Paramount Resources Ltd. Reports Third Quarter 2019 Results

2019-11-07

TSX - Toronto Stock Exchange · Natural Gas · Oil · Natural Gas Liquids · Ethane · Canada

Canada NewsWire

CALGARY, Nov. 7, 2019

CALGARY, Nov. 7, 2019/CNW/ -

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HIGHLIGHTS

Paramount's sales volumes averaged 81,046 Boe/d in the third quarter of 2019, relatively unchanged from the second quarter. Third quarter liquids sales volumes, however, increased 1,441 Bbl/d to 31,612 Bbl/d (39 percent of total sales) compared to 30,171 Bbl/d (37 percent of total sales) in the second quarter. At Wapiti, third quarter sales volumes increased 109 percent to 8,163 Boe/d (74 percent liquids) compared to the second quarter. All 11 (11.0 net) Montneywells on the Wapiti 9-3 pad have started-up and are producing at restricted rates largely due to intermittent, but improving, runtime associated with the commissioning of the new third-party Wapiti natural gas processing facility (the ʺWapiti Plantʺ). Under those operating conditions, the 11 wells averaged gross peak 30-day production of 1,198 Boe/d per well, with average CGRs of 378 Bbl/MMcf.(1) At the new 5-3 pad in Wapiti, three of 12 (12.0 net) wells were temporarily brought-on production through inline test facilities in late-September. The remaining wells are being flowed on cleanup on a rotational basis to recover completion fluids prior to the installation of permanent surface facilities. Initial flowback results have demonstrated higher production rates than the 9-3 pad. At Karr, 5 (5.0 net) new Montneywells were started-up on the 4-24 pad in late-September, averaging 2,027 Boe/d of gross peak 30-day production per well, with an average wellhead CGR of 339 Bbl/MMcf.(1) Paramount is increasing its fourth quarter 2019 production guidance to between 87,000 Boe/d and 90,000 Boe/d. The Company's third quarter netback was $68.2 millioncompared to $82.1 millionin the second quarter of 2019, mainly due to lower commodity prices and incremental third-party processing fees following the sale of the Karr 6-18 natural gas processing facility (the ʺ6-18 Facilityʺ) in August.(2) Cash from operating activities was $48.6 millionin the third quarter of 2019. Adjusted funds flow was $50.9 million($0.39per share).(2) Base capital spending totaled $113.1 millionfor the third quarter and $265.0 millionfor the nine months ended September 30, 2019, with capital programs at Wapiti and Central Albertacoming in under budget. As a result of capital efficiencies realized to date in the 2019 program, the Company has accelerated drilling operations for 10 (10.0 net) Montneywells at Karr into the fourth quarter of 2019 that were originally scheduled for 2020, while maintaining its 2019 base capital budget at $350 million.(2) The Company commenced its first area-based closure (ʺABCʺ) abandonment and reclamation project in the third quarter at Hawkeye. Economies of scale gained under the ABC approach have resulted in significantly lower costs than prior estimates. The Company's undiscounted estimated asset retirement obligation was revised down by approximately $140 millionfrom December 31, 2018to September 30, 2019.

| | | | (1) | Production measured at the wellhead. Natural gas sales volumes are lower by approximately 14 percent (Karr) and 11 percent (Wapiti) and Wellhead Liquids sales volumes are lower by approximately 12 percent (Karr) and 3 percent (Wapiti) due to shrinkage, under normalized operations. 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. See ʺOil and Gas Measures and Definitionsʺ in the Advisories. | | (2) | Netback, adjusted funds flow and base capital are non-GAAP measures. See ʺNon-GAAP Measuresʺ in the Advisories. |

CORPORATE

Paramount's natural gas diversification strategy resulted in an average realized natural gas sales price of $1.58/Mcf in the third quarter, 46 percent higher than average AECO prices. In the third quarter of 2019, approximately 65 percent of Paramount's natural gas production was sold at AECO prices. The Company is well positioned to take advantage of the recent strengthening of market fundamentals in Alberta. In October 2019, the Company entered into AECO fixed-price physical contracts to sell 40,000 GJ/d of natural gas at $2.34/GJ for winter 2019/2020 and 60,000 GJ/d of natural gas at $1.56/GJ for summer 2020. Paramount closed the sale of its Karr 6-18 Facility for net cash proceeds of $327.6million in August 2019. The Company's long-term debt balance at September 30, 2019was $720.9 million. Paramount has a $1.5 billionbank credit facility that matures in November 2022. To date, the Company has purchased and cancelled 2.6 million Paramount common shares under its 2019 normal course issuer bid program (the ʺ2019 NCIBʺ) at a total cost of $14.4 million. These purchases were mainly funded by the disposition of a portion of the Company's investment in MEG Energy Corp.

