CALGARY, AB, March 9, 2021 /CNW/ – 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, 2020, and its year-end 2020 reserves, as independently evaluated by Sproule Associates Limited (“Sproule”).
2020 FINANCIAL, OPERATIONAL, AND RESERVES HIGHLIGHTS
Surge Energy Inc. Announces 2020 Fourth Quarter and Year-End Financial and Operating Results and 2020 Year-End Reserves (CNW Group/Surge Energy Inc.)
- Achieved an all-in payout ratio1of less than 100 percent for 2020 while oil averaged less than US$40 WTI per barrel, generating cash flow from operating activities less payments on lease obligations of $64.1 million and employing a disciplined exploration and development program of $52.8 million;
- Generated realized hedging gains on financial contracts of over $20 million in 2020 pursuant to the Company’s ongoing strategic risk management program;
- Added over $90 million of new credit facility commitments, including a previously announced BDC financing ($40 million second lien) and a $51 million commitment by EDC into Surge’s existing first lien credit facility;
- Reduced net bank debt1by $36.5 million in 2020 from $313.6 million at December 31, 2019 to $277.1 million at December 31, 2020;
- Continued Surge’s focus on ESG, completing a total of $9.3 million on abandonment activities. This was funded using a combination of cash flow from operating activities, as well as grants received through the Alberta Site Rehabilitation Program;
- Achieved average daily production of 17,356 boepd (84% liquids) during the fourth quarter of 2020; consistent with the second and third quarters of 2020 despite no production additions from drilling activity during those periods and a significantly reduced exploration and development expenditure program as compared to the prior year;
- Prior to suspending major exploration and development expenditures in March 2020, successfully drilled 19 consecutive Sparky wells at an all-in cost of $22 million.
- Reduced P+PDP decline from 21% (2019YE) to 18%2(2020YE);
- Estimated Total P+P Net Asset Value of $2.43 per basic share and Total Proved Net Asset Value of $1.19 per basic share at a US $55 WTI Flat Price Deck3;
- Surge’s 401 net (427 gross) booked locations of undeveloped reserves in the Company’s new Sproule December 31, 2020 Engineering Report, have a Finding & Development (“F&D”) cost of $12.43/boe on a Proved plus Probable Undeveloped (“P+PUD”) reserves basis;
- 2020 Drilling (19 Wells) F&D was $12.05/boe PDP and $10.25/boe P+PDP;
- Increased Total P+P reserve life index to 16 years;
Subsequent to the year-end 2020, on March 5, 2021 Surge announced:
- The Company is nearing completion of its successful, 32 well 1H/21 drilling program – and anticipates adding more than 3,200 boepd for an “all-in” cost of $39 million;
- The strategic sale of 2,700 boepd of production (the “Sale”) for proceeds of $106 million (closing March 25/21).
- The disposed assets had reserves of 10.3 MMBOE on a Total Proved basis and 20.6 MBOE on a Total Proved plus Probable basis as at December 31, 2020.
- The disposed assets had 40.8 net Proved locations booked and 62.8 net Proved plus Probable locations booked.
- Surge maintains a deep inventory of booked locations, with 270 net Proved and 339 net Proved plus Probable locations net of the disposition. Furthermore, the Company has an additional >400 net unbooked locations4;
- Following the Sale, Surge retains a deep, 14 year drilling inventory of more than 750 highly economic drilling locations for medium and light gravity crude oil; and
- At the closing of the Sale, Surge anticipates it’s first lien credit facilities will be re-determined at $215 million, with the Company’s next bank review scheduled on or before November 30, 2021. In addition, the previous obligation to conduct an asset sale solicitation process in 2021 is eliminated. This re-determination is forecast to provide the Company with over $25 million of available liquidity5 upon the closing of the Sale, and to significantly reduce Surge’s annual interest expense.
Surge’s high quality, low cost conventional reservoirs continued to deliver excellent results throughout the year. Surge completed a reduced Q1/20 drilling program in early March, drilling 19 successful horizontal wells in seven different Sparky pools. This program included the delineation of two new Sparky pool discoveries on its lands at Betty Lake North and Eyehill South.
