HIGHLIGHTS
- Sales volumes averaged 80,540 Boe/d (43% liquids) in the first quarter of 2021, well ahead of the Company's first half 2021 production guidance of 74,000 Boe/d to 76,000 Boe/d (43% liquids) due to significant outperformance at Karr as well as higher than expected field reliability corporately. (1)
- Sales volumes at Karr averaged 33,230 Boe/d (55% liquids) in the quarter compared to 26,914 Boe/d (56% liquids) in the fourth quarter of 2020.
- This increase was driven by strong performance from the six well 3-10 pad that was brought onstream in February and the five well 5-16 West pad that was brought onstream in the fourth quarter of 2020, as well as workovers on the 16-4 pad that were completed in the fourth quarter of 2020.
Paramount achieved an important milestone at Karr, with first quarter exit sales volumes exceeding targeted plateau production of 40,000 Boe/d for the first time and March sales volumes averaging 39,938 Boe/d (53% liquids).Paramount estimates that 12 to 16 new wells per year will be required to maintain plateau production.- At plateau production of 40,000 Boe/d, annual asset level free cash flow at Karr would be
$260 million to$290 million . (2) - Sales volumes at Wapiti averaged 14,107 Boe/d (62% liquids) in the quarter compared to 10,764 Boe/d (64% liquids) in the fourth quarter of 2020. The 31% increase in sales volumes was primarily due to new well production from the 5-3 West pad that was brought onstream partway through the fourth quarter.
________________________________________ | |
(1) | In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane combined. See the Product Type Information section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section. |
(2) | "Asset level free cash flow" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section. Stated amounts are illustrative assuming Karr per-unit netbacks of |
- First quarter capital spending totaled
$59.3 million , which was focused on drilling and completion activities at Karr and Wapiti. - All-in lease construction, drilling, completion, equip and tie-in (collectively "DCET") costs for the six well Karr 3-10 pad averaged a pacesetting
$6.8 million per well,$0.2 million lower per well than prior estimates and representing a 12% reduction relative to average DCET costs for Karr wells in 2020. - Preliminary DCET costs at the three well Karr 4-28 pad, which was brought on production in late
April 2021 , were$6.9 million per well. Paramount's continued focus on strong execution, cost control and innovation has contributed to anticipated cost savings of$30 million in the Company's 2021 capital program.- Abandonment and reclamation expenditures in the first quarter totaled
$8.4 million , net of$1.7 million in funding under the Alberta Site Rehabilitation Program. Activities included the abandonment of 120 wells, 119 of which were abandoned under the Company's ongoing area-based closure program atZama . - Cash from operating activities was
$81.3 million in the first quarter. Adjusted funds flow was$90.9 million or$0.69 per share. (1) Paramount generated$23.2 million of free cash flow in the first quarter that, along with approximately$80 million in cash proceeds from non-core dispositions, was directed to debt reduction. (1)- Free cash flow in 2021 is expected to be directed towards debt reduction, with anticipated year-end 2021 net debt to adjusted funds flow of less than 1.5x.(1)
______________________________ | |
(1) | "Adjusted funds flow", "free cash flow" and "net debt to adjusted funds flow" are Non-GAAP financial measures. See "Non-GAAP Financial Measures" in the Advisories section. |
NON-CORE ASSET DISPOSITION
REVISED 2021 GUIDANCE
Second quarter 2021 sales volumes are expected to average between 77,000 Boe/d and 78,000 Boe/d (42% liquids). Second half 2021 sales volumes guidance remains unchanged at between 80,000 Boe/d and 84,000 Boe/d (45% liquids) notwithstanding the Birch Disposition.
The Company will be advancing approximately
Inclusive of the increased capital at Wapiti,
Approximately 52% of forecast midpoint production is hedged over the final three quarters of 2021. After taking such hedging into account, 2021 forecast free cash flow would still be approximately
The Company targets net debt to adjusted funds flow of between 1.0x and 2.0x. Free cash flow in 2021 is expected to be directed towards debt reduction, with anticipated year-end net debt to adjusted funds flow of less than 1.5x. The Company currently prioritizes the allocation of free cash flow to: (i) achieving the targeted range of net debt to adjusted funds flow; (ii) shareholder returns; and (iii) incremental growth.
