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Surge Energy Inc. Announces 2019 Fourth Quarter and Year-End Financial and Operating Results; 2019 Year-End Reserves; and Dividend Reduction


CALGARY – Surge Energy Inc. (“Surge” or the “Company”) (TSX: SGY) is pleased to announce its financial and operating results for the quarter and year ended December 31, 2019, and its year-end 2019 reserves, as evaluated by Sproule.

MESSAGE TO THE SHAREHOLDERS

Surge had a solid year in 2019. The Company’s 2019 production averaged 21,175 boepd (84% oil and NGLs), an increase of more than 17 percent as compared to 2018 average production volumes of 18,058 boepd (81% oil and NGLs).

During the year Surge was able to maintain production to within 1.5 percent of the Company’s 2019 budget production guidance, while drilling 12 (21 percent) fewer net wells, and spending $15 million less capital than originally budgeted. These results were achieved due to drilling and waterflood programs outperforming expectations, as well as improved capital efficiencies.

In 2019, Surge achieved an all-in payout ratio1 of 91 percent, with dividends paid representing only 18 percent of adjusted funds flow1. Through a combination of reduced capital spending and non-core asset sales, Surge was able to reduce net debt1 by $79 million in 2019.

Operationally, the Company’s high quality, large original oil in place2 (“OOIP”), conventional reservoirs continue to deliver consistent results. The Company delivered Finding, Development and Acquisition2 (“FD&A”) costs of $16.09 per boe on a Proved Developed Producing (“PDP”) basis in 2019, driving a 1.76 times recycle ratio2. On a three-year basis, the Company organically replaced 109 percent of production2 on a Total Proved plus Probable (“Total P+P”) basis, with a reserve life index2 of approximately 15 years.

Furthermore, Surge’s highly economic 2019 Sparky capital program (24.6 net wells) replaced more than 94 percent of the Company’s total 2019 production, adding Total P+P reserves of more than 7.3 MMboe.

Strategically, during 2019 Surge continued to grow its dominant position in the medium to light crude oil window of the large Sparky play trend, acquiring over 23 net sections of highly prospective land in the Company’s Sparky core area. All of these lands are defined by detailed geological and geophysical mapping, which is supported by both vertical well control and production. Portions of these lands will be drilled as part of Surge’s 2020 Sparky drilling program, which will further de-risk the Company’s future drilling inventory. 

Corporately, the Company’s core area land acquisitions organically added 133 net internally estimated drilling locations3,  replacing more than 2 years of annual drilling inventory for Surge, at a low total cost of $8.49 million.

In Surge’s Sparky core area, the Company has now amassed a conventional, low cost, low risk, medium/light oil play that has the following characteristics:

  • > 1.0 billion bbls of net internally estimated OOIP;
  • Delivered production growth of over 490 percent, from 1,500 boepd five years ago, to more than 8,900 boepd (>90% oil) today;
  • An extensive, low risk, 500 location, >10-year drilling inventory – with waterflood upside;
  • Per well economics that deliver quick payouts and excellent rates of return;
  • Top tier production efficiencies4 of $9,565 per boepd (i.e. 115 boepd 90 day initial production rate4 (“IP90”) for a total cost of $1.1 mm);
  • Proven waterflood results, and excellent long-term profit to investment ratios; and
  • The Company has “de-risked” its Sparky core area geologically, operationally, and financially, drilling 138 horizontal wells with a success rate of 99 percent.

Based on the recent volatility stemming from the COVID-19 outbreak, Surge’s management and Board of Directors continue to closely monitor the impact on global crude oil prices. In response to this volatility, the Company has acted quickly to shift capital from Q1, 2020 into the second half of the year, providing Surge with greater operational and financial flexibility for the balance of 2020.

Furthermore, the drastic drop in world crude oil prices, from US$63.05 WTI per barrel on January 3, 2020, to a low of US $27.62 WTI per barrel on March 8, 2020, has caused Surge to re-evaluate the current level of its dividend. Surge’s management and Board assess market conditions on a weekly and monthly basis with respect to protecting the Company’s balance sheet, weighing the efficacy of capital expenditures, and assessing the appropriate level of the Company’s dividend.

