“During the second quarter we took decisive steps to adjust our business model in the face of extremely volatile crude oil markets. We are now starting to benefit from the actions we have taken as we generated positive free cash flow during the quarter and maintained approximately
Q2 2020 Highlights
- Generated production of 72,508 boe/d (81% oil and NGL), consistent with our previously announced guidance range for the second quarter of 72,000 to 73,000 boe/d.
- Delivered adjusted funds flow of
$18 million ($0.03 per basic share). - Realized an operating netback (inclusive of realized financial derivatives gain) of
$8.02 /boe. - Reduced net debt by
$57 million as the Canadian dollar strengthened relative to theU.S. dollar and we generated positive free cash flow of$6 million . - Maintained undrawn credit capacity of
$363 million and liquidity, net of working capital, of approximately$300 million . - Achieved a 15% reduction in our GHG emissions intensity in 2019 and remain committed to our 30% target by the end of 2021.
2020 Outlook
We continue to forecast annual capital spending of
We previously announced voluntary production shut-ins of approximately 25,000 boe/d. These volumes remained off-line for April and May. As operating netbacks improved in June, we initiated plans to bring approximately 80% of these volumes back on-line. At current commodity prices, the resumption of production from these previously shut-in barrels is expected to have a positive impact on our adjusted funds flow and improve our financial liquidity. For the second half of 2020, we currently project about 5,000 boe/d of heavy oil production to remain shut-in.
On
We remain intensely focused on driving further efficiencies to capture or sustain cost reductions identified during this downturn, while protecting the health and safety of our personnel.
Three Months Ended | Six Months Ended | |||||||||||||||||||
2020 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||
FINANCIAL (thousands of Canadian dollars, except per common share amounts) | ||||||||||||||||||||
Petroleum and natural gas sales | $ | 152,689 | $ | 336,614 | $ | 482,000 | $ | 489,303 | $ | 935,424 | ||||||||||
Adjusted funds flow (1) | 17,887 | 132,935 | 236,130 | 150,822 | 456,900 | |||||||||||||||
Per share - basic | 0.03 | 0.24 | 0.42 | 0.27 | 0.82 | |||||||||||||||
Per share - diluted | 0.03 | 0.24 | 0.42 | 0.27 | 0.82 | |||||||||||||||
Net income (loss) | (138,463 | ) | (2,498,217 | ) | 78,826 | (2,636,680 | ) | 90,162 | ||||||||||||
Per share - basic | (0.25 | ) | (4.46 | ) | 0.14 | (4.71 | ) | 0.16 | ||||||||||||
Per share - diluted | (0.25 | ) | (4.46 | ) | 0.14 | (4.71 | ) | 0.16 | ||||||||||||
Capital Expenditures | ||||||||||||||||||||
Exploration and development expenditures (1) | $ | 9,852 | $ | 176,777 | $ | 106,246 | $ | 186,629 | $ | 260,089 | ||||||||||
Acquisitions, net of divestitures | (11 | ) | (40 | ) | 1,647 | (51 | ) | 1,647 | ||||||||||||
Total oil and natural gas capital expenditures | $ | 9,841 | $ | 176,737 | $ | 107,893 | $ | 186,578 | $ | 261,736 | ||||||||||
Net Debt | ||||||||||||||||||||
Bank loan (2) | $ | 704,135 | $ | 678,740 | $ | 414,691 | $ | 704,135 | $ | 414,691 | ||||||||||
Long-term notes (2) | 1,225,395 | 1,270,800 | 1,543,645 | 1,225,395 | 1,543,645 | |||||||||||||||
Long-term debt | 1,929,530 | 1,949,540 | 1,958,336 | 1,929,530 | 1,958,336 | |||||||||||||||
Working capital deficiency | 65,423 | 102,077 | 70,350 | 65,423 | 70,350 | |||||||||||||||
