Gear Energy Ltd. Announces 2018 Year-End Reserves

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Gear Energy Ltd. Announces 2018 Year-End Reserves

Canada NewsWire

CALGARY, Feb. 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

 

ADVISORY ON FORWARD-LOOKING STATEMENTS: This press release contains certain forward-looking information and statements within the meaning of applicable securities laws. In particular, this press release contains forward-looking information relating to, among other things: estimates of reserves and future net revenue, estimated number of future drilling locations and estimated future development capital. The use of any of the words "expect", "continue", "estimate", "may", "will", "should", "believe", "plans", "cautions" and similar expressions are intended to identify forward-looking information or statements. Forward-looking statements or information are based on a number of material factors, expectations or assumptions of Gear which have been used to develop such statements and information but which may prove to be incorrect. Although Gear believes that the expectations reflected in these forward-looking statements are reasonable, undue reliance should not be placed on them because Gear can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. In particular, in addition to other factors and assumptions which may be identified herein, assumptions have been made regarding: that Gear's exploration and development activities will be successful or that material volumes of petroleum and natural gas reserves will be encountered, or if encountered can be produced on a commercial basis; that additional drilling operations will be successful such that further development activities is warranted; that Gear's efforts to raise additional capital will be successful; that Gear will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities will be consistent with past operations; the accuracy of the estimates of Gear's reserve volumes; the general stability of the economic and political environment in which Gear operates; drilling results; field production rates and decline rates; the general continuance of current industry conditions; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Gear to secure adequate product transportation; future commodity prices and heavy oil differentials; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Gear operates; and the ability of Gear to successfully market its oil and natural gas products; the ability of Gear to obtain financing on terms acceptable to Gear; and the continued availability of credit under the Company's credit facilities.

Further, events or circumstances may cause actual results to differ materially from those predicted as a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Gear, including, without limitation: changes in commodity prices and heavy oil differentials; changes in the demand for or supply of Gear's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Gear or by third party operators of Gear's properties, increased debt levels or debt service requirements; any actions by Gear's lenders to reduce the availability under its credit facilities; inaccurate estimation of Gear's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Gear's public disclosure documents. Additional information regarding some of these risk factors may be found under "Risk Factors" in Gear's annual information form for the year ended December 31, 2018, which is expected to be filed on or before March 31, 2019. The reader is cautioned not to place undue reliance on this forward-looking information. To the extent that any forward-looking information contained herein may be considered future oriented financial information or a financial outlook, such information has been included to provide readers with an understanding of management's assumptions used for budgeting and developing future plans and readers are cautioned that the information may not be appropriate for other purposes. The forward-looking statements contained in this press release are made as of the date hereof and Gear undertakes no obligations to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

ADVISORY ON USE OF "BOEs": "BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

OIL AND GAS METRICS: This press release contains a number of oil and gas metrics, including F&D, FD&A, reserves life index, operating netback and recycle ratio, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. F&D and FD&A costs are used as a measure of capital efficiency. The calculation for F&D includes all exploration, development capital for that period plus the change in FDC for that period. This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions for that same period. The calculation for FD&A is calculated in the same manner except it also accounts for any acquisition costs incurred during the period. Reserves life index is calculated by dividing the reserves in each category by the corresponding Sproule forecast annual production. Operating netbacks are presented before taking into account the effects of hedging and are calculated based on the amount of revenues received on a per unit of production basis after royalties and operating costs. Recycle ratio is defined as operating netback per barrel of oil equivalent divided by either F&D or FD&A costs on a per barrel of oil equivalent.

NET ASSET VALUE: For the purposes of calculating the net asset value as presented herein, undeveloped land has been based on internal estimates of the value of the Company's undeveloped land. Net debt represents debt of the Company less working capital items, excluding risk management contracts. The number of shares outstanding does not include any shares issuable on any securities of the Company that are convertible, exchangeable or exercisable into shares of the Company.

DRILLING LOCATIONS: This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from Sproule reserves report as of December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Gear's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production, pricing assumptions and reserves information. There is no certainty that Gear will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which Gear actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of Gear's unbooked locations are extensions or infills of the drilling patterns already recognized by the independent evaluator, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

NON-GAAP MEASURES: This press release contains the terms net debt and operating netback, which do not have standardized meanings under Canadian generally accepted accounting principles ("GAAP") and therefore may not be comparable with the calculation of similar measures by other companies. Management believes that these key performance indicators and benchmarks are key measures of financial performance for Gear and provide investors with information that is commonly used by other oil and gas companies. Net debt is calculated as debt less current working capital items, excluding risk management contracts. Operating netback is calculated based on the amount of revenues received on a per unit of production basis after royalties and operating costs. Additional information relating to certain of these non-GAAP measures can be found in the MD&A.

SELECTED DEFINITIONS: The following terms used in this press release have the meanings set forth below:

"boe" means barrel of oil equivalent of natural gas and crude oil on the basis of 1 boe for six thousand cubic feet of natural gas (this conversion factor is and industry accepted norm and is not based on either energy content or current prices)
"Mbbl" means thousand barrels
"Mboe" means 1,000 barrels of oil equivalent
"MMcf" means one million cubic feet
"NGL" means natural gas liquids

SOURCE Gear Energy Ltd.

View original content: http://www.newswire.ca/en/releases/archive/February2019/27/c5709.html

Copyright CNW Group 2019

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