PRELIMINARY 2022 GUIDANCE
$250 million of sustaining capital and maintenance activities;$75 million of growth capital with production benefits in 2022; and$60 million of discretionary growth capital with production benefits largely in 2023.
A capital program in this range would be expected to result in 2022 annual average sales volumes of between 84,000 Boe/d and 88,000 Boe/d (45% liquids) and free cash flow of approximately
CORPORATE
The Company successfully closed non-core asset dispositions for cash proceeds of approximately
In
The Company has engaged an outside engineering firm and is working with
REVIEW OF OPERATIONS
Q1 2021 | Q4 2020 | %Change | |||
Sales volumes | |||||
Natural gas (MMcf/d) | 122.6 | 94.3 | 30 | ||
Condensate and oil (Bbl/d) | 23,974 | 19,635 | 22 | ||
Other NGLs (Bbl/d) | 2,984 | 2,429 | 23 | ||
Total (Boe/d) | 47,385 | 37,782 | 25 | ||
% liquids | 57% | 58% | |||
Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | % Change in $ |
Petroleum and natural gas sales | 194.0 | 45.50 | 125.1 | 36.00 | 55 |
Royalties | (11.6) | (2.72) | (6.2) | (1.78) | 87 |
Operating expense | (49.0) | (11.49) | (42.4) | (12.20) | 16 |
Transportation and NGLs processing | (20.0) | (4.69) | (14.2) | (4.07) | 41 |
113.4 | 26.60 | 62.3 | 17.95 | 82 |
________________________________ | |
(1) | "Netback" is a Non-GAAP financial measure. See "Non-GAAP Financial Measures" in the Advisories section. |
Karr sales volumes and netbacks are summarized below:
Q1 2021 | Q4 2020 | % Change | |||
Sales volumes | |||||
Natural gas (MMcf/d) | 90.2 | 70.5 | 28 | ||
Condensate and oil (Bbl/d) | 16,095 | 13,348 | 21 | ||
Other NGLs (Bbl/d) | 2,108 | 1,817 | 16 | ||
Total (Boe/d) | 33,230 | 26,914 | 23 | ||
% liquids | 55% | 56% | |||
Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | % Change in $ |
Petroleum and natural gas sales | 132.5 | 44.31 | 86.1 | 34.79 | 54 |
Royalties | (8.6) | (2.89) | (4.6) | (1.87) | 87 |
Operating expense | (31.9) | (10.67) | (27.8) | (11.24) | 15 |
Transportation and NGLs processing | (14.0) | (4.68) | (10.5) | (4.26) | 33 |
78.0 | 26.07 | 43.2 | 17.42 | 81 |
First quarter sales volumes at Karr averaged 33,230 Boe/d (55% liquids) compared to 26,914 Boe/d (56% liquids) in the fourth quarter of 2020. Sales volumes increased as a result of new well production that came onstream in the first quarter and from a full quarter of production from wells that came onstream in the fourth quarter of 2020. Incremental production from existing wells following workovers in the fourth quarter of 2020 also contributed to the overall increase.
The 3-10 pad has continued to outperform internal type well projections, averaging gross peak 30-day production per well of 2,068 Boe/d (6.0 MMcf/d of shale gas and 1,073 Bbl/d of NGLs) with an average CGR of 180 Bbl/MMcf.(1) Likewise, production at the five well 5-16 West pad that came onstream in
Three new
Additional gas lift compression was recently installed to support base and incremental production in the area. The Company anticipates base production up-lift at a number of pads that had been impacted by insufficient lift gas supply.
Per unit operating costs trended lower as a result of higher production volumes combined with a continued focus on cost reduction initiatives. The Company achieved per unit operating costs of
Drilling operations at the five well 7-18 pad were completed in the first quarter under budget and included one new pacesetter well, drilling an average 313 meters per day.
Production in the second quarter will be impacted by scheduled curtailments at the third-party Karr 6-18 facility related to inlet separation and liquids handling optimization. The curtailments are anticipated to reduce sales volumes by approximately 50% for seven days in May.