In this regard, until such time as Surge’s management and Board see a sustainable recovery in world crude oil prices, Surge anticipates reducing the Company’s dividend from $0.10 per share per year to $0.01 per share per year, effective with the March 2020 dividend payable in April 2020.

FINANCIAL AND OPERATING HIGHLIGHTS
($000s except per share amounts)

Three Months Ended December 31,

Years Ended December 31, 

2019

20182

% Change

2019

2018

% Change

Financial highlights

Oil sales

86,905

51,424

69 %

376,238

285,378

32 %

NGL sales

2,076

2,477

(16)%

8,109

11,022

(26)%

Natural gas sales

2,808

4,226

(34)%

10,002

8,147

23 %

Total oil, natural gas, and NGL revenue

91,789

58,127

58 %

394,349

304,547

29 %

Cash flow from operating activities

34,474

26,770

29 %

149,417

121,907

23 %

Per share – basic ($)

0.11

0.09

22 %

0.47

0.50

(6)%

Adjusted funds flow1

38,881

6,249

522 %

172,988

113,651

52 %

Per share – basic ($)

0.12

0.02

500 %

0.55

0.46

20 %

Net loss3

(143,801)

(82,473)

74 %

(158,664)

(71,533)

122 %

Per share – basic ($)

(0.44)

(0.29)

52 %

(0.50)

(0.29)

72 %

Total exploration and development expenditures

30,760

33,598

(8)%

119,465

120,552

(1)%

Total acquisition and dispositions

2,458

299,032

(99)%

(42,438)

327,765

(113)%

Total capital expenditures

33,218

332,630

(90)%

77,027

448,317

(83)%

Net debt1, end of period

382,309

461,187

(17)%

382,309

461,187

(17)%

Operating highlights

Production:

Oil (bbls per day)

16,441

16,578

(1)%

17,127

13,992

22 %

NGLs (bbls per day)

630

703

(10)%

692

623

11 %

Natural gas (mcf per day)

19,521

22,598

(14)%

20,135

20,658

(3)%

Total (boe per day) (6:1)

20,325

21,047

(3)%

21,175

18,058

17 %

Average realized price (excluding hedges):

Oil ($ per bbl)

57.46

33.72

70 %

60.19

55.88

8 %

NGL ($ per bbl)

35.84

38.28

(6)%

32.09

48.51

(34)%

Natural gas ($ per mcf)

1.56

2.03

(23)%

1.36

1.08

26 %

Netback ($ per boe)

Petroleum and natural gas revenue

49.09

30.02

64 %

51.02

46.21

10 %

Realized gain (loss) on financial contracts

0.13

(1.25)

(110)%

(0.61)

(1.67)

(63)%

Royalties

(7.00)

(3.86)

81 %

(6.71)

(6.55)

2 %

Net operating expenses1

(14.91)

(15.70)

(5)%

(14.50)

(14.76)

(2)%

Transportation expenses

(1.40)

(1.53)

(8)%

(1.54)

(1.50)

3 %

Operating netback1

25.91

7.68

237 %

27.66

21.73

27 %

G&A expense

(1.95)

(1.83)

7 %

(1.85)

(2.01)

(8)%

Interest expense

(3.16)

(2.60)

22 %

(3.45)

(2.47)

40 %

Adjusted funds flow1

20.80

3.25

540 %

22.36

17.25

30 %

Common shares outstanding, end of period

326,330

309,286

6 %

326,330

309,286

6 %

Weighted average basic shares outstanding

324,836

288,744

12 %

316,639

246,252

29 %

Stock option dilution

—%

—%

Weighted average diluted shares outstanding

324,836

288,744

12 %

316,639

246,252

29 %

 

1. This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.

2. IFRS 16 was adopted January 1, 2019 using the modified retrospective approach and as such, comparative information for 2018 that may have been impacted has not been restated. Refer to the Changes in Accounting Policies section of the financial statements and MD&A for additional information.

3. For the year ended December 31, 2019, the Company incurred a net loss of $158.7 million, including a non-cash asset impairment charge of $180.7 million recognized in the fourth quarter of 2019 primarily due to a decrease in the independent engineering price forecast. The impairment charge does not impact the Company’s adjusted funds flow, and is reversible in future periods should there be any indicators that the value of the assets has increased.

