Paramount Reports 2020 Annual Results & Provides 2021 Guidance

Source: www.gulfoilandgas.com 3/3/2021, Location: North America

- Annual sales volumes averaged 68,340 Boe/d (39% liquids) in 2020. Fourth quarter 2020 sales volumes averaged 73,460 Boe/d (42% liquids), ahead of guidance of 70,000 to 72,000 Boe/d.(1)
- Fourth quarter sales volumes at Karr, which benefitted from bringing onstream the five-well 5-16 West pad in November, averaged 26,914 Boe/d (56% liquids), compared to 19,246 Boe/d (57% liquids) in the third quarter.
- Fourth quarter sales volumes at Wapiti averaged 10,764 Boe/d (64% liquids), compared to 7,925 Boe/d (63% liquids) in the third quarter. The Company brought five new wells onstream on the 5-3 West pad during the fourth quarter.
- Cash from operating activities was $81 million in 2020 and $53 million in the fourth quarter. Adjusted funds flow in 2020 was $150 million or $1.12 per share. Fourth quarter 2020 adjusted funds flow was $68 million or $0.51 per share.(2)
- Capital spending in 2020 totaled $221 million, below guidance of $225 million. Fourth quarter 2020 capital spending was $65 million, resulting in free cash flow of $3 million in the quarter.(2)
- Abandonment and reclamation expenditures in 2020 totaled $35 million. In addition, approximately $4 million of activities were funded through government programs. Activities included the abandonment of 254 inactive wells, 236 of which were abandoned under the Company's ongoing area-based closure program at Hawkeye and Zama.
- Based on Paramount's strong financial and operational performance, in March 2021 the Company elected to exit the covenant relief period under its $1.0 billion bank credit facility prior to the scheduled expiry of the period on June 30, 2021.

The Company exceeded its previously announced 2020 cost reduction targets of $25 million in operating costs and $15 million in general and administrative expenses ("G&A").

Operating costs were $0.62/Boe lower in 2020 than in 2019, averaging $11.88/Boe in 2020. Fourth quarter operating costs were $11.80/Boe and included unbudgeted workovers on five wells in Karr, which partially contributed to fourth quarter production outperformance.

G&A costs were approximately $20 million ($0.43/Boe) lower in 2020 than in 2019, averaging $1.31/Boe in 2020.

The Company successfully closed non-core asset dispositions for cash proceeds of approximately $80 million in the first quarter of 2021. The estimated impact to average 2021 production is approximately 2,600 Boe/d (15 MMcf/d of conventional natural gas and 135 Bbl/d of NGLs).

GRANDE PRAIRIE ACTIVITIES AND PERFORMANCE
At Karr, a total of 15 new Montney wells were brought on production in the second half of 2020 following completion of an expansion to the third-party Karr 6-18 facility in July.

The five-well 12-18 pad and the five-well 2-1 pad were brought on production in the third quarter. These 10 wells averaged 1,502 Boe/d (3.6 MMcf/d of shale gas and 905 Bbl/d of NGLs) of peak 30-day wellhead production per well, with an average condensate to gas ratio ("CGR") of 253 Bbl/MMcf.(1)

The five-well 5-16 West pad was brought onstream in November 2020. These wells averaged 1,617 Boe/d (3.7 MMcf/d of shale gas and 1,002 Bbl/d of NGLs) of peak 30-day wellhead production per well, with an average CGR of 271 Bbl/MMcf.(1)

Six new Montney wells on the 3-10 pad at Karr were brought onstream in February 2021, two months ahead of schedule. The wells averaged 1,850 Boe/d (5.1 MMcf/d of shale gas and 1,000 Bbl/d of NGLs) of raw wellhead production per well over the first 20 days of production with an average CGR of 196 Bbl/MMcf.(1)

At Wapiti, five Montney wells on the 5-3 West pad were brought onstream in 2020 and averaged 1,271 Boe/d (2.7 MMcf/d of shale gas and 827 Bbl/d of NGLs) of peak 30-day wellhead production per well, with an average CGR of 311 Bbl/MMcf.(2) A pre-existing tenure well was also brought onstream.

