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Cequence Energy Announces 2018 Financial and Operating Results and Provides Operational Update


CALGARY, Alberta, March 12, 2019 (GLOBE NEWSWIRE) — Cequence Energy Ltd. (“Cequence” or the “Company”) (TSX: CQE) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2018, as well as its year-end reserve evaluation as prepared by its qualified independent reserve evaluator. The Company’s Consolidated Financial Statements and Management’s Discussion and Analysis are available at www.cequence-energy.com and on SEDAR at www.sedar.com.

2018 Highlights

  • Achieved full year 2018 production of 6,507 boe/d and increased liquids weighting to 23% up from 17% in 2017;
  • Funds flow from operations in 2018 was $13.1 million or $0.53 per share based on year end 2018 outstanding shares;
  • Fourth quarter 2018 oil production increased by 160% over the same period in 2017;
  • Strengthened the Company’s balance sheet through a $8.6 million rights offering and renegotiation of the $60 million term debt with a 4 year maturity and 5% interest rate;
  • Continued successful step out drilling of the Company’s Dunvegan oil pool.  Drilled, completed, and tied in 5 gross (4 net) horizontal Dunvegan oil wells and 1 gross (1 net) successful stratigraphic oil well test;
  • Corporate 10% proved developed producing reserve value of $74 million includes a $20.6 million unutilized take or pay short fall under this scenario.  Additional Cequence production volumes from the total proved and proved plus probable cases would alleviate this shortfall;
  • The Corporate net asset value per share at a 10% discount rate using GLJ January 1, 2019 prices and year end 2018 net debt is $4.31/share total proved and $15.19/share proved plus probable;
  • Achieved a Corporate proved plus probable FD&A of $3.50/boe;
  • Before production, Dunvegan oil proved developed producing, total proved, and proved plus probable reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe, 2.9 MMboe and 5.3 MMboe;
  • Dunvegan oil total proven and proven plus probable net present values at 10% discount rate are $41.8 million and $74.7 million respectively using GLJ January 1, 2019 prices; and
  • Added market diversity away from AECO prices with 10,850 GJ/d of production sold at Dawn beginning April 1, 2018. Realized gas price in 2018 was $2.40/mcf, an increase of 58% over the AECO 2018 spot price of $1.52/mcf.

Comparative financial and operating information for 2018 and 2017 are as follows:

(000’s except per share and per unit amounts) Three months ended
December 31,
Twelve months ended
December 31,
  2018 2017 % Change 2018 2017 % Change
FINANCIAL
Total revenue(1), (5) 12,184 13,585 (10 ) 58,921 65,836 (11 )
Comprehensive loss (3,802 ) (6,638 ) (43 ) (9,699 ) (99,362 ) (90 )
Per share – basic and diluted (6) (0.16 ) (0.54 ) (70 ) (0.61 ) (8.09 ) (92 )
Funds flow from operations (2), (5) 2,071 1,583 31 13,087 19,329 (32 )
Per share, basic and diluted (6), (7) 0.08 0.13 (38 ) 0.82 1.57 (48 )
Capital expenditures, before acquisitions (dispositions) 13,397 5,593 140 23,800 25,857 (8 )
Capital expenditures, including acquisitions (dispositions) 12,463 1,316 847 20,937 21,580 (3 )
Net debt (3), (5) (72,103 ) (68,501 ) 5 (72,103 ) (68,501 ) 5
Weighted average shares outstanding – basic (6) 24,553 12,277 100 15,942 12,277 30
Weighted average shares outstanding – diluted (6) 24,553 12,277 100 15,942 12,277 30
Common shares outstanding – end of period 24,553 12,277 100 24,553 12,277 100
OPERATING        
Production volumes        
Natural gas (Mcf/d) 27,645 33,331 (17 ) 30,098 40,466 (26 )
Crude oil (bbls/d) 736 283 160 763 344 122
Natural gas liquids (bbls/d) 227 257 (12 ) 250 254 (2 )
Condensate (bbls/d) 427 617 (31 ) 478 797 (40 )
Total (boe/d) 5,997 6,713 (11 ) 6,507 8,139 (20 )
Sales prices        
Natural gas, including realized hedges ($/Mcf) 2.91 2.33 25 2.49 2.53 (2 )
Crude oil and condensate, including realized hedges ($/bbl) 37.74 66.73 (43 ) 61.89 61.44 1
Natural gas liquids ($/bbl) 35.37 38.55 (8 ) 38.18 30.72 24
Total ($/boe) 22.08 22.00 1 24.81 22.16 12
Netback ($/boe)        
Price, including realized hedges 22.08 22.00 1 24.81 22.16 12
Royalties (1.33 ) (0.63 ) 111 (1.67 ) (1.06 ) 58
Transportation (3.84 ) (1.66 ) 131 (3.01 ) (1.88 ) 60
Operating costs (9.86 ) (12.91 ) (24 ) (10.14 ) (9.29 ) 9
Operating netback (5) 7.05 6.80 4 9.99 9.93 1
General and administrative (2.07 ) (1.88 ) 10 (2.22 ) (1.48 ) 50
Interest (4) (1.42 ) (2.46 ) (42 ) (1.98 ) (2.07 ) (4 )
Cash netback (5) 3.56 2.46 45 5.79 6.38 (9 )
  1. Total revenue is presented gross of royalties and includes realized gains (loss) on commodity contracts.
  2. Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital.
  3. Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the principal value of the Senior Notes and Term Loan (as such terms are defined below).
  4. Represents finance costs less refinancing expenses, amortization on transaction costs, accretion expense on Senior Notes and provisions.
  5. Refer to “Non-GAAP Measures” advisory in this press release.
  6. On October 22, 2018, the Company’s shareholders approved a share consolidation based on one new common share for every 20 pre-consolidation shares. All information relating to issued and common shares, stock options, warrants, restricted share units and per share amounts, have been restated to reflect the share consolidation for all periods presented.
  7. Funds flow per share calculated as if the ending 24,553,000 common shares at December 31, 2018 were outstanding for the entire period would be $0.53 per share for the twelve months ended December 31, 2018.

