Paramount Resources Ltd. reports first quarter 2020 results
May 13, 20205:00 AM CNW
CALGARY – HIGHLIGHTS
Sales volumes averaged 70,022 Boe/d (38 percent liquids) in the first quarter of 2020.(1)
Production in the first quarter of 2020 was impacted by three separate outages (two unscheduled, one scheduled) at a third-party processing facility in the Wapiti area. This amounted to approximately one full month of downtime or the equivalent of approximately 4,300 Boe/d of high netback production for the quarter. Severe cold weather in January also impacted production in both the Grande Prairie and Kaybob Regions. Production in the Central and Other Region was approximately 6,200 Boe/d lower in the first quarter as a result of the sale of certain assets in the fourth quarter of 2019.
Paramount’s netback was $44.5 million in the first quarter of 2020 compared to $114.9 million in the fourth quarter of 2019 mainly due to lower commodity prices and production. (2)
Cash from operating activities was $30.5 million in the first quarter of 2020. Adjusted funds flow was $33.5 million or $0.25 per share.(2)
At Karr, drilling operations were concluded in the first quarter on the remaining wells from the five-well 12-18 pad first spud in the fourth quarter of 2019. An additional five-well pad at 5-16 was spud part way through the first quarter. Completion operations on the 12-18 pad are now finished, with total lease construction, drilling, completion, equip and tie-in (collectively, “DCET”) costs estimated at a pacesetting $9.5 million per well. This compares with historic type well DCET costs of $12.3 million per well in Karr.
Two new water disposal wells were brought into service towards the end of the first quarter of 2020 at Karr. These wells will reduce operating costs associated with water trucking and disposal and are expected to meet Karr area development needs for the foreseeable future.
At Wapiti, drilling operations commenced on the five-well 5-3 West pad and two wells on the eight-well 6-4 pad were drilled in the first quarter of 2020. In response to current market conditions, Paramount elected to defer the drilling of the remaining six wells on the 6-4 pad.
Abandonment and reclamation projects at Hawkeye and Zama under the area-based closure (“ABC”) program continued in the first quarter of 2020, with the Company abandoning 224 wells between the two properties, including all remaining operated wells in the Hawkeye area. An additional 24 wells were abandoned in other areas for a total of 248 well abandonments in the first quarter of 2020 at a total cost of $30.3 million. Paramount’s abandonment and reclamation activities for the year are budgeted at $33 million and are now largely complete.
First quarter capital spending totaled $63.8 million, primarily related to drilling activities at Karr and Wapiti. Capital expenditures were lower than expected as a result of both lower costs and improved efficiencies.
_______________(1)See “Oil and Gas Measures and Definitions” in the Advisories section.(2)“Netback” and “Adjusted funds flow” are Non-GAAP measures. See “Non-GAAP Measures” in the Advisories section. CORPORATE
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. Under the plan, Paramount staff are working remotely other than in situations where physical workplace attendance is essential. Paramount has taken action to ensure its field operations are being conducted in compliance with public health requirements and guidelines, including by providing additional personal protective equipment and restricting access to its work sites to critical personnel.
The Company has moved aggressively to further reduce its cost structure in response to the recent significant decline in liquids prices:
Paramount has revised its 2020 capital guidance to $165 million. This revised guidance reflects expected cost reductions at planned activity levels generally unchanged from the low end of previous capital guidance of $185 million.
Measures to reduce operating costs, including securing lower contractor and supplier rates, are expected to result in total savings of approximately $25 million over the final three quarters of 2020.
Workforce reductions, a 20 percent reduction in the salary of the Chief Executive Officer and in the cash compensation of the Board of Directors, a 10 percent reduction in the salaries of all other staff and the suspension or elimination of a number of benefits and incentive compensation programs are expected, when combined with previous initiatives, to reduce 2020 general and administrative costs by approximately $15 million.
Paramount has temporarily shut-in approximately 6,600 Boe/d of production at various properties and will adjust shut-in levels as required to maximize the economics of its production base.
The Company has also entered into incremental 2020 and 2021 natural gas hedges and near-term liquids hedges to mitigate volatility and protect cash flows. See below under “Hedging”.