In accordance with industry practice, the Company uses adjusted funds flow to analyze the cash flow generated from its ongoing principal business activities. On this basis, both adjusted funds flow and cash flow from operating activities are provided for comparative purposes.  Please see the Non-GAAP Financial Measures section of this release for further details.

2019 YEAR-END FINANCIAL AND RESERVES HIGHLIGHTS

  • Average daily production increased by 17 percent in 2019 to 21,175 boepd, from 18,058 boepd in 2018;
  • Achieved an all-in payout ratio of 91 percent for 2019;
  • Increased liquids weighting by 3 percent in 2019 to 84 percent, as compared to 81 percent in 2018;
  • Reduced net debt by $79 million from December 31, 2018 to December 31, 2019;
  • Operating netbacks increased by more than 27 percent, to $27.66/boe for the year ended December 31, 2019, compared to $21.73/boe in the prior year;
  • Increased Total Proved (“TP”) reserves per debt adjusted share5 by 4 percent in 2019;
  • Delivered PDP FD&A costs of $16.09/boe in 2019, including changes in future development capital, with a recycle ratio of 1.76 times;
  • Maintained a Total P+P reserve life index of approximately 15 years;
  • Organically added 21.6 MMboe of Total P+P reserves over the past three years, replacing 109 percent of production;
  • Increased Total P+P reserves in the Sparky core area by 7.3 MMboe, replacing over 94 percent of Surge’s total 2019 corporate production;
  • Surge’s 428 net (458 gross) booked locations of undeveloped reserves in the Company’s new Sproule December 31, 2019 engineering report, have a Finding & Development5 (“F&D”) cost of $13.03/boe6 on a Proved plus Probable Undeveloped (“P+PUD”) reserves basis;
  • The Company’s 2019 drilling program (35.6 net wells) added PDP reserves at an F&D cost of $12.90/boe7;
  • Oil and natural gas liquids make up more than 86 percent of Total P+P reserves;
  • Estimated Total P+P Net Asset Value5 of $4.27 per basic share; and
  • Estimated Total Proved Net Asset Value of $2.37 per basic share.

 

2019 OPERATIONAL HIGHLIGHTS

Surge’s disciplined operating strategy of focusing on high quality conventional, large OOIP, light and medium gravity crude oil assets continued to provide strong operational results in 2019.

In total, the Company spent $119.5 million of exploration and development capital in 2019 ($15 million less than budgeted), drilling 36 gross (35.6 net) wells, along with waterflood injector conversions, associated infrastructure, land, seismic and corporate overheads.

Through step-out delineation drilling and strategic land acquisitions, the Company was able to increase Surge’s drilling inventory to more than 850 gross (800 net) net internally estimated locations, replacing more than two years of corporate drilling inventory during the year.

Sparky Core Area

In the Sparky core area, Surge drilled 25 gross (24.6 net) wells in four separate pools during the year.

In addition to continued successful drilling at Eyehill and Provost, the Company also drilled seven successful wells at Betty Lake, further de-risking this large OOIP, Sparky discovery. Peak production from the Betty Lake asset was over 850 boepd (>90 percent oil), and six additional successful wells have now been drilled into the pool in Q1, 2020. With over 120 net internally estimated locations remaining at Betty Lake and Betty Lake North, this large OOIP Sparky asset is very well-positioned for long term, sustainable growth, as well as waterflood upside.

At Surge’s large OOIP Sounding Lake pool, the Company drilled its first Sparky horizontal infill well in Q4, 2018, which was subsequently followed up with two additional successful wells drilled in Q1 of 2019. Four additional wells have now been successfully drilled at Sounding Lake off a single pad in the Q1, 2020 drilling program.

With drill, complete and equipment costs of under $1.2 million, year-round access, well-developed infrastructure, proven waterflood performance, and over 500 net internally identified locations, the Sparky core area is a cornerstone growth asset in Surge’s business model.

Valhalla Core Area

At Valhalla, Surge successfully drilled and completed 5 gross (5 net) wells in 2019. Four of these wells were drilled into the Doig formation, and each well had an average 30 day initial production oil rate (IP30) of over 800 bopd.

Excitingly, during Q4, 2019 the Company drilled and brought on production its first horizontal well into Surge’s large 40 MMbbl net OOIP, conventional Montney light oil pool, with a IP30 oil rate of over 1,000 bopd. This prolific well continues to produce at over 700 bopd of high netback light oil today. The Company has now identified a number of follow-up Montney locations.