In late Q4/20, Surge commenced a disciplined, 32 well drilling program, following the closing of the Company’s previously announced $40 million Term Facility under the Business Development Bank of Canada’s Business Credit Availability Mid-Market Financing Program. The Company drilled and rig released 13 gross (13.0 net) Sparky wells in late Q4/20. These wells have all now been completed and are anticipated to be on production in late Q1/21.
This drilling program continued into Q1/21, and the Company has rig released an additional 18 gross (18.0 net) wells to date in 2021, all in the Company’s Sparky core area. One additional (1.0 net) well is budgeted to be drilled in late Q1/21 into the Company’s large OOIP Montney turbidite pool in the Valhalla core area. This is a development offset location to the Company’s successful Montney horizontal well drilled and brought on production in Q4/19. This well had an IP30 oil rate of more than 1,000 bopd and has delivered cumulative production of over 215,000 barrels of light oil in one year.
FINANCIAL AND OPERATING HIGHLIGHTS
|FINANCIAL AND OPERATING HIGHLIGHTS||Three Months Ended December 31,||Years Ended December 31,|
|($000s except per share amounts)||2020||2019||% Change||2020||2019||% Change|
|Natural gas sales||2,597||2,808||(8)%||7,228||10,002||(28)%|
|Total oil, natural gas, and NGL revenue||59,907||91,789||(35)%||211,049||394,349||(46)%|
|Cash flow from operating activities||11,000||34,474||(68)%||72,190||149,417||(52)%|
|Per share – basic ($)||0.03||0.11||(73)%||0.21||0.47||(55)%|
|Adjusted funds flow1||8,467||38,881||(78)%||59,872||172,988||(65)%|
|Per share – basic ($)1||0.02||0.12||(83)%||0.18||0.55||(67)%|
|Net loss2||(57,727)||(143,801)||(60)%||(747,297)||(158,664)||371 %|
|Per share basic ($)||(0.17)||(0.44)||(61)%||(2.22)||(0.50)||344 %|
|Total exploration and development expenditures||14,276||30,760||(54)%||52,773||119,465||(56)%|
|Total acquisitions & dispositions||–||2,458||(100)%||(6,038)||(42,438)||(86)%|
|Total capital expenditures||14,276||33,218||(57)%||46,735||77,027||(39)%|
|Net debt1, end of period||381,023||382,309||– %||381,023||382,309||– %|
|Oil (bbls per day)||13,788||16,441||(16)%||14,558||17,127||(15)%|
|NGLs (bbls per day)||726||630||15 %||600||692||(13)%|
|Natural gas (mcf per day)||17,050||19,521||(13)%||16,906||20,135||(16)%|
|Total (boe per day) (6:1)||17,356||20,325||(15)%||17,976||21,175||(15)%|
|Average realized price (excluding hedges):|
|Oil ($ per bbl)||43.80||57.46||(24)%||37.39||60.19||(38)%|
|NGL ($ per bbl)||26.14||35.84||(27)%||21.00||32.09||(35)%|
|Natural gas ($ per mcf)||1.66||1.56||6 %||1.17||1.36||(14)%|
|Netback ($ per boe)|
|Petroleum and natural gas revenue||37.52||49.09||(24)%||32.08||51.02||(37)%|
|Realized gain (loss) on commodity and FX contracts||(3.91)||0.13||(3,108)%||3.05||(0.61)||(600)%|
|Net operating expenses1||(15.99)||(14.91)||7 %||(14.72)||(14.50)||2 %|
|G&A expense||(1.86)||(1.95)||(5)%||(1.90)||(1.85)||3 %|
|Interest expense||(5.21)||(3.16)||65 %||(4.20)||(3.45)||22 %|
|Adjusted funds flow1||5.30||20.80||(75)%||9.11||22.36||(59)%|
|Common shares outstanding, end of period||339,785||326,330||4 %||339,785||326,330||4 %|
|Weighted average basic shares outstanding||339,785||324,836||5 %||336,052||316,639||6 %|
|Weighted average diluted shares outstanding||339,785||324,836||5 %||336,052||316,639||6 %|
|1 This is a non-GAAP financial measure which is defined in the Non-GAAP Financial Measures section of this document.|
|2 For the year ended December 31, 2020, the Company incurred a net loss of $747.3 million, including a non-cash asset impairment charge of $628.1 million recognized in the year primarily due to a decrease in the average independent engineering price forecasts. 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.|
ENVIRONMENTAL, SOCIAL, AND GOVERNANCE
Surge was recently allocated an additional $3.2 million under the Government of Alberta’s Site Rehabilitation Program (“SRP”) to abandon and reclaim well bores, pipelines, and well sites. To date, the Company has now received more than $14 million in grant funding from the Alberta SRP.
