Headwater Exploration Inc. Announces 2020 Reserves, Fourth Quarter and Year End 2020 Operating and Financial Results and Operations Update

HEADWATER EXPLORATION INC. ANNOUNCES 2020 RESERVES, FOURTH QUARTER AND YEAR END 2020 OPERATING AND FINANCIAL RESULTS AND OPERATIONS UPDATE

CALGARY, ALBERTA – Headwater Exploration Inc. (the “Company” or “Headwater“) (TSX:HWX) announces its operating and financial results for the three months and year ended December 31, 2020. Selected financial and operational information is outlined below and should be read in conjunction with the audited financial statements and the related management’s discussion and analysis (“MD&A”).  These filings will be available at www.sedar.com and the Company’s website at www.headwaterexp.com. In addition, readers are also directed to the Company’s Annual Information Form for the year ended December 31, 2020, dated March 10, 2021, filed on SEDAR at www.sedar.com.

 Financial and Operating Highlights

(1) See “Non-IFRS” measures

(2) See ‘”Barrels of Oil Equivalent.”

(3) Excludes accretion on decommissioning liabilities and interest on lease liability.

(4)  Includes in-the-money dilutive securities as at December 31, 2020, which include 6.3 million stock options at a weighted average exercise price of $1.04/share and 21.7 million warrants vested and exercisable at an average exercise price of $0.92/share and 15 million warrants issued to Cenovus at $2.00/share.

FOURTH QUARTER 2020 HIGHLIGHTS

• Closed the acquisition of Cenovus Energy Inc.’s position in the Marten Hills area of Alberta for estimated total consideration of $135.3 million. The acquired assets included a 100% working interest in approximately 2,800 barrels per day of heavy oil production and 270 net sections of Clearwater rights.
• Generated average production of 1,646 boe/d inclusive of one month of production from the acquired Marten Hills assets.
• Achieved adjusted funds flow from operations of $4.8 million ($0.03/share basic), representing a 150% increase from the fourth quarter of 2019.
• Achieved an operating netback of $35.04/boe and an adjusted funds flow netback of $31.79/boe.
• Generated net income of $16.9 million ($0.10/share basic).
• As at December 31, 2020, Headwater had adjusted working capital of $80.8 million and no outstanding debt.

YEAR ENDED DECEMBER 31, 2020

• Production averaged 882 boe/d for the year, an increase of 42% from 2019 annual production of 620 boe/d.
• Achieved adjusted funds flow from operations of $8.8 million ($0.06/share basic).
• Achieved free cash flow of $6.5 million.
• Proved developed producing reserves increased by 67% to 5.0 mmboe from 3.0 mmboe.
• Total proved reserves increased by 217% to 9.5 mmboe from 3.0 mmboe.
• Proved plus probable reserves increased 254% to 13.1 mmboe from 3.7 mmboe.
• Achieved finding, development, and acquisition (“FD&A”) costs, including changes in future development costs of $26.89 per boe on a proved basis and $18.87 per boe on a proved plus probable basis.
• As at December 31, 2020, Headwater’s Liability Management Rating (“LMR”) was 31 in Alberta significantly exceeding the Alberta industry LMR average. Headwater remains committed to maintaining an LMR rating above the industry average and minimizing its environmental footprint.   

Operations Update

 Marten Hills Core Area Development

The first quarter of 2021 has been very active to date.  Accomplishments include:

• Rig released 11 8-leg horizontal wells in the core producing area of Marten Hills;
• Currently drilling our one remaining 8-leg horizontal well in Marten Hills to complete Headwater’s first quarter program;
• Rig released 5 horizontal injection wells including 1 4-leg horizontal injector, 2 2-leg horizontal injectors and 2 single leg horizontal injectors;
• Drilled, completed and tested two Grand Rapids/Clearwater source wells;
• Drilled and evaluated one stratigraphic test well; and
• Drilled in excess of 150,000 meters and achieved average well costs equivalent to established Clearwater operators.

