Paramount Resources Details Q3 2019 Results

In the fourth quarter of 2019, the Company commenced drilling operations for 10 (10.0 net) Montney wells 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 million per 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.

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 Montney well location inventory, in the context of optimizing recoveries and capital efficiencies.

Montney wells 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:

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 ( $18.94 per 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 million per 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:

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

KAYBOB REGION

Kaybob Region sales volumes averaged 34,615 Boe/d (31 percent liquids) in the third quarter of 2019 compared to 37,127 Boe/d (31 percent liquids) in the second quarter of the year. Sales volumes were lower in the third quarter as a result of base declines, scheduled facility outages and the temporary shut-in of dry gas wells due to low gas prices, partially offset by increased production at Kaybob South Duvernay.  

Kaybob South Duvernay

At Kaybob South Duvernay, 5 (2.5 net) new wells on the 2-28 pad were drilled between June 2018 and January 2019 and completed in the spring of 2019. These wells were tied-in and brought-on production in June 2019 , averaging 1,222 Boe/d of gross peak 30-day production per well, with an average wellhead CGR of 171 Bbl/MMcf.⁽¹⁾ To date, these wells have an average cumulative CGR of 158 Bbl/MMcf.⁽²⁾

Kaybob Smoky Duvernay

In the fourth quarter of 2018, the Company brought 4 (4.0 net) new wells on production on the 10-35 pad at Kaybob Smoky Duvernay through Paramount's Smoky 06-16 gas plant. These wells are continuing to exceed internal type curve estimates. The following table summarizes the performance of the four wells on the 10-35 pad:

Ante Creek Montney

The Kaybob Region drilling program for 2019 included an initial Montney appraisal well at Ante Creek. This well was completed and brought-on production in September. Initial production results are encouraging and continue to be evaluated.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 18,504 Boe/d in the third quarter of 2019 compared to 18,862 Boe/d in the second quarter of 2019. The Company participated in one (0.5 net) well at Birch in northeast British Columbia , which was completed and brought-on production in the second quarter.

Paramount completed the full shut-down of Zama area production in June 2019 . The closure program will continue into 2020 to permanently suspend all facilities and over 2,000 kilometers of pipelines. The closure of Zama is expected to reduce the Company's total operating expenses by approximately $27 million per year.

The Company commenced its first ABC project in the third quarter at Hawkeye. Economies of scale gained under the ABC approach have resulted in significantly lower costs than prior estimates. Paramount will continue to optimize its abandonment and reclamation activities based on the actual experience and knowledge gained from this and other projects and pursue additional opportunities to further reduce costs on an on-going basis. The Company's undiscounted estimated asset retirement obligation was revised from $1.79 billion as at December 31, 2018 to $1.65 billion as at September 30, 2019 , and from $807.9 million to $749.1 million on a discounted basis.

Corporate

Paramount has 16,000 Bbl/d of liquids hedged for the remainder of 2019 at an average price of $78.05 /Bbl and 4,000 Bbl/d of liquids for 2020 at an average price of $80.11 /Bbl.

Paramount's natural gas diversification strategy includes approximately 122,000 GJ/d of sales under long-term contracts priced at the Dawn, US Midwest and Malin markets. The Company's average realized natural gas sales price for the third quarter of 2019 was $1.58 /Mcf, approximately 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, which have resulted in sharp increases in Alberta natural gas prices. In October 2019 , Paramount 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.  

The Company's debt balance at September 30, 2019 was $720.9 million . Paramount has a $1.5 billion bank credit facility that matures in November 2022 .

In January 2019 , Paramount implemented the 2019 NCIB, under which the Company may purchase up to 7.1 million shares for cancellation. To date, the Company has purchased and cancelled 2.6 million common shares at a total cost of $14.4 million under the 2019 NCIB. These purchases were mainly funded by the disposition of a portion of the Company's investment in MEG Energy Corp.