Financial

Natural gas prices remained low in both 2018 and 2017 with AECO prices averaging $1.52/mcf and $2.23/mcf, respectively. Annual funds flow from operations decreased 32% to $13.1 million mainly due to lower natural gas prices and volumes. The decrease was partially offset by increased crude oil, condensate and NGL prices and oil volumes year over year. Fourth quarter funds flow increased 31% to $2.1 million, mainly due to increased production revenue, lower operating expenses and lower interest expense on the Term Loan. For the twelve months ended December 31, 2018, the Company recorded a comprehensive loss of $9.7 million compared to $99.3 million in 2017. The decrease is due to impairments of $96.2 million in the second quarter of 2017 as a result of a lower outlook for crude oil and natural gas prices.

Capital expenditures for the year were $23.8 million ($20.9 net of dispositions) with $19.9 million focused on wells with higher oil and liquids content. The majority of capital was spent as follows: $16.3 million on drilling and completion activity, $4.8 million on facilities and equipment, and $1.0 million on workovers.

On July 27, 2018 Cequence announced a series of transactions to refinance the Company’s balance sheet and provide greater flexibility and liquidity to execute the ongoing business plan of the Company. Cequence entered into a second lien secured loan agreement for a $60 million term loan facility due October 3, 2022 (the “Term Loan”) to refinance the existing $60 million unsecured five year senior notes which were due on October 3, 2018 (the “Senior Notes”). At the same time, Cequence launched a rights offering for holders of its common shares as of August 9, 2018 to subscribe for 12,276,394 (post-consolidation) flow through common shares of the Company for gross proceeds of up to $8.6 million. The rights offering was fully subscribed for and closed on September 13, 2018.

The Company has $72.1 million in net debt as at December 31, 2018, which is comprised of the Term Loan ($60 million) and a working capital deficiency of $12.1 million (excluding commodity contracts). The Company also has a senior credit facility of $7 million that remains undrawn other than letters of credit of $1.6 million and has a maturity date May 31, 2019.

The Company has hedged approximately 26% of its 2019 estimated production, including 40% of its forecasted oil volumes, at a price of $85.29/bbl CAD. Since April 1, 2018 the Company has been selling 10,850 GJ/d of gas production in the Dawn market. The Dawn marketing arrangement has provided the Company diversification away from the volatile AECO prices for approximately 1/3 of its gas production. For the year ended December 31, 2018, Dawn prices averaged approximately $4.15/mcf compared to AECO pricing of approximately $1.52/mcf.

2018 Operational and Production

During the winter of 2017/2018 and the fourth quarter of 2018, Cequence drilled, completed, and brought on stream 5 gross (4 net) horizontal Dunvegan oil wells as well as drilled 1 gross (1 net) vertical stratigraphic oil test well. The horizontal wells drilled in the fourth quarter of 2018 were tied into permanent facilities on January 10, 2019. In February 2019, the pumps were removed from the two wells and they are both flowing. The recent production from the fourth quarter 2018 wells are shown in the table below.