The producing and injection wells drilled this quarter occurred from three pad sites which prevented many of the new wells from being placed on production until all drilling and completion operations for the quarter were completed.  Through some ingenuity the team was able to begin production from four of the 8-leg horizontal wells in the last couple of weeks.  The balance of the new producing wells will be placed on production in conjunction with the completion of the multi-well batteries prior to the end of March.  Headwater looks forward to providing a fulsome production update in conjunction with our first quarter results to be released in early May.

The Marten Hills area is characterized by challenging break-up conditions from April through to June.  With the expected ramp up in production, and associated fluid movement in April, Headwater has been actively preparing contingencies to tackle the logistical challenges of break-up at Marten Hills.  The advanced preparations will assist the company in minimizing downtime during the second quarter.

Enhanced Oil Recovery

Headwater initiated construction of a temporary injection setup and anticipates having first injection into the 4-leg horizontal injector by the end of April which is six months ahead of schedule.  The remaining injection wells will be placed on production prior to the end of March and produce until the third quarter of 2021, at which time the wells will then be converted to injection. 

Production testing of two source wells showed strong inflow results of greater than 1,000 bbls/d per well confirming there is sufficient source water for our first phase of injection.

Gas Conservation

During the first quarter, Headwater executed an agreement with another area operator to construct a joint gas processing facility.  The facility is currently under construction and is expected to be commissioned by early July 2021.  This facility will allow us to achieve gas conservation from production in the core area nine months ahead of initial expectations.

Exploration Update

 Access to a portion of the Marten Hills exploration lands was confirmed during the first quarter.  We expect to license the first four exploration tests imminently and expect to begin drilling as early as late August 2021.  An additional three to five exploration tests will be drilled as soon as access allows, which is anticipated to commence in December and continue into the first quarter of 2022.

McCully Asset

The McCully asset has performed strongly throughout this winter season and Headwater anticipates continuing to produce the field until May 1, 2021, when it will be shut-in to await next winter’s premium pricing season. Based on field receipts to date, the McCully field is expected to generate approximately $4.5 million of free cash flow during the first quarter of 2021.

Reserves growth with minimal capital expenditures continued for this property in 2020.  Positive technical revisions and improved recovery replaced 2020 production by 0.9 times on a proved basis and 1.3 times on a proved plus probable basis.

 2021 Guidance

 Headwater is reaffirming its 2021 production guidance.  Based on recent strip commodity prices Headwater now expects to achieve adjusted funds flow from operations of $90 – $95 million, an increase from approximately $48 – $52 million from our previously announced December guidance.  The acceleration of the gas plant construction results in a modest increase in capital expenditures to $90 – $95 million from $85 – $90 million.

2020 Reserve Information

Headwater currently has heavy oil reserves located in the Marten Hills area of Alberta and natural gas reserves in the McCully Field near Sussex, New Brunswick.  GLJ Ltd. (“GLJ“) assessed the Company’s reserves in its report dated effective December 31, 2020 (“GLJ Report”) which were prepared in accordance with standards of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities and is based on the average forecast prices as at December 31, 2020 of three independent reserves evaluation firms. Additional information regarding reserves data and other oil and gas information is included in Headwater’s Annual Information Form for the year ended December 31, 2020 which will be filed on SEDAR on March 10, 2021.     

The following tables are a summary of Headwater’s petroleum and natural gas reserves, as evaluated by GLJ, effective December 31, 2020. 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 our 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. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates provided herein. Reserves information may not add due to rounding.    

Reserves Summary

• Reserves have been presented on gross basis which are the Company’s total working interest share before the deduction of any royalties and without including any royalty interests of the Company.
• Based on the 3 consultants’ average of GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2021.
• Pursuant to the COGE Handbook, reported reserves should target at least 90 percent probability that the quantities actually recovered will be equal to or exceed the estimated proved reserves and that at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Net Present Value of Future Net Revenue

• Based on the average of the commodity price forecasts of GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2021.
• All future net revenues are stated prior to provision for interest income and other, general and administrative expenses and after deduction of royalties, operating costs, estimated well and facility abandonment and reclamation costs and estimated future capital expenditures.