Throughout 2019 Surge continued to expand its drilling inventory in this stacked, light oil, multi-zone area. The Company has 78 net internally estimated locations in the Doig, Montney, and Charlie Lake formations.

Greater Sawn Core Area

Surge’s core operating area at Greater Sawn provides a low decline light oil production base, underpinned by large OOIP, with conventional carbonate reef reservoirs that have proven waterflood upside. These high quality, light oil assets continue to provide a stable production and cash flow base, complementing Surge’s low decline, growth and dividend paying business model.

During 2019, the Company brought on production 4 gross (4 net) wells at Sawn. Combined to date, these wells have produced over 175,000 barrels of high netback light oil, and continue to produce at a combined rate of over 465 bopd.

Waterflood has proven to be very successful in the Sawn pool with five gross horizontal wells having now been converted to water injection. On this basis, Surge undertook a comprehensive reservoir simulation study in 2019, in order to optimize future infill drilling and waterflood development.

Shaunavon Core Area

Surge successfully drilled 4 gross (4 net) wells at its Shaunavon core area in the past year, targeting both the Upper and Lower Shaunavon formations. Strategically positioned in Southwest SaskatchewanShaunavon receives Fosteron grade crude oil pricing, which has historically traded at a premium to WCS. Accordingly, Shaunavon has one of the highest operating netbacks in the Company and generates cash flow in excess of the properties exploration and development capital expenditures, providing cash flow that can be deployed across Surge’s asset base. 

2019 YEAR-END RESERVES

The Company’s reserves were evaluated by Sproule in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) effective December 31, 2019. Surge’s annual information form (the “AIF”) for the year ended December 31, 2019 contains Surge’s reserves data and other oil and natural gas information as mandated by NI 51-101.

The following tables summarize Surge’s working interest oil, natural gas liquids and natural gas reserves and the net present values (“NPV”) of future net revenue for these reserves (before taxes) using forecast prices and costs as evaluated in the Sproule Report.  The evaluation is based on Sproule’s forecast pricing and exchange rates at December 31, 2019 which is available on their website www.sproule.com. All references to reserves in this release are to gross Company reserves, meaning Surge’s working interest reserves before deductions of royalties and before consideration of the Company’s royalty interests. The amounts in the tables may not add due to rounding.

RESERVES SUMMARY AND NET PRESENT VALUE

Gross Reserves(a)

Crude Oil
and NGLs

(Mbbl)(b)

Natural
Gas

(MMcf)(c)

Oil
Equivalent
Total
Reserves

(Mboe)

Before Tax NPV of Future Net
Revenue
(d) Discounted at

5%

($MM)

10%

($MM)

15%

($MM)

Proved:

Proved Producing

34,505

31,104

39,689

663

603

537

Proved Non-Producing

253

217

289

5

4

3

Proved Undeveloped

31,589

35,146

37,446

577

416

307

Total Proved

66,346

66,467

77,424

1,245

1,023

848

Probable

34,082

32,006

39,417

875

621

467

Total Proved Plus Probable

100,428

98,474

116,841

2,120

1,644

1,315

a)

Amounts may not add due to rounding.

b)

Includes light, medium, heavy and tight oil and natural gas liquids.

c)

Includes conventional natural gas, solution gas and coal bed methane.

d)

Total ADR (Abandonment, Decommissioning, Reclamation) is included in the reserves report, as it is best practice stated in the COGE Handbook.

FUTURE DEVELOPMENT CAPITAL (“FDC”)

Total Proved Developed
Producing

Total Proved

Total Proved
Plus Probable

($MM)

($MM)

($MM)

2020

9

114

123

2021

7

149

180

2022

6

164

209

2023

5

116

168

2024

3

88

126

Remaining

20

58

91

Total (Undiscounted)

50

690

897

Total (Discounted at 10%)

34

537

682

RESERVE PERFORMANCE METRICS(a)

2019

Three Year Average

PDP

TP

TPP

PDP

TP

TPP

F&D ($/boe)

$21.88

$24.65

$29.61

$20.42

$20.65

$21.95

F&D Recycle Ratio

1.29

1.15

0.95

1.24

1.23

1.15

FD&A ($/boe)

$16.09

$23.75

$55.35 (b)

$24.30

$23.82

$21.92

FD&A Recycle Ratio

1.76

1.19

0.51 (b)

1.04

1.06

1.16

Production Replacement (%)

71%

89%

78%

82%

115%

109%

RLI (Years)

5.3

10.4

15.7

5.6

10.2

14.7

a)

See the Oil and Gas Advisories section of this document for further details.

b)

The Company views this calculation as “not meaningful” due to the reserves associated with the Doe Creek disposition in 2019 primarily offsetting organic reserve adds. 

