Canada NewsWire
CALGARY, May 13, 2020
CALGARY, May 13, 2020 /CNW/ -
HIGHLIGHTS
_______________ | |
(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
REVIEW OF OPERATIONS
GRANDE PRAIRIE REGION
Karr
Karr sales volumes and netbacks are summarized below:
Q1 2020 | Q4 2019 | % Change | |||
Sales volumes | |||||
Natural gas (MMcf/d) | 59.4 | 69.1 | (14) | ||
Condensate and oil (Bbl/d) | 9,691 | 11,816 | (18) | ||
Other NGLs (Bbl/d) | 1,290 | 1,614 | (20) | ||
Total (Boe/d) | 20,885 | 24,943 | (16) | ||
% liquids | 53% | 54% | |||
Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | % Change in $ |
Petroleum and natural gas sales | 64.2 | 33.76 | 92.5 | 40.32 | (31) |
Royalties | (5.0) | (2.62) | (6.8) | (2.98) | (26) |
Operating expense | (30.8) | (16.19) | (30.5) | (13.29) | 1 |
Transportation and NGLs processing | (6.7) | (3.54) | (6.9) | (3.00) | (3) |
21.7 | 11.41 | 48.3 | 21.05 | (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) | ||||||
Total | Wellhead Liquids | CGR (3) | Total | Wellhead | CGR (3) | Days on | |
(Boe/d) | (Bbl/d) | (Bbl/MMcf) | (MBoe) | (MBbl) | (Bbl/MMcf) | ||
01-19 Pad | |||||||
03/13-29-065-05W6/0 | 1,704 | 1,209 | 407 | 205 | 138 | 343 | 141 |
03/14-29-065-05W6/0 | 1,357 | 1,067 | 611 | 120 | 91 | 518 | 122 |
04/13-29-065-05W6/0 | 1,566 | 1,170 | 493 | 161 | 117 | 450 | 136 |
Avg. per well | 1,542 | 1,149 | 486 | 162 | 115 | 412 | 133 |
04-24 Pad | |||||||
00/01-11-065-06W6/0 | 1,878 | 1,271 | 349 | 268 | 165 | 265 | 201 |
00/02-12-065-06W6/0 | 1,836 | 1,308 | 413 | 222 | 152 | 362 | 202 |
00/03-12-065-06W6/0 | 2,307 | 1,583 | 365 | 356 | 230 | 307 | 216 |
00/04-12-065-06W6/0 | 2,097 | 1,329 | 289 | 358 | 216 | 253 | 209 |
02/03-12-065-06W6/0 | 2,029 | 1,308 | 302 | 318 | 199 | 278 | 209 |
Avg. per well | 2,029 | 1,360 | 338 | 304 | 192 | 286 | 207 |
2018 Wells | |||||||
5 wells (Avg. per well) | 1,877 | 1,121 | 247 | 587 | 308 | 184 | 536 |
2016/2017 Wells | |||||||
27 wells | 1,969 | 1,171 | 245 | 707 | 356 | 169 | 776 |
(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) | ||||||
Total | Wellhead Liquids | CGR (3) | Total | Wellhead | CGR (3) | Days on | |
(Boe/d) | (Bbl/d) | (Bbl/MMcf) | (MBoe) | (MBbl) | (Bbl/MMcf) | ||
5-3 East Pad | |||||||
03/11-27-067-06W6/0 | 2,226 | 1,412 | 289 | 147 | 93 | 286 | 92 |
04/06-15-068-06W6/0 | 1,736 | 1,187 | 360 | 80 | 55 | 366 | 58 |
02/09-28-067-06W6/0 | 1,776 | 1,110 | 278 | 95 | 61 | 291 | 67 |
02/11-27-067-06W6/0 | 2,076 | 1,344 | 306 | 130 | 84 | 303 | 86 |
00/12-27-067-06W6/0 | - | - | - | 36 | 24 | 348 | 25 |
02/12-27-067-06W6/0 | - | - | - | 55 | 36 | 328 | 27 |
00/09-28-067-06W6/0 | - | - | - | 41 | 28 | 369 | 22 |
03/06-15-068-06W6/0 | 1,465 | 1,036 | 403 | 68 | 49 | 423 | 52 |
00/05-15-068-06W6/0 | 1,481 | 1,066 | 428 | 46 | 34 | 443 | 32 |
02/05-15-068-06W6/0 | - | - | - | 41 | 29 | 399 | 23 |
00/08-16-068-06W6/0 | - | - | - | 31 | 22 | 395 | 20 |
02/08-16-068-06W6/0 | - | - | - | 21 | 16 | 494 | 10 |
Avg. per well | 1,793 | 1,193 | 331 | 66 | 44 | 340 | 43 |
9-3 Pad | |||||||
00/11-27-067-06W6/0 | 1,360 | 880 | 306 | 174 | 111 | 294 | 195 |
03/08-15-068-06W6/0 | 962 | 689 | 421 | 142 | 104 | 459 | 227 |
04/09-27-067-06W6/0 | 1,536 | 1,102 | 423 | 276 | 175 | 288 | 281 |
03/09-27-067-06W6/0 | 1,268 | 794 | 279 | 255 | 162 | 289 | 279 |
02/06-15-068-06W6/0 | 1,511 | 1,088 | 429 | 157 | 113 | 424 | 150 |
02/09-27-067-06W6/0 | 1,094 | 769 | 395 | 218 | 142 | 314 | 259 |
03/07-15-068-06W6/0 | 1,042 | 787 | 516 | 167 | 115 | 369 | 249 |
02/10-27-067-06W6/0 | 1,137 | 779 | 362 | 207 | 135 | 312 | 242 |
03/10-27-067-06W6/0 | 1,111 | 749 | 345 | 210 | 129 | 266 | 259 |
02/08-15-068-06W6/0 | 969 | 693 | 419 | 154 | 105 | 353 | 229 |
02/07-15-068-06W6/0 | 1,192 | 815 | 360 | 154 | 107 | 379 | 207 |
Avg. per well | 1,198 | 831 | 378 | 192 | 127 | 325 | 234 |
(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:
Oil | Volume | Price | Remaining term |