Given the significant ongoing uncertainty in market conditions and the unknown extent and duration of shut-ins, Paramount is withdrawing its 2020 sales volume guidance.
Long-term debt as at March 31, 2020 was $651.5 million. Paramount was in compliance with the financial covenants contained in its senior secured revolving bank credit facility (the “Paramount Facility”) as at March 31, 2020. These covenants are described under the heading “Liquidity and Capital Resources” in the Company’s Management’s Discussion & Analysis for the quarter. The current adverse pricing conditions for liquids that have arisen in connection with the COVID-19 pandemic have resulted in a risk of non-compliance with these financial covenants in future periods. In response to this risk, Paramount has initiated negotiations for financial covenant relief and these negotiations are ongoing. Paramount anticipates that any agreement for financial covenant relief will include a reduction in the size of the Paramount Facility, among other changes.
The impact of the COVID-19 pandemic on forecast liquids and natural gas prices has caused the Company to record impairments to petroleum and natural gas assets totaling $191.8 million and a $130.0 million charge to derecognize a portion of the Company’s deferred tax asset.
REVIEW OF OPERATIONS GRANDE PRAIRIE REGION Karr Karr sales volumes and netbacks are summarized below: Q1 2020Q4 2019% ChangeSales volumesNatural gas (MMcf/d)59.469.1(14)Condensate and oil (Bbl/d)9,69111,816(18)Other NGLs (Bbl/d)1,2901,614(20)Total (Boe/d)20,88524,943(16)% liquids53%54%Netback($ millions)($/Boe) ($ millions)($/Boe)% Change in $ millionsPetroleum and natural gas sales64.233.7692.540.32(31)Royalties(5.0)(2.62)(6.8)(2.98)(26)Operating expense(30.8)(16.19)(30.5)(13.29)1Transportation and NGLs processing(6.7)(3.54)(6.9)(3.00)(3)21.711.4148.321.05(55) First quarter 2020 sales volumes at Karr averaged 20,885 Boe/d compared to 24,943 Boe/d in the fourth quarter of 2019. First quarter sales volumes were impacted by severe cold weather and the back-out of production from certain legacy wells due to high pressures from the 4-24 and 1-19 pads. The Company has installed gas lift and related compression at pads near the southwest terminus of Paramount’s gathering system. This work was done to mitigate the impact from newer higher-pressure wells upstream. Work is ongoing to mitigate current and future potential back-out issues in the Karr gathering system, as new production continues to be brought online. The bulk of these efforts are scheduled to be completed in third quarter of 2020. Paramount brought into service two additional water disposal wells towards the end of the first quarter of 2020. These new wells are anticipated to reduce operating costs in the second quarter of 2020 and beyond by reducing the need to truck and dispose of water at third-party facilities. Trucking is expected to be reduced even further upon the start-up of the third-party Karr 6-18 expansion in the second half of 2020 as additional high-pressure pumps will facilitate increased transportation of water to the disposal wells. The Company estimates that with the addition of these wells and related infrastructure, water disposal capacity is now sufficient to meet development needs for the foreseeable future. Drilling operations on 5 (5.0 net) wells on the 12-18 pad that commenced in the fourth quarter of 2019 were completed in the first quarter of 2020. New drill bit technology and improved directional drilling performance resulted in an 18 percent decrease in per meter costs on an Upper Montney well relative to equivalent wells on prior pads. Likewise, the Company saw improved efficiencies in its completion operations with a 25 percent increase in peak fracking stages per day at the 12-18 pad. Paramount continues to incorporate cost savings through design changes that maintain performance without compromising on completion effectiveness. The streamlining of pad facility design combined with improved execution and strategic alliances with key vendors has proven effective in reducing equipping and tie-in costs. The Company anticipates savings of approximately 10 percent on upcoming pads with the potential for further reductions based