Surge will continue to be actively engaged with the Government of Alberta regarding additional SRP developments, as well as new developments in both Federal and Government of Saskatchewan programs, in order to accelerate the decommissioning of the Company’s asset retirement obligations.
Surge strives to be a leader in reducing the impact of its operations on the environment. The Company is committed to producing energy in a safe, responsible, and sustainable manner.
2020 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, 2020. Surge’s annual information form (the “AIF”) for the year ended December 31, 2020 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, 2020 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
|Before Tax NPV of Future Net
Revenue(d) Discounted at
|Total Proved Plus Probable||86,965||86,165||101,326||1,222||960||765|
|a)||Amounts may not add due to rounding.|
|b)||Includes light, medium, heavy and natural gas liquids.|
|c)||Includes non-associated and 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.|
|e)||As discounting decreases, abandonment costs become more significant.|
FUTURE DEVELOPMENT CAPITAL (“FDC”)
|Total Proved Developed
|Total Proved||Total Proved
|Total (Discounted at 10%)||30||488||631|
NET ASSET VALUE at US$55 WTI Flat
|Reserve Value NPV10 BT ($MM) (a)||$673||$1,096|
|Undeveloped Land and Seismic ($MM) (b)||$113||$113|
|Net Debt ($MM)||$(381)||$(381)|
|Total Net Assets ($MM)||$404||$827|
|Basic Shares Outstanding (MM)||339.8||339.8|
|Estimated NAV per Basic Share ($/share)||$1.19/share||$2.43/share|
|a)||Run on a US$55 Flat price deck (-US$12.50/bbl WCS & -US$4.00/bbl EDM differentials, 0.78 FX and C$2.80/mmbtu AECO)|
|b)||Internally estimated as $80 MM for non-reserve assigned land and $33 MM for seismic data.|
Outlook; Guidance 2021/2022
In just the last 4 months, oil prices have rallied over 90%, from a low of US$33.64 per barrel on November 3, 2020 to over US$64 WTI per barrel, today. Furthermore, WCS differentials are trading below their long-term average of approximately US$17 per barrel to less than US$12 per barrel, today. Light oil differentials are also trading below their long-term average of approximately US$6 per barrel to less than US$3 per barrel today.
In 1H/21, the Company is completing a $39 million development drilling capital program, adding estimated production of more than 3,200 boepd (>90% medium/light oil) from 32 gross (32.0 net) wells. Concurrently, during Q1/21, Surge executed a binding Purchase and Sale Agreement for the sale of 2,700 boepd for total gross proceeds of $106 million (before customary adjustments); the sale is set to close on or before March 25, 2021.
On a go forward basis, Surge is planning a disciplined capital allocation strategy with an emphasis on free cash flow generation in 2H/21. The Company is currently budgeting for a 2H/21 maintenance drilling program, allocating the incremental free cash flow to continued reduction of bank indebtedness.
Surge will be reforecasting 2021, and providing 2022 guidance, after the closing of the Sale on March 25, 2021.
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: Surge’s declared focus and primary goals; management’s expectations and plans with respect to the development of its assets and the timing thereof; the timing of bringing recently drilled wells onto production; Surge’s planned drilling program for 2H/21; Surge’s drilling inventory and locations; the Sale and the terms, timing and anticipated proceeds and benefits therefrom; the expected impact of the Sale on Surge’s bank indebtedness , liquidity and interest expense; management’s expectations regarding 2021 production; Surge’s anticipated abandonment program and reduction of its decommissioning liabilities and asset retirement obligations and the timing thereof; Surge’s ongoing engagement regarding the Alberta SRP program and other federal and provincial programs; Surge’s stated goals regarding environmental responsibility; Surge’s plans regarding the reduction of bank indebtedness; and the timing of reforecasted 2021 and 2022 guidance.
