HEADWATER EXPLORATION INC. Financial and Operating Highlights
Three months ended | ||
2021 | 2020 | |
Financial (thousands of dollars except share data) | ||
Sales, net of blending (1) | 23,122 | 2,308 |
Cash flow provided by operating activities | 12,783 | 1,182 |
Per share - basic | 0.07 | 0.01 |
- diluted | 0.07 | 0.01 |
Adjusted funds flow from operations (2) | 14,479 | 5,413 |
Per share - basic | 0.07 | 0.05 |
- diluted | 0.07 | 0.05 |
Net loss | (12,793) | (6,810) |
Per share - basic | (0.07) | (0.06) |
- diluted | (0.07) | (0.06) |
Adjusted net income (loss) (2) | 6,402 | (6,810) |
Per share - basic | 0.03 | (0.06) |
- diluted | 0.03 | (0.06) |
Development capital expenditures | 37,272 | 70 |
Adjusted working capital (2) | 58,367 | 114,200 |
Shareholders' equity | 257,461 | 157,235 |
Weighted average shares (thousands) | ||
Basic | 195,322 | 105,436 |
Diluted | 195,322 | 105,436 |
Shares outstanding, end of period (thousands) | ||
Basic | 195,574 | 144,327 |
Diluted (5) | 240,456 | 145,552 |
Operating (6:1 boe conversion) | ||
Average daily production | ||
Heavy crude oil (bbls/d) | 3,385 | - |
Natural gas (MMcf/d) | 8.5 | 8.9 |
Natural gas liquids (bbls/d) | 5 | 7 |
Barrels of oil equivalent (3) (boe/d) | 4,805 | 1,487 |
Average daily sales (6) (boe/d) | 4,768 | 1,487 |
Netbacks ($/boe) (7) | ||
Operating | ||
Sales, net of blending (1) | 53.89 | 17.06 |
Royalties | (5.49) | (0.42) |
Transportation (1) | (6.04) | - |
Production expense | (5.62) | (4.78) |
Field netback (2) | 36.74 | 11.86 |
Realized gain (loss) on financial derivatives | (1.28) | 29.09 |
Operating netback (2) | 35.46 | 40.95 |
General and administrative expense | (1.97) | (5.05) |
Interest income and other (4) | 0.26 | 4.10 |
Adjusted funds flow netback (2) | 33.75 | 40.00 |
(1) Heavy oil sales are netted with blending expense to compare the realized price to benchmark pricing while transportation expense is shown separately. In the interim condensed financial statements blending is recorded within blending and transportation expense. |
(2) See "Non-IFRS" measures. |
(3) See '"Barrels of Oil Equivalent." |
(4) Excludes accretion on decommissioning liabilities and interest on lease liability. |
(5) Includes in-the-money dilutive instruments as at |
(6) Includes sales of unblended heavy crude oil, natural gas and natural gas liquids. The Company's heavy crude oil sales and production volumes differ due to changes in inventory. |
(7) Netbacks are calculated using average sales volumes. |
FIRST QUARTER 2021 HIGHLIGHTS
- Generated average production of 4,805 boe/d representing an increase of 192% over the fourth quarter of 2020.
- Achieved adjusted funds flow from operations of
$14.5 million ($0.07 per share basic), representing an increase of 201% over the fourth quarter of 2020. - Achieved an operating netback of
$35.46 /boe and an adjusted funds flow netback of$33.75 /boe. - Achieved adjusted net income of
$6.4 million ($0.03 per share basic). - Successfully executed a
$37.3 million exploration and development capital program in theMarten Hills area inclusive of drilling 12, 8-leg multi-lateral producing wells, 5 horizontal injection wells, 2 source water wells and 1 stratigraphic test well. - Executed an agreement with another area operator to construct a joint gas processing facility. The facility is currently under construction and is on track to be commissioned by early
July 2021 . This facility will allow Headwater to achieve gas conservation from production in the core area ofMarten Hills . - The Company's McCully asset performed strongly throughout the quarter contributing
$5.0 million in operating cash flow. Consistent with prior years and to optimize cash flow, Headwater shut-in productionMay 1, 2021 , to await next winter's premium pricing season. Approximately 40% of next winter's volumes are hedged at an average price ofUS$7.39 /mmbtu. - As at
March 31, 2021 , Headwater had adjusted working capital of$58.4 million with no outstanding debt.
Operations Update
During the first quarter, Headwater drilled 12 producing 8-leg horizontal wells. Numerous drilling strategies were tested including changes to drilling mud systems, drill bit design, strategies to improve steering, and techniques to increase penetration rates. Tracer surveys were conducted on several of the producing wells to understand relative contribution from each lateral.