NET ASSET VALUE

TP

TPP

Reserve Value NPV10 BT ($MM)

$1,023

$1,644

Undeveloped Land and Seismic ($MM) (a)

$131

$131

Net Debt ($MM)

$(382)

$(382)

Total Net Assets ($MM)

$772

$1,393

Basic Shares Outstanding (MM)

326.3

326.3

Estimated NAV per Basic Share ($/share)

$2.37/share

$4.27/share

a)

Internally estimated as $95 MM for non-reserve assigned land and $36 MM for seismic data.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

In 2019, the Company elected to participate in the Alberta Energy Regulators (“AER”) Area Based Closure program (“ABC program”). During this timeframe, the Company achieved abandonment costs that are approximately 50 percent of AER estimates, confirming Surge’s belief in the economies of scale that are found within the ABC program. Given the success under the ABC program in 2019, Surge has initiated ABC programs in a number of the Company’s non-core areas for 2020.

Surge spent $5.5 million in 2019 in executing the Company’s proactive annual abandonment and reclamation program. This builds on the $17.5 million the Company has spent since 2014.

In 2019, due to capital efficiencies afforded under the ABC program, the Company abandoned 149 wells, which is more than four times the number of wells the Company drilled in 2019. In addition to Surge’s extensive annual abandonment and reclamation program set forth above, the Company also pays annually into the industry wide Alberta Orphan Well Fund.

Surge is a supporter of community engagement and recognizes the importance of supporting charitable organizations in the communities in which the Company operates. Details on the Company’s recent community engagement initiatives can be found on Surge’s website at www.surgeenergy.ca.

OUTLOOK

Surge’s high quality, light and medium gravity crude oil asset and opportunity base continues to outperform management’s expectations. The Company’s conventional low decline, high netback, large OOIP reservoirs deliver solid, stable cash flow, together with excellent production efficiencies.

Based on the recent volatility stemming from the COVID-19 outbreak, Surge’s management and Board of Directors continue to closely monitor the impact on global crude oil prices. In response to this volatility, the Company has acted quickly to shift capital from Q1, 2020 into the second half of the year, providing Surge with greater operational and financial flexibility for the balance of 2020.

Furthermore, the drastic drop in world crude oil prices, from US$63.05 WTI per barrel on January 3, 2020, to a low of US $27.62 WTI per barrel on March 8, 2020, has caused Surge to re-evaluate the current level of its dividend. Surge’s management and Board assess market conditions on a weekly and monthly basis with respect to protecting the Company’s balance sheet, weighing the efficacy of capital expenditures, and assessing the appropriate level of the Company’s dividend.

In this regard, until such time as Surge’s management and Board see a sustainable recovery in world crude oil prices, Surge anticipates reducing the Company’s dividend from $0.10 per share per year to $0.01 per share per year, effective with the March 2020 dividend payable in April 2020.

FORWARD LOOKING STATEMENTS:

This press release contains forward-looking statements. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

More particularly, this press release contains statements concerning: Management’s expectations and plans with respect to the development of its assets and the timing thereof; Surge’s declared focus and primary goals; Surge’s assets and the characteristics thereof; Surge’s annual exploration and development capital expenditure program and budget and its flexibility to make adjustments thereto; Surge’s drilling program and inventory, and the risk associated therewith; commodity prices and management’s ability to react to changes thereto; Surge’s hedging program; the continued use by Surge of ABC programs in 2020; maintenance of Surge’s decline rate; production curtailments; export pipelines; availability of undrawn capacity with respect to Surge’s credit facility; and Surge’s dividend policy.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions the performance of existing wells and success obtained in drilling new wells; anticipated expenses, cash flow and capital expenditures; the application of regulatory and royalty regimes; prevailing commodity prices and economic conditions; development and completion activities; the performance of new wells; the successful implementation of waterflood programs; the availability of and performance of facilities and pipelines; the geological characteristics of Surge’s properties; the successful application of drilling, completion and seismic technology; the determination of decommissioning liabilities; prevailing weather conditions; exchange rates; licensing requirements; the impact of completed facilities on operating costs; the availability and costs of capital, labour and services; and the creditworthiness of industry partners.

