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.
- 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.
________________________________________ |
|
(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 $26.00/Boe, consistent with the first quarter of 2021, and 12 to 16 new wells per year at an average DCET cost of $7.5 million per well and excludes the cost of any potential incremental infrastructure requirements in the future. |
- 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 at Zama.
- 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
Paramount has entered into a definitive agreement for the sale of its non-operated Birch asset in northeast British Columbia for total consideration of approximately $77 million (the “Birch Disposition”). Closing is subject to customary conditions and is anticipated to occur in early July. Estimated second half 2021 production from the asset, net to Paramount, was approximately 1,900 Boe/d.
REVISED 2021 GUIDANCE
Paramount is increasing its 2021 sales volume forecast as a result of strong year-to-date performance. Sales volumes in 2021 are now expected to average between 80,000 Boe/d and 82,000 Boe/d (44% liquids) after taking into account the Birch Disposition. This is an increase from previous guidance of 77,000 Boe/d to 80,000 Boe/d (45% liquids).
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 $60 million of activities in the Wapiti area by six months into the second half of 2021, capitalizing on the $30 million of anticipated cost savings in its 2021 capital program, incremental cash flow generation in light of higher production guidance and the Birch Disposition. Accordingly, the Company’s capital budget for 2021 is being increased to between $265 million and $285 million, excluding land acquisitions and abandonment and reclamation activities. This is an increase of $30 million at the mid-point from the previous guidance range of between $230 million and $260 million. Additional activities at Wapiti will 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 December 2021.
Inclusive of the increased capital at Wapiti, Paramount forecasts 2021 free cash flow of approximately $140 million. This is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $39.50/Boe (US$60.84/Bbl WTI, US$2.84/MMBtu NYMEX, $2.78/GJ AECO), (iv) royalties of $2.60/Boe, (v) operating costs of $11.30/Boe and (vi) transportation and processing costs of $3.85/Boe.
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 $60 million at an average WTI oil price of US$40.00/Bbl over the final three quarters of the year and would rise to $155 million at an average WTI oil price of US$65.00/Bbl over the final three quarters of the year.
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
Paramount expects to finalize its 2022 capital budget and related guidance in the first quarter of 2022. Based on preliminary planning and current market conditions, Paramount anticipates 2022 capital spending, excluding land acquisitions and abandonment and reclamation activities, to range between $325 million and $385 million, broken down as follows:
- $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 $185 million. The free cash flow estimate is based on the following assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $30 million in abandonment and reclamation costs, (iii) realized pricing of $37.25/Boe (US$57.78/Bbl WTI, US$2.71/MMBtu NYMEX, $2.43/GJ AECO), (iv) royalties of $2.35/Boe, (v) operating costs of $11.10/Boe and (vi) transportation and processing costs of $3.75/Boe. If all expected free cash flow was directed towards debt reduction, anticipated year-end 2022 net debt to adjusted funds flow would be significantly less than 1.0x.
CORPORATE
The Company successfully closed non-core asset dispositions for cash proceeds of approximately $80 million in the first quarter of 2021.
In May 2021, Moody’s Investors Service Inc. assigned a “B2” corporate family rating to the Company with a positive outlook and S&P Global Ratings assigned its “B-” issuer credit rating to the Company with a positive outlook.
Paramount continues to evaluate and pursue opportunities to provide environmentally sustainable value creation for its stakeholders. Advancements in technology paired with government incentive programs have the potential to create stakeholder benefits from both a greenhouse gas (“GHG”) emissions reduction and economic perspective.
The Company has engaged an outside engineering firm and is working with Clean Energy Systems, Inc. (“CES”) to assess the opportunity for ultra-low emission upgrades to one of the Company’s facilities. The project envisions deploying CES’s oxy-combustion technology with CO2 capture to eliminate GHG emissions and generate excess electricity. The captured CO2 could be used for enhanced oil recovery in a Paramount owned and operated oil development or sequestered using the facility’s existing H2S and CO2 disposal system. The CES technology also provides an opportunity to treat produced water that can be used in place of fresh water for Paramount’s future developments. Paramount has held an indirect ownership interest in CES (through its investment in Paxton Corporation) for over a decade and is excited about the prospects for this technology.
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Grande Prairie Region sales volumes and netbacks are summarized below:(1)
Q1 2021 |
Q4 2020 |
%Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
122.6 |
94.3 |
30 |
||
Condensate and oil (Bbl/d) |
23,974 |
19,635 |
22 |
||
Other NGLs (Bbl/d) |
2,984 |
2,429 |
23 |
||
Total (Boe/d) |
47,385 |
37,782 |
25 |
||
% liquids |
57% |
58% |
|||
Netback |
($ 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 AREA
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 November 2020 continues to exhibit higher initial production rates than predicted by the type well. This performance, along with higher than anticipated production from the two well 16-4 pad, post-workover, combined to increase first quarter production above prior projections.
Three new Montney wells on the 4-28 pad were brought onstream in late April. Pressure data collected pre-completion from the pad confirms the northeast portion of Karr is in the over-pressured window of the Montney. This new data has resulted in an adjustment of the over-pressured boundary to the east of Karr and has increased the potential well inventory.
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 $10.67/Boe in the first quarter of 2021 and anticipates operating costs of approximately $10.00/Boe at plateau production levels.