Future Development Costs (“FDC”)

 The following is a summary of the estimated FDC required to bring proved undeveloped reserves and proved plus probable undeveloped reserves on production.

• Future development capital after 2022 is associated with McCully gas plant optimization.

• Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2020, reflected in the GLJ Report, using the average of commodity price forecasts from GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited effective as at January 1, 2021, to estimate the reserves volumes and associated values in the GLJ Report.  These price assumptions were provided to Headwater by GLJ and were GLJ’s then current forecast at the date of the GLJ Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS ⁽¹⁾
as of December 31, 2020
FORECAST PRICES AND COSTS

• Thereafter Escalation rate of 2.0%
• Notes:
  • This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
  • The exchange rate used to generate the benchmark reference prices in this table.
  • As at December 31, 2020.
  • The forecast McCully gas price is used by GLJ in calculating the net present value of Headwater’s future natural gas net revenues from the McCully field. The McCully gas price is determined by adjusting the forecast AGT gas prices to reflect the expected premiums received at Headwater’s delivery point, transportation costs, as applicable, heat content and marketing conditions. The McCully gas price in years 2021 – 2023 reflects only the winter producing months (January to April and November to December) or correlate to the intermittent production strategy employed by the Company to capture seasonal premium pricing.    After 2023, the GLJ Report assumes Headwater produces volumes from its reserves continuously over the year and as such, McCully pricing reflects the full year.

Response to COVID-19

Headwater continues to prioritize the health and safety of the Company’s employees, contractors, partners, service providers and the communities in which we operate.  The Company remains committed to protecting the well‐being of all stakeholders and following the guidance of public health officials, while maintaining safe operations and business continuity.

Additional corporate information can be found in our corporate presentation on our website at www.headwaterexp.com

FOR FURTHER INFORMATION PLEASE CONTACT:

HEADWATER EXPLORATION INC.                                HEADWATER EXPLORATION INC.

Mr. Neil Roszell, P. Eng.                                                  Mr. Jason Jaskela, P.Eng.                         

Chairman and Chief Executive Officer                         President and Chief Operating Officer

HEADWATER EXPLORATION INC.

Ms. Ali Horvath, CPA, CA

Vice President, Finance and Chief Financial Officer

info@headwaterexp.com

(587) 391-3680

FORWARD LOOKING STATEMENTS: This press release contains forward-looking statements. The use of any of the words “guidance”, “initial, “anticipate”, “scheduled”, “can”, “will”, “prior to”, “estimate”, “believe”, “potential”, “should”, “unaudited”, “forecast”, “future”, “continue”, “may”, “expect”, “project”, and similar expressions are intended to identify forward-looking statements. The forward-looking statements contained herein, include, without limitation, Headwater’s revised 2021 guidance including expected 2021 capital expenditures and 2021 adjusted funds flow from operations; Headwater’s expectation to maintain a LMR rating above the industry average and minimize its environmental footprint;  first quarter 2021 well production results; the expectation that the balance of new wells will be placed on production in conjunction with the multi-well batteries by the end of March; Headwater’s ability to manage logistical challenges of break-up in Marten Hills and have limited downtime during the second quarter of 2021; timing of first injection and injection well conversion associated with injection wells; the expectation that the gas plant will be commissioned by early July and gas conservation will be achieved;  expected timing to license and drill certain exploration wells; Headwater’s intent to continue the Company’s previous strategy of production optimization of the McCully gas field in New Brunswick; the expectation that production from the McCully field will be shut-in May 1 to take advantage of premium gas pricing and expected free cash flow generation. The forward-looking statements contained herein are based on certain key expectations and assumptions made by the Company, including but not limited to expectations and assumptions concerning the success of optimization and efficiency improvement projects, the availability of capital, current legislation, receipt of required regulatory approval, the success of future drilling, development and waterflooding activities, the performance of existing wells, the performance of new wells, Headwater’s growth strategy, general economic conditions, availability of required equipment and services, prevailing equipment and services costs, prevailing commodity prices and certain other guidance assumptions as detailed in the MD&A available on SEDAR at www.sedar.com.. Although the Company 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 the Company 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 oil and gas industry in general (e.g., operational risks in development, exploration and production; disruptions to the Canadian and global economy resulting from major public health events, including the COVID-19 pandemic, war, terrorist events, political upheavals and other similar events; events impacting the supply and demand for oil and gas including the COVID-19 pandemic and actions taken by the OPEC + group; 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, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Refer to Headwater’s most recent Annual Information Form dated March 10, 2021, on SEDAR at www.sedar.com, and the risk factors contained therein.