on recent discussions with its key vendors. In aggregate, Paramount estimates that the all-in DCET cost on the 12-18 pad will average approximately $9.5 million per well; a new pacesetter cost for the Company. This compares with historic type well DCET costs of $12.3 million per well in Karr. The Company plans to complete and bring on production all 10 (10.0 net) wells from the 2-1 pad, drilled in the fourth quarter of 2019, and the 12-18 pad over the remainder of the year in conjunction with the completion of the third-party Karr 6-18 processing facility expansion, expected in the second half of 2020. Paramount commenced the drilling of 5 (5.0 net) Montney wells on the 5-16 pad in the first quarter of 2020 with current plans to complete and bring the wells on production in 2021. Production in the second and third quarters of 2020 will be impacted by the temporary shut-in of certain offsetting wells due to completion activities at both the 12-18 and 2-1 pads. As these wells resume production and wells on the 12-18 and 2-1 pads are brought onstream, production at Karr is expected to increase through the second half of the year. A scheduled one-week outage in May at the third-party operated Karr 6-18 facility, in relation to expansion activities, is currently underway and will also impact second quarter volumes. The following table summarizes the performance of the wells on the 1-19 and 4-24 pads, as well as the five wells drilled in 2018 and the 27 wells drilled in the 2016/2017 capital program at Karr: Peak 30-Day (1)Cumulative (2)TotalWellhead LiquidsCGR (3)TotalWellhead LiquidsCGR (3)Days on Production(Boe/d)(Bbl/d)(Bbl/MMcf)(MBoe)(MBbl)(Bbl/MMcf)01-19 Pad03/13-29-065-05W6/01,7041,20940720513834314103/14-29-065-05W6/01,3571,0676111209151812204/13-29-065-05W6/01,5661,170493161117450136Avg. per well1,5421,14948616211541213304-24 Pad00/01-11-065-06W6/01,8781,27134926816526520100/02-12-065-06W6/01,8361,30841322215236220200/03-12-065-06W6/02,3071,58336535623030721600/04-12-065-06W6/02,0971,32928935821625320902/03-12-065-06W6/02,0291,308302318199278209Avg. per well2,0291,3603383041922862072018 Wells5 wells (Avg. per well)1,8771,1212475873081845362016/2017 Wells27 wells (Avg. per well)1,9691,171245707356169776 (1)Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and liquids sales volumes are approximately 12 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates 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. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures and Definitionsʺ in the Advisories.(2)Cumulative is the aggregate production measured at the wellhead to March 31, 2020. Natural gas sales volumes are approximately 10 percent lower and liquids sales volumes are approximately 12 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.(3)CGRs calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. Wapiti First quarter sales volumes at Wapiti averaged 7,209 Boe/d (66 percent liquids) compared to 11,498 Boe/d (66 percent liquids) in the fourth quarter of 2019. Production in the first quarter of 2020 was impacted by three outages at the third-party processing facility consisting of an unplanned outage in January of approximately 12 days (1,500 Boe/d), a planned outage in early March of approximately 7 days (1,100 Boe/d) and an unplanned outage in the second half of March of approximately 11 days (1,700 Boe/d). During the outages, both Paramount and the third-party operator capitalized on the downtime by conducting optimization and maintenance work that would have otherwise required future near-term outages. While it is expected that these activities will improve the reliability and efficiency of the processing facility and associated infrastructure, Paramount continues to assume a lower uptime factor until consistent reliability is exhibited. The Company commenced drilling operations on 5 (5.0 net) wells at the 5-3 West pad and completed the drilling of 2 (2.0 net) new Montney wells at the 6-4 pad in the first quarter of 2020. Plans to complete and bring onstream wells on the 5-3 West pad, drill the remaining 6 (6.0 net) wells on the 6-4 pad, and complete and bring onstream all 8 wells, have been deferred. A tenure well drilled and completed in 2015 is planned to be brought