The different strategies employed resulted in a larger variability in the peak 30-day average production per well ("IP 30") than initially anticipated. The IP 30's varied from 205 - 720 bbls/d of oil. A summary of results by section is as follows:
Section | April Producing bbls/d per 8-leg Well | Oil Quality Degree API | # of Laterals | Production per |
26-74-25W4 | 420 | 19 | 32 | 34 - 88 |
23-74-25W4 | 295 | 18 | 16 | 25 - 49 |
35-74-25W4 | 308 | 19 | 16 | 32 - 45 |
27-74-25W4 | 248 | 18 | 32 | 20 - 44 |
The combined learnings from the different drilling strategies employed provide technical clarity and confidence going forward. These will allow Headwater to improve production per lateral during the next phase of planned drilling operations and provide greater certainty on expected returns on capital deployed.
Enhanced Oil Recovery
Headwater commenced water injection into the 4-leg horizontal injector, 02/16-35-74-25W4, on
Exploration Update
Headwater is rapidly moving towards the licensing of eight exploration wells in two prospect areas of Marten Hills. The current budget contemplates drilling four of these tests with a start date in mid-August. Once success is confirmed on the prospects, Headwater will return and drill the remaining four additional delineation wells on these prospects in the fourth quarter of 2021.
Multiple additional exploration prospects in the
Gas Conservation
Facility construction on the joint gas processing facility continues with expected commissioning in early
Guidance Increase
At the end of the first quarter Headwater took steps to prepare for an earlier restart of drilling activities by placing rig mats on three of our existing padsites. The pads have held together very well during the second quarter, resulting in Headwater being optimistic that drilling operations will recommence by early July.
As a result of the success achieved to date, the Board of Directors of Headwater has approved an increase to the Company's 2021 capital expenditure budget and associated production guidance as follows:
Previous | Revised | |
Annual average daily production (boe/d) | 6,500 - 7,000 | 7,000 - 7,250 |
Fourth quarter 2021 daily production (boe/d) | 8,000 - 8,500 | 9,000 - 9,500 |
Capital expenditures ($millions) | 90 - 95 | 105 - 110 |
Exit adjusted working capital ($millions) | 80 | 60 |
The revised budget contemplates that three drilling rigs are expected to spud in early July. The three drilling rigs will initially drill within the core development area. Once access is available into Headwater's exploration lands, one of the rigs will be re-deployed to drill exploration tests in mid-August.
Outlook
Headwater has had an exceptional start to 2021, with the successful execution of the Company's inaugural
Headwater's guiding principles of shareholder value creation, sustainability, asset development with an emphasis on environmental, social, and governance goals, and maintaining a pristine balance sheet continue to be unwavering.
Additional corporate information can be found in our corporate presentation and on our website at www.headwaterexp.com
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, the revised 2021 guidance including expected 2021 annual average production, fourth quarter 2021 average production, expected 2021 capital expenditures and estimated exit adjusted working capital; the expectation that Headwater's learnings from its first quarter 2021 results will provide improvements in production per lateral during the next phase of drilling operations and provide greater certainty on expected returns on capital deployed; the expectation that Headwater's 4-leg horizontal injection has injection capacity in excess of 1,000 bbls/d; expectation of water source availability for waterflood operations; 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; the expectation of significant per share growth; the expectation to restart drilling operations by early
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. The assumptions used in the revised 2021 guidance include: WTI
NON-IFRS MEASURES: This document contains the terms "adjusted funds flow from operations", "adjusted net income", "adjusted working capital", "operating cash flow", "field netback", "operating netback", and "adjusted funds flow netback", 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. Management uses adjusted net income to assess financial performance that is more comparable between periods and is calculated as net income or loss before the remeasurement loss of the warrant liability. 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. Management uses operating cash flow as a measure of the company's efficiency and its ability to fund future capital expenditures and is calculated as sales received after royalties, production, blending and transportation costs and realized gains (losses) on financial derivatives. 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 using unblended sales volumes 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. Additional information relating to certain of these non-IFRS measures, including the reconciliation of cash flow from operating activities to adjusted funds from operations, net income or loss to adjusted net income or loss, working capital to adjusted working capital, and sales to operating cash flow 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.
INITIAL PRODUCTION RATES: References in this press release to initial production rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. Additionally, such rates may also include recovered "load oil" fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, the Company cautions that the test results should be considered to be preliminary.
SOURCE
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