The forward-looking statements contained in this press release are made as of the date hereof and the Company 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.

FUTURE ORIENTED FINANCIAL INFORMATION: Any financial outlook or future oriented financial information in this press release, as defined by applicable securities legislation, has been approved by management of the Company as of the date hereof. Readers are cautioned that any such future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The Company and its management believe that the prospective financial information as to the anticipated results of its proposed business activities for 2021 has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results.

NON-IFRS MEASURES: This document contains the terms “adjusted funds flow from operations”, “field netback”, “operating netback”, “free cash flow”, “adjusted funds flow netback” and “adjusted working capital”, which do not have standardized meanings prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures by other companies. Management uses adjusted funds flow from operations to analyze operating performance and leverage. Adjusted funds flow from operations is calculated as cash flow provided by (used in) operating activities before changes in non-cash working capital and adding back transaction costs. Free cash flow is defined as adjusted funds flow from operations after capital expenditures. Management believes “field netback”, “operating netback” and “adjusted funds flow netback” are useful supplemental measures to consider the profitability of the Company’s operations on a per unit basis and have been calculated in respect of field netback by taking the amount of sales received after royalties and production and blending and transportation costs, in respect of operating netback by taking the amount of sales received after royalties, production, blending and transportation costs and realized gains (losses) on financial derivatives, and in respect of adjusted funds flow netback by taking the amount of sales received after royalties, production, blending and transportation costs, realized gains (losses) on financial derivatives, general and administrative costs, interest income and other (excluding accretion on decommissioning liabilities) and decommissioning liabilities settled. Adjusted working capital is used by the Company to measure liquidity. Adjusted working capital is defined as working capital excluding the effects of the Company’s financial derivatives and warrant liability. Additional information relating to certain of these non-IFRS measures, including the reconciliation between adjusted funds from operations and cash flow from operating activities and working capital and adjusted working capital, can be found in the MD&A.

 BARRELS OF OIL AND CUBIC FEET OF NATURAL GAS EQUIVALENT: The term “boe” (or barrels of oil equivalent) and “Mcf” (or thousand cubic feet of natural gas equivalent) may be misleading, particularly if used in isolation. A boe and Mcf conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Additionally, given that the value ratio based on the current price of crude oil, as compared to natural gas, is significantly different from the energy equivalency of 6:1; utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

 OIL AND GAS METRICS: This press release contains a number of oil and gas metrics, including FD&A and reserves replacement which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.  FD&A costs are used as a measure of capital efficiency.  The calculation includes all capital costs including acquisition costs for that period plus the change in FDC for that period.  This total capital including the change in the FDC is then divided by the change in reserves for that period incorporating all revisions and production for that same period. Total proved FD&A is calculated as follows = ($135,297 thousand + 2,277 thousand + $45,254 thousand) / (9,495 mboe – 3,018 mboe +323 mboe) = $26.89 per boe. Total proved plus probable FD&A is calculated as follows = ($135,297 thousand + 2,277 thousand + $45,309 thousand) / (13,080 mboe – 3,709 mboe +323 mboe) = $18.87 per boe. The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year.