Although Surge believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Surge 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. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the condition of the global economy, including trade, public health (including the impact of COVID-19) and other geopolitical risks; risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks); commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; and failure to obtain the continued support of the lenders under Surge’s bank line. Certain of these risks are set out in more detail in Surge’s MD&A dated March 9, 2020 which has been filed on SEDAR and in Surge’s AIF for the period ended December 31, 2019, which will be filed on SEDAR before March 31, 2020. Both of which can be accessed at www.sedar.com.

The forward-looking statements contained in this press release are made as of the date hereof and Surge undertakes no obligation 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.

Oil and Gas Advisories

The term “boe” means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. “Boe/d” and “boepd” mean barrel of oil equivalent per day. Bbl means barrel of oil and “bopd” means barrels of oil per day.  NGLs means natural gas liquids.

This press release contains certain oil and gas metrics and defined terms which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar metrics/terms presented by other issuers and may differ by definition and application. All oil and gas metrics/terms used in this document are defined below:

Original Oil in Place (“OOIP”) means Discovered Petroleum Initially In Place (“DPIIP”). DPIIP is derived by Surge’s internal Qualified Reserve Evaluators (“QRE”) and prepared in accordance with National Instrument 51-101 and the Canadian Oil and Gas Evaluations Handbook (“COGEH”). DPIIP, as defined in COGEH, is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and Resources Other Than Reserves (ROTR). OOIP/DPIIP and potential recovery rate estimates are based on current recovery technologies. There is significant uncertainty as to the ultimate recoverability and commercial viability of any of the resource associated with OOIP/DPIIP, and as such a recovery project cannot be defined for a volume of OOIP/DPIIP at this time. “Internally estimated” means an estimate that is derived by Surge’s internal QRE’s and prepared in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. All internal estimates contained in this new release have been prepared effective as of Jan 1, 2020.

Recycle ratio equals the profit per barrel divided by the total cost of discovering and extracting that barrel (i.e. the 2019 operating netback excluding realized gain (loss) on financial contracts divided by F&D or FD&A.

Initial production rate (“IP”) is the average production rate over a given period of time given in days (i.e.: IP90 is equal to the average rate of production from a well over a 90 day period).

Production efficiency is calculated as total exploration and development expenditures during the period, divided by an initial production rate for a specified number of days (i.e., $1.1 million / 115 boepd on a 90 day basis). IP90 of 115 boepd is supported by Surge’s internally estimated average Sparky type curve.

Reserve life index is calculated as total Company share reserves divided by the annualized fourth quarter production.

FD&A is calculated on the total exploration and development capital, acquisition and divestiture capital (proceeds) and change in FDCs divided by the reserves category in which FD&A is being calculated.

F&D is calculated on the capital and divided by the reserves category in which F&D is being calculated.

Replacement of production/Production replacement is calculated as the total organic reserve additions (i.e. excluding acquisitions and dispositions) divided by annual production for the year in which its being calculated.

Net Asset Value is the total discounted (10%) value of reserves plus undeveloped land and seismic value, minus debt, divided by the number of shares.

Drilling Inventory

This press release discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations derived from an internal evaluation using standard practices as prescribed in the Canadian Oil and Gas Evaluations Handbook and account for drilling locations that have associated proved and/or probable reserves, as applicable.

Unbooked locations are internal estimates based on prospective acreage and assumptions as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by Surge’s internal certified Engineers and Geologists (who are also Qualified Reserve Evaluators) as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company 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 the Company actually drills 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 certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of 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.

Assuming a Jan 1, 2020 reference date, the Company will have over >850 gross (>800 net) drilling locations identified herein, of these >400 gross (>380 net) are unbooked locations.  Of the 428 net booked locations identified herein 331 net are Proved locations and 97 net are Probable locations based on Sproule’s 2019YE reserves.  Assuming an average number of wells drilled per year of 65, Surge’s >850 locations provides 13 years of drilling.