Net debt (1) | $ | 1,994,953 | $ | 2,051,617 | $ | 2,028,686 | $ | 1,994,953 | $ | 2,028,686 | ||||||||||
Shares Outstanding - basic (thousands) | ||||||||||||||||||||
Weighted average | 560,512 | 559,804 | 556,599 | 560,158 | 556,022 | |||||||||||||||
End of period | 560,545 | 560,483 | 556,798 | 560,545 | 556,798 | |||||||||||||||
BENCHMARK PRICES | ||||||||||||||||||||
Crude oil | ||||||||||||||||||||
WTI (US$/bbl) | $ | 27.85 | $ | 46.17 | $ | 59.81 | $ | 37.01 | $ | 57.36 | ||||||||||
MEH oil (US$/bbl) | 26.40 | 49.54 | 66.37 | 37.97 | 63.42 | |||||||||||||||
MEH oil differential to WTI (US$/bbl) | (1.45 | ) | 3.37 | 6.56 | 0.96 | 6.06 | ||||||||||||||
29.85 | 51.43 | 73.84 | 40.64 | 70.19 | ||||||||||||||||
(6.31 | ) | (7.92 | ) | (4.61 | ) | (7.24 | ) | (4.72 | ) | |||||||||||
WCS heavy oil ($/bbl) | 22.70 | 34.48 | 65.73 | 28.68 | 61.17 | |||||||||||||||
WCS differential to WTI (US$/bbl) | (11.47 | ) | (20.53 | ) | (10.68 | ) | (16.00 | ) | (11.48 | ) | ||||||||||
Natural gas | ||||||||||||||||||||
NYMEX (US$/mmbtu) | $ | 1.72 | $ | 1.95 | $ | 2.64 | $ | 1.83 | $ | 2.89 | ||||||||||
AECO ($/mcf) | 1.91 | 2.14 | 1.17 | 2.03 | 1.56 | |||||||||||||||
CAD/USD average exchange rate | 1.3860 | 1.3445 | 1.3376 | 1.3653 | 1.3334 |
Three Months Ended | Six Months Ended | |||||||||||||||||||
2020 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||
OPERATING | ||||||||||||||||||||
Daily Production | ||||||||||||||||||||
Light oil and condensate (bbl/d) | 38,951 | 45,717 | 42,585 | 42,333 | 43,809 | |||||||||||||||
Heavy oil (bbl/d) | 11,832 | 28,854 | 27,320 | 20,343 | 27,107 | |||||||||||||||
NGL (bbl/d) | 7,634 | 7,822 | 10,986 | 7,728 | 11,356 | |||||||||||||||
Total liquids (bbl/d) | 58,417 | 82,393 | 80,891 | 70,404 | 82,272 | |||||||||||||||
Natural gas (mcf/d) | 84,546 | 96,356 | 105,065 | 90,451 | 104,874 | |||||||||||||||
Oil equivalent (boe/d @ 6:1) (3) | 72,508 | 98,452 | 98,402 | 85,479 | 99,751 | |||||||||||||||
Netback (thousands of Canadian dollars) | ||||||||||||||||||||
Total sales, net of blending and other expense (4) | $ | 147,229 | $ | 315,257 | $ | 461,110 | $ | 462,486 | $ | 897,746 | ||||||||||
Royalties | (29,156 | ) | (56,720 | ) | (86,617 | ) | (85,876 | ) | (167,942 | ) | ||||||||||
Operating expense | (73,680 | ) | (104,470 | ) | (100,474 | ) | (178,150 | ) | (200,766 | ) | ||||||||||
Transportation expense | (5,031 | ) | (10,342 | ) | (11,869 | ) | (15,373 | ) | (25,199 | ) | ||||||||||
Operating netback (1) | $ | 39,362 | $ | 143,725 | $ | 262,150 | $ | 183,087 | $ | 503,839 | ||||||||||
General and administrative | (7,438 | ) | (9,775 | ) | (11,506 | ) | (17,213 | ) | (25,642 | ) | ||||||||||
Cash financing and interest | (27,387 | ) | (28,535 | ) | (28,092 | ) | (55,922 | ) | (56,276 | ) | ||||||||||
Realized financial derivatives gain | 13,624 | 26,850 | 12,993 | 40,474 | 31,807 | |||||||||||||||
Other (5) | (274 | ) | 670 | 585 | 396 | 3,172 | ||||||||||||||
Adjusted funds flow (1) | $ | 17,887 | $ | 132,935 | $ | 236,130 | $ | 150,822 | $ | 456,900 | ||||||||||
Netback (per boe) | ||||||||||||||||||||
Total sales, net of blending and other expense (4) | $ | 22.31 | $ | 35.19 | $ | 51.49 | $ | 29.73 | $ | 49.72 | ||||||||||
Royalties | (4.42 | ) | (6.33 | ) | (9.67 | ) | (5.52 | ) | (9.30 | ) | ||||||||||
Operating expense | (11.17 | ) | (11.66 | ) | (11.22 | ) | (11.45 | ) | (11.12 | ) | ||||||||||
Transportation expense | (0.76 | ) | (1.15 | ) | (1.33 | ) | (0.99 | ) | (1.40 | ) | ||||||||||