_________________________________________ | |
(1) | Production measured at the wellhead. Natural gas sales volumes are lower by approximately 7% and liquids sales volumes are lower by approximately 7% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section. |
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
Q1 2021 | Q4 2020 | % Change | |||
Sales volumes | |||||
Natural gas (MMcf/d) | 32.1 | 23.3 | 38 | ||
Condensate and oil (Bbl/d) | 7,884 | 6,286 | 25 | ||
Other NGLs (Bbl/d) | 867 | 589 | 47 | ||
Total (Boe/d) | 14,107 | 10,764 | 31 | ||
% liquids | 62% | 64% | |||
Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | % Change in $ |
Petroleum and natural gas sales | 61.4 | 48.42 | 38.9 | 39.30 | 58 |
Royalties | (2.9) | (2.32) | (1.6) | (1.58) | 81 |
Operating expense | (16.8) | (13.25) | (14.2) | (14.36) | 18 |
Transportation and NGLs processing | (6.0) | (4.73) | (3.6) | (3.62) | 67 |
35.7 | 28.12 | 19.5 | 19.74 | 83 |
First quarter sales volumes at Wapiti averaged 14,107 Boe/d (62% liquids), 3,343 Boe/d higher than in the fourth quarter of 2020 primarily due to new well production from the 5-3 West pad that was brought onstream partway through the fourth quarter.
Drilling operations were completed at the seven well 6-4 pad in the first quarter,
In the first quarter
The 2021 capital program at Wapiti is being expanded to bring forward activities by approximately six months to advance the next major phase of development. Activities include drilling, completing and bringing onstream the seven well 9-22 pad, the tie-in of a pre-existing well from the 10-22 pad and the installation of associated infrastructure. Initial production from these activities is anticipated to come onstream in
KAYBOB REGION
The Company holds a material, contiguous
HEDGING
The Company's commodity hedging position at
- Natural Gas:
April – December 2021 60,000 MMBtu/d atUS$2.71 /MMBtu
April – October 2021 50,000 GJ/d atCDN$2.52 /GJ
April – December 2021 50,000 GJ/d atCDN$2.51 /GJ
- Oil:
April – June 2021 23,000 Bbl/d atUS$46.93 /Bbl
July – September 2021 15,000 Bbl/d atUS$45.87 /Bbl
October – December 2021 10,000 Bbl/d atUS$45.82 /Bbl
April – September 2021 3,000 Bbl/d atCDN$65.29 /Bbl
The Company has also hedged the differential on 4,000 Bbl/d of condensate at
Further details of
ABOUT
https://mma.prnewswire.com/media/1503692/Paramount_Resources_Ltd_Announces_Q1_2021_Results.pdf . A summary of historical financial and operating results is also available on
This information will also be made available through
FINANCIAL AND OPERATING RESULTS (1) ($ millions, except as noted) | ||||||||
Q1 2021 | Q4 2020 | |||||||
Net income (loss) | (82.5) | 311.5 | ||||||
per share – basic and diluted ($/share) | (0.62) | 2.35 | ||||||
Cash from operating activities | 81.3 | 53.2 | ||||||
per share – basic and diluted ($/share) | 0.61 | 0.40 | ||||||
Adjusted funds flow | 90.9 | 67.9 | ||||||
per share – basic and diluted ($/share) | 0.69 | 0.51 | ||||||
Total assets | 3,583.1 | 3,497.0 | ||||||
Long-term debt | 712.7 | 813.5 | ||||||
Net debt | 761.7 | 854.1 | ||||||
Common shares outstanding (thousands)(2) | 132,754 | 132,284 | ||||||
Sales volumes | ||||||||
Natural gas (MMcf/d) | 273.1 | 256.3 | ||||||
Condensate and oil (Bbl/d) | 29,854 | 25,752 | ||||||
Other NGLs (Bbl/d) (3) | 5,170 | 4,987 | ||||||
Total (Boe/d) | 80,540 | 73,460 | ||||||
% liquids | 43% | 42% | ||||||
47,385 | 37,782 | |||||||
24,938 | 27,056 | |||||||
8,217 | 8,622 | |||||||
Total (Boe/d) | 80,540 | 73,460 | ||||||
Netback | $/Boe (4) | $/Boe (4) | ||||||
Natural gas revenue | 77.3 | 3.14 | 66.7 | 2.83 | ||||
Condensate and oil revenue | 185.9 | 69.20 | 123.3 | 52.03 | ||||
Other NGLs revenue (3) | 15.0 | 32.29 | 9.5 | 20.61 | ||||
Royalty and other revenue | 1.7 | ─ | 2.5 | ─ | ||||