on production later in 2020. Paramount continues to maximize production from wells on the 12-well 5-3 East pad drilled in 2019 as third-party infrastructure capacity allows. The wells on the 5-3 East pad are seeing improved performance relative to wells on the 9-3 pad as a result of changes to well equipping configuration and more efficient fluid handling. To date, seven wells on the 5-3 East pad have flowed through permanent facilities with all having produced through test facilities. The following table summarizes the performance of wells on the 9-3 and 5-3 East pads: Peak 30-Day (1)Cumulative (2)TotalWellhead LiquidsCGR (3)TotalWellhead LiquidsCGR (3)Days on Production(Boe/d)(Bbl/d)(Bbl/MMcf)(MBoe)(MBbl)(Bbl/MMcf)5-3 East Pad03/11-27-067-06W6/02,2261,412289147932869204/06-15-068-06W6/01,7361,18736080553665802/09-28-067-06W6/01,7761,11027895612916702/11-27-067-06W6/02,0761,344306130843038600/12-27-067-06W6/0–––36243482502/12-27-067-06W6/0–––55363282700/09-28-067-06W6/0–––41283692203/06-15-068-06W6/01,4651,03640368494235200/05-15-068-06W6/01,4811,06642846344433202/05-15-068-06W6/0–––41293992300/08-16-068-06W6/0–––31223952002/08-16-068-06W6/0–––211649410Avg. per well1,7931,1933316644340439-3 Pad00/11-27-067-06W6/01,36088030617411129419503/08-15-068-06W6/096268942114210445922704/09-27-067-06W6/01,5361,10242327617528828103/09-27-067-06W6/01,26879427925516228927902/06-15-068-06W6/01,5111,08842915711342415002/09-27-067-06W6/01,09476939521814231425903/07-15-068-06W6/01,04278751616711536924902/10-27-067-06W6/01,13777936220713531224203/10-27-067-06W6/01,11174934521012926625902/08-15-068-06W6/096969341915410535322902/07-15-068-06W6/01,192815360154107379207Avg. per well1,198831378192127325234 (1)Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Under standard process flowing conditions at contracted rates, the natural gas sales volumes are approximately 11 percent lower and liquids sales volumes are approximately 3 percent lower due to process shrinkage. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates 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. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures and Definitionsʺ in the Advisories. (2)Cumulative is the aggregate production measured at the wellhead to March 31, 2020. Under standard process flowing conditions at contracted rates, the natural gas sales volumes are approximately 11 percent lower and liquids sales volumes are approximately 3 percent lower due to process shrinkage. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.(3)CGRs calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. KAYBOB REGION Kaybob Region sales volumes averaged 32,700 Boe/d (29 percent liquids) in the first quarter of 2020 compared to 33,167 Boe/d (31 percent liquids) in the fourth quarter of 2019. The annual decline rate on base well production in the Region is expected to be 15 percent over 2020 and is expected to largely flatten to 11 percent by 2022. In the first quarter of 2020 the Company drilled 1 (1.0 net) Montney oil well at Ante Creek for Crown land retention purposes. A second land retention well that was planned to be drilled in 2020 prior to the Government of Alberta’s announcement extending land expiries by one year will be deferred in reliance on this extension. The Company will benefit from this extension in a number of other areas. The Company’s crude oil terminal adjacent to the Kaybob North 8-9 gas plant continues to ramp-up operations smoothly with the capacity to handle growing Paramount and third-party volumes. Along with significant crude storage capability at this facility, Paramount is well positioned to take advantage of recent and anticipated price volatility in the crude and condensate markets in order to enhance Kaybob Region netbacks. CENTRAL ALBERTA AND OTHER REGION Central Alberta and Other Region sales volumes averaged 9,108 Boe/d (14 percent liquids) in the first quarter of 2020 compared to 15,455 Boe/d (26 percent liquids) in the fourth quarter of 2019. Sales volumes in the fourth quarter of 2019, when adjusted to exclude production from assets sold in December 2019, averaged approximately 9,200 Boe/d. The Company continued its ABC abandonment and reclamation projects at Hawkeye and Zama in 2020. In the first