Operating netback (1) | $ | 5.96 | $ | 16.05 | $ | 29.27 | $ | 11.77 | $ | 27.90 | ||||||||||
General and administrative | (1.13 | ) | (1.09 | ) | (1.28 | ) | (1.11 | ) | (1.42 | ) | ||||||||||
Cash financing and interest | (4.15 | ) | (3.19 | ) | (3.14 | ) | (3.59 | ) | (3.12 | ) | ||||||||||
Realized financial derivatives gain | 2.06 | 3.00 | 1.45 | 2.60 | 1.76 | |||||||||||||||
Other (5) | (0.03 | ) | 0.07 | 0.07 | 0.02 | 0.19 | ||||||||||||||
Adjusted funds flow (1) | $ | 2.71 | $ | 14.84 | $ | 26.37 | $ | 9.69 | $ | 25.31 |
Notes:
- The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. See the advisory on non-GAAP measures at the end of this press release.
- Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of capital or repayment obligations.
- Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
- Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
- Other is comprised of realized foreign exchange gain or loss, other income or expense, and current income tax expense or recovery. Refer to the Q2/2020 MD&A for further information on these amounts.
Q2/2020 Results
During the second quarter we took decisive steps to adjust our business plan in the face of extremely volatile crude oil markets. In addition to voluntarily shutting-in production, we suspended drilling operations in
Production during the second quarter averaged 72,508 boe/d (81% oil and NGL), as compared to 98,452 boe/d (83% oil and NGL) in Q1/2020. Production in
We delivered adjusted funds flow of
We continue to emphasize cost reductions across all facets of our organization. We have identified approximately
In the Eagle Ford, strong well performance continued across our acreage position. In Q2/2020, we commenced production from 17 (4.6 net) wells. These wells were brought on-stream in April and generated an average 30-day initial production rate of approximately 1,550 boe/d per well. We expect to bring approximately 16 to 18 net wells on production in the Eagle Ford in 2020, down from our original guidance of 22 net wells.
Production in the Viking averaged 19,717 boe/d (90% oil and NGL) during Q2/2020, as compared to 24,696 boe/d in Q1/2020. The quarterly impact of voluntary shut-ins in the Viking was approximately 2,000 boe/d. As operating netbacks improved in June, these volumes were brought back on-line. We suspended all drilling in the Viking, and as such, there was limited activity during the second quarter. In the first half of 2020, we invested
Heavy Oil
Our heavy oil assets at
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 717 boe/d (85% oil and NGL) during Q2/2020, as compared to 1,717 boe/d in Q1/2020. The quarterly impact of voluntary shut-ins for the Pembina Duvernay was approximately 1,000 boe/d. As operating netbacks improved in June, these volumes were brought back on-line.
In Q1/2020, we drilled two wells in the core of our Pembina acreage, bringing total wells drilled to nine in this area. Completion activities, originally scheduled for Q2/2020 have been deferred.
Financial Liquidity
Our credit facilities total approximately
Our net debt, which includes our bank loan, long-term notes and working capital, totaled
Note:
- 2020 full year pricing assumptions: WTI -
US$39 /bbl; WCS differential -US$14 /bbl; MSW differential –US$6 /bbl,NYMEX Gas -US$1.90 /mcf;AECO Gas -$2.05 /mcf and Exchange Rate (CAD/USD) - 1.36. 2021 full year pricing assumptions: WTI -US$41 /bbl; WCS differential -US$15 /bbl; MSW differential –US$7 /bbl,NYMEX Gas -US$2.60 /mcf;AECO Gas -$2.35 /mcf and Exchange Rate (CAD/USD) - 1.36.