Petroleum and natural gas sales | 279.9 | 38.61 | 202.0 | 29.89 | ||||
Royalties | (18.6) | (2.57) | (11.7) | (1.73) | ||||
Operating expense | (84.3) | (11.63) | (79.8) | (11.80) | ||||
Transportation and NGLs processing (5) | (27.9) | (3.84) | (24.6) | (3.63) | ||||
Netback | 149.1 | 20.57 | 85.9 | 12.73 | ||||
Financial commodity contract settlements | (32.7) | (4.51) | 7.9 | 1.18 | ||||
Netback including financial commodity contract settlements | 116.4 | 16.06 | 93.8 | 13.91 | ||||
Total Capital Expenditures | ||||||||
51.3 | 64.3 | |||||||
5.0 | 1.8 | |||||||
1.2 | 0.8 | |||||||
Corporate (6) | 1.8 | (1.8) | ||||||
Total capital expenditures | 59.3 | 65.1 | ||||||
Asset retirement obligation settlements | 8.4 | 0.1 |
(1) | Readers are referred to the advisories concerning Non-GAAP Financial Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP financial measures: Adjusted funds flow, Net debt, Netback and Total capital expenditures. Readers are referred to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product types. | ||||||||
(2) | Common shares are presented net of shares held in trust under the Company's restricted share unit plan (000's of common shares): Q1 2021: 1,914 and Q4 2020: 1,914. | ||||||||
(3) | Other NGLs means ethane, propane and butane. | ||||||||
(4) | Natural gas revenue presented as $/Mcf. | ||||||||
(5) | Includes downstream transportation costs and NGLs fractionation costs. | ||||||||
(6) | Includes transfers between regions. |
PRODUCT TYPE INFORMATION
This press release refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". "Liquids" means NGLs (including condensate) and oil combined, "natural gas" refers to conventional natural gas and shale gas combined, "condensate and oil" refers to condensate, light and medium crude oil and tight oil combined and "other NGLs" refers to ethane, propane and butane combined. Below is a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. Numbers may not add due to rounding.
Total |
| Kabob |
| |||||
Q1 2021 | Q4 2020 | Q1 2021 | Q4 2020 | Q1 2021 | Q4 2020 | Q1 2021 | Q4 2020 | |
Shale gas (MMcf/d) | 197.8 | 170.7 | 120.6 | 92.7 | 42.1 | 41.9 | 35.1 | 36.1 |
Conventional natural gas (MMcf/d) | 75.3 | 85.6 | 2.0 | 1.6 | 65.8 | 76.3 | 7.5 | 7.7 |
Natural gas (MMcf/d) | 273.1 | 256.3 | 122.6 | 94.3 | 107.9 | 118.2 | 42.6 | 43.8 |
Condensate (Bbl/d) | 27,017 | 22,782 | 23,974 | 19,635 | 2,611 | 2,631 | 433 | 515 |
Other NGLs (Bbl/d) | 5,170 | 4,987 | 2,984 | 2,429 | 1,677 | 1,953 | 509 | 605 |
NGLs (Bbl/d) | 32,187 | 27,769 | 26,958 | 22,064 | 4,288 | 4,584 | 942 | 1,120 |
Tight oil (Bbl/d) | 479 | 437 | – | – | 342 | 299 | 136 | 138 |
Light and Medium crude oil (Bbl/d) | 2,358 | 2,533 | – | – | 2,321 | 2,480 | 37 | 54 |
Crude oil (Bbl/d) | 2,837 | 2,970 | – | – | 2,663 | 2,779 | 173 | 192 |
Total (Boe/d) | 80,540 | 73,460 | 47,385 | 37,782 | 24,938 | 27,056 | 8,217 | 8,622 |
Karr | Wapiti | |||
Q1 2021 | Q4 2020 | Q1 2021 | Q4 2020 | |
Shale gas (MMcf/d) | 89.1 | 69.6 | 31.5 | 22.8 |
Conventional natural gas (MMcf/d) | 1.1 | 0.9 | 0.6 | 0.5 |
Natural gas (MMcf/d) | 90.2 | 70.5 | 32.1 | 23.3 |
NGLs (Bbl/d) | 18,203 | 15,165 | 8,751 | 6,875 |
Total (Boe/d) | 33,230 | 26,914 | 14,107 | 10,764 |
The Company forecasts that 2021 sales volumes will average between 80,000 Boe/d and 82,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second quarter 2021 sales volumes are expected to average between 77,000 Boe/d and 78,000 Boe/d (58% shale gas and conventional natural gas combined, 36% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2021 sales volumes are expected to average between 80,000 Boe/d and 84,000 Boe/d (55% shale gas and conventional natural gas combined, 39% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).
