HIGHLIGHTS
- First quarter 2022 sales volumes averaged 82,137 Boe/d (45% liquids), in-line with expectations.(1)
- Sales volumes at Karr averaged 38,611 Boe/d (51% liquids).
- Sales volumes at Wapiti averaged 16,126 Boe/d (59% liquids).
- Cash from operating activities was $175 million ($1.25 per basic share) in the first quarter. Adjusted funds flow was $238 million ($1.70 per basic share). Free cash flow was $103 million ($0.74 per basic share).(2)
- First quarter capital expenditures totaled $117 million and were predominantly focused on drilling and completion activities at Karr and Wapiti as well as in the Kaybob region.
- Paramount realized cash proceeds of approximately $51 million from the sale of a portion of its investments in securities in the first quarter.
- Net debt was reduced by approximately $96 million quarter-over-quarter to $361 million at March 31, 2022, including drawings under the Company’s credit facility of $305 million. Net debt does not account for the $479 million carrying value of the Company’s investments in securities as at March 31, 2022. (3)
- Paramount now expects to achieve its net debt target of about $300 million by mid-year, earlier than previously forecast, even after accounting for the $40 million Willesden Green acquisition.
- Abandonment and reclamation expenditures in the first quarter totaled $15 million, net of $5 million in funding under the Alberta Site Rehabilitation Program (“ASRP”). A total of 63 wells were abandoned in the quarter, including 36 under the Company’s ongoing area-based closure program at Zama.
- In late April, the Company acquired Duvernay lands and production directly offsetting its existing 61,000 net acre position in the Willesden Green area of Alberta for approximately $40 million in cash prior to adjustments. The acquisition is accretive on all key metrics and more than doubles Paramount’s land position and internally estimated drilling locations in the area, setting the stage for more efficient future development and potential infrastructure synergies. Current production from the acquisition is approximately 1,300 Boe/d (49% liquids).
- In May, Paramount increased the capacity of its bank credit facility to $1.0 billion and extended the maturity date to May 3, 2026. The capacity of the credit facility can be further increased by up to $250 million pursuant to an accordion feature, subject to incremental lender commitments.
_______________________________________________ |
|
(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. 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, light and medium crude oil and tight oil. See also “Oil and Gas Measures and Definitions” in the Advisories section. |
(2) |
Adjusted funds flow and free cash flow are capital management measures used by Paramount. Adjusted funds flow per basic share and free cash flow per basic share are supplementary financial measures. Refer to the “Specified Financial Measures” section for more information on these measures. |
(3) |
Net debt is a capital management measure used by Paramount. Refer to the “Specified Financial Measures” section for more information on this measure. |
INCREASED DIVIDEND
Paramount’s Board of Directors has approved a 25% increase in the Company’s regular monthly dividend from $0.08 to $0.10 per Common Share. The first increased dividend will be payable on May 31, 2022 to shareholders of record on May 16, 2022. The dividend will be designated as an “eligible dividend” for Canadian income tax purposes.
UPDATED 2022 GUIDANCE AND PRELIMINARY 2023 BUDGET
The Company’s planned 2022 capital expenditures have been upwardly revised by $20 million to a range of between $520 million and $560 million. The additional capital expenditures will be used to accelerate the drilling of a five-well pad at Karr from 2023 into late 2022 to facilitate further production growth in 2023. Paramount remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices and other factors. The Company continues to budget $33 million of abandonment and reclamation expenditures in 2022, net of approximately $8 million in funding under the ASRP.
Paramount is reaffirming its 2022 annual average sales volume guidance of between 91,000 Boe/d and 95,000 Boe/d (46% liquids).
- First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d (44% liquids).
- Second half 2022 sales volumes are expected to average between 101,000 Boe/d and 105,000 Boe/d (47% liquids).