Financial Covenants
The following table summarizes the financial covenants applicable to the credit facilities and Baytex's compliance therewith as at
Covenant Description | Position as at | Covenant |
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio) | 1.0:1.0 | 3.5:1.0 |
Interest Coverage(3) (Minimum Ratio) | 6.6:1.0 | 2.0:1.0 |
Notes:
- Senior Secured Debt is defined as the principal amount of the credit facilities and other secured obligations identified in the credit agreement. As at
June 30, 2020 , the Company's Senior Secured Debt totaled$719.9 million which includes$704.1 million of principal amounts outstanding and$15.8 million of letters of credit. - Bank EBITDA is calculated based on terms and definitions set out in the credit agreement which adjusts net income or loss for financing and interest expense, income tax, non-recurring losses, certain specific unrealized and non-cash transactions (including depletion, depreciation, exploration and evaluation expense, impairment, deferred income tax expense or recovery, unrealized gains and losses on financial derivatives and foreign exchange and share-based compensation) and is calculated based on a trailing twelve month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended
June 30, 2020 was$704.4 million . - Interest coverage is computed as the ratio of Bank EBITDA to financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, and is calculated on a trailing twelve month basis. Financing and interest expense, excluding accretion of debt issue costs and asset retirement obligations, for the twelve months ended
June 30, 2020 was$106.5 million .
Risk Management
To manage commodity price movements, we utilize various financial derivative contracts and crude-by-rail to reduce the volatility of our adjusted funds flow. The following table summarizes our crude oil hedges in place.
Q3/2020 | Q4/2020 | 2021 | ||||
WTI Fixed Hedges | ||||||
Volumes (bbl/d) | 23,732 | 8,000 | --- | |||
Fixed Price (US$/bbl) | --- | |||||
WTI 3-Way Option (1) | ||||||
Volumes (bbl/d) | 24,500 | 24,500 | 5,000 | |||
Baytex Receives (2) (3) (4) | WTI plus | WTI plus | ||||
Total Volumes (bbl/d) | 48,232 | 32,500 | 5,000 | |||
Notes:
- WTI 3-way options consist of a sold put, a bought put and a sold call. Baytex’s average sold put, bought put and sold call for Q3/2020 and Q4/2020 are
US$50.44 /bbl,US$58.04 /bbl andUS$63.06 /bbl, respectively. Baytex’s average sold put, bought put and sold call for 2021 areUS$35 /bbl,US$45 /bbl andUS$55 /bbl, respectively. - For Q3/2020 and Q4/2020, Baytex receives WTI plus
US$7.60 /bbl when WTI is at or belowUS$50.44 /bbl; Baytex receivesUS$58.04 /bbl when WTI is betweenUS$50.44 /bbl andUS$58.04 /bbl; Baytex receives WTI when WTI is betweenUS$58.04 /bbl andUS$63.06 /bbl; and Baytex receivesUS$63.06 /bbl when WTI is aboveUS$63.06 /bbl. - For 2021, Baytex receives WTI plus
US$10 /bbl when WTI is at or belowUS$35 /bbl; Baytex receivesUS$45 /bbl when WTI is betweenUS$35 /bbl andUS$45 /bbl; Baytex receives WTI when WTI is betweenUS$45 /bbl andUS$55 /bbl; and Baytex receivesUS$55 /bbl when WTI is aboveUS$55 /bbl. - Based on the forward strip for the balance of 2020, Baytex will receive WTI plus
US$7.60 /bbl. Based on the forward strip for 2021, Baytex will receiveUS$45 /bbl.
For the remainder of 2020, we also have WTI-MSW basis differential swaps for 7,783 bbl/d of our light oil production in
Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For Q2/2020, we delivered approximately 5,250 bbl/d of our heavy oil volumes to market by rail.
A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2020 financial statements.
Sustainability
We are committed to managing the environmental and social impacts of our business and continual improvement is an important element of this commitment. In 2019, Baytex established for the first time a GHG emissions reduction target. Our objective is to reduce our corporate GHG emission intensity (tonnes of CO2 per boe) by 30% by 2021, relative to our 2018 baseline.