Through a continued focus on innovation, technological advancement and efficient execution, the Company realized significant cost savings in its 2020 capital program without compromising deliverability from new wells. Cost savings have been achieved across many aspects of the capital program through improvements in well design, drill bit technology, fluid selection and reducing vendor rates.

All-in lease construction, drilling, completion, equip and tie-in (collectively, "DCET") costs for the five-well Karr 5-16 West pad averaged $7.5 million per well.

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. CGRs are calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

Production measured at the wellhead. Natural gas sales volumes are lower by approximately 15% and liquids sales volumes are lower by approximately 3% 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. CGRs are calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

DCET costs for the last four pads (comprised of 21 wells) at Karr averaged approximately $7.5 million per well. As a consequence of structural cost improvements, the Company is revising downward its internal Karr type well DCET cost assumption to $7.5 million from the previous assumption of $8.4 million, the latter of which was used by the Company's independent third-party reserves evaluator in the preparation of the 2020 reserves report.(1)

At Wapiti, DCET costs on the five-well 5-3 West pad averaged $7.6 million per well. This represents a 27% reduction compared with average DCET costs for the initial two Wapiti pads and is consistent with Paramount's internal type well DCET cost assumption for Wapiti of $7.9 million, which was also used by the Company's independent third-party reserves evaluator in the preparation of the 2020 reserves report. (1)

2021 GUIDANCE
The Company's capital budget for 2021 is expected to range between $230 million and $260 million, excluding land acquisitions and abandonment and reclamation activities. Over 60% of the capital budget will be incurred in the first half of 2021. Approximately 85% of the 2021 program will be focused on advancing the Company's liquids-rich Montney developments at Karr and Wapiti. Approximately 70% of the 2021 capital budget is being allocated to sustaining capital and maintenance activities and the remaining 30% to production growth.

At Karr, Paramount plans to drill 21 Montney wells and bring onstream a total of 19 wells in 2021. The six-well 3-10 pad was brought on production in February 2021, and the Company is currently drilling the three-well 4-28 East pad and the five-well 7-18 Pad that are expected to be onstream late in the second quarter and third quarter, respectively. The Company also plans to drill and bring onstream the five-well 5-16 East pad by the end of the third quarter and begin drilling the ten-well 16-17 pad during the fourth quarter.

At Wapiti, the Company is currently drilling the remaining four Montney wells on the seven-well 6-4 pad. All seven wells are expected to be brought onstream starting in the third quarter of 2021. The Company also plans to drill a tenure well at Wapiti in 2021.

Other key activities include a two-well Duvernay pad at Willesden Green, completion of a single well at Ante Creek (Montney oil) and the initiation of an enhanced oil recovery pilot at the Kaybob North Montney oil pool.

The Company expects 2021 sales volumes to average between 77,000 Boe/d and 80,000 Boe/d (45% liquids), slightly higher than preliminary guidance after accounting for first quarter dispositions of approximately 2,600 Boe/d of annualized production. (2)

First half 2021 sales volumes are expected to average between 74,000 Boe/d and 76,000 Boe/d (43% liquids) as the majority of new wells will be brought on later in the year and volumes will be impacted by a scheduled outage at Karr in the second quarter.

Despite a scheduled outage at Wapiti in the third quarter, second half 2021 sales volumes are expected to increase to average between 80,000 Boe/d and 84,000 Boe/d (46% liquids) as additional liquids-rich wells are brought onstream.

Readers are referred to the advisories concerning "Reserves Data" in the Advisories section of this document.

See the Product Type Information section for further information respecting the composition of forecast sales volumes.

The Company forecasts 2021 free cash flow of approximately $160 million based on: (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$58.60/Bbl WTI, US$3.00/MMBtu NYMEX, $2.80/GJ AECO), (iv) operating costs of $11.65/Boe, and (v) transportation and processing costs of $4.00/Boe. With approximately 57% of forecast midpoint 2021 production hedged, forecast free cash flow would still be approximately $100 million at an average 2021 WTI oil price of US$43.50/Bbl.(1)

The Company has budgeted approximately $31 million for abandonment and reclamation activities in 2021. Approximately $6 million is to be funded directly through the Alberta Site Rehabilitation Program ("ASRP"), resulting in approximately $25 million net to Paramount. The majority of these funds will be directed to the Zama area.