Oil – NYMEX WTI Swaps (Sale) | 4,000 Bbl/d | CDN$80.11/Bbl | April 2020 – December 2020 |
Oil – NYMEX WTI Swaps (Sale) | 6,000 Bbl/d | CDN$38.78/Bbl | May 2020 |
Oil – NYMEX WTI Swaps (Sale) | 6,000 Bbl/d | CDN$40.15/Bbl | June 2020 |
Gas | Volume | Price | Remaining term |
NYMEX Swaps (Sale) | 10,000 MMBtu/d | US$2.93/MMBtu | November 2020 - March 2021 |
NYMEX Swaps (Sale) | 20,000 MMBtu/d | US$2.75/MMBtu | January 2021 - December 2021 |
Physical | 80,000 GJ/d | $1.61/GJ | April 2020 - October 2020 |
Physical | 10,000 GJ/d | $2.11/GJ | May 2020 - October 2020 |
Physical | 10,000 GJ/d | $2.65/GJ | November 2020 - March 2021 |
Physical | 20,000 GJ/d | $2.50/GJ | January 2021 - December 2021 |
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas reserves and resources, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Class A common shares are listed on the Toronto Stock Exchange under the symbol "POU".
Paramount's first quarter 2020 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at https://mma.prnewswire.com/media/1167577/Paramount_Resources_Ltd_ReportsQ12020.pdf
This information will also be made available through Paramount's website at www.paramountres.com and on SEDAR at www.sedar.com.
FINANCIAL AND OPERATING RESULTS (1) ($ millions, except as noted) | ||||
Q1 2020 | Q4 2019 | |||
Net loss | (235.1) | (31.1) | ||
per share – basic and diluted ($/share) | (1.76) | (0.24) | ||
Cash from operating activities | 30.5 | 70.5 | ||
per share – basic and diluted ($/share) | 0.23 | 0.54 | ||
Adjusted funds flow | 33.5 | 93.5 | ||
per share – basic and diluted ($/share) | 0.25 | 0.71 | ||
Total assets | 3,009.5 | 3,531.3 | ||
Long-term debt | 651.5 | 632.3 | ||
Net debt | 771.9 | 703.5 | ||
Common shares outstanding (thousands)(2) | 133,346 | 133,337 | ||
Sales volumes | ||||
Natural gas (MMcf/d) | 261.5 | 299.0 | ||
Condensate and oil (Bbl/d) | 21,898 | 28,516 | ||
Other NGLs (Bbl/d) (3) | 4,539 | 7,064 | ||
Total (Boe/d) | 70,022 | 85,411 | ||
% liquids | 38% | 42% | ||
Grande Prairie Region (Boe/d) | 28,214 | 36,789 | ||
Kaybob Region (Boe/d) | 32,700 | 33,167 | ||
Central Alberta and Other Region (Boe/d) | 9,108 | 15,455 | ||
Total (Boe/d) | 70,022 | 85,411 | ||
Netback | $/Boe (4) | $/Boe (4) | ||
Natural gas revenue | 53.6 | 2.25 | 75.1 | 2.73 |
Condensate and oil revenue | 111.4 | 55.92 | 175.0 | 66.70 |
Other NGLs revenue (3) | 4.4 | 10.75 | 8.5 | 13.03 |
Royalty and sulphur revenue | 2.7 | ─ | 1.3 | ─ |
Petroleum and natural gas sales | 172.1 | 27.01 | 259.9 | 33.08 |
Royalties | (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) |
Netback | 44.5 | 6.98 | 114.9 | 14.63 |
Commodity contract settlements | 7.0 | 1.10 | 4.7 | 0.60 |
Netback including commodity contract settlements | 51.5 | 8.08 | 119.6 | 15.23 |
Total Capital Expenditures | ||||
Grande Prairie Region | 49.8 | 60.7 | ||
Kaybob Region | 10.1 | 9.5 | ||
Central Alberta and Other Region | 2.8 | 0.6 | ||
Corporate | 1.1 | ─ | ||
Land and property acquisitions | ─ | 1.4 | ||
Total | 63.8 | 72.2 | ||
Asset retirement obligations settlements | 30.3 | 18.0 |
(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
Forward-looking Information
Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:
Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:
Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. In addition, although Paramount expects that negotiations for financial covenant relief under the Paramount Facility will be successful, there is no assurance that an agreement will be reached on acceptable terms. Forward-looking information is based on expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information. The material risks and uncertainties include, but are not limited to:
The foregoing list of risks is not exhaustive. For more information relating to risks, see the sections titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2019, and in the MD&A which are available on SEDAR at www.sedar.com. The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.