The Company is increasing its forecast of 2022 free cash flow from approximately $590 million to approximately $710 million to reflect higher commodity price assumptions and its updated capital expenditure plan.(1)
________________________ |
|
(1) |
The stated free cash flow forecast is based on the following assumptions for 2022: (i) the midpoint of forecast capital spending and production, (ii) $33 million in net abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $72.55/Boe (US$97.07/Bbl WTI, US$6.34/MMBtu NYMEX, $5.34/GJ AECO), (v) a $US/$CDN exchange rate of $0.793, (vi) royalties of $12.40/Boe, (vii) operating costs of $11.30/Boe and (viii) transportation and processing costs of $4.10/Boe. |
The Company’s 2022 capital program, targeted net debt reduction and regular monthly dividend would remain fully funded down to an average WTI price of about US$50.00/Bbl over the last three quarters of 2022. (1)
Paramount’s anticipated 2023 capital expenditure budget, based on preliminary planning and current market conditions, has been upwardly revised by $60 million at the midpoint to a range of between $540 million and $580 million. The additional capital expenditures will largely be focused on accelerating development activities at Karr to grow production by approximately 4,000 Boe/d in 2023 to a range of 45,000 Boe/d to 49,000 Boe/d and set the stage for a new production plateau range of 50,000 Boe/d to 54,000 Boe/d in 2024.
The Company expects that a capital program in this range will result in 2023 average sales volumes of 105,000 Boe/d to 110,000 Boe/d (47% liquids), 6,500 Boe/d higher than previous estimates and a 15% increase at midpoint from forecast average 2022 sales volumes.
Paramount is updating its estimate of 2023 free cash flow that would be expected from such a capital program from approximately $580 million to approximately $820 million to reflect higher production and commodity price assumptions.(2)
UPDATED FIVE-YEAR OUTLOOK
The Company is updating its previously provided five-year outlook to reflect revised capital and production expectations and recent commodity prices. Paramount now anticipates cumulative free cash flow through to the end of 2026 of approximately $4.1 billion, up from $3.3 billion. The Company now anticipates annual capital expenditures of approximately $550 million (up from $500 million) and a compound annual production growth rate of approximately 7% (up from 5%) through the period.(3)
DELIVERING ON FREE CASH FLOW PRIORITIES
Paramount’s free cash flow priorities are: (i) the achievement of its net debt target of about $300 million and the maintenance of conservative leverage levels thereafter, (ii) shareholder returns and (iii) incremental growth. Paramount has and will continue to deliver on these priorities.
- The Company expects to achieve its net debt target of about $300 million by mid-year 2022. At this level, year-end 2022 net debt to adjusted funds flow would be less than 0.3x.(4)
- Paramount has increased shareholder returns by implementing a regular monthly dividend in July 2021 of $0.02 per share and increasing it three times to $0.10 per share beginning in May 2022. The Company retains the flexibility to make repurchases of shares under its normal course issuer bid.
- The Company has allocated incremental capital to its highest risk-adjusted rate of return organic growth opportunities and to accretive acquisitions, adding to the significant free cash flow and production growth described in the five-year outlook.
_________________________ |
|
(1) |
Assuming no changes to the other free cash flow forecast assumptions for 2022. |
(2) |
The revised free cash flow estimate is based on the following assumptions for 2023: (i) the midpoint of stated capital spending and production, (ii) $40 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $63.80/Boe (US$87.88/Bbl WTI, US$5.04/MMBtu NYMEX, $4.48/GJ AECO), (v) a $US/$CDN exchange rate of $0.794, (vi) royalties of $12.05/Boe, (vii) operating costs of $10.60/Boe and (vii) transportation and processing costs of $3.80/Boe. |
(3) |
The five-year outlook is based on preliminary planning and current market conditions and is subject to change. The stated anticipated cumulative free cash flow is based on the following assumptions: (i) the stated annual capital expenditures and compound annual production growth; (ii) approximately $40 million in average annual abandonment and reclamation costs, (iii) approximately $7 million in annual geological and geophysical expenses, (iv) strip commodity prices and foreign exchange rates as at April 21, 2022, and (v) internal management estimates of future royalties, operating costs, transportation and processing costs and, in 2026, cash taxes. |
