate

(USD/CAD)

WTI Cushing

(40 API)

(USD/bbl)

Edmonton
MSW

(40 API)

(CAD/bbl)

WCS
Hardisty

(21 API)

(CAD/bbl)

AECO/NIT
Spot

(CAD/mmbtu)

2019

0.0

0.76

58.58

67.30

51.55

1.88

2020

2.0

0.78

64.60

75.84

59.58

2.31

2021

2.0

0.80

68.20

80.17

65.89

2.74

2022

2.0

0.80

71.00

83.22

68.61

3.05

2023

2.0

0.81

72.81

85.34

70.53

3.21

2024

2.0

0.81

74.59

87.33

72.34

3.31

2025

2.0

0.81

76.42

89.50

74.31

3.39

2026

2.0

0.81

78.40

91.89

76.44

3.46

2027

2.0

0.81

79.98

93.76

78.10

3.54

2028

2.0

0.81

81.59

95.68

79.81

3.62

2029+

2.0

0.81

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr



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