    January 2019 calendar day average (gross) Last 10/24 Operating days February (gross)
Well UWI CQE % Oil (bbl/d) Gas (mcf/d) Oil (bbl/d) Gas (mcf/d)
10-04-062-26W5 100 % 266 650 310 1,300
16-02-062-26W5 100 % 225 370 260 1,000

In 2018, approximately $19.9 million dollars or 84% of the Corporation’s $23.8 million capital expenditures, before acquisitions, was spent on the Dunvegan oil program. This Dunvegan capital included $6.4 million for drilling, $9.5 million on completions, and $4.0 million on facilities and equipment including the installation of an 8 inch gathering line to the new 2018 multi-well pad site as well as an upgrade to the 5-7-62-25W5 oil handling facility to eliminate long term rental equipment. A majority of the remaining 2018 capital spend was focused on expanding and optimizing water disposal capacity in the Simonette area.

For the year ended December 31, 2018, operating costs averaged $10.14/boe in 2018, up 9% from 2017, with operating costs down 24% in the fourth quarter to $9.86/boe as compared to the same period of 2017. In the second half of 2017 and extending into the first quarter of 2018, the Company had one-time expenses associated with accelerating a water handling and disposal project to reduce its surface water and associated costs at the Simonette field. In the fourth quarter of 2018, a second water disposal well and associated equipment was added in the east side of Simonette which has further reduced water trucking and disposal costs. Despite lower forecasted 2019 total production rates the 2019 operating costs are expected to remain between $9.50 and $10.50 per boe.

Corporate production for the three and twelve months ended December 31, 2018 averaged 5,997 boe/d and 6,507 boe/d, respectively, compared to production of 6,713 boe/d and 8,139 boe/d in 2017. Oil and liquids production for the same periods increased to 1,390 bbl/d and 1,491 bbl/d, up 20% and 7% respectively.

2018 Independent Reserve Evaluation Matters

GLJ Petroleum Consultants (“GLJ”) prepared the reserves report effective December 31, 2018 (the “GLJ Report”) for the oil, natural gas liquids and natural gas reserves attributable to the properties of Cequence. The GLJ 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 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The reserves data provided in this press release represents only a portion of the disclosure required by NI 51-101. Additional information from the GLJ Report, including all disclosure required under NI 51-101, will be contained in the Company’s Annual Information Form for the year ended December 31, 2018, which will be filed on SEDAR on or before March 31, 2019. Reserves highlights of the Company include:

  • Corporate reserves were 10.6 MMboe proved developed producing, 57.0 MMboe proven, and 129.4 MMboe on a proved plus probable basis.
  • Corporate FD&A, including changes in future development capital, was $3.50/boe on a proven plus probable basis;
  • The Corporate net asset value per share at a 10% discount rate using GLJ January 1, 2019 prices and year end 2018 net debt is $4.31/share total proved and $15.19/share proved plus probable;
  • Before production, Dunvegan oil proved developed producing, total proved, and proved plus probable reserves increased by 303%, 74%, and 90% respectively to 1.6 MMboe, 2.9 MMboe and 5.3 MMboe.
  • Dunvegan oil total proven and proven plus probable net present values at 10% discount rate are $41.8 million and $74.7 million respectively using GLJ January 1, 2019 prices
  • Undeveloped Dunvegan oil inventory is 5.5 net proven and 10.5 net proved plus probable locations.
  • The Dunvegan oil program finding, development, and acquisition costs inclusive of changes in booked future development capital, was $12.64/boe proved developed producing, $20.77/boe total proved, and $14.91/boe proved plus probable. The 2018 operating netback for the Dunvegan oil area is estimated at $34.74/boe which yields recycle ratios of 2.7, 1.7, and 2.3 respectively.
  • Due to lower commodity prices and other economic factors non-core assets totaling 1.4 MMboe proved and 2.3 MMboe proven plus probable were not assigned reserves.
  • A total of 0.31 MMboe proven and 0.51 MMboe proven plus probable reserves were sold in calendar year 2018.