(4) |
Assuming 2022 adjusted funds flow in excess of $1 billion. |
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Grande Prairie Region sales volumes and netbacks are summarized below:
Q1 2022 |
Q4 2021 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
152.5 |
158.9 |
(4) |
||
Condensate and oil (Bbl/d) |
26,048 |
26,278 |
(1) |
||
Other NGLs (Bbl/d) |
3,267 |
3,276 |
– |
||
Total (Boe/d) |
54,737 |
56,035 |
(2) |
||
% liquids |
54% |
53% |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
72.1 |
5.25 |
71.5 |
4.89 |
1 |
Condensate and oil revenue |
277.1 |
118.21 |
230.5 |
95.37 |
20 |
Other NGLs revenue |
18.1 |
61.47 |
16.6 |
54.97 |
9 |
Royalty and other revenue (3) |
10.7 |
– |
– |
– |
NM |
Petroleum and natural gas sales |
378.0 |
76.74 |
318.6 |
61.81 |
19 |
Royalties |
(61.4) |
(12.46) |
(39.8) |
(7.74) |
54 |
Operating expense |
(53.7) |
(10.89) |
(54.9) |
(10.64) |
(2) |
Transportation and NGLs processing |
(23.2) |
(4.73) |
(19.0) |
(3.68) |
22 |
239.7 |
48.66 |
204.9 |
39.75 |
17 |
(1) |
“Netback” is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the “Specified Financial Measures” section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
(3) |
In the first quarter of 2022, royalty and other revenue includes $10.6 million in respect of a contingent business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three months ended March 31, 2022. |
NM means not meaningful. |
|
KARR AREA
Karr sales volumes and netbacks are summarized below:
Q1 2022 |
Q4 2021 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
113.3 |
124.0 |
(9) |
||
Condensate and oil (Bbl/d) |
17,246 |
18,521 |
(7) |
||
Other NGLs (Bbl/d) |
2,475 |
2,449 |
1 |
||
Total (Boe/d) |
38,611 |
41,629 |
(7) |
||
% liquids |
51% |
50% |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
53.1 |
5.21 |
55.2 |
4.84 |
(4) |
Condensate and oil revenue |
182.4 |
117.56 |
161.3 |
94.67 |
13 |
Other NGLs revenue |
14.4 |
64.60 |
13.1 |
58.20 |
10 |
Royalty and other revenue |
0.1 |
– |
– |
– |
NM |
Petroleum and natural gas sales |
250.0 |
71.95 |
229.6 |
59.96 |
9 |
Royalties |
(54.0) |
(15.52) |
(35.7) |
(9.32) |
51 |
Operating expense |
(35.2) |
(10.14) |
(36.0) |
(9.38) |
(2) |
Transportation and NGLs processing |
(16.1) |
(4.65) |
(14.0) |
(3.68) |
15 |
144.7 |
41.64 |
143.9 |
37.58 |
1 |
(1) |
“Netback” is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the “Specified Financial Measures” section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
NM means not meaningful. |
|
First quarter 2022 sales volumes at Karr averaged 38,611 Boe/d (51% liquids) compared to 41,629 Boe/d (50% liquids) in the fourth quarter of 2021. Sales volumes were lower primarily due to natural declines. Several short, unplanned curtailments at third-party operated facilities in the first quarter, all of which have now been resolved, also contributed to the reduction.
The first seven wells at the 16-17 pad came on production ahead of schedule and under budget with preliminary drilling, completion, equipping and tie-in (“DCET”) costs averaging $6.9 million per well. Average gross peak 30-day production per well was 1,395 Boe/d (3.6 MMcf/d of shale gas and 802 Bbl/d of NGLs) with an average CGR of 225 Bbl/MMcf.(1) The Company continues to strive for improved efficiencies in its development activities to mitigate inflationary pressures on DCET costs without compromising completion effectiveness or health, safety and environmental performance. The 16-17 pad, as well as the Wapiti 9-22 pad, are the Company’s first two pads to have been equipped with instrument air to operate all pneumatically driven controllers. Paramount plans to equip new pads with instrument air where possible to minimize methane emissions from its operations.
Second quarter activities at Karr include completing the drilling of the remaining five wells at the 16-17 pad. These wells are expected to be brought onstream in the third quarter. Second quarter sales volumes are expected to be impacted by a 16-day full field outage for scheduled turnaround activities at third-party midstream facilities.
In the second half of 2022, the Company plans to drill, complete, tie-in and bring on production the four-well 1-2 North pad and commence drilling the five-well 4-2 South pad. In addition, the Company is accelerating the drilling of the five-well 4-2 North pad into the fourth quarter. Paramount plans to bring onstream additional gas lift compression in the year to support liquids production and continue to build out infrastructure to debottleneck future production.