In 2019, we made significant improvements in our emissions profile, achieving a 15% reduction in our GHG emissions intensity as we commissioned our
2020 Guidance
There is no change to our guidance announced
2020 Guidance | ||
Exploration and development expenditures | ||
Production (boe/d) | 78,000 - 82,000 | |
Expenses: | ||
Royalty rate | ~ 18.5% | |
Operating | ||
Transportation | ||
General and administrative | ||
Interest | ||
Leasing expenditures | ||
Asset retirement obligations |
Additional Information
Our condensed consolidated interim unaudited financial statements for the three and six months ended
Conference Call Tomorrow | ||
Baytex will host a conference call tomorrow, An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com. |
Advisory Regarding Forward-Looking Statements
In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "believe", "continue", ""estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.
Specifically, this press release contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; restarted shut-in volumes will have a positive impact on our adjusted funds flow; that the resumption of production from shut-in barrels is expected to positively impact adjusted funds flow and improve financial liquidity; our ability to re-start shut in wells or shut-in additional volumes; we expect 5,000 boe/d of heavy oil to remain shut-in for H2/2020; we are focused on further efficiencies to capture or sustain cost reduction while protecting the health and safety of our personnel; that we have identified
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural gas prices and price differentials (including the impacts of COVID-19); availability and cost of gathering, processing and pipeline systems; failure to comply with the covenants in our debt agreements; the availability and cost of capital or borrowing; that our credit facilities may not provide sufficient liquidity or may not be renewed; risks associated with a third-party operating our
These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
Non-GAAP Financial and Capital Management Measures
In this news release, we refer to certain financial measures (such as adjusted funds flow, exploration and development expenditures, free cash flow, net debt and operating netback) which do not have any standardized meaning prescribed by Canadian GAAP (“non-GAAP measures”) and are considered non-GAAP measures. While adjusted funds flow, exploration and development expenditures, free cash flow, net debt and operating netback are commonly used in the oil and gas industry, our determination of these measures may not be comparable with calculations of similar measures for other issuers.
Adjusted funds flow is not a measurement based on generally accepted accounting principles ("GAAP") in
In addition, we use a ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period to period depending on our capital programs and the maturity of our operating areas. The settlement of abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. Changes in non-cash working capital are eliminated in the determination of adjusted funds flow as the timing of collection, payment and incurrence is variable and by excluding them from the calculation we are able to provide a more meaningful measure of our cash flow on a continuing basis. For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three and six months ended
Exploration and development expenditures is not a measurement based on GAAP in
Free cash flow is not a measurement based on GAAP in
Net debt is not a measurement based on GAAP in
Operating netback is not a measurement based on GAAP in
Advisory Regarding Oil and Gas Information
Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
References herein to average 30-day initial production rates and other short-term production rates 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. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the assets for which such rates are provided. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.
Throughout this news release, “oil and NGL” refers to heavy oil, bitumen, light and medium oil, tight oil, condensate and natural gas liquids (“NGL”) product types as defined by NI 51-101. The following table shows Baytex’s disaggregated production volumes for the three and six months ended
Three Months Ended | Six Months Ended | ||||||||||
Heavy Oil (bbl/d) | Light and Medium Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | Heavy Oil (bbl/d) | Light and Medium Oil (bbl/d) | NGL (bbl/d) | Natural Gas (Mcf/d) | Oil Equivalent (boe/d) | ||
4,735 | 6 | 15 | 6,278 | 5,802 | 9,377 | 7 | 14 | 9,450 | 10,973 | ||
7,098 | 10 | — | 1,039 | 7,281 | 10,966 | 14 | — | 1,160 | 11,174 | ||
Viking | — | 17,735 | 105 | 11,267 | 19,717 | — | 20,110 | 109 | 11,925 | 22,206 | |
— | 430 | 176 | 670 | 717 | — | 680 | 348 | 1,381 | 1,258 | ||
Remaining Properties | — | 581 | 638 | 17,728 | 4,174 | — | 690 | 654 | 18,124 | 4,365 | |
— | 20,189 | 6,701 | 47,564 | 34,817 | — | 20,832 | 6,603 | 48,410 | 35,503 | ||
Total | 11,832 | 38,951 | 7,634 | 84,546 | 72,508 | 20,343 | 42,333 | 7,728 | 90,451 | 85,479 |
For further information about Baytex, please visit our website at www.baytexenergy.com or contact:
Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com
Source:
2020 GlobeNewswire, Inc., source