The Company’s Sparky core area has 184 net booked locations, of which 137 net are Proved locations and 47 net are Probable locations based on 2019YE reserves.   The Company’s Betty Lake asset has 35 net booked locations, of which 25 net are Proved locations and 10 net are Probable locations based on 2019YE reserves.  The Company’s Valhalla asset has 44 net booked locations, of which 36 net are Proved locations and 8 net are Probable locations based on 2019YE reserves.

Surge’s internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2020.  All locations were risked appropriately, and EUR’s were measured against OOIP estimates to ensure a reasonable recovery factor was being achieved based on the respective spacing assumption. Other assumptions, such as capital, operating expenses, wellhead offsets, land encumbrances, working interests and NGL yields were all reviewed, updated and accounted for on a well by well basis by Surge’s Qualifies Reserve Evaluators.  All type curves fully comply with Part 5.8 of the Companion Policy 51 – 101CP.

Non-GAAP Financial Measures

Certain secondary financial measures in this press release – namely, “all-in payout ratio”,”adjusted funds flow”, “adjusted funds flow per share”, “net debt”, “net operating expenses”, “operating netback”, and “adjusted funds flow per boe” are not prescribed by GAAP. These non-GAAP financial measures are included because management uses the information to analyze business performance, cash flow generated from the business, leverage and liquidity, resulting from the Company’s principal business activities and it may be useful to investors on the same basis. None of these measures are used to enhance the Company’s reported financial performance or position. The non-GAAP measures do not have a standardized meaning prescribed by IFRS and therefore are unlikely to be comparable to similar measures presented by other issuers. They are common in the reports of other companies but may differ by definition and application. All non-GAAP financial measures used in this document are defined below:

All-in Payout Ratio

All-in payout ratio is calculated using the sum of total exploration and development capital, plus dividends paid, divided by cash flow from operating activities less payments on lease obligations. This non-GAAP measure is used by management to analyze allocated capital in comparison to the cash being generated by the principal business activities. This measure is provided to allow readers to quantify the amount of cash flow from operations that is being used to either: i) pay dividends; or ii) deployed into the Company’s development and exploration program. A ratio of less than 100% indicates that a portion of the cash flow from operations is being retained by the Company and can be used to fund items such as asset abandonment, repayment of debt, fund acquisitions or the costs related thereto or other items.

Adjusted Funds Flow & Adjusted Funds Flow per Share

The Company adjusts cash flow from operating activities in calculating adjusted funds flow for changes in non-cash working capital, decommissioning expenditures, transaction and other costs, and cash settled stock-based compensation plans, particularly cash used to settle withholding obligations on stock-based compensation arrangements that are settled in shares. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating Surge’s cash flows.

Changes in non-cash working capital are a result of the timing of cash flows related to accounts receivable and accounts payable, which management believes reduces comparability between periods. Management views decommissioning expenditures predominately as a discretionary allocation of capital, with flexibility to determine the size and timing of decommissioning programs to achieve greater capital efficiencies and as such, costs may vary between periods. Transaction and other costs represent expenditures associated with acquisitions, which management believes do not reflect the ongoing cash flows of the business, and as such reduces comparability. Subsequent to the third quarter of 2018, all of the Company’s stock-based compensation plans are equity classified as the Company has the intention of settling all awards with shares. Cash settled stock-based compensation currently represents the statutory tax withholdings required on stock-based compensation awards and is a discretionary allocation of capital. The Company has the option to either require the holder to sell shares earned in the stock-based compensation plan to satisfy tax withholdings, or the Company can issue less shares to the individual and remit a cash payment to satisfy tax withholding requirements. Each of these expenditures, due to their nature, are not considered principal business activities and vary between periods, which management believes reduces comparability.

Adjusted funds flow per share is calculated using the same weighted average basic and diluted shares used in calculating income per share.