_________________________ |
|
(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 6% and liquids sales volumes are lower by approximately 6% 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 2022 |
Q4 2021 |
% Change |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
39.2 |
34.9 |
12 |
||
Condensate and oil (Bbl/d) |
8,802 |
7,757 |
13 |
||
Other NGLs (Bbl/d) |
792 |
827 |
(4) |
||
Total (Boe/d) |
16,126 |
14,406 |
12 |
||
% liquids |
59% |
60% |
|||
Netback (1) |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Change in $ |
Natural gas revenue (2) |
19.0 |
5.39 |
16.3 |
5.07 |
17 |
Condensate and oil revenue |
94.7 |
119.49 |
69.2 |
97.03 |
37 |
Other NGLs revenue |
3.7 |
51.67 |
3.5 |
45.43 |
6 |
Royalty and other revenue (3) |
10.6 |
– |
– |
– |
NM |
Petroleum and natural gas sales |
128.0 |
88.20 |
89.0 |
67.15 |
44 |
Royalties |
(7.4) |
(5.13) |
(4.1) |
(3.18) |
80 |
Operating expense |
(18.5) |
(12.69) |
(18.9) |
(14.26) |
(2) |
Transportation and NGLs processing |
(7.1) |
(4.92) |
(5.0) |
(3.69) |
42 |
95.0 |
65.46 |
61.0 |
46.02 |
56 |
(1) |
“Netback” is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the “Specified Financial Measures” section for more information on these measures. |
(2) |
Natural gas revenue presented as $/Mcf. |
(3) |
In the first quarter of 2022, royalty and other revenue includes $10.6 million in respect of a contingent business interruption insurance claim. Refer to Note 12 in the unaudited Interim Condensed Consolidated Financial Statements as at and for the three months ended March 31, 2022. |
NM means not meaningful. |
|
First quarter 2022 sales volumes at Wapiti averaged 16,126 Boe/d (59% liquids) compared to 14,406 Boe/d (60% liquids) in the fourth quarter of 2021 as a result of new production from the seven-well 9-22 pad that came onstream between late in the fourth quarter of 2021 and the first quarter of 2022. The increase in sales volumes was achieved despite three unplanned outages at the Wapiti Plant that resulted in approximately three weeks of downtime and approximately 5,100 Boe/d of lost production in the quarter.
Royalty and other revenue for the three months ended March 31, 2022 includes $10.6 million in respect of the Company’s business interruption claim arising from outages at the Wapiti Plant in 2020 and 2021.
Despite operational challenges associated with outages at the Wapiti Plant, initial results from the seven-well 9-22 pad have been encouraging, averaging gross peak 30-day production per well of 1,503 Boe/d (4.0 MMcf/d of shale gas and 840 Bbl/d of NGLs) with an average CGR of 211 Bbl/MMcf.(1)
Drilling operations at the eight-well 8-22 pad that commenced in late 2021 are now complete. The pad is the Company’s first where all wells have been configured as monobores. This delivers a cost advantage compared to conventional multiple casing wells due to lower steel requirements and higher pumping efficiencies.
_________________________ |
|
(1) |
Production measured at the wellhead. Natural gas sales volumes are lower by approximately 12% and liquids sales volumes are lower by approximately 2% 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. |
Second quarter sales volumes are anticipated to increase as all eight wells on the 8-22 pad are brought onstream. Additional second quarter activities include the drilling of eight wells at the 6-32 pad, which is forecast to be brought on production in the third quarter, and the commencement of drilling operations at the eight well 16-15 pad, which is forecast to be brought on production in early 2023. The Company also plans to commence the drilling of the eight well 8-15 pad later in the year.
KAYBOB REGION
Kaybob Region sales volumes averaged 20,726 Boe/d (28% liquids) in the first quarter compared to 21,725 Boe/d (29% liquids) in the fourth quarter of 2021. The decrease in production is primarily attributable to natural declines.
Development commenced at the Company’s two Duvernay assets at Kaybob Smoky and Kaybob North. Drilling operations at the four well 10-35 pad at Kaybob Smoky were recently completed on time with preliminary drilling cost estimates coming in approximately 7% under budget. The Company plans to commence completion operations in the second quarter and expects all four wells to be onstream in the third quarter. The Company also plans to expand its 100% owned and operated 6-16 facility in 2022. Drilling of the two remaining wells at the three well Kaybob North 12-21 pad have recently commenced. The Company plans to bring all three wells onstream in the fourth quarter.