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 AIF dated March 9, 2021 and in Surge’s MD&A for the period ended December 31, 2020, both of which have been filed on SEDAR and 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, 2021.
Reserve life index is calculated as total Company share reserves divided by the annualized fourth quarter production.
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.
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, 2021 reference date, the Company will have over >950 gross (>925 net) drilling locations identified herein; of these >530 gross (>500 net) are unbooked locations. Of the 401 net booked locations identified herein, 310 net are Proved locations and 91 net are Probable locations based on Sproule’s 2020YE reserves. Assuming an average number of wells drilled per year of 50, Surge’s >950 locations provide 19 years of drilling.
Assuming a Mar 31, 2021 reference date (proforma the disposition announced on March 5th), the Company will have over >750 gross (>750 net) drilling locations identified herein; of these >400 gross (>400 net) are unbooked locations. Of the 338 net booked locations identified herein, 269 net are Proved locations and 68 net are Probable locations based on Sproule’s 2020YE reserves. Assuming an average number of wells drilled per year of 50, Surge’s >750 locations provide 14 years of drilling.
Surge’s internally used type curves were constructed using a representative, factual and balanced analog data set, as of January 1, 2021. 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 bank 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, and cash settled transaction and other costs. 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. Cash settled 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. 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, 2020:
|Three Months Ended Dec 31,||Years Ended December 31,|
|($000s except per share amounts)||2020||2019||2020||2019|
|Cash flow from operating activities||11,000||34,474||72,190||149,417|
|Change in non-cash working capital||(5,084)||2,876||(16,721)||16,569|
|Cash settled transaction and other costs||–||106||98||1,480|
|Adjusted funds flow||$||8,467||$||38,881||$||59,872||$||172,988|
|Per share – basic||$||0.02||$||0.12||$||0.18||$||0.55|
There is no comparable measure in accordance with IFRS for net debt. Net debt is calculated as bank debt, term debt, dividends payable plus the liability component of the convertible debentures plus or minus working capital, however, excluding the fair value of financial contracts, decommissioning obligations, and lease and other obligations. 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)||Dec 31, 2020||Sep 30, 2020||Dec 31, 2019|
|Prepaid expenses and deposits||5,253||4,900||4,875|
|Accounts payable and accrued liabilities||(51,265)||(33,507)||(40,848)|
Net Bank Debt
There is no comparable measure in accordance with IFRS for net bank debt. Net bank debt is calculated as current portion of bank debt plus or minus working capital (accounts receivable, prepaid expenses and deposits and accounts payable and accrued liabilities).
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, 2020 and 2019 are calculated on a per unit basis as follows:
|Three Months Ended Dec 31,||Years Ended December 31,|
|Petroleum and natural gas revenue||59,907||91,790||211,049||394,349|
|Processing and other income||1,006||1,563||4,772||4,303|
|Realized gain (loss) on commodity and FX contracts||(6,247)||248||20,099||(4,679)|
|Adjusted funds flow||8,467||38,881||59,872||172,988|
|Barrels of oil equivalent (boe)||1,596,718||1,869,819||6,579,239||7,728,923|
|Operating netback ($ per boe)||$||12.37||$||25.91||$||15.21||$||27.66|
|Adjusted funds flow ($ per boe)||$||5.30||$||20.80||$||9.11||$||22.36|
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 First year P+PDP decline from 2020YE reserve database|
|3 US$55.00/bbl WTI Flat Price Deck (-US$12.50/bbl WCS & -US$4.00/bbl EDM Differentials, 0.78 FX, C$2.80/mmbtu AECO)|
|4 See Drilling Inventory in Forward Looking Statements|
|5 Calculated as $215 million Credit Facilities less $189 million in forecast post-closing bank indebtedness as at April 1, 2021.|
SOURCE Surge Energy Inc.
For further information: Paul Colborne, President & CEO, Surge Energy Inc., Phone: (403) 930-1507, Fax: (403) 930-1011, Email: email@example.com; Jared Ducs, Chief Financial Officer, Surge Energy Inc., Phone: (403) 930-1046, Fax: (403) 930-1011, Email: firstname.lastname@example.org