ADVISORIES
Forward-looking Information
Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:
- the estimated number of wells required per year to maintain plateau production at Karr;
- illustrative asset level free cash flow at Karr at plateau production;
- anticipated cost savings in the Company's 2021 capital program;
- the anticipated closing of the Birch Disposition;
- forecast sales volumes for 2021 and certain periods therein;
- forecast free cash flow in 2021;
- planned capital expenditures in 2021;
- planned abandonment and reclamation expenditures in 2021;
- the Company's expectation that 2021 free cash flow will be directed towards debt reduction;
- forecast 2021 year-end net debt to annual adjusted funds flow;
- preliminary anticipated capital expenditures in 2022 and the resulting expected 2022 average sales volumes, free cash flow and year-end net debt to adjusted funds flow;
- planned exploration, development and production activities, including the expected timing of completing and bringing new wells on production;
- scheduled facility curtailments at Karr and the anticipated impact thereof;
- anticipated operating costs;
- the expected benefits of monobore drilling techniques; and
- the expected benefits of additional gas lift compression at Karr and new gas lift infrastructure at Wapiti.
Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:
- future commodity prices and the potential impact of the COVID-19 pandemic thereon;
- the likely impact of the COVID-19 pandemic on operations;
- the satisfaction of the conditions to closing of the Birch Disposition;
- the ability to realize expected cost savings;
- royalty rates, taxes and capital, operating, processing, transportation, general & administrative and other costs;
- foreign currency exchange rates and interest rates;
- general business, economic and market conditions;
- the ability of
Paramount to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations; - the ability of
Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities; - the ability of
Paramount to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities; - the ability of
Paramount to market its production successfully to current and new customers; - the ability of
Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations; - the timely receipt of required governmental and regulatory approvals;
- the receipt of benefits under government programs;
- the application of regulatory requirements respecting abandonment and reclamation; and
- anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance).
Although
- fluctuations in commodity prices, including in relation to the impact of the COVID-19 pandemic;
- the failure to satisfy the conditions to closing of the Birch Disposition;
- changes in capital spending plans and planned exploration and development activities;
- the potential for changes to preliminary anticipated 2022 capital expenditures prior to finalization and changes to the resulting expected 2022 average sales volumes, free cash flow and year-end net debt to adjusted funds flow;
- changes in foreign currency exchange rates and interest rates;
- the uncertainty of estimates and projections relating to future revenue, free cash flow, production, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
- the ability to secure adequate product processing, transportation, fractionation, and storage capacity on acceptable terms;
- operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
- the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost;
- potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);
- processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
- risks and uncertainties involving the geology of oil and gas deposits;
- the uncertainty of reserves estimates;
- general business, economic and market conditions;
- the ability to generate sufficient cash from operating activities and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations);
- changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
- the ability to obtain required governmental or regulatory approvals in a timely manner, and to enter into and maintain leases and licenses;
- the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
- the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
- uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders;
- the outcome of existing and potential lawsuits, insurance claims, regulatory actions, audits and assessments; and
- other risks and uncertainties described elsewhere in this document and in
Paramount's other filings with Canadian securities authorities.