In addition to the activities at Kaybob Smoky and Kaybob North, Paramount is advancing a number of other high return opportunities in the Kaybob Region. The first (1.0 net) of four (2.5 net) Montney gas wells in the Kaybob Presley area planned for 2022 was drilled, completed and brought onstream in the first quarter and a second (0.5 net) well was drilled in the quarter and is forecast to come onstream in the second quarter. The remaining two (1.0 net) wells at Kaybob Presley are expected to be drilled, completed and brought onstream by the fourth quarter. The two (2.0 net) Kaybob Gething oil wells planned for 2022 have completed drilling operations and are forecast to come onstream in the third quarter. In addition, one (1.0 net) Kaybob Montney Oil well is planned to be drilled, completed and brought onstream over the second and third quarters.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 6,674 Boe/d (22% liquids) in the first quarter compared to 7,505 Boe/d (26% liquids) in the fourth quarter of 2021. The decrease in production is primarily attributable to natural declines.
The recently completed acquisition at Willesden Green adds over 90,000 net acres (after deducting near-term expiries) to Paramount’s land position and approximately 200 internally estimated Duvernay drilling locations.(1) Prior to the acquisition, the Company’s preliminary development plans for Willesden Green targeted a full field production plateau of approximately 20,000 Boe/d, which could be sustained for over 15 years based on approximately 180 internally estimated Duvernay drilling locations. Paramount’s five-year outlook includes capital to advance development of the asset with production expected to begin ramping up in 2025/26. The incremental drilling inventory provided by the acquisition allows for the potential to expand development plans to increase the ultimate targeted plateau production level. The Company had already initiated an engineering design study for the expansion of its majority owned Leafland gas plant in the area as part of its 2022 capital program and will now incorporate the acquisition into the study to optimize full field development plans for Willesden Green. Paramount continues to review its plans for Willesden Green, including the targeted plateau production level, capital allocation and pace of development.
_________________________ |
|
(1) |
See also “Oil and Gas Measures and Definitions” in the Advisories section for additional information respecting internally estimated drilling locations. |
HEDGING
Paramount has hedged approximately 31% of its remaining 2022 forecast production to provide greater free cash flow certainty. The Company’s current hedging position is summarized below:
Type (1) |
Q2 2022 |
Q3 2022 |
Q4 2022 |
Q1 2023 |
Average Price (2) |
||
Oil – WTI Swaps (Sale) (Bbl/d) |
Financial |
3,500 |
3,500 |
3,500 |
– |
US$75.79/Bbl |
|
Oil – WTI Swaps (Sale) (Bbl/d) |
Financial |
3,500 |
3,500 |
3,500 |
– |
CDN$91.38/Bbl |
|
Oil – WTI Collars (Bbl/d) |
Financial |
7,000 |
7,000 |
7,000 |
– |
CDN$82.50/Bbl (Floor) |
|
CDN$100.47/Bbl (Ceiling) |
|||||||
Sweet Crude Oil – Basis (Sale) (Bbl/d) |
Physical |
5,186 |
– |
– |
– |
WTI – US$2.15/Bbl |
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
30,000 |
– |
– |
– |
US$4.62/MMBtu |
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
– |
30,000 |
– |
– |
US$4.67/MMBtu |
|
Gas – NYMEX Swaps (Sale) (MMBtu/d) |
Financial |
– |
– |
3,370 |
– |
US$4.91/MMBtu |
|
Gas – AECO fixed price (GJ/d) |
Physical |
80,000 |
80,000 |
26,957 |
– |
CDN$3.78/GJ |
|
Gas – Dawn fixed price (MMBtu/d) |
Physical |
20,000 |
20,000 |
6,739 |
– |
US$4.03/MMBtu |
|
Fx – CDN/USD Forwards (US$MM/Month) |
Forwards |
$15 |
$20 |
$20 |
$10 |
1.2804 C$ / US$ |
|
Fx – CDN/USD Collars (US$MM/Month) |
Financial |
$5 |
$5 |
$3.3 |
– |
1.25 C$ / US$ (Floor) |
|
1.30 C$ / US$ (Ceiling) |
|||||||
Fx – CDN/USD Swaps (US$MM/Month) |
Financial |
$6.7 |
$10 |
$10 |
$10 |
1.2888 C$ / US$ |
(1) |
Financial, refers to financial commodity and foreign currency exchange contracts. Physical, refers to fixed-priced and basis physical contracts. Forwards, refers to foreign currency exchange forwards contracts. |
(2) |
Average price is calculated using a weighted average of notional volumes and prices. |
ANNUAL GENERAL MEETING
Paramount will hold its annual general meeting of shareholders in a virtual-only format accessible at https://meetnow.global/MD9YA2M on Wednesday, May 4, 2022 at 10:30 a.m. (Calgary time).