The following table reconciles cash flow from operating activities to adjusted funds flow and adjusted funds flow per share for the three months and year ended December 31, 2019:

Three Months Ended

Years Ended

($000s except per share)

Dec 31, 2019

Dec 31, 2018

Dec 31, 2019

Dec 31, 2018

Cash flow from operating activities

$

34,474

$

26,770

$

149,417

$

121,907

Change in non-cash working capital

2,876

(25,464)

16,569

(24,338)

Decommissioning expenditures

1,425

1,439

5,522

6,348

Cash settled transaction and other costs

106

3,504

1,480

5,288

Cash settled stock-based compensation

4,447

Adjusted funds flow

$

38,881

$

6,249

$

172,988

$

113,651

Per share – basic

$

0.12

$

0.02

$

0.55

$

0.46

Net Debt

There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt plus the liability component of the convertible debentures plus or minus working capital, however, excluding the fair value of financial contracts and other long term liabilities. This metric is used by management to analyze the level of debt in the Company including the impact of working capital, which varies with timing of settlement of these balances.

($000s)

As at Dec 31, 2019

As at Dec 31, 2018

Bank debt

$(316,404)

$(408,593)

Accounts receivable

41,486

21,084

Prepaid expenses and deposits

4,875

9,222

Accounts payable and accrued liabilities

(40,848)

(42,350)

Convertible debentures

(68,699)

(37,973)

Dividends payable

(2,719)

(2,577)

Total

$(382,309)

$(461,187)

Net Operating Expenses

Net operating expenses are determined by deducting processing and other revenue primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest. It is common in the industry to earn third party processing revenue on facilities where the entity has a working interest in the infrastructure asset. Under IFRS this source of funds is required to be reported as revenue. However, the Company’s principal business is not that of a midstream entity whose activities are dedicated to earning processing and other infrastructure payments. Where the Company has excess capacity at one of its facilities, it will look to process third party volumes as a means to reduce the cost of operating/owning the facility. As such, third party processing revenue is netted against operating costs in the MD&A.

Operating Netback & Adjusted Funds Flow Netback

Operating netback, operating netback excluding realized gain (loss) on financial contracts & adjusted funds flow per boe for the three and twelve months ended December 31, 2019 are calculated on a per unit basis as follows:

Three Months Ended

Years Ended 

($000s except per share)

Dec 31, 2019

Dec 31, 2018

Dec 31, 2019

Dec 31, 2018

Petroleum and natural gas revenue*

$

91,790

$

58,127

$

394,349

$

304,547

Processing and other income*

1,563

576

4,303

2,818

Royalties*

(13,096)

(7,478)

(51,837)

(43,203)

Operating expenses*

(29,448)

(30,985)

(116,338)

(100,108)

Transportation expenses*

(2,624)

(2,971)

(11,866)

(9,878)

Realized gain (loss) on financial contracts*

248

(2,430)

(4,679)

(11,007)

Operating netback

$

48,433

$

14,839

$

213,932

$

143,169

G&A expense*

(3,640)

(3,551)

(14,287)

(13,228)

Interest expense*

(5,911)

(5,039)

(26,657)

(16,289)

Adjusted funds flow

$

38,881

$

6,249

$

172,988

$

113,651

Barrels of oil equivalent (boe)

1,869,819

1,936,352

7,728,923

6,591,007

Operating netback ($ per boe)

$

25.91

$

7.68

$

27.66

$

21.73

Adjusted funds flow ($ per boe)

$

20.80

$

3.25

$

22.36

$

17.25

* Taken directly from the financial statements.

Additional information relating to non-GAAP measures can be found in the Company’s most recent management’s discussion and analysis MD&A, which may be accessed through the SEDAR website (www.sedar.com).

Neither the TSX nor its Regulation Services Provider (as that term is defined in the policies of the TSX) accepts responsibility for the adequacy or accuracy of this release.

_____________________________

1 

This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.

2 

See the Oil and Gas Advisories section of this document for further details.

3

See the Drilling Inventory section of this document for further details regarding all references to drilling locations.

4

See the Oil and Gas Advisories section of this document for further details.

See the Oil and Gas Advisories section of this document for further details.

6 

Calculated as $763 million in P+P FDC (Drill Complete Equipment and Tie in Only) divided by 59 million boe of P+P undeveloped reserves

7 

Calculated as the Total DCET Capital in 2019 ($66.5 million), divided by the sum of PDP reserves and total production from these wells in 2019 (5,186 mboe).



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