Paramount continues to focus on driving DCET costs lower while maintaining well performance and in the first quarter realized cost improvements relative to the most recent pacesetting results. All-in DCET costs at the six well 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 4-28 pad averaged $6.9 million per well.
Drilling operations at the five well 7-18 pad were completed in the first quarter under budget and included one new pacesetter well, drilling an average 313 meters per day. Paramount plans to complete, tie-in and bring on production all five wells on the 7-18 pad by the third quarter. Drilling of the five well 5-16 East pad recently commenced, and the Company plans to complete, tie-in and bring on production all five wells by the fourth quarter. Paramount anticipates commencing drilling operations on the ten well 16-17 pad in the fourth quarter and expects that seven wells will be drilled by year end.
Production in the second quarter will be impacted by scheduled curtailments at the third-party Karr 6-18 facility related to inlet separation and liquids handling optimization. The curtailments are anticipated to reduce sales volumes by approximately 50% for seven days in May.
_________________________________________ |
|
(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 7% and liquids sales volumes are lower by approximately 7% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section. |
WAPITI AREA
Wapiti sales volumes and netbacks are summarized below:
Q1 2021 |
Q4 2020 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
32.1 |
23.3 |
38 |
||
Condensate and oil (Bbl/d) |
7,884 |
6,286 |
25 |
||
Other NGLs (Bbl/d) |
867 |
589 |
47 |
||
Total (Boe/d) |
14,107 |
10,764 |
31 |
||
% liquids |
62% |
64% |
|||
Netback |
($ 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, $4.4 million under budget for the pad. A pilot project to test the viability of monobore drilling techniques on two wells on the 6-4 pad was successful. Lower drilling and completion costs and higher frac fluid pumping rates in the wellbore compared to conventional multiple casing wellbores are anticipated to further enhance the economics and productivity of these wells. The Company anticipates completing and bringing on production all seven wells by the third quarter.
In the first quarter Paramount tied its Wapiti gas lift infrastructure into the high-pressure gas gathering system managed by the third-party operator of the Wapiti natural gas processing plant. This new connection provides Wapiti area wells with a more reliable source of lift gas which is anticipated to reduce the time required to re-start wells after turnarounds, workovers and other disruptions.
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 December 2021.
KAYBOB REGION
Kaybob Region sales volumes averaged 24,938 Boe/d (28% liquids) in the first quarter of 2021 compared to 27,056 Boe/d (27% liquids) in the fourth quarter of 2020. Production in the Kaybob Region was relatively flat after adjusting for the impact of non-core asset dispositions in the first quarter. The Company completed and recently brought on production one Montney oil well in Ante Creek that was drilled in 2020.
Paramount holds material positions in Duvernay and Montney resource plays in the Kaybob Region that will compete for capital in the medium term.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 8,217 Boe/d (14% liquids) in the first quarter compared to 8,622 (15% liquids) in the fourth quarter of 2020.
The Company holds a material, contiguous Duvernay position at Willesden Green and continues to actively evaluate longer-term full field development plans for this asset. Drilling operations are ongoing at a two well, liquids rich Duvernay pad in the Willesden Green area and Paramount plans to complete, tie-in and bring on production both wells in the second half of the year.
HEDGING
The Company’s commodity hedging position at March 31, 2021 is summarized below:
- Natural Gas:April – December 2021 60,000 MMBtu/d at US$2.71/MMBtu
April – October 2021 50,000 GJ/d at CDN$2.52/GJ
April – December 2021 50,000 GJ/d at CDN$2.51/GJ
- Oil:April – June 2021 23,000 Bbl/d at US$46.93/Bbl
July – September 2021 15,000 Bbl/d at US$45.87/Bbl
October – December 2021 10,000 Bbl/d at US$45.82/Bbl
April – September 2021 3,000 Bbl/d at CDN$65.29/Bbl
The Company has also hedged the differential on 4,000 Bbl/d of condensate at Edmonton for the second quarter at WTI plus US$0.06/Bbl.
Further details of Paramount’s commodity hedging position are provided in its first quarter 2021 Management’s Discussion and Analysis and Consolidated Financial Statements.
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company’s principal properties are located in Alberta and British Columbia. Paramount’s class A common shares are listed on the Toronto Stock Exchange under the symbol “POU”.
Paramount’s first quarter 2021 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at:
https://mma.prnewswire.com/media/1503692/Paramount_Resources_Ltd_Announces_Q1_2021_Results.pdf . A summary of historical financial and operating results is also available on Paramount’s website at http://www.paramountres.com/investor-relations/financial-reports#2021.
This information will also be made available through Paramount’s website at www.paramountres.com and on SEDAR at www.sedar.com.
FINANCIAL AND OPERATING RESULTS (1) ($ 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% |
||||||
Grande Prairie Region (Boe/d) |
47,385 |
37,782 |
||||||
Kaybob Region (Boe/d) |
24,938 |
27,056 |
||||||
Central Alberta and Other Region (Boe/d) |
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 |
||||||||
Grande Prairie Region |
51.3 |
64.3 |
||||||
Kaybob Region |
5.0 |
1.8 |
||||||
Central Alberta and Other Region |
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 |
Grande Prairie |
Kabob |
Central Alberta and |
|||||
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).