quarter of 2020, Paramount abandoned 224 wells in these areas (out of total of 248 abandoned by the Company in the quarter), including all remaining operated Hawkeye wells. In doing so, the Company realized an approximate 7 percent decrease in per-well abandonment costs compared to the fourth quarter of 2019. GREENHOUSE GAS REDUCTION INITIATIVE As part of Paramount’s continued commitment to responsible energy development, the Company has been participating in greenhouse gas (“GHG”) emission reduction programs and investing in new equipment to reduce GHG emissions from its operations. The Company is continuing upgrades to replace its remaining high-bleed controllers at various sites with modern low-bleed units. 196 low-bleed units are expected to be installed in the Grande Prairie Region in the second quarter of 2020. These new units are expected to eliminate approximately 8,600 tonnes of GHG emissions per year and generate approximately $0.5 million in GHG credits under current regulations through 2022. HEDGING The Company’s current commodity hedge position is summarized below: OilVolumePriceRemaining termOil – NYMEX WTI Swaps (Sale)4,000 Bbl/dCDN$80.11/Bbl April 2020 – December 2020Oil – NYMEX WTI Swaps (Sale)6,000 Bbl/dCDN$38.78/Bbl May 2020 Oil – NYMEX WTI Swaps (Sale)6,000 Bbl/dCDN$40.15/Bbl June 2020 GasVolumePriceRemaining termNYMEX Swaps (Sale)10,000 MMBtu/dUS$2.93/MMBtu November 2020 – March 2021NYMEX Swaps (Sale)20,000 MMBtu/dUS$2.75/MMBtuJanuary 2021 – December 2021Physical80,000 GJ/d$1.61/GJApril 2020 – October 2020Physical10,000 GJ/d$2.11/GJMay 2020 – October 2020Physical10,000 GJ/d$2.65/GJNovember 2020 – March 2021Physical20,000 GJ/d$2.50/GJJanuary 2021 – December 2021 ABOUT PARAMOUNT Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company’s principal properties are located in Alberta and British Columbia. Paramount’s Class A common shares are listed on the Toronto Stock Exchange under the symbol “POU”. Paramount’s first quarter 2020 results, including Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at https://mma.prnewswire.com/media/1167577/Paramount_Resources_Ltd_ReportsQ12020.pdf This information will also be made available through Paramount’s website at www.paramountres.com and on SEDAR at www.sedar.com. FINANCIAL AND OPERATING RESULTS (1) ($ millions, except as noted)Q1 2020Q4 2019Net loss(235.1)(31.1)per share – basic and diluted ($/share)(1.76)(0.24)Cash from operating activities30.570.5per share – basic and diluted ($/share)0.230.54Adjusted funds flow33.593.5per share – basic and diluted ($/share)0.250.71Total assets3,009.53,531.3Long-term debt651.5632.3Net debt771.9703.5Common shares outstanding (thousands)(2)133,346133,337Sales volumesNatural gas (MMcf/d) 261.5299.0Condensate and oil (Bbl/d)21,89828,516Other NGLs (Bbl/d) (3)4,5397,064Total (Boe/d)70,02285,411% liquids38%42%Grande Prairie Region (Boe/d)28,21436,789Kaybob Region (Boe/d)32,70033,167Central Alberta and Other Region (Boe/d)9,10815,455Total (Boe/d)70,02285,411Netback$/Boe (4)$/Boe (4)Natural gas revenue53.62.2575.12.73Condensate and oil revenue111.455.92175.066.70Other NGLs revenue (3)4.410.758.513.03Royalty and sulphur revenue2.7─1.3─Petroleum and natural gas sales172.127.01259.933.08Royalties(11.7)(1.84)(17.2)(2.19)Operating expense(92.3)(14.49)(105.0)(13.36)Transportation and NGLs processing (5)(23.6)(3.70)(22.8)(2.90)Netback44.56.98114.914.63Commodity contract settlements7.01.104.70.60Netback including commodity contract settlements51.58.08119.615.23Total Capital ExpendituresGrande Prairie Region49.860.7Kaybob Region10.19.5Central Alberta and Other Region2.80.6Corporate1.1─Land and property acquisitions─1.4Total63.872.2Asset retirement obligations settlements30.318.0 (1)Readers are referred to the advisories concerning Non-GAAP Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP measures: Adjusted Funds Flow, Net Debt, Netback, and Total Capital Expenditures.(2)Common shares are presented net of shares held in trust under the Company’s restricted share unit plan (000’s of common shares): 2020: 852.4; 2019: 859.7(3)Other NGLs means ethane, propane and butane.(4)Natural gas revenue presented as $/Mcf.(5)Includes downstream transportation costs and NGLs fractionation costs. Advisories & Contact