The foregoing list of risks is not exhaustive. For more information relating to risks, see the sections titled "Risk Factors" in
Certain forward-looking information in this press release, including forecast free cash flow in 2021 and forecast 2021 year-end net debt to annual adjusted funds flow, may also constitute a "financial outlook" within the meaning of applicable securities laws. A financial outlook involves statements about
Non-GAAP Financial Measures
In this press release, "adjusted funds flow", "asset level free cash flow", "free cash flow", "netback", "net debt", "net debt to adjusted funds flow" and "total capital expenditures", together the "Non-GAAP financial measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards. Certain comparative figures have been reclassified to conform to the current years' presentation.
"Adjusted funds flow" refers to cash from operating activities before net changes in non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements and provision. Adjusted funds flow is used to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company.
Three months ended | March 31, 2021 (MM$) | (MM$) | ||
Cash from operating activities | 81.3 | 53.2 | ||
Change in non-cash working capital | (7.9) | 12.5 | ||
Geological and geophysical expenses | 1.6 | 2.1 | ||
Asset retirement obligations settled | 8.4 | 0.1 | ||
Provision | 7.5 | – | ||
Adjusted funds flow | 90.9 | 67.9 |
"Asset level free cash flow" refers to aggregate netback from an asset during the period less capital expenditures with respect to such asset for the period. Asset level free cash flow is used by management and investors to assess the cash generating capacity of an asset.
"Free cash flow" refers to adjusted funds flow less total capital expenditures and asset retirement obligation settlements. Free cash flow is used by management and investors to assess the amount of internally generated cash available to repay debt, reinvest in the business or return to shareholders. The following is the calculation of free cash flow from the nearest GAAP measure for the three months ended
Three months ended | (MM$) | ||
Cash from operating activities | 81.3 | ||
Change in non-cash working capital | (7.9) | ||
Geological and geophysical expenses | 1.6 | ||
Asset retirement obligations settled | 8.4 | ||
Provision | 7.5 | ||
Adjusted funds flow | 90.9 | ||
Total capital expenditures | (59.3) | ||
Asset retirement obligation settlements | (8.4) | ||
Free cash flow | 23.2 |
"Netback" equals petroleum and natural gas sales less royalties, operating expense and transportation and NGLs processing costs. Netback is commonly used by management and investors to compare the results of the Company's oil and gas operations between periods. Refer to the tables under the headings "Review of Operations" and "Financial and Operating Results" for the calculation thereof.
"Net debt" is a measure of the Company's overall debt position after adjusting for certain working capital and other amounts and is used by management to assess the Company's overall leverage position. Refer to the Liquidity and Capital Resources section of the Company's Management's Discussion and Analysis for the three months ended
"Net debt to adjusted funds flow" is a ratio calculated as the period end net debt divided by the sum of adjusted funds flow for the trailing four quarters. The ratio of net debt to adjusted funds flow is commonly used by management and investors to assess the Company's overall debt position and to measure the strength of the Company's balance sheet.
"Total capital expenditures" refers to the Company's property, plant and equipment and exploration expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures section of the MD&A for the calculation thereof.
Non-GAAP financial measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP financial measures are unlikely to be comparable to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
Abbreviations
Liquids | Natural Gas | |||
Bbl | Barrels | GJ | Gigajoules | |
Bbl/d | Barrels per day | GJ/d | Gigajoules per day | |
MBbl | Thousands of barrels | Mcf | Thousands of cubic feet | |
NGLs | Natural gas liquids | MMcf | Millions of cubic feet | |
Condensate | Pentane and heavier hydrocarbons | MMcf/d | Millions of cubic feet per day | |
WTI | West Texas Intermediate | AECO | AECO-C reference price | |
NYMEX |
Oil Equivalent | |
Boe | Barrels of oil equivalent |
MBoe | Thousands of barrels of oil equivalent |
MMBoe | Millions of barrels of oil equivalent |
Boe/d | Barrels of oil equivalent per day |
This press release contains disclosures expressed as "Boe", "$/Boe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A 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 well head. For the three months ended
This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.
Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended
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