The tables below are a summary of the oil, NGL and natural gas reserves attributable to the properties of Cequence and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Report based on forecast price and cost assumptions. The calculated NPVs include a deduction for estimated future well abandonment and reclamation costs. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of Cequence’s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Summary of Oil, Natural Gas and NGL Reserves

Light and Medium Crude Oil Tight Oil Conventional Natural Gas Shale Gas NGL  Total Oil Equivalent
Reserves Category Gross(2) Net(3) Gross(2) Net(3) Gross(2) Net(3) Gross(2) Net(3) Gross(2) Net(3) Gross(2) Net(3)
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) MMcf MMcf (Mbbl) (Mbbl) (MBOE) (MBOE)
Proved
Developed Producing 735 615 0 0 18,615 16,961 33,153 28,325 1,259 826 10,623 8,989
Developed Non-Producing 12 9 0 0 2,569 2,267 4,328 3,569 146 90 1,307 1,072
Undeveloped 649 564 0 0 3,688 3,369 223,813 194,944 6,541 5,485 45,107 39,101
Total Proved 1,396 1,187 0 0 24,872 22,596 261,293 226,838 7,946 6,402 57,036 49,161
Probable 1,193 965 0 0 58,926 54,068 311,007 259,564 9,524 7,070 72,372 60,306
Total Proved plus Probable 2,589 2,152 1 0 83,799 76,665 572,300 486,402 17,470 13,471 129,409 109,468

Notes:

  1. Columns may not add due to rounding.
  2. “Gross” reserves means the Company’s working interest (operated and non‐operated) share before deduction of royalties payable to others and without including any royalty interests of the Company.
  3. “Net” reserves means the Company’s working interest (operated and non‐operated) share after deduction of royalty obligations plus the Company’s royalty interests in reserves.

Summary of Net Present Value of Future Net Revenue

Reserves Category Before Future Income Tax Expenses Discounted at (%/year)
0 5 10 15 20 10
(M$) (M$) (M$) (M$) (M$) ($/mcfe)
Proved
Developed Producing 90,358 81,708 74,036 67,593 62,231 1.37
Developed Non-Producing 11,110 8,846 7,134 5,855 4,889 1.11
Undeveloped 311,475 175,301 96,640 49,580 20,458 0.41
Total Proved 412,943 265,855 177,810 123,028 87,577 0.6
Probable 875,166 460,970 267,145 166,182 108,799 0.74
Total Proved plus Probable 1,288,109 726,824 444,955 289,210 196,377 0.68

 

Reserves Category After Future Income Tax Expenses Discounted at (%/year)
0 5 10 15 20
(M$) (M$) (M$) (M$) (M$)
Proved
Developed Producing 90,358 81,708 74,036 67,593 62,231
Developed Non-Producing 11,110 8,846 7,134 5,855 4,889
Undeveloped 311,475 175,301 96,640 49,580 20,458
Total Proved 412,943 265,855 177,810 123,028 87,577
Probable 678,622 369,651 220,181 140,117 93,468
Total Proved plus Probable 1,091,566 635,505 397,991 263,145 181,046

Notes:

  1. Columns may not add due to rounding.
  2. It should not be assumed that the undiscounted and discounted future net revenues estimated by GLJ represent the fair market value of the reserves.

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of January 1, 2019 in the GLJ Report in estimating Cequence’s reserves data using forecast prices and costs:

Natural Gas Light Crude Oil Pentanes Plus
Henry Hub AECO Gas Price WTI Edmonton Edmonton Inflation Rates Exchange Rate
Year ($US/MMBtu) ($Cdn/MMBtu) ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) %/year ($US/$Cdn)
Forecast
2019 3 1.85 56.25 63.33 67.67 2 0.75
2020 3.15 2.29 63 75.32 79.22 2 0.77
2021 3.35 2.67 67 79.75 83.54 2 0.79
2022 3.5 2.9 70 81.48 85.49 2 0.81
2023 3.63 3.14 72.5 83.54 87.8 2 0.82
2024 3.7 3.23 75 86.06 90.3 2 0.825
2025 3.77 3.34 77.5 89.09 93.33 2 0.825
2026 3.85 3.41 80.41 92.62 96.86 2 0.825
2027 3.93 3.48 82.02 94.57 98.81 2 0.825
2028 4 3.54 83.66 96.56 100.8 2 0.825
Thereafter escalation rate of 2%

The following table summarizes the elements of future net revenue attributable to reserves estimated using forecast prices and costs.