REVIEW OF OPERATIONS

Paramount's sales volumes averaged 81,046 Boe/d in the third quarter of 2019, relatively unchanged from the second quarter. Liquids volumes increased to 31,612 Bbl/d (39 percent of total sales) in the third quarter compared to 30,171 Bbl/d (37 percent of total sales) in the second quarter. Liquids-rich production continued to ramp-up at both Wapiti and Kaybob South Duvernay. Third quarter production at Karr and Kaybob was impacted by planned facilities outages as well as the temporary shut-in of certain dry gas wells, as the Company proactively managed seasonally low natural gas prices.

Cash from operating activities was $48.6 millionin the third quarter of 2019 compared to $48.1 millionin the second quarter. Third quarter adjusted funds flow was $50.9 million($0.39per share) compared to $54.2 million($0.41per share) in the second quarter of 2019. Adjusted funds flow was impacted by lower realized prices and incremental third-party processing fees following the sale of the Karr 6-18 Facility.

Paramount permanently shut down its dry gas Hawkeye property in late-2018 and its Zamaproperty in the first half of 2019 due to challenging economics. The closure of Zamais expected to reduce the Company's total operating expenses by approximately $27 millionper year. The Company has permanently shut-in approximately 2,100 Boe/d of uneconomic production since the fourth quarter of 2018.

Base capital spending totaled $113.1 millionfor the third quarter and $265.0 millionfor the nine months ended September 30, 2019, with capital programs at Wapiti and Central Albertacoming in under budget. As a result of capital efficiencies realized to date in the 2019 program, the Company has accelerated drilling operations for 10 (10.0 net) Montneywells at Karr into the fourth quarter of 2019 that were originally scheduled for 2020, while maintaining its 2019 base capital budget at $350 million.

GRANDE PRAIRIEREGION

Karr

| | Q3 2019 | Q2 2019 | | | | Sales volumes | | | | | | Natural gas (MMcf/d) | 58.3 | 68.5 | | | | Condensate and oil (Bbl/d) | 8,712 | 8,858 | | | | Other NGLs (Bbl/d) | 1,117 | 1,505 | | | | Total (Boe/d) | 19,542 | 21,782 | | | | % liquids | 50% | 48% | | | | | | | | | | Netback | ($ millions) | ($/Boe) | ($ millions) | ($/Boe) | | Petroleum and natural gas sales | 63.3 | 35.24 | 72.0 | 36.32 | | Royalties | (5.7) | (3.15) | (9.8) | (4.90) | | Operating expense | (27.8) | (15.47) | (20.1) | (10.14) | | Transportation and NGLs processing | (6.6) | (3.66) | (5.2) | (2.65) | | | 23.2 | 12.96 | 36.9 | 18.63 |

Third quarter 2019 sales volumes at Karr averaged 19,542 Boe/d compared to 21,782 Boe/d in the second quarter of 2019. Third quarter production at Karr was impacted for 12 days by scheduled processing facility outages and the temporary shut-in of two wells for approximately six weeks due to offsetting completion activities at the 4-24 pad.

The third quarter decrease in Karr netbacks was mainly the result of lower production, incremental third-party processing fees and higher water disposal costs. Incremental processing fees at the 6-18 Facility represented approximately $2.85per Boe of third quarter per-unit operating costs for Karr alone and $0.70per Boe for the Company.

At the 4-24 pad, 5 (5.0 net) new Montneywells were completed and brought-on production in late-September, exhibiting very strong initial performance, averaging 2,027 Boe/d of gross peak 30-day production per well with a CGR of 339 Bbl/MMcf.(1) Completion costs for these wells averaged $6.8 millionper well compared to budgeted type-well completion costs of $7.7 million.

Paramount has also drilled 3 (3.0 net) new Montneywells on the 1-19 pad, which are scheduled to be brought on-stream late in the fourth quarter. Karr area sales volumes are expected to increase through the balance of the year as new production ramps up on the 4-24 and 1-19 pads.

In the fourth quarter of 2019, the Company commenced drilling operations for 10 (10.0 net) Montneywells that were originally scheduled for 2020. Paramount's focus on continuous improvement resulted in a new pacesetter well drilling cost of approximately $2.9 million, which compares to budgeted Karr type-well drilling costs of $4.0 millionper well.