Non-GAAP Measures
In this press release, "Adjusted funds flow", "Netback", "Net Debt" and "Total Capital Expenditure", together the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards.
"Adjusted funds flow" refers to cash from operating activities before net changes in operating non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements, provision and other, dispute settlements, closure costs and transaction and reorganization costs. Adjusted funds flow is used to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company. Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as being an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS. The following is a reconciliation of adjusted funds flow to the nearest GAAP measure for the three months ended March 31, 2020 and December 31, 2019:
Three months ended | Mar 31, 2020 (MM$) | Dec. 31, 2019 (MM$) |
Cash from operating activities | 30.5 | 70.4 |
Change in non-cash working capital | (34.3) | (7.9) |
Geological and geophysical expenses | 2.6 | 3.5 |
Asset retirement obligations settled | 30.3 | 18.0 |
Provision and other | 4.4 | - |
Closure costs | - | 4.7 |
Dispute settlements | - | 2.5 |
Transaction and reorganization costs | - | 2.3 |
Adjusted funds flow | 33.5 | 93.5 |
"Netback" equals petroleum and natural gas sales less royalties, operating costs and transportation and NGLs processing costs. Netback is commonly used by management and investors to compare the results of the Company's oil and gas operations between periods. Refer to the table under the heading "Financial and Operating Results" for the calculation thereof.
"Net Debt" is a measure of the Company's overall debt position after adjusting for certain working capital and other amounts and is used by management to assess the Company's overall leverage position. Refer to the Liquidity and Capital Resources section of the Company's MD&A for the calculation of Net Debt.
"Total capital expenditures" refers to the Company's property, plant and equipment and exploration expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures section of the Company's MD&A for the calculation thereof.
Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
The term "liquids" includes oil, condensate and Other NGLs (ethane, propane and butane). NGLs consist of condensate and Other NGLs.
Abbreviations
Liquids | Natural Gas | |||
Bbl | Barrels | GJ | Gigajoules | |
Bbl/d | Barrels per day | GJ/d | Gigajoules per day | |
MBbl | Thousands of barrels | Mcf | Thousands of cubic feet | |
NGLs | Natural gas liquids | MMcf | Millions of cubic feet | |
Condensate | Pentane and heavier hydrocarbons | MMcf/d | Millions of cubic feet per day | |
AECO | AECO-C reference price | |||
Oil Equivalent | WTI | West Texas Intermediate | ||
Boe | Barrels of oil equivalent | |||
MBoe | Thousands of barrels of oil equivalent | |||
MMBoe | Millions of barrels of oil equivalent | |||
Boe/d | Barrels of oil equivalent per day |
This press release contains disclosures expressed as "Boe", "$/Boe", "MBoe","MMBoe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2020, the value ratio between crude oil and natural gas was approximately 26:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.
This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses this oil and gas metric for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measure is not a reliable indicator of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.
Additional information respecting the Company's oil and gas properties and operations, including a breakdown of 2019 annual and quarterly production volumes by product type, is provided in the Company's annual information form for the year ended December 31, 2019 which is available on SEDAR at www.sedar.com.
SOURCE Paramount Resources Ltd.
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