Revenue ($000s) Royalties ($000s) Operating Costs ($000s) Development Costs ($000s) Abandonment and Reclamation Costs ($000s) Future Net Revenue Before Income Taxes ($000s) Income Taxes ($000s) Future Net Revenue After Income Taxes ($000s)
Proved Reserves 1,611,942 111,793 601,968 462,720 22,518 412,943 412,943
Proved Plus Probable Reserves 3,890,561 324,825 1,379,871 859,026 38,729 1,288,109 196,543 1,091,566

Future Net Revenue by Product Type

Reserves Category Product Type Future Net Revenue Before Income Taxes (3) (discounted at 10% per year) ($000s) Unit Value $/boe Unit Value $/MMcf
Proved Reserves Light and Medium Oil (1) 37,336 14.64 2.44
Tight Oil (1) 7 15.83 2.64
Conventional Natural Gas (2) 11,041 4.17 0.70
  Shale Natural Gas 129,426 2.94 0.49
  Total 177,810 3.62 0.60
Proved Plus Probable Reserves Light and Medium Oil (1) 70,019 15.23 2.54
Tight Oil (1) 12 17.91 2.98
Conventional Natural Gas (2) 28,028  2.45 0.41
  Shale Natural Gas 346,896 3.71 0.62
  Total 444,955 4.06 0.68

Notes:

  1. Includes solution gas and other by-products
  2. Including by-products but excluding solution gas
  3. Other Company revenue and costs not related to a specific production group have been allocated proportionately to production groups.  Unit values are based on Company Net Reserves.

Dunvegan Oil: Company Interest Reserves Reconciliation

Proved Producing Total Proved Total Proved Plus Probable
Technical Revisions 85.7 72.9 246.1
Drilling Extensions 1,493.1 1,378.6 2,493.5
Change in Finding and Development Costs ($M) $ 0 $ 10,192 $ 20,890
2018 Capital $ 19,961 $ 19,961 $ 19,961
F&D ($/boe)(1) $ 12.64 $ 20.77 $ 14.91
2018 Netback ($/boe) (1) $ 34.74 $ 34.74 $ 34.74
Recycle Ratio(1) 2.7 1.7 2.3

Notes:

  1.  See “Non-GAAP Measures” in this press release.

Board of Directors and Management Update

Daryl Gilbert has announced his resignation from the Company’s board, effective the end of the day today, March 12, 2019. Mr. Gilbert has served on the Company’s board since 2012, and Cequence and the rest of the board thank Mr. Gilbert for his years of dedicated service to the Company and his contribution to helping the Company navigate a difficult commodity price environment.

Cequence is pleased to announce that Dan O’Neil has been appointed to the Company’s board effective today. Mr. O’Neil is a professional engineer with over 30 years of experience in the Canadian oil and gas business, including senior management positions with EnCana Corporation and later serving as the Chief Executive Officer of Surge Energy Inc. until May 2013. Mr. O’Neil was also one of the founders of Breaker Energy Ltd., which was acquired by NAL Energy Corporation (formerly NAL Oil & Gas Trust)

As previously announced on February 12, 2019 Allan Mowbray will be joining Cequence as Chief Financial Officer effective March 15, 2019. In connection Mr. Mowbray joining the Company, Howard Crone has, effective today, resigned from his position as Executive Vice President of the Company. Mr. Crone will continue to serve as a director of Cequence. Also effective today, Donald Archibald’s title will change from Executive Chairman to Chairman.

2019 Guidance:

The Company’s guidance for the year ended December 31, 2019 includes the results of the fourth quarter 2018 oil wells, the restructured $60 million Term Loan (with its 5% interest rate), and an additional planned 2 gross (2 net) Dunvegan oil wells drilled and on production at the end of the third quarter of 2019. Cequence will continue to monitor volatility in commodity prices with the focus that 2019 capital activity will remain within funds flow from operations.

(000’s, except per share and per unit references) Guidance
year ended
December 31, 2019
Average production, BOE/d (1) 5,800
Funds flow from operations ($)(2) 17,000
Funds flow from operations per share(2) 0.69
Exploration and development expenditures ($) 13,000
Net wells 2.0
Operating and transportation costs ($/boe) 15.00
G&A costs ($/boe) 2.30
Royalties (% revenue) 10
Crude – WTI (US$/bbl) 57.50
Natural gas – AECO (CDN$/GJ) 1.69
Period end, net debt ($) (3) 69,000
Common shares outstanding end of period 24,553

(1) Average production estimates on a per BOE basis are comprised of 72% natural gas and 28% oil and natural gas liquids in 2019.
(2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net changes in non-cash working capital. See “Non-GAAP Measures” in this press release.
(3) Net debt is calculated as working capital deficiency (excluding commodity contracts) plus the aggregate principal amount of the term loan.

About Cequence

Cequence is a publicly traded Canadian energy company involved in the acquisition, exploitation, exploration, development and production of natural gas and crude oil in western Canada. Further information about Cequence may be found in its continuous disclosure documents filed with Canadian securities regulators at www.sedar.com.



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