These ten new Karr wells will be completed and brought-on production in 2020, once the third-party midstream operator completes its expansion of the 6-18 Facility. Paramount is also investing in additional water injection facilities in 2020 to add incremental water disposal capacity. As Karr production ramps up, the expansion of the 6-18 Facility is completed and new water injection facilities come on-stream, per-unit operating costs at Karr are expected to decrease.

| _ | | | (1) | Production measured at the well head, see table on page 4. |

The Company drilled its first Lower Montney well at Karr in 2018, and the 4-24 and 1-19 pads each include one Lower Montney well. The results of these three wells will be incorporated in Paramount's assessment of total Montneywell location inventory, in the context of optimizing recoveries and capital efficiencies.

Montneywells at Karr continue to exhibit strong production rates and condensate yields. The following table summarizes the performance of wells on the 4-24 and 1-2 pads, and the 27 wells drilled in the 2016/2017 capital program:

Liquids | CGR (3) | Total | Wellhead Liquids | CGR (3) | Days on Production | | | (Boe/d) | (Bbl/d) | (Bbl/MMcf) | (MBoe) | (MBbl) | (Bbl/MMcf) | | | 4-24 Pad | | | | | | | | | 00/01-11-065-06W6/0 (4) | 1,878 | 1,271 | 349 | 89 | 59 | 328 | 50 | | 00/02-12-065-06W6/0 | 1,836 | 1,308 | 413 | 83 | 59 | 410 | 50 | | 02/03-12-065-06W6/0 | 2,029 | 1,308 | 302 | 110 | 69 | 280 | 57 | | 00/04-12-065-06W6/0 | 2,084 | 1,320 | 288 | 114 | 69 | 256 | 57 | | 00/03-12-065-06W6/0 | 2,307 | 1,584 | 365 | 139 | 91 | 316 | 64 | | 1-2 Pad | | | | | | | | | 02/01-26-065-05W6/0 | 2,108 | 1,333 | 287 | 431 | 245 | 220 | 360 | | 02/04-25-065-05W6/0 | 1,703 | 951 | 211 | 484 | 231 | 152 | 393 | | 00/02-26-065-05W6/0 | 2,058 | 1,286 | 278 | 627 | 351 | 212 | 405 | | 00/04-25-065-05W6/0 (4) | 1,598 | 975 | 261 | 400 | 227 | 219 | 411 | | 00/01-26-065-05W6/0 | 1,878 | 1,180 | 282 | 551 | 301 | 201 | 412 | | 2016/2017 Wells | | | | | | | | | 27 wells (Avg. per well) | 1,971 | 1,186 | 252 | 650 | 333 | 175 | 659 |

| (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 14 percent lower and Wellhead 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 October 31, 2019. Natural gas sales volumes are approximately 14 percent lower and Wellhead 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. | | (4) | Lower Montney well. |

Wapiti

Sales volumes at Wapiti averaged 8,163 Boe/d in the third quarter of 2019, comprised of 13.0 MMcf/d of natural gas and 6,002 Bbl/d of liquids, and generated a netback of $14.2 million($18.94per Boe). Intermittent production during the commissioning of the new third-party Wapiti Plant resulted in higher fuel gas and shrink losses. These impacts are expected to diminish as operations at the Wapiti Plant stabilize and throughput increases. Third quarter 2019 capital spending at Wapiti was $61.2 million, focused on completion operations at the 5-3 pad, which came in significantly under budget.

All 11 (11.0 net) wells on the Company's first pad at Wapiti, the 9-3 pad, have been brought- on production. This 11-well pad consists of a six-well block drilled to the south and a five-well block drilled to the north. The north and south blocks are specifically designed to test landing zone and spacing patterns. Completion costs for the 9-3 pad averaged $5.5 millionper well, compared to budgeted Wapiti type-well completion costs of $7.8 million.

Initial production rates for these wells were impacted by an extended cycle time between completion operations and initial flowback, tubular limitations and intermittent production due to infrastructure capacity restrictions and commissioning activities at the Wapiti Plant. These early operational challenges have been largely alleviated and runtime and production rates have stabilized. Despite the operational challenges encountered with start-up, these wells have exhibited significantly higher CGRs than third-party offsetting wells which utilized a different completion design. The wells on the 9-3 pad are Paramount's first Wapiti wells fracked with the same completion design as utilized at Karr, which have also exhibited higher long-term production rates and higher CGRs than offsetting third-party wells.