RESERVES (1)
Despite a significant reduction in commodity price assumptions used by the independent third-party reserves evaluator, Paramount's 2020 proved plus probable ("P+P") reserves were unchanged versus 2019 at 632 MMBoe while proved developed producing ("PDP") reserves increased by 8% to 121 MMBoe. This reflects the Company's success in sustainably reducing both its operating and capital cost structure, as well as improvements in well performance. Optimizing Paramount's 5-year capital program resulted in a 2020 total proved ("TP") reserves decrease of 7% to 311 MMBoe compared to 335 MMBoe in 2019.

Total undiscounted future development costs were reduced by $962 million for TP reserves and by $1,196 million for P+P reserves. Further reductions may be realized if actual DCET costs continue to be lower than the costs used by the Company's independent third-party reserves evaluator in 2020.

The liquids weighting of the Company's 2020 reserves remain largely unchanged from 2019 (P+P 53% natural gas, 39% condensate and oil, 8% other NGLs).

The Company's reserves replacement ratio was 1.4x for PDP reserves.

PDP finding and development costs were $6.31/Boe in 2020.

Estimated future net revenue at December 31, 2020, discounted at 10% before tax, totaled $1.9 billion for TP reserves and $3.6 billion for P+P reserves.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE
Paramount has a long history of sustainable resource development and environmental stewardship and is committed to creating value for our stakeholders in an environmentally and socially responsible manner. Environmental, Social and Governance ("ESG") highlights in 2020 include:

Participation in the 2020 CDP Climate Change Survey.

Completion of a multi-year project to replace approximately 1,900 high vent controllers with modern low or no vent units, reducing Paramount's annual greenhouse gas emissions by an estimated 75,000 tonnes of carbon dioxide equivalent ("tCO2e"). Information about Paramount's other emissions reduction activities can be found in our ESG report.

Paramount has implemented a corporate pandemic response plan aimed at ensuring the health and safety of its staff and contractors and the people they come in contact with. The Company is conducting its operations in compliance with public health requirements and guidelines, including providing additional personal protective equipment and restricting access to its work sites to critical personnel.

Readers are referred to the advisories concerning "Reserves Data" and "Oil and Gas Measures and Definitions" in the Advisories section of this document. Reserves evaluated by McDaniel & Associates Consultants Ltd. ("McDaniel") as of December 31, 2020 and December 31, 2019 in accordance with National Instrument 51-101 definitions, standards and procedures. Reserves are gross reserves representing working interest before royalties. Net present values of future net revenue were determined using forecast prices and costs and do not represent fair market value.

CORPORATE
To provide greater certainty of free cash flow levels and the funding of the Company's 2021 capital program, Paramount has hedged approximately 57% of its 2021 forecast production.

Natural Gas: approximately 67,400 MMBtu/d at US$2.73/MMBtu and approximately 89,200 GJ/d at CDN$2.53/GJ over 2021.

Oil: approximately 18,100 Bbl/d at US$46.35/Bbl in 2021 and 3,000 Bbl/d at CDN$65.29/Bbl in the second and third quarters.

Condensate: 1,000 Bbl/d at US$WTI plus US$0.50/Bbl in the first quarter and 4,000 Bbl/d at US$WTI plus US$0.06/Bbl in the second quarter.

Paramount's natural gas diversification strategy includes arrangements to sell approximately 60,000 GJ/d of natural gas at Dawn, approximately 22,000 GJ/d of natural gas at Malin, and 40,000 GJ/d of natural gas sales priced in the US Midwest.

The Company's long-term debt at December 31, 2020 was $813 million. In January 2021, Paramount's $1.0 billion senior secured revolving bank credit facility was amended to remove prior conditions on facility availability in excess of $900 million. Concurrent with the amendments, the Company completed a private placement of $35 million of senior unsecured convertible debentures.

In March 2021, the Company elected to exit the covenant relief period under its $1.0 billion bank credit facility prior to the scheduled expiry of the period on June 30, 2021.


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