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, 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 2022 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements, can be obtained on SEDAR at www.sedar.com or on Paramount’s website at https://www.paramountres.com/investors/financial-shareholder-reports.
A summary of historical financial and operating results is also available on Paramount’s website at https://www.paramountres.com/investors/financial-shareholder-reports.
FINANCIAL AND OPERATING RESULTS (1) |
||||||||
($ millions, except as noted) |
Q1 2022 |
Q4 2021 |
Q1 2021 |
|||||
Net income (loss) |
16.6 |
101.0 |
(82.5) |
|||||
per share – basic ($/share) |
0.12 |
0.75 |
(0.62) |
|||||
per share – diluted ($/share) |
0.11 |
0.70 |
(0.62) |
|||||
Cash from operating activities |
174.9 |
191.8 |
81.3 |
|||||
per share – basic ($/share) |
1.25 |
1.42 |
0.61 |
|||||
per share – diluted ($/share) |
1.20 |
1.33 |
0.61 |
|||||
Adjusted funds flow |
237.8 |
174.6 |
90.9 |
|||||
per share – basic ($/share) |
1.70 |
1.29 |
0.69 |
|||||
per share – diluted ($/share) |
1.63 |
1.21 |
0.69 |
|||||
Free cash flow |
103.4 |
99.0 |
21.6 |
|||||
per share – basic ($/share) |
0.74 |
0.73 |
0.16 |
|||||
per share – diluted ($/share) |
0.71 |
0.69 |
0.16 |
|||||
Total assets |
4,095.5 |
3,885.1 |
3,583.1 |
|||||
Long-term debt |
302.6 |
386.3 |
712.7 |
|||||
Net debt |
361.2 |
456.7 |
761.7 |
|||||
Common shares outstanding (millions) (2) |
140.0 |
139.2 |
132.8 |
|||||
Sales volumes (3) |
||||||||
Natural gas (MMcf/d) |
272.9 |
284.8 |
273.1 |
|||||
Condensate and oil (Bbl/d) |
31,375 |
32,342 |
29,854 |
|||||
Other NGLs (Bbl/d) |
5,276 |
5,462 |
5,170 |
|||||
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
|||||
% liquids |
45% |
44% |
43% |
|||||
Grande Prairie Region (Boe/d) |
54,737 |
56,035 |
47,385 |
|||||
Kaybob Region (Boe/d) |
20,726 |
21,725 |
24,938 |
|||||
Central Alberta & Other Region (Boe/d) |
6,674 |
7,505 |
8,217 |
|||||
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
|||||
Netback |
$/Boe (4) |
$/Boe (4) |
$/Boe (4) |
|||||
Natural gas revenue |
127.1 |
5.18 |
124.7 |
4.76 |
77.3 |
3.14 |
||
Condensate and oil revenue |
331.9 |
117.53 |
281.1 |
94.46 |
185.9 |
69.20 |
||
Other NGLs revenue |
29.3 |
61.64 |
27.4 |
54.61 |
15.0 |
32.29 |
||
Royalty and other revenue |
11.3 |
─ |
1.3 |
─ |
1.9 |
─ |
||
Petroleum and natural gas sales |
499.6 |
67.59 |
434.5 |
55.40 |
280.1 |
38.64 |
||
Royalties |
(76.2) |
(10.31) |
(52.5) |
(6.69) |
(18.6) |
(2.57) |
||
Operating expense |
(89.2) |
(12.07) |
(91.0) |
(11.61) |
(84.3) |
(11.63) |
||
Transportation and NGLs processing |
(31.3) |
(4.24) |
(26.1) |
(3.33) |
(27.9) |
(3.84) |
||
Sales of commodities purchased (5) |
48.8 |
6.59 |
22.1 |
2.82 |
8.6 |
1.18 |
||
Commodities purchased (5) |
(49.1) |
(6.64) |
(22.3) |
(2.85) |
(8.8) |
(1.21) |
||
Netback |
302.6 |
40.92 |
264.7 |
33.74 |
149.1 |
20.57 |
||
Risk management contract settlements |
(49.7) |
(6.72) |
(72.4) |
(9.23) |
(32.7) |
(4.51) |
||
Netback including risk management contract |
252.9 |
34.20 |
192.3 |
24.51 |
116.4 |
16.06 |
||
Capital expenditures |
||||||||
Grande Prairie Region |
76.8 |
57.7 |
51.3 |
|||||
Kaybob Region |
31.1 |
3.8 |
5.0 |
|||||
Central Alberta & Other Region |
0.1 |
2.6 |
1.2 |
|||||
Corporate |
9.0 |
1.6 |
1.8 |
|||||
Total |
117.0 |
65.7 |
59.3 |
|||||
Asset retirement obligations settlements |
14.8 |
7.0 |
8.4 |
(1) |