The following table summarizes the performance to date of the 11 Montney wells on the 9-3 pad:

Liquids | CGR (3) | Total | Wellhead Liquids | CGR (3) | Days on Production | | | (Boe/d) | (Bbl/d) | (Bbl/MMcf) | (MBoe) | (MBbl) | (Bbl/MMcf) | | | 9-3 Pad | | | | | | | | | 02/06-15-068-06W6/0 | 1,511 | 1,088 | 429 | 66 | 48 | 444 | 50 | | 00/11-27-067-06W6/0 | 1,360 | 880 | 306 | 95 | 61 | 299 | 90 | | 02/07-15-068-06W6/0 | 1,192 | 815 | 360 | 112 | 77 | 367 | 133 | | 03/08-15-068-06W6/0 | 962 | 689 | 421 | 99 | 72 | 444 | 133 | | 02/08-15-068-06W6/0 | 969 | 693 | 418 | 106 | 73 | 369 | 137 | | 02/10-27-067-06W6/0 | 1,137 | 779 | 363 | 133 | 89 | 337 | 138 | | 03/10-27-067-06W6/0 | 1,111 | 749 | 345 | 140 | 87 | 274 | 155 | | 03/07-15-068-06W6/0 | 1,042 | 787 | 514 | 120 | 83 | 374 | 156 | | 02/09-27-067-06W6/0 | 1,094 | 769 | 394 | 150 | 100 | 333 | 158 | | 03/09-27-067-06W6/0 | 1,268 | 794 | 279 | 185 | 121 | 315 | 174 | | 04/09-27-067-06W6/0 | 1,536 | 1,102 | 423 | 191 | 123 | 301 | 175 |

| (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 11 percent lower and Wellhead Liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operations. 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 October 31, 2019. Natural gas sales volumes are approximately 11 percent lower and Wellhead Liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operations. 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. |

The new 5-3 pad at Wapiti includes 12 (12.0 net) Montneywells. The Company achieved a new pacesetter drill cost of approximately $2.6 millionfor one of these wells, compared to budgeted type-well drilling costs of $3.5 millionper well.

Three of the twelve wells on the 5-3 pad were brought-on production through inline test facilities in late-September, and three additional wells were started-up in October. The remaining wells are also scheduled to flowback on a rotational basis to recover completion fluids and prepare for the installation of permanent surface facilities. Initial flowback results have demonstrated higher initial production rates than the 9-3 pad, primarily due to flowing without tubular restrictions and a shorter cycle time between completion operations and initial flowback. The following table summarizes the initial production results for six of the wells that have produced to date:

| | Last Day of Production (1) | Cumulative (2) | | | | | | | | | Total | Wellhead Liquids | CGR (3) | Average | Total | Wellhead Liquids | CGR (3) | Days on Production | | | (Boe/d) | (Bbl/d) | (Bbl/MMcf) | (Boe/d) | (MBoe) | (MBbl) | (Bbl/MMcf) | | | 5-3 Pad | | | | | | | | | | 00/09-28-067-06W6/0 | 1,893 | 1,336 | 400 | 1,501 | 9 | 7 | 465 | 6 | | 02/11-27-067-06W6/0 | 2,042 | 1,432 | 391 | 1,975 | 23 | 17 | 445 | 12 | | 00/12-27-067-06W6/0 | 1,869 | 1,281 | 363 | 1,805 | 24 | 17 | 398 | 14 | | 02/12-27-067-06W6/0 | 2,064 | 1,296 | 281 | 2,071 | 33 | 21 | 310 | 16 | | 03/11-27-067-06W6/0 | 2,620 | 1,612 | 267 | 2,021 | 46 | 30 | 317 | 23 | | 02/09-28-067-06W6/0 | 1,538 | 939 | 261 | 1,412 | 57 | 36 | 296 | 40 |

| (1) | Volumes measured on October 31, 2019, or the last day the well was produced. Production measured at the wellhead. Natural gas sales volumes are approximately 11 percent lower and Wellhead Liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operations. The production rates and volumes shown are over a single day and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. See ʺOil and Gas Measures and Definitionsʺ in the Advisories. | | (2) | Cumulative is the aggregate production measured at the wellhead to October 31, 2019. Natural gas sales volumes are approximately 11 percent lower and Wellhead Liquids sales volumes are approximately 3 percent lower due to shrinkage under normalized operations. 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. |