Adjusted funds flow, free cash flow and net debt are capital management measures used by Paramount. Netback and netback including risk management contract settlements are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income, that is presented on a per share, $/Mcf or $/Boe basis is a supplementary financial measure. Refer to the “Specified Financial Measures” section for more information on these measures. Prior period free cash flow has been reclassified to conform with the current year’s presentation. |
(2) |
Common shares are presented net of shares held in trust under the Company’s restricted share unit plan: Q1 2022: 1.5 million; Q4 2021: 1.5 million; Q1 2021: 1.9 million. |
(3) |
Refer to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product type. |
(4) |
Natural gas revenue presented as $/Mcf. |
(5) |
Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties. |
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. 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 Region |
Kaybob Region |
|||||||
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
|
Shale gas (MMcf/d) |
213.1 |
220.4 |
197.8 |
151.4 |
156.5 |
120.6 |
35.7 |
35.6 |
42.1 |
Conventional natural gas (MMcf/d) |
59.8 |
64.4 |
75.3 |
1.1 |
2.4 |
2.0 |
53.6 |
56.8 |
65.8 |
Natural gas (MMcf/d) |
272.9 |
284.8 |
273.1 |
152.5 |
158.9 |
122.6 |
89.3 |
92.4 |
107.9 |
Condensate (Bbl/d) |
29,098 |
29,797 |
27,017 |
26,042 |
26,272 |
23,974 |
2,130 |
2,184 |
2,611 |
Other NGLs (Bbl/d) |
5,276 |
5,462 |
5,170 |
3,267 |
3,276 |
2,984 |
1,558 |
1,788 |
1,677 |
NGLs (Bbl/d) |
34,374 |
35,259 |
32,187 |
29,309 |
29,548 |
26,958 |
3,688 |
3,972 |
4,288 |
Tight oil (Bbl/d) |
403 |
497 |
479 |
– |
– |
– |
322 |
355 |
342 |
Light and medium crude oil (Bbl/d) |
1,874 |
2,048 |
2,358 |
6 |
6 |
– |
1,832 |
2,000 |
2,321 |
Crude oil (Bbl/d) |
2,277 |
2,545 |
2,837 |
6 |
6 |
– |
2,154 |
2,355 |
2,663 |
Total (Boe/d) |
82,137 |
85,265 |
80,540 |
54,737 |
56,035 |
47,385 |
20,726 |
21,725 |
24,938 |
Central and Other Region |
Karr |
Wapiti |
|||||||
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
Q1 2022 |
Q4 2021 |
Q1 2021 |
|
Shale gas (MMcf/d) |
26.0 |
28.2 |
35.1 |
112.8 |
122.5 |
89.1 |
38.6 |
34.0 |
31.5 |
Conventional natural gas (MMcf/d) |
5.1 |
5.3 |
7.5 |
0.5 |
1.5 |
1.1 |
0.6 |
0.9 |
0.9 |
Natural gas (MMcf/d) |
31.1 |
33.5 |
42.6 |
113.3 |
124.0 |
90.2 |
39.2 |
34.9 |
32.4 |
Condensate (Bbl/d) |
926 |
1,341 |
433 |
17,246 |
18,521 |
16,095 |
8,796 |
7,751 |
7,879 |
Other NGLs (Bbl/d) |
451 |
398 |
509 |
2,475 |
2,449 |
2,108 |
792 |
827 |
876 |
NGLs (Bbl/d) |
1,377 |
1,739 |
942 |
19,721 |
20,970 |
18,203 |
9,588 |
8,578 |
8,755 |
Tight oil (Bbl/d) |
81 |
142 |
136 |
– |
– |
– |
– |
– |
– |
Light and medium crude oil (Bbl/d) |
36 |
42 |
37 |
– |
– |
– |
6 |
6 |
– |
Crude oil (Bbl/d) |
117 |
184 |
173 |
– |
– |
– |
6 |
6 |
– |
Total (Boe/d) |
6,674 |
7,505 |
8,217 |
38,611 |
41,629 |
33,230 |
16,126 |
14,406 |
14,155 |
The Company forecasts that 2022 sales volumes will average between 91,000 Boe/d and 95,000 Boe/d (54% shale gas and conventional natural gas combined, 40% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 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 half 2022 sales volumes are expected to average between 101,000 Boe/d and 105,000 Boe/d (53% shale gas and conventional natural gas combined, 41% light and medium crude oil, tight oil and condensate combined and 6% other NGLs).
SPECIFIED FINANCIAL MEASURES
Non-GAAP Financial Measures
Netback and netback including risk management contract settlements are non-GAAP financial measures. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company’s primary financial statements or other measures of financial performance calculated in accordance with IFRS.
Netback equals petroleum and natural gas sales (the most directly comparable measure disclosed in the Company’s primary financial statements) plus sales of commodities purchased less royalties, operating expense, transportation and NGLs processing expense and commodities purchased. Netback is used by investors and Management to compare the performance of the Company’s producing assets between periods.
Netback including risk management contract settlements equals netback after including (or deducting) risk management contract settlements received (paid). Netback including risk management contract settlements is used by investors and Management to assess the performance of the producing assets after incorporating Management’s risk management strategies.
Refer to the table under the heading “Financial and Operating Results” in this press release for the calculation of netback and netback including risk management contract settlements for the three months ended March 31, 2022 and 2021.
Non-GAAP Ratios
Netback and netback including risk management contract settlements presented on a $/Boe basis are non-GAAP ratios as they each have a non-GAAP financial measure (netback and netback including risk management contract settlements, respectively) as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company’s primary financial statements or other measures of financial performance calculated in accordance with IFRS.
Netback on a $/Boe basis is calculated by dividing netback for the applicable period by the total production during the period in Boe. Netback including risk management contract settlements on a $/Boe basis is calculated by dividing netback including risk management contract settlements for the applicable period by the total production during the period in Boe. These measures are used by investors and Management to assess netback and netback including risk management contract settlements on a unit of production basis.
Capital Management Measures
Adjusted funds flow, free cash flow and net debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 15 – Capital Structure in the unaudited Interim Condensed Consolidated Financial Statements of Paramount as at and for the three months ended March 31, 2022 for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company’s primary financial statements, for the three months ended March 31, 2022 and 2021 and (iii) a calculation of net debt as at March 31, 2022 and December 31, 2021.
Supplementary Financial Measures
This press release contains supplementary financial measures expressed as: (i) cash from operating activities, adjusted funds flow and free cash flow on a per share – basic and per share – diluted basis and (ii) revenue, petroleum and natural gas sales, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Bbl, $/Mcf or $/Boe basis.
Cash from operating activities, adjusted funds flow and free cash flow on a per share – basic basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average basic shares outstanding during the period determined under IFRS. Cash from operating activities, adjusted funds flow and free cash flow on a per share – diluted basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average diluted shares outstanding during the period determined under IFRS.
Revenue, petroleum and natural gas sales, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased and commodities purchased on a $/Bbl, $/Mcf or $/Boe basis are calculated by dividing the revenue, petroleum and natural gas sales, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased or commodities purchased, as applicable, over the referenced period by the aggregate applicable units of production (